fEAC
)OE
!PA
Texas Energy Advisory Council
Austin, Texas 78701
United States
Department of
Energy
United States
Environmental Protection
Agency
Office of Technology
Impacts
Washington DC 20545
Office of Energy, Minerals, and
Industry
Washington DC 20460
EPA-600/7-79-111a
May 1979
Integrated
Assessment of
Texas Lignite
Development
Volume I. Technical
Analyses
Interagency
Energy/Environment
R&D Program
Report
EPA/600/7-79/11 la
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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 nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine 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
8. "Special" Reports
9. Miscellaneous Reports
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 sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmep^^jlataancLcpntrol technology. Investigations include analy-
ses of thfrffcTnspd^^^nergy^ated 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 environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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AN INTEGRATED ASSESSMENT OF TEXAS LIGNITE DEVELOPMENT
VOLUME I - TECHNICAL ANALYSIS
J. C. Lacy - Project Director
R. J. Davis - Policy
F. H. Sheffield - Policy
R. L. Leonard - Scenario Development
J. R. Stewant. - Air
A. P. Covar - Water
D. D. Harner - Socioeconomics
O. W. Hargrove - Engineering
M. L. Wilson - Program Manager
April, 1979
Prepared for:
TEXAS ENERGY ADVISORY COUNCIL
Energy Development Fund
Project #L-4-7
Project Officer: David White
Office of Research and Development
U.S. Environmental Protection Agency
EPA Grant No. R806359-01
Project Officer: Paul Schwengels
Office of Environment
U. S. Department of Energy
Interagency Agreement DOE EE-78-A-28-3286
Project Officer: F. Jerome Hinkle
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FOREWORD
Recent years have witnessed increasing awareness of the declining
availability of our most widely used energy sources - oil and natural gas -
accompanied by sharp increases in price. Both direct government policy
and the market price mechanism are now operating to stimulate a shift away
from oil and natural gas to other fuels wherever possible. One area in which
this shift is likely to be especially pronounced is the Gulf Coast. There,
massive electric utility and industrial capacity is fueled by oil and nat-
ural gas which have historically been locally plentiful. Assuming this
shift continues, other fuels will be required to power both new and existing
sources. One promising candidate to fill much of the emerging energy gap
in the Gulf Coast region over the near and medium term is lignite which
exists in the same general region and appears to be very competitive econo-
mically. There are, however, significantly different and more serious en-
vironmental consequences associated with extraction, transportation, and
utilization of large quantities of lignite than.is the case for oil and
natural gas.
Thus, this study was conceived as a timely first attempt at defining
and analyzing the consequences and constraints associated with the potential
extensive use of lignite in Texas (which comprises a major portion of the
region in question), and the public policy options available for managing
this development. A notable feature of this research effort has been its
cooperative interagency character. It has been a valuable experience in
federal/state research cooperation between the Department of Energy (DOE)
and the Environmental Protection Agency (EPA), two federal agencies for
which cooperation is essential in this sensitive policy area, and the Texas
Energy Advisory Council, an agency of the State of Texas. In addition,
active involvement of the DOE and EPA regional offices was incorporated
into the design and management of the study. Efforts required to establish
this complex structure were amply compensated for by the range of viewpoints
and experience brought into the research design.
The study has been conducted under demanding constraints of both
funds and time. The time constraint has been an especially difficult one.
From the study's inception, it was agreed that major users to whom this
study would be directed were state and local policy makers (although appro-
priate elements of the federal government, including regional offices, are
considered to be major users as well). In that context it was considered
essential that the study results be available to the 1979 session of the
Texas State Legislature (which meets once every two years). Consequently,
only eight months were available to complete this research, limiting the
level of detail at which lignite development issues could be examined.
A significant decision made early in the study's planning was to
emphasize the aggregate, regional impacts rather than the specific impacts
associated with a single mine or power plant. This decision was based on
two primary factors. First, because of its geologic and geographic distri-
bution, lignite's development will occur over a broad region of Texas rather
than be concentrated in a few limited areas. As such, it was felt that an
analysis of the regional impacts of lignite development might yield valuable
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information not recognized at the level of an individual site. Second, the
attempt to hypothetically site future plants at a more detailed geographic
level was too complex a task to be completed in a credible manner within the
constraints of the study.
Given this perspective, the study team has done an excellent job of
analyzing a number of constraints to and consequences of lignite development
at the regional level and has pointed out many potential problems which
deserve examination at a finer level of detail. Many environmental problems
do not become apparent in an analysis at the regional level of aggregation
although their cumulative impacts may be substantial. This study should,
therefore, be viewed as a "first cut" overview of the issues associated with
Texas lignite development. A finer grained analysis is still required In
future research studies as well as through the permitting process.
The reader should also be sensitive to the effect of assumptions on
conclusions in a study such as this. It was necessary, of course, to make
assumptions about a wide range of future social and economic conditions in
order to assess the potential impacts of lignite development. Varying these
assumptions could substantially alter the study's conclusions. One clear
example relates to availability of water for lignite development. Assump-
tions were made concerning future municipal and agricultural water demand
and future development of dams and other measures to augment water supply.
Given these assumptions, water availability does not appear to pose a signif-
icant constraint to lignite development in most areas of the lignite belt.
Other assumptions, however, could have resulted in quite different conclu-
sions. It was not possible within the limits of the study to examine the
sensitivity of conclusions to variations in many such assumptions. The
reader should, therefore, be aware of the context of assumptions in which
these conclusions were drawn and the resulting limits on their predictive
validity.
The project team, put together by the Radian Corporation, is to be con-
gratulated for producing a thcmgh8:-provoking technical and policy analysis
report. In addition, special thanks are due to all members of the review
panel and to Bill Honker and Mike Gibson of EPA's Dallas Regional Office and
Lila Williams of DOE's Dallas Regional Office for unselfish commitments of
time and experience to the project.
Paul Schwengels, Project Officer Jerry Hlnkle, Project Officer
Office of Environmental Engineering Division of Environment
and Technology Department of Energy
Environmental Protection Agency
David M. White, Project Officer
Texas Energy Advisory Council
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READER'S GUIDE
This Integrated Assessment of Texas Lignite Development was performed
by the Radian Corporation of Austin, Texas, for the Texas Energy Advisory
Council. Joint sponsors of the project, with TEAC, are the U.S. Environ-
mental Protection Agency and ^he U.S. Department of Energy.
The report is divided into sections, as follows:
VOLUME I - Technical Analysis
Chapter I - Potential Use of Solid Fossil Fuels
Chapter II - Lignite Development Scenario
Chapter III - Siting Constraints
Chapter IV - Environmental and Socioeconomic
Impacts
VOLUME II - Policy Analysis
Chapter V - Policy Analysis
VOLUME III - Technical Working Papers
The organization of the first two volumes of the report follows the
sequence of tasks performed in the analysis. Thus, the material in the
later chapters is developed from work presented in the earlier chapters.
Recognizing however, that most readers will not be equally interested in
all of the report's contents, it has been organized for "skipping".
Each of the first four chapters begins with an abstract, summarizing
the topics to be discussed. The technical presentation that follows is
subdivided into major subsections, each prefaced by a brief summary. The
technical presentation is followed by a summary statement of key policy
issues arising from the analysis, which will be discussed subsequently in
Chapter V. Finally, major data gaps and recommendations for further
research are listed, again in summary form. (Chapters III and IV are
organized roughly by disciplinary area, with research recommendations
at the end of each major section.) Each chapter is followed by its
own list of references.
Chapter V contains an analysis of the eighteen policy issues identi-
fied in the first four chapters. Each discussion stands alone, and con-
sists of a summary statement of the issue, a table comparing the attri-
butes of alternative actions or policy options, and a short explanatory
text. The "meat" of the analysis is in the tables. A final section of
Chapter V discusses several underlying issues bearing on lignite develop-
ment.
Ill
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Volume III contains a number of technical working papers developed
midway through the research project to provide background information on
specific areas. The working papers have not been edited or extensively
reviewed prior to printing and may contain typographical and informational
errors. They do, however, provide summaries of the information which was
readily available to the project at the time they were prepared on speci-
fic aspects of Texas lignite development. A limited number of these
volumes have been printed and will be made available on request from
David White, Texas Energy Advisory Council, 7703 North Lamar, Austin,
Texas 78757.
A reader wishing to get an overview of the report before deciding
which sections to read in detail is advised to begin with Volume I, by
reading the abstracts for each chapter, and the summaries of each major
section. Then, a brief glance at the summary statements of the issues
presented in Chapter V will acquaint the reader with the scope of the
policy analysis portion of the study.
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ACKNOWLEDGEMENTS
In addition to the authors listed on the title page, a
great many people gave assistance in the preparation, review, and
production of this report. The heartiest thanks are due to these
people from the authors, and it is with pleasure that we acknowl-
edge the contributions of these individuals.
The conduct of the study was overseen by two groups:
an Overview Committee representing the three funding agencies,
and a Review Panel representing various parties of interest to
lignite development, assembled to advise and comment on the tech-
nical aspects of the work.
The Overview Committee served to steer the overall
direction of the study, and consisted of the following individuals
Mr. David M. White
Texas Energy Advisory Council
Austin, Texas
Mr. Paul Schwengels
Environmental Protection Agency
Office of Research and Development
Washington, D.C.
Mr. Michael Gibson
Environmental Protection Agency
Region VI
Dallas, Texas
Ms. Lila Williams
Department of/ Energy
Region VI
Dallas, Texas
Mr. William Honker
Environmental Protection Agency
Region VI
Dallas, Texas
The Review Panel consisted of an invited group of tech-
nical experts, interest group representatives, industrial and
acedemic personnel, and government agencies involved in lignite
development in Texas. This group reviewed the draft reports pro-
duced by the Radian study team, and provided expert guidance and
v
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suggestions. The present report strongly reflects the valuable
contributions of this group, as interpreted by the Radian staff.
Panel members are not, however,^responsible for the contents of
the final report nor does it always represent a consensus among
the group.
The following people participated on the Review Panel,
or sent deputies:
Dr. William Avera
Public Utility Commission
Austin, Texas
Dr. Hal B. H. Cooper
Civil Engineering Department
University of Texas at Austin
Austin, Texas
Mr. Hugh Davis
Heart of Texas Council of Government
Waco, Texas
Dr, Richard M. Davis
Oak Ridge National Laboratory
Oak Ridge, Tennessee
Dr. William Fisher
Bureau of Economic Geology
University of Texas at Austin
Austin, Texas
Mr. Steve Frishman
Texas Environmental Coalition
Port Aransas, Texas
Dr. Charles Groat
Louisiana Geological Survey
Baton Rouge, Louisiana
Dr. Herb Grubb
Texas Department of Water Resources
Austin, Texas
Dr. George Hardy
Bates School of Law
University of Houston
Houston, Texas
Mr, Joe Harris
County and Rural Services Division
Texas Department of Community Affairs
Austin, Texas
vi
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Mr. Howard Hickman
House Energy Resources Committee
Austin, Texas
Ms . Bobette Higgins
Texas Environmental Coalition
Denton, Texas
Mr. Tom Hill
Gas Utilities Division
Texas Railroad Commission
Austin, Texas
Dr. Jack Hopper
Utility Rate Consultant
Austin, Texas
Mrs. Laura Keever
League of Women Voters of Texas
Houston, Texas
Dr. Sally Lopreato
Center for Energy Studies
University of Texas at Austin
Austin, Texas
Mr. Mike Marshall
Ozark Regional Commission
Little Rock, Arkansas
Mr. Clifford R. Miercort
North American Coal Corporation
Dallas, Texas
Mr. Joe G. Moore, Jr.
Environmental Science Program
University of Texas at Dallas
Richardson, Texas
Mr. Steve Naeve
Houston Lighting & Power
Houston, Texas
Mr. Mike Plaster
Legislative Aide to Rep. Bill Keese
Austin, Texas
vii
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Dr. Louis R. Roberts
Texas Air Control Board
Austin, Texas .-,
Mr. Pieter Schienkkan
Attorney General's Office
Austin, Texas
Dr. Michael Schwartz
Shell Development Company
Houston, Texas
Mr. Elof Soderberg
Lower Colorado River Authority
Austin, Texas
Mr. Peter Szabo
Petroleum and Minerals Department
Republic National Bank
Dallas, Texas
Mr. Richard L. White
Texas Utilities Generating Company
Fairfield, Texas .
In addition, special thanks are due to the following
individuals for contributing their time as well as technical
materials to the project:
Mr. William H. Hoffman
Texas Department of Water Resources
Mr. Charles Gilliam
Texas Department of Water Resources
Mr. Ron Freeman
Texas Department of Water Resources
Mr. Ray Newton
Texas Department of Water Resources
Mr. Everett Rowland
Texas Department of Water Resources
Mr. Jay Snow
Texas Department of Water Resources
Mr. Dennis Haverlah
Texas Air Control Board
viii
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Dr. Ronald D. Lacewell
Texas Water Resources Institute
Texas A&M University
Dr. Spencer R. Baen
Center for Energy and Mineral Resources
Texas A&M University
Dr. Kurt J. Irgolic
Center for Energy & Mineral Resources
Texas A&M University
Dr. William R. Kaiser-
Bureau of Economic Geology
The University of Texas at Austin
Dr. Martha Gilliland
Energy Policy Studies, Inc.,
El Paso, Texas
Dr. Marian Blissett
LBJ School of Public Affairs
The University of Texas at Austin
The following present or former members of the Radian
staff also contributed to the conduct of the study: Koren
Sherrill, Faith George, Bill Hamilton, Bill Thomas, Bill Menzies,
David Malish, Jude McMurry, Kirk Holland, Ann St.Glair, Laura
Dennison, Bill Coltharp, Tom Grimshaw, Gordon Page, Jim Norton,
Bill Corbett, and Biff Jones. Lindy Vaughan prepared the graphics
Special acknowledgement is due to David White, TEAC
Project Office, for technical assistance, advice, and ongoing
participation in all aspects of the study.
Finally, the greatest appreciation is due to Mrs.
Mildred Massa, for organizing and supervising secretarial support,
and for her personal dedication to the project.
ix
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X
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ACRONYMS AND ABBREVIATIONS
CAA - Clean Air Act of 1977
DoE - Department of Energy
EPA - Environmental Protection Agency
ERA - Economic Regulatory Administration
(Department of Energy)
FUA - Fuel Use Act (Portion of National
Energy Act of 1978)
HC . - Hydrocarbons
LNG - Liquefied Natural Gas
MBFC - Mandatory Boiler-Fuel Conversion
NAA - Non-Attainment Area
NAAQS - National Ambient Air Quality Standards
NEA - National Energy Act of 1978
NOX - Oxides of Nitrogen
NSPS - New Source Performance Standards
O&M - Operation and Maintenance
PAN - Peroxy Acyl Nitrate
PSD - Prevention of Significant Deterioration
PUC - Public Utility Commission (Texas)
RD&D - Research, Development & Demonstration
RRC - Railroad Commission (Texas)
SIP - State Implementation Plan
S02 - Sulfur Dioxide
TACB - Texas Air Control Board
TDWR - Texas Department of Water Resources
208 - Section 208 of the Water Pollution
Control Act Amendments of 1977,
mandating areawide wastewater
management
316a - Section 316a of the Water Pollution
Control Act Amendments of 1977,
dealing with variance procedures
for thermal discharges
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CHAPTER IV: ENVIRONMENTAL AND SOCIOECONOMIC
IMPACTS OF THE DEVELOPMENT SCENARIO
TABLE OF CONTENTS
4
Page
ABSTRACT 233
1.0 INTRODUCTION AND STATEMENT OF PURPOSE 235
2.0 AIR QUALITY IMPACTS OF LIGNITE DEVELOPMENT. ... 237
2.1 Emissions from Lignite Development 238
2.1.1 Emissions from Mining 238
2.1.2 Emissions from Combustion 239
2.1.2.1 Potential Emissions of
Criteria Pollutants from
Single Sources 239
2.1.2.2 Control Technology for
Criteria Pollutants 240
2.1.3 Emissions from Gasification
Processes 243
2.1.4 Trace Elements and Radioactive
Emissions 243
2.1.5 Secondary Impacts 246
2.2 Projected Emissions of Criteria Pollutants . 246
2.3 Potential Long-Term Impacts of Increased
Coal and Lignite Burning 250
2.3.1 Downwind Fate of Power Plant
Emissions 250
2.3.2 Potential Ecological and Health
Impacts of Power Plant Emissions. . . 254
2.4 Research Needs 256
xii
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TABLE OF CONTENTS (Continued)
Page
3.0 IMPACTS OF LIGNITE-RELATED SOLID WASTES 257
3.1 Sources of Solid Waste 258
3.1.1 Ash 258
3.1.2 Sulfur Removal Residues 259
3.2 Solid Waste Characteristics 261
3.2.1 Ash and Sludge Composition 261
3.2.2 Definition of "Hazardous Waste"
under RCRA 262
3.3 Potential Volumes of Solid Waste Produced
in Texas 265
3.3.1 Waste Production from Individual
Sources 265
3.3.2 Cumulative Waste Production Levels • 267
3.4 Alternative Disposal Methods and Practices- 270
3.4.1 Waste Collection and Transport . . . 270
3.4.2 Disposal Options 271
3.5 Potential Environmental Impacts of Solid
Waste Disposal 273
3.5.1 Leaching Conditions 273
3.5.2 Groundwater Contamination 274
3.5.3 Groundwater Usage 275
3.6 Environmental Limitations on Suitable
Waste-Disposal Sites 276
3.7 Other Wastes 278
3.8 Research Needs 279
xiii
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TABLE OF CONTENTS (Continued)
Page
4.0 IMPACTS ON SURFACE AND GROUNDWATER QUANTITIES. . .281
4.1 Consumptive Water Use by the Development
Scenario 282
4.2 Impacts of Water Development 283
4.2.1 Impacts of Surface Water Development .284
4.2.2 Impacts of Water Rights Transfer . . .285
4.2.3 Impacts of Increased Use of Ground-
water 285
4.3 Impacts of Consumptive Water Use 286
4.3.1 Navigation 287
4.3.2 Groundwater Recharge 289
4.3.3 Stream Ecology 290
4.3.4 Freshwater Inflow to Bays and
Estuaries 290
4.3.5 Waste Assimilative Capacity 291
4.4 Impacts on Groundwater 295
4.4.1 Groundwater Consumption 295
4.4.2 Groundwater Recharge Impacts 296
4.5 Research Needs 298
5.0 IMPACTS ON SURFACE AND GROUNDWATER QUALITY , . . .299
5.1 Surface Water Quality 300
5.1.1 Point Source Effluents 300
5.1.2 Non-Point Sources 305
5.1.3 Effects on Assimilative Capacity . , .306
5.1.4 Effect of TDS Control on Water
Requirements 307
xiv
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TABLE OF CONTENTS (Continued)
Page
5.2 Groundwater Quality 308
5.3 Research Needs 310
6.0 IMPACTS ON FISH AND WILDLIFE 311
6.1 Terrestrial Ecosystems 312
6.1.1 Extent of Habitat Disturbance .... 312
6.1.2 Reclamation in Perspective 314
6.1.3 Regionwide Trends in Habitat
Quality .315
6.2 Aquatic Ecosystems 317
6.2.1 Types of Impacts on Aquatic
Ecosystems 317
6.2.2 Effects of Flow Depletion ...-.,. 319
6.2.3 Trends in Aquatic Habitat Quality . . 319
6.3 Research Needs 320
7.0 SOCIOECONOMIC IMPACTS 321
7.1 Community-Level Impacts 322
7.1.1 General Overview 322
7.1.2 Impacts Experienced by Communities- • 326
7.1.2.1 Housing Demand 326
7.1.2.2 Public Services and
Facilities 327
7.1.2.3 Local Government Response- • 329
7.1.2.4 "Oldtimers" vs.
"Newcomers" 332
7.1.3 A Boom Town Simulation 333
xv
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TABLE OF CONTENTS (Continued)
Page
7.1.4 The Mount Pleasant Experience:
A Case Study 337
7.1.5 Variability in Community Impacts. . . 340
7.2 Regional and Subregional Impacts 341
7.2.1 Subregional Development Patterns. . . 342
7.2.2 Measures of Subregional Impact. . . . 343
7.2.3 Factors Mitigating the Extent of
Subregional Impact 345
7.2.4 Larger Implications of Regional
and Subregional Growth Patterns . . . 347
7.2.5 Implications for Planning ...... 348
7.3 Research Needs 349
8.0 POLICY ISSUES RELATED TO IMPACTS 351
8.1 Issues Related to Finding Solutions for
Developing Problems 351
8.2 Issues Related to Administering Existing
Policy 356
REFERENCES 359
xvi
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CHAPTER V: POLICY ANALYSIS
TABLE OF CONTENTS
Page
ABSTRACT. 365
1.0 INTRODUCTION 367
2.0 CONTEXT-SETT ING ISSUES 371
2.1 Implementation of Mandatory Boiler Fuel
Conversion 375
2,1.1 Summary and Conclusions 375
2.1.1.1 Alternatives to MBFC . . , . 375
2.1.1.2 Resolving Conflicts Be-
tween MBFC and Clean-
Air Policy 376
2.1.1.3 Economic Efficiency of
Fuel Allocation Under
MBFC 377
2.1.1.4 Texas Options and Concerns . 378
2.1.2 Background and Context 379
2.1.3 MBFC and Clean Air 381
2.1.4 Economic Efficiency & Administra-
tion of MBFC ', 384
2.1.5 Alternatives to MBFC 386
2,1.5.1 Common Features 389
2.1.5.2 Cost Control 390
2.1.5.3 Market Allocation
Mechanisms , , 392
xvi i
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TABLE OF CONTENTS (Continued)
Page
2.1.5.4 Import Quotas 393
2.1.5.5 Reduction of Fossil Fuel
Demand 393
2.1.6 Alternative Methods of Reducing
Conflicts Between MBFC and Clean
Air Policies 394
2.1.7 Alternatives for Administering MBFC
with Respect to Economic Efficiency . 398
2.1.8 Potential Roles for Texas 402
2.2 Ambient Ozone Levels 407
2.3 Control of Atmospheric Sulfates 4,15
2.4 Solid Waste 421
3.0 RESOURCE MANAGEMENT ISSUES 425
3.1 Water Supply 431
3.1.1 Surface Water Development 431
3.1.2 Equity and Efficiency in Water
Allocation 435
3.1.3 Water Conservation 437
3.1.4 Leverage on the Water Supply Issue. . 438
3.2 Consumptive Water Use 443
3.3 Lignite Reserve Depletion 449
3.3.1 Severance Tax on Lignite 451
3.3.2 Encouragement of Mexican Oil and
Gas Imports 452
3.3.3 Encouragement of Energy Conservation. 453
3.3.4 Encouragement of Increased Western
Coal Use 454
xviii
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TABLE OF CONTENTS (Continued)
Page
3.3.5 Removal of Impediments to Non-
Fossil Energy Sources 455
3.4 Lignite Research, Development and
Demonstration Priorities 459
3.5 Export of Lignite-Generated Energy
Through Electric Grid System . 465
4.0 RESPONSE ISSUES 467
4.1 Response Issues Related to Possible
Need for New Policies 469
4.1.1 Infrastructure Financing 473
4.1.2 Flow Reduction and Water Quality • . 479
4.1.3 Ecological Impacts of Mining .... 485
4.1.4 Control of Boom-Town Growth 491
4.1.5 Regionwide Costs and Benefits- • • • 495
4.1.5.1 Alternatives for Cost-
Spreading 496
4.1.5.2 Alternatives for Benefit-
Sharing 497
4.1.6 Aesthetics and Attitudes Toward
Growth 503
4.2 Response Issues Related to Implementing
Existing Policy 507
4.2.1 State Surface Mining Program
Approval 511
4.2.2 Land Unsuitable for Mining 517
4.2.3 Multi-Agency Permit Review 525
xix
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TABLE OF CONTENTS (Continued)
Page
5.0 INTEGRATING PERSPECTIVES ON POLICY ISSUES. ... 529
5.1 Underlying Issues 529
5.1.1 Limitations in Environmental
Review 53°
5.1.2 Internalizing Environmental Costs. . 531
5.1.3 Long-Range Planning Under Condi-
tions of Uncertainty 534
5.1.4 Equity versus Efficiency in Re-
source Allocation 536
REFERENCES CITED; CHAPTER V 539
xx
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CHAPTER I: POTENTIAL USE OF SOLID FOSSIL FUELS
LIST OF TABLES
Number
3-1
3-2
4-1
4-2
5-1
Title
Status of Future Nuclear Plants to Supply Texas.
Basic Provisions of the Federal Fuel Use Act . .
Alternative Choices for Firing New Industrial
Boilers
Summary of Annualized Operating Costs for Alter-
native Energy Pathways for New Industrial Boilers
Summary of Annualized Operating Costs .for Alter-
Page
. 20
. 25
32
. 34
native Energy Pathways for New and Existing
Utility Boilers 51
6-1 Derivation of Solid Fossil Fuel Requirements ... 59
6-2 Sensitivity of Solid Fossil Fuel Requirements in
the Year 2000 to Alternative Assumptions 59
xxi
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CHAPTER II: LIGNITE DEVELOPMENT SCENARIO
LIST OF TABLES
Number Title
2-1 Alternative Fuel Costs 92
3-1 Steps Taken to Derive Subregional Lignite Develop-
ment Scenario 100
3-2 Lignite "Resource Units" Held by Lessor Groups. . 102
3-3 Texas Coal and Lignite Power Plants 103
3-4 Coal and Lignite Consumption by Texas Electric
Utilities 109
3-5 Existing & Planned Texas Industrial Coal/Lignite
Use 110
3-6 Potential Requirements for Lignite Commitment . . 112
3-7 Sensitivity to Alternative Assumptions of Lignite
Commitment by the Year 2000 113
3-8 Coal and Lignite Commitments in the Year 2000, by
Subregion 119
3-9 Concentration of Lease Ownership 119
xxii
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CHAPTER III: SITING CONSTRAINTS
LIST OF TABLES
Number Title Page
2-1 Industrialization of the Lignite Belt: Pro's
and Con's 139
3-1 Water Supply & Demand Summary Analysis, in
Thousands of Acre-Feet, Neches River Basin .... 151
3-2 TDWR Supply-Demand for the Year 2000, Showing
Non-Firm Supply 152
3-3 Typical Plant Water Requirements 154
3-4 Year-2000 Steam-Electric Water Demand Estimates
by Subregion 155
3-5 Year-2000 Steam-Electric Water Supply/Demand
Estimates by Subregion 156
3-6 Critical Basins 166
3-7 Estimated SOz Emission Rate for 1500-MWe Electric
Generating Stations, Firing Lignite of Various
Grades 181
3-8 PSD Classifications 182
3-9 Significance Level for PSD Analysis 184
3-10 Design Parameters for 1500-MWe Electrical Generat-
ing Stations Used in Air Quality Modelling .... 190
3-11 Comparison of PSD Implementation Strategies. . . . 205
3-12 Siting Constraints in Flood Prone Areas 208
3-13 Extent of ETJ in Texas 213
3-14 Overall Substrate Capability as a Siting Factor,
Defined by Construction Suitability and Permea-
bility ' 216
xxiii
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CHAPTER IV: ENVIRONMENTAL AND SOCIOECONOMIC
IMPACTS OF THE DEVELOPMENT SCENARIO
LIST OF TABLES
Number Title Page
2-1 Emissions from a Hypothetical 1500-MWe Station
Firing a Typical Texas Lignite from the Wilcox
Group 240
2-2 Air Emissions of Criteria Pollutants from a
250 MMscfd Lurgi Plant 244
2-3 The 1976 Ambient Air Quality Concentrations in
the Urban Areas Around the Lignite Belt 246
2-4 Coal and Lignite Combustion in the Study Area:
Estimated 1985 & 2000 S02 Emissions 248
2-5 Coal and Lignite Combustion in the Study Area:
Estimated 1985 & 2000 NOX Emissions 248
2-6 Coal and Lignite Combustion in the Study Area:
Estimated 1985 & 2000 Particulate Emissions. . . . 249
3-1 Ash Content of Selected Texas Lignites 261
3-2 Maximum Concentrations of Contaminants Allowed
Under NIPDWS and RCRA 264
3-3 Comparative Volumes of Solid Waste Produced by
Coal and Lignite Combustion 266
3-4 Industrial and Utility Solid Waste Volumes by
Study Area Subregion 267
3-5 Cumulative Land Commitments for Solid Waste
Disposal by Study Area Subregion 268
4-1 Subregional Water Consumption by Lignite- and
Coal-Fired Power Plant Development in Year 2000. . 283
4-2 Subregional Flow Reduction Due to New Power Pro-
duction, Year 2000 287
4-3 Critical Low Flows for Selected Texas Rivers . . . 293
xxiv
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LIST OF TABLES (continued)
Number Title
4-4 East, Central, and Southern Existing and Planned
Steam Electric Power Plants in Texas Using
Groundwater as the Prime Cooling Source 295
5-1 Priority List of Toxic Substances 302
5-2 Comparison of Toxic Control by Selected Tech-
nologies 303
5-3 Plant Data Relating to Water Quality Parameters
for Coal Pile Runoff 306
7-1 Project Characteristics , . . . 325
xxv
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CHAPTER V: POLICY ANALYSIS
LIST OF TABLES
Number Title
1-1 Summary of Policy Issues 367
2-1 Reduce Dependence on Foreign Energy Imports , . . 387
2-2 Find a Compromise Between MBFC & Clean Air Goals. 395
2-3 Administer MBFC with Respect to Economic Ef-
ficiency of Allowable Gas & Oil Use 399
2-4 Ambient Ozone Levels 406
2-5 Control of Atmospheric Sulfates 41'2
2-6 Solid Waste Disposal 420
3-1 Water Supply 428
3-2 Consumptive Water Use 442
3-3 Lignite Reserve Depletion .... 448
3-4 Lignite RD&D Priorities 458
3-5 Utility Interconnection 464
4-1.1 Infrastructure Financing 472
4-1.2 Flow Reduction and Water Quality 478
4-1.3 Wildlife Impacts of Reclamation 484
4-1.4 Control of Boom-Town Growth 490
4-1.5 Regionwide Costs and Benefits 494
4-1.6 Aesthetics and Attitudes Toward Growth 502
4-2.1 Approval of State Surface Mining Program 510
4-2.2 Lands Unsuitable for Mining 516
4-2.3 Multi-Agency Permit Review 522
xxvi
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CHAPTER I: POTENTIAL USE OF SOLID FOSSIL FUELS
LIST OF FIGURES
Number Title Page
2-1 Areas Out of Compliance with National Ambient
Air Quality Standards for Ozone as of January 1,
1979 8
2-2 Growth Rate in Conventional Energy Demand for
Electric Power Generation 12
2-3 Demand Growth for Conventional Energy in In-
dustry (Excluding Feedstocks) 15
3-1 Energy Use Versus Resource Size '22
3-2 1975 Use of Oil and Gas in Texas 22
4-1 Breakeven Sensitivity to Coal Prices (Midwest
Location, 1980 Startup) 35
4-2 Breakeven Curves (Midwestern Location,
1980 Startup) 37
4-3 Breakeven Sensitvity to Capital Costs (Midwest
Location, 1980 Start up, Coal Versus Oil) 39
6-1 Fuel Mixes for Texas - Nominal Case 58
-------
CHAPTER II: LIGNITE DEVELOPMENT SCENARIO
LIST OF FIGURES
Number Title Page
1-1 Effect of Reserve Size on Rate of Increase in
Cost of Production 86
1-2 Strippable Lignite Reserves by Subregion 88
3-1 Existing and Planned Coal and Lignite Power
Plants in Texas 108
XXVI11
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CHAPTER III: SITING CONSTRAINTS
LIST OF FIGURES
Number Title Page
1-1 Study Area Subregions Showing Existing and
Planned Power Plants 132
2-1 Growth Centers, in Relation to Lignite Deposits. . 137
3-1 Water Availability as a Constraining Factor in
Siting 159
3-2 Critical Surface Supply . 161
3-3 Year 2000 Critical Basin Segments 165
3-4 Surface Water Use 170
3-5 Groundwater Use 176
3-6 Area of Impact (Radius & Isopleth Method) .... 186
3-7 Hypothetical "Existing Facilities" Within an
Area (Equally Spaced) 189
3-8 "Proposed Facility" and Area of Impact 192
3-9 Facilities Included in Modeling 192
3-10 Worst-Case Predicted 24-Hour S02 Concentrations
Versus Distance for Hypothetical 1500-MWe Power
Plant 193
3-11 Air Quality Areas 199
3-12 Flood Prone Areas 212
3-13 Areas Constrained by ETJ Considerations 214
3-14 Construction Suitability as a Constraining Factor
in Siting 217
3-15 Distance from Lignite 220
4-1 Composite Site Suitability Map Showing Study Area
Subregions 222
XXIX
-------
CHAPTER IV: ENVIRONMENTAL AND SOCIOECONOMIC
IMPACTS OF THE DEVELOPMENT SCENARIO
LIST OF FIGURES
Number Title
2-1 Schematic Diagram of Short-Range and Long-Range
Air Quality Impacts from Single and Multiple
Point Sources 252
4-1 Waste Assimilative Capacity of the Brazos River
as a Function of Flow 292
7-1 Population Distribution, 1970 323
7-2a (No Title) 335
7-2b (No Title) 335
7-3 Quasi-Equilibrium (Without Energy Development)
Simulation 336
7-4 Worst Case Boom Town Simulation 336
7-5 Hypothetical Lignite/Coal Facility Construction
By Subregion, 1985-2000 342
XXX
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CHAPTER I: POTENTIAL USE OF SOLID FOSSIL FUELS
Abstract
This chapter addresses the extent to which coal and
lignite may contribute to the Texas fuel mix through the
end of the century. Plausible growth rates in total en-
ergy demand by utilities and industry are developed, and
upper and lower bounds discussed. The effects of nuclear
policy and the Fuel Use Act on interfuel competition are
estimated. Alternative fuels and technologies for indus-
trial use are discussed in terms of economic and engi-
neering feasibility. A series of working assumptions
about future fuel choices are outlined based on imple-
mentation of the Fuel Use Act and plausible market pene-
tration rates for new technologies. These are used to
estimate total solid fossil fuel use. Sensitivity of
this use level to changes in these assumptions is evalu-
ated. Relevent policy issues related to overall energy
growth and to fuel choices are summarized. Recommenda-
tions are also made for further RD&D and planning-related
research.
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1.0 OVERVIEW OF METHODS
The first step in evaluating the potential impact of
lignite development in Texas' future is to obtain an idea of how
rapid and extensive this development may be. The process by
which a reference energy demand scenario was developed for use
in this study is described below.
The process begins with a determination of plausible
future demands for energy in sectors where lignite is a competi-
tive fuel. The potential effects of conservation and the intro-
duction of renewal energy resources were accounted for in
developing these demand curves. The role of nuclear power was
then evaluated, leaving that portion of demand likely to be met
by fossil fuels. A plausible estimate of the amount of oil and
gas use probable in the remainder of the century was derived
from a critical examination of fuel choice economics and the
probable effect of the recently enacted Fuel Use Act. The re-
maining demand represents the potential for coal and lignite use
in Texas. The ratio of coal to lignite use as well as the
geographic distribution of coal and lignite demand are investi-
gated in the next chapter.
A quantitative evaluation of the complex relationships
among the variables which help to detefmine the rate and extent
to which demand for solid fossil fuel develops requires sophis-
ticated modeling techniques. Even with such techniques, the
influence of behavioral variables often limits the usefulness of
the result. Accordingly, the study team chose not to attempt a
modeling approach. Instead, this task was conducted as a series
of "what if" questions, in which values of the key variables con-
sistent with reasonably probable futures were used in making
simple calculations. Variant cases were also examined to deter-
mine how much flexibility was inherent in the situation under study.
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2.0
DEMAND FOR CONVENTIONAL ENERGY
Summary and Conclusions
Utility demand growth in Texas has historically been
higher than the national average. This reflects both
substantial population growth and the major role on
industry in the state.
The Nominal Case scenario developed for use in this
study assumes an annual growth rate of 5.3% to 1987,
and 4.3% thereafter. This scenario reflects a modest
level of voluntary conservation based largely on
price increases, with little or no federal involve-
ment.
Industry uses more energy than utilities, but its
energy use has grown more slowly in recent years.
Economics already favor a substantial trend toward
conservation, which has been steadily reducing the
ratio of energy input to product output.
The Nominal Case scenario assumes an annual growth
rate of raw energy input (excluding feedstocks) of
3.8% to 1990, and 3.2% after 1990.
Lignite competes with other fuels chiefly in the
generation of electricity and industrial process heat and steam.
It does not contribute directly to either commercial/residential
or transportation sectors. Thus, the following discussion centers
on that portion of Texas' overall demand for energy in which
lignite has a potential role to play. Demand for energy is
evaluated separately for electric utilities (which includes in-
direct contributions to residential and commercial needs) and for
industrial applications. Potential demand reductions from con-
servation are considered, along with the possibility that solar
energy, biomass, and other renewable energy forms may reduce de-
mand. What is left is the demand for "conventional" energy:
fossil fuels and nuclear power.
-------
2.1 Limiting Effects of Non-Attainment of Oxidant Standard
To a significant degree, energy demand growth in Texas
will be driven by growth in the state's dominant economic
sectors: petroleum, petrochemicals, and allied industry, Not
only does growth in these sectors directly influence the amount
of energy used by them, it has a strong bearing on employment and
population in-migration. Population growth, in turn, increases
the demand for electricity. Since lignite potentially provides
energy to both industry and utilities, any factor which can
affect growth in the petroleum and petrochemical sectors can
affect the future of lignite.
A key air-quality issue currently under debate could
prove to be such a factor; the decisions to be made in the near
future regarding permitting of new sources in areas not in
attainment of National Ambient Air Quality Standards (NAAQS)
could have a large impact on the petroleum/petrochemicals
industries.
Under the Federal Clean Air Act of 1970, the Nation's
air quality was mandated to attain the national primary Ambient
Air Quality Standards by 1975, or by 1977 in certain areas.
Permits for new sources were not to be issued in areas not
attaining the standards. By 1976, it had become apparent that
large areas of the nation would be unable to meet the standards.
To permit continued industrial growth and still provide progress
toward the objectives of the Act, EPA adopted a policy of emission
offsets.1 This policy permits major new sources to locate in non-
attainment areas (NAA's) if the emissions from the new source can
be more than offset by a corresponding reduction in emissions
from other sources in the vicinity.
-------
Each state is required to show in its State Implementa-
tion Plan (SIP) that each NAA can be brought into attainment by
December 31, 1982.* If EPA has not accepted a state's SIP by
July 1, 1979, EPA will not approve permits for construction of
new sources. Additional sanctions include a cutoff of federal
highway funds and sewage treatment grant monies.
Texas is largely in compliance with standards for three
of the five regulated pollutants. Several counties fail to comply
with NAAQS for particulates and ozone, but the ozone problem is
considered the more serious. Although only fifteen out of 254
Texas counties have been designated by EPA as out of attainment
for ozone, these counties comprise 58 percent of the state's
population and 71 percent of the state's economic activity.**
Figure 2-1 shows their location.
On January 26, 1979, EPA announced the revision of both
the primary and secondary ozone standard from 0.08 ppm to 0.12
ppm, to be exceeded for not more than a single one-hour period
during the course of a full year. Under the new standard, most
of the inland counties are below or very near compliance levels.
Oxidant levels measured in the Gulf Coast industrialized zone,
however, exceed even the new standard. In the Houston area,
recent ozone statistics indicate 50 to 60 hours of noncompliance
yearly. Monitoring data for adjacent inland areas are lacking.
Because of the degree of noncompliance in the coastal industrial
zones, however, and considering air parcel movements from that
* Extensions to December 31, 1987 are available for carbon
monoxide and oxidant NAA's if the state can show that com-
pliance by 1983 is not possible.
**Based on 1974 Bureau of Census estimates and wage and salary
income (excluding certain sectors such as self-employed).2
-------
r~7*»
! i i i
i; 'pxan—jaoaurininr-iasu
^
-pwr-Uss—T«
I i i
' -- -pk.— friinr-Tijifc— T»-BB- -pain- -
; i i
l l-
OZONE NONATTAINMENT
Figure 2-1. Areas Out of Compliance with National Ambient Air
Quality Standards for Ozone as of January 1, 1979.
02-4335-1
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region, it is reasonable to expect that noncompliance problems
may be fairly widespread in eastern Texas.*
The extent and severity of Texas' ozone problem is of
great concern to the petroleum refining and chemicals industries.
These industries, together with mobile sources (i.e., autos) emit
hydrocarbons which combine with nitrogen oxides in the presence
of sunlight to form ozone and other oxidants. (According to
TACB emissions data for the Houston-Calveston area, 53 percent
of hydrocarbon emissions come from "major sources"--virtually
all of which involve the petroleum and petrochemical industries.)
The Texas economy is currently based, to a large extent,
on these industries. Although the state is moving toward a more
diversified industrial base, petroleum refining and petrochemicals
will continue to be a significant driving force in the economy.
Given that large areas of the state adjacent to the existing re-
fining and chemicals industrial complex are out of compliance
with even the newly relaxed standards for ozone, the method of
permitting new sources in non-attainment areas is crucial to the
expansion of these industries.
The current offsets policy, if rigidly enforced, will
almost certainly increase costs and introduce delays into the
process of siting new chemicals-related industry and may force
a shift to less economically desirable sites away from present
* In a September 16, 1977 meeting of the Texas Air Control Board,
a written status report on attainment/non-attainment of the
then-applying National Ambient Air Quality Standards was pre-
sented which made the following observation regarding oxidants:
"the oxidant standard has been exceeded at every location in
the State monitoring zone. It is expected that the standard
will continue to be exceeded at these locations and other
violations could probably be found if monitors were located in
other areas of the State."
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industrial concentrations. There is considerable polarity of
opinion as to the seriousness of this effect on the state
economy. EPA has contended that, through expansion into neigh-
boring counties in attainment of the ozone standard and simulta-
neous control of vehicle traffic, industrial expansion can take
place without undue hindrance.3 Texas officials point out that
because of past efforts at the state level, hydrocarbon emissions
are now well enough controlled that further offsets will come
only at increasing expense, if they are possible at all.4
It is beyond the scope of this study to evaluate quan-
titatively the potential effects of the offsets policy on growth
in Texas' demand for energy. It has been assumed here that a
resolution to the problem will be found which does not signifi-
cantly affect either the growth rate of Texas industry, or the
mix of industries potentially developing.
2.2 Utility Energy Demand
Historically, electricity demand has grown rapidly in
Texas. The annual growth rate was 9.7 percent between 1960 and
1975, as compared with 6.3 percent nationally.5 This higher
growth rate reflects the rapid growth of industry in the state,
as well as recent rapid population growth.
Growth rates this high are not expected to continue,
as is foreshadowed by the drop in Texas' annual growth rate to
7.2 percent between 1970 and 1975.5 The expected down-trend
includes four components: a reduction in population growth rate;
a decline in the rate of increase of per capita energy use be-
cause of changing technology and industrial mixes; increased
conservation; introduction of the so-called "soft" energy
technologies to substitute for electricity. The growth curves
used to define the demand scenario developed here take all four
factors into account.
10
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An average annual population growth rate of 1.7 percent
has been used in this study and was derived in consultation with
economists from the Texas Department of Water Resources. This
figure contrasts with an annual rate of 1.8 percent between 1970
and 1974.6 The presumption behind the declining growth rate is
that the intensity of the "Sun Belt Phenomenon," which produced
the high in-migration of the 1970's, will not remain at this
level, although growth from in-migration could continue for a long
time. Also, a nationwide trend of declining fertility is ex-
pected to be expressed in lower birth rates.
2.2.1 Conservation and Unconventional Sources
Rising prices and increasing public awareness suggest
that some degree of conservation will act to reduce future growth
in electricity consumption. Very high levels of conservation in
residential and utility energy use have been considered tech-
nologically feasible, leading to predictions of annual demand
growth rates for electric energy of as little as 0.7 percent.7
However, without substantial government intervention to provide
artificial economic incentives to change consumer attitudes, major
gains may take place slowly. Slow turnover rates for housing
and large equipment help hold back the trend. A further draw-
back is the low short-term economic return perceived by many
consumers faced with large capital investments in energy-conserving
equipment and structures.
Similar drawbacks are expected to prevent the so-called
"soft" energy technologies—solar and related renewable forms such
as wind and biomass--from contributing large amounts of energy
in the near term. The technology needed to use these uncon-
ventional sources is available. Recent studies indicate that
they could meet between eight and 25 percent of the nation's
11
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energy demand in 2000.8'9 However, large capital requirements
and uncertain economics suggest that without a substantial
national program to promote them, these sources will not dis-
place a significant portion of the demand placed upon utilities
2.2.2
Development of Utility Fuel Use Scenario
Figure 2-2 shows the estimate of energy demand growth
in utilities developed for use in this study. It represents a
middle-ground view, assuming no major changes in federal policy
affecting conservation and soft energy. The effects of volun-
tary conservation, a slowdown in population growth, and market
saturation are reflected at levels which are felt to be a rea-
sonable extrapolation from today's trends. The upper and lower
bounds were developed to show what are believed to be plausible
limits. Without major changes in the economy or styles of life,
the use of energy in utilities is not expected to go beyond these
limits. A tacit assumption in all three curves is that major
changes in the efficiency of power production do not occur.
FUEL 4
CONSUMPTION
(QUADS)
3-
2-
UPPER BOUND ^'
^
NOMINAL CASE
LOWER BOUND
1975
1980
1985
1990
1995
Figure 2-2. Growth Rate in Conventional Energy Demand for Electric Power Generation
02-4311-1
12
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A number of estimates are available for annual utility
growth applicable to Texas, ranging from between 2.6 and 3.1 per-
cent2 to between 6 and 7 percent.10 The study team chose an
intermediate set of forecasts, prepared by the Electric Reliabil-
ity Council of Texas (ERGOT),11 which shows growth to 1987 of
5.3 percent, and from 1987 to 1997 of 4.8 percent per year. For
comparative purposes, electrical growth in Texas averaged 7.7
percent per year between 1975 and 197712, and is estimated to
have grown 7.4 percent in 1978.13 Presently, ERGOT represents
roughly 80 percent of the electrical generation in Texas, and
it was assumed that these projections are representative of the
entire state. Using TEAC figures for 1975 fuel consumption, the
solid curve was generated using the ERGOT growth rates, breaking
at 1987. The ERGOT projections assume modest levels of voluntary
conservation.
The curve for the upper bound was derived assuming a
continuation of the 5.3 percent growth rate of 1975-1987 through
the end of the century. A higher growth rate than this would
involve a major change in baseline assumptions, such as increasing
(rather than declining) population growth, or introduction of
new electricity-intensive technologies, such as electric cars.
The lower bound was calculated by letting the per-capita
growth in electricity consumption fall to zero by 1987. From
this point on, population growth alone accounts for the rise in
energy demand.
To test the reasonableness of the values so obtained,
the year-2000 energy demand was calculated that results from a
variety of projections of potential conservation and soft-energy
futures.5'7 The effects of conservation alone could reduce this
demand from 4.8Q to between 4.6 and 3.4Q. Adding soft energy9 '^
13
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brings it down to between 3.7 and 2.5Q. The lower bound projection
for the year 2000 is 3.3Q. Thus it appears that something near a
zero per-capita growth rate in demand for conventional energy
sources to generate power may lie within the realm of technological
feasibility. However, as is pointed out in the preceding section,
numerous economic and institutional variables presently oppose
such a trend.
2.3 Industrial Energy Demand
In 1975, Texas industry used more energy (excluding
feedstocks) than did utilities: 2.2Q as compared with 1.56Q.
Virtually all of this energy was in the form of oil and gas, with
gas accounting for 1.5Q. Furthermore, most of this industrial
fuel use was concentrated on the Gulf Coast. Seventy-five per-
cent of the natural gas used in industrial boilers was burned
there.15 Petroleum refining and petrochemicals together account
for two-thirds of the state's industrial fuel use.
Industrial fuel consumption grows more slowly than fuel
demand for power generation. Largely, this is because economic
incentives produce improvements in processes and operating pro-
cedures. Further advances in energy efficiency could be made by
improving operating and maintenance practices, by capital expen-
ditures in new processes and equipment, and by the introduction
of cogeneration.*
2.3.1 Conservation and Unconventional Sources
Significant reductions in energy use by industry may be
possible, both by improved operation and maintenance procedures
and through the replacement of capital equipment. Estimates of
*Cogeneration is here defined broadly as the use of "waste" heat
from power generation to perform useful work.
14
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total energy savings possible by the end of the century range
from 10 percent to 40 percent.5»J*>*6> l7 >ls There is consider-
able disagreement, however, about the relationship between con-
servation at these levels and the health of the nation's economy,
The key uncertainty is the degree of elasticity of industrial
energy demand in the face of rising prices. Cogeneration may be
the most immediately attractive option, from an economic stand-
point, and extensive opportunities may exist for its application
in Texas.19 Reluctance on the part of utilities to accept power
generated by industry, and concern by industry over possible
government regulation, remain to be overcome.20 Nevertheless,
at least one large-scale Texas cogeneration project is already
in the planning stages.
Unconventional energy sources at present do not appear
widely applicable in industry. The displacement possible by
2000 may be equivalent to only 0.05 to 0.10Q--less than five
percent of energy consumption in 1975.21
2.3.1
Development of Industrial Fuel Use Scenario
Figure 2-3 presents the fuel use growth curve for
industry developed for this study. It is bounded by what are
5-
4-
FUEL
CONSUMPTION
(QUADS) 3.
UPPER BOUND
NOMINAL CASE
LOWER BOUND
1975
1980
1985
YEAR
1990
1996
2000
Figure 2-3. Demand Growth for Convential Energy In Industry (Excluding Feedstocks)
15
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believed to be reasonable upper and lower limits to plausible
growth in energy demand.
The beginning value of 1975 fuel consumption was derived
from TEAC, Bureau of Mines, and Federal Power Commission data and
represents process heat, process steam, and on-site electric
power production. The solid curve is based on an annual growth
rate of 3.8 percent from 1975 through 1990. This growth rate
is consistent with studies done by TEAC and FPC,5'22 and is
based on both Chase Econometrics and Bureau of Economic Analysis
projections of economic activity. After 1990, the growth rate
is dropped to 3.2 percent to reflect what is believed to be a
moderate degree of voluntary conservation (roughly 2 percent per
year per unit output, as estimated by TEAC5) and a changing in-
dustrial mix in which services and non-energy-intensive industries
become more important.
The upper bound corresponds to the rate at which earn-
ings in industrial sectors are projected to grow by the Texas
Water Resources Department. This effectively assumes that pro-
ductivity per worker, energy intensity per worker, and the ratio
of salaries to output do not change. The lower bound is calcu-
lated using population growth rate alone. This assumes that per-
capita measures of productivity and energy intensiveness in
industry, taken across the entire population, do not change.
The validity of the lower limit was checked by comparing
it to the effect of widespread measures promoting conservation
and soft energy.5'7'9'l"'17'23 Counting only the highest esti-
mates of potential conservation, the year-2000 energy demand of
5.18Q shown on the solid curve is reduced to between 3.8 and
3.10Q. Adding the potential contribution of soft energies in
direct industrial applications brings the total into the range
of 3.75 to 3.0Q. Thus, it is concluded that the lower bound is
16
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a reasonable estimate of what might happen if a strong push
toward conservation took place. However, as was discussed in
the preceding section, such large amounts of conservation might
be associated with other economic consequences which would have
far-reaching negative effects.
17
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3.0
EFFECTS OF REGULATORY POLICY ON CONVENTIONAL FUEL MIX
Summary and Conclusions
For the remainder of the century, the bulk of Texas'
energy supply is expected to come from "conventional"
sources: oil, gas, coal, lignite, and nuclear energy.
Nuclear power is presently constrained by uncertainty
regarding costs and lead-times, which have recently
forced cancellation of several large power projects
in Texas. Given this trend, it was assumed that no
new nuclear capacity would come on line in the 1990's.
The Nominal Case scenario projects 0.3Q of nuclear
power in 1985 and 0.4Q in 2000.
The Fuel Use Act portion of the National Energy Act
contains provisions for mandatory boiler fuel conver-
sion (MBFC) that are more stringent than those already
in force or under consideration at the state level
(Railroad Commission Docket 600). For this reason,
the federal policy is expected to take precedence over
the state's.
Depending upon its administration, the Fuel Use Act
may substantially increase amounts of coal and lignite
used under new industrial boilers, as well as existing
utility boilers required to stop using gas and oil.
Rising prices and uncertainty of supply over long
plant life-times have already caused a shift to coal
and lignite for new utility boilers.
At this point in the analysis, we have derived an
estimate of input energy requirements for uses where lignite is
a competitive fuel. The contributions of "soft" energy and co-
generation have been shaved off, leaving that portion of the
demand which must be met by oil, gas, coal, lignite, and nuclear
energy (for utilities). The next step is to derive a reasonable
estimate of nuclear power availability and divide the remaining
demand among the other four "conventional" fuels. To do so
19
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requires consideration of policies and trends surrounding
nuclear energy and mandatory boiler fuel conversion as they
affect interfuel competition in Texas.
3.1
Nuclear Trends and Policy
Nuclear energy will compete with coal and lignite in
the electricity sector over the next two decades. Although no
nuclear power is currently produced in Texas, construction is
underway on two plants and at least one other is in the planning
stage.
Table 3-1 lists nuclear plants planned for Texas, along
with out-of-state nuclear plants which might provide power to
consumers in Texas. Year-2000 estimates of Texas nuclear capacity
(without the breeder reactor) have ranged from a low of what is
TABLE 3-1. STATUS OF FUTURE NUCLEAR PLANTS TO SUPPLY TEXAS
Status
Plant (Unit)
Utility
MW(«) Net On-Llna
D.C.
D.C.
U.C
D.C.
Planned
Council* Peak (1)
South Texaa (1)
Counchi Paak (2)
South Texas (2)
Allen'• Cr««k
Palo Verde (1)
Palo V«rd« (2)
Palo Varda (3)
River Band (I)
IK-STATE
Taxai Utilitlaa 1150 1981
Houston Lighting t Power* 1230 1983
Taxai Utilitiaa 1130 1982
Houaton Lighting t Powar* 1230 1982
Houaton Lighting & Power 1130 1983
OUT-OP-STATE
El Paao Elaettle'
*»
El Paao Elactric
**
El Paao Elaettle
Gulf Stataa Utllltlaat
1240 (136) 1982
1240 (136) 1984
1240 (136) 1986
933 (468) 1983
Alao ihara of powar to City of Auatin, City of San Antonio, and Cantral
Powar and Light.
El Paao Elactrlc'a ahara In Arizona's Palo Varda unlta. Tha figura in
paranthaaaa ia tha estimate available for Taxaa uaa.
tHalf of this unit's capacity is axpactad to be ganaratad to supply
CSU'a Taxaa damanda.
Source Provision of Elactrtc Powar in Texas: Key Issues and 1'r.certain-
tias."Modifications basad on updated information (ram John
Cordon of TCAC.
20
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now planned (less than 7000 MWe) to a high of 20,000 to 25,000
MWe.21* The high estimate is based on Texas' share of the nation's
uranium reserves.
Given the ten-to-twelve-year lead time required for
nuclear plant construction, any units which will be on line by
1990 must be in the planning stages now. Recent trends suggest
that without substantial changes in the licensing process and in
public attitudes, few new plants will be planned in the 1980's.
Thus, for purposes of determining Texas' coal and
lignite demands, it will be assumed that no new nuclear plants
are added during the 1990's. Therefore, the Texas nuclear supply
is estimated to 0.3Q in 1985 and 0.4Q in 2000.
If, indeed, current trends in policy are reversed,
several additional plants could be added in the 1990's raising
the nuclear supply estimate for 2000 to between 0.7 and 1.0
Quads.
3.2 Mandatory Boiler Fuel Conversion Policies
The impetus to develop a public policy forcing
utilities and industry to convert from oil and gas as a boiler
fuel stems from two aspects of the U.S. energy situation. First,
domestic oil and gas supplies are perceived as decreasing at a
dangerous rate. Second, continued dependence on oil imports is
seen as potentially disastrous both from an economic and a
foreign policy viewpoint. Perhaps the most compelling evidence
in support of mandatory boiler fuel conversion (MBFC) policies
is a comparison of recent patterns of energy use with estimated
domestic resource availability on a fuel-by-fuel basis. These
data are graphically illustrated in Figures 3-1 and 3-2.
Figure 3-1 shows the distribution of energy use by fuel in the
21
-------
INIftOV Utli U*
-------
U.S. and Texas, and compares this to the energy reserves in the
U.S. by fuel. Figure 3-2 shows how oil and gas were used in
Texas in 1975.
The conclusion which may be drawn from this presentation
is that the shift should take place as quickly as possible from
fuels with dwindling domestic supplies to the nation's more
abundant energy sources. As indicated in Figure 3-1, the reliance
on oil and gas in Texas (95 percent of all energy inputs in 1975)
is even greater than that of the nation as a whole (80 percent of
all energy inputs in 1975). And, as shown in Figure 3-2, over
half of the oil and gas used in Texas in 1975 was used to generate
electric power and industrial heat and steam. Many of these
uses are technologically amenable to coal substitution. Conse-
quently, a strong policy of fuel conversion can have a very great
impact on Texas industries and utilities.
