United States
Environmental Protection
Agency
Office of Environmental
Engineering and Technology
Washington DC 20460
EPA-600/7-81-008
January 1981
Research and Development
Ohio River Basin
Energy Study
(ORBES)
Main Report
Interagency
Energy/Environment
R&D Program
Report
-------
ERRATA
Ohio River Basin Energy Study (ORBES): Main Report
Pacje 10, line 7: For of of local read of local
Page 12, line 10: For figure ES-5 read figure ES-4
Page 13, line 2: For figure ES-6 read figure ES-4 . "
Page 14, line 5: For figure ES-5 read figure ES-6 • •*•
Page 14, line 7: For figure ES-6 read figure ES-5
Page 15, line 15: For 55 percent read 45 percent
Page 65, lines 28-32: For Approximately 68 percent of this amount is used to
generate electricity; in other words, it takes approximately 2 Btu's of
conventional fuels to produce 1 Btu of electricity. Thus, 24 percent of
the total regional consumption of conventional fuels actually generates
electricity, read In the ORBES region, approximately 3.2 Btu's of
conventional fuels are required tc produce 1 Btu of electricity.
Page 89, line 25: For The other 8 read The other 6
Paae 103, line 4: For between 0.03 and 0.05 read between 0.0035 and 0-0060
• " •' - - - " "
Page 103, line 5: For Roughly half read Over 90 percent
Page 103, lines 7-8: For 10 million megawatts were produced by nuclear-fueled
power plants read installed nuclear-fueled electrical generating capacity
totaled approximately 1800 megawatts electric
Page 103, lines 8-9: For between 150 and 250 cas°es of cancer are expected to
have occurred in 1976 because of nuclear power generation read between
0.0063 and 0.011 cases of cancer are expected to result from nuclear power
generation in 1976 in the ORBES region
Page 165, line 25: For $95 million read $95 billion
-------
EPA-600/7-81-008
January 1981
OHIO RIVER BASIN ENERGY STUDY (ORBES):
MAIN REPORT
by
The ORBES Core Team
Grant Nos. R804816, R805585, R805588, R805589,
R805590, R805603, R805608, R805609,
R806451 and
Cooperative Agreement No. CR807395
Project Officer
Lowell Smith
Program Integration and Policy Staff
Office of Environmental Engineering and Technology
Washington, D.C. 20460
OFFICE OF ENVIRONMENTAL ENGINEERING AND TECHNOLOGY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
-------
DISCLAIMER
This report has been reviewed by the Office of Research and Development,
U.S. Environmental Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the views and policies
of the U.S. Environmental Protection Agency, nor does mention of trade names
or commercial products constitute endorsement or recommendation for use.
ii
-------
FOREWORD
If the development of our nation's energy resources is to be
undertaken with proper consideration for the interests of all parties
affected, the consequences of this development for the economy,
environment, and society must be identified and understood. In its
role as coordinator of the Federal Interagency Energy/Environment
Research and Development Program, the U.S. Environmental Protection
Agency is responsible for programs that range from the analyses of
health and environmental effects of energy development to the
development of environmental control technologies. A component of this
interagency effort is the Strategy Research Program, (formerly known as
the Integrated Assessment Program).
The Strategy Research Program was initiated in order to provide
comprehensive evaluations of energy development alternatives and to
identify those that are environmentally acceptable. In carrying out
this responsibility, the program attempts to achieve several
objectives. First, the program ties together results of scientific and
engineering research programs and presents these results in a format
that is useful to decision makers in dealing with policy and regulatory
strategy issues. This includes feedback to the research programs
concerning information needed for policy analysis but not being
generated by these programs. In addition, Strategy Research combines
with technical research results the socioeconomic, institutional, and
policy analysis methods necessary to identify a full range of
energy/environmental policy options and to evaluate their probable
implications. Finally, the program attempts to identify and evaluate
second and higher order impacts of development, including synergistic
and cumulative effects of combinations of facilities or technologies.
The program produces results that inform the potential decision
makers and interested parties of the possible consequences of
alternative technologies and policies and the uncertainties inherent in
projecting these consequences. The program has utilized technology
assessment and other related policy analysis methods in carrying out
its research. Two major projects have applied these methods to energy
development in specific regions of concern. The first analyzed
potential energy/environmental concerns in eight western energy
resource states. The study of the Ohio River Basin is the second such
regional energy technology assessment.
In the early 1970s a group of environmentally concerned citizens
voiced concerns about plans for accelerated power plant development
along the Ohio River. They and other basin residents sought informa-
-------
tion on the effects that energy development could have on their
environment. These effects include not only the obvious physical ones
on air, land, and water quality, as well as those on public health, but
also less easily measurable economic and social effects. The
availability of this kind of information to policy makers and
interested citizens can support knowledgeable and reasonable decisions
about a region's energy and environmental future.
The Ohio River Basin Energy Study (ORBES) was mandated by the U.S.
Congress in response to the concerns expressed by citizens living
within the basin. In the spirit of its origin, ORBES carried out the
congressional directive both with the maximum degree of independence by
the university researchers chosen to conduct the study and with
strenuous efforts made to communicate with affected citizens throughout
the research phase of the program. A major objective of this
continuing communication effort was to ensure that the researchers
considered those issues of greatest importance to the interested
parties.
The first phase of the study (1976-1977) identified relevant energy
use and environmental management alternatives and articulated a range
of emerging policy issues. In the second phase (1977-1980), these
issues were refined, and in-depth analyses were conducted in a number
of areas.
Refinements in policy issues were made not only as a result of
interim research findings and the input of the public, but also because
of changing conditions nationally and within the six-state ORBES study
region over the last half decade. For example, since the study began,
the rate of growth in the regional demand for electricity has continued
the dramatic decline begun earlier in the decade. In response to this
decrease in demand many fewer power plants will be built over the next
decade than previously planned. While at the beginning of the study
new plants were governed by strict EPA emission standards, substan-
tially less stringent standards apply to existing plants. Even more
stringent emission requirements have been in force for those power
plant units on which construction was initiated after August 1978. As
a result, it is now thought that facilities currently in operation will
produce the greatest effects on regional air quality throughout the
remainder of this century.
The decline in the electricity demand growth rate occurred because
of a number of factors that were not well appreciated at the initiation
of ORBES. Among these factors were a substantial rise in electricity
prices and changing demographic and economic conditions. Other factors
concern the energy supply situation. For example, national efforts to
begin deregulation of natural gas, a fuel that competes with
electricity for many end uses, has dramatically increased the rate at
which new natural gas supplies are being discovered. This fuel may
become even more abundant in the Middle Wsst if a pipeline is
constructed to bring new Alaskan and Canadian supplies to U.S. markets.
IV
-------
Institutional awareness of and accountability for environmental
issues of a regional nature have evolved rapidly since the QRBES effort
began. Regional organizations such as the Ohio River Valley Water
Sanitation Conmission (ORSANCO) and the Ohio River Basin Commission
(ORBC) increasingly are studying regional and interregional approaches,
crossing many state lines, to the solution of environmental problems.
Moreover, the administrators of the three EPA regional offices with
jurisdiction over the ORBES states have established a task force to
coordinate their pollution control efforts. Not only have government
agencies on all levels become increasingly aware of regional problems,
but so also have many citizens and representatives of various interests
in the area begun to recognize and respond to the regional components
of unresolved environmental issues, as they already do to local
components of these issues.
Since its beginning in 1976, ORBES may have contributed
substantially to some of these rapid changes in the study region,
although claims of cause and effect seldom can be proven. "Hie
project's open research process was an experiment in communications,
carried out in various ways, including a newsletter reaching almost
5000 subscribers in the study region, a series of public forums
presenting research results, and written reports discussing specialized
topics and overall findings. The project Advisory Committee, drawn
from groups expected to be affected by regional energy development, was
an especially important part of this communications process. Among the
Committee members were electric utility company and coal-mining associ-
ation representatives, representatives from environmental, civic,
agricultural, transportation, and labor interests, designees of the
governors of the six ORBES states, ORSANCO and ORBC representatives,
the administrators of the three EPA regional offices, and the chief of
the Ohio River Basin division of the Army Corps of Engineers.
Included in the functions of the Advisory Committee was sustained
interaction with the researchers, including the opportunity to partici-
pate in internal project meetings and to review research reports in
draft form. Strong EPA input also has been maintained since ORBES
began, through the Advisory Committee mechanism, the project management
team, and an agency work group. However, in keeping with the Congres-
sional mandate that an independent research effort be conducted, this
main report and all other project reports are entirely the product of
the university researchers.
This main report summarizes the results of analyses of a range of
coal-based energy development scenarios for the study region. These
results include potential beneficial and adverse impacts on the envi-
ronment, society, the economy, and public health. Major areas of
concern include the problems associated with the long-range transport
of air pollutants and the institutional difficulties in dealing with
environmental problems that are regional in nature. The report also
-------
presents the results of analyses of a range of policy alternatives for
dealing with adverse impacts.
Ihe Ohio River Basin Energy Study would not have been possible
without the thoughtful and sustained participation of a number of
individuals, to each of whom I extend my personal appreciation.
Central to the effort was the work of the 13-member interdisciplinary
core team. Additional specialized inquiries were carried out by a
number of support researchers. As mentioned above, the Advisory
Committee played an important role throughout the project. Special
recognition should be given to the project managers, Jim Stukel and
Boyd Keenan, as ably assisted by Stephanie Kaylin. The insights and
mature judgment that each contributed to the study left their defini-
tive marks. Without their dedicated and unfailing efforts in
coordinating this complex project, including the preparation of this
main report, ORBES could not have been carried through to its
successful conclusion.
Lowell Smith, Director
Program Integration and Policy Staff
Office of Research and Development
-------
PREFACE
Release of this publication concludes the Ohio River Basin Energy Study
(ORBES), a research activity undertaken by over 100 university faculty members
at eight institutions in the Middle West and the area popularly known as the
Ohio River valley. Grants from the U.S. Environmental Protection Agency (EPA)
totaling $4.3 million funded the project.
Entitled the Ohio River Basin Energy Study (ORBES) Main Report, this
document is one of a number issued since the study began in the fall of 1976.
The main report is the principal element of the ORBES publication series; it
represents the collective end product of a 13-member interdisciplinary faculty
group known as the ORBES core team. Its members, the authors of this report,
are James J. Stukel, professor of environmental engineering and mechanical
engineering and director, Office of Energy Research, University of Illinois at
Urbana-Champaign, and Boyd R. Keenan, professor of political science,
University of Illinois at Chicago Circle, both of whom also served as co-
directors of the project; and (alphabetically) Robert E. Bailey, professor of
nuclear engineering and director, Program on Energy Research, Education, and
Public Service, The Ohio State University; Donald A. Blome, research
scientist, Institute for Mining and Mineral Research, Energy Research
Laboratory, University of Kentucky; Vincent P. Cardi, professor of law, West
Virginia University; Gary L. Fowler, associate professor of geography and
associate director, Energy Resources Center, University of Illinois at Chicago
Circle; Steven I. Gordon, assistant professor of city and regional planning,
The Ohio State University; James P. Hartnett, professor of energy engineering
and director, Energy Resources Center, University of Illinois at Chicago
Circle; Walter P. Page, associate professor of economics, West Virginia
University; Harry R. Potter, associate professor of sociology, Purdue
University; J.C. Randolph, associate professor of ecology and director of
environmental programs, School of Public and Environmental Affairs, Indiana
University; Maurice A. Shapiro, professor of environmental health engineering,
University of Pittsburgh; and Hugh T. Spencer, associate professor of
environmental engineering, University of Louisville. A roster of the core
team and rosters of other project participants appear in Appendix A.
On points of general policy relating to substantive research questions,
the core team generally resolved conflicts by majority vote. The core team's
work grew out of ORBES Phase I, which extended from the fall of 1976 through
November 1977, when QRBES Phase I_: Interim Findings was published. This
vii
-------
latter publication, written by professors Stukel and Keenan, synthesized
findings of the three preliminary research teams that operated independently
during Phase I. As mandated by a congressional committee, the Phase I study
region consisted of portions of Illinois, Indiana, Kentucky, and Ohio, and
researchers were from universities in these states. However, EPA officials as
well as members of Congress and their staffs agreed that in the second phase
the ORBES study region should be expanded to include virtually all of West
Virginia and the southwestern portion of Pennsylvania.
Core team authors generated far more specialized material for this
interdisciplinary report than could be included here. Thus, they were given
the opportunity to place their findings in individual core team research
reports, which are referred to in this report. Additional specialized work
was carried out by support research subprojects, which also are referred to in
this report. These studies were commissioned by the core team. Whenever
possible, support researchers were selected from the eight institutions with
which the core team members themselves were associated. Such selection
allowed close coordination of core team and support research efforts. In
several instances, however, the necessary expertise was available only at
other universities or independent research organizations.
While the main report is written primarily for the lay reader, certain of
the core team and support research studies are more technical and are intended
primarily for specialists. Core team review committees examined these reports
for acceptability for inclusion in the ORBES series. However, their review
does not represent verification of the contents.
Along with various other groups noted below, core team members were
invited to comment on the final edited version of this main report. Their
statements, each limited to 10 pages, comprise a separate volume. Some core
team members used the opportunity to comment upon majority decisions with
which they were not in total agreement.
For ORBES Phase I, EPA's Office of Research and Development, which
administered the grants to ORBES participants, provided the researchers with a
work plan. The core team prepared the Phase II work plan. As part of the
EPA-administered Interagency Energy-Environment Research and Development
Program, ORBES followed the general format of a technology assessment. A
usual practice in such assessments is to develop sets of plausible,
hypothetical conditions, or scenarios, in which such problems as energy
development are examined.
ORBES may be unique in terms of its management framework and its openness
to the public. The work of the interdisciplinary, interuniversity core team
was coordinated by a management team and by a project office maintained on the
University of Illinois campuses at Urbana-Champaign and at Chicago Circle. At
Vlll
-------
least once a month, and sometimes more frequently, the full core team held
two- and three-day working sessions that were open to the public on the
various campuses and in other locations around the study region. These
meetings began in the fall of 1977 and continued for two years. Moreover,
during both Phase I and Phase II, open meetings on research results were held
throughout the study region.
Early in Phase I, an advisory committee was appointed, consisting of
representatives from government, business, labor, agriculture, the public, and
other sectors. Committee membership was expanded throughout Phase II and
reached a total of 43- Advisory committee members had an ongoing invitation
to provide written or oral comments on core team research results. They
reviewed a preliminary draft of the main report and provided considerable
input throughout the study.
As with core team members themselves, each of the advisory committee
members was invited to supply comments on the final version of the main report
and to contribute these comments to a separate volume entitled Comments on the
Ohio River Basin Energy Study. Support researchers and members of the ORBES
management team also contributed to this volume.
The core team is indebted to hundreds of citizens and public officials
and regrets that space limitations prevent acknowledging all of those people
here. Special appreciation must be expressed to a small number of advisory
committee members who attended virtually every core team meeting. The role of
the media also has been important in alerting the general public to the ORBES
project. Because of the complexity of the scenario approach, the media are
urged to exercise care in extracting portions of the main report. That is,
the results reported must be read in the context of the methodologies used to
arrive at them.
The cooperation of Lowell Smith, the EPA project officer for ORBES, is
gratefully acknowledged. His helpful counsel was consistent with the
conditions of the individual grants that assured faculty members1
independence. Neither he nor any other EPA personnel made any attempt to
exert untoward influence in the preparation of this report; they did, however,
make frequent efforts to sensitize the project co-directors and the core team
members to the realities of government. The core team also wishes to
acknowledge the assistance of the other members of the management team: James
H. Phillips, of EPA Region V offices in Chicago, Illinois; Victor F. Jelen, of
the EPA Industrial Environmental Research Laboratory, Cincinnati, Ohio; and
David Hopkins, of EPA Region IV, Atlanta, Georgia.
The highest quality research support and staff coordination was provided
by Stephanie L. Kaylin, ORBES staff associate, in the preparation of this
report. Like the ORBES co-directors, she was a key member of the project from
start to finish.
ix
-------
The usual authors' acceptance of total responsibility for errors in
judgment, omissions, and misinterpretations is difficult to articulate in this
instance. It has been necessary for all core team members, as co-authors, to
accept on faith much specialized data from their colleagues. In instances
where this faith has resulted in misinterpretations or inaccuracies deemed to
be of a serious nature, project researchers have addressed the matters in
their individual comments.
These procedures, as well as such unorthodox practices as inviting
members of the public to participate in working research sessions, presented
unusual problems for the university researphers. But we trust that certain
frontiers of knowledge and public awareness have been advanced by the
experiment.
-------
CONTENTS
FOREWORD iii
PREFACE vii
EXECUTIVE SUMMARY FIGURES xvi
EXECUTIVE SUMMARY TABLES xvii
MAIN REPORT FIGURES xvii
MAIN REPORT TABLES xx
EXECUTIVE SUMMARY
1. The ORBES Project 3
2. General Regional Characteristics 3
3. Regional Air, Water, and Land Status in Mid-1970s 5
4. The Issue Areas of Concern in the ORBES Project 8
5. Coal-Dominated Scenarios 8
6. Comparison of Coal-Dominated Scenarios 11
6.1 Emissions, Concentrations, and
Air-Quality-Related Impacts 11
6.2 Economic Impacts Related to Air Quality Impacts 22
6.3 Other Impacts Related to Expanded Capacity 26
7. Mitigation Strategies 30
8. Fuel Substitution and Conservation Scenarios 33
9. Comparison of Fuel Substitution and Conservation Scenarios 33
xi
-------
9.1 Emissions, Concentrations, and
Air-Quality-Related Impacts ....................................... 33
9 . 2 Economic Impacts Related to Air Quality Impacts ................... 36
9 . 3 Other Impacts Related to Expanded Capacity ........................ 36
10. Institutional Considerations: Nuclear Energy,
Alternative Fuels, and Conservation .................................... 39
11 . Concluding Note
MAIN REPORT
INTRODUCTION 45
1. ORBES Background and Organization 45
2. Policy Issues 49
2.1 Air-Related Policy Issues 49
2.2 Land-Related Policy Issues 51
2.3 Water-Related Policy Issues 52
2.4 Social Policy Issues 53
2.5 Other Policy Issues 54
2.6 Underlying Methodological Issues 55
3. Assessment Approach and Report Organization 57
3.1 Assessment Approach 57
3.2 Report Organization 60
4. Base Period Conditions in the ORBES Region 63
4.1 Energy and Fuel Use 63
4.2 Economy 67
4.3 Air 69
4.4 Land 80
xii
-------
4.5 Water 85
4.6 Health 96
'4.7 Social Conditions 104
4.8 Social Values 107
COAL-DOMINATED FUTURES 113
5. Descriptions of the Coal-Dominated Scenarios 115
6. Comparison of Impacts among Coal-Dominated Scenarios 125
6.1 Emissions, Concentrations, and
Air-Quality-Related Impacts 125
6.2 Economic Impacts Related to Air Quality Impacts 142
6.3 Other Impacts of Expanded Capacity 147
7. Impacts of the Base Case 154
7.1 Air 154
7.2 Land 161
7.3 Water 166
7.3-1 Water Variation 169
7.4 Employment 170
7.5 Health 171
8. Impacts of the Strict Environmental Control Case 175
8.1 Air 175
8.2 Land 179
8.2.1 Land Variations 180
8.3 Water 182
8.4 Employment 185
8.5 Health 186
9. Impacts of the SIP Noncompliance Case 188
9.1 Air 188
xiii
-------
9.2 Land 191
9.3 Health 194
10. Impacts of the High Electrical Energy Growth Case 195
10.1 Air 195
10.1.1 Air-Related Variations 199
10.2 Land 208
10.3 Water ' 210
10.4 Employment 213
10.5 Health 213
11. Impacts of the Electrical Exports Case 215
11.1 Air 215
11.2 Land ' 216
11.3 Water 217
11.4 Employment 219
11.5 Health , 220
12. Mitigation Strategies 221
12.1 Coal Impact Mitigation 222
12.1.1 Technical Strategies 222
12.1.2 Techno-Organizational Strategies 223
12.1.2.1 Local Transboundary Air Pollution 223
12.1.2.2 Long-Range Transboundary Air Pollution 226
12.2 Possible Influences 236
12.3 Underlying Questions 239
FUEL SUBSTITUTION AND CONSERVATION EFFECTS 241
13. Descriptions of the Fuel Substitution and Conservation Scenarios 243
14. Comparison of Impacts of the Fuel Substitution and
xiv
-------
Conservation Scenarios * 254
14.1 Emissions, Concentrations, and Air-Quality-Related Impacts 254
14.2 Economic Impacts Related to Air Quality Impacts 259
14.3 Other Impacts Related to Expanded Capacity 259
14.4 Overview . **...« I 269
15. Institutional Considerations: Nuclear Energy,
Alternative Fuels, and Conservati6n 271
15.1 Nuclear Energy * * 271
15.2 Alternative Fuels 1. ,. * 277
15.2.1 Solar Energy *..»*.* * 277
15.2.2 Wind Energy Conversion Systems 283
15.2.3 Biomass ; * 287
15.3 Conservation : i.»* 293
CONCLUDING NOTE ». i;, 295
APPENDICES
A. ORBES Phase II Participants 299
B. ORBES Publications k 305
C. Alternative Scenario Designations.... * 311
-------
EXECUTIVE SUMMARY FIGURES
ES-1 ORBES-Region Coalfields 4
ES-2 Ohio River Basin Energy Study (ORBES) Region 4
ES-3 Sectoral Contributions to ORBES Gross Regional Product 4
ES-4 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Coal-Dominated Scenarios 11
ES-5 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
High Electrical Energy Growth Case 12
ES-6 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Base Case and SIP Noncompliance Case 13
ES-7 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Dispatching Variations under High Electrical Energy Growth 16
ES-8 Electric Utility Particulate Emissions in the ORBES Region,
Coal-Dominated Scenarios 17
ES-9 Electric Utility Nitrogen Oxide Emissions in the ORBES Region,
Coal-Dominated Scenarios 17
ES-10 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (1976 and Base Case in 2000) 20
ES-11 Annual Average Sulfate Concentrations,
Electric Utility Contribution (1976 and Base Case in 2000) 20
ES-12 Cumulative Capital Costs, Coal-Dominated Scenarios, 1976-2000 24
ES-13 Electricity Prices, Coal-Dominated Scenarios 25
ES-14 Construction Workers, Coal-Dominated Scenarios, 1975-95 28
ES-15 Cumulative Capital Costs, Base Case, Fuel Substitution Scenarios,
and Conservation Emphasis Scenario, 1976-2000 37
ES-16 Construction Workers, Base Case, Fuel Substitution Scenarios,
and Conservation Emphasis Scenario, 1975-95 38
xvi
-------
EXECUTIVE SUMMARY TABLES
ES-1 Growth Rates and Installed Capacity, ORBES Region, Annual Averages
(197^-2000), by Scenario 10
ES-2 Sulfur Dioxide and Sulfate Annual Average Concentrations,
ORBES Region, Percent Change from 1976,
Highest Concentration Region 19
ES-3 Sulfur Dioxide and Sulfate Episodic Concentrations,
ORBES Region, Percent Change from August 27, 1974, Episode,
Highest Concentration Region 21
ES-4 Sulfur Dioxide, Particulate, and Nitrogen Oxide Emissions,
Fuel Substitution and Conservation Scenarios, Year 2000 34
MAIN REPORT FIGURES
1-1 Ohio River Basin Energy Study (ORBES) Region 48
1-2 ORBES-Region Coalfields 48
3-1 Electrical Generating Capacity, ORBES Region, 1976 59
4-1 Conventional Fuel Consumption, ORBES Region 66
4-2 Installed Electrical Generating Capacity, ORBES Region,
by Fuel Type 66
4-3 Sectoral Contributions to ORBES Gross Regional Product 68
4-4 AQCRs with High Sulfur Dioxide Emission Densities,
Eastern United States 71
4-5 Average Yearly Visibility 75
4-6 Calculated Air Mass Trajectories at 600 Meters above the Ground,
Eastern United States, August 25, 1974 77
4-7 Sulfur Dioxide Concentrations, August 27, 1974 79
4-8 Sulfate Concentrations, August 27, 1974 79
xvii
-------
4-9 Annual Average Sulfur Dioxide Concentrations 79
4-10 Annual Average Sulfate Concentrations 79
4-11 Percentage Agricultural and Forest Land, by ORBES State Portion 81
4-12 ORBES-Region Rivers Selected for Detailed Analysis 92
4-13 ORBES-Region Population Distribution, by State Portion 105
5-1 Major Variables and Comparisons, Base Case and
Other Coal-Dominated Scenarios 116
5-2 Announced Coal-Fired Electrical Generating Capacity Additions,
ORBES Region, 1976-85 120
5-3 Announced Nuclear-Fueled Electrical Generating Capacity Additions,
ORBES Region, 1976-85 121
5-4 Coal-Fired Electrical Generating Capacity,
ORBES Region, Base Case, Year 2000 123
6-1 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Coal-Dominated Scenarios 126
6-2 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Base Case and SIP Noncompliance Case 128
6-3 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
High Electrical Energy Growth Case 129
6-4 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Dispatching Variations under High Electrical Energy Growth 131
6-5 Electric Utility Particulate Emissions in the ORBES Region,
Coal-Dominated Scenarios 133
6-6 Electric Utility Nitrogen Oxide Emissions in the ORBES Region,
Coal-Dominated Scenarios 134
6-7 Cumulative Capital Costs, Coal-Dominated Scenarios, 1976-2000 143
6-8 Electricity Prices in the ORBES Region,
Coal-Dominated Scenarios 146
6-9 Construction Workers, Coal-Dominated Scenarios, 1975-95 150
7-1a Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Base Base, by Unit Type 155
7-1b Price of Electricity in the ORBES Region, Base Case 155
xvi 11
-------
7-2 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (1976 and Base Case in 2000) 159
7-3 Annual Average Sulfate Concentrations,
Electric Utility Contribution (1976 and Base Case in 2000) 159
7-4 Terrestrial Ecosystem Units, Base Case, by OHBES State Portion 166
8-1 Base Case versus Strict Environmental Control Case 177
8-2 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (Base Case and
Strict Control Case in 2000) 178
8-3 Annual Average Sulfate Concentrations,
Electric Utility Contribution (Base Case and
Strict Control Case in 2000) 178
9-1 Base Case versus SIP Noncompliance Case 190
9-2 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (Base Case and
SIP Noncompliance Case in 2000) 192
§-3 Annual Average Sulfate Concentrations,
Electric Utility Contribution (Base Case and
SIP Noncompliance Case in 2000) 192
10-1 Base Case versus High Electrical Energy Growth Case
(45-Year Plant Life) 197
10-2 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (Base Case and
High Growth Case (45-Year) in 2000) 198
10-3 Annual Average Sulfate Concentrations,
Electric Utility Contribution (Base Case and
High Growth Case (45-Year) in 2000) 198
10-4 Base Case versus High Electrical Energy Growth Case
(35-year Plant Life) 200
10-5 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (Base Case and
High Growth Case (35-Year) in 2000) 202
10-6 Annual Average Sulfate Concentrations,
Electric Utility Contribution (Base Case and
High Growth Case (35-Year) in 2000) 202
10-7 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
High Electrical Energy Growth Case 204
xix
-------
10-8 Least Emissions Dispatching Case versus
Least Cost Dispatching Case (High Electrical Energy Growth) 206
10-9 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (Least Cost and
Least Emissions Dispatching in 2000) 207
10-10 Annual Average Sulfate Concentrations,
Electric Utility Contribution (Least Cost and
Least Emissions Dispatching in 2000) 207
13-1 Major Variables and Comparisons, Base Case,
Fuel Substitution Scenarios, and Conservation Scenario 244
13-2 Coal-Fired Electrical Generating Capacity, ORBES Region,
Conservation Emphasis Scenario, Year 2000 247
14-1 Annual Average Sulfur Dioxide Concentrations,
Electric Utility Contribution (Base Case and
Natural Gas Substitution Case in 2000) 257
14-2 Annual Average Sulfate Concentrations,
Electric Utility Contribution (Base Case and
Natural Gas Substitution Case in 2000) 257
14-3 Cumulative Capital Costs, Base Case, Fuel Substitution Scenarios,
and Conservation Emphasis Scenario, 1976-2000 260
14-4 Construction Workers, Base Case, Fuel Substitution Scenarios,
and Conservation Emphasis Scenario, 1975-95 265
MAIN REPORT TABLES
4-1 ORBES Reference Concentrations and Water Quality Standards and
Criteria in Effect in the ORBES Region 90
4-2 Rivers Studied in Detail: Protection Levels, Number of Reaches,
Pollutants Violating ORBES Reference Concentrations at
7-Day-10-Year Low Flow, and Flow per Second at
7-Day-10-Year Low Flow 93
4-3 Aquatic Habitat Impacts on Rivers Studied in Detail,
7-Day-10-Year Low Flow 94
5-1 Growth Rates and Installed Capacity, ORBES Region,
Coal-Dominated Scenarios, Annual Averages (1976-2000),
by Scenario 119
xx
-------
5-2 Coal-Fired Capacity Additions, ORBES Region,
Coal-Dominated Scenarios, 1986-2000 ................................ 123
6-1 Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Coal -Dominated Scenarios ........................................... 126
6-2 Electric Utility Particulate Emissions in the ORBES Region,
Coal-Dominated Scenarios ........................................... 1 33
6-3 Electric Utility Nitrogen Oxide Emissions in the ORBES Region,
Coal -Dominated Scenarios
6-4 Sulfur Dioxide and Sulfate Annual Average Concentrations,
ORBES Region, Percent Change from 1976,
Highest Concentration Region ....................................... 136
6-5 Sulfur Dioxide and Sulfate Episodic Concentrations,
ORBES Region, Percent Change from August 27, 1974, Episode,
Highest Concentration Region ....................................... 1 37
6-6 Minimum, Probable, and Maximum Crop Losses Due to
Regional Sulfur Dioxide and Nitrogen Oxide Emissions,
ORBES Region ........................... . ........................... 1 39
6-7 Electricity Prices and Cumulative Revenues, ORBES Region,
Coal-Dominated Scenarios, 1976-2000 ................................ 145
6-8 Land Conversion for New Electrical Generating Facilities,
Coal-Dominated Scenarios, 1976-2000 ................................ 148
6-9 Terrestrial Ecosystem Assessment Units, Coal-Dominated Scenarios,
1976-2000 [[[ 148
7-1 Land Use Conversion for Electrical Generating Facilities,
Base Case , 1 976-2000 ............................................... 1 63
7-2 Aquatic Habitat Impacts, 7-Day- 1 0-Year Low Flow, Year 2000,
versus Impacts in 1 976, 7-Day- 1 0-Year Low Flow ..................... 1 68
7-3 Health Impacts Related to Coal Mining, Processing, and
Transportation, Base Case, 1985 and 2000 ........................... 173
8-1 Land Converted for Electrical Generating Facilities ................ 181
8-2 Agricultural and Forest Land Converted for
Electrical Generating Facilities ................................... 182
8-3 Terrestrial Ecosystem Assessment Unit Impacts ...................... 1 83
8-4 Aquatic Habitat Impacts, Base Case, versus
Strict Environmental Control Case,
-------
10-1 Aquatic Habitat Impacts, Base Case, versus
High Electrical Energy Growth Case,
7-Day-10-Year Low Flow, Year 2000 212
11-1 Aquatic Habitat Impacts, Base Case, versus
Electrical Exports Case,
7-Day-10-Year Low Flow, Year 2000 218
13-1 Growth Rates and Installed Capacity, Base Case,
Fuel Substitution Scenarios, and
Conservation Emphasis Scenario (1974-2000), Annual Averages 245
13-2 Coal-Fired and Nuclear-Fueled Capacity Additions, ORBES Region:
Base Case, Fuel Substitution Scenarios, and
Conservation Emphasis Scenario, 1986-2000 249
14-1 Sulfur Dioxide, Particulate, and Nitrogen Oxide Emissions,
ORBES Region, Fuel Substitution and
Conservation Emphasis Scenarios, Year 2000 255
14-2 Land Converted for Electrical Generating Facilities,
ORBES Region, Fuel Substitution Scenarios and
Conservation Emphasis Scenario, 1976-2000 262
14-3 Terrestrial Ecosystem Assessment Units, Base Case,
Fuel Substitution Cases, and Conservation Emphasis Case,
1976-2000 264
14-4 Aquatic Habitat Impacts, Fuel Substitution and
Conservation Emphasis Scenarios, 7-Day-10-Year Low Flow,
Compared with Base Case Impacts,
7-Day-10-Year Low Flow, Year 2000 267
14-5 Health Impacts Related to Coal Mining, Processing, and
Transportation, Base Case, Fuel Substitution Scenarios, and
Conservation Emphasis Scenario, Year 2000 269
xxn
-------
Executive Summary
-------
1. THE ORBES PROJECT
The Ohio River Basin Energy Study (ORBES) began in the fall of 1976 in
order to assess the potential environmental, social, and economic impacts of a
proposed concentration of power plants in a portion of the basin. The U.S.
Senate Appropriations Committee had mandated the U.S. Environmental Protection
Agency (EPA) to carry out this study just after the Arab oil embargo (1973-74)
in response to 6itizen concern. At that time several utility companies had
announced plans to construct additional generating units in the Ohio River
Basin.
The Ohio River region offered the electric utilities (and related
industries) some of the nation's most suitable power plant sites, particularly
since coalfields containing almost half of the nation's reserves by tonnage
are within easy reach (see figure ES-1). Some citizens, however, questioned
the necessity of adding such a large number of generating facilities,
particularly near the Ohio River* itself. They also pointed out that the
proposed new plants would transmit much of their electricity far from the
immediate area.
In an effort to identify the implications of locating future energy
conversion facilities in this particular part of the Ohio River Basin, the
Senate Appropriations Committee directed EPA to conduct a study "comprehensive
in scope, investigating the impacts from air, water, and solid residues on the
natural environment and [on the] residents of the region. The study should
also take into account the availability of coal and other energy sources in
the region."
2. GENERAL REGIONAL CHARACTERISTICS
The ORBES region covers 190,377 square miles in 423 counties in the
states of Illinois, Indiana, Kentucky, Ohio, Pennsylvania, and West Virginia
(see figure ES-2). The predominant land use in the region is agriculture,
which accounts for 54 percent of regional acreage. The types of farming range
from vast corn and soybean tracts in Illinois to smaller tobacco farms in
Kentucky. Mixed mesophytic, northern hardwood, beech-maple, oak-hickory, and
other forests cover another third of the region.
The regional river systems and aquatic life are as diverse as can be
found in the United States. These regional water systems range from
Whitewater canoe and mountain trout streams to deep, clear lakes popular as
recreational spots, major rivers both navigable and free flowing, and numerous
wetlands and sloughs. These water systems support more than 250 fish species,
with several of the navigable rivers containing at least 90 species and some
large lakes containing over 125.
-------
Figure ES-1
ORBES-Region Coalfields
Interior
Coal Province
Appalachian
Coal Province
Figure ES-2
Ohio River Basin Energy Study (ORBES) Region
-------
The ORBES region contains about 11 percent of the national population and
accounts for about 10 percent of the gross national product. The major
economic sector in the region is manufacturing, which accounts for about 31
percent of the gross regional product, followed by trade (16 percent),
government (12 percent), and finance, insurance, and real estate (11 percent).
The remaining 5 sectors each accounts for less than 11 percent of the gross
regional product (see figure ES-3); the coal-mining and agricultural sectors
constitute 3 percent and 4 percent, respectively.
Coal is the most significant indigenous fuel in the ORBES region and
accounts for two-thirds of national production. Coal also is the primary fuel
used in the region. Coal use accounts for about half of the total regional
fuel consumption, and the electric power industry in the region consumes about
two-thirds of this coal. About 95 percent of regional electrical generating
capacity is coal fired. Nonfossil fuels, in general, account for less than 1
percent of the total conventional fuel use in the region—approximately the
same percentage as in the nation.
Figure ES-3 Sectoral Contributions to
ORBES Gross Regional Product
manufacturing 30.7%
trade 16.2%
government 11.5%
finance, insurance, real estate 11.2%
services and other 10.1%
transportation, communication,
utilities 9.2% ES3farm 4%
construction — 4.1%
mining—3%
3. REGIONAL AIR, WATER, AND LAND STATUS IN MID-1970S
AIR. Perhaps because of the high coal use, air quality standards for sulfur
dioxide and particulates were not being met at several locations in the ORBES
region during the study's base period (the mid-1970s). Several other
locations were close to violation. For example, in 1977, 11 ORBES-region
counties violated national ambient air quality standards (NAAQS) for sulfur
dioxide, and an additional 13 counties did not have available the full
prevention of significant deterioration (PSD) increment for sulfur dioxide to
accommodate new sources; the ambient concentrations in these counties were at
or just below the NAAQS. In the same year, 130 counties in the region
-------
violated the NAAQS for total suspended particulates (TSP), and an additional 5
counties had less than the full PSD increment available. Many of the counties
that violated the TSP and sulfur dioxide NAAQS were clustered in extreme
southwestern Ohio and along the Ohio-Pennsylvania-West Virginia border.
However, since over 50 percent of the counties in the ORBES region are without
monitoring for sulfur dioxide or TSP, the number of 1977 violations probably
is underestimated.
In all probability, ORBES-region generating units contribute
substantially to sulfur dioxide concentrations since they produce about 80
percent of regional sulfur dioxide emissions. In fact, in 1975, regional
utility sulfur dioxide emissions constituted 52 percent of national utility
sulfur dioxide emissions and 32 percent of national sulfur dioxide emissions
from all sources. In contrast, during that same period, about 36 percent of
the national coal-fired electrical generating capacity was located in the
ORBES region.
ORBES-region utilities contributed smaller but significant shares of the
1975 regional nitrogen oxide and particulate emissions—about 47 percent of
regional nitrogen oxide emissions from all sources and about 22 percent of
regional particulate emissions from all sources.
However, regional data indicate that long-range transport of emissions,
even over distances of several hundred kilometers, was and is an important
factor in regional pollutant concentrations. At several locations throughout
the region, between 30 and 50 percent of the 25 highest daily sulfur dioxide
concentrations are associated with transport by extremely persistent winds.
Moreover, under certain meteorological conditions, sulfur dioxide is
transformed into sulfates, thereby contributing to regional sulfate
concentrations. In addition, since sulfates are, by definition, the total
water-soluble component in TSP, such transformation of sulfur dioxide into
sulfates ultimately affects the TSP concentrations. Data from the base period
confirm the importance of both sulfates and their transport in TSP
concentration levels.
It is important to understand the relationship among the transport of
sulfur dioxide, its transformation, and regional sulfate episodes. Sulfur
dioxide concentrations of 130 micrograms per cubic meter (one-tenth of the
secondary three-hour standard) in the presence of current ozone levels have
been linked to vegetation damage and crop loss. Also, a growing body of
evidence supports the hypothesis that the annual average exposure to
sulfates—or something closely related to them—results in an increased
mortality rate. In addition, sulfate episodes are correlated with acidic
precipitation episodes; acidic precipitation is believed to be due primarily
to the presence of sulfate and nitrate ions. Finally, sulfate episodes often
are associated with the occurrence of reduced visibility over large areas.
-------
An examination through mathematical modeling of four representative
regional sulfate episodes between 1974 and 1976 reveals similarities among the
episodes. In general, sulfur dioxide emissions in the lower ORBES region
contributed significantly (between 50 and 90 percent) to the sulfate
concentrations in the upper region. Moreover, of the sulfate concentrations
in the upper region attributable to emissions in the lower region, utility
sulfur dioxide emissions in the lower region contributed at least half; in at
least two of the four episodes, these emissions contributed over 90 percent.
(The lower ORBES region consists of the ORBES state portions of Illinois,
Indiana, Kentucky, and western Ohio; the upper region, of the ORBES portions
of eastern Ohio, Pennsylvania, and West Virginia.) Similar results are found
when the annual sulfur dioxide and sulfate concentrations are examined.
Thus, both data and modeling confirm that long-range transport from the
lower region contributes significantly to the concentration averages in the
upper region and to violations of NAAQS in that region.
Finally, when the relationship between ORBES-region sulfur dioxide
emissions and Canadian concentrations is examined, utility sulfur dioxide
emissions from the ORBES region are shown to contribute about 50 percent of
the sulfur dioxide and sulfate concentrations estimated to occur in
southeastern Canada.
WATER. An analysis of the regional water quality in 1976 indicates the
presence of high pollutant concentrations. These pollutants can be further
concentrated by the diminished flow that occurs under 7-day-10-year low flow.
In general, the minimum of the water quality standards in the ORBES states was
used as a guide (since these standards vary from state to state and even from
river to river). Approximately 19 of the region's 24 largest streams would
have violated at least 3 of the 20 pollutant standards at some time in 1976
under 7-day-10-year low flow conditions. Moreover, if such conditions had
occurred, aquatic habitat impacts could have been heavy on 14 of these 24
streams. (Heavy impacts are defined as entailing eutrophication, a
concentration of heavy metals, possible stream dessication, local fish kills,
and a recovery period of possibly five to seven years.)
LAND. If all energy-related land uses are considered, such land use through
1976 had affected 1.86 million acres in the ORBES region, or 1.5 percent of
the regional land area. Land use for past and present surface mining of coal
represents 86.9 percent of this figure (1.6 million acres); electrical
generating facilities, 7-6 percent (140,700 acres); and transmission line
rights-of-way, 5.5 percent (103,000 acres). In general, the reclamation of
surface-mined land for permanent land use tends to be a slow process. Data
are available only for a quarter of the region's 1.6 million affected acres.
7
-------
These data show that this portion has been affected for 10 years and has not
yet been fully reclaimed.
4. THE ISSUE AREAS OF CONCERN IN THE ORBES PROJECT
The ORBES study investigated possible impacts of an expanded generating
capacity in the context of a number of issues. In the area of air quality,
the study focused on the regional effects of changes in pollutant
concentrations as a .result of different levels of electrical generation,
different control technologies, emission limitations, generating unit
retirement schedules, and other factors. Examined in the context of the air
quality analysis were the cost of electricity to the consumer, capital costs
for pollution control devices, losses in agricultural output as the result of
air pollution, and health impacts related to sulfates. In terms of land
impacts, the study focused on land displacement for energy-related uses and
the amount of land affected by surface mining. Another area investigated was
water quality and quantity, including water consumption by electrical
generating units, the effects of this consumption on pollutant concentrations
(which increase as the water quantity decreases), and the effects of pollutant
concentrations on aquatic habitats. The social areas chosen for analysis
included labor demand for coal mining, labor demand for power plant
construction and operation, and occupational death, disease, and disability
from coal mining, processing, and transportation.
These topics were examined through a technology assessment approach. A
variety of scenarios, all regionally based, were decided on and examined.
Each scenario is thus an "as if" statement that does not predict what might
happen. Rather, a scenario represents what one future might be like if.
assumed conditions are present in the ORBES region. Nine scenarios are
compared in this report. First, those scenarios that assume an emphasis on
coal as a fuel are compared. Next, those scenarios that assume a substitution
of other fuels for coal or that emphasize conservation are compared with each
other and with the coal-dominated scenario designated as the base case. The
assumed economic and energy growth rates, as well as the assumed regional
electrical generating capacity under each scenario in the year 2000, appear in
table ES-1.
5. COAL-DOMINATED SCENARIOS
The five scenarios chosen for the most detailed analysis assume that coal
will continue to be the dominant fuel used for regional electrical generation
through the year 2000. The primary scenario of these five is the base case,
the scenario to which all others are compared. Variations in base case
environmental controls characterize two of th"e« remaining four scenarios—the
strict environmental control case and the noncompliance case. Variations in
base case electricity demand growth account for the remaining two scenarios,
8
-------
the high electrical energy growth case and the electricity exports case. The
latter case is so named because it also assumes that additional installed
capacity in the ORBES region will transmit electricity to the northeastern
United States to replace oil-fired capacity in that part of the country.
For the three scenarios that assume the same environmental standards—the
base case, the high electrical energy growth case, and the electricity exports
case—air and land standards are defined in terms of what currently exists as
applied to present and future sources of pollution; in other words, these
three scenarios reflect the full implementation of current air and land
environmental policies. For water, the standards consist of current practices
for the design and construction of industrial and municipal facilities. Power
plant effluents, however, were assumed to be uncontrolled. The strict
environmental control case, oh the other hand, calls for more stringent
environmental regulations. In the case of air, strict controls mean that the
generally stringent pollutant emission standards for urban areas—which are
set by current (as of September 1978) state implementation plans (SIPs)—would
be applied throughout a state. For water, power plant effluent levels were
assumed to be about 5 percent of base case levels. Strict environmental
controls on land reclamation call for interim and permanent performance
standards under the Surface Mining Control and Reclamation Act of 1977, but
with strengthening of site-specific applications. Special interim and
permanent standards are applied to steep-slope mining, mountaintop removal,
the mining of prime farmland, and the surface effects of underground mining.
Under the noncompliance case, it is assumed that emission limits in state
implementation plans will not be met, but that the water and land
environmental policies will be the same as under the base case.
Three of the five coal-dominated scenarios assume the same electricity
demand growth rate: the base case, the strict environmental control case, and
the noncompliance case assume an average annual rate of 3.13 percent through
the year 2000. The electricity exports case, however, assumes an electricity
demand growth rate of 3.2 percent, and the high electrical energy growth case
assumes a rate of 3-9 percent. The high rate of electricity demand growth
under the latter scenario is that suggested in recent estimates made by the
National Electric Reliability Council (NERC).
The coal-dominated scenarios are further defined by a variety of energy
and fuel use characteristics; growth rates for various sectors under each
scenario appear in table ES-1. Also given in table ES-1 is the regional
installed capacity that is projected to occur by 2000 under each scenario
because of the electricity demand growth rates.
The same population, fertility, and economic growth rates were assumed
for all five coal-dominated scenarios. Similarly, all scenarios assume that
the coal to supply regional generating units will come from Bureau of Mines
-------
Table ES-1
Growth Rates and Installed Capacity, ORBES Region,
Annual Averages (1974-2000), by Scenario
Scenario
Base Case
Strict
Environmental
Controls
Noncompliance
with State
Implementation
Plans
High Electrical
Energy Growth
Exports of
Electricity
Natural Gas
Substitution
Nuclear Fuel
Substitution
Alternative
Fuel
Substitution
Conservation
Emphasis
Economic
Growth
2.47%
2 47%
2.47%
247%
2.47%
2.47%
2.47%
2.47%
2.47%
Electricity
Growth
3.13%
3.13%
3.13%
3.90%
3.20%
2.00%
3.11%
2.69%
0.90%
Coal
Growth
2 40%
2.47%
2.40%
N/A
2.77%
0.74%
1 .52%
1 73%
0.20%
Natural Gas
Growth
-0.40%
-0.40%
-0.40%
-0.40%
-0.39%
3.55%
-0.40%
-1 .20%
-0.31%
Refined
Petroleum
Growth
0.37%
0.37%
0.37%
0.37%
043%
0.51%
0.37%
0.15%
-0.54%
Energy
Growth
1.49%
1 .53%
1 .53%
N/A
1.73%
1.61%
1.50%
0.95%
0.10%
Installed Capacity
Year 2000 (MWe)
153,245
153,245
1 53,245
178,372
173,395
113,595
145,295
134,395
104,495
(BOM) districts in the six ORBES states (districts 1 through 4 and 6 through
11). All scenarios also assume that the regional generating units announced
by the utility companies as of December 31, 1976, including both coal-fired
and nuclear facilities, will be built as planned and that these facilities
will come on-line on the dates announced by the utilities. Finally, all
scenarios assume that sulfur dioxide emissions will be controlled through the
use of flue gas desulfurization systems ("scrubbers") or the use of of local,
blended low- and high-sulfur coals.
10
-------
6. COMPARISON OF COAL-DOMINATED SCENARIOS
6.1 Emissions, Concentrations, and Air-Quality-Related Impacts
For all of the coal-dominated scenarios, utility emissions are the most
important regional factor since their magnitude and their distribution
consistently correlate with ambient air concentrations and, thus, with crop
losses and mortality related to air quality. Under all coal-dominated
scenarios, utility sulfur dioxide emissions would decrease by the year 2000
from their 1976 levels. However, the rate of decrease and the actual totals
in 2000 would vary among the scenarios (see figure ES-4). Because of the
scenario assumptions that produced the differences charted in figure ES-4,
several observations can be made about possible strategies to reduce sulfur
Figure ES-4
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Coal-Dominated Scenarios
-SIP-N
2-
1-
Base Case (BC)
Strict Environmental Controls (SEC)
SIP Noncompliance (SIP-N)
High Electrical Energy Growth (HEG)
'Electrical Exports, emissions in 2000
SEC
1976
1980
1985
1990
1995
2000
11
-------
dioxide emissions at the individual plant level from their high 1976 levels.
A discussion of mitigation strategies in an organizational context appears
later in this summary.
SULFUR DIOXIDE
SIP Compliance. First, the base (compliance) case, the high electrical energy
growth case, and the noncompliance case demonstrate how sensitive regional
sulfur dioxide emissions are to compliance with and enforcement of SIP
standards. Both the base case and the high growth case assume that complete
SIP compliance will occur by 1985. As a result, under both scenarios, sulfur
dioxide emissions are reduced continuously and dramatically between 1976 and
1985, and at about the same rate (see figure ES-5). The noncompliance
scenario, however, assumes that there would be no utility compliance schedule;
the SIP units would continue burning historical coals and using emission
controls as in 1976. Thus, under this latter case, sulfur dioxide emissions
Figure ES-5
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
High Electrical Energy Growth Case
CO
c
3
c
o
CO
CO
'e
0)
6
CO
10-
9-
8-
7-
4-
«
3
\
-------
actually would increase between 1976 and 1985, ensuring that the base period
air quality problems would continue and perhaps get worse (see figure ES-6).
Since nearly the same electrical generation is assumed in all three of these
scenarios in 1985, the immediate benefits of SIP compliance are clear: total
utility sulfur dioxide emissions could be reduced by one-third by 1985.
Plant Retirements. Utility sulfur dioxide emission patterns between 1985 and
2000 demonstrate yet another way to control emissions of this pollutant.
After 1985, the level of utility sulfur dioxide emissions under the same three
scenarios depends on the retirement of SIP units and the replacement and
addition of present generating capacity by units governed by revised new
source performance standards (RNSPS). Both the base case and the
noncompliance case assume that SIP units will be retired after 35 years; the
high growth case, on the other hand, assumes 45-year generating unit
lifetimes. As figure ES-4 indicates, sulfur dioxide emissions thus decrease
under the first two scenarios and increase slightly under the last scenario.
Figure ES-6
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Base Case and SIP Noncompliance Case
11-
10-
9-
w
r-
0 8-
C
g 7-
-§ 6-
(fl
c
0 5-
C/J
1 4"
(D
CM O _
0 3
CO
2-
1-
\— SIP-N, 55-year unit lifetime
f.s' ^^^. £— SIP-N, 45-year unit lifetime
X"' x — -
Z x x
x
x olP-N, 35-year unit lifetime
^-^^
^^^^_
— • ^
\^
>^
f
*- BC, 35-year unit lifetime
oir Noncompliance (oir—N)
"~l 1 l l | i
1976 1980 1985 1990 1995 2000
13
-------
However, given the costs of installing new generating capacity and the
costs of complying with the stricter NSPS and. RNSPS controls, it is quite
possible that utilities may postpone the retirement of SIP units. Under two
scenarios—noncompliance and high growth—this possibility was examined
briefly. Figure ES-5 indicates the sulfur dioxide emission levels that would
occur under noncompliance if 35-, 45-, or 55-year generating unit lifetimes
are assumed. Figure ES-6 compares the high growth case that assumes 45-year
lifetimes with a variation that is identical except for a 35-year lifetime
assumption. Both of these figures demonstrate the difference that early
retirement of SIP units could have on regional sulfur dioxide emission levels.
The periodic maintenance of an existing plant can result in a substantial
renovation of that plant. The effect of such an alteration is that the plant
may not be retired as early as it would have been otherwise. If, however,
certain modifications were considered major enough to warrant the
reclassification of SIP units from an existing to a new source category, such
a revised definition might result in a utility's evaluation of the relative
merits of (1) continuing to use an existing unit or (2) building a new unit.
If existing SIP units were retired through such an evaluation, substantial
emission reductions could result.
The 35-year retirement of SIP units still would not wholly alleviate the
air quality problems stemming from regional sulfur dioxide emissions. Even in
2000, SIP-regulated units would account for the bulk (at least 6? percent) of
utility sulfur dioxide emissions, regardless of whether a 35- or 45-year life
is assumed. However, SIP units would account for no more than 28 percent of
the electrical generation in the year 2000 under any of the coal-dominated
scenarios. Thus, the emissions contributed by SIP units would be
disproportionate to the benefits of SIP generation in the year 2000. SIP
units comprise such a major portion of the total utility emissions in 2000 and
such a low percentage of the generation because they emit about five to six
times more sulfur dioxide than a new plant supplying the equivalent amount of
electricity.
Stricter Controls. One way to achieve a more balanced emission-generation
ratio would be to make stricter the SIP compliance strategies currently in
existence. The strict environmental control case offers an example of what
might be expected if such stricter controls were enacted and enforced. This
latter case assumes that in each ORBES state the urban SIPs—which are
stricter than rural SIPs~would be applied throughout the ORBES portion of
that state. As a result of such strict controls, by the year 2000, sulfur
dioxide emissions would decrease more under this scenario than under any other
coal-dominated scenario. Moreover, the rate of decrease would be more rapid
(see figure ES-4).
14
-------
Least Emissions Dispatch. Another way to achieve a more balanced emission-
generation ratio would be to use least emissions dispatching. At present, and
under all of the coal-dominated scenarios, generating units are loaded
(brought on-line) in order of operating costs. As a result, SIP units
generally are the first units dispatched, since, as discussed previously,
newer units are more expensive to operate. Under the high growth case, a
variation was examined that assumed coal-fired units would be dispatched
according to least emissions of sulfur dioxide. Under the least emissions
criterion, the units emitting the most sulfur dioxide (on a per Btu basis)
would be loaded last. Under one such dispatching order, for example, RNSPS
units might be dispatched first, then NSPS units, then urban SIP units, and
finally rural SIP units. However, such a dispatching order may not always be
feasible.
Under this least emissions policy, total regional utility sulfur dioxide
emissions would be 55 percent lower than they would be under the least cost
policy in the year 2000 (see figure ES-7). SIP emissions alone would be 35
percent lower under the former case than under the latter case. Moreover, in
the year 2000 under the least emissions dispatching variation, a more balanced
emission-generation ratio would be achieved. Under least emissions
dispatching, SIP units would emit 1.5 million tons of sulfur dioxide—or 45
percent of all utility sulfur dioxide emissions—and generate about 171
million megawatt hours. Under the least cost policy, on the other hand, SIP
units would emit 4.32 million tons of sulfur dioxide—or 71 percent of the
total emissions—and generate only about 162 million megawatt hours.
As this discussion of sulfur dioxide emissions under the different coal-
dominated scenarios thus has revealed, the current emission standards, if
complied with, would reduce total sulfur dioxide emissions between 1976 and
1985 from the 1976 levels. Any further reductions would be determined by the
lifetime of SIP plants. As will be discussed shortly, such further reductions
would be important since episodic concentrations still would result from the
1985 emission levels of most of the scenarios. Before such concentrations are
discussed, however, particulate and nitrogen oxide emission trends under these
coal-dominated scenarios are examined.
PARTICULATE EMISSIONS. Utility particulate emissions would be reduced
significantly by the year 2000 from the 1976 levels under all of the coal-
dominated scenarios except the noncompliance case. Moreover, except under the
latter scenario, particulate emissions would be reduced at about the same rate
and would be about the same in 2000—nearly five times lower than the 1976
emissions (see figure ES-8). In addition, such variations as least emissions
dispatching would result in emissions about the same as those charted in
figure ES-8. Noncompliance, however, would result in increased particulate
emissions through 1985. In 2000 under noncompliance, particulate emission
levels would be only slightly lower than the 1976 levels. These scenarios
15
-------
Rgure ES-7
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Dispatching Variations under High Electrical Energy Growth
•<^ LtJdSl l^USl I
— _—^* -—— «.
Least Cost Dispatching
Least Emissions Dispatching
1976
1980
1985
1995
2000
thus suggest that current particulate standards—which are the same in urban
and rural settings—will be effective. One major reason for this
effectiveness, however, is that particulate removal technology is assumed to
be between 85 and 94 percent efficient depending on when the unit was built.
NITROGEN OXIDE EMISSIONS. All scenarios would result in increased utility
nitrogen oxide emissions. Similarly, except under the high electrical energy
growth scenario, utility nitrogen oxide emissions would increase at about the
same rate through 1985 and would be nearly the same in 2000—approximately 35
percent higher than 1976 emissions (see figure ES-9). There are two reasons
for the similarity among scenarios. First, nitrogen oxide emission limits do
not exist for SIP plants in the ORBES region, except in the urban areas of
Illinois. Second, the same emission limits were assumed for new units under
all scenarios. Thus, nitrogen oxide emissions would increase from the 1976
levels primarily in proportion to electricity demand growth and to the
lifetime of SIP units. This fact also explains why, after 1985, nitrogen
16
-------
Figure ES-8
Electric Utility Paniculate Emissions in the ORBES Region,
Coal-Dominated Scenarios
1.75-
1.50-
OT
c
o
"w
OT
E
(D
_CO
o
ro
Q.
1.00-
.75-1
.50-
.25-
SIP-N
Base Case (BC)
Strict Environmental Controls (SEC)
SIP Noncompliance (SIP-N)
High Electrical Energy Growth (HEG)
* Electrical Exports, emissions in 2000
HEG
SEC
1976
1980
1985
1990
1995
2000
oxide emissions would increase under the high electrical growth case at a
faster rate than under the other scenarios: the high growth case has the
highest electricity demand growth and assumes 45-year SIP unit lifetimes
instead of the 35-year lifetimes assumed under the other coal-dominated
scenarios.
POLLUTANT CONCENTRATIONS. The magnitude of changes in utility sulfur dioxide
emission levels under each scenario corresponds to changes in annual average
17
-------
(or long-term) and episodic (short-term) regional sulfur dioxide and sulfate
concentrations. Moreover, since, as discussed earlier, the transformation of
sulfur dioxide into sulfates contributes to concentrations of total suspended
particulates, reductions in both utility particulate emissions and utility
sulfur dioxide emissions could reduce measured TSP concentrations. However,
the ratio of the lower ORBES region's contribution to concentrations in the
upper region is not likely to change from the ratio during the base period
under any of the scenarios.
Many of the same statements made about emissions under the various
scenarios also apply to comparisons of the scenarios and their annual
concentrations. For example, regardless of scenario, the regional sulfur
dioxide and sulfate concentrations in 2000 attributable to utility emissions
Figure ES-9
Electric Utility Nitrogen Oxide Emissions in the ORBES Region,
Coal-Dominated Scenarios
nitrogen oxide emissions (million tons)
O -^ -"• ro ro u
> in b en b en b
i i i i i '
^-HEG
f+*
,>'"''
*EX
/''' SIP-N
-"'' RC
^" ">"''" "ll^-^^ ^—SEC
-^^---^~^:^^ ~~~"
base L-ase iuo)
Strict Environmental Controls (SEC)
SIP Noncompliance (SIP-N)
Ulinh Pla^tr i^al Pncirnw f^mvAfth fWFf^
— nign tiecincai criciyy uruwui ^nc_oj
* Electrical Exports, emissions in 2000
°T - -, , | , ,
1976 1980 1985 1990 1995 2000
18
-------
would be lower than the present concentrations. Again, it is the strict
environmental control case that would reduce the annual average concentrations
the most and that would reduce them more rapidly than any of the other
scenarios (see table ES-2). Similarly, the high electrical energy growth case
and the noncompliance case would result in the least reduction by the year
2000. In fact, the 1976 concentrations would even increase through 1985 under
the noncompliance case. In general, most concentration reductions would occur
by 1985—regardless of scenario—if SIP plants have complied by that date.
Figures ES-10 and ES-11 illustrate the reductions in annual average sulfur
dioxide and sulfate concentrations under the base case in 2000 as compared
with the 1976 concentrations.
Another benefit of lower utility sulfur dioxide emissions is the probable
reduction of the concentrations that would occur under episodic conditions.
If the characteristics of the August 27, 1974, sulfate episode were to be
repeated in 2000 under any of the scenarios, the predicted utility-related,
short-term sulfur dioxide and sulfate concentrations would be reduced from the
utility-related, short-term concentrations that were registered during that
episode (see table ES-3). However, since these short-term concentrations were
quite high during the August 27 episode (the most frequently occurring type of
episode in the ORBES region) even the 49 and 51 percent reductions that would
occur in 2000 under the base case would result in short-term sulfur dioxide
levels on the order of 30 micrograms per cubic meter and in short-term sulfate
levels that would be considered marginally episodic—that is, on the order of
15 micrograms per cubic meter over a large area. On the other hand, the
strict environmental control case would lead to reductions of such magnitude
that the short-term levels of sulfur dioxide and sulfates no longer would be
Table ES-2
Sulfur Dioxide and Sulfate Annual Average Concentrations,
ORBES Region, Percent Change from 1976,
Highest Concentration Region
Pollutant
Sulfur dioxide
Sulfur dioxide
Sulfates
Sulfates
Concentration,
1976(xtg/m3)
25.88
25.88
9.2
9.2
Year
1985
2000
1985
2000
Base Case
-28
-50
-27
-49
Strict
Environmental
Controls
(5
-62
-71
-56
-66
SIP
Noncompliance
6)
+ 16
-18
+ 13
-20
High Electrical
Energy Growth
-30
-29
-25
-25
19
-------
Figure ES-10
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
1976-
2-5.9
6-9.9
10-13.99
14-17.99
18-24
Figure ES-11
Annual Average Sulfate Concentrations, Electric Utility Contribution
1-2.99
3-4.99
5-6.99
7-9
20
-------
considered episodic. As can be deduced, therefore, the noncompliance and the
high growth cases, which reduce emissions the least by 2000, would result in
relatively high episodic concentrations.
V
Annual average and episodic concentrations are important in terms of both
regional crop loss impacts and regional health impacts (among other things)
since the reductions in concentrations consistently correlate with less crop
loss and fewer health impacts.
PHYSICAL CROP LOSSES. In terms of agricultural impacts, studies have
indicated that sulfur dioxide concentrations as low as 130 micrograms per
cubic meter (one-tenth of the secondary three-hour standard) in the presence
of moderate ozone levels (0.06 to 0.1 parts per million) can affect
vegetation. Thus, three coal-dominated scenarios—the base case, the
noncompliance case, and the high growth case—were examined to determine the
regional acreage that could be affected by the sulfur dioxide concentrations
attributable to ORBES-region utility emissions. Each of these three scenarios
also was examined to determine the impact of such affected acreage on crop
yields, and it was found that crop yield losses would not be as high in both
1985 and 2000 as they were in 1976. However, because utility sulfur dioxide
emissions would be higher under the noncompliance case and because more
acreage would be affected by the resulting sulfur dioxide concentrations of
130 micrograms per cubic meter, noncompliance would result in the highest
losses. Nevertheless, regardless of the scenario, physical crop losses
related to utility sulfur dioxide emissions would represent less than 1
percent of the expected regional yield in any given year. Thus, from this
regional perspective, the direct effects of sulfur dioxide emissions in the
ORBES region on agricultural losses can be thought of as negligible under all
three of these scenarios.
Table ES-3
Sulfur Dioxide and
Sulfate
Percent Change
Episodic
Concentrations, ORBES
from August 27, 1 974,
Episode,
Region,
Highest Concentration Region
Concentration,
Pollutant 1976Ug/m)
Sulfur dioxide 94.04
Sulfur dioxide 94.40
Sulfates 40.10
Sulfates 40.10
Year
1985
2000
1985
2000
Strict
Environmental
SIP
Base Case Controls Noncompliance
-31
-49
-25
-51
(%
-68
-75
-76
-78
)
+ 18
-13
+ 16
-30
High Electrical
Energy Growth
-34
-30
-23
-18
21
-------
The majority of regional crop losses are the result of oxidants formed
from hydrocarbons and from nitrogen oxide emissions. Nitrogen oxide emissions
in the ORBES region originate primarily from transportation and from
electrical generation. However, it is projected that nitrogen oxides from
transportation will decrease significantly by the year 2000. Thus, utility
nitrogen oxide emissions will begin to constitute a larger proportion of the
regional nitrogen oxide emissions, especially since nitrogen oxide standards
do not yet exist for SIP units in the ORBES region and since SIP-unit
emissions are projected to account for the majority of all utility emissions.
As a result, the rate of decrease in ozone production as well as the rate of
decrease in ozone-related crop losses may be dictated by utility nitrogen
oxide emissions.
In general, regardless of the scenario, losses due to oxidants would
constitute about 99 percent of all the losses expected because of sulfur
dioxide and ozone. Moreover, the distribution of the losses due to oxidants
would vary among state portions. However, the ORBES state portions of
Illinois, Indiana, and Ohio would account for about 95 percent of both sulfur
dioxide and ozone losses. Finally, the distribution of all crop losses due to
air pollution is not merely a local problem—that is, merely in the vicinity
of a power plant—but, because of pollutant transport, these losses may occur
in areas removed from major point sources. The dollar losses related to crop
losses due to sulfur dioxide and all oxidants are given in section 6.2.
MORTALITY. Substantial controversy exists about the quantification of deaths
related to air quality. Yet increasing evidence exists to support the
hypothesis that the annual average exposure to sulfates—or something closely
related to them—results in an increased mortality rate. Therefore,
cumulative sulfate-related deaths between 1975 and 2000 were projected for the
coal-dominated scenarios. Such projections depend on the damage function
employed since rates between 0 and 9 per 100,000 persons exposed per microgram
of sulfates per cubic meter are found in the literature. If a rate of 3 is
used, it becomes clear that the magnitude of utility emissions is a dominant
factor: the strict control case would result in the lowest number of
cumulative deaths, while the noncompliance case and the high growth case would
result in the most such deaths. Cumulative sulfate-related deaths under the
latter two scenarios also would be nearly 3^ and 13 percent higher,
respectively, than would the deaths under the base case.
6.2 Economic Impacts Related to Air Quality Impacts
The costs to the utilities and to the consumer of the possible reductions
in emissions and other air-related impacts also were projected for the five
coal-dominated scenarios as well as for the least emissions variation and the
22
-------
high electrical energy growth case with a 35-year lifetime variation.
Agricultural monetary losses also were estimated for three scenarios—the base
case, the noncompliance case, and the high growth case. Knowing these costs
permits comparisons to be made among the scenarios in terms of the social
benefits derived from reduced emissions versus the economic impacts of such
reductions.
UTILITY COSTS. Figure ES-12 charts the costs to the utilities of installing
new coal-fired generating capacity, of installing pollution control devices on
these new units, and of retrofitting existing units. As shown in this figure,
the base case, the strict control case, and the noncompliance case would
result in the same capital costs but in different pollution control costs.
The differences in pollution control costs among these three scenarios would
result entirely from the retrofitting of existing SIP plants with pollution
control devices. Thus, the total cumulative pollution control costs for the
base case would be higher than those under the noncompliance case because
under the base case about one-third of existing capacity would be retrofitted.
Under the strict control case, on the other hand, almost all of the existing
capacity would be retrofitted, resulting in the highest cumulative pollution
control costs of the three scenarios.
The high growth case and its variations and the export case would result
in higher costs to the utilities than would the first three scenarios. These
higher costs, however, would be due to the costs of installing the expanded
generating capacity and the pollution control devices on this new capacity.
Thus, if the proportion of pollution control costs to total capital costs is
examined, the base case and the high growth case are similar: under both
scenarios, pollution control costs would total about 21 to 22 percent of the
total costs. It should be noted, however, that these total capital costs do
not reflect the operating costs. The operating costs are included in the
calculation of the price of electricity, which reflects all the costs borne by
the utilities each year. Thus, for example, while the high growth scenario
and the high growth least emissions variation are projected to have the same
capital costs, there would be differences in their operating costs since the
least emissions dispatching variation would require increased operation of
pollution control devices and the burning of greater quantities of cleaned or
low-sulfur coals.
CONSUMER COSTS. The direct costs to the consumer would increase regardless of
scenario. In the short run, however, some scenarios may result in a faster
rate of increase in the price of electricity (see figure ES-13). Several
observations can be made about the electricity prices and their rate of
increase. For one, between 1976 and 1985, the price of electricity rises
according to the added costs of complying with SIP emission limits, paying for
rising fuel and capital costs, and meeting electricity demand. Thus, as
figure ES-13 indicates, the price of electricity between 1976 and 1985 would
23
-------
Figure ES-1 2
Cumulative Capital Costs, Coal-Dominated Scenarios, 1976-2000
130-
120-
110-
10P-
90-
w
j§ 80-
"5
5*0-
h-
O)
T- 60-
V4—
0
£50-
0
5 40-
30-
20-
10-
0J
8
I
(
i
L
I
5.6'
3as«
;as«
3 Curr
3 coal
]Cum
cont
a Cum
3 cont
r
6.12
12.55
67.0
5 £
i Envi
C<
ulal
-fire
ulat
rol,
ulat
rol,
39.7
>tric
ronn
antr
ive cap
dgene
ive cos
1976-2
ive cos
1976-2
6.12
E
16.58
67.0
t
nental
ols Co
ital
ratir
tsfo
OOC
tsfo
OOC
0.1.