3.2.1 Federal MBFC Policies
The Fuel Use Act, recently enacted as part of the
National Energy Act, mandates much more extensive conversion away
from gas and oil by large boiler fuel users. Exemptions are pro-
vided for, but the burden of proof for securing them rests not
with the government, as under previous legislation requiring
boiler fuel conversion (ESECA), but with utilities and industries.
This form of administration makes it much easier for the Department
of Energy, as the agency charged with implementing the Act, to take
and hold a tough regulatory stance. Draft regulations under the
Act, issued in November, reflect just such a policy.27
The major thrust of President Carter's original energy
plan involved controlling boiler fuel use through a system of
disincentives and incentives (through oil and gas taxes and tax
rebates). This approach was intended to promote conversion
23
-------
of oil and gas to coal for utility and industrial use. In its
course through the legislative process, the taxing provisions
have been stripped away. The original MBFC provisions have also
been substantially altered through the creation of numerous exemp-
tions and alternative compliance schemes. Nevertheless, since
the Act vests considerable discretionary authority in the Depart-
ment of Energy, the FUA is potentially a powerful instrument for
forcing utility and industrial boiler fuel users to convert to
coal.
Federal MBFC policy deals primarily with two classes
of oil and gas users: utility power plants and industrial
"major fuel-burning installations" (MFBI's). Neither power plants
nor MFBI's which have a heat input rate of less than 100 million
Btu1s per hour are affected by the act. However, if there are
several units at a single site and the total fuel-burning capa-
bility exceeds 250 million Btu's, all of the units fall under the
provisions of the Act.
The major provisions of the Fuel Use Act are summarized
in Table 3-2. The Act prohibits the use of oil or natural gas in
new utility and industrial boilers coming under the Act's size
criteria, and calls for a total phaseout of gas use in existing
utility boilers by 1990. Existing MFBI's, however, are not
specifically required to convert, although DOE is given authority
to designate categories of MFBI's which must stop using oil and
gas. Similar discretionary authority is given DOE to prohibit the
use of oil and gas in designated categories of MFBI's for purposes
other than boiler fuel.
The Act is set up to be administered through the grant-
ing of both temporary and permanent exemptions, and sets forth a
variety of criteria under which they may be justified. The
principal criteria are inability to meet environmental standards
with alternative fuels and excessive costs of conversion.
24
-------
i
i
e
•f
S.-
P
•"•J
TUU vi. usic pvmsion* or m
IMIC nuuHTioM
. Oil or |M eoopoe bo «ood M prtaur (uol
. nut bo eooocnocod vlch olutooio (ml copuUlcy
. lo u* MO .(tor 19M
. *> fM ooo la o ploat clue did IMC 1100 (M la HIT
. Cooo-br-o*M proMblaooo (or (oeil&ioo vtth oool-
bunlog oopobliicy
• Oclllcloo My Apply (or OBOOpclooo or OMMIM CM
. Oil or MO eoaooc b« uMd «o prlaory (uol soureo
. Dot **r «ociBli«B c«et(orie«l prabibleiooo (or
aon-bollor uo«o
. lo pluoo out ro«.t*irod
. Dec Mir prohlhlt oil or f«o m o eocofforieal hoiio
or ntol liiraloi Xaoeollocloa
rDnua nm. use ACT
XAJOI tXBffTIWS
. All imlto !••• chaa 10 Nlfo unl*io total
eipulcr OB •!» oeoodo 25 Mb (P)
. CorolUblo or blgh-eoot aool oupplioo
(Tor F)
. Ou or oora itto Uotutlou (T or P)
. Tioltcloa o( oovtrBoMoeol ngulociooo
(outo or (oaorol) (T or P)
. Futile taconot (T)
. Otmllikllttr o( coplul (P)
. Cafoaorocioa (P) CMrtooer OM (P)
. I*>«lmne o( rollobUlcr (t)
. Doo a( irttftMlo or alxcuroo (T or P)
. rookloo*1 nd oortala Inumdlou loido
oro oleo lUtucioao (T at F)
(t'or^r ° " ">™™< i**"10"
. Syofuolo or iaaovoel** eoebaolocr (T)
. Fuolle iacorooc (T)
. blUMllcr Coi.o«r.eloo (P)
. Fook lood
. nsTBi cnmjaa onion (biocioi
OUllUoo)
Ubmtt plu br 1MO
Ko oo« boMload oil or (oo imlt*
l«duco to 20 poreooe o( 1976 |u eoo-
iinpcloo bT 1°»
DoC opprovol o( cu contract*
Coovloco olloioocloa o( goo uoo by 2000
uoleollr iAeludoi Moot of tboM llotod uador
"aov »«lltl««" 4bov«.
(P) ForauMM (I) Tovorur
In principle, it would be possible to fine-tune such a
scheme, so as to allow for adjustment to changing conditions of
oil and gas supply. The Act itself is comparatively open, and
leaves a great deal to the discretion of the Energy Secretary.
However, the draft regulations for new boilers reflect an
opposite interpretation. The draft regulations have been de-
signed to make exemptions very difficult to obtain at the outset,
leaving little room for increasing stringency as a response to
changing oil and gas supplies. Thus the Act is being administered
specifically as a means to reduce imports, rather than as a more
generalized conservation tool.
25
-------
DOE's regulations clearly evince a willingness to pay
a significant economic price for the benefits of conversion.
Requests for exemptions on the basis of unfavorable economics
must show not simply that an alternative fuel costs more to use
than oil and gas, but that the cost differential be "significant,"
perhaps in excess of 80 percent. The final regulations will
specify a cost differential; the draft regulations use 50 percent.
Alternatively, the applicant must show that the additional
capital required to switch to an alternative fuel is more than
25 percent of the parent company's average annual capital budget
over the last three years.
Alternative sites must be investigated, including sites
outside the utility's service territory, before an exemption may
be granted on the basis of unavailability of alternative fuels,
or inability to comply with environmental regulations. In
addition, the formal permit procedure must be exhausted before
an exemption may be made on environmental grounds. A final
determination from EPA or the state confirming the unacceptability
of alternative fuels is required to support such an application.
A comprehensive "Fuels Decision Report," containing
a detailed examination of alternative fuels, alternative sites,
and environmental and other considerations, must be submitted
with an application for exemption. Also, compliance with NEPA
will be required for most permanent exemptions.
3.2.2 Texas MBFC Policy
In the early 1970's, prompted by concern over long-
term prices and availability of natural gas, the. Texas Railroad
Commission instituted a formal plan to phase out the use of
natural gas under boilers. The original order, Gas Utilities
26
-------
Docket 600, was issued in December of 1975 and was amended in
March 1976. Subsequent minor revisions have been based on
administrative decisions and litigation.
Since the Commission regulates the transport and sale
of natural gas, Docket 600 imposes boiler fuel restrictions by
prohibiting deliveries of natural gas to boiler fuel users in
excess of 3,000 Mcf per day.* This prevents new large boilers
from using gas. Existing users are exempt from the prohibition.
However, Docket 600 requires a ten-percent reduction in deliver-
ies to all current boiler fuel users (exceeding 3,000 Mcf/d) by
January 1, 1981, and a 25-percent reduction by January 1, 1985.
The reduction is calculated on the basis of the customer's 1974
or 1975 boiler fuel use (whichever is greater).
Docket 600 reserves the right of the Commission to
grant exemptions to its provisions. To date, economic cost-
benefit criteria have been paramount in considering exemption
requests.
With the passage of the Fuel Use Act, it is expected
that Docket 600 will very soon be withdrawn. Unlike the federal
Act, Docket 600 requires existing industrial firms to reduce their
use of gas, a measure which might put Texas industries at a
competitive disadvantage. The federal Act is also more stringent
with regard to both the total extent of conversion and the grant-
ing of exemptions. Thus, its provisions effectively encompass
and exceed the goals of the Texas measure.
*The 3,000 Mcf is calculated as a daily average over a year.
This level was chosen because it exempts small users (hospitals,
schools, laundries, etc.) but affects 95 percent of the gas
burned in boilers.28
27
-------
-------
4.0
FOSSIL FUEL ALTERNATIVES FOR INDUSTRY
Summary and Conclusions
Coal and lignite are not presently as attractive for
industrial use, based on economic considerations
alone, as are oil and gas, even at current prices.
The regulatory approach proposed^ by ERA in its
draft FUA regulations effectively alters the
economics of interfuel competition to favor coal by
placing an arbitrary economic penalty or "handicap"
on oil and gas use.
While conventional pulverized coal boilers will
probably dominate in industrial applications,
favorable economics suggest possible significant
penetration of AFBC systems by the 1990*s.
The proposed DoE regulatory approach improves the
chances for commercial-scale gasification as an
environmentally acceptable alternative in cases
where an alternative site is infeasible and poor
air quality restricts direct coal combustion.
Unless non-boiler fuel choices came to be widely
regulated under FUA, with a similar "handicap"
approach, synthetic fuels are not likely to achieve
significant market penetration in process heat
applications.
In addition to fuel uses, gas made from coal or
lignite has a large potential market as a chemical
feedstock. Large solid-fuel-based integrated com-
plexes combining steam, heat and power generation
with chemical syntheses, may develop.
Before gasification becomes widespread, two key
uncertainties must be resolved:
/ Environmental control requirements, especially
NSPS, which can affect economics.
29
-------
/ The potential for high ambient ozone levels to
limit siting.
The combined uncertainty felt by industry over both
the future of clean air rules and the future of
MBFC, may cause many firms to delay making large
investments in expansions. The situation on the
Gulf Coast is particularly constrained in this regard.
Some firms may perceive incentives to consider long-
term relocations.
Having considered potential regulatory influence on
boiler-fuel choice, it now remains to consider in some detail
how the general energy use patterns discussed in Section 2 may
break down into a mix of fuels. This section deals with industry;
Section 5 contains a similar discussion for electric utilities.
Future industrial fuel choices will be made against a constantly
changing backdrop of economics, environmental controls, and
technology. Moreover, most of these decisions will be made
within the rules set by mandatory boiler fuel conversion policy.
The following sections present an overview of the principal
driving forces behind the choice of fuels for generating process
steam and heat.
Boiler fuel choice is under the jurisdiction of the
Fuel Use Act, while the status of fuel choices for generating
process heat alone is unclear. Although the FUA provides for
extending its provisions over non-boiler applications, no
determinations have yet been made. Depending on how non-boiler
fuel uses are eventually regulated, choices in this area of
applications could be made quite differently than those in the
area of boiler fuels. For this reason, the two types of appli-
cations will be discussed separately.
Finally, although chemical feedstocks have been delib-
erately excluded from the potential energy demand curves for
30
-------
industry, they constitute a potential market for lignite.
Therefore, feedstock choices will be briefly discussed, as a
potential additional demand.
Background
As was pointed out in Section 2.3 above, petroleum
refining and petrochemicals together account for two-thirds of
the fuel used by Texas industries. These industries experience
considerable economies of agglomeration, and tejid to develop in
clusters or strips. Between 75 percent and 90 percent of the
state's large industrial boilers are located within 50 miles of
the Gulf Coast between Corpus Christi and the Louisiana border.29
The Houston area is the center of this development, and now
comprises the largest petroleum refining-petrochemicals complex
in the nation.
The high degree of interconnection between plants in
the Gulf Coast industrial complex is an important characteristic
with respect to fuel choices. A 1200-mile pipeline network,
known as the Spaghetti Bowl, allows complex direction of product
streams, which can be adjusted almost on a day-to-day basis to
allow for economic optimization. Many streams can be either sold
or used as fuel. Thus, the actual fuel mix in use at any time
will consist of a variety of substances which varies both with
the cost of raw fuels and with product prices.
Natural gas is now the dominant energy source in Texas
petroleum and petrochemicals industries. The larger integrated
refining and petrochemical facilities may own gas supplies suffi-
cient for a large part of their needs. These supplies are
exempt from the Fuel Use Act. Additional gas is supplied by
utility-type vendors, or on long-term contract from producers.
Thus, the delivered price of natural gas may vary from the recent
31
-------
intrastate prices of up to $3.00 per million Btu, to well under
$1.00 on older, long-term contracts. This situation could result
in considerable firm-to-firm variation in the economic cost of
converting to coal or lignite, and hence on ability to pass the
FUA cost test.
4.1
Alternative Boiler Fuel Choices
Table 4-1 summarizes what is thought to be a currently
feasible range of 'choices for new industrial boilers. The table
TABLE 4-1.
Mew coal- or lignite-fired
boiler with FGD
New residual fuel oil-fired
hollar with FCD
Naw distillate fuel oil-
fired boiler
New natural gas-fired
boiler
Mew coal or lignite AFBC
boiler
New low-Btu gas-fired
boiler
New nedluo-Btu gal-
fired boiler
ALTERNATIVE CHOICES
Hew Facilities and
Site Requirements
Boiler; scrubber;
coal handling;
solid waste dis-
posal and handling;
lime/limestone
handling.
Boiler; scrubber;
oil storage;
solid waate dis-
posal.
Boiler; oil
storage
Boiler.
Boiler; coal han-
dling; solid
waste disposal &
handling; lime/
lime 1C one han-
dling.
Caslfler; boiler;
coal handling
facilities; waste
disposal at
gaslfier.
Boiler; avail-
ability of mediun-
Btu gaa from off-
aite producer.
FOR FIRING NEW
Transport
Requirements
Rail or Barge
Transport
Pipeline or
Barge Ter-
minal
Pipeline or
Barge Ter-
minal
Pipeline
Rail or Barge
Terminal
Rail or Barge
Terminal
Pipeline
INDUSTRIAL BOILERS
Limiting Environmental
Considerations
PSD at boiler.
PSD at boiler.
PSD at boiler.
PSD at boiler.
PSD at boiler.
NAAQS at gaslfier.
PSD at gaaifler.
Gasifler aoltd and
liquid wastes.
PSD at (aslfler.
Technical
Feasibility
Commercial
Commercial
Commercial
Commercial
Conceptual,
might be
available in
1990 for in-
dustrial
applications.
Commercially
demonstrated
in U.S. except
for HjS re-
moval unit.
Commercially
demonstrated
overseas. No
commercial
U.S. Installa-
tions.
32
-------
indicates equipment, siting, and transportation requirements for
each option, as well as pointing out potential siting limitations
imposed by environmental restrictions. Table 4-2 gives rough
cost comparisons, which should be considered approximate.
Particularly for synthetic fuels and fluidized bed combustion,
the exact figure depends on a number of assumptions which vary
considerably between applications. Thus, these figures are
useful principally as a means of comparing the various choices
on the basis of the same assumptions.
4.1.1 Present Coal, Oil, and Gas Economics
Not surprisingly, it is less expensive to burn fossil
fuels directly to generate steam than it is to burn gasified
coal. However, the relative economics of coal versus oil or gas
in new boilers vary with the size of the boiler and with its
capacity utilization rate.
Coal-fired boilers are favored at large sizes and high
capacity utilization rates. This is due to the fact that the
annualized costs of coal-fired boilers are more capital-intensive
than those of oil- or gas-fired boilers, as shown in Table 4-2.
Thus, economics of scale have a more beneficial impact on coal-
fired boilers (in dollars per thousand pounds of steam) than on
oil- or gas-fired boilers. Also, higher capacity utilization
rates for a given boiler size favor coal boilers more than oil
or gas boilers. This is because the fixed capital-related
charges can be spread over a higher steam production rate, giving
a lower cost per thousand pounds of steam.
To examine for this effect, it is useful to plot combi-
nations of size and capacity utilization rate at which, the costs
of using coal just balances those of using an alternative fuel.
Such a set of "break-even" curves, developed by IGF, Inc. in a
recent (June, 1978) report,30 is shown in Figure 4-1. Boilers
33
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CO
-F-
TABLE 4-2. SIMIARY OF ANNUALIZED OPERATING COSTS FOR ALTERNATIVE ENERGY PATHWAYS FOR NEW INDUSTRIAL BOILERS1'
Annualized Operating Costs, S/10' Ib
Heat Rate, Capital
Btu/lb 650 pslg, Investment, Annualized 0 + M
750*F stm $10* Capital Charges * Costs
New coal- or lignite-fired
boiler'
Boiler 21.6 1.93 0.58
Pollution Control 8.9 0.80 0.55
Total 1400 30.5 2.73 1.13
New residual fuel oil-
fired boiler
Boiler 7.2 0.64 0.41
Pollution Control 7.0 0.63 0.45
Total 1350 14.2 1.27 0.86
New distillate fuel oil-
fired boiler
Boiler 7.2 0.64 0.41
Pollution Control 1.0 0.09 0.04
Total 1350 8.2 0.73 0.45
New natural gas-fired
boiler
Boiler 1380 6.1 0.55 0.35
New coal- or lignite-fired
AFBC boiler
Boiler 1400 23.2 2.08 1.14-2.29
New boiler fired with low-
Btu gas from coal or
lignite
Boiler 1380* 6.1 0.55 0.35
Caalfler 29.6 2.65 1.40
Total 1850 35.7 3.20 1.75
New boiler fired with
nK^diuu-btu gas from
coal ui UBuUe 13BO 6.1 0.55 0.35
'All costs are Bid-mtt dollars.
Fuel5
Costs
1.96
_
TM
2.70
-
2.70
3.64
-
3.64
3.45
1.96
-
2.62
2.62
6.90-9.66
'Pollution control includes both S02 and particulates for coal- and residual fuel oil-fired boilers. Only participate control
distillate fuel oil flred-boller and AFBC boiler.
'Based on steam demand of 300,000 Ibs/hr.
"Annualized capital-related charges were calculated aa 20 percent of capital investment.
5Fuel costs used: coal - $1.40/tM Btuj Residual fuel oil - $2.00/MM Btu; Distillate fuel oil - $2.70/>M Btu,
Medium- Btu gas - $5.00 to $7.OO/HM Btu.
uapiiai cuquirt.mt.niti are oasea on £ equivalent units each rated at iOU,OOO Ib stm/hr with an average annual
which equals a 300,000 Ib stm/hr facility with an 85 percent annual operating factor.
Low- Btu gasification facility includes two 275 x 10* Btu/hr trains with a 75 percent reliability factor and
of 64 percent.
aNedJum-BlM gasification facility is located off-site and supplies fuel gas via pipeline.
Source of Uata: AFBC capital requirements and O + M costs developed from data presented In Reference 29.
l.ow-Btu gasification costs are Radian estimates for on-site Wellman-Calusha gaslfiers with
MzS removal.
Medlum-Btu gas costs are Radian estimates for Lurgl gasification system.
All other cost Information and boiler heat rate data were taken or developed from Reference
Natural gaa - $2
2,5
stm
Total Annualized
Costa
4.47
1.35
O2
3.75
1.08
4.83
4.69
0.13
4.82
4.35
5.18-6.33
0.90
6.67
7.57
7.80-10.56
is included for
.50/M4 Btu;
operating factor of 64 percent ,
an average annual operating factor
Stretford process
30.
used for
-------
I30p
I
iiol-
I
— I"*1'
90
I "
1 70
Oil Versus High Coal Pricm
(20% more)
Oil Venus Reference Case
Coal Prices
Oil Venus Low Coal Prices
(L/T contract and unit trains)
$0 100 200 300 -100
BOILER SYSTEM SIZE (10^ lb./hr.)
Figure 4-1.Breakeven Sensitivity to Coal Prices
(Midwest Location, 1980 Start up)
(Redrawn from ICF, Inc. 1978 30) 02-4328-1
35
-------
with capacity factors and sizes falling above each curve favor
the use of coal, while points below each curve represent design
conditions better suited to the alternative fuel.
Because of low capital and operating costs, natural gas
at current prices* is a far more economical boiler fuel than
either coal or oil. Natural gas, however, is widely seen as a
highly uncertain fuel, both in terms of price and of supply.
Since gas prices account for 70 to 80 percent of the total cost
of steam from a gas-fired industrial boiler,30 price changes are
highly significant. The Natural Gas Policy Act, enacted as part
of the National Energy Act of 1978, allows for the deregulation
of new gas by 1985. It also requires boiler fuel users and
some other, yet-to-be-specified, industrial users to pay the
incremental cost of higher priced gas supplies purchased by the
pipeline companies serving them, up to the equivalent cost of
fuel oil. These two provisions assure price increases for
industries purchasing gas from pipelines. Added to rising prices
is the threat of supply curtailments under conditions of short-
fall. Thus, even without the Fuel Use Act, substantial incen-
tives exist for industry to turn away from heavy dependence on
natural gas.
The next major competitor with coal for industrial
boiler-fuel markets would normally be fuel oil. Figure 4-2 shows
breakeven curves for coal versus low- and high-sulfur oil. Under
the existing NSPS, low-sulfur oil may be burned without a scrubber.
The proposed new NSPS, however, would require a scrubber for many
oil-fired boilers. The curve shown here for high-sulfur residual
oil reflects the use of both flue-gas desulfurization (FGD) and
baghouse filters for particulate control. Some distillate fuel
oils may have sufficiently low sulfur contents to be burned with-
out a scrubber even under the new NSPS. These oils can, therefore,
*Price used by IGF, Inc. in developing these curves was $2.85 per
million Btu, based on delivery to a midwest location.
36
-------
I
120 \-
I
noj-
I
— 1001-
< 80
ce
z
O 70
3
> 50
Midwestern Coal Verius
Natural
Midwestern Coal verms
High Sulfur Oil
Midweitern Coal Venus
Low Sulfur Oil
50
100 200
3OILER SYSTEM SIZE (10-< Ib./hr.)
300
Figure 4-2. "Breakeven Curves"
(Midwestern Location, 1980 startup)
(Redrawn from ICF, Inc. 1978 30)
400
02-4329-1
37
-------
command a higher market price. In consequence, coal competes
more effectively with low-sulfur oil, as the figure shows.
However, coal becomes the most economical fuel only at high
capacity factors and large boiler sizes.
Given the uncertainties inherent in so generalized a
set of curves, it is fair to say that a comparatively small drop
in the cost of using coal relative to either high- or low-sulfur
oil would allow coal to compete effectively over a wider range
of boiler sizes and capacity utilization rates. Conversely, a
small increase in the cost of coal use would tend to reduce
even further the portion of the market in which coal is now
competitive with oil. Since coal-fired plants require more
capital than oil-fired plants, changes in capital costs and
interest rates will affect coal use more than oil use, as shown
in Figure 4-3.
Under the Fuel Use Act, most but not all affected
boilers will probably have difficulty obtaining exemptions based
on cost. The approach taken by the "cost test" in the FUA
regulations has been to "handicap" oil. Requiring the cost of
using coal to exceed that of using oil (or natural gas) by some
percentage before an exemption can be granted effectively shifts
the breakeven curves down and to the left, just as if the cost
of using oil had been increased. These curves suggest that the
higher the percentage handicap on the use of oil, the smaller
must be both boiler size and capacity utilization factor before
oil is again the preferred fuel. According to these curves, at
the level of 50 percent proposed in the draft regulations, boilers
running at the 85 percent capacity factor used in Table 4-2 would
be unable to overcome the oil-use handicap at any size. Boilers
running at a 55 percent capacity utilization rate (close to a
recent national average among all industrial boilers)31 would
find oil the preferred fuel at sizes below 100,000 pounds of
38
-------
Reference Caw \
-.too
I 90
ui
r
O 70
1.
I"
§ 40
3
30
20
10
0
ZOX Higher Capital Cotts
V
Reformed COM Oil
20% Lower Capital Cotts for Coal
SO
100 200 300
BOILER SYSTEM SIZE <103 Ib./hr.)
400
Figure 4-3. Breakeven Sensitivity to Capital Costs
(Midwest Location, 1980 Startup, Coal Versus Oil)
(Redrawn from ICF, Inc. 1978 30) 02-4327-1
39
-------
steam per hour. For reference, the lower size limit of 100,000
Btu/hour on boilers affected by the FUA is roughly equal to
70,000 pounds per hour.
To summarize, the economic forces which help determine
the extent of oil-firing that might be economically feasible in
industrial boilers fall into two groups. Those favoring coal
over oil include potential increases in the price of fuel oil
and the imposition of a percentage handicap on oil use through
the Fuel Use Act. Working in the opposite direction are rising
capital costs and interest rates, which affect the economics of
coal more than oil. Also, the price of coal use may be expected
to rise, largely in response to implementation of the Federal
Surface. Mining Control and Reclamation Act, the Resources Con-
servation and Recovery Act, and increases in rail tariffs approved
by the Interstate Commerce Commission. The balance among these
forces at any given moment will determine the amount of oil which
might be economically used in new industrial boilers.
Uncertainty regarding any or all of these factors,
however, may tend to make decision makers shy away from oil, as
they have recently done from gas. Applying for an economic
exemption also promises to be a lengthy process, which industrial
observers fear is likely to add one to three years to a project's
schedule.
The foregoing discussion has compared oil and gas to
conventional pulverized-coal-fired (PC) boilers. At present,
atmospheric fluidized bed combustion (AFBC) appears to hold
promise as an alternative mode of burning coal. Based on pilot-
scale experience, AFBC appears competitive with PC (with scrubber)
and has the added advantage of requiring no flue-gas S02 scrubber.
The principal technical drawbacks keeping AFBC out of the present
marketplace are problems in scale-up and untested operational
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reliability at commercial sizes. However, for some industrial
applications, these problems may be overcome in the next ten
years.* Other uncertainties regarding AFBC include its ability
to meet the proposed New Source Performance Standards requiring
85 percent sulfur removal and the disadvantages arising from the
very large amounts of solid waste generated.**
4.1.2 Possible Effects of MBFC on the Attractiveness of
Gasification
For some industries, limited as to location, the
combination of MBFC and clean air requirements might make
gasification a feasible alternative. Given the high degree of
interconnection in coastal refining-petrochemical complexes,
and the associated economies of agglomeration, it may be con-
sidered very desirable to build a certain proportion of needed
new boiler capacity on or near existing sites.*** Many such
complexes, however, are located in areas where the PSD increment
for S02 allowable under the Clean Air Act of 1977 has already
been filled. In these areas, burning coal directly would require
obtaining offsets and possibly operating at very low emission
rates.
Environmental exemptions may be granted under the FUA
to firms demonstrating that coal cannot be burned without
violating environmental standards. However, the entire permitting
process must be exhausted before such an application can be made,
which could substantially delay a project. Applying for an
*Because utility applications require much larger sizes, it may
take longer to commercialize AFBC in this area.
**The amount of solid waste produced goes up rapidly at higher
levels of S02 removal, because the sulfur removal process re-
quires a Ca/S ratio of between 2 and 2.5 to one, in practice.
***rhe FUA draft regulations define a site to include a company's
facilities located within ten miles of each other.
41
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environmental exemption also entails a risk, which cannot be
evaluated without some experience with the new regulatory
procedure, of being obligated to select one of the alternative
sites or alternative fuels which must be evaluated in the report
which accompanies application. In some instance, if the proposed
boiler is not part of a highly integrated system, it may be
preferable to choose a remote site where PSD is not a problem.
An alternative to the environmental-exemption route is
to burn medium- or low-Btu gas from coal or lignite, from which
the sulfur has been removed at the gasification plant. High-Btu
gas costs more to produce than either low- or medium-Btu gas, and
at current prices the higher heating value does not justify the
added expense for industrial applications. Both economic and
technological hurdles must be cleared before liquefaction pro-
cesses can enter the industrial fuels market. Synthetic fuels
from coal would be attractive in cases where the extra cost is
outweighed by the potential costs either of obtaining emissions
offsets to burn coal directly or of moving to another site. The
key factor, however, will be the cost-test percentage fixed in
the final FUA regulations. Set toward the low end of the 30 to
80 percent range, the cost test could allow exemptions to burn
oil or gas where the only environmentally acceptable way to burn
coal was to gasify it before combustion in the boiler. Set
toward the high end, gasification, unable to pass the cost test
in favor of oil or gas use, might be the selected technology.
The price of coal-derived gas is sensitive to essentially
the same factors as is direct coal-firing. Because capital costs
are high, the gas price is very sensitive both to plant size and
changes in capital costs. Next in importance is the price of
the feedstock coal itself, of which transportation cost is the
most significant component.
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The economics of gasification vary with the application.
Because of the large capital costs involved, gasification is most
economically applied to uses with a continuous, high-volume fuel
demand. Thus, the gasification plant can run steadily at a more
or less constant load. According to a recent study32 of potential
syngas market penetration in industrial applications, the two best-
suited industries in this respect are petroleum refining and chem-
ical production. Without taking into account the differential
effects of the FUA on process heat and process steam generation,
this study evaluated applications within refineries and chemical
plants where syngas could replace other fuels. Based on cost
alone, the study concluded that medium-Btu gas from coal or
lignite could displace some volume of both natural gas and refinery
liquids as in-plant fuels. The study pointed out that the size
of large integrated refining-chemical complexes makes reliability .
of supply an extremely important concern. Thus, only a relatively
small part of a complex* s fuel requirements would typically come
from any one source. This tendency, coupled with concerns over
reliability in gasification processes not yet well proven on a
commercial scale, was cited as potentially setting a limit on
market penetration.
In general, low Btu is favored over medium Btu for
smaller, on-site applications with short internal distribution
distances. For larger applications with complex internal dis-
tribution, or where the gasifier cannot be located on site,
medium-Btu may be the economical choice. Furthermore, where
syngas replaces natural gas, medium-Btu gas can usually be burned
without rebuilding the boiler, while low-Btu gas requires exten-
sive retrofit. However,to fully realize potential economics of
scale, medium Btu gasification plants must be very large - 150
billion Btu/day or more. This favors their development by joint
ventures or very large firms.
43
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A potential option for the user with fuel requirements
of small or intermediate size is to build a large gasifier at a
remote location serving several industrial customers. The
gasifier might be built and run by the users themselves, as a
joint venture, a form of business development common among
petroleum and petrochemical firms along the Texas Coast. Gasi-
fiers might also be built and operated by a separate firm
functioning as a utility or supplier.
Large gasifiers may run into air-quality-related siting
problems, however, even at remote locations. If violations of
the National Ambient Air Quality Standard for ozone is as wide-
spread in Texas as some suspect, then gasification plants might
have to obtain offsets for their hydrocarbon emissions. Another
potential problem with gasification is uncertainty regarding the
future imposition of environmental standards and their costs,
particularly New Source Performance Standards and standards for
solid waste disposal.
4.1.3 Other Industrial Options
Two additional choices are available: major relocation
away from the current center of activity, or delay. For highly
integrated chemical operations, the combined constraints of
finding offsets for both hydrocarbons and coal plant emissions
might be seen as an incentive to consider long-range relocation
plans. A less drastic and perhaps more likely response is to
postpone expansions, waiting to see if the current set of air-
quality and fuel-use constraints may not give way to economic
pressure.
44
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4.2 Alternative Fuel Choices for Process Heat
It is not possible to tell what regulatory stance DoE
will take regarding fuels not used in boilers. For the present
study, however, it should be assumed that non-boiler fuels are
not brought under the FUA, or at least not extensively.
The direct firing of coal to supply process heat will
likely be limited, in an unregulated situation, first by process
suitability, and next by economic factors, including the cost of
compliance with environmental rules. Applications requiring
rapid turn-down, special flame characteristics, or special
atmospheres are not well suited to coal as a substitute for
natural gas. For those applications not so restricted, the
difficulty of controlling emissions or obtaining offsets in PSD-
limited industrial areas provide a strong disincentive to burn
coal, even in the face of rising oil and gas prices. Also,
coal-burning requires more capital equipment and higher fixed
operating costs than either oil or gas, coupled with substan-
tially larger site requirements and solid waste disposal costs.
Thus, direct firing of coal for process heat does not seem as
promising as its use for boiler fuel.
The high cost of synthetic gas relative to oil and
natural gas is a major drawback to widespread process-heat
applications. Recent prices for gas and fuel oils range from
$2.50 to $3.00 per million Btu's32, while most current estimates
place the cost of medium-Btu gas from coal at $5.00 to $7.00 per
million Btu's.33
45
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The ability of synthetic fuels to compete with natural
fuels is largely a matter of their price. Currently, that price
is not sufficiently competitive with most natural fuels to pro-
vide the driving force for investments in commercial-scale plants,
Various proposals have been made for the federal government to
take action making investments in synfuels more attractive. The
newly enacted Energy Tax Act, passed as part of the National
Energy Act, allows a 10 percent tax credit to industry for equip-
ment to produce, store, and handle alternative fuels, including
synfuels. This tax credit is in addition to the existing 10
percent investment tax credit. Funds for direct financial
assistance in syngas commercialization are presently limited.
However, uncertainty over the supply and price of gas
and oil might tend to favor gasification as an alternative in
applications where a solid fuel is unsuitable. SRI32 estimated
that independent of mandatory boiler fuel conversion, a total
syngas market penetration in the Houston area of 0.15 quads was
possible in 1985, and 0.33 quads might be used by 2000. For
comparison, the nominal-case industrial demand for energy in
2000 is 5.2 quads.
Low-Btu gasification may lend itself cost-effectively
to process heat applications. This is because low-Btu gasifi-
cation is more cost-effective (versus medium-Btu) for small
sizes; that is, they have relatively low capital and operating
costs. Thus, some on-site low-Btu gasification could take place
for such applications as drying and low-temperature heat.
4.3 Synthetic Feedstocks
In addition to its utility as a fuel, medium-Btu gas
from coal or lignite can also be used as a feedstock in certain
-------
existing chemical synthesis processes requiring CO or H2 as a
base. Currently, natural gas is subjected to reforming or partial
oxidation processes to produce a synthesis gas rich in Ha and CO.
Since coal or lignite gasification produces a product already
rich in these substances, it could be cleaned and used directly
as a feedstock, without further treatment. Because the H2:CO
ratio in gasified coal or lignite is lower than that in synthesis
gas made from methane, CO-intensive syntheses such as methanol and
acetic acid production might be favored economically over H2-
intensive processes such as ammonia synthesis. The H2:CO ratio
can be controlled, however, either through adjustments in re-
action conditions in the gasifier, or by chemically reacting the
CO with H20 to form H2 and C02. Additionally, technology exists
for producing various chemicals from CO, rather than from hydro-
carbons, but these processes would not be competitive at historic
natural gas prices.
The production of ammonia and methanol together con-
stituted 25 percent of the activity in Texas chemical manufac-
turers in 1975. Consequently, there is a large potential market
for snythesis gas from coal or lignite. By-products such as
phenols may also have commercial value. The convenience of large
lignite deposits to the coastal chemical centers makes it likely
for Texas to be the first state to introduce synthetic feed-
stocks. 32 At least one firm, Air Products and-Chemicals, Inc.,
foresees large-scale integrated complexes combining gasification,
cogeneration, and chemical synthesis.31*
At present, shortages of natural gas severe enough to
force curtailments for feedstock applications do not seem likely
before the end of the century. Consequently, the introduction of
synthetic feedstocks will depend largely on the comparison
between the cost of producing synthesis gas from conventional
hydrocarbons and the cost of gasification. The situation is
47
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further complicated by the complexity of overall chemical
manufacturing economics and its sensitivity to a variety of
product prices. However, one company is currently proceeding
with plans to build a large gasification plant in East Texas to
produce synthesis gas for piping to the coast. Whether or not
economics eventually justify the completion of the project re-
mains to be seen. System reliability will undoubtedly be a
principal concern.
48
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5.0
FOSSIL FUEL ALTERNATIVES FOR UTILITIES
Summary and Conclusions
Conventional pulverized-coal combustion technologies,
with flue-gas clean-up, are expected to dominate at
least through 1985 and probably for the remainder of
the century.
AFBC technology offers promise by the end of the
century as an alternative to flue-gas scrubbers.
Commercial-scale demonstration, however, is needed.
Coal or lignite gasification for use as boiler fuel
is inefficient and costly, and is not expected to
be used by utilities.
Gasification and pressurized fluidized bed combustion
can potentially be used more cost-effectively with
combined cycles, but technological problems are likely1
to hold back combined cycles until late in the century)
or beyond.
In-situ gasification still has many problems to over-
come, both in the gasification process itself and in
adapting potential uses to the special conditions of
in-situ production. Although it can make available
very large amounts of energy from the deep-basin
lignites, widespread use of the technology is not
expected in this century.
Most utilities are expected to find the FUA's "System
Compliance Option" attractive, whereby total gas
phaseout is delayed until 2000 on condition that no
new gas- and oil-fired boilers are built.
The situation regarding future fuel choices by utili-
ties is considerably clearer at this time than that of industrial
users as well as being visible over a longer time frame because
of the forecasting and reporting requirements of government
49
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regulatory agencies. Also, unlike industrial boilers, both
existing and new units come under the jurisdiction of the Fuel
Use Act. However both the choices and the appropriate economic
considerations open to existing utility boilers differ somewhat
from those available for new units. For this reason, they will
be discussed separately.
5.1 New Utility Boilers
Most new utility generating units planned in the state
of Texas are large—at least 400 MWe--and will be part of multi-
ple-unit plants at grass-roots sites. Both economics and environ-
mental considerations favor remote locations for large new plants,
A typical unit lifetime is 30 years.
Even without the impetus of the FUA, coal is clearly
the fuel of choice for new, base-loaded units. Their large size
and long operating lifetimes improve the economics of coal use.
Also, the high premium placed on the reliability of fuel supply,
combined with uncertainty over the long-term price of oil and gas
and inability to obtain long-term supply contracts, favors coal
over oil and gas. Accordingly, by far the bulk of the new
capacity proposed for Texas before 1985 is to be fired with coal
or lignite.
Given that solid fossil fuel appears to be the domi-
nant new utility-boiler fuel for the remainder of the century,
a variety of options exist for using it. Table 5-1 summarizes
those currently thought of as having potential utility applica-
tions. Because of their proven reliability and economics, how-
ever, conventional combustion methods can be expected to dominate
the scene at least until 1985, and most likely through the re-
mainder of the century.
50
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TABLE 5-1.
SUMMARY OF ANNUALIZED OPERATING COSTS FOR ALTERNATIVE ENERGY PATHWAYS
FOR MEW AND EXISTING UTILITY BOILERS
Annualized Operating Costs.
N«w coal- or lignite-
fired unit
Power Plant
FGD
Total
Heat Rate,
Btu/kwk
9,000
9,500
Capital
Investment
S/kw
475- 575
145- 210
620- 785
Annualized
Capital Charges
1.08-1.31
0.33-0.48
1.41-1.79
0+M Fuel
Costs Costs
1.33
0.3 1.33
c/kvh
Total
Annualized
Costs
3.04-3.42
New coal-or lignite
AFBC Unit 9,500 580- 835 1.32-1.91
Convert existing gas-
fired boiler to fire
medium-Btu gas
Power Plant 9,000
Gasifier 1000
Total 15,000 1000+
0.3 1.33
see notes——-——
2.28 2.10
2.28+ 0.3 2.10
New facility fired
with low-Btu gas
from coal or
lignite (Lurgi)
Power Plant 9,000 310- 375 0.71-0.86
Gasifier 665- 880 1.52-2.01
Total 13,600 975-1255 2.23-2.87
New facility fired
with medium-Btu
gas from moving
bed slagging
gaslfler
Power Plant 9,000 310- 375 0.71-0.86
Gasifier 435- 625 0.99-1.43
Total 11,300 745-1000 1.60-2.29
Combined cycle using
low-Btu Lurgi
Power Plant 7,500 260- 345 0.59-0.79,
Gasifier 570- 760 1.30-1.74
Total 9,500 830-1105 1.89-2.53
Combined cycle using
medlum-Btu slagging,
moving bed process
Power Plant 7,500 260- 345 0.59-0.79
Gasifier 370- 530 0.84-1.21
Total 9,100 630- 875 1.43-2.00
0.3
1.90
1.90
2.95-3.54
4.68+
4.43-5.07
1.58
0.3 1.53 3.48-4.17
1.33
0.3 1.33 3.52-4.16
1.27
0,3 1.27 3.00-3.57
Notes: All costs are mid-1978 dollars.
Total heat rates for coal derived gas-fired boilers include gasification Inefficiency.
Annualized capital-related charges were calculated as 14 percent of capital investment.
All facilities are assumed to have a 70 percent average annual operating factor.
Costs shown for medium-Btu gas retrofit case do not include any costs associated with the
operation of the existing gas-fired boilers.
Source of Data: Capital investment for cedium-Btu gasification facility for retrofit case is
a Radian estimate, pro-rated from a 150 x 10* Btu/day facility using Lurgi
technology. All other cost data and heat rate Information were obtained iron
Reference 35 and escalated to 1978 dollars at 8 percent/year. 0+M costs were
reported in Reference 35 to vary between 2 and 4 mils/kwh. Since this is a
small portion of the total annualized costs, 3 mils/kwh was used for all cases.
51
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Of the developing technologies, AFBC appears at present
to offer the greatest promise. Because sulfur is removed during
the combustion process, it offers an alternative to the use of
scrubbers. A recent DoE-funded study36 compared three conceptual
designs, prepared by boiler manufacturers, for AFBC units in the
neighborhood of 550 MWe. Compared with these manufacturers'
own designs for similarly sized PC boilers, the conceptual AFBC
units were economically competitive.* AFBC economics are more
sensitive to the cost of coal, however, than the conventional
units.
Before AFBC can be shown ready to enter the market,
however, its reliability must be demonstrated at a commercial
scale, and several technical problems must be solved. In par-
ticular, scaling up the beds themselves will require further
R&D, as regards bed placement, bed expansion, and particle
circulation behavior. Another technological problem involves
splitting the incoming feed stream so that coal can be intro-
duced evenly into the beds. These problems may hold back com-
mercialization until the 1990's or beyond.
The environmental acceptability of AFBC also remains
to be demonstrated at a commercial scale. Although pilot-scale
operations have shown that S02 emissions can be reduced to com-
ply with current NSPS, it is not certain whether AFBC can com-
ply with the more stringent NSPS recently proposed by EPA.
Similarly, NO emissions at the pilot scale appear acceptable.
X
However, although the low combustion temperatures used in AFBC
retard formation of NO , the mechanism by which NO is produced
X X
^Comparisons were made with PC boilers equipped with limestone
scrubbers. When compared with PC boilers equipped with more
expensive regenerable FGD systems, AFBC appears more favorable
yet.
52
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is not yet well known. The acceptability of NOX emissions
remains to be shown under the less rigidly controlled operating
conditions of a large demonstration unit. Finally, AFCB gener-
ates large amounts of solid waste, especially at limestone/coal
ratios appropriate to more stringent sulfur control standards.
Disposal of these wastes, however, may not pose problems much
different than those attending the disposal of ash and scrubber
wastes from conventional boilers.
Gasification offers a way to burn coal cleanly in
boilers of conventional design. However, the two energy con-
version steps required to generate electricity in this way make
gasification followed by combustion very inefficient compared
with direct combustion, which requires only one step. This
feature, combined with high capital and operating costs, make
for an unfavorably high cost of power at the busbar. The newer
slagging moving-bed gasifiers which are being developed poten-
tially will offer some improvement in both efficiency and
capital costs, but the improvement is not sufficient to provide
an economic advantage over direct combustion.
Combined cycles offer a possibility of improved
efficiencies, and producing electricity at competitive prices.
A variety of gasification processes, as well as pressurized
fluidized bed combustion (PFBC), can in principle be adapted to
use in a combined cycle. Both are "clean" coal-conversion steps.
However, combined cycle technology integrated with gasification
or PFBC has not yet been demonstrated, and important technical
problems still remain to be solved. Particularly with PFBC,
turbine-blade corrosion and erosion is a major technical draw-
back. For these reasons, it is not expected that combined cycles
will achieve market penetration before 2000. Because of its
relatively high water content, lignite use may result in lower
53
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gas temperatures than coal. Pretreatment to lower its water
content may be needed to adapt it to use in combined cycles.
An alternative to above-ground gasification is the
process of gasifying lignite seams in place. In-situ gasification
has strong proponents in Texas, and considerable monies are being
invested in its development. It is still too early to tell,
however, whether the technology can be successfully applied to
Texas lignite. It is then another step to develop an economic
method of using the product gases. If in-situ gasification can
be commercialized, however, it may offer the only means of
recovering the energy in Texas lignites too deeply buried for
conventional mining. The size of this resource may be ten times
that of the strip-mineable resource.
Recent efforts at Texas A&M University to gasify a
five-foot lignite seam in place encountered serious problems in
part resulting from the seam's close proximity to a highly per-
meable aquifer.37 Although, in general, the lignite-bearing
formation itself is not a major aquifer, it can and does trans-
mit water under pressure, and is hydrologically connected with
the overlying Carrizo and underlying Simsboro aquifers. Thus,
it may be that, depending on local conditions, the kind of geo-
logic circumstances hampering the TAMU test may be encountered
elsewhere. Air injection problems also resulted in very low
heating values in product gases.
Given the technological problems involved, it seems
unlikely that in-situ gasification will become commercially
available until after the turn of the century. The potential it
affords to extend the recoverable lignite reserve, however, en-
sures continuing interest in this technology. Commercialization,
however, may encounter legal questions surrounding the effect of
in-situ gasification, and related subsidence, on subsequent land
use and the recovery of other mineral values.
54
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5.2 Existing Utility Boilers
Most of the utility boilers now in service in Texas
are fired with natural gas. These boilers cannot be converted
to burn coal without extensive rebuilding and/or derating.38
Consequently, there has been some interest expressed in gasify-
ing coal or lignite so that it can be burned in boilers. How-
ever, as Table 5-1 shows, the cost of electricity produced in
this way is higher than that generated in a new grass-roots,
coal-fired unit. In addition, no gasification technology has
yet been operated at a current commercial scale in this country;
and reliability factors are uncertain. Environmental uncer-
tainties, discussed above under industrial applications, also
argue against attempting to apply gasification to existing
boilers, where unforeseen delays due to permitting could cause
serious reliability problems.
In the face of these difficulties in converting exist-
ing gas-fired boilers, it is likely that many Texas utility
companies will take advantage of the System Compliance Option
written into the Fuel Use Act. This provision allows utility
systems to put off conversion in the short term, provided that
they build no new base-loaded units fired with oil or gas, re-
duce gas consumption by 80 percent by 1990, and end gas use en-
tirely by 2000. Unless prohibited by the FUA regulations
concerning existing utility boilers, much of the required
reduction in gas use may come from substituting oil.
If oil substitution is not allowed, coal-oil or coal-
methanol slurries might be viable options. Also, the Lower
Colorado River Authority is making efforts to beneficiate
lignite so that it can be used independently in a gas-fired
boiler. If such methods of firing can be made feasible, they
55
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could save millions in short-term fuel costs and reduce the large
capital expenditures required to replace gas-fired capacity with
new units firing coal or lignite.
56
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6.0
DERIVATION OF DEMAND FOR SOLID FOSSIL FUELS
Summary and Conclusions
Under Nominal-Case assumptions, solid fossil fuel use
in Texas would rise from present levels of 0.50 in
utilities and 0.05Q in industry to 1985 levels of
l.OQ in utilities and 0.2Q in industry.
By the year 2000, 3.1Q would be used in new utilities
and 1.4Q in new industry, under the Nominal Case.
Utility use might be reduced by 2.0Q if nuclear
power is developed rapidly. Extensive replacement
of existing oil and gas use with solid fuel could
raise the year-2000 total to 4.4 as much as 4.4Q
(utilities) and 1.6Q (industry).
The amount of coal and lignite likely to be used in
1985 and 2000 was estimated as a proportion of total utility and
industrial "conventional" energy growth. A Nominal Case was
selected to be used in .subsequent analysis, which represents a
plausible, slightly conservative outlook for growth in solid
fossil fuel use. Variations of the Nominal Case were investi-
gated to show the sensitivity of solid fossil demand to overall
conventional energy growth, and to alternative assumptions re-
garding the availability of nuclear power and the extent to
which boiler fuel conversion is enforced. Figure 6-1 shows the
"conventional" fuel mix corresponding to the Nominal Case.
Tables 6-1 and 6-2 present the results of the sensitivity tests.
The Nominal Case was based on the solid curves of
conventional energy demand graphed in Figures 2-2 and 2-3, and
considered utilities and industry separately. Simplifying
assumptions were made regarding fuel choices under the Fuel Use
Act. These assumptions reflect the foregoing discussion of
alternatives available to both utilities and industry, but do
not reflect any quantitative attempt at technological forecasting.
57
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94
13
ui
2.4
3.1
I
UTIL. INO. UTIL. IND. UTIL. INO..
_ 1978 1988 2000
I GAS
^_^ OIL & GAS
I I NUCLEAR
I COAL
I LIGNITE
02-4330-1
Figure 6-1. Fuel Mixes for Texas • Nominal Case
Assumptions regarding utilities included:
New utility power plants will rely primarily
on lignite, coal and nuclear fuels. Some
use of oil will be allowed in new poer plants
in order to maintain system reliability.
Some existing utility power plants will shift
from gas to oil, some will receive conversion
exemptions based on environmental or economic
grounds, and some will continue to use gas
for peaking purposes. None will convert
directly to coal or lignite.
Present use of solid fossil fuel amounts to
0.5Q.
5S
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TABLE 6-1. DERIVATION OF SOLID FOSSIL FUEL REQUIREMENTS
Tot«l Conventional Energy
Rejuireoant
Utilities
Industry
Exeapted Oil «nd Gas Ps«
Utilities
Industry
Prospective Nuclear Supply
OtUltlM
Solid Foesil Fuel
Requirement
utilities
Industry
2000
1978 1985 High Nomltul Low
1.760. 2.6 1.4 4.8 3.3
2.42Q 3.1 6.J J.2 3.3
1.26Q 1.3 1.3 1.3 1.3
2.37Q 2.9 4.6 4.0 3.0
O.OQ 0.3 0.4 0.4 0.4
O.SOQ 1.0 3.7 3.1 1.6
O.OSQ 0.2 1.9 1.2 0.3
'TABLE 6-2. SENSITIVITY or SOLID FOSSIL FUEL REQUIREMENTS
IK THE TEAR 2000 TO ALTERNATIVE ASSUMPTIONS
Utilities
Nominal Case 3.1Q
High Nuclear Case 2.0Q
(l.SQ in 2000)
Constrained Oil & Gas Supply 4.4Q
• Utilities replace existing gas use with
solids by 2000
• Industries replace 251 existing gas use
with solids by 2000
Moderstely Constrained Oil & Gas Supply 4.4Q
• Utilities replace existing gas use with
solids by 2000
3Z Ann"1!? Retirement Rate 3.7Q
• Utilities replace oil & gas retirements with
j solids •
! • Industries replace 501 of oil t gas retirements
with solids
Industry
1.2Q
1.2Q
l.SQ
1.2Q
l.SQ
59
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Nuclear power will supply 0.3Q in 1985 and
0.4Q in 2000. No new nuclear plants will
be built other than those announced.
All new capacity after 1978, other than
nuclear, will be fired with solid fossil
fuel.
Assumptions used to calculate industrial demand were:
Feedstocks are excluded from calculation.
Process heat represents half of industrial
fuel use; process steam is the other half.
Existing industrial boilers are currently
exempt by law from conversion requirements
and assumed to remain exempt.
New industrial process heat demands will
continue to be met by either oil or gas.
New industrial boilers built between 1978
and 1982 will be fired with oil (change-
over to solids involves four-year lag time).
. New industrial boilers after 1982 will be
fired with solid fossil fuel or gasified
solid fossil fuel.
The basic picture behind the Nominal Case is one in
which conventional energy sources still constitute the bulk of
the energy used, and conservation takes place slowly. Lignite
and coal use grows rapidly in utilities, because uncertainties
60
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of oil and gas supply and price, together with considerable
freedom of siting, make solid fossil fuels the least risky choice.
Exemptions from MBFC are obtained for existing gas- and oil-fired
utility boilers through a combination of the environmental, site,
and cost provisions described above. In addition, new gas and/or
oil-fired peaking, and perhaps combined-cycle, units are built in
order to assure system reliability such that total oil and gas use
remains the same. (Given the present DoE perception of natural
gas oversupply, and the emphasis placed on reducing oil imports,
this assumption may become increasingly plausible.) Industry
experiences a cutback in gas use arising jointly from increasing
prices and the threat of curtailment, and from MBFC.
Table 6-1 shows how the fuel mix would differ if the
lower and upper bounding curves had been used for total conven-
tional energy demand for utilities and industry (see Figures 2-2
and 2-3). None of the other assumptions are varied.
Table 6-2 shows four sensitivity cases, compared with
the Nominal Case, in which key assumptions were varied, using
the Nominal Case curves for total energy requirements.
In the high-nuclear case, it was assumed that nuclear
power was available in Texas in proportion to the state's share
of the nation's uranium reserves. This translates to a total
"share" of 25,000 MWe of power generation.2" Assuming a 0.7
capacity factor and a heat rate of 101* Btu/kwh, this is the
equivalent of 1.5Q.
A more stringent case for MBFC was derived by requiring
the use of natural gas and oil to be phased out completely in
2000. It was further assumed for this case that this amount
would be entirely replaced by coal. In addition, it was assumed
that 25 percent of current industrial gas use will be replaced by
61
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the year 2000 with solids or solid-based synthetic fuel. The
rationale for this more stringent scenario would be scarcity or
uncertainty of supplies of gas, coupled with high prices or
supply curtailment of oil. Major OPEC price increases or oil
and gas shortfalls, for example, could conceivably bring about
such a scenario.
A sub-case was defined in which utilities phased out
oil and gas completely, but industry did so only to the extent
of the Nominal Case. Such a situation might arise if oil were
available, but long-term contracts, such as utilities require,
were difficult to obtain. This oil-supply situation might pro-
vide a more serious constraint to utilities than to industry,
causing a divergence in utility and industrial behavior. If the
Department of Energy takes a strong stand on total phase-out of
existing boilers by 2000, this subcase may become more plausible
than the Nominal Case.
In the Nominal Case, retirements of existing oil- and
gas-fired boilers have been neglected. This choice was made
originally to provide conservatism in the ultimate requirements
for lignite. However, a fourth sensitivity case was run to
evaluate the potential significance of this assumption. An
annual retirement rate of three percent was assumed. For utili-
ties, the total amount of gas use thus retired was assumed to be
replaced by solids, probably in large new base-loaded units. For
industry, half the retired gas use was assumed to be replaced by
new gas- or oil-fired installations and half converted to solids.
The gas- and oil-fired portion could be made up principally of
process heat, which is not covered by MBFC. As pointed out above,
process heat accounts for roughly half the fuel now used by
industry. Thus, the allocation is consistent with other assump-
tions in the Nominal Case.
62
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As can be seen from Table 6-2, the "sensitivity"
assumptions cause more variation in utility requirements for
solid fossil fuels than in industry. This reflects the view
that utilities may generally prefer to convert to coal rather
than oil, that most of the generating capacity in 2000 will be
new capacity, and that utility companies are basically free to
avoid sites at which coal cannot be burned without violating
air quality rules. The range of variation in utility use of
solid fossil fuel among the sensitivity cases is as great as
that between the high and low energy growth cases. The range
among the industry figures, however, is much less between the
sensitivity cases than between the different growth cases.
63
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7.0 POLICY ISSUES RELATED TO ENERGY GROWTH AND FUEL MIX
Ozone; Even as revised, National Ambient Air Quality
Standards for ozone may restrict the growth of the
petrochemicals and refining industries in areas of
present concentration. These industries affect
lignite demand both directly, as potential consumers
for fuel and feedstocks, and indirectly as driving
forces behind statewide economic and population growth.
For purposes of this analysis, it was assumed that Texas
industry continues to grow at a fairly steady rate throughout the
remainder of the century. However, more than half of the state's
current economic activity is located in areas now designated as
out of compliance with the National Ambient Air Quality Standards
for ozone. As additional measurements are taken over the state,
the area found to be in non-attainment may become much larger.
Even as revised, the current ozone standard of 0.12 ppm is low
enough that many non-attainment areas in the industrialized Gulf
Coast will be unable to comply by 1982. New sources cannot be
permitted in non-attainment areas without a simultaneous greater
offsetting reduction in emissions from another source or sources.
Industries mainly affected by this requirement are those
which emit large amounts of hydrocarbons, which are oxidant
precursors. NOX emissions also play a part in ozone formation.
Future control strategies may involve both pollutants. Petroleum
and petrochemicals, and potentially power production, would be
the major industrial targets of control.
It is feared that non-attainment areas will soon run out
of offsets, and be unable to obtain permits for new sources. If
large parts of the state are found to be out of compliance, it
may be difficult to find other sites for these sources.
65
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A reduction or stoppage of industrial growth in Texas
affects lignite in two ways. First, it reduces demand for lignite
as an industrial fuel. Second, through its effects on population
inmigration, it affects demand for electric power, much of which
is generated with lignite.
Implementation of MBFC; Recent major oil and gas dis-
coveries in Mexico and Canada have greatly increased
world reserves. Under these conditions the need for a
stringent fuel-choice policy to conserve gas and oil is
open to question. A fuel-choice policy may, however,
be used to reduce imports. Such a policy involves
widespread secondary economic costs and potential en-
vironmental problems. How can these secondary impacts
be reduced?
Under the Fuel Use Act, MBFC affects primarily new in-
dustry and existing utilities. Concerns over the FUA and its
implementation focus both on the total economic impact of the re-
quired conversion and on the way the impact is spread. The total
impact is reduced when limited allowable gas and oil use is dis-
tributed in ways that give the largest economic return, including
jobs and value of products. If oil and gas use are cut back
across the board, the result may be reallocation of gas and oil
away from economically efficient industrial uses in the indus-
tralized Gulf Coast, and into less efficient non-industrial uses
in other parts of the country. The recent ERA draft regulations
for the FUA do not explicity consider the economic efficiency of
gas use in the exemption procedure.
Increased coal and lignite use under MBFC will increase
the pressure on the available PSD increments, primarily for S02.
ERA's proposed draft regulations for the FUA require alternative
sites to be considered before granting exemptions from coal or
lignite use. If this provision results in more new industrial
sources locating away from the Gulf Coast, conflicts over the use
66
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of the air resource could develop between utilities and industry.
In addition, NOX emissions from coal and lignite burning may add
to existing oxidant problems by contributing to ozone formation.
Potentially more serious conflicts could arise if sulfates and
ozone forming downwind of large sources are carried into adjacent
states.
67
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8.0 RECOMMENDED FUTURE RESEARCH
The foregoing analysis and scenario development is based
on existing quantitative studies and readily available data. A
more sophisticated and, therefore, more sensitive analysis would
require additional basic research and information-gathering.
Below are listed major areas where further technological research
and development appears most likely to extend and improve potential
applications of lignite besides direct combustion. Also listed
are subjects in which more detailed information and analysis is
needed to support energy planning and forecasting.
8.1 Technological RD&D in Lignite-Related Technologies
Extraction Technology
Economic recovery techniques for deeper seams
Economic recovery techniques for thinner seams
Technological improvements to lower conventional
mining costs
Atmospheric Fluidized Bed Combustion
Demonstrate technological feasibility of scaled-up
operations
Measure emissions of scaled-up installation, with
respect to further control needs for S02, NO ,
X
hydrocarbons
Compare economics with conventional PC boiler with
scrubber, for application in industrialized areas
with dirty or marginal air
69
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Characterize amounts and composition of solid
wastes, disposal options, and potential impacts
of federal rulemaking under RCRA
Coal-Oil and Coal-Methanol Slurry Firing
• Adaptability to retrofit on existing utility
and industrial boilers
• Economic feasibility
Pollution control requirements, solid waste
characteristics and disposal options under
RCRA
Identify and assess effectiveness of state
options for encouraging coal-oil and coal-
methanol slurry firing
Co-Generation and Energy/Industrial Parks
Evaluate technological, economic, and
environmental feasibility of developing
lignite-based industrial parks including
co-generation and/or gasification for fuel
and feedstock use
Identify potential siting constraints and
conflicts, especially over air resources
and water requirements
7C
-------
Identify and assess effectiveness of federal,
state, and local options for encouraging such
development, through taxation, utility rate-
setting, and assistance with front-end
financing
Above-Ground Gasification
Evaluate potential effects of Fuel Use Act
"cost test" on economic feasibility of
gasification in various applications and en-
vironments
Potential future demand for gasification
Design improvements that lower capital costs
. Advantages/disadvantages of lignite vs coal
as a feedstock; process and design alternatives
to reduce disadvantages
Pollution control requirements, especially
for hydrocarbons with respect to ozone
formation and possible violation of standards
Identify and assess effectiveness of federal,
state, and local options for encouraging
gasification
In-Situ Gasification
Improvements in ignition and burn control, well
link-up, product quality, energy recovery
efficiency
71
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Control of gas leakage, subsidence, ground-
water penetration
Adapt products of in-situ gasification
potential uses; develop means of prod-
uct transport to point of use
Identify areas particularly suitable or un-
suitable for in-situ gasification by reason
of:
Seam thickness and depth
Overburden character with respect to well
integrity, subsidence problems
Proximity to aquifers with respect to
groundwater intrusion and process con-
trol, as well as potential pollution.
Evaluate potential quantities of energy
recoverable by in-situ technologies
Combined Cycle Power Generation, Using PFBC or
Gasification
Adaptability of lignite as a fuel, with respect
to:
Turbine blade erosion from particulate
carry-over
Turbine blade corrosion from alkali metals,
sulfur species
72
-------
• Lowered gas temperatures because of high
lignite moisture content
8.2 Information Needed for Better Energy Planning and
Forecasting
Future Texas Industrial Mix
Identify existing trends, the economic and
policy factors driving them, and key un-
certainties about the future
What role do state policies and actions
have influencing the ultimate energy mix?
How is the industry mix reflected in overall
energy demand growth and desirable fuel mix?
Future Industrial Siting Patterns
Evaluate the role of economics of agglomer-
ation in site selection for petroleum and
petrochemical facilities. Using economic
criteria, evaluate flexibility of siting
choices and alternatives to Gulf Coast
siting
Inventory status of PSD increments and the
availability of offsets for future growth
in and near existing industrialized areas
Identify existing trends and their causes
and key uncertainities in future siting
patterns
73
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What role do state policies and actions have
in influencing industrial siting choices
Industrial Use of Lignite
Evaluate the engineering cost and environ-
mental feasibility of lignite use or sub-
stitution in selected new and existing
processes and installations
Identify and quantify advantages and dis-
advantages of lignite versus coal in
industrial applications; identify R&D needs
to improve lignite's position
• What factors appear to drive the ratio of
lignite to coal use?
Mexican Oil and Gas
What is the potential demand for Mexican
oil and gas in Texas?
What options exist for international cooperation/
investment in developing the Mexican refining
and petrochemicals industry?
What potential effects could Mexican fuels have
on the overall Texas energy mix, and the demand
for lignite?
Evaluate key policy issues:
-------
Import limitations
Import prices
Allocation of imported fuels
Evaluate the consequences for the Texas
economy of using vs not using Mexican fuels:
Domestic energy production
Energy costs
Product prices and competitiveness
Assess the potential impact of Mexican
oil and gas on national MBFC policy
Conservation
Develop measures of conservation technically
and economically feasible in the short,
medium, and long term, for representative
uses in Texas
Evaluate/estimate demand elasticities for
these uses in Texas
Evaluate financial incentives, price levels,
required to achieve given levels of conser-
vation, identify most readily achievable
energy use reductions
75
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Identify and evaluate effectiveness of
state options for encouraging conservation,
including assistance in front-end financing
76
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REFERENCES CITED: CHAPTER I
1. Federal Register 41:55524, December 21, 1976.
2. U.S. Bureau of the Census, 1976, "County Business Patterns."
3. Environmental Reporter, June 30, 1978.
4. Texas Pollution Report , January 11, 1978, and March 15, 1978
5. Governor's Energy Advisory Council, 1977a, Texas Energy
Outlook: The Next Quarter Century, Austin, Texas, G.E.A.C.,
vii +167 pp.
6. U.S. Bureau of the Census, 1976, Current Population Re-
ports, Series P-25, No. 620, "Estimates of the Population
of Counties: July 1, 1973 and 1974." U.S. Govt. Prtg.
Office, Washington, B.C.
7. Demand and Conservation Panel of the Committee on Nuclear
and Alternative Energy Systems, 1978 U.S. Energy Demand:
Some Low Energy Futures, Science 200:142-152.
8. Office of Technology Assessment, 1978. Application of
Solar Technology to Today's Energy Needs, Vol. I, Wash-
ington, D.C., O.T.A., vii + 525 p.
9. U.S. Solar Energy Policy Committee, Domestic Policy Review
Task Force, 1978. Status Report on Solar Energy, Domestic
Policy Review, Public Review Draft., Washington, D.C. , 72 p.
10. Bankers Trust Association data.
11. Electric Reliability Council of Texas (ERGOT). Report to
DoE on Coordinated Bulk Power Supply Programs, August 1,
1978.
12. Edison Electric Institute, 1975 and 1977, Statistical
Year Books of the Electric Utility Indus try , Numbers 43,
4T7"45, NewTofkT
13. Electrical World, February 1, 1979.
14. Cepeda, W.L. , 1977. Potential for Energy Conservation in
Texas. Governor's Energy Advisory Council, Austin, Texas,
xii + 170 pp.
15. Texas Railroad Commission data.
77
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16. Prengle, W.H., Jr., 1974. Potential for Energy Conser-
vation in Industrial Operations in Texas. University of
Houston, Project S/D-10, Governor's Energy Advisory
Council, Austin, Texas.
17. Boretsky, M., 1977. Opportunities and Strategies for
Energy Conservation. Technol. Rev., 79:56-62.
18. Starr, C., 1976. The Year 2000: Energy Enough? EPRI
Journal, 7:6-13.
19. Thermo Electron Corporation, 1976. Cited in: Davis, 1977,
20. Davis, R.J., 1977. National Energy Plan Analysis: A
Texas Response, Austin, Texas. Governor's Energy Ad-
visory Council.
21. King, R.J., 1977. Alternatives to the Energy Crisis.
Governor's Energy Advisory Council, Austin, Texas,
x + 248 p.
22. Seidel, M.R., 1976. State Projections of Industrial Fuel
Needs, Office of Energy Systems, Federal Power Commission,
23. University of Texas at Austin, Center for Energy Studies,
1977. Provision of Electric Power in Texas: Key Issues
and Uncertainties, Vol. I, Governor's Energy Advisory
Council, Austin, Texas, 325 p.
24. Gordon, J., 1977. The Future of Nuclear Power in Texas.
Austin, Texas, Governor's Energy Advisory Council.
25. Dupree, W., H. Enzer, S. Miller and D. Hillier, 1976.
Energy Perspectives 2. Washington, D.C., U.S. Department
of the Interior, 224 p.
26. Governor's Energy Advisory Council, 1977b. Texas Energy:
A Twenty-Five Year History, Austin, Texas, G.E.A.C.
27. Federal Register. November 17, 1978.
28. Texas Railroad Commission, Internal Memorandum, April 25,
1978.
29. White, David M., 1979. Texas Lignite Technology Develop-
ment Priorities Over the Next 25 Years, Austin, Texas,
Texas Energy Advisory Council, 10 p.
30. ICF, Inc., 1978. Economic Considerations in Industrial
Boiler Fuel Choice, Final Report, Submitted to the
Congressional Budget Office.
78
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31. Exxon Research and Engineering Company, 1977. Applica-
tion of Fluidized Bed Technology to Industrial Boilers-
Linden, N.J.
32. Olsen, D.L., et al., 1978. Market Opportunities for Low-
and Intermediate-Btu Gas from Coal in Selected Areas of
Industrial Concentration, SRI International, Menlo Park,
California, xiii + 203 pp.
33. Radian technical staff calculations.
i
34. Amos, W.J., Mgr. Business Development, Energy Systems
Department, Air Products and Chemicals, Inc., 1977.
"An Industrial Gas Company's Viewpoint on Chemical Values
from Coal Gasification." Paper presented at the 4th
Annual International Conference on Coal Gasification,
Liquefaction and Conversion to Electricity, University
of Pittsburgh, August 2-4, 1977.
35. EPRI, 1976. Clean Coal: What Does it Cost at the
Busbar? EPRI Journal, 9:6-13.
36. Radian Corporation, 1978. "A Comparison of Atmospheric
Fluidized Bed Combustion Conceptual Designs for Utility
Steam Generation." Interim Report, Washington, D.C.,
Radian Corporation, 125 pp.
37. Strickland, R.F., and J.W. Jennings, 1978. Recent De-
velopments in Texas A&M University's Lignite Gasification
Project. Presented at Fourth Annual Underground Coal
Conversion Symposium, Steamboat Springs, Colorado, June,
1978.
38. White, D.M. , and O.B. demons, 1977. Coal and Lignite:
Mining, Transportation and Utilization Needs for Texas,
TEAC, Report No. 77-003, xiv + 325 pp.
79
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80
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CHAPTER II: LIGNITE DEVELOPMENT SCENARIO
Abstract
In this chapter, a working scenario of plausible
levels of lignite development is derived. The present
study did not attempt a modeling exercise that would
show how coal and lignite price and supply are driven
by economic and policy variables. These variables are
discussed qualitatively, along with certain distinctive
aspects of the developing Texas market for solid fossil
fuels. The development scenario is developed in a
"what-if" manner, based on a series of simplifying as-
sumptions. The sensitivity of the result is tested by
varying the assumptions. It is concluded that the de-
mand for lignite will be high enough to result in the
commitment by 2000 of most or all of the currently eco-
nomically strippable reserve above 150 feet.
81
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1.0
FACTORS AFFECTING THE SUPPLY OF SOLID
FOSSIL FUELS IN TEXAS
Summary and Conclusions
Coal supply shortages are not foreseen under
current policy. Wyoming and Illinois are
expected to be Texas' main suppliers.
It is assumed that federal coal leasing policy
will not constrain the supply to Texas of coal
from the western states. The potential for
supply problems to arise over leasing policy
or controversies is noted, however.
Texas lignite is almost entirely under private
control.
Low heating value versus high ash and water con-
tent place economic limitations on the distance
lignite can be shipped. Combined with high in-
state demand, this makes export to other states
unlikely.
Texas lignite lies in sloping beds; thus the
economics of recovery tend to determine reserve
size. Consequently, lignite reserve size
responds to price, within geological limits.
It is estimated that 6.7 billion tons of lig-
nite can be economically stripped to depths
of 150 feet. The reserve estimate is increased
to 8.9 billion tons when mining to 200 feet is
assumed.
The competition between coal and lignite for the Texas
market is driven partly by the relative supply of the two fuels,
and partly by their price. This section discusses supply; fac-
tors influencing price are discussed in the following section.
83
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1.1 Factors Affecting the Supply of Coal in Texas
As a national resource, coal is extremely plentiful.
Supplies entering the market in the remainder of this century
will be determined by demand, rather than limited by resource
availability.1'2 The National Energy Act, passed without pro-
posed taxes on the use of oil and gas, and without the crude
oil equalization tax, does not appear likely to create a sudden
short-term upswing in coal demand. Thus, over the entire study
time frame, coal supply shortages are not foreseen under current
policy.
Currently, almost all of Texas' coal imports come from
the western states, where much of the resource is under federal
control. Thus, the development of federal coal leasing policy
is of potential concern in the state. Some 70 percent of the
nation's unleased coal is federally owned, and the proportion is
higher in the western states most likely to supply Texas: Wyo-
ming, Montana, and New Mexico. In a recent report, the Depart-
ment of Energy's Coal Leasing Policy Development Office expresses
the belief that more reliance on diligence requirements for ex-
isting leases and emphasis on non-federal reserves will reduce
the need for new leasing.3 New leasing would still be required,
however, particularly in the heavily federal western states.
For purposes of the development scenario used in this
study, it has been assumed that no shortages of coal occur.
This reflects the view that any difficulties surrounding leasing
or production will be resolved in the short term, and will not
have a significant effect as far in the future as 2000. Given
that lead times for opening large mines are now five years or
more, a serious impasse over leasing, coupled with a high nation-
wide demand for coal, could result in inadequate supplies.
84
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However, since future leasing decisions cannot be predicted at
this time, it has been assumed for purposes of this study that
coal supplies in Texas will be adequate through 1985.
Of those areas capable of supplying coal to Texas,
eastern Wyoming has the most reliable proven supply, with some
excess production capacity in existing mines. The Illinois
Basin is also producing at a high rate from numerous mines, but
with little excess capacity. These two areas are likely to be
the main suppliers to Texas.
1.2 Factors Affecting the Supply of Texas Lignite
The Texas lignite resource differs from coal in two
important ways, with respect to supply response. First, the
federal government has no control over leasing the bulk of the
state's lignite, which is privately owned. Thus, leasing and
mine development is free to respond to demand. Second, lig-
nite's low heating value and high ash and water content limit
the distances it can be economically shipped. Combined with
high demand in-state, this makes it unlikely that Texas lignite
will be used outside the state. Competition from other states
will therefore not affect supplies available for use in Texas.
In addition, the lignite found in Texas lies in beds
that dip downward toward the coast, so that the bulk of the
resource is buried too deeply for economic recovery by strip
mining techniques.* The boundary between strippable and deep-
basin resources is. set by economics; if prices rise, more lignite
can be mined profitably than if prices are low. Thus, the amount
of lignite actually "available" for use is somewhat indeterminate
*The looseness of the overburden also precludes conventional
underground mining, except at great cost.
85
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Practical limits to surface mining, however, are set by technol-
ogy. Within these limits, the resource is quite small, compared
to the amounts of coal mineable from the basins supplying Texas
imports.
Figure 1-1 illustrates the effect of resource size on
price. Although data for drawing a lignite supply curve are not
yet available, its qualitative relation to a typical coal supply
curve from one of the basins supplying Texas would be as shown.
Thus, it can be seen that for both fuels, the most economically
recoverable resources are mined first, leading to higher prices
for later increments of supply. Because there is less lignite,
however, the lignite curve rises faster, and at a given cumula-
tive level of resource consumption crosses the curve for coal.
When this quantity of lignite has been consumed, it becomes the
more expensive of the two fuels and demand can be expected to
fall off. Although rising prices can shift the crossover point
to the right, the size of the resource limits this flexibility.
INCREMENTAL
COST OF
PRODUCTION
CUMULATIVE RESERVES MINED
02-4318-1
Figure 1-1. Effect of Reserve Size on Rate of Increase in Cost of Production
86
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Geologically, a "resource" is considered the amount of
a mineral which is actually present, as opposed to the concept
of the "reserves," which is the proportion of the resource that
can be recovered economically. At present, exploration of the
Texas resource is not sufficiently advanced to support detailed
estimates of reserves, although drilling is proceeding at an
accelerated rate. The size of the resource, however, has been
estimated, first by Perkins and Lonsdale for the Bureau of Mines4
and later by Kaiser, of the Texas Bureau of Economic Geology.5
The earlier study (1955), estimating 3.3 billion tons of-
strippable lignite, has been adopted by the Bureau of Mines and
is still widely quoted in national assessments. Kaiser's work
(1974, updated in 19786) is based on more extensive drilling
information and uses a detailed consideration of the depositional
environments to attempt to develop accurate resource estimates.
Kaiser's current estimate of strippable lignite—in seams three
feet thick or more under less than 200 feet of overburden--is
12.2 billion tons. Figure 1-2 shows its distribution across
the state. Assuming mining to 150 feet, and an excluded frac-
tion of 10 percent for roads, lakes, and similar obstructions,
two-thirds of this resource is economically recoverable with
present methods. Of this, only 85 percent may actually be re-
covered using conventional mining technology. The economically
recoverable reserve is estimated statewide as 6.7 billion tons.
This estimate is one of the most important figures
used in this study. It is based on geological and technological
considerations not directly coupled to price. Although tests of
Kaiser's predictions against subsequent drilling data have shown
his method to be remarkably accurate, price increases taking
place in the future could result in recovery of a larger frac-
tion of the resource. The 6.7 billion ton estimate assumes min-
ing to only 150 feet in depth. However, several mines have been
87
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L—J Study Rigton
1700 I Million* of tent of Mtlrmtid itrippabl* lignitt r*wrv*$
02-4332-1
Figure 1-2. Strippable Lignite Reserves by Subregion
planned with the potential for recovery up to 250 feet below the
surface. Also, some lignite promoters are reporting much larger
reserve estimates than Kaiser's estimates would appear to support,
Typically, as a mineral deposit is explored, reserve estimates
tend to rise.
Thus, while Kaiser's estimates are considered to be the
most rigorously derived statewide figures now available, the
88
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actual tonnage ultimately recovered could prove to be consider-
ably different. Even assuming recovery to a depth of 200 feet
raises the reserve estimate from 6.7 to 8.9 billion tons.7 Over
the time frame of the present study, then, the amount of lignite
mined is likely to be driven primarily by the cost at which min-
ing can be justified. Price competition with coal will thus
prove to be a major determining factor.
89
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2.0
FACTORS AFFECTING THE PRICES OF COAL AND LIGNITE
Summary and Conclusions
Recent federal legislation, coupled with ris-
ing costs and the demands of organized labor,
are expected to drive up the price of both coal
and lignite. Their effects are expected to be
stronger on coal, however, so that lignite
prices will not rise as fast.
The imposition of uniform scrubbing standards
in the Clean Air Act and in pending EPA regula-
tions removes a major advantage of low-sulfur
western coal over higher-sulfur Texas lignite.
It is expected that a favorable regulatory
climate will allow continued escalation of
interstate rail freight rates for coal.
Within Texas, lignite shipment costs are not
expected to rise as rapidly, since the rail
rates are state regulated and much lignite is
moved by truck or on short private rail lines.
Much of Texas' lignite is leased by the firms
intending to use it. The lignite recovered
from these "captive leases" can be valued by
these firms at anything between the cost of
mining and the cost of replacement with coal.
Because of this uncertainty regarding lignite's
price, lignite and coal will not compete in a
normal market situation.
Table 2-1 presents a summary of current prices for
coal from Wyoming (Powder River Basin), Illinois (Illinois Basin)
and lignite from eastern Texas. All of these prices are given
as of mid-1978. The coal prices are based on representative
costs for typical mines. Transportation costs reflect recent
ICC approvals of substantial rail tariff increases.
91
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TABLE
2.1 ALTERNATIVE
FUEL COSTS8
Illinois Powder River Basin
No. 6 Subbituminous
Ash, wtZ
Moisture, wtZ
Sulfur, wt%
Heat Content, Btu/lb
Hinemouth Cost
$/ton
$/106 Btu
Transportation Cost
(to the Gulf Coast)
Methods
$/ton
$/106 Btu
Delivered Cost
$/ton
$/106 Btu
11.0
11.0
3.5
11,000
22.00
1.00
Barge
9.00
0.41
31.00
1.41
6.0
, 29.0
0.5
8,500
8.00
0.47
Rail
17.00
1.00
25.00
1.47
Texas
Lignite
13.9
33.0
1.2
6,700
13.40
1.00
Rail
4.50
0.34
17.90
1.34
2.1
Policy Factors Affecting the Cost of Coal
and Lignite
Several new pieces of federal legislation are likely
to cause the costs of mining to rise over the next twenty years.
Among these are:
The Surface Mining Control and Reclamation Act
Mine Health and Safety Act Amendments
Black Lung Legislation
Likewise, the recent negotiated settlement with the United Mine
Workers will cause labor costs to rise substantially for eastern
and midwestern coals, at least in the near term.
92
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These pieces of legislation, along with increasing
costs and the continued demands of labor, will cause the prices
of coal and lignite to escalate over the remainder of the cen-
tury. It is reasonable to suspect, however, that their effect
may not be -as strong in Texas as in the west and midwest. Mid-
western coals may receive the higher increase due to labor-oriented
costs, not only because of union strength but because much of
the coal is mined underground. Mine health and safety costs will
thus be higher than in the west and in Texas, where surface min-
ing prevails.
Another potentially important factor is the imposition
of severance taxes on coal sold outside the state of origin to
help defray environmental and socioeconomic costs. Recently
imposed severance taxes amounting to 30 percent of the value of
Montana coal indicate how important a factor this can be.
Uncertainties regarding reclamation costs in semiarid
climates could introduce some additional cost to Western coal,
while prime farmlands requiring special topsoil handling and
replacement could do the same to Illinois coal. Since seams are
thick, however, high per-acre costs can often be spread over
large tonnages. Here again, Texas is fortunate in having a cli-
mate which favors reclamation, thus holding down costs. Recent
disputes over the definition and treatment of prime farmlands in
Texas have been resolved in favor of allowing mixed overburden
strata to be used as the planting medium, when suitable, rather
than requiring topsoil to be saved and respread in all cases.
With the thinner seams characteristic of Texas lignite, holding
down per-acre reclamation cost is particularly important to
maintaining a competitive price.
Thus, until the physical limits of mining technology
are reached, it is reasonable at this time to expect that the
93
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price of coal relative to lignite may tend to rise. It seems
unlikely, given the factors just mentioned, to fall.
2.2 Effect of S02 Emission Standards
The development of new New Source Performance Standards
for coal burning may affect the relative economics of using coal
and lignite. Under the old standards, many utilities contracted
for long-term supplies of low-sulfur western coal rather than
installing scrubbers as would have been required with lignite.
Although uniform scrubbing standards have been proposed
by EPA, alternative proposals are being pushed which would allow
partial scrubbing of coals with low sulfur contents. Ebasco
Services, Inc., calculated for Phillips Coal Company the differ-
ence made by scrubber requirements in total cost of electricity
at the busbar.10 These results, for a 1300-MWe power plant with
a 70 percent capacity factor, showed the cost'per-KW of lignite
generation as 30 percent higher than the cost of using coal under
the old NSPS. When both fuels require scrubbing of 100 percent
of the flue gas, the difference becomes only 5 percent.*
2.3 Transportation Costs
Transportation costs add greatly to the cost of fuels
away from the mine mouth. Particularly in the case of the wes-
tern railroads, recent large tariff hikes for unit coal trains
have brought this factor to national attention. The Interstate
^Assumptions used in the calculation: lignite is 6100 Btu/lb,
0.647<> sulfur; 6570 of the flue gas is scrubbed under the old
NSPS, with a heat rate of 10,170 Btu/Kwh. For western coal,
heating value is 8250 Btu/lb, sulfur content is 0.4870) unscrubbed
under the old NSPS; the heat rate is 9600 Btu/Kwh. Heat rates
under 10070 scrubbing are 10,220 Btu/Kwh and 9700 Btu/Kwh.
94
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Commerce Commission has recently granted rate increases of more
than 20 percent to individual lines, including an increase that
will raise the cost of Wyoming coal delivered to San Antonio 30
percent.11'12'13 With ICC's backing, this trend of large tariff
increases seems very likely to continue, at least in the short
term.
Over the longer term, the likelihood of continued rapid
increases in interstate rail freight rates is difficult to assess.
However, it seems at this point that the pressures toward very
rapid escalation in the next few years are strong. To summarize
a discussion of this question contained in an internal EPA memor-
andum, lf* several circumstances conspire to push higher tariffs.
These include:
New regulatory approach of the Railroad
Revitalization and Regulatory Reform
Act of 1976
Large capital requirements to improve ex-
isting facilities and build new trackage
and rolling stock
• The increased maintenance and shortened
life span of unit trains and trackage
A favorable attitude of ICC
In Texas, however, conditions do not suggest similar
increases in the cost of shipping lignite within the state.
Within Texas, railroads are regulated not by the ICC but by the
Texas Railroad Commission. The Commission is currently very
concerned over the economic costs to the state of the National
Energy Act's plan to regulate intrastate gas and to encourage
95
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the use of coal. It therefore seems unlikely that it would ap-
prove rate increases that might decrease lignite's attractive-
ness compared with coal, and thus drive dollars out of the
state that could be invested in energy production here. In ad-
dition, the Texas Lignite Belt is served by a number of rail-
roads that must compete with one another. Over short distances,
it may also be more economical for the firm using the lignite to
build and operate its own railway. Finally, the much shorter
hauls within Texas, compared to the distances travelled by unit
trains from out of state, require fewer cars, less trackage, and
afford longer lifetimes for both. All of these factors together
suggest that rail tariffs for lignite shipment in Texas will
rise much more slowly than interstate freight rates.
Although utilities will most probably exploit the much
lower costs of lignite at the mine mouth by siting on or near the
Lignite Belt, industries may not be as free to do so. Thus, the
relative escalation rates of coal and lignite transport cost may
have an impact on the competition between these fuels for use by
industries on the Gulf Coast.*
Midwestern coal could be moved by barge as well as
rail. However, uncertainties as to the capacity of existing
waterways to carry large volumes of coal place calculation of an
appropriate escalation factor beyond the scope of this study.
*Much highex interstate freight rates could raise the cost of
using coal on the Gulf Coast to the point where even with the
cost of shipping, lignite would be cheaper. At the same time,
however, the value of lignite to utilities would also rise,
driving up the cost of new supplies. This would act to dampen
the advantage conferred by transport costs on coastal lignite
use.
96
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2.3 Market Characteristics
The picture emerging at this point is one where lig-
nite, already economically attractive at the mine mouth, may be-
come even more so, to the point of eventually becoming competi-
tive on the Gulf Coast (with respect to delivered price). How-
ever, the situation is further complicated in that coal and
lignite in Texas do not compete equally in a mature market,
owing to the fact that much of the lignite is owned by potential
users.
Texas lignite lessors can be divided into three groups.
The first, which holds 32 percent of the acreage now under lease,
consists of utilities planning to develop the lignite themselves
for use in mine-mouth power plants. The second group is made up
of industrial firms also likely to develop and use lignite them-
selves. They hold 19 percent of the lignite acreage currently
leased. The remaining 49 percent is leased by firms classed as
"vendors." These will either open mines and sell lignite in the
same market as coal, or they will sell or sublease their holdings
to utilities, industries, or other vendors.
Under ordinary conditions, the price of lignite in a
developed market would be expected to rise eventually until the
cost of using it met that of using coal from outside the state.
However, 51 percent of the coal already leased is held by firms
that will not necessarily pay that price. At the very least,
owners of "captive" leases can obtain lignite for the cost of
producing it, regardless of the price of replacing it with an-
other fuel. Depending upon the financial posture of the in-
dividual firm, however, it may be desirable to value the lignite
at something above the cost of production. A firm with a mining
subsidiary, for example, may include a return on investment in
the value of the lignite it produces. Utilities and industry
97
-------
may differ in their behavior, since the prices charged by utili-
ties for their product are regulated by government, while those
charged by industry are controlled by competition in the open
market.
Thus, a substantial proportion of the lignite under
lease in Texas may be valued below the price of replacing it on
the open market. A portion of that controlled by vendors may
also enter this category if it is transferred into the hands of
utilities or industrial users. This situation places even
greater potential pressure on lignite, as an economically de-
sirable alternative to oil, gas, and--it appears likely--to coal,
98
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3.0
DERIVATION OF LIGNITE DEVELOPMENT SCENARIO
Summary and Conclusions
Even using the conservative assumption that the
coal/lignite ratio through 2000 will be the same
as that in announced plans through 1987, it ap-
pears that by the end of the century, virtually
all of the reserves currently estimated to be eco-
nomically recoverable by strip mining are likely
to have been committed (although it will be close
to 2030 before all are mined).
Current reserve estimates are based on recovery
to 150 feet. If mining recovered lignite to 200
feet, the resulting reserves would be extended
from 6.7 to 8.9 billion tons. This amount would
cover even the highest estimates of commitments
required by 2000. The price increase needed to
bring about this increase in production is not
known.
Industry has so far been cautious in converting
to solid fossil fuels. If, as may be the case,
most of the strippable lignite is committed to
the coming decade, this slowness could reduce
the proportion of lignite used by industry, under
the mandate of the Fuel Use Act.
If the economics of gasification and liquefaction
do not become favorable until after 2000, there
may not be enough uncommitted strippable lignite
available for them to support widespread develop-
ment. In-situ gasification of deep-basin reserves
would then appear to be the most promising of the
new technologies in the long term.
99
-------
Given the difficulty of estimating a future "price"
for lignite to compare with competing coal prices, the lignite
development scenario presented here was not developed by balanc-
ing supply and demand in a competitive situation. Instead, the
scenario represents a what-if situation, based on historical
trends. Several alternative cases were also evaluated, to test
the sensitivity of lignite development rates to plausible future
situations. The results are expressed in terms of subregional
divisions of Texas, illustrated in Figure 1-2. Since transporta-
tion costs make lignite non-competitive in west Texas, only the
eastern part of the state is involved in the scenario. Table
3-1 summarizes the steps taken in the analysis.
TABLE 3-1.
STEPS TAKEN TO DERIVE STJBREGIONAL
LIGNITE DEVELOPMENT SCENARIO
Step 1 Based on known acreage under lease, esti-
mate recoverable tonnages of lignite now
held by utilities, Industry, and vendors.
Assume this ratio holds for future dis-
position of lignite yet to be leased.
Step 2 Calculate the number of facilities, equiv-
alent to a 500 MWe steam-electric unit
with a 30-year lifetime, which could be
fired with the amounts of recoverable lig-
nite under lease (resource unit). Table
3-9)
Step 3 Based on solid fossil fuel demands cal-
culated for the Nominal Case, assume that
60Z will be satisfied by lignite and 40Z
by coal, through 2000. Express the re-
quired amounts of each as resource units.
(Table 3-13)
Step 4 Within each subregion, allocate vendor
holdings to utilities and industry so as
to satisfy both groups' needs. (Table
3-15)
Step 5 Allocate remaining coal demand, for
utilities and industry, to subregions,
based on announced plans through 1985 ex-
trapolated to 2000, and projected indus-
trial growth through 2000. (Table 3-15)
IOC
-------
3.1 Leaseholding Patterns
The best information currently available on actual
leaseholdings is that supplied by Steele and Associates, of
Huntsville. Based on a 1978 search of courthouse records, the
total acreage under lease in each county was identified, by
holder. Using these data, holdings were aggregated into the
five subregions and the three holder groups. Then, to translate
acreage into tonnages, the resource endowment in each region
(see Figure 1-2) was divided by the total leased acreage. This
amounts to assuming first that all acreage underlain by strip-
pable lignite is leased, and second that the ratio of recover-
able lignite reserve to acreage is the same for each lease.
A comparison of 1978 leaseholdings with 1977 holdings
data (also furnished by Steele and Associates) indicates that
little change occurred in that twelve-month period. Thus, short-
term evidence does not belie the first assumption. The second
is likely in practice not to be true. Many new entries into the
leasing arena are companies with little experience in coal, and
there is reason to suspect that they are leasing larger amounts
of "scenery" than firms with more experience.15 However, since
it-would be mere guesswork to estimate what effect this pattern
might have on actual tonnages held, the second assumption was
made as a matter of convenience.
The acreage totals thus obtained were converted to re-
source units equivalent to that tonnage required to fire a 500-
MWe steam-electric station for thirty years. Assuming a 0.7
capacity factor, a 10,000 Btu/kwh heat rate, and a heating
value for lignite of 6500 Btu/lb, such a facility requires ap-
proximately 77 MMT. Results were rounded to the nearest tenth,
and leaseholders with fewer than 36 MMT under lease were ne-
glected. Table 3-2 presents the results of these calculations.
101
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TABLE 3-2. LIGNITE "RESOURCE UNITS" HELD BY LESSOR GROUPS
(Assumes uniform ratio of tonnage to acres leased)
Utilities
Industries
Vendors
Total Holdings
Northeast
13.6
5.8
22.5
41.9
North
Central
9.2
8.9
12.6
30.7
Note: A "resource unit" is equivalent to
fire a 500-MWe steam-electric unit
Gulf
South
3.5
0.5
4.3
8.3
Central Coast Total
1.9
1.3
2.4
5.6
the amount of lignite
for 30 years.
0 28.2
0 16.5
1.8 43.6
1.8 88.3
required to
The table shows that the amount calculated as "vendor-
held" is the largest of the three classes. This might be an
overestimate, since at least some of the vendors may be specula-
tors whose strategy is to lease relatively large acreages, with-
out extensive prior exploration. These leases may therefore
have a lower ratio of tonnage to acres leased than those held
by potential users.
3.2 Ratios of Lignite to Coal Use
The third step in the analysis refers to the total
demand for solid fossil fuels. Announced plans through the year
1988 show that if all plants are built as planned, the split
between coal and lignite for existing and new capacity will be
42 percent to 58 percent. Table 3-3 summarizes these announce-
ments, and Figure 3-1 shows their locations. Table 3-4 sum-
marizes forecast consumption of coal and lignite by utilities
through 1987. The split for the year 2000 was calculated assum-
ing a continuation of this 60/40 ratio.
102
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o
OJ
Year
of
Start-
Up
1978
and
ear-
lier
Total
Exist.
1979
Total
1979
1980
Total
1980
Plant
Harrington
Deely ll
Deely 02
Welsh #1
Harrington
Parish 95
6 Units
Coleto Cr
Parish 06
Fayette 01
3 Units
Fayette 02
Welsh #2
Harrington
Parish 91
4 Units
TABLE 3-3
COAL
Mw(e)
ll 333
418
418
528
02 338
660
2695
01 550
660
550
1760
550
528
03 317
570
1965
TEXAS COAL
Utili-
ty
Code
SPS
CPSB
CPSB
SWEP
SPS
HL&P
CP&L
HL&P
LC/A
LC/A
SWEP
SPS
HL&P
AND LIGNITE POWER
Plant
Sandow (1-3)
Big Brown fl
Big Brown #2
.Monticello 01
Monticello 02
Monticello 03
Martin Lake 01
Martin Lake 02
10 Units
Martin Lake 03
San Miguel 01
2 Units
PLANTS
LIGNITE
Utili-
ty
Mw(e) Code
360 TU/A1.
575 TO
575 TO
575 TO
575 TO
750 TO
750 TO
750 TO
4910
750 TO
400 ST/B
1150
Composite
Total
Coal/
Lignite
7605 Mw
•
2910 Mw
1965 Mw
-------
TABLE 3-3 (CONTD.)
COAL
Year
of
Start-
Up
1981
Total
1981
1982
Total
1982
1983
1983
1984
Total
1984
Plant Mw(e)
Welsh #3 528
To Ik tl 508
2 Units 1036
Morgan Creek 16 460
Parish #8 550
2 Units 1010
TMPA Undeter- 200
mined
1 Unit 200
LIGNITE
Utili- Utili-
ty ty
Code Plant Mw(e) Code
Sandow #4 545 TU
1 Unit 545
SWEP Gibbon's Creek 400 TMPA
SPS tl
1 Unit 400
TU
HL&P
TMPA Pirkey #1 640 SWEP
San Miguel t2 400 ST/B
Jorest Grove tl 750 TU
5 Units 1790
Composite
Total
Coal/
Lignite
545 Mw
1436 Mw
1010 Mw
1990 Mw
-------
o
Ul
TABLE 3-3 (CONTD.)
COAL
Year
of
Start-
Up
1985
Total
1985
1986
Total
1986
1987
Total
1987
1988
Total
1988
utili-
ty
Plant Mw(e) Code Plant
Tolk t2 508 SPS Martin Lake 04
DeCordova 713 TU HL&P 01
2 Units 1221 2 Units
TMPA Undeter- 200 IMP A Twin Oak #1
mined Kamack 11
HL&P 02
Fayette #3
Mill Creek #1
1 Unit 200 5 Units
Lake Kemp 11 640 C&SW Twin Oak 92
Oak Knoll Si
Mill Creek 12
1 Unit 640 3 Units
Coleto Creek 42 640 CP&L
1 Unit 640 CP&L
LIGNITE
Composite
Utill- Total
ty Coal/
Mw(e) Code Lignite
750 TU
750 HL&P
1500 2721 Mw
563 TU
640 C&SW
750 HL&P
400 LCRA
750 TU
3103 3303 Mw
563 TU
750 TU
750 TU
2063 2703 Mw
-------
TABLE 3-3 (CONTD.)
COAL
LIGNITE
Year
of
Start-
Up
TOTAL
EXISTING
TOTAL
79-87
TOTAL
EXISTING
AND PLANNED
Utili- Utili-
ty ty
Plant Hw(e) Code Plant Mw(e) Code
6 Units 2695 10 Units 4910
15 Units 8032 19 Units 10,551
21 Units 10,727 29 Units 15,461
Composite
Total
Coal/
Lignite
7605 Mw
17,773 Mw
26,188 Mw
-------
TABLE 3-3 (CONTD.)
Information Sources;
1. Status of Coal Supply Contracts for Mew Electric Generating Units, 1977-
1986, U.S. DOE, FERC, Office of Electric Power Regulation, May 1978.
2. Electric Reliability Council of Texas (ERCOT), "Report to DOE on Coor-
dinated Bulk Power Supply Programs," August 1, 1978.
3. Personal communication with utility officials:
- Southwestern Public Service Company, Amarillo (Pete Smith).
- Central & Southwest Corporation (SWEPCO, WTU, CP&L) (Jim Bruggeman,
Dallas).
- Texas Utility System Inc. (TUSI) (Ken Herman, Dallas).
A. Texas Air Control Board, Permit Records
5. Newspaper Article Press Release
6. Texas Department of Water Resources planning data
Utility Code
TU
TU/AL
CPSB
SWEP
SPS
HL&P
CP&L
LCRA
LC/A
TMPA
ST/B
C&SW
Utility Name(s)
Texas Utilities System (Texas
Power & Light, Texas Electric
Service, Dallas Power & Light)
Joint Project, TU and ALCOA
City Public Service Board of
San Antonio
Southwestern Electric Power
Southwestern Public Service
Houston Lighting & Power Co.
Central Power & Light
Lower Colorado River Authority
LCRA/City of Austin Joint Project
Texas Municipal Power Agency
Joint Project, South Texas
Electric Cooperative & Brazos
Electric Co.
Central & South West Corporation,
Holding Company for SWEP, CP&L,
West Texas Utilities, and Public
Service of Oklahoma
107
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EXISTING AND PLANNED COAL AND LIGNITE
POWER PLANTS IN TEXAS THROUGH 1987
(AS OF 10/78)
KARNACK
• HARRINGTON
Wichita Falls*
LAKE KEMP
Ft. Worth
PIRKEY
Longvitw
FOREST GROVE •
• MORGAN CREEK
TWIN OAK*
SANDOW*
IBBONS CREEK
•'FAYETTE
I Houston
PARISH •
N •COLETO
MIGUEL CHEEK
COAL PLANTS
(through 1987)
Plant/Units
Harrington (3)
OMly (2)
Walsh (3)
Parish (4)
ColMo Creak (1)
Fayatta (2)
Tolk <2)
Morgan Crtak (1)
OaCordova (1)
Laka Kamp (1)
Othars:
Sita Unnanouncad (2)
Siza (MW)
988
838
1684
2440
560
1100
1016
460
713
640
400
TOTALS (22) 10,727
COAL
LIGNITE
LIGNITE BELT
LIGNITE PLANTS
(through 1987)
Plant/Units
Sandow (4)
Big Brown (21
Monticallo (3)
Martin Laka (4)
San Migual (2)
Gibbons Craak (1)
Pirkay (1)
Forast Grova ( 1 1
Fayattsd)
Twin Oak (2)
Karnack (1)
Mill Craek (2)
Oak Knoll (1)
Othars:
Sita Unannounced (2)
TOTALS (27)
Siza
905
1150
1900
3000
800
400
640
750
400
1126
640
1500
750
1500
15,461
Figure 3-1. Existing and Planned Coal and Lignite
Power Plants in Texas
108
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TABLE 3-4. COAL AND LIGNITE CONSUMPTION BY TEXAS ELECTRIC UTILITIES
Coal
Lignite
Total Quads
Year Quads Tons x 106 Quads Tons x 106 Coal and Lignite
1977
1980
1985
1987
0.10
.37
.54
.63
6.0
21.8
31.7
37.2
0.23*
.43
.74
1.09
17.6*
32.7
56.9
84.2
0.33
0.80
1.28
1.72
*Actual lignite production reported by the DoE. All other figures are year-
end rates of consumption based on assumptions stated below.
Assumptions
• Current announced plans (Table 3-3) are carried out on schedule.
• Each unit reaches full output by the end of the year it is
scheduled to start up.
Heating values of 6,500 Btu/lb for lignite; 8,500 Btu/lb for coal.
• No retirements take place.
• Each coal plant requires 3,400 tons per year per MW of installed
capacity; each lignite plant requires 5,400 tons per year per MW
of installed capacity.
The tonnage figures were calculated based on the amount of coal and lignite
required to support the plants announced by Texas electric utilities in
DoE's Status ot_ Coal Supply Contracts of New Electric Generating Units 1977-
1985.
Existing and planned industrial coal and lignite use
is summarized in Table 3-5. Although the potential for use of
coal and lignite in the industrial sector in Texas is large,
the pace of industrial conversion appears to fall far short of
utility plans. A comparison of Tables 3-4 and 3-5 indicates
that announced industrial coal use through 1982 amounts to less
than half the current utility coal/lignite use. Among the rea-
sons for this are the following:
Utilities are required to make known their in-
tentions at an earlier point in the planning
stage. Thus, while utility plans may be an-
nounced 10 years in advance, a major indus-
trial expansion may not be revealed more than
109
-------
TABLE 3-5. EXISTING & PLANNED TEXAS INDUSTRIAL COAL/LIGNITE USE1
Start-Up
Date Industry Location Facility Coal Type
1979 Celanese Corp.
1980 Texas Eastman
1944 Id, Americas
1983
1982
1974-
1981
Union Carbide
AMOCO
Monsanto
(CAM)
Shell
Brick, Cement
& Lime Kilns
Pampa
Longview
Darco (near
Marshall)
Texas City
Houston
Scattered:
North Central,
South Central,
& Southeast
Texas
Cogeneration Western Coal
2 Boilers (540,000 t/y)
116,000 Ib/hr
steam capac-
ity each
3 Boilers
70,000 Ib/hr
capacity each
Mine-mouth
activated
carbon pro-
duction
Process steam/
electric
power cogenera-
tion facility
3 Boilers
total capacity
218,000 Ib/hr
23 Facilities
43 kilns
Undecided
(300,000 t/y)
Lignite
(300,000 t/y)
Undecided
(3,000,000 t/y)
Undecided
(1,500,000 t/y)
Texas
bituminous,
Texas lignite,
& Western coal
(1,800,000 t/y)
Total Coal & Lignite Tonnage:
Estimated Energy Content*:
7,440,000 tpy
116 x 1012 Btu or 0.12 Quads
'Primary source for most of these data is the permit application file at the
Texas Air Control Board (data as of 10/78). ALCOA lignite production is used
jointly by Texas utilities & ALCOA & is tabulated under utilities in Table 3-2.
*Assume half lignite, half bituminous with average Btu content of 7,500 per pound.
two or three years in advance. Therefore,
Table 3-5 represents a shorter time horizon
than does Table 3-2 (announced utility plans)
Utility boilers are generally several times
larger than industrial boilers and therefore
more economical for coal burning.
110
-------
As indicated in Chapter I, existing indus-
trial boilers are not required to convert
under the new federal mandatory boiler fuel
conversion legislation.
The major industrial energy consumers in Texas,
the petrochemical and refining sectors, are
more site-constrained than electric utilities.
New utility power plants can locate along the
Lignite Belt (or otherwise outside the indus-
trial coastal zone or other urban areas) and
supply their customers through the power grid.
Utilities are less subject to economic un-
certainties regarding the major investment
decisions involving coal/lignite conversion.
A favorable regulatory climate in Texas has
enabled Texas electric utilities to attract
the needed capital for coal conversion.
Thus, for a variety of reasons, Texas industry has
taken a wait-and-see attitude with respect to coal conversion
relative to the firm commitment to conversion exhibited by the
utility sector. Under these circumstances, it is not possible
to detect trends that can be extended as far as 2000.
3.3 Sensitivity of Lignite Development to
Alternative Assumptions
Because of these reasons and the price uncertainties
discussed earlier, the actual coal-lignite ratio in industry
cannot be predicted. Therefore, it was assumed for purposes of
this study that the same 60/40 ratio would apply to industry as
does to utilities.
Ill
-------
The results of this assumption, given in Table 3-6,
indicate that by 2000, 6.0 billion tons of lignite will have
been committed for all uses. Given the uncertainty in the
method used, this can be considered very close to the total 6.7
billion tons of economically recoverable strippable reserves
estimated by Kaiser. It should be understood that this tonnage
does not reflect the amount burned or produced in that year. It
represents the amount that must have been committed, by 2000, to
support all of the lignite use that has taken place up to that
time, plus future use, assuming a 30-year plant lifetime for all
installations.
TABLE 3-6. POTENTIAL
Total Energy Required (Quads)
Solid Fuel Demand (Quads)
Lignite Demand (Quads)
Lignite Reserve Commitment
Required (Billions of Tons
@ 6500 Btu/lb)
Resource Equivalents
REQUIREMENTS
Utilities
Industry
Utilities
Industry
Utilities
Industry
Utilities
Industry
Total
Utilities
Industry
FOR LIGNITE
1978
1.76
2.42
.50
.05
.30
.05
.70
.10
.80
10.0
2.0
COMMITMENT
1985
2.60
3.14
1.28
.15
.74
.09
1,72
.17
1.89
25.0
3.0
2000
4.80
5.18
3.14
1.16
1.90
.70
4.38
1.62
6.00
62.0
23.0
To test the sensitivity of this measure of develop-
ment rate, a series of cases were considered that reflect the
assumptions used earlier in examining the sensitivity of overall
solid fossil fuel demand. The results of these cases, calculated
for the year 2000, are shown in Table 3-7. As can readily be
seen, the only two cases which produced a lignite commitment
112
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TABLE 3-7. SENSITIVITY TO ALTERNATIVE ASSUMPTIONS OF
LIGNITE COMMITMENT BY THE YEAR 2000
Utilities
(billion tons)
Nominal Case 4.4
High Growth 5.2
Low Growth 2.2
High Nuclear; Moderate Growth 2.8
Constrained Gas & Oil; Moderate 6.1
Growth
Moderately Constrained Gas & Oil; 6.1
Moderate Growth
High Lignite Demand for Utilities; 5.1
Moderate Growth
3% Annual boiler retirement 5.1
Industry Total
(billion tons) (billion tons)
1.6 6.0
2.6 7.8
0.4 2.6
1.6 4.4
2.5 8.6
1.6 7.7
1.6 6.7
2.5 7.6
6.7
8.9
level lower than the Nominal Case were the low-growth and high-
nuclear cases. The first assumes that per-capita consumption
of electricity stabilizes in 1985, and that per-capita consump-
tion of energy in industry remains at 1975 levels. Thus, demand
grows only in proportion to population. The high-nuclear case
is based on the moderate conventional energy growth used for the
Nominal Case, but assumes 25,000-MWe of nuclear power generation.
Both of these cases appear extremely unlikely.
It is interesting to note that the highest total re-
sults , not from the high growth case, but from the cases in which
boiler fuel conversion is assumed to be most stringently applied.
Although strong economic, social, and political forces would
oppose such a trend, the initial moves by DoE in administering
the Fuel Use Act point in that direction.
113
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If the current reserve estimate of 6.7 billion tons
is correct, then the cases totalling to commitments greater than
this number iniply the possibility of running out of uncommitted
lignite some time in the 1990's. The residual demand would then
be met with coal. However, it will be recalled that, since the
lignite-bearing strata dip toward the coast, more lignite might
be strip-mined if economics warranted digging deeper. The price
of coal, the logical replacement for lignite, may rise faster
than that of lignite over the next 22 years, as discussed above.
Thus, economics may justify the more expensive mining methods
required to recover larger amounts of lignite. As indicated in
the table, mining to 200 feet could produce enough lignite to
cover all the cases. The price increases necessary to support
this increment cannot, however, be estimated without a more de-
tailed analysis than the scope of this study will support.
In interpreting the figures in Table 3-7, it should
be borne in mind that leasing typically takes place in advance
of the demand, as firms attempt to secure themselves against un-
certain future needs. Thus, the time frame over which the tab-
ulated commitments are actually to be made may be considerably
shorter than the 22 years between now and the year 2000.
The significance of this accelerated rate could be
great for industry if large amounts of lignite are needed. As
has been pointed out, industries have so far been cautious and
held back on committing themselves to solid fossil fuels.
Marketplace competition adds an element of risk to such a move,
as seen by individual firms, which regulated utilities do not
experience.
Utilities already recognize the value of using lignite.
If industry is slower in responding, it may find itself competing
with utilities for vendor-controlled lignite. Lignite could be
114
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obtained from vendors by direct purchase and transfer of lease,
by sub-leasing for "captive" development, or by purchase of
lignite mined by the vendor. The first two modes are likely to
prevail in the short term, with each round of trading raising
the per-ton cost of leasing and thus the value or price of the
lignite. Operating a "captive" mine may be economically prefer-
able, in many cases, to purchasing lignite directly from a sup-
plier. However, as time passes, it may become more and more
difficult to obtain the necessary leases. Also, the cost differ-
ential between "captive" and purchased lignite may decrease with
time, as more lease trading takes place.
It may also be possible that utilities will tie down
the most economically recoverable lignite fast enough to leave
fewer, or more expensive reserves for industry use. In order
to satisfy utility demands, the consolidation of lease blocks
into mining units of at least 75 million tons will be important.
Thus, there may be a danger of fragmenting remaining holdings,
which may hamper industry if it enters the picture late.
Adding to the strength of the concern over utility-
industry competition for lignite is the current debate over
interconnecting the present Texas Interconnect System with sur-
rounding interstate grids. Some TIS members, through corporate
linkages with interstate, non-TIS utilities, favor interconnec-
tion, to reduce costs and increase reliability. The Carter
Administration also favors interconnection for the same reasons.
The result of interconnecting the TIS network might be to in-
crease the overall demand for lignite for power generation.
Thus, the longer industry waits to ente.r the game, the
higher the price it may have to pay for the lignite it uses.
The result of paying higher fuel costs may be expected to show
up in product prices. To evaluate whether this effect is large
115
-------
or small, relative to competing industry outside the state, is
beyond the scope of this study.
In all but the low-growth and high-nuclear cases, then,
it appears that there is a good chance that all of the currently
estimated economic reserves of lignite could be committed for
specific uses by the end of the century. It also appears, to
judge by current behavior, that industry may enter the picture
late, with an attendant penalty in the cost of the lignite it
eventually obtains. Both conclusions are significant with re-
spect to developing new technologies for use with lignite.
As has been discussed in the preceding chapter, the
economics of gasification and liquefaction, and of certain ap-
plications of fluidized bed combustion, do not appear favorable
at present compared with conventional combustion. Widespread
application of these technologies is likely therefore to occur
late in the century or into the next. If the economically re-
coverable strippable lignite reserves are committed by then,
these technologies will be forced to use coal. If, on the other
hand, relatively lower-cost lignite were still available by then,
it might reduce product costs and conceivably add to incentives
to bring these technologies on line slightly sooner.* Otherwise,
in-situ gasification is likely to be the only one of the new
technologies with a long-term future using lignite.
3.4 Subregional Breakdown of Lignite Development
Step 4 takes the statewide requirement for lignite
and distributes it among the regions. This is accomplished in
the following manner:
*It should be pointed out that capital costs at present contrib-
ute more than feedstock costs to product price in gasification
Therefore, this effect would not be decisive across the board,
though it might be in individual cases.
116
-------
1. The difference is calculated, at the state
level, between utility and industrial hold-
ings and their projected needs (Nominal Case)
expressed as resource units.
2. All utility use is assumed to be within the
same subregion as the associated lignite
production (mine mouth or near it).
3. The proportion of vendor holdings is calcu-
lated which must be transferred to utilities
to meet the entire requirement.
4. It is assumed that vendor-utility transfers
involve that same portion in each of the
five regions.
5. The subregional transfers are calculated by
multiplying the proportional factor from
(3) by the vendor holdings in each subregion.
All of these steps are performed only for the year 2000. Re-
sults for utilities are truncated to the nearest whole number of
resource units. This method permits generation of power outside
the subregion consuming it, and produces results which reflect
the distribution of lignite. This pattern squares well with an-
nounced plans through 1987.
Industrial demand was derived in a similar fashion, by
first assuming that vendor holdings would be distributed to in-
dustry so as to satisfy industry's requirements in the year 2000
for the Nominal Case. The proportion of vendor holdings was
then applied as an allocation factor to vendor holdings in each
117
-------
region to obtain a measure of resources available to industry
in each subregion.
At this point, the two methods diverged. Industrial
use was assumed to be possible at any point—not only at the
mine mouth. It was also decided to enter two medium-Btu lignite
gasification plants into the scenario, sized at 300 MMBtu per
day. These were arbitrarily sited in the northeast and north
central regions. The commitments required for these plants were
counted as coming from the lignite available to the Gulf Coast
region, reflecting a probable pattern of mine-mouth gasification
and pipelining to coastal industrial centers. The remaining
lignite use was divided among the regions based on their projected
growth in industrial sectors of the economy. Projections made
by the Texas Department of Water Resources of the chemical and
allied industries--the main energy consumers among Texas indus-
tries --we re used as an index.
The final step of the analysis allocates the remaining
solid fossil fuel requirement to coal. For utilities, this is
accomplished by using as an index projections made by the Texas
Department of Water Resources of manufacturing growth. This in-
dex, disaggregated to a subregional level, was thought to reflect
both economic growth and population growth. For industry, the
growth of chemical and allied industry was used as the alloca-
tion index, as was done in allocating lignite use.
Table 3-8 presents, in terms of resource units, the
resulting lignite and coal commitments by subregion. The paren-
thetical number entered for utilities translates these resource
units into 1500-MWe station equivalents.
A comparison of Tables 3-2 and 3-8 shows that indus-
trial demand for lignite matches supplies held more closely
118
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TABLE
3-8. COAL AND LIGNITE COMMITMENTS IN THE YEAR 2000, BY SUBREGION
Coal Utilities
Lignite
Utilities
Coal Industrial
Lignite
Industrial
1985
2000
1985
2000
1985
2000
1985
2000
W
4(1)
12(4)
0
0
.2
1.4
0
2.1
^Entries are in resource units,
a 500 -WMe steam-electric unit.
Numbers
NE
' m
10(3)
32(11)
.1
.7
.5
5.3
equivalent
NC
2(1)
4(1)
7(2)
20(7)
.2
1.3
2
6.2
to a
S
0
0
3(1)
6(2)
0
.2
0
.3
30-year
in parentheses are nearest equivalent to a 1500
C GC
2(1} 4(1}
7(2) 12(4)
1(1) 0
3(1) 1(1)
0 1.5
.2 11.2
0 .5
.4 8.7
Total
14(5)
41(13)
21(7)
62(21)
2
15
3
23
commitment of fuel for
MWe generating
station.
than is the case for utilities. Thus, it seems plausible that,
over the short term, "vendors" may transfer proportionately
more lignite to utilities than to industries. If utility demand
is high, equilibrium prices for lignite (and/or the values of
leases directly transferred) will rise. This may hurt lignite
in competition with coal in areas like the Gulf Coast where lig-
nite transportation is a cost factor. The effect on industry
depends on the speed with which industrial firms enter the mar-
ket. Another potentially significant factor is the high propor-
tion of lignite in the hands of a few firms, as shown in Table
3-9.