M
SIP
Non
mpli
costs to install new
g capacity, 1976-2000
r sulfur dioxide 15
rparticulate 114.20 114.20
103.4
14.8
•>
2.79 f=^\
10.33 p=3
I 181'9
R70 U- 1
Electrical 4E
Exports Lea
ance (EX) \
—
-ye
stC
\
H
7.04
16.78
90.38
ar 4,
lost 1
En
(
H
^~
5-ye
.eas
lissi
LEC
704
16.78
90.38
ar 3
t Le
ons
»
'6.21
HI7-67
—
5-ye
astl
/
18.5
100.04
ar
Zosl
/
Cumul
sulfur
particu
contro
Scenario
BC
SEC
SIP-N
EX
HEG
LED
35-Year
ative
jioxide £
late
costs
costs
billion
$
18.67
22.7
13.12
21.5
23.82
23.82
26.17
ind
total
costs
21.8
25.3
16.4
20.8
20.9
20.9
20.7
V
jgh Electrical Energy
Growth
rise similarly when nearly the same degree of compliance is assumed—that is,
under all the scenarios but the noncompliance case. The strict environmental
control case, however, would result in the greatest increase in electricity
prices since complying with stricter SIP standards would cost the utilities
more. The price of electricity under the noncompliance case, of course,
reflects the absence of such control costs.
-------
Figure ES-13
Electricity Prices in the ORBES Region, Coal-Dominated Scenarios
in
f-
O)
w
c
o
o
o
+~l
>
•4—'
'o
0)
•5
CD
o
6-1
5-
4-
3-
2-
1-
HEG, 35-year
SIP-N
-Base Case (BC)
•Strict Environmental Controls (SEC)
-SIP Noncompliance (SIP-N)
-High Electrical Energy Growth, 45-year unit lifetime (HEG, 45-year)
•High Electrical Energy Growth, Least Emissions Dispatching (LED)
-High Electrical Energy Growth, 35-year unit lifetime (HEG,35-year)
1976
1980
1985
1990
1995
2000
Between 1985 and 1995, the rise in electricity prices depends on the
annual electricity demand growth rate, capacity replacement, and capacity
expansion. Since the base case, the strict control case, and the
noncompliance case assume nearly the same replacement, expansion, and growth
rates, the price of electricity would rise little between these years. Under
the high growth scenario and its variations, however, the price of electricity
rises between 1985 and 1995 since more capacity expansion is projected under
these scenarios. The greater operating costs of least emissions dispatching
also are reflected in the higher price of electricity under this variation.
Between 1995 and 2000, all scenarios show a rise in the price of
electricity. This increase would result because additional generating units
must be constructed to satisfy electricity demand after the year 2000 and
25
-------
because a significant number of SIP units will retire during these years and
must be replaced.
Because some scenarios would cause electricity prices to be higher in the
short run, the cumulative costs to consumers between 1976 and 2000 give a
better idea of the total consumer costs than the price of electricity in a
given year. Under the compliance or base case, such cumulative revenues
required from consumers would total $525 billion (1975 dollars, or
approximately $709 billion in 1979 dollars). Compared to the base case
revenues, the cumulative revenues required under the strict environmental
control case would be about 4 percent higher, while the revenues required
under the noncompliance case would be about 10 percent lower. A high
electrical energy growth rate would require about 18 percent more revenues
than would the base case. Of the two high growth variations, the 35-year
variation would require the most revenues (about 21 percent higher than the
base case), while the revenues required by the least emissions dispatch
variation would be about 19 percent higher than under the base case.
MONETARY CROP LOSSES. When comparing the agricultural monetary losses that
would occur because of physical crop losses due to sulfur dioxide and
oxidants, some of the same statements made under the physical crop loss
discussion can be repeated. First, monetary losses of oxidant-related crop
losses would constitute virtually all (about 99 percent) of the economic
losses under all of these scenarios. In addition, monetary losses related to
the crop losses due to sulfur dioxide emissions would be similar under the
three scenarios examined (less than 1 percent of the total monetary losses).
Also, the total agricultural monetary losses would be concentrated in certain
ORBES state portions (Illinois, Indiana, and Ohio) regardless of scenario.
Finally, the high growth case would result in the highest cumulative
agricultural monetary losses ($8.4 billion in 1975 dollars, or approximately
$11.3 billion in 1979 dollars). The base case and the noncompliance case
would result in about the same cumulative agricultural monetary losses ($7
billion in 1975 dollars, or approximately $9.5 billion in 1979 dollars).
6.3 Other Impacts Related ^to Expanded Capacity
LAND. The regional impacts of an expanded utility industry on land use would
be about the same for three of the coal-dominated scenarios—the base case,
the strict environmental control case, and the noncompliance case—since their
generating capacity is about the same and their siting patterns somewhat
similar. The base case, for example, converts about 184,000 acres, or 0.15
percent of the ORBES region, for generating facility use through 2000.
However, although the regional acreage affected would be about the same under
all three cases, affected acreage at the state level would vary slightly.
Policies that encourage high electrical energy growth or the export of
electricity from the region would result in much larger generating capacities
26
-------
than the three other coal-dominated scenarios. Thus, the land converted would
be about 30 percent higher under the high growth case than under the base
case; under the export case, land conversion would be about 17 percent higher
than it would be under the base case.
EMPLOYMENT. An increase in the employment of power plant construction and
operation workers would be expected under both the high electrical energy
growth case and the electrical exports case. In fact, such employment would
rise dramatically under these two scenarios between 1983 and 1987, although
the high growth scenario would require more workers than the export case (see
figure ES-14). However, such rapid changes as occur under the high growth
case could result in short-term labor shortages followed by a surplus of labor
as experienced workers have a choice of jobs and then few choices. Moreover,
shortages of the skilled labor necessary to power plant construction and
operation—such as boilermakers, pipefitters, and electricians—might
accompany the high growth case. In general, however, skilled labor shortages
would not be a major problem for the region under any of the other coal-
dominated cases, although local shortages could possibly occur.
Annual coal production in the region for all purposes and mining
employment would increase under the base case, the strict environmental
control case, and the electrical exports case. However, annual coal
production would be much higher in 2000 under the electrical exports case than
it would be under the other two scenarios. Thus, regional mining employment
would rise similarly under the base case and the strict control case, from a
minimum of 36 percent to a maximum of about 226 percent, depending on the
county. Such employment would increase from a minimum of 42 percent to a
maximum of 270 percent under the electrical exports case. It is also
projected that at least 79 to 88 of the 152 ORBES counties with a
concentration in coal mining would experience boom-town effects (growth over
200 percent) under all three of these scenarios.
HEALTH. Under all of the coal-dominated scenarios, the health impacts related
to supplying coal to ORBES power plants would increase. This increase results
because, under all scenarios, coal production as well as electric utility coal
consumption would rise from current levels. In 1985, the increases in the
health impacts in the coal-mining and coal-processing sectors would be the
same under all coal-dominated scenarios. In 2000, three of the scenarios—the
base case, the strict control case, and the noncompliance case—would result
in similar health impacts in these sectors, while the high growth case and the
exports case would result in impacts about 17 percent higher. The health
impacts in the coal transportation sector were analyzed only for the base case
and the strict control case and only for the year 2000. Both cases would
result in an increase in the fatalities associated with transport to ORBES
electrical generating facilities, but in the same number of injuries as
currently since railroad injuries are projected to decline at a greater rate
than fatalities.
27
-------
number of construction workers
IV)
OO
I
I
O
ff
55
? =
£0 (Q
Is
CO
o
CD
B)
^
F
-------
WATER QUALITY. A comparison of the water quality analyses conducted for the
coal-dominated scenarios reveals that none of these scenarios would result in
aquatic habitat impacts very different from each other or from those that
could have occurred in 1976 under 7-day-10-year low flow conditions. Thus,
whether historical municipal and industrial growth continues, or whether low,
high, or base case electricity demand occurs, the region already appears to
have the potential to experience its most serious aquatic habitat impacts
under 7-day-10-year low flow conditions. However, although overall aquatic
habitat impacts change little under most of these scenarios, under the strict
control case and the high growth case, some rivers would register perhaps
slightly less or more stress than they would under the base case.
Background Concentrations. The reason why the majority of the streams would
experience the same impacts under the scenarios as they would under 1976
conditions concerns the high background concentration levels that exist in the
region. As noted under the base period discussion (sec. 3), 19 of the 24
streams studied could have violated several of the study's reference
concentrations under 7-day-10-year low flow at some time in 1976. Further,
the overwhelming majority of these high background concentrations are
estimated to be geochemical or to originate from nonpoint sources under
conditions of higher flow. Since the likelihood of bringing nonpoint sources
under control during the time frame of this study is considered almost
impossible by most experts, background levels in the ORBES streams were
projected to remain constant between 1975 and 2000 under all scenarios except
the strict control case. Under the strict control case it was assumed that
background levels would be reduced by half by the year 2000. (It also was
assumed under this case that power plant effluent loadings would be reduced 95
percent from the base case loadings.) Such calculations reveal that if such a
reduction were to occur, aquatic habitat impacts would remain about the same
although slightly less stress would be experienced on all rivers. The results
under the strict control case thus suggest that background levels are so high
that they would have to be reduced by more than half to avoid serious aquatic
habitat impacts under 7-day-10-year low flow conditions.
Loadings. The influence of these background concentrations is further
indicated when the effluent loading assumptions of these scenarios are
compared. Under all of the coal-dominated scenarios except the strict
environmental control case, power plant effluents were not limited. The
strict control case, however, along with its assumption of reduced
concentrations, assumed that energy conversion facilities would operate at 5
percent of base case levels. However, a comparison of the strict control case
with the other coal-dominated cases—the base case, for example—reveals
little difference because of the loading assumptions. Although slightly less
stress would occur on all rivers under strict controls, aquatic habitat
impacts remain the same as under the base case on all but four rivers. If the
impacts under the strict control case then are compared to those that could
29
-------
have occurred in 1976, only two rivers would register changes from the 1976
aquatic habitat impacts. Thus, since loading is not a significant factor,
background concentrations appear mainly responsible for the substantial
impacts that could occur under 7-day-10-year low flow conditions.
Consumption. Power plant consumption would be important on those of the
region's smaller streams where little municipal and industrial consumption
occurs and where flow under 7-day-10-year low flow conditions would be
curtailed drastically. However, if background concentrations were not so high
on these small streams, power plant consumption might have little impact.
Thus, once again the high background levels are more important than the
consumption source.
What the impacts on these small streams suggest is that alternative
siting or technology could alleviate almost all power-plant-related impacts on
water quality under all scenarios. There is, however, one, perhaps
significant, problem with alternative siting of power plants. Although water
quality would be protected, air quality would suffer since most of the
suitable alternative sites in terms of water quality are located along the
Ohio River main stem, where air quality problems exist. A further
concentration of power plants in this area thus could exacerbate these air
quality problems.
What can be done to avoid the combined effects of natural forces and high
background concentrations thus is hard to pinpoint, especially if it is
unlikely that nonpoint sources can be brought under control. Preventing the
rather minor power-plant-related impacts would necessitate the tradeoff just
discussed. Avoiding the potentially significant impacts of municipal and
industrial consumption also would involve tradeoffs. If, for example,
regulatory bodies were to implement siting restrictions that prohibit the
siting of any entity that consumed water along streams having 7-day-10-year
low flows less than 100 cubic feet per second, a number of rivers would not be
available for growth of any kind. This condition would result in a very
limited number of sites for industry, especially for power plants. Thus, as
this brief outlining of some possible steps and their limitations suggests,
improvements in water quality may require some environmental, social, and
economic tradeoffs that would have their own repercussions.
7. MITIGATION STRATEGIES
On a regional scale, existing institutional mechanisms are inadequate to
ameliorate air quality impacts, many of which transcend political boundaries
both inside and outside the ORBES region, particularly to the northeast.
TECHNICAL STRATEGIES. A variety of technical strategies, usually applied on a
plant-by-piant basis, could be more effective if implemented regionally.
30
-------
Among the technical strategies discussed in the context of the ORBES scenarios
(see sec. 6.1) are the use of flue gas desulfurization systems, or
"scrubbers"; least emissions dispatching; modified plant retirement schedules;
and stricter environmental standards.
TECHNO-ORGANIZATIONAL STRATEGIES. In contrast to technical strategies, which
usually are applied at single generating units or within a single utility
service area, techno-organizational strategies are broader and could be
developed on an interstate, multistate, or regional scale. The need for such
strategies arises from transboundary air pollution transport, which can be
divided into two types: (1) local transboundary air pollution transport (the
movement of air masses is over relatively short distances across state lines
and the contributions from individual plant sources usually can be identified)
and (2) long-range transboundary air pollution transport (the air masses
travel longer distances, often across several state lines, and the
contributions from individual sources are difficult to isolate).
Local Transboundary Transport. Local transboundary air pollution transport is
treated in the Clean Air Act, in provisions that attempt to make a state
responsible for pollution that originates within its borders but is
transported short distances into other states. At present, action is pending
on at least three petitions filed by several ORBES-region states in regard to
air pollution generated by power plants in neighboring states. Protracted
legal proceedings on related local transboundary pollution questions also have
taken place in the region within the context of the Clean Air Act.
Long-Range Transboundary Transport. Long-range transboundary air pollution
transport, on the other hand, is not covered specifically in the Clean Air
Act. However, as discussed previously (sec. 6.1), long-range transport
contributes to violations of NAAQS in the upper ORBES region. Thus, air
quality in the ORBES region and beyond could be improved if there were a
regionwide techno-organizational strategy for determining expected emissions
from coal-burning plants, siting new plants, and operating both existing and
new facilities. A coordinated strategy is necessary because of the
interdependency of emission reductions, siting, and operations.
A coordinated siting mechanism could help to reduce pollutant
concentrations at local "hot spots," where these concentrations are highest.
However, total regional pollutant loadings would remain the same whether a
regional siting mechanism is developed or not. Thus, regional coordination
appears to be required to reduce pollutant loadings and/or to reduce
concentrations from long-range transboundary pollution in the ORBES region and
beyond.
Utilities and State Governments. If new organizational approaches are to be
devised in a meaningful way, both the states and the electric utilities must
31
-------
participate. Voluntary cooperation among utility companies is one
possibility, but it may not be realistic to expect utilities in different
states to work together in activities aimed at the mitigation of negative
transboundary air quality impacts. Moreover, cooperation would have to
encompass operations as well as siting if extraregional impacts were to be
mitigated.
If utilities were to agree upon the desirability of cooperation in either
siting or operations across state lines, the most appropriate organizational
arrangements are not clear. At present, utilities are regulated by individual
states, and most utility service areas follow state lines. Thus, voluntary
cooperation across state lines probably would be difficult. Yet the utilities
do engage in interstate cooperation in several other areas, principally in the
assurance of electric power reliability. It is conceivable that regional
reliability councils now in operation could stimulate further cooperation.
Indeed, the expansion of existing federal legislation might encourage
cooperative siting, if not cooperative operations. Cooperation among the
states in this regard also should be examined, but prospects do not appear
promising. In only one ORBES state, Ohio, has the legislature mandated
admininstrative leaders to seek cooperation with other states in developing
mitigation strategies. Ohio is also the only ORBES state with a "one-stop"
siting procedure; if similar arrangements existed in the other ORBES states,
they might provide a vehicle for interstate discussions on siting problems.
Interstate Compacts. Another potential vehicle is the interstate compact.
For example, an existing compact, the Ohio River Valley Water Sanitation
Commission (ORSANCO), might be expanded in scope to permit supplementary
agreements, between two or more member states, to resolve transboundary air
pollution conflicts and other problems related to interstate facility siting
and possibly operations.
No interstate compact to mitigate long-range transboundary air pollution
is known to operate anywhere in the country at this time. However, the
Delaware River Basin Compact has organizational elements that could be
relevant in the consideration of such a mechanism for the ORBES region. For
example, the Delaware compact has been instrumental in obtaining interstate
approval of power plant sites.
Other Regional Bodies. The Tennessee Valley Authority (TVA) cannot be ignored
in any consideration of mitigation strategies. A portion of Kentucky is
included in the TVA area, and problems of long-range transboundary air
pollution transport are shared by the TVA area and the ORBES region. In fact,
the two areas are connected in so many ways as to make separate treatment
impossible.
-------
Other regional bodies that should be considered in this context are the
Ohio River Basin Commission and the Appalachian Regional Commission (ARC).
Some have suggested that the ARC'S functions be expanded so that this
organization could address air impacts in the Ohio River valley and perhaps
participate in interstate siting. However, the proposal has found little
support.
Federal Action. The most likely federal initiatives will center on the Clean
Air Act; an upcoming debate in Congress will review the entire act, including
the 1977 amendments. The most extreme possibility, federal preemption, is
considered unlikely.
8. FUEL SUBSTITUTION AND CONSERVATION SCENARIOS
Four scenarios investigate energy and fuel use characteristics that
differ from those of the coal-dominated scenarios (see table ES-1). Three of
the cases assume relatively less emphasis on coal use for electrical
generation because of partial substitution by other fuels. In the natural gas
substitution case, natural gas is substituted for other fuels whenever
practicable, but not to fire utility boilers. In the nuclear fuel
substitution case, nuclear-fueled electrical generating capacity substitutes
directly for coal-fired capacity. In the alternative fuel substitution case,
a variety of alternative fuels, including biomass and solar energy, partially
replace coal-fired capacity. The fourth case assumes that energy growth in
the ORBES region is significantly less than under all other scenarios because
of the implementation of conservation measures. All four cases are compared
with the coal-dominated base case.
The same regional population, fertility, and economic growth rates are
assumed in the four scenarios discussed here as are assumed in the coal-
dominated case. Moreover, base case environmental controls are assumed under
all four scenarios. Finally, the same assumptions as under the coal-dominated
scenarios are made concerning the mining for utility coal and the utility-
announced capacity.
9. COMPARISON OF FUEL SUBSTITUTION AND CONSERVATION SCENARIOS
An analysis of these fuel substitution and conservation scenarios
suggests that all of these scenarios would reduce the emission-related impacts
that are projected to occur under the coal-dominated base case. Other
across-the-board comparisons, however, are more difficult to make.
9.1 Emissions, Concentrations, and Air-Quality-Related Impacts
EMISSIONS. Utility sulfur dioxide emissions would be only slightly lower in
2000 under the fuel substitution and conservation scenarios than under the
33
-------
base case (see table ES-4) even though substantially fewer coal-fired units
would be added under the substitution and conservation scenarios. The
conservation case would reduce sulfur dioxide emissions the most (resulting in
emissions 11 percent lower than under the base case), and the nuclear
substitution case would reduce them the least (resulting in emissions only 3
percent lower).
The expanded use of SIP generating units under each of the fuel
substitution and conservation scenarios explains why these scenarios would
result in sulfur dioxide emissions quite similar to those of the base case.
Under both the conservation emphasis case and the natural gas substitution
case, fewer new generating units would be built than under the base case;
under the nuclear fuel substitution case, new units added after 1985 would be
nuclear fueled rather than coal fired. As a result, SIP-regulated generating
units would be used more than they would under the base case, where some of
the electrical generation shifts to the new, cleaner RNSPS units. For
example, under the natural gas substitution case, SIP units would account for
32 percent of the electrical generation in the year 2000, whereas they would
account for 25 percent under the base case. Thus, while sulfur dioxide
emissions from SIP-regulated units would account for 67 percent (or 2.93
million tons) of the sulfur dioxide emitted in 2000 under the base case, under
the natural gas case such emissions not only would be higher (3.05 million
Table ES-4
Sulfur Dioxide, Particulate, and Nitrogen Oxide Emissions,
ORBES Region, Fuel Substitution and Conservation Emphasis Scenarios,
Year 2000
Sulfur Dioxide
Emissions
1976 8.94
Base Case 4.35
Natural Gas Substitution 3.93
Nuclear Fuel Substitution 4.21
Conservation Emphasis 3.87
Particulate
Emissions
(millions of tons)
1.38
0.19
0.16
0.18
0.16
Nitrogen Oxide
Emissions
1.49
2.00
1.51
1.84
1.47
Note: Emission levels were not calculated for the alternative fuel substitution case.
-------
tons) but also would account for more of the total emissions (78 percent of
the 3.93 million tons emitted).
Particulate emissions also would be lower under all of the fuel
substitution and conservation scenarios than they would be under the base
case. However, again because of the expanded use of SIP units to generate
electricity, these emissions would be only slightly lower than under the base
case.
Utility nitrogen oxide emissions would not increase as much under the
fuel substitution and conservation scenarios as under the base case (see table
ES-U) since such emissions rise in proportion to increased generating
capacity, and less generating capacity is added under all of the substitution
and conservation scenarios than under any of the coal-dominated scenarios.
Although annual and episodic concentrations, crop losses, and emission-
related mortality were not examined thoroughly under these fuel substitution
and conservation scenarios, a few general observations can be made using the
patterns developed under the coal-dominated scenario analyses.
CONCENTRATIONS. Since the magnitude of sulfur dioxide and particulate
emission reductions consistently correlates with reductions in annual and
episodic sulfur dioxide and particulate concentrations, and since all of the
fuel substitution and conservation scenarios would reduce these emissions more
than the base case would, concentrations should be lower in 2000 under any of
the fuel substitution and conservation scenarios than under the base case.
This observation is confirmed by calculations performed for the natural gas
substitution case. Under the natural gas case, episodic sulfur dioxide and
sulfate concentrations would be 25 and 15.6 percent lower, respectively, in
the year 2000 than they would be under the base case in that year. Annual
average concentrations would be about the same in 1985 and about 7 percent
lower in 2000 than under the base case.
PHYSICAL CROP LOSSES. Similarly, physical crop losses in the year 2000 due to
utility sulfur dioxide emissions should be lower under any of the fuel
substitution and conservation cases than they would be under the base case.
However, even under the base case such crop losses would represent less than 1
percent of the total regional yield.
It is the crop losses due to oxidants that these substitution and
conservation scenarios should reduce the most. As will be recalled, increased
utility nitrogen oxide emissions under the coal-dominated base case could
contribute significantly by the year 2000 to crop losses. Thus, since the
fuel substitution and conservation scenarios would result in utility nitrogen
oxide emissions significantly or substantially lower than those under the base
case, related crop losses also should be significantly to substantially lower
under these scenarios.
\
35
-------
MORTALITY. Finally, mortality related to air quality should decrease under
all of these fuel substitution and conservation scenarios. An analysis of
sulfate-related deaths under the natural gas substitution case bears out this
observation. Under this case, cumulative sulfate deaths related to ORBES-
region electrical generation would be 21 percent lower between 1975 and 2000
than they would be under the base case.
9.2 Economic Impacts Related to Air Quality Impacts
UTILITY COSTS. In terms of the monetary costs to the utilities and to the
consumer for the lower emissions, all three of these substitution and
conservation scenarios should result in lower cumulative pollution control
costs and lower cumulative capital costs to install new coal-fired capacity
than would the base case (see figure ES-15). These reductions are the direct
result of decreased coal-fired generating capacity under all of these
scenarios. However, when the costs of installing nuclear-fueled capacity are
added, the nuclear fuel substitution case results in total costs about 10
percent higher than the total costs under the base case. The nuclear
substitution case would result in these higher costs because the cost of
building a nuclear-fueled plant is approximately 20 percent higher than the
cost of building a comparable coal-fired plant.
CONSUMER COSTS. Consumer costs were calculated only for the natural gas
substitution case. Thus, the exact economic benefits for the consumer of
reduced pollution control costs and of reduced capital costs are unknown for
the other fuel substitution and conservation scenarios. Under the natural gas
substitution case, however, the total revenues collected from consumers
between 1976 and 2000 would be lower (by about 26 percent) than the total
revenues collected under the base case during the same years. Yet the actual
price of electricity in 2000 under the former case would be only 0.2 percent
lower in 2000 than it would be under the coal-dominated base case. The reason
for this similarity in the year 2000 can be traced to the fact that similar
electricity demand growth rates were assumed for these two scenarios between
1985 and 2000.
9-3 Other Impacts Related to Expanded Capacity
HEALTH AND LAND. As a result of decreased generating capacity, decreased coal
production, and decreased utility coal consumption under the fuel substitution
and conservation scenarios, fewer health impacts related to coal mining, coal
processing, and coal transport would occur than would occur under the coal-
dominated scenarios. Similarly, land conversion would be lower under these
substitution and conservation options than under base case. However, even
under the base case, land conversion would represent less than 1 percent of
regional acreage, although some state portions would be more affected than
others.
36
-------
Figure ES-15
Cumulative Capital Costs, Base Case, Fuel Substitution Scenarios, and
Conservation Emphasis Scenario, 1976-2000
Note: The same nuclear capacity was assumed under all scenarios but the nuclear fuel substitution case.
For all scenarios but the nuclear case, cumulative capital costs for nuclear-fueled capacity were
$8.3 billion.
90-
80-
70-
60-
J5
"5
•o
to
0) 50-
o
40-
30-
20
10
85.67
6.12
12.55
Cumulative capital costs to install new coal-fired
generating capacity, 1976-2000
Cumulative costs for sulfur dioxide
control, 1976-2000
Cumulative costs for particulate
control, 1976-2000
54.70
15.05
67.0
8.71 42.23
4.71
7.12
49.22
84.94 46.7
40.94
30.4
7.98
36.3
Cumulative sulfur dioxide
and particulate control
costs
Scenario
BC
NG
CON
NF
Costs
billion $
18.67
13.76
11.83
12.92 26.2
% total
costs
21.8
25.1
28.0
Base Natural Conservation
Case Gas Emphasis
Substitution (CON)
(NG)
Coal-
fired
\
Nuclear-
Fueled
Nuclear Fuel Substitution (NF)
EMPLOYMENT. Since coal-fired power plant construction and operation would not
increase rapidly under the fuel substitution and conservation scenarios,
neither would related employment under any of these cases. Compared to the
coal-dominated base case, for example, the number of construction and
operation workers needed would be much lower (see figure ES-16). However,
employment needs related to the increased use of natural gas, nuclear power,
or alternative fuels were not calculated; in fact, these needs could
compensate for the lower demand for coal-fired power plant workers. '
Again because fewer coal-fired generating facilities are sited and
because growth is lower in all sectors, less coal would be needed under all of
37
-------
Figure ES-1 6
Construction Workers, Base Case, Fuel Substitution Scenarios, and
Conservation Emphasis Scenario, 1 975-95
17500-
15000-
fuel substitution case was not calculated. j/
VA'A^/V^V/^
\
\ /\
\ A / \
/ \ •' \
j V*,\. /\\ ' \ l^
r \**. «*••»*•. ••^. ^X*^ \ •/ ''•
\ // \ : \ ..-NG
V \\ , / "\---"
:: ^--Tvx /A
'; / \ •• / / ^
!- / Vi/ X
': .-' \
\
Natural laas ouustitution (No) \
Alternative Fuel Substitution (AF) v^%>-.- CON
Conservation Emphasis (CON)
1975 1980 1985 1990 1995
the fuel substitution and conservation scenarios than under the coal-dominated
cases, although such coal demand would be somewhat higher than at present (see
table ES-1). Thus, coal-mining employment for all purposes would increase
from current levels at a slower rate under the substitution and conservation
scenarios. Moreover, if county-level population increases should exceed the
employment increases, negative county-level impacts that might have been
avoided under coal-dominated scenarios might be felt under the substitution
and conservation cases.
WATER. Regional water quality impacts would be about the same under both the
fuel substitution and conservation scenarios and the coal-dominated scenarios.
In fact, no changes would be registered in base case protection levels and
base case aquatic habitat impacts for any river under any of the fuel
substitution and conservation scenarios. This across-the-board similarity, as
38
-------
discussed previously (see sec. 6.3)> results primarily from high background
concentrations alone or in conjunction with municipal and industrial
consumption. In comparison, power plant consumption would have only an
incremental impact on most of• the streams under all scenarios.
10. INSTITUTIONAL CONSIDERATIONS; NUCLEAR ENERGY, ALTERNATIVE FUELS,
AND CONSERVATION
It is considered unlikely that either nuclear energy or alternative fuels
will contribute substantially to energy supplies in the ORBES region or the
nation, at least by the end of this century. One reason is that a major
increase in the proportion of electricity generated by nuclear fuels is not
expected to occur in the coal-dominated ORBES region. A second reason is that
a major shift to alternative fuels would require more extensive technological
and institutional changes than are considered possible in the next 20 years.
However, conservation could make significant inroads by the end of the
century. Conservation would require improvements in end-use efficiencies and
changes in lifestyle, but no radically new technologies. (Existing
institutional mechanisms would be adequate to handle a major increase in the
use of natural gas.)
NUCLEAR ENERGY. Within the ORBES region, opposition to the use of nuclear
energy for electrical generation is particularly visible in Kentucky,
Pennsylvania, and West Virginia. Among the factors leading to this opposition
are the doctrine of federal preemption, controversy over the health effects of
low- and high-level radiation, and growing dissatisfaction with the economics
of nuclear energy.
With regard to preemption, the central, unresolved question is whether a
state may legally pass legislation to control the placement of nuclear
facilities or the transportation or storage of nuclear materials within its
borders. With regard to the economics of nuclear-fueled generation, nuclear-
fueled units are slightly more expensive to build than are coal-fired units
under the current fiscal and regulatory schemes prevalent in the ORBES region.
In addition, at least in a representative portion of the region, the cost
advantage of coal would be substantially greater without present federal tax
and other fiscal policies that favor capital-intensive production (including
the nuclear industry).
ALTERNATIVE FUELS. The alternative fuels case considers the partial
substitution of direct and indirect solar energy processes for coal-fired
electrical generation in the ORBES region.
Solar Energy. Three broad groups of institutional issues are associated with
the introduction of solar energy: legal and physical access to sunlight,
39
-------
integration with existing energy infrastructures and institutions, and
government program implementation and management.
The solar access barrier stems from the basic orientation of real
property law toward the development of land. That is, the potential investor
in a solar energy system is not guaranteed permanent access to sunlight.
Changes in nuisance law, zoning, solar easements, and restrictive covenants
offer possible remedies. At present, limited solar access laws have been
enacted in Illinois and Ohio.
The integration of solar energy systems into existing energy
infrastructures and systems raises a number of issues, including (1) the rates
paid by utilities for power sold to the grid as well as for back-up power and
other services provided to on-site generators, (2) the legal status of on-site
generators, (3) the financing and ownership of dispersed capacity, and (4)
utility management problems and perceived risks. The first two issues are
dealt with in part by the Public Utility Regulatory Practices Act of 1978
(PURPA), part of the National Energy Act. The third issue is handled somewhat
by the National Energy Conservation Policy Act. For the fourth issue to be
dealt with, utility management techniques would have to change to accommodate
a transition to dispersed capacity.
Finally, the present management of government solar programs is hampered
by a number of deficiencies within the Department of Energy's Conservation and
Solar Energy Programs, such as a constantly changing organizational structure.
Wind Energy. As with solar and other dispersed electric energy systems, the
widespread introduction of wind energy conversion systems would raise a number
of legal and institutional issues. These include financing, siting, tort
liability, and environmental problems.
Biomass. Although biomass is a promising energy source for the ORBES region,
its use on a wide scale also would entail the solution of unresolved
institutional questions. An issue common to all bioenergy sources is the need
to develop programs to provide information and technical assistance to
bioenergy users. Also needed is the establishment of reliable supply
infrastructures for direct energy uses of biomass resources. In both public
and private operations, long-range energy and resource planning and proper
resource management would have to take place. Institutional changes would be
required to link bioenergy to conventional energy supply infrastructures and
users. For example, where biomass is used to produce electricity, provisions
must be made to sell surplus power to the grid at equitable rates and to
supply back-up power to producers of bio-electricity. Finally, federal
administration of bioenergy research, development, and implementation would
have to be improved.
-------
Each form of biomass entails additional issues. The primary
institutional issue associated with the use of wood as energy is the
management and care of the resource base, that is, forest lands. The primary
institutional issues associated with intensive agricultural production for
energy are the integration of energy demand for crops into existing markets
and the potential for environmental damage. The use of municipal solid wastes
for energy raises institutional issues related to the removal of barriers to
resource recovery.
CONSERVATION. Only one conservation measure—cogeneration—was quantified for
use in an ORBES scenario. Economic factors are the primary institutional
considerations associated with the introduction of cogeneration by industries,
notably the rate of return on investment in cogeneration technology. The most
important cost consideration is the savings realized from cogeneration when
compared with the alternative costs of separate operations for in-house steam
production and purchased electricity. Other concerns are effects on the
environment and potential regulatory constraints.
11. CONCLUDING NOTE
One important insight gained by the ORBES researchers is that the study
region, part of which is known popularly as the Ohio River valley, is far more
diverse than they had suspected and probably more so than most public
officials realize. Failure to recognize this diversity most certainly will
doom to failure any attempt at basinwide institutional innovations. There is
indeed balkanization within the ORBES region, and with a continued emphasis on
coal, ideological divisions probably will become more pronounced.
The local and long-range transboundary movement of air pollutants across
state lines is the single issue within the broad context of continued (and
perhaps increased) reliance on coal that could produce the most conflict.
Since ORBES began in 1976, this issue has gained increased attention in the
region. It affects employment levels in the coal-mining industry as well as
in industry in general. It triggers emotions that are easily translated into
political controversy.
But many of the ORBES researchers—air pollution experts, economists,
lawyers, political scientists, and others—believe that institutional
mechanisms can be devised that will permit the region to enjoy the benefits of
both reasonably clean air and a degree of economic growth. The creation of
such mechanisms will require the highest technological competence, as well as
social and political imagination. If there is any single finding of the Ohio
River Basin Energy Study, it is that steps toward both clean air and economic
growth in the region can be taken only if ways can be found to unite the
various factions. Many residents of the region have recognized this reality,
but they remain separated by ideology. Some believe that the steps should be
41
-------
initiated by government, while others favor action within the private sector.
It is not the responsibility of ORBES researchers to recommend which path
should be followed. But it is our responsibility to warn that inaction could
result in economic stagnation and accompanying social problems capable of
draining much-needed vitality from the region and from the nation at-large.
-------
Main Report
-------
INTRODUCTION
1. ORBES Background and Organization
The Ohio River Basin Energy Study (ORBES) began in the fall of 1976 in
order to assess the potential environmental, social, and economic impacts of a
proposed concentration of power plants in a portion of the basin. At that
time, the U.S. Environmental Protection Agency (EPA) awarded grants to faculty
members from a group of universities in the basin states of Illinois, Indiana,
Ohio, and Kentucky. As the investigation progressed, researchers from
universities in Pennsylvania and West Virginia were added to the study group.
Experts from outside the academic community also took part throughout the
project.
In 1975, the U.S. Senate Appropriations Committee had directed EPA to
carry out such a study. It was not long after the Arab oil embargo (1973-74),
and a number of electric utilities had announced plans to construct additional
generating units in the Ohio River Basin and in nearby areas that share its
fuel supply. The Ohio River region offers electric utilities and related
industries some of the nation's most suitable sites. Coalfields that contain
almost half the tonnage of national reserves are within easy reach. Adequate
water for cooling also is available in the area, and regional waterways
provide good fuel transportation routes. Finally, in sparsely populated areas
of the basin, large generating facilities can be constructed without
displacing as many residents as they would in urban areas.
In the fall of 1974, publicity was given to plans by electric utility
companies to locate coal-fired plants on a 100-mile reach of the Ohio River
from Louisville, Kentucky, northward and eastward to Cincinnati, Ohio, and
beyond. Utility planners and observers from related industries, such as coal
producers, viewed the plans as consistent with emerging national energy
policies for dealing with increased fuel prices and with such external
disruption of the fuel supply as had just been experienced during the oil
embargo. From the perspective of these sectors and others, the expansion of
the nation's coal-fired capacity is 'essential if the U.S. standard of living
and quality of life are to be maintained. Citing such examples as the high
production efficiency that is dependent on energy-intensive machines and the
air conditioning that is vital to the elderly, they state that continuation of
the present national standard of living and quality of life is tied to the
availability of energy.
45
-------
In contrast to this view, some citizens in the Ohio River region became
increasingly concerned about the effects of the announced units and questioned
the necessity for such expansion. In late 1974, Public Service Indiana
announced that it would build a nuclear-fueled facility, the Marble Hill
plant, on the Ohio River between Louisville and Cincinnati. Citizen concern
intensified. Over the six years since this plant, now under construction, was
announced, controversy has grown. Citizens opposing this and other proposals
have questioned the necessity of adding such a large number of generating
facilities on the Ohio River itself, which already contains almost 40 percent
of the capacity in the six states that border the river—Illinois, Indiana,
Kentucky, Ohio, Pennsylvania, and West Virginia. Opponents have pointed out
that the proposed new plants would transmit much of their electricity far from
the immediate area.
In an effort to identify the implications of locating future energy
conversion facilities in this particular part of the Ohio River Basin, the
Senate Appropriations Committee directed EPA to conduct a study,
"comprehensive in scope, investigating the impacts from air, water, and solid
residues on the natural environment and [on the] residents of the region. The
study should also take into account the availability of coal and other energy
sources in this region."
The region investigated in this report is somewhat different from that
studied when the project first got underway. The Senate committee had called
for a study of "the proposed concentration of power plants along the Ohio
River in Ohio, Kentucky, Indiana, and Illinois." Phase I of the Ohio River
Basin Energy Study focused on portions of these four states. Findings were
integrated in a summary publication.
Although the present report expands on the findings of Phase I, it deals
primarily with the second phase of the project. Phase I researchers were
aware that a study of the "lower Ohio River Basin" in the four states noted in
the Senate committee report meant an emphasis on the Eastern Interior Coal
Province, approximately located in western and southern Illinois, southern
Indiana, and western Kentucky. Thus, the boundaries of the ORBES Phase I
study region extended northward and westward beyond the Ohio River Basin to
include most of the province. Excluded was the northern tier of industrial
1 The mandate appears in U.S. Congress, Appropriations Committee, 94th
Congress, 1st Session, Senate, Department of Housing and Urban Development-
Independent Agencies (Senate Report 940326, 1975).
2 See James J. Stukel and Boyd R. Keenan, ORBES Phase I: Interim
Findings. Citations to all ORBES reports appear in Appendix B.
46
-------
counties in Illinois, Indiana, and Ohio. The region covered approximately
152,000 square miles, including some coal-laden land actually outside the
drainage basin. Because only a small portion of the Appalachian Coal Province
was included in the Phase I region, utility leaders, state and federal
government officials, and university researchers objected to the boundaries.
They felt that the study region should be extended to the headwaters of the
Ohio River. Thus, at the beginning of the second phase of ORBES, the region
was expanded by about 38,000 square miles to include the southwestern portion
of Pennsylvania and virtually all of West Virginia (see figure 1-1). The
relationship of the Phase II region to the Eastern Interior and Appalachian
coal provinces is shown in figure 1-2.
ORBES Phase II began in the fall of 1977; active research concluded in
early 1980. As in Phase I, the project management team included the EPA
project officer, other officials of the agency, and two of the university
researchers. These two faculty members coordinated the activities of a core
team of researchers (on which they also served), the project advisory
committee, and support researchers. See Appendix A for rosters of each of
these groups.
-------
Figure 1-1
Ohio River Basin Energy Study (ORBES) Region
Rgure1-2
ORBES-Region Coalfields
-Eastern
Interior
Coal Province
Appalachian
Coal Province
-------
2. Policy Issues
In accordance with its congressional mandate, the Ohio River Basin Energy
Study identified a number of environmental, economic, and social issues
associated with increased coal-fired electrical generation in the region of
concern. All of these issues relate to the policy assumptions made during the
study, which are discussed in chapter 3 in the context of the overall approach
to the ORBES assessment. The present chapter deals with the major policy
issues and the major energy and environmental laws considered in the study.
2.1 Air-Related Policy Issues
Air quality is of major importance in the ORBES region because of the
regional emphasis on coal-fired electrical generation. The key air quality
issue is the local and regional effects of changes in pollutant concentrations
as a result of different levels of electric generation and different control
technologies.
Related directly to the key air quality issue are such factors as
emission limitations, generating unit retirement schedules, and other factors,
as well as a variety of economic and social issues. These social and economic
issues include the cost of electricity to the consumer, capital costs for
pollution control devices, mortality related to air pollution, and losses in
agricultural output as the result of air pollution.
CLEAN AIR ACT. The first federal legislation concerned with air quality was
the Air Pollution Control Act of 1955. At present, the governing federal law
is the Clean Air Act (42 U.S.C. 1857 et seq.), a sweeping national approach to
the control of air pollution. The act is implemented by the U.S.
It is recognized, of course, that a variety of other issues and laws
are of present or potential importance in the ORBES region. Among these
statutes are the National Environmental Policy Act (42 U.S.C. 4321 et seq.),
the Resource Conservation and Recovery Act of 1976 (42 U.S.C. 6901 et seq.),
the Energy Supply and Environmental Coordination Act (P.L. 93-319 as amended
by P.L. 94-163 and P.L. 95-70), and the Powerplant and Industrial Fuel Use Act
of 1978 (P.L. 95-620).
49
-------
Environmental Protection Agency in cooperation with the states. Passed in
1963, the Clean Air Act has been strengthened considerably by a series of
amendments, particularly those passed in 1970 and 1977.
The fundamental concept behind the 1970 and 1977 amendments is that the
federal government has the responsibility (assigned in the amendments to EPA)
to set national ambient air quality standards (NAAQS) as well as standards for
the control of emissions from new sources of pollution. These standards set
limits for concentrations in the ambient air (free-flowing air outside
buildings) of certain air pollutants, known as criteria pollutants. These
concentration limits are stated in parts per million or micrograms per cubic
meter.
In partnership with EPA, each state is to develop a specific strategy to
ensure that federal standards will be achieved in all areas of the state.
These strategies are known as state implementation plans (SIPs). If a state
does-not develop an implementation plan, EPA will develop a plan for achieving
the standards within that state. Each SIP must contain emission limitations
for each major emission source in the state, set either on a case-by-case
basis or by source category. SIPs also must ensure that full compliance with
NAAQS must be achieved by 1982, with some exceptions made for two criteria
pollutants. As of September 1980, EPA had approved all sections of the state
implementation plans developed by two of the six ORBES states—Illinois and
Indiana.
At present, EPA has set NAAQS for seven criteria pollutants: total
suspended particulates, sulfur dioxide, oxides of nitrogen (expressed as
nitrogen dioxide), hydrocarbons, photochemical oxidants, carbon monoxide, and
lead. Significant amounts of sulfur dioxide and nitrogen dioxide, as well as
an appreciable fraction of fine particulates, are emitted by coal-fired plants
and other coal-fired industrial sources. The four other criteria pollutants
are primarily products of transportation. Other potentially harmful compounds
that are not regulated nationally are formed through chemical transformation
of criteria pollutants. For example, sulfates are formed by the
transformation of sulfur dioxide.
Each criteria pollutant must meet two types of standards: primary
standards, which are intended to protect human health, and secondary
standards, which are intended to protect the public welfare (defined as
including property, soil, vegetation, scenic value, and other effects not
related directly to human health). Depending on the pollutant, these two
types of standards are broken down further into annual average, 1-hour, 3-
hour, 8-hour, and/or 24-hour concentrations. EPA standards for 1-hour, 3-
hour, 8-hour, or 24-hour concentrations of criteria pollutants in the ambient
air may not legally be exceeded more than once a year at any one location.
50
-------
New stationary sources of pollution are required to meet emission
standards set for a number of individual source.categories—such as those set
for the fossil-fueled power plant category—based on when their construction
began. These standards are known as new source performance standards (NSPS).
In the fossil-fueled power plant category, NSPS apply to sources on which
construction began between 1971 and 1978 and are designed to limit the
emissions from each new plant according to the type of activity and the size
of the plant. Standards stricter than the NSPS apply to sources under
construction after August 1978. In this report, these standards are referred
to as revised new source performance standards (RNSPS).
To aid the states in developing and carrying out the SIPs, EPA has
formally designated attainment and nonattainment areas according to whether or
not these areas meet primary and/or secondary standards. Within nonattainment
areas, emission offset provisions are in effect. This means that a new source
cannot - be built unless it obtains from existing sources in the area an
emission reduction that is equal to or greater than its own expected
emissions. Thus, over time, attainment status will be achieved and air
quality in the area will improve. If violations of a state implementation
plan are widespread, EPA can enforce any SIP requirement by issuing an order
to comply, bringing a civil action, and/or prohibiting the construction or
modification of a major stationary source of pollution in the area.
The original design of the Clean Air Act provided that all areas of the
country would have the same NAAQS. However, this design permitted pollutant
emissions to increase considerably in areas with very clean air. Judicial
interpretation and the 1977 amendments changed this design. Prevention of
significant deterioration (PSD) requirements now are prescribed. Under the
PSD requirements, new facilities in areas where air quality is above that
specified by NAAQs are subject to extensive preconstruction review and permit
requirements, including maximum allowable increases, or increments, in ambient
concentrations of pollutants from those facilities. Special protection is to
be given to visibility near selected federal lands, such as national parks,
but this provision is not yet implemented fully.
2.2 Land-Related Policy Issues
Land is another environmental receptor that raises issues in the ORBES
assessment. These include land displacement for energy-related uses, the
effects of air pollutants on plant species, and the effects of energy
facilities on terrestrial ecosystems.
SURFACE MINING ACT. The Surface Mining Control and Reclamation Act (30 U.S.C.
1201), passed in 1977 and administered by the Department of the Interior, is
the major federal law that governs coal surface mining. This act is based on
the premise that surface mining is only a temporary use of the land and that
51
-------
other beneficial uses should follow. The law is intended to change coal-
mining practices that entail severe social and environmental costs and to
prohibit mining operations in areas that cannot be reclaimed. However,
because of revisions to the regulations promulgated under the law since its
enactment, as well as because of continuing litigation over certain aspects of
the act, the final way in which this legislation will be enforced is unclear.
In accordance with the act, state permits for new coal mines must include
comprehensive performance standards for surface mining operations and for the
surface effects of underground mining. These standards are intended to
prevent adverse effects on the environment, such as subsidence, ground and
surface water contamination, and degradation of land quality. Thus, before a
permit can be obtained, the mining operator must demonstrate that the land can
be restored to a postmining land use that is the same as or of higher quality
than its premining use. Until these state permit programs are in force, or in
the event of a state's failure to establish an adequate program, the federal
government retains regulatory authority.
Also in accordance with the surface mining act, states must institute a
planning process for the designation of areas unsuitable for all or certain
types of surface mining. Among such areas are those where reclamation would
not be technically or economically feasible; where it would not be compatible
with existing land use plans; where it would adversely affect important
historic, cultural, scientific, or aesthetic values; where it would result in
substantial loss of or reduction in long-range productivity of water supplies
or food or fiber products; and where it would endanger life or property in
areas subject to flooding or unstable geology.
Finally, the act establishes a fund for the reclamation of abandoned
mines and prohibits surface mining on federal land valuable for recreation or
for other purposes, such as national forests, except for valid existing
rights.
2.3 Water-Related Policy Issues
Because of the amount of water required from streams to cool power plant
boilers, this environmental medium also is of primary importance to the ORBES
assessment. The key policy issues are the availability of water, water
consumption by electrical generating facilities, the effects of consumption on
effluent concentrations (which increase as the quantity of water decreases),
and the effects of effluent concentrations on aquatic habitats.
CLEAN WATER ACT. The Clean Water Act (33 U.S.C. 125) contains numerous
provisions that apply to the use of water for the extraction of fossil fuels
and the generation of electricity. The 1972 amendments to the act continued
the existing requirement that states establish water quality standards for
52
-------
their interstate waters and broadened this requirement to include intrastate
waters. Each state must classify the desirable uses of its waters and define
the pollutant concentrations that may not be exceeded in order for these
desirable uses to continue without hindrance.
The National Pollution Discharge Elimination System (NPDES) is the means
for ensuring that individual dischargers comply with effluent limitations set
under the Clean Water Act. Every facility that discharges effluents into
navigable waters must receive a permit that specifies the minimum effluent
requirements. EPA may delegate the authority to issue these permits to the
states, although it retains the authority to review permits. As of March
1980, the ORBES states of Illinois, Indiana, Ohio, and Pennsylvania were
responsible for administering their programs, while permits still were issued
by EPA in Kentucky and West Virginia. These individual source permits specify
effluent limitations by pollutant, derived from the limitations established by
EPA or from classifications of desirable use established by the state,
whichever is more stringent. However, stricter limitations can be imposed if
they are necessary to achieve a state's water quality standards.
The 1972 amendments set forth water pollution control standards to be met
by all effluent dischargers by 1977- In addition, the amendments established
more stringent standards, to be met by 1983. Both sets of standards included
a combination of water quality standards and technology standards. The
technology standards required that, by 1977, every discharger install
equipment representing the best practicable control technology. By 1983,
dischargers were required to install additional equipment representing the
best available technology that is economically achievable. Additional
amendments in 1977 changed the requirements for 1983. First, the deadline was
postponed until July 1984. Second, the best available technology requirement
was replaced with a more complicated formula. The best conventional
technology (stricter than the best available technology) is required for
certain conventional pollutants. The best available technology is required
for toxic pollutants. The best available technology also is required for
certain other pollutants (subject to possible extension of the deadline to
July 1987).
2.4 Social Policy Issues
The public and occupational health consequences of energy development, as
well as the employment requirements associated with energy facilities, are
major social policy issues. These include death, disease, and disability
related to coal conversion and nuclear generation; occupational death,
disease, and disability from the mining, processing, and transportation of
fuels; and labor demand for coal mining and for power plant construction and
operation.
53
-------
MINE HEALTH AND SAFETY ACT. The most recent expression of congressional
intent to remedy unsafe working conditions and practices in mines and thereby
reduce the number of mining fatalities and injuries is the Federal Mine Health
and Safety Act (30 U.S.C. 801), enacted in 1977. This act is based on the
1969 Federal Coal Mine Health and Safety Act. The 1977 act incorporates many
of the provisions of the 1969 act—such as those that deal with mandatory
health and safety standards and with black lung benefits—but increases the
level of protection for miners. Under the 1977 act, standard-setting and
enforcement procedures are made uniform throughout the mining industry, while
the standards themselves reflect the characteristics of different segments of
the industry. Each step in the standard-setting and revision process requires
compliance within a specific period, and enforcement timetables are more
rigorous than in previous legislation. Provisions also are made for training
courses for new miners and refresher courses for experienced ones. During
these courses, workers receive their normal rates of pay and are compensated
for any costs incurred while attending the training.
The Department of Labor administers the law. The Federal Mine Safety and
Health Review Commission, an independent adjucticatory authority, provides due
process. Affected miners or their representatives can participate in the
conmission's proceedings.
2.5 Other Policy Issues
A secondary set of issues considered in the ORBES assessment concerns a
possible decrease in coal use due to the partial replacement of coal by other
fuels or by conservation measures. One substitution fuel_is natural gas, not
as a utility boiler fuel, but as a replacement for electricity in other
sectors. Nuclear fuel constitutes a direct substitution for coal in the
generation of electricity. Alternative sources of energy, such as biomass,
solar energy, and wind, also could lower the demand for coal-fired generation.
Finally, conservation could decrease the demand for all fuels, including coal.
The orientation of the ORBES region to coal for electrical generation is
unlikely to change significantly within the next 20 years.2 Toward the year
2000 and beyond, however, fuel substitutions could begin to decrease the
regional coal emphasis, although significant change is considered unlikely by
many. On the other hand, conservation could make major inroads before the end
It is extremely likely that synthetic fuels made from coal will become
increasingly important in the ORBES region. However, a full-fledged synthetic
fuel industry probably could not be in place within the next 20 years, which
is the time frame of the ORBES study. Thus, synthetic fuels were not
considered in the analysis.
-------
of the century, although a variety of institutional problems exist.
Therefore, the emphasis in the examination of the fuel substitution and
conservation scenarios is on the institutional barriers to their
implementation.
2.6 Underlying Methodological Issues
It is recognized that the choice of policy issues, and indeed the ORBES
study as a whole, could be affected by methodological fallacies.3 Such
fallacies are common in research, which is one activity among many social
decisionmaking processes.
Three possible methodological fallacies are termed the appeal to the
people, also called the fallacy of consensus; the appeal to authority; and the
argument from ignorance, or proceeding without all the facts. Ideally, the
selection of a policy issue or of any research direction should be valid
either because of empirical evidence or the logical inferences on which it is
based. It should not be considered valid because of the number or authority
of those who support it. The opinion of the majority may be wrong, and
consensus is logically irrelevant to the truth of the statement in question.
The conclusions of authorities in a given field also may be wrong, and these
conclusions should be checked by the replication of data.
The most troublesome methodological problem, but an unavoidable one, is
the argument from ignorance. The choice of a policy issue should not be
considered valid because it is assumed so until proven otherwise. Several
examples illustrate this problem in the case of ORBES. First, the impacts of
nuclear-fueled electrical generating units are evaluated without knowledge of
the health effects of low-level radiation. Similarly, the effects of such
radiation from the burning of coal are unknown. On the other hand, the health
benefits from electricity—such as its use for life support systems and air
conditioning—are not entirely clear. Moreover, the contribution of coal-
generated carbon dioxide emissions to concentrations of this pollutant in the
atmosphere is not understood. The argument from ignorance also is committed
when high electrical energy growth rates are projected without information on
whether there is need for the electricity that would be generated by increased
numbers of power plants. Nor is there information about what would occur if
this electricity were not generated. In addition, whether utility expansion
contributes to overall economic growth is unknown. Finally, without adequate
information on the need for additional plants, decisions on the taking of land
by means of eminent domain are made in ignorance. Also unknown are the
o
J For discussion, see Preliminary Technology Assessment Report. vol. II-B
(ORBES Phase I).
55
-------
effects on society as a whole if sites for power plants could not be acquired
through eminent domain and if these plants were not built.
It is acknowledged that during the course of ORBES many judgments were
made based on inadequate data. This problem was inescapable, as it is in any
research exercise, or indeed any decisionmaking process.
56
-------
3. Assessment Approach and Report Organization
3.1 Assessment Approach
The approach taken in the Ohio River Basin Energy Study was that of a
technology assessment. The objective was to analyze a broad range of
environmental, social, economic, and institutional effects associated with
possible energy development in the study region. The primary focus was on the
consequences of coal use within the region for the generation of electricity.
This focus reflects both the congressional mandate for the study and existing
fuel use patterns (see section 4.1).
A variety of scenarios, all regionally based, are presented and analyzed
in this report. Each scenario is an "as if" statement that does not predict
what will occur. Rather, a scenario represents what one future might be like
if assumed conditions are present in the ORBES region. As mentioned above,
the analysis emphasizes those scenarios in which the continued use of coal in
the region through the year 2000 is assumed. However, there are a number of
variations in the paths entailing coal emphasis, such as the degree of
strictness of environmental regulations and the rate of electrical energy
growth. Whatever the distinguishing feature of a scenario, the scenario is
cast in terms of the study region, not the United States as a whole or the six
ORBES states.
It also is important to note that the impacts of the various scenarios
are not intended to form the basis for regulatory action. Rather, these
impacts are discussed in terms of their overall policy implications. Even
though severe local problems might exist under a given scenario, the analysis
emphasizes impacts on a regionwide basis. Thus, the study results cannot be
applied directly to such activities as the writing of environmental impact
statements, which focus on specific sites.
Only potentially important impacts, both positive and negative, are
described in this report. Judgments were made in the course of the research
as to which impacts were worthy of analysis and presentation, and thus the
detail in which impacts are presented varies among scenarios. Moreover, the
study results are not presented with the same exactitude as they would be in a
scientific journal; the intent is to inform policymakers of the possible
57
-------
consequences of a range of hypothetical futures. In addition, the analysis
emphasizes extreme, but possible, natural conditions—for example, 7-day-10-
year low flow conditions and adverse meteorological conditions. The impacts
identified for each scenario are divided into the issue areas discussed in
chapter 2: air and associated economic questions; land and associated
economic questions; water; employment; and health.
In order to develop the scenarios, it was necessary to delineate base
period conditions in the ORBES region. In general, the base period is the
mid-1970s. The scenarios then were developed by means of a regional energy
and fuel demand model. This model can take into account alternative policy
specifications for future conditions, such as interfuel substitution and
technological change. Among the outputs of the model are the regional energy
and fuel use requirements by end user that are associated with various levels
of economic activity. These requirements are necessary information for
application of a model to site central station coal-fired and nuclear-fueled
electrical generating unit additions in the study region from 1976 through
2000.
Figure 3-1 depicts regional electrical generating capacity as of December
31, 1976. Units announced by the electrical utilities, both coal fired and
nuclear fueled, were assumed to come on-line as scheduled through the mid-
1980s. For each scenario, "standard" units were projected—650 megawatts
electric for each coal-fired unit, operating at a 50 percent capacity factor,
and 1000 megawatts electric for each nuclear-fueled unit, operating at a 65
percent capacity factor. However, nuclear-fueled units beyond those scheduled
were sited in only one scenario (see chapter 13).
Throughout this report, references to the more specialized documents in
the ORBES series are only by author and title. These other reports should be
consulted for documentation of results.
2
Because of the large number of researchers in different disciplines, it
was not possible to investigate all base period conditions in terms of a
single year; the best data bases available varied among disciplines. However,
the conditions of most interest are projected to the year 2000.
3 See Walter P. Page, Doug Gilmore, and Geoffrey Hewings, An Energy and
Fuel Demand Model for the Ohio River Basin Energy Study Region (ORBES Phase
II).
See Gary L. Fowler et al., The Ohio River Basin Energy Facility Siting
Model: Methodology (vol. I) (ORBES Phase II).
58
-------
Rgure 3-1
Electrical Generating Capacity,
ORBES Region, 1976
Megawatts
3001 or more
2001-3000
1001-2000
501-1000
101- 500
1- 100
0
The necessary number of standard units were sited to meet the final
energy demand projected for each scenario by the energy and fuel demand model.
The siting model was used to locate these units at the county level, in
accordance with scenario policies in selected impact or issue areas. A
generating unit lifetime of 35 years was assumed for all but one scenario.
Nine scenarios are presented and analyzed in this report; their major
policy variables are discussed in chapter 5, which describes the coal-
dominated scenarios, and chapter 13, which describes the fuel substitution and
conservation scenarios. Impacts are presented in detail for those scenarios
that call for the continued use of coal in the region through the year 2000
(chapters 6 through 11). Impacts of the remaining cases are examined in less
detail (chapter 14).
See Gary L. Fowler et al., The Ohio River Basin Energy Facility Siting
Model: Sites and On-Line Dates (vol. II) (ORBES Phase II).
59
-------
Among the five coal-dominated futures, the conditions emphasized consist
of, respectively, (1) "base case" environmental regulatory policies, fuel use
patterns, and economic and energy growth rates in the ORBES region, (2) more
stringent environmental regulations, (3) less stringent environmental
regulations, (4) high electrical energy growth, and (5) exports of electricity
from the ORBES region. The scenarios calling for partial coal substitution
emphasize (1) the use of natural gas wherever possible, although not as a fuel
for the generation of electricity, (2) the use of nuclear fuel, and (3) the
use of less conventional energy sources. The final scenario assumes a
regional emphasis on energy conservation, which also would lessen the demand
for all fuels, including coal.
Impacts of the coal-dominated base case in the year 2000 are compared
with current conditions in the ORBES region (that is, the mid-1970s). In
general, impacts of the other cases are contrasted with those of the base case
and with each other, not with conditions during the base period. Certain
special cases, variations of the major scenarios, also are discussed.
3.2 Report Organization
The substantive chapters in this report contain a description of base
period conditions in the ORBES region, presentations of the various scenarios
and their impacts in 1985 and 2000, and discussions of policy considerations
associated with the scenarios. In chapter 4, base period regional conditions
are delineated in eight areas, primarily as they relate to the production and
use of electrical energy in the region. The topics covered are regional
energy and fuel use patterns (section 4.1), the regional economy (section
4.2), air quality (section 4.3), water quantity, water quality, and aquatic
ecology (section 4.4), land use and terrestrial ecology (section 4.5), public
and occupational health (section 4.6), social conditions in the region
(section 4.7), and social values (section 4.8). The presentation of current
conditions serves as an introduction to consideration of the scenarios
(chapters 5 and 13) and of the impacts that would result from each scenario
future (chapters 6, 7, 8, 9, 10, 11, and 14).
Chapter 5 describes the five scenarios that emphasize regional coal use
for the generation of electricity. Two basic parameters, environmental
regulations and regional electrical energy growth, are varied. In chapter 6,
the impacts are contrasted across scenarios in terms of air, land, water,
employment, and health. Economic impacts associated with air and land are
Alternative designations for the various scenarios as used in other
ORBES reports appear in Appendix C.
60
-------
discussed in these topical areas. Impacts by scenario then are treated in
chapters 7 through 11.
The first of these coal-dominated futures, discussed in detail in chapter
7, is termed the base case. As the starting point for the other scenarios, it
is the most fully analyzed future. In terms of environmental regulatory
policies, the regional economy, and regional energy and fuel use, the base
case is comparable to conditions in the ORBES region during the base period.
Therefore, the impacts in the various areas that would arise under base case
conditions in 1985 and 2000 are compared with base period conditions.
In chapter 8, the focus is on stricter environmental regulatory policies
than those of the base case. The scenario presented assumes that stricter
air, water, and land quality regulations will be in effect in the ORBES
region, while the moderate regional electricity demand growth and the coal
emphasis of base case conditions are maintained. Future impacts of the strict
environmental control case are contrasted with those of the base case.
In chapter 9, the policy examined is noncompliance with state
implementation plans (SIPs) for achieving clean air standards (see chapter 2)
along with a continued regional emphasis on the use of coal for electrical
generation. Impacts of the SIP noncompliance case, chiefly on air quality,
are contrasted with those of the base case.
In chapter 10, the effects of higher electrical energy growth than that
of the^ base case are considered. The emphasis again is on coal-fired
electrical generation. A high rate of regional electrical energy growth and a
45-year generating unit lifetime are assumed. (In all other cases, a plant
lifetime of 35 years is assumed.) The high electrical energy growth rate is
based on projections of the National Electric Reliability Council (NERC). Two
variations also are presented. In the first, a 35-year generating unit life
is assumed under the same conditions of high electrical energy growth. In the
second, a policy of least sulfur dioxide emissions dispatch is assumed. That
is, the criterion for the order in which a generating unit comes on-line, or
is dispatched, is on the basis of the unit's expected emissions of sulfur
dioxide. In all other scenarios, the dispatching order is on the basis of
least cost—the usual utility practice.
The final coal-dominated scenario examined, in chapter 11, concerns a
major increase in the "export" of coal-generated electricity from the ORBES
region to the Northeast. Aside from the siting of an additional 20,000
megawatts of electrical generating capacity to be transmitted outside the
region, all conditions are identical to those of the base case.
As became clear from the analysis, the major policy implications of the
coal-based futures relate to regional air quality issues. Strategies to
61
-------
mitigate adverse impacts on air quality from electrical generating facilities
are discussed in chapter 12.
In chapters 13 and 14, the focus is on partial regional substitution for
coal by other fuels, as well as on energy conservation. The four scenarios
considered are described in chapter 13; their impacts are compared in chapter
14. The emphasis, however, is the institutional barriers and opportunities
associated with the implementation of these alternatives to coal; these
barriers and opportunities are the subject of chapter 15.
Finally, a concluding note presents the diverse perspectives in the ORBES
region and the relationship of these perspectives to regional economic and
environmental problems.
62
-------
4. Base Period Conditions in the ORBES Region
In this chapter, base period conditions in the Ohio River Basin Energy
Study (ORBES) region are delineated in eight areas: energy and fuel use
(section 4.1), the economy (section 4.2), air (section 4.3), land (section
4.4), water (section 4.5), health (section 4.6), social conditions (section
4.7), and social values (section 4.8). In general, the base period is the
mid-1970s. However, the years reported vary according to the availability and
quality of data. Base period conditions are presented primarily as they
relate to the production and use of electrical energy in the study region.
4.1 Energy and Fuel Use
COAL. Coal is both widely abundant and widely used in the ORBES region. It
is the only significant indigenous fuel in the region, and the region contains
a major portion of the nation's coal reserves. Coal is also the primary fuel
used within the region; the electric utility industry accounts for over two-
thirds of the regional coal consumption.
As noted in chapter 1, there are two extensive coal provinces in the
ORBES region. The Appalachian Province extends from western Pennsylvania and
eastern Ohio southwestward through West Virginia and eastern Kentucky into
Alabama. The Eastern Interior Province is located in Illinois, western
Indiana, and western Kentucky (see figure 1-2). These provinces have been
further divided by the U.S. Bureau of Mines (BOM). Seven BOM districts are in
the ORBES portion of the Appalachian Province and three BOM districts are in
the Eastern Interior Province, all of which is in the ORBES region.
The ORBES region contains an immense coal reserve base—193 billion tons,
or 45 percent of the national total by tonnage, and probably a majority on the
basis of heat value (Btu's). This coal represents 55 percent of the national
reserves recoverable by underground mining and 23 percent of the national
reserves recoverable by surface mining.
For more detailed information on the regional coal-mining industry,
consult David S. Walls et al., A Baseline Assessment of Coal Industry
Structure in the Ohio River Basin Energy Study Region (ORBES Phase II), and
63
-------
Great variability exists in the type of coal mined in the Eastern
Interior and Appalachian provinces. In general, the coal mined in the Eastern
Interior Province has a high sulfur content, while the Appalachian coal of
eastern Kentucky and southern West Virginia is low in sulfur. The
northwestern Appalachian coal of Ohio and northern West Virginia has a sulfur
content similar to that found in the Eastern Interior Province. The sulfur
content of most Pennsylvania coal is between that of the Eastern Interior and
that of the southern Appalachian coals. Similarly, the moisture and the ash
content of Eastern Interior coals tend to be higher than those of Appalachian
coals, and the Btu content tends to be lower.
In 1970, the ORBES portion of the Appalachian Province provided 65.3
percent of the total coal consumed in the ORBES region, while the Eastern
Interior Province supplied 34.2 percent. However, from 1970 to the present,
there has been a decline in the percentage of U.S. coal production supplied by
these two provinces. This decline is attributable to expanded production in
the West and to more stringent environmental controls. Among the ORBES state
portions, coal production has fallen most markedly in West Virginia, due
primarily to declining markets for metallurgical coal and to labor disputes.
It also should be noted, however, that coal markets are highly competitive
within the Eastern Interior and Appalachian Provinces.
Until 197^, U.S. underground mines produced more coal than did surface
mines. Since that year the opposite has been true. In the ORBES region,
however, underground mines still produce more coal, although the proportion
produced by surface mines is increasing. In the ORBES region in 1965,
approximately 30 percent of the active mines were surface mines; by 1975, this
figure had risen to 63 percent. In terms of numbers of mines, Kentucky,
especially the eastern part of the state, contributed most heavily to the
increase in surface-mining operations. However, despite a 90 percent increase
between 1965 and 1975 in the number of ORBES-region surface mines, the
percentage of production from these mines rose only 13 percent. The reason is
that many of the new surface mines are relatively small operations. Both the
number of regional surface mines and the amount of regional and national coal
production could be reduced by the implementation of the Surface Mining
Control and Reclamation Act of 1977 (see section 2.2).
As part of the ORBES project, deep mine costs were estimated and coals
were distinguished on the basis of sulfur categories that are assumed to
reflect low- and high-sulfur coals that might be used by existing SIP plants
Donald A. Blome, Coal Mine Siting for the Ohio River Basin Energy Study (ORBES
Phase II). For a discussion of regional energy and fuel use, see Walter P.
Page, Energy Consumption in the Ohio River Basin Energy Study Region. 1974. by.
End User and Fuel Type (ORBES Phase II).
-------
and by NSPS and RNSPS plants. A low-sulfur coal is defined as having 1.8
percent or less sulfur, and a high-sulfur coal as having more than 1.8
percent. In that context, economically recoverable reserves from deep mining
vary widely within the regional BOM districts. For example, one BOM district
in the Appalachian Province has 88.6 percent of its deep mine reserves in the
economically recoverable low-sulfur category, compared with no such reserves
in a BOM district in the Eastern Interior Province. In the high-sulfur
category, economically recoverable reserves are 8?.5 percent of total deep
mine reserves for the same Eastern Interior district, but only 1.2 percent for
the same Appalachian district. The sulfur content of the remaining reserves
in these two districts is unknown. On the basis of classifying the various
districts in the region in terms of low-sulfur, deep-minable reserves, four
different producing areas within the ORBES region were identified and were
used to perform the scenario coal supply analysis.
When all end-use sectors are considered, coal use accounts for about half
of the total conventional fuel consumption in the ORBES region (see figure 4-
1).3 in comparison, coal use accounts for only about one-fifth of the total
conventional fuel consumption in the nation. The largest user of coal within
the region is the electric utility industry, which accounts for 67 percent of
the total coal used in the region. In comparison, the industrial sector is
the next largest user of coal and accounts for about 28 percent of the
regional coal consumption. However, the 67 percent consumed by the electric
utilities constitutes 95 percent of the fuels used for electrical generation
in the region (versus 51 percent in the nation). The 27 percent consumed by
the industrial sector accounts for only 48 percent of its total consumption.