TABLE 3-9.
TOP TWO: 2
Utilities 28
Industries 15
Vendors 23
*
Percentage of total acreage
SOURCE: Steele & Associates,
CONCENTRATION OF LEASE OWNERSHIP*
TOP FOUR: Z
Utilities 30
Industries 19
Vendors 30
under lease.
July 1, 1978
TOP SIX *
Utilities 31
Industries 20
Vendors 37
119
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4.0 POLICY ISSUES
Utility Interconnection. Federal policy supports intercon-
nection of the Texas Interconnect System with surrounding
interstate grids. Certain utilities within TIS are plan-
ning lignite-fired plants and interties with the interstate
grid. This trend could increase the demand for the limited
supply of Texas lignite, at the expense of Texas utilities
and ratepayers.
Interconnection potentially offers increased reliability
to participating utilities and reduces inequalities in generating
costs. While these advantages apply over the interconnected system
as a whole, the effects of interconnection may vary among different
components. If transportation economics continue to preclude using
Texas lignite outside the state, then the cost advantages of lig-
nite-fired generation would be limited to utilities in the Texas
Interconnect System. Interconnection would allow these benefits
to be spread over a larger area, but at the cost of reducing the
relative advantage to Texas consumers. In some ways, this paral-
lels the historical regulation of natural gas production and dis-
tribution, which causes some concern in Texas over potential unfair
exploitation of indigenous lignite reserves.
The extent of any such potential inequity depends both
on the extent of interconnection and the relative cost advantage
of lignite versus other fuels for power generation. In new capa-
city, the comparison will be chiefly with coal. Presently, the
costs of generation differ little between coal and lignite. How-
ever, current trends suggest that the price of coal may rise
faster than that of lignite, so that any inequities arising from
interconnection might become more pronounced with time.
Also, since the economically recoverable lignite reserve
is limited, any significant increase in demand arising from inter-
connection would shorten the time frame of resource development
• 01
i-i. L
-------
and depletion. This, in turn, would tend to intensify environ-
mental impacts. As well, it would contribute to the problem of
resource depletion before the next generation of utilization
technologies becomes commercialized.
Rapid Lignite Commitment. It appears that a substantial
portion of the state's strippable lignite reserve may be
committed by 2000, largely to combustion uses. Should
large-scale synthetic fuel production become desirable
after this time, the least costly potential feedstock—
lignite—would no longer be available. A tradeoff there-
fore exists between the short-term benefits of using
lignite as a boiler fuel and having it available in the
future as a feedstock.
Left unhampered, the market system will tend to allo-
cate lignite, as a relatively cheap fuel, to boiler use in the
short term. Since the resource is limited, it can very quickly
be committed to this use. A few decades from now, however, it
may be possible and desirable to commercialize synthetic gas and
liquids technologies, not only for fuels but as chemical feedstocks
as well. The demand for synthetic feedstocks in Texas could be
quite high, if the petrochemicals industry continues to expand.
If lignite is not available, or only the most expensive
reserves remain uncommitted, imported coal will necessarily pro-
vide most of the feedstock. But coal prices are expected to in-
crease steadily, and perhaps markedly, due to a host of factors
affecting the cost of production and transportation.
Thus, it appears that if coal were to provide a greater
part of the fuel mix now, it might be possible to spread the eco-
nomic advantages of lignite over a longer time frame. If the
cost savings realized by using lignite as a feedstock for synthe-
tics were greater than the added expense of using coal now, the
result would be greater economic efficiency in the use of the
lignite reserve.
122
-------
This argument applies to the reserve as a whole, looked
at from the point of view of the whole state's economy. However,
different firms would probably use lignite for synthetic produc-
tion than those which would realize short-term benefits from
using it as boiler fuel now. Therefore, this issue involves a
question of inter-firm equity versus economic efficiency at a
larger scale.
Lignite RD&D Priorities. Given the Nominal Case projec-
tions of demand, most of the state's currently economi-
cally strippable lignite may be committed to specific
projects by the end of this century. If such is the
case, RD&D efforts with regard to technologies which
will not be commercialized within the next two decades
do not appear justified. Key assumptions in the Nominal
Case which affect this conclusion are the economical
depth of surface mining and the utilization of lignite
by the industrial sector.
Because of the finite size of the state's lignite re-
source, lignite RD&D should focus on expansion of the reserve
base and on facilitating the fuel conversion requirements of the
Fuel Use Act. Efforts to expand the reserve base should include
improvements in the efficiency and depth of near surface lignite
recovery and development of technologies that would make the
deep-basin resource available. The greatest uncertainty with
regard to the state's ability to satisfy the state's economic,
environmental and fuel use objectives concurrently is over the
future use of coal and lignite in the major industrial centers
located on the Gulf Coast. Efforts to identify and clarify
regulatory conflicts and to develop economically and environ-
mentally acceptable technologies for industrial lignite use in
the next two decades are needed.
RD&D efforts to develop utilization technologies which
will not be commercially available in the next two decades do
not currently appear cost-effective. Examples of such technologies
123
-------
include liquefaction and chemical processes using lignite-derived
feedstocks. These technologies are currently held back by both
the need for further RD&D and unfavorable economics as compared
to oil and natural gas.
124
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5.0 RECOMMENDED FUTURE RESEARCH
The lignite development scenario derived in this chap-
ter relies of necessity upon a number of assumptions in key
places. The most critical of these are the assumptions of total
available lignite, of a continued 60/40 ratio of lignite to coal
use in all applications throughout the century and the rigid en-
forcement of the Fuel Use Act. Additional research is needed
to make a more refined estimate and to identify those factors
to which these assumptions are most sensitive. Research in the
following topic areas would be particularly useful in providing
needed insights.
Quantitative Analysis of the Relationship of
Recoverable Resource to Price
Geological factors
Equipment and operating costs
Economies of scale
• Labor costs and trends
Reclamation costs
Utility Demand for Lignite
Effects of interconnection on the demand for
lignite
Effects of proposed New Source Performance
Standards for sulfur on relative economics
of coal and lignite: percentage removal
versus sliding scale
125
-------
Industry Demand for Lignite
Specific industrial applications appropriate
for lignite
Applications where lignite is superior or
inferior to coal
Potential use of lignite as a chemical feedstock
Factors constraining the use of coal and lignite
in the industrialized Gulf Coast region
Industry/Utility Competition
Improved characterization of "vendor" category
of leaseholders
Estimates of proportion of lignite held by
utilities and industries that has already been
committed to future uses
Industry and utility perceptions of the future
desirability and availability of lignite
Estimate elasticity of lignite/coal demand
with price for utilities versus industry
126
-------
REFERENCES CITED: CHAPTER II
1. Exxon Company, U.S.A., 1978, Energy Outlook 1978-1990,
Houston, Exxon Company, U.S.A., 18 p.
2. Shell Oil Company, 1978, The National Energy Outlook,
1980-1990, Houston, Shell Oil Company, 21 p.
3. U.S. Department of Energy, Leasing Policy Development
Office, June, 1978, Federal Coal Leasing and 1985 and
1990 Regional Coal Production Forecasts, Washington,
D.C., U.S.D.O.E., 103 p.
4. Perkins, J.M., and J.T. Lonsdale, 1955, Mineral Re-
sources of the Texas Coastal Plain, Preliminary Report,
Bureau of Economic Geology, The University of Texas at
Austin, Mineral Res. Circular 38, 65 p.
5. Kaiser, W.R., 1974, Texas Lignite: Near-Surface and
Deep-Basin Lignite Resources, Bureau of Economic Geology,
The University of Texas at Austin, Report of Investiga-
tions 79, 70 p.
6. Kaiser, W.R., 1978, Electric Power Generation from Texas
Lignite, Bureau of Economic Geology, The University of
Texas at Austin, Geological Circular 78-3, v + 17 pp.
7. W.R. Kaiser, personal communication, January, 1979.
8. Dickerman, J.C., W.R. Menzies, andM.D. Matson, 1978,
Direct Combustion of Coal for Steam and Power Generation:
A Technical and Economic Analysis of Coal Selection.
Paper presented at the International Coal Utilization
Conference and Exhibition, Houston, Texas, October 17-19,
1978.
9. E.P.A. Electric Utility Steam Generating Units: Pro-
posed Standards of Performance, Fed. Reg., 43:42154-
42184, September 19, 1978, Part V~
10. Phillips Coal Company, 1977, Texas Lignite, Dallas,
Phillips Coal Company, 40 p.
11. Coal Outlook, November 6, 1978.
12. Chemical Week, March 29, 1978.
13. Austin American Statesman, November 1, 1978.
127
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14. E.P.A. Office of Research and Development, Internal
Memorandum, July 18, 1978, Lowell Smith to Dave Hawkins,
Asst. Admin, for Air and Waste Management.
15. W.R. Kaiser, personal communication, September 6, 1978.
128
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CHAPTER III: SITING CONSTRAINTS
Abstract
This chapter considers factors which may affect sit-
ing the energy facilities called for in the development sce-
nario, and specifically considers the availability of an
adequate number of power plant sites. Six potentially con-
straining factors, reflected in the cost and difficulty of
permitting a new 1500-MWe station, are evaluated. A series
of maps is developed, showing how these factors vary across
the study area. A composite site-suitability map, based on
these factors, weighted according to perceived importance
is generated. This map indicates that future siting may be
most difficult and costly along the Gulf Coast, and least
constrained near the Lignite Belt. It is not expected that
any or all of these constraints would preclude developing
all the facilities called for by the scenario in each sub-
region, although they may tend to "herd" them somewhat.
Because industrial uses of coal and lignite are varied both
in size and locational constraints, it was not feasible to
perform a similar evaluation for them. An overview of fac-
tors affecting industrial siting in the study area is given.
In the light of the power plant siting exercise, it is not
expected that industrial growth will be hampered by siting
constraints. Some conflict with utilities, however, espe-
cially over emissions permitting, may be inevitable.
129
-------
-------
1.0 INTRODUCTION AND OVERVIEW
The scenario developed in the preceding chapter al-
locates a certain number of lignite- and coal-fired power
plants to each of five subregions in the eastern half of the
state (see Figure 1-1). Lignite production for industrial con-
sumption is also included. The principal questions raised by
this scenario are whether all the required facilities could
actually be sited in the appropriate subregions, given certain
constraints, and what factors can be anticipated to constrain
siting the projected number of facilities.
In practice, site selection includes a large number of
factors specific to the project, including the firm's economic
position, availability and cost of land, proximity to markets,
transportation links, labor supply, other natural resources, the
personal preferences of the decision makers, and the political/
legal context of the jurisdiction. Certain factors, however,
must be considered in all siting decisions, and can be studied
to gain insights into potential siting constraints on a regional
basis. In the analysis which follows, siting factors are evalu-
ated which have a direct impact on the cost of construction and
operation, on the availability of sites, and on the likelihood
of delay or difficulty in the permitting process. These in-
clude :
water availability,
ambient air quality with respect to allowable
deterioration,
flood prone areas,
extraterritorial jurisdictions of communities,
131
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EXISTING AND ANNOUNCED
COAL(V)AND LIGNITE (•) FIRED
ELECTRIC GENERATING STATIONS
02-4309-1
Figure 1-1. Study Area Subregions Showing
Existing and Planned Power Plants.
132
-------
foundation suitability, and
distance from lignite deposits.
Other factors, such as aesthetic considerations and
public willingness to accept a large project, are also important
concerns. However, their costs are not yet formally internalized,
and the importance given them will vary considerably from case
to case. Since the purpose of the present exercise is to evalu-
ate the factors which will influence siting choices, not those
which possibly should, only those factors universally affecting
costs, site availability and permittability were included.
The siting analysis which forms the bulk of this
Chapter focuses primarily on power plants, and to a lesser degree
on surface mines, but does not attempt to deal specifically
with industrial uses of lignite. Utility boilers will in gen-
eral tend to be much larger than industrial boilers, and thus
more subject to certain constraints such as air quality and
water availability. Also, they can be postulated to be of a
uniform size for purposes of analysis, so that the total number
of facilities to be sited can be derived. Industrial boilers
may vary greatly in size, and thi-s, along with the complexity of
the industries potentially using coal, makes it difficult to
identify a realistic "standard" size, or to estimate the total
number of lignite-fired industrial plants in individual regions.
Even greater uncertainty attaches to the nature and
strength of the forces which drive industrial siting patterns.
These forces, and their relationships, could easily be the sub-
ject of an entire study in themselves. A summary of current
attitudes and thinking about industrial growth -in the Lignite
Belt is presented as the first section of the Chapter.
133
-------
The following sections present the study team's eval-
uation of the geographical distribution, and significance to
power plant development, of the six types of constraints listed
above. A map accompanies each section.
To arrive at a composite evaluation of the cumulative
effects of all the constraints examined, a computer program was
used which divided the study area into a grid of 20-kilometer
squares. Each constraining factor was given a weight, according
to the comparative degree of constraint it presented, and the
maps converted to digital form. The sum of the weighted values
for all factors was determined for each grid square and the re-
sults plotted on a map (Figure 4-1).
134
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2.0
POTENTIAL PATTERNS OF INDUSTRIAL SITING IN THE
LIGNITE BELT
Summary and Conclusions
Current trends indicate that new growth may be
attracted to smaller metropolitan areas, rather
than large existing centers.
Industrial or energy parks would probably be
favored by cogeneration.
Although lignite is relatively cheap at the mine
mouth, this advantage may be outweighed, at least
for the petrochemicals industry, by the economic
benefits of siting near existing industrial com-
plexes.
Increased pressures from mandatory boiler-fuel
conversion, clean-air policies, and difficulties
of obtaining water supplies may drive some new
industrial growth away from the Gulf Coast.
Lignite-generated electricity, if cheap and
plentiful, might attract heavy energy-consuming
industry, but siting would be dispersed through-
out the appropriate service territories, not con-
centrated on the Lignite Belt proper.
Gasification plants, which emit hydrocarbons,
might encounter siting difficulties because of
high ambient ozone levels.
Currently, there is too little concrete industrial
siting activity in the Lignite Belt to identify
a trend.
It is assumed for purposes of this study that the
Lignite Belt .will not become an area of concen-
trated industrial growth.
135
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Figure 2-1 shows the position of major industrial
growth centers of the next two decades, relative to the Lignite
Belt. Also shown are announced new coal- and lignite-fired
power plants. While economics clearly favor mine-mouth siting
for utilities using lignite, the siting priorities for indus-
tries are not nearly as clearcut. The amount of industrial
lignite use taking place on the Lignite Belt itself is signifi-
cant both in terms of its immediate impact, as well as on com-
petition with utilities for sites in favorable areas. A wide
variety of opinions have been expressed concerning possible
lignite-related industrial expansion along the Lignite Belt.
Fred Benson, Vice President of Engineering at Texas A&M
and head of its Civil Engineering Department, has projected
that lignite development will make parts of Texas resemble
Germany's Ruhr Valley or England's industrial midlands. Other
observers suggest that it is too early to discern a significant
trend in industrial locations.1 The following discussion sets
forth the principal factors that militate both for and against
a concentration of industrial growth localized along the Lignite
Belt, as the study team perceives them.
2.1 Socioeconomic Background of the Lignite Belt
At present, the Lignite Belt and its surrounding re-
gion is comparatively sparse in population, without major
metropolitan centers. Employment in manufacturing (SIC cate-
gories 19-39) is low, and excess labor migrated out of the area
in the 1950's and 1960's.2 The Tyler-Longview-Marshall district,
however, stands out as a rising metropolitan area with a more
diversified industrial base and higher manufacturing employment
than the rest of the region.
136
-------
PERCENT OF TOTAL MANUFACTURING
GROWTH IN STUDY AREA THROUGH 2000
D
.0-.4
.5-.9
1.0-2.9
3.0-
02-4324-1
Figure 2-1. Growth Centers in Relation to Lignite Deposits
137
-------
Without lignite, it would be expected that growth would
occur first in those counties which are immediately adjacent to
existing metropolitan counties.3 Current trends indicate that
smaller metropolitan areas, rather than large existing centers,
may be the growth areas of the future.2
Transportation is a key factor in industrial location.
The Lignite Belt is not well connected with the rest of the state
by major highways. This area is well served by railroads, however.
The Missouri-Pacific's main line runs roughly parallel with the
entire lignite trend, and is crossed by numerous other main or
secondary lines. Not only are there several available rail ship-
ment routes crossing the Lignite Belt, these routes are owned by
different railroad companies, encouraging competition in freight
rate and services. A drawback to rail service, however, is the
separation of the Lignite Belt from the Gulf industrial centers
by a broad band, just inland from the coast, in which there are
few rail lines. Thus, the Lignite Belt is better connected to
the north and east than to the south.
2.2 Regional Factors Affecting Industrial Siting
on the Lignite Belt
Table 2-1 summarizes the major pro's and con's regard-
ing industrialization along the Lignite Belt. The table, and
the following discussion, are based on telephone and personal
interviews with personnel of the Texas Industrial Commission and
local Chambers of Commerce, along with insights developed at
Radian in the process of conducting specific studies for its
industrial clients.
138
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TABLE 2-1. INDUSTRIALIZATION OF THE LIGNITE BELT:
PRO'S AND CON'S
Pro
• Availability of reliable
electric power, greater
certainty of price.
• Air quality constraints on
coastal siting, coupled
with gas cutback and in-
creasing difficulty of
obtaining water supplies.
• Lignite's main economic
advantage is at the mine
mouth.
• Economies of scale might
make siting secondary
chemical plants near large
gasification plants
desirable.
Con
• Economics of agglomeration
along the Gulf Coast vs
limited skilled labor, infra-
structural gaps on Lignite
Belt.
• Rail shipment of lignite to
Gulf Coast may be increasingly
cost-effective; this would
tend to reduce economic draw-
backs of coastal siting.
• Community desires for clean
industry.
• Possible PSD limitations and
siting conflicts.
• Difficulty obtaining offsets
along Lignite Belt, if moni-
toring shows widespread
"baseline" violation of ozone
standard.
Industry uncertainty over
regulatory postures, leading
to hesitation over new
ventures .
2.2.1
Cogeneration
Considering all these factors, it appears that concen-
trated development, involving several heavy industrial installa-
tions within a few miles of one another, would be favored by co-
generation. Cogeneration would help to make industrial parks
more feasible under PSD, as well as adding to the economic ad-
vantage of mine-mouth location. Thus, it is possible to envision
combined power plants and electricity-intensive industries, such
139
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as steel plants, using cogeneration. Similarly, it is possible
to imagine large gasification plants with associated chemical
plants, provided that their hydrocarbon emissions do not inter-
fere with ozone standards. However, although complexes such as
these might conceivably be built and operated within environ-
mental limitations, very complex economic considerations unique
to individual firms are also involved. It is beyond the scope
of this study to examine any of these economic variables.
2.2.2 Fuel Cost
The most obvious advantage of the Lignite Belt for in-
dustrial siting is the much lower cost of lignite at the mine
mouth. Currently, lignite shipped by rail to the Gulf Coast
from East Texas would be worth almost exactly as much per mil-
lion Btu's delivered as western coal and Illinois coal.1* Using
lignite at the mine mouth would reduce this cost by about a
quarter. This advantage, as shown in Chapter II, is a major
factor in expected heavy use of lignite by utilities at the mine
mouth. While industrial facilities could do the same, it seems
to be generally felt that lignite's real economic drawing card
is the perceived reliability and cheapness of electric power
generated by utilities with a long-term supply firmly committed.
Dr. Benson5 sees plentiful electricity as having the power to
attract big power consumers such as carbon-arc steel manufacturing
aluminum refining, and other heavy industry. This view is
shared by many Chambers of Commerce. Such a trend, however,
would be more likely to be spread throughout the service ter-
ritories of utilities with long-term lignite supplies than con-
centrated near the lignite itself.
140
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2.2.3 Coastal Environmental and Resource Constraints
Currently, stringent air quality requirements, coupled
with mandatory boiler-fuel conversion, are seen by many as a
potentially serious constraint on future industrial growth.*
Not only are many areas currently out of compliance with ozone
standards, but recent efforts to obtain permits have revealed
that the PSD increment for S02 in many places is partially or
completely consumed. Thus, future siting will require offsets.
The situation is complicated by the requirement contained in the
National Energy Act for new facilities to shift from oil and
gas toward coal.**
The extent of these limitations is imperfectly known
to date because of limited monitoring. As PSD permits are sought
for new sources, required background monitoring will reveal how
widespread these problems are.
The potential power of this situation to induce new
industrial facilities to locate away from the industrialized
coastal zone depends on several factors which cannot yet be
evaluated:
Geographic extent of nonattainment of ozone
standards and unavailability of PSD increment;
*See Chapter I, Section 2.1 for a discussion of this view, and
Chapter V, Section 2.2, for an analysis of policies surround-
ing the issue.
**For a complete discussion of the mandatory boiler-fuel conver-
sion provisions of this Act, and Texas' own regulations, see
Chapter I, and Chapter V. This chapter assumes the reader is
familiar with these policies.
141
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Long-term availability of offsets in indus-
trial zones; and
Administration of exemptions from mandatory
boiler-fuel conversion.
It should also be pointed out that industries locating away from
existing centers would not necessarily move inland as far as the
Lignite Belt. Particularly for refineries dependent on access
to ocean shipping, Mexico might prove an attractive alternative,
especially if large quantities of Mexican natural gas become
available.6
In addition to air-quality constraints, water supply
may place increasing difficulties on siting new industrial
facilities in the coastal basins. As is discussed at greater
length in Section 3.1, below, these basins are among the most
strained in the state.
2.2.4 Prevention of Significant Deterioration (PSD)
Prevention of Significant Deterioration (PSD) regula-
tions can also be cited as a possible constraint to siting in-
dustrial facilities on the Lignite Belt proper. PSD limits the
number of sites along the Lignite Belt that may be occupied by
sources meeting proposed New Source Performance Standards. In
Section 3.2 below, it will be shown that several new plants, not
subject to these standards, as well as existing facilities not
subject to PSD, will consume all or part of the increment for
SOa over large sections of the North Central and Northeast
Subregions--the richest in lignite reserves. These areas are
also projected to experience the largest growth in both coal and
mine mouth lignite power generation. Thus, by the turn of the
142
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century, offsets might be needed to site industrial facilities
at the mine mouth or near it.
Potentially significant over a broader area than the
Lignite Belt proper would be a need to obtain offsets for hydro-
carbons. If, as some believe, oxidant standards are already
widely violated in East Texas, refineries, petrochemical plants,
or gasification plants might require offsets. It might be
easier to obtain offsets in the industrialized coastal zone
than in the relatively undeveloped areas near the Lignite Belt.
Such a constraint would considerably reduce the attractiveness
of siting new facilities inland from the coast. The choice of
location, other factors being equal, would involve a tradeoff
between the cost of offsets on the coast and strict emission
control inland.
2.2:5 Gasification
If natural gas supplies continue to be restricted,
and mandatory boiler-fuel conversion is strictly enforced,
gasification could gain attractiveness as a means of burning
coal or lignite cleanly in existing industrialized areas. Econ-
omies of scale favor large installations of 300 billion Btu/day
or more for medium-Btu gas. Based on the comparative cost of
shipping lignite versus medium-Btu gas, these plants may be most
economically sited at the mine mouth, all other factors being
equal. Plants this size might also justify co-location of
certain chemical industries as well. For example, methanol and
ammonia can be synthesized directly from low- or medium-Btu gas
made from lignite. These two chemicals made up 25 percent of
the output of Texas' chemical industry in 1975.3
143
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Gasification plants might also prove difficult to site
near the coast because of their air quality impacts. Large gasi-
fication plants could emit substantial amounts of fugitive hydro-
carbons under normal operating conditions. Upset and start-up
conditions might also result in significant short-term emissions.
Currently, EPA favors hydrocarbon control as a major strategy to
control the formation of ozone, of which many hydrocarbons are
precursors.7 The availability of offsets for a large new gasi-
fication plant might also become more of a problem as time
passes. Long lead times for planning and financing would there-
fore increase the difficulty of finding coastal sites.
2.2.6 Infras tructure
One major drawback to industrial location along the
Lignite Belt is its current lack of the kind of infrastructure
found on the coast: large labor pools, a good rail network,
and supporting industries and facilities. The affinity for
areas with a well developed infrastructure is especially high
in the chemical industry, which forms a highly interdependent
complex. Labor supply is low in the Lignite Belt. A strong
demand for additional workers would soon bring a response of in-
migration, and large new industrial developments near communities
already experiencing growth from utility exploitation of lignite
could seriously overtax local government services and facilities.
A possible alternative to industrial siting on the
Lignite Belt proper would be a trend toward siting at inter-
mediate locations, closer to the industrially developed areas
of the Gulf. However, as mentioned above, rail service in the
area between the coast and the Lignite Belt is poor. At the
same time, continued rapid rises in interstate rail tariffs on
coal may make shipment of lignite to the coast more economically
attractive.*
*For a more complete discussion of rail tariffs, see Chapter II,
Section 2.2.
144
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2.2.7 Community Attitudes
Another possibly influential factor is the desire of
some—but not all—communities to attract only "clean" industry.
As lignite development impacts begin to be widely experienced,
it is possible that this feeling may grow in intensity. As one
Chamber of Commerce representative put it, "We're selling life-
style here."
2.2.8 Availability of Oil and Gas
Finally, uncertainty over future availability of
natural gas and oil can be expected to discourage any major
siting trend in response to lignite. The current oversupply of
natural gas is apparently widely perceived as a sign of things
to come, at least in the short term. With large supplies of
both domestic and foreign gas recently discovered, there is no
widespread impetus to consider looking away from existing in-
dustrial centers. Such a move would be very risky in the face
of potential new gas supplies becoming available.
2. 3 Current Activity
At the present time, although many firms and more
promoters are talking about future industrial growth along the
Lignite Belt, there is too little concrete activity to identify
a definite trend. Pulp and paper companies could use lignite,
and one firm owns substantial acreage underlain by lignite. Most
of the major chemical firms are investigating lignite, although
few have made specific plans to use it at or near the mine.
Texas Utilities has a Soviet in-situ gasification process under
study. One Chamber of Commerce executive indicated that an
industrial firm had expressed an interest in using lignite at
145
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the mine mouth as a boiler fuel. To our knowledge, however, no
major mine-mouth industrial user has yet entered the permit-
application stage.
2.4 Conclusion
For purposes of subsequent impact analysis, it has
been assumed that lignite development does not include a major
shift of industrial growth into areas near the Lignite Belt
itself.
146
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3.0 ANALYSIS OF CONSTRAINTS ON POWER PLANT SITING
""" -..——•- __ - -Jy. - J
The following sections present detailed discussions of
the constraints placed upon power plant siting by water supply,
air quality, flood-prone areas, the extra-territorial jurisdic-
tions of cities and towns, geological factors, and distance
from lignite deposits.
These factors impose costs directly, by constraining
design and operation, the cost of sites, and the cost of raw
materials. Delays induced by controversies over permits or
water rights also add to the cost of siting. These factors may
thus be said to have been internalized into the cost of building
and operating a power plant, and affect the costs incurred by
all potential developers.
The siting analysis conducted here is not an attempt
to predict where plants will be sited. Rather, it is intended
to show geographic variation in the degree of difficulty--
measured in terms of costs and delays in permitting--likely to
be encountered by a utility attempting to site a large, new
generating station. Though developed specifically with lignite-
fired plants in mind, essentially the same pattern of constraints
applies to coal-fired plants. Removing the distance-from-lignite
factor from the analysis does not materially alter the final
pattern.
147
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3.1
Water Availability as a Constraining Factor
Summary of Conclusions
Calculations were made of aggregate water supply and
demand by study-area subregion, based on planning
data published by the Texas Department of Water Re-
sources. Supply data included both existing and pro-
jected surface water development, as well as maximum
potential use of groundwater. Demand figures used by
TDWR were adjusted by substituting figures for energy-
related demand appropriate to the development scenario
of Chapter II.
Based on these data, it appears that, considering
supply and demand in the aggregate at the subregional
level, more than enough water can be developed to
supply the needs of the scenario along with other
demands.
New surface developments are critical to future ade-
quacy of supply. Without them, supply deficits could
develop by the year 2000 over most of the basins in
the Southern and Central Subregions, as well as in
the Trinity and the Brazos basins.*
The process of increasing water consumption for
energy development is likely to result in heavier
demands on groundwater, both from direct use by en-
ergy and from displacement of surface water demand.
Two potentially important demands on the study area's
developable water supplies are not presently quanti-
fiable. These are: freshwater inflows for bays and
estuaries, as required by law; and future supplements
to the dwindling groundwater supplies of the irrigated
High Plains.
*Although apparent surpluses would remain in the Brazos basin, commitments by
existing contract or water rights to coastal users would exceed these sur-
pluses if all projected water projects are not built in a timely manner.
148
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3.1.1 Selection of Data Base
In studies such as this, where the range and scope of
various issues can become quite extensive, the data base used
in the analysis should meet certain criteria in order to be ac-
ceptable. The criteria are completeness, consistency, accuracy,
objectivity, and applicability. For the purposes of this tech-
nology assessment, water resources data compiled by the Texas
Department of Water Resources met these criteria. In Section
3.1.6, below, comparisons are made with other published studies
of water and energy.
As part of an ongoing process to update and revise the
Texas Water Plan, the Department published a comprehensive two-
volume report presenting an analysis of current water develop-
ment and use in Texas along with projections of future water
needs. The report, entitled Continuing Water Resources and
Development for Texas,8"...identifies major water and water-
related problems... actions currently underway to provide for
part of Texas1 present and future water needs, and presents a
preliminary draft plan of development ... for meeting water sup-
ply and water-related needs in parts of the State through the
year 2000."
3.1.1.1 Water Supply Data
The supply figures developed by the TDWR represent
total amounts from three components: surface water, ground-
water, and return flows. The surface-water component consists
of the safe yield from existing and proposed reservoirs. The
groundwater component consists of an amount equal to an aquifer's
recharge rate plus an annual depletion rate based on that aqui-
fer's recoverable storage volume (safe yield). Return flow
represents that volume of water which is returned to surface
waters after use.
149
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One portion of the supply component, that amount from
proposed reservoirs, is critical to subsequent sections of this
analysis. If these reservoirs are not built, or if the con-
struction of key reservoirs is delayed, then the water surpluses
in certain basins would be greatly diminished or eliminated
completely. The lead time for the construction of some of these
reservoirs can easily take 10 to 15 years, depending on funding
and possible opposition. The importance of this issue is ad-
dressed in more detail in Section 3.1.7 below.
In the following analysis, no constraints have been
placed on water use relative to the quality of available water
supplies. It is assumed that if the water is physically avail-
able, the water will be of sufficient quality to meet all needs.
While this assumption may not be valid on a site-specific basis,
it is generally valid given the existing quality of Texas'
waters and the existing regulatory framework.
3.1.1.2 Water Demand Data
The primary components of water demand used by TDWR
are municipal, manufacturing, steam-electric power generation,
and irrigation. Municipal demand consists of the total amount
of water distributed to a municipality, less any water sold to
industries for use, and is based on population projections.
Figures for manufacturing use are projected based on 1974 base-
year demands by industry and include corrections for employment,
labor productivity, recirculation practices, and technology changes
TDWR steam-electric power generation figures for
water demand are based on "actual plant design data" assuming
that future additions to the system consist of equal proportions
of nuclear and coal/lignite generation. Since 1974, a series
of nuclear power plant cancellations has taken place, which makes
150
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this assumption appear too favorable to nuclear power. The TDWR
steam-electric stations have accordingly been replaced by figures
developed to match the assumptions of the lignite demand scenario
Irrigation demands represent water drawn off for non-
project irrigation. Thus, demand is a measure of required
throughput, rather than consumptive use alone.
3.1.1.3 Typical Basin Figures
An example of the type of information used in the fol-
lowing analysis is given in Table 3-1, a supply/demand analysis
for the Neches River Basin.
For the lignite development analysis, basin figures
were recompiled according to the five subregions shown in
TABLE 3-1. WATER SUPPLY AND DEMAND SUMMARY ANALYSIS, IN THOUSANDS
OF ACRE-FEET, NECHES RIVER BASIN*
Supply and
2000
Projected Demand Groundwater Surface Water
BASIN SUMMARY
Firm Supply
Import
Return Flows
TOTAL SUPPLY
In-Basln Demand
Export
SUBTOTAL DEMAND
Surplus/Shortage—
Project Irrigation
Demand
Surplus/Shortage—
I/ - Requirements exclude
supplies.
78.3 1227.1
-0- 5.7
-0- 146.3
78.3 1429.1
78.3 357. 6-'
-0- 430.3
78.3 787.9
-0- 641.2
-0- -0-
-0- 641.2
mining and livestock needs
Total
1355.4
5.7
146.3
1507.4
435.9
430.3
866.2
641.2
-0-
641.2
, which
Groundwater
92.5
-0-
-0-
92.6
92.6
92.6
-0-
-0-
-0-
can be met from
2030
Surface Water
1921.2-'
11.2
418.9
2351.3
816.7i'
517.6
1334.3
1017.0
-0-
1017.0
Total
.2013.8
11.2
418.9
2443.9
909.3
517.6
1426.9
1017.0
-0-
1017.0
local, unregulated
21 - Shortages are indicated by parentheses.
31 - Firm supply Includes
incremental yield of authorized Rockland Reservoir.
*From Continuing Water Resources Planning and Developments
for Texas.8
151
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Figure 1-1. This recompilation tends to average out some of the
local variations in water supply and demand.
3.1.2 Analysis by Region (Recompilation of TDWR
Estimates by Study Region)
3.1.2.1 Regional Supply and Demand
Based on the recompilation of TDWR estimates of water
supply and demand by subregion, each subregion of the study
area is projected to have a surplus of water in the year 2000,
even after water for power production is accounted for. This
analysis is shown in Table 3-2. The subregion with the greatest
surplus based on this analysis is the Northeast, with 1,270
TABLE 3-2. TDWR SUPPLY-DEMAND FOR THE YEAR 2000,
SHOWING NON-FIRM SUPPLY
(Units are thousands of acre-feet per year)
Subregion
Supply
Demand
Surplus
"Non-Firm
Supply"*
Ratio of
NF Supply
To Surplus
Northeast
North Central
Central
Southern
Gulf Coast
Totals
2,264
2,582
1,950
858
7.732
15,386
993
1,931
1,698
694
6,965
12,281
1,270
651**
252
164
350t
2,687
398
335
246
477
103
1,559
.31
.51
.98
2.91
.29
.58
*"Non-firm supply" consists of water from reservoirs that have been pro-
posed, but not yet built. Any delay or cancellation of such plans would
affect this analysis.
**Approximately 586 thousand acre-feet per year of this surplus must be
passed through to the Gulf Coast Subregion to satisfy existing water
rights and contracts.
tSurplus may be greater than figure shown due to municipal return flows,
and water pasaed through from the North Central Subregion.
152
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thousand acre-feet per year surplus water remaining from a
supply'of 2,264 and demand of 993 thousand acre-feet per year.
The smallest surplus projected occurs in the Southern Subregion
and is 164 thousand acre-feet per year. The surplus for the
Gulf Coast Subregion may be greater than the 350 thousand acre-
feet per year indicated, because of municipal return flows not
included in the TDWR analysis, and because of contracted sur-
plus water from the North Central Subregion.
The distribution of water supplies is only considered,
in this analysis, on a subregional basis. In the Gulf Coast
Subregion, most of the supply comes from the eastern coastal
basins. In order to distribute this supply throughout the sub-
region, some means of conveyance would be necessary. A major
east-to-west distribution system has been proposed, but no firm
plans have been made.
3.1.2.2 "Non-Firm" Supply
Also shown in Table 3-2 is that portion of water sup-
ply projected for each area which is comprised of water from
reservoirs that have been proposed but not yet built. This "non-
firm" supply can be quite significant, as illustrated by an exam-
ination of the supply/demand figures for the Southern Subregion.
Of the 858 thousand acre-feet per year (TAF/y) in projected
water supply, 477 TAF/y are from reservoirs not yet built. Ob-
viously, any cancellation, interruption, or delay in the con-
struction of these reservoirs would significantly alter the
long-term supply/demand picture for the subregion. Even in the
subregion least dependent on this non-firm supply, the Gulf
Coast, 29 percent of the surplus of 350 TAF/y, or 103 TAF/y,
consists of non-firm sources of supply.
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3.1.3
Revised Steam-Electric Water Demand Figures
The water demand estimates in Table 3-3 show consump-
tive water demand figures for the various energy facilities con-
sidered in the development scenario. These figures do not in-
clude water that is taken in, used, and released again. Through-
put varies with plant design. In general, the need to clean up
waste streams has led to a trend toward recycling them for in-
plant use. Thus total water withdrawals for new plants are
tending to go down, with consumptive use a greater portion of
the whole. While there are significant regional and technologi-
cal variables which ultimately determine the amount of water
consumed by any given power plant or mine/plant complex, these
figures are reasonable estimates for the purposes of this
analysis.
TABLE 3-3. TYPICAL
Technology
Lignite Mine & Power Plant
Coal-Fired Power Plant
Nuclear Power Plant
Medium-Btu Gasification
PLANT WATER
Size
500 MWe
1,500 MWe
500 MWe
1,500 MWe
500 MWe
2,000 MWe
0.2 Quads
REQUIREMENTS
Water Demand
AF/y*
(unit) 7,815
(plant) 23,450
7,567
22,700
9,625
38,500
18,400
*Acre-feet per year, estimates by Radian staff.
The consumptive water demand figures for the lignite
mine and power plant configuration include mine-related demands,
cooling, and make-up water at the power plant. The coal and
nuclear demand figures include cooling and make-up estimates,
154
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while the medium-Btu gasification figures include all uses. In
the case of a mine-mouth, lignite-fired power plant, more than
80 percent of the water consumed is required for power plant
cooling.
These technology-based water demand estimates were
matched with projected steam-electric demand figures for each
study region to produce a new subregional analysis of water
demand as indicated in Table 3-4. These new demand figures re-
place those developed by TDWR.
TABLE 3-4. YEAR-2000 STEAM-ELECTRIC WATER DEMAND ESTIMATES BY SUBREGION
Subregion
Northeast
North Central
Central
Southern
Gulf Coast
Totals
Number
Coal
6
4
7
0
12
29
of 500 MWe
Lignite
32
20
3
6
1
62
Units
Nuclear
0
0
4.6
0
6.9
11.5
Medium-Btu
Gasification
Quads
.2
.2
0
0
0
.4
Water Demand
TAF/y*
314
205
121
47
165
852
*Thousand acre-feet per year.
The Northeast Subregion has the greatest projected
need for water to satisfy future energy demands, with a 314
TAF/y consumptive water demand. Next greatest in terms of water
demand is the North Central Subregion, with a projected water
demand of 205 TAF/y, followed by the Gulf Coast, Central, and
lastly the Southern Subregion.
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3.1.4
Updated Water Supply/Demand Analysis
The new estimates of steam-electric water demand,
when substituted for the 1974 TDWR figures, yield the analysis
shown in Table 3-5. On a state-wide basis, the two estimates of
year-2000 steam-electric water demand are quite close. In 1974,
the TDWR, then the Texas Water Development Board, projected a
year-2000 steam-electric water demand of 909 TAF/y statewide.
This is in substantial agreement with the 852 TAF/y estimate
generated by the revised analysis. On a subregional basis,
however, some differences do occur. The siting analysis figures
indicate a shift in steam-electric water demand from the Central
and Gulf Coast Subregions to the Northeast. This is illustrated
by the significant decrease in water demand in these two sub-
regions and the increase in water demand from 159 to 314 TAF/y
in the Northeast Subregion. The projected water surplus figures
do not differ significantly in the two analyses, with the largest
differences occurring in the subregions with the largest sur-
pluses.
TABLE 3-5. YEAR-2000 STEAM-ELECTRIC WATER SUPPLY/
DEMAND ESTIMATES BY SUBREGION, TAF/y*
Subregion
Northeast
TDWR
Surplus
1,270
North Central 651**
Central
Southern
Gulf Coast
Totals
*Thousand
**Existing
be passed
252
164
350
2,687
acre-feet per year.
contracts and water
through to the Gulf
TDWR
Steam-Electric
Demand
159
281
214
41
214
909
rights require that
Coast Subregion.
Revised
Surplus
1,115
727**
345
158
399
2,744
Revised
Steam-Electric
Demand
314
205
121
47
165
852
586 TAF/y of this surplus
156
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The conclusion to be drawn from this analysis is,
therefore, that surface and ground water supplies more than
sufficient to meet the year-2000 consumptive water demand of the
development scenario can be made available at the subregional
level. This means that if planned and proposed water projects
are implemented in a timely manner, the aggregated supply in
each subregion should be enough to meet all projected aggregated
needs, including consumptive water use for energy.
The word, "aggregated" is important, however. Con-
sidering water supply and demand at the level of the subregion
necessarily assumes that there is no insurmountable problem of
distribution within the subregion; in other words, that water
is either fairly equally available everywhere within it, or can
be made so without undue expense or difficulty. This assump-
tion, although needed to simplify the analysis, is not equally
valid for all subregions. In particular, the Gulf Coast Sub-
region's surplus is mainly in the northeastern portion of the
subregion; extensive diversion works would be needed to dis-
tribute this surplus through the entire subregion. In order
to obtain a better focus upon such geographical discontinuities,
supply was reconsidered at the level of river basins and sub-
basins.
3.1.5 Water Supply and Siting
In the case of an actual proposed power plant, de-
tailed engineering studies would be made concerning the avail-
ability of a suitable water supply. These studies would ex-
amine the amounts of water available, the "timing" of this
availability, the question of water rights, and engineering
options for optimizing the water system selected. Such detailed
157
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studies are beyond the scope of this present study, but an ef-
fort was made to look at water as a constraint on a subbasin
basis. The following method was used in this analysis:
Using TDWR data base values for the year-
2000, compute the following by subbasin:
Total Supply = Supply - (Demand + Steam-Electric Demand)
Area of the Subbasin
TT o T ™ j Total Supply (TAF/y)
Water Supply Density = f-,nn 7T\"
Area (100 sq. miles)
Map the values by subbasin and water supply
density based on the following arbitrary criteria:
£0, £0.5, £1.0, and £l.O
The results of this analysis are shown in Figure 3-1.
The selection of the mapping units is somewhat arbitrary and
meaningful to the extent that it allows a comparison of water
supply amounts on a subregional basis.
3.1.6 Comparison with Other Studies
Several recent studies at the national level have
focused attention on the potential conflict of energy develop-
ment with water supply. The National Academy of Sciences' Com-
mittee on Nuclear and Alternative Energy Strategies has recently
completed studies which conclude that "there is a high probabil-
ity that freshwater supplies will significantly constrain the
158
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n
WATER
AVAILABILITY
THOU. ACR6-FT/YR PER
HUNDRED SO. MILES
10
iO.5
£ 1.0
< 1.0 (ASSUMED)
> 1.0
Significant amounts of water are
commitad to downstream users.
WATER AVAILABILITY AS A CONSTRAINING
FACTOR IN SITING
Fig. 3-1 02-4305-1
159
-------
growth of energy in the U.S."9 Oak Ridge National Laboratory
reached a similar conclusion in an evaluation of the effects of
the proposed National Energy Plan.10 Figure 3-2 shows where
this study projects water supply problems in 1985, considering
demands from all sectors. Over most of Texas, this study shows
that potentially all or nearly all of the "Critical Surface
Supply" could be consumed even at this early date. The situation
in the year 2000 would be even more serious. Yet another nation-
wide survey of surface water supply and demand, conducted for the
Utility Water Act Group (UWAG) by Espey, Huston and Associates,
Inc.11, reached the conclusion that demand for water currently
exceeds "dependable" surface water supply over most of Texas.
At first glance, these studies appear to contradict
the conclusions drawn here, on the basis of planning informa-
tion developed by the Texas Department of Water Resources.
These studies, however, used very different methods of cal-
culating "supply," which resulted in substantially lower esti-
mates than those in the basin-by-basin studies reported by TDWR.
Also, none of them attempted to account for new surface water
supply development or transfers within and between basins, a
very substantial consideration in TDWR's figures.
CONAES, Oak Ridge, and Espey, Huston all calculated
supply as some proportion of low flow, averaged over large
areas. CONAES based their estimates on 7-day, 10-year low
flow and evaluated potential water consumption from energy de-
velopment as a fraction of this value. Use of flow statistics
creates unavoidable problems, although it is the only method of
obtaining a nationwide supply estimate on a consistent basis.
First, not all records span the same period. Rivers with short
periods of record may show unrealistic values for statistical
measures of low flow. Second, new on-stream impoundments are
continually being built for flood control and water supply.
160
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D
< 20% CONSUMED
20-80K CONSUMED
80-100% CONSUMED
> 100% CONSUMED
Figure 3-2. Critical Surface Supply.
Source: Oak Ridge National Laboratory
02-4336-1
-------
Their operation can greatly alter flow regimes, and tend to in-
crease low flows. Old records do not account for these changes,
and low-flow statistics may be obsolete. Future impoundments
thus not only increase supply by storage, but affect flow-
derived estimates by stabilizing discharge regimes.
The CONAES study also assumed that substantial amounts
of synfuels made from coal might be needed to replace dwindling
supplies of oil and natural gas, and linked water supply prob-
lems to the added water demand of these industries over and
above that of mining and conventional combustion. It did not
count groundwater as part of the total water supply. Although
few large energy facilities would actually use groundwater di-
rectly, surface water can be displaced from other users and made
available to energy industries if groundwater is substituted.
Thus, omission of this source of supply has a considerable in-
fluence on the results.
The Oak Ridge study computed surface supply on the
basis of Water Resources Council Aggregated Sub-Areas (ASA's).
Two measures were used. On a national level, each ASA's supply
was considered as the surface outflow with a 95 percent chance
of being exceeded in critical supply months. This "Critical
Surface Supply" was corrected for current storage and manage-
ment practices. A second measure, used in a more detailed
look at federal Region VI, estimated water supply available to
energy as 10 percent of the 7-day, 10-year low flow. Ground-
water was included in supply calculations, but in basins with
existing depletion problems, use was frozen at 1975 levels.
This was the case in most Texas basins.
Despite their conservatism, however, these studies
point to the importance of developing new supplies in Texas.
They may be taken as evidence that the time frame for such de-
velopment is not long. If existing supplies appear incapable
162
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of supporting anticipated consumptive use, at low-flow periods,
as soon as 1985, then small delays in implementing supply pro-
jects are obviously significant. These projections of supply
problems also serve as a signal for potential heavy increases
in groundwater demand, which would be intensified by failures to
develop surface supplies. Figure 3-2 can thus be construed
broadly as a map of potential future groundwater demand, and
possibly of depletion problems, for the next decade.
3.1.7 Sensitivity of Key Water Supply Policies
The conclusions that a water supply adequate for the
entire development scenario may be made available depends upon
the maintenance of a delicate and sensitive equilibrium. For
sufficient supplies of water to be available for energy develop-
ment at any particular time, three sources must contribute
s imul t ane ous ly :
• New surface water development,
Groundwater pumping (mainly replacing
surface water for other uses), and
Water rights conversion, from other
beneficial uses to steam-electric power
generation.
If energy's total demand is thought of as growing at a given
rate, corresponding to growth in consumptive demand, then it is
clear that if the contribution from one source is restricted,
the other sources must supply still more.
In practice, as demand grows, the balance between
sources will not always be the same. The nature and extent of
163
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the problems that accompany the process of supplying energy's
needs will be determined by the degree to which the three
sources balance one another. Should any one of them be unduly
constrained, then pressures on the others may result in both
economic and environmental stress.
That these needs will be met is assumed, since in
Texas law the only beneficial use with priority over industry
(including steam-electric power production) is municipal water
supply. Growth in municipal demand as projected by the Texas
Department of Water Resources is not large enough to compete
seriously with industrial requirements.
3.1.7.1 Policy Constraints on Timely Development of
Surface Water Supplies
Table 3-2 illustrates the significance of new surface
water development in the five subregions of the study area, by
the year 2000. As seen in the table, new supplies (planned or
recommended by TDWR) account for a significant percentage of
projected surpluses in the North Central and Central Subregion,
while in the Southern Subregion there would be a considerable
short-fall without new development.
Looking at a finer scale, Table 3-6 shows those indi-
vidual basins in which projected surplus in the year 2000 is
less than new development, or in which a deficit is forecast.
The accompanying map (Figure 3-3) shows their locations.
Many of the new reservoirs included in TDWR's supply
projection are not yet authorized or funded. Construction de-
lays or cancellations could considerably strain water supplies
in several basins.
164
-------
Areas which could develop water
deficits by the year 2000.
*Even though the Brazos basin is indicated
here as having a year-2000 surplus, much
of this surplus water must be passed
through to satisfy downstream contracts and
water rights.
Figure 3-3. Year 2000 Critical Basin Segments.
02-4302-1
165
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TABLE 3-6. CRITICAL BASINS
Basin and Segment
Surplus (Shortage) New Development
Trinity 1
Colorado 3
Guadalupe
Nueces
Nueces-Rlo Grande 1
Lavaca
86
(6)
75
89
36
191
(Richland Creek*)
151
(Columbus Bend*)
58
(Ingram*, Cloptin
Crossing**, Lockhart*)
252
(Choke Canyon**)
225
(Choke Canyon**)
75
(Palmetto Bend**)
*Needed but not authorized.
**Authorlzed federal project.
Funding and participation from federal agencies, as
well as the Texas Department of Water Resources, will be neces-
sary to bring all of the needed projects on line. Recently,
however, the federal water agencies have been requiring more
state and local participation in funding, increasing the price
of water to users, and looking harder at non-structural alterna-
tives to flood control. Recent presidential vetoes of reservoir
appropriations and attempts by the Executive Branch to develop a
more restrictive national water policy also suggest a trend to-
ward a reduced federal role. At the same time, the TDWR lost
its last bid to increase bonding authority from $400 million to
$800 million, and "Proposition 13 fever" will certainly result
in generally greater scrutiny for publicly funded projects.
Opposition to specific reservoirs on environmental grounds, or
because of land use conflicts, can also slow surface water de-
velopment.
166
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These issues, and potential alternatives for assuring
adequate water supply, are discussed at greater length in
Chapter V.
3.1.7.2 Water Rights and Surface Water Distribution
Most of the water needed to support lignite mining is
expected to come from local surface and groundwater sources.12
Utility and industrial boilers, and gasification plants, however,
require substantially more water to meet their cooling require-
ments. Typically, cooling will be provided by wet towers or by
ponds. An off-stream cooling pond sized appropriately for
cooling a large installation may not be able to impound enough
water through runoff to supply consumptive needs. The remainder
must be made up by water brought in from a main-stem reservoir,
3.1.7.3 Water Rights Doctrine
Texas currently recognizes both riparian and appropria-
tive water rights. Riparian rights are limited to a "reasonable
use" of the base flow of streams. The use of riparian rights
is generally limited to domestic use, livestock watering, and
irrigation.13 Appropriative rights apply to flood flows, and
base flow not under riparian rights. Statutory priorities were
established by the Wagstaff Act of 1931, giving the order in
which needs for different beneficial uses are to be met in ap-
propriating these supplies. These are, in order:
1) Municipal supply,
2) Industry and manufacturing, including non-
hydroelectric power generation,
*San Miguel Station, in Atascosa County, is designed to use
groundwater for cooling tower makeup.
167
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3) Irrigation,
4) Mining, oil and gas extraction,
5) Hydroelectric power,
6) Navigation, and
7) Recreation and pleasure.
These priorities are to be applied in cases of dispute and
during water shortages. They do not affect the granting of per-
mits which are not contested. The key concept behind these
priorities, and reflected throughout the body of case law, ap-
pears to be that water should be allocated to the most eco-
nomically efficient uses, after basic domestic needs have been
met.
Water impounded by reservoirs is appropriated to the
operator of the reservoir in the same manner as direct with-
drawals. Authorizations are made of proportions of the usable
supply for various beneficial uses. Viewed in the aggregate,
authorizations for municipal uses comprise the largest propor-
tion in existing reservoirs, followed by industry, irrigation,
and mining.12 The operator of the reservoir is free to con-
tract with individuals to supply needs within the authorized
beneficial use categories, at a price mutually agreed upon.
Except for municipalities, appropriations may not be
made in excess of need, anticipating future use.13
3.1.7.4 Water Rights Adjudication
The pressure of a dual water-rights system in Texas
creates administrative confusion, which grows more significant
as pressures on water supplies increase. To correlate the two
168
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doctrines, the Legislature passed the Water Rights Adjudication
Act of 1967. Its purpose is the clarification of the very un-
certain water rights held under the riparian doctrine, and the
eventual merger of the two doctrines into a single permit system.
Claims on any basis are collected for each basin, and evaluated
case by case by the Texas Water Commission. Those judged valid
are granted a certificate which states the quantity of water
which may be used. The adjudication process is expected to be
complete by the mid 1980's. As it proceeds, the Commission is
attempting to cancel unused appropriation permits.*
After adjudication, however, some streams may still
be over-appropriated, since the new certifications will be
based on maximum use in a given period. All users will not
have actually made these maximal withdrawals at the same time.
A second round of cancellations may follow adjudication. All
told, it is estimated that water freed up in this way could
total upwards of 25 percent of the available supply, in some
basins. 12
3.1.7.5 Current Uses of Surface Water
Figure 3-4 indicates the relative amounts of surface-
water resources now used for different types of demands within
the various basins. Generally, a much higher percentage of
total demand goes for irrigation in the more southerly basins.
Towards the north, where the bulk of the highest quality lig-
nite is found, manufacturing and municipal uses predominate.
In the central portion, municipal and agricultural uses gen-
erally dominate the total demand. Mining uses very little of
the total water supply. Power generation uses large quantities
in the Trinity and Guadalupe basins. In the Guadalupe basin,
*A 1971 Supreme Court Decision, Texas Water Rights Commission
vs. Wright, establishes the right of administrative cancella-
tion of permits after 10 years of continuous non-use.
169
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200.000 ACRE FEET
500.000 ACRE PERT
100.000 ACRE FEET
| | IRRIGATION
PX?I MUNICIPAL
MANUFACTURING
Figure 3-4. Surface Water Use
SCALE IN MILES
-r 1—
o 20 so
100
MINING
I STEAM-ELECTRIC
LIVESTOCK
02-4301-1
-------
most of this water is used to generate hydroelectric power. In
the Trinity basin, however, the entire amount goes to cooling.
In comparison to streams of the eastern United States
and to even the main streams of the western United States, the
numerous rivers that drain the Texas coastal plain are relatively
small. This means that an incremental increase in demand, such
as could result from lignite development, can have a large impact
on flow patterns. It also means that rising overall demand
potentially affects all the users in the basin.
Where the surface water resource is almost completely
allocated, particularly on those streams in the southwestern
extension of the Lignite Belt, continued growth in surface-water
use will require additional conservation measures and wider appli-
cation of water re-use. Water re-use has already begun to expand
in industry, under economic pressure. Especially for individual
large users, recycling and re-use can produce significant economic
benefits. Consequently, those basins where manufacturing is a
dominant water use may be in a better position to adjust to lignite-
related increases in water demand than other basins. Use patterns
in the agricultural sector, especially in irrigation, are harder
to shift than industrial ones, in part because of the large capi-
tal expenditures required for equipment. Individual farmers and
ranchers may have more difficulty financing newer, water-saving
technologies than industrial operations. Municipal demand is
very difficult to curtail, largely because there are few oppor-
tunities to conserve enough water to have basinwide significance.
Also, many individual household decisions are needed to produce
a measurable demand reduction. Figure 3-4, therefore, suggests
that the greatest potential flexibility in water use patterns
probably exists in the northern part of the Lignite Belt. For-
tunately this coincides with the greatest expected development
of the resource.
171
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3.1.7.6 Transfer of Water Rights
Given that little if any surface water remains to be
appropriated in Texas, new energy industries will have to obtain
most of their surface water needs either by contract from large
*
reservoirs or by purchase and conversion of water rights. It
appears likely that the net result of this trend will be the
transfer of water out of agricultural use and into the higher-
priority industrial use.
Both riparian and appropriative rights may, with admin-
istrative approval, be severed from the lands on which the water
was originally used, and sold to other persons for use on other
lands.13 Riparian rights, however, remain limited to domestic,
livestock, and irrigation use. Appropriative rights may be con-
verted to a new beneficial use, if approved by the Water Commis-
sion, Thus, the division of beneficial uses in the current body
of appropriative rights appears the more likely to experience
significant changes as a result of energy development.
The economic return from the use of a unit of water
for agriculture is as much as an order of magnitude less than
that from its use in power generation or other energy activities,
This means that if demand for water grows faster than supply,
agriculture will be less able to keep up with increases in its
value. Industries capable of more economically efficient use
of the water supply will be able to pay high prices in competi-
tion for contract water, and to purchase water rights from less
efficient agricultural users. Unless efforts are made to inter-
fere, the economic system, which by itself tends to allocate
*Construction of an off-stream cooling impoundment requires a
permit to appropriate and impound runoff, but quantities sup-
plied by runoff will typically be only part of the total make-
up required.
-------
resources most efficiently, will allow the gradual shift of water
away from the agricultural sectors.
Publicly owned power companies may occupy a unique
position with regard to competition for water supply. Munici-
palities are granted by statute the right to make appropriations
from streams other than the Rio Grande "which will supersede
appropriations already made...for other purposes."13 State
agencies generally can condemn water if a fair price is paid, and
this right might extend to water supplies for power production.l*
3.1.7.7 Uncertain Future Demand Factors
In addition to existing and projected demands for sur-
face water, two potentially large additional demands could fur-
ther stress water availability: freshwater inflows to bays and
estuaries, and transfers of water to the High Plains irrigated
agricultural region.
Some quantity of freshwater inflow is required to sus-
tain ecosystem productivity in bays and estuaries. Regulatory
agencies are now required to evaluate water withdrawals and
reservoir regulation with respect to ecological effects on the
estuaries. The data base for this evaluation, however, is only
in the formative stages. The Texas Department of Water Resources
has been charged by the Legislature to prepare a detailed report
on estuarine freshwater inflow requirements by December of 1979.
Once these inflows are quantified, they must be reserved from
other uses. The Legislature will determine what priorities these
inflows will have relative to other uses. In order to assure
these inflows, the state may have to condemn and purchase exist-
ing rights, or condition their use on maintenance of required
instream flows.
173
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The rapid depletion of the Ogallala Aquifer, source of
irrigation water for the highly productive High Plains area, is
a growing concern to water planners. Attempts to plan an inter-
state diversion of water from the Mississippi have already been
made and discarded because of the extremely high cost and
potential inequities of cost distribution. Potential imports
from Arkansas are currently being discussed,8 but plans are far
from consummation. Thus, it is not unreasonable to consider
the possibility that planners might turn to East Texas as a
possible source of water for the High Plains.
The economic stakes may be very high. The High
Plains supplies 20 percent of the nation's cotton, 25 percent
of its grain sorghum and 5 percent of its wheat. Demand for
these commodities is relatively inelastic, such that a decrease
in supply is met with a more than proportional increase in price.
Without imports of water, TDWR calculates that irrigated acre-
age will have declined by more than 40 percent in the year 2000.8
The economic impacts of such a reduction in productivity could
be felt nationwide. The amounts of water needed to avert it
total to millions of acre-feet annually.
The High Plains situation potentially affects lignite
in two ways. First, about three-fourths of the runoff in Texas
originates in the eastern quarter of the state,15 making it a
prime potential candidate for intrastate transfers. Second,
very large amounts of electric power would be needed to raise
the needed millions of acre-feet of water several thousand feet
in elevation between East Texas and West Texas. This need
would also apply to water from outside the state. The result
would not only be potentially larger demands on lignite to gen-
erate the power, but significant increases in cooling water
demand as well.
174
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3.1.7.8 Indirect Pressures on Groundwater
The consumptive use of groundwater from all of the
aquifers in the lignite trend is shown in Figure 3-5, according
to the various surface drainage sectors. Generally, where
surface supplies and usage are relatively large (Figure 3-4),
groundwater use is small, and vice versa. Irrigation use is
concentrated in the southwestern part of the trend, and virtually
no groundwater is now used for steam-electric power generation.
With institutional and economic constraints on surface-water
development increasing and with potential additional pressure
on surface water from freshwater inflow allocations, the rela-
tive proportion of the total water demand that is met by ground-
water is likely to increase.
Groundwater is considered a property right, and can be
taken without limit from under the land on which it is found.
It can likewise be freely sold or transported for any beneficial
purpose. Currently, the only means of controlling pumpage rates
is by the formation of a Groundwater Conservation District.
This process is complex and must be approved by a regional
election. Consequently, only a few have been formed in the
High Plains and in areas near Houston affected by subsidence
and saltwater intrusion.
The result of this lack of regulation has been the
development of widespread depletion problems. In the Lignite
Belt, the Carrizo and the Trinity Group Aquifers have already
been affected. Increased drawdown increases pumping costs, and
may also result in quality problems.12 Over the long run, un-
controlled pumpage depletes long-term storage and reduces
future availability to the amount that is recharged each year.
175
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100.000 ACRE FEET
200.000 ACRE FEET
50.000 ACRE FEET
IOO
I I IRRIGATION
\/f\ MANUFACTURING
3 MINING
STEAM-ELECTRIC
Figure 3-5. Groundwater Use
02-4299-1
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Given its essentially unregulated status, groundwater
offers a limited "cushion" in the event that surface water sup-
plies are constrained. Those users which would suffer most
would be those whose groundwater supply is completely depleted,
or whose pumping costs were increased by drawdown beyond the
point where economic returns justify the cost. For the reasons
cited in the previous section, agriculture is again likely to
be the most strongly affected.
177
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3.2
Air Quality as a Constraining Factor
Summary and Conclusions
The minimum allowable distance between new emission
sources is jointly determined by New bource Performance
Standards (NSPS) and the available PSD increments.
The analysis presented here used SOa as an indicator
pollutant to estimate minimum new-source spacing.
If the S02 increment is fully available, it is esti-
mated that under proposed NSPS, new 1500 MWe lignite^
fired power plants could be sited as close as 20 km
apart.
In many areas along the coast, and in the eastern
portion of the Gulf Coast Subregion, existing sources
may impose moderate to severe siting constraints.
Further constraints might develop from efforts to pre
serve high standards of air quality in and around the
Big Thicket and the East Texas National Forests.
In spite of these constraints, more than an adequate
number of sites, separated by a minimum distance of
20 km, can be found in each subregion to accommodate
all scenario power plant activity.
Pending decisions on strategies for allocating the
PSD increments could have an impact on "packing" of
new sources. In general, economics-based methods
improve packing.
178
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3.2.1 Air Quality Regulations That Constrain Plant Spacing
Current policy for the prevention of significant air-
quality deterioration (PSD) approaches the problem from two direc-
tions, with standards both for areawide increments of allowable
deterioration and for emissions from new sources. The PSD incre-
ments in effect refer to emission densities. An acceptable den-
sity—one which does not allow the increments to be exceeded--
can be achieved both by emission control and by source spacing.
Emissions must meet New Source Performance Standards set by EPA.
Given these emission levels, minimum source spacing is effectively
set by the requirements of PSD.
The following discussion relates proposed NSPS to lig-
nite- and coal-fired power plants, and sets forth the. methods by
which compliance of a new source with PSD is assessed. Then, in
the following section, these methods are used in a hypothetical
example to estimate a minimum distance by which the new plant
called for in the scenario must be separated. The availability
of the full PSD increment is evaluated over the study area, and
the extent to which siting might be constrained is evaluated.
Finally, in the last section, current uncertainties in policy
are evaluated as they affect new-source spacing.
3.2.1.1 New Source Performance Standards
Emissions from a new power plant must meet applicable
New Source Performance Standards (NSPS). EPA has not yet com-
pleted promulgation of revised New Source Performance Standards
(NSPS) for fossil-fired steam electric plants, which are required
by the Clean Air Act Amendmqpts bf August, 1977.
179
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The Amendments dictate that NSPS require a maximum al-
lowable emission rate and a percent reduction of a particular
pollutant from an uncontrolled emission. At this time EPA is
proposing that the maximum allowable emission rate for SOa would
be 1.2 Ib/MM Btu (same as the current standard) and an 85 percent
removal efficiency. The removal efficiency requirement would be
waived if emissions of 0.2 Ib/MM Btu or less could be achieved
with a lower removal. EPA1s current interpretation suggests that
the removal efficiency is to be based on emissions without con-
trols versus emissions with the proposed control device; therefore
"credit" cannot be taken, for example, for sulfur retention in
the ash.
To determine the effect of these proposed standards
on lignite-fired generating stations, a "typical" quality of
lignite was derived from data presented in Radian's earlier En-
vironmental Overview of Future Texas Lignite Development.3 Five
grades of lignite were identified in that report, based on ranges
of heating value, sulfur content and ash content. For this appli-
cation only sulfur content and heating value were used. A sin-
gle heating value and sulfur content was selected to represent
each grade of lignite conservatively. This conservatism en-
tailed using a heating value lower than the average of the range
and a sulfur content higher than the average of the range.
Given the assumed plant conditions (three 500 MWe units
and heat rate « 10,000 Btu/kwhr), the typical fuel quality, using
EPA emission factors for S02,16 and assuming 85-percent scrubber
efficiency, the S02 emission rate for each grade of fuel could
be calculated.17 The ranges of heating value and sulfur content,
assumed coal characteristics and calculated SO2 emission rate
for each of the five grades of lignite are presented in Table
3-7.
180
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TABLE 3-7.
Heating Value1
Grade1 Range (Btu/lb)
t 7000-7500
2 7500-8000
3 6500-7000
4 <7000
5 <6500
ESTIMATED S02 EMISSION RATE FOR 1500 MWe ELECTRIC
GENERATING STATIONS, FIRING LIGNITE OF VARIOUS GRADES
Sulfur Content1 Assumed Heating
Range (%) Value (Btu/lb)
<1.0 7200
1.0-1.5 7700
1.0-1.5 6700
1.5-2.0 6900
1.5-2.0 6200
Calculated S02 2 ' '
Assumed Sulfur Emission Rate
Content (Z) (Ib/hr)
0.8 3750
1.3 5698
1.3 6549
1.8 8804
1.8 9798
'from An Environmental Overview of Future Texas Lignite Development.3
2Plant conditions assumed: 1500 MWe (three 500-MWe units)
Heat rate - 10,000 Btu/kwhr
Total Heat Input - 15,000 x 10 Btu/hr
'Assumes EPA AP-42 factors.
The calculated emissions in Table 3-7 are less than
18,000 Ib/hr (1.2 Ib/MM Btu) and more than 3000 Ib/hr (0.2 Ib/MM
Btu). Thus it appears that the proposed requirement for 85 per-
cent removal efficiency is the more restrictive of the two
s tandards.
3.2.1.2 PSD Increments
The Clean Air Act Amendments of 1977 establish allow-
able increases (or "increments") in ambient air pollutant levels
above "baseline concentrations" for each of three area classifi-
cations (Class I, II, or III). These classifications are gen-
erally based on the increase in pollutant-emitting industries
considered acceptable. The floor for each class is the baseline
concentration level and the ceiling is the NAAQS.
At the present time, increments exist for two pollu-
tants - total suspended particulates (TSP) and sulfur dioxide
181
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(S02). Table 3-8 gives these allowable increments and a brief
description of the area classifications. With the exception of
two areas in west Texas (which are Class I areas), the entire
state of Texas has been designated Class II.
TABLE 3-8. PSD CLASSIFICATIONS
Allowable Increments
Class Type of Area
I International parks;
national parks;
monuments; wilderness
areas; etc., and other
areas designated by
each state.
II All areas not
classified I or III.
Ill Areas with heavy
Industrial concen-
trations, or where
such concentrations
are planned.
'S02 annual standard Is arithmetic
*The 24-hr or 3-hr increments may
Industrial Potential
Little or no growth of
pollutant-emitting
industries
Moderate growth of
pollutant-emitting
industries
Restricted growth of
industries emitting
pollutants for which
NAAQS are threatened.
Large but controlled
growth where few
Industries exist.
mean but TSP annual standard
be exceeded once per year.
Averaging Period
Annual1
24-hr max
3-hr max
Annual1
24-hr max
3-hr max
Annual1
24-hr max
3-hr max
is geometric mean.
S02
2
5*
25*
20
91*
512*
40
182*
700*
TSP
5
10*
none
19
37*
none
37
75*
none
Regulations18 implementing the amendments to the Clean
Air Act require that all new sources undergo a PSD review (a few
exceptions have been made). Most sources of pollutants addressed
in this study would be considered "major" sources and therefore
must undergo a detailed review. The general requirements of the
review consist of the following:
• Description of the Proposed Facility
Location, operating characteristics, design
specifications, control equipment, fuels,
process description.
182
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• Description of Emissions
Sources of emissions, calculated emissions
(controlled and uncontrolled), removal
efficiencies.
• Best Available Control Technology (BACT)
Assessment
Includes a discussion of justification of
control equipment proposed based on energy,
environment, economics, and ability to meet
NSPS.
• Air Quality Analysis
Includes assessment of impacts of the pro-
posed facility on PSD increments, NAAQS,
regional visibility, soil and vegetation,
industrial, residential and commercial growth.
This evaluation must consider the effects of
the proposed source in combination with those
other "applicable sdurces."
Of greatest concern here is the Air Quality Analysis.
The general approach used in a PSD Air Quality Analysis consists
of four steps:
Step 1: .Define the source's "Area of Impact."
Step 2: Identify other "Applicable Sources."
Step 3: Identify meteorological data to be used.
Step 4:. Model combined impacts of new source and
"Applicable Sources" and identify areas
where PSD increment is exceeded.
183
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Step 1. Define the "Area of Impact"
In the regulations implementing the PSD requirements
of the Clean Air Act,18 the Administrator indicates that EPA did
not intend to analyze impacts of a proposed facility beyond 50
km, due to model inaccuracy and decreasing concentrations with
distance. Alternatively, no analysis would be required for dis-
tances beyond which concentrations due to the proposed facility
fall below certain "significant" values. "Significant" is de-
fined in the regulation. These values are presented in Table
3-9.
Pollutant
TSP
SO 2
NO 2
CO
N/A = Not
TABLE 3-9.
Annual
1 yg/m3
1 yg/m3
1 yg/m3
N/A
applicable.
SIGNIFICANCE LEVEL FOR PSD ANALYSIS
24-Hour
5 jag/m3
5 yg/m3
N/A
N/A
Averaging Time
8-Hour
N/A
N/A
N/A
0.5 yg/m3
3-Hour
N/A
25 yg/m3
N/A
N/A
1-Hour
N/A
N/A
N/A
2 yg/m3
The "area of impact" of a facility is defined as that
area surrounding a proposed facility within which that facility
would be expected to have a "significant" impact (either where
concentrations fall below "significant" values, or within a 50-
km radius , whichever area is smaller) .
methods of determining the area of impact can be
used: the radius approach and the isopleth method. The radius
approach involves determination of the greatest distance in any
direction at which the facility's impact is considered signifi-
cant. A circle is centered on the facility, with a radius equal
184
-------
to that distance, which defines the area of impact. The isopleth
approach involves determination of the maximum distance in each
direction where the facility would be expected to have a signifi-
cant impact. The area of influence defined in this way is thus
an irregular shape, with the facility centrally located.
The difference in the size and shape of the area of
impact calculated by these two methods can be seen in Figure
3-6. Region VI of EPA requires the use of the radius method in
PSD air quality analyses.
The area of impact is used to define the area in which
impacts of the proposed facility are to be assessed, as well as
serving as a guide to which sources should be included in the
analysis.
Step 2. Identify Other "Applicable Sources"
As mentioned earlier, the proposed source or modifica-
tion in combination with other "applicable sources" must demon-
strate compliance with the NAAQS and PSD increments. "Applicable
sources" are at least those within the area of impact. In addi-
tion, Region VI requires inclusion of sources outside the area
of impact, if including them may significantly affect the results
of the analysis.
For the PSD increment analysis "applicable sources"
are those which consume increment within the area of impact
(and significant sources outside). For the analysis of compli-
ance with NAAQS, "applicable sources" are all sources of the pol-
lutant of concern within the area of impact and significant
sources outside the area of impact.
185
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AREAOF IMPACT
DEFINED BY
ISOPLETH METHOD
MAXIMUM RADIAL EXTENT
OF "SIGNIFICANT" IMPACT
AREA OF IMPACT
DEFINED BY
RADIUS METHOD
Figure 3-6. Area of Impact
(Radius and Isopleth Method)
02-4337-1
Step 3. Identify Meteorological Data To Be Used
Two basic types of models are used in an air-quality
analysis: climatological models and sequential models.
The climatological models are used to assess compliance
with the annual standards. Meteorological data used in the mod-
els consist of joint frequency distributions of wind speed, sta-
bility, and wind direction, averaged over an extended period of
time (five years or more). Such data are available from the
National Climatic Center for many weather stations throughout
Texas. The primary concern with respect to modeling compliance
with annual standards is assuring that the data selected are
representative of the area of impact.
The sequential models are used for assessing compliance
with the short-term standards (24 hours and less). These models
186
-------
calculate a concentration for each data period (usually an hour)
and average these concentrations appropriately to produce the
desired short-term average. EPA suggests that five years of
data "yield an adequate meteorological data base."16 At pre-
sent, hourly data covering five years can seldom be obtained.
Even if such data were available, the cost of modeling multiple
sources (if applicable) would be prohibitive. The usual approach
is to identify a worst-case meteorological sequence by use of
screening techniques (aided by professional) judgment. This
worst case is then used as the basis of the modeling exercise.
The screening techniques themselves vary considerably, depend-
ing upon the particular situation, but generally involve the use
of simplified dispersion models. Representativeness of the me-
teorological data is extremely important for modeling short-term
impacts as well as long-term impacts.
Step 4. Model Combined Impacts and Evaluate Compliance
This is fairly self-explanatory and involves applica-
tion of the models selected to the sources identified for the
meteorological conditions chosen. Another important part of
this portion of the analysis is selection of the receptor loca-
tions used in the model.
Analysis of modeling results involves identification •
of the areas of noncompliance (if any) and an assessment of the
potential impacts (soils, vegetation, visibility, etc.).
3.2.2 Effect of Air Quality Constraints on Siting New
Sources in the Study Area
A three-step approach was used in this portion of the
analysis. In the first step, assuming the full Class II incre-
ment was available, the closest spacing of power plants which
187
-------
would allow compliance with the increment was determined. The
second step involved an assessment of existing air quality to
identify areas in which siting may be limited and to evaluate
the extent of the constraint. The third step involved assess-
ment of relative suitability of various areas and determination
of site availability.
3.2.2.1 Minimum Spacing for Fully Available Class II
Increments
The question to be answered in this part of the analy-
sis is, "If the total Class II S02 increment were available, how
close together could the proposed 1500 MWe electric generating
facilities be placed?" Essentially this amounts to a determina-
tion of the maximum number of facilities which could be accommo-
dated given the "best" practical conditions.
S02 was selected for this portion of the analysis for
three primary reasons. These were:
• The nature and scope of this study dictated
a generic approach to the assessment of air
quality. Since it was not possible to examine
impacts of all pollutants associated with the
development scenario, the use of some "indicator"
pollutant was desirable.
• For a major portion of the study area the
Class II increments appeared more restric-
tive than other factors such as NAAQS. Since
increments currently exist for Total Suspended
Particulates (TSP) and S02, the choice was
narrowed to two.
188
-------
X "fximno PLANTS-*
Figure 3-7. Hypothetical "existing facilities" 02-4313-1
within an area (equally spaced).
• SO2 is a major component of emissions from
lignite combustion. TSP also results, but
the situation is complicated in that atmos-
pheric reactions result in the formation of
additional TSP downwind from the plant. S02
is more amenable to modeling.*
It should be realized that on a localized basis, the
estimated impact of SOa emissions on air quality may not indi-
cate the impact of other pollutants, but should provide a rea-
sonable assessment of overall air quality.
*The potential importance of TSP and other products of downwind
atmospheric transformations is discussed in Chapter IV, Section
2.0.
189
-------
A modeling approach was taken to estimate the minimum
spacing possible between hypothetical 1500-MWe stations. The
approach used assumed that a series of identical, equally spaced
electric generating facilities exists within a grid area, and
that a permit is being sought for one facility. Such a hypothe-
tical grid of existing sources is shown in Figure 3-7. The pro-
posed facility is to be located in the unfilled space in the
center. The model calculates the space between the sources in
this arrangement.
According to the guidelines for an air quality analysis
described earlier, the first step is to determine the area of
impact of the proposed facility. In this case, however, it was
necessary to establish some design parameters for the facilities.
The design parameters assumed are provided in Table 3-10. As
stated, the "proposed facility" exhibits the same parameters as
the "existing facilities."
TABLE 3-10. DESIGN PARAMETERS FOR 1500 MWe ELECTRICAL GENERATING
STATIONS USED IN AIR QUALITY MODELLING
Size:
Heat Rate:
S02 Emission Rate:
Stack Height:
Stack Diameter:
Stack Gas Temperature:
Stack Gas Volumetric Flow:
Stack Gas Velocity:
Capacity Factor:
1500 MWe (3 Units @ 500 MWe)
10,000 Btu/kwh
6000 Ibs/hr (0.4 lbs/106 Btu)
500 Feet
24.2 Feet
160°F
1,442,200 ACFM
52.5 ft/sec
100%
190
-------
Given these parameters, the area of impact can be
determined. For this facility size, the area of impact was found
to have the maximum modelable radius of 50 km. The "proposed
source" and its area of impact together with the "existing
sources" are shown in Figure 3-8.
The sources included in the analysis consisted of the
"proposed" source, those "existing sources" within the area of
impact, and other "existing sources" within 10 km of the area of
impact. This approach effectively defines the area of impact
at a 60 km radius which is somewhat conservative. The "appli-
cable sources," in the sense of PSD permitting procedures, are
shown in Figure 3-9.
The assessment considered the 24-hour and annual
averaging periods. A plot of predicted worst-case 24-hour con-
centrations versus distance from the proposed facility is shown
in Figure 3-10. This plot can be considered highly conservative,
since the highest 24-hour concentrations at each receptor
distance have been used. In reality, the same type of meteoro-
logical conditions producing a peak 24-hour average would not
cause the high concentrations shown at greater distances.
4P
Assuming alignment of the sources in any particular
wind direction (a maximum of seven "applicable sources" could be
so aligned in the patterns evaluated here), calculating minimum
plant spacing for the 24-hour average involved determining
coincident peak concentrations at various distances. Figure 3-10
cannot be an accurate guide to maximum possible 24-hour concen-
trations, but is provided to give "feel" for downwind concen-
trations from a facility.
The annual averaging period provided to be the most re-
strictive with the assumptions used. Determination of the
191
-------
X
X X
AREA OF IMPACT
"PROPOSED PLANT"
Ij ••t*aro»to fwkNT-
X "ixirrtNa PLANTS*
a 10 20
MALI I Km)
Figure 3-8. "Proposed facility" and area of impact 02-4314-1
AREA OF IMPACT
"PROPOSED PLANT"
<£) "PHOPOStD PtANT-
X "tXIfTINO PUNTS" MODELED
0 10 20
SCALI IKml
Figure 3-9. Facilities included in modeling.
02-1315-
192
-------
60—
50—
40— \
PREDICTED 24 HOUR
CONCENTRATIONS
go-
VO
LO
10 —
r
10
r i
20 30
DISTANCE (km)
I
to
Figure 3-10. Worst-case predicted 24-hour SC>2 concentrations versus
distance for hypothetical 1500-MWe power plant.
02-4316-1
-------
minimum plant spacing permitting PSD levels to be maintained
over the annual period required trial and error, since no "guide"
(such as Figure 3-10) is provided by the model. The results from
the short-term analysis were useful in determining a starting
point for the analysis of the annual period, however.
The theoretical minimum spacing between the power plants
was determined to be 20 km on the basis of the modeling performed.
The models used were the CDM (Climatological Dispersion Model)
for modeling annual periods and the Single Source CRSTER Model
for the modeling short-term conditions. Both models are EPA-
developed and approved.
Meteorological data from Hobby Airport were used,
covering the period from 1959 to 1968 for the annual modeling.
1976 data were used for the short-term modeling. These data are
probably not representative of meteorological data in the Lignite
Belt; however, the differences in the maximum predicted concen-
trations would probably not be substantial.
The modeling described above is intended to be a guide
to evaluating the maximum number of power plants that could be
located in a region, taking into account only the PSD increment
The results are extremely sensitive to the assumptions made and
the assumptions implicit in the models. Of particular importance
are the following:
Stack Parameters
The diameter, velocity, temperature and
height of the stack ultimately influence
effective plume height, which can affect
predicted concentrations (thus spacing)
significantly.
194
-------
Emission Rate
Concentrations are directly proportional
to the emission rate for a particular
source.
Pollutant Considered
Increments for other pollutants (when pro-
mulgated) could be more restrictive than
SC-2, which would affect spacing. For
example, the proposed NSPS for NOX is 0.6
Ib/MM Btu; the proposed maximum allowable
NSPS for S02 is 1.2 Ib/MM Btu. Thus, if
the NO2 increment were based on the same
ratio to NSPS as characterizes the S02
increment, the annual Class II increment
would be 10 ug/m3, which would require a
wider plant spacing than suggested here.
Location
The spacing derived assumed the total Class
II S02 increment was available. In areas
where this is not true, spacing would be
affected.
Terrain
The model assumed level terrain. In areas
exhibiting extreme relief, plume impaction
could cause significantly higher concentra-
tion, thus requiring greater spacing.
195
-------
Meteorological Data
Although not thought to be significant in
this determination of spacing requirements,
it is possible that different joint frequency
distributions could require different plant
spacing.
If long-distance transport and transformation
of pollutants is shown to be a significant
contributor to background TSP levels downwind
of plants or groups of plants, wider spacing
might be required to control areawide emission
density. The meterological conditions that
favor such additive effects are not the same
as worst-case conditions for S02 alone (see
Chapter IV, Section 2.0).
Thus it is concluded that the modeling results should
be interpreted only as a useful guide to estimating the number
of power plants that can be accommodated in a given region. The
spacing derived involves a complex relationship of meteorological
conditions, source strengths, number of sources and source rela-
tionships. For examnle, a decrease in spacing increases concen-
trations at receptors where plume interaction is prevalent
(assuming other factors remain constant). This is magnified by
the possibility of increasing the number of sources which are
within the area of influence. Therefore a change in any of these
factors could significantly alter the results.
3.2.2.2 Assess Limitations of Increment Availability
The major assumption in the previous analysis was that
the Class II S02 increment was totally available. It is intui-
tively obvious, however, that this is not the case throughout
196
-------
the study area. The next step of the analysis involved evalua-
ting the availability of the PSD increment for S02 throughout
the study area.
A great deal of judgment was required in this step.
There are two possible ways of evaluating the availability of
the increment: modeling and monitoring. Neither method, how-
ever, can be applied to the study area at this time.
Monitoring cannot accurately assess the status of
the increment because an extensive monitoring network does not
exist. Although Texas has a large network of monitors, the data
are not sufficient to support conclusions in many portions of
the state. There is also a lack of accurate emissions data.
Ambient monitoring data can be extremely misleading if all sour-
ces are not emitting at their permitted rates. Finally, it is
not possible to differentiate between the contributions of dif-
ferent sources. If monitoring is to be used to show compliance,
there must be a mechanism for differentiating the contributions
of non-baseline sources from those of baseline sources. This
is not possible in areas where a large number of sources cur-
rently exist.
Modeling would appear to be the most precise method of
"tracking" the progressive use of the increment. This would en-
tail modeling the entire state of Texas, however, including every
source for the pollutant being modeled. This would be a massive
undertaking. The Texas Air Control Board (TACB) is currently
performing such modeling for certain portions of the state; how-
ever, results are not yet available.
Although the availability of the S02 increment was of
primary concern, areas of potentially high concentrations of
197
-------
other pollutants were identified when they appeared more restric-
tive. Of particular importance in this regard were non-attainment
areas for TSP and photochemical oxidants (PCO).
Five degrees of air quality constraints on power plant
siting were identified and mapped (see Figure 3-11). These were
defined as follows:
Type 1 - No Constraints
Areas where few or no pollutant-emitting
sources are located or are proposed accord-
ing to announced plans. Host or all of the
Class II S02 increment should be available.
* Type 2 - Single Constraint
Area in which a single large source (exist-
ing or proposed) is thought to produce levels
of S02 approaching the Class II increment.
Siting can generally be accomplished in these
areas; however, interaction with the large
source should be considered.
Type 3 - Moderate Constraint
The Class II S02 increment may not be fully
available in portions of these areas for one
or more reasons. Siting can be accomplished
in these areas as well, although special con-
sideration should be given to possible air
quality limitations.
These areas include:
198
-------
TYPE 1 AREAS
TYPE 2 AREAS
TYPE 3 AREAS
IB!
ill TYPE 4 AREAS
TYPES AREAS
AIR QUALITY AREAS
Figure 3-11
02-4307-1
199
-------
Potentially sensitive areas - an example
of this is the Big Thicket area in por-
tions of Liberty, Hardin, Polk and pos-
sibly Tyler Counties,
- Buffer zones around Class I areas and
potentially sensitive areas,
- Buffer zones around Type 5 Areas, and
Areas where a moderate number of pollutant
sources exist.
Type 4 - Strong Constraint
A higher probability of Class II increment
being partially consumed. Areas included
are those areas where Type 2 and Type 3
Areas overlap.
Type 5 Areas - Severe Constraint
Location of a fossil-fueled electric-
generating facility in these areas would
incur large economic penalties due to
tighter S02 control required; emission
trade-offs would be necessary, and
possible delays in permitting could occur.
Type 5 Areas include:
Designated Class I areas,
Areas in which up to several hundred
sources exist and the Class II incre-
ment and/or NAAQS is judged to be
exceeded, and
200
-------
National forests. Although not Class I
Areas, the national forests are consi-
dered undesirable for power plant siting
in this exercise. Areas which have been
designated non-attainment for particulates
and/or photochemical oxidants are included
in Type 5 Areas as well.
3.2.2.3 Analysis of Site Availability
This portion of the analysis used data derived in the
first two steps. The number of sites that could be accommodated
in each region could be determined using only air quality con-
straints. The maximum number of sites available was assessed by
a "site" ranking system of desirability. The Type 1 Areas (Figure
3-11) were most desirable whereas Type 5 Areas were least de-
sirable. For purposes of this exercise, Type 5 Areas were
considered unavailable for siting. A grid was laid over Figure
3-11 such that each grid unit would accommodate a hypothetical
1500-MWe power plant under conditions of full increment avail-
ability (each grid square was 20 km on a side). Each grid unit
was rated on a scale of 1 to 5, with 1 being most desirable and
5 being least desirable. These ratings correspond to the area
types described earlier; thus a grid unit totally within a Type
5 Area was rated 5, a grid unit totally within a Type 1 Area was
rated 1, and so on. Interpolation was used for grid units par-
tially covered by a particular area type.
Given the number of sites estimated to be needed in
each subregion, the first approach was to count the number of
grid units rated 1 in each region. If the number of grid units
was greater than the number of sites required, it could be con-
cluded that sufficient sites could be accommodated on the basis
of air quality alone. If there were not enough Type 1 "sites",
201
-------
then Type 2 Areas were assessed, but with two (an arbitrarily
assigned value) grid squares required for each power plant rather
than one.
The total number of 1500-MWe complexes (three 500-Mwe
units) to be sited in the study area by the year 2000 is 34.
Taking into account only air quality, an assessment of the study
area (assuming a plant could be located every 20 km) looking only
at Type 1 Areas determined that far more than the required 34
plants could be sited in the total study area.
These plants are not anticipated to be equally distri-
buted throughout the study area, as reflected by the regional
scenario breakdown. The greatest number are expected to be in
the Northeast Subregion (13 plants) followed by the North Central
Subregion with 9, the West and the Gulf Coast Subregion with 4
each, the Central Subregion with 3 plants, and the Southern with
2 plants. Even the most restrictive region had sufficient Type 1
Areas to accommodate the required number of facilities.
The conservatism in the modeling exercise would tend
to make the allowable spacing greater than could otherwise be
allowed if less conservatism were used. Also, the Type 2, 3, 4,
and 5 Areas in the air quality exercise are felt to be conser-
vatively approximated. If less conservatism were used in these
two analyses, the decreased spacing requirement and the increased
extent of Type 1 areas would allow many more facilities.
3.2.3 The Influence of Developing Air Quality Policy on
Siting Density
Current policy for the prevention of air quality deter-
ioration approaches the problem from two directions, setting
standards both for areawide increments of allowable deterioration
202
-------
and for emissions from new sources. Both aspects of air quality
policy, however, require further definition. EPA must soon
promulgate final New Source Performance Standards for S02 from
power plants. Also, states must submit plans for implementing
PSD by March 19, 1979,* and are encouraged to choose from a wide
range of strategies with varying potential impacts on siting
patterns.l8
Depending on how the issues surrounding these decisions
are resolved, the minimum siting distance could be extended. A
rough calculation was made, for each subregion, of the theoretical
spacing between plants which would just allow all the plants re-
quired by the development scenario to be sited. If larger dis-
tances were mandated, for example, as part of a strategy to
control regional sulfate formation,** it would begin to be diffi-
cult to site all the needed plants. This "threshold spacing" was
least in the Northwest, at 65 km. In all other subregions,
minimum spacings of 100 km or more would be needed before air
quality alone could hamper the siting of the required number of
both coal- and lignite-fired plants. Thus, the primary effects
of PSD strategies and NSPS will probably be felt to the Northeast
Subregion, in which the largest number of plants must be sited
within the smallest area.
3.2.3.1 Alternative PSD Strategies and Their Impact on
Clustered Development
When permits are granted to new sources under PSD re-
quirements, clean air is effectively treated as an allocable
*Although this date is indicated in the final regulations of
June 19, 1978, staff of EPA's Office of Air Quality Planning
and Standards indicate that no sanctions will be applied to
states not submitting a plan by this date.
**See Chapter IV, Section 2.0.
203
-------
resource, limited in supply. Thus, the assimilative capacity
of the air is a resource as necessary for the operation of a
new power plant as the water it uses for cooling. In allocating
its use among competing applicants, a balance must be struck be-
tween promoting economic efficiency and assuring equity of dis-
tribution. Similar considerations apply to water rights, and
the two situations are analogous in many ways. In each case,
the state's economy benefits most by allocating limited resour-
ces to users which generate the most employment, personal income,
value added, and other measures of economic efficiency. At the
same time, the rights of prior users have a claim to protection,
and unfair interference with normal competition among firms
should be avoided if possible.
Besides the currently practiced first-come, first-served
method of allocating the increment, EPA has suggested that states
consider methods based on economics. Table 3-11 compares three
such mechanisms with first-come, first-served, and summarizes
their relative effectiveness with respect to efficiency and equity
criteria. The table also shows their potential effects on siting
density, or packing of new sources, under a given PSD ceiling.
Economics-based systems which internalize the cost of
air pollution tend to provide incentives to reduce emissions.
This in turn makes it possible to fit more users into a set in-
crement of allowable air-quality deterioration. These effects
will be most pronounced in areas where the increment is all or
partly consumed. Thus, these strategies could increase packing
in the Gulf Coast Subregion and parts of the Northeast Subregion.
Eventually, under the first-come, first-served system, offsets
would be required to add new sources. In the interim, however,
emissions themselves have value of future offsets. This produces
a worst-case situation for siting density until the increment is
consumed.
204
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205
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3.2.3.2 NSPS and Its Impact on Clustered Development
EPA has proposed an across-the-board requirement for
power plants to remove 8570 of the sulfur content of flue gases
(daily average). An alternative option has been suggested by
DOE and by the utility industry which would allow partial scrub-
bing for lower-sulfur coals. The effect of this option on emis-
sions from individual plants--and thus on spacing--would depend
on the fuel used and the amount of scrubbing required. If low-
sulfur coal could be burned without scrubbing or with little
enough scrubbing to give it an economic advantage over lignite,
then widespread use of low-sulfur coal might result. The emis-
sions from these plants could be lower than those from lignite-
fired plants with scrubbers, allowing closer packing. Plant sit-
ing density might be reduced if a sliding scale of sulfur-
removal requirements allowed many coal or lignite-fired plants to
emit significantly more S02 than 8570 scrubbing would allow.
Calculations of the sensitivity of spacing between plants to
allowable sulfur emissions were beyond the scope of the present
s tudy.
206
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3.3 Flood-Prone Areas as a Constraining Factor
Summary and Conclusions
Between five and ten percent of the land area of
the Texas Lignite Belt may lie in 100-year flood-
plains .
Floodplain regulations are significant local con-
straints on siting mines and energy facilities;
in many cases, however, engineering solutions can
be applied which allow siting in floodplains.
Scenario activities may be ranked as follows in
order of constraint by floodplain regulations:
Surface Mines > Mine-Mouth Plants >
Other Utilities and Industry
Provisions of federal and state surface mining
legislation could preclude recovery of some lig-
nite underlying major floodplains, subject to
interpretation. At present, such restrictions
are not thought likely to have a significant
impact on the overall development scenario.
3.3.1 Constraints on Energy Development Activities
Table 3-12 summarizes the major provisions of state,
federal, and local floodplain regulations affecting scenario
activities.
3.3.1.1 Lignite Surface Mines
Floodplains intersect the Lignite Belt in many places,
and mining is confined to areas with economically favorable min-
ing conditions. Thus, lignite surface mining is likely to be
207
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o
00
TABLE 3-12. SITING CONSTRAINTS IN FLOOD PRONE AREAS
Activity
Surface
Mining
Mine-Mouth
Power Plants
Industrial
Plants
Description of Regulation
Federal and State
Surface Mining Acts
Provision Constraint
Federal:
Reclamation . Cost
plan review
Designation . Prohibition
of areas un-
suitable for
mining
. State:
Reclamation . Cost
plan review
Designation . Prohibition
of areas un-
suitable for
mining
Not Applicable
Not Applicable
National Flood
Insurance Program
Provision Constraint
. Participating . Prohibition
counties only: or Cost
Construction (depends on
permit accord- flood level)
ing to county reroute
floodplain stream
ordinance levee
Same as above Same types
floodproofing
elevation
Same as above Same types
floodproofing
elevation
Wetlands Protection
Provision Constraint
. Federal . Prohibition
Corps of Engineers or Cost
404 permit review (Mitigation)
. State . Same
Certification
of Corps 404
permit
Comment by wild-
life agency
Same as above Same as above
Same as above Same as above
-------
the most constrained by floodplain regulations of all scenario
activities. Mining within a 100-year floodplain will be subject
to special review requirements and encounter special site design
standards regarding maintenance of drainage patterns. It is pos-
sible that actual prohibitions may arise on a case-by-case basis,
based on interpretation of the "lands unsuitable" provision in
the federal and state mining laws. Mining anywhere within the
100-year floodplain could possibly be prohibited because it may
not be possible to properly mine and reclaim the area. Opera-
tions proposed for the floodway will almost certainly be consid-
ered as areas unsuitable for mining. Engineering solutions may,
however, be available in each instance, which would allow mining
of the resource. The cost will increase, and feasibility of
engineering solution (such as rerouting the stream around the
mine site or constructing protective levees) is likely to decline
as the flood frequency factor increases.
3.3.1.2 Power Plants
Mine-mouth generating facilities would have somewhat
greater flexibility in siting than surface mines and so would
have less difficulty avoiding floodplain problems. Although
presently constrained to be sited relatively near the lignite
source by transportation costs, a power plant would have com-
paratively more alternatives than a mine within a particular
locale in terms of being sited outside floodprone areas.
3.3.1.3 Industries
Industrial facilities using lignite are not necessarily
confined to the lignite region and therefore will not encounter
floodplain constraints different than at present. Conversion
to lignite will not necessarily increase their existing problems
with floodplain restrictions.
209
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3.3.1.4 Secondary Development
Secondary development such as housing, schools, hospi-
tals, commercial services, etc. would be required to either locate
outside floodprone areas or elevate and floodproof structures.
The constraint posed on secondary development would not affect
the scale of lignite development, but could influence community
land use patterns on a local level.
3.3.2. Authority for Floodplain Regulations
Floodplain restrictions exist at the federal, state,
and local level. Federal controls include:
Surface mining requirements under the Federal
Surface Mining and Reclamation Act,20
Wetland protection measures pursuant to
Section 404 of the Federal Clean Water Act,21
Floodplain management provisions of the
National Flood Insurance Program.22
State controls include:
• Review of facilities located in water courses
under the Texas Water Code,
Certification of Section 404 permits issued
by the Corps of Engineers, and
Surface mining requirements under the Texas
Surface Mining and Reclamation Act.
210
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Local control outside municipal boundaries is exercised
by county floodplain management ordinances adopted pursuant to
National Flood Insurance Program requirements, which restrict
development in flood hazard areas. Of 61 counties underlain by
lignite, 18 now have such ordinances and many, if not most, of
the remainder can be expected to enact similar ordinances so as
to participate in the Flood Insurance Program.
3.3.3 Geographic Scope of Floodplains
Twelve major river basins intersect Texas' Lignite
Belt, flowing roughly perpendicular to the direction of the lig-
nite trend. Approximately five to ten percent of the total area
of the Lignite Belt may lie within a 100-year floodplain. This
percentage is higher for certain areas, especially those in the
Northeast and Central Subregions, where lignite deposits with
the best potential are found. Figure 3-12 shows floodplains
intersecting lignite deposits.
Figure 3-12 shows that the,Central, North Central, and
Northeast: Subregions are intersected by numerous floodplains of
varying geographic extent. The development of lignite resources
could be significantly restricted in or near major water courses
and the siting of lignite facilities could be affected by flood-
plain controls in as much as 10 percent of the entire study area.
211
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FLOOD PRONE AREAS
Figure 3-12
02-4308-1
212
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3.4
ETJ's (and Incorporated Areas) as a Constraining
Factor
Summary and Conclusions
Extraterritorial jurisdictions (ETJ's) are not
expected to impose a serious constraint on the
overall development scenario, although it is
assumed that siting within an ETJ will be dif-
ficult or impossible in the future.
For the most part, ETJ's of significant size do
not overlie the actual lignite trend.
According to Article 970A, TEX. REV. CIV. STAT., an
incorporated town or city in Texas has certain authority (sub-
division controls, for instance) over land beyond the city limits.
This authority is referred to as extra-territorial jurisdiction
(ETJ). The geographic extent of ETJ varies directly with popu-
lation size, according to the schedule in Table 3-13.
TABLE 3-13. EXTENT OF ETJ IN TEXAS
Population
ETJ
Less than 5,000
5,000 to 25,000
25,000 to 50,000
50,000 to 100,000
Over 100,000
h mile
1 mile
2 miles
3% miles
5 miles
213
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An assumption used in this siting analysis is that
decision makers will choose not to locate a power plant within
the ETJ of a city because of potential controls the city might
exercise and because of probable opposition from within the. city.
Hence, areas within the ETJ of a city are generally not consid-
ered available for power plant or surface mine siting. In actual
practice, plants are sometimes located within ETJ's; thus, this
assumption reflects an expected future trend.
Only those cities with populations greater than 25,000
are included in the siting analysis. The reason for excluding
cities less than 25,000 is that their areas, even with a one-
mile ETJ, are not sufficiently large to affect the overall avail-
ability of sites within the entire study area.
The results of the exercise are presented in Figure
3-13.
AREAS CONSTRAINED
BY ETJ CONSIDERATIONS
Figure 3-13
02-4310-1
214
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3.5
Substrate Capability as a Constraining Factor
Summary and Conclusions
Suitability of physical land features was evaluated,
at the county level, on the basis of suitability for
heavy construction and surface-water impoundment.
No counties were classed as good according to
these criteria.
Relatively speaking, counties in the Gulf Coast Sub-
region, and in parts of the Southern, Central, and
Northeastern Subregions, exhibited the greatest con-
straint.
Substrate capability, or the suitability of a partic-
ular location for the construction of a power plant in terms of
physical land features, was examined according to the following
method. The source of information for this analysis was work
done by the Bureau of Economic Geology at the University of
Texas at Austin.211 This very useful study classified different
areas of Texas according to natural suitability for particular
•land uses. One such category of analysis was construction suit-
ability. The following descriptions define physical properties
and features in terms of construction suitability;
Construction Suitability
Good
Moderate
Properties and Features
Poor
Generally suitable for light and
heavy construction, high foundation
strength, low flood potential.
Structural designs may require
modification because of moderate to
high shrink-swell potential, low
foundation strength, moderate to
steep slopes.
Includes areas with high flood
potential, unstable slopes, high
potential for storm drainage, high
biological productivity.
215
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These construction-suitability categories were further
refined by including permeability as a factor. Low permeability
was defined as optimum and high permeability as a negative fac-
tor, due to the difficulties of impounding necessary water for
power-plant cooling and make-up in permeable soils. The two
factors, construction suitability and permeability, were joined
according to Table 3-14.
TABLE 3-14. OVERALL SUBSTRATE CAPABILITY AS A SITING
FACTOR, DEFINED BY CONSTRUCTION SUITABILITY
AND PERMEABILITY
Construction Suitability
Rating
Good
Good
Good
Moderate
Moderate
Moderate
Low
Permeability
Low
Moderate
High
Low
Moderate
High
Any Rating
Overall
Substrate
Capability
Good
Moderate
Poor
Moderate
Moderate
Poor
Poor
This analysis resulted in all areas being defined as
moderate or poor in terms of substrate capability. There were
no areas where construction suitability was judged to be good
and where permeability was low. Therefore, using the percent
of land area in each county classified as poor in terms of sub-
strate capability, the map shown in Figure 3-14 was made. The
darkest areas show those counties which had 90 percent or more
of their land area classified as poor in terms of substrate
capability. These regions include the entire Gulf Coast and
portions of South, Central, and Northeast Subregions.
216
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CONSTRUCTION
SUITABILITY
CONSTRUCTION SUITABILITY AS A
CONSTRAINING FACTOR IN SITING
Figure 3-14
02-4306-1
217
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3.6 Distance from Lignite as a Constraining Factor
Summary and Conclusions
• Presently, lignite shipments covering more than 50
miles are not considered economical.
Rail access and condition of lines is not
expected to constrain lignite shipment.
At this time, almost all lignite is used at or near
the mine mouth, and haul distances of more than a few miles are
generally considered uneconomical. The primary reason for this
is the high ash and water content of lignite, relative to its
heating value. Based on current shipping costs, the per-million-
Btu-mile cost of moving lignite by rail is higher than that for
either western or midwestern coal. Short hauls made by truck
are even more expensive, per million-Btu-mile. Another drax^back
to long-distance transport of lignite is its tendency to spon-
taneous combustion. Overcoming this problem during shipment
requires special precautions that add to the overall cost.
Presently, most lignite is hauled less than five miles
by truck from the mine to the point of use. Only three instances
of regular rail shipment of lignite are known at present. Two of
these are in North Dakota, at distances of 20 and 28 miles. The
third is in Texas, and covers a total distance of 45 miles from
the mine to Texas Utilities' Monticello Generating Station.
As pointed out in Chapter II, however, the economical
transport distance for lignite is really set by the delivered
cost of coal. As this cost rises, due to increasing production
costs, rail tariffs, severance taxes, etc., it may become econ-
omical to ship lignite longer distances by rail. This factor is
218
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more likely to affect industrial uses, which may have a strong
affinity for existing industrial centers, than power plants
which can be more easily sited near lignite supply sources.
Rail access is good throughout the Lignite Belt. Al-
though some lines might have to be upgraded to carry unit lignite
trains, availability of rail transport was not considered a con-
straint in and of itself.
Figure 3-15 presents the base map used to illustrate
lignite shipping distance as a constraint on siting. Distances
of less than 25 miles, and 25 to 50 miles are shown.
219
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SO MILES
25 MILES
25 MILES
DISTANCE FROM LIGNITE
Figure 3-15 02-4323-1
220
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4.0
DEVELOPMENT OF COMPOSITE SITE-SUITABILITY MAP
The evaluations given in the preceding section of po-
tential siting constraints imposed by six physical and environ-
mental factors were combined to yield a composite evaluation of
all the constraints acting together. To do this, a grid of
squares 20 km on a side was laid over each of the constraint
maps. This size was chosen to correspond with the minimum spac-
ing acceptable between 1500-MWe power plants, when the full PSD
increment for S02 is available. Each grid unit was then given
a rating from one to five for each of the constraining factors,
reflecting the relative degree of constraint appropriate for that
square. (A rating of one indicated least constraint, and five,
most.) Then, each factor's score was weighted by a factor se-
lected by the study team as a whole to reflect the strength of
that factor relative to the others. Out of a possible range of
one to five, the following weights were chosen:
Factor
Air Quality
Fresh Water Availability
Flood-Prone Areas
Extr a-Ter ri t o rial
Jurisdiction
Construction Suitability
Distance to Lignite
Weight
4
3
3
4
2
2
Figure 4-1 depicts the composite grid array and identi-
fies various ranges of calculated values. The original array of
undifferentiated composite numerical values was first separated
into ten classes by dividing the interval between the highest and
lowest scores into ten equal parts. Then these groups were con-
densed into the four groups shown in Figure 4-1, on the basis
221
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aUGMTEBELT
CONSTRAINTS
LEAST
1 D
2 0
3 0
4 •
02-4333-1
Figure 4-1. Composite Site Suitability Map
Showing Study Area Subregions
MOST
222
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of the major breaks between groups in the original series of ten.
. For example, the numbers of squares differentiating the three
highest-scoring groups was small, compared to the number of
squares added when the fourth-highest is added. Thus, the first
three were combined, while the fourth was considered as belong-
ing to a new group.
The composite map primarily depicts zones of increas-
ing cost and decreasing permittability. While there may be small
areas within each square where a power plant could not be sited,
it is doubtful that in even the highest-scoring squares there
would be no possible sites at all. However, the differences in
the cost of constructing and operating a plant, as well as the
difficulty of obtaining the necessary permits, may differ consi-
derably between high- and low-scoring squares.
As an aid to identifying potential future siting pat-
terns, the two lowest-scoring zones — the zones of lowest pre-
sumed cost and highest permittability--may be considered likely
to experience siting activity sooner, and perhaps more intensi-
vely, than the others. Of eight new or planned coal- and lignite-
fired power plants within the five study subregions, six are
located in areas mapped in the lowest-scoring zone in Figure
4-1. Eleven are in the following zone, but this number may be
slightly misleading, since potential air quality effects of these
plants were included as a factor in evaluating air-quality con-
straints. Only one plant falls in the highest-scoring category,
and none in the second-highest.
The circumstances which may induce a utility to locate
a plant in an area with high attendant costs and risks vary from
firm to firm and cannot be predicted. Thus, it would not be
reasonable to conclude that future siting patterns will conform
223
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exactly to the zones in Figure 4-1. However, the map suggests
that an overall trend toward siting new plants away from the
Gulf Coast may be looked for, not only for lignite-fired plants
but for coal-fired plants as well.
Because industrial uses of lignite and coal will vary
greatly in size, no such standardized analysis may be applied
to them. Also, different industries experience varying degrees
of economic affinity for already-developed areas. However, it
appears from the preceding analysis that sufficiently large
areas exist which are relatively free of serious constraint to
accommodate both industrial and utility growth. Some conflicts
are likely to arise, especially over air emissions, especially
in areas which are favorably located with respect to both major
market centers and available lignite.
-------
5.0 POLICY ISSUES
Most of the policy issues related to siting arise over
the impacts of individual projects, considered one by one. These
issues concern provision of adequate protection for the environ-
ment and adequacy of governmental resources to plan for and cope
with change. Issues of this kind are identified at the end of
Chapter IV, which deals with impacts, rather than here. Two
distinctive issues emerge from the discussion of water as a
constraining factor, however, which relate to problems of allo-
cation, rather than impact.
Water Supply. How can adequate supplies of water
be made available for energy growth, at reasonable
cost and without undue conflict between water users?
As was discussed at length in Section 3.1, increasing
pressure on the state's water supplies, arising partially from
energy growth, appears likely to result in a redistribution of
use patterns. Both changes in the relative amounts of water
used by different sectors are probable as prices rise under in-
creasing competition. At the same time, increased demands will
be placed on ground water. Higher pumpage rates will draw down
aquifers and pumping costs per unit of water will rise as water
is withdrawn from greater and greater depths.
These trends potentially pose problems of equity and
efficiency. On the one hand, some present users - particularly in
agriculture - may find themselves progressively disadvantaged rela-
tive to other users with greater economic returns. On the other
hand, these other users may return more to the economy through
their use of water. The considerations of equity - protection
of existing users - must be balanced against those of economic
efficiency - getting the most for everybody from the use of a
limited resource.
225
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Of particular concern is the lack of control over
ground water use and pumping rates. Considerable debate also
centers around pricing new water supplies. It has been proposed
that increased water prices will promote conservation, but not
all users are in a position to make the necessary investments in
new equipment and technologies.
Consumptive Water Use. How can increasing power-plant
cooling water consumption be kept from placing an undue
burden on water supply management.
Evaporative cooling consumes very large amounts of
water, which accounts for the bulk of the consumptive water use
by power plants. Current federal and state policies, however,
conflict over the best way to balance consumptive use with con-
trol of thermal discharge. Aside from dry cooling, which entails
very large efficiency penalties, the available options consist of
once-through cooling in natural or constructed water bodies, or
wet cooling towers. Once-through cooling on a large water body,
such as the ocean or a large, multi-purpose reservoir, consumes
relatively smaller amounts of water than the others. The Texas
Department of Water Resources advocates such designs. But EPA,
administering the Clean Water Act of 1977, which generally pro-
hibits thermal discharge, requires a complex and costly study
program in support of a variance to permit once-through cooling.
The amounts of water consumed by cooling towers or
special-purpose cooling lakes vary with the climate where they
are located. There is thus an optimal distribution for the two
options across the state resulting in the lowest combined water
consumption. However, a distinction is made in the federal law
between specially constructed cooling lakes and cooling ponds,
the former requiring the same variance procedure needed for dis-
charge into rivers, lakes, and the ocean. As interpreted by EPA,
nearly all cooling impoundments are classified as cooling lakes.
226
-------
A key pending decision is EPA's promulgation of new
source performance standards for thermal discharges from steam-
electric power plants. The original standards were overturned
by a federal court in 1976.
227
-------
-------
6.0 FUTURE RESEARCH AND INFORMATION NEEDS
Specific information regarding the perceived im-
portance of various siting factors in recent or
pending siting decisions by utilities and indus-
try.
More specific breakdown of potential industrial
lignite use, followed by a detailed analysis of
factors which may constrain siting for various
types of industrial facilities in the study area.
Particular attention should be given to potential
conflicts with utilities and their consequences
for overall management of the PSD increment.
Revision of the current supply-demand forecasts
of the Department of Water Resources to include
the effects of existing contracts and water rights,
Following publication of the results of the Bays
and Estuaries Study, evaluate alternative mech-
anisms—both legal and engineering—of managing
current and future water supply to provide needed
fresh water inflows.
Evaluation of potential extent to which rising
prices displace surface-water demand onto ground-
water resources, as well as the hydrological and
economic consequences of such a shift.
Evaluate the possibility of conflicts between
demands for eastern Texas water for energy use
and to maintain and support potential economic
growth in more arid western Texas.
Collect existing data and establish new monitoring
stations to evaluate precisely the geographic ex-
tent to which PSD increments for both TSP and S02
are completely available.
Perform an evaluation of the sensitivity of minimum
source-spacing to site-specific meteorological con-
ditions characteristic of the Lignite Belt.
229
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Evaluate quantitatively the effects of alternative
strategies for allocating the PSD increment on area*
wide emission densities.
Evaluate the additive effects of potential new com-
bustion sources in the Lignite Belt, with special
attention to downwind formation of suspended partic-
ulates, to determine if the availability of PSD in-
crements for TSP are threatened at a greater distance
than that to which new source compliance is nor-
mally calculated. Analyze the impact of spacing and
emission control on such effects.
Quantitatively estimate the tonnage of lignite
potentially in questionable status due to location
under 100-year floodplains.
Perform sensitivity analyses of the CLASS method of
evaluating the joint effects of several constraining
factors by varying the weights assigned to them.
230
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REFERENCES CITED: CHAPTER III
1. Texas Industrial Commission staff, personal communication,
November 16, 1978.
2. Beale, Calvin, The Revival of Population Growth in Non-
Metropolitan America, USDA-ERS #605, U.S. Department of
Agriculture, 1975.
3. Radian Corporation, 1978, An Environmental Overview of Future
Texas Lignite Development, U.S. Environmental Protection
Agency, Washington, D.C.
4. Dickerman, J. C., W. R. Menzies, and M. D. Matson, 1978.
Direct Combustion of Coal for Steam and Power Generation:
A Technical and Economic Analysis of Coal Selection. Paper
presented at the International Coal Utilization Conference
and Exhibition. Houston, Texas. October 17-19, 1978.
5. Benson, Fred J., Vice-President Engineering and Non-
Renewable Resources, Texas A&M University, personal communi-
cation, November 21, 1978.
6. Austin American-Statesman. November 12, 1978.
7. Dimitriades, B., 1978. EPA's View of the Oxidant Problem
in Houston. Env. Sci. Techn., 12:642-643.
8. Texas Department of Water Resources, 1977, Continuing Water
Resources Planning and Development for Texas, Austin, Texas.
9. Harte, J. and M. El-Gasseir, 1978. Energy and Water.
Science 199:623-634.
10. Dobson, J. E., et al., 1977. Nationwide Assessment of
Water Quantity Impacts of the National Energy Plan.' Vol.
I: Summary and Conclusions. Oak Ridge National Laboratory.
11. Espey, Huston and Associates, Inc., 1977. Final Report:
The Use of Surface Water Impoundments for Cooling of Steam-
Electric Power Stations.
12. McNeely, J. G., and R. D. Lacewell, 1977. Surface Water
Development in Texas. Texas A&M University, Agricultural
Experiment Station.
231
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13. Hutchins, W. A., 1977. Water Rights Laws in the Nineteen
Western States., Misc., Pub. No. 1206, Natural Resource
Economics Division, Economic Research Service, U. S. Dept.
of Agriculture, U. S. Gov't. Printing Office, Washington,
D.C., 3 Vols.
14. Personal communication with legal staff of Texas Depart-
ment of Water Resources, October 17, 1978.