ELECTRICITY. If all conventional fuels are considered, the electric utility
industry consumes about 34 percent of the regional total. Approximately 68
percent of this amount is used to generate electricity; in other words, it
takes approximately 2 Btu's of conventional fuels to produce 1 Btu of
electricity. Thus, 24 percent of the total regional consumption of
conventional fuels actually generates electricity.
p
See Walter P. Page, An Economic Analysis of Coal Supply in the Ohio
sin Energy Study Region (ORBES Phase II).
-' In this analysis, conventional fuels are defined as coal, petroleum
products, natural gas (all uses), plus hydroelectric and nuclear power for the
generation of electricity. Total final consumption is defined as consumption
in the residential-commercial, industrial, transportation, and miscellaneous
sectors, plus the use of energy and fuels for electric power generation
(including losses and omissions). See Page, Energy Consumption, for further
details on energy and fuel use.
65
-------
Rgure 4-1 Conventional Fuel
Consumption, ORBES Region
coal
petroleum products
natural gas
hydro/nuclear
48.6%
•30%
•21%
- 0.4%
In 1976 there were 83,125 megawatts electric of installed generating
capacity in the ORBES region. Slightly more than half of this regional
installed capacity is located in the first two rows of counties along the Ohio
River. As already emphasized, coal-fired facilities comprise the majority of
these facilities (see figure 4-2).
Rgure 4-2 Installed Electrical Generating
Capacity, ORBES Region, By Fuel Type
coal
oil-
nuclear
hydroelectric
unknown
natural gas —
waste fuel —
multifueled —
88.4%
- 5.8%
- 2.2%
-1.3%
-1.6%
- 0.4%
- 0.2%
-0.1%
See Steven D. Jansen, Electrical Generating Unit Inventory. 1976-1986:
Illinois. Indiana, Kentucky, Ohio, Pennsylvania. and West Virginia - (ORBES
Phase II).
66
-------
The ORBES region exports a large amount of the electricity it generates.
Net regional exports in 1974 totaled about 276 trillion Etu's, or 26 percent
of the electricity generated within the region. No OREES investigation was
conducted on the destination of electricity exports. It appears, however,
that since the six OREES states export only 7 percent of their electricity,
much of the electricity exported from the study region is used in the northern
portions of Illinois, Indiana, and Ohio; central and eastern Pennsylvania;
Maryland; and other east coast states.
Nonfossil fuels play an insignificant role in the CREES region. In 1974,
they equaled less than 1 percent of the total conventional fuel use in the
region—approximately the same percentage as in the six OREES states and the
nation.
A comparison of the OREES region and the six OREES states shows that the
region- accounts for about half of the six-state total consumption of
conventional fuels for all end-use sectors; that the region is highly
concentrated in the use of energy for electrical generation; and that the
region makes heavy use of coal as a primary fuel.
4.2 Economy
CONTRIBUTIONS TO GROSS REGIONAL PRODUCT. Manufacturing and trade are the two
sectors that contribute the most to the OREES gross regional product—about 31
and 16 percent, respectively.^ Seven other economic sectors in the OREES
region contributed from 3 to 12 percent each to the gross regional product
(see figure 4-3). However, although mining constitutes only 3 percent of the
gross regional product and agricultural activities constitute only 4.1
percent, these contributions are higher in the CREES region than they are in
the nation (1.6 and 3-2 percent, respectively).
Of the six ORBES state portions, the Ohio portion contributes the most to
the gross regional product—32 percent. The other five state portions
contribute from about 6 to 18 percent each. It should be remembered, however,
that large metropolitan areas of the OREES states of Illinois, Indiana, Ohio,
and Pennsylvania are excluded from the region. Thus, the gross product of an
ORBES state portion may be only a percentage of that state's overall gross
product. For example, whereas the ORBES state portion of Illinois contributed
c
Gross regional product information is based on 1975 data. For further
information on the regional economy, see Walter P. Page and John Gowdy, Gross
Regional Product in the Ohio River Basin Energy Study Region, 1960-1975 (OREES
Phase II).
67
-------
Rgure 4-3 Sectoral Contributions to
ORBES Gross Regional Product
manufacturing 30.7%
trade 16.2%
government 11.5%
finance, insurance, real estate 11.2%
services and other 10.1%
transportation, communication,
utilities 9.2% KSSS1 farm 4%
construction—4.1% CUD mining—3%
only 15.4 percent of the 1975 regional gross product, the state of Illinois
contributed 29.4 percent of the 1975 six-state gross product.
Since coal mining is closely tied to electrical generation in the ORBES
region, it is of interest to see how much this sector contributes to the gross
product of each state portion. Of the gross products of the six OREES state
portions in 1975, raining constituted the highest percentages in the West
Virginia portion (14.2 percent), the Kentucky portion (5.7 percent), and the
Pennsylvania portion (4.1 percent). Mining constituted only 2 percent of the
gross product in the Illinois state portion, 0.9 percent in the Ohio portion,
and 0.5 percent in the Indiana portion.
GROWTH IN GROSS REGIONAL PRODUCT. Between 1960 and 1975, the growth in gross
product in the OREES region was substantially less than the growth in the
gross products of the six ORBES states and the United States in the same
period. The overall gross regional product grew at an average annual
compounded rate of 2.47 percent while the six-state gross product grew at 2.82
percent and the national gross product at 3-26 percent. During this same
period, the most rapidly growing economic sectors in the ORBES region were
government (3-43 percent), transportation-communication-utilities (also 3-^3
percent), and finance-insurance-real estate (3.41 percent). These growth
rates were significantly higher than those of the remaining sectors; the
highest of these, the trade sector, grew by 2.80 percent.
In general, however, structural characteristics of the ORBES-region
economy—the proportion each sector contributes to the gross regional
product—remained stable during this period. The largest percentage increase
of a sector's contribution to gross regional product was only 2 percent (in
68
-------
the government sector), as was the largest decrease (in the construction
sector).
PER CAPITA GROSS PRODUCT. In 1975, per capita gross product in the ORBES
region was $5205 (approximately $7027 in 1979 dollars), or 8.6 percent less
than per capita gross product in the six ORBES states ($5695, or approximately
$7688 in 1979 dollars) and 6.7 percent less than per capita gross product in
the nation as a whole ($5578, or approximately $7530 in 1979 dollars).
4.3 Air
Since the passage of the Clean Air Act in 1963, and especially since the
amendments of 1970 and 1977, air quality in the ORBES region has improved (see
section 2.1 for a discussion of the Clean Air Act). However, air quality
measurements during the study's base period (the mid-1970s) indicate that air
quality standards are still not being met at several locations in the ORBES
region and that other locations could be close to violation. Here, the base
period trends of concern are delineated with representative examples.
COMPLIANCE WITH AIR QUALITY STANDARDS. Air quality measurements indicate that
sulfur dioxide pollution problems still exist in the region. In 1977, 11 of
the 423 ORBES-region counties violated the national ambient air quality
standards (NAAQS) for sulfur dioxide. An additional 13 counties did not have
available the full 24-hour prevention of significant deterioration (PSD)
increment for sulfur dioxide to accommodate new sources since the ambient
concentrations were at or just below the NAAQS. Most of the counties that
violated the NAAQS were clustered on the Ohio-Pennsylvania-West Virginia
border. However, since over 50 percent of the counties in the ORBES region
are without sulfur dioxide monitoring, the number of 1977 violations probably
are underestimated.
For further details, see James J. Stukel and Brand L. Niemann,
Documentation in Support of Key ORBES Air Quality Findings, and Teknekron
Research, Inc., Air Quality and Meteorology in the Ohio River Basin: Baseline
and Future Impacts, vols. I and II, respectively, of James J. Stukel, ed.,
Ohio River Basin Energy Study: Air Quality and Related Impacts. The 1977
concentration data for sulfur dioxide (and for total suspended particulates)
come from National Aerometric Data Bank monitors. The majority of the data
used as examples in this delineation of base period trends comes from this
latter system, as well as from the EPA's National Emission Data System, the
SURE Phase I project (April 1974, to March 1975), and the SURE Phase II project
(August 1977 to October 1978). The remaining data used as examples come from
such sources as the EPA/DOE Multi-State Atmospheric Power Production Pollution
Study, utility monitoring networks, and U.S. EPA Region III.
69
-------
Nearly four years (1974-77) of sulfur dioxide data from a utility
monitoring network located primarily along the Ohio River main stem further
indicate that many other areas in the region could be close to violations.
According to these data, about half the available annual air resource for
sulfur dioxide has been used up around this network in the vicinity of the
lower reaches of the Ohio River, and all or nearly all has been used up in the
vicinity of the upper reaches. Data from a more regional monitoring network
that were collected between August 1977 and October 1978 show that sulfur
dioxide annual averages throughout the rest of the region ranged from one-
fourth to one-third the annual standard.
The nonattairment of the standards for total suspended particulates (TSP)
also has been a problem in the ORBES region. Of the counties that had TSP
monitoring in 1977 (again about half), 130 violated the NAAQS for this
pollutant; an additional 5 counties had less than the full PSD increment
available. Moreover, many of the counties that violated the primary 24-hour
NAAQS for TSP were clustered in extreme southwestern Ohio and, again, along
the Ohio-Pennsylvania-West Virginia border.
SULFUR DIOXIDE EMISSIONS AND TRANSPORT. The ORBES region is an area of very
high sulfur dioxide emission density (mass per unit area). In 1975 the ORBES
states were 6 of 10 contiguous states east of the Mississippi River with
sulfur dioxide emissions greater than 1 million tons per year. There are 31
states in this area, and in 1975 their sulfur dioxide emissions ranged from
2000 tons (in Vermont) to 3.9 million tons (in Ohio). Moreover, in 1973, 15
air quality control regions (AQCRs) in the ORBES region (or almost 40 percent
of the AQCRs completely or partially in the region) had sulfur dioxide
emission densities greater than 10,000 kilograms per square kilometer (see
figure 4-4).7
The primary sources of regional emissions are large, isolated point
sources (usually power plants) or complexes of urban and industrial sources.
However, coal-fired electrical generating units emit at least 2.4 times more
sulfur dioxide than do nonutility sources of this pollutant. Data from the
AQCRs over a period of years indicate the predominance of utility sulfur
dioxide emissions over nonutility sulfur dioxide emissions within the region.
In 1973i in 9 of the 15 AQCRs with high sulfur dioxide emissions, utility
sources predominated. Emissions from these sources were 10 or more times
' AQCRs are based on jurisdictional boundaries, urban-industrialized
concentrations, and such factors as climate, meteorology, and topography.
They were created for the purpose of setting ambient air quality standards.
AQCR data are coordinated by EPA's National Emission Data System.
70
-------
Figure 4-4
AQCRs with High Sulfur Dioxide Emission Densities, Eastern United States
Q Fossil steam plants are the predominant SOX
emission source
A Sources other than fossil steam plants predominate
All AQCRs with no symbol have mixture of SOX emission
source categories
SOX emissions >99,999 kg/km
SOX emissions 50,000-99,999 kg/km
SOX emissions 10,000-49,999 kg/km
SOxemissions < 10,000 kg/km
71
-------
those of nonutility sources and accounted for 50 percent or more of the total
emissions (see figure 4-4).
Electrical generating facilities in the ORBES region thus provide a
majority of total regional sulfur dioxide emissions as well as a significant
percentage of national sulfur dioxide emissions. For example, in 1976,
ORBES-region coal-fired electrical generating units produced about 78 percent
of the regional sulfur dioxide emissions from all sources. In terms of
national emission levels in that year, utility sulfur dioxide emissions in the
region constituted nearly 52 percent of U.S. electric utility sulfur dioxide
emissions and 32 percent of U.S. sulfur dioxide emissions from all sources.
In comparison, the ORBES region contained about 36 percent of the national
coal-fired electrical generating capacity in 1976.
However, high sulfur dioxide emission densities within any subregion of
the ORBES region may not be solely responsible for high sulfur dioxide
concentrations in that subregion. Moreover, a location without high sulfur
dioxide emissions still can experience high concentrations of this pollutant.
The explanation involves the transport of sulfur dioxide emissions—that is,
the transport over regional-scale distances on the order of several hundred
kilometers.
Regional data indicate that transport of emissions by extremely
persistent winds (winds that blow from one direction for extended periods of
time) is an important factor in regional sulfur dioxide concentrations. At
several locations throughout the region, between 30 and 50 percent of the 25
highest daily sulfur dioxide concentrations each year are associated with
transport by extremely persistent winds. Specific data from along the Ohio-
Pennsylvania-West Virginia border further indicate that the transport of
sulfur dioxide emissions from local and long-range sources contributes to
violations of the 24-hour sulfur dioxide standards along that border.
As discussed previously, a large number of ORBES-region counties have TSP
concentrations that violate the NAAQS for TSP, or they have available less
than the full PSD increment for TSP. However, the TSP concentrations do not
represent as much of a constraint to utility growth as do the sulfur dioxide
concentrations, primarily because regional utility particulate emissions
account for a small percentage of both regional and national emissions. For
example, in 1976, ORBES-region coal-fired electrical generating units produced
about 22 percent of the regional particulate emissions from all sources, about
50 percent of total U.S. electric utility particulate emissions, and about 7
percent of total national particulate emissions from all sources.
Q
These calculations do not include "fugitive dust" contributions from
unpaved roads and airstrips. If such contributions were considered, regional
72
-------
SULFATES
Contribution to TSP Nonattainment. However, if utility sulfur dioxide
emissions were controlled or if a fine particulate standard were to be
implemented, TSP concentrations would decrease dramatically since sulfates
would decrease with such controls or such a standard.9 Although sulfates are
directly emitted in small amounts and can occur naturally (though there is
controversy as to the amount of this natural occurrence), the transformation
of sulfur dioxide to sulfates in the atmosphere contributes the most to
sulfate and TSP concentrations. Thus, since utility sulfur dioxide emissions,
as already noted, constitute the majority of regional sulfur dioxide
emissions, utilities could be implicated in TSP nonattainment more than they
are at present if the sulfate contribution to TSP concentrations is examined
further.
Data indicate that sulfates are a major contributor to the elevated TSP
levels in the ORBES region. During the period August 1977 to October 1978,
measurements at least three regional monitoring stations indicated that
elevated sulfate concentrations contributed to TSP nonattainment since the
24-hour secondary standard would not have been violated if the sulfate
concentration was subtracted from the TSP concentration. During this period,
there were 6 cases in the ORBES region (out of the 21 cases observed in the
eastern United States) in which the sulfate concentrations caused the 24-hour
secondary standard to be exceeded.
Transport. Further data indicate that transport contributes to elevated TSP
concentrations. Assuming that sulfate concentrations are a good measure of
the contribution of nonlocal sources to local TSP measurements, long-range
transport of sulfates over several hundred kilometers contributed between 15
to 20 percent of the total annual TSP concentrations in the upper Ohio River
region during the period from 1975 to 1977. Moreover, during a sulfate
episode, such as the episode of August 27, 1974, sulfate concentrations can
exceed 30 micrograms per cubic meter over a 24-hour period, and the
sulfate/TSP ratios can range from 20 to 45 percent.'^ This fact suggests that
utility particulate emissions would constitute about 16 percent of regional
particulate emissions from all sources and about 3 percent of total U.S.
particulate emissions from all sources.
° Sulfates are a part of the total suspended particulate measurement.
For purposes of ORBES, episodes are defined as days with sulfate
concentrations exceeding 20 micrograms per cubic meter at 25 percent or more
of the stations reporting; at least 25 percent of the total number of
available stations must have reported on that day.
73
-------
long-range transport contributes 20 to 45 percent of the total measured
concentration of TSP under such episodic conditions.
Examination of data, at specific sites also indicates sulfate transport
trends. In Pennsylvania, for example, long-range transport of sulfur dioxide
emissions can contribute significantly (between 25 to 50 percent) to
widespread violations of the Pennsylvania sulfate standard and to violations
of the federal 24-hour TSP secondary standard in that state. Further analysis
of data from the southwestern Pennsylvania border area shows that these high
sulfate concentrations are associated more often with long-range transport
from the west and southwest (that is, the lower ORBES region) than from the
opposite directions.
When further impacts of meteorological conditions on sulfate and TSP
concentrations are considered, other observations can be made. One
observation is that air mass trajectories associated with major sulfate
episodes in the northeastern United States and southeastern Canada pass over
the ORBES region, strongly implicating it as a major source region for these
episodes.
Acidic Precipitation. Sulfate episodes are important . to understand since
acidic precipitation is due primarily to the presence of sulfate and nitrate
ions and since the sulfate ions are estimated to be primarly man made.
Precipitation is considered acidic if its pH is less than 5.6, the normal
value for natural precipitation. Although data are sketchy for determination
of the frequency of acid rain, between November 1978 and May 1979, five
stations in or near the ORBES region recorded 41 events in which precipitation
pH was less than 5.6. Between September 1978 and May 1979, mean regional pH
values were about 4.1; minimum values were about 3.6.
Wet sulfur deposition, or the amount of sulfur that reaches the ground,
is another parameter often used to characterize acidic deposition. During the
base period, annual wet deposition in the ORBES region tended to be in the
middle of the range observed in the eastern United States. In the study
region, the range was between 1 and 2 grams of sulfur per square meter per
year, with the highest measured values occurring immediately downwind in
central Pennsylvania. Moreover, a number of wet deposition episodes (low pH
and/or high sulfate ion concentrations) appear to be associated with very
light rainfall or with rainfall over a limited area at the end of major
ambient sulfate episodes.
Visibility. Understanding regional sulfate episodes also is important since
such episodes often are associated with reduced visibility. Based on yearly
airport data, the visual range along the portion of Ohio River valley with
elevated sulfate concentrations is less than 16 kilometers. The yearly
average visibilities outside of the valley but within the six ORBES states
range between 16 and 24 kilometers (see figure 4-5).
74
-------
Figure 4-5
Average Yearly Visibility
|<16Km
j 16-24 Km
j 24-40 Km
j 40-72 Km
I 72-112 Km
| |>112Km
Episodes. The significant contribution of both simple and complex
meteorological conditions to regional pollutant concentration trends is
demonstrated further by four regional sulfate episodes that were evaluated by
the Prahm regional transport model. In that evaluation, the subregional
sources of these episodes were examined.11 These four episodes were selected
to provide a representative cross-section of flow patterns, seasons, and
special situations. They occurred on August 27, 1974; July 10, 1974; June 11,
1976; and June 23, 1975.
The most frequent type of sulfate episode (occurring at least 10 times
per year) is exemplified by the August 27, 1974, episode. This type of
For a discussion of the regional application of the Prahm model, see
Teknekron Research, Inc., Air Quality in the Ohio River Basin. For a
discussion of the model itself, see L.P. Prahm and 0. Christensen, "Long-Range
Transmission of Pollutants Simulated by a Two-Dimensional Pseudospectral
Dispersion Model," Journal of Applied Meteorology 16:896-910.
75
-------
episode involves a rather straightforward, simple flow pattern of extremely
persistent winds blowing from west to east over the ORBES region for several
days (see figure 4-6 for a depiction of air mass trajectories during the
August 27 episode). Modeling results suggest that, during this episode,
sulfur dioxide emissions in the lower ORBES region contributed about 75
percent of the peak sulfate concentrations in the upper region. Nearly 100
percent of the contribution from the lower region came from utility emissions.
Thus, under these episodic conditions, modeled sulfur dioxide and sulfate
concentrations in an area of the upper region were 94 and 40 micrograms per
cubic meter, respectively.
On a state basis, the Prahm model predicts that, during the August 27
episode, utility sulfur dioxide emissions from the ORBES states of Illinois,
Indiana, and Kentucky produced peak sulfate concentrations of about 8, 14, and
25 micrograms per cubic meter, respectively, at locations in the upper ORBES
region. Isopleth maps of the sulfur dioxide and sulfate concentrations due to
utility emissions on August 27 indicate that the area of highest
concentrations occurred along the Ohio River main stem and particularly along
the Ohio-Pennsylvania-West Virginia border (see figures 4-7 and 4-8).
Although the three other episodes had meteorological patterns different
from the August 27 episode and from each other, the Prahm model indicates that
the transport of emissions again was an important factor in the concentrations
recorded during all three of these episodes. During these three episodes, as
in the August 27 episode, sulfur dioxide emissions from all sources in the
lower region contributed significantly (as much as 80 percent) to the sulfate
concentrations in the upper region. Similarly, utility sulfur dioxide
emissions in the lower region alone contributed at least half (and in one
episode almost all) of the sulfate concentrations in the upper region.
Modeling of the June 23, 1975, episode in particular points up the importance
of transport by predicting that utility sulfur dioxide emissions from the
upper portion of the ORBES region contributed about 50 percent of the
predicted sulfate concentrations in an area northeast of the region. Even
under nonepisodic conditions, however, these emissions would have been
transported beyond the region and would have contributed to sulfate
concentrations beyond the continental United States.
1 O
^ Data for this episode come from the SURE Phase I project, April 1974
to March 1975. An "area" in the SURE project was determined by using a grid
pattern of 80-by-80 kilometer squares, and this same averaging method was used
in ORBES modeling. Thus, for example, while the area of highest concentration
may have had an average sulfate concentration of 40 micrograms per cubic
meter, specific locations within or outside the 80-by-80 kilometer area might
have experienced higher or lower concentrations.
76
-------
Figure 4-6
Calculated Air Mass Trajectories at 600 Meters Above the Ground,
Eastern United States, August 25,1974
• Starting point of trajectory on August 25, 1974
o Twelve-hour interval beginning at noon (Greenwich Median Time)
A Twelve-hour interval beginning at midnight (Greenwich Median Time)
77
-------
ANNUAL AVERAGE CONCENTRATIONS. Sulfur dioxide and sulfate concentrations of
longer duration also were calculated. While the Prahm regional transport
model predicts the impacts of short-term episodes, the TRI/Fay model predicts
long-term aspects, such as annual average concentrations and their sources. '-
One of the model's predictions is that utility sulfur dioxide emissions in the
ORBES region contribute about 75 percent of the annual regional sulfur dioxide
and sulfate concentrations. Another prediction is that the long-range
transport of utility sulfur dioxide emissions contributes about 30 percent of
the observed annual sulfur dioxide concentrations in the industrialized areas
of the upper ORBES region. Figures 4-9 and 4-10 show that the annual average
sulfur dioxide and sulfate concentrations in 1976 due to utilities were higher
in the upper ORBES region than in the lower region. In the area of highest
concentration, 1976 modeled sulfur dioxide and sulfate concentrations were 26
and 9 micrograms per cubic meter, respectively.
The TRI/Fay model also was used to assess an individual state's
contribution to the annual concentrations in other states. For example, the
model predicts that of the 10 states east of the Mississippi with sulfur
dioxide emissions greater than 1 million tons per year, the sulfur dioxide
emissions from Ohio contribute between 3 and 4 micrograms per cubic meter to
the annual sulfate concentrations in the states of Pennsylvania, Maryland, and
West Virginia. Within Ohio itself, sulfur dioxide emissions contribute over 4
micrograms per cubic meter to annual sulfate concentrations in that state.
Finally, the TRI/Fay model was used to assess the relationship between
the ORBES region and southeastern Canada in regard to sulfur dioxide
emissions, pollutant concentrations, and transport impacts. The total sulfur
dioxide emission rate from eastern Canadian sources (east of 105 degrees west
longitude) is about 4.6 million tons per year. In comparison, Ohio—the state
with the highest sulfur dioxide emissions in the United States—has sulfur
dioxide emissions of about 3-45 million tons per year. Despite the high
emissions in eastern Canada, sulfur dioxide emissions from this area
contribute only about 2 micrograms per cubic meter to the annual sulfur
dioxide and sulfate concentrations in the northeastern United States.
However, sulfur dioxide emissions from electrical generating units in the six
ORBES states contribute about 50 percent of the annual sulfur dioxide and
sulfate concentrations estimated to occur in southeastern Canada.
^ For a discussion of the TRI/Fay model, see James A. Fay and Jacob T.
Rosenzweig, "An Analytical Diffusion Model for Long Distance Transport of Air
Pollutants," Atmospheric Environment 14:355-65. For a discussion of the
regional adaptation of the Fay/Rosenzweig model, see volume II of the air
quality report: Teknekron Research, Inc. (TRI), Air Quality and Meteorology
in the Ohio River Basin: Baseline and Future Impacts.
78
-------
Figure 4-7
Sulfur Dioxide Concentrations,
August 27, 1974
Figure 4-8
Sulfate Concentrations,
August 27,1974
Cqg/m3)-
Figure 4-9 Annual Average
Sulfur Dioxide Concentrations
2-5.9 6-9.9 10-13.99 14-17.99 18-24
(M9/m3)
Figure 4-10 Annual Average
Sulfate Concentrations
3-4.99 5-6.99
(M9/m3)
79
-------
Thus, both actual measurements during the base period and mathematical
modeling of base period concentrations support the importance of transport in
sulfur dioxide and sulfate concentrations as well as the contribution of
regional emissions to both local and distant concentrations.
NITROGEN OXIDE EMISSIONS. Emissions of nitrogen oxides also were examined
briefly. In the mid-1970s, power plants in the ORBES region contributed about
47 percent of regional nitrogen oxide emissions from all sources. In terms of
national emissions, nitrogen oxide emissions from regional facilities
constituted about 21 percent of total U.S. electric utility emissions of
nitrogen oxides and about 6 percent of U.S. emissions of nitrogen oxides from
all sources.
LAND USE. The ORBES region covers approximately 122 million acres (or about
190,000 square miles) in six states. Except for the ORBES state portion of
Pennsylvania, at least 75 percent of each state is included in the study
region (see figure 1-1). The predominant land use is agriculture
(accounting for 54 percent of regional acreage), which ranges from vast corn
and soybean tracts in Illinois to smaller tobacco farms in Kentucky. Regional
forest area, the next highest land use category in the region, accounts for 31
percent of the regional acreage. The remainder of the region is comprised of
urban and built-up areas (6 percent), public lands (4 percent), and
miscellaneous uses, including surface and underground mining areas (5
percent).
The two major land uses tend to be subregional, with agricultural land
use dominating in the Eastern Interior Coal Province states, and forest areas
dominating in the Appalachian Coal Province states (see figure 4-11). Given
the land use distribution within the region, it is clear that the greatest
potential for conflict between agricultural and energy-related land
use—especially the surface mining of coal—occurs in the Eastern Interior
Province, particularly in Illinois. Conversely, the greatest potential for
conflict between forest and energy-related land use occurs in the Appalachian
Province, especially in West Virginia.
COAL MINING. At present, approximately two acres of land must be surface
mined in the Appalachian Province to yield the same amount of coal as one acre
For additional details on land use in the study region, see two ORBES
Phase II reports: J.C. Randolph and W. W. Jones, Ohio River Basin Energy
Study: Land Use and Terrestrial Ecology, and Daniel E. Willard et al., A Land
Use Analysis of Existing and Potential Coal Surface Mining Areas in the Ohio
River Basin Energy Study Region.
80
-------
Figure 4-11
Percentage Agricultural and Forest Land, by ORBES State Portion
71%
70%
agricultural
land
forest
land
69%
10%
IL
PA
WV
in the Eastern Interior Province. Given this fact and the fact that a longer
time is required for the regrowth of forests in contrast to the regrowth of
pastures, more time and money is necessary to restore a surface-mined site in
the former province than in the latter; the requirements of the Permanent
Regulatory Program of the Surface Mining Control and Reclamation Act of 1977
would increase these expenditures. Ecological disruption also is severer in
the former province than in the latter, especially if the land is not returned
to its original forest coverage.
In general, the reclamation of surface-mined land for permanent land use
tends to be a slow process. A minimum of two years from the cessation of
surface mining is required just to reclaim the land with quick-growing cover
species. In 1976, 151,000 acres in the ORBES region were undergoing the two-
year reclamation process. Additional data show that another 400,000 surface-
mined acres were at least 16 years old in 1976 or only partially reclaimed, or
both.
Underground mining also can degrade surface land quality through the
improper disposal of mined residuals and through subsidence of the land
surface. Mined residuals can cause local problems, but these problems can be
controlled by the same reclamation techniques used for surface mining. Land
surface subsidence can affect large areas but can be minimized by using long-
wall mining techniques and by leaving 50 percent or more of the coal seam
unmined.
ENERGY-RELATED LAND USE. If all energy-related land uses through 1976 are
considered,-total energy-related land use in the ORBES region (including past
81
-------
and present surface mining for coal) had affected about 1.5 percent of the
regional acreage (1.86 million acres). Land use for past and present surface
mining of coal represents 86.9 percent of this figure (1.6 million acres);
electrical generating facilities, 7.6 percent (140,700 acres);1^ and
transmission line rights-of-way, 5.5 percent (103,000 acres).
PHYSICAL CROP LOSSES. Evidence exists in the literature to indicate that
agricultural and natural vegetation can undergo physiological changes due to
present air quality.16 It has been recognized widely that very high short-
term ozone exposures can cause visible vegetation damage (a criterion used in
deciding the current federal ambient air quality standards for ozone).
However, more recent literature indicates strongly that chronic exposures to
low ozone (and sulfur dioxide) concentrations can have effects on yield
comparable to the results from acute exposures. For example, chronic exposure
to 0.05 parts per million of ozone has been shown to cause significant
vegetation damage that is not visibly apparent at first.^ Moreover, power
plant nitrogen oxide emissions and nonmethane hydrocarbons have been shown to
increase ozone concentrations significantly under certain weather conditions.
Thus, one of the matters examined in this study with respect to land quality
15
The average land ownership at electrical generating facilities using
cooling towers is 1100 acres per 650 megawatts electric. Of this amount, 400
acres are affected directly; 700 acres are affected indirectly. In general,
the 400 directly affected acres are comprised of building sites (approximately
6 percent), fuel and waste storage areas (approximately 44 percent), and
roads, parking lots, and miscellaneous uses (50 percent). In cases where
surface water resources are insufficient to meet cooling needs and cooling
reservoirs are required, an additional 975 acres per 650 megawatts would be
needed on the average. These figures are based on a study of six
representative generating facilities in the ORBES region. See Randolph and
Jones, Ohio River Basin Energy Study: Land Use and Terrestrial Ecology.
1 f\
For a review of the pollutant response literature and for the
calculation of crop and forest losses in the ORBES region, see Orie Loucks et
al., Crop and Forest Losses Due to Current and Projected Emissions from Coal-
Fired Power Plants in the Ohio River Basin (ORBES Phase II). Estimates of
crop losses due to ozone formed by nitrogen oxides are annual estimates. Loss
estimates related to sulfur dioxide assume the peak load operation of power
plants. Forest losses are estimated based on total annual power plant
emissions.
17
' Air impact modeling examined the regional impacts of sulfur dioxide,
particulate, and nitrogen oxide emissions but did not examine the effects of
ozone. See Loucks, Crop and Forest Losses, for information on ozone.
82
-------
is the contribution of nitrogen oxide emissions in the ORBES region to ozone
concentrations and, thus, to regional crop losses.
From the evidence gathered, it appears that ozone concentrations in the
rural areas of the ORBES region are high enough and of sufficient duration to
cause negative responses in vegetation and crops. A further examination
reveals that natural events in the region do not account for these high ozone
concentrations; hydrocarbons from regional forests and agricultural crops are
rarely as important for the production of ozone as are nitrogen oxides, which
are produced primarily from transportation sources (about 35 percent) and from
power plants (about 50 percent).
Given the regional nitrogen oxide levels in 1976, crop loss estimates
were derived based on numerous controlled field studies throughout the eastern
United States. These estimates are expressed as lower bound (minimum) values,
representing the most conservative assumptions possible, to upper bound
(maximum) values, reflecting likely aggregate plant response during sensitive
growing conditions and life-cycle stages. These estimates also utilize
cumulative ozone exposures from ozone monitoring at various locations in the
ORBES region.
Soybean, corn, and wheat yields were examined. Three-year yields (1975
to 1977) for each crop were averaged to obtain a mean normal yield for each
affected county in the ORBES region. The results show the total annual
production in the ORBES region for corn to be 2.11 billion bushels; for
soybeans, 550 million bushels; and for wheat, 180 million bushels. Because
this normal yield already includes the effects of air pollutants present in
the base period, a probable "clean air" yield was calculated. Thus, the
projected losses for the three crops can be considered equivalent to the
potential crop production gains achievable from complete pollution abatement.
As the projected gains from complete abatement, these numbers provide a
comparative idea of what current pollution levels cost in terms of yield as
well as what yields complete abatement would provide.
It is projected that 1976 regional crop gains due to the complete
abatement of oxidants formed by regional nitrogen oxides could have ranged
from a minimum of 118 million bushels to a maximum of 480 million bushels,
with 258 million bushels representing the probable gain. Soybeans are
estimated to account for 30 percent of the probable gain; corn, 66 percent of
the probable gain; and wheat, 4 percent of the probable gain. It also should
be kept in mind that what was lost in 1976, therefore, is not merely a local
problem—that is, only in the vicinity of power plants—but, because of
pollutant transport, the losses may occur in areas of the region removed from
major point sources. In addition, about 95 percent of these losses are
projected to have occurred in the ORBES state portions of Illinois, Indiana,
and Ohio.
83
-------
Studies in the literature also indicate that sulfur dioxide
concentrations of 130 micrograms per cubic meter (one-tenth of the three-hour
secondary standard) in the presence of moderate ozone levels (0.06 to 0.1
parts per million) cause additional local vegetation damage and, thus, crop
losses. (Sulfite has been identified as the chemical form largely responsible
for causing sulfur-dioxide-related injury within the plant system.)
Approximately 9.3 percent of the acreage in the ORBES region experienced such
sulfur dioxide concentrations in 1976 due to power plant emissions. The
percentage of area affected in the six ORBES state portions ranged from 6.9
percent of the Illinois portion to 18.1 percent of the Ohio portion.
Regional crop losses in 1976 due to these concentrations were estimated,
and these losses retain the same features as the projected ozone-related
losses: upper and lower bounds as well as the concept of the yield that could
be gained due to complete abatement. The 1976 crop gains that could have been
achieved from complete abatement of sulfur dioxide concentrations are
estimated to range from 867,000 bushels to 6.1 million bushels, with 3-2
million bushels representing the probable gain. About 45 percent of the
probable gain would come from soybeans; 43 percent, from corn; and 12 percent,
fron wheat. Again, about 95 percent of the probable gain would occur in the
ORBES state portions of Illinois, Indiana, and Ohio.
The amount of corn, soybean, and wheat that was lost in 1976 because of
the existing sulfur dioxide concentrations is estimated to be less than 1
percent of the total regional production in 1976. However, on a-more local
scale, such as the county, the losses may be significant, and the losses to
individual farmers near sources of sulfur dioxide may be substantial.
Furthermore, whether plants develop tolerances to sulfur dioxide or to ozone
is placed in doubt by the fact that pollutant-induced physiological
disruptions, including disruption of translocation, may speed up the aging
process in plants.
FOREST LOSSES. Forest species also experience problems at the current air
pollution levels; species like the catalpa, the American elm, the eastern
white pine, the maple, and the Lombardy poplar are susceptible to visible
injury from current sulfur dioxide levels. In general, oxidants—and,
locally, sulfur dioxide—result in reduced vigor and growth in forest species.
Moreover, since pollutant-affected forest species may become too weak to
resist insect damage, additional losses due to insect damage also might be
attributable to air pollution. However, estimates of reduced growth due to
such insect damage cannot be made at this time. Thus, total forest losses,
due primarily to ozone, are estimated to have ranged between 0.7 and 3-4
percent of total annual regional growth in 1976.
TERRESTRIAL ECOSYSTEMS. The four terrestrial ecosystem components examined
for purposes of ORBES include those for which a somewhat homogenous data base
84
-------
was available: the percentage of forest lands, the percentage of Class I anc
II soils, the number of natural areas, and the number of endangered species.
Class I and II soils reflect the highest degree of productivity; 39
percent of the ORBES region consists of Class I and II soils, ranging from 58
percent of the ORBES portion of Indiana to 6 percent of the ORBES portion of
West Virginia.
Natural areas, which contain unique biological, geological, or scenic
features, can serve, in their distribution and abundance, as overall
indicators of environmental quality. The number of natural areas within the
ORBES state portions varies considerably, however, because of different
emphases placed on natural area programs by the six states. For example,
Illinois has the greatest number of recognized natural areas (426) while
Kentucky, with the lowest number, has only 67.
Finally, the number of endangered species reflects the high
susceptibility of certain of the region's ecosystems to even minor changes.
Riparian habitats (those bordering water) generally support the greatest
number of rare or endangered species in the ORBES region. Each state has its
own list of such species. Only one of these species—the Indiana bat—is on
the federally recognized list of endangered species.
Values for each of these variables in 1976 were indexed by units ranging
from 1 (low) to 10 (high). These units were weighed equally and summed to
produce a county-level index. State totals then were summed. However, no
absolute threshold values for assessment unit totals indicate "good" or "poor"
ecological quality, but these units do provide a means of making relative
comparisons among the ORBES scenarios. Terrestrial ecosystem units in each
ORBES state portion in the base year (1976) were assigned as follows:
Illinois, 290 units; Indiana, 209; Kentucky, 165; Ohio, 297; Pennsylvania,
192; and West Virginia, 154.
4.5 Water
WATER SYSTEMS. The ORBES region encompasses most of the Ohio River Basin, the
portion of the Mississippi River Basin that borders the states of Illinois and
Kentucky, and the southern periphery of some Great Lakes drainages.
18
For a complete discussion of the terrestrial ecosystem analysis, see
Randolph and Jonesi -Ohio River Basin Energy Study; Land Use and Terrestrial
Ecology.
85
-------
Consequently, the water systems in the ORBES region and the aquatic life they
currently support are quite varied.^ 9 These regional systems include
Whitewater canoe and mountain trout streams, deep, clear lakes popular as
recreational spots, major rivers both navigable and free flowing, and numerous
wetlands and sloughs found both in mountain valleys in the east and along the
major river basins in the west. In addition, there are a number of accidental
lakes created by abundant rainfall in combination with poor farming,
foresting, and mining practices. Moreover, in late summer, navigable pools on
the Ohio River main stem become long, narrow lakes.
The Ohio River main stem is the major navigable river of the ORBES
region. This system connects the industrial eastern portion of the region to
its western agricultural base and, since completion of the high-lift dam
system, serves as an almost open river from Pittsburgh, Pennsylvania, to
Cairo, Illinois. The region's other navigable rivers are the Mississippi, the
Illinois, the Tennessee, the Cumberland, the Green, the Kentucky, the Kanawha,
the Monongahela, the Allegheny, and the Kaskaskia. With the exception of the
Mississippi, these rivers are somewhat smaller than the Ohio, have lower lift
lock chambers, and carry considerably less traffic. At present, consideration
is being given to the closing of some of the smaller systems, for example, the
Kentucky River.
AQUATIC ECOLOGY. The richness of the region's aquatic ecology can be seen in
the diversity of the fish species found in the 70 streams and rivers selected
for specific analysis. Of the 258 fish species in the ORBES region, 25 are
regionally ubiquitous (occurring in 60 of the 70 selected ORBES-region
waterways), 102 are dispersed (occurring in 11 to 59 of the 70 selected
waterways), 97 are limited (occurring in 2 to 12), and 3^ are isolated
(occuring in only 1 of the selected waterways). However, a species regionally
isolated in a specific stream should not be considered endangered—except in
the case of the Scioto raadtom—since many of these isolated species are
hybrids of common types and others are peripheral and occur in the ORBES
region simply because it borders their range.
All of the regional water systems—the navigable waterways, the
tributaries, and the lake systems, for example—exhibit rich aquatic
ecologies. The bank systems of the region's navigable waterways, in
particular, are the ecological mainstay of these diverse habitats. The lower
Ohio (from Cincinnati, Ohio, to Cairo, Illinois), the Tennessee, the
^ For a description of the region's water systems and a discussion of
its aquatic ecology, see Clara Leuthart and Hugh T. Spencer, Fish Resources
and Aquatic Habitat Impact Assessment Methodology for the Ohio River Basin
Energy Study (ORBES Phase II).
86
-------
Cumberland, and the Mississippi rivers each contain some 90 fish species,
including many important game species.
The ORBES-region tributaries contain more site-specific ecosystems than
the navigable waterways. Some entirely unique systems, which are protected to
a degree, are evident in the tributaries. The most outstanding and
ecologically rich stream system of the 70 regional streams and rivers selected
for study is the Bayou de Chien-Obion Creek system, which is located in
Kentucky. One hundred and eight species live in this small system of sluggish
streams and wetlands, including eight isolated species, the most of any
regional stream system studied.
The regional lake systems also have diverse ecologies. For example, Lake
Barkley, part of the Cumberland River system, contains 128 fish species—the
most of any lake system in the region. Kentucky Lake, part of the Tennessee
River system, contains 101 fish species—the second highest number in the
region. Lake Barkley and Kentucky Lake also are the largest lakes in the
region.
WATER RESOURCES. The water resources that support these systems and their
habitats come from both within and outside of the region. Within the region,
stream flow (measured in cubic feet per second) is aided by precipitation
runoff, groundwater, and reservoirs. Although the average annual rainfall in
the ORBES region results in a potential water supply to the region of about
584,000 cubic feet per second, the runoff that actually reaches the region's
streams is, under average conditions, about 216,000 cubic feet per second.
River inflows from outside the region also make major contributions to
regional water supply. The inflow under average conditions is about 257,000
cubic feet per second. Thus, the total water supply in the ORBES region under
average conditions is about 474,000 cubic feet per second.^
Besides supporting the waterways and the aquatic life of the region, this
water supply also is heavily used by industries, municipalities, and electric
utility companies. As a result of this use, a certain amount of the region's
water supply is lost through consumption (evaporation). In 1970, for example,
it is estimated that municipalities in the ORBES region consumed 500 million
gallons per day (or 774 cubic feet per second) and that self-supplied
industries, excluding the electric utility industry, consumed 720 million
on
For calculation of the water supply available to the ORBES region, see
E. Downey Brill, Jr., et al., Potential Water Quantity and Water Quality
Impacts of Power Plant Development Scenarios on Major Rivers in the Ohio Basin
(ORBES Phase II).
87
-------
gallons per day (or 1120 cubic feet per second). It is estimated that in 1975
water consumption by the electric utility industry totaled 564 cubic feet per
second.
WATER QUALITY. Within the region, water quality standards vary from state to
state and even from river to river. For purposes of ORBES, however, one
reference concentration was selected for each pollutant to facilitate the
scenario examinations of the potential regionwide water quality impacts of
power plant discharges. Each reference was selected by considering the water
quality criteria of the six ORBES states, the Ohio River Valley Water
Sanitation Commission (ORSANCO), ^ and the U.S. Environmental Protection
Agency. Table 4-1 lists the ORBES reference concentrations that were selected
for 20 pollutants; the table also lists the standards or criteria recommended
by each state, ORSANCO, and EPA.
Seven-Day-10-Year Low Flow. The concept of 7-day-10-year low flow also was
used in the study. This concept is a design parameter commonly used in river
basin management and water quality assessments, primarily as a worst case
decision tool or parameter. In the simplest of terms, it is the lowest flow
that would be expected to occur on the average for seven days at least once
every 10 years. During 7-day-10-year low flow, regional water supply drops,
on the average, to about 88,000 cubic feet per second, compared to about
474,000 cubic feet per second under average conditions. Specific flow numbers
also are given for each stream reach and can be influenced by impoundment
management above that reach as well as by land use in the immediate area. For
example, 7-day-10-year low flow in 1930 at the McAlpine lock and dam on the
Ohio River (mile point 606.8) was projected to have been 6000 cubic feet per
second. This projection was based on the historical record available at the
time and on knowledge of how impoundment releases in the region above mile
21
These estimates were calculated assuming that municipal consumption
would be 20 percent of projected withdrawals and that industrial consumption
would be 10 percent of the withdrawals that were projected using manufacturing
earnings. These percentages are considered to represent the most probable
consumption factors. However, a range of estimates exists. A low estimate
projects a combined municipal and industrial consumption of 810 million
gallons per day, and a high estimate projects a combined consumption of 1400
million gallons per day. Projections about consumption by the power
generation industry were based on varying assumptions under different cooling
alternatives. For a discussion of these more complex assumptions as well as
for projections about future water consumption, see Brill, Potential Water
Quantity and Water Quality Impacts.
The ORSANCO criteria apply only to the main stem of the Ohio River.
-------
point 606.8 were managed. The same projection for the same mile point today
stands at about 14,700 cubic feet per second, more than double the 1930 value.
In the interim, many impoundments.have been added to regional waterways, and
their influence on the projection is obvious. However, the region's current
7-day-10-year low flow projections also are affected significantly by two
other factors: (1) these projections are based on an average and (2) severe
drought conditions, which could affect that average, have not occurred in the
region since 1930.
Travel times on the region's major river systems at 7-day-10-year low
flow greatly exceed seven days, making the analysis essentially reach
specific. For example, travel time for the Ohio River main stem at 7-day-10-
year low flow is 192 days. Thus, the projected impacts under 7-day-10-year
low flow are not assumed to occur simultaneously. The impact for each river
is considered basin specific and, with the obvious exception of a major
receiving stream like the Ohio, may or may not occur in association with any
other river's impact.
Protection Levels. Based on the number of ubiquitous, dispersed, limited, or
isolated fish species, on normal flow conditions, and on certain rules and
definitions, each of the 24 ORBES-region streams selected for the most
detailed analysis was assigned a protection level (A, B, C, or D) to indicate
its current status and to provide comparisons among scenarios.^3 A stream
received an aquatic habitat ranking of "A" if it could not experience stress
without undergoing a structural change in the direction of degradation.
Eighteen of the 24 streams have this ranking and should be considered high-
quality streams. The other 8 have a ranking of "B," which designates that
they are in a transitional state between high and low ranking, but closer to a
high ranking. A ranking of "C" indicates the same transitional state but
indicates that the stream is closer to a low ranking. A ranking of "D"
designates low-quality streams that already are degraded and that have a fauna
tolerant to pollutants.
Of these 24 waterways, 6 are in Kentucky, 5 in Illinois, 4 in Ohio, 3 in
Pennsylvania, 2 in West Virginia, and 2 in Indiana. One of the 2 remaining
rivers, the Wabash, borders Indiana and Illinois; the other, the Ohio, borders
all six ORBES state portions (see figure 4-12).
-3
-1 The 24 largest streams in the region were selected for more detailed
analysis out of 70 streams studied because they have the most potential to be
selected for power plant siting. For a discussion of the protection levels
and of the other streams studied, see Leuthart and Spencer, Fish Resources and
Aquatic Habitat Impact Assessment Methodology.
89
-------
Table 4-1
ORBES Reference Concentrations and
Water Quality Criteria and
Standards in Effect in the ORBES
Constituent
IDS
TSS
Sulfate
Ammonia
Arsenic
Barium
Cadmium
Chloride
Chromium
Phosphorus
Selenium
Silver
Copper
Iron
Lead
Manganese
ORBES
Reference
trations
(mg/1)
500
50
250
1.10
.05
1.0
.01
250
.01
.05
.01
.005
.06
.30
.05
.05
Mercury (u.g/13) .05
Nicke!
Zinc
Boron
1.00
.205
1.00
U.S.
Prit
EPA
(mg/1)
Domestic
2503
5
3
1.16
.058
1.0
.01
3
.05
N
.01
.05
1.0
.30
.05
.05
2.0
N
5.0
12
Aquatic
N
N
N
N
N
N
9
N
.01
N
.01 L
.01 L
.1L
1.0
.01 L
.1
.05
.01 L
.01 L
N
ORSANCO
Criteria
Main Stem)
Region
State Standards
(mg/1)
Illinois1
(mg/1) Domestic
500
N
250
N
.05
1.0
.01
250
.05 10
N
.01
.05
.11
N
.05
N
.2
N
.01 L
N
500
N
250
N
.1
1.0
.01
250
.05
N
.01
N
N
N
.05
.05
N
N
N
N
General
1000
N
500
1.5
1.0
5.0
.05
500
1.05
.05
1.0
.005
.02
1.0
.1
1.0
.5
1.0
1.0
1.0
Indiana
750
N
250
N
N
N
N
250
N
N
.01 L
.01 L
.1L
N
.01 L
N
N
.01 L
.01 L
N
Kentucky
500
N
N
N
.05
1.0
.01
N
.0510
N
.01
.05
.1L
N
.05
N
N
.1L
.11
N
The ranking of each of these 24 streams during the base period and under
normal flow conditions is indicated in table 4-2, along with the number of
reaches into which each stream was divided for purposes of the analysis, the
river's expected low flow, and the pollutants that are projected to have been
in violation of the study's reference concentrations at some point in 1976 if
7-day-10-year low flow had occurred. As the table indicates, approximately 19
of the region's 24 largest streams would have violated at least three of the
ORBES reference concentrations at some time in 1976. The conservative agents
in most frequent violation at 7-day-10-year low flow are phosphorus, iron,
manganese, copper, and chromium.
90
-------
Table 4-1 (continued)
ORBES Reference Concentrations and Water Quality Criteria and
Standards in Effect in the ORBES Region
State Standards (mg/1)
Ohio1 Pennsyl- West Ohio1 Pennsyl
West
Constituent Domestic Aquatic vania Virginia2 Constituent Domestic Aquatic vania Virginia2
TDS 5004 15004 500 N Selenium .01 .01 L N
(150) (150) Silver .05 .01 L N
TSS N N N N Copper 1.0 .0611 .1L
Sulfate 250 N 250 N Iron .3 1.0 1.5
Ammonia N 1 .47 .5 N Lead .05 .03 .05
Arsenic .05 N .05 .01 Manganese .05 N 1.0
Barium 1.0 N N .50 Mercury (qg/D 2.0 .05 N
Cadmium .01 .012 N .01 Nickel N .01 L .01 L
Chloride 250 N 150 100 Zinc 5.0 .20511 .01 L
Chromium .05 .1 .05 .0510 Boron N N N
Phosphorus N N N N
N No standard
L- 96-hour LCSO
'Toxic substance < 0 1 (96 LC50) or 0 1 (96-hour median tolerance limit)
Assuming Kanawha River criteria and all toxic substances < 0.1 (96-hour median tolerance limit)
3For chlorides and sulfates
•May exceed either 1500 mg/l or 150 mg/l attributable to human activities
5Does not reduce depth of compensation point for photosynthetic activity by more than 10% from norm
"Based on 0 02 mg/l un-ionized NH3with PH = 7.5, T = 25°C.
'Based on 0 05 mg/l un-ionized NH3 with PH = 7.5, T = 25°C
=01 00 for irrigation
"Standard (mg/l)
soft water hard water typg of aquatic life
0.0004 00012 cladocerans, salmonid fish
0.004 0 012 less sensitive aquatic life
'"As hexavelent Cr
"Based on total hardness = 260-280 mg/l as CaCO3 and 0.1 (96 LC50) if Cu and 0.01 (96 LCSD) if Zn
120 75 for irrigation on sensitive crops
.01
.05
.1L
N
.05
N
N
.1L
.1L
N
In the late summer under 7-day-10-year low flow conditions, navigable
pools on the Ohio River main stem experience temperatures of 86 degrees
Fahrenheit, which is 2 degrees above the temperature used by ORBES as a
reference standard. Dissolved oxygen levels at this time drop below 5
milligrams per liter, the level used in the study as a reference necessary to
maintain a system's balance.
Pollutant Sources. The sources of these pollutants that are in violation of
the study's reference concentrations during 7-day-10-year low flow vary
91
-------
Rgure 4-12
ORBES-Region Rivers Selected for Detailed Analysis
RIVER
Allegheny •
Beaver —
MAP NO.
Big Muddy •
Big Sandy-
Cumberland -
Great Miami
Green
Illinois
Kanawha
Kaskaskia
Kentucky -
Licking —
-1
-2
-3
-4
-5
-6
-7
-8
9
-10
-11
-12
RIVER
Little Miami
Mississippi -
MAP NO.
Monongahela
Muskingum —
Rock
Salt
Scioto •
Susquehanna
Wabash
White
Whitewater
Ohio Main Stem
-13
-14
-15
-16
-17
-18
-19
-20
-21
-22
-23
-24
92
-------
Table 4-2
Rivers Studied in Detail: Protection Levels, Number of Reaches,
Pollutants Violating ORBES Reference Concentrations at
1 7-day-1 0-Year Low Flow, and Flow per Second at 7-Day-1 0-Year Low Flow-
I *•
River "• -1 z f
Allegheny A 4
Beaver B 2
Big Muddy A 1
Big Sandy A 2
Cumberland A 3
Great Miami A 4
Green A 2
Illinois A 9
Kanawha A 2
Kaskaskia A 1
Kentucky A 3
Licking A 1
Little Miami B 1
Mississippi A 7
Monongahela A 3
Muskingum B 2
Ohio Main Stem A 32
Rock B 1
Salt A 1
Scioto A 4
Susquehanna A 1
Wabash A 10
White B 6
Whitewater B 1
TDS
•
TSS
•
•
•
•
«
•
•
•
«
1
<
so;
NHa
•
•
1
*
AS
•
Ba
Cd
•
•
»
»
t
Cl
Cr
•
•
•
•
0
t
»
1
»
P
•
•
•
•
•
•
«
»
I
«
•
•
1
1
t
i
t
Se
t
Ag
9
t
Cu
•
•
»
9
*
•
*
Fe
*
»
•
t
•
•
«
»
t
•
•
»
*
Pb
•
t
0
t
1
Un
9
*
9
0
t
»
1
»
*
*
1
t
Hg
•
•
/
t
»
1
•
«
i
t
»
•
Nl
9
9
»
Zn
•
t
B
f
7-Day-1 0-Year
Low Flow (cfs)
470-1098
86-232
37
26-59
8-4100
58-281
306-500
451-3601
1106-1285
100
113-164
10
27
15,752-47,412
384-459
551-566
booo— 4o, 4*J1
1306
20
48-337
136
130-2498
155-685
82
• Violates ORBES reference concentration at 7-day-1 0-year low flow
93
-------
Table 4-3
Aquatic Habitat Impacts on Rivers Studied in
7-Day-1 0-Year Low Flow
Detail,
River
Allegheny
Beaver
Big Muddy
Big Sandy
Cumberland
Great Miami
Green
Illinois
Kanawha
Kaskaskia
Kentucky
Licking
Little Miami
Mississippi
Monongahela
Muskingum
Water Quality
1976 Protection Impact Index
Levels (normal flow) (range: 0 to 1 00)
A
B
A
A
A
A
A
A
A
A
A
A
B
A
A
B
Ohio River Main Stem A
Rock
Salt
Scioto
Susquehanna
Wabash
White
Whitewater
B
A
A
A
A
B
B
*Background data
26
30
15
39
30
47
38
15
31
15
—
30
45
18
30
38
40
—
—
35
—
20
30
—
incomplete; analysis
1976 Protection
Levels (7-day-
1 0-year low flow)
C
C
B
C
C
C
C
B
C
B
*
C
D
B
C
C
C
*
*
C
*
B
D
*
1976 Aquatic Habitat
lmpacts(7-day-
1 0-year low flow)
Heavy
Heavy
Moderate
Heavy
Heavy
Heavy
Heavy
Moderate
Heavy
Moderate
—
Heavy
Heavy
Moderate
Heavy
Heavy
Heavy
—
—
Heavy
—
Moderate
Heavy
—
could not be conducted.
-------
according to the type of waterway. In general, nonpoint sources—such as
agricultural and urban storm runoff—account for the majority of the 1976
concentrations. Navigable waterways draining into the Ohio carry primarily
industrial and organic pollutants, while those draining into the Mississippi
carry primarily agricultural pollutants. Habitats along the smaller
tributaries, on the other hand, are affected primarily by siltation (sediment
deposits) and stream desiccation (drying)—mostly from farming and mining
rather than from industrial development. In particular, orphan-mined
(abandoned) land in both the Appalachian and Eastern Interior coal provinces
is the major source of water quality problems for many ORBES-region
tributaries. However, some tributaries do receive substantial quantities of
organic waste, and a few small streams and many of the small accidental lakes
created by surface mining and rainfall are threatened directly by acid mine
drainage.
AQUATIC HABITAT IMPACTS. The projected aquatic habitat impacts that would
occur under 7-day-10-year low flow as a result of the projected 1976 low flow
concentrations appear in table 4-3. This table indicates (1) any changes in a
stream's protection level, (2) the water quality index value, and (3) the
resulting aquatic habitat impacts. The water quality index is based on
violations in water quality parameters and is weighted according to those
violations.24
In table 4-3, a water quality index value of less than 10 percent of the
maximum possible impact (a value of 100) represents light impacts. Under
these conditions, impacts on a system's biota probably would not be detectable
except locally in the vicinity of outfalls. No change in a stream's
protection level would be expected to occur.
Moderate impacts are projected based on a water quality index equal to or
greater than 10 percent but less than 25 percent of the maximum possible
impact. Under these conditions, minor eutrophication with some loss of
existing embryonic fishes would be expected.25 The effects would be
noticeable at low flow, but recovery over the next several seasons also could
be expected. A stream's protection level would drop one level during the
period of recovery.
24
For a further discussion of this index and of the projected aquatic
habitat impacts, see Leuthart and Spencer, Fish Resources and Aquatic Habitat
Assessment Methodology.
Eutrophication—the enrichment of natural waters with soluble
nutrients—often results in the formation of a bacterial growth medium with
the subsequent depletion of dissolved oxygen required for fish and aquatic
life.
95
-------
A water quality index equal to or greater than 25 percent but less than
50 percent of the maximum possible impact represents heavy impacts. Under
these conditions, eutrophication, a concentration of heavy metals, and
possible stream desiccation would combine to have a marked effect on the
stream's biota. The effects would be immediately noticeable with local fish
kills. A longer period of recovery, possibly five to seven years, would be
required. A stream's protection level would drop two levels for a minimum of
five years.
Drastic impacts would occur when the water quality index is equal_ to or
greater than 50 percent of the maximum possible impact. Under these
conditions, eutrophication, a concentration of heavy metal salts, dissolved
oxygen depletion, siltation, and stream desiccation would combine to
essentially destroy the existing system. Extensive fish kills would be
expected all along the waterway, with nearly complete loss of embryonic
fishes. The period of recovery might range up to 20 years, depending on the
final condition of the watershed or the steps taken to recover it. A stream's
protection level would drop three levels for at least 15 years.
As table 4-3 indicates, the majority of the region's largest streams
would have experienced significant aquatic habitat impacts in 1976 under 7-
day-10-year low flow conditions, primarily because total water consumption
would have concentrated the high background pollutant levels to levels
intolerable to many fish species.
4.6 Health
In general, the ORBES region has a worse health status (as measured by
the age-adjusted death rate) than does the nation. Moreover, some of the
ORBES states that exhibit high mortality rates or that account for most of the
regional or national coal-processing deaths and disabling injuries tend to
rank low in health services.
In this section the health status of the region is delineated, and
regional health services are described. Estimates also are made of the deaths
and diseases attributable in 1976 to the use of coal for electrical generation
in the ORBES region. Finally, the potential health problems associated with
regional nuclear-generated electricity and with electrical transmission are
characterized.26
2^ This discussion of public and occupational health in the region is
based on the following ORBES Phase II reports: Edward P. Radford, Impacts on
Human Health from the Coal and Nuclear Fuel Cycles and Other Technologies
Associated with Electric Power Generation; Maurice A. Shapiro and A.A. Sooky,
Ohio River Basin Energy Study; Health Aspects; and Symposium on Energy and
Human Health: Human Costs Q£_ Electric Power Generation.
96
-------
HEALTH STATUS. During the 25 years prior to the base period, each of the six
ORBES states (with the exception of Ohio in the early 1950s) exhibited age-
adjusted death rates higher than the national rate.27 in 1975, Indiana had
the lowest rate in the ORBES region (705.6 deaths per 100,000 persons), while
West Virginia had the highest rate (772.2 deaths per 100,000 persons). In the
same year, the national average was 692.9-
Five indicators of health status were selected and analyzed statistically
at the county level to identify areas of health difficulty in the region.
These indicators are (1) age-adjusted death rates for all causes, (2) age-
adjusted respiratory cancer (lung, trachea, and bronchus) mortality for white
females, (3) the same cancer mortality for white males, (4) infant mortality
rates, and (5) the percentage of total deaths due to ischemic heart disease.
(Ischemia is disability due to reduced or suppressed blood supply.)
Of the six ORBES state portions, Kentucky and West Virginia display the
highest concentration of counties with high age-adjusted mortality rates, high
infant mortality rates, and high female respiratory cancer mortality rates.
However, Kentucky also exhibits a high concentration of counties with low male
respiratory rates and low ischemic heart disease mortality rates. As a
result, when individual death rate statistics are used to calculate a health
status index for each ORBES county, Kentucky is the state with the greatest
percentage of counties with high health status index values. West Virginia,
on the other hand, is the state with the greatest percentage of counties with
a low (unhealthy) index. Of the four remaining ORBES state portions, Illinois
displays a very high concentration of counties with high ischemic heart
disease mortality rates.
HEALTH SERVICES. To complement the health status information, health services
in the ORBES region also were surveyed, and a county-by-county ranking of
health service availability was performed. While there is some problem in
equating health service availability with equity of access or improved health
status as well as in equating health manpower with availability, health
service indices were constructed to permit comparisons to be made among the
ORBES county rankings.28
27 For a discussion of the region's health status, see Shapiro and Sooky,
Ohio River Basin Energy Study: Health Aspects.
pO
For a discussion of the limitations of the health availability
concept, of the data used, of its limitations, and for county-by-county
tables, see Shapiro and Sooky, Ohio River Basin Energy Study; Health Aspects.
Indices for individual categories—such as physicians, nurses, and
pharmacists—also are given in this report.
97
-------
For the most part, health service availability is directly correlated
with population: high-population counties rank higher in health service
availability than do counties with low populations. Mapping of this trend
frequently illustrates that such counties are often in close proximity—that
is, larger metropolitan counties are ranked high while immediately surrounding
or nearby counties are ranked low. Counties in the lowest tenth of the health
service availability ranking tend to be located south of the Ohio River
throughout the states of Kentucky and West Virginia, where counties usually
are less populated and/or are in or near mountainous areas. In fact, a high
concentration of low availability counties was noted in northeastern Kentucky
and northcentral West Virginia. In contrast, there is a high concentration of
counties with high health service availability rates in western Pennsylvania.
COAL-RELATED IMPACTS. The use of coal for electrical generation by utilities
results in potential health impacts in the ORBES region. These impacts are
related to the five steps of the coal fuel cycle: coal mining, coal
processing, coal transport, coal conversion, and waste disposal. In general,
projections of accidental injuries and deaths are built upon current knowledge
of cause-and-effect relationships. However, the health consequences of
chronic, relatively low-level exposure to several environmental contaminants
remain a matter of some controversy.
Coal Mining. The occupational health impacts related to mining are fairly
easy to document, primarily because annual data are kept nationally on
mining-related deaths, injuries, and disabilities. Nevertheless, variations
exist in the number of coal-related deaths, injuries, and diseases that have
been specifically attributed in the literature to coal demand by power
plants.29 in this study, rates were derived for the ORBES region based on the
1975 state coal-mining fatalities, injuries, and disabilities, on the 1975
coal purchases by ORBES power plants, and on the 1975 state distributions of
underground and surface mining.30 The number of coal-mining deaths, injuries,
and disabilities attributable in 1975 to ORBES power plant coal demand are as
follows: 37 accidental deaths, 2656 disabling injuries, 2198 nondisabling
injuries, 6 disease deaths, and 284 disease disabilities (including 13 to 51
new cases of disabling pneumoconiosis).
2^ For calculation of rates and a discussion of the ranges that exist in
the literature, see Shapiro and Sooky, Ohio River Basin Energy Study: Health
Aspects.
3° See Shapiro and Sooky, Ohio River Basin Energy Study: Health Aspects.
Because calculations were based on annual purchases, some of which are from
outside the region, a small portion of these health impacts (about 2 to 3
percent) occur outside of the region.
98
-------
The long-term health impacts of coal mining on the general public are not
well understood, especially since some of the effects created by coal
mining—such as fugitive dust and abandoned mine fires—are episodic,
localized, and the result of past mining practices. Therefore, it is not
possible at this time to quantify the health-impacts of these effects.
Coal Processing. The primary function of coal cleaning and processing is to
supply a feedstock that satisfies the physical and chemical specifications
required for final use. About 50 percent of the total coal output in the
ORBES region is mechanically cleaned and about 5.8 percent is thermally dried.
Health impacts from coal processing in the ORBES region include injuries
to cleaning plant personnel as well as indirect impacts from the release into
water of toxic trace metals from generated residuals. The first group of
impacts has been quantified and recorded for the past sixty years. The second
group of impacts, however, is extremely difficult to quantify due to many
site-specific modifying factors.
Data for the period 1972 through 1976 indicate that a yearly average of 3
fatalities and 198 disabling injuries were associated with coal processing for
ORBES-region power plants.31 It should be noted, however, that in some years
the ORBES region sometimes accounts for a majority of the deaths and injuries
reported nationally for coal cleaning by mechanical plants. For example, all
of the 1974 and 1976 fatalities reported at mechanical coal-cleaning plants
occurred in the study region, and the disabling injuries included in the
statistics were reported mainly in ORBES-region plants. Within the region,
three ORBES states—Kentucky, Pennsylvania, and West Virginia—consistently
account for most of the fatalities and the major share of the disabling
injuries in the study region. (Health aspects due to disease-related deaths
and illnesses could not be determined because the effects are not known.)
According to 1976 data, coal processing results nationally in about 100
million tons per year of refuse. Coal wastes contain a broad array of trace
or minor elements such as lead, arsenic, mercury, and cadmium. The presence
of these elements is of some concern because of their toxicity and because of
the low tolerance of plants and animals to them. Coal-processing refuse also
is a significant source (about 25 percent of the total from all mining
operations) of acid residues, which can leach into water, and is a major
source of trace elements in leachates. However, as in the public health
impacts of mining, there is as yet no basis for providing quantitative
estimates of these public health impacts of coal processing.
o 1
J See Shapiro and Sooky, Ohio River Basin Energy Study; Health Aspects,
for the method of calculation.
99
-------
Coal Transportation. Since most of the indirect damage of coal transportation
is due to the air pollution generated by the transportation units, and since
such damage cannot be quantified at the present time, only accidental injuries
and deaths are reported. For the general public, these injuries and deaths
are related to railway grade-crossing, switching, and yard accidents as well
as to truck collisions on highways.
In the ORBES region, about 68 percent of the coal is shipped by rail;
another 14 percent, by barge; and another 12 percent, by truck. The remaining
portion is transported by other means or goes directly by conveyor belt to
mine-mouth plants. The health impacts associated with coal transportation to
ORBES-region power plants are the highest for train transportation and the
lowest for barge transportation. However, both train and truck health impacts
vary according to whether statistics based on weight transported or miles
traveled are used. Thus, there is variation in the estimates of the total
deaths and injuries in 1975 attributable to the transportation of coal to
ORBES-region power plants. If the miles traveled are used, approximately 12
deaths and 48 injuries are attributable to such demand. If the weight
transported is used, approximately 49 deaths and 207 injuries are attributable
to such demand. Both occupational and public deaths and injuries are included
in these estimates, although deaths are suffered mostly by the public sector
while the injuries are fairly evenly divided between the two sectors.32 In
general, if statistics based on the weight transported are used, health
damages are relatively high because, compared to most freight, the density of
coal is high (except for barges). Assigning health damages based on the miles
traveled probably results in a slight underestimate because the heavy weight
of coal may lead to greater probability of injury in case of accidents.
Coal Conversion. Substantial controversy exists about the quantification of
the morbidity and mortality attributable to the increased air pollution
resulting from the burning of coal to produce electricity. New information on
the subject continues to be published. The problem becomes increasingly
difficult as ambient concentrations are reduced from the high concentrations
that prevailed in well-known air pollution episodes. However, a number of
conclusions about the current state of knowledge can be drawn. For one, only
a few studies prior to 1970 can be relied on to provide any quantitative
estimate of risk. This is due primarily to the lack of reliable pollutant
measurements and the confounding aspects of personal risks that derive from
cigarette smoking and from occupational and indoor exposure. Also, sulfur
dioxide, by itself, in concentrations of 500 micrograms per cubic meter or
^2 For a fuller discussion of the calculations involved and of the
differences between ton-miles and vehicle-miles, see Shapiro and Sooky, Ohio
River Basin Energy Study: Health Aspects.
100
-------
less, has no significant short-term effect on respiratory mechanics, symptoms,
or disease.
Recently it has been possible to relate acute morbidity and mortality
from cardiovascular disease, but not respiratory disease, to total suspended
particulates in the range of 300 micrograms per cubic meter and higher over a
period of several years. Recent studies suggest that particulates in this
range are associated in a reasonably dose-related fashion with an increased
mortality rate. However, an increased mortality rate is correlated less, if
at all, with sulfur dioxide. In addition, there is evidence to support the
hypothesis that cardiovascular disease is the principal cause of mortality
associated with acute air pollution effects. Unfortunately, the biological
mechanisms by which inhalation of airborne particulates influences
cardiovascular disease mortality remain obscure.