15. Texas Water Development Board, Texas Water Plan, 4 Vols.
Austin, 1968.
16. EPA, Guideline on Air Quality Models, EPA-405/2-78-027,
OAQPS No. 1.2-080, U. S. Environmental Protection Agency,
April, 1978.
17. EPA, Compilation of Air Pollution Emission Factors, 2nd Ed.,
Apri1, 1973.
18. Federal Register, Vol. 43, No. 118, "1977 Clean Air Act;
Prevention of Significant Air Quality Deterioration, State
Implementation Plan Requirement," Monday, June 19, 1978.
19. Clean Air Act, Pub. 1. 95-95, 91 Stat. 685, 42 U.S.C. 7401
(1977).
20. Surface Mining Control and Reclamation Act, Pub. L. 95-87,
91 Stat. 445, 30 U.S.C. 1201 et seq. (1977).
21. Clean Water Act of 1977, Pub. L. 95-217, 91 Stat. 1566,
33 U.S.C. 1251 et seq. (1977).
22. Flood Disaster Protection Act, Pub. L. 93-234, 42 U.S.C.
4001, as amended.
23. Texas Surface Mining and Reclamation Act, art. 5920-10,
TEX. REV. CIV. STAT.
24. Kies, R. S., L. E. Garner, andL. F. Brown, Jr., 1977.
Land Resources of Texas, Bureau of Economic Geology,
Austin, Texas.
232
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CHAPTER IV: ENVIRONMENTAL AND SOCIOECONOMIC
IMPACTS OF THE DEVELOPMENT SCENARIO
Abstract
In this chapter, the development scenario derived in
Chapters I and II is used as a basis for evaluating the
potential impacts of energy development in the study area.
Impacts are considered in the areas of air quality, solid
waste, water quality , water supply, aquatic and terres-
trial ecosystems, and socioeconomic factors. The discus-
sion of each area is preceded by a summary of conclusions,
and followed by suggestions for further research which
would improve impact evaluation and prediction. Emphasis
has been placed on discovering impacts operating at a
cumulative, regional level, which might not become evi-
dent from studying local impacts only. Local, site-spe-
cific impacts are also discussed, but from a generic per-
spective. The concluding section of this chapter sets
forth policy issues arising from the findings of this en-
vironmental review.
233
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1.0 INTRODUCTION AND STATEMENT OF PURPOSE
The following sections present the results of an en-
vironmental and socioeconomic review of the development scenario
derived in Chapters I and II. The scope of this review was
limited to existing information. Thus, the results illustrate
not only what can be said at this time about the impacts of
energy development, but also where more research is needed. In
addition to literature review, emphasis has been placed on ex-
pert opinion among individuals involved in dealing with these
impacts. Many of the ideas presented here are derived from
discussions with utility representatives, environmentalists,
regulatory agency personnel, and other researchers in academic
and private institutions.
In conducting this review of impacts, emphasis has
been placed on identifying impacts occurring on a cumulative,
regional scale, which are not immediately apparent from a study
of individual projects. This decision was based on the fact
that the current system of permits required for large energy
facilities requires extensive local data-gathering, and evalua-
tion of site-specific impacts. There is also a large and grow-
ing body of academic literature on site-specific impacts and
case studies. Comparatively little effort has yet been made to
integrate these local perspectives into a regional picture. Yet,
it is with long-term regional-level phenomena that resource
planners must deal.
In some cases, this effort has revealed significant
new perspectives, as in the case of the additive air quality
impacts of regionwide lignite combustion and dispersion of em-
ployment impacts over time. In other cases, what appeared to
be a potential regional problem was shown, on further investiga-
tion, to be of less concern than was first thought. Thus, the
235
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impacts of consumptive water use on streamflow and assimilative
capacity, at the basin level, are shown to be measurable, but
small. Both negative and positive results are of value, for
they point out to planners where the most pressing problems may
lie.
The progressive interlocking of regulatory policies
governing various environmental resources is tending more and
more to place long-term planning responsibilities on agencies
which in the past have been chiefly concerned with granting
permits. It is hoped, therefore, that what follows will provide
both useful perspectives for the evolution of this kind of plan-
ning capability, and point the way to further research efforts
needed to provide it support.
236
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2.0
AIR QUALITY IMPACTS OF LIGNITE DEVELOPMENT
Summary and Conclusions
The overview of potential air qual'ity impacts presented
here considers the joint effects of both coal- and
lignite-fired facilities built in the East Texas study
area. Modeling was not attempted, either of single
sources or areawide patterns of sources.
New Source Performance Standards will result in power-
plant emissions an order of magnitude or more below
uncontrolled sources. New plants will be cleaner than
most existing ones.
Gasification plants emit criteria pollutants, but levels
are held down when product gas is used to supply the
plant's fuel needs. Fugitive hydrocarbon emissions
arise from a variety of in-plant sources.
Lignite appears to contain less arsenic than average
values -for western coals, but may contain very large
levels of uranium at seam boundaries or near partings,
Based on combined emissions from all coal and lignite
sources operating in 2000, the lignite development sce-
nario would raise particulate emissions 5 percent,
S02 emissions 70 percent, and NOX emissions 60 percent
over 1973 state-wide totals.
Gaps in air quality and meteorological data and possibly
inadequacies in theory, prevent definitive evaluation
of the risk of long-distance transport and trans-
formation of pollutants. The potential for downwind
violation of TSP and ozone standards because of atmos-
pheric transformation and transport processes remains
an open question.
237
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2.1 Emissions from Lignite Development
The increased development and use of lignite in Texas
will directly contribute to the state's air pollutant loading
through mining, combustion, gasification, and indirectly through
urban growth induced by economic growth along the lignite belt.
2.1.1 Emissions from Mining
Although the heavy equipment used in mining produces
some sulfur dioxide (802), nitrogen oxide (NOX).particulates.
carbon monoxide, and hydrocarbon emissions, the principal air-
quality impact of mining is on particulate levels close to the
mine.
In most circumstances, lignite mining operations will
generate considerable particulate matter--coal dust and soil
particles. Except for the fine particulates, it appears that
most of this matter settles to earth within the mined area it-
self.
In the southwestern portion of the lignite belt, which
generally contains lower-quality lignite and also has lower an-
nual rainfall, there is greater potential for fugitive dust
emissions from mines. Wetting mine haul roads will minimize the
formation of fugitive dust, and dust-suppression systems can
control emissions from lignite handling. The handling of lig-
nite for mine-mouth steam electric stations typically does not
include processes that heat, wash, or blow air upon the lignite
or involve discrete air emission sources. Handling facilities
such as hoppers, silos, stackers, and crushers include dust-
suppression systems which dampen the lignite for dust control.
Dust collection systems are generally used at transfer points
to minimize dust release from lignite handling.
238
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Current federal air quality regulations exempt fugi-
tive dust, defined as native soils uncontaminated by industrial
activity, from consuming the PSD increment, and the state of
Texas similarly does not regulate fugitive dust from mining. A
potential problem may exist in that NAAQS for particulates make
no distinction as to their source. Thus, in cases where mining
may contribute to NAAQS violations, the regulatory situation is
ambiguous, and could lead to litigation.
2.1.2 Emissions from Combustion
Particulates, sulfur dioxide, and nitrogen oxides
emissions are the three major criteria pollutants emitted from
lignite- and coal-combustion, and have received most of the at-
tention that has been directed toward control of atmospheric
emissions from power plants.
2.1.2.1 Potential Emissions of Criteria Pollutants
from Single Sources
Fuel type and quality play an important role in deter-
mining the quantities of particulates, sulfur dioxide, and ni-
trogen oxides which are emitted from uncontrolled conventional
combustion operations. Particulate emissions are greater for
coal-fired units than for oil- or gas-fired units, due to the
greater ash content of the fuel. Sulfur dioxide emissions depend
upon the amount of sulfur in the fuel, which may vary considerably
depending upon fuel source. Boiler design and operating condi-
tions will affect the particulate and nitrogen oxide emissions
from a power plant. In general, Texas lignite has a higher ash
and sulfur content than the subbituminous western coals which
will compete with it as a boiler fuel in Texas.
239
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Lignite (on an as-received basis) ranges in grade
from 10 to 40 percent ash and 0.6 to 2.3 percent sulfur (by
weight).1 A 1,500-MWe power plant (three 500-MWe units) will
produce the emissions shown in Table 2-1.* These figures re-
flect the use of lignite from the Wilcox Group, which accounts
for about 70 percent of the total lignite resource, and is the
best in quality of the Texas lignites.
TABLE 2-1. EMISSIONS FROM A HYPOTHETICAL 1500-MWe STATION
FIRING A TYPICAL TEXAS LIGNITE FROM THE WILCOX
GROUP
Sulfur Dioxide
Particualtes
Nitrogen Oxides
No Emission
Controls
141,500 tpy
849,000 tpy
106,000 tpy
New Source Performance Standards
September 19, 1978.
With Controls Required
for Proposed NSPS^
21,200 tpy
1,380 tpy
27,600 tpy
as proposed by EPA on
2.1.2.2 Control Technology for Criteria Pollutants
The application of emission control at the level re-
quired by EPA-proposed new standards vastly reduces the poten-
tial emissions. Various options for controlling to these levels
are now available.
*Assumes 70 percent capacity factor, and lignite with 6500 Btu/
Ib, 12 percent ash and 1 percent sulfur, 10,000 Btu/kwh heat
rate.
240
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Particulates
Particulates emitted from both coal and lignite combus-
tion consist primarily of carbon, silica, alumina, and iron oxide
in the fly ash. The quantity of particulate emissions depends
upon the design of the boiler, the ash content of the coal, and
the type of control equipment used.
Until recently the primary means of controlling par-
ticulate emissions from stationary combustion sources has been
electrostatic precipitation. With the increasing emphasis on
reducing SOz emissions, wet scrubbers and baghouses have become
alternatives for the control of particulates.
Sulfur Oxides
Coal-burning electric generating stations are the
major source of sulfur dioxide emissions in the United States.
Other than the use of relatively scarce clean fuels, flue gas
desulfurization (FGD) is the viable SOa control alternative
currently available for lignite. AFBC technologies, currently
in the developmental stages, offer an alternative to FGD toward
the end of the study period.
Flue gas desulfurization systems may be classified
into two general categories: throwaway processes (systems in
which the sulfur product is disposed of as a waste); and re-
covery processes (systems in which the sulfur product, such as
sulfur or sulfuric acid, may be sold). A number of FGD systems
are in various stages of development. At the present time, six
processes are generally considered to be the most advanced for
control of S02 emissions from fossil-fuel burning electric gen-
erating stations. Three of these--lime Scrubbing, limestone
scrubbing, and double alkali scrubbing--are throwaway processes.
241
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These processes convert the S02 from the flue gas to calcium
sulfite and calcium sulfate solids which must be disposed of as
a waste sludge or solid by-product. Three recovery processes
are considered to be well advanced: magnesia or magnesium
oxide scrubbing; sodium-based scrubbing (Wellman-Lord); and
catalytic oxidation. These processes recover S02 in the flue
gas for conversion to sulfuric acid, liquid S02, or elemental
s ulfur.
In AFBC systems, sulfur oxides are captured by sor-
bents (usually calcined limestone) which are mixed with the coal/
lignite in the fluidized bed itself. The residue, which contains
both ash and calcium-sulfur-oxygen compounds, is dry. AFBC
pilots have been successfully tested at current NSPS of 1.2 Ib
per million Btu's, but performance under proposed NSPS has not
yet been evaluated.
Nitrogen Oxides
Nitrogen oxides may be formed during combustion of
fossil fuels either by thermal fixation of atmospheric nitrogen
from combustion air (thermal NOX) or by conversion of fuel bound
nitrogen to NOX (fuel NOX). By modifying the conditions at which
fuel combustion occurs, it is possible to minimize the formation
of both fuel and thermal NOX. In simple terms, the most signif-
icant combustion parameters are the combustion temperature, the
amount of oxygen available to combine with nitrogen, the length
of time which N2 and 02 remain in high concentrations in high
temperature regions, and the rate of combustion-gas cooling.
Methods for controlling NOX emissions from fossil
fuel-fired electric generating stations are 1) low excess air
firing (LEA), 2) staged combustion (SC), 3) flue gas recircula-
tion (FGR), and combinations of these.
242
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2.1.3 Emissions from Gasification Processes
The sulfur contained in feed coal or lignite is re-
moved from the product gas stream in a gasification plant, so
that the gas will burn cleanly. Sulfur is ultimately removed
in the solid, elemental form, so the plant has no major SOa-
containing waste gas stream. Process vent gases, which contain
hydrocarbons and carbon monoxide are typically incinerated so
that only COz and water are released. Small amounts of sulfur
in these vent gases are oxidized to
Facilities ancillary to the; gasifier train itself may
produce larger emissions. If coal is combusted to supply in-
plant heat, steam and power needs, its emissions will be similar
to those from a power plant boiler, although lower in total
quantity.
Product and by-product storage and transfer may re-
sult in fugitive emissions of hydrocarbons. Hydrocarbon emis-
sions arise from a very large number of sources such as pump
seals, joints, valves, flanges, and storage tanks. Use of
mechanical seals on pumps, vapor recovery systems on tanks,
and other protective design and equipment features , properly
maintained, can reduce these emissions considerably. •
Table 2-2 summarizes all of these various emissions
expected from a well-operated Lurgi-process gasification plant
of a size similar to that postulated for the development scenario
under analysis.
2.1.4 Trace Elements and Radioactive Emissions
Trace elements contained in coal may be captured in
bottom ash or may volatilize and go out the stack. Portions of
243
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TABLE 2-2. AIR EMISSIONS OF CRITERIA POLLUTANTS FROM A 250 MMacfd LURGI PLANT*
Stack Parameters
Air Emissions (Ib/hr)
Source
Boilers & Turblnaa
Steam Superheater
Fuel Gag Heater
Incinerator
Storage
Fugitive Loaaea
TOTAL
Paniculate
negligible
negligible
negligible
negligible
—
—
negligible
SOi
248
34
B
226
—
—
516
NOX CO
418 —
57 —
13 —
161 —
—
- -
649 —
Source: Radian Corporation. Characterliatlon of
•Producing Hlgh-Btu gaa.
HC Rate(lb/hr) Flou(ACFM)
5.7 xlO6 1.8 xlO*
-- 0.31x10' 0.10x10*
— 68.0 x!0s 22.0 xlO'
1.6 xlO' 0.5 xlO'
7 7
40 40
47
Waste Effluenta fron t Lurnl
Velocity Hgt
(fpa) (ft)
60 300
60 300
60 300
60 300
50
—
Caalflcatlon
Temp
CF)
300
300
300
300
--
Plant.1
the volatilized emissions of this latter group of elements typ-
ically recondense on small fly ash particles as the flue gas
cools. Three of these elements are particularly relevant to the
use of Texas lignite.
Arsenic from coal combustion, carried mainly on
particles, is one of the major components of man-made arsenic
contributions to the atmosphere. Because arsenic pollution from
man-made sources is about five times the size of natural contri-
butions in the Northern Hemisphere, EPA is considering emission
standards for arsenic.3 Arsenic has been measured in a limited
number of samples from the Wilcox lignite in Freestone County.1*
The values found ranged from 1.0 to 5.5 ppm, as compared with an
average value of 101 western coals of 15 ppm.5 Thus, at least
in some cases, Texas lignite may result in arsenic emissions con-
siderably lower than those of some competing western coals.
In the same set of Texas lignite samples, selenium
concentrations varied from 3.9 to 22.9 ppm, and exhibited strong
244
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fluctuations within the same seam. The upper values are consid-
erably higher than average concentrations of 2 ppm for 101 western
coal. The highest value among the western coals were only 8 ppm.5
Thus, depending on whether the average selenium concentrations
of the large volumes of coal used in a commercial facility lie
toward the upper or lower end of this range, selenium emissions
from lignite could be higher than those of most competing western
coals. Unlike arsenic, however, selenium is not one of the un-
regulated pollutants which EPA is required by the Clean Air Act
Amendments of 1977 to give immediate regulatory consideration.
Uranium.is found in Texas lignite in quantities that
vary considerably throughout seams. Highest uranium levels are
found at the contacts of lignite seams with sandstones or shales,
and sometimes adjacent to shale partings. In the Wilcox lignite,
concentration at these contacts may be by a factor of as much as
20, resulting in maximum concentrations of 20 ppm. In the Yegua-
Jackson lignite, similar concentration factors lead to high values
of 70 ppm, while in the Upper Jackson, a noncommercial lignite
strata, concentrations are reported of up to 7800 ppm.6
The maximum values are very high, compared both to
seam averages and to comparable values in western coals. Fort
Union Coal from Wyoming, for example, typically contains less
than 1 ppm. Thus, those portions of seams with the highest
uranium values will probably need to be segregated from fuel
supplies delivered to commercial users.
Under the Clean Air Act Amendments of 1977, EPA is
required to determine whether radioactive emissions require
regulation to protect human health. Any such regulation, ap-
plied to Texas lignite, would have to take account of the oc-
currence of localized uranium concentrations.
245
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2.1.5
Secondary Impacts
Although the major air quality impacts associated with
lignite development relate to the mining and combustion of the
resource, the activities associated with increased population
and secondary developments will generate air pollutants. These
are primarily in the form of hydrocarbons, carbon monoxide and
nitrogen oxide emissions from automobiles.
2.2
Projected Emissions of Criteria Pollutants
Currently, there are no areas designated as non-attain-
ment for S02 or NOX in Texas. Only small portions of several coun-
ties have been designated as non-attainment for particulates.*
None are near lignite producing areas. In general, the air quality
for the entire study area is good. Table 2-3 shows representative
cities.
TABLE 2-3.
THE 1976 AMBIENT AIR QUALITY CONCENTRATIONS IN THE URBAN AREAS AROUND
THE LIGNITE BELT (mlcrograms per cubic meter)
Total Suspended Particulates
Site Location
Austin
Bryan
Dallas
Houston (Cyprcsa)
San Antonio
Mt. Pleasant
Texarkana
Tyler
National Ambient
Air Quality
Standard
Source: Tcxao Air
Maximum
24-Hour
Average
193
169
175
166
202
116
194
151
260
Control
2nd Maximum
24 -Hour Geometric
Average Mean
163
110
161
148
96
103
ISO
111
260
Board'
60
74
69
62
53
56
99
55
75
Sulfur Dioxide
Maximum
24-Hour
Average
9
2
19
8
2
96
18
15
365
(SOj)
2nd Maximum
24-Hour Arithmetic
Average Mean
2
2
8
2
2
67
14
2
365
2
2
2
2
2
6
3
2
80
Nitrogen
Dioxide
(N02)
Arithmetic
Mean
28
4
54
23
24
23
25
30
100
*As noted in the Federal Register, March 3, 1978 (p. 9037),
parts of the following counties were designated as non-attain-
ment for particulates: El Paso, Cameron, Hidalgo, Nueces,
Dallas, Harris, Galveston, Maverick and Bexar.
246
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within the study area and recent ambient air quality data.
Also listed in the table as a point of reference is the appli-
cable primary national ambient air quality standard (NAAQS).
The table indicates that, in general, the air quality of the
region is below NAAQS. In,particular, the levels of SOz are
well below NAAQS.
It would be useful to compare the ambient air quality
data in Table 2-3 with levels estimated based on the siting exer-
cise described in Chapter III. However, estimates of future air
quality cannot be made without extensive dispersion modeling.
Therefore, it must be presumed that unless the NAAQS are changed,
the ambient levels of SC-2, NOX and particulates will fall below
NAAQS. The future levels of these pollutants are, however, anti-
cipated to be higher than present levels.
Although future estimates of ambient air quality can-
not be made with confidence, estimates of emissions can be made
based on assumptions regarding fuel characteristics, plant capac-
ity factors, coal and lignite consumption rates, and emission
control levels.
Tables 2-4, 2-5, and 2-6 indicate estimated regional
and total S02, NOX, and particulate emissions for 1985 and 2000
based on the proposed NSPS, current NSPS, and controls on exist-
ing sources. The emission level estimates are based on the
number of coal and lignite plants forecast in Chapters I and II
and sited in Chapter III.
To put these emission estimates in better perspective,
actual emission data based on Texas Air Control Board's 1973
emission inventory for the entire state are also presented.
247
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TABLE 2-4. COAL AND
AND 2000
Assumed
Emission
Rates
Total Number of
Coal Facilities1
Total Number of
Lignite Facilities
-------
TABLE 2-6. COAL AND LIGNITE COMBUSTION IN THE STUDY AREA: ESTIMATED 1985
AND 2000 PARTICULATE EMISSIONS (tons per year)
Assumed
Emission
Rates 1973 1985
Total Number of
Coal Facilities1 — 16
Total Number of
Lignite Facilities 2 24
@ .03 lb/106 Btu2 18,400
@ .1 lb/10* Btu3 61,300
@ .3 lb/106 Btu" 184,000
Actual 1973s 29,500
'Utilities and industrial facilities equivalent to 500 MWe units
2Proposed NSPS levels
'Current NSPS levels
"Current control levels for existing sources
5TACB actual historical data for coal- and lignite-burning sources
2000
56
85
74,800
216,200
648,500
only
From Table 2-4, it is evident that even under the
strict proposed NSPS (requiring 85 percent sulfur removal), SOa
emissions from coal- and lignite-fired utility and industrial
facilities are projected to increase approximately six-fold be-
tween 1973 and 2000. While this appears to be a significant
increase, it should be noted that total statewide SOa emissions
(from all sources) were approximately 1,215,000 tons per year in
1973.7 If the total emissions (from all sources) were to re-
main unchanged through year 2000, the incremental increase
caused by the new coal and lignite facilities would be about 70
percent (assuming application of the proposed NSPS). In addi-
tion, it should be kept in mind that there is no simple and
direct relationship by which air quality can be predicted on
the basis of emissions only.
249
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Table 2-5 shows that NOX emissions from coal- and lig-
nite-fired facilities will increase to about 1.3 million tons per
year by 2000. This compares to the 1973 total of 2.1 million
tons of NOX emissions from all point sources in the state.7
Table 2-6 shows that particulate emissions under the
proposed NSPS will result in more than doubling 1973 levels from
coal and lignite combustion. The approximately 75,000 tons per
year projected for year 2000 is small, however, compared to the
approximately 1.4 million tons per year of total particulate
emissions for all point sources in the state in 1973.
2.3 Potential Long-Term Impacts of Increased
Coal and Lignite Burning
2.3.1 Downwind Fate of Power Plant Emissions
By law, all new power plants permitted in Texas will be
required to avoid violating either NAAQS or PSD for regulated pol-
lutants. Models used to assess compliance are considered accur-
ate out to 50 km,* although accuracy becomes very uncertain at
greater distances. Thus, standards may be presumed met at least
this close to each plant. Assuming that these standards are ade-
quately set, then substantially adverse affects on human health,
vegetation, and animals will be avoided within this 50-km radius.
Recent research, however, has shown that the impacts
of large power plants potentially extend well beyond this range,
especially where plants are aligned with respect to wind direc-
tion. Of particular importance is the formation of particulate
sulfate compounds through the oxidation of S02 in the atmosphere
downwind of the original source.9 Since water participates in
^Reference is made to the EPA CRSTER model.
250
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these reactions, they are favored by high humidity. The pres-
ence in the atmosphere of ozone, a strong oxidizing agent, also
promotes sulfate formation. Other airborne participates may
also form in a similar manner downwind from the source.8 These
particles contribute to acid rainfall, and are frequently a
significant component of total suspended particulates (TSP).
Sulfate is through to be directly related to visibility.9
Conditions in East Texas combine both humidity and,
perhaps, high ozone levels.* In addition to the ozone already
in the ambient air, recent observations suggest that under some
conditions ozone may form downwind from power plants by light-
mediated atmospheric reactions of NOX.10>11 A downwind ozone
"bulge" is not always observed, however. The reactions re-
sponsible for it have been shown in laboratory experiments to
depend strongly on the presence of a high ratio of ambient non-
methane hydrocarbons to NOX. Also, meteorological conditions
must allow the plume to remain stable for several hours so that
the rather slow reactions have time to build up significant
amounts of ozone. Warm temperatures and bright sunlight are
also needed. The best conditions for the formation of a downwind
ozone bulge are thought to occur in rural areas with naturally
high nonmethane hydrocarbon levels and naturally low NOX-10
Where more than one source is involved, these impacts
may be additive if they are aligned with persistent winds.
Figure 2-1 illustrates schematically that these additive effects
are more pronounced for the secondary pollutant, sulfate, than
for the original pollutant, S02. The figure also gives an idea
^Although ozone has not been extensively monitored in East
Texas, recorded levels in adjacent coastal areas are high
enough to suggest that elevated levels may characterize inland
regions, as well.
251
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c
o
O
O
in
Visunl DIIIIOU - Mnlliplo Point Sources
Sulfalu Multiple Puint Sources
SO, Mulliplu Point Sources
SO] Siiujla Point Source
Sulliilo Sinijlu Point Source
u
Ol
c
»60 KM
Short flanfiu
: 300 KM 1000 KM
LOIIIJ nnii(|t!
Figure 2-1. Schematic Diagram of Short-Range and Long-Range Air Quality Impacts
from Single and Multiple Point Sources
(Courtesy of Teknakron, Inc.) 02-4304-1
of the distances at which these downwind effects occur. It
should also be noted that worst-case conditions used in modeling
to determine the effects of single sources are not necessarily
those which produce the worst cases for additive impacts.
To determine whether these effects could cause viola-
tions of air quality standards becuase of the relatively cluster-
ed development of lignite- and coal-fired power plants in East
Texas would require sophisticated computerized modeling beyond
the scope of this study. Appropriate modeling techniques are
being developed,* but their application is hampered by the
^Considerable in-depth investigation of this problem is now
being funded by EPA's Office of Energy, Minerals, and In-
dustry.
252
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absence of meteorological and ambient air quality data at a
sufficient level of detail.*
In the present state of uncertainty, several concerns
have been raised which cannot yet be quantitatively assessed.
There is concern that emissions originating on the industrial-
ized Gulf Coast may be carried inland and added to emissions
from lignite-belt development. At the TEAC-sponsored Third
Annual Texas Energy Policies Conference held at Austin in May
of 1978, Dr. Louis R. Roberts, Director of the Texas Air Control
Board Permits and Source Evaluation Division pointed out that
SC-2 emissions in highly industrialized coastal areas may already
be high enough to approach ambient standards. At the same
meeting, Mr. Joe Moore, Head of the Graduate Program in Environ-
mental Sciences at the University of Texas at Dallas, suggested
that the combined effect of effluents from the 12 to 15 new
power plants sited and upwind of Dallas-Fort Worth may keep this
area from attaining NAAQS. The national secondary particulate
standard is also thought likely to be threatened by power plant
development, such that siting new facilities will become pro-
gressively more difficult.13 Additions to TSP because of sul-
fate formation would worsen this situation.
In addition to these effects, which would take place
within Texas, concern has also been expressed over transport of
pollutants over longer distances. Data analyzed by Teknekron,
Inc., under contract to EPA, suggest that measured levels of TSP
in Arkansas, high enough to violate the secondary standard, may
be related to long-distance transport both from the Ohio River
Valley and from the areas along the Gulf Coast. J" In a number
of cases examined by Teknekron, air parcel paths suggested that
*Brand Niemann, Teknekron, Inc., personal communication,
February 9, 1979.
253
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sulfate levels in the Ohio River Valley may have been elevated
by long-distance transport from parts of the Gulf Coast. In-
sufficient data on the prevailing directions of persistent winds
near the surface and at plume levels make it impossible to say
with certainty whether developing an array of new sources in
East Texas would contribute to these problems.
It appears, however, that both plant spacing and emis-
sion levels would together contribute to the extent of whatever
long-distance transport problems might develop. Although strict
controls might mitigate relatively short-range additive impact
problems, continued growth in a relatively confined area could
offset strict controls at the mid-range level of interstate
distances. At very long distances, such as those separating
Texas from the Ohio Valley, local siting arrangements and emis-
sion controls might have little effect, even though mid-range
problems were eased.1"
Thus, regulation of the additive, downwind impacts of
an array of power plants, should it prove necessary, might in-
volve very fundamental control of regional development, so as
to acquire the necessary leverage on total emissions over large
areas.
2.3.2 Potential Ecological and Health Impacts of
Power Plant Emissions
A major concern expressed about sulfate buildup is
the potential for acid rainfall.9 The mechanisms by which rain-
fall is acidified are only beginning to be understood. However,
it is thought that sulfate, nitrate, and chloride are the major
chemical species involved.15 Acid rainfall problems can occur
quite locally, around individual plants or small clusters of
them, or regionally as a result of heavy concentrations of
254
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sources. Although techniques to predict rainfall pH from SOz
emission rates have not yet been developed, the relationship
of sources in the Ohio Valley to acid rain in the eastern United
States is generally well accepted.9 Emission levels there,
however, average more than 20 tons/km2,16 much higher than what
seems likely to result from the growth of power production in
East Texas. Thus, acid rainfall problems on a parallel scale
appear unlikely to result, although impacts at lower levels
cannot be ruled out without further research. Evidence has also
been presented implicating atmospheric sulfates in health damage.17
Recent research, however, has led to a general lessening of con-
cern over health effects.18
Recent modelling and epidemiological work17'19'20'21
also suggests that even with extensive development of coal and
lignite, East Texas populations are unlikely to experience sig-
nificant changes in mortality rate or life span due to emissions
of presently regulated pollutants. Although long-term increases
in respiratory disease or dysfunction cannot be entirely ruled
out, the S02 and particulate levels accompanying regional lig-
nite and coal development will be unlikely to cause noticeable
effects of this kind. National Ambient Air Quality Standards
for SOz, NOa, and particulates should, if met, provide adequate
protection from short-term adverse health effects.
255
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2.4 Research Needs
Further characterization of trace-element concentrations
in lignites from various parts of Texas.
Measurement of radioactive emissions from existing
lignite-fired power plants, and evaluation of potential
desirability of lignite segregation as a means of control.
Realistic, sophisticated modeling of the additive impacts
of multiple sources in East Texas. Effect on PSD incre-
ments for SOz and particulates should be particularly
emphasized.
Improved assessment of reaction rates for key atmospheric
pollutant-transformation processes, and identification of
principal sources of geographic and temporal variation in
these rates.
Observations of conditions producing "ozone bulges" down-
wind of existing coal- and lignite-fired power plants,
and assessment of the potential importance of this phenome-
non to meeting NAAQS for ozone.
Extensive collection and assembly of meteorological tower
data and ambient air quality data for use in relating air
parcel trajectories originating in Texas to potential
problems in other states.
Improved modeling of pollutant transformation, transporta-
tion and dispersion at regional and sub-national scales.
Improved understanding and assessment of the potential
for acid rain in East Texas due to lignite demand.
Analysis of potential interstate policy conflicts concern-
ing long-distance pollutant transport, and alternative
modes of resolution.
Assessment of the potential for visibility deterioration
in East Texas as a result of increased formation of sul-
fates and other particulates.
256
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3.0
IMPACTS OF LIGNITE-RELATED SOLID WASTES
Summary and Conclusions
Solid wastes associated with the development scenario
consist chiefly of ash and residues from sulfur re-
moval. Ash and scrubber sludges are usually disposed
of in slurry form. Wastes from fluidized bed combus-
tion are dry, and contain both ash and sulfur salts.
All these wastes are alkaline, and contain most of the
trace elements originally present in the coal. When
leached with water, many of these materials go into
solution at concentrations higher than those permitted
in drinking water.
According to criteria proposed by EPA under the
Resource Conservation and Recovery Act, many of these
wastes would be considered "hazardous" and require
special handling.
A 500-MWe generating unit with a lime/limestone scrub-
ber and ESP would produce, over its lifetime, about
9,000 to 21,000 acre-feet of solid wastes if it burned
Texas lignite of various grades, 7,600 if it burned
western coal, and 11,000 with midwestern coal. Use of
regenerable scrubber systems, which produce no solid
wastes requiring disposal, would cut these amounts by
one half to two thirds.
Cumulative volumes produced depend on the choice of
fuel and SOa- removal method. Assuming as a worst case
that lime/limestone scrubbing is used on all plants
projected by the development scenario, a total of about
1.3 million acre-feet of sludge and ash would ultimately
be produced. A grand total of 66 square miles would be
needed for disposal, assuming surface impoundments 30
feet in depth.
Because aquifer recharge is a complex phenomenon over
the Lignite Belt, disposal sites must be carefully
chosen. Simultaneous growth in both ground water use
and solid waste production will probably result in in-
creasing difficulty in siting disposal facilities.
257
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3.1 Sources of Solid Waste
Federal and state air pollution requirements to re-
move particulates and sulfur dioxide from flue gases are re-
sulting in a large and growing solid waste disposal problem.
By far the largest amounts of solid wastes generated from in-
creased coal and lignite use will be ash and sludge from sulfur
removal.
3.1.1 Ash
Coal and lignite combustion produces two kinds of
solid residue: bottom ash and fly ash. Bottom ash is a coarse
material somewhat like gravel. Fly ash is the very fine par-
ticulate matter that is carried in the flue gas. When collected,
it has a fine texture similar to cement.
A requirement for near-total removal of fly ash from
flue gas is now standard. EPA's performance standard for par-
ticulate removal for fossil-fuel fired electric generating units
is 0.1 Ib/million Btu heat input, with an opacity rating of no
more than 20 percent (visually measured smoke density), for units
permitted after 1971.23
Collection methods and the estimated percentage of
power plants using each is as follows:2"*
Method Percent
Dry Electrostatic Precipitators (ESP) 61
Mechanical (Baghouse, etc.) 13
Wet ESP 6
Particulate Scrubber 3
Other 17
258
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ESP's are capable of removing more than 99 percent of
the particulates if properly designed. Mechanical collection
methods usually achieve a somewhat higher efficiency and are
sometimes used in parallel with ESP's.
Since operators are required to achieve about a 99
percent removal efficiency, the volume of ash residues produced
does not significantly affect the choice of removal technologies.
The ability of the method to meet air quality requirements, and
its cost and its reliability are considerably more important
factors.
3.1.2 Sulfur Removal Residues
Current proposals call for removal of 85 percent of
the sulfur dioxide in flue gas from all coals.25 SOa in flue
gas can be controlled both by techniques which remove sulfur
from the flue gas itself (Flue Gas Desulfurization or FGD) and
by capturing sulfur in the combustion zone (Fluidized Bed Com-
bustion, or FBC). A number of FGD systems, usually called scrub-
bers, are available now. FBC is not expected to become commer-
cial until late in the study period.*
The removal of S02 by means of scrubbers is a choice
between two general types of processes — regenerable and nonre-
generable. Regenerable scrubbers produce elemental sulfur as a
marketable by-product, and can reuse the sorbent. Non-regener-
able or "throwaway" processes produce an unusable solid waste
stream which requires disposal. The most widely used of the
throwaway processes is lime or limestone scrubbing. This is
the only FGD technology currently planned for uses in Texas.
*See Chapter I, Sections 4 and 5, for a discussion of FBC as
applied to industrial and utility boilers.
259
-------
with respect to groundwater contamination. Trace elements not
extracted with the fly ash and bottom ash will generally be de-
posited in sludge. For both separate and mixed disposal, sev-
eral trace elements potentially toxic to humans may leach out
of the wastes. The degree and rate of leaching primarily de-
pends on the stability of the wastes and the permeability of
the material used to line the disposal site. Mixing ash and
sludge wastes from lignite usually results in a more stable
material due to chemical reactions which take place when they
are combined.
Solid residues from FBC operation also contain various
sulfur-based salts of silicon, iron, potassium, sodium, magnesium,
aluminum and titanium, and oxides and salts of various trace
heavy metals.
3.2.2 Definition of "Hazardous Waste" under RCRA
The Resource Conservation and Recovery Act (RCRA) re-
quires EPA to develop criteria for identifying "hazardous"
wastes. Hazardous wastes are defined in the Act as:
"waste, which because of its quantity, concentration,
or physical, chemical, or infectious characteristics
may - (A) cause, or significantly contribute to an
increase in mortality or an increase in serious ir-
reversible, or incapacitating reversible, illness; or
(B) pose a substantial present or potential hazard to
human health or the environment when improperly treated,
stored, transported, or disposed of, or otherwise
managed." [Subtitle C, Section 1004(5)]
Criteria for identifying the characteristics of hazard-
ous waste were proposed under Sec. 3001, on December 18, 1978
(43 FR 58946), and include:
262
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toxicity • radioactivity
flammability • infectiousness
corrosiveness • toxicity to plants
ignitability • mutagenicity
reactivity • teratogenicity
Of these criteria, toxicity is most pertinent to
solid wastes from coal and lignite. EPA has proposed to classify
utility waste as "special waste" along with certain other high-
volume/low-risk wastes. Treatment, storage and disposal
requirements are being deferred until further studies are com-
pleted.
EPA's approach to establishing criteria for contami-
nant levels is twofold:
1) Determine the risk of toxic wastes becoming
available to the environment (i.e., the ability
of toxic species to migrate out of wastes); and
2) Set concentration levels based on the National
Interim Primary Drinking Water Standards (NIPDWS)
which take into account an appropriate dilution
factor, providing an adequate margin of safety.
In assessing the potential for utility wastes to contami-
nate the environment, EPA calls for testing ash and sludge leachate,
An extraction procedure is used, which attempts to simulate real
leaching conditions, and assesses the composition of the leachate,
rather than the wastes themselves.
Threshold concentration levels are established for
leachate on the basis of uncontrolled conditions. They are
based only on the chronic toxicity to humans (rather than genetic
263
-------
activity, bioaccumulation in tissue, and toxicity to plants and
animals) as defined by the drinking water standards promulgated
pursuant to the Safe Drinking Water Act of 1974, The proposed
level is ten times theNIPDWS. The ten-fold dilution factor is
based on the amount of purification that can reasonably be ex-
pected from the point at which the contaminants enter an aquifer
to the point of a water well (assuming a 500-foot minimum dis-
tance) .2 7
TABLE 3-2.
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Nickel
Selenium
Silver
MAXIMUM CONCENTRATIONS OF CONTAMINANTS
ALLOWED UNDER NIPDWS AND RCRA
NIPDWS mg/liter
.05
1.0
.010
.05
.05
.002
10.
.01
.05
RCRA mg/liter
.5
10.
.1
.5
.5
.02
100.
.1
.5
Several of the trace elements in scrubber sludge
leachate may occur in concentrations of more than the national
drinking water standard. These elements include: arsenic,
barium, boron, cadmium, chromium, lead, mercury, and selenium.
Depending on the results of an individual test, the elements
selenium, mercury, barium, boron, and chromium may exist in con-
centrations of more than ten times the drinking water standard.28
Waste containing concentrations at these levels would be classi-
fied as hazardous by EPA under Subtitle C of the Resource Con-
servation and Recovery Act. Any contaminant concentration of
more than ten times drinking water standards must be viewed as
264
-------
exceeding the safe contaminant threshold for groundwater quality
protection resulting from lignite solid waste disposal.
According to these criteria, EPA Region VI officials
believe that much, if not most, of the sludge and ash generated
by coal- and lignite-fired power plants in Texas may be defined
as hazardous.
3.3 Potential Volumes of Solid Waste Produced in Texas
3.3.1 Waste Production from Individual Sources
For systems using throwaway FGD technology, total
solid waste production rates depend on the following factors:
Btu content of coal or lignite,
Sulfur and ash content of coal or lignite,
Boiler size and type,
Type of ash and SOa control equipment, and
Separation or blending of ash and scrubber sludge.
Since the first two of these factors depend on fuel
type, the choice of fuel affects the total volume of waste pro-
duced. Table 3-3 shows how these volumes differ between coals
from the west and midwest, and between lignites from various
parts of Texas. Emission control is assumed to be by a cold-
side ESP and a throwaway limestone scrubber.
A comparison of the volumes of ash and sludge wastes
resulting from the use of lignite and coal, assuming other non-
fuel factors to be the same in each case, shows that for a
typical 500-MWe power plant, use of lignite will produce consid-
erably more ash residue than eastern coal and somewhat more than
265
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TABLE 3-3. COMPARATIVE
VOLUMES OF
SOLID WASTE PRODUCED BY COAL AND LIGNITE COMBUSTION
Texas Lignites
Northeast
.7* SOj
14% Ash
Fuel Assumptions 7000 Btu/lb
Coal Rates
tons/hr 406
tons/year 2,845,000
Waste Quantities
tons/yr dry sludge
tons/yr ash
Waste Volumes
acre-ft/yr sludge
acre-ft/yr fly ash
acre-ft/yr bottom ash
total acre-ft
Total acre-ft per 30-yr
plant life
Total acres assuming 30-
ft average disposal
depth
98,000
398,300
117
157
_ii
313
9390
313
Assumptions: Unit rating
Load factor
Efficiency
Scrubber efficiency
Fly ash/bottom ash ratio
North Central
1.1% S02
8% Ash
7500 Btu/lb
379
2,650,000
132,500
212,000
159
86
21
IS6
7980
266
500 MWe
80%
30%
90%
80/20
Central & South
2.0% S03
20% Ash
6500 Btu/lb
437
3,060,000
275,400
612,000
330
249
62
641
19,230
641
West
.8% SOj
10% Ash
8500 Btu/lb
334
2,340,000
88.920
234,000
107
96
24
227
6810
227
S0i,/S0j ratio
Ash dry density
Sludge percent dry solids
Average disposal depth
Average plant life
Coal
East
3.5% SOj
10% Ash
12,500 Btu/lb
227
1,600,000
256,000
160,000
307
65
16
388
11,640
388
80/20
90 lb/ft'
45%
30 ft
30 years
western coal, except for lignites from the central and southern
study regions, which are characterized by higher ash contents.
For sludge residues, lignite results in greater volumes than
western coal, but less than eastern coal, except once again in
the central and southern regions of the Lignite Belt.
The higher amounts of both ash and sulfur sludge from
lignite occur largely because it simply takes more lignite to
generate 1 MWe of electricity than in the case of either western
or eastern coal. Any comparative advantage lignite may have for
the ash and S02 content factors tends to be offset or lost en-
tirely by its considerably lower heating value.
This comparison shows that western coal would be some-
what preferable to lignite in terms of the quantities of solid
-------
wastes in need of disposal. The difference, however, is probably
not great enough to be a factor in choosing to use coal rather
than lignite, except possibly in the case of poorer grade lig-
nite desposits containing high ash and sulfur contents and having
comparatively low heat value. For better lignite deposits, the
difference in volume is in the range of from only 7 to 15 per-
cent, whereas for the poorer quality lignite deposits, the dif-
ference is as much as 275 percent.
It has been demonstrated in pilot FBC systems that
solid waste is produced at a rate of about 0.5 acre-feet/MWe-
year when the unit operates under present NSPS. For a 500-MWe
unit, this would result in an annual production of 250 acre-
feet, or 7500 acre-feet over a 30-year lifetime.29 This volume
would increase if new NSPS were met.
3.3.2 Cumulative Waste Production Levels
Table 3-4 shows the cumulative volumes of ash and
sludge which would result from the lignite development scenario.
TABLE
Coal Utilities 1985**
Coal Utilities 2000
Lignite Utilities 1985
Lignite Utilities 2000
Coal Industrial 1985
Coal Industrial 2000
Lignite Industrial 1985
Lignite Industrial 2000
*Radlan staff estimates
**Coal is assumed to be
3-4. INDUSTRIAL AND UTILITY SOLID WASTE VOLUMES
AREA SUBREGION (acre-feet per year)*
i
Western
908
2724
0
0
45
318
0
657
, assuming
all western
Northeast
454
1362
3130
10,016
23
158
156
1658
99 percent
coal.
North
Central
454
908
1862
5320
45
295
532
1643
ash removal
Southern
0
0
1923
3846
0
45
0
192
and 90 percent
BY STUDY
Central
454
1583
641
1923
0
45
0
256
sulfur
Gulf Coast
908
2724
0
266
340
2542
133
2314
dioxide removal
Total
3178
9301
7556
21,371
453
3403
821
6720
267
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These figures are a worst-case estimate, since they assume throw-
away scrubbing on all plants. In reality, some might use re-
generable scrubbing systems, reducing the total wastes generated.
In addition, these figures include all industrial facilities,
some of which may not use scrubbers. They also assume state-of-
the-art removal efficiencies.
If all these wastes were disposed of in impoundments
above ground, the total land required would be what is shown in
Table 3-5. This total volume, however, will be divided among
numerous disposal sites. The amount of land needed to dispose
of the solid wastes from a single coal- or lignite-fired power
plant is sizable, but still only a small percentage of the total
area required for the generating station. Sludge handling and
disposal may use from 100 to 200 acres of land, compared with an
average of 2000 acres for the plant site, coal pile storage and
drainage areas, cooling reservoir, and haul roads. If one in-
cludes a surface mining area adjacent to a lignite-fired plant,
the proportional land requirements of waste disposal grows even
smaller.
1985
2000
Western
953
3699
^Calculated for
of 30 feet.
TABLE
3-5. CUMULATIVE LAND COMMITMENTS FOR SOLID
WASTE DISPOSAL BY STUDY AREA SUBREGION* (ACRES)
North
Northeast Central
3763
13,194
30-year
2893
8166
Southern
1923
4083
operating lifetime, with
Central Gulf Coast
1095
3807
wastes piled
1381
7846
Total
12,008
40,795
to an average depth
Of the totals shown in Table 3-5, approximately 12,700
acres will be required by 2000 to dispose of the wastes from
plants projected to use low-sulfur western coal in Texas.
This figure could vary considerably if less western coal were
268
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used because of the proposed NSPS requirement for full scrubbing
for virtually all coals and lignites.
The total cumulative land area required for disposal
of sludge and ash will be an estimated 40,800 acres.* Although
a significant percentage of lignite use will be from the North-
east and North Central Subregions of the Lignite Belt, which are
characterized by comparatively low waste volumes, enough will use
lignite from the Central and Southern Subregions to justify a
total figure above 40,000 acres.
Disposal sites for lignite wastes will generally be
concentrated along the Lignite Belt near the generating stations
themselves. The total land area required for lignite waste dis-
posal represents only about 4 percent of the area estimated to
be overlain by lignite by the Bureau of Economic Geology (1 mil-
lion acres), but represents 16 percent of the area estimated by
the Bureau of Mines (251,000 acres). This may not be considered
a serious obstacle to the siting of the projected number of lig-
nite facilities on a regional basis, but the land requirement is
the equivalent of approximately 50 square miles, assuming an
average depth of 30 feet.
Added to the combined estimates for coal and lignite
wastes from power plants is the amount of land required to dis-
pose of coal and lignite wastes from industrial processes.
Since the requirements for S02 removal are less stringent than
for power plants, quantitative estimates are less certain.
Table 3-4 provides estimates describing "worst-case conditions"
which assume full scrubbing for all industrial boilers. Gener-
ating sources for these wastes will tend to be located near
*Assuming storage to an average depth of 30 feet over a 30-year
plant lifetime.
269
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the Gulf Coast, away from the Lignite Belt, Disposal options
may, however, include disposal in places at some distance from
the coast due to the environmental and economic difficulties of
siting large numbers of surface disposal facilities in the coast-
al region itself.
3.4 Alternative Disposal Methods and Practices
Current industrial sludge disposal methods include
ocean dumping, incineration, ponding or landfilling, land spread-
ing as a soil fertilizer and conditioner, and recycling for com-
mercial utilization. Only ponding, landfilling and recycling
are presently used for disposal of ash and sludges resulting
from the combustion of coal and lignite. In Texas, an esti-
mated 25 percent is reused.30
3.4.1 Waste Collection and Transport
While fly ash may be collected dry, as with an electro-
static precipitator or a baghouse, wet sluicing may then be em-
ployed to convey the ash to a disposal pond. Where wet sluicing
and ponding are not employed, the material is usually hauled by
truck for landfill disposal or recycling. If the ash is col-
lected with a wet system, as with a wet venturi, disposal is
usually accomplished by subsequent pumping to a pond in slurry
form. The choice of pumping a water mixture of the ash or trans-
porting it dry is often site-specific and highly dependent upon
the method of collection.
In addition to direct disposal of fly ash, it is often
advantageous to mix fly ash and scrubber sludge together to take
advantage of the increased stabilization and fixation resulting
from the mixture.
270
-------
3.4.2 Disposal Options
The options for disposal of scrubber sludge involve
direct ponding or dewatering. In either case, the sludge can
be mixed with fly ash or a mixture of fly ash and lime. A
number of other materials are also mixed with sludge in com-
mercial fixation processes. If not dewatered, sludges are
commonly pumped at 10 to 15 percent solids. Sludges can undergo
partial dewatering and be pumped to ponds at 20 to 35 percent
solids. The sludges also can be vacuum filtered to 50 to 60 per-
cent solids and trucked or otherwise hauled to the landfill. A
predominantly gypsum scrubber sludge can be produced by some
processes which can be sold as a marketable by-product. Pre-
dominantly sulfite sludges can also be fully oxidized to gypsum.
The options for disposal of combined fly ash and
scrubber sludge, such as that generated from a combined particu-
late and SOa scrubber, are basically the same as those for
sludge alone. The combined sludge can be pumped directly to a
pond, either fully oxidized to gypsum or as a sulfite sludge.
The sludge can be dewatered and fixed and, depending on the ex-
tent of dewatering, either ponded or landfilled.
Landfill sites for dry ash disposal are rarely lined.
In the case of ponding of wet sluiced fly ash or combined fly
ash and scrubber sludge, the ponds can be lined or unlined.
Common liners include clay and synthetic liners. A stabilized
mixture of fly ash and scrubber sludge can also serve as an ef-
fective pond liner.
In every case where ponding is used, either for de-
watered sludges or the slurry pumped directly to ponds, the
solids can be removed and landfilled after settling. The eco-
nomics of alternative disposal techniques depend upon:
271
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Whether the sludge is treated or untreated,
The design and operating characteristics of
a pond or landfill, and
Which sludge treatment method is used.
Untreated sludge generally becomes cheaper over time
when compared with treated disposal techniques. Although the
capital costs for untreated waste may exceed certain treated
processes, the total lifetime revenue requirement of the un-
treated alternative is less than any other treated alternative.
The principal cost for untreated waste is in the acquisition,
construction, and operation of the pond or landfill. Also, the
use of synthetic linings rather than natural liners such as clay
greatly increases the capital costs of ponds or landfills. An-
other cost factor is the distance from the disposal site of
generation source. If trucks-are used for transportation, the
difference is not major. If pipelines are used, the incremental
cost of longer disposal distances will be important because of
the expense of laying additional pipe.31
Mine disposal is an attractive option for mine-mouth
lignite-fired facilities. However, the combined provisions of
RCRA regarding hazardous wastes and of the Surface Mining Con-
trol and Reclamation Act regarding groundwater protection are
likely to make mine disposal less attractive. Final programs
have not yet been developed under both acts to cover solid waste
disposal in mines. When fully implemented, however, they are
likely to both raise the cost and increase the difficulty of
permitting mine-site disposal.
272
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3.5 Potential Environmental Impacts of Solid
Waste Disposal
The greatest potential concern over solid waste dis-
posal is over possible contamination of groundwater through
leaching from disposal sites. Leachate from solid wastes is
high in pH (alkaline) and contains a variety of trace elements
which may be present in quantities as much as ten times those
allowable in drinking water. The likelihood of groundwater
becoming contaminated by waste leachate varies from site to
site, and with the nature of the wastes and the treatment given
them before disposal.
3.5.1 Leaching Conditions
The "leachability" of solid wastes depends on a number
of factors including:
Solids content of the wastes;
Reactivity between the ash and sludge if mixed;
Status of the disposal site (active or inactive);
Disposal site climate (rainfall, humidity, etc.);
Subsurface soils and geology; and
Type of disposal facility (pond or landfill).
When seepage occurs, contaminants form a plume down-
gradient from the disposal site. The shape, extent, and flow
rate of the plume will be determined by local geology, ground-
water flow, characteristics of the contaminants, and the con-
tinuity of waste disposal. Nearby groundwater pumping may speed
the flow rate and elongate the plume.32
273
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The teachability of ash and sludge wastes may be al-
tered by various chemical treatment processes. Chemical treat-
ment or "fixes" serve to stabilize the wastes, reduce solubility,
and ultimately reduce concentrations of trace elements in leach-
ate.
3.5.2 Groundwater Contamination
The Environmental Protection Agency has established
primary and has proposed secondary standards for drinking water.
Primary standards indicate the maximum contaminant levels above
which human health would be endangered, whereas the secondary
standards are based upon aesthetic considerations such as smell,
taste, and color of water.
Primary drinking water standards (mg/liter) have been
promulgated for arsenic, barium, cadmium, chromium, nickel, lead,
mercury, selenium and silver. Secondary drinking water stan-
dards have been promulgated for copper, iron, manganese, fluorine,
and zinc. EPA has also promulgated standards applicable to the
use of water for irrigation purposes. These standards set levels
for beryllium, boron, cadmium, chromium, cobalt, copper, fluorine,
iron, lead, manganese, molybdenum, nickel, and selenium.
Contaminants will, to some extent, be attenuated by
the soils beneath the disposal site. Sulfite/sulfate crystals
may serve to clog natural soil pores and impede the flow of
water containing dissolved elements. Soils will also selectively
absorb various contaminants, including many heavy metals, leaving
only certain ones to migrate into groundwater supplies. It is
possible that certain sandy soils will be able to remove up to
95 percent of the elemental contaminants over ten years of flow.
This ability of soils below disposal sites to attenuate con-
taminants which are passing through them is the basis of the
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500-foot "margin-of-safety" assumption in the proposed RCRA
criteria.
As noted above, the maximum tolerable level of con-
taminants in solid waste leachate has been set by EPA at ten
times the primary or secondary drinking standard. These levels
allow for the natural processes of purification and cleansing
that take place as the leachate percolates through various sub-
strata. It is assumed that a distance of 500 feet between dis-
posal site and groundwater withdrawal point will reduce con-
taminants by a factor of ten.
One important implication of this threshold of con-
tamination is that the siting of disposal facilities in close
proximity to wells which are used for drinking water purposes
would possibly result in trace element levels above the national
primary drinking water standard. Another implication is that
identifying suitable sites at sufficient distances from existing
wells may become more difficult as both waste volumes and de-
pendence on groundwater increase.
3.5.3 Groundwater Usage
The Wilcox-Carrizo aquifer is the major water-bearing
formation of East Texas. Wells in the Wilcox-Carrizo aquifer
supply water for most municipal and industrial uses in East
Texas. Although figures for individual localities within the
Wilcox-Carrizo vary, the pattern of numerous small communities
which depend upon groundwater sources for their drinking water
supplies is noteworthy. Throughout the region, there is a high
dependence on groundwater supplies for drinking water when com-
pared to other areas of the state, especially the large metro-
politan regions, which rely more heavily on developed surface
water supplies. There is a strong likelihood that groundwater
275
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pumpage rates will increase and as a result the potential for
drinking water contamination may increase as the number of
sludge disposal sites in the area of the Carrizo-Wilcox aquifer
grows.
Another factor which should be considered when examin-
ing current and future groundwater usage patterns, is that as
groundwater withdrawal rates increase, and the level of the
water table is drawn down, there could be two changes:
The distance between a surface disposal site
and the water table will increase, thus al-
lowing for a greater degree of purification
before contaminant plumes reach groundwater
supplies; but
The flow rate of the aquifer could increase,
thus speeding up the rate at which contami-
nants would be transmitted through water-
bearing formations to the location of water
supply wells nearby.
3.6 Environmental Limitations on Suitable
Waste-Disposal Sites
To guard against aquifer contamination, disposal sites
over possible recharge zones should be avoided or very carefully
managed. Groundwater recharge is a complex phenomenon over most
of the Lignite Belt. The several geological strata outcropping
in the vicinity of potential mine and plant sites are hydraulical-
ly interconnected. Within each of these strata, moreover, per-
meability varies substantially. Thus, selection of a disposal
site without due attention to local groundwater hydrology would
risk possible seepage problems from waste leachate.
276
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Most of the groundwater in the Lignite Belt is found
in sandy strata which act as aquifers. The most important of
these aquifers are the relatively continuous Carrizo and Simsboro
sands, which lie stratigraphically immediately above and below
the Calvert Bluff Formation, in which the lignite is found. The
Carrizo aquifer is a major regional freshwater source for munici-
pal, industrial, and agricultural use, especially on and near
its outcrop. Other dominantly sand formations occur in a coast-
ward direction and are also widely used as minor aquifers. These
sands are generally isolated stratigraphically, and no significant
lignite occurs within their recharge areas. However, these minor
aquifers (especially the Queen City and Sparta sands) are locally
important sources of water near the Yegua lignite trend.
The principal aquifers potentially affected by lignite
mining are the Carrizo and Simsboro. The aquifers actually con-
sist of a complex, hydrologically interconnected system of sand
bodies which function as a single water-bearing unit. The man-
ner of water movement into and through these aquifers is essen-
tially the same in both. The Calvert Bluff Formation which lies
between them is a mixed mud and sand formation. Although gen-
erally less permeable than the two sand strata, the Calvert Bluff
can transmit water under pressure. Thus, the two aquifers are
connected through the Calvert Bluff.
The Simsboro and Carrizo aquifers are recharged pri-
marily by rainfall and streamflow infiltrating the sandy strata
where they crop out at the surface. In these areas, water is
found at quite shallow depths. In a similar manner, a much
smaller amount of water infiltrates the Calvert Bluff Formation.
All of the sediments in these three geologic units
have some degree of permeability. Disposal sites located over
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any part of their outcrop have the potential for infiltrating
and entering the groundwater system to some extent. However,
the more permeable sand elements will transmit contaminants
into the groundwater at a much faster rate than other components.
Permeability values for some of these sands in East Texas range
from 17 to 338 gpd/ft3, and average 88 gpd/ft3. The permeabil-
ity of the sandy clays is around .01 gpd/ft3 , or only about one-
fourth the rate of the sands.33 Because of their extensiveness
at the surface, the Carrizo and Simsboro sands have the poten-
tial for a significant amount of groundwater contamination in
the event scrubber and ash sludges are disposed of without pro-
per safeguards.
3.7 Other Wastes
In addition to the ash and sulfur-removal wastes
arising from power generation, two other solid waste types
require consideration: gasification plant wastes, and potentially
dangerous high-radioactive strata disturbed in mining.
Low- and medium-Btu gasification produce an ash simi-
lar to that resulting from combustion. This ash is mixed with
a fraction of unburned coal and may contain a variety of organic
substances. For a lignite-based plant in the size range econo-
mically attractive for Texas, this waste stream might be produced
at a rate of 2500 to 3500 tons per day. Gasification also produces
tars which may contain highly carcinogenic organic compounds.
These tars, however, may be burned as fuel within the plant.
This process destroys the hazardous organic compounds they contain.
Sulfur is recovered from product gas in solid form.
If this material cannot be sold, it must be either stored or
disposed of as solid waste.
278
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It was pointed out in Section 2 above that very high
uranium concentrations occur where lignite seams come in contact
with sandstones and shales. High concentrations also sometimes
appear next to shale partings.6 In some instances, concentrations
are high enough to suggest possibilities of commercial recovery.
Uranium in lignite is oxidized on contact with air, and
becomes soluble. Thus, mixture of this material with overburden
for backfill in strip mines might result in leaching and poten-
tial groundwater contamination. No data exist to show whether
such problems have developed at existing lignite mines. An al-
ternative to disposal, however, might be to segregate these
uranium-bearing materials for processing to recover the uranium.
Tests of the feasibility of uranium recovery from lignite are
now being conducted at Texas A&M University's Center for Energy
and Mineral Resources.6
3.8 Research Needs
• Investigation of the potential for groundwater contamin-
ation with uranium leached from waste lignite left in
mines. Observation of existing mines for evidence of
uranium solution and migration.
• Testing scrubber sludge and ash from lignite-based pro-
cesses (combustion and gasification) for potential
hazardous classification.
• Investigation of the fate of solid-waste contaminants
following disposal, utilizing both laboratory tests and
detailed field sampling to provide a basis of estimating
risk of exposure.
Evaluation of potential effects of solid waste disposal
on future uses of the disposal site.
279
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Identification and mapping of conditions related to the
suitability of sites for sludge and ash disposal.
Evaluation of various ash and sludge treatment processes
for stabilizing wastes and reducing trace metal migra-
tion into groundwater.
Evaluation of techniques for reuse or recycling of solid
waste products in terms of environmental effects.
' Investigation of possible regulatory barriers to recycling
solid waste.
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4.0 IMPACTS ON SURFACE AND GROUNDWATER QUANTITIES
Summary and Conclusions
Over the entire study area, consumptive use by the
mining and power-production aspects of the develop-
ment scenario would total to about 4.6 percent of
developed supply in the year 2000. By subregion,
the proportion of consumption to supply varies from
13 percent (Northeast) to 1.3 percent (Gulf Coast).
The cost of developing new surface water impoundments
increases as a basin is developed. Thus, new supplies
will cost more to the user than existing ones.
As the value of water rises, there may be a tendency
for the percentage used by agriculture to go down as
energy's share goes up.
Groundwater is likely to be developed as a substitute
for high-priced surface supplies. As more is pumped,
existing drawdown problems are likely to become more
widespread. As this happens, the cost of using
groundwater will go up. Agriculture may have little
flexibility to cope with these rising costs.
Although consumptive use is likely to cause general
flow reductions, this effect is not expected to be
serious on a subregional level. Impacts at specific
locations could be significant.
As flow is reduced, a stream's capacity to assimilate
certain wastes also goes down, but much more slowly.
Using the Brazos River as an example, a 20-percent re-
duction in flow results in only a 2-percent decrease
in ability to assimilate biologically oxygen demanding
waste (B.O.D.).
Mining in some areas will disturb aquifer systems and
replace them with new, artifically mixed material. In
some instances, this may cause localized "aquifer dam-
ming," or sealing of a recharge area. The result could
be a permanent loss of local well yields.
Dewatering working mines can lower well levels within
an area surrounding the mine. This impact is temporary.
2S1
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4.1 Consumptive Water Use by the Development Scenario
The greatest consumptive use of water from the develop-
ment scenario arises from power plant cooling. Added to this is
the amount of water consumed in industrial coal and lignite use,
especially gasification, and the increased demands of growing
populations for municipal and domestic use.
Much of the water withdrawn by plants and communities
is returned to the basin after use. Although the patterns of
these withdrawals and return flows are of importance at the
local scale to water planners, they are too complex, and too
site-specific, to consider directly in this study. The major
potential impact of the scenario on water management at the sub-
regional level will arise through increased consumptive use,
water which is withdrawn but not returned.
Table 4-1 summarizes the level of consumptive use as-
sociated with the power production part of the scenario, broken
down by subregion. Industrial development will also consume
water, but amounts vary depending on plant size and process.
Without specifying all such uses, it would not be possible to
estimate industrial water consumption, for the scenario. In
general, however, it may be considerably lower for industrial
uses not involving the production of power. A Lurgi gasification
plant of 300 billion Btu-per-day capacity uses almost six times
the lignite consumed by a 1500-MWe power plant over identical
30-year lifetimes, but consumes slightly less water. Consump-
tive losses from municipal and domestic uses are very small in
comparison with both industrial and utility uses. For this
reason, they can be safely neglected in the evaluation.
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TABLE 4-1. SUBREGIONAL WATER CONSUMPTION BY LIGNITE- AND COAL-FIRED POWER PLANT
DEVELOPMENT IN YEAR 2000 (in thousand acre-feet year - TAF/y)
Lignite Coal
Plants: Plants:
Number of Number of
500 HWe 500 MWe
Northeast
North Central
Central
Southern
Gulf Coast
Total
Units Units .
32 6
20 4
3 7
6 0
_1 12
62 29
Water
Consumption
TAF/y
295
186
76
47
_2i
703
Consumption
Water Supply as Percent
TAF/y* of Supply
2264 13.0
2582 7.2
1950 3.9
858 5.5
7732 U3
15,386 4.6
Assumed Water Consumption:
• Lignite-Fired
Plant
Cooling: 6700 acre-feet/yr
Mine:
Other
250 acre-feet/yr
900 acre-feet/yr
•Based on Texas Department of Water Resources
Coal-Fired
Cooling:
Other:
future supply
Plant
6700 acre-feet/yr
900 acre-feet/yr
projections by river basin.
Note, from the table, that water consumption related
to the development scenario ranges from 13.0 to 1.0 percent of
the supply for the Gulf Coast and Northeast regions, respectively.
For all regions, a total of about 4.6 percent of the supply will
be consumed.
4.2
Impacts of Water Development
Energy's added water demand must be compensated for
by further development of water supplies. As was discussed in
Chapter III, the amounts of water needed for the growth of coal-
and lignite-based industry and power generation can be made
available in three basic ways. First, new surface water may be
developed, either by the user or by a water development agency.
Much of this development would involve new impoundments. Second,
existing water rights can be converted from their present uses
to energy-related uses. Third, some potential surface water
demands can be satisfied by groundwater supplies, freeing surface
283
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supplies for new uses. Since the large quantities of water
needed by utilities generally make surface water most desirable
as a source, energy users would benefit indirectly from a general
shift to groundwater supplies in other sectors. The following
discussion highlights some of the consequences of these three
modes of supplying water for energy.
4.2.1 Impacts of Surface Water Development
The first major impoundments in a river basin are
generally developed high in the basin. Subsequent downstream
reservoirs have less runoff available for capture, since up-
stream impoundments cut off large parts of the watershed. For
a given yield of water, a larger conservation pool must be de-
veloped, and the reservoir must be larger. Downstream sites
are likely to be shallower, resulting in higher evaporative
losses per unit of water stored. Larger land areas must be in-
undated, as well.
Thus, surface water development proceeds, those im-
pacts which relate to the size of impoundments increase relative
to the yield of usable water. The investment required per unit
yield also rises. When water prices are based on cost recovery,
the price to the user goes up.
On-site cooling ponds have been a popular mode of de-
velopment in the past, and may continue to be .preferred. Al-
though these ponds are not usually big enough to impound all of
the water needed, they sometimes retain runoff from substantial
acreage. In a basin with many such impoundments, design of main-
stem reservoirs must compensate for this reduction in watershed
area. Thus, the problems of larger size and higher cost may be
made even worse.
2S4
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4.2.2 Impacts of Water Rights Transfer
As the price of surface water from reservoirs increases,
it may become prohibitively high for some users. In some older
reservoirs, water may sell for about $15.00 an acre-foot. Water
prices for new reservoirs, based on cost recovery, may be as
high as $75.00 an acre foot.* These high prices reflect not
only the higher conservation-to-yield ratio, but higher interest
rates and construction costs as well.
Under these circumstances, agricultural users are
likely to find it difficult to obtain affordable new supplies.
Meanwhile, the potential value of old supplies to new users who
can pay more for them will continue to rise. The result is
likely to be a shift of water supplies away from agriculture.
There are presently no particular institutional safeguards to
protect agricultural uses from the impacts of rising water
prices.**
4.2.3 Impacts of Increased Use of Groundwater
An alternative to high-priced surface water is the
development of groundwater wells. Texas law regards ground-
water as a property right, which may be developed at the land-
owner's discretion. For the most part, no regulatory control is
exercised over either the manner or extent of development.***
In most cases, the Right of Capture principle allows pumping
from a new well to draw down levels of adjacent existing wells.
*Water Resources Department personnel, personal communication,
January 12, 1979.
**Water Resources Department personnel, personal communication,
October 17, 1978.
***In some areas, local Groundwater Conservation Districts have
been formed to regulate pumping rates and new well develop-
ment. See Chapter III for further information.
285
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As pressure on groundwater grows, the current draw-
down problems that plague roost of the aquifers in the Lignite
Belt may be expected to grow. As well levels fall, pumping
costs increase. Also, in some cases, water quality degrada-
tion may accompany increased drawdown, leading to higher treat-
ment costs .
Municipal, domestic, and agricultural uses account
for a large share of the groundwater used in the Lignite Belt
especially in the drier, southern parts. Rising pumping and/or
treatment costs will disadvantage these users. Again, agricul-
ture seems likely to have the least flexibility to cope with
these trends.
4. 3 Impacts of Consumptive Water Use
Translating water consumption into estimates of re-
duced flow requires estimates of the amount of water supply
that will be developed by lignite users to support their own
needs. Recognizing that this development will occur, it may be
concluded that flow reduction will be less than the total amount
of water consumed. Consequently, for this study, it was assumed
that flow reduction in a subregion will be about 70 percent of
the total water consumed by the mines and power plants located
in it. This supposes that the entire complex will develop 30
percent of the needed additional water supplies. (It is real-
ized that any given complex may develop from zero to 100 percent
of its needs, depending on local topography and hydrology; the
assumption is for illustrative purposes only.)
Results of regional flow reduction based on the 70
percent assumption are shown in Table 4-2. The projections
show that a low of 0.9 percent reduction may be expected in the
2C6
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Gulf Coast region and a high of 9.1 percent will occur in the
Northeast reeion.
Northeast region
TABLE 4-2.
Northeast
SUBKEGIONAL FLOW REDUCTION DUE TO NEW POWER PRODUCTION,
YEAR 2000 (In thousand acre-feet per year - TAF/y)
Total Water Supply
TAF/y r
2,264
North Central 2,582
Central
Southern
Gulf Coast
1,950
858
7,732
Percent Reduction •
In Flow In Region
9.1
5.0
2.7
3.8
0.9
These flow reduction estimates would change somewhat
if the water demands of industry were known. However, consider-
ing that these demands will probably be overshadowed by utility
requirements, including them would not be likely to change
Table 4-2's estimates greatly.
4.3.1 Navigation
The effect of reduced flows on navigation primarily
deals with inland waterways. Coastal waters used for navigation
depend on the depth to channel-bottom below mean sea level. This
level must be sufficient to provide the depth of water necessary
to float boat or barge traffic. While dredging is frequently
necessary to maintain this depth, it is important to realize
that freshwater inflow is not a significant factor in maintain-
ing the navigability of a channel.
Such is not the case in inland waters. These waters
rely on the volume of water flowing in their channels to provide
287
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a sufficient depth. The depth is dependent on flow in a fairly
predictable fashion for any given waterway. One expression com-
monly used is:
Depth = a • Flow
The expression states that the depth of a flowing channel is
predicted to vary with changes in flow, with the flow raised to
some exponential power. The value of this exponent is 0.6 in
the case of rectangular channels under steady flow, and varies
from 0.3 to 0.8 under normal river conditions.
The Texas river most frequently considered as a poten-
tial inland waterway is the Trinity River. This river flows
through east central Texas from Fort Worth to the coast east of
Houston. Considerable work would be required to make this water-
way conductive to heavy barge traffic. However, it is instruc-
tive for the purposes of this study to use it as an example for
the analysis that follows.
Assume that depth varies according to the flow raised
to the 0.6 power, and a reduction in average flow in the Trinity
River is 5.0 percent (North Central Subregion). The average
depth in the Trinity River will be reduced according to the fol-
lowing formula:
Depth = a • Flow
= a • (1.00 - 0.050)0'6
= a • (0.950)0'6
- a • (0.970)
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The new depth at reduced flow will be 0.970 or 97 per-
cent of the old depth, a reduction of 3 percent. Assuming a
12-foot depth (adequate to float small barges), this reduction
amounts to 0.36 feet or 4.3 inches. For actual existing condi-
tions in the Trinity River, the average depth is closer to 3.0
feet, which under the reduced flow used in this example would
be reduced to 2.9 feet (3.00 - .03 x 3.00).
To predict the actual effects of reduced flow (and
depth) on the navigability of Texas rivers, of course, requires
a much more specific and rigorous analysis than that given here.
It does, however, illustrate that flow reduction may have a sig-
nificant effect on the average depths of affected rivers. This
effect will be more pronounced as flows are increasingly re-
duced. It may be possible in such cases to control withdrawals
so that while average flows and depths are reduced, a certain
level of low flow would be maintained in order to insure suf-
ficient flow and depth for navigation purposes. This same argu-
ment of scheduling withdrawals to protect a given water use can
be applied to each of the problem areas addressed below.
4.3.2 Groundwater Recharge
A certain amount of groundwater recharge comes from
water flowing in existing river channels. A reduction in flow
affects recharge because of three factors: (1) reduced stream
width and contact area, (2) reduced pressure at the streambed
due to reduced depths, and (3) reduced amounts of water available
for infiltration.
A crude quantification of the recharge process is pos-
sible on a similar basis as that presented for navigation. However,
the net result would be restricted to stating that flow reductions
will reduce ground-water inflow to some essentially unknown degree.
289
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That degree, on a percertage basis, will be roughly comparable
to the amount of flow reduction. This reduction refers only to
that portion of recharge attributed to streambed infiltration.
Other sources of recharge will not be affected by the reduced
flow. In and along rivers where no groundwater infiltration is
occurring or where rivers are gaining flow from groundwater
sources, the reduced flow will have no effect.
4.3.3 Stream Ecology
During years of normal stream flow, the changes in
flow specific to lignite development will cause only minimal
changes in the overall freshwater ecosystem. The most severe
impacts probably will occur under low flow conditions, during
which time some of the aquatic biota will suffer. This impact
can be mitigated to a considerable degree by limiting water
withdrawals during these periods as much as possible.
4.3.4 Freshwater Inflow to Bays and Estuaries
The estimates of Table 4-1 indicate the range of flow
reduction to be from 0.9 to 9.1 percent of supply. The North-
east Subregion does not drain to the Texas Gulf Coast. This
feature reduces the range of flow reduction in those areas
draining to the coast from 0.9 to 5.0 percent. A considerable
effort is now underway by the Texas Department of Water Re-
sources and U.S. Fish and Wildlife Service to determine the ef-
fects of freshwater inflow on the ecological environment of
Texas bays and estuaries. They include the development of
methods of providing and maintaining the ecological environment
in a manner suitable for living marine resources. The productiv-
ity of the bays is being studied relative to the amount of fresh-
water inflow and other inputs. The analysis of this production/
290
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inflow relationship requires investment of considerable effort
in both time and money.
The regional effects of flow reduction due to lignite
development on freshwater inflows and on this production/inflow
relationship are impossible to calculate without having the
relationship defined.
4.3.5 Waste Assimilative Capacity
The waste assimilative capacity of a river or stream
refers to the capacity of that water body to accept, neutralize,
and render unobjectionable a given pollutant. A variety of pro-
cesses are involved, which are usually grouped under the term
"natural purification." Numerous variables enter the calculation,
and assessment of assimilative capacity. Assimilative capacity for
a particular pollutant under specific conditions allows some
degree of water quality degradation to take place during the assimi-
lation and purification process.
Waste assimilative capacity most often refers to the
capacity of a stream to assimilate pollutants which exert an
oxygen demand upon decay. The assimilative process results in
some amount of depletion of the oxygen resource of the water
body. The assimilative capacity of a flowing water body for
oxygen-demanding substances is a function of steam flow, decay
rate of the waste in the receiving stream, rate of oxygen
addition to the system, and the degree of oxygen depletion al-
lowed during the assimilating process. The rate of oxygen addi-
tion is predominantly that of atmospheric reaeration under normal
conditions. Reduced stream flow changes stream depths and
velocities, which in turn change the atmospheric reaeration rate.
Flow reduction also affects assimilative capacity by reducing
the amount of water available.
291
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These effects may be illustrated using the assimila-
tive capacity of the Brazos River as an example. The assimila-
tive capacity, expressed as an allowable discharge of a certain
amount of biochemically oxygen demanding substances, is graphed
as a function of stream flow in Figure 4-1. Similar curves may
be developed for most Texas streams given sufficient information
on decay rates and stream hydraulics. However, the given ex- .
ample is representative of the process.
The key feature of the figure is that the assimila-
tive capacity of the river decreases as flow decreases, but more
slowly. Note that a flow reduction from 400 to 320 cfs (20 per-
cent) causes a corresponding reduction in assimilative capacity
9 22°
i
ft
i j-
i -.
0
^^
1 7X REDUCTION ^^^~*
^^\ , m
• j REDUCTION
j T
. . . .i !
100 WO 300 400 500
FLOW • cubic (ml/second
02-4317-1
Figure 4-1. Waste Assimilative Capacity of the Brazos River as a
Function of Flow
>
292
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of from 213,000 to 210,000 pounds per day (a reduction of less
than 2 percent). The ratio between flow reduction and assimila-
tive capacity reduction varies from one river to another, but
always indicates a proportionately smaller reduction in as-
similative capacity compared to the flow reduction when expressed
as a percentage.
The assimilative capacity of a flowing water body, as
a function of flow, is more critical under low flow situations.
In Texas, the critical flow, with respect to water quality
standards, is the seven-day, two-year low flow. That is, the
average seven-day low flow that may be expected to recur once
every two years. Examples of this critical, seven-day, two-
year low flow are given for some Texas rivers in Table 4-3. The
range in these flows is considerable, varying from less than one
cubic foot per second to over 300 cfs for the examples shown.
TABLE 4-3. CRITICAL LOW FLOWS FOR SELECTED TEXAS RIVERS
Seven-Day, Two-Year
Low Flow
River Location (cfs)
Trinity
San Antonio
Brazos
Nueces
Sabine*
Sabine**
Rosser
Below San Antonio
Bryan
Three Rivers
Longview
Longview
194
80
357
0.25
54
35.7
*Based on flow records since 1938.
**Based on flow records since 1960.
Source: Personal Communication with Texas Department of
Water Resources staff, November, 1978.
293
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The question of flow reduction and its effect on assimi-
lative capacities, while somewhat involved technically, becomes
in the end one of maintaining the critical low flow. Through
proper management of water withdrawals, it is possible to main-
tain this low flow within certain limits, at previous levels.
Waste assimilative capacity is reduced as flow is reduced, as
shown in the previous example. But as with flow-recuction effects
on navigation, the assimilative-capacity reduction is significantly
less (on a percentage basis) than the flow reduction itself.
Also like the navigation issue is the conclusion that through
proper management practices which regulate the timing of water
withdrawals, the impacts of flow reduction can be greatly re-
duced or eliminated.
The previous discussions on flow reduction related im-
pacts should not be interpreted as proposing that for any given
site there will be no more significant impact from water con-
sumption by energy development. On the contrary, a careful
examination of all water-related impacts is a vital part of any
environmental assessment. In some areas, and for given types
and sizes of developments, water-related impacts, including flow
reduction, may be of critical importance. The foregoing dis-
cussion suggests only that flow reduction attributable to lig-
nite development will probably not have any great impact on the
state as a whole. As water becomes more scarce, through in-
creased use by agricultural and industrial and municipal users,
proper water resources management practices will be required to
mitigate the potential detrimental impacts.
It should also be reiterated that the supply figures
used in this analysis reflect timely development of new water
supply projects, as set forth by the Water Resources Department's
Continuing Water Resources Planning and Development for Texas. 3"*
To the extent that such developments are delayed or not built,
the impacts of flow reduction would be to a degree increased.
294
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4.4
Impacts on Groundwater
In Texas, steam electric generating plants use both
surface and subsurface sources of water for cooling and process
make-up purposes. Surface supplies are the preferred source
where possible because of costs, difficulties of developing a well
field, and the sometimes high cost of pumping the water to the
surface. Some plants, of course, do use groundwater for these
purposes because of the lack of available surface water supplies.
4.4.1
Groundwater Consumption
The discussion that follows addresses groundwater con-
sumption and effects on water quantity and quality as related
to lignite development. A compilation of steam-electric power
plants within the lignite and coastal areas which use ground-
water for cooling is given in Table 4-4. The installed capacity
TABLE 4-4.
EAST, CENTRAL, AND SOUTHERN EXISTING AND PLANNED STEAM
ELECTRIC POWER PLANTS IN TEXAS USING GROUNDWATER AS
THE PRIME COOLING SOURCE*
Installed
Capacity
MUt
flant Name
Bryan
Champion
Clark-Hiram
Collin
Oalla*
Cable Street
Cretni Bayou
Leon Creek
Mission Road
Vcuman
Pearsall
San Miguel
Texas ASM
Tutcle
Vhacton
TOTAL
*Sourcei / Draft
County
Brazos
Harris
Harris
Co 11 la
Dallas
Harris
Harris
Baxar
Bexar
Dallas
Frio
Atascosa
Brazos
Bexar
Harris
Planning
Aquifer
C-Wileox
Coastal
Coastal
Trinity G.
Trinity 0.
Coastal
Coastal
Edvards
Edwards
Trinity G.
C-Wileox
C-Wilcox
C-Wileox
Edvards
Coastal
Document, Texas
1978
140
22
336
153
14S
62
1141
197
120
94
75
0
24
364
1221
4094
Department
1987
140
20
336
0
0
62
1141
145
SO
94
75
800
24
364
1221
4502
of Water
Fuel Type
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Lignite
Gas
Gas
Gas
Resources, 1978.
295
-------
of these plants in 1978 is 4094 MWe, and all of the existing
plants are gas-fired. Existing installed capacity using ground-
water as a cooling supply is expected to decrease between now
and 1987. The increase shown in the total installed capacity
is attributable to the San Miguel lignite-fired plant in
Atascosa County, coming on line before 1987.
The aquifers being used as sources are the Carrizo-
Wilcox, the Trinity Group, the Edwards, and the Coastal Group.
According to information gathered by the Texas Department of
Water Resources, all of these aquifers are experiencing either
local or area-wide problems due to excessive pumping.3"
Problems include excessive drawdown, infiltration of bad water
into clean water aquifers, and land-surface subsidence.
Most Texas aquifers are already in a stressed condi-
tion. Therefore, it seems likely that the developers of lig-
nite mines and power plants will look first to surface supplies
to provide cooling and process waters. Where a new lignite
development uses ground-water resources considerable effort
should be spent to insure that this water resource is not taxed
at an unacceptable rate.
Finally, the increasing demand for water in all sec-
tors is expected to place growing pressure on most of the state's
aquifers. Thus, the problems discussed below must be viewed
in context of increasing stress.
4.4.2 Groundwater Recharge Impacts
Lignite development may have an impact on groundwater
recharge near mines and power plants . Recharge may increase in
recently mined areas, at least temporarily, due to the "expan-
sion" of the replaced overburden. In such eases, the expanded
296
-------
overburden will have an increased permeability because of in-
creased pore space. This will not occur at all mines, and may
be only temporary. Under its own weight the overburden may
settle and compact to undisturbed levels. In some areas of
the state it appears that the overburden disturbance caused by
surface mining will decrease recharge due to the formation of
relatively impermeable clay layers or crusts on the surface.
The question is a very complicated one, requiring extensive
studies at each mine site.
Considerable concern has been expressed over the
possibility of "aquifer damming" where mining affects a recharge
zone.35'36 Permeable sandy strata are often interspersed with
less permeable clayey layers near lignite seams. Sometimes,
these sandy strata are part of an aquifer system, which is re-
charged where they outcrop on the surface. If a mining opera-
tion excavates an area in which both sand and clay layers are
found, the two materials will be mixed when returned to the
pit. The mixed material, less permeable than the sandy strata,
now replaces them in what was once a recharge zone. If the
mixed material is sufficiently impermeable, recharge may be so
much reduced that wells drilled into the aquifer system, within
a few miles of the mine may stop producing. While this effect
is necessarily a local one, it is essentially irreversible.
A second groundwater problem associated with mining
results from the need to pump groundwater out of a working pit,
when mining intercepts an overlying aquifer. The resulting
cone of depression may extend one or two miles from the mine
site, and can, depending on the circumstances, reduce well
yields or even cause wells to go dry. Where mining occurs near
municipal well fields, or other intensive groundwater development,
this problem can be locally serious, and requires the development
297
-------
of a substitute water supply. Unlike the "aquifer damming"
problem, however, this effect is temporary.
As previously discussed, reduced stream flows down-
stream from the power plant may alter stream bed recharge due to
reductions in contact areas, water depth, and water availability.
None of these effects are likely to be significant on a regional
basis and some offset each other to some extent. Site-specific
problems may occur and should be studied as part of any complete
environmental assessment. The quantitative groundwater effects,
even in the most severe cases due to changes in recharge, will
be a local, not a regional, phenomenon.
4.5 Research Needs
Individual basin studies and forecasts of the impacts
of consumptive use on low flows and on reservoir
operation.
Investigate potential impacts on aquatic impacts of
altered flow regimes, especially of lowered'or more
frequent low flows.
Well monitoring at existing mines to detect and measure
permeability changes over time, resulting from mixing
and subsequent compaction of overburden materials after
replacement.
Monitoring existing mines to observe water-table
recovery time after cessation of pit dewatering.
Additional study of the hydrodynamics of aquifers,
particularly in the Northeast and North Central Sub-
regions, in the immediate vicinity of developable
lignite resources.
Investigate the adequacy of existing institutions to
protect against excessive aquifer drawdown and per-
manent or temporary reduction in productivity that
may result directly or indirectly from energy develop-
ment. Review policy options available for providing
such protection, including those used by other states.
293
-------
5.0
IMPACTS ON SURFACE AND GROUNDWATER QUALITY
Summary and Conclusions
Power plant effluents potentially contain substances
listed by EPA as "priority pollutants" of concern as
toxins. Control technologies are available for each
of these. Toxics-control strategies will vary between
plants.
Coal pile and mine runoff constitute major non-plant
pollution sources. Their main threat to water qual-
ity is through silt and suspended solid loadings.
Runoff can be caught in settling basins to allow the
water to clear before it is released.
Liquid wastes from gasification plants may contain
relatively high levels of hazardous contaminants,
particularly heavy hydrocarbons that may be cancer-
causing. These waste streams would most probably
be handled by forced evaporation. The solid residue
remaining would require care in disposal.
The need to dilute high-TDS waste streams from power
plant cooling increases net plant throughput of water,
and places greater demands on upstream reservoirs.
Solid waste disposal will probably be the greatest
threat to groundwater quality posed by the develop-
ment scenario.
t
Mining may affect groundwater quality because of
overburden leaching. The potential extent and seri^-
ousness of this impact is highly site-specific and
requires further study.
Where well fields are developed for power plant cool-
ing, excessive pumping may cause intrusion of poor-
quality water into the aquifer.
299
-------
5.1 Surface-Water Quality
Water quality of streams and reservoirs will be af-
fected by the nature, quantity, and type of wastewater effluents
associated with lignite mining and power plant operation. These
effluents will be generated by a number of diverse processes but
may be designated as "point" and "non-point" sources of pollu-
tion.
The development scenario does not extend in detail to
the level of specifying generating technologies and their as-
soicated water uses. Therefore, an estimate of wastewater vol-
umes was not attempted. The information that follows is a
general discussion of potential wastewater problems.
5.1.1 Point Source Effluents
Power-plant effluents are generally associated with
various aspects of operation. These sources typically are:
Cooling water systems,
Water conditioning,
Fuel pile runoff,
General plant drainage,
Process spills and leaks,
Ash handling,
Equipment cleaning, and
Boiler blowdown
The last three sources are typically operated as closed systems,
and do not result in waste discharges.
Under the Toxic Substances Control Act, the Environ-
mental Protection Agency has developed a list of toxic pollutants
JOO
-------
of concern to that agency. The 126 compounds of concern, or
priority pollutants, are listed in Table 5-1. Based on current
preliminary findings, those substances most likely to be found
in utility effluents are indicated by an asterisk.
Based on a Radian study for the assessment of control
technologies for toxic effluents from the electric utility in-
dustry,37 a number of control technologies have been identified.
These control technologies and the toxic pollutants removed by
them are summarized in Table 5-2. The effectiveness of many of
these controls is dependent on concentrations of toxic materials,
and waste stream characteristics. As such, Table 5-2 serves
only to indicate that for the proper circumstances, the tech-
nologies will control the indicated toxics to some appreciable
degree. Table 5-2 also indicates that some control technology
can be applied to each of the identified toxics. The selection
of a specific control method at any particular generating sta-
tion will depend on data specific to that station concerning
fuel characteristics, plant design, and other controls used.
Because the operations and effluents of power plants are so
site-specific, required strategies to control toxics will vary
from plant to plant.
The quantity and quality of industrial waste streams
depends on the processes involved, plant design, and operating
characteristics. The development scenario used here does not
specify such detail. Special mention should be made, however,
of the wastes produced by gasification.
A large coal- or lignite-gasification plant produces
a number of liquid effluents, including:
Oily and tarry gas liquors
• Process condensates
301
-------
TABLE 5-1. PRIORITY LIST OF TOXIC SUBSTANCES
CO
o
KJ
Accnapiithene
* Acrolcln
Acryloiii t rl Je
* Benzene
Benzidlne
* Carbon tutrachlorldu (tetrachloro-
ne thane)
* Chlorobunzene
* 1,2,4-Trlchlorobenzene
* Hexachlorobenzene
* 1,2-Ulchlorouthane
* 1,1,1-Trichluroethane
* llexachloroethaue
* 1,1-Uichlorethane
* 1,1,2-Tricliloroethane
* 1,1,2-Tetrachlorocthane
* Chloroulhane
* Bis(ClilucomeChyl) ether
* Bis(2-chloroethyl) ether
* 2-Chluroethyl vinyl ether (mixed)
2-Chlurohaphthalcne
* 2,4,6-Trichlorophenol
4-Chloro-m-cresol
* Chloroform (trichlorouethane)
* 2-Chloropheuul
* 1,2-bichlorubenzene
* i,3-Dlchlorobenzene
* ] ,4-l>li:hlarobenzene
3. 3-l>ichlorobenzidlne
1,l-Dichloroethylene
1,1-Trans-dichloruethylene
* 2,4-IHchlovcjpheiiul
I ,2-Diclilorupropanu
1,3-Dlcliloroprupylene (1, 3-Dlcblor-
oprnpunu
2,4-Diuethylpbeiiol
2,4-Olnltrotoluene
2,6-Dlnltruloluene
1,2-Ulphenylhydrazine
Ethyl benzene
FUiordiithcne
4-Clilorophenylplicnyl ether
4-Brouophunylphenyl ether
Bls-(2-clilorolsopropyl) ether
Bls(2-chloroethoxy) methane
Methylene chloride (dlchloro-
•ethane)
Methyl chloride (chloronethane)
HeChly bromide (bronomethane)
Bromoform (tribromomethane)
01rhlorobronoaethane
Trlchlorofluoronethane
Dlchlorodlfluoroaethane
ChlorodibromoBethane
Hexaclilorobutadiene
Hexachlorocyclopentadiene
Isophorane
* Naphthalene
Nitrobenzene
2-Nltrophenol
A-Nitrophenol
2,4-Dioltrophenol
4,6-Dlnitro-o-creaol
* N-nitrosodlmethylaaine
* N-nitroaodiphenylaaine
* N-nitrosodl-n-propylaalne
* Pentachlorophenol
* Phenol
Bls(2-ethylhexyl) phthalate
Butylbenzyl phthalate
Di-n-butyl phthalate
Dlethyl phtlialate
Dimethyl phthalate
1,2-Benzanthracene
3,4-Benzopyrene
3,4-Benzof luorantliene
Jl,12-Benzofluoranthene
Chrysene
Acenaphthylene
* Anthracene
I,12-Benzoperylene
Fluoreue
* Phenanthrene
1,2,5,6-Dibenznathracene
Indeno(l,2,3-c,d) pyrene
Pyrene
2,3f 7,fl-Tetrachlorodibenzo~p-
dloxin (TCDD)
Tetrachloroethylene
* Toluene
Trichloroe thyIene
Vinyl chloride (cliloroethylene)
Aldrln
Dieldrln
Clilordane (technical mixture
and metalbolites)
4,4'-DDT
4,4'-DDE (p,p'-DDX)
4,4'-DDD (p,p'-TDE)
a-Endosulfan
0-Endosulfan
Endosulfan sulfate
End r in
Endrin aldehyde
Endrln ketone
Heptachlor
lleptachlor epoxide
ct-Uexachlorocyclohexane
0-Hexachlorocyclohexane
•f-Hexachlorocyclohexane (llndane)
£-Hexachlorocyclohe3cane
* Polychlorinated biphenyl (Arocblor
1242)
* Polychlorinated biphenyl (Arochlor
1254)
Toxaphene
* Antimony (total)
* Arsenic (total)
* Asbestos (fibro)
* Beryllium (total)
* Cadmium (total)
* Chromium (total)
* Copper (total)
* Cyanide (total)
* Lead (total)
* Mercury (total)
* Nickel (total)
* Selenium
* Silver (total)
* Thallium (total)
* Zinc (total)
* Vanadium (total)
* Ethylenedlanlnetetraacetate (EDTA)
*SubtitaLices most likely tu be present in utility effluents based on preliminary data and literature survey.
SIHIKCK: Kice, J. & S. Strauss, 1977. "Water Pollution Control In Steam Plants."5'
-------
CO
o
CO
TABLE 5-2. COMPARISON OF TOXIC CONTROL BY SELECTED TECHNOLOGIES
Process
Acrolein
Toxic Pollutants
•o
o
Antimony & Comp
a
§
Arsenic & Compo
I
N
C
M
•8
a
a
Beryllium & Com
„
TJ
§
Cadmium & Compo
.•j
•H
h
0
Carbon Tetrachl
H
vl
tn
ia
Thallium & Comp
—4
•o
1
O
V0
*H
tsj
ACTIVATED CARBON / */* //////* */ / ///* t
PRECIPITATION /// /// ///
REVERSE OSMOSIS /////////////////////// / /////
BRINE CONCENTRATION /////////////////////// / /////
EVAPORATION PONDS /////////////////////// ^ /////
* Highly site-specific
SOURCE: Rice, J. & S. Strauss, 1977. "Mater Pollution Control In Stean Plants.""
-------
Boiler blowdown
Cooling tower blowdown
Demineralizer and zeolite softener regeneration
Wastes
Lime softener sludge
Sewage treatment wastes
Ash quenching overflow.
When the raw gas is cooled, a portion of the gas
stream's water content is condensed. This oily and tarry liquor
contains a variety of heavy hydrocarbons, phenols, and trace
inorganic compounds which may be toxic, carcinogenic or muta-
genie. Phenols have market value and are likely to be removed
for sale. This waste stream may also be partially cleaned to
permit reuse in the plant. Eventually, however, this water
must be discarded. Because of their hydrocarbon and trace in-
organic contents, it is usual to design plants for on-site
evaporation of these wastes. In Texas' humid climate, forced
evaporation would be a likely method, resulting in a solid
residue. This residue would probably require special handling
for disposal.
The remaining waste streams can all be recycled with-
in the plant and/or used to quench and slurry gasifier ash.
Gasification plants can thus be operated without any
liquid discharge to the environment. The result is the trans-
fer of potentially hazardous waste components to a solid waste
stream. With proper handling and disposal, these components
may be more effectively contained in the solid form.
304
-------
5.1.2 Non-Point Sources
Non-point sources are generally associated with waste
streams from the mine area and lignite pile at the power plant.
The prin-cipal effluents derive from runoff associated with rain-
fall events, mine dewatering, and beneficiation processes, if
used. The greatest threat to water quality from this area run-
off will be from silt and assorted suspended solids carried into
area streams. It is standard practice to construct temporary
impoundments to catch turbid runoff waters, allowing sedimenta-
tion to remove most of the solids before release.
The location and design of these basins is a part of
all mining plans required under current surface mining regula-
tions. Runoff from lignite storage piles creates a more dif-
ficult problem with respect to the chemical character of the
waste stream. Table 5-3 presents plant data relating to water
quality parameters for coal pile runoff. While the chemical
characters of lignite and coal differ in many ways, the table is
useful in showing the types of contaminants in runoff from a
fossil-fuel storage pile. The range shown for some of the con-
taminant concentrations is also significant, indicating the
variability of concentrations due to different fuel characteris-
tics and storage methods.
A common wastewater management option is to store and
use captured runoff as a water supply for processes which do not
need clean water. Such processes include some ash handling
systems and other miscellaneous processes. Runoff from non-
process areas within the generating plant property are generally
not a problem from a pollutant standpoint. Where this discharge
is contained in a wastewater system, effluent limitations are
usually specified only for oil and grease content and suspended
solids.
305
-------
TABLE 5-3. PLANT DATA RELATING TO WATER QUALITY PARAMETERS
flue Cotfi
AlUUsltT (aj/O
M3 (•!/!)
COO (•(/:)
V
TO
ISJ
Aaeal*
Stint*
fboiplMTout
Turbid!:?
ieuitr
Toc»l 3*rini«i
Sul£*:«
C»lorl*«
Altai tola
Chraiia
Copptr (BS/t)
Ina (sj/l)
Sapmiua (sj/l)
Zlac <«»/tl
Sottim (B|/l)
U
Source: EPA,
34o:
<
0
UIO
1330
710
tio
0
04
.3
303
-
130
123
3.t
-
0
1.6
0.161
-
1.4
1260
2.1
1974
FOR
3401
0
0
1010
1330
720
610
0
103
-
130
323
J.6
.
0
1.6
0.161
1.6
1260
2.1
39
COAL PILE RUNOFF
3»36
0
10
106
J999
77*3
22
1.77
1.2
-
-
1109
3731
411
-
0.37
-
-
M
2.43
160
3
1123
-
-
13
iOOO
3100
200
1.35
_
-
-
1130
161
-
-
0.03
-
0.06
17*
0.0006
-
4.4
i7a
12
1
1099
334*
247
3302
0.33
0.23
-
-
-
133
2}
-
-
-
-
-
0.01
-
7.1
172) 3626
-
-
-
-
- 21970
100
-
. .
-
- 21700
-
6137 19000
.
1200
13.7
1.1
0.361 4700
-
12.3
-
Z.7 2.1
.0107 3303
0 21.36
-
-
43000 -
440JO
120
-
.
1.37
27110 1.61
-
21920
-
123
0.3
3.4
93000 1.0
-
23
-
2.1 6.7
3303 )303
14.32 36.41
-
- .
-
-
-
-
.
2.77 6.13
10.23 S.I4
-
-
.
-
-
-
1.03 0.1
-
-
-
6.6 6.6
5.1.3
Effects on Assimilative Capacity
Wastewater discharges from surface mines and steam-
electric generating plants will not directly affect the waste
assimilative capacity of area streams. This is due to the ab-
sence of oxygen-demanding substances in typical wastewaters from
these sources. As discussed above, assimilative capacity may
be affected by flow reductions in area streams, but wastewater
discharges from mines and power plants are not a major factor
in determining the oxygen resources of a water body.
-------
5.1.4 Effect of IDS Control on Water Requirements
The evaporative cycle of a power plant, whether it in-
volves a cooling reservoir or cooling towers, builds up dissolved
solids. The total dissolve*solids level (TDS) must be con-
trolled to avoid equipment corrosion and scaling. In a cooling
reservoir, solids control may also.be required to protect fisheries
To keep TDS levels at an equilibrium, a portion of the water in
the system is continually bled off and discharged, while fresh
water is constantly added. This blowdown stream, if discharged
into a body of water, must not cause that water body to exceed
the quality standards set for it. Consequently, the solids
content of the blowdown stream must be controlled.
The amount of extra water required to control TDS may
be a significant part of the plant's water budget. Blowdown
from a cooling tower designed for a 500 MWe lignite-fired plant
with 35 percent efficiency might range from 4,000 to 17,000 gpm,
with salt concentration proportional to the size of the stream.
Halving its TDS concentration would require an equal amount of
dilution. Texas water planners have expressed concern over the
magnitude of this demand, and its effects on water delivery.1*0
The requirement for dilution water does not change
consumptive requirements, but increases the plant's net through-
put of water. This in turn increases the demands on upstream,
existing reservoirs. Because it is continuous, the incremental
demand may reduce the flexibility available in managing reservoir
discharge. Also this kind of demand moves water through the
reservoir system more rapidly, limiting the intensity of use
possible.
307
-------
The potential significance of the extra demand for IDS
dilution is greatest in drainages of streams which are already
salty, such as the Brazos and some of its tributaries, and in
dry areas where streamflow is periodically much reduced. The
problem is least troublesome in moist regions, with relatively
high flows even during dry periods or times of extensive with-
drawal.
5.2 Groundwater Quality
Surface mining and steam electric power generation
may affect the quality of local groundwaters by several dif-
ferent mechanisms. These are:
Intrusion of poor-quality water into the
aquifer, caused by excessive pumping where
groundwater is used for power plant cooling;
Groundwater contamination due to subsurface
disposal of wastewaters;
Groundwater contamination associated with
leaching in disturbed overburden; and
Groundwater contamination associated with
solid waste disposal.
Of these processes, the greatest threat to local groundwater
quality comes from the disposal of solid wastes. This problem
is discussed in Section 3.0, above.
Where groundwater supplies are used for power plant
cooling and where poor-quality water is already entering fresh-
water aquifers, the power plant withdrawals will only increase
303
-------
this problem. The encroachment of poorer-quality water is now
a problem in many aquifers, including the Carrizo, the Trinity
Group, and the Gulf Coast aquifer. The question of decreasing
water quality as pumping continues will be an important factor
in deciding on a groundwater or surface water supply. This
issue is one of the driving forces behind efforts to develop
additional surface water supplies within the state.
With the major exception of the oil production indus-
try, subsurface disposal of wastewater is not a general practice
in Texas at this time. Most wastewaters from steam electric
generation plants are treatable by conventional methods and
either discharged to surface waters or used within the plant
where a cleaner water is not needed. It is unlikely that this
situation will change as a result of lignite development.
Excluding solid waste disposal questions, the most
serious threat to groundwater quality from lignite-related ac-
tivities concerns groundwater contamination from the disturbed
overburden. Water may enter the replaced overburden by two
routes: surface-water infiltration and underground seepage. In
either case, salts and trace elements may be dissolved. This
is an area of ongoing research, but the following generaliza-
tions may be made:
Groundwaters within the area of disturbed
overburden will probably have somewhat
higher levels of dissolved solids than
those same waters before mining;
The elevated dissolved solids will consist
primarily of salts, organic compounds, and
trace elements;
309
-------
This phenomenon is site-specific in terms
of occurrence, dissolved solids type and
concentration, and significance; and
More research concerning this question is
needed,
5.3 Research Needs
Monitor surface streams around existing mines to
evaluate water quality impacts of runoff, altered
subsurface hydrology.
Monitor groundwater quality around existing mines
to detect evidence of contamination from overburden
leaching; measure rates of resaturation of over-
burden after mining.
Leaching tests of overburden from existing mines,
of various ages and states of weathering, to de-
termine changes in the solubility and mobility of
contaminants with time.
Column leach studies to determine the contaminant-
immobilization capacity of Lignite Belt soils and
strata potentially disturbed by mining.
Investigate the adequacy of present institutional
mechanisms to protect against groundwater contamina-
tion from mining and waste disposal. Identify avail-
able mechanisms for providing such protection,
including those used in other states.
310
-------
6.0
IMPACTS ON FISH AND WILDLIFE
Summary and Conclusions
Mining and plant siting will account for most of the
direct destruction of terrestrial habitat accompany-
ing the development scenario. Total acreage is very
small compared to habitat available. However, current-
ly, wildlife habitat is in poor condition over much of
the Lignite Belt. Thus, impacts will often occur in a
context of heavy present stress.
Reclamation has been successful on existing lignite
mines. Most landowners appear to prefer restoration
for "tame grass" pastures to reclaiming wildlife habi-
tat values. This kind of monoculture is of low value
to most native wildlife. Planting tame grass pasture
may therefore result in a net habitat loss, even after
successful reclamation.
Cooling pond and reservoir construction destroys ripar-
ian and bottomland habitat. These are the least abun-
dant terrestrial habitat types in the Lignite Belt, and
have uniquely high value to wildlife of many kinds.
Continued deterioration of surrounding habitat through
poor land-use practices could outweigh the benefits of
successful reclamation of mined lands for wildlife
values. In the long run, poor agricultural and grazing
practices may do far more damage to terrestrial eco-
systems than mining.
Construction of new impoundments fragments river habi-
tats and replaces them with greatly different aquatic
systems.
Experience to date does not indicate that acid mine
drainage is likely to be a widespread problem.
Water development and use alters flow regimes in af-
fected basins. Unless reservoirs are operated so as
to compensate for the effects of consumptive use, low-
flow conditions will occur more frequently. The degree
of stress this places on aquatic ecosystems will vary
between and within basins.
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6.1 Terrestrial Ecosystems
The major impacts on terrestrial communities resulting
from lignite development fall into two groups: direct destruc-
tion of habitat and indirect reduction of habitat quality result-
ing from overall population growth. Both kinds of impacts have
already occurred over most of the Lignite Belt. These impacts
arise from activities other than mining, and have drastically
altered the character of both vegetation and animal populations
over the course of the last century. The potential ecological
impact of mining and plant siting must therefore be evaluted
both in terms of the extent of disturbance expected and of the
present condition and trend of affected habitat.
6.1.1 Extent of Habitat Disturbance
Accompanying the direct effects of lignite development
will be indirect effects caused by the creation of thousands of
new jobs and significant numbers of new people moving into the
lignite area. People may commute 50 miles or more to work in
semi-rural areas. The distribution of these new families and
the land-use impacts of developing housing for them is therefore
difficult to predict. As will be discussed in Section 7, below,
most of the increased population is expected to settle in the
existing small communities throughout the Lignite Belt, thereby
causing little direct disturbance to the more remote wildlife
habitats.
The major direct impact on habitat resulting from
lignite development will be land clearing for mining and for
plant siting. Assuming an average seam thickness of six feet,
the process of mining sufficient lignite to support a single
500 MWe generating unit for a lifetime of 30 years would ulti-
mately disturb approximately 5,700 acres of land. A 1500-MWe
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station would disturb over 17,000 acres. However, only about
570 acres would be disturbed each year. Assuming that three
years pass before revegetation is complete, a total of about
1,700 acres would be in a disturbed condition during any given
year after mine start-up. Considered on a regional basis, the
forecast levels of lignite development projected in Chapter II
will entail the ultimate disturbance of: 187,000 acres in the
Northeast Subregion; 119,000 acres in the North Central Sub-
region; 34,000 acres in the Southern Subregion; and 17,000
acres each in the Gulf Coast and Central Subregions by 2000.
These acreages, large as they may seem, constitute
only a small fraction of the total available habitat. Three
major vegetation types characterize the bulk of the Lignite Belt:
the Pineywoods, the Post Oak Savannah, and the South Texas
Plains vegetation associations. These community types extend
over 15 million acres, 8.5 million acres, and 20 million acres,
respectively. Thus, the total land disturbance associated with
lignite mining is equivalent to only about one percent of the
total habitat available. Even if all this activity were concen-
trated in the least abundant habitat type—the Post Oak Savannah--
only six percent of the total habitat area—would be affected.
Considering the revegetation can be accomplished within three
years in most areas, the percentage totally devoid of habitat
value at any given time would be smaller yet.
Another major cause of habitat destruction will be the
construction of off-steam cooling reservoirs. In addition, new
mainstem reservoirs must also be built to provide sufficient
surface water supplies to accommodate lignite growth along with
other expected increases in water demand. The construction of
such impoundments is important not only because of the relatively
large acreages involved in any one of them, but also because of
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the type of habitat most frequently inundated, Over much of
East Texas, bottom lands, rivers, and stream courses provide
continuous ribbons of good cover and abundant food for many
terrestrial wildlife species, and provide habitat for aquatic
and semiaquatic forms as well. These habitats in some places
are in better condition than upland habitats, long subject to
grazing and the plow. In generally disturbed areas such as the
eastern half of the state, riparian habitats may often serve as
corridors permitting wildlife to move between scattered patches
of appropriate upland habitat. Reservoir construction not only
destroys the intrinsic value of the habitat inundated, but also
cuts off these routes of movement.
6.1.2 Reclamation in Perspective
Even though reclamation can ultimately restore a vege-
tation cover to the mined areas, the ultimate impact on wildlife
will depend on the use for which the reclamation is designed.
Currently, there seems to be a strong preference among land-
owners for restoration to "tame grass" pastures, chiefly of
Coastal Bermuda grass. This grass has comparatively little
value as food for most wildlife, and provides very little cover.
Also, a monoculture of one species tends to be more sensitive
to variation in environmental conditions, such as drought, than
a vegetation cover consisting of many species, each with its own
range of tolerance. Thus, restoration of mined surfaces to this
type of vegetation may result in a net loss of habitat value,
even though revegetation is successful.1*1
The U.S. Fish and Wildlife Service, in a recent evalu-
ation of Texas lignite mining, concluded that "climate and soil
conditions of many Texas areas are such that strip mining and
reclamation could be accomplished in a manner which would not
result in permanent damage to the environment, if strip mining
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is restricted from rivers and streams, bottom lands are kept
intact, proper reclamation techniques are used, and reclamation
managers try conscientiously to meet the requirements of the
New Surface Mining Bill."1*1 However, the regional significance
of even the most successful reclamation program must be evalu-
ated in terms of the quality of the unmined habitat surrounding
the disturbed area. It is this habitat which must furnish the
native plant and animal species needed to recolonize the re-
claimed area. Also, it is habitat conditions over large regional
areas which determine the overall health and diversity of eco-
logical communities. Successful reclamation of mines of few tens
of thousands of acres in size, scattered throughout a larger area,
may be wasted if habitat quality in the overall region declines
sufficiently over the same period of time.
6.1.3 Regionwide Trends in Habitat Quality
Currently, over much of the Lignite Belt, habitat
conditions are poor and populations are subjected to consider-
able man-made disturbances. Conditions in the Post Oak Savannah
have been particularly well documented with respect to lignite
mining.
Originally, this vegetation type was predominantly
post oak and hickory savannah or forest, integrated with open
prairie. Now, however, under the pressure of intensive grazing
and cultivation, mesquite has invaded much of the area. A great
deal of the original woody cover was cut for building materials,
fire wood, and to clear farm land. Forests that remain are
often grazed, which keeps them in a highly disturbed state.
Young seedlings and understory trees are often unable to survive
in sufficient numbers to assure the perpetuation of the canopy.
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Under continued grazing, the probable result will eventually be
thinning of the overstory and possibly invasion by the mesquite-
shortgrass savannah.
Upland areas have been cleared and cultivated for many
years, although much former agricultural land has now been al-
lowed to return to grazing. Heavy soil erosion has taken place
over a long period of time, and the vegetation now found on the
heavily grazed uplands may often be very weedy. In some areas
studied, unpalatable species such as Croton may make up the bulk
of the annual production. Heavy grazing tends to select against
the more palatable grasses and forbs, and favors less valuable
weedy species.
Heavy disturbance of the vegetation community has pro-
duced changes in the original animal population as well. Faunal
communities currently inhabiting the post oak savannah region
are not natural assemblages. They have developed under man-made
conditions, in response to a considerable degree of stress.
Species diversity is high, probably in part the result of the
introduction of year-round water supply. The creation of very
large amounts of edge habitat through clearing has also helped
promote diversity. Total numbers of animals, however, are prob-
ably much lower than those originally inhabiting the area. Thus,
in spite of high species richness, low abundance may make present-
day disturbed faunal communites less stable than the original
ones .
In addition to habitat change, larger animals are un-
der considerable stress from hunting and trapping, both legal
and illegal. Deer are rarely found in the area, and beaver,
fox, and bobcats are hunted and trapped regularly in and out of
season. Also, dogs running in packs, either with or without
humans in attendance, regularly harass wildlife,
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Such circumstances, if allowed to continue and to de-
teriorate, seem likely to do far more harm to the local eco-
systems than mining by itself. However, looked at another way,
these conditions suggest that any reasonable attempt to restore
wildlife habitat on reclaimed areas could produce habitat
superior to that which existed before. Before this can happen,
however, there must be an incentive to reclaim for wildlife
values, rather than grazing.*
6.2 Aquatic Ecosystems
Impacts of lignite development on aquatic ecosystems
are not as easily discussed on a regional level as are terres-
trial impacts. The surface-minable deposits of lignite in Texas
cross nearly every major river within the state. Species compo-
sition, species diversity, and population sizes vary between
rivers and within each river depending on a wide variety of en-
vironmental parameters. Since Texas has no natural lakes, all
of the native fresh water organisms are riverine in nature even
though they may reside in man-made impoundments. Some species
have been artificially introduced into the Texas river systems
from various sources from outside the state. Thus, the impact
of lignite mining and use will vary considerably from site to
site.
6.2.1 Types of Impacts on Aquatic Ecosystems
The major impacts of mining and mine-mouth power gener-
ation on aquatic ecosystems arise from three kinds of disturbance.
The process of mining itself may involve draining, filling, or
rerouting small streams around the mine. Although the new Sur-
face Mining Control and Reclamation Act generally prohibits mining
*See Chapter V for a discussion of methods to provide such in-
centives .
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within one hundred feet of a stream channel, exemptions to this
provision may be authorized. Impacts from this type of activity
include the loss of habitat and downstream siltation.
Another set of impacts arises when off-stream impound-
ments are built for cooling. According to the Texas Department
of Water Resources, cooling-water reservoir capacity is expected
to quadruple in the next 50 years. Each impoundment has a small
but measurable effect on flow regimes, and on the movement of nu-
trients and sediments through the drainage system affected. It
should be recalled, in addition, that large new main-stem reser-
voirs will also be constructed over the same time period. The
combined effect of all this activity will depend upon its concen-
tration in a given basin. Replacing a flowing water habitat with
an artificial lake completely changes the nature of the former.
In addition to the natural replacement of species requiring shal-
low, running water and riffly habitat by organisms adapted to res-
ervoir conditions, most reservoirs are also planted with game
species for recreational purposes. Reservoir operation and
timing of floodwater release can have a very strong effect on in-
stream flow regimes. This affects not only downstream freshwater
habitat, but potentially affects conditions in downstream estu-
aries .
Occasionally, concern is expressed about acid mine
drainage, similar to that experienced in the Appalachian regions.
Excessively low pH produces severe habitat damage. Experience
in lignite mining to date has not shown such problems to be as-
sociated with Texas lignite. In south Texas, however, the lig-
nite may contain considerably more sulfur than that in which
mining had taken place up to this time. Whether or not this
will result in acid drainage conditions remains to be seen.
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6.2.2 Effects of Flow Depletion
While most aquatic impacts are likely to be site-
specific, a potentially more widespread effect of lignite de-
velopment on river ecosystems could arise from overall flow
depletion. During the years of normal river flow, the reduc-
tion in flow caused by cumulative water use related to lignite
is likely to be a small enough percentage of the flow remaining
that significant changes in the fresh water biota would not be
observed. However, in the long run, flow depletion will in-
crease the frequency of low flow conditions, unless reservoir
operation is adjusted to compensate for the change. While Texas
river ecosystems are naturally adapted to periods of drought,
there is no reason to believe that increasing the frequency of
such stresses would not eventually result in harm to the over-
all ecosystems. Countering this trend is the requirement to
preserve fresh water inflows to estuaries sufficient to protect
the productivity of the ecosystems there. Thus, the opportunity
exists, in passing the fresh water flows downstream, to correct
for flow deficiencies induced by consumption along the way.