An analysis of recent data indicates that cardiovascular mortality is
increased by 5 percent with sustained, long-term (several years) exposure to
airborne particulates at a concentration of about 350 micrograms per cubic
meter. If such an increased risk is scaled down to possible annual urban
levels (100 micrograms per cubic meter) and then adjusted for the population
exposed and the contribution of utility emissions, the maximum number of
annual cardiovascular deaths per 1000 megawatt plant is about three. This
projection is an upper limit. The lower limit is zero because the defense
mechanisms of the body may be able to cope with low-dose exposures without any
significant effect on cardiovascular disease.33
Other researchers, however, believe that a growing body of evidence
supports the hypothesis that the annual average exposure to sulfates—or
something closely related to them—results in an increased mortality rate.34
According to this line of thought, long-term exposure to air pollution,
particularly in childhood, increases susceptibility to respiratory infection;
a history of repeated respiratory infection, possibly coupled with continued
air pollution exposure, then increases the prevalence of chronic respiratory
disease, leading to more deaths from a broad range of cardiopulmonary
diseases. Based on this sequence, these researchers project annual deaths
attributable to sulfate air pollution in terms of damage functions of 0 to 9
00
See Shapiro and Sooky, Ohio River Basin Energy Study; Health Aspects.
and Radford, Impacts on Human Health.
See Leonard D. Hamilton, "Areas of Uncertainty in Estimates of Health
Risks" in Symposium on Energy ^nd Human Health. For disagreement with this
approach, see Radford, Impacts on Human Health. For a discussion of both
sides, see Shapiro and Sooky, Ohio River Basin Energy Study: Health Aspects.
101
-------
deaths per 100,000 persons exposed per microgram per cubic meter. On the
basis of a damage function of 3 deaths per such exposure (which is close to
the median value of the proposed health damage functions), it can be
calculated that 8000 deaths occurred in the ORBES region in 1975 due to
sulfate air pollution by ORBES electrical generating facilities—provided that
the same conditions would be maintained steady-state for a sufficient number
of years to allow full development of the impact. However, the possibility
exists that the attributable 1975 mortality is as low as zero or as high as
25,000. The figure of 8000 yearly deaths constitutes about 3.6 percent of the
total 1975 mortality in the ORBES region.
The fact that this sulfate damage figure is nearly 40 times higher than
the cardiovascular-particulate damage figure points up the current uncertainty
in estimating a relevant damage function. Thus, while these quantitative
estimates of health impacts are helpful in grasping the magnitude of the
impact, they must be considered in light of unquantified potential effects of
air pollution and in light of other uncertainties in the many related factors,
such as background levels, time distribution of induced deaths, and the
variability in individual responses to air pollutants. The major usefulness
of the damage function for the ORBES study lies not in the accuracy of the
estimated health impacts but in the comparison of the impacts between the
various scenarios.
Occupational injuries among workers at coal-fired plants average about
0.02 fatalities per year per 1000 megawatts and about 1.2 disabling injuries
per year per 1000 megawatts.35 jn terms of occupational disease among such
workers, the same controversy about the quantification of morbidity and
mortality exists as outlined in the last two paragraphs.
Waste Disposal. As yet no evidence exists of public health impacts related to
waste disposal, although the potential exists for the leaching of potentially
hazardous wastes from storage areas into water supplies. The possibility of
workers' exposure to fugitive dusts from waste storage also exists, but the
potential effects of such exposure are unknown.
NUCLEAR IMPACTS. There are nine possible steps in the nuclear fuel cycle:
mining, milling, conversion, enrichment, fuel fabrication, power generation,
reprocessing, waste management, and transport. However, not all of these
steps,are currently carried .out in the ORBES region or in the nation. Within
the ORBES region, only the uranium enrichment, the fuel fabrication, and the
35 For a discussion of these rates, see Radford, Impacts on Human Health.
102
-------
power generation steps take place at present.3" Assuming a single year of
exposure, three steps in the nuclear cycle—the mining, milling, and power
generation steps—are expected to result in a total incidence of lifetime
cancers among the general public of between 0.03 and 0.05 cases per year per
1000 megawatts electric of nuclear power production.3? Roughly half of these
cases would be associated with the power generation step. In 1976 in the
ORBES region, 10 million megawatts were produced by nuclear-fueled power
plants. Thus, between 150 and 250 cases of cancer are expected to have
occurred in 1976 because of nuclear power generation. (No attempt was made in
this study to quantify possible genetic effects from accidental releases.)
Occupational health effects related to the nuclear fuel cycle can be
presented with more certainty than can those for the general population.
However, neither possible genetic effects nor the risks from accidental
releases were quantified for workers.
The whole-body annual exposure of all workers—but primarily those in the
power generation step—results in about 0.2 to 0.8 excess lifetime cancers per
year for each 1000 megawatts of electricity generated. For miners, millers,
and fuel fabrication workers, who receive significant lung doses from alpha
^ For a full discussion of all of the steps in the nuclear fuel
cycle—some of which have much severer health impacts than indicated for the
ORBES region—see Radford, Impacts on Human Health. See also Steven D. Jansen
et al., Nuclear Energy Risks and Benefits (ORBES Phase II). Estimates in the
Radford report are derived from the March 1979 draft report of the Advisory
Committee on the Biological Effects of Ionizing Radiation (BEIR Committee),
U.S. National Academy of Science.
Of
For each 1000 megawatts of nuclear-fueled electricity generated each
year, the following exposure rates were assumed. For the general public, the
whole-body total exposure (measured in person-rems) is less than 1 for the
enrichment and fabrication steps and 20 for the power generation steps;
individual maximum exposures (measured in rems per year) are 0.006 (lung) for
the enrichment step, 0.005 (lung) for the fabrication step, and 0.01 (thyroid)
for the power generation step. The number of workers exposed each year was
assumed to be about 500 for the enrichment step and about the same number for
the fabrication step; for the power generation step, about 800 workers were
assumed to be exposed each year. The whole-body total exposure for these
workers is 25 for the enrichment step, 100 for the fabrication step, and 800
for the power generation step. Individual occupational average exposures
(rems per year) are 0.05 (whole body) for the enrichment step; 10 (lung) and
0.2 (whole body) for the fabrication step; and 1.0 (whole body) for the power
generation step. See Radford, Impacts on. Human Health.
103
-------
radiation, additional lung cancers will occur from this exposure—about 1.3
excess lung cancers from a year's exposure. Thus, the total lifetime excess
cancers arising from annual occupational exposures in the nuclear fuel cycle
range from 1.5 to 2.1 per year for each 1000 megawatts generated. Other
occupational health impacts were examined, and the following rates per 1000
megawatts generated were projected: a 2.0 trauma rate, an 0.5 silicosis rate,
and an 0.5 chronic lung disease rate.
ELECTRICAL TRANSMISSION IMPACTS. One final area of potential health effects
related to electrical generation involves the transmission of electricity.3°
Possible risks to both the general public and power line workers include the
effects of electric and magnetic fields, the effects of corona around
transmission lines, and accidental injuries and deaths from fallen or broken
transmission lines. Occupational risks also include the risks associated with
direct contact with high-voltage terminals or other low-resistance pathways.
In studies to date, no general public health effects from transmission
lines have been demonstrated other than those resulting from accidents
involving fallen or broken lines. Besides accidental deaths and injuries, the
same statement is true for persons employed in transmitting electricity.
However, many of the studies tend to examine short-term effects. Studies on
long-term effects would give a better understanding of the risks involved in
this phase of electrical generation.
4.7 Social Conditions
Basic social measurements of population, schooling, employment, housing,
and income trends indicate that in many respects the ORBES region is quite
different from the United States as a whole.39 por example, regional
population is growing at a slower rate than is national population, and
housing prices are lower in the region than in the nation. In general, the
region is one of contrasts. It contains heavily industrialized metropolitan
areas; intensively farmed, low-population sections; and extensive portions
with low population and only minimal economic activity.
~> For a discussion on the health impacts of electrical transmission, see
Radford, Impacts gn Human Health.
3" The most recent data were used for each of the social measurements
discussed in this section. In some cases, however, data from 1970 constituted
the only available information. It is recognized that updated information
could change some of the conclusions in this section.
^ For details on current social indicators in the study region, see the
following ORBES Phase I reports: Preliminary Technology Assessment Report
104
-------
In 1977, the ORBES region had 23.7 million inhabitants, about 11 percent
of the 1977 U.S. population of 216.4 million. The ORBES state portion of Ohio
accounted for most (31 percent) of this 1977 regional population (see figure
4-13 for the contributions of the other state portions).
If both crude death and birth rates in 1977 are considered, it appears
that there is a smaller rate of natural population increase in the region than
in the nation as a whole.1*1 The crude birth rate in the ORBES region in 1977
was only slightly higher (about 1 percent) than in the nation in that year,
while the crude death rate in the ORBES region in 1977 was considerably higher
(12.5 percent) than in the nation. However, fertility rates in the ORBES
region have usually been lower than in the nation as a whole. In 1960 and
1970, for example, fertility rates (measured in the lifetime number of births
per woman) in the region were 4.1 percent and 2.6 percent lower, respectively,
than were national rates. Between 1970 and 1978, regional population grew by
about 750,000 persons due to natural increase. During this period, however,
more persons left the ORBES region than entered the area; the total number of
persons who left the region was approximately 352,000.
Rgure4-13 ORBES—Region Population
Distribution, by State Portion
•31%
17%
wv-
•15%
•14%
-8%
vols. Il-a, II-B, and II-C. See also James J. Stukel and Boyd R. Keenan,
ORBES Phase I: Interim Findings. The following ORBES Phase II reports
provide further details: Vincent P. Cardi, ed., West Virginia Baseline;
Maurice A. Shapiro, ed., Pennsylvania Baseline; and David S. Walls et al., A
Baseline Assessment of Coal Industry^ Structure in the Ohio River Basin Energy
Study Region.
41
Crude death and birth rates are gross rates; that is, they have not
been adjusted for age or any other variation.
105
-------
EDUCATION. The regional population has less education than the national
population. In 1970, the average schooling in the region was 9.7 years per
person, compared with 12.2 years in the United States as a whole.
EMPLOYMENT. In 1970 the ORBES workforce (the number of employed persons)
totaled about 8.8 million. The regional unemployment rate was about 5.8
percent, compared with the national rate of 5.4 percent in that year. The
average number of employees per county in 1970 was about 20,000. About 3
percent of the 1970 workforce (276,000 persons) was employed in agriculture.
Among the ORBES state portions, Illinois accounted for the most agricultural
employment in 1970 (about 29 percent of the regional total). The Indiana
state portion accounted for about 20 percent; the Kentucky portion, for 25
percent; the Ohio portion, for 19 percent; the Pennsylvania portion, for 4.8
percent; and the West Virginia portion, for 2.5 percent.
In 1977 in the ORBES region, about 28 percent of the workforce (2.5
million people) was employed in manufacturing. Among the six state portions
in 1977, Ohio accounted for most of the manufacturing employment (about 36
percent of the regional total). The Indiana state portion accounted for 20.7
percent of the regional total; the Pennsylvania portion, for 1*1.9 percent; the
Illinois portion, for 12 percent; the Kentucky portion, for 11.3 percent; and
the West Virginia portion, for 5.1 percent.
About 2 percent of ORBES-region inhabitants (or 212,000 people) were
employed in mining in 1977. Among the ORBES state portions, West Virginia
accounted for most of the coal-mining employment (about 32 percent of the
regional total), followed by Kentucky (22 percent), Pennsylvania (19 percent),
Ohio (11 percent), Illinois (11 percent), and Indiana (4 percent). The
ORBES-region mining workforce in 1977 represented about 80 percent of all U.S.
miners.
HOUSING. In general, housing rates (prices for both rental and purchase) in
the ORBES region are lower than in the rest of the nation. In 1970, the
average of the median rental among the six ORBES state portions was $85 per
month, with a range of $40 to $130 among all ORBES counties. In the nation in
1970, the median rental was $89 per month.
In both the ORBES region and the United States, areas with fewer new
units and more older units could experience housing problems with an increase
in population since a higher proportion of older units indicates a relatively
inactive housing construction industry. In the ORBES region, 48.7 percent of
the housing was built before 1939; the comparable figure for the nation is
40.6 percent. Within the region, 22.3 percent of the housing was built after
1959; in the nation, 24.7 percent was built after that year.
INCOME. Income is another key social indicator. Compared to the U.S. median
income, median income in the ORBES region is low, due in large measure to a
106
-------
number of poverty pockets. Across all ORBES counties, the median family
income in 1970 was $7672, with a range among these counties of $11,694 to
$2407. The median U.S. family income in 1970' was $10,480. However, per
capita income is only slightly different in the nation and the region. In
1975, for example, average regional per capita income was $4517; average
national per capita income, $4572. On the other hand, the region has a higher
percentage of families below the poverty level than does the nation. In 1970,
16 percent of the families in the ORBES region were below the poverty level.
In comparison, about 11 percent of families in the nation were below the
poverty level in that year. Among the 423 ORBES counties, the proportion of
families below the poverty level ranged from 2.4 to 61.6 percent of the
families in each of these counties.
4.8 Social Values
A secondary analysis of studies conducted in the six ORBES states between
1974 and 1979 indicates how the values held by the residents of these states
h o
relate to energy policy.^^ In this analysis, seven key values were examined
as they relate to the residents' responses about energy. These values are
conservation/preservation, economic benefit, equity, freedom and government
activity, progress/growth,^ health/safety, and material comfort.
Conservation/preservation implies "doing more with less"; the objective
is to use more energy-efficient technologies to produce the same output of
goods, or simply to use or produce less energy, with resulting changes in
lifestyle. Economic benefit refers to the tendency to evaluate things and
people in monetary terms, and equity is the degree of fairness and social
justice associated with the distribution of costs and benefits. Freedom and
government activity are discussed here not as separate values, but as opposite
ends of a continuum. Freedom refers to allowing a person maximum choices,
with only limited control by others over what the individual may do; the
control operates through group norms rather than formal laws. In contrast,
42
Illinois data were available for the ORBES portion of the state;
Pennsylvania data, for counties in the southwestern part of the state. For
the four other ORBES states, data were statewide. See Harry R. Potter and
Heather Norville, Ohio River Basin Energy Study: Social Values and Energy
Policy (ORBES Phase II).
i|0
The separate concepts of progress and growth were grouped for this
analysis; it is recognized that they are not necessarily identical. However,
many definitions of progress imply economic growth and increased material
accumulation.
107
-------
government activity is intervention by government to facilitate, inhibit, or
regulate certain decisions and actions through policies and legislation.
Progress/growth is an important value with respect to energy development
because it emphasizes the future rather than the past or present; a
receptivity to change is implied, as well as a belief that things in general
can and should be made better. The value of health/safety implies giving high
priority to citizens' health and to devoting resources to ensure good health
for as many people as possible; it also includes the desire for healthful and
safe surroundings. Material comfort involves an orientation toward the
acquisition of goods and/or the concept that self-esteem is linked to material
worth.
In general, it appears that in the region, as in the nation as a whole,
no one value has predominant importance over all others. Rather, people
strive to achieve a balance between competing values when confronted with
difficult choices. The analysis also suggests that when people are asked to
choose among energy policies, they do not necessarily choose those that would
be in their own self-interest. For example, although the majority may favor
policies that provide financial rewards for insulation and oppose policies
that would increase fuel taxes, they also may favor conservation policies and
equity even though these may lead to increased costs. In addition, although
people may express verbal support of a certain action in response to survey
questions, their actual behavior may not match their stated willingness.
CONSERVATION/PRESERVATION. The responses that seem to stress
conservation/preservation as a value begin to demonstrate some of these
complexities. Studies in the six ORBES states and the nation have found a high
degree of willingness among respondents (ranging from 55 to 95 percent) to
engage in such conservation/preservation practices as recycling, traveling
less, turning down the heat in winter, improving home insulation, and using
fewer electrical appliances. However, support for government activity aimed
at achieving conservation/preservation appears to vary.
In general, the analysis shows that respondents support government
policies aimed at achieving conservation through positive rewards for
conservation. But they oppose policies that have negative sanctions for not
conserving, such as rationing and higher fuel prices. Similarly, support for
conservation/preservation is divided when the values of freedom, material
comfort, or economic benefit are seriously threatened. For example, a 1975
Kentucky study showed a majority of the respondents (53 percent) were opposed
to regulations that would ensure that people use less fuel. Yet, in the same
study, a majority of the respondents (71 percent) favored stricter regulations
that would require industries to use less fuel. However, a majority also
expressed support for policies that would preserve the environment even though
such policies would cost them money; 85 percent favored stricter regulations
requiring industries to pollute less even though products might cost more.
108
-------
Support or opposition for a government policy that encourages
conservation also can vary according to income, race, and other variables.
For example, in a national study, unlike the majority in the Kentucky study, a
slight majority of respondents with incomes below $7000, a slight majority of
blacks, and a slight majority of farmers favored a policy whereby the
government would ration family energy consumption and the family would decide
how to apportion its use.
Similar differences related to age, sex, income, and education can be
found in the ORBES states when people are asked about what they are doing to
conserve energy. In a 1978 Illinois study, the respondents with higher
incomes were more selective in their conservation practices; like other people
they tended to conserve energy for heating and air conditioning, but they
indicated that they were much less likely to live in a smaller house or to use
appliances less. In the same study, female respondents were more likely to
say they were conserving than males. Also in the Illinois study, older
persons were as likely as younger people to approve home insulation. Unlike
the same group nationwide, more older persons in the Illinois survey reported
that they were using fewer appliances and living in a small house or apartment
to conserve energy.
ECONOMIC BENEFIT. As the Kentucky study referred to above begins to suggest,
and as data from other states and the nation support, the economic benefit of
a situation is important, although it is not the single criterion people use
in choosing among policies. Most of the available data are based on trade-
offs between this value and others. In many instances, respondents are
willing to endorse certain costs when the choice is posed against other
values, such as government activity, health/safety, and conser-
vation/preservation. Thus, 85 percent of the Kentucky respondents supported
government control of industrial pollution even if the prices of products were
to rise, and 85 percent also expressed strong support for more government
spending to develop new energy sources.
EQUITY. Equity also has varied support as a value within the region.
Although data on equity as a value are limited, they indicate that social
class factors and age relate quite consistently to views on equity issues.
Data also indicate support for policies that would help compensate the poor or
elderly for added energy costs due to policies designed to conserve energy
through increased prices, such as price deregulation.
In a 1978 Illinois study, 63 percent of the respondents were willing to
see tax money spent to help pay the heating bills of low-income people.
However, a closer look at these responses shows that those with less education
and lower incomes, as well as older respondents, place greater stress on
equity than those with college degrees and higher incomes or than younger
respondents. For example, about 74 percent of the respondents with annual
109
-------
incomes below $9000 favored spending tax money to help low-income people with
heating bills, compared with only 51 percent with incomes of $25,000 to
$39,999 and 43 percent with annual incomes of $40,000 or more. In the same
study, older people favored the "equity" answer (that is, providing tax
dollars to low-income people) more than younger people did. These responses
appear to be very similar to nationwide attitudes.
Equity as a value also is supported when it benefits those whose efforts
have been largely responsible for the potential benefits. Thus, enforcement
of a policy returning the coal severance tax to coal-producing counties is
favored strongly by Kentuckians (82 percent of those surveyed), with only
small variations across the social and demographic factors studied.
FREEDOM AND GOVERNMENT ACTIVITY. As some of the above responses to
governmental policies suggest, respondents value both freedom and governmental
activity. Of particular importance for policy choices is the respondents1
tendency to support government activity strongly when it provides direct
benefits to people, not to industry. An example of such a tendency is the
Kentucky respondents' opposition to regulation of consumer fuel use and their
support for regulation of industrial fuel use. Similarly, a 1978 study in
Ohio found a majority of the respondents (65 percent) opposed to deregulation
of natural gas because it would lead to major cost increases.
However, there can be substantial regional variation, as well as
variation by social class, on support of the use of tax dollars to attract new
industry to respondents' areas. In 1975, most Kentucky respondents who
resided in rural areas and towns with populations under 10,000 favored using
more tax money for this purpose, compared with only about one-third of those
in the larger urban areas in the state. In Illinois the older respondents
were more likely to favor the use of tax dollars to attract new industry,
although 73 percent overall were willing to see tax dollars used for such a
purpose.
Support for government activity also seems to be strong when it promotes
equity, progress/growth, and health/safety. As noted, Kentucky respondents
favored government regulations to curb pollution, and Illinois respondents
favored the use of tax dollars to help the disadvantaged with added energy
costs.
State and national studies thus show people can be quite divided with
regard to the role government should play in conserving energy or in
developing new sources of energy. For example, in both state and national
studies, some groups, such as farmers, consistently favored voluntary action
rather than government-mandated action with regard to energy policy.
PROGRESS/GROWTH. As both the varied support for governmental encouragement of
new industries and the varied support for governmental encouragement of new
110
-------
energy sources suggest, support for progress/growth as a value can be varied.
In general, a positive attitude toward progress/growth is shown quite
frequently through the need many people express for new jobs and new industry,
often naming the lack of available employment opportunities as the most
frequent community problem. However, substantial concern also is indicated at
times for the environmental and inflationary effects of growth. The data thus
suggest that ORBES-region residents tend to value progress/growth selectively,
favoring it under certain conditions and opposing it under others.
HEALTH/SAFETY. Even though many ORBES-region residents may favor new industry
and new energy sources under some circumstances, they do not accept such
development without qualification when associated risks to health and safety
are present. Both regionally and nationally, health/safety is of major
importance. Nationally, a majority of respondents indicate strong concern
about the effects on health and safety of industrial installations and power
plants (both coal fired and nuclear fueled). A majority also were willing to
pay $30 more per year to cut down on air pollution caused by power plants.
MATERIAL COMFORT. Respondents in both the region and the nation also rank
material comfort as an important component of their lives. Nationally, the
majority of Americans surveyed (71 percent) felt that allowing the mass of
people to share a high standard of living was a major factor in making the
nation great. However, people are willing to trade material comfort for
economic benefit. For example, the majority surveyed (76 percent) preferred
lowering the heat in their homes to paying $70 more per year for fuel.
In the ORBES region, views on material comfort vary with income and
education—just as have the views on many of the other values discussed. In
Illinois and Kentucky, for example, those with more education have expressed
more willingness to lower their thermostats in the winter than the same group
has in the nation. Similarly, in both Illinois and Kentucky, about 70 percent
of those with less than a high school education and three-fourths of those
with low to modest incomes (less than $10,000 per year) have reported that
they are willing to move to smaller quarters, while only . 50 percent in
Illinois and 60 percent in Kentucky with a high school education or more, and
less than half in both states with incomes of $20,000 or more, have expressed
willingness to do the same.
111
-------
-------
COAL-DOMINATED FUTURES
As documented in previous chapters, the Ohio River Basin Energy Study
region is heavily concentrated in the use of coal for electrical generation.
This condition is unlikely to change during the remainder of this century.
Therefore, the regional energy-environmental futures, or scenarios, chosen for
the most detailed impact analysis stress the continued use of coal for
electrical generation. *
All ORBES scenarios are derived from an array of policy assumptions about
various conditions in the study region from the base period (the mid-1970s)
through the year 2000. These assumptions, plus data on current conditions and
the results of various scenario models, are the basis for construction of the
scenarios themselves. Each scenario analyzed is characterized in terms of
basic policy assumptions, exogeneous variables (such as the growth in the
demand for electricity), energy and fuel use, siting patterns for electrical
generating units, sources of coal supply, and underlying dominant social
attitudes.
The basic scenario with which all other scenarios are contrasted is
termed the base case. The conditions assumed in the base case are comparable
to but not projections of 'current conditions in the ORBES region. For
example, fuel use patterns and energy growth rates reflect a range of
plausible futures, but they are not simple extrapolations of historical
trends. Impacts of the base case in the year 2000 are compared with current
conditions in the region, while impacts of the four other coal-dominated
scenarios are compared with those of the base case. These latter scenarios
are the strict environmental control case, the SIP noncompliance case, the
high electrical energy growth case, and the electrical exports case. The
coal-dominated futures are described in chapter 5.
Five major impact areas are considered for each scenario: air, land,
water, employment, and health. In chapter 6, these impacts are compared
across scenarios. Impacts of each scenario then receive detailed treatment.
First, impacts of the base case are compared with current conditions (chapter
7). Impacts of the remaining coal-dominated futures then are compared with
base case impacts: the strict environmental control case in chapter 8, the
SIP noncompliance case in chapter 9, the high electrical energy growth case in
chapter 10, and the electrical export case in chapter 11.
113
-------
The analysis of these coal-dominated futures reveals that the changes in
air quality would have the most wide-ranging impacts under the various
policies examined. In chapter 12, a number of technical and organizational
strategies to mitigate these air-related impacts are discussed.
114
-------
5. Descriptions of the Coal-Dominated Scenarios
As discussed in chapter 3 and in the introduction to this part of the
report, the five scenarios chosen for the most detailed impact analysis call
for the continued use of coal for electrical generation in the ORBES region
through the year 2000. However, a variety of policy assumptions differentiate
these coal-dominated futures from each other.
As shown in figure 5-1, the base case is the scenario to which all others
are compared. Although the base case is relatively conventional in terms of
its assumptions about the ORBES region—following historical trends—there are
two major exceptions. The first exception is that the assumed rate of
regional electricity demand growth is historic only through 1985. From 1985
through 2000 a lower rate is assumed. The second major exception is that full
compliance with air and land environmental regulations is assumed; to date,
however, such compliance has not been achieved.
Figure 5-1 also shows the basic variations between the base case and the
other coal-dominated scenarios. The second coal-dominated future, the strict
environmental control case, differs from the base case only with regard to the
stricter environmental regulations assumed. On the other hand, air quality
regulations are less stringent than those of the base case in the scenario in
which noncompliance with state implementation plans is assumed. A high rate
of growth in the demand for electricity is another variation of base case
conditions. In the final coal-dominated future, the electrical exports case,
it is assumed that an additional 20,000 megawatts electric over that of the
base case will be installed in the ORBES region. The electricity generated
would be transmitted to the northeastern United States to replace oil-fired
generation in that part of the country.
.SOCIAL. VALUES. Two major sets of social values are implicit in the
assumptions made concerning the coal-dominated futures. These are (1)
economic benefit, material comfort, and progress/growth, which come from
policies that promote a high economic growth rate, and (2) government activity
and nationalism, especially in regard to fuel policy, since implementation of
these scenarios would decrease U.S. dependence on foreign oil. In addition,
an increased emphasis on health and safety is implicit in the strict
environmental control case.
See Harry R. Potter and Heather Norville, flhig River Basin Energy
Study: Social Values and Energy Policy (ORBES Phase II).
115
-------
Rgure 5-1
Major Variables and Comparisons
Base Case and Other Coal-Dominated Scenarios
Variations
in
environmental
controls
Noncompliance
with State
Implementation
Plans
Strict
Environmental
Controls
High
Electrical
Energy Growth
Electrical
Exports
Variations
in
electricity
demand
growth
POPULATION AND ECONOMIC GROWTH. The same annual regional population growth is
assumed for all ORBES scenarios. Between 1970 and 2000, population would grow
by 15 percent, resulting in a regional population of 26.6 million persons in
the year 2000, or 3-5 million more than in 1970. The same fertility rate also
is assumed for all scenarios: 2.1 lifetime births per woman (that is, the
population replacement rate). Also common to all the scenarios is the assumed
regional economic growth rate: an annual average rate of 2.47 percent between
1974 and 2000.
See Walter P. Page, Doug Gilmore, and Geoffrey Hewings, An Energy and
Fuel Demand Model for the Ohio River Basin Energy Study Region (ORBES Phase
II).
116
-------
ENVIRONMENTAL STANDARDS. Among the coal-dominated scenarios, environmental
standards are assumed to be the Same for the base case, the high electrical
energy growth case, and the electrical exports case. Most of these assumed
standards are defined in terms of what currently exists as applied to present
and future sources of pollution. For air, controls are defined as the
application of existing standards (as of September 1978) contained in the
state implementation plans (SIPs) developed for specific states under the
Clean Air Act. New source performance standards (NSPS) or revised new source
performance standards (termed RNSPS in this report) are applied to all new
sources of pollution, according to when they are scheduled. The controls for
land reclamation are derived from federal standards prior to the 1977 Surface
Mining Control and Reclamation Act. For water, the standards consist of
current practices for the design and construction of industrial, municipal,
and electrical generating facilities. Wasteload management practices,
however, reflect treatment and recycling practices of older sources rather
than the practices performed by new sources. With regard to environmental
protection of air and land quality, then, the base case, the high electrical
energy growth case, and the electrical exports case reflect the full
implementation of current policies.
The strict environmental control case calls for more stringent
environmental regulations. In the case of air, strict controls mean that the
generally stringent pollutant emission standards for urban areas set by
current (as of September 1978) state implementation plans would be applied
throughout a state. For water, guidelines were developed under strict
controls that would reduce power plant effluents by about 95 percent from base
case conditions. It also was assumed that strict environmental controls would
result in a two-fold drop in stream pollutant background levels by the year
2000; in reality, however, such a decrease is unlikely. Strict environmental
controls on land reclamation call for interim and permanent performance
standards under the Surface Mining Control and Reclamation Act of 1977, but
with strengthening of site-specific applications; state standards may exceed
o
See James J. Stukel, ed., Ohio River Basin Energy Study: Air Quality
and Related Impacts (ORBES Phase II) (3 vols.), for descriptions of air
quality paramaters under all the scenarios.
4
See J.C. Randolph and W.W. Jones, Ohio River Basin Energy Study: Land
Use and Terrestrial Ecology (ORBES Phase II), for land reclamation assumptions
under the various scenarios.
5
See Clara Leuthart and Hugh T. Spencer, Fish Resources and Aquatic
Habitat Impact Assessment for the Ohio River Basin Energy Study Area (ORBES
Phase II), for the water-related assumptions made under the scenarios.
117
-------
federal ones. Special interim and permanent standards are applied to steep-
slope mining, mountaintop removal, the mining of prime farmland, and the
surface effects of-underground mining.
In the SIP noncompliance case, environmental regulations for land and
water are the same as in the base case. With regard to air, however, it is
assumed that present state implementaion plans will not be enforced.
Currently SIPs for sulfur dioxide and particulates exist in all six of the
ORBES states. A SIP for oxides of nitrogen exists only in the urban areas of
Illinois.
ENERGY AND FUEL USE. The coal-dominated futures are further defined by a
variety of energy and fuel use characteristics; growth rates for the various
sectors under each scenario appear in table 5-1. The push to coal produces
large percentage increases in the use of regional coal between 1974 and 2000,
decreases in the use of natural gas, and modest increases in the use of
refined petroleum products. Electricity.growth ranges from an annual average
rate of 3.13 in the the base case, the strict environmental control case, and
the SIP noncompliance case; to 3-20 percent in the electrical exports case; to
3.90 percent in the high electrical energy growth case. The high rate of
electricity demand growth under the latter scenario is that suggested^ in
recent estimates made by the National Electric Reliability Council (NERC).
The varying assumptions about electricity demand growth lead to an
installed regional electrical generating capacity of 153,245 megawatts
electric in the year 2000 under the base case, the strict environmental
control case, and the SIP noncompliance case; 173,395 megawatts under the
electrical exports case; and 178,372 megawatts under the high electrical
energy growth case. Coal-fired generating units are assumed to have 35-year
lifetimes under all scenarios except the high electrical energy growth case,
in which 45-year lifetimes are assumed.
COAL SUPPLY. In all ORBES scenarios, it is assumed that the coal to supply
regional generating units comes from Bureau of Mines (BOM) districts in the
six ORBES states (districts 1 through 4 and 6 through 11). In the high-sulfur
category (coal of 1.8 percent sulfur or more), the largest percentage increase
in coal production between 1974 and 2000 would occur in BOM districts 1 and 3-
The percentage of high-sulfur coal, both surface and underground, would remain
For discussion, see Page, Gilmore, and Hewings, An Energy and Fuel
Demand Model.
^ See Summary of Peak Load. Generating Capability, and Fossil Fuel
Requirements. 1979 (National Electric Reliability Council, July 1979).
118
-------
Table 5-1
Growth Rates and Installed Capacity, ORBES Region,
Coal-Dominated Scenarios (1974-2000), Annual Averages
Scenario
Base Case
Strict
Environmental
Controls
Noncompliance
with State
Implementation
Plans
High Electrical
Energy Growth
Exports of
Electricity
Economic Electricity
Growth Growth
2.47%
2.47%
2.47%
2.47%
2.47%
3.13%
3.13%
3.13%
3.90%
3.20%
Coal
Growth
2.40%
2.47%
2.40%
N/A
2.77%
Natural Gas
Growth
-0.40%
-0.40%
-0.40%
-0.40%
-0.39%
Refined
Petroleum
Growth
0.37%
0.37%
0.37%
0.37%
0.43%
Energy
Growth
1 .49%
1.53%
1 .53%
N/A
1.73%
Installed
Capacity
Year 2000
(MWe)
153,245
153,245
153,245
178,372
173,395
the same among scenarios, although there would be differences among coal
districts. As in the base year, districts 7 and 8 would provide no high-
sulfur coal in the year 2000. In the low-sulfur category (coal of less than
1.8 percent sulfur), the largest percentage increase in production between
1974 and 2000 is assumed to occur in BOM districts 1 and 3; output in
districts 7 and 8 is estimated to increase by a somewhat smaller percentage.
Among the ORBES scenarios, the absolute coal tonnages arising from the various
groups of districts would vary, but the percentage differences produced by
these groups of districts would be the same across scenarios.
o
SITING. In all ORBES scenarios, it is assumed that sited generating unit
additions in the region announced by utility companies as of December 31,
1976, including both coal-fired and nuclear-fueled facilities, will be built
as planned. The announced fuel type, unit size, and location are assumed to
Q
See Walter P. Page, An Economic Analysis of Coal Supply in the Ohio
River Basin Energy Study Region (ORBES Phase II), and Donald A. Blome, Coal
Mine Siting for the Ohio River Basin Energy Study (ORBES Phase II).
119
-------
Figure 5-2
Announced Coal-Rred Electrical Generating Capacity Additions,
ORBES Region, 1976-85
Megawatts
2001-3000
1001-2000
•1111501-1000
251- 500
101- 250
1- 100
[=Z|o
be identical to utility plans.The dates on which these facilities will come
on-line are assumed to be the same as those announced by the utilities.
Between 1976 and 1985, the utilities have scheduled 68 coal-fired and 13
nuclear-fueled electrical generating units of varying size in the ORBES
region. These 81 units total 43,799 megawatts electric. Most of this
capacity will be built along the main stem of the Ohio River (about 25,500
megawatts) and its tributaries (about 10,500 megawatts). Among the ORBES
For an inventory of existing and planned electrical generating units in
the six ORBES states, see Steven D. Jansen, Electrical Generating Unit
Inventory, 1976-1986; Illinois, Indiana, Kentucky, Ohio. Pennsylvania, and
West Virginia (ORBES Phase II).
Exceptions were made in the case of two scenarios (see chapter 13).
See Gary L. Fowler et al., The Ohio River Basin Energy Facility Siting Model:
Methodology (vol. I) (ORBES Phase II), for a full description of the siting
methodology.
120
-------
Figure 5-3
Announced Nuclear-Fueled Electrical Generating Capacity Additions
ORBES Region, 1976-85
Megawatts
2001-3000
1001-2000
501-1000
251- 500
101- 250
1- 100
state portions, most of the capacity additions are scheduled in Indiana, where
over 11,000 megawatts electric are planned, 80 percent coal fired and 20
percent nuclear fueled. Illinois follows, with about 8500 megawatts electric,
52 percent coal fired and 48 percent nuclear fueled. All of the nearly 9000
megawatts electric scheduled for Kentucky are coal fired. The remaining
capacity additions are accounted for in Pennsylvania (nearly 8000 megawatts
electric, 77 percent coal fired and 23 percent nuclear fueled), Ohio (less
than 5000 megawatts electric, 83 percent coal-fired and 17 percent nuclear
fueled), and West Virginia (slightly over 2500 megawatts electric, all of it
coal fired). Although additions scheduled from 1986 through the year 2000 are
less certain, nonetheless they also are assumed to come on-line as planned by
the utilities. The utility-announced coal-fired capacity additions scheduled
between 1975 and 1985 are depicted in figure 5-2; the utility-announced
nuclear-fueled capacity additions, in figure 5-3.
In order to fill the increment between electricity to be supplied by
planned coal-fired and nuclear-fueled facilities and the demand for
electricity projected under each scenario, standard 650 megawatt electric
coal-fired generating units are sited in the region after 1985. No additional
121
-------
nuclear-fueled generating units are sited to meet the scenario demands beyond
those already planned by the utilities. The siting patterns of the various
scenarios differ according to the policy assumptions made for each scenario.
Under the base case, 95 standard coal-fired units are sited in the study
region after 1985. These 95 incremental units are concentrated in counties
bordering the Ohio River main stem and its tributaries, particularly in the
upper Ohio River Basin along the main stem, in the coalfields of southeastern
Ohio, and in counties bordering the Monongahela and Allegheny rivers in
Pennsylvania. (The SIP noncompliance pattern is the same as that of the base
case.) Figure 5-4 depicts the coal-fired generating capacity in the year 2000
under the base case.
Although the installed capacity under the base case, the SIP
noncompliance case, and the strict control case is the same in the year 2000,
the strict environmental control assumptions lead to a more dispersed siting
pattern for post-1985 electrical generating unit additions. Capacity
additions along the middle and lower Ohio River main stem are concentrated on
the reach from Cincinnati, Ohio, to Louisville, Kentucky, and in southwestern
Indiana and southeastern Illinois in counties bordering the Wabash River.
However, strict air quality standards restrict the number of suitable sites
along the Ohio River main stem. Consequently, more units are located on
smaller tributaries away from the main stem, in areas of lower water
availability. Fifteen reservoirs are required to accommodate the dispersed
siting pattern. 3
The installed capacity is higher under the two remaining coal-dominated
scenarios, the high electrical energy growth case and the electrical exports
case. Under the high electrical energy growth scenario, additional units over
those of the base case are sited off the Ohio River main stem, on its major
tributaries. Under the electrical exports case, 20,000 megawatts electric
over the base case are sited to replace oil-fired capacity on the East Coast
with coal-fired capacity in the ORBES region. Because of the distances
involved in "transporting" the electricity to the East, the additional units
are sited in the eastern portion of the ORBES region and in close proximity to
See Gary L. Fowler et al., The Ohio River Basin Energy Facility Siting
Model: Sites and On-Line Dates (vol. II) (ORBES Phase II).
12
The siting patterns of all the coal-dominated scenarios appear in
Fowler et al., The Ohio River Basin Energy Facility Siting Model (vol. II).
1 ?
For details, see E. Downey Brill, Jr., et al., Potential Water
Quantity and Water Quality Impacts of Power Development Scenarios on Major
Rivers in the Ohio. Basin (ORBES Phase II).
122
-------
Table 5-2
Coal-Fired Capacity Additions, ORBES Region,
Coal-Dominated Scenarios, 1986-2000
ORBES
State Portion
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
Total Units
Number of Scenario Unit Additions
Base Case and Strict Environmental High Electrical
SIP Noncompliance Controls Energy Growth
13 13 18
18 18 25
16 16 28
20 20 32
14 14 16
14 14 25
95 95 144
Exports of
Electricity
13
18
18
33
19
25
126
Note: Standard coal-fired capacity additions are 650 megawatts electric per unit. Included in the figures are
units scheduled by the utilities through 2000; these units are of varying megawattage.
Rgure 5-4
Coal-Fired Electrical Generating Capacity,
ORBES Region, Base Case, Year 2000
Megawatts
3001 or more
2001-3000
1001-2000
101-1000
1- 100
123
-------
major coalfields. Those units dedicated to exports are added to existing
utility sites (either announced or designated in the base case). Each county
with scenario unit additions is limited to a total megawattage of 2600.
Table 5-2 presents the number of scenario unit additions for each of the
coal-dominated scenarios.
124
-------
6. Comparison of Impacts among Coal-Dominated Scenarios
In general, the different assumptions of the five ORBES coal-dominated
scenarios affect the level of utility air emissions more than they affect any
other impact area examined. The magnitude and distribution of these emissions
consistently correlate with ambient air concentrations and, thus, with crop
losses and emission-related mortality. Therefore, in section 6.1, the air-
related impacts of the coal-dominated scenarios are examined. In section 6.2,
some of the costs associated with the air-related impacts are discussed: (1)
cumulative capital costs for installing new generating capacity and pollution
control devices, (2) electricity prices, and (3) agricultural dollar losses.
Finally, in section 6.3, other environmental and social impacts that the
expanded generating capacity could entail are noted. In general, the impacts
of expanded regional generating capacity on regional land use, terrestrial
ecology, employment, and non-emission-related injuries and mortality are about
the same under the base case, the strict environmental control case, and the
SIP noncompliance case. The high electrical energy growth case and the
electrical exports case would result in greater impacts in these latter areas
than the first three coal-dominated scenarios. Regional water quality would
be affected similarly by the projected generating capacity, regardless of the
scenario.
6.1 Emissions, Concentrations, and Air-Quality-Related Impacts
SULFUR DIOXIDE
SIP Compliance. Under all the coal-dominated scenarios, total utility sulfur
dioxide emissions would decrease by the year 2000 from their 1976 levels (see
table 6-1).1 However, the rate of decrease and the actual totals in 2000
would vary among the scenarios (see figure 6-1). The scenario assumptions
that produce the differences charted in table 6-1 and figure 6-1 lead to
several observations about possible strategies to reduce sulfur dioxide
emissions at the individual plant level from their high 1976 levels. A fuller
discussion of mitigation strategies—both at the individual plant level and in
an organizational context—appears in chapter 12.
For a discussion of air pollutant emissions and the resulting
concentrations, see James J. Stukel and Brand L. Niemann, Documentation la
Support Q£ Kev ORBES Air Quality Findings: Teknekron Research, Inc., Air
125
-------
Figure 6-1
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Coal-Dominated Scenarios
w
o
c
o
7-
= 6-
w
O
5-
I 4-
Q)
CM
O 3-
CO
2-
1-
SIP-N
\ x^=
HEG
\
\
Base Case (BC)
— Strict Environmental Controls (SEC)
— SIP Noncompliance (SIP-N)
--High Electrical Energy Growth (HEG)
* Electrical Exports, emissions in 2000
•SEC
1976
1980
1985
1990
1995
2000
Table 6-1
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Coal-Dominated Scenarios
BC
SEC
SIP-N
HEG
EX
SIP
Total
SIP
Total
SIP
Total
SIP
Total
Total
1976
1980
1985
1990
1995
2000
7.95
5.60
4.73
3.98
2.93
8.94
8.14
6.10
5.55
5.16
4.35
6.89
2.49
1.94
1.55
1.15
(million tons)
8.94
7.08
2.99
2.74
2.73
2.55
9.50
9.88
9.00
7.85
6.47
8.94
9.62
10.10
9.45
8.66
7.55
7.65
5.45
5.20
4.91
4.32
8.94
7.84
5.93
6.07
6.24
6.06
8.94
4.55
126
-------
First, the base case, the high electrical energy growth case, and the SIP
noncorapliance case demonstrate how sensitive regional sulfur dioxide emissions
are to compliance with and enforcement of state implementation plans (SIPs).
Under both the base case and the high growth case it is assumed that complete
SIP compliance will occur by 1985.^ As a result, under both scenarios, total
utility sulfur dioxide emissions would be reduced continuously and
dramatically between 1976 and 1985, and at about the same rate. The SIP
noncompliance scenario, however, assumes that there will be no utility
compliance schedule; SIP units would continue burning historic coals and using
emission controls as in 1976. Thus, under this latter case, annual utility
sulfur dioxide emissions would increase between 1976 and 1985, ensuring that
the air quality problems of the base period would continue and perhaps get
worse. Since nearly the same annual electrical generation is assumed in all
of these scenarios through 1985, the immediate benefits of SIP compliance are
clear: total utility sulfur dioxide emissions could be reduced by one-third
by 1985 from their 1976 levels.
Plant Retirements. Utility sulfur dioxide emission patterns between 1985 and
2000 suggest yet another way to control emissions of this pollutant. After
1985, utility sulfur dioxide emissions under the same three scenarios would
parallel the retirement of SIP units, which would be replaced by units
governed by new source performance standards (NSPS) and revised new source
performance standards (RNSPS). Under both the base case and the noncompliance
case, it is assumed that SIP units will be retired after 35 years; under the
high growth case, generating units would have 45-year lifetimes.3 As figure^
6-1 indicates, sulfur dioxide emissions thus would decrease between 1985 and
2000 under the first two scenarios and would increase slightly under the last
scenario.
Quality and Meteorology in the Ohio River Basin; Baseline and Future Impacts;
and Teknekron Research, Inc., Selected Impacts of Electric Utility Operations
in the Ohio River Basin (1976-2000): An Application Qf the Utility Simulation
Model (vols. I, II, and III, respectively, of James J. Stukel, ed., Ohio River
Basin Energy Study: Air Quality and Related Impacts (ORBES Phase II)).
p
Most plants are assumed to comply with SIPs by switching to coals lower
in sulfur than those presently used or by switching to cleaned coals. Thus,
less than half the existing capacity would be retrofitted with flue gas
desulfurization devices ("scrubbers") under the base case. The costs of
retrofitting are discussed in section 6.2.
A 35-year life for coal-fired units would lead to the retirement of
about one-third of existing SIP capacity by the year 2000. A 45-year life
would lead to the retirement of only about 8 percent of existing SIP capacity
by that year.
127
-------
Figure 6-2
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Base Case and SIP Noncompliance Case
11-
10-
9-
co
c
0 8-
c
O 7-
-§. 6-
c
0 5-
co
CO
I 4-
CD
CM O _
0 3
(f)
2-
1-
^— - SIP-N, 55-year unit lifetime
-"'^ XN jf~
ys' ""^^ £— SIP-N, 45-year unit lifetime
x"x x~~ — -
\^ ~^x
Zv
x JIP-N, 35-year unit lifetime
^-^^
^^-— _^
^^^
>>.
j^
f
*- BC, 35-year unit lifetime
SIP Noncompliance (SIP N)
T 1 1 1 I 1
1976 1980 1985 1990 1995 2000
However, given the costs of installing new generating capacity and the
costs of complying with the stricter NSPS and RNSPS controls, it is quite
possible that utilities may postpone the retirements of SIP units. Under two
scenarios—noncompliance and high growth—this possibility , was examined
briefly. Figure 6-2 indicates the utility sulfur dioxide emission rates that
would occur under noncompliance if 35-, 45-, or 55-year generating unit
lifetimes are assumed. Figure 6-3 compares the high growth case that assumes
a 45-year lifetime with a variation that is identical except for a 35-year
lifetime assumption. Both of these figures demonstrate the difference that
early retirement of SIP units could have on regional utility sulfur dioxide
emission levels. A 45-year SIP unit lifetime under SIP noncompliance, for
example, could increase emission levels about 34 percent in the year 2000 over
the already high levels that would be recorded under the SIP noncompliance
case with 35-year lifetimes.
Another consideration in regard to the retirement of SIP units concerns
modifications to such units. That is, since the periodic maintenance of a SIP
128
-------
Rgure 6-3
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
High Electrical Energy Growth Case
CO
O
4-*
c
O
CO
O
'co
co
0
OJ
O
w
10-
8-
7-
6-
5-
1-
\\
\
HEG, 45-year
•«5«J..—
HEG ,35-year
High Electrical Energy Growth, 45-year unit lifetime
High Electrical Energy Growth, 35-year unit lifetime
1976
1980
1985
1990
1995
2000
plant can result in a substantial renovation of that plant, it may not be
retired as early as it would have been otherwise. If, however, certain
modifications were considered major enough to warrant the reclassification of
SIP units from an existing to a new source category, such a revised definition
might result in a utility's evaluation of the relative merits of (1)
continuing to use an existing unit or (2) building a new one. If existing SIP
units were retired because of such an evaluation, substantial emission
reductions could result.
The 35-year retirement of SIP units still would not wholly alleviate the
air quality problems stemming from regional sulfur dioxide emissions. Even in
2000, SIP-regulated units would account for the bulk (at least 67 percent) of
total regional utility sulfur dioxide emissions, regardless of whether a 35-
or a 45-year lifetime is assumed (see table 6-1). However, SIP units would
129
-------
account for between 15 and 40 percent of the regional electrical generation in
the year 2000 depending on the scenario. For example, SIP units would emit
2.93 million tons of sulfur dioxide in the year 2000 under the base case (or
67 percent of all utility sulfur dioxide emissions) and would produce about 24
percent of the total regional generation. Under the SIP noncompliance case,
SIP units would emit 6.47 million tons in 2000 (86 percent of the total) and
would account for about 40 percent of the total regional generation of
electricity. These examples thus suggest that the emission contribution of
SIP units would be disproportionate to the benefits of SIP generation in the
year 2000. SIP units contribute such a major portion of the total utility
sulfur dioxide emissions in 2000 and a lower percentage of the generation
because each SIP unit emits about five to six times more sulfur dioxide than a
new plant supplying the equivalent amount of electricity.
Stricter Controls. One way to achieve a more balanced emission-generation
ratio would be to tighten the SIP compliance strategies currently in
existence. The strict environmental control case offers an example Of what
might be expected if such stricter controls were enacted and enforced. This
latter case assumes that in each OKBES state the state's urban SIPs—which are
stricter than rural SIPs—would be applied throughout the ORBES portion of
that state.1* As a result of such strict controls, utility sulfur dioxide
emissions would decrease more by the year 2000 under this scenario than under
any other coal-dominated scenario (see figure 6-1 and table 6-1). In
addition, the rate of decrease would be more rapid under the strict control
case. Moreover, in the year 2000 under the strict control case, SIP units
would emit 1.15 million tons of sulfur dioxide (or 45 percent of the total
regional utility emissions of this pollutant) and would account for about 24
percent of the total regional electrical generation.
Least Emissions Dispatching. Another way to achieve a more balanced
emission-generation ratio, would be to use least emissions dispatching. At
present, and under all of the coal-dominated scenarios, generating units are
loaded (brought on-line) in order of operating costs. As a result, SIP units
are the first units dispatched, since newer units are more expensive to
operate.
Under the high growth case, a variation was examined that assumed that
coal-fired units would be dispatched according to least emissions of sulfur
dioxide. Under the least emissions criterion, the units emitting the most
sulfur dioxide (on a per Btu basis) would be loaded last. Under one such
dispatching order, for example, RNSPS units might be dispatched first, then
^ Because of this assumption of stricter controls, almost all of existing
SIP capacity would need to be retrofitted with flue gas desulfurization
devices, compared with about one-third of existing capacity under the base
case.
130
-------
NSPS units, then urban SIP units, and finally rural SIP units.5 While such a
dispatching order may not always be possible, the results of such dispatching
under the high growth variation indicate that it is an alternative worth
consideration. Total regional utility sulfur dioxide emissions would be 55
percent lower under this least emissions policy than they would be under the
least cost policy in the year 2000 (see figure 6-4). SIP emissions alone
Figure 6-4
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
Dispatching Variations under High Electrical Energy Growth
en
O
•W
c
o
CO
c
q
"co
I
CD
CNJ
O
CO
V'—Leasi ^osi i
_JS
Least Cost Dispatching
Least Emissions Dispatching
1976
1980
1985
1990
It is interesting to note that such a dispatching policy would reduce
the proportion of generation that actually would occur in the ORBES region.
Such a reduction would occur because the region has a high proportion of
high-emission SIP capacity compared to the proportion in the utility service
areas that are partially outside the region. Thus, if least emissions
dispatching were to be implemented, some generation probably would be shifted
to the plants outside the ORBES region.
131
-------
would be 35 percent lower under the former case than under the latter case.
Moreover, in the year 2000 under the least emissions dispatching variation,
SIP units would emit 1.5 million tons of sulfur dioxide—or 45 percent of all
utility sulfur dioxide emissions—and account for about 15 percent of the
electrical generation projected under this scenario. Under the least cost
policy, on the other hand, SIP units would emit 4.32 million tons of sulfur
dioxide—or 71 percent of the total utility emissions—and account for about
25 percent of the total electrical generation projected under this scenario.
As this discussion of utility sulfur dioxide emissions under the
different coal-dominated scenarios has revealed, the current emission
standards, if complied with, would reduce total sulfur dioxide emissions
between 1976 and 1985 from the 1976 levels. Any further reductions would be
determined by the lifetimes of SIP plants. As discussed below, such further
reductions would be important since episodic concentrations still would result
from the 1985 emission levels of most of the scenarios. Before such
concentrations are discussed, however, utility particulate and nitrogen oxide
emission trends under the coal-dominated scenarios are examined.
PARTICULATE EMISSIONS. Utility particulate emissions would be reduced
significantly by the year 2000 from the 1976 levels under all of the coal-
dominated scenarios except the SIP noncompliance case (see table 6-2).
Moreover, except under the latter scenario, utility particulate emissions
would be reduced at about the same rate and would be about the same in
2000—nearly five times lower than the 1976 emissions (see figure 6-5). In
addition, the least emissions dispatching variation would result in utility
particulate emission levels about the same as those charted in figure 6-5.
SIP noncompliance, however, would result in increased utility particulate
emissions through 1985. As a result, in 2000 under SIP noncompliance, utility
particulate emission levels would be only slightly lower than the 1976 levels.
These scenarios thus suggest that current particulate standards—which are the
same in urban and rural settings—will be effective as applied to the utility
industry. One major reason for this effectiveness is that particulate removal
technology is assumed to be between 85 and 94 percent efficient depending on
when the unit was built.
NITROGEN OXIDE EMISSIONS. All scenarios would result in increased utility
emissions of oxides of nitrogen (see table 6-3). Similarly, except under the
high electrical energy growth scenario, utility nitrogen oxide emissions would
increase at about the same rate through 1985 and would be nearly the same in
2000—approximately 35 percent higher than the 1976 emissions (see figure 6-
6). There are two reasons for this similarity among the scenarios. First,
Throughout this report, the term nitrogen oxide emissions refers to
emissions of oxides of nitrogen, not emissions of nitrogen oxide alone.
132
-------
Rgure 6-5 Electric Utility Particulate Emissions in the ORBES Region,
Coal-Dominated Scenarios
1.75-
1.50
«• 1-25-
c
2
c
o
CO
c
o
W
'E
0
0)
D
O
1.00-
.75 J
a .so.
.25-
SIP-N
Base Case (BC)
Strict Environmental Controls (SEC)
SIP Noncompliance (SIP-N)
High Electrical Energy Growth (HEG)
* Electrical Exports, emissions in 2000
HEG
1976
1980
1985
1990
1995
2000
Table 6-2 Electric Utility Particulate Emissions in the ORBES Region,
Coal-Dominated Scenarios
BC
SEC
SIP-N
HEG
EX
1976
1980
1985
1990
1995
2000
1.38
0.83
0.25
0.22
0.21
0.19
1.38
0.83
0.25
0.24
0.23
0.21
(million tons)
1.38
1.44
1.53
1.37
1.23
1.06
1.38
0.83
0.25
0.25
0.26
0.26
1.38
0.20
133
-------
Figure 6-6
Electric Utility Nitrogen Oxide Emissions in the ORBES
Coal-Dominated Scenarios
3.0-
2.5-
"w"
1
5 2.0-
nitrogen oxide emissions (millk
o -•• -*
3 in b en
ff*
/"''
/'
„•' .
,-"' ^
-:^^^=
-^=^—^:^^'' —
btuct Environmental Contiols (StC)
SIP Noncompliance (SIP-N)
Mign electrical energy orowtn (nbo)
* Electrical Exports, emissions in 2000
v i i i i
1976 1980 1985 1990 1995
Region,
^.-HEG
f+*
r
?. SIP-N
S—BC
^-SEC
2000
Table 6-3
Electric Utility Nitrogen Oxide Emissions in the ORBES
Coal-Dominated Scenarios
Region,
BC SEC SIP-N HEG
(million tons)
1976 1.49 1.49 1,49 1.49
1980 1.63 1.60 1.66 1.63
1985 1.71 1.69 1.82 1.67
1990 1.77 1.74 1.88 1.93
1995 1.98 1.96 2.08 2.34
2000 2.00 1.99 2.16 2.63
EX
1.49
2.22
134
-------
nitrogen oxide emission limits do not exist for SIP plants in the ORBES
region, except in the urban areas of Illinois. Second, the same nitrogen
oxide emission limits were assumed for new units under all scenarios. Thus,
utility nitrogen oxide emissions would increase from the 1976 levels primarily
in proportion to electricity demand growth and to the lifetime of SIP units.
This last point also explains why, after 1985, utility nitrogen oxide
emissions would increase at a faster rate under the high growth case than
under the other scenarios: the high growth case has the highest electricity
demand growth and assumes 45-year SIP unit lifetimes instead of the 35-year
lifetimes assumed under the other coal-dominated scenarios. Specifically,
utility nitrogen oxide emissions in 2000 under high growth would be 18 percent
higher than the next highest emissions—those under the electrical exports
case—and 77 percent higher than the 1976 emissions.
POLLUTANT CONCENTRATIONS. The magnitude of utility sulfur dioxide emission
levels under each scenario corresponds to annual average (long-term) and
episodic (short-term) sulfur dioxide and sulfate concentrations. Moreover,
since the transformation of sulfur dioxide into sulfates contributes to
concentrations of total suspended particulates (TSP) (see section 4.3),
reductions in both utility particulate emissions and utility sulfur dioxide
emissions could reduce TSP concentrations. However, the ratio of the lower
ORBES region's contribution to sulfur dioxide and sulfate concentrations in
the upper region is not likely to change from the ratio during the base period
(see section 4.3) under any of the scenarios.
Many of the same statements made about the emissions under the coal-
dominated scenarios also apply to annual concentrations under these scenarios.
For example, regardless of scenario, the regional annual average sulfur
dioxide and sulfate concentrations in 2000 attributable to utility emissions
would be lower than the present concentrations (see table 6-4).? Again, it is
the strict environmental control case that would reduce the annual average
concentrations the most and that would reduce them more rapidly than any of
the other scenarios. Similarly, the high electrical energy growth case and
the SIP noncompliance case would result in the least reduction by the year
2000. In fact, concentrations even would increase through 1985 under the
noncompliance case. In general, most concentration reductions would occur by
1985—regardless of scenario—provided that SIP plants have complied by that
7
The percentages listed in both table 6-4 and table 6-5 are the changes
in the area of highest concentration. An "area" is based on the averaging
method of a grid pattern of 80-by-80 kilometers. Thus, while such an average
represents the highest concentration area, specific locations within or
outside of the 80-by-80 kilometer area may experience higher or lower
concentrations.
135
-------
Table 6-4
Sulfur Dioxide and Sulfate Annual Average Concentrations,
ORBES Region, Percent Change from 1976,
Highest Concentration Region
Pollutant
Sulfur dioxide
Sulfur dioxide
Sulfates
Sulfates
Concentration,
1976(x*g/m3) Year
25.88 1985
25.88 2000
9.2 1985
9.2 2000
Strict
Environmental
Base Case Controls
(c
-28 -62
-50 -71
-27 -56
-49 -66
SIP
Noncompliance
fc)
+ 16
-18
+ 13
-20
High Electrical
Energy Growth
-30
-29
-25
-25
date. Also, the noncompliance case and the high electrical energy growth case
would result in substantially higher concentrations in 2000 than would the
base case.
Another benefit of lower utility sulfur dioxide emissions is the probable
reduction of the concentrations that would occur under episodic conditions.
If the characteristics of the August 27, 1974, sulfate episode were to be
repeated in 2000 under any of the scenarios, the predicted utility-related,
short-term sulfur dioxide and sulfate concentrations would be reduced from the
utility-related, short-term concentrations that were registered during that
episode (see table 6-5).° However, since these short-term concentrations were
quite high under the August 27 episode, the 31 and 25 percent reductions that
would occur in 1985 under the base case still would lead to relatively high
concentrations of sulfur dioxide and sulfates over the ORBES region. Even the
49 and 51 percent reductions that would occur in 2000 under the base case
would result in short-term sulfur dioxide levels on the order of 30 micrograms
per cubic meter and in short-term sulfate levels that could be considered
marginally episodic—that is, on the order of 15 micrograms per cubic meter
over a large area. On the other hand, the strict environmental control case
would lead to reductions of such magnitude that the short-term levels of
8 As discussed in section 4.3, the August 27, 1974, episode is the most
frequently occurring type of meteorological episode in the ORBES region (about
10 times per year). This type of episode involves a simple flow pattern of
extremely persistent winds blowing from the west to the east over the region.
136
-------
Table 6-5
Sulfur Dioxide and Sulfate Episodic Concentrations, ORBES
Percent Change from August 27, 1974, Episode,
Highest Concentration Region
Concentration,
Pollutant 1976 Utg/m )
Sulfur dioxide
Sulfur dioxide
Sulfates
Sulfates
94.04
94.4
40.1
40.1
Year
1985
2000
1985
2000
Base Case
-31
-49
-25
-51
Strict
Environmental
Controls
0
-68
-75
-76
-78
SIP
Noncompliance
6)
+ 18
-13
+ 16
-30
Region,
High Electrical
Energy Growth
-34
-30
-23
-18
sulfur dioxide and sulfates in both 1985 and 2000 no longer would be
considered episodic. As can be deduced, therefore, the SIP noncompliance and
the high electrical energy growth cases, which reduce emissions the least by
2000, would result in relatively high episodic concentrations.
Annual average and episodic concentrations are important in terms of both
regional crop loss impacts and regional health impacts (among other things)
since the reductions in concentrations consistently correlate with less crop
loss and fewer health impacts.
PHYSICAL CROP LOSSES. In terms of agricultural impacts, studies have
indicated that sulfur dioxide concentrations as low as 130 micrograms per
cubic meter (one-tenth of the secondary three-hour standard) in the presence
of moderate ozone levels (0.06 to 0.1 parts per million) can affect
vegetation." Thus, three coal-dominated scenarios—the base case, the SIP
noncompliance case, and the high electrical energy growth case—were examined
to determine the regional acreage that could be affected by the sulfur dioxide
concentrations attributable to utility emissions in the ORBES region. Of
these three scenarios, the SIP noncompliance case would subject the most
regional acreage to such concentrations in both 1985 and 2000. However,
except for the SIP noncompliance case in 1985, all three of these coal-
dominated scenarios would subject less regional acreage to such concentrations
y For a discussion of vegetation impacts and losses, see Orie Loucks et
al., Crop and Forest Losses Due to. Current and Projected Emissions from Coal-
Fired Power Plants in the Ohio River Basin (ORBES Phase II).
137
-------
than was subjected in 1976 (approximately 12.2 million acres). Thus, while
about 10 percent of the ORBES region experienced such concentrations in 1976,
3.1 percent, 4.5 percent, and 6.0 percent would experience such concentrations
in 2000 under the base case, the high growth case, and the noncompliance case,
respectively.
Each of these three coal-dominated scenarios also was examined to
determine the impact of such affected acreage on crop yields in the presence
of moderate ozone levels. As discussed previously (see section 4.4), between
867,000 and 6.1 million bushels of three selected crops—soybeans, corn, and
wheat—were estimated to have been lost in 1976 because of such utility-
related sulfur dioxide concentrations; the probable loss was projected to be
3.2 million bushels. Under these three scenarios, crop yield losses would not
be as high in 1985 and 2000 as they were in 1976 (see table 6-6). However,
because utility sulfur dioxide emissions would be higher under the SIP
noncompliance case and because more acreage would be affected by the resulting
sulfur dioxide concentrations of 130 micrograms per cubic meter, noncompliance
would result in the highest losses. Nevertheless, regardless of the scenario,
crop losses related to sulfur dioxide concentrations in the presence of
moderate ozone levels would represent less than 1 percent of the expected
regional yield in any given year. However, on a local scale, such as the
county, losses could be significant, and losses to individual farmers could be
substantial. For example, under all three scenarios, losses in the ORBES
state portions of Illinois, Indiana, and Ohio would account for approximately
95 percent of the total losses. In general, though, crop losses related to
utility sulfur dioxide emissions would be only a fraction of the total losses
attributable both to sulfur dioxide and to ozone formed from nitrogen oxide
emissions.
As discussed in section 4.4, the majority of regional crop losses are the
result of oxidants formed from nitrogen oxide emissions in combination with
other pollutants. During the base period, nitrogen oxide emissions in the
ORBES region originated primarily from transportation (35 percent) and from
electrical generation (50 percent). However, it is projected that nitrogen
oxides originating from transportation sources will decrease significantly by
the year 2000. Thus, utility nitrogen oxide emissions will begin to
constitute a larger proportion of the regional nitrogen oxide emissions,
especially since nitrogen oxide standards do not yet exist for SIP units in
the ORBES region and since emissions from these units are projected to account
for the majority of all utility nitrogen oxide emissions. As a result, the
rate of decrease in ozone production may be dictated by utility nitrogen oxide
emissions.
As table 6.6 indicates, crop losses attributable to oxidants formed from
all regional nitrogen oxide emissions would increase under each of the three
scenario examined. Because both utility and nonutility nitrogen oxide
138
-------
Table 6-6
Minimum, Probable, and Maximum Crop Losses Due to Regional
Sulfur Dioxide and Nitrogen Oxide Emissions, ORBES Region
Year
Pollutant
Minimum
Probable
Maximum
BASE PERIOD
1976
1976
Sulfur dioxide
Ozone
Total
(thousand bushels)
867 3,241
117,944 258,067
118,811
261,308
6,132
480,208
486,340
BASE CASE
1985
1985
Sulfur dioxide
Ozone
Total
329
290,504
290,833
1,228
412,030
413,258
2,338
691,541
693,879
2000
2000
Sulfur dioxide
Ozone
Total
248
99,484
99,732
924
171,412
172,336
1,716
358,549
360,265
SIP NONCOMPLIANCE
1985 Sulfur dioxide
1985 Ozone
Total
817
290,504
291,321
3,010
412,030
415,040
5,666
691,541
697,207
2000
2000
Sulfur dioxide
Ozone
Total
564
99,484
100,048
2,189
171,412
173,601
4,078
358,549
362,627
HIGH ELECTRICAL ENERGY GROWTH
1985 Sulfur dioxide
1985 Ozone
2000
2000
Total
Sulfur dioxide
Ozone
Total
327
290,504
290,831
289
369,795
370,084
1,219
412,030
413,249
1,081
468.310
469,491
2,301
691,541
693,842
2,157
705,123
707,280
Note: Crop losses related to sulfur dioxide depend on the amount of regional area affected by concentra-
tions of 130 ng/m3 in the presence of moderate ozone levels. The concentrations are those attributable
to peak load utility SO2 emissions (which comprise about 80% of all regional SO2 emissions). Crop
losses related to NOx emissions are those projected to occur because of oxidants formed from all
regional NOx emissions. Finally, projected corn, soybean, and wheat losses are added to derive the
numbers in this table. For the percentage that each of these crops comprises of the minimum,
probable, and maximum losses, see Orie Loucks et al., Crop and Forest Losses Due to Current and
Projected Emissions from Coal-Fired Power Plants in the Ohio River Basin (ORBES Phase II).
139
-------
emissions are projected to rise similarly from 1976 to 1985 under the three
scenarios examined, related crop losses would be the same in 1985—ranging
from a minimum of 290 million bushels to a maximum of 691 million bushels.
However, because nitrogen oxide emissions from nonutility sources are
projected to decline significantly after 1985, ozone production is expected to
begin leveling off after that year, even with the capacity additions projected
under the base case and the SIP noncompliance case. As a result, in the year
2000 under the base case and the SIP noncompliance case, crop losses
attributable to oxidants formed from nitrogen oxide emissions are projected to
be lower than in 1985; they would range from a minimum of 99 million bushels
to a maximum of 358 million bushels in that year. However, since the high
growth case adds many more electrical generating units after 1985 than do the
other two scenarios, the decrease in nonutility nitrogen oxide emissions would
be offset by a larger increase in utility nitrogen oxide emissions. As a
result, crop losses attributable to oxidants would range from a minimum of 369
million bushels to a maximum of 705 million bushels under the high growth case
in the year 2000.
As a means of comparing the crop losses related to sulfur dioxide and
ozone under the three scenarios, the cumulative probable crop losses between
1976 and 2000 were calculated for each of the three crops in question under
each of the three scenarios. Each of these cumulative probable numbers then
was compared to what the cumulative regional production could be if complete
abatement of these pollutants (that is, "clean air") occurred. Under the base
case, cumulative soybean losses would represent 26.3 percent of cumulative
soybean clean air production; cumulative corn losses, 10.8 percent of
cumulative corn clean air production; and cumulative wheat losses, 12.1
percent of cumulative wheat clean air production. The percentages under the
SIP noncompliance case would be almost identical to those of the base case.
Under the high growth case, however, cumulative soybean losses would represent
28.3 percent of the cumulative soybean clean air yield; cumulative corn
losses, 15.2 percent of the cumulative corn clean air yield; and cumulative
wheat losses, 12.5 percent of the cumulative wheat clean air yield.
In general, regardless of the scenario, losses due to oxidants would
constitute about 99 percent of all losses expected because of sulfur dioxide
and ozone (see table 6-6). The distribution of the losses due to oxidants
would vary among the ORBES state portions, but the state portions of Illinois,
Indiana, and Ohio again would account for about 95 percent of the losses. It
should be noted that the distribution of all crop losses due to air pollution
is not a local problem—that is, merely in the vicinity of a power plant—but,
because of pollutant transport, these losses may occur in areas removed from
major point sources.