6.2,3 Trends in Aquatic Habitat Quality
As is the'case with terrestrial communities, river
ecosystems in Texas are considerably altered from what they
originally were. In general, the extensive development of the
land around the major rivers has altered both water quality and
flow regimes. From the time of the early settlers in the 1800's
through the early 1900's, aquatic environments were used as
dumping grounds for a great variety of waste material. In ad-
dition, they have received large loads of soil from poorly
managed agricultural lands and over-grazed pastures. By the
first part of the twentieth century, most of the fish had been
removed from the rivers by commercial over-fishing or because
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of habitat degradation. Efforts by the Texas Parks and Wildlife
Department have restored many of the depleted populations to
reasonable levels. Still, pollution levels in the rivers, along
with consumptive water use, strains most of the state's aquatic
resources.
6.3 Research Needs
Estimate present and future demand for wildlife-related
outdoor recreation by residents of the large metropoli-
tan areas just outside the Lignite Belt. Evaluate
whether this demand could be made to support a system
of recreational lands based on reclaimed mined lands.
Compare and evaluate means of administering, managing,
and financing such a system; give special emphasis to
the concept of recreational leasing, similar to hunting
leases, which provides income to the landowner and in-
centives to reclaim and maintain for wildlife habitat.
Identify areas of unique or exceptionally valuable
terrestrial habitat within the Lignite Belt.
Experiment on existing surface mines with techniques
for restoring wildlife habitat value. Develop combina-
tions of forage species with value to both wildlife
and livestock. Develop maintenance programs for lands
so reclaimed.
Evaluate the effect of illegal hunting, trapping, and
harrassment by dog packs on the successful reestablish-
ment of wildlife or mined lands.
Investigate techniques for protecting aquatic/riparian
communities during mining of surrounding areas; fac-
tors to consider include flow maintenance, water qual-
ity, shading and temperature regime, and organic matter
influx.
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7.0
SOCIOECONOMIC IMPACTS
Summary and Conclusions
Most lignite-related activity will occur away from
large population centers. The Lignite Belt is close
enough to metropolitan centers, large cities, and
towns that boomtown growth is not likely to be wide-
spread.
Typically, communities affected by lignite develop-
ment will experience some degree of strain on housing
and municipal services. Some changes in the commun-
ity's demographic structure will occur. These impacts
will probably be most pronounced in the Southern Sub-
region, and least pronounced in the Gulf Coast Sub-
region.
A common problem is mismatching between the taxing
entity receiving increased revenues from new plant
construction and those which must provide most of the
services needed by a growing population. A particu-
lar problem arises where a new plant is built by a
non-taxable publicly owned entity.
The cumulative effects of the entire development
scenario could have substantial impacts at the sub-
regional level. Growth impacts are likely to be
shared among many communities, rather than concentrat-
ing on those nearest to new plants and mines.
Spreading growth among many communities may create
additional secondary environmental and socioeconomic
impacts.
Planning at the local level is likely to be more
difficult when growth impacts are spread.
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7.1 Community-Level Impacts
Figure 7-1 illustrates one overriding feature which is
very important in analyzing community impacts: there are no
major metropolitan centers on the Lignite Belt itself. Most of
the mining and power plant activities in the development scenario
will be sited in nonmetropolitan areas. The reader is referred
to Figure 4-1 in Chapter III, which shows even more obviously
that nonmetropolitan locations will be developed in lieu of
metropolitan areas. This characteristic makes it easier to pro-
ject the type of impacts the individual communities will ex-
perience.
No attempt is made here to project impacts in particular
towns in Texas. However, some general comments about the major
problems may be made, based upon recent literature on the topic.
Also, the results of an impact assessment model (BOOM) are pre-
sented for a hypothetical community vulnerable to boom-town impact.
Finally, the change in one Texas community which has experienced
the type of growth under consideration is summarized.
7.1.1 General Overview
The most extreme potential impacts of lignite activity
can be anticipated by examining the general body of "boom town"
literature. A larger literature into which the "boom town" studies
4 2
fall is the rural industrialization literature. The most impor-
tant concepts drawn from both can be applied to developments in
Texas.
The impacts of new economic activity in a metropolitan
region are relatively minor because the increment of population
growth is small relative to the original, or the host population.
If there is unemployment or underemployment, there may be no
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POPULATION DISTRIBUTION AND LIGNITE BELT
Population . 100
• 200 • 999
1,000-2,499
. 2,500 - 4,999
• 5,000.9,999
• 10,000 - 24,999
• 29,000 • 49,999
• 50,000 • 9,999
• 100,000-249,999
D Li,
Lignite Arm
Adapted from: Robert K. Holz, "Population Distribution in Texas:
Pattern* of Population Distribution", Texas Business Review, June 1973.
02-4322-1
Figure 7-1. Population Distribution, 1970
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population growth at all. This is likely to be the case in most
of the Gulf Coast Subregion.
The same is not true, however, in sparsely populated
nonmetropolitan areas. A new economic activity in a small, iso-
lated town results in almost instantaneous growth which everyone
in the region will perceive. Some of the local population may be
employed at the new activity, while most of the new jobs will go
to inmigrants or long-distance commuters. This type of sudden
massive impact is more probable in the sparsely developed Southern
Subregions, as can be seem from Figure 7-1.
Most areas in the Northeast, North Central, and Cen-
tral Subregions will fall somewhere between these two extremes.
Population growth related to new economic activity is
not necessarily adverse. Many small towns in nonmetropolitan
Texas have experienced net outmigration for decades. They have
been left with relatively older populations. New economic activ-
ity can mean that former residents who left for lack of employ-
ment activity may be able to move back. This "return migration"
is a rather common phenomenon in areas which have new activity
after a long period of outmigration.
A major impact of the population growth caused by the
new activity is on the demographic profile of the community.
For an activity with a major construction phase, the profile of
the initial immigrants usually differs drastically from the local
population. '*3 The construction worker profile has a high pro-
portion of single men who form a sharp contrast to the older
native population which has a fairly typical male-to-female
ratio. Those construction workers who do bring their families
tend to have school-age children in greater numbers than the
local population.
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Community planners need to know the anticipated popu-
lation increase. The answer is primarily a function of two
variables: the number of new jobs and the spatial pattern of
population centers.
Most activities have a construction phase and an
operation phase. The former typically requires more workers than
does the latter. However, the secondary employment effect of
construction phases is not as great as that created by the opera-
tion phases. Many construction workers will send large portions
of their income home rather than spend it at the construction
site. Others will commute long distances, thus taking their
incomes out of the local area. In contrast, the operation phase
typically requires a smaller labor force, but these "permanent"
workers will tend to live nearer the activity. This tendency to
live nearer the job makes the employment multiplier effect of
the operation phase greater than that of the construction phase.
Regardless of the phasing, there will be population growth due
to the new activity itself and secondary growth to serve the
primary growth increment. This secondary growth is supported by
increased retail activity, demand for housing and increased pub-
lic services (schools, police, etc.). Employment estimates for
various types of facilities are presented in Table 7-1.
TABLE 7-1. PROJECT CHARACTERISTICS*
Type of
Facility
5 MMT/Year Lignite Mine
1500 MWe Power Plant
300 MCF/Day Gasification
Plant
Construction
Employment
(maximum)
200
2000
3000
*These estimates were averaged from several
only as guidelines, not predictions.
Construction
Time
2-3 years
6-8 years
5 years
sources and are
Operation
Employment
400
200
1200
intended to serve
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The second key variable in predicting population growth
is the spatial pattern of population centers near the new activ-
ity. At one extreme would be a site remote from existing commun-
ities. A company town with all the workers living in that town
would probably be developed. However, this appears unlikely for
most sites in the Texas Lignite Belt. A mine and plant site will
generally be within reasonable driving distance from several
small towns. The population growth stimulated by the new activity
will tend to disperse itself among the respective communities.
Distance to work is often used in spatial allocation models,
along with the population sizes of competing towns (a surrogate
for goods and services available in the towns), to predict where
the inmigrants will settle.**"*
7.1.2 Impacts Experienced by Communities
The ability of a community to accommodate growth is
reflected in its response to several factors. These range from
increased demands for services to changes in social interactions
between community members.
7.1.2.1 Housing Demand
The demand for housing in a growth situation can be
met in several ways. The most important determinant of the
response is the duration of the demand. In rapid growth situa-
tions, mobile homes are usually the short-term solution to the
housing shortages. This is especially true for those activities
with large construction labor requirements and subsequently
smaller labor requirements for the operation of the facility.
Another partial solution (in the case of a remote facility
during the construction phase) is a dormitory for the single
workers. The less desirable alternatives to either of these
solutions are long-distance commuting and over-crowding.
JZ'D
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In areas with high housing demands over short periods
of time, mobile homes may be the appropriate solution. For
instance, two mobile homes can be co-located on one lot for a
short period. Once the "boom" is over, the unneeded homes can
be moved elsewhere and a permanent house can be built where two
mobile homes previously were. This avoids overbuilding.
Mobile homes gain notoriety when they become a long-
term solution to a housing shortage. Mobile homes are generally
considered to be inferior environments when compared to permanent
housing. Mobile home parks are often unkempt and overcrowded.
Mobile homes are smaller than permanent houses. In remote areas,
people have to spend more time in these cramped homes because
there is little else to do. Interpersonal relationships may tend
to become strained as a result.
7.1.2.2 Public Services and Facilities
The housing problem leads to a number of other problems.
Most of these are related to providing services and facilities
for the housing units and their residents. These problems are
often aggregated under the heading "public services and facili-
ties."
When a community is faced with population growth, a
number of public services and facilities must be addressed with
respect to their ability to serve the anticipated incremental
growth. Most nonmetropolitan towns have very little unfilled
capacity since population decline rather than growth has been the
trend for several decades. Water supply is an obvious limiting
factor. New wells may have to be developed to meet household
requirements. Even if the water is available, there are often
problems with distribution to population growth areas. How a
community pays for this type of development is examined in the
following section.
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A consequence of an expanded water supply is a require-
ment for wastewater treatment. Septic tanks are a common solution
to this problem even within towns. However, septic tanks are
often not an acceptable solution in a period of rapid population
increase. Hence, a community may have to expand an existing
treatment system or construct a new one. These systems are rel-
atively expensive and difficult to finance. Complicating waste-
water management is the collection system problem which is similar
to the freshwater distribution. This may require simple expansion
of the existing system or something much more extensive, such as
a lift station (if population growth occurs in the wrong drainage
basin).
Public safety can be a major problem in a genuine boom-
town situation. The "4 D's" (drunkenness, divorce, depression,
and delinquency) often plague boom towns. 26 Hence, the city po-
lice department and the county sheriff's office must be expanded
because of the population growth and subsequent social problems.
Retaining qualified people is difficult because competing jobs
(such as company guards) offer higher wages. Fire protection
may also be affected by rapid growth. The problems of extending
water lines and finding fire-fighters can be serious. Volunteers
may be the only source of fire protection.
The level of health care in most small towns is limited
more by the quantity and quality of health personnel (physicians,
nurses, and dentists) than by the physical facilities. Qualified
personnel are difficult to attract and retain in rural areas.
When the overall population of a region is low, it is difficult
to support a variety of medical specialists. Hence, many resi-
dents of nonmetropolitan areas must drive long distances to re-
gional hospitals for specialized care.
-------
In some instances, population growth can be looked
upon as a blessing for health care. The new population, after
a growth period, may be perceived as large enough to support
additional physicians, hence the ratio of qualified health per-
sonnel to patients could improve.
As with nearly everything else in a growth situation,
the school system may become overcrowded. Physical crowding can
be overcome in the short-term by adding temporary rooms. Even-
tually, new schools have to be built. In an actual boom-town
situation, the school system must often be expanded to meet a
temporary demand which is greater than the demand for the opera-
tion phase. It is that situation which often makes the temporary
building more inviting than a permanent structure.
In more remote areas, finding teachers to work in the
new classrooms can be a serious problem. Rural areas have always
had a problem attracting and retaining qualified teachers. Com-
pounding this situation is the fact that wages paid in the new
facility are often much higher than the teacher salaries, making
teacher attrition high.
7.1.2.3 Local Government Response
Most of the solutions to these problems require action
by government, primarily at the city or county level. These
governments usually lack the expertise and finances to provide
the needed services.1*5
Small town city managers and county judges are often
not professionally trained for these jobs. They sometimes resist
change rather than seeking the advice of regional councils of
government or staff agencies. Public opinion in the communities
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they serve often runs against involving larger government
entities.*6
The wages paid to local government professional staffs
are often less attractive than those paid at the new facility.
Hence, there may be a problem with personnel turnover in the public
sector jobs. Few of these governments have planned to accommodate
rapid population growth since they have, for the most part,
experienced population decline for long periods. Also, there is
often the problem of jurisdiction. If population growth occurs
outside city limits, the city can do little to control the growth.
An issue involving the equitable distribution of costs
and benefits arises when a new facility is sited in one taxing
jurisdiction (school/county) and the impacts must be borne by
other jurisdictions. If the impact is in one county and the
capital investment in another, there is no change in the property
tax base for the affected county.
A particular aspect of this problem is the presence in
Texas of many publicly owned utilities. These entities are exempt
from taxes. In two recent cases, new plants either wholly or
partially owned by such utilities have been sited in rural areas.
Both the South Texas Nuclear Plant in Matagorda County and the
proposed Gibbons Creek Plant in Grimes County have met strong
local opposition. Some residents feel that the local communities
are being forced to carry an unfair burden in shouldering the
costs of providing increased services.1*
Another problem related to financing new facilities is
the reluctance of long-time residents of an area to add to their
tax load to pay for new facilities to accommodate immigrants.
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Finally, it can be a problem if a boom caused by a
temporary activity such as construction is to be followed by a
lower level of employment during the operation phase. It is
possible to over-build during the boom period and have excess
capacity after that without the necessary taxpayers to continue
payment (the so-called "boom and bust" phenomenon).
A problem common to nearly all energy-related develop-
ments is the lack of land-use control mechanisms. Counties in
Texas do not have formal land-use control authority. Towns some-
times have zoning authority but it never extends far enough into
the surrounding countryside to be very effective. A rapid-growth
situation often leads to haphazard, low-density development of
the areas peripheral to the affected town, creating problems
providing services and facilities as well as adverse aesthetic
impacts.
Another potentially serious problem faced by local
communities is uncertainty. Those responsible for the final
authorization of the new facility often hesitate to announce that
project until the last moment because of their uncertainty (due
to financing, marketing, and regulatory requirements). That
creates uncertainty at the local level and decisive mitigating
measures are postponed.
There are other planning problems which governments
in rapid growth areas are poorly equipped to solve, such as a
lack of adequate solid waste disposal systems and stress on the
existing transportation network. These problems make it just
that much more difficult for government to act responsibly.
These problems are partially the cause of a certain amount of
animosity which will develop between "oldtimers" and "newcomers."
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7.1.2.4 "Oldtimers" vs. "Newcomers"
The problems discussed thus far are related to the
effects people have on social and economic systems. However,
a rapid growth situation also affects people socially and
physiologically. This was suggested in the discussion of public
safety through the identification of the 4 D's.
A recent review by Freudenburg49 highlights these
social problems that are difficult to quantify yet very real in
the final analysis. Sudden change, regardless of whether or not
it is caused by energy development, is often difficult to accom-
modate. This applies both the newcomers and the oldtimers in the
boom town situation. Freudenburg concluded his review by hypothe-
sizing that social disruption:
. Is socially related to the size and suddenness
of the development;
• Is inversely related to the population density
of the impact region;
• Is inversely related to the percent of jobs
going to people already living in the region;
• Is directly related to the level of skills
required; and
• Is directly related to number of inmigrants to
the region.
532
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The social disruption affects both newcomers and
oldtimers. Both must adapt to changing environments. Jealousy
is inevitable because one group (newcomers) causes the change
while the other group (oldtimers) feels "invaded" and have to
react. Old local residents often cannot compete financially
since many are on fixed incomes and cannot pay inflated food and
housing costs. Oldtimers usually have lower job skills preclud-
ing their employment in higher paying jobs. Newcomers have few
friends and feel powerless against the established social and
political order. Oldtimers fear that the established political
order and value systems will be eroded.
7.1.3 A Boom Town Simulation
The socioeconomic impacts of energy-related develop-
ments at any site along the Texas Lignite Belt will probably not
be as severe as similar situations have been in the West, primarily
because the Lignite Belt contains a more dense pattern of commu-
nities to absorb growth-related stress (see Figure 7-1). However,
a model to simulate boom town conditions in a hypothetical com-
munity will help to highlight major problems which could develop.
The BOOM model was originally developed by the Los
Alamos Labs and has recently been adapted by the Center for
Energy Studies at The University of Texas at Austin for use
in Texas. The most useful feature of the model is that it simu-
lates various social and economic indicators for a hypothetical
community over time. It is based upon an elaborate set of equa-
tions which have been derived to capture the complex interrela-
tionships among various components of the socioeconomic environ-
ment (housing, public finance, retail trade and services, the
new economic activity, and population growth). A change in any
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one of the components affects the others both directly and in-
directly through the predefined set of equations. The model is
not intended to unravel the detailed behavior of any one sector.
Rather, it shows how they interact and affect one another. A
detailed presentation is beyond the scope of this report. How-
ever, a brief discussion of the public service sector shows how
the boom town problem can develop.
An aggregate measure of the public service sector con-
siders those elements highlighted in Figure 7-2(a). Each of
these components has a number of inputs defined by equations.
For instance, education includes all those elements shown in
Figure 7-2(b). The model uses data descriptive of any community
under consideration. Standard planning parameters are also in-
corporated to calibrate the model. Output from the model can
include estimates of impacts on individual components (for in-
stance, capital costs for new schools or wastewater treatment
facilities), or on all components together. The user can then
change input data and parameter values to simulate various
policy options.
An example BOOM simulation is presented to show how
the "boom and bust" cycle would work in a hypothetical town of
10,000 in an isolated area. This simulation is not intended to
depict any particular situation in Texas. The hypothetical pro-
ject under consideration is a 1500-MWe power station located so
that only one town would be affected. The model has been de-
signed to show the town's public service capacity as being ade-
quate before any new activity begins. Figure 7-3 shows the
excess capacity without the new activity. Figure 7-4 illus-
trates the "boom and bust" cycle caused by a construction phase
followed by a less significant operation phase. The excess in
public services after the construction phase is over is obvious.
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EDUCATION
POLICE
PROTECTION
PUBLIC SERVICES
AND FACILITIES
FIRE
PROTECTION
SEWER
Figure 7-2a.
ELEMENTARY
REQUIREMENTS
ELEMENTARY
FACILITIES
POPULATION
GROWTH
HIGH SCHOOL
REQUIREMENTS
HIGH SCHOOL
FACILITIES
ELEMENTARY
SHORTAGE
HIGH SCHOOL
SHORTAGE
Figure 7-2b.
02-4321-1
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-0.25
OJ
CO
PUBLIC
SERVICE
CAPACITY
«0.5
1974
1978
1982
1986 1990
02-4320-1
Figure 7-3. Quasi-Equilibrium
(Without Energy Development) Simulation
•0.5
-0.2S
PUBLIC
SERVICE
CAPACITY
••0.25
«0.5
CESS CAPACITY
CAUSED BY
OVERBUILDING
1970
1978
1982
1986
1990
02-4319-1
Figure 7-4. Worst Case Boomtown Simulation
-------
Which particular public sector activities are inade-
quate is not important. Important is the concept that a com-
munity can provide services and facilities for a short term
which will not be needed after the construction phase is over.
This unused capacity becomes an even greater burden for the
community because it cannot make the payments, which in turn
creates other problems.
This delineation of a boom and bust cycle is important
because it serves as a "worst case" scenario for the assessment
of community impacts of lignite development. Only in South Texas
(where the density of population and communities is low) could a
boom and bust cycle similar to boom towns of the West be experi-
enced. However, minimal development is projected for that re-
gion. The remainder of the lignite region might experience tem-
porary booms, but the activity will be dispersed over so many
small towns that the possibility of severe impacts are minimal.
7.1.4 The Mount Pleasant Experience: A Case Study
The socioeconomic impacts on one nonmetropolitan com-
munity in Texas where lignite development has occurred have been
fairly well documented.51 The types of problems which occurred
there are representative of what might happen in a similar situa-
tion. The town of Mount Pleasant in Titus County has experienced
the impacts discussed in the previous sections resulting from the
simultaneous development of two power plants and a lignite mine
located in the county. The population of Titus County increased
26 percent, from 16,702 in 1970 to 21,000 in 1976, while the
population of Mount Pleasant increased 43 percent, from 9,549 to
13,700, over the same two-year period.
Housing this population increase was a significant
problem since there were no available units. Four hundred mobile
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homes in ten parks provided a partial solution. Other mobile
homes were located throughout the county on individual lots.
Yet, there was still a housing construction boom. In Mount
Pleasant, 625 single-family units and 500 apartments were built
by 1975. Another 1,000 homes were built outside the city
limits. Housing supply eventually surpassed demand in 1975.
Financing this housing construction was difficult for
local institutions. Deposits by inmigrants did not equal the
demand for loans for several years and the financial institu-
tions had to incur some short-term debts. In the long run,
these institutions realized substantially increased deposits
and profits. In the meantime, however, they changed signifi-
cantly the way in which they did business.
As housing developed on the periphery of Mount Pleasant,
the traditional geographic pattern of the city changed. Retail
establishments located on the periphery to be near the new popu-
lation and to avoid a stagnating central business district. The
competitive pressures forced many of the older establishments to
abandon their central locations and relocate on the periphery.
One aspect of this geographical change was that people without
cars who had relied upon the central business district were in-
convenienced, since Mount Pleasant had no public transportation.
Rapid growth also presented problems for city and
county government. A ban on mobile homes within the city was
lifted as a short-term solution to the housing problem. How-
ever, in a period when land-use control within the extraterri-
torial jurisdiction (ETJ) of the city was not exercised, con-
siderable haphazard growth occurred. Even with changes in
government leadership, severe problems with community services
and facilities were encountered. A water shortage became worse.
City sewer treatment, already inadequate, became more overloaded.
33*
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Solid waste was a problem both with respect to collection and
disposal.. Traffic flow on city streets changed drastically and
major routing changes had to be made. The county highway sys-
tem was even more severely affected because heavy trucks began
using roads designed for lighter loads. Crime increased dra-
matically, requiring law enforcement manpower additions and new
jail construction. Fire protection service declined in quality
and fire insurance rates were subsequently increased.
The Mount Pleasant Independent School District profited
greatly from the growth. The tax base increased substantially
but the enrollment did not increase proportionately (many of the
newcomers were single, without children). The physician per
patient ratio improved as demand grew. Future health care will
improve since a hospital district was formed to build a new hos-
pital.
City government had to revalue and reassess property
to raise enough money for the additions to facilities and
services. Bonds had to be sold to pay for water and wastewater
improvements. User rates for all services were increased.
Titus County had similar financial problems because it needed
capital improvements. However, taxes were not increased because
the assessed valuation of property increased dramatically with
the additions of the major projects.
In summary, the Mount Pleasant area changed drastically
in a four-year period due to lignite-related population growth.
The conservative city and county governments were replaced by
those more able to cope with change. Values changed drastically
with the influx of outsiders. Older residents had little choice
in the matter as their community changed. Thus far, there has
not been a bust part of the boom and bust cycle because the
economic activity continues today.
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Although their severity will differ considerably from
place to place,* problems of this kind are typical of what a non-
metropolitan community can expect. However, Mount Pleasant was
better equipped to cope because of its size at the beginning of
the change (8,500). A smaller town hit with the same population
growth would be much more severely affected. Also, much of the
population growth attributable to the economic growth occurred
in surrounding counties, so that Mount Pleasant did not receive
the full impact of the activity.
7.1.5 Variability in Community Impacts
The severity of socioeconomic impacts will vary with
the size and type of facility located near a community. A lig-
nite mine for export will present the fewest problems since it
involves the fewest people and because it does not have a "bust"
component. A gasification facility would have the greatest im-
pact based upon the size of the construction and operation crews.
Intermediate in severity would be a 1500-MWe power plant. Both
the power plant and gasification facility potentially have sub-
stantial socioeconomic impacts associated with their construc-
tion and operation. The socioeconomic problems associated with
any of these three activities are related to the population
growth, not the facility itself.
The most obvious impacts are those on local govern-
ments. Services and facilities become overburdened and the
governments involved often have neither the financial resources
*In contrast to the Mount Pleasant experience, development of
the South Texas Nuclear Project in remote Matagorda County pro-
duced considerably less strain than had been anticipated, al-
though qualitatively the same range of impacts was felt. "8
340
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nor the expertise to solve the problems. When the assistance
becomes available, it is often too late to be effective. Also,
because of political boundaries and other institutional barriers,
the community required to provide the services and facilities
may not be receiving the proper tax benefits.
Another potential problem is related to the "boom and
bust" cycle. A construction phase followed by a significantly
less labor-intensive operations phase could cause the over-
development of services and facilities. The potential for this
type of situation along the Texas Lignite Belt is not great.
However, that potential must be acknowledged in the planning
process.
Finally, lignite development will inevitably cause
change in the character of life in that region. There will be
aesthetic and visual changes as well as changes in the values
of the people. Low-density sprawl of housing changes the rural
landscape. Whether or not these changes are good or bad is for
the individual to determine. Yet, to recognize that change is
inevitable and that it affects various groups differently is
important in planning for it.
7.2 Regional and Subregional Impacts
The preceding discussions show that the boom-town
phenomenon at the community level is not expected to become a
serious problem in Texas. The main reason is the tendency for
impacts to be spread over larger areas, reducing the pressure
on individual cities and towns. At the regional and subregional
levels, however, this same tendency may result in significant
cumulative effects, as the whole development scenario unfolds.
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7.2.1
Subregional Development Patterns
The lignite development scenario projects seven 1500-
MWe power plants will be built through 1985 and that 14 more will
be built through 2000. Those projected by 1985 are already an-
nounced or under construction, and their sites are known. How-
ever, the locations of the other 14 are uncertain.
Figure 7-5 shows, by subregion, how construction of
the facilities might be phased from 1985 through 2000. A six-
year construction period for each 1500-MWe plant is assumed.
Lignite Facility Gasification Facility
_ __^_ C Time Frame *or Not completed bv 2000
Coil Facility
I I 1 1 1
MORTM11ST c
L/C
L
NORTH CENTRAL
L/C
SOUTH
uc
CENTRAL
L/C
GULP COAST ' '"'•
L/C
L
02-4303-1
Figure 7-5. Hypothetical Lignite/Coal Facility Construction
By Subregion 1985-2000
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Although the scenario stops at the year 2000, other facilities
will continue to come on line after that year. Construction
for some of these plants would begin before 2000, as indicated
by the dashed lines on the figure.
The figure is based on several simplifying assumptions.
First, it is assumed that plant construction would be evenly
staggered through time. In reality, of course, a certain amount
of bunching up would occur. Second, no time lags are assumed
between building the three 500-MWe units comprising each plant.
In the past, such gaps have often occurred.
Most important, the construction activity related to
industrial coal and lignite use is not included. Without know-
ing the kinds of facilities to be built, and their sizes, it
would be misleading to try to include them in this chart.
However, judging only by the amount of industrial coal and
lignite use projected, facility constuction will add significant-
ly to the total. In the Northeast 'Subregion, industrial coal
and lignite use is 15 percent of that projected for utilities,
while in the North Central Subregion it is 30 percent of utility
use. Although projected industrial use is very small in both
the Southern and Central Subregions, in the Gulf Coast half
again the volume of coal and lignite goes to industry as to
utilities.
7.2.2 Measures of Subregional Impact
While the development scenario involves impacts in
both the construction and operating phases, the construction
phase impacts are likely to be the more important at the sub-
regional level. Construction impacts occur first, and involve
more workers. The scope of the present study does not permit a
detailed investigation of all relevant measures of impact.
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However, a comparison of projected cumulative employment levels
with the available workforce gives a rough index of the poten-
tial socioeconomic impacts that might be expected.
Figure 7~5 suggests that the Gulf Coast, Central,
and Southern Subregions will be relatively unaffected at the
subregional scale by the levels of development projected there.
The situation is more complex in the Northeast and North Central
Subregions. In the North Central there might be as many as
three construction events at one time. If all three were to
coincide with their peak construction phases, there would be
as many as 7500 (1.5 workers/MWe) workers employed in construc-
tion at any one time. For the entire North Central Subregion,
with a labor force of 1,794,000, this does not present a man-
power problem. However, for the nonmetropolitan counties in
the North Central Subregion, with a total labor force of 81,000
people, 7500 new jobs does represent a substantial increase.
There may also be considerable secondary employment growth
associated with that initial growth. Part of the labor would
come from the surrounding metropolitan areas (Austin, Temple-
Belton, Waco, Bryan-College Station). However, much of that
area is effectively beyond commuting distance from metropolitan
areas.
The situation is similar in the Northeast Subregion.
By the end of the 1990's there could be four or five power
plant projects underway simultaneously. That subregion has a
total labor force of only 365,000 people in 1978, 212,000 of
which are in the nonmetropolitan counties. Five 1500-MWe power
stations under construction at any one time might create as
many as 12,000 construction jobs in the region and generate a
significant number of secondary jobs. That increase would have
to be considered a source of concern if these nonmetropolitan
regions did not change substantially between now and 1995. The
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impacts which occur in the early 1980's at isolated sites should
be watched carefully to determine whether or not a regional ap-
proach to accommodate the development in the 1990's will be
necessary.
7.2.3 Factors Mitigating the Extent of Subregional Impact
These rough figures do not by themselves convey a
sense of how widespread construction-related impacts may be in
the Northeast and North Central Subregions. The intensity and
distribution of impact depends on the geographic pattern of con-
struction activity. The clustering of development is in itself
important. However, in addition, the relative economic develop-
ment of the immediately surrounding region has a great deal to
do with how well the impact can be absorbed.
If mine-mouth power plant development proceeds as pro-
jected in the development scenario, then there may be a tendency
toward clustered development. The reader is referred to Figure
3-2 in Chapter I, where is may be seen that clustering around
lignite deposits is already evident. A breakdown of this trend,
such as might develop if air quality concerns dictate control of
regionwide source spacing, might result in more scattered siting.
However, subregional development levels are based on projected
subregional demand growth. Therefore, only a very extreme form
of regulation would greatly alter the total amount of construction
in the Subregions.
The diversity of a town or a county's economic base,
the variety and extent of the goods services it can provide to
an industrial or utility project, its population size, and the
complexity of its governmental framework, can be though of
collectively as measuring its ability to accept growth.52 In
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this respect, the Northeastern and North Central Subregions are
not homogeneous. Some small communities, such as Mount Pleasant,
prior to the advent of power plant construction, have experienced
little change or a decline in their economic base in recent dec-
ades. Others, like Navasota, in Grimes County, have attracted
a variety of industries and have healthy growing economics .1*7
The Tyler-Longview-Marshall area in the Northeast Subregion, and
Bryan-College Station and Waco-Temple-Belton in the North Central,
have recently experienced considerable growth and diversification.
These major centers, with their larger growth capaci-
ties, are located very conveniently with respect to possible
clustered development along the Lignite Belt. Tyler-Marshall-
Longview, located between the two major outcrops of Wilcox lig-
nite, could serve as growth centers for the entire subregion.
Bryan-College Station is likewise located between the Wilcox
and Yegua-Jackson belts in the North Central Subregion. Acting
as secondary growth centers could be the communities of Palestine,
Nacogdoches, Lufkin, Sulfur Springs, Mount Pleasant, and Texarkana,
Development in South Texas will probably be much more
disruptive to the individual towns that in the other regions.
First, the metropolitan centers are far from the Lignite Belt.
Commuting would be less of a solution. Second, the density of
towns is significantly lower. The fewer the towns to disperse
the impacts, the greater the impacts on any one town. This sit-
uation more closely approximates the boom town situation of the
West. From this perspective it is fortunate that little de-
velopment is projected for that region.
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7.2.4 Larger Implications of Regional and Subregional
Growth Patterns
Spreading the impacts of economic growth could under
some circumstances, create some secondary environmental and
social impacts, also on a subregional scale. A detailed and
predictive analysis of these impacts was beyond the scope of
this report. However, a number of potential concerns may be
listed which might warrant further study.
• Wastewater Management As more and more communities experience
growth, upgrading and expansion of sewage treatment systems
could become a widespread problem. Difficulties in identifying
planning horizons, delays in obtaining federal funds, and con-
struction holdups could result in temporary system inadequacies
which could result in temporary water quality problems. The ex-
tent of such problems would depend on the regionwide relation-
ship between available capacity and needed expansions.
• Aesthetics and Quality of Life The extent to which growth
changes the quality of life for better or worse is a matter of
individual perception. However, spreading growth among more
communities will mean that changes in the quality of life will
be more widespread. These will range from the aesthetics of
new commercial and housing developments, plants and mines to
more subtle social changes resulting from changed population
structures and community attitudes. This study will not
presume to qualify these changes as good or bad. Nevertheless,
it is clear that it may be more and more difficult to find
communities in which older ways of life persist unchanged.
• Energy Export A somewhat more abstract impact arises because
the demand which will drive lignite development is in the me-
tropolitan centers to the west (the San Antonio to Dallas urban
belt) and southeast (Houston to Beaumont). Energy will be
"exported" to those demand centers, where many other jobs will
be created as a consequence of that development. Fewer jobs,
in proportion to energy produced, may be created along the
Lignite Belt. This may be construed by some as a regional
inequity.
Another aspect of this question is that communities af-
fected by rapid growth will have to expand services and facilities
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to meet the demand created by metropolitan areas. Some would
argue that the metropolitan users should pay for the socio-
economic impacts associated with lignite development in non-
metropolitan areas. While regional questions such as this are
more difficult to resolve, they are important considerations in
the total impact assessment.
7.2.5 Implications for Planning
As has been pointed out, the extent and distribution
of cumulative scenario impacts is highly sensitive to both geo-
graphic and temporal factors. Thus, even though impacts may be
felt cumulatively, it may prove difficult to anticipate them
with the accuracy that adequate planning may require. Utility
siting announcements usually precede construction by one to
several years, because of the forecasting requirements of regu-
latory agencies. Industries are not so obligated.
An important aspect of Figure 7-5 is the length of
time over which high levels of activity are expected to persist.
Over this entire period, planners will be operating in a rela-
tively fast-response mode, reacting to new developments as they
arise. Also, impact-spreading implies that each county or com-
munity is liable, to a greater or lesser degree, to impacts from
construction in areas outside their jurisdiction. Thus, planners
will not have clear-cut targets to deal with, a situation which
may persist indefinitely.*
Finally, the question naturally arises of whether a
regionally distributed lignite boom is subject to a subsequent
*This situation contrasts sharply with that of a typical boom
town.
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bust. This question cannot be answered without extensive fur-
ther study. However, it can be pointed out that the tendency
to "bust" will depend very much in how lignite growth affects
the overall economic development of the subregions. If it pro-
vides the impetus for varied economic growth and industrial ex-
pansion, a bust will be less likely as the resource is depleted.
7.3 Research Needs
More thorough evaluation of the carrying capacity of the Lignite
Belt region as a whole to support energy growth. Major intra-
regional differences in growth capacity need to be related
to probable future development patterns.
Detailed assessment of sources of aid in planning and financing
new services, for use by individual communities. Evaluation
of need to streamline the system, disseminate information con-
cerning available help.
Identification of individual counties and communities which
appear likely to become subregional growth centers as a result
of the dispersion of the socioeconomic impacts of energy develop-
ment.
Identification and evaluation of ways to diversify the Lignite
Belt's economic base, so as to forestall or avoid "bust" condi-
tions when the lignite is gone.
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8.0 POLICY ISSUES RELATED TO IMPACTS
The preceding sections have shown that some of the
impacts which may reasonably be expected from the development
scenario may not be effectively mitigated by existing institu-
tions and policies. These problems without immediate solutions
are likely to become issues in the evolution of environmental
and energy policy. Seven such problems are stated below, which
cover a range of impacts at a generally high level.
In addition, the implementation of existing policy in-
volves a number of unresolved questions , especially in areas
where the enabling legislation is new and is undergoing inter-
pretation. Jurisdicational problems, problems of definition,
and problems of efficiency of implementation arise as Texas
seeks to adapt to the development of national policy. Four
issues relating to problems of this kind are set forth below.
All of these issues are discussed in detail in
Chapter V. There, more thorough assessments are given, includ-
ing alternatives for resolution of the issues, and implications
of implementing them.
8.1 Issues Related to Finding Solutions for
Developing Problems
Atmospheric Sulfates. Sulfates formed from power-plant
S02 emissions contribute to regional TSP loadings and
are associated with a variety of impacts, including
visibility, acid rainfall, and human health. However,
mechanisms relating power-plant emissions to their
ultimate expression in these effects are very imperfectly
known. Should an attempt be made now to regulate sulfates?
Without a relatively complete and realistic theoretical
understanding of the atmospheric chemistry involved in the forma-
tion of atmospheric sulfates, any attempt to regulate ambient
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sulfate levels must be relatively arbitrary. However, problems
related to sulfate in the atmosphere may be upon us before these
processes are known well enough to be modeled. Modeling is needed
not only to predict and regulate impacts from single sources, but
to devise realistic control strategies and evaluate compliance.
The Clean Air Act Amendments of 1977 require EPA to
study the impacts of sulfates on health, welfare, and visibility,
and several states have enacted sulfate standards. EPA's decision
to regulate or not to regulate sulfates at this time will have
to be made under conditions of significant ignorance of key as-
pects of the situation.
Infrastructural Financing. Energy development in the
Lignite Belt is expected to result in significant needs
for additional services and facilities provided by local
government. These needs will be dispersed through the
Lignite Belt, continuing over the entire study period.
Some communities will experience greater growth impacts
than others. Problems arise in anticipating capital
needs and obtaining funds.
The principal financing problems experienced by com-
munities affected by lignite development have related to timing
and equity. Timing problems arise because the heaviest demands
for services and facilities typically occur in the construction
phase of a large project. Tax revenues from the property, however,
do not peak until construction is complete.
Equity problems arise in two ways. First, the site
chosen for the project may lie outside the taxing jurisdiction
of those government entities which will have to absorb most of
its impacts. Secondly, a number of utilities in Texas are owned
and operated by Tax-exempt government entities.
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Flow Reduction and Water Quality. Reduction in in-
stream low flows can reduce assimilative capacity for
existing and future waste loads. To continue to meet
stream standards, waste loads in heavily burdened
streams may have to be reallocated. The costs of im-
proved cleanup would thus be imposed upon existing
permittees by consumptive users. In principle, this
problem could be alleviated by joint water management
and waste-load allocation. There may be practical
constraints, however, to implementing such a program.
In the past, permanent changes in flow regimes due to
consumptive water use have not been a major consideration in
wasteload allocation. In basins where assimilative capacity is
already heavily committed, progressive declines in low flows
may require repeated readjustments in wasteload allocations.
The cumulative expense involved in this kind of reactive ap-
proach to maintaining stream standards may be relatively high.
If flows could be managed as well, at least to the extent that
changes in assimilative capacity could be planned, it would be
possible to allocate wasteloads in a forward-looking manner.
To the extent that fewer dischargers would be faced with a need
to retrofit for better effluent cleanup, the cumulative cost of
clean water might be reduced. Neither the State of Texas nor
EPA, however, endorse the concept of flow augmentation as a
means of pollution control.*
Wildlife Impacts of Reclamation. Habitat conditions
over much of the Lignite Belt are poor for wildlife,
and could be improved by reclamation. At the same time,
there is a large and growing need for wildlife- and
aesthetics-based on outdoor recreation. How can this
need be turned into a potential economic incentive for
landowners to include wildlife values in postmining
land uses ?
*Note, however, that the existing problem of increased water
throughput to prevent high TDS levels in blowdown from power
plant cooling systems, discussed in Section 5.0, essentially
reflects a flow (or throughput) augmentation approach to pol-
lution control.
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As discussed in Section 6.0 above, reclamation poten-
tial is good over much of the Lignite Belt. However, most land-
owners consider that reclamation of mined land to monocultures
of cultivated forage grasses is their most profitable choice.
This type of cover is of very low value to wildlife.
The tradition of leasing hunting privileges is well
established in Texas, and can constitute an important source of
income for some ranchers. If similar value could be realized
from leases for recreational privileges—hiking and camping--it
might provide an incentive for farmers and ranchers to develop
wildlife habitat, rather than monocultures. Such uses can be
integrated with grazing, if properly managed. Not only are in-
centives needed to specify wildlife habitat as an end use in
reclamation, but continuing incentives to maintain and manage it
are also required.
Control of Boom-Town Growth. For communities which are
relatively isolated, nearby energy development may cause
a sudden spurt of economic and population growth, fol-
lowed by a sharp decline as construction is completed.
Later, a second decline may follow the depletion of the
local lignite resource. What can be done to reduce the
abruptness of this boom-bust cycle?
It was pointed out in Section 7.0 that boom-town
growth such as that experienced by communities in energy-rich
western states is not likely to be a widespread problem in
Texas. However, for those few communities which are not so
located as to allow population impacts to be spread among sur-
rounding towns and cities, boom-and-bust cycles could be serious
problems.
354
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Energy "Export" from Rural Areas. Mining and mine«-mouth
use of lignite will tend to focus the impacts of lignite
development on producing regions. These areas are in
general rural, and much of the power produced there will
go to users in distant metropolitan areas. To a degree,
the jobs produced through the use of the lignite resource
will "leak" away from the Lignite Belt to better developed
areas.
The concept of resource-rich rural areas as "energy
colonies" of more advanced urban areas rests on the assumption
that the rural areas will not experience diverse economic
growth as a result of energy development. More study is required
to determine to what extent this may be true of the Lignite Belt.
Potential economic diversification is a key factor in balancing
costs and benefits for the lignite belt.
Aesthetics. Lignite development and attendant population
growth will alter the looks of the lignite belt. Potential
declines in visibility would also have an aesthetic impact.
Presently, Texans appear willing to accept a degree of
aesthetic change. Most, however, have not yet experienced
the degree of change that may take place. Will this at-
titude change as development proceeds?
Aesthetic impacts of energy development are a matter
of personal opinion. They are also extremely persistent,
measured in human lifetimes. In addition, they tend to affect
a larger part of the population than that which benefits direct-
ly from the change. Mitigation potential is relatively limited;
they cannot be treated, assimilated, or paid for. These factors
make them unique among the range of impacts accompanying energy
development.
As the aesthetic impacts of lignite development begin
to be felt in more than a few communities, the present favorable
355
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attitudes may change. This reaction is likely to vary consider-
ably from place to place. The attitudes of big energy develop-
ers, and their willingness to work with local residents, will
probably influence the response.
8.2
Issues Related to Administering Existing Policy
Approval of State Surface Mining Program. The Federal
Surface Mining Control and Reclamation Act allows for
administration by the states, provided that the states'
proposed programs are approved by the Office of Surface
Mining. To conform to federal requirements, Texas must
essentially duplicate the federal program. This pro-
gram contains elements which are considered by some to
be inappropriate for Texas. The alternative is federal
administration in Texas.
A continuing problem in developing a national system
of regulating surface mining has been the difficulty of matching
a consistent set of national standards with mining conditions
that vary widely from state to state. Of particular concern in
Texas have been requirements to control suspended solids in
mine runoff and to segregate and replace certain layers of top-
soil and overburden.
The state viewpoint favors maintaining some ability to
adapt the application of the strip mining program to the specific
conditions encountered. Obtaining authorization to administer
the program is a key objective. Texas has a surface mining
statute of its own, passed prior to the SMCRA but containing, by
design, most of the concepts subsequently enacted in the federal
law. State-federal conflicts have arisen over the need to re-
write the Texas law to increase its detailed resemblance to the
federal statute.
356
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Lands Unsuitable for Mining. Under the lignite development
scenario, about 350,000 acres might ultimately be disturbed
by mining. The state's land area has not been extensively
studied by environmental scientists, particularly ecologists.
Should the Railroad Commission attempt now to identify areas
unsuitable for mining or continue to make this judgment on a
case-by-case basis?
Under the Texas surface mining legislation, the Rail-
road Commission is authorized to make a prospective designation
of areas unsuitable for surface mining. The right to petition
that areas be so designated is granted the public under both
the federal and state statutes. Lands may be considered unsuit-
able because of potential damage of important historic, cultural,
ecological, scientific, or aesthetic values. Lands important to
long-range watershed stability or to agriculture, or subject to
natural hazards such as flooding, may also be so designated.
At present, considerable uncertainty exists as to the extent of
potentially unsuitable lands, and their significance to mining.
Solid Waste Management. Large volumes of solid waste,
containing leachable salts, must be disposed of as coal-
and lignite-burning increases. Much of this waste would
logically be disposed of in or near the Lignite Belt, a
region of complex hydrology not well understood on a
fine scale. What measures are needed to insure against
groundwater contamination?
The detailed body of regulations called for by the
Resource Conservation and Recovery Act (RCRA) are still in the
formative stages, and may take several years to finalize. In
developing these regulations, it is important not only to pro-
vide adequate protection to the environment, but to avoid un-
necessary costs. Meeting these goals requires a more thorough
knowledge of the movement of potential contaminants through the
soil-water environment. Also needed is a realistic method of
testing wastes to determine appropriate disposal and containment
357
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procedures. This latter step is a key element in the process
of matching control efforts to the level of environmental pro-
tection needed.
Multiple Permitting. Several state agencies have statutory
responsibilities relating to site approval for mines and
associated energy-conversion facilities. Each is concerned
only with impacts that fall within its jurisdiction. Cur-
rently, there is no formal governmental mechanism for co-
ordinating these decisions. Should one be established?
Both regulators and project developers are hampered by
the delays and uncertainties related to multiple permitting.
Also, the overall impact of a proposed project may not be re-
viewed specifically. Impacts not covered by a specific permit
can also be inadequately addressed. Coordinated permit review
would offer a way to avoid these difficulties, while potentially
streamlining the siting process.
353
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REFERENCES CITED: CHAPTER IV
1. Kaiser, W.R., 1978, Electric Power Generation from Texas
Lignite, Bureau of Economic Geology, The University of Texas
at Austin, Texas, Geological Circular 78-3, v + 17 pp.
2. Radian Corporation, 1975, Characterization of Waste Effluents
from a Lurgi Gasification Plant, Radian Technical Note, 15 p.
3. Chemical and Engineering News. November 27, 1978.
4. Clark, P.J., R.A. Zingaro, and K.J. Irgolic, 1978, Arsenic
and Selenium in Texas Lignite and Synthoils. Unpublished
manuscript.
5. Gluskoter, J.H., et al., 1977, Trace Elements in Coal:
Occurrence and Distribution, Final Report, Urbana, Illinois,
Illinois State Geological Survey, EPA-600/7-77-064.
6. Huang, W.H. and J. Chatham, 1977, Occurrences of Uranium in
Texas Lignite and Their Implications, Unpublished manuscript.
7. Texas Air Control Board, 1977, Biennial Report, Austin,
Texas, 25 p.
8. Sander, S.P., and J.H. Seinfeld, 1976, Chemical Kinetics of
Homogeneous Atmospheric Oxidation of Sulfur Dioxide, Env. Sci
Techn. 10 (21):1115.
9. Kaiser, W.R., et al., 1978, The Impact of Coal Utilization
in Texas Under the National Energy Plan, paper presented at
the 71st Annual Meeting of the Air Pollution Control Associa-
tion, Houston, Texas, June 25-30, 1978.
10. Niemann, B.L., 1977, Transport and Fate of Gaseous Pollutants
Associated with the National Energy Plan (NEP)(Sections 2A,
6, 7B and 8B), extended paper prepared for the Office of
Energy, Minerals, and Industry, U.S. Environmental Protection
Agency, Washington, D.C., for the President's Committee on
the Health and Environmental Effects of Increased Coal
Utilization, xi + 91 p.
11. Miller, D.F., et al., 1978, Ozone Formation Related to Power
Plant Emissions, Science 202: 1186-1188.
12. Chameides, W.L., and D.H. Stedman, 1976, Ozone Formation from
N02 in "Clean Air," Env. Sci. Techn. 19 (2):150.
359
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13. Gautam, S.R., et al. , 1978, An Assessment of Air Quality
Impacts of Coal and Lignite Use in Texas, paper presented
at the 71st Annual Meeting of the Air Pollution Control
Association, Houston, Texas, June 25-30, 1978.
14. Teknekron, Inc., Meteorology Group, 1978, An Integrated
Technology Assessment of Electric Utility Energy Systems;
Air Quality Impact Methodology, Regional Study and Sub-
regional Problem Areas: Gulf Coast Area, briefing materials
prepared for Dr. Lowell F. Smith, Office of Energy, Minerals
and Industry, Office of Research and Development, U.S. Envi-
ronmental Protection Agency, Washington, D.C.
15. Niemann, Brand L., personal communication, February 9, 1979.
16. Whittaker, R.H., et al., 1974, The Hubbard Brook Ecosystem
Study: Forest Biomass and Production, Ecol. Monogr.44:
223-254.
17. Shriner, D.S., et al., 1977, Character and Transformation of
Pollutants from Major Fossil Fuel Energy Sources, Oak Ridge
National Laboratory, Environmental Sciences Division, Pub-
lication No. 1049, ix + 39 p.
18. Lave, L., and E.P. Seskin, 1977, Air Pollution and Human
Health. Baltimore, Johns Hopkins University Press.
19. Wolff, G.L., 1979, The Question of Sulfates: A Conference
Summary, Journ. Air Poll. Contr. Assoc., 29: 26-27.
20. Ferris, B.C., Jr., 1978, Health Effects of Exposure to Low
Levels of Regulated Air Pollutants, a critical review, Jour.
Air Poll. Contr. Assoc., 28: 482-497.
21. Dvorak, A.J., et al., 1977, The Environmental Effects of
Using Coal for Generating Electricity, NUREG-0252, Argonne
National Laboratory, Argonne, Illinois.
22. Colucci, A.V., 1976, Sulfur Oxides: Current Status of
Knowledge, EPRI Research Project 681-1, Final Report,
xii + 142 p.
23. 40 CFR, Part 60.
24. Jones, B.F., et al., 1978, Study of Non-Hazardous Wastes
from Coal-Fired Electric Utilities, Draft Final Report, EPA
Contract 68-02-2608, Office of Solid Waste, Systems Manage-
ment Division, Radian Corporation, Austin, Texas.
360
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25. Federal Register, September 19, 1978, Part V.
26. Christiansen, W., and T.H. Clark, 1976, A Western Perspec-
tive on Energy: A Plea for Rational Energy Planning,
Science 194: 578-584.
27. Resource Conservation and Recovery Act, Section 3001.
28. Electric Power Research Institute, 1978, The Impact of RCRA
(PL94-580) on Utility Solid Wastes, Final Report.
29. Radian Corporation, 1978, A Comparison of Atmospheric
Fluidized Bed Combustion Conceptual Designs for Utility
Steam Generation, Interim Report, prepared for: Department
of Energy, Energy Technology, Fossil Energy Office, Power
Systems Division, Washington, D.C., Radian Corporation, vii
+ 125 pp.
30. Ledbetter, W.B., 1978, Unexpected Good Fallout—Ash from
Coal-Fired Power Plants, Texas Transportation Institute,
Texas A&M University.
31. U.S. Environmental Protection Agency and Tennessee Valley
Authority, 1978, Economics of Disposal of Limestone Scrubbing
Wastes: Untreated and Chemically Altered Wastes.
32. Chemical and Engineering News, November 8, 1978.
33. Henry, Christopher D., 1976, Land Resources Inventory of
Lignite Strip-Mining Areas, East Texas, Bureau of Economic
Geology, University of Texas at Austin, Texas, Geological
Circular 76-2.
34. Texas Water Development Board, 1977, Continuing Water Re-
sources Planning and Development for Texas, 2 Vols., Texas
Water Development Board, Austin, Texas.
35. Henry, Christopher D. personal communication, January 3,
1979.
36. Hoffman, H.W., Jr., 1978, The Impact of Lignite Strip Mining
and Use on Water Resources in Texas--A Brief Overview} paper
presented to seminar on Surface Mining in Texas, Texas A&M
University, Department of Urban and Regional Planning and
Center for Energy and Mineral Resources, College Station,
Texas, October 19, 1978.
37. Radian Corporation, 1977, An Assessment of Technology for
Control of Toxic Effluents from the Electric Utility Industry.
Technical Note.
361
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38. Rice, J. and S. Strauss, 1977, Water Pollution Control in
Steam Plants, Atomic Power, April, 1977, pp. 51-520.
39. U.S. Environmental Protection Agency, Air and Water Programs,
Effluent Guidelines Division, 1974. Development Document
for Proposed Effluent Guidelines and New Source Performance
Standards for the Steam-Electric Power Generation Point-
Source Category.
40. Texas Department of Water Resources Staff, personal communica-
tion, January 3, 1979.
41. Cloud, T.J. Jr., 1978, Texas Lignite: Environmental Planning
Opportunities, U.S. Department of the Interior, Fish and
Wildlife Service, Office of Biological Services, Western
Energy Land Use Team. FWS/OBS-78/26, Washington, D.C.,
Government Printing Office, iv + 14 p.
42. Summers, G.F. , et al. , 1976, Industrial Invasion o_f Non-
Metropolitan America, New York, Praeger.
43. Booz, Allen, and Hamilton, Inc., 1974, A Procedures Manual
for Assessing the Socioecpnomic Impact o_f the Construction
and Operation of Coal Utilization Facilities in the Old West
Region, Washington, D.C.
44. Sanderson, D. and M. O'Hare, 1977, Predicting the Local Im-
pacts of Energy Development: A Critical Guide to Forecasting
Methods and Models, Cambridge, Massachusetts, Massachusetts
Institute of Technology.
45. Bolt, R.M. , et al, 1976, Boom Town Financing Study, Vol. I_,
Financial Impacts of Energy Development in Colorado-Analysis
and Recommendations, Department of Local Affairs State of
Colorado,Denver.
46. Blisset, Dr. M. , personal communication, February 24, 1979.
47. Flippen, M.L., 1977, Municipal Lignite Development in Texas:
The Grimes County Case, Masters Thesis, University of Texas
at Austin, LBJ School of Public Affairs, 112 p.
48. LBJ School of Public Affairs, 1978, Texas Energy Issues:
1978, University of Texas at Austin, Texas, xi + 116 p.
49. Freudenburg, W.R. , 1976, The Social Impact ojf Energy Boom
Development on Rural Communities, Yale University.
50. Ford, Andrew, 1976, Summary Description of_ the BOOM 1^ Model,
Los Alamos Laboratory, Los Alamos, New Mexico.
362
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51. Burke, Pat, 1976, An Impact Evaluation of Energy Development
Upon the City of. Mount Pleasant and Titus County, Texas ,
RPC, Inc.
52. Reinschmidt, L., 1976, An Evaluation of Economic Benefits
and Costs of Industrialization in Rural Communities in
Texas, Ph.D. Dissertation, Texas A&M University.
363
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1.
4.
7.
REPORT NO.
EPA-finO/7-7Q-TI1a
2.
TITLE AND SUBTITLE
Integrated Assessment of Texas Lign
Volume I: Technical Analyses
AUTHOR(S)
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
^p nA- T - ^ May 1979 issuing date
ite DeVelujjme^RFORM|NG ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Blvd.
P.O. Box 9948
Austin, Texas 78766
12
15
16
17.
a.
18
. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agenc]
Office of Research & Development
Office of Energy, Minerals & Industi
Washington, DC 20460
10. PROGRAM ELEMENT NO.
1NE 827C
11. CONTRACT/GRANT NO.
Grant No.: R806359-01
13. TYPE OF REPORT AND PERIOD COVERED
f
14. SPONSORING AGENCY CODE
-y
EPA/600/7
. SUPPLEMENTARY NOTES
This project is part of the EPA-planned and coordinated Federal Interagency
Energy/ Environment R&D program.
. ABSTRACT
This three volume report contains the results of a project to assess the
probable impacts of expected future development of Texas lignite resources.
This multi-disciplinary, policy-oriented study considered possible lignite
extraction and utilization options through the year 2000. The research
team attempted to identify and characterize the amjor environmental, socio-
economic, public health and institutional impacts which could result from
this process and the policy issues created or aggrevated by these impacts.
Alternative solutions to policy problems are outlined with probable
consequences of each.
Volume I contains Technical Analyses, including: evaluation of the poten-
tial for use of lignite, the likely siting patterns of lignite facilities,
and the environmental and socio-economic impacts of lignite use. Volume
II contains Policy Anslyses which identify major public policy issues
related to lignite use in Texas and discuss the alternative policies avail-
able for resolving the issues. Volume III contains technical working papers.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Environments
Energy Resources
DISTRIBUTION STATEMENT
DISTRIBUTE TO PUBLIC '
i
b. IDENTIFIERS/OPEN ENDED TERMS
icological Effects
lealth Effects
19. SECURITY CLASS (This Report)
Tn fl^ciQ'i "F *i &fl
20. SECURITY CLASS (This page)
Tnr*! ^ eic:i •F'i f»H
c. COSATI Field/Group
97A
21. NO. OF PAGES
47=1
22. PRICE
EPA Form 2220-1 (9-73)
:r U.S. GOVERNMENT PRINTING OFFICE: 1980- 311-726:3858
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