FOREST LOSSES. The total estimated reduction in forest growth in the ORBES
region in 1985 due to air pollutants, principally ozone, would be 1.3 percent
140
-------
to 6.3 percent of the total production regardless of the scenario. In the
year 2000, losses would vary depending on energy development: under the base
case and the SIP noncompliance case, projected losses are estimated to be
between 0.4 percent and 1.9 percent of total production; under the high energy
growth case, these losses would be between 2.0 and 9.3 percent. In 1976, the
direct forest loss from air pollution is projected to have been from 0.7 to
3.4 percent of the total production. It also should be noted that evidence
suggests that insect damage is more prevalent in areas of air pollution in
comparison to the damage in relatively cleaner areas of the ORBES region.
However, such damage is not taken into account in these figures.
MORTALITY. As discussed in section 4.6, substantial controversy exists about
the quantification of deaths related to air quality. Some researchers believe
that only total suspended particulates can be related firmly to increased
morbidity and mortality and then only to cardiovascular disease, not to
respiratory disease. Many other researchers believe, however, that a growing
body of epidemiological evidence exists to support the hypothesis that the
annual average exposure to sulfates—or something closely related to
them—results in an increased mortality rate.
If the damage functions that were derived under the base period
assessment (see section 4.6) are corrected for the projected particulate
emissions of each scenario, damage functions ranging from 0-0.36 to 0-3.24 are
obtained per 1000 megawatts. (The damage functions derived for the base
period range from 0 to 3 cardiovascular deaths per 1000 megawatts of coal-
fired electrial generation.)
Based on the corrected damage functions, between 0 and 1555
cardiovascular deaths are projected to occur under the base case from 1975 to
2000 because of particulate emissions from coal-fired generation in the ORBES
region. The strict environmental control case would result in about the same
range of cumulative particulate deaths. However, under the SIP noncompliance
case (which has the highest corrected damage function), the number of
particulate deaths related to coal-fired generation between 1975 and 2000
would range from 0 to 4072. This latter range is about 162 percent higher
than the range for the base case.
Cumulative sulfate-related deaths between 1975 and 2000 also were
projected for the coal-dominated scenarios.10 Such cumulative sulfate-related
For discussions of the controversy surrounding sulfate-related death
projections, see Maurice A. Shapiro and A.A. Sooky, Ohio River Basin Energy
Study: Health Aspects (ORBES Phase II); Edward P. Radford, Impacts on Human
Health from the Coal and Nuclear Fuel Cycles and Other Technologies Associated
141
-------
deaths are dependent upon which damage function in the range of 0 to 9 is used
per 100,000 persons exposed per microgram of sulfates per cubic meter. If a
rate of 3 is used, it again becomes clear that the magnitude of utility
emissions is a dominant factor since the strict control case would result in
the fewest such cumulative deaths (109,000), while the noncompliance case and
the high growth case would result in the most such deaths (about 218,000 and
184,000, respectively). Such cumulative deaths under the latter two scenarios
also would be nearly 34 and 13 percent higher, respectively, than would the
deaths under the base case (163,000). However, as stated in section 4.6, the
major usefulness of such damage functions is not in the accuracy of the
absolute values of the estimated health impacts, but in the comparisons among
the various scenarios that these values make possible.
6.2 Economic Impacts Related to Air Quality Impacts
The costs to the utilities and to the consumer of the possible reductions
in emissions and other air-related impacts also were projected for the five
coal-dominated scenarios as well as for the least sulfur dioxide emissions
variation and the high electrical energy growth case with a 35-year lifetime
variation. Agricultural monetary losses also were estimated for three
scenarios—the base case, the SIP noncompliance case, and the high electrical
energy growth case.'^ Knowing these costs permits comparisons to be made
between the scenarios in terms of the social benefits derived from reduced
emissions versus the economic impacts of such reductions.
UTILITY COSTS. Figure 6-7 charts the costs to the utilities of installing new
coal-fired generating capacity, of installing pollution control devices on
these new units, and of retrofitting existing units. 3 As shown in the
figure, the base case, the strict environmental control case, and the SIP
noncompliance case would lead to the same capital costs exclusive of pollution
control costs. Pollution control costs, however, would differ. The
with Electric Power Generation (ORBES Phase II); and Leonard D. Hamilton,
"Areas of Uncertainty in Estimates of Health Risks," in Symposium on Energy
and Human Health; Human Costs Qf Electric Power Generation (ORBES Phase II).
For a discussion of all these costs, see Teknekron Research, Inc.,
Selected Impacts Q£ Electric Utility Operations in the Ohio River Basin.
12 See Walter P. Page, James Cieeka, and Gary Arbogast, Estimating
Regional Losses to. Agricultural Producers from Airborne Residuals in the Ohio
River Basin Energy Study Region. 1976-2000 (ORBES Phase II).
^ The cumulative capital costs shown in figure 6-7 include only the
costs of the generating capacity and the pollution control equipment installed
142
-------
Figure 6-7
Cumulative Capital Costs, Coal-Dominated Scenarios, 1976-2000
130-
120-
110-
100-
90-
2?
« 80-
"5
O
T- 60-
"o
£50-
O
5 40-
30-
20-
10-
8
E
<
i
L"
5.6"
—
3asc
Dast
3 Cum
2 gem
:Cum
cont
"33 Cum
§ cont
7
6.12
12.55
67.0
} J
» Envh
C(
ulat ve capital costs to install new
srating capacity, 1976-2000
ulative costs for sulfur dioxide
ro I, 1976-2000
ulative costs for paniculate 1 '
rol, 1976-2000
103.4
He.7
B9.7
—
Stric
onn
antr
6.12
e
16.58
67.0
t
lental
ols Co
0.1
SIP
Non
mpli
•>
2.79
10.33
67.0
Elc
- Ex
ance (
sctri
port
EX)
14.8
81.9
cal 4E
s Le:
\
COS
4.2
CTJ
—
-ye
stC
\
H
il-fired
0 11
7.04
16.78
90.38
ar 4,
lost 1
En
(
12
4.20
^ 7.04
—
5-ye
.eas
lissi
LEC
16.78
90.38
ar 3
t Le
ons
»
6.21
|| 7.67
5-ye
astl
/
18.5
100.04
ar
=ost
/
sulfur dioxide and
paniculate
control costs
costs %
Scenario billion total
$ costs
BC 18.67 21.8
SEC 22.7 25.3
SIP-N 13.12 16.4
EX 21.5 20.8
HEG 23.82 20.9
LED 23.82 20.9
35-Year 26.17 20.7
igh Electrical Energy
Growth
in the ORBES region between 1976 and 2000. The capital costs required for
units coming on-line after 2000 are excluded. However, these costs are
included in the calculations of the price of electricity and required revenues
since expenditures for these units begin before the year 2000.
143
-------
differences in pollution control costs among these three scenarios would
result entirely from the retrofitting of existing SIP plants with pollution
control devices. Thus, the total cumulative pollution control costs for the
base case would be higher than those for the noncompliance case because about
one-third of existing capacity would be retrofitted under the base case.
Under the strict control case, on the other hand, almost all of the existing
capacity would be retrofitted, resulting in the highest cumulative pollution
control costs of the three scenarios.
The high electrical energy growth case and its variations and the
electrical exports case would lead to higher costs to the utilities than would
the three scenarios discussed above. These higher costs would result because
of the installation of both additional generating capacity and the pollution
control devices on this new capacity. Thus, if the proportion of pollution
control costs to total capital costs is examined, the base case and the high
growth case are similar: under both scenarios, pollution control costs would
total about 21 to 22 percent of the total costs. It should be noted, however,
that these total capital costs do not reflect the operating costs. The
operating costs are included in the calculation of the price of electricity,
which reflects all the costs borne by the utilities each year. Thus, for
example, while the high growth scenario and the high growth least emissions
variation are projected to have the same capital costs, their operating costs
would differ: the least emissions dispatching variation would entail the
increased operation of pollution control devices and the burning of greater
quantities of cleaned or low-sulfur coals.
CONSUMER COSTS. The direct costs to the consumer would increase regardless of
scenario (see table 6-7). In the short run, however, some scenarios might
result in a faster increase in the price of electricity (see figure 6-8).
Several observations can be made about the electricity prices and their rate
of increase. For one, between 1976 and 1985, the price of electricity would
rise according to the added costs of complying with SIP emission limits,
paying for rising fuel and capital costs, and meeting electricity demand.
Thus, as figure 6-8 indicates, the price of electricity between 1976 and 1985
would rise similarly when nearly the same degree of compliance is
assumed—that is, under all the scenarios but the SIP noncompliance case. The
strict environmental control case, however, would result in the greatest
increase in electricity prices since complying with stricter SIP limits would
cost the utilities more. The price of electricity under the SIP noncompliance
case, of course, would reflect the absence of such control costs.
Between 1985 and 1995, the increases in electricity prices depend on the
electricity demand growth rate, capacity replacement, and capacity expansion.
Since the base case, the strict control case, and the noncompliance case
assume nearly the same replacement, expansion, and growth rates, the price of
electricity would rise little between these years under these scenarios.
144
-------
Electricity
Table 6-7
Prices and Cumulative Revenues, ORBES
Coal-Dominated Scenarios, 1976-2000
Region,
Scenario
Base Case
Strict Environmental
Controls
SIP Noncompliance
High Electrical
Energy Growth
High Electrical
Energy Growth,
35-Year Unit Life
High Electrical
Energy Growth,
Least Emissions
Dispatch
Price of Electricity (1975 P/kWh) Cumulative Revenues
1976 1985 1990 1995 2000 (billions of 1975 $)
2.58 3.87 3.93 4.18 4.64
2.58 4.21 4.07 4.30 4.71
2.58 3.10 3.52 3.87 4.44
2.58 3.80 4.11 4.53 5.53
2.58 3.80 4.27 4.82 5.70
2.58 3.86 4.19 4.60 5.60
525
544
475
617
639
626
Note: No data available for electrical exports case.
Under the high growth scenario and its variations, however, the price of
electricity would rise between 1985 and 1995 since more capacity expansion is
projected under these scenarios. The higher operating costs of least
emissions dispatching also are reflected in the higher price of electricity
under this variation.
Between 1995 and 2000, all scenarios would show a rise in the price of
electricity. This increase would result because additional generating units
would have to be constructed to satisfy electricity demand after the year 2000
and because a significant number of SIP units would retire during these years
and would have to be replaced.
Because some scenarios would cause electricity prices to be higher in the
short run, cumulative costs to consumers between 1976 and 2000 give a better
idea of total consumer costs than does the price of electricity in a given
year. Under the base case, such cumulative revenues required from consumers
would total $525 billion (in 1975 dollars, or approximately $709 billion in
1979 dollars). Compared to the base case revenues, the cumulative revenues
required under the strict environmental control case would be about 4 percent
145
-------
Rgure 6-8
Electricity Prices in the ORBES Region, Coal-Dominated Scenarios
.G
^
in
o>
0)
E
v>
c.
o
o
O
o
"fc_
•4-t
O
JD
0)
(1)
_o
*
6-1
5-
4-
3-
2-
HEG, 35-year
SIP-N
-Base Case (BC)
-Strict Environmental Controls (SEC)
-SIP Noncompliance (SIP-N)
•High Electrical Energy Growth, 45-year unit lifetime (HEG, 45-year)
•High Electrical Energy Growth, Least Emissions Dispatching (LED)
•High Electrical Energy Growth, 35-year unit lifetime (HEG,35-year)
1976
1980
1985
1990
1995
2000
higher, while the revenues required under the SIP noncompliance case would be
about 10 percent lower. A high electrical energy growth rate would require
about 18 percent more more revenues than would the base case. Of the two high
growth variations, the 35-year variation would require the most revenues
(about 21 percent higher than for the base case), while the revenues required
for least emissions dispatching would be about 19 percent higher than for the
base case.
MONETARY CROP LOSSES. The agricultural monetary losses that would occur
because of sulfur dioxide and oxidants follow some of the same patterns as the
146
-------
physical crop losses. First, monetary losses due to oxidants would constitute
virtually all (about 99 percent) of the economic losses due to oxidants and
sulfur dioxide under the three scenarios examined: the base case, the SIP
noncompliance case, and the high electrical energy growth case. In addition,
agricultural monetary losses related to sulfur dioxide emissions would be
similar under the three scenarios examined (less than 1 percent of the total
monetary losses). Also, the total agricultural monetary losses would be
concentrated in certain ORBES state portion (Illinois, Indiana, and Ohio)
regardless of scenario. Finally, the high growth case would result in the
highest cumulative agricultural monetary losses ($8.4 billion in 1975 dollars,
or approximately $11.3 billion in 1979 dollars). The base case and the SIP
noncompliance case would result in about the same cumulative agricultural
monetary losses ($7 billion in 1975 dollars, or approximately $9-5 billion in
1979 dollars).14
6.3 Other Impacts Related to Expanded Capacity
LAND. As mentioned in the first paragraph of this chapter, the impacts of an
expanded regional generating capacity on land use conversion and the number of
terrestrial ecosystem units would be about the same under three of the coal-
dominated scenarios—the base case, the strict environmental control case, and
the SIP noncompliance case—since their generating capacity is about the same
and their siting patterns somewhat similar (see tables 6-8 and 6-9). How-
ever, although regionwide impacts would be about the same, impacts at the
state level would vary slightly among these scenarios.
The high electrical energy growth case and the electrical exports case
would entail larger generating capacities than the three other coal-dominated
scenarios. Thus, the amount of land converted and the terrestrial units
assessed would rise accordingly: both would be about 30 percent higher under
the high growth case than under the base case; under the exports case, land
conversion and terrestrial units would be about 17 percent higher than under
the base case.
For a discussion of agricultural losses, see Page, Ciecka, and
Arbogast, Estimating Regional Losses ifi Agricultural Producers.
* As discussed in section 4.4, land use refers to the amount of land
that must be converted to install the generating capacity of each scenario.
Terrestrial ecology refers to the forest lands, Class I and II soils,
endangered species, and natural areas that might be affected given this land
use conversion. For a fuller discussion of these two aspects, see J.C.
Randolph and W.W. Jones, Ohio. River Basin Energy Study: Land Use and.
Terrestrial Ecology (ORBES Phase II).
147
-------
Table 6-8
Land Conversion for New Electrical Generating Facilities,
Coal-Dominated Scenarios, 1976-2000
State
Portion
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
ORBES
Region Total
Base Case
28,528
39,540
36,433
31,572
27,990
19,806
183,869
Strict
Environmental
Controls
30,717
40,643
36,431
31,543
27,990
19,805
187,129
Scenario
SIP
Noncompliance
(acres)
28,528
39,540
36,433
31,572
27,990
19,806
183,869
High Electrical
Energy Growth
31,841
48,377
49,687
44,884
30,197
31,959
236,945
Electrical
Exports
28,528
39,540
36,433
45,930
33,513
31,961
215,905
Table 6-9
Terrestrial Ecosystem Assessment Units,
Coal-Dominated Scenarios, 1976-2000
State
Portion
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia*
ORBES
Region Total
Base Case
356
451
266
305
270
156
1804
Strict
Environmental
Controls
390
458
268
300
277
164
1857
*No substate endangered vertebrate species data
Scenario
SIP
Noncompliance
356
451
266
305
270
156
1804
available
High Electrical
Energy Growth
442
533
396
427
350
249
2397
Electrical
Exports
378
444
274
434
330
257
2117
148
-------
EMPLOYMENT. More power plant construction and operation workers would be
employed under the high electrical energy growth case and the electrical
exports case than under the three other coal-dominated scenarios. In fact,
such employment would rise dramatically under these two scenarios between 1983
and 1987, although the high growth case would require more workers than the
exports case (see figure 6-9).
The rapid changes that could occur under the high growth case might
result in short-term labor shortages followed by a surplus of labor as
experienced workers have a choice of jobs and then few choices. Moreover,
shortages of the skilled labor necessary to power plant construction and
operation—such as boilermakers, pipefitters, and electricians—might
accompany the high growth case. In general, however, skilled labor shortages
would not be a major problem for the region under any of the other coal-
dominated scenarios, although local shortages might occur.
Annual regional coal production and coal-mining employment would increase
from the 1974 levels under the base case, the strict control case, and the
electrical exports case.^7 However, annual coal production would be much
higher in 2000 under the electrical exports case than it would be under the
two other scenarios. Thus, regional mining employment would rise similarly
under the base case and the strict control case, from a minimum of 36 percent
to a maximum of about 226 percent, depending on the county. Such employment
would increase from a minimum of 42 percent to a maximum of 270 percent under
the electrical exports case. It also is projected that at least 79 to 88 of
the 152 ORBES-region counties with a concentration in coal mining would
experience boom-town effects (growth over 200 percent) under all three of
these scenarios.
HEALTH. Under all of the coal-dominated scenarios, the health impacts related
to supplying coal to ORBES-region power plants would increase. ' ° This
increase would result because, under all scenarios, utility coal consumption
would be higher than currently. In 1985, the health impacts in the coal-
mining and coal-processing sectors would be the same under all coal-dominated
scenarios. In 2000, three of the scenarios—the base case, the strict
For projections of regional power plant construction and operation
employment and of regional coal-mining employment, see Steven I. Gordon and
Anna S. Graham, Regional Socioeconomic Impacts of Alternative Energy Scenarios
for the Ohio River Basin Energy Study Region (ORBES Phase II).
1^ For coal production estimates, see Donald A. Blome, Coal Mine Siting
for the Ohio River Basin Energy Study (ORBES Phase II).
ifi
' See Shapiro and Sooky, Ohio River Basin Energy Study; Health Aspects.
149
-------
number of construction workers
to
VJl
o
(A
O
J 31
T
-------
environmental control case, and the SIP noncompliance case—would result in
similar health impacts in these sectors, while the high electrical energy
growth case and the electrical exports case would result in impacts about 17
percent higher. The health impacts in the coal transportation sector were
analyzed only for the base case and the strict control case and only for the
year 2000. Both cases would result in an increase in the fatalities
associated with the transportation of coal to ORBES-region electrical
generating facilities. Injury rates, however, would be about the same as
currently since railroad ^njuries are projected to decline at a greater rate
than fatalities.
WATER. All of the coal-dominated scenarios would result in aquatic habitat
impacts very similar to those that could have occurred in 1976 under 7-day-
10-year low flow conditionoJ9 Thus, whether historic municipal and
industrial growth continues, or whether high or base case electricity demand
occurs, the region already appears to have the potential to experience its
most serious aquatic habitat impacts under 7-day-10-year low flow
conditions.20 However, although aquatic habitat impacts would be about the
same under all coal-dominated scenarios, some rivers would register changes in
their water quality indices under the strict control case and the high growth
case—indicating that a river perhaps would experience slightly less or
slightly more stress than it would under the base case. Under the high growth
case, in particular, these incremental changes in the water quality index
would be due to power plant siting.
Background Concentrations. The same aquatic impacts would occur under the
coal-dominated scenarios as in 1976 because of the high pollutant
concentrations that already exist in the region (called background
concentrations). As noted in section 4.5, almost all of the 24 streams
19
As discussed under base period conditions (section 4.5), the concept
of 7-day-10-year flow is a parameter commonly used in river basin management
and water quality assessments, primarily as a worst case decision tool or
parameter. The water quality analysis carried out for ORBES is reported in
Clara Leuthart and Hugh T. Spencer, Fish Resources and Aquatic Habitat Impact
Assessment Methodology for the Ohio River Basin Energy Study (ORBES Phase II).
20
The five coal-dominated scenarios assume the use of cooling towers.
If once-through cooling were to be used, however, impacts could be much
severer. Under the base case and the electrical exports case, a variation
that assumed once-through cooling on the Ohio River main stem was examined.
This variation indicates that if such a cooling alternative were used, serious
impacts would result. See sections 7-3-2 and 11.3 for a discussion of the
impacts under this variation.
151
-------
studied in detail would have violated several of the study's reference
concentrations under 7-day-10-year low flow at some point in 1976.
Furthermore, the overwhelming majority of these high background concentrations
are estimated to be geochemical or to come from nonpoint sources. Since it is
considered unlikely that nonpoint sources could be brought under control
during the time frame of this study, background levels in the ORBES streams
were projected to remain constant between 1975 and 2000 under all scenarios
except the strict environmental control case. Under the strict control case,
it was assumed that background levels will be reduced by half by the year
2000. However, even if such a reduction were to occur, it is projected that
aquatic habitat impacts would remain unchanged although water quality impact
indices might improve slightly. The results under the strict control case
thus suggest that background levels are so high that they would have to be
reduced more than half to make a difference in aquatic habitat impacts.
Pollutant Loadings. The influence of these background concentrations is
further indicated when the pollutant loading assumptions of these scenarios
are compared. Under all of the coal-dominated scenarios except the strict
environmental control case, power plant effluents were not limited. Along
with its assumption of reduced background concentrations, the strict control
case assumes that energy conversion facilities will limit effluents to 5
percent of base case levels. However, a comparison of the strict control case
with the other coal-dominated cases—the base case, for example—reveals
little difference because of the loading assumptions. Although the water
quality indices would improve slightly on all rivers under strict controls,
protection levels and aquatic habitat impacts would remain the same as under
the base case on all but four rivers. If the impacts under the strict control
case then are compared to those that could have occurred in 1976, only two
rivers would register changes from 1976 protection levels and aquatic habitat
impacts. Thus, since loading is not a significant factor, background
concentrations appear mainly responsible for the substantial impacts that
could occur under 7-day-10-year low flow conditions.
POWER PLANT CONSUMPTION. Power plant consumption would be important on those
of the region's smaller streams where little municipal and industrial
consumption occurs and where the river's flow under 7-day-10-year low flow
conditions would be curtailed drastically. However, if background
concentrations were not so high on these small streams, power plant
consumption might have little impact. Thus, once again the high background
levels are more important than the consumption source.
AFFECTED STREAMS. Of the coal-dominated scenarios, the high growth case would
affect the most small streams in the region as well as a number of medium size
streams since a large number of units must be sited under that case. Under
the high growth case, six rivers would experience higher water quality impact
indices because of additional capacity, although these rivers still would
152
-------
register the same protection levels and aquatic habitat impacts as they did
under the base case. However, three small streams under the high growth
case—the Big Sandy, the Great Miami, and the Little Miami—would register
drastic impacts and "D" protection levels with the siting of two or more units
on each river.
The impacts on these small streams suggest that alternative siting or
technology could alleviate almost all of the impacts on water quality related
to power plants under all scenarios. There is, however, one, perhaps
significant, problem with alternative siting of power plants. Although water
quality would be protected, air quality would suffer since most of the
suitable alternative sites in terms of water quality are located along the
Ohio River main stem, where air quality problems exist. A further
concentration of power plants along this corridor thus could exacerbate these
air quality problems.
What can be done to avoid the combined effects of natural forces and high
background concentrations is harder to pinpoint, especially since it is
unlikely that nonpoint sources can be brought under control. Preventing the
rather minor impacts related to power plants would necessitate the tradeoff
just discussed. Avoiding the potentially significant impacts of municipal and
industrial consumption also would involve tradeoffs. For example, a number of
rivers would not be available for growth of any kind if regulatory bodies were
to implement siting restrictions that would prohibit the siting of any entity
that consumed water along streams having 7-day-10-year low flows less than 100
cubic feet per second. Such restrictions would result in a very limited
number of sites for industry, especially for power plants. Thus, as this
brief outlining of some possible steps and their limitations suggests,
improvements in water quality may require some environmental, social, and
economic tradeoffs that would have their own repercussions.
In the chapters that follow, each of the five OREES coal-dominated
scenarios is discussed in detail in terms of the following impact areas: air,
land, water, employment, and health. Impacts of the base case are considered
in chapter 7; impacts of the strict environmental control case, in chapter 8;
impacts of the SIP noncompliance case, in chapter 9; impacts of the high
electrical energy growth case, in chapter 10; and impacts of the electrical
exports case, in chapter 11. The base case impacts are compared with base
period conditions in the ORBES region, while the impacts of the other
scenarios are compared with those of the base case.
153
-------
7. Impacts of the Base Case
In this chapter the air, land, water, employment, and health impacts that
could be expected under the base case are identified and contrasted with
conditions in the ORBES region during the mid-1970s (see chapter 4). Under
the base case, current environmental standards are applied to present and
future sources of pollution. With regard to air, for example, controls are
defined as the application of standards set forth in state implementation
plans (SIPs), new source performance standards (NSPS), and revised new source
performance standards (RNSPS). The average annual electricity demand growth
rate is 3-13 percent under the base case, and this rate results in an
installed regional electrical generating capacity of 153,245 megawatts
electric in the year 2000. Ninety-five standard coal-fired units are sited in
the study region after 1985 under the base case. For a more detailed
discussion, see chapter 5.
7.1 Air
Under base case environmental regulations, utility sulfur dioxide and
particulate emissions would decrease through the year 2000 from the 1976
emission levels, while utility nitrogen oxide emissions would increase.1 Both
annual average and episodic concentrations of sulfur dioxide and sulfates due
to utility emissions also would decrease substantially. Electricity prices,
however, would increase dramatically over the 1976 price.
SULFUR DIOXIDE EMISSIONS. A definite trend is evident with regard to regional
utility sulfur dioxide emissions under the base case: total utility emissions
would follow a pattern similar to emissions from SIP-governed units (see
figure 7-1a). The assumption that SIP units will achieve full compliance by
For projections of air pollutant emissions and concentrations under the
base case, as well as under the other ORBES scenarios, see James J. Stukel and
Brand L. Niemann, Documentation in. Support of Key. ORBES Air Quality Findings;
Teknekron Research, Inc., Air Quality and Meteorology in the Ohio River Basin:
Baseline and Future Impacts; and Teknekron Research, Inc., Selected Impacts of.
Electric Utility Operations in the Ohio River Basin (1976-2000): An
Application 'of. the Utility Simulation Model (vols. I, II, and III,
respectively, of James J. Stukel, ed., Ohio River Basin Energy Study: Air
Quality and Related Impacts (ORBES Phase II)).
-------
price of electricity (1975
Cn
I
f> _
g
(O
oo
in
(O
cn
O CD (O
O 00 ->l
O Ol O)
^ U N)
a> bo in
•f^ »>i oo
a
m
o_
«<"
5'
03
m FT
o
(Q
O
CD
ff
M
-------
1985 would reduce total utility emissions as well as emissions from SIP units
between 1976 and 1985. Between 1985 and 2000, both total utility and SIP
emissions would decline because of the assumption that SIP units would be
retired after 35 years. However, such retirements after 1985 also would
result in an increase in emissions from RNSPS units as more such units replace
the retired SIP plants. In terms of absolute numbers, regional utility sulfur
dioxide emissions in 1976 totaled 8.94 million tons. By 1985, sulfur dioxide
emissions from all electrical generating units in the ORBES region (those
regulated by SIPs, NSPS, and RNSPS) would decrease 32 percent—to 6.1 million
tons. By 2000, they would decrease 51 percent—to 4.35 million tons.
Despite the decrease in SIP emissions and the increase in RNSPS
emissions, SIP emissions still would be the key to further reductions of the
emissions projected under the base case. RNSPS units already are very clean
units, removing approximately 90 percent of their potential sulfur dioxide
emissions. In fact, five or six RNSPS units produce about the same amount of
sulfur dioxide emissions as an average complying SIP unit that supplies the
equivalent amount of electricity. As a result of the comparative "dirtiness"
of SIP units, in the year 2000 they would account for approximately 67 percent
(or 2.93 million tons) of all utility sulfur dioxide emissions in the ORBES
region. However, these units would account for only 24 percent of the
electricity generated. (In 1985, by contrast, when emissions from SIP units
would account for 92 percent (or 5.6 million tons) of total utility sulfur
dioxide emissions, these units would account for 68 percent of the total
regional electrical generation.) It is clear, therefore, that although SIP
standards would reduce emissions from the 1976 levels, other strategies would
be required to achieve a more balanced emission-generation ratio between 1985
and 2000.
Nonutility sulfur dioxide emissions in the ORBES region would increase by
about 30 percent between 1975 and 2000, based on some recent, highly
approximate projections. As a result of such increases, nonutility emissions
would make up a larger fraction of the total sulfur dioxide emissions in 2000
than they did in 1975. Thus, while nonutility emissions accounted for
approximately 20 percent of all sulfur dioxide emissions in 1975, these
emissions would account for approximately 29 percent of all sulfur dioxide
A higher power plant capacity factor and a lower BTU content for coal
were assumed in the utility simulation model analysis than was assumed by
other ORBES researchers. The combined effect of these differences in
assumptions is a higher coal use estimate in the ORBES region in the year
2000. For a discussion of these, different assumptions, see Teknekron
Research, Inc., Selected Impacts Q? Electric Utility Operations.
156
-------
emissions in 2000 under the base case.-^ As a result of the increased
nonutility emissions and the decreased utility emissions, total sulfur dioxide
emissions in the ORBES region would decrease by about 40 percent by the year
2000 from the total emissions of this pollutant in 1975.
PARTICIPATE EMISSIONS. Total regional particulate emissions would continue to
be dominated by nonutility emissions under the base case, as they were during
the base period. Utility particulate emissions would decrease dramatically.
Annual utility particulate emissions in the ORBES region, which totaled 1.38
million tons in 1976, would decrease 82 percent by 1985 and 86 percent by 2000
(to 250,000 tons in 1985 and to 190,000 tons in 2000). Nonutility particulate
emissions in the ORBES region also would decrease (by about 60 percent) under
the base case between 1976 and 1985, again according to some recent, highly
approximate projections. However, between 1985 and 2000, regional nonutility
particulate emissions would increase by about 30 percent from their 1985
levels. (The different growth rates assumed for the utility and nonutility
sectors result in the decrease in utility emissions and the increase in
nonutility emissions after 1985.) Thus, since nonutility emissions account
for about 75 percent of the total regional particulate emissions, total
particulate emissions would decrease about 60 percent by 1985 from the 1976
levels and would increase about 14 percent during the period between 1985 and
2000.
NITROGEN OXIDE EMISSIONS. Annual utility emissions of oxides of nitrogen, on
the other hand, would increase between 1976 and 2000. Such emissions would
total 1.71 million tons in 1985, an increase of 15 percent over the 1.49
million tons in 1976. By 2000, annual utility nitrogen oxide emissions in the
ORBES region would total 2 million tons, a 34 percent increase. As discussed
in chapter 6, utility nitrogen oxide emissions would increase because no SIP
standards for oxides of nitrogen exist in the ORBES region, except in the
urban areas of Illinois. Thus, the greater the electricity demand growth, the
greater the emissions.
SULFUR DIOXIDE AND SULFATE CONCENTRATIONS. As a result of decreased utility
sulfur dioxide emissions under the base case, regional utility emissions
should contribute less to regional sulfur dioxide and sulfate concentrations
by the year 2000 than they contributed during the base period. However, the
ratio of the lower ORBES region's contribution to sulfur dioxide and sulfate
concentrations in the upper region is not likely to change under the base
case, or under any scenario, from the 1976 ratio.^
Nonutility emissions are estimated in Teknekron Research, Inc., Air
Quality and Meteorology in the Ohio River Basin.
4
For a discussion of concentration projections, see Teknekron Research,
Inc., Air Quality and Meteorology in the Ohio River Basin.
157
-------
If the same conditions of extremely persistent winds were to occur under
the base case as those that occurred during the August 27, 1974, sulfate
episode, the utility-related sulfur dioxide and sulfate concentrations would
be reduced significantly in both 1985 and 2000.5 Specifically, utility-
related sulfur dioxide concentrations in the area that experienced the highest
concentrations in 1976 would total 65.2 micrograms per cubic meter (31 percent
lower) in 1985 and 48.2 micrograms per cubic meter (49 percent lower) in 2000.
Sulfate concentrations in this high concentration area due to all regional
utility emissions would total 30 micrograms per cubic meter (25 percent lower)
in 1985 and 19-7 micrograms per cubic meter (51 percent lower) in 2000. About
12 micrograms per cubic meter of these sulfate concentrations in the year 2000
would come from utility emissions in just the lower ORBES region. However,
the contribution by the lower region to the upper region would be about 60
percent lower than the amount contributed by the lower region to the upper
region during the August 27 episode.
Annual utility-related sulfur dioxide and sulfate concentrations in the
ORBES region also would decrease under the base case from the 1976 regional
utility-related concentrations, especially in the area with the highest annual
concentrations in 1976. In 1985 under the base case, the annual sulfur
dioxide concentration in this high concentration area would be 18.55
micrograms per cubic meter (or 28 percent lower), and the annual sulfate
concentration would be 6.7 micrograms per cubic meter (or 27 percent lower).
By 2000 under the base case, the annual sulfur dioxide concentration in this
high concentration area should have decreased about 50 percent from the 1976
levels—to 12.94 micrograms per cubic meter—and the annual sulfate
concentration, about 49 percent—to 4.7 micrograms per cubic meter.
Figures 7-2 and 7-3 depict the significant improvements throughout the
region in annual utility-related concentrations under the base case. Figure
7-2 compares the 1976 sulfur dioxide concentrations with the projected 2000
sulfur dioxide concentrations. As can be seen, the area affected by the
highest sulfur dioxide concentrations would be significantly smaller under the
base case, although the general location of the highest sulfur dioxide
concentrations would remain about the same. Figure 7-3 compares the annual
average sulfate concentrations in 1976 and 2000 and shows the extensive
improvements projected in such utility-related concentrations both within and
outside of the region.
Since nonutility sulfur dioxide emissions would increase between 1976 and
2000, the annual average concentrations attributable to such emissions also
The August 27, 1974, episode, discussed in section 4.3, exemplifies the
most frequently occurring type of sulfate episode. Such an episode involves a
simple flow pattern of extremely persistent winds blowing from the west to the
east over the ORBES region.
158
-------
Figure 7-2
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
1976-
Figure 7-3
Annual Average Sulfate Concentrations, Electric Utility Contribution
1-2.99
3-4.99 5-6.99
(i|g/m3)
7-9
159
-------
would increase. However, since nonutility sulfur dioxide emissions would
comprise only about 29 percent of total regional sulfur dioxide emissions in
2000, non-utility-related concentrations would be much lower than the
utility-related concentrations. The annual average sulfur dioxide
concentrations resulting from nonutility emissions would increase from about 2
micrograms per cubic meter in 1975 to about 4 micrograms per cubic meter in
2000. Between these same years, annual average sulfate concentrations would
increase from approximately 1 microgram per cubic meter to approximately 2
micrograms per cubic meter.
UTILITY COSTS. To achieve these significantly reduced emissions and
concentrations, total cumulative capital costs for pollution control through
the year 2000 would be $18.67 billion (expressed in constant 1975 dollars, or
approximately $25.20 billion in 1979 dollars). Of this total, $12.55 billion
would be required for the control of sulfur dioxide emissions, and $6.12
billion for the control of particulate emissions." These pollution control
costs reflect (1) the costs of retrofitting SIP units with flue gas
desulfurization devices (scrubbers) and electrostatic precipitators to meet
base case SIP emission limits and (2) the costs of installing these devices on
new units.
Cumulative capital costs to install new coal-fired capacity under the
base case would total $67 billion (1975 dollars, or approximately $90 billion
in 1979 dollars). Thus, the pollution control costs of $18.67 billion would
represent approximately 22 percent of the total cumulative capital costs
($85.67 billion) that would be required to achieve the environmental standards
and the growth in coal-fired electrical generating capacity projected under
the base case.
CONSUMER COSTS. In terms of direct costs to the consumer, the real price of
electricity would rise between 1976 and 1985 to 3.87 cents per kilowatt hour,
an increase of 4.6 percent per year (see figure 7-1b). This increase reflects
several factors: the added costs of achieving base case environmental
regulations, rising fuel costs, rising capital costs, and the costs of meeting
increased electricity demand.? Between 1985 and 2000, the price of
electricity would not rise as rapidly, due partly to the lower annual growth
The electricity prices and capital costs associated with the ORBES
scenarios, including the base case, are discussed in Teknekron Research, Inc.,
Selected Impacts of Electric Utility Operations. Cumulative capital costs to
install projected nuclear-fueled generating capacity under the base case—as
well as under all the coal-dominated scenarios—would total $8.3 billion.
7
It is interesting to note that the increases in coal costs associated
with the depletion of reserves in order to produce the anticipated tonnage in
160
-------
rate assumed during this period. As a result, the price of electricity in
2000 would be 4.64 cents per kilowatt hour. Since the price of electricity in
1976 was 2.58 cents per kilowatt hour, base case prices would be 50 percent
higher in 1985 and 80 percent higher in 2000.
However, electricity prices at one or two points in time do not fully
capture the actual costs to the consumer; the price of electricity in a single
year is merely a snapshot of the changes that would occur. The cumulative
revenues that actually would be required from consumers between 1976 and 2000
better represent the average price differences over this period. Under the
base case, the cumulative revenues required during the study period would
total $525 billion (in 1975 dollars, or approximately $709 billion in 1979
dollars).
7.2 Land
LAND USE. The single most important factor in terms of total land use
conversion under the base case—and indeed under all scenarios—is the growth
rate of generating capacity through the year 2000. In general, land resources
probably would meet the demand adequately. However, given both land and other
siting criteria, the number of suitable sites for generating facilities could
be limited by the year 2000.^
The land conversion required under the base case between 1976 and 2000
for all new energy-related uses (new generating facilities, new transmission
line rights-of-way, and new surface mining for utility coal) would total about
991,000 acres (1548 square miles), or 0.8 percent of the total land in the
ORBES region. Of this total, the conversion required for new electrical
generating facilities would represent about 19 percent (183,869 acres), and
the estimated land use requirement for new transmission line rights-of-way
the year 2000 are invariant across the base case, the strict control case, and
the high growth case. Thus, the production of low-sulfur coal from BOM
districts 1 and 3 and from BOM districts 7 and 8 to supply the anticipated
demand in 2000 would lead to an increase in coal tonnage costs from depletion
of approximately 14 percent and 33 percent, respectively. High-sulfur coal
production from BOM districts 2, 4, 6, 10, and 11 and from BOM districts 1 and
3 would lead to increases from such depletion of 40 percent and 78 percent,
respectively. For discussion, see Walter P. Page, An Economic Analysis of
Coal Supply in the Ohio River Basin Energy Study Region (ORBES Phase II).
p
See J.C. Randolph and W.W. Jones, Ohio River Basin Energy Study: Land
Use and Terrestrial Ecology (ORBES Phase II) for a discussion of energy-
related land use. For a discussion of the siting criteria, see Gary L. Fowler
et al., The Ohio River Basin Energy Facility Siting Model: Methodology (vol.
I) (ORBES Phase II).
161
-------
would represent 14 percent (or 134,224 acres).9 Surface mining for utility
coal represents the remaining 67 percent. Although the total land conversion
required under the base case represents less than 1 percent of the region,
conversion at the county level could represent a substantial portion of that
county's total acreage.
Of the total land needed for new facilities, the most (21.5 percent)
would be taken from the ORBES portion of Indiana and the least (15.2 percent)
from the Pennsylvania portion (see table 7-1). In terms of the land types
converted to install base case generating facilities by the year 2000, 52
percent would be agricultural lands; 37 percent, forest lands; 2 percent,
public lands; and 9 percent, other lands.
Coal Mining. Of the total amount of land required under the base case for the
surface mining of coal for regional electrical generation (673,000 acres),
184,000 acres would be affected in the Eastern Interior Coal Province; 489,000
acres would be affected in the Appalachian Province. 1^> This acreage affected
by surface mining for regional utility coal under the base case would
represent 29 percent of the cumulative amount of land (2.32 million acres)
required for the surface mining of coal for all purposes between 1976 and
2000.
Under the base case, underground production would increase by the year
2000. Surface-mining production would range from 26 to 60 percent of total
production depending on the geographical location. In the base period, the
range was between 19 and 98 percent.
Of the total acres required for new generating facilities under all
scenarios, approximately 36.5 percent would be reversibly committed between
1976 and 2000, and approximately 63-5 percent would be irreversibly committed
during the same period. Reversible commitments refer to the areas associated
with a facility but not affected directly—for example, utility-owned lands at
a facility site that are contiguous to but not actually included in the
construction area. Irreversible commitments include buildings, fuel and waste
storage areas, and associated roads at the construction site. However, the
notion of reversible and irreversible is a matter of debate. But the expense
and time needed to reverse certain uses of land would be so far beyond the
time frame of this project as to be irrelevant. Therefore, for purposes of
ORBES, an irreversible land use is defined as one that is at least likely to
exist for the normal life of a generating facility, and probably much longer.
For a discussion of surface mining in the ORBES region, see Daniel E.
Willard et al., A Land Use Analysis of Existing and Potential Coal Surface
Mining Areas in the Ohio River Basin Energy Study Region (ORBES Phase II).
162
-------
Land
Table 7-1
Use Conversion for Electrical Generating Facilities,
Base Case, 1976-2000
State
Portion Public Lands
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
ORBES Region
356
1,009
313
1,700
1,120
352
4,827
Agricultural
Lands Forest Lands Other Lands
(acres)
23,046 3,179 1,947
25,674 9,799 3,058
20,425 12,508 3,187
13,122 14,175 2,575
8,315 14,347 4,208
4,598 13,148 1,708
95,920 67,311 15,809
Total
28,528
39,540
36,433
31,572
27,990
19,806
183,869
Land Use Conflict. In general, under the base case—as well as under all
scenarios—the probability of conflict between prime agricultural land use,
steep slope land use (forested lands or lands recommended for forestation),
and surface mining would change little from base period conditions. For
example, the low-sulfur coal that supplies SIP-governed units in the ORBES
region currently originates, and would continue to originate, in the hills of
eastern Kentucky, West Virginia, and Pennsylvania. Therefore, the possibility
of conflicts with prime farmland in supplying these plants is small, and the
probability of conflict with steep slopes higher. However, because the
surface mining of coal for scenario additions would take place in the same
state as each sited plant, the surface mining of coal to supply these new
units in the ORBES region would be 22 percent more likely to affect prime
farmland and 6 percent more likely to affect steep slopes than the mining for
existing SIP units.
Land Reclamation. In the year 2000 under the base case, 220,000 acres would
be undergoing a two-year reclamation process. Although the Appalachian Coal
Province contains more sloping land than does the Eastern Interior Province,
reclaimed ecological productivity and land use would vary only slightly under
the base case—and, indeed, under all scenarios—from present reclaimed
productivity and land use.
The ecological impacts of base case energy-related land use patterns
would vary according to the type of impact that is being examined. In general
163
-------
in the year 2000, as compared to base period conditions, less land would be
affected by sulfur dioxide concentrations resulting from utility emissions;
less crop loss would occur because of utility sulfur dioxide emissions and
because of oxidants formed by nitrogen oxide emissions; and more terrestrial
ecosystem units (measuring the amount of forest lands and of Class I and II
soils and the number of natural areas and endangered species affected) would
be assessed.
Under the base case, less land would be affected by utility-related
sulfur dioxide concentrations of 130 micrograms per cubic meter in the
presence of moderate ozone levels than was affected in 1976.^ Thus, while
the land affected by such concentrations represented 10 percent of the ORBES
region in 1976, such concentrations would affect only 4.8 percent of the
region in 1985 and only 3 percent of the region in 2000. Similarly, the
acreage affected by such concentrations would be lower in each state portion,
although the percentage reduction would vary significantly among the state
portions.
PHYSICAL CROP LOSSES. Regional agricultural losses due to such utility-
related sulfur dioxide concentrations in the presence of moderate ozone levels
are estimated not to be as high under the base case as the losses estimated
for 1976. In 1985, regional soybean, wheat, and corn losses would result in a
combined loss ranging from a minimum of 329,000 bushels to a maximum of 2.3
million bushels; the probable combined loss is estimated to be 1.2 million
bushels. In the year 2000, the range for the combined annual losses would be
from 248,000 to 1.7 million bushels, with 924,000 bushels representing the
probable combined loss.
Under the base case as well as during the base period, agricultural
losses due to sulfur dioxide would account for less than 1 percent of the
regional losses projected to occur because of sulfur dioxide and ozone. Yet,
on a local scale, such as the county, losses related to sulfur dioxide could
be significant, and losses to individual farmers substantial.
Regional agricultural losses due to ozone formed from regional nitrogen
oxide emissions in combination with other pollutants are estimated to increase
11 For a discussion of the acreage affected by sulfur dioxide
concentrations and for crop loss projections, see Orie L. Loucks et al., Crop
and Forest Losses Due to. Current and Projected Emissions from Coal-Fired Power
Plants in the Ohio River Basin (ORBES Phase II). In this analysis, peaic load
operation was assumed since crops would be most affected by sulfur dioxide
concentrations during the summer growing season, when electricity demand is
the highest.
164
-------
through 1985 under the base case. After 1985, however, as the nitrogen oxide
emissions of regional transportation sources decrease, regional agricultural
losses would decrease dramatically. It is projected, therefore, that after
1985 utility nitrogen oxide emissions will begin to account for a larger
percentage of the crop losses than they did in 1976 or 1985 since utility
nitrogen oxide emissions are not regulated and would continue to increase
through the year 2000.
In 1985, agricultural losses related to oxidants formed from all regional
nitrogen oxide emissions are projected to range from a minimum of 290 million
bushels to a maximum of 691 million bushels; the probable loss is estimated to
be 412 million bushels. In the year 2000, such agricultural losses are
projected to range from 99 million bushels to 358 million bushels, with 172
million bushels representing the probable loss.
It should be noted that soybean losses make up the majority of the
agricultural losses attributable to sulfur dioxide and that corn losses make
up the majority of the agricultural losses attributable to ozone. Moreover,
the percentage of losses in each state portion varies considerably. For both
the losses related to sulfur dioxide and those related to ozone, the ORBES
state portions of Illinois, Indiana, and Ohio would account for 95 percent of
the projected losses.
MONETARY CROP LOSSES. Also projected was the economic impact of these crop
losses attributable to utility sulfur dioxide emissions and to oxidants formed
from all regional nitrogen oxide emissions. Cumulative regional crop losses
between 1976 and 2000 would have a present discounted value of $70 billion (in
1975 dollars, or approximately $95 million in 1979 dollars).12 Oxidant
damages represent virtually all (99.3 percent) of this figure. In terms of
the crops examined, soybean dollar losses would represent 54 percent of the
total dollar loss figure; corn losses, 42 percent; and wheat losses, 3
percent. Of the ORBES state portions, dollar losses in Illinois and Indiana
would account for the majority (about 79 percent) of the probable regional
dollar losses, and Illinois, Indiana, and Ohio together would account for
about 95 percent.
1 ?
Present discounted value represents the cumulative dollar amount
between 1976 and 2000 that has been discounted to its value in 1976. The
projected cumulative dollar loss also is based on the probable crop loss
figures. For minimum and maximum losses, see Walter P. Page, James Ciecka,
and Gary Arbogast, Estimating Regional Losses to Agricultural Production from
Airborne Residuals in, the Ohio River Basin Energy Study Region, 1976-2000
(ORBES Phase II).
165
-------
FOREST LOSSES. Similar to the crop loss projections, forest losses are
projected to increase through 1985 and to decrease thereafter. The estimated
annual reduction in forest growth in 1985 due to air pollutants, principally
ozone, would be from 1.3 to 6.3 percent of the total production. In 2000,
projected annual losses would range from 0.4 to 1.9 percent of total
production. The reduction in forest growth projected for 1976 was from 0.7 to
3.4 percent.
TERRE
ECOLOGY. Between 1976 and 2000 under the base case, terrestrial
ecosystem assessment units would increase bv 1804 units over the 1976 total of
1306 units (a 138 percent increase).13 Among the ORBES state portions,
Indiana would experience the largest increase in 2000 (216 percent) from the
ecosystem units assigned to that state portion in 1976 (see figure 7-4). The
increases in state terrestrial ecosystem units among the other state portions
could range from a 101 percent increase in West Virginia to a 161 percent
increase in Kentucky.
7.3 Water
The aquatic habitat impacts that would occur in the year 2000 under base
case conditions, the ORBES reference concentrations, and 7-day-10-year low
Rgure 7-4
Terrestrial Ecosystem Assessment Units,
Base Case, by ORBES State Portion
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
20%
25%
15%
17%
15%
8%
(356 units)
(451 units)
(266 units)
(305 units)
(270 units)
(156 units)
1804 units
1 ?
J See Randolph and Jones, Ohio River Basin Energy Study:
Terrestrial Ecology.
Land Use and
166
-------
flow were projected for each of the 24 regional rivers selected for detailed
analysis. In general, aquatic habitat impacts under the base case would be
very similar to the impacts that could have occurred in 1976 under these low
flow conditions (see table 7-2). Moreover, as table 7-2 indicates, these
aquatic habitat impacts under the base case would be almost entirely the
result of high background concentrations alone or in conjunction with
municipal and industrial water consumption.15
Only two streams—the Big Muddy and the Illinois rivers—are projected to
experience aquatic habitat impacts different from those they could have
experienced in 1976, and only three streams—the latter two rivers plus the
Allegheny—are projected to experience impacts because of high background
concentrations and water consumption by power plants. Both of these results
would occur either because the stream in question is small and has a very low
flow under 7-day-10-year low flow or because a rather large amount of
generating capacity was added under the base case to a medium-size stream.
The Big Muddy, for example, is one of the region's smaller streams, with only
one reach and a flow of 37 cubic feet per second under 7-day-10-year low flow
conditions. Thus, as summarized in table 7-2, when 346 megawatts electric are
added on this river, drastic aquatic habitat impacts are projected to occur.
A rather large capacity (planned units plus scenario additions) is added to
the Allegheny and Illinois rivers under the base case. As a result, it is
projected that the Illinois would experience heavy aquatic impacts in
comparison to the moderate impacts that it would have experienced in 1976
under 7-day-10-year low flow conditions. The Allegheny River, however, would
experience the same aquatic habitat impacts as it was projected to experience
in 1976, although the water quality index would increase slightly under the
base case, indicating that the Allegheny would experience slightly more stress
than it would have in 1976.
Although additional generating capacity is added to other streams under
the base case, such capacity appears not to cause significant impacts either
because the stream is very large or because the impacts of background
concentrations and of municipal and industrial consumption far outweigh the
impacts that would occur because of power plant consumption. For example,
14
Details on water quality and aquatic ecology impacts are provided in
Clara Leuthart and Hugh T. Spencer, Fish Resources and Aquatic Habitat Impact
Assessment Methodology for the Ohio River Basin Energy Study Region (ORBES
Phase II).
IP;
For details on water consumption projections, see E. Downey Brill, Jr.
et al., Potential Water Quantity and Water Quality Impacts of Power Plant
Development Scenarios on Major Rivers in the Ohio Basin (ORBES Phase II).
167
-------
ON
00
"Background dal
tP = power plan
and C = combir
CD r »
°- » §
Q ^ <
2 o sr
^ W Q}
•o » 2
5T c ®
3. 3 si
Sf-a.
1 " 1
|||
f H'8~
8*8
° s3
0) (t> T3
1st
a. 3 o.
=• w •
M
H.
o'
m
I
TT
ID
5
c
a
o
(D
1
3.
i
i
*
i
i
o
i
s
i
o
CO
o
D
I
CD
1
m
0
-L
8
Wabash
o
.is
DO
•^
^
O
Q.
CD
3
CD
m
*
05
"8
ro
CO
0)
i
1
*
1
1
-
O
Scioto
O
8
O
I
CD
1
m
ro
§
CO
SL
1
*
1
1
O
O
3
g
JT
1
*
I
1
ro
O
Ohio River Main
CO
i
o
ft
o
CD
m
"2
«^j
^0
^
f^
"oo
ro
(0
Muskingum
O
O
o
I
CD
1
m
O
CO
-A
00
0)
Monongahela
O
s
o
CD
1
m
"s
CO
ro
O
S
|
0
00
CD
^
&
CD
3
CD
m
ro
Ol
0)
0)
(D
5'
o
01
O
I
0
1
m
0
0
5'
I
O
CO
o
o
I
0
1
m
0
0
Kentucky
1
*
1
1
O
I
f
0
Ol
03
•^
01
3
Better (+)
Worse (-)
Same (0)
as 1976
Impacts
Water Quality
Impact
(range: 0-1 00)
Base Case
Protection Levels
Base Case Aquatic
Habitat Impacts
Aquatic Habitat
Impactst
Number of
Scenario Additions
Utility-planned
Installed
Capacity (MWe)
If
§1
0)
. O"
< ™
CD ^B
tn _ m
C 3
i?
1*
cop®
"*"* M *J
V*"
•< ^
J^ 1
?o
(^ -<
r~ Z
^3 r^
£ <
^^ *c
-------
although 72 units, or 46,800 megawatts electric, were added to the Ohio main
stem under the base case in addition to the 42,829 megawatts electric
announced by the utilities, aquatic habitat impacts would be the same under
the base case in the year 2000 as they could have been in 1976 under 7-day-
10-year low flow conditions. As table 7-2 indicates, high background
concentrations and municipal and industrial consumption on the main stem
overwhelm the contribution of power plant consumption.
To summarize, base case water quality impacts, like the projected 1976
impacts, are primarily the result of the high background concentrations.
Thus, such concentrations would have to be lowered to avoid many of the
impacts that a natural phenomenon such as 7-day-10-year low flow could cause.
However, as discussed in chapter 6, it is deemed unlikely that the major
reason for these high background concentrations—nonpoint and geochemical
sources—could be brought under control during the time period of this study.
7-3.1 Water Variation
A variation of the base case also was explored in the water quality
analysis. In this variation, the water quality impacts of once-through
cooling were examined.^ Except for the substitution of once-through cooling
for cooling towers in the 72 units added to the Ohio River main stem under the
base case, this variation has the identical assumptions of the base case.
Once-through cooling is an older method of dissipating excess heat that
is not converted into electricity, and some plants currently using this method
are being retired or converted to newer methods such as evaporative cooling
towers. In the once-through cooling process, large quantities of water are
removed from a body of water, passed through the plant once so that the
temperature of the water is raised slightly, and then returned to the original
source. The heated effluents tend to slide along the surface of the water and
against the banks, where they enter the water. This mixing pattern does raise
the temperature of the water locally, but the temperature usually is
dissipated within 10 miles of the point of entry.
At present, 38 power plants along the Ohio River main stem reject heat
directly into the river by the once-through cooling method. In 1977, these
plants—assuming that they operate at a 50 percent capacity factor—released
the equivalent heat value of 51,600 tons of typical bituminous coal. By 1985,
the amount of heat rejected into the Ohio River main stem by once-through
cooling should be reduced by 11 percent because of planned retirements; by
2000, planned retirements and replacements should reduce the amount by 95
For a discussion of this variation, see Leuthart and Spencer, Fish
Resources and Aquatic Habitat Impact Assessment Methodology.
169
-------
percent. Water withdrawal for the cooling of power plants by 2000 thus would
be reduced considerably, and the loss of aquatic organisms (especially
embryonic fishes, eggs, and plankton) due to entrainment and impingement
should be reduced as well.1 ?
Although the 72 units added along the Ohio River main stem under the base
case are assumed to use once-through cooling under this variation, the rise in
water temperature that would occur from bank to bank is projected to be
important only locally. Water withdrawal, however, could have a serious
impact.
Water withdrawal under the once-through cooling case would be drastically
increased for the Ohio River main stem from the withdrawal under base case
conditions. This increase could have a devastating entrainment-impingement
impact on the main stem under 7-day-10-year low flow conditions. With once-
through cooling, the reduction in sensitive species that would occur as a
result of entrainment and impingement would range from a maximum of 16.2
percent at Ohio River mile point 70 to 7-53 percent below mile point 772.
The temperature impacts under the once-through cooling case would be
damaging locally, especially to sensitive bank habitats. Such temperature
impacts would be nonexistent under the base case. With a temperature of 83
degrees Fahrenheit, dissolved oxygen sags would occur from mile point 5.2 to
mile point 84.2, with levels reaching less than 4 milligrams per liter at the
midpoint. Dissolved oxygen sags would not be significant below mile point
84.2.
7.4 Employment
POWER PLANTS. Between 1975 and 1995 under the base case, a rise in employment
of about 327,000 person-years would occur because of power plant construction
and operation in the ORBES region.18 Moreover, the rate of increase in the
17
Entrainment is the process by which small organisms, particularly
embryonic fish, are caught up in the water intake, are passed through the
plant's system, and are killed or severely injured in the process.
Impingement is the process by which larger organisms are caught up in the
intake current, are trapped on the screen of the intake structure, and are
subsequently pounded to death.
18
Because of the scheduling of power plant construction, these
requirements were calculated only through 1995 for all ORBES scenarios
considered. For a discussion of such scheduling, see Gary L. Fowler et al.,
The. Ohio River Basin Energy Facility Siting Model (2 vols.). A person-year is
170
-------
demand for construction workers would be relatively stable between 1975 and
1995, and thus the potential for short-term labor shortages would be minimal.
The supply also should be adequate for the three critical skill
categories required for power plant construction: boilermakers, electricians,
and pipefitters.19 in 1990, the peak construction year, about 2400
boilermakers, 2300 electricians, and 2600 pipefitters would be needed. It
should be noted, however, that such regional projections do not mean that
localized shortages would be eliminated.
COAL MINING. In 1985 under the base case, coal production for all purposes
would increase by 162 million tons per year over 1974 levels (439.7 million
tons), and coal-fired electrical generating facilities in the ORBES region are
projected to consume 193-1 million tons of coal, compared with 134.9 million
in 1974. By 2000, annual coal production under the base case would be 376
million tons more than production in 1974, and the electric power sector is
projected to consume 248.3 million tons.
To meet this increased coal demand for all purposes under base case
conditions, coal-mining employment would increase dramatically in the 152
ORBES counties that have concentrations in coal-mining activity. In general,
the estimated increase in regional coal mining employment between 1970 and
2000 would be between a minimum of 35 percent and a maximum of 222 percent.
It also is projected that at least 79 of the 152 ORBES coal-producing counties
would experience mining employment growth rates of 200 percent or more and
thus that boom-town effects might be felt in these counties. At least 55
additional counties would experience growth rates between 50 and 199 percent.
7.5 Health
Because of the increased demand for coal under the base case, the
the equivalent of one person working full time for one year. For the
calculation of employment impacts, see Steven I. Gordon and Anna S. Graham,
Regional Socioeconomic Impacts of Alternative Energy Scenarios for the Ohio
River Basin Energy Study Region (ORBES Phase II).
1Q
It was assumed that the growth rate in the supply of these three
skills within the ORBES region would be similar to the growth rate of the
1970s and that the proportion of these workers employed in power plant
construction during the 1970s would remain constant.
20
For projections and discussions of regional coal demand, see Donald A.
Blome, Coal Mine Siting for the Ohio River Basin Energy Study (ORBES Phase
II). Coal is measured in short tons.
171
-------
occupational and public health impacts related to the coal cycle also would
increase in 1985 and 2000.21
In 1985 under the base case, about a 44 percent increase would be
experienced in the 1975 occupational health impacts related to coal extraction
for regional electrical generation. In 2000 under the base case, such impacts
would increase by approximately 102 percent (see table 7-3 for absolute
values).
In the coal-processing step of the coal cycle, health impacts due to
disease are difficult to estimate accurately. Thus, only those impacts
related to occupational accidents are projected. In 1985 under the base case,
an increase of approximately 44 percent would occur in the health impacts
related to coal processing for regional electrical generation. In 2000, an
increase of approximately 102 percent would occur over the 1975 impacts (see
table 7-3 for absolute values).
Whether statistics based on miles traveled or on weight transported are
used, accidental injuries related to coal transport for electrical generation
in the ORBES region would be about 45 percent lower in 2000 than they were in
1975. However, accidental deaths related to such transport would be about the
same in 2000 as they were in 1975 (see table 7-3 for absolute numbers) since
railroad injuries are projected to reduce at a greater rate than deaths.
As stated previously, the number of deaths attributable to air quality is
a matter of some controversy (see section 4.6 for an extended discussion).
Thus, all projections of future health impacts, although based on findings
reported in the current literature, could change as new evidence develops.
For the base case, projections are made of both particulate-related and
sulfate-related deaths, both of which would be reduced because of the improved
air quality resulting from SIP compliance.
21 See Maurice A. Shapiro and A.A. Sooky, Ohio River Basin Energy Study:
Health Aspects, for a discussion of the estimates relating to the health
impacts of coal mining, coal processing, and coal transportation. All
estimates for the coal-mining and coal-processing impacts under all the
scenarios assume a constant health impact rate using 1975 as a base year,
constant thermal efficiency and loading factors in the ORBES-region power
plants, similar extraction technologies (that is, deep and surface mining),
and a similar processing technique or source of fuel. The coal transportation
health impacts for all scenarios assume that coal is distributed to subregions
in proportion to the generating capacity in the subregion and that power
plants will continue to be supplied with coal from the same sources as in
1975.
172
-------
_
Table 7-3
Health Impacts Related to Coal Mining,
and Transportation, Base Case, 1985
Processing,
and 2000
COAL MINING
Accidental deaths
Disabling injuries
Nondisabling injuries
Disease-related deaths
Disease-related disabilities
COAL PROCESSING
Accidental deaths
Disabling injuries
Nondisabling injuries
COAL TRANSPORTATION
Vehicle miles traveled
Deaths
Injuries
Weight transported
Deaths
Injuries
1985
53
3813
3155
9
408
6
336
725
—
2000
75
5359
4435
12
573
9
472
1019
12
26
50
123
The best estimate of the annual deaths in the region because of
electrical generation and the resulting sulfate air pollution is 6350 deaths
in 1985 and 5150 deaths in 2000. However, these numbers could be as low as
zero or as much as three times higher than estimated because of the uncertain
nature of the damage functions used in the calculations.22 These figures
represent reductions from the projected 1975 sulfate-related deaths of 17.5
percent in 1985 and of 35 percent in 2000. As a result of this reduced health
damage, the mortality rate under the base case would be reduced by 0.6 percent
in 1985 and by about 1 percent in 2000. Cumulative sulfate-related deaths
between 1975 and 2000 due to ORBES-region electrical generation could total
about 163,000 if a rate of 3 deaths is used per 100,000 persons exposed per
microgram of sulfates per cubic meter.
22 See Shapiro and Sooky, Ohio River Basin Energy Study: Health Aspects.
for a fuller discussion of how these estimates were calculated. Upper and
lower limits can be found using a rate of 9 and 0 deaths, respectively, per
100,000 persons exposed per microgram of sulfates per cubic meter. A rate of
3 was used to calculate the numbers reported in the text.
173
-------
The best estimate of the cumulative deaths expected in the ORBES region
because of electrical generation and the resulting particulate air pollution
is about 1555.
-------
8. Impacts of the Strict Environmental Control Case
In this chapter, differences in impacts stemming from differences between
strict and base case environmental control policies in the ORBES region are
summarized and discussed. Under the strict environmental control case, the
same assumptions were made as under the base case except with regard to
environmental regulations. The strict control case calls for the application
of more stringent air, land, and water regulations. For details, see chapter
5.
8.1 Air
Between 1976 and 2000 under the strict environmental control case,
utility sulfur dioxide emissions and utility-related annual and episodic
concentrations would decrease more than they would under the base case.
Utility particulate and nitrogen oxide emissions, however, would be about the
same under both scenarios. Cumulative capital costs to install coal-fired
generating capacity also would be about the same under both scenarios,
although cumulative pollution control costs would be significantly higher
under the strict control case. Both the price of electricity and the
cumulative revenues required from consumers would be slightly higher under the
strict control case.^
SULFUR DIOXIDE EMISSIONS. Total utility sulfur dioxide emissions in the ORBES
region would be about twice as low under the strict environmental control case
in both 1985 and 2000 as they would be under the base case in the same years.
This reduction would occur because urban state implementation plans (SIPs),
which under strict controls would be applied throughout a state, are much
stricter than rural SIPs, which would be in force in rural areas under the
base case.
Specifically, with strict environmental controls, sulfur dioxide
emissions from all generating units in the ORBES region (SIP units, new source
No references to other ORBES reports consulted for this chapter are
given here or in the succeeding chapters on the coal-dominated futures. These
references appear in the corresponding sections of chapter 7.
175
-------
performance standards (NSPS) units, and revised new source performance
standards (RNSPS) units) would be about 51 percent lower by 1985 and about 41
percent lower by 2000 than under the base case (see figure 8-1a). Sulfur
dioxide emissions from SIP units alone also would be lower (56 percent lower
by 1985 and 61 percent lower by 2000). However, emissions from these units
still would make up the majority (83 percent) of all utility emissions in 1985
and a sizeable portion (45 percent) of all utility emissions in 2000.
Moreover, in 2000 under the strict control case, as under the base case, SIP
units would account for only 24 percent of the regional electrical generation.
However, since emissions from SIP units would constitute 6? percent of all
utility emissions in 2000 under the base case, the strict control case would
lead to a more balanced emission-generation ratio.
PARTICULATE EMISSIONS. Utility particulate emissions in the ORBES region
would be identical in 1985 and nearly the same in 2000 under the strict
environmental control case and the base case since SIP particulate standards
are assumed to be the same under both cases in both rural and urban areas.
NITROGEN OXIDE EMISSIONS. Utility emissions of oxides of nitrogen in the
ORBES region would be almost identical in 1985 and 2000 (less than 1 percent
difference) under both the strict environmental control case and the base
case. The primary reason for this similarity is that both of these scenarios
have the same generating capacity and assume the same nitrogen oxide controls.
SULFUR DIOXIDE AND SULFATE CONCENTRATIONS. If the same conditions of
extremely persistent winds were to occur under the strict environmental
control case as those that occurred during the August 27, 1974, sulfate
episode, the sulfur dioxide and sulfate concentrations related to utility
emissions would be so much lower than the concentrations that occurred on
August 27, 1974, that they no longer would be considered episodic.
Specifically, in the area that experienced the highest episodic concentrations
under the base case in 1985, the sulfur dioxide and sulfate concentrations
would be 54 and 68 percent lower, respectively, in the same year under the
strict control case. In the year 2000, episodic sulfur dioxide and sulfate
concentrations would be 50 and 55 percent lower, respectively, under strict
controls than under the base case.
Annual regional sulfur dioxide and sulfate concentrations due to utility
sulfur dioxide emissions would be substantially lower under the strict
environmental control case than under the base case. In the area that
experienced the highest annual concentrations under the base case, sulfur
dioxide and sulfate annual concentrations would be significantly reduced both
in 1985 (by 46 and 39 percent, respectively) and in 2000 (by 42 and 33
percent, respectively). In figures 8-2 and 8-3, the concentrations that would
result in 2000 under" the two scenarios are compared. These figures
reemphasize that the location of the highest concentrations would tend to stay
176
-------
Rgure 8-1
Base Case versus Strict Environmental Control Case
8-1 a. Electric Utility Sulfur Dioxide Emissions
11 -j
10-
~ 9-
co
1 8-
c
i 7-
le-
CO
2 5-
CO
E
0
6 3"
W 2-
1-
U
V
\ \
vy^^
\ — -~^ ^^
\ ^"^^^
\ ^^-
\ ^
\
\ */~~ ^^^
~" —^—
Base Case (BC)
Strict Environmental Controls (SEC)
976 1980 1985 1990 1995 2000
8-1 b. Sulfur Dioxide Emissions
and Control Costs
40-
30-
20-
g 10-
0
O) ft
01 0
CO
o-10-
-20-
-30-
-40-
-50-
i?5^ Increase over Base Case
8feg!j Cumulative SO2 Control Costs
Reduction from Base Case
SO, Emissions in 20OO
.^p: SEC
|§1
yWyjfif
^M
J 4?^|
SS^ r-./^
DL>
SEC
8-1 c. Electricity Prices
6 -i
Z 5-
10 4~
o>
1 3"
0
0
"o
2
1~
/ SEC
/ ^_^^^^BC
X^>^"
_^s/
Price (1 975
-------
Figure 8-2
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
Base Case in 2000
Strict Control Case in 2000
Rgure 8-3
Annual Average Sulfate Concentrations, Electric Utility Contribution
.Base Case in 2000
Strict Control Case in 2000
1-2.99
3-4.99 5-6.99
Ojg/m3)
7-9
178
-------
about the same as under the base case even though the concentrations would be
reduced under the strict control case.
UTILITY COSTS. To achieve the air quality regulations of the strict control
case, cumulative capital costs for pollution control through the year 2000
would be about 20.7 percent higher than under the base case. This increase
would be due entirely to differences in the costs of retrofitting additional
SIP units with flue gas desulfurization systems ("scrubbers"); this additional
retrofitting would result in costs 32.1 percent higher under the strict
control case than under the base case. Thus, a tradeoff is indicated between
the emission reductions that could be achieved by the year 2000 and the
utility costs to achieve such reductions (see figure 8-1b). The cost of
controlling particulate emissions would be nearly identical under both
scenarios.
CONSUMER COSTS. Despite the higher capital costs for pollution control under
the strict environmental control case, the cost of electricity to the consumer
would be only slightly higher (see figure 8-1 c). In 1985 under the strict
control case, the cost of electricity to the consumer would be 8.8 percent
higher than under the base case, primarily because of the costs of
retrofitting more SIP units to meet the stricter standards. As the costs are
such retrofitting are paid off, however, the cost of electricity under the
strict control case would start to level off and would be only 1.5 percent
higher in the year 2000 than under the base case. The cumulative revenues
collected from consumers between 1976 and 2000 also reflect the similarities
between these two scenarios. These cumulative revenues would be only 4
percent higher under the strict control case than under the base case.
8.2 Land
The land conversion required in the ORBES region for all energy-related
uses and for electrical generating facilities in particular would be only
slightly higher under the strict environmental control case than under the
base case. The acreage required for surface mining, however, would be
slightly lower under the strict control case. The number of terrestrial
ecosystem units assessed would be slightly higher under the strict control
case.
LAND USE. Under the strict environmental control case, the land conversion
required for all new energy-related uses (new generating facilities, new
cooling reservoirs, new transmission line rights-of-way, and new utility
surface mining) would be approximately 1 percent higher in 2000 than under the
base case. The land required for electrical generating facilities alone would
be 1.8 percent higher in 2000. Most of this increase can be attributed to the
fact that approximately 40 standard 650 megawatt electrical generating units
179
-------
would be sited in more dispersed locations under the strict control case than
under the base case.
The strict environmental control case would result in 5.5 percent more
agricultural land being converted for generating facilities than the
conversion required under the base case. Most of the additional agricultural
land would be converted in the ORBES state portion of Ohio, where more of the
dispersed siting occurs. The amount of public land used for electrical
generating facilities, however, would be 6.7 percent lower; the amount of
forest land, 1.1 percent lower; and the amount of other land, 6.4 percent
lower.
In the year 2000 under strict controls, the total regional acreage needed
for the surface mining of coal for regional utilities would be less than the
acreage needed under the base case. Specifically, 1.2 percent less acreage
would be affected by surface mining for utility coal between 1976 and 2000.
As a result, the amount of land required at the state level for the surface
mining of utility coal would be less than under the base case; the largest
decrease (6 percent) would be in the ORBES portion of Illinois.
TERRESTRIAL ECOSYSTEMS. In the ORBES region under the strict control case,
the number of terrestrial ecosystem units assessed for the period 1976 to 2000
would be 3 percent higher than the number assessed under the base case between
those same years. This difference suggests that counties located inland from
the Ohio River corridor generally would have higher ecological assessments (as
defined in the model) than counties bordering the river. Only the ORBES
portion of Ohio would have fewer terrestrial ecosystem units assessed in 2000
under the strict control case than it would under the base case. In all other
ORBES state portions, however, the terrestrial ecosystem units assessed under
the strict control case would be slightly higher than those assessed under the
base case, ranging from a 1 percent increase in Kentucky to a 9 percent
increase in Illinois.
8.2.1 Land Variations
Two variations in land use under the strict control case also were
examined; both concern agricultural land protection. In these two variations,
the same assumptions and environmental controls as under strict controls
Of these 40 units, 15 are sited in areas of Ohio that are removed from
major water sources. If an average-size cooling reservoir (975 acres) were to
be built for each of these 15 units, 14,600 more acres would be required under
the strict control case than indicated in the text.
180
-------
prevail except for the fact that a county is excluded as a generating unit
site if 50 percent or more of its area is in Class I and II soils. The first
variation calls for both agricultural land protection and dispersed siting of
electrical generating facilities, while the second calls for such protection
and concentrated siting.
The land conversion required for electrical generating facilities under
both variations would be lower than that required under the strict control
case, although installed capacity would be the same under all three cases (see
table 8-1). In general, fewer units are sited in northern Illinois and
Indiana and in western Ohio under the dispersed variation. The new units
instead are sited in the coal-producing areas of southern Illinois and Indiana
and in southeastern Ohio. In the concentrated siting variation, generating
units are sited nearer the Ohio River main stem.
Such agricultural land protection policies would help preserve
agricultural land, but there would be a corresponding increase in the
conversion of forest land. Of the concentrated and dispersed patterns,
concentrated siting would require more agricultural land than dispersed siting
would; the dispersed pattern would require more forest land (see table 8-2).
Regionwide terrestrial ecosystem units, however, would be only slightly
higher under the dispersed siting variation than under the strict control
Land Converted for
Table 8-1
Electrical Generating Ricilities
ORBES State Portion
Scenario Illinois Indiana
Strict
Environmental
Controls 30,717 40,643
Dispersed Siting,
Agricultural
Protection 28,562 38,942
Concentrated
Siting, Agricultural
Protection 28,566 38,945
ORBES
West Region
Kentucky Ohio Pennsylvania Virginia Total
(acres)
36,431 31,543 27,990 19,805 187,129
32,774 17,159 27,991 33,060 178,488
32,777 27,077 27,936 24,228 179,529
181
-------
Table 8-2
Agricultural and Forest Land Converted for
Electrical Generating Facilities
ORBES State Portion
Scenario
Strict
Environmental
Controls
Agricultural Lands
Forest Lands
Dispersed Siting,
Agricultural
Protection
Agricultural Lands
Forest Lands
Concentrated Siting,
Agricultural
Protection
Agricultural Lands
Forest Lands
Illinois
24,691
3,353
21,953
4,070
21,328
4,609
Indiana
26,534
10,087
25,416
10,381
26,046
10,217
West
Kentucky Ohio Pennsylvania Virginia
(acres)
21,165 18,274 6,779 3,790
12,663 9,601 16,280 14,608
16,076 7,057 6,911 6,453
13,987 7,572 15,795 24,586
17,127 11,841 7,819 5,263
12,287 11,677 15,199 17,813
ORBES
Region
Total
101,233
66,592
83,866
76,391
89,424
71,802
case, while the concentrated siting variation would result in slightly fewer
terrestrial units than would the strict case (see table 8-3). The dispersed
siting case would result in this higher number of units because the protection
of Class I and II soils along with the dispersed criteria would cause a shift
to areas with terrestrial ecosystem variables that are more interrelated:
forest lands, natural areas, and endangered species.
The strict environmental control case is unique in several respects with
regard to water impacts. It is the only scenario in which electrical
generating units (a total of 15) are sited in areas requiring water storage
for cooling. It also is one of only two scenarios in which units are sited on
relatively small tributaries (the high electrical energy growth case is the
other—see section 10.3). However, as under the base case, aquatic habitat
impacts under the strict control case and 7-day-10-year low flow conditions
would be due largely to the high background levels of pollutants alone or in
conjunction with municipal and industrial consumption. Only 2 of the 24
182
-------
Table 8-3
Terrestrial Ecosystem Assessment Units
ORBES State Portion
Scenario
Strict Environmental
Controls
Dispersed Siting,
Agricultural
Protection
Concentrated Siting,
Agricultural
Protection
ORBES
West Region
Illinois Indiana Kentucky Ohio Pennsylvania Virginia Total
390 458 268
41 1 447 274
413 452 241
300 277 164 1857
178 283 273 1866
240 270 191 1807
rivers selected for detailed analysis, the Big Muddy and the Allegheny, would
experience impacts related to power plant consumption.
Table 8-4 indicates the differences that would occur under the strict
environmental control case during 7-day-10-year low flow conditions from the
impacts projected under the base case during these same conditions. As the
table indicates, most of the rivers would have the same protection levels and
the same aquatic habitat impacts as under the base case. Only five rivers
would register changes, and these changes would be in the direction of
improvement. It should be noted, however, that most of the water quality
indices of the other rivers would change, registering slight improvements over
the base case index values. Such improvements suggest that less stress and
perhaps fewer violations of water quality parameters would occur on these
rivers. Nevertheless, these slight improvements would not be significant
enough to change the overall aquatic habitat impacts.
The reason for these improvements in the index—even when units are added
to a stream—concerns two assumptions. First, it is assumed that all but 5
percent of power plant effluents will be controlled under the strict control
case, while the base case assumes no effluent controls. Moreover, the strict
control case also assumes that by the year 2000 background levels will be
one-half of the levels that are assumed for the base case, as well as for all
other scenarios. As a result, under. strict controls, the White River, for
example, can have three more units added than under the base case, have a
183
-------
Table 8-4
Aquatic Habitat Impacts, Base Case versus Strict
Environment Control Case, 7-Day-1 0-Year Low Flow, Year 2000
River
Allegheny
Beaver
Big Muddy
Big Sandy
Cumberland
Great Miami
Green
Illinois
Kanawha
Kaskaskia
Better (+)
Worse (-)
Same (0)
As Base Case
Habitat Impacts
0
0
+
0
0
0
0
+
0
0
Water Quality Change in Change in Number of
Impact Index Base Case Base Case Units Added or
(range: Protection Habitat Removed from
0 to 100) Levels Impacts Base Case
25 +4
25 - 3
15 B Moderate
33 + 1
25
25 + 1
25
15 B Moderate - 5
25 + 1
15
Kentucky — — * —
Licking
Little Miami
Mississippi
Monongahela
Muskingum
+
0
0
0
0
Ohio Main Stem 0
Rock
—
1 6 B Moderate
41 + 1
15
25
30 - 3
33 -29
*
Salt — — —
Scioto
Susquehanna
Wabash
White
Whitewater
*Background
0
—
0
0
—
25
*
15 +2
15 C Moderate + 3
- * - +1
data unavailable; analysis could not be completed.
184
-------
water quality index value of 15 rather than 30, and have moderate rather than
heavy aquatic habitat impacts. Similarly, a stream like the Big Sandy, which
had no scenario additions or planned capacity under either the base case or
the strict control case, still would register improvements in its index (from
39 to 33); both indices, however, indicate heavy aquatic habitat impacts.
Thus, as a whole, despite the assumptions concerning loadings and background
concentrations, few changes in overall aquatic habitat impacts would be
registered under the strict control case. These results suggest that
background levels are so high that they would have to be reduced by more than
half to avoid serious aquatic habitat impacts under 7-day-10-year low flow
conditions.
As under the base case, the Allegheny and the Big Muddy rivers would be
the only two rivers whose impacts are related to high background
concentrations and power plant consumption rather than to such concentrations
alone or in conjunction with municipal and industrial consumption. The
Allegheny would experience such impacts because of the large added capacity;
the Big Muddy, because it is a very small stream.
Two general observations can be made about the impacts projected to occur
under strict controls because of power plant consumption. First, minor shifts
in siting patterns or the use of alternative cooling technologies could
alleviate power-plant-related water quality problems. Second, even though
many of the region's smaller tributaries, such as the Big Muddy, meet criteria
for water supply, these streams probably are not suitable for the siting of
650 megawatt electric units under either strict environmental controls or the
base case. However, as discussed in chapter 6, such shifts in siting could
cause other environmental impacts to occur. Moreover, high background
concentrations are the main reason for most of the water quality problems
under strict controls—even though these concentrations are assumed to be 50
percent lower. However, as discussed previously, it is improbable that
background concentrations can be reduced during the time frame of this study
since nonpoint and geochemical sources account for most of these
concentrations, and these sources probably will not be brought under control
by the year 2000.
8.4 Employment
POWER PLANTS. Under the strict environmental control case, employment related
to power plant construction and operation would be about 7 percent higher
between 1975 and 1995 than it would be under the base case between those same
years. Moreover, as under the base case, the rate of increase in the demand
for construction workers would be relatively stable between 1975 and 1995, and
thus the potential for short-term labor shortages would be minimal.
The differences in labor demand between these two scenarios would occur
primarily because the strict environmental control case assumes the use of
185
-------
scrubbers on both urban and rural electrical generating units. Under the base
case, however, scrubbers would be required only on urban units. Labor
requirements for the construction of facilities with scrubbers are about 16
percent higher than those for similar facilities without scrubbers.
The strict environmental control case also would employ slightly more
(about 5-7 percent more) power plant construction and operation workers in
1990 than would the base case in the three critical skill categories
examined—boilermakers, electricians, and pipefitters. In addition, the
demand for boilermakers would be high and the possibility of a shortage in
this skill category would exist. The demand for electricians and pipefitters
should be met easily.
The slightly higher labor demand under the strict control case as
compared to the base case is interesting in light of the dispute over the use
of scrubbers. Such higher employment benefits, plus the fact that the high-
sulfur coals in the ORBES region would be more competitive and keep more
miners employed, are a tradeoff with the costs of building such systems.
Because the increased use of scrubbers by electrical generating
facilities under the strict control case would result in a decrease in thermal
efficiency, generating facilities would have to burn more coal to produce the
same amount of electricity as under the base case. To meet the increased
needs of these facilities as well as the needs of all other industries, annual
coal production would be slightly higher (about 2 percent) by 2000 under the
strict control case than under the base case in that year. Similarly,
electrical generating units also would consume approximately 2 percent more
tons of coal in 2000 under the strict control case than they would under the
base case in 2000.
However, since the demand for coal would be similar under the strict
control case and the base case, both scenarios would require essentially the
same numbers of coal-mining workers for all purposes. For example, regional
coal-mining employment would increase between 36 and 231 percent under the
strict control case, compared with a range of 35 to 222 percent under the base
case. Moreover, differences in coal-mining employment trends, as well as in
the geographical distribution of this employment, would be minimal. For
example, only 4 more counties might experience boom-town effects under strict
controls than might experience such effects under the base case. At least 53
counties would experience growth rates between 50 and 199 percent under the
strict control case, compared to at least 55 such counties under the base
case.
8.5 Health
Since the demand for coal for electrical generation would be nearly the
186
-------
same under the strict control case as under the base case, and since nearly
the same number of workers are needed under both cases, the same health
impacts are projected to occur under both cases in the coal-mining, coal-
processing, and coal transportation sectors. Similarly, since utility
particulate levels would be almost identical under the two scenarios, the
number of deaths related to emissions of this pollutant would be almost the
same under both scenarios. However, because the regional sulfur dioxide air
quality would improve significantly under strict controls, substantially fewer
cumulative deaths (about 33 percent fewer) are projected to occur between 1975
and 2000 from sulfate air pollution by ORBES-region electrical generating
facilities. This cumulative reduction is projected based on annual average
deaths that are 58 percent lower in 1985 and 52 percent lower in 2000 than
they would be under the base case in 1985 and 2000, respectively.
18?
-------
9. Impacts of the SIP Noncomplianoe Case
This chapter sets forth comparisons in impacts between the base case (the
SIP compliance case) and the SIP noncompliance case. However, neither
employment nor water quality analyses were conducted for the SIP noncompliance
case.
The primary assumption of the SIP noncompliance case is that present
state implementation plans (SIPs) will not be enforced in the ORBES region.
Currently, SIPs exist for sulfur dioxide and particulates in all six of the
ORBES states. Only the urban areas of Illinois, however, are regulated by a
SIP for oxides of nitrogen. Other than this assumption, the noncompliance
case is identical to the base case.
9.1 Air
If state implementation plans are not complied with, regional utility
sulfur dioxide and particulate emissions would be substantially higher than
those under the base case. As under all of the coal-dominated scenarios,
utility emissions of oxides of nitrogen would increase between 1976 and 2000
under the SIP noncompliance case. Regional episodic and annual sulfur dioxide
and sulfate concentrations related to utility sulfur dioxide emissions also
would increase under SIP noncompliance. However, costs to both utilities and
consumers would decrease under the noncompliance case since less pollution
control equipment would be installed under the noncompliance case than under
the base case.
SULFUR DIOXIDE EMISSIONS. Utility sulfur dioxide emissions in the ORBES
region would range from 70 to 120 percent higher between 1985 and 2000 under
the SIP noncompliance scenario than under the base case. More specifically,
the sulfur dioxide emissions from regional, noncomplying SIP units would be 81
percent higher in 1985 and 121 percent higher in 2000 than the emission levels
for SIP units under the base case in those years. Sulfur dioxide emissions
from all generating units in the ORBES region (SIP units, new source
performance standards (NSPS) units, and revised new source performance
See the corresponding sections of chapter 7 for references to the other
ORBES reports consulted for this chapter.
188
-------
standards (RNSPS) units) would be 66 percent higher by 1985 and 74 percent
higher by 2000 than base case emission levels for all units in those years
(see figure 9-1a). Since SIP emissions would constitute 98 percent of all
utility emissions in 1985 and 86 percent in 2000 under the SIP noncompliance
scenario, noncompliance would be responsible for almost all of the emission-
related impacts projected to occur. However, SIP units would account for only
40 percent of total regional electrical generation in 2000 under the SIP
noncompliance case. The disproportionality of the emission-generation ratio
thus emphasizes the disadvantages of such noncompliance.
Plant Lifetime. It is interesting to note the significant emission increases
that are projected to occur under the SIP noncompliance case when longer
generating unit lifetimes are assumed. In the year 2000, total utility sulfur
dioxide emissions would be 7.55 million tons assuming a 35-year generating
unit life, 10.1 million tons assuming a 45-year life, and 11.1 million tons
assuming a 55-year life. Thus, utility sulfur dioxide emissions would be 25
percent higher in the year 2000 with a 45-year plant life than with a 35-year
life, and 32 percent higher in that year with a 55-year life than with a 35-
year life.
PARTICULATE EMISSIONS. In both 1985 and 2000, utility particulate emissions
in the ORBES region would be as much as six times higher under the SIP
noncompliance case than the emissions that would be expected under compliance,
or the base case, in those years.
NITROGEN OXIDE EMISSIONS. Utility emissions of oxides of nitrogen in the
ORBES region, however, would not be significantly different in either 1985 or
2000 under the SIP noncompliance case and the base case. Similar emission
levels would result because none of the ORBES states has SIP standards for
nitrogen oxides, except for the urban areas of Illinois. Thus, since both
scenarios have the same nitrogen oxide standards and generate about the same
amount of electricity, they would result in about the same utility nitrogen
oxide emissions.
SULFUR DIOXIDE AND SULFATE CONCENTRATIONS. If the same conditions of
extremely persistent winds were to occur under the SIP noncompliance case as
those that occurred during the August 27, 1974, sulfate episode, sulfur
dioxide and sulfate concentrations due to utility emissions would be much
higher. In 1985, in the area that experienced the highest episodic
concentrations due to utilities under the base case, sulfur dioxide
concentrations would be 71 percent higher; sulfate concentrations would be 42
See chapter 6 for the possible effect on plant lifetimes of a change in
the regulatory definition of a modification to an existing unit.
189
-------
to
-g
0>
(O
oo
o
VO
o
(O
(O
o.
price of electricity (1975 O/kWh)
CD CO
§> TJ
CD z
o o
CD o
si
-~ Q3
U
r>
CD
(O
- W IV)
^ Ul
. O OQ
a>
a>
p
m
CD
O
•^
2!
TJ
o'
SO2 emissions (million tons)
-L ro w
I 1 |
W fO -t
o o o
I I I
change (%)
3 8 S £
Ul
o
-si
o
00
o
CO
I
CD
O
CO
T3
Q>
m
I
^
o"
c
CO
c
q
5'
X
a!
CD
m
3
w'
M
5'
2
sr
3 E
§0
••*• O
3 a.
— Q.
oo
S m
M
5'
(A
00
DJ
(A
CD
(g
3
CO(Q
o cp
"
5'
i
o
-------
percent higher in that area. By 2000, regional episodic sulfur dioxide and
sulfate concentrations in the same area would be 71 and 41.6 percent higher,
respectively, than under the base case in that year.
Annual concentrations in the ORBES region due to utility sulfur dioxide
emissions would be substantially higher under the SIP noncompliance case than
under the base case. In 1985, in the area that experienced the highest annual
concentrations under the base case, annual sulfur dioxide and sulfate
concentrations would be about 61 and 54 percent higher, respectively, than the
concentrations projected under the base case for that year. In 2000 under SIP
noncompliance, annual sulfur dioxide and sulfate concentrations in the same
area would be about 64 and 56 percent higher, respectively, than the
concentrations projected under the base case for that year. Figures 9-2 and
9-3 emphasize the differences between these two scenarios in annual average
concentrations within the region in the year 2000.
UTILITY COSTS. With SIP noncompliance, cumulative costs for pollution control
through the year 2000 would be about 30 percent lower than under the base
case. The cost of controlling sulfur dioxide emissions would be about 18
percent lower under the noncompliance case than the cost under the base case
since no SIP units would be retrofitted with sulfur dioxide control systems
under the noncompliance case. However, this 18 percent difference in sulfur
dioxide pollution control costs translates into a 74 percent increase in
utility sulfur dioxide emissions by the year 2000 (see figure 9-1b). Because
of fioficompliance with SIP particulate limits, the cost of controlling
particulate emissions would be about 54 percent lower than under the base
case. As a result of the lower pollution control costs under the SIP
noncompliance case, cumulative costs to the utilities between 1976 and 2000
for new coal-fired generating capacity and for retrofitting and installing
pollution control devices would be about 5 percent lower under the SIP
noncompliance case than such costs would be under the base case.
CONSUMER COSTS. With these reduced pollution control costs, the cost of
electricity to the consumer would be about 20 percent lower in 1985 under the
SIP noncompliance case than under the base case in that year. By 2000,
however, the price of electricity would be only about 4 percent lower under
the noncompliance case than it would be under the base case (see figure 9-1c).
The reason why there is such a small difference between the two scenarios in
2000 concerns the fact that the compelling forces behind rising prices between
1985 and 2000 would be the expansion and replacement of generating capacity.
The cumulative revenues required from consumers between 1976 and 2000 would be
about 9 percent lower under the SIP noncompliance case than under the base
case ($475 billion under the former case and $525 billion under the latter).
9.2 Land
Since the generating capacity and the siting would be the same under both
191
-------
Rgure 9-2
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
Base Case in 2000
SIP Noncompliance Case in 2000
i
2-5.9 6-9.9
10-13.99
(ng/m3)—
14-17.99 18-24
Rgure 9-3
Annual Average Sulfate Concentrations, Electric Utility Contribution
Base Case in 2000
SIP Noncompliance Case in 2000
I
1-2.99 3-4.99 5-6.99 7-9
192
-------
the base case and the SIP noncompliance case, the amount of land converted and
the number of terrestrial ecosystem units assessed also would be the same
under both scenarios. However, because utility sulfur dioxide emissions would
be significantly higher under the noncompliance case, related regional crop
losses also are estimated to be higher. On the other hand, because utility
and thus total nitrogen oxide emissions under SIP noncompliance would change
little from the emissions projected under the base case, crop losses due to
oxidants formed from such emissions as well as forest losses (which are due
primarily to ozone) are estimated to be the same under both scenarios in both
1985 and 2000. Thus, any change in crop losses under the noncompliance case
would be related to sulfur dioxide emissions. Since losses due to ozone
impacts account for about 98 percent of regional crop losses, any change in
the sulfur-dioxide-related losses would be a small percentage of the total
losses.
In general under SIP noncompliance, substantially more acres than under
the base case would be affected by utility-related sulfur dioxide
concentrations of 130 micrograms per cubic meter in the presence of moderate
ozone levels (0.06 to 0.1 parts per million). Under SIP noncompliance, 114
and 105 percent more land would be affected in 1985 and 2000, respectively, by
such concentrations than would be affected under the base case in those years.
Thus, while under the base case the land affected by such concentrations would
represent 4.8 percent of the ORBES region in 1985 and 3.1 percent in 2000,
such concentrations under SIP noncompliance would affect 9-6 percent of the
region in 1985 and 6.2 percent in 2000.
PHYSICAL CROP LOSSES. Regional agricultural losses due to such sulfur dioxide
concentrations are estimated to be substantially greater under SIP
noncompliance than the losses projected under the base (SIP compliance) case.
In 1985 under SIP noncompliance, regional soybean, wheat, and corn losses
would result in a combined loss ranging from a minimum of 817,000 bushels to a
maximum of 5.6 million bushels; the probable combined loss is estimated to be
3 million bushels. These ranges are about 140 percent higher than the ranges
estimated under the base case in 1985. In the year 2000, the combined loss
under the SIP noncompliance case would range from a minimum of 564,000 bushels
to a maximum of 4 million bushels, with 2.2 million bushels representing the
probable loss. These ranges are about 136 percent higher than the ranges
estimated under the base case in 2000.
Under the SIP noncompliance case, as under the base case, agricultural
losses related to sulfur dioxide would represent less than 1 percent of the
total regional yield. However, on a local scale, such as the county, losses
could be significant; losses to individual farmers could be substantial. For
example, as under the base case, the ORBES state portion of Illinois would
account for most of the regional crop losses—from 45 to 56 percent of the
regional losses in 1985 and from 54 to 68 percent in 2000, depending on the
crop. Illinois together with two other ORBES state portions—Indiana and
193
-------
Ohio—would account for about 95 percent of these estimated sulfur dioxide
losses.
MONETARY CROP LOSSES. The cumulative regional agricultural dollar
losses—comprising wheat, corn, and soybean losses—would be almost identical
under both the SIP noncompliance case and the SIP compliance (base) case for
losses associated with utility sulfur dioxide concentrations and with ozone
concentrations due to regional nitrogen oxide emissions. Furthermore, the
distribution of monetary losses across the ORBES state portions would be
almost identical under both scenarios. Thus, agricultural dollar losses, as
well as the distribution of these losses, are not at all sensitive to
alternative policy statements concerning SIP compliance.
9.3 Health
Since coal-fired installed capacity would be the same in 1985 and in 2000
under both the base case and the SIP noncompliance case, health impacts in the
coal-mining and coal-processing sectors would be the same under both cases.
However, because air quality would be significantly worse under SIP
noncompliance, substantially more cumulative deaths are projected to occur
between 1975 and 2000 from sulfate and particulate air pollution by electrical
generating facilities in the ORBES region. Under SIP noncompliance,
cumulative deaths related to sulfate air pollution are estimated to be 3^
percent higher than under the base case. The annual number of deaths
associated with sulfate air pollution would be 55 percent higher in 1985 and
62 percent higher in 2000 than they would be under the base case in those
years. Cumulative deaths related to particulate air pollution are projected
to be 162 percent higher under the SIP noncompliance case than under the base
case.
194
-------
10. Impacts of. the High Electrical Energy Growth Case
In this chapter, the effects of high electrical energy growth in the
ORBES region (at an annual average rate of 3«9 percent between 1974 and 2000)
are compared with those of energy growth under the base case (3.13 percent
annually). The high electrical energy growth case also assumes a 45-year
lifetime for new generating units, while the base case assumes a 35-year
lifetime for new units. As a result of the high electrical energy growth
projected, installed generating capacity in the ORBES region would be 178,372
megawatts electric in the year 2000, compared with 153,245 megawatts electric
under the base case. Other than the electrical energy growth and generating
unit lifetime assumptions, the base case and the high electrical energy growth
case are the same. For more details, see chapter 5.
Two variations of the main high growth scenario also were examined in the
air quality analyses; these variations are discussed in section 10.1.1.
10.1 Air
The high electrical energy growth case and the base case would result in
about the same utility sulfur dioxide, particulate, and nitrogen oxide
emissions and about the same regional sulfur dioxide and sulfate
concentrations in 1985. These emissions and concentrations would be similar
in 1985 because the same generating capacity is assumed for both scenarios in
that year. However, since capacity expands more under the high growth case
after 1985, and since generating units have a 45-year rather than a 35-year
lifetime, all emissions and concentrations would be higher under the high
growth case than under the base case by the year 2000.'
EMISSIONS. Under high electrical energy growth, sulfur dioxide emissions from
units regulated by state implementation plans (SIPs) would be 47 percent
greater in 2000 than the emissions from SIP-regulated units under the base
case in that year. SIP emissions also would make up 71 percent of the
regional utility emissions in 2000 under the high growth case, although units
regulated by SIPs would account for only 25 percent of the total regional
References to the other ORBES reports consulted for this chapter appear
in the corresponding sections of chapter 7.
195
-------
electrical generation in 2000. Additional data suggest that the majority of
the increase in emissions would be attributable to the differences in plant
lifetimes and not to the differences in electrical energy growth. Utility
sulfur dioxide emissions from all units would be 39 percent higher in 2000
under high electrical growth than under the base case (see figure 10-1a). By
2000 under the high electrical energy growth case, utility particulate
emissions would be 36.8 percent higher than base case levels in that year.
Similarly, utility nitrogen oxide emissions would be 31.5 percent higher in
2000 than they would the be under the base case in that year.
CONCENTRATIONS. If the same conditions of extremely persistent winds were to
occur under the high growth case in 2000 as those that occurred during the
August 27, 1974, sulfate episode, utility-related sulfur dioxide and sulfate
concentrations would be higher than under base case conditions in 2000. In
the area of highest concentrations under the base case, for example, utility-
related sulfur dioxide and sulfate concentrations would be about 37 and 65
percent higher, respectively, under the high growth case.
In the year 2000, annual regional sulfur dioxide and sulfate
concentrations due to utility sulfur dioxide emissions would be about 43 and
47 percent higher, respectively, under the high electrical energy growth case
in the area of highest concentration than the projected concentrations in the
same area under the base case. Figures 10-2 and 10-3 illustrate the
differences between the annual concentrations under the base case and under
the high growth case. Figure 10-2 compares annual sulfur dioxide
concentrations in the year 2000 under both scenarios. As this figure
indicates, the area along the Ohio River main stem still would be the most
affected portion of the ORBES region under high growth, although more of that
area would be affected by higher concentrations. Figure 10-3 compares annual
sulfate concentrations under the two scenarios. As shown by the figure, the
acreage affected by the highest concentration—almost the entire ORBES
region—would be almost identical under both scenarios; the concentration
levels, however, would increase under the high growth case.
UTILITY COSTS. Cumulative capital costs for new coal-fired generating
capacity in the ORBES region, exclusive of pollution control costs, would be
substantially higher (35 percent higher) under the high electrical energy
growth case than they would be under the base case. Pollution control costs
would be similarly higher under the former case: sulfur dioxide pollution
control costs would be about 34 percent higher than under the base case, and
particulate emission control costs would be about 15 percent higher. These
higher pollution control costs are entirely the result of the increased
generating capacity under the high growth case. Thus, both the high
electrical energy growth case and the base case would result in pollution
control costs that are about 21 percent of the total cumulative costs for
achieving the installed capacity and the environmental regulations under both
196
-------
Figure 10-1
Base Case versus High Electrical Energy Growth Case (45-Year Plant Life)
11-
10-
10-1 a. Electric Utility Sulfur
Dioxide Emissions
2-
1"
HEG
High Electrical Energy Growth (HEG)
Base Case (BC)
1976 1980 1985 1990 1995 2000
10-1b. Sulfur Dioxide Emissions
and Control Costs
50-i
40-
30-
20-
5 10-
HEG
-BC
Increase over Base Case
Cumulative SO2 Control Costs
Increase over Base
Case SO2 Emissions in 2000
o>
i
975 C/kWh)
01
i
ic
ice of elect
u
i
ro
I
-*
I
10-1c. Electricity Prices
Priced 975 ip/kWh)
Year
BC
HEG
1976
1985
— Base Case (BC) 2000
---High Electrical Energy Growth (HEG)
2.58
3.87
4.64
2.58
3.80
5.53
1976
1980
1985
1990
1995
2000
197
-------
Figure 10-2
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
Base Case in 2000
High Growth Case (45-Year) in 2000
Figure 10-3
Annual Average Sulfate Concentrations, Electric Utility Contribution
High Growth Case (45-Year) in 2000
198
-------
scenarios. Moreover, the increase in sulfur dioxide pollution control costs
in comparison to the increase in sulfur dioxide emissions under the high
growth case suggests that such pollution control costs merely parallel
generating capacity (see figure 10-1b).
CONSUMER COSTS.. Since both the base case and the high electrical energy
growth case have the same installed generating capacity in 1985, the price of
electricity would be nearly the same in that year under both scenarios.
However, because of the growth in electricity demand that would occur after
1985 under the high growth case, electricity prices would be significantly
higher in 2000 (19 percent) under this case than under the base case in that
year (see figure 10-1c). This increase between 1985 and 2000 also is
reflected in the cumulative revenues collected from consumers between 1976 and
2000. Such revenues would be about 18 percent higher under the high growth
case than under the base case, or $617 billion under the former case and $525
billion under the latter.
10.1.1 Air-Related Variations
Two variations of the high electrical growth case also were examined in
the air quality analyses. One variation is identical to the high growth case
in all respects except that a 35-year generating unit lifetime is assumed.
This case, called the high-growth, 35-year case, is compared to the base case
and to the high electrical energy growth case. In the second variation,
generating units in the ORBES region are projected to come on-line, or to be
dispatched, in the order of least sulfur dioxide emissions, rather than least
cost, which is assumed in the high electrical energy growth case (and in all
other scenarios). Otherwise, this latter variation, called the least
emissions dispatch case, is identical to the high growth case and is compared
to that case.
BASE CASE yjRSUS HIGH GROWTH, 35-YEAR CASE. The high growth, 35-year case
would result in nearly the same emissions and concentrations as those that are
projected when a historic rate of growth in the demand for electricity is
assumed (the base case).
In 1985, utility sulfur dioxide, particulate, and nitrogen oxide
emissions under the high growth, 35-year case would be almost identical to the
emissions under the base case. In 2000, however, utility sulfur dioxide,
particulate, and nitrogen oxide emissions under the 35-year case would be 8.3,
10.5, and 23 percent higher, respectively, than those of the base case in that
year (see figure 10-4a for sulfur dioxide emission comparisons). In terms of
plant types, sulfur dioxide emissions from SIP-regulated plants would be
similar in 2000 under both the high growth, 35-year case and the base case.
This similarity would occur because the additional installed capacity under
the former case is subject to revised new source performance standards
(RNSPS), which are the strictest of all the standards. (RNSPS units would
199
-------
Figure 10-4
Base Case versus High Electrical Energy Growth Case (35-Year Plant Life)
10-4a
11-
10-
Electric Utility Sulfur Dioxide Emissions
1-
HEG
-Base Case (BC)
-High Electrical Energy Growth (HEG)
1976 1980 1985 1990 1995 2000
10-4b. Sulfur Dioxide Emissions
and Control Costs
60-
50-
40-
30-
20-
.
o> 0
CO
•5-10-
-20-
-30-
-40-
-50-
HEG
HEG
•BC
Increase over Base Case
Cumulative SO2 Control Costs
Increase over Base Case
SO2 Emissions in 2000
10
h-
O)
4-
.- 3-
o
0 2-
"o
0
g
a 1_
10-4c. Electricity Prices
/HEG
Price (1975
-------
provide about 67 percent of all coal-fired electrical generation in 2000 under
the 35-year case.) Nevertheless, since each SIP unit emits five to six times
more sulfur dioxide than a comparable RNSPS unit does, SIP emissions still
would comprise the bulk of total emissions under the high growth, 35-year
case, accounting for 2.9 million tons in 2000, or 62 percent of the 4.71
million tons emitted in that year.
Because utility sulfur dioxide emissions would be about the same in 1985
under both scenarios, utility-related annual and episodic sulfur dioxide and
sulfate concentrations also would be about the same. In 2000, however, since
emissions under the high growth, 35-year case would increase more between 1985
and 2000, utility-related annual and episodic concentrations would be somewhat
higher under the high growth, 35-year case than under the base case. For
example, annual utility-related sulfur dioxide and sulfate concentrations
would be 13 percent and 18 percent higher, respectively, under the 35-year
case in 2000 than they would be in the area of highest annual concentrations
under the base case (see figures 10-5 and 10-6). Episodic sulfur dioxide and
sulfate concentrations related to utility emissions would be 8 percent and 4.5
percent higher, respectively, under the high growth, 35-year case than they
would be in the area of highest episodic concentrations under the base case.
Exclusive of pollution control costs, the cumulative cost of new coal-
fired generating capacity through the year 2000 under the high growth, 35-year
case would be 49 percent higher than under the base case. Cumulative
pollution control costs would be 40 percent higher under the high growth, 35-
year case than under the base case; cumulative capital costs for sulfur
dioxide control would be 47.4 percent higher than such costs under the base
case, and TSP control costs would be 25 percent higher. Figure 10-4b
emphasizes the higher expenditures that would be necessary between 1976 and
2000 to keep sulfur dioxide emissions from being more than 8.3 percent higher
in 2000 than under the base case.
In 1985, the price of electricity would be nearly identical under both
the high growth, 35-year case and the base case (see figure 10-4c). In 2000,
however, electricity prices would be about 23 percent higher under the high
growth, 35-year case than under the base case. The cumulative revenues
required from consumers between 1976 and 2000 because of these electricity
prices would be 22 percent higher under the high growth, 35-year case than
under the base case.
35-YEAR VERSUS 45-YEAR. One suggestion for achieving further emission
reductions has concerned the reclassification of modified units. An estimate
of the emission reductions possible under such a change can be made by
comparing the emissions of the two high electrical energy growth cases—one
with 35-year units and one with 45-year units.
201
-------
Figure 10-5
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
Base Case in 2000
-High Growth Case (35-year) in 2000
2-5.9 6-9.9 10-13.99 14-17.99 18-24
Rgure10-6
Annual Average Sulfate Concentrations, Electric Utility Contribution
Base Case in 2000
"High Growth Case (35-year) in 2000
1-2.99 3-4.99 5-6.1
7-9
202
-------
Under both the 45-year plant lifetime case and the 35-year plant lifetime
case, sulfur dioxide emissions from all generating units (SIP, NSPS, and RNSPS
units) as well as those from SIP regulated units alone would be the same in
1985. In 2000, however, sulfur dioxide emissions from SIP-regulated units
would total 4.32 million tons under the 45-year plant lifetime case; this
amount is 49 percent higher than the 2.9 million tons emitted under the 35-
year plant lifetime case. Sulfur dioxide emissions from all generating units
(SIP, NSPS, and RNSPS) would total 6.06 million tons in 2000 under the 45-year
plant lifetime case, or 29 percent higher than the 4.71 million tons emitted
under the 35-year plant lifetime case (see figure 10-7). Thus, under high
growth conditions, the retirement of SIP units could make a substantial
difference in sulfur dioxide emission levels.
Similarly, utility particulate and nitrogen oxide emissions would be
about the same in 1985 under both the 45-year plant lifetime case and the 35-
year plant lifetime case. By 2000, however, under the 45-year case, utility
particulate emissions would be about 24 percent higher than the emissions
under the 35-year case, and utility nitrogen oxide emissions would be about 7
percent higher than under the 35-year case. Thus, again, under high
electrical energy growth conditions, earlier retirements would have a positive
impact on emission levels.
Early retirement also would result in significantly reduced utility-
related sulfur dioxide and sulfate concentrations in the year 2000. In the
area that would experience the highest sulfur dioxide concentrations under the
45-year case, episodic sulfur dioxide concentrations would be 21 percent lower
and annual sulfur dioxide concentrations would be 42 percent lower in the year
2000. Similarly, episodic and annual sulfate concentrations under the 35-year
case in 2000 in the same area would be 37 percent and 31 percent lower,
respectively, than those under the 45-year case.
Because the 45-year lifetime assumption would permit the longer use of
units and thus would result in fewer new units being built, the costs to both
the utilities and to the consumer would be lower under the 45-year lifetime
case than under the 35-year lifetime case. For the utilities, cumulative
capital costs for new coal-fired generating capacity through the year 2000,
exclusive of pollution control costs, would be about 10 percent lower under
the 45-year lifetime assumption than under the 35-year lifetime assumption;
cumulative pollution control costs would be 9 percent lower. In particular,
cumulative capital costs for the control of sulfur dioxide emissions would be
9.3 percent lower under the 45-year case than under the 35-year case; the TSP
control costs would be 8.2 percent lower under the former case than under the
latter.
Costs to the consumer also would be lower under the 45-year unit lifetime
case, although costs would not decrease as much for the consumers as they
would for the utilities. In fact, the price of electricity would be the same
203
-------
Figure 10-7
Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
High Electrical Energy Growth Case
CO
c
o
•4—•
C
o
CO
c
o
E
CD
CM
O
to
10
7-
6-
5-
3-
2-
1-
\
\
H EG ,45-year
H EG, 35-year
High Electrical Energy Growth, 45-year unit lifetime
High Electrical Energy Growth, 35-year unit lifetime
1976
1980
1985
1990
1995
2000
for both cases in 1985. In 2000, electricity prices would be about 3 percent
lower under the 45-year case than under the 35-year case. The cumulative
revenues required from the consumer between 1976 and 2000 also would be lower
(3.4 percent lower) under the former case than under the latter.
Overall, the 45-year generating unit lifetime assumption produces
substantially higher utility sulfur dioxide and particulate emissions, lower
cumulative capital costs for generating capacity and pollution abatement, and
only slightly lower electricity prices. These tradeoffs are in contrast to
those that would occur with a shorter plant lifetime: substantially lower
emissions, higher utility costs, and only slightly higher electricity prices.
LEAST COST VERSUS LEAST EMISSIONS DISPATCH. However, there are ways to reduce
sulfur dioxide emissions under high electrical energy growth while retaining
204
-------
the feature of longer plant lifetimes. For example, units with 45-year
lifetimes could be dispatched according to the least amount of sulfur dioxide
emissions rather than according to least cost. If such a dispatching order
was implemented, utility sulfur dioxide, particulate, and nitrogen oxide
emissions and utility-related regional sulfur dioxide and sulfate
concentrations would be lower than under least cost dispatch.
In general, utility sulfur dioxide emissions in the ORBES region would be
significantly lower in 1985 and substantially lower in 2000 under the least
emissions dispatch case than they would be under the least cost dispatch case.
Sulfur dioxide emissions from SIP-regulated generating units in the ORBES
region would be 24 percent and 65-3 percent lower in 1985 and 2000,
respectively, under least emissions dispatch than they would be under least
cost dispatch in the same years. Sulfur dioxide emissions from all generating
units (SIP, NSPS, and RNSPS) in the ORBES region would be about 21 percent and
45 percent lower in 1985 and 2000, respectively, under least emissions
dispatch than they would be under least cost dispatch in the same years (see
figure 10-8a).
Utility particulate emissions would be about the same in 1985 under both
assumptions (only 4 percent lower under least emissions dispatch). In 2000,
however, utility particulate emissions would be significantly lower (19.2
percent) under the least emissions dispatch case than under the least cost
dispatch case.
Nitrogen oxide emissions would be 5 percent lower in 1985 and 8.4 percent
lower in 2000 under the least emissions dispatch case than they would be under
the least cost dispatch case. The reason for this difference involves the
assumption of nitrogen oxide standards for NSPS and RNSPS units in contrast to
the absence of such standards for SIP units. Since NSPS and RNSPS units would
be in service more of the time under least emissions dispatching, the least
emissions dispatch case would lead to slightly lower nitrogen oxide emissions
than the least cost dispatch case, in which SIP units are in service more of
the time.
Annual regional sulfur dioxide and sulfate concentrations due to utility
sulfur dioxide emissions would be significantly lower under the least
emissions dispatch case than they would be under the least cost dispatch case.
In 1985, in the area of highest concentrations, annual regional sulfur dioxide
and sulfate concentrations due to utility sulfur dioxide emissions would be
about 12 percent lower under least emissions dispatch than the concentrations
projected under least cost dispatch. In 2000, annual regional sulfur dioxide
and sulfate concentrations due to utility sulfur dioxide emissions would be
about 42 and 31 percent lower, respectively, under least emissions dispatch
than the concentrations projected under least cost dispatch (see figures 10-9
and 10-10). Episodic concentrations in the same area in the year 2000 also
205
-------
00
o
SH
en
ro
o
in
price of electricity (1975 dVkWh)
I- I-
CD CD
D) 0)
S3- J2.
O m
o =?
co E.
** CO
O w
co' §
^j CO
o O
?. w
3 X3
(Q W.
SI
D CO
3 C
Q. =S
21
(Q
2!
O
Ii
Q) m
CD i.
i»
§1
m n
II
m,2
-------
Figure 10-9
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
Least Cost Dispatching in 2000
-Least Emissions' Dispatching in 2000
2-5.9 6-9.9 10-13.99 14-17.99 18-24
Rgure 10-10
Annual Average Sulfate Concentrations, Electric Utility Contribution
Least Cost Dispatching in 2000
Least Emissions Dispatching in 2000
207
-------
would be lower under least emissions dispatching: episodic sulfur dioxide
concentrations would be 51 percent lower, and episodic sulfate concentrations,
36 percent lower.
Since the same generating systems would be operated under both
dispatching options, the cumulative capital costs of new coal-fired generating
units and of pollution control devices would be the same. Thus, for the same
cumulative sulfur dioxide pollution control costs, a 45 percent reduction in
emissions could be achieved by 2000 if least emissions dispatching were used
(see figure 10-8b). The major differences in costs between the two cases
would be due to the increased operation and maintenance of pollution control
devices required under least emissions dispatching and the increased fuel
costs encountered under this case. These differences are reflected in
electricity prices and revenues from consumers, although consumer costs would
be only slightly higher under least emissions dispatching. For example, the
price of electricity in 1985 would be 3.86 cents per kilowatt hour under least
emissions dispatching and 3.8 cents under least cost dispatching. In 2000,
electricity prices under the former case would be 5.6 cents per kilowatt hour
and 5.53 cents under the latter case (see figure 10-8c). Thus, the cumulative
revenues required from consumers between 1976 and 2000 would be only 1.5
percent higher under the least emissions dispatch case than they would be
under the least cost dispatch case.
10.2 Land
The high electrical energy growth case with a 45-year generating lifetime
would result in the greatest land use conversion and would have the highest
terrestrial ecosystem unit assessment of any scenario analyzed. Similarly,
substantially more area would be affected by utility-related sulfur dioxide
concentrations of 130 micrograms per cubic meter than would be affected under
the base case. As a result, it is estimated that agricultural losses due to
regional utility sulfur dioxide emissions would be significantly higher than
the losses projected under the base case. Agricultural losses due to oxidants
formed from regional nitrogen oxide emissions also are projected to be higher
under the high growth case.
LAND USE. Under the high electrical energy growth case, land converted for
all energy uses (new generating facilities, new transmission line rights-of-
way, and new surface mining for utility coal) in the ORBES region would total
approximately 1.1 million acres by 2000. This acreage is 12 percent higher
than under the base case and represents 1 percent of the total land in the
region. Although the percentage of regional acreage affected by such
conversion is quite small, the percentage of county acreage affected could be
significant.
Among the ORBES scenarios, the greatest land conversion for electrical
generating facilities also would occur under the high electrical energy growth
208
-------
case (29 percent higher than under the base case). In terms of the ORBES
state portions, the West Virginia portion would experience the largest
increase in land use (61 percent) over the amount required under the base case
since 11 more generating units are sited in that state portion than are sited
under the base case. The percentage increases over the base case of the five
other ORBES state portions would range from 8 percent in Pennsylvania to 42
percent in Ohio.
In terms of the land types converted to install the high growth energy
capacity, substantially more forest land (32 percent more) and agricultural
land (25 percent more) would be converted under the higher electrical energy
growth case than under the base case. Similarly, 31 percent more public land
and 42 percent more other types of land would be converted than under the base
case.
Under high electrical energy growth, substantially more land would be
affected than under the base case by utility-related sulfur dioxide
concentrations of 130 micrograms per cubic meter. Although nearly the same
amount of land would be affected in 1985 under both the high growth case and
the base case, 49 percent more land would be affected in 2000 under the former
case than under the latter. Thus, while the acreage affected by such
concentrations under the base case in 2000 would represent 3.1 percent of the
ORBES region, such concentrations would affect 4.5 percent of the region in
2000 under the high electrical energy growth case.
PHYSICAL CROP LOSSES. Regional agricultural losses due to such sulfur dioxide
concentrations in the presence of moderate ozone levels are estimated to be
higher under the high electrical energy growth case than the losses projected
under the base case. In the year 2000, the regional losses under the high
growth case would range from a minimum of 289,000 bushels to a maximum of 2
million bushels, with 1 million bushels representing the probable loss. Under
the base case, the range in 2000 would be from 248,000 bushels to 1.7 million
bushels.
As under the base case, agricultural losses under the high growth case
would represent less than 1 percent of the regional clean air yield. However,
on a local scale, such as the county, losses could be significant, and losses
to individual farmers substantial. For example, as under the base case, the
ORBES state portion of Illinois would account for most of the regional crop
losses—from 59 to 74 percent in 2000, depending on the crop—and the state
portions of Illinois, Indiana, and Ohio would account for 95 percent of all
losses.
Regional agricultural losses due to ozone formed from regional nitrogen
oxide emissions in combination with other pollutants would be higher under the
high growth case in the year 2000 than under the base case in that year. As
209
-------
will be recalled, nitrogen oxide emissions from transportation are projected
to decline after 1985 while nitrogen oxide emissions from the electric utility
sector are projected to increase. Under the high growth case, these utility
emissions would increase even more than they would under the base case. As a
result, high growth utility emissions would exceed the decreases in
transportation emissions. Thus, more nitrogen oxide emissions would exist for
ozone formation under the high growth case than under the base case.
Correspondingly, agricultural losses due to such ozone formation would
increase.
Under the high electrical energy growth case, oxidant-related
agricultural losses in 2000 would range from a minimum of 370 million bushels
to a maximum of 705 million bushels, with 468 million bushels representing the
probable losses. These probable loss projections are approximately 173
percent higher than the probable losses projected to occur under the base case
in 2000.
MONETARY CROP LOSSES. Between 1976 and 2000 under the high electrical energy
growth case, cumulative probable agricultural dollar losses attributable to
regional utility sulfur dioxide emissions and to oxidants formed from regional
nitrogen oxide emissions would be about 20 percent higher than such losses
under the base case. The distribution of dollar losses among crops and the
ORBES state portions would be almost identical under both the high electrical
energy growth case and the base case.
TERRESTRIAL ECOSYSTEMS. The high electrical energy growth case would result
in the highest number of regionwide terrestrial ecosystem units between 1976
and 2000 of all the scenarios. The unit total under high growth would be 33
percent higher than the unit total under the base case between those years.
All the ORBES state portions would have more terrestrial ecosystem units
assessed under the high electrical growth case than under the base case. The
increase in unit totals would range from about 18 percent in the ORBES portion
of Indiana to 60 percent in the ORBES portion of West Virginia.
FOREST LOSSES. Forest losses also are projected to be higher in the year 2000
under the high growth case. Under this case, the estimated annual reduction
in forest growth by 2000 due to air pollutants, principally ozone, would be
from 2.1 to 9.3 percent of the total production. In 2000 under the base case,
the reduction in forest growth would range from 0.4 to 1.9 percent of the
total production.
10.3 Water
Under the high electrical energy growth case with a 45-year generating
unit lifetime, 144 coal-fired units—each 650 megawatts electric—are sited;
142 ultimately would affect the Ohio River main stem, while 2 are on the
Susquehanna. However, again, as under the base case, the majority of the
210
-------
impacts would be due to high background concentrations either alone or in
conjunction with municipal and industrial consumption. Since so many units
are sited under the high growth case, some are sited on the region's smaller
streams. As discussed previously, these streams generally are not suitable
for the siting of even 650 megawatt plants because of their high background
concentrations and their low flow per second under 7-day-10-year low flow
conditions. As a result, more streams would be affected by power plant
consumption under the high growth case than under any other scenario.
For a majority of the streams, however, aquatic habitat impacts under the
high electrical growth case and 7-day-10-day low flow would be about the same
as they would be under the base case and such low flow conditions (see table
10-1). For three streams, however, aquatic habitat impacts under the high
electrical growth case would be severer than they would be under base case
conditions.
The streams that would be affected by high background concentrations in
conjunction with power plant consumption under the base case—the Allegheny,
the Big Muddy, and the Illinois—also would be affected because of high
background concentrations in conjunction with power plant consumption under
the high growth case. Three additional rivers—the Big Sandy, the Great
Miami, and the Little Miami—also would be affected by such concentrations and
consumption under the high growth case. These three rivers, all of which
would undergo heavy aquatic habitat impacts under base case conditions, would
undergo drastic impacts under the high electrical growth case, in which two or
more standard generating units are sited on each river.
Under high growth, six additional streams would experience incremental
increases in their base case water quality index values because of additional
installed capacity. However, these six rivers—the Beaver, the Kanawha, the
Monongahela, the Muskingum, the Wabash, and the White—would have the same
protection levels and aquatic habitat impacts as under the base case.
Moreover, high background levels in conjunction with municipal and industrial
consumption would cause the majority of these rivers' problems under both
scenarios. Thus, for example, when one more unit is sited on the Beaver under
the high growth case, the water quality index value changes from 35 under the
base case to 40 under the high growth case (see table 10-1). This change
indicates that a few more water quality parameters would be violated with this
additional siting. However, such violations would not be significant enough
to cause changes in the aquatic habitat impacts, although additional stress
might be -experienced on this river.
To alleviate the impacts related to power plants projected under the high
electrical energy growth case would require some of the same tradeoffs
discussed in chapter 6. Alternative siting of the units could make a
substantial difference on such small rivers as the Little Miami and could
alleviate the stress on such rivers as the Allegheny. However, since such a
211
-------
Aquatic Habitat
Energy Growth
Table 10-1
Impacts, Base Case versus High Electrical
Case, 7-Day-1 0-Year Low Flow, Year 2000
Better (+)
Worse (-)
Same (0)
As Base Case
River Habitat Impacts
Water Quality
Impact Index Change in
(range: Base Case
0 to 1 00) Protection
if changed Levels
Change in Number of
Base Case Units Added or
Habitat Removed from
Impacts Base Case
Allegheny 0
Beaver 0
40
+ 1
Big Muddy 0
Big Sandy —
70 D
Drastic + 2
Cumberland 0
Great Miami —
58 D
Drastic + 4
Green 0
Illinois 0
Kanawha 0
35
+ 1
+ 4
Kaskaskia 0
Kentucky —
*
- +5
Licking 0
Little Miami —
65 D
Drastic + 2
Mississippi 0
Monongahela 0
Muskingum 0
Ohio Main Stem 0
Rock —
Salt —
36
41
*
*
+ 1
+ 2
+ 14
—
—
Scioto 0
Susquehanna —
Wabash 0
White 0
Whitewater —
_ *
26
32
*
- + 1
+ 2
+ 3
- +2
*Background data unavailable; analysis could not be completed.
212
-------
large generating capacity is projected under the high growth case, suitable
alternative sites are more limited under this case than under the other
scenarios. In general, alternative siting under this case probably would
result in a high concentration of units along the Ohio main stem. This
concentration would in turn exacerbate the air quality problems that already
exist in that area.
10.4 Employment
A high electrical energy growth rate along with a 45-year generating unit
lifetime would result in a vigorous rise in the employment of power plant
construction workers in the ORBES region. However,'the very large increase in
power plant construction over a short period of time could induce critical
construction labor shortages. In contrast, no regional shortages would be
expected under base case conditions.
Between 1975 and 1995 under the high electrical energy growth case, the
total demand for power plant construction and operation workers—as measured
by person-years—would be about 32 percent higher than the demand projected
under the base case. Between 1983 and 1985, there would be a 60 percent rise
in employment demand under high electrical energy growth. This dramatic rise
would not occur under the base case.
To construct the power plants projected under high electrical energy
growth, substantially more boilermakers and slightly more electricians and
pipefitters would be required than probably could be supplied. The resulting
shortages could cause construction delays, in-migration of labor from other
regions, and/or labor shortages in other industries. Under the base case, no
such shortages would be expected. In fact, in 1990, the peak construction
year, the demand for such specialized labor would be from 67 to 73 percent
higher under the high growth case than the demand under the base case in 1990,
depending on the skill involved.
10.5 Health
Since coal-fired capacity would be the same in 1985 under both the base
case and the high electrical energy growth case, the health impacts of the
coal-mining and coal-processing sectors would be the same in that year under
both cases. However, because coal-fired capacity under high growth would be
significantly greater by 2000 than the capacity under the base case in that
year, so would the health impacts related to supplying coal to this increased
capacity. Accidental and disease-related deaths and injuries in the coal-
mining and coal-processing sectors would be about 18.2 percent higher by the
year 2000 than such deaths and injuries under the base case in that year.
213
-------
Because air pollutant emissions would increase significantly between 1985
and 2000 under the high electrical energy growth case, more cumulative deaths
are projected to occur between 1975 and 2000 from sulfate and particulate air
pollution by ORBES-region electrical generating facilities. Under the high
growth case, the cumulative deaths associated with sulfate air pollution are
projected to be 13 percent higher. The yearly deaths associated with sulfate
air pollution would be only 3 percent higher in 1985 under the high growth
case than under the base case. In 2000, however, yearly deaths would be 46
percent higher under the former case than under the latter. The cumulative
deaths associated with particulates between 1975 and 2000 are projected to be
H6 percent higher under the high growth case than under the base case.
214
-------
11. Impacts of frhe Electrical Exports Case,
In this chapter, the impacts of the electrical exports case are compared
with base case impacts in all five impact areas (air, land, water, employment,
and health).
The electrical exports case has many of the same assumptions as the base
case. For example, the same environmental controls are assumed. The primary
difference between the two scenarios lies in the assumed electricity demand
growth rate. The higher rate under the electrical exports case (an average
annual rate of 3-2 percent, compared with 3-13 percent under the base case)
results from the assumption that there will be a major increase in the amount
of electricity exported from the ORBES region. Because of the expanded coal-
fired electrical generating capacity under the exports case, other fuel use
characteristics also are different from those under the base case. See
chapter 5 for details.
11.1 Air
Because more coal-fired units would be sited in the ORBES region between
1985 and 2000 under the electrical exports case than under the base case,
regional utility sulfur dioxide, particulate, and nitrogen oxide emissions
would be higher in 2000 under the exports case than they would be under the
base case.1 However, the increase would be small because it is assumed that
all exported power will be supplied by units governed by the revised new
source performance standards (RNSPS), which are the strictest of the three
standards- (state implementation plans (SIPs), new source performance standards
(NSPS), and RNSPS). Thus, in the year 2000 utility sulfur dioxide emissions
from all generating units in the ORBES region would be only 4.6 percent higher
under the exports case than under the base case, and utility particulate
emissions would be about 5.3 percent higher under the former case than under
the latter in that year. Finally, utility nitrogen oxide emissions in 2000
would be about 11 percent higher under the exports case than under the base
case.
For calculations of emissions, pollution control costs, and capital
costs under the electrical exports case, see Teknekron Research, Inc., The
Calculation Q£ Several Measures for ORBES Scenarios 2a, £, and & (RM-032-EPA-
80, June 1980).
215
-------
With the increased export of coal-fired electricity from the region,
cumulative pollution control costs through the year 2000 would be about 15
percent higher than they would be under the base case. The costs of
controlling utility sulfur dioxide emissions would be about 18 percent higher,
and the costs of controlling utility particulate emissions would be about 9.5
percent higher. Cumulative capital costs of installing the coal-fired
generating capacity under the electrical exports case would be about 22
percent higher than the costs of installing base case coal-fired capacity,
exclusive of pollution control costs. However, the ratio of pollution control
costs to the total costs of installing new capacity and pollution control
devices would be nearly identical for both scenarios. Thus, the rise in
pollution control costs under the exports case would result entirely from the
larger installed capacity.
11.2 Land
IJnder the electrical exports case,'regionwide land use requirements for
electrical generating facilities and for surface mining would be significantly
higher than base case requirements. More terrestrial ecosystem units likewise
would be assessed under the former case than under the latter.
The electrical exports case would require 17 percent more land for
electrical generating facilities between 1976 and 2000 than would the base
case. Most of this increase would occur in the ORBES state portions of Ohio,
Pennsylvania, and West Virginia—the ORBES states closest to the northeastern
United States, the destination of the exported electricity. The increase in
land use requirements for generating units within these state portions would
be greatest in West Virginia (65 percent), followed by Ohio (45 percent) and
Pennsylvania (20 percent).
In terms of the types of lands converted under the electrical exports
case for electrical generating facilities, 29 percent more public lands would
be converted between 1976 and 2000 than would be converted under the base
case. Increases ,also would occur in the conversion of other types of land:
27 percent more forest land, 9 percent more agricultural land, and 21 percent
more other types of land.
The electrical exports case also would result in an increase in surface
mining for utility coal; more acres in the ORBES region (8 percent) would be
affected by such surface mining in 2000 under the exports case than under the
base case. The ORBES state portion of Ohio would have the most acreage
2
See the corresponding sections of chapter 7 for references to the ORBES
reports consulted for this section and the following ones.
216
-------
affected by this increased surface mining for utility coal (28 percent of the
total acres affected under the exports case); the state portion of Illinois,
the least (7 percent). The surface mining of coal for all purposes within the
ORBES region would be about 6 percent higher between 1976 and 2000 under the
electrical exports case than under the base case.
Seventeen percent more terrestrial ecosystem units -would be assessed
under the electrical exports case than under the base case. The unit
assessment would be highest in the ORBES state portions of Ohio (42 percent
higher than the base case assessment), Pennsylvania (22 percent higher), and
West Virginia (65 percent higher), where most of the additional facilities are
sited to reduce transmission losses.
Under the electrical exports case, aquatic habitat impacts under 7-day-
10-year low flow conditions would not be different from the impacts under the
base case and these conditions for any of the rivers selected for detailed
analysis (see table 11-1). Thus, as may be recalled from the discussion of
impacts under the base case (see section 7.3), aquatic habitat impacts under
the exports case would occur primarily because of high background
concentrations either alone or in conjunction with municipal and industrial
consumption; power plant consumption would have a minor impact on most
streams. Only the Allegheny and the Big Muddy rivers would experience impacts
attributable to high background levels in conjunction with power plant water
consumption under the exports case—as they would under the base case. Two
other rivers—the Muskingum and the Scioto—would register incremental
increases in their water quality indices, suggesting that additional
violations of parameters would occur because of the additional installed
capacity. However, these violations would not be significant enough to cause
a change in aquatic habitat impacts, although additional stress could be
experienced by both rivers, which already were projected to experience heavy
impacts under the base case.
A variation of this scenario also was developed to explore the potential
water quality impacts that would occur if once-through cooling, rather than
cooling towers, was used for the 82 units sited on the main stem of the Ohio
River under the electrical exports case. Other than this change, the once-
through cooling variation has the same energy and fuel use characteristics as
the exports case with cooling towers.
If once-through cooling were to be used for the 82 coal-fired, 650
megawatt electric units added by the electrical exports case on the Ohio River
main stem, water withdrawal would increase drastically. This increase could
have a devastating entrainment-impingement impact on the main stem at 7-day-
217
-------
Table 11-1
Aquatic Habitat Impacts, Base Case versus Electrical
Exports Case, 7-Day-1 0-Year Low Flow, Year 2000
Better (+) Water Quality
Worse (-) Impact Index Change in
Same (0) (range: Base Case
As Base Case 0 to 1 00) Protection
River Habitat Impacts if changed Levels
Allegheny
Beaver
Big Muddy
Big Sandy
Cumberland
Great Miami
Green
Illinois
Kanawha
Kaskaskia
Kentucky
Licking
Little Miami
Mississippi
Monongahela
Muskingum
Ohio Main Stem
Rock
Salt
Scioto
Susquehanna
Wabash
White
Whitewater
0 34
0
0
0
0
0
0
0
0
0
*
0
0
0
0
0 41
0
*
*
0 40
*
0
0
*
Change in Number of
Base Case Units Added or
Habitat Removed from
Impacts Base Case
+ 4
+ 1
—
+ 2
+22
—
—
+ 2
—
—
*Background data unavailable; analysis could not be completed.
218
-------
10-year low flow. Temperature impacts under once-through cooling would be
damaging locally, especially to sensitive bank habitats, although once-through
cooling would not affect the total river temperature. Such local temperature
impacts would be nonexistent under the electrical exports case with cooling
towers. Finally, a dissolved oxygen sag would be observed along the first 50
miles of the main stem with the use of once-through cooling; levels would
return to seasonal norms below that point.
11.4 Employment
Employment would increase under the scenario in which electricity is
exported from the ORBES region to the middle Atlantic states. Such export of
power would require the concentrated construction of a large number of power
plants in the eastern portion of the ORBES region over a short period of time.
As a result, the demand for construction workers would be dramatically higher
than the demand under base case conditions. Dramatic increases also would be
expected in coal-mining employment.
Between 1975 and 1995 under the electrical exports case, about 20 percent
more person-years would be required for power plant construction and operation
than would be required under the base case. Between 1983 and 1985 in
particular, there would be a precipitous rise, over 60 percent, in the number
of workers needed for power plant construction under the exports case. In
1990, about 45 percent more workers in each of the three critical skill
categories examined would be needed than under the base case in that year.
The intensity of this demand would last until 1994, the peak construction year
under the electrical exports case.
To meet the increased need for coal under the electrical exports case,
annual coal production for all purposes would be about 10 percent higher by
the year 2000 than the levels projected for the base case in that year.
Electrical generating units also would be consuming 14 percent more coal under
the exports case in 2000 than under the base case in that year.
Given these increases in coal production and in electric power coal
consumption under the exports case, coal-mining employment in the ORBES region
for all purposes would increase between 42 and 270 percent from 1970 to 2000,
compared with between 35 and 222 percent under the base case. At least 47 of
the 152 coal-producing counties in the region would experience mining
employment growth rates between 50 and 199 percent. Also, an additional 88
counties might experience rates over 200 percent and, thus, boom-town effects.
In comparison, under the base case at least 55 counties would experience rates
between 50 and 199 percent, and 79 would experience rates greater than 200
percent.
219
-------
11.5 Health
The number of deaths and injuries related to coal mining and coal
processing would be about 15 percent greater by 2000 under the electrical
exports case than under the base case in that year. Due to the fact that the
same electrical generating capacity is assumed for both scenarios in 1985, the
number of such deaths and injuries would be the same under both scenarios in
that year.
220
-------
12. Mitigation Strategies
The five energy-environmental futures, or scenarios, discussed in
previous chapters are based on the central assumption that, through the year
2000, coal will continue to be the dominant fuel for the generation of
electricity in the Ohio River Basin Energy Study (ORBES) region. The
scenarios whose impacts are set forth and contrasted assume, respectively:
(1) base case conditions, (2) stricter environmental controls, (3)
noncompliance with state implementation plans (SIPs), (4) high electrical
energy growth, and (5) a significant increase in the export of electricity
from the region.
The analysis of the coal-dominated futures reveals that, among all the
impacts identified, those on air quality would be affected the most by the
various scenario policies examined. The analysis shows that certain economic
and health effects are associated with the air quality impacts. The health
impacts are related to air pollutant concentrations, while the economic
impacts are associated with the cost of air pollution control and the dollar
losses associated with decreases in agricultural yields due to air pollution.
Impacts on water quality due to coal-fired electrical generating facilities
would be relatively insignificant on a regional basis. However, a number of
severe impacts might occur because of water consumption by industries and
municipalities under 7-day-10-year low flow conditions and current pollutant
levels. Impacts on land use and on employment would be relatively minor,
although in some areas coal-mining employment might increase significantly.
Since institutional mechanisms exist to handle impacts in all areas but
those related to air quality, the major purpose of this chapter is to offer
examples of strategies that might be utilized to mitigate impacts on air
quality at the interstate-regional level. It should be emphasized that under
all the ORBES scenarios—including the SIP noncompliance case and the high
electrical energy growth case—overall regional emission levels of both sulfur
dioxide and particulates would be lower in the year 2000 than in 1976.
Emissions of oxides of nitrogen, however, would be higher under all the
scenarios.
Despite the emission reductions projected in the ORBES scenarios at the
regional level, pollutant concentrations still would be a problem at local
"hot spots." Moreover, episodic conditions still would lead to high
concentrations both within and beyond the study region. The reason for this
continuing problem lies in local and long-range transboundary air pollution
221
-------
transport. Thus, this chapter focuses on a variety of strategies to mitigate
these negative impacts.
12.1 Coal Impact Mitigation
Strategies to mitigate air quality impacts are numerous and can be
classified in many different ways. The approach taken here groups mitigation
strategies into two categories, technical and techno-organizational. The
first category, technical strategies, includes methods that can be applied at
a single generating unit. The second category, techno-organizational
strategies, acknowledges the importance of technology but stresses that the
technology is applied within a broader organizational context. '
Although this study emphasizes impacts and strategies in the ORBES
region, it is quite possible that extraregional impacts could be more
significant than either local or regional conditions in determining future air
quality mitigation strategies. Even though the ORBES region is critical for
the production of electricity, it also. is part of a broader natural region
that ranges eastward from the Mississippi River to the Atlantic coast and
encompasses nearly half of the nation's land area. In this broader area,
other sections besides the ORBES region also are important for the generation
of electricity and for overall air quality. For example, it is difficult to
consider air quality strategies for the ORBES region independent of the area
served by the Tennessee Valley Authority (TVA), especially since the ORBES
region overlaps the TVA service area in portions of Kentucky. More important,
perhaps, is the fact that air masses from the two regions mix and often move
toward the northeastern United States and southwestern Canada. This
transboundary air pollution transport could be the impetus for the development
of joint strategies to mitigate negative impacts.
12.1.1 Technical Strategies
A number of technical strategies to mitigate negative impacts on air
quality are assumed in the ORBES scenarios. Traditionally, such strategies
are applied on a plant-by-plant basis, with little or no attempt at
coordination.
SCRUBBERS. An obvious example of a technical strategy is the use of flue gas
desulfurization systems, or scrubbers, on coal-fired generating facilities.
This option could be very effective for the ORBES region, as shown in the
scenario analysis.
See Boyd R. Keenan, Ohio Basin Interstate Energy Options: Constraints
of Federalism (ORBES Phase II), for discussions of both technical and techno-
organizational strategies.
222
-------
RECLASSIFICATION. Another technical strategy centers around boiler
maintenance programs, which are a vital part of utility operations. Many of
these programs cause an existing installation to be upgraded to such an extent
that they are comparable to new installations in a number of respects. It has
been suggested that certain extensive maintenance activities, such as the
successive replacement of boiler tubes, should result in the reclassification
of a unit from an existing source of pollution to a new source (Clean Air Act,
sec. 111). This suggestion is made because existing boilers operate under
less stringent emission regulations. Since the less stringent emission
regulations also are less costly to implement, often it is attractive to the
utility to operate large existing installations as long as possible. The
effect of this prolonged plant life is evaluated in chapter 10 in reference to
high electrical energy growth conditions.
If extensive modifications were to result in the reclassification of an
installation from an existing to a new source, then economic decisions
regarding the useful lifetime of a plant would have to be made very early in
that plant's period of operation. In some cases, existing plants might be
retired early and replaced by new ones.
12.1.2 Techno-Organizational Strategies
The technical mitigation strategies reviewed above usually are applied on
a plant-by-plant basis. The term techno-organizational is used here to
describe broader strategies that already are available or that could be
developed on an interstate, multistate, or regional scale.
Transboundary air pollution transport can be separated into two basic
types. These are (1) local transboundary air pollution transport, where air
masses move over relatively short distances across state lines and the
contributions from individual plant sources usually can be identified, and (2)
long-range transboundary air pollution transport, where air masses travel
longer distances (often across several state lines) and the contributions from
individual sources are difficult to isolate. Often it is unclear which of the
two types is involved: at power plant sites, as elsewhere, the meteorology
changes from hour to hour. Wind, temperature, rain, and topography all
contribute to changes. In general, emissions cannot be identified as being
from a particular plant more than about 30 miles (50 kilometers) away.
Occasionally, however, the meteorology is such that emissions can be traced to
a particular plant at considerably longer distances.
12.1.2.1 Local Transboundary Air Pollution
Because the sources of local transboundary pollution can be identified,
it was possible to include provisions in the Clean Air Act that attempt to
make a state responsible for pollution that originates within its borders but
223
-------
is transported short distances into other states (sees. 110, 126, and 160).
These provisions constitute a legal framework that can help remedy disputes
that arise from local transboundary pollution.
SECTION 126. Basic in such disputes is section 126, "Interstate Pollution
Abatement," which specifies the procedures for a state or its political
subdivisions to seek action from the U.S. Environmental Protection Agency
against operators of sources in other states. In at least three cases, ORBES
state officials have filed formal petitions against neighboring states with
the EPA administrator; it is believed these petitions represent the only
formal efforts in the entire country to utilize the petitioning provision of
section 126.
The first petition was filed by the state of Kentucky. In July 1979, EPA
hearings were held to pursue the state's claim that sulfur dioxide emissions
from an Indiana plant are affecting Kentucky's efforts to comply with air
quality standards in the area immediately across the Ohio River from Madison,
Indiana. The facility in question is the Clifty Creek plant, operated by the
Indiana-Kentucky Electric Corporation, a consortium of investor-owned
companies. EPA now is in the process of considering the Kentucky petition.
The second instance where the interstate petition procedure of section
126 has been utilized also involves a claim by a Kentucky unit of government
against a source in Indiana. In December 1979, the Jefferson County Air
Pollution Control District in Louisville petitioned EPA. This petition argues
that the Gallagher power plant, operated in southern Indiana by Public Service
Indiana, is frustrating Kentucky's efforts to maintain air quality standards
and to assure industrial growth in that state. At issue are the extremely
different air quality standards in effect in Jefferson County, Kentucky, and
Floyd County, Indiana. Although the two counties are separated only by the
Ohio River, standards for Jefferson County are considerably stricter than
those for Floyd County.
Hearings on the Gallagher situation were held by EPA in April 1980; an
announcement of the findings is expected soon. The problem may be linked to
that of Clifty Creek, which is located only 40 miles away. That is, it may be
necessary to determine the contribution of emissions from Clifty Creek to air
quality degradation in the vicinity of Gallagher.
The final known instance of a state's seeking remedy under the petition
provision of section 126 is an action taken in 1978 by West Virginia against a
plant in Ohio. That facility, the W.H. Sammis plant, is operated by the Ohio
Edison Company at Stratton, Ohio, across the Ohio River from New Manchester,
in the northern "panhandle" of West Virginia. The action on the Sammis plant
is believed to be the first in the nation filed under section 126. As with
the two other petitions noted above, no final resolution has been reported.
224
-------
In addition to allowing action against existing sources, section 126 of
the Clean Air Act also prohibits a state from approving construction of new
facilities whose emissions would prevent another state from attaining or
maintaining national ambient air quality standards. Similar petitioning and
public hearing procedures as for existing sources are provided. For both
kinds of actions, of course, states have the final recourse of judicial
review.
PATRIOT. Despite the framework for addressing local transboundary pollution
transport questions provided by the Clean Air Act, protracted legal conflicts
between ORBES states have taken place. One of the most illustrative in
revealing the complexity of local transboundary pollutant transport took place
in the late 1970s; it concerned the siting of a proposed electrical generating
facility on the Indiana side of the Ohio River.
The case began with the announcement by the Indianapolis Power and Light
Company (IPL) of its intention to build three 650 megawatt electric units on
an 884-acre site in southeast Indiana. Located southwest of Cincinnati, about
50 miles downstream on the Ohio, the site is near the Indiana town of Patriot
in Switzerland County. Across the river is Boone County, Kentucky, where two
Ohio-based utilities, the Cincinnati Gas and Electric Company and the Dayton
Power and Light Company, operate the East Bend plant.
In May 1978, Kentucky officials informed EPA of modeling results
indicating that, in conjunction with the existing East Bend facility, the
Patriot facility proposed by IPL would cause the allowable PSD increments for
sulfur dioxide to be exceeded in Kentucky. Taking the Kentucky modeling
results into consideration, EPA Region V disapproved construction of Patriot
in August 1978 by denying a PSD permit, which is required under section 160 of
the Clean Air Act.
After the EPA decision, IPL petitioned the U.S. Court of Appeals, Seventh
Circuit, to review the matter (Indianapolis Power and Light Company v. U.S.
Environmental Protection Agency, docket no. 78-2062, filed October 2, 1978).
The utility company also asked the court for a temporary injunction to prevent
EPA from approving permits sought by other electric utility companies in the
area. Apparently, IPL feared that the EPA Region IV offices in Atlanta would
grant the other utilities a permit to expand the East Bend plant. This effort
is believed to represent the first time in American history that an electric
utility in one state has fought in federal court to "stake its claim" for
clean air before a utility in a neighboring state could make its own claim.
In October 1978, the Court of Appeals denied IPL the temporary injunction.
After the case was argued in the court of appeals, EPA admitted error-
based on misinterpretation of the Kentucky modeling data. On May 21, 1979, at
EPA's suggestion the court remanded the proceedings to the agency for
225
-------
administrative ruling. Finally, EPA reversed itself and awarded the permit.
But the permit was awarded only after extensive technical arguments involving
the court, EPA, both states, and the utility affected. The cost of the
negotiations, in terms of both time and money, was apparently considerable to
both public and private parties to the dispute.
This case shows how interstate conflicts can arise over power plant
siting. Often it is cited in discussions of possible mechanisms that might
both avoid such disputes and preserve air quality in a "local" two or three-
state area. Three-state configurations are particularly complex. In the
ORBES region, conflict over transboundary air pollution transport could occur
in several tristate areas, including (1) West Virginia's northern panhandle, a
portion of Ohio, and a part of Pennsylvania, (2) the area around Huntington,
West Virginia, and Ashland, Kentucky, which includes portions of those two
states, plus Ohio, and (3) the Cincinnati area, which includes portions of
Ohio, Kentucky, and Indiana.
In these and other interstate areas of the ORBES region, certain federal
structural patterns, particularly EPA's organizational structure for
regulatory functions, do not promote communication among the states. The
ORBES states fall into three different EPA regions: Region III (offices in
Philadelphia), with responsibility for Pennsylvania and West Virginia; Region
IV (Atlanta), with responsibility for Kentucky; and Region V (Chicago), with
responsibility for Illinois, Indiana, and Ohio. EPA has responded to the
difficulties associated with air quality management in the Ohio River Valley
and the broader ORBES region by creating a tri-regional task force. Comprised
of the three regional administrators, the body's primary objective is to
strengthen cooperation in meeting interstate and interregional air quality
issues.
12.1.2.2 Long-Range Transboundarv Air Pollution
As noted above, the distinguishing characteristic of long-range
transboundary air pollution is that emissions transported across state lines,
although capable of being measured, cannot be identified with a particular
source. There is ambiguity within legal circles as to whether individual
plant sources must be distinguished before legal actions can be brought by one
state against another under the Clean Air Act. Some scholars feel that it is
possible to seek action if groups of plant sources are identifiable. However,
the matter has not been litigated definitively, and no consensus exists within
the legal community.
The remainder of this chapter is drawn chiefly from Keenan, Ohio Basin
Interstate Energy Options, and James A. McLaughlin, Legal and Institutional
Aspects of Interstate Power Plant Development in the Ohio River Basin Energy,
Study Region (ORBES Phase II).
226
-------
The critical question, then, is whether there is evidence to suggest that
any strategy, beyond the use of strictly technical approaches at individual
plant sites, could be successful in mitigating impacts from polluted air
masses that travel long distances. For more than a decade, the exploration of
such strategies has centered on possible multistate siting arrangements;
national siting legislation was being considered by Congress as early as 1970.
For both technical and political reasons, however, these proposals have not
been accepted. Thus, at neither the national nor the interstate regional
level are siting arrangements in place that address air quality problems.
EMISSION REDUCTIONS. However, on the basis of ORBES research, a cautious
assessment can be made that air quality could be improved by a regionwide
techno-organizational strategy that would determine expected emissions, site
plants, and coordinate operations related to air pollutant emissions. One way
to achieve emission reductions would be the adoption of more stringent
environmental controls, as in the strict environmental control scenario, in
which more stringent criteria for siting plants also were assumed.
Another way in which emission reductions might be achieved is by the
implementation of least emissions dispatching. This day-to-day load
management technique would put fossil-fueled generating units into service in
the order of least sulfur dioxide emissions, rather than least cost. Least
cost dispatching is the traditional utility practice, and only one company
that uses least emissions dispatching, Southern California Edison, has been
identified.3 Of course, individual utility companies in the ORBES region
could initiate least emissions dispatch at their respective plants. The
effects would be greatest, however, if this option were implemented by the
large systems that operate in the region. So far as is known, least emissions
dispatch has not been practiced on an interutility or interstate basis.
However, regional reliability councils might encourage an interutility,
interstate approach, and state public service commissions could do likewise
within their states.
The least emissions dispatch strategy illustrates the positive effect
that a regionwide change in utility operations could have on air quality, even
under conditions of high electrical energy growth. A regional body concerned
with both utility siting and operations could weigh the advantages and
disadvantages of approaches such as those taken in the various ORBES
scenarios. For example, in the electrical export case, a regional body might
recommend that the electricity exports should be produced by nuclear-fueled
rather than coal-fired units, thus avoiding the air quality impacts
identified.
3 Southern California Edison applies the least emissions dispatch
strategy only to oxides of nitrogen emitted primarily from oil-fired plants.
227
-------
REGIONAL LOADINGS. A regional siting mechanism alone could indeed reduce
pollutant concentrations at local "hot spots," where these concentrations are
highest and where PSD increments are not available to accommodate new sources.
Also, local situations where two or more power plant plumes interact could be
avoided. Siting alone, however, could not reduce total regional pollutant
loadings. The total regional pollutant loading would not be affected by a
regional siting mechanism. Coupled with regional siting, however, certain
operational changes—such as least emissions dispatch and uniform or
differential emission reductions—could reduce total regional loadings, thus
also reducing extraregional impacts. Given the interdependency of emission
reductions, siting, and operations, it appears that regional coordination
would be required to reduce pollutant loadings and/or to reduce concentrations
from long-range transboundary pollution in the region and beyond.
Recent focus has been provided to the long-range transport issue by the
attention given it by the northeastern states, which because of prevailing
wind patterns experience impacts from pollutant loadings transported from the
ORBES region. Policymakers must determine whether these negative impacts are
significant enough to justify the creation of regional air pollution control
bodies. Again, any organizational arrangement devised either to decrease
total regional emissions or to reduce pollution transported to downwind states
would require regional coordination of certain aspects of power plant
operations.
If policymakers at either the state or national levels should decide to
consider such a mechanism, several critical air-oriented questions must be
answered. For example, should such an entity be, in effect, a regional air
quality control agency? If it were to function as an air quality control
agency, should it deal only with operational aspects of power plant air
pollution or should it extend to siting? Finally, should such a mechanism be
considered for the ORBES region or a similar area centered in the Ohio River
valley, or should it be part of a national arrangement? Given the present
dynamic character of the ORBES region, any public discussion of these
questions also would include other issues. For example, in addition to power
plants, other energy-related facilities are being developed in the region, and
consideration of power plant siting probably would trigger controversy over
the desirability of including other energy facilities in any siting
arrangement. These issues are discussed in section 12.2, below.
Specialists disagree as to the desirability of multistate strategies to
mitigate negative long-range transboundary pollution transport impacts, but
the matter cannot be avoided. This is due in part to the controversy over
acidic deposition, or acid rain, brought into prominence by officials in
northeastern states and Canada. EPA officials have been forced to acknowledge
the sensitivity between ORBES states, with their heavy use of coal, and
northeastern states; recently the EPA administrator has addressed the matter.
228
-------
As discussed in detail later in this chapter, the administrator has indicated
his preference for a "regional, multi-state approach" to begin the process of
combating emissions that he believes are associated with acid deposition. He
has not elaborated on such an approach, but one must presume that he envisages
a federal mechanism that would be administered by EPA or a similar agency.
Although the acid rain phenomenon is not understood fully, it is clear that
long-range transport plays an important role. Increasingly, the acid rain
question is affecting consideration of organizational mechanisms designed to
mitigate multistate transboundary air pollution problems in the broadest
sense.
STATE AND UTILITY PARTICIPATION. If the dialogue regarding the suitability of
new organizational approaches for dealing with long-range transboundary
pollution transport is to be meaningful, it must include participation by the
states and the electric utilities. Increased voluntary cooperation among
utilities themselves and among state administrative officials might be a way
to mitigate negative air quality impacts. One rationale for such cooperation
is that procedural difficulties and delays might be avoided and thus that
negative air quality impacts could be alleviated sooner. However, it may not
be in the utility's self-interest to cooperate. The Patriot case provides an
example. Despite the difficulties encountered, Indianapolis Power and Light
was awarded a permit to construct the facility. (In that instance, of course,
cooperation among relevant utilities and the states of Kentucky and Indiana
would have addressed local transboundary pollution transport problems as
opposed to long-range transboundary problems.)
Little agreement appears to exist as to whether it is realistic to expect
electric utilities in different states to cooperate in activities aimed at the
mitigation of negative transboundary air quality impacts. Much of the
disagreement stems from lack of consensus on whether technology and existing
"know how" would permit utilities to achieve such an objective jointly.
Suggested cooperative strategies can be divided into two categories: (1)
operations and (2) siting. Least emissions dispatch is a prime example of the
former; as discussed in the context of the high electrical energy growth case,
it might reduce total regional emissions of sulfur dioxide. However, since
not even one utility in the ORBES region has felt it to be sound policy to
institute this system in its own system, it seems unlikely that, without
strong incentives from government at some level, two or more utilities would
voluntarily implement the practice across system and state lines. Also, some
utility leaders have stated that the potential for this mitigation strategy
has been exaggerated.
Douglas M. Costle, "A Law in Trouble?," remarks delivered at the annual
meeting of the Air Pollution Control Association (Montreal, June 23, 1980).
229
-------
With respect to siting, the ORBES conclusion that local transboundary
impacts indeed could be reduced through interstate siting efforts already has
been noted. Whether siting alone could mitigate long-range transboundary
impacts significantly is doubtful. Even if the utilities were to launch
voluntary cooperative siting efforts, it is not clear that they could make the
necessary organizational arrangements, given existing orientations to states
and service areas. On the other hand, the industry cooperates voluntarily in
other functions. Much of this cooperation takes place through the National
Electric Reliability Council (NERC) and nine regional reliability councils.
Through these councils, the nation's major electric power systems collect and
exchange information on such matters as load projections, generating
resources, and interconnected network facilities.5
It might be possible for Congress to expand existing legislation to
encourage utility coordination of power plant siting across state lines,
similar to the way the reliability councils were created following the 1965
"blackout" in the Northeast. Over the past decade, bills introduced in the
Congress, some obtaining considerable support, have called for extensive use
of the councils and/or the electric utility industry in general to create
plans for power plant siting.
If utilities in some combination of states were to agree among themselves
on an arrangement for interstate and/or multistate siting of plants, a method
still would be required for administrative and/or regulatory review of their
decisions at both the federal and the state levels. It is difficult to
envisage alternative paths for such review. Under existing structural
arrangements, review by the Federal Energy Regulatory Commission and either
state siting agencies or public service commissions probably would be
required. Coordination among utilities in such a voluntary arrangement would
be extremely difficult. If such coordination were achieved, consideration
also might be given to the identification or even the acquisition of sites on
a regional basis by some interstate entity. Suggestive is a practice
initiated by the state of Maryland, which buys and "banks" future sites.
Cooperation among states themselves to mitigate negative transboundary
pollution is another possibility, but few such initiatives have been taken.
Only one major proposal in the ORBES region is known. In September 1976, the
then-governor of Kentucky proposed to the governors of four other states
5 Most of the electric utility service in the ORBES region is coordinated
by two regional councils: the East Central Area Reliability Council (ECAR)
and the Mid-America Interpool Network (MAIN). See Jan L. Saper and James P.
Hartnett, eds., The Current Status of the Electric Utility Industry in the.
ORBES States (ORBES Phase II).
230
-------
bordering the Ohio River (all of the ORBES states except Pennsylvania) that
they cooperate in the siting of power plants. However, the idea was not
pursued.
Officials of such state agencies as public service commissions,
environmental protection departments, and energy units apparently communicate
very little across state lines in regard to possible cooperation in power
plant siting. In fact, it appears to be difficult for such officials to
communicate on siting issues even within their own states, due to the
complexities of such areas as operations and permit and licensing procedures
associated with plant siting and construction.
Before interstate or multistate cooperation in the mitigation, of
transboundary air pollution impacts could occur, legislative leaders in the
various states would have to perceive these impacts as major problems. In
only one ORBES state, Ohio, has the legislature given its administrative
leaders a clear mandate to seek cooperation with other states. A section of
Ohio's power siting statute specifically provides for joint proceedings with
other states and the federal government and for entering into interstate
compacts or agreements. Ohio also is the only ORBES state that, by
legislation, has fashioned a "one-stop" siting procedure through which one
agency has the authority to resolve all issues involving the acceptability of
an electrical generating facility site (Ohio Rev. Code Ann., sec. 4906.01 et
seq.). The Ohio Power Siting Commission, the lead agency through which the
process operates, is made up of chief executive officers of the relevant state
agencies and also includes public and legislative membership. If the other
ORBES states were to create similar commissions, a suitable vehicle would
exist for interstate discussions on siting problems.
INTERSTATE COMPACTS. Another potential vehicle is the interstate compact.
The U.S. Constitution declares that "no state shall, without the consent of
Congress...enter into any Agreement or Compact with another State" (art. I,
sec. 10). The courts have held, however, that such congressional consent is
required only when states create an organization "tending to the increase of
political power in the states, which may encroach upon or interfere with the
just supremacy of the United States" (Virginia v. Tennessee. 148 U.S. 503
(1893)). Given the current concern over energy developments, the courts might
hold that congressional approval would be required of any new interstate
agreement designed to mitigate transboundary air impacts.
Ohio River Valley Water Sanitation Commission. Although in recent years
interest has increased in the use of interstate compacts as a possible
mechanism to mitigate air-related impacts, no serious attention has been given
to such an approach in any ORBES state legislature. However, state
commissioners of an organization established 22 years ago through an
interstate compact to improve water quality in the Ohio River valley have
231
-------
expressed considerable interest in transboundary air problems. This
organization is the Ohio River Valley Water Sanitation Commission (ORSANCO),
formed when governors of the six ORBES states, plus New York and Virginia,
signed an interstate compact. Since early 1979, the possible role of ORSANCO
in the development of a multistate siting entity has been under discussion by
commission members. Beyond supporting an exploratory study on whether there
is need for a new or existing organization to engage in siting activities, the
ORSANCO commission has made no formal recommendation on the establishment of
such a body.
Some members of ORSANCO panels believe that the group's compact could be
modified to permit supplementary agreements, between as few as two member
states, to resolve transboundary air pollution conflicts and other problems
relating to interstate facility siting. Under such an agreement, the concept
of "advance consent" might be exercised, thus avoiding the need to obtain
congressional approval- of each agreement between states. ORSANCO
commissioners who favor such an expansion of the organization's role have
emphasized that a change need not interfere with siting-related steps,
particularly the issuance of construction and operating permits, that now are
performed by state or federal agencies. Rather, the goal would be to identify
both prime siting areas and those unacceptable on the basis of multistate and
regional criteria. As a proposal from one former commissioner stated it, an
ORSANCO-based arrangement could be "applicable to the entire river valley or
portions thereof adjacent to two or more states. At the very least, a permit
coordination, or perhaps a multistate certification process, could be devised
even if nothing more profound were done."?
A number of advantages and disadvantages can be cited in regard to
ORSANCO's role in mitigating negative air quality impacts. A major advantage
is that ORSANCO is an entity already in place, and it would take years to
approve a separate interstate body. However, ORSANCO is a water-related
organization, while air quality probably will be the major controlling factor
in operational and siting problems. Moreover, although the agency has
qualified staff to carry out its present functions, the staff is limited in
their air-related capabilities. Another advantage is that eight key states
are commission members; nevertheless, the commission includes neither
See memorandum from Kentucky Commissioner Eugene F. Mooney, chairman,
Task Force on Major Facility Siting, to ORSANCO members (January 10, 1979),
and Eugene F. Mooney, Proposal to ORSANCO on Major Facilities Siting Process
for Ohio River, distributed as Appendix G, at ORSANCO commission meeting
(September 14, 1978).
7 Mooney, Proposal to ORSANCO.
232
-------
Tennessee nor other states in the broader Ohio Basin. A third advantage is
the broad base of the long-time ORSANCO constituency, which consists of the
eight member states; industry, including the electric utilities; and
municipalities. However, "newer" concerns, such as environmental groups that
focus on coal-related air quality problems, perceive limited access to the
body. Finally, ORSANCO is experienced in political affairs and interstate
diplomacy and probably is capable of articulating the states' position in
conflicts with the federal government.
Delaware River Basin Compact. No interstate compact to mitigate transboundary
air pollution is known to operate anywhere in the country at this time.
However, the Delaware River Basin Compact has organizational elements that
could be relevant in the consideration of such mechanisms for the ORBES
region. The organization "has played an active role in electric energy
facility siting and has been instrumental in both assisting and obtaining
overall approval of sites and in discouraging the utility from mis-siting
projects."" An agency established by the compact has the authority to manage
the water resources of the river basin without regard to political boundaries.
Generating facilities on the Delaware River were threatening to seriously
affect the water quantity and quality of basin streams at low flow.
Therefore, in 1971, the Delaware commission amended its rules to require that
utilities obtain approval of water use for projects with generating capacities
of 100 megawatts electric or more. Although water issues were the impetus for
the creation of the Delaware Compact Commission, while air quality problems
are viewed as most critical in the ORBES region, the tools utilized in
interstate administration of the use of water resources might suggest
organizational techniques for regional management of air quality problems.
TENNESSEE VALLEY AUTHORITY. In considering strategies to mitigate negative
air quality impacts in the ORBES region, it is difficult to ignore the
Tennessee Valley Authority, a federal corporation created in 1933 and a major
consumer of coal among the nation's utilities. The TVA service area includes
parts or all of seven states: Vi ginia, North Carolina, Kentucky, Tennessee,
Mississippi, Alabama, and Georgia. Of these states, only Kentucky also is in
the ORBES region. However, in terms of overlapping problems of long-range
transboundary air pollution transport, the two regions are so interconnected
as to make separate treatment almost impossible. Vital connections also are
evident in at least four other areas: (1) relationships and comparisons
between TVA- and ORBES-region utilities in providing coal-generated
electricity to uranium enrichment facilities, (2) ongoing comparisons of
Q
Herbert A. Hewlett, "The Role of River Basin Commissions in Energy
Facility Siting," paper delivered at a seminar of the Southern Governors'
Conference (March 25, 1977).
233
-------
different rate structures between TVA and ORBES-region utilities, (3)
competition among coal suppliers in obtaining contracts with ORBES-region
utilities and TVA, and (4) linkages between the two regions in waterway
management. Thus, it is necessary to ask whether any strategy in the ORBES
region—operational or siting-oriented—could be effective without the
inclusion of the six other states that, together with Kentucky, form the TVA
service area.
Even casual consideration of operational and/or siting cooperation
between the ORBES and TVA areas for purposes of mitigating air impacts
probably would result in emotional responses from utility leadership in both
regions. Intense ideological differences separated the early supporters of
the TVA idea from the leaders of the investor-owned utilities. Although this
conflict has diminished somewhat over the years and TVA and ORBES-region
utilities work together in such areas as electric power reliability,
cooperation would be difficult to implement. However, given the increasing
importance of the TVA region and the ORBES region in eastern U.S. air quality
management, pressures might force some form of cooperation among TVA, the
investor-owned utilities in the ORBES region, and other, smaller generating
entities such as the rural electric cooperatives and the municipalities that
produce electricity.
OHIO RIVER BASIN COMMISSION. For different reasons, then, both ORSANCO and
TVA will be important in discussions of multistate air quality management in
the ORBES region. Probably of less significance are a number of other
regional organizations. One of these groups apparently shares with ORSANCO an
interest in providing counsel on the interstate siting of power plants. This
is the Ohio River Basin Commission (ORBC), a federal-state partnership
composed of 11 Ohio River Basin states (including the 6 ORBES states), 9
federal agencies, and ORSANCO. ORBC was created in 1971 under Title II of the
Water Resources Planning Act of 1965 (42 U.S.C. 1962). Commission
spokespersons have noted that the organization may be suitable for studying
siting dilemmas and possibly becoming involved in giving counsel or making
decisions. In developing its budget in recent years, the ORBC staff has
acknowledged power plant siting problems, including transboundary air
transport, and has sought funds to study associated interstate issues.
A negative factor in considering ORBC for a possible role in air quality
impact mitigation is its basic organizational mission, which is limited to
planning focused on water problems. However, the argument has been made that,
in the absence of other effective organizations, the basin commission is an
appropriate institution to participate in planning for future air quality
management. Most of the disadvantages noted above in connection with
ORSANCO's possible role in air quality affairs apply to ORBC, perhaps in a
more telling fashion. In addition, leaders in certain of the states holding
commission membership have been dissatisfied with the organization's
234
-------
activities. In the late 1970s, Ohio withdrew its financial support, charging
that the state had derived little benefit from ORBC membership.
APPALACHIAN REGIONAL COMMISSION. A 13-state economic development-oriented
organization centered in Appalachia is so tied to a continued emphasis on coal
that it must be mentioned in the context of air quality concerns. This body
is the Appalachian Regional Commission (ARC). It was created by Congress in
1965 under the Public Works and Economic Development Act of 1965 (42 U.S.C.
3121) for the purpose of promoting Appalachian economic development. The ARC
region includes all of West Virginia; portions of three other ORBES states,
Pennsylvania, Kentucky, and Ohio; and parts or all of nine other states.
Because of the overlap between much of the ARC region and the TVA service
area, many of the comments above in regard to TVA and the ORBES region air
quality relationships apply equally to the interface between the ORBES region
and the ARC area. A proposal has been made that ARC's functions be expanded
so that it could address transboundary impacts in the Ohio River valley and
perhaps become an energy facility siting body. This also would involve an
expansion of the commission's region. However, the proposal finds little
support in Indiana, Illinois, and Ohio, where many disagree with the ARC's
policies on economic growth.
FEDERAL ACTIONS. Most federal initiatives probably will center on the Clean
Air Act. Since the 1977 amendments were signed, various interests with a
variety of perspectives have sought radical changes in the act. Often
electric utility representatives describe it as unnecessarily complex and
excessively time consuming. On the other hand, environmentalists and some EPA
officials characterize the Clean Air Act as ineffective in addressing
troublesome problems, including multistate, long-range transboundary air
pollution transport.
In August 1981, current authorization measures to fund the administration
of the Clean Air Act will expire. This means, in effect, that Congress soon
will be reviewing the 1977 amendments. The EPA administrator has stated that
the act "could be gutted if people don't pay attention to what is happening."
He has emphasized the problem of acidic deposition, which involves "numerous
jurisdictions, existing sources, and energy issues," noting that "the Clean
Air Act's primary reliance on the States is sound, but on this issue we
confront one of its principal shortcomings: how to deal effectively with
regional and area-wide problems involving transport over long distances, and
across state and national boundaries." Moreover, he has questioned seriously
"whether the State Implementation Plan process—requiring as it does a State-
by-State, plant-by-piant approach—is the best way to solve this problem in a
timely fashion. I would personally prefer a regional, multi-state approach to
the problem of total loadings—one which would, for example, allow an entire
utility system to find the most cost-effective approach to getting a
235
-------
percentage reduction from among a mix of all their loadings; such a system
should even be flexible enough to permit trade-offs with other utility
networks. This would require a change in the law."9 Thus, it appears likely
that any new national initiatives aimed at the mitigation of transboundary air
pollution impacts will focus mainly, perhaps exclusively, on mechanisms to
combat the acidic deposition phenomenon.
To emphasize points made above, a mechanism capable of addressing rather
well-understood impacts might be far different from one that focuses on
little-understood long-range, multistate transboundary problems. The policy
debate that will take place in the upcoming Clean Air Act review will include
at least three distinct points of view. The first argument, whose proponents
will include many leaders from the ORBES coal-producing states, is that
present energy needs and associated national security matters are so serious
that additional attention cannot be paid to questions of transboundary air
pollution. The second argument, made by many northeastern groups, probably
will call for new organizational mechanisms to combat long-range multistate
transboundary pollution transport at almost any cost. Power plants in ORBES
states seem certain to be among the targets. A possible third argument might
be made by a coalition of ideological opponents of further federal action,
particularly in the form of regional approaches, and some environmentally
conscious individuals. These environmentalists, though concerned over long-
range transboundary pollution transport, might well question the possibilities
for success of any multistate strategy and might fear that such an emphasis
would turn attention from better-understood local impacts.
Finally, it should be noted that arguments for more aggressive federal
action in mitigating air quality impacts, perhaps even federal preemption,
will continue.
12.2 Possible Influences
The analysis of the five ORBES coal-dominated scenarios reveals that air
quality problems probably will present the most serious challenges through the
year 2000, even with the reductions in pollutant emissions projected under the
scenarios. However, air quality alone may not be the impetus for policy
changes to ameliorate these negative impacts. Among the other possible
factors are the U.S.-Canadian discussions on acid rain, nuclear fuel use,
synthetic fuels, and energy mobilization.
U.S.-CANADIAN DIALOGUE. At any time, the ongoing dialogue between Canada and
the United States over air pollution transport across their common border
Costle, "A Law in Trouble?"
236
-------
could trigger unexpected developments in the ORBES region. If the Canadian
position should become particularly aggressive, the problem of long-range
transboundary pollution transport from the ORBES region suddenly could become
an international problem in need of national attention. Thus, any multistate
mechanism designed to address the problem would be likely to assume first-line
management responsibility.
NUCLEAR ENERGY. Action at one or more levels of government could be
stimulated by developments other than coal-related impacts. In turn, this
action could set in motion broader strategies affecting the total energy
sector—including coal-fired facilities in the ORBES region. The present
uncertainty with respect to the use of nuclear energy for electrical
generation is a case in point. A nuclear fuel substitution scenario is
discussed in chapter 14, and policy questions relating to nuclear facilities
are discussed in chapter 15. However, these chapters do not deal with the
possibility that concern over nuclear power also could stimulate consideration
of the impacts of coal-fired plants. In fact, many such deliberations have
occurred in recent years at both the national and the regional levels. Often
they conclude that a plan for power plant siting and operations could not be
effective if it is designed to deal with only one type of fuel use. If
interstate or multistate mechanisms were to be used in the siting and
operation of nuclear-fueled generating facilities, they also might be used for
other installations associated with the broad nuclear fuel cycle, including
nuclear weapons facilities, uranium mines, uranium enrichment facilities, and
waste disposal sites.
Thus, discussions of interstate or multistate siting mechanisms for
coal-fired electrical generating facilities often cannot be separated from
consideration of nuclear-fueled generating facilities or other nuclear
installations. And the complexity does not end there. Given the national
policy for reducing our dependence on foreign oil, regional or national
proposals for energy facility siting increasingly have included consideration
of a number of types of installations in addition to electrical generating
plants.
SYNTHETIC FUEL PLANTS. Relevant here is the renewed emphasis on coal-based
synthetic fuel plants, using both gasification and liquefaction processes,
which now are being planned in the ORBES region. Such plants are not
projected in the ORBES scenarios, chiefly because these installations are not
expected to be a significant energy source by the year 2000 in the study
region.
In July 1980, the President signed a bill that allocates $20 billion to
spur the production of synthetic fuels to replace foreign oil. The
legislation sets a goal of synthetic fuel production equivalent to 500,000
barrels of oil a day by 1987 and 2 million barrels a day by 1992. To put this
237
-------
goal in perspective, for the four-week period ending September 5, 1980, gross
imports of crude oil and petroleum products together averaged 5.7 million
barrels a day, which is 33.2 percent less than the average for a comparable
period in 1979.10
In practical terms, policymakers will likely be faced with the task of
assessing the possible interaction of the impacts from new synthetic fuel
plants with certain of the impacts from power plants identified in the ORBES
analysis. Synthetic fuel plants probably would not have major negative
effects on air quality and would not be expected to consume more water than
coal-fired generating plants of comparable size.11 However, any case being
made for future interstate, multistate, or national power plant siting and
operation mechanisms probably will consider the incorporation of synthetic
fuel installations.
COAL TRANSPORTATION. The success of the nation in using larger amounts of
coal in order to reduce its dependence on foreign oil will rest in part on the
response capability of various coal transportation modes: railroads,
waterways, highways, and pipelines (for slurry). Many of the transport
problems to be faced are intrastate in nature. Solutions to most of the
intrastate problems will be built on long legal and institutional histories.
However, the possible need to expand existing river ports or to construct new
port facilities is one interstate aspect of coal transport that presents new
challenges. Protracted conflict between states over major riverport and coal
terminal sites on the Ohio River conceivably could bring pressure for such
installations to be included in any proposal for an interstate facility siting
and operation mechanism.
ENERGY MOBILIZATION. The unpredictable factors discussed above relate to
possible multistate or international action designed to mitigate air quality
impacts. However, unexpected events also could trigger the relaxation of such
efforts. For example, Congress could decide that the need to develop energy
facilities is so overriding that a mobilization posture is required. The
President's 1979 proposal for a national Energy Mobilization Board (EMB),
stalled in Congress in late June 1980, assumes such a need for energy
development. The EMB proposed by the President would have exercised sweeping
powers to expedite energy projects, including the lowering of environmental
standards for certain energy projects. If the President's proposed EMB or
U.S. Department of Energy, Energy Information Administration, Weekly
Petroleum Status Report (DOE/EIA-0208 (80-37), September 12, 1980).
U.S. Department of Energy and U.S. Environmental Protection Agency,
Energy/Environment Fact Book (EPA-600/9-77-041, March 1978).
238
-------
similar legislation is passed, this would indicate a climate in which
multistate action to mitigate negative air quality impacts might not be taken.
12.3 Underlying Questions
This chapter indicates that air quality probably is the most crucial
factor in the use of coal for electrical generation in the ORBES region. Many
technology-oriented strategies to mitigate negative air quality impacts from
coal use for electrical generation are in various stages of operation,
experimentation, and study. An array of organizational approaches could
encourage cooperation among the ORBES states in reducing negative impacts.
Also, however, new national legislation to stimulate construction of coal
facilities other than power plants might render obsolete certain aspects of
proposed multistate mechanisms aimed primarily at air pollution from coal-
fired electrical generating facilities.
Three basic questions must be answered from both the regional and the
national perspectives: (1) Would any organizational change under
consideration make it less difficult to mitigate negative impacts from burning
coal? (2) Would such a change enable the United States to reduce its
dependence on foreign oil? (3) Would the change be consistent with the
essential democratic values of our society?
239
-------
-------
FUEL SUBSTITUTION AND CONSERVATION EFFECTS
It appears extremely unlikely that, before the year 2000, regulatory
factors and other conditions will result in substantial changes in patterns of
fuel use for electrical generation in the Ohio River Basin Energy Study
(ORBES) region. Reflecting regional conditions, this report has stressed the
use of coal. However, policymakers must be aware of the institutional
barriers and opportunities associated with partial substitution of other fuels
for coal, as well as the barriers and opportunities associated with a major
regional emphasis on energy conservation.
This portion of the report considers the effects of four hypothetical
futures that would mean less emphasis on the use of coal for electrical
generation in the ORBES region. The first three scenarios call for fuel
substitutions for coal-fired electrical generation: (1) an increase wherever
possible in the use of natural gas for applications other than central station
electrical generation (the natural gas substitution case), (2) an increase in
nuclear-fueled electrical generation, and (3) an emphasis on alternative
fuels, such as solar energy. The final scenario calls for a regional emphasis
on conservation. These four scenarios are described in chapter 13-
Even under any of the futures discussed here, however, the ORBES region
still would be dominated by the use of coal for electrical generation. Thus,
policymakers still would have to deal with the impacts on air quality
associated with coal emphasis.
In contrast to the extensive impact analysis carried out for the coal-
dominated futures (chapters 6 through 11), impact analysis of the fuel
substitution and conservation scenarios is relatively limited. Thus, the
impacts of the four cases are contrasted with each other and with the coal-
dominated base case in one chapter, chapter 14. In general, the same impact
areas are considered as for the coal-dominated futures: air, land, water,
employment, and health.
As indicated above, institutional barriers and opportunities associated
with the partial replacement of coal by other fuels and by conservation
measures are of chief interest here. These barriers can be assessed with
varying degrees of certainty. In the case of natural gas substitution, it
need only be noted that over many years an institutional system has been
developed for the production, transmission, and distribution of this fuel.
Therefore, no major institutional changes probably would be required, and
241
-------
institutional considerations related to an expanded use of natural gas are not
dealt with. If nuclear-generated electricity were to replace a substantial
portion of the electricity generated by coal—a highly improbable circum-
stance—an extensive though controversial literature on institutional
considerations is available; this literature is reviewed briefly. With regard
to alternative fuels and conservation, however, institutional barriers or
opportunities must be discussed in a more general way, even though significant
regional problems could be present. This is due not only to the focus of
ORBES on electrical generation, but also to the relatively late entry that
these measures would have during the study period, which makes the analysis
less certain. Institutional factors relating to implementation of the nuclear
substitution, alternative fuel substitution, and conservation scenarios are
treated in chapter 15.
242
-------
13- Descriptions of the Fuel Substitution and Conservation Scenarios
The four scenarios discussed in this portion of the report reflect
assumptions about energy and fuel use characteristics that differ from those
of the coal-dominated futures (see chapter 5). Three of these scenarios
assume somewhat less emphasis on coal use for electrical generation because of
partial substitution by other fuels. In the natural gas substitution case,
natural gas is substituted for other fuels whenever practicable, except to
fire utility boilers. In the nuclear substitution case, nuclear-fueled
electrical generating capacity substitutes directly for coal-fired capacity.
In the alternative fuel substitution case, a variety of alternative fuels,
including biomass and solar energy, partially replace coal-fired capacity.
The fourth case assumes that, because of the implementation of conservation
measures, energy growth in the ORBES region is significantly less than under
all other scenarios. As shown in figure 13-1, all four cases are compared
directly with the coal-dominated base case; comparisons also are made among
the fuel substitution and conservation scenarios themselves.
SOCIAL VALUES. The social values implicit in the nuclear and natural gas
substitution scenarios parallel those associated with the coal-dominated
futures. In addition, under nuclear substitution, a strong belief in science
as a means to achieve advancement is implicit. The additional values implicit
in the alternative fuel substitution case are individualism, science, and
conservation/preservation; in the conservation case, efficiency and
conservation/preservation.
POPULATION GROWTH. ECONOMIC GROWTH. AND ENVIRONMENTAL STANDARDS. The same
regional population growth rate as in the coal-dominated futures (15 percent
over the period 1970 to 2000) is assumed in the four fuel substitution and
conservation scenarios. Likewise, regional economic growth is assumed to
average 2.47 percent annually in all cases. Base case environmental controls
also are assumed for all four scenarios.
ENERGY AND FUEL USE. There is great variation, however, in the energy and
fuel use characteristics that define the fuel substitution and conservation
See Harry R. Potter and .Heather Norville, Ohio River Basin Energy
Studv: Social Values and Energy Policy (ORBES Phase II).
2M3
-------
Figure 13-1
Major Variables and Comparisons
Base Case, Fuel Substitution Scenarios, and Conservation Scenario
Natural Gas
Substitution
Nuclear Fuel
Substitution
Alternative
Fuel
Substitution
Conservation
Emphasis
scenarios. Growth rates for the various sectors appear in table 13-1, which
includes base case rates as well as those for the four cases under discussion.
In the natural gas substitution case, natural gas supplies 57 percent of the
heat required for industrial processes in 1985 and 85 percent in 2000,
compared with 37 percent and 10 percent, respectively, under the base case.
This difference is reflected in significantly lower rates of electricity
demand growth and coal growth and a significantly higher rate of natural gas
See Walter P. Page, Doug Gilmore, and Geoffrey Hewings, An Energy and.
Fuel Demand Model for the Ohio River Basin Energy Study Region (ORBES Phase
ID.
-------
Table 13-1
Growth Rates and Installed Capacity, Base Case,
Fuel Substitution Scenarios, and Conservation
Emphasis Scenario (1974-2000), Annual Averages
Scenario
Base Case
Natural Gas
Substitution
Nuclear
Substitution
' Alternative
Fuel
Substitution
Conservation
Installed
Natural Refined Capacity
Economic Electricity Coal Gas Petroleum Energy Year 2000
Growth Growth Growth Growth Growth Growth (MWe)
2.47% 3.13% 2.40% -0.40% 0.37% 1.49% 153,245
2.47% 2.00% 0.74% 3.55% 0.51% 1.61% 113,595
2.47% 3.11% 1.52% -0.40% 0.37% 1.50% 145,295
2.47% 2.69% 1.73% -1.20% 0.15% 0.95% 134,295
2.47% 0.90% 0.20% -0.31% -0.54% 0.10% 104,495
growth. With nuclear substitution, however, energy and fuel use
characteristics are about the same as in the base case, except for a reduction
in the use of coal corresponding to the replacement of coal-fired by nuclear-
fueled electrical generating capacity under this scenario. On the other hand,
under the alternative fuel substitution case, growth in conventional energy
sectors is much lower than under the base case and all other scenarios except
the conservation emphasis case. This lower growth occurs because of
limitations placed on end uses of the fuels emphasized in the other ORBES
scenarios. Natural gas experiences an especially sharp decline under
alternative fuel substitution. Among all the ORBES scenarios, the
conservation emphasis case results in the smallest overall energy growth rate,
which is reflected in all sectors. For example, the demand for -electricity
under the conservation case grows at an annual average rate of 0.90 percent
annually, compared with 3.13 percent under the base case.^
The major assumptions of the alternative fuel substitution case
concerning the replacement of coal-fired capacity in the region with less
conventional fuels were implemented by prorating national data reported in the
Technology Assessment of Solar Energy (TASE) to the ORBES region. See Y.M.
245
-------
COAL SUPPLY. The same assumptions about the location and sulfur content of
coal to supply scenario demands are made under the fuel substitution and the
conservation scenarios as were made under the coal-dominated futures.
Although the absolute tonnages of coal arising from different Bureau of Mines
districts are lower in all these cases than under the base case, the
percentages remain the same across scenarios.
SITING. The same method of projecting the generating unit additions needed to
meet electricity demand was used for both the coal-dominated scenarios and the
fuel substitution and conservation scenarios. In general, the base case
pattern was followed for the fuel substitution and conservation cases, with
subtractions as necessary. (See figure 5-4 for a depiction of the regional
coal-fired generating capacity under the base case in the year 2000.)
However, under the two scenarios that call for the fewest coal-fired
additions—natural gas substitution and conservation emphasis—the relatively
few additions are located in those counties that, according to base case
environmental controls, are the most suitable. The siting pattern for coal-
fired generating capacity under the conservation emphasis scenario in the year
2000 is shown in figure 13-2. As implied above, the conservation case calls
for the fewest capacity additions between 1986 and 2000 among all the ORBES
scenarios.
In both the conservation emphasis scenario and the natural gas
substitution scenario, the on-line dates of selected capacity additions
planned by the utilities are delayed to permit an approximately equal annual
increment of additions over the study period, as in all the other scenarios.
Shiffman, TASE Project: DPR Data Base and Maximum Practical Solar Case
Disaggregations (MITRE, WP-79W-00110, 1979), and Technology Assessment of
Solar Energy: Description of Solar Technology and Energy Scenarios (MITRE,
WP-79W-0028, vols. II and III, 1979); Page, Gilmore, and Hewings, An Energy
and Fuel Demand Model; and Walter P. Page and John Gowdy, Gross Regional
Product in the Ohio River Basin Energy Study Region. 1960-1975 (ORBES Phase
ID.
n
See Donald A. Blome, Coal Mine Siting for the Ohio River Basin Energy
Study (ORBES Phase II), and Walter P. Page, An Economic Analysis of Coal
Supply in the Ohio River Basin Energy Study Region (ORBES Phase II).
^ See Steven D. Jansen, Electrical Generating Unit Inventoryf 1976-1986;
Illinois. Indiana. Kentucky. Ohio. Pennsylvania, and West Virginia (ORBES
Phase II); Gary L. Fowler et al., The Ohio River Basin Energy Facility Siting
Model: Methodology (ORBES Phase II); and Gary L. Fowler et al., The Ohio
River Basin Energy Facility Siting Model: Sites and On-Line Dates (ORBES
Phase II).
246
-------
Figure 13-2
Coal-Rred Electrical Generating Capacity, ORBES Region,
Conservation Emphasis Scenario, Year 2000
Megawatts
3001 or more
2001-3000
1001-2000
101-1000
E2ZS21- 100
0
If some planned additions were not rescheduled under this overall low growth
rate in regional electrical generating capacity, there would be negative
growth rates in capacity between 1985 and 2000. Finally, a 35-year generating
unit lifetime is assumed for the three fuel substitution scenarios and the
conservation emphasis scenario.
Under the nuclear substitution case, regional generating unit additions
after 1985 are both nuclear fueled and coal fired. The nuclear substitution
case is the only scenario in which nuclear-fueled capacity additions are
sited. Distribution of the nuclear-fueled units is based on three major
factors. First, the current practice of locating only coal-fired capacity in
Kentucky and West Virginia is assumed to continue, and thus no nuclear-fueled
units are sited in those states. Second, scenario unit additions in other
state subregions are allocated with preference to counties where utilities
have announced nuclear-fueled plants whose capacity can be expanded or to
counties where such plants already are in operation. Third, nuclear-fueled
247
-------
scenario unit additions are allocated to counties independent of the location
of planned or scenario-designated coal-fired generating capacity.
The number of scenario unit additions for the fuel substitution cases and
the conservation case appear in table 13-2. For purposes of comparison, table
13-2 also includes the number of additions for the base case.
SOLAR ENERGY PROCESSES. In the year 2000 under the alternative fuel
substitution scenario, energy from direct and indirect solar energy processes
is assumed to account for almost 11 percent of utility-owned energy production
in the ORBES region. These processes consist of a variety of solar energy
technologies, wind, and biomass. In addition, dispersed generation of
electricity by means of wind would supply 0.6 percent of electricity demand.
Heat for industrial processes from solar energy and from biomass would account
for 16 percent of process heat requirements. Seventeen percent of space
heating requirements would be supplied by biomass in the form of wood and by
active and passive solar systems, while 33 percent of water heating
requirements would be supplied by solar energy.
Direct Solar Energy Conversion. The four basic types of direct solar energy
conversion systems are (1) passive and hybrid solar energy heating and cooling
systems, (2) active solar heating and cooling systems, (3) photovoltaic energy
systems, and (4) solar thermal power systems. Passive and hybrid solar
heating and cooling systems rely primarily on building designs and components
that transfer energy into, out of, and within the building through the natural
processes of conduction, convection, and radiation. Mechanical equipment,
such as fans, pumps, or compressors, plays a minimal role in passive solar
except when this equipment can be used effectively to augment the natural
energy flows or when capital costs and operating energy are justified by
improved system performance. When another solar technology is integrated into
a passive solar building, it is considered a hybrid solar application.
Passive cooling systems discharge unwanted heat through natural means.
The sky, atmosphere, ground, and water are potential heat sinks for these
The siting patterns for the nuclear fuel substitution scenario, the
natural gas substitution scenario, the alternative fuel substitution scenario,
and the conservation emphasis scenario appear in Fowler et al., The Ohio River
Basin Energy Facility Siting Model (vol. II).
7
' Page, Gilmore, and Hewings, An Energy and Fuel Demand Model.
p
Descriptions of these technologies are taken from U.S. Department of
Energy, Solar Energy Program Summary Document: FY 1981. See also Vincent P.
Cardi, Larry Harless, and Thomas Sweet, Legal and Institutional Issues in the
Ohio River Basin Energy Study (ORBES Phase II).
248
-------
Table 13-2
Coal-Fired and Nuclear-Fueled Capacity Additions, ORBES Region:
Base Case, Fuel Substitution Scenarios, and Conservation
Emphasis Scenario, 1986-2000
Number of Scenario Unit Additions
Alternative
Base Natural Gas Nuclear Fuel Conservation
ORBES Case Substitution Substitution Substitution Emphasis
State Portion coal coal coal nuclear coal coal
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
13
18
16
20
14
14
4
7
5
8
4
6
4
6
4
8
4
6
19
7
0
2
5
0
9
13
11
14
9
10
2
4
2
6
2
4
Total Units 95 34 32 33 66 20
Note: Standard coal-fired capacity additions are 650 megawatts electric per unit. Standard nuclear-fueled
capacity additions are 1000 megawatts electric per unit. Included in the figures are units scheduled
by the utilities through 2000; these units are of varying megawattage.
systems. All new buildings can benefit from passive heat and cooling design
concepts, but often it is not cost effective to retrofit existing buildings
for passive solar systems.
Active solar heating and cooling systems use modular or site-built
collection systems (predominantly flat plate collectors) to convert insolation
into thermal energy by absorbing radiation. Mechanical subsystems transfer
the heat into the building by means of air or liquids, and the heat then
either is used directly to heat space or water or is stored for later use.
Swimming pool heating, domestic hot water heating, and space heating are the
leading applications in present use. Solar cooling technology provides for
more economical year-round employment of solar collection systems.
The third category of direct solar energy conversion systems,
photovoltaic systems, provide a clean, simple method for the direct conversion
of sunlight to electrical energy. First developed for use in the space
program, photovoltaic solar cells absorb sunlight and convert it directly into
electricity. Because photovoltaic systems are intrinsically modular, a wide
range of system sizes and models can be designed to fit almost any need. The
249
-------
systems can be used either in central stations in which power is generated for
sale to customers or in distributed applications in which the customers
produce the power themselves. Two major markets for photovoltaic power
systems are (1) grid-connected applications and (2) stand-alone or off-grid
applications (such as remote telephone relay stations). The principal grid-
connected applications are considered to be residential (5 to 20 kilowatts),
community and intermediate load center (50 to 2000 kilowatts), and central
station (over 20 megawatts).
In the final category, solar thermal power systems, the sun's heat is
concentrated and used to heat water or some other fluid to provide industrial
process heat or to drive a turbogenerator. The primary objective is to
provide an alternative to fossil fuels for industrial and utility
applications. Applications that provide both heat and electricity, called
"total energy systems," also are included. The high-temperature heat from
solar thermal systems can be used directly in industrial processes, in
turbines to produce electricity, in cogeneration, and ultimately to produce
liquid and gaseous fuels. Moreover, in low-temperature applications,
concentrating collectors are expected to compete strongly with flat-plate
collectors, which already are commercial.
Wind Energy. Wind energy conversion systems (WECS) provide another promising
way to tap the sun's energy. A small portion of the solar energy received by
the earth, about 2 percent, is converted naturally into surface winds as a
result of the uneven heating of the atmosphere. Natural forces tend to
concentrate this resource so that a reasonably windy site has about the same
annual energy available per square foot of collector as does a good solar
insolation site. Under a conservative estimate, the total wind energy
available over the land area of the United States, calculated at 115 billion
megawatt hours, has the potential of generating 1 billion megawatt hours of
electricity annually, or about 20 percent of the amount of electricity
generated each year in the United States.
WECS usually are classified as horizontal- or vertical-axis machines. A
typical horizontal-axis machine has the classic windmill blades; it swings, or
yaws, to follow changes in wind direction. One vertical-axis machine under
development is the Darrieus ("eggbeater") type, with blades that catch wind
from any direction. The main components of both types of machines are their
q
Information on wind energy conversion systems is drawn from U.S.
Department of Energy, Solar Energy Program Summary Document; FY 1981, and
D.A. Wiederecht, Small Wind Energy Systems: Their Application and Testing
(Rocky Flats, February 1977). See also Cardi, Harless, and Sweet, Legal and
Institutional Issues.
250
-------
rotor blades, gear trains, electric generators, structures, and towers. The
principal engineering challenge is to design wind machines that can be
manufactured cheaply, can perform reliably, and can capture a significant
fraction of available energy. The principal applications of WECS are for
mechanical water pumping and electric power generation, although heating,
cooling, and other applications also are practicable. Small-scale systems (1
to 100 kilowatts) can be employed on-site for residential and farm uses;
intermediate-scale systems (100 to 1000 kilowatts), for larger farms,
irrigation, small utilities, and remote communities; and large-scale systems
(over 1 megawatt), for electric utility and industrial uses.
Biomass. The final broad class of alternative energy processes that would
substitute for coal is biomass, which means the products of photosynthesis
(such as grasses, wood, and agricultural crops and their residues) and other
biological products (such as animal waste) that can be energy sources.
Although their origins are not entirely biological, other waste materials
(such as municipal solid waste and food-processing wastes) often are
considered in discussions of bioenergy.
Biomass energy sources are extremely versatile. Wood and other
lignocellulosic materials (such as crop residues and grass and legume herbage)
can produce heat, steam, or electricity when burned directly in large boilers
or in small units such as wood stoves. These materials also can be used to
produce alcohol and other liquid fuels. Municipal solid waste has the same
applications but, like animal waste, also can be gasified in anaerobic
digesters to produce methane, the primary component of natural gas. Starch
and sugar crops (including corn, wheat, oats, sugarcane, sugarbeets, and grain
and sweet sorghum), as well as many food-processing wastes, are used to
produce ethanol, the alcohol component of gasohol.
CONSERVATION. In the conservation emphasis case, two major factors account
for the extremely low energy growth rate projected for that scenario. First,
it is assumed that the maximum practicable end use efficiencies would be
achieved for all energy uses. In the industrial and commercial sectors, an
energy efficiency increase is defined as a reduction in the amount of energy
product used per unit of output. In the residential sector, an energy
efficiency increase for space heating or water heating is defined as the
reduction in energy consumed in these activities on a per capita basis. This
efficiency is achieved by such means as increased insulation and better heat
See U.S. Congress, Office of Technology Assessment, Energy from
Biological Processes (OTA-E-124, July 1980), and Materials and Energy from
Municipal Waste (OTA-M-93, July 1979).
251
-------
transfer. However, these energy efficiencies have not been quantified by type
for purposes of ORBES.11
Cogeneration. The second major factor that accounts for the low energy growth
rate in the conservation case is the assumption that cogeneration will be
employed on a wide scale in the ORBES region. Cogeneration means the combined
production of power, either mechanical or electrical, and of useful thermal
energy such as process steam. Expressed differently, the heat rejected from
one process becomes the energy input into a subsequent process. On a national
basis, waste heat from electrical generation and process steam production
amounted to the energy equivalent of over 7 million barrels of oil per day in
1975. Because of its fuel savings potential and other benefits, interest in
cogeneration as an energy conservation measure has been renewed in both
industry and utilities.
Using currently available technology, cogeneration systems incorporate
either a "bottoming cycle" or a "topping cycle" configuration. These terms
refer to the point in the cogeneration system at which the electrical or
mechanical energy is produced. In bottoming cycle configurations, fuel is
burned initially to produce process heat, with the rejected heat used to
generate either electrical or mechanical power. However, industrial process
heat requirements (400 degrees Fahrenheit or lower) usually are too low for
the rejected heat to be used effectively in power generation. Although
technology may overcome this problem, at present no complete, reliable, and
problem-free system exists. Therefore, apart from occasional installations,
the bottoming cycle is not expected to have a major impact on industrial
fossil fuel demand within the next 8 to 10 years.
In a topping cycle configuration, fuel is burned to produce high-
temperature heat, which is expanded through a turbine to generate electrical
or mechanical power. After passing through the turbine, the rejected heat is
then used in industrial applications as process heat. Because of the energy
required to generate the electrical or mechanical power, more fuel is consumed
in a cogeneration system than in the production of process heat alone.
However, the total fuel required to produce both power and process heat in one
system is less than the fuel required to produce power and heat in separate
systems. For example, the overall efficiency of a steam turbine topping cycle
11
Page, Gilmore, and Hewings, An Energy and Fuel Demand Model.
12
The information on cogeneration is taken from two sources: Robert
Stobaugh and Daniel Yergin, eds., Energy Future (New York: Random House,
1979), and U.S. Comptroller General, Industrial Cogeneration—What It Is, How
It Works. Its Potential (EMD-80-7, April 29, 1980).
252
-------
cogeneration system is about 79 percent, compared with the combined efficiency
of 58 percent for two separate systems.
Topping cycle systems are of two types. In the first, fuel is burned in
either a gas turbine or a diesel engine that produces electric or mechanical
power directly. The exhaust is used to provide process heat or, with the
addition of a heat recovery boiler, process steam. In the second' type, fuel
is burned initially to produce high-pressure steam, which is then passed
through a steam turbine to produce power. The exhaust is used to provide
process steam.
Cogeneration systems and components must be selected for compatibility
with the industrial processes that they complement. Thus, selection on a
site-by-site basis is necessary. The most important distinguishing features
of these systems are the fuels that can be used, the capital investment
required, the efficiency in converting fuel to electricity, the electricity
produced per unit of steam generated, and the resulting effects on the
environment. Each choice carries its own advantages and disadvantages. For
example, no pollution control equipment is needed to control particulates and
sulfur oxides from gas turbines, but expensive devices are required to control
the high sulfur dioxide and particulate emissions from steam turbines fueled
by certain types of coal. However, the steam turbine is the only commercially
available cogeneration system that can use coal for fuel. The use of coal
instead of liquid or gaseous fuels in a steam cogeneration system increases
capital costs and could make the system uneconomical. As a result, coal-fired
steam turbines are usually not considered except for large applications where
economies of scale are possible. On the other hand, the development of
alternative liquid fuels and of gasifiers capable of using coal, biomass, or
other alternative fuels could greatly increase the prospects for cogeneration.
The major difference between industrial and utility cogeneration is which
output drives the system. Cogeneration systems can be designed for process
steam requirements, with electricity as a secondary consideration, or their
design can be reversed, with electric power as the primary requirement.
In the following chapter, impacts in the ORBES region are compared among
the natural gas substitution scenario, the nuclear fuel substitution scenario,
the alternative fuel substitution scenario, and the conservation emphasis
scenario. As in the presentation of the comparative impacts of the coal-
dominated scenarios (see chapter 6), the major sections deal with emissions,
concentrations, and air-quality-related impacts (section 14.1); economic
impacts related to air quality impacts (section 14.2); and other impacts
related to expanded electrical generating capacity (section 14.3). In
addition, in section 14.4, there is an overview of the impacts projected under
each of the fuel substitution and conservation scenarios.
2,53
-------
14. Impacts of the Fuel Substitution and Conservation Scenarios
A comparison of the three fuel substitution scenarios and the
conservation emphasis scenario demonstrates that, under all these scenarios,
the emission-related impacts that are projected to occur under base case,
coal-dominated conditions would be reduced. Other across-the-board
comparisons, however, are more difficult to make since not all impact areas
were examined under each of these scenarios. As a result, all of the fuel
substitution and conservation scenarios are discussed together rather than
separately. In section 14.4, however, there is a brief synopsis of the
general trends under each scenario.
See chapter 13 for descriptions of the conservation emphasis scenario,
the natural gas substitution scenario, the nuclear fuel substitution scenario,
and the alternative fuel substitution scenario.
14.1 Emissions, Concentrations, and Air-Quality-Related Impacts
SULFUR DIOXIDE EMISSIONS. Utility sulfur dioxide emissions would be only
slightly lower in 2000 under the fuel substitution and conservation scenarios
than they would be under the base case even though substantially fewer coal-
fired units would be needed under these scenarios than under the base case
(see table 14-1). The conservation emphasis case would reduce utility sulfur
dioxide emissions the most (resulting in emissions 11 percent lower than under
the base case), and the nuclear substitution case would reduce utility sulfur
For a discussion of air pollutant emissions and the resulting
concentrations under the natural gas substitution case, see James J. Stukel
and Brand L. Niemann, Documentation in Support of Key ORBES Air Quality
Findings; Teknekron Research, Inc., Air Quality and Meteorology in the Ohio
River Basin; Baseline and Future Impacts; and Teknekron Research, Inc.,
Selected Impacts of Electric Utility Operations in, the Ohio River Basin
(1Q76-2000): An Application a£ the Utility Simulation Model (volumes I, II,
and III, respectively, of James J. Stukel, ed., Ohip River Basin Energy Study:
Air Quality and Related Impacts (ORBES Phase II)). Emissions under the
nuclear fuel substitution scenario and the conservation emphasis scenario are
presented in Teknekron Research, Inc., The Calculation of Several Measures
ORBES Scenarios 2a. 2e_, aM 6. (RM-032-EPA-80, June 1980).
254
-------
Table 14-1
Sulfur Dioxide, Particulate, and Nitrogen Oxide Emissions,
ORBES Region, Fuel Substitution and Conservation Emphasis Scenarios,
Year 2000
Sulfur Dioxide
Emissions
1976 8.94
Base Case 4.35
Natural Gas Substitution 3.93
Nuclear Fuel Substitution 4.21
Conservation Emphasis 3.87
Particulate
Emissions
(millions of tons)
1.38
0.19
0.16
0.18
0.16
Note- Emission levels were not calculated for the alternative fuel substitution
Nitrogen Oxide
Emissions
1.49
2.00
1.51
1.84
1.47
case.
dioxide emissions the least (resulting in emissions only 3 percent lower than
under the base case).
The expanded use of generating units governed by state implementation
plans (SIPs) explains why the fuel substitution and conservation scenarios
would result in utility sulfur dioxide emissions quite similar to those of the
base case. Under both the conservation emphasis case and the natural gas
substitution case, fewer new generating units (75 and 61 fewer units,
respectively) would be built than under the base case; under the nuclear
substitution case, half of the new units added after 1985 would be nuclear
fueled rather than coal fired. As a result, SIP-regulated generating units
would be used more than they would under the base case, where some of the
electrical generation would shift to new, cleaner units governed by revised
new source performance standards (RNSPS). However, the specific emission
levels of SIP units were calculated only for the natural gas substitution
case. Under this case, SIP units would account for about 35 percent of the
electrical generation in the year 2000, whereas they would account for 24
percent under the base case. Thus, while sulfur dioxide emissions from SIP-
regulated units would account for 67 percent (or 2.93 million tons) of the
sulfur dioxide emitted in the year 2000 under the base case, under the natural
gas case such emissions not only would be higher (3.05 million tons) but also
255
-------
would account for more of the total emissions (78 percent of the 3.93 million
tons emitted in 2000).
PARTICULATE EMISSIONS. Utility particulate emissions would be lower under all
of the fuel substitution and conservation scenarios than they would be under
the base case. However, again because of the expanded use of SIP units to
generate electricity, these emissions would be only slightly lower than under
the base case (see table 14-1).
NITROGEN OXIDE EMISSIONS. Unlike the coal-dominated scenarios, however, the
fuel substitution and conservation scenarios would not raise utility nitrogen
oxide emissions at all or as much (see table 14-1). Such emissions rise in
proportion to increased generating capacity, and less capacity is installed
under all of the substitution and conservation scenarios than under the base
case. In fact, under the conservation emphasis case, utility nitrogen oxide
emissions would be lower in the year 2000 than in 1976, and under the natural
gas substitution case, the 1976 emission levels would be increased by only 1
percent. In contrast, the strict environmental control case would result in
the lowest utility nitrogen oxide emissions in 2000 of all of the coal-
dominated cases, and it still would increase utility nitrogen oxide emissions
about 34 percent over the 1976 levels. Of the fuel substitution and
conservation scenarios, only the nuclear substitution case would raise utility
nitrogen oxide emissions significantly (about 23 percent) from the 1976
levels. Even this increase, however, would result in lower emission levels
than any of those projected for the coal-dominated scenarios.
SULFUR DIOXIDE AND SULFATE CONCENTRATIONS. Although annual and episodic
concentrations, related crop losses, and emission-related mortality were not
examined consistently under the fuel substitution and conservation scenarios,
a few general observations can be made using the patterns that emerged from
the coal-dominated scenario analyses. For example, since the reduction of
utility sulfur dioxide emissions consistently would result in reductions in
annual and episodic sulfur dioxide and sulfate concentrations, and since all
of the fuel substitution and conservation scenarios would reduce these
emissions more than the base case would, such sulfur dioxide and sulfate
concentrations should be lower in 2000 under any of the fuel substitution and
conservation scenarios than under the base case. This observation is
confirmed by calculations performed for the natural gas substitution case.
Under this scenario, episodic sulfur dioxide and sulfate concentrations would
be 25 and 15.6 percent lower, respectively, in the year 2000 than they would
be under the base case in that year. Annual average concentrations also would
be lower under the natural gas case, although not as dramatically. Figures
14-1 and 14-2 compare the annual average sulfur dioxide and sulfate
concentrations under the base case and the natural gas case. As can be seen,
the area affected by concentrations of a given magnitude would be slightly
smaller under the latter case than under the former. In general, annual
256
-------
Rgure 14-1
Annual Average Sulfur Dioxide Concentrations, Electric Utility Contribution
Base Case in 2000
Natural Gas Substitution in 2000
L
2-5.9 6-9.9 10-13.99 14-17.99 18-24
Figure 14-2
Annual Average Sulfate Concentrations, Electric Utility Contribution
Natural Gas Substitution in 2000
3-4.99 5-6.99
(M9/m3)
257
-------
average concentrations would be about 7 percent lower under the natural gas
case in the year 2000 than under the base case in that year.
PHYSICAL CROP LOSSES. Crop losses in the year 2000 due to utility-related
sulfur dioxide concentrations in the presence of moderate ozone levels (0.06
to 0.1 parts per million) also should be lower under any of the fuel
substitution and conservation cases than they would be under the base case.^
However, even under the base case such crop losses would represent less than 1
percent of the total regional yield.
It is the crop losses due to oxidants formed from nitrogen oxide
emissions that these substitution and conservation scenarios should reduce the
most. As may be recalled, by the year 2000 utility nitrogen oxide emissions
may dictate the level of ozone-related crop losses because the nitrogen oxide
emissions from transportation sources are projected to decrease substantially
between 1985 and 2000. Since the fuel substitution and conservation scenarios
would result in utility nitrogen oxide emissions significantly or
substantially lower than those under the coal-dominated scenarios, related
crop losses also should be significantly to substantially lower under the
former scenarios than under the latter ones.
MORTALITY. The mortality related to air quality should decrease under all of
the fuel substitution and conservation scenarios from that projected under the
coal-dominated scenarios since emission levels would decrease more under the
former group of scenarios than under the latter.3 As discussed in section
4.6, substantial controversy exists about the quantification of deaths related
to air quality. Nevertheless, an analysis of the projected deaths related to
sulfates and particulates under the natural gas substitution case bears out
this observation. Under this case, the cumulative deaths related to sulfate
air pollution by regional electrical generating facilities between 1975 and
2000 are estimated to be 21 percent lower than they would be under the base
case. Annual sulfate-related deaths would be 3^ percent lower in 1985 under
the base case; in 2000, such deaths would be 36 percent lower under the
natural gas case. Particulate health impacts also would be lower under the
natural gas substitution case. Cumulative particulate-related deaths between
1976 and 2000 would be 11 percent lower under the natural gas substitution
case than under the base case.
2
For a discussion of vegetation impacts and losses, see Orie Loucks et
al., Crop and Fprest Losses Due ip_ Current and Projected Emissions from Coal-
Fired Power Plants IQ the Ohip River Basin (ORBES Phase II).
^ See Maurice A. Shapiro and A.A. Sooky, Ohio River Basin Energy Study;
Health Aspects (ORBES Phase II).
258
-------
14.2 Economic Impacts Related to Air Quality Impacts
UTILITY COSTS. In terms of the monetary costs to the utilities for these
lower emissions, two of the fuel substitution scenarios (natural gas and
nuclear) and the conservation emphasis scenario should result in lower
cumulative pollution control costs and lower cumulative capital costs to
install new coal-fired capacity than would the base case (see figure 14-3).
These reductions would be the direct result of decreased coal-fired electrical
generating capacity under all of these scenarios. However, when the costs of
installing nuclear-fueled capacity under the nuclear substitution case are
added, the result is total costs about 10 percent higher than the total costs
under the base case. The nuclear substitution case would result in these
higher costs because the cost of building a nuclear plant is approximately 20
percent greater than the cost of building a comparable coal-fired plant.
CONSUMER COSTS. Consumer costs were calculated only for the natural gas
substitution case. Thus, the exact economic benefits for the consumer of
reduced pollution control costs and of reduced capital costs are unknown for
the other fuel substitution scenarios and for the conservation emphasis
scenario. Under the natural gas substitution case, total revenues collected
from consumers between 1976 and 2000 would be lower (by about 26 percent) than
the total revenues collected under the base case between the same years. Yet
the actual price of electricity in 2000 under the natural gas case would be
only 0.2 percent lower in 2000 than it would be under the base case. The
reason for this similarity in the year 2000 is that similar electricity demand
growth rates were assumed for these two scenarios between 1985 and 2000.
Between these years, an average annual rate of 1.6 percent is assumed for the
natural gas case; an average annual rate of 2.1 percent, for the base case.
14.3 Other Impacts Related to Expanded Capacity
LAND. Under all of the fuel substitution cases and the conservation emphasis
case, fewer generating facilities would be required than under the base case.
As a result, land conversion would range from slightly to substantially lower
under these substitution and conservation scenarios than under the base case
For calculations of both utility costs and consumer costs under the
natural gas substitution scenario, see Teknekron Research, Inc., Selected
Impacts pjF Electric Utility Operations in. thjg, Ohio River Basin. For
calculations of utility costs under the nuclear fuel substitution scenario and
the conservation emphasis scenario, see Teknekron Research, Inc., The
Calculation of. Several Measures fo-r ORBES Scenarios 2a_, 2c_, and. £. The costs
of the alternative fuel substitution scenario were not calculated.
259
-------
Rgure14-3
Cumulative Capital Costs, Base Case, Fuel Substitution Scenarios, and
Conservation Emphasis Scenario, 1976-2000
Note: The same nuclear capacity was assumed under all scenarios but the nuclear fuel substitution case.
For all scenarios but the nuclear case, cumulative capital costs for nuclear-fueled capacity were
10
s.
O)
o
CO
c
o
$8.3 billion.
80-
70-
60-
50-
40-
30-
20-
10-
85.67
6.12
12.55
Cumulative capital costs to install new coal-fired
generating capacity, 1976-2000
Cumulative costs for sulfur dioxide
control, 1976-2000
Cumulative costs for particulate
control, 1976-2000
67.0
54.70
.05
8.71 42.23
4.71
7.12
49.22
^4.94 46.7
40.94
30.4
7.98
36,3
Scenario
Cumulative sulfur dioxide
and particulate control
costs
BC
NG
CON
NF
Costs
billion $
18.67
13.76
11.83
12.92
% total
costs
21 8
25.1
28.0
26.2
Base Natural Conservation Coal- Nuclear-
Case Gas Emphasis fired Fueled
Substitution (CON)
(NG)
Nuclear Fuel Substitution (NF)
(see table 14-2).^ However, under all of these scenarios, land conversion
would represent less than 1 percent of regional acreage, although in some
state portions more land would be converted under some scenarios than others.
Of the fuel substitution and conservation scenarios, the nuclear substitution
5 For a full discussion of land impacts, see J.C. Randolph and W.W.
Jones, Ohio River Basin Energy Study: I^and Use and Terrestrial Ecology (ORBES
Phase II).
260
-------
scenario has the highest installed capacity and thus would require the most
land conversion.
In terms of the land types that would be converted for new generating
units, less agricultural, forest, public, and other land would be converted
under all of the fuel substitution and conservation scenarios—except the
nuclear substitution scenario—than under the base case (see table 14-2).
Under the natural gas substitution case, the conversion of these land types
would range from 34 to 43 percent lower than under the base case; under the
alternative fuel substitution case, from 12 to 19 percent lower; and under the
conservation emphasis case, from 40 to 52 percent lower. The nuclear fuel
substitution case, however, would result in a slightly higher conversion of
agricultural lands than would the base case. This higher conversion would
occur because no nuclear-fueled scenario additions are built in the ORBES
state portions of Kentucky and West Virginia. Rather, more units are sited in
Illinois, where there is more agricultural land than forest, public, or other
types of land. Finally, because of the siting assumptions of each scenario,
the fuel substitution or conservation scenario that would convert the most or
the least of any land type within a state will vary.
The amount of land that would be converted for all energy uses (new
electrical generating facilities, new transmission line rights-of-way, and new
surface mining for utility coal) was examined only under the alternative fuel
substitution case. Under that case, 10 percent less land would be converted
for all energy-related uses than would be converted under the base case.
However, the amount of land required for the alternative sources was not
analyzed. Indeed, the total land requirements for the alternative fuel
substitution case might not be very different from those of the scenarios
requiring conventional fuels. The regional acreage that would be affected by
surface mining for coal to supply electrical generating facilities under the
alternative case would be 8 percent less than under the base case, ranging
from 4 percent less in the ORBES state portion of Indiana to 12 percent less
in the Illinois portion. Surface mining for all purposes would affect 4
percent less acreage under the alternative fuel substitution case than under
the base case.
The nuclear substitution case would result in the highest assessment of
regional terrestrial ecosystem units of all the fuel substitution and
conservation scenarios (see table 14-3). Moreover, the ecosystem units
assessed under nuclear substitution would be highly concentrated in the ORBES
state portion of Illinois. Because of the siting assumptions of each scenario
as well as the county-level assumptions of the terrestrial ecosystem analysis,
the scenario that would result in the highest or lowest unit assessment within
a state will vary.
EMPLOYMENT. Since the construction and operation of coal-fired power plants
would not increase rapidly under any of the fuel substitution and conservation
261
-------
Table 14-2
Land Converted for Electrical Generating Facilities, ORBES
Base Case, Fuel Substitution Scenarios,
Region,
and Conservation
Emphasis Scenario, 1976-2000
Natural Gas Nuclear Fuel Alternative Fuel Conservation
State Portion
Illinois
Agricultural
Forest
Public
Other
Indiana
Agricultural
Forest
Public
Other
Kentucky
Agricultural
Forest
Public
Other
Ohio
Agricultural
Forest
Public
Other
Base Case Substitution Substitution
(acres)
23,046 16,993 43,358
3,179 2,144 5,124
356 301 657
1,947 1,395 4,031
28,528 20,833 53,170
25,674 19,771 27,237
9,799 6,430 8,997
1 ,009 800 811
3,058 1 ,490 2,235
39,540 28,491 39,280
20,425 11,161 12,679
12,508 7,988 8,872
313 155 169
3,187 1,322 1,463
36,433 20,626 23,183
13,122 7,195 10,546
14,175 7,133 8,561
1 ,700 738 791
2,575 1 ,824 2,364
31,572 16,890 22,262
Substitution
21,689
2,463
334
1,846
26,332
23,716
7,954
877
2,572
35,119
17,994
10,706
224
1,982
30,906
10,504
10,852
1,280
2,255
24,891
Emphasis
15,194
1,905
290
1,263
18,652
17,616
5,621
690
1,248
25,175
1 1 ,043
8,135
166
1,614
20,958
7,322
6.266
464
2,002
16,054
scenarios, neither would related employment under these scenarios. Compared
to the base case, for example, the number of construction and operation
For employment projections, see Steven I. Gordon and Anna S. Graham,
Regional Socioeconomic Impacts Q£ Alternative Energy Scenarios for the Ohio
River Basin Energy Study Region (ORBES Phase II).
262
-------
Table 14-2 (continued)
Land Converted for Electrical Generating Facilities, ORBES
Base
Region,
Case, Fuel Substitution Scenarios, and Conservation
Emphasis Scenario, 1976-2000
State Portion
Pennsylvania
Agricultural
Forest
Public
Other
West Virginia
Agricultural
Forest
Public
Other
ORBES Region
Total
Agricultural
Forest
Public
Other
Natural Gas Nuclear Fuel Alternative Fuel
Base Case Substitution Substitution Substitution
8,315 5,554 4,935 6,990
14,347 8,248 10,988 12,605
1,120 449 383 825
4,208 2,639 2,793 3,065
27,990 16,890 19,099 23,485
4,598 2,907 5,569 3,805
13,148 10,253 9,659 12,821
352 319 678 367
1,708 802 1,348 1,146
19,806 14,281 17,255 18,139
95,920 63,581 111,815 84,698
67,311 42,196 58,562 57,401
4,827 2,762 3,633 3,907
15,809 9,472 15,238 12,866
183,869 118,011 174,249 158,872
Conservation
Emphasis
4,790
7,077
361
2,450
14,678
1,891
6,429
176
261
8,757
57,856
35,433
2,147
8,838
104,274
workers needed would be much lower under the natural gas case (38 percent
lower), the alternative fuel case (19 percent lower), and the conservation
emphasis case (50 percent lower). (See figure 14-4.) However, employment
related to the increased use of natural gas or alternative fuels was not
calculated, and, in fact, could compensate for the lower demand for workers on
coal-fired power plants.
Of the fuel substitution and conservation scenarios examined, all would
result in the need for fewer skilled laborers—boilermakers, pipefitters, and
electricians—than would the base case. The natural gas substitution case
would require 31 percent fewer skilled workers for power plant construction
and operation in 1990 (the peak construction year), and the conservation
emphasis case would require 40 percent fewer skilled workers for such
263
-------
Table 14-3
Terrestrial Ecosystem Assessment Units, Base Case,
Fuel Substitution Cases, and Conservation
Emphasis Case, 1976-2000
state Base Natural Gas Nuclear Fuel Alternative Fuel Conservation
Portion Case Substitution Substitution Substitution1 Emphasis
Illinois 356 309 679 334
Indiana 451 331 425 386
Kentucky 266 148 167 213
Ohio 305 170 212 247
Pennsylvania 270 134 216 196
West Virginia2 156 87 87 122
ORBES Region
Total 1804 1179 1786 1498
258
301
129
161
118
71
1038
impacts of alternative fuel technology sitings are not included in the analysis.
2No substate endangered vertebrate species data were available for West Virginia.
construction and operation in 1990. However, the labor requirements
associated with expanded natural gas use and conservation were not calculated.
The alternative fuel substitution case also would require fewer skilled
workers in 1990 (about 33 percent fewer) than would the coal-dominated base
case in that year. However, the surplus of skilled workers could be offset by
a demand for labor to implement a substitution of alternative fuels. This
demand might be two to three times as great as the demand for power plant
construction and operation under the base case.? Thus, some retraining might
be required so that unemployed power plant construction workers could be used
to install alternative energy systems. However, no skill breakdowns were
calculated for the workers associated with the alternative fuel systems.
For such estimates of alternative fuel labor requirements, see
testimony before the Subcommittee on Energy, Joint Economic Committee, U.S.
Congress (2d session, March 1978, pp. 28, 51, 95, and 136). Similar estimates
have been given in other studies. For references, see Gordon and Graham,
Regional SocioeconomiG Impacts of Alternative Energy Scenarios.
26M
-------
Rgure14-4
Construction Workers, Base Case, Fuel Substitution Scenarios, and
Conservation Emphasis Scenario, 1975-95
17500
15000-
I
O
§
'-^
o
12500
C
O
o
"5 10000
i_
0)
JD
E
7500
5000
Note: Same starting point in 1970 assumed. The number
of construction workers required under the nuclear
fuel substitution case was not calculated.
BC
/ *^\ A.\
f V-. ^-v-."-x
v /•' \ ~~r
V K , / v---
\ *7VA
\ ./ ^^7 \
Base Case (BC)
Natural Gas Substitution (NG)
•— Alternative Fuel Substitution (AF) V*.^ _^.—
— Conservation Emphasis (CON)
CON
1975
1980
1985
1990
1995
Because fewer coal-fired generating units are sited and because growth is
lower in most sectors, less coal should be needed under all of the fuel
substitution and conservation scenarios than would be needed under the base
case. However, coal production under these substitution and conservation
scenarios still would be higher than in 1974. For example, of the scenarios
examined, coal production for all purposes would be 14 percent lower in 2000
under the alternative fuel substitution case and 35 percent lower in 2000
under the natural gas substitution case than the production for all purposes
under the base case in 2000. Nevertheless, coal production for all purposes
would be 59 percent higher in 2000 under the alternative fuel case and 21
percent higher in 2000 under the natural gas case than the production for all
265
-------
purposes in 1974. In comparison, coal production for all purposes would be 85
percent higher in 2000 under the base case than in 1974.°
Because coal production for all purposes should rise under all of the
fuel substitution and conservation scenarios, coal-mining employment also
would increase, although not as much as it would under the base case. Between
1970 and 2000, coal-mining employment would increase between 24 and 154
percent under the alternative fuel case, depending on the county; under the
base case, the increase would range from 35 to 222 percent. Under the natural
gas substitution case, the increase would range from 9 to 55 percent. In
general, therefore, since employment simply would rise at a slower rate under
the natural gas and conservation scenarios, no negative coal -mining employment
impacts should be felt. In fact, 131 of the 152 coal-producing counties in
the ORBES region would experience mining employment growth rates of 50 percent
or more under the alternative case. In comparison, 121 counties would
experience such rates under the natural gas case; 134 counties, under the base
case. However, if county-level population increases should exceed the
employment increases, negative county-level impacts that might have been
avoided under the coal-dominated scenarios might be experienced under the
substitution and conservation scenarios.
Certainly it appears that the coal demand associated with a substitution
of other fuels would not be as beneficial to some coal-mining areas as would
implementation of the coal -dominated scenarios. However, it should be noted
that positive benefits could accrue to urban areas, where alternative energy
systems would be developed and where a sufficient supply of labor exists and a
good supply of the services required is present.
Regional water quality impacts would be about the same under both the
fuel substitution and conservation scenarios and the coal -dominated
scenarios. 9 in fact, no changes would be registered in base case protection
levels and base case aquatic habitat impacts for any river under any of the
fuel substitution and conservation scenarios (see table 14-4). This across-
the-board similarity, as discussed in chapter 6, results primarily because of
high background concentrations alone or in conjunction with municipal and
industrial consumption. In comparison to these causes, power plant
Q
For coal production estimates, see Donald A. Blome, Coal Mine Siting
J&L the Ohio River Basin Energy Study (ORBES Phase II).
" For discussion, see Clara Leuthart and Hugh T. Spencer, Fish Resources
and. Aquatic Habitat Impact Assessment Methodology fsc th£ Ohio River Basin
Energy. Study, Region (ORBES Phase II).
266
-------
Table 14-4
Aquatic Habitat Impacts, Fuel Substitution and Conservation
Emphasis Scenarios, 7-Day-10-Year Low Flow,
Compared with Base Case Impacts, 7-Day-10-Year Low Flow
Natural Gas
Substitution
Nuclear Fuel
Substitution
Alternative Fuel
Substitution
Conservation
Emphasis
River
Allegheny
Water
Quality
Impact
Index
(Range:
0-100)
if changed
29
Number of
Units
Added or
Removed
from
Base Case
- 6
Water
Quality
Impact
Index
(Range:
0-100)
if changed
31
Number of
Units
Added or
Removed
from
Base Caset
- 6C
+ 1N
Water
Quality
Impact
Index
(Range:
0-100)
if changed
31
Number of
Units
Added or
Removed
from
Base Case
- 2
Water
Quality
Impact
Index
(Range:
0-100)
if changed
21
Number of
Units
Added or
Removed
from
Base Case
- 7
Beaver
30
- 3
30
- 3C
31
- 2
30
- 3
Big Muddy
Big Sandy
Cumberland
Great Miami
Green
Illinois
25
- 7
34
- 8C
+ 13N
25
- 3
25
o
Kanawha
Kaskaskia
Kentucky
Licking
Little Miami
Mississippi
23
+ 5N
- 1
- 1
Monongahela
42
+ 2N
- 1
- 1
Muskingum
39
- 2
39
- 2C
39
- 2
Ohio Main Stem
40
-47
- 7C
+ 3N
-23
40
-54
Rock
- 2
- 2C
+ 2N
- 2
Salt
Scioto
- 2
- 2C
- 2
- 2
Susquehanna
- 1
- 1C
- 1
Wabash
-2C
+2N
20
- 3
White
Whitewater
Note: Protection levels, overall aquatic habitat impacts (light, moderate, heavy, or drastic), and the cause of
those impacts would remain the same as under the base case on all rivers under the fuel substitution
and conservation scenarios.
'Background information not available; analysis not completed
tC = coal-fired unit; N = nuclear-fueled unit
267
-------
consumption would have only an incremental impact on most of the streams under
all scenarios.
Ihus, for example, both the base case and all four of the fuel
substitution and conservation scenarios are projected to result in the same
(heavy) aquatic habitat impacts on the Ohio River main stem in the year 2000
under 7-day-10-year low flow conditions. Ibis projection holds even though
widely different capacities are sited on the Ohio River main stem under these
scenarios (see table 14-4). Moreover, under all these scenarios, the major
cause of these heavy impacts is projected to be the high background levels
either alone or in conjunction with municipal and industrial consumption.
As also emphasized in chapter 6, it appears that, under the natural
phenomenon of 7-day-10-year low flow, such impacts probably could not be
avoided unless background concentrations are reduced. However, it also
appears unlikely that these concentrations will be reduced during the time
frame of this study since nonpoint and geochemical sources are primarily
responsible for the.high concentrations and are unlikely to be controlled by
the year 2000.
HEALTH. A regional substitution of other fuels for coal or a regional
emphasis on conservation would reduce the annual deaths and injuries
attributable to coal mining, coal processing, and coal transportation (see
table 14-5).10 Moreover, under the nuclear substitution case, there would be
an increase in the illnesses and deaths of uranium miners, workers exposed to
radiation, and the general public. National-level health impacts for the
nuclear fuel cycle were projected for the year 2000 in terms of impacts per
1000 megawatts per year of electrical generation.11 According to the rates
derived, the general population could experience 0.11 to 0.31 cancers per 1000
megawatts per year of nuclear-fueled generation, based on the assumption that
Plutonium is recycled. Occupational workers would experience the following
rates per 1000 megawatts generated: 1.4 to 1.7 cancers (on the assumption
that whole-body exposures are reduced by one-half); 1 trauma incidence (based
on the assumption that injury morbidity is reduced by one-half and that
silicosis is eliminated); and 0.5 chronic lung diseases.
10 See Shapiro and Sooky, Ohio River Basin Energy Study; Health Aspects.
Projections of national-level health impacts of nuclear-fueled
generation are given in Edward P. Radford, Impacts g& Human Health from the
Coal and Nuclear Fuel Cycles and Other Technologies Associated with Electric
Power Generation (ORBES Phase II). These projections are derived from the May
1979 draft report of the Advisory Committee on the Biological Effects of
Ionizing Radiation (BEIR Committee), U.S. National Academy of Sciences.
268
-------
Table 14-5
Health Impacts Related to Coal Mining, Processing, and
Transportation, Base Case, Fuel Substitution Scenarios, and
Conservation Emphasis Scenario, Year 2000
Natural Nuclear
Base Gas Fuel
Case Substitution Substitution
Coal Mining
Accidental deaths 75 54 53
Disabling injuries 5359 3860 3814
Nondisabling injuries 4435 3194 3156
Coal Processing
Accident deaths 966
Disabling injuries 472 340 336
Nondisabling injuries 1019 734 725
Coal Transportation
Vehicle miles traveled
Deaths 12 9 —
Injuries 26 19 —
Weight transported
Deaths 50 36 —
Injuries 123 88 -
Alternative
Fuel Conservation
Substitution Emphasis
65 50
4638 3513
3838 2907
7 6
408 309
882 668
10 -
23 -
44 _
107 -
Under present conditions, it is not possible to quantify the health
consequences of an accidental release of radioactivity. The primary factor
that would govern exposure of the surrounding population to radiation is
whether the primary containment vessel is breached.
14.4 Overview
NATURAL GAS SUBSTITUTION. Under the natural gas substitution case, utility
sulfur dioxide, particulate, and nitrogen oxide emissions and annual and
episodic concentrations of sulfur dioxide and sulfates would be slightly lower
than under the base case. The price of electricity under the two cases,
however, would be only slightly different in 1985 and nearly identical in
2000. Water quality and aquatic habitat impacts also would be similar under
both cases. On the other hand, the amount of land converted for electrical
generating facilities, the number of terrestrial ecosystem units assessed, and
the employment related to power plant construction and operation would be
about one-third lower under the natural gas case than under the base case.
269
-------
NUCLEAR FUEL SUBSTITUTION. Under the nuclear fuel substitution case, utility
sulfur dioxide, particulate, and nitrogen oxide emissions, land conversion for
electrical generating facilities, and the number of terrestrial ecosystem
units assessed would be slightly lower in 2000 than they would be under the
base case. Water quality and aquatic habitat impacts would be about the same
under both cases, while the health problems related to coal mining and coal
processing probably would be lower under the nuclear case than under the base
case. The possible health problems associated with nuclear-fueled generation
would increase under the nuclear substitution case.
ALTERNATIVE FUEL SUBSTITUTION. Under the alternative fuel substitution case,
regional land use conversion for electrical generating facilities and the
number of terrestrial ecosystem units assessed should be lower. Water quality
and employment impacts, however, would be about the same under both cases.
The health impacts associated with coal mining and coal processing would be
lower under the alternative fuel substitution case.
CONSERVATION EMPHASIS. Under the conservation emphasis case, regional utility
sulfur dioxide, particulate, and nitrogen oxide emissions would be lower than
the levels projected under the base case, as would pollution control costs and
capital costs. The conservation case also would entail the lowest land use
conversion for generating units and the lowest terrestrial ecosystem unit
assessment of all the cases analyzed. Finally, water quality impacts would be
about the same under both the conservation case and the base case, while the
conservation case would call for only about half of the labor required under
the base case for power plant construction and operation.
270
-------
15. Institutional Considerations:
Nuclear Energy, Alternative Fuels, and Conservation
In this chapter, the focus is on the institutional barriers and
opportunities that would be associated with the implementation of the nuclear
substitution, alternative fuel substitution, and conservation emphasis
scenarios.1 The impacts of these scenarios in the Ohio River Basin Energy
Study (ORBES) region are discussed in chapter 14.
As emphasized in previous chapters, neither conservation nor any of the
fuel substitutions for coal is considered likely to contribute substantially
to regional or national energy supplies, at least by the end of this century.
However, the conservation case is the most plausible option among the three;
conservation already is making inroads in the region and the nation. The
conservation emphasis case would require improvements in end-use efficiencies
and changes in lifestyle, but no radically new technologies. On the other
hand, especially in the coal-dominated ORBES region, a major increase in the
proportion of electricity generated by nuclear fuels is not expected to occur.
This is due in large measure to political constraints. In addition, a major
shift to alternative fuels would require more extensive technological and
institutional changes than are considered possible in the next 20 years.
15.1 Nuclear Energy
Even before the nuclear accident at the Three Mile Island plant near
Harrisburg, Pennsylvania, in March 1979, it was considered extremely unlikely
that a large number of additional nuclear-fueled generating units would come
on-line in the region, permitting nuclear fuel to penetrate the present coal
emphasis to any major extent.2 However, many nuclear energy supporters around
the nation still contend that nuclear-fueled units should be constructed even
in areas where coal is plentiful. Nevertheless, at present three of the six
ORBES states seem to be placing institutional barriers on any greater reliance
on this form of electrical generation. In Kentucky and West Virginia, both
Existing institutional mechanisms would be adequate to handle a major
increase in the use of natural gas. Therefore, implementation of the natural
gas substitution scenario is not considered in this chapter.
2
Three Mile Island is close to but not within the ORBES region.
271
-------
state and local governments oppose nuclear energy strongly; no nuclear-fueled
plants are located or planned in either state. The basis for the opposition
appears to be both fear of nuclear power and the concern that it would make
coal less attractive as a fuel. In addition, since it occurred in 1979, the
Three Mile Island accident has appeared to intensify opposition by
Pennsylvania residents to the construction of additional nuclear-fueled
plants.
The opposition to nuclear power, which among the ORBES states is
particularly apparent in Kentucky, Pennsylvania, and West Virginia, arises
from a number of factors, including the doctrine of federal preemption,
increased concern over the health effects of low- and high-level radiation,
and growing dissatisfaction with the benefits of nuclear energy.
PREEMPTION. The central question in relation to the preemption doctrine and
the use of nuclear fuels is whether a state may legally pass legislation to
control the placement of nuclear facilities or the transportation or storage
of nuclear materials within its borders.
In 1972, the U.S. Supreme Court held (Northern States Power Co. v.
Minnesota. 282 U.S. 83*0 that the Atomic Energy Act gave the U.S. Atomic
Energy Commission (now the Nuclear Regulatory Commission) the exclusive
authority to regulate radioactive waste releases so as to preclude any
regulatory authority by the state of Minnesota. At present, however, many
legal scholars would argue that, because of an apparent shift in the Court's
views and the development of a complex body of law on intergovernmental
nuclear issues and on other environmental and energy issues since 1972, the
Court would not summarily affirm that decision.
A few states in the nation have attempted to prohibit the further
development of nuclear energy within their boundaries by placing nuclear
moratorium initiatives on the ballot, but the constitutionality of such
initiatives is uncertain. States also have attempted to circumvent the
federal preemptive doctrine by turning to forms of indirect regulation through
such traditional state powers as zoning, site certificate requirements, and
economic regulation of all sales from electrical generators (including
nuclear-fueled units). Perhaps the most important point to emphasize is the
possibility that state challenges may so engulf the industry in complex
intergovernmental legal problems that the use of nuclear fuels for electrical
generation will not increase significantly.
^ For discussion, see Boyd R. Keenan, Ohio Basin Interstate Energy
Options: Constraints of Federalism (ORBES Phase II).
272
-------
Nuclear Waste Disposal. The problem of nuclear ^waste disposal highlights the
issues that surround the preemption doctrine. . By their nature, nuclear
wastes probably will remain at their disposal sites forever, at least in terms
of human time. Moreover, even if no additional nuclear-fueled generating
units are built, other activities such as military defense operations and
medical diagnostic and treatment processes will continue to produce
radioactive wastes. Finally, waste disposal sites appear to bring no
advantages to the local community to offset their inherent dangers, except a
relatively small number of jobs.
The Atomic Energy Act established a regulatory scheme that gave all
authority over the disposal and storage of nuclear wastes to the Atomic Energy
Commission and, subsequently, the Nuclear Regulatory Commission (NRC). In
1959, amendments to the Atomic Energy Act gave the states limited control over
the disposition of certain nuclear wastes through individual agreements
between a state and the federal government. However, regulations do not allow
an "agreement" state to assume regulatory authority for the disposal of high-
level wastes, such as spent fuel rods. In addition, agreement states do not
have regulatory authority over either the storage and handling of radioactive
wastes at a nuclear generating facility site or the discharge of effluents
from the site.
The provisions of the Atomic Energy Act were addressed further in
February 1980, when the President announced a "comprehensive plan for burying
the nation's radioactive nuclear wastes" at permanent sites by the mid-1990s.
Some utilities already are running out of temporary storage space near
reactors. Thus, the President asked Congress to authorize, in the interim,
the building or purchase of one or more "away-from-reactor" sites where
utilities could store spent fuel on a temporary basis for up to 30 years. It
is hoped that at least one such site will be ready for use by 1985 or 1986.
In seeking to avoid the kind of future institutional barriers discussed
in this section, the President announced that he intended to create by
executive order a council of governors and other officials. The council's
charge would be to overcome the local problem of disposal site selection.
However, a state would not have the power to veto a site once the
"consultation and concurrence" process is finished. Debate within Congress
and elsewhere over what is meant by "consultation and concurrence" is a
further illustration of the conflict over federal preemption and raises
additional questions on whether the Supreme Court will uphold the doctrine.
This debate also points up the improbability of an increasing reliance on
nuclear fuel.
See Keenan, Ohio Basin Interstate Energy Options.
273
-------
The administration's announcement that it is seeking to build or buy one
or more interim sites for storing spent fuel rods touched off controversy in
the Illinois portion of the ORBES region; Illinois was mentioned as one of
three states from which the site would be selected. State political leaders
expressed concern that the President already had decided to deposit fuel rods
from throughout the United States and several foreign countries at a facility
in Morris, Illinois, 65 miles southwest of Chicago, in the extreme northern
portion of the ORBES region. Depending on the final interpretation of
"consultation and concurrence" in light of the Atomic Energy Act provisions
related to waste disposal, a decision to acquire the Morris site could be made
totally at the national level.
It is clear that any greater reliance on nuclear power in the ORBES
region and elsewhere would depend on reforms in the management of nuclear
waste that are acceptable to the sectors involved, including the general
public, the utility industry, and federal, state, and local governments.
However, reform proposals now being offered are contradictory and not likely
to result in consensus. For example, a recent NRC task force specifically
rejected the desirability of allowing states to regulate nuclear wastes. It
recommended that the federal government take over and establish a perpetual
care program. On the other hand, members of Congress have urged
reconsideration of whether preemption should apply to nuclear waste management
and disposal.
In the abstract, most Americans probably would agree that federal action
to preempt local land use control decisions from state and local governments,
particularly when the land use might involve serious health risks, is
undesirable and a break from traditional values associated with the federal
system. However, most of the public probably also would agree that decisions
on defense, international trade, and major economic matters, and now even
major energy decisions, are best made at the national level. Thus, it may be
necessary to determine whether the nuclear facility siting and regulation
question is primarily one of local land use and health hazard control or
primarily one of defense, trade, economics, and energy. However, so many
sensitivities and sub-issues are associated with this choice that it probably
will not be made soon. If the courts continue to construe the Atomic Energy
Act as giving almost exclusive control over nuclear facilities to the federal
government, then the question remains with Congress. The resolution will
depend on the strength of states' rights feelings, public fears of nuclear
hazards, the dimensions of the energy crisis, international trade, the
stability of the dollar, and domestic economics.
COMPARATIVE COAL AND NUCLEAR COSTS. A second factor that could influence the
future of nuclear power is pointed up by an ORBES inquiry into the comparative
costs and associated electricity prices for coal-fired generation compared
274
-------
with nuclear-fueled generation. One key finding is that, under the current
fiscal and regulatory schemes prevalent in the ORBES region, coal-fired units
have a slight cost advantage over nuclear-fueled units. Perhaps even more
significant for future energy policy and development is another key finding:
without present federal tax and other fiscal policies that favor capital-
intensive production (including the nuclear industry), the cost advantage of
coal-fired over nuclear-fueled generation would be substantially greater.
However, regulatory environments, tax and subsidy provisions, and fuel and
other costs vary across states as well as within a given state. Therefore, no
set of results for a particular area necessarily applies to the region in
general.
Representative utilities in southern Indiana, an area thought to
reasonably exemplify conditions throughout the ORBES region, were chosen for
the analysis. The study focused on the choice by the utility between coal-
fired and nuclear-fueled electrical generating capacity in the context of
specified economic tax and regulatory conditions. Nuclear-fueled capacity has
been widely believed to be less costly than coal-fired capacity for electric
utilities as well as for the consumer of electrical energy. (Standard
industry studies suggest that coal-fired electrical generation is about 16 to
20 percent more expensive than nuclear generation.) This conclusion was
examined in the representative portion of the study region.
Two primary methods of electric pricing were considered: (1) the
constant real price, which escalates base price for overall inflation rates,
and (2) the rate base price, which is determined by conventional regulatory
methods where rate base return to capital and fuel and operating expenses
figure into price determination. Using constant real price, both nuclear-
fueled and coal-fired facility costs would rise by approximately 7 percent per
year, suggesting real 1988 dollar costs that are quite similar: 7.33 cents
per kilowatt hour for nuclear and 6.3 cents per kilowatt hour for coal. In
1977 dollars, nuclear and coal facility costs would be 3.5 cents per kilowatt
hour and '3.0 cents per kilowatt hour, respectively. Therefore, with existing
subsidies, the conventional after-tax costs to utilities are higher for
nuclear-fueled than for coal-fired generating units. Nuclear capacity, then,
is not less costly than coal in this representative case.
Tax Subsidies. An important consideration when assessing utility costs and
electric prices is the presence of tax subsidies at both the state and the
federal levels, which affect comparative costs as well as prices of nuclear-
See Duane Chapman, Kathleen Cole, and Michael Slott, Energy Production
and Residential Heating: Taxation, Subsidies, and Comparative Costs (ORBES
Phase II).
275
-------
fueled and coal-fired generation. If adjustments are made in the tax
structure so as to remove major deductions and credits (which constitute
subsidies) from the corporate income tax structure, nuclear costs rise to 11
cents per kilowatt hour, compared with coal costs of 7.6 cents per kilowatt
hour (1988 dollars). Thus, within the present corporate income tax structure,
nuclear-generated electricity is slightly more expensive than coal-generated
electricity. When tax subsidies are excluded, however, nuclear power appears
to be considerably more expensive. In particular, the subsidy received by a
representative nuclear unit is almost three times greater than that received
by a representative coal unit (for a 1000 megawatt unit, in 1988 dollars, $201
million and $68 million, respectively). The explanation for the magnitude of
this difference in tax subsidies lies in the different capital intensities of
the two processes. In 1988 dollars, the representative nuclear unit has a
rate base investment of $3238 per kilowatt at the beginning of operation in
1988. The representative coal unit has a rate base investment of $1364 per
kilowatt in 1988 dollars at the beginning of its operation in 1984.
Utility planning also is influenced by the timing of net income tax
liability and flow of funds. Particular patterns with respect to time may
encourage or discourage the early retirement of generating units. Using the
rate base pricing method, which simulates actual regulatory behavior, the
overall effect of the interaction of regulatory procedures, tax provisions,
and net income accounting is to create a financial incentive for premature
construction of new plants as well as premature retirement of old ones.
Inflation and Interest Rates. General inflation and interest rates also are
important when considering subsidies to nuclear-fueled and coal-fired units.
These rates also are important for the price of electricity. All of the above
conclusions are based on a 7 percent inflation rate and a 9.5 percent interest
rate. Because of the difference in capital intensity between nuclear-fueled
and coal-fired units, higher inflation and interest rates could change these
conclusions. Assuming an inflation rate of 12 percent and an interest rate of
14.5 percent, and including existing tax subsidies, nuclear-fueled generating
costs in 1988 dollars would be 11.1 cents per kilowatt hour, while coal-fired
generating costs would be 9.3 cents per kilowatt hour. Without subsidies,
nuclear costs would be 18.9 cents per kilowatt hour; coal costs, 11.3 cents
per kilowatt hour. The tax subsidy on nuclear-fueled generation, then, would
amount to 7.8 cents per kilowatt hour; that on coal-fired generation, to 2
cents per kilowatt, hour. Thus, the slight advantage of coal-generated
electricity rises with higher inflation and interest rates.
Research and Development Subsidies. Among the major federal subsidies of
nuclear-fueled generation is extensive government research and development in
the nuclear field. These activities have been significant in the past 40
years and have far exceeded public funds devoted to research on coal and on
coal-fired electrical generating processes during the period. Although
276
-------
national defense has been the principal consideration of the federal
government in subsidizing the nuclear research,.the resulting information and
innovations have tended to decrease the costs and raise the profits of private
nuclear developers.
Price-Anderson Act. Another federal subsidy that should be mentioned is
provided by the Price-Anderson Act, which was passed by Congress in 1957 to
limit the aggregate liability for a single "nuclear incident" to $560 million.
The federal government is directed to subsidize the liability insurance
premiums of private nuclear developers, a subsidy not extended to coal
producers and their utility consumers. The announced purpose of the subsidy
under the act, which applies to insurance coverage over $1 million, is to
encourage nuclear development.
15.2 Alternative Fuels
In this section, the emphasis is on institutional issues associated with
the use of direct and indirect solar energy processes for electrical
generation: solar energy (section 15.2.1), wind energy (15.2.2), and biomass
(section 15.2.3). The processes themselves are described briefly in chapter
13.
15.2.1 Solar Energy
The widespread adoption of solar energy as a substitution fuel for coal
would have major effects in the ORBES region. Although much of the necessary
technology is available or close to available (see chapter 13), a series of
economic and institutional barriers would have to be overcome. The
institutional issues associated with the introduction of solar energy can be
divided into three groups: legal and physical access to sunlight, integration
with existing energy infrastructures and institutions, and government program
implementation and management.
SOLAR ACCESS. Problems surrounding legal and physical access to sunlight
constitute a significant barrier to the widespread introduction of solar
energy. This barrier, which stems from the basic orientation of real
property law toward the development of land, confronts almost any potential
solar energy system investor. In general, the investor is not guaranteed
permanent access to sunlight. Unless assured of such access, the investor
will be reluctant to install a solar system, even though tax incentives and
" For a complete discussion of access to sunlight, see Vincent P. Cardi,
Larry Harless, and Thomas Sweet, Legal and Institutional Issues in the Ohio
River Basin Energy Study Region (ORBES Phase II).
277
-------
the costs of other energy sources do much to compensate for the large initial
investment required for solar equipment. Thus, the investor must be concerned
not only with the unique climatic and geographic factors that influence site
location, but also with what is or will be located on adjacent property.
As elsewhere in the United States, the owner of a solar collector in the
six ORBES states usually is without legal remedy when his access to sunlight
is blocked. This situation exists because decisions based on U.S. common law
have not established a legal right to access to sunlight. The basis is an
ancient doctrine that allows a person to build any structure on land he owns;
legally nothing can be done to prevent it, whether the structure blocks
sunlight or not.
Through the centuries, however, slight modifications have been made to
this absolute right. Under the doctrine of ancient lights, promulgated in
1610, an English court held that if a landowner has received light from across
a neighbor's land for a certain period of time, the right to enjoy this light
continues. This doctrine was rejected early in American history on the
grounds that it could not be applied in the growing cities and that its
application would hinder the development of property.
Nuisance Law. Application of the nuisance concept is a possible way in which
legal access to light might be ensured. To prove a private nuisance, or a
"nontresspatory invasion of another's use and interest in the private use and
enjoyment of land," one must show (1) intentional or negligent interference
with the use and enjoyment of property, (2) the unreasonableness of such
interference, and (3) substantial harm. The major issue in a private nuisance
action involving solar access may be the reasonableness of the interference.
In the past, courts have ruled for land development over energy development,
but some legal scholars feel that a case can be made for energy development to
take precedence. However, the use of private nuisance as a means of ensuring
access to sunlight has been criticized severely; some claim that the very
nature of a private nuisance action, balancing competing interests of
landowners, hinders its effectiveness.
In contrast to a private nuisance, a public nuisance affects an interest
common to the general public, rather than an interest of only one or a few
individuals. Thus, for an interference with solar access to be declared a
public nuisance and a valid area, for exercise of the police power of the
state, it actually must affect the public interest. The present energy
situation might mandate a public interest in the development of alternative
energy sources, such as residential solar energy systems. Perhaps it could be
argued successfully that the preservation of the community is at stake in
providing alternative sources of energy and hence that alternative energy
development falls within the guidelines of the police power. Since shadows
were not a public nuisance under the common law, enactment of legislation
278
-------
would be necessary to have interference with access to sunlight legally
defined as a public nuisance. Most state legislatures appear unwilling to
take this step; one exception is in California (Cal. Pub. Res. CodeT sec.
25982 (Deering)).
Zoning. The police power of the state as expressed in zoning also could be
applied to solar access. The legal power to zone, which is derived from the
police power and usually is delegated to local governments, exists in all 50
states. The purpose of a solar zoning ordinance, of course, would be to
encourage utilization of solar energy for the heating and cooling of buildings
and to reduce consumption of and dependence on fossil fuels. Unquestionably
this purpose relates to the general welfare and health of people and the
state. It follows, then, that the enactment of such an ordinance could be a
legitimate exercise of the police power.
Zoning can take the external benefits of solar energy into account, so
that "society as a whole pays for the higher quality environment made possible
by individual investments in solar energy devices. The main advantage of
zoning would be uniformity of application: the burden of bringing suit is not
on the individual user, and an immediate right to solar access is vested in
each individual. A major disadvantage of this approach would be the political
machinations that are inherent in local zoning schemes. Present zoning
ordinances and building codes in themselves also present problems, because in
many cases they impede private investment in solar energy installations. For
example, solar permits have been denied for failure to comply with ordinances
that restrict the total area of mechanical equipment to a certain percentage
of the area of the supporting roof.
Solar Easements and Restrictive Covenants. Two other approaches, the solar
easement and the restrictive covenant, also should be noted. The solar
easement is a variation of the property easement, which is an interest in land
that is in the possession of another party and which gives the owner of the
easement an interest in or limited enjoyment of that land. Most simply, the
solar easement usually obtained by a solar investor is a device to gain
airspace above the property of a neighbor. However, solar easements are
complicated and must be expressed clearly in legal terms; they cannot be
created by implication. Costs could be the major problem with the easement
approach. To ensure total solar access, easements would have to be obtained
over all property that could possibly be developed so as to block access.
Thus, the cost of obtaining these easements might be greater than the value of
switching to a solar energy system. This is almost certain to be the case in
densely populated areas. Also, even though a potential seller of an easement
may not plan to construct high buildings or plant trees, he may be reluctant
to encumber his property for the future except at a relatively high price.
Most legal commentators appear to believe that solar easements alone would be
inadequate to ensure continuous access to sunlight, particularly in cities,
where airspace is so valuable.
279
-------
The restrictive covenant often is used by property developers to assure
homogeneity and aesthetic qualities deemed necessary to attract investors.
Many covenants are used to control the changes that the purchaser of a
developed lot can make in his property after buying it. (Although covenants
can be used to protect solar access, they also can prevent installation of a
solar collector on aesthetic grounds.) A "solar covenant" would assure the
solar investor that no structure would block the flow of sunshine across
adjacent property and shadow the collector.
The transition to protection of solar access through restrictive
covenants would not seem to be particularly difficult. The use of such
covenants to prevent solar collector installation was held to be invalid in a
recent California case (Krave v. Old Orchard Association, no. C209453,
L.A.S.Ct., March 1, 1979). Recognizing a statewide policy to conserve
nonrenewable fossil fuels and encourage the use of alternative energy sources,
the court held restrictive covenants to be "invalid and unenforceable to the
extent that they prohibit the rooftop installation of solar collector plates."
Solar covenants could be important tools in the development of solar energy
use in new developments, but they would provide no remedy to the solar
investor in an existing neighborhood.
State Legislation. Finally, as in California, Colorado, and Oregon, state
legislatures could act on the solar access measures described above.7 Only
two ORBES states, Illinois and Ohio, have enacted such legislation; both laws
are limited. The Illinois Comprehensive Solar Energy Act (111. Ann. Stat.,
ch. 96-1/2, sec. 7301 et seq.), which became effective in 1977, declares that
it is in the public interest to define solar energy systems, demonstrate solar
energy feasibility, apply incentives for using solar energy, educate the
public on solar feasibility, study solar energy applications, and coordinate
governmental programs affecting solar energy. More important, it creates a
"solar skyspace easement," a concept introduced in this piece of legislation,
but a rather indirect approach to the problem. The statute fails to provide
for (1) tracing collectors and greenhouses that can use sunlight at times of
day other than those specified in the act, (2) specific conditions where an
easement is to be granted, and (3) tax incentives or exemptions.
Nevertheless, it is a step toward ensuring solar access. The Ohio statute,
which became effective in 1979, recognizes solar easements and prescribes
their contents (Ohio Rev. Code, sees. 1551.20, 4933-32, 5301.63, and 5709-53).
However, this law does little more than recognize solar easements. It makes
no attempt to mandate them or to define them further.
7 For a summary of solar access laws, see "Access to Sunlight: the
Legislative Response," Solar Law Reporter 1 (1979):110-21.
280
-------
INTEGRATION WITH EXISTING SYSTEMS. In addition to solar access, the
integration of solar energy systems into existing energy infrastructures and
institutions presents a series of legal and institutional issues. Among the
problem areas are (1) the rates paid by utilities for power sold to the grid
as well as for back-up power and other services provided to on-site
generators, (2) the legal status of on-site generators, (3; the financing and
ownership of dispersed capacity, and (4) utility management issues and
perceived risks.
Utility Interconnections. Prior to the National Energy Act of 1978, there
were three major obstacles faced by on-site solar electricity generators
seeking to establish interconnected operation with a utility. First,
utilities usually were not required to purchase electric output at an
appropriate rate. Second, some utilities charged extremely high rates for
back-up service to on-site generators; the reasoning was that this service
would increase capacity reserve requirements and thus the incremental cost of
providing power to all customers. Third, an on-site generator that provided
electricity to a utility grid, or sold any of the excess power generated to
anyone else (such as a neighborhood association or cooperative apartment
selling to its members or residents), ran the risk of being considered an
electric utility and, as such, subject to state and federal regulation.
Sections 201 and 210 of the Public Utility Regulatory Policies Act
(PURPA) of 1978 (16 U.S.C. 2601 et seq.), part of the National Energy Act, are
designed to remove these obstacles.8 Under section 210 of PURPA, each
electric utility is required to offer to purchase available electric energy
from on-site generators that obtain qualifying status under section 201 of the
act. For such purposes, electric utilities are required to pay rates that are
just and reasonable to the ratepayers of the utility, that are in the public
interest, and that do not discriminate against on-site generators. These
rates must reflect the cost that the purchasing utility can avoid as a result
of obtaining energy and capacity from these sources rather than generating an
equivalent amount of energy itself or purchasing the energy or capacity from
other suppliers. In addition, utilities must provide certain other types of
service that may be requested by on-site generators to supplement or back up
their own facilities. Finally, the Federal Energy Regulatory Commission can
exempt on-site generators from state regulation regarding utility rates and
financial organization, from federal regulation under the Federal Power Act
(other than licensing under Part I), and from the Public Utility Holding
Company Act.
See Federal Register 45 (February 25, 1980):12214.
281
-------
Financing and Ownership. A number of issues have been raised about the
financing and ownership of dispersed electric generating capacity, including
solar systems.9 On the one hand, it is argued that the potential for unfair
competition supports a complete prohibition of utility involvement in such
matters as financing and supplying on-site generators. Those who support this
view argue that the substantial utility investment in conventional generating
equipment will make it in their interest to restrict competitive energy
sources rather than promote them. In addition, utilities could use their
financial strength to drive smaller rivals out of business. Even if utilities
actively seek to use on-site capacity resources rather than stifle them,
business advantages from dealing with utilities could make it too difficult
for other entities to compete or for emerging technologies to gain a place in
the market. It is exactly these concerns related to unfair competition that
led to the prohibition in the National Energy Conservation Policy Act (NECPA)
(P.L. 95-619, codified in sections of titles 12, 15, 23, and 42 of the U.S.
Code) of utility involvement in supplying, installing, or financing
residential energy conservation measures, including solar and wind generators.
Individual utilities may get a waiver from this NECPA prohibition if they can
demonstrate that "fair and reasonable prices and rates of interest would be
charged. . . and that such activities would not be inconsistent with the
prevention of unfair methods of competition and the prevention of unfair or
deceptive acts or practices" (sec. 216).
On the other hand, it has been argued that homeowners and others
interested in on-site generation do not have the access to capital markets and
financing mechanisms that utilities do, and that without utility participation
initial investment costs will be prohibitive. Moreover, many utilities now
desire to diversify their capacity and those that want to enter the market
would not be able to do so. If the NEPCA prohibition did not exist, utilities
would have to raise several times less capital than for central station
capacity. This money could be turned over at least twice as quickly. Thus,
the utilities would retain their attractive rate of return on capital.10
However, utilities would have to be allowed to include the financing,
supplying, and installing of on-site generation equipment in their rate base.
It is probable that the close scrutiny of utility promotional and other
activities that has been commonplace since the 1960s would provide sufficient
checks against unfair competition or stifling of the expansion of on-site
generation.
9 For discussion, see William H. Lawrence and John H. Minan, "The
Competitive Aspects of Utility Participation in Solar Development," Indiana
Law Journal 54 (1978-79):229.
10 Amory B. Lovins, "Energy Strategy: The Road Not Taken?," Foreign
Affairs (October 1976), pp. 87-88.
282
-------
Utility Management. Another problem related to integration of on-site
generators with existing energy systems, mainly utilities, is that current
utility management and other infrastructures are designed around central
station capacity. Management techniques would have to change to accommodate a
transition to dispersed capacity, including perception of risks by management.
GOVERNMENT PROGRAMS. The final set of institutional issues related to solar
energy has to do with the management of government solar programs. A recent
study done for Congress has identified a number of deficiencies within the
Department of Energy's Conservation and Solar Energy Programs (CSE) that are
retarding the development and deployment of solar energy.11 First, the
internal DOE organizational structure, including the responsibility for solar
energy, changes so frequently that jurisdictional disputes and uncertainty
seriously detract from the real business of CSE. Second, according to the
study, CSE lacks a clear vision of where it is going and how it will get
there. Evidently, this deficiency results from a lack of clear direction from
DOE management and the lack of a strong analytic capability within CSE. There
is a pervasive belief within and outside of DOE that senior agency management
has been inadequate as well as transient. This is compounded by long delays
(sometimes up to 18 months) in DOE processing of CSE requests for hiring new
staff and letting contracts. Another conclusion is that there could be
improved coordination between CSE and other federal agencies responsible for
solar energy as well as with state and local governments.
State and local programs designed to promote solar energy vary widely.
Some, such as those of the state of California and its cities of Los Angeles
and San Diego, either mandate or actively encourage the use of solar in new
construction and in retrofitting activities. These programs include low-
interest loans, zoning codes that require solar hot water in all new houses,
active information dissemination and technical assistance, and other
aggressive measures.
15.2.2 Wind Energy Conversion Systems
Wind energy conversion systems (WECS) have been in use for many
centuries, traditionally for irrigation and milling operations. As long as
400 years ago, windmills in the Netherlands were used in the production of
paper and the processing of timber. Since the early 1900s, wind energy
systems also have been used to generate electric power. Prior to World War
II, over 6 million small windmills had been built in the United States; most
U.S. Congress, Office of Technology Assessment, Conservation and Solar
Energy Programs of the Department of Energy; A Critique (OTA-E-120, June
1980).
283
-------
were used in rural areas to pump water and produce electricity. In general,
these were small systems, ranging in output from a few watts to a few
kilowatts. The notable exception was the 1.25 megawatt Smith-Putnam wind
turbine located at Grandpa's Knob, Vermont, which fed power into the local
grid from 1943 until April 1945. A number of intermediate-sized units were
tested in Europe from the 1930s through the 1950s. However, the vast majority
of windmills in the United States have fallen into disuse due to the advent of
cheap fossil fuels and the provision of inexpensive and reliable power from
the rural electrification program. Recently, as oil prices have climbed and
the environmental risks of nuclear and fossil fuels have been perceived,
interest in wind energy has risen sharply.
Large-scale systems (over 1 megawatt) are expected to compete first with
utilities that depend heavily on oil and also in areas with a large
hydroelectric capability, where the conventional system can serve as a backup.
As a result of the cost reductions for wind turbines through mass production
and advanced design, the use of WECS is expected to increase.
DOE has established an energy cost goal of 3 to 4 cents per kilowatt hour
(1980 dollars) for both small and large WECS. This goal is a levelized life-
cycle energy cost. It is anticipated that an initial market will begin to
form when the cost is about 4 to 7 cents per kilowatt hour, a level sufficient
to support the production of early systems in moderate quantities.
As with other solar and dispersed electric energy systems, the widespread
introduction of WECS raises a number of legal and institutional issues. These
include financing, siting, tort liability, and environmental problems.12
Issues related to interconnection with utilities are discussed in section
15.2.1.
FINANCING. Although cost effective over the long run in most circumstances,
present wind energy technologies, both small- and large-scale, have relatively
high initial investment costs. This problem is heightened because WECS are a
new technology, and the financial institutions that control most of the money
used for such projects tend to be conservative in backing new technologies.
Therefore, financial incentives from the government and the private sector
might accelerate the introduction of WECS. Issues related to utility
financing are discussed in section 15.2.1.
12 See Lynde Coit, Wind Energy: Legal Issues and Institutional Barriers
(SERI/TR-62-241, June 1979), and Cardi, Harless, and Sweet, Legal and
Institutional Issues.
284
-------
A number of states provide income tax deductions and credits that apply
to wind systems. Under the Energy Tax Act of 1978 (P.L. 95-618), part of the
National Energy Act, the federal government allows tax credits for homeowners
and businesses. The residential energy credit provided under Title I of the
Energy Tax Act applies to "wind energy for nonbusiness residential purposes,"
while Title II provides a business investment tax credit "to encourage new
energy technology." The availability of these credits should spur homeowners,
utilities, and industry to consider wind energy generation.
ZONING AND BUILDING CODES. In addition to access to wind, the siting of WECS
raises issues related to zoning and building codes. As discussed in section
15.2.1, zoning is the most pervasive form of land use control in the United
States. All states have enabling legislation for zoning, and most communities
with more than 5000 inhabitants have enacted zoning ordinances. The typical
ordinance provides for areas restricted to residential, commercial, and
general industrial uses. Because almost any use is permitted in an industrial
area, WECS should meet no zoning problems there. It is in residential and
coranercial areas that problems are most likely to arise. The most probable
challenges to wind machines will be on aesthetic grounds, or because they
violate height restrictions, or because they are not an "approved use" for the
area. However, the main zoning issue for small machines is public acceptance;
in the absence of objections by homeowners and tenants, variances may be
obtained from other provisions that limit their use. Larger WECS should
encounter fewer problems with zoning ordinances, primarily because they are
more likely to be sited in rural areas. However, if the total capacity of all
the machines at any one site is greater than 80 megawatts, the siting
provisions of state public utility commissions may apply.
WECS in urban areas also will be subject to building code requirements.
At present, the primary obstacle is the lack of a general consensus on what a
wind-oriented building code should be, due to the lack of data on wind turbine
performance under a variety of conditions. A set of interim performance
standards could be developed that emphasize fire safety, structural soundness
of the tower, 'ability to withstand the strongest foreseeable wind, and
conformity with standards for electrical work. In the absence of state action
in this area, it is likely that wind-oriented building codes will be preempted
by the federal government, as is the case for mobile homes and energy
performance standards for buildings.
WIND ACCESS. The legal issue surrounding guaranteed access to the wind does
not involve conflicts with existing laws, as in zoning, but rather the lack of
any legal doctrine assuring a wind machine owner continued access to unimpeded
wind flow over his property. The problem is significant because wind power
varies directly with the cube of velocity. This means that by reducing the
wind speed by one-half, the energy that can be generated is reduced to one-
eighth its original amount. Even a seemingly slight reduction in wind speed
285
-------
from 10 miles to 8 miles an hour results in a 50 percent reduction from the
energy originally available. This reduction may be sufficient to shut some
machines down entirely, depending on the "kick-in" speed, or to make them no
longer cost effective. Large-scale WECS developers probably will want to
locate in remote areas far from any obstructions and to purchase sufficient
land to guarantee their wind flow. However, purchase of surrounding land may
be prohibitively expensive for small users and may be impossible in urban
areas.
Snail users may be able to acquire negative easements over the property
of adjoining landowners, similar to the easements for solar access discussed
in section 15.2.1. With a negative eastment, the WECS owner could purchase
the legal right to prevent the adjoining landowners from obstructing wind
flow. However, these rights probably would have to be purchased in several
directions, and where they reduce the development potential of the adjoining
land, and thus its value, they also could be extremely expensive. It is more
likely that statutory rights to wind access would be created by legislatures,
but the form of such legislation is problematic in most developed areas.
TORT LIABILITY. The issue of tort liability related to wind machines is
essentially a question of their safety. WECS being considered today bear
little resemblance to the small, innocuous rural windmills common prior to
World War II. Today, machines up to 750 feet high are being proposed, and
WECS with "wingspans" of 300 feet are under construction. Understandably,
there is concern about the safety of these large systems. In 19^5, the
Grandpa's Knob machine threw a blade weighing eight tons a distance of 750
feet, the result of a design defect that had not been corrected due to the
shortage of steel during World War II. Under "worst case" conditions, a blade
could land over 1500 feet from the supporting tower. Another concern is the
collapse of a tower. A third situation that could give rise to tort liability
is if a workman were injured or killed while working on utility lines during a
time when power was shut down to allow repairs, but the WECS continued to feed
electricity into the grid.
Ultimately these issues will be resolved by technological, improvements in
wind turbine systems. During power outages, synchronous inverters will
disconnect a WECS automatically. Towers will be reinforced to allow for the
stresses placed on them by long and heavy rotors. Moreover, the machines
built today all feather their blades in high winds and shut down completely
when the wind reaches a certain speed, so that even unusually high winds
should not pose problems. In adddtion, the National Aeronautic and Space
Administration (NASA) is investigating "fail-safe" systems that would prevent
a thrown blade from traveling significant distances from the tower.
However, until these technical fixes are mandated by industry standards,
liability will remain a question for manufacturers because they may be liable
286
-------
under consumer products liability law; for potential owners because they may
not be able to get insurance; and for neighbors of owners because they are
concerned about their property and personal safety. In the case of
manufacturing or installation defects, it is likely that the manufacturer will
be held liable under either strict liability or negligence. The American Wind
Energy Association is concerned that these doctrines might frighten
prospective manufacturers and retailers out of the market, and the association
is lobbying for a federally imposed limit on liability similar to that in the
Price-Anderson Act for nuclear plants (see section 15.1). An alternative
solution might be some form of government-funded product liability insurance
for WECS manufacturers, retailers, and users whose products meet certain
standards. On the other hand, if standards are developed, conforming machines
are publicized widely, and private sector insurance becomes available for
these machines, it is unlikely that a legislative approach will be necessary.
ENVIRONMENTAL QUESTIONS. Finally, WECS are not free from environmental
problems. The rotating metal blades can produce video distortion of
television reception, especially on the upper ultrahigh frequency channels and
where the wind machine is directly between the broadcaster and the receiving
antenna. This distortion can be avoided in part by the use of nonmetal blades
or by proper siting. Courts have held that landowners have no right to
uninterrupted television reception (People ex rel. Hoogasian v. Sears, Roebuck
Co., 52 I11.2d 301, 28? N.E.2d 677 (1972), cert. den. 409 U.S. 1001). With
large arrays of wind machines, such as those proposed for utility use, the
owner could construct a relay station for the radio waves and thus circumvent
the problem. Although the possibility of weather modification and noise
problems from WECS has been raised, these problems are not expected to occur,
or, in the case of noise, are subject to simple technical fixes. Similarly,
most migratory birds fly too high to be killed by rotating blades, and bird
kills probably will be a problem only when endangered species are involved,
which is a siting issue. The most significant adverse environmental impact of
WECS is likely to be aesthetics. Without legislative or judicial intervention
in the public interest to promote renewable energy sources, aesthetic
objections alone may be sufficient to keep WECS out of zoned areas. However,
if WECS are sited so as to minimize their adverse aesthetic impact, they
probably will be accepted in the public interest, as power lines and other
similar structures have been.
With the exception of financing and utility integration issues, most of
the problems discussed above are likely to be minimal once the public becomes
used to WECS and realizes their value as a domestic, renewable energy source.
15.2.3 Biomass
The biomass fuels and conversion processes outlined in chapter 13 either
are in present use in the United States or could become commercial in the next
287
-------
5 to 10 years. In addition, their prices probably will be competitive with
that of imported oil. A number of other bioenergy sources are considered
promising, but none is expected to contribute significantly to U.S. energy
supplies for at least 20 years. Among these unconventional sources are
saltwater and freshwater algae and other plants (mariculture and aquaculture),
land-based oil and hydrocarbon crops (such as eucalyptus, guayule, euphorbia,
jojoba, and milkweed), and the intensive cultivation of plants for energy
purposes on tree farms and other "energy plantations."
The ORBES region is rich in biomass resources. As discussed in section
4.4, forest areas cover 31 percent of the region. Among the state portions,
the proportion ranges from 69 percent in West Virginia to 10 percent in
Illinois. Three of the state portions—Illinois, Indiana, and Ohio—have a
high proportion of cropland to total land area (from 71 to 57 percent). These
three states are among the five highest ranking states with crop residues
usable for energy. The potential for additional grass production for energy
uses is high in Kentucky, while Illinois, Indiana, Ohio, and Pennsylvania have
average potential.
ADVANTAGES. There are advantages and disadvantages common to all forms of
11
biomass energy.'J A major advantage is that, when managed properly, biomass
resources are renewable. Moreover, these resources are domestic and thus can
reduce U.S. dependence on imported oil. In fact, biomass can contribute to
energy self-sufficiency in certain sectors, including municipalities,
agriculture, and the forest product industries. With regard to the
environment, biomass conversion tends to be less polluting than conventional
fuels. Thus, biomass use could help solve pollution and waste disposal
problems. Finally, depending on the technologies adopted and the scale of
production, bioenergy may provide the basis for the growth of small businesses
and the decentralization of economic activity, both of which are valued by
many Americans.
DISADVANTAGES. Among the disadvantages of biomass fuels (especially wood and
starch and sugar crops) is that they already have established nonenergy uses
that could compete with new uses for energy. Also, many biomass technologies
produce energy in a quantity, quality, or form that is not easy to match with
existing energy distribution or consumption systems. Many of the existing
small-scale conversion technologies require individual labor for continuous
operation. Thus, these technologies are less convenient than conventional
technologies. It also should be noted that the harvesting of biomass
resources in logging and agriculture could lead to a higher incidence of
1 ?
0 See U.S. Congress, Office of Technology Assessment, Energy from
Biological Processes (OTA-E-124, July 1980).
288
-------
occupational injury than the extraction of conventional fossil fuels,
including coal mining.
The widespread introduction of bioenergy raises a number of institutional
issues. Those common to all bioenergy sources are discussed first. In
general, these institutional problems fall into two categories: (1)
governmental response and (2) as with solar and wind energy, integration with
existing energy infrastructures. "
SHARED INSTITUTIONAL ISSUES
Government Programs. A number of measures have been proposed by Congress to
promote new energy sources of all kinds, and many of these measures will
improve the prospects for bioenergy. However, because of the wide range of
biomass feedstocks and conversion technologies, policies carefully tailored to
bioenergy would appear to be desirable. For example, programs could be
developed to provide information and technical assistance to bioenergy users
and to establish reliable supply infrastructures for energy uses of biomass
resources. To assure that bioenergy resources will be renewable, there would
have to be long-range energy and resource planning and proper resource
management in both public and private operations. This long-term need,
however, is not met by present political, economic, and energy planning. If
the use of biomass for energy is expanded, previously independent economic
sectors will become linked. These links could have significant institutional
implications for regulation, such as those related to antitrust.
Federal administration of bioenergy research, development, and
implementation has been deficient in various ways. Most federal bioenergy
programs are understaffed and underfunded; rapid management turnovers are the
norm. Where more than one agency has jurisdiction, there tends to be little
coordination between them; in some areas, lead responsibilities either are
poorly defined or change frequently. Also, as discussed in section 15.2.1,
federal programs tend to focus on large central-scale applications, with
little support for small users and on-site technologies. Finally, basic
resource inventories need to be conducted for all bioenergy sources.
Integration with Existing Energy Infrastructures. Because bioenergy may not
be in a quality, form, or quantity that fits conventional energy supply
infrastructures or users, institutional changes would have to be made. For
example, where biomass is used to produce electricity, provisions must be made
See U.S. Congress, Office of Technology Assessment, Energy from
Biological ProcessesT and Materials and Energy from Municipal Waste (OTA-M-93,
July 1979).
289
-------
to sell surplus electricity to the grid at equitable rates and to supply
back-up power to producers of bio-electricity. To some extent this issue has
been addressed by the Public Utility Regulatory Policies Act of 1978 (see
section 15.2.1), but implementation of PURPA by the states will take several
years. Similarly, where biomass produces more methane gas than can be used on
the site, either a storage facility or a pipeline linkage must be provided.
In addition to institutional issues associated with all bioenergy
sources, other issues are specific to each form of biomass. In general, these
questions relate to the regulation of forest lands or agricultural crops,
environmental damage, and economic controls.
WOOD. The primary institutional issue related to the use of wood for energy
is the management and care of the resource base, that is, forestlands. Wood
is an attractive energy source in part because an increase in demand could
lead to better forest management, which in turn would increase the quantity
and quality of timber available for all uses. However, this is not certain to
occur. Also, in the process it may not be possible to avoid the many kinds of
environmental damage that can result from wood harvesting, transportation, and
conversion. Supportive programs are particularly needed outside the forest
products industry, where inexperience with wood harvesting could lead to
"mining" of the resource. Fifty-eight percent of the nation's forest land is
controlled by 4.5 million private, nonindustrial woodlot owners, and their
behavior is unpredictable. Short-term economic incentives tend to favor
improper management, and few effective state and federal programs provide
incentives for environmentally sound management by these private owners.
The timber available for all uses could be increased in quantity and
improved in quality by intensive timber management, but the character of the
forests would change. Removing logging residues and increasing stand
conversions and thinning would mean more uniform, open forests with a higher
proportion of even-age, single-species stands—similar to those in Europe
today. Bird, animal, and insect species that depend on dead and dying trees
would decline in population, and other species would increase in number. The
greatest changes in forest character would occur in flat, easily accessible
lands; steep or environmentally vulnerable lands would be affected less
because often harvesting is more expensive there. Such changes would not be
welcomed by many environmental groups, especially those concerned with
preserving natural ecosystems, although other groups concerned with promoting
hunting or increased public access might welcome such changes.
AGRICULTURE. The primary institutional issues associated with intensive
agricultural production for energy are the integration of energy demand for
crops into existing markets and the potential for environmental damage. Grain
and sugar feedstocks for ethanol also have food and feed value, and buyers for
all three uses would be expected to compete for farm commodities. With an
290
-------
increase in the production of grain-based ethanol, distillers who wish a
greater share of the market would have to pay higher feedstock prices. These
higher prices make it profitable for farmers to bring additional cropland into
production: it is both costlier and riskier to farm currently idle land.
Moreover, higher prices for grain and sugar crops also make it profitable for
farmers to substitute these crops for those currently produced and to change
livestock rations. For example, corn and alfalfa could be planted instead of
soybeans, and distillers' grain byproducts could be used instead of corn and
soybean meal in animal feed. Moreover, higher commodity prices could reduce
foreign demand, thus increasing the supply available to distillers. However,
the demand for exports has been rising rapidly; this also could contribute to
higher prices. In addition, if distillers' grain is not exported at prices
comparable to whole grain or soybean products, distilling grain into ethanol
rather than exporting it could increase the U.S. balance of trade deficit.
Furthermore, higher prices would reduce the purchasing power of domestic grain
and sugar crop consumers. Finally, higher commodity prices would be necessary
to increase grain reserves, which constitute a buffer against short-term
supply fluctuations.
If the market adjustments noted above lead to greater production of
grain-based ethanol with relatively small price increases, then little effect
on food prices would be felt. If, however, very large price incentives are
required to divert land from existing uses to ethanol feedstocks, then the
indirect costs of ethanol production to food consumers could be prohibitively
expensive. With appropriate priorities and support for research and
development, conversion processes for making alcohol fuels from other
feedstocks besides grain and sugar crops probably would become commercial
before resulting increases in food prices become severe.
Moreover, if large resource shifts can be accomplished at a relatively
small cost, it probably would not be necessary to increase and/or control
feedstock production by changes in agricultural programs. Rather, current
agricultural policies in conjunction with end use subsidies (for example, the
federal excise tax exemption for gasohol) could help increase distillers'
share of supplies. This would reduce the need for farm income supports, and
the focus of agricultural subsidies could shift to the maintenance of
strategic reserves, the preservation of cropland against other agricultural
uses and against urbanization, and the control of environmental problems
associated with agriculture. The critical issues then would be the size,
type, and duration of end use subsidies.
Usual agricultural practices often degrade land quality and pollute
surface and ground waters; the two problems are linked closely. For instance,
erosion both reduces land productivity and is the major cause of sedimentation
in surface waters. Similarly, fertilizers and pesticides build up in the
soil, changing its ecology, and then enter aquatic ecosystems through runoff.
291
-------
Both sedimentation and chemical pollution through runoff are regulated under
section 208 of the Clean Water Act, which requires states to develop plans for
the control of water pollution from nonpoint sources. Effective
implementation, however, has been hampered by such problems as the political
sensitivity surrounding any federal involvement in land use planning; a lack
of direction in EPA guidelines for determining which sources of nonpoint
pollution to control, as well as the degree of this control; and short
deadlines for the development of new and controversial land use management
techniques. As a consequence, the control of nonpoint pollution has received
less emphasis in funding to carry out the Clean Water Act than has the control
of more immediate and better understood water pollution problems with strict
statutory control deadlines, such as sewage treatment and industrial process
controls. Future implementation of section 208 is expected to focus more on
regulatory, statewide nonpoint source controls. However, given the
traditional resistance to regulatory controls by farmers, the low priority
assigned to environmental problems of agriculture by both state and federal
agencies, and other constraints, it is unclear whether future implementation
of section 208 will be any more effective than it has been in the past.
Thus, if set-aside and other potential croplands are brought into
production for energy crops, the effects on water pollution could be
substantial. In general, these lands have a higher potential for erosion than
does land now under production. Therefore, they are more likely to contribute
to sedimentation of surface waters. Also, potential croplands may not be as
productive, requiring increased use of fertilizers and pesticides that
contribute to chemical water pollution. A complicating factor is that any
controls introduced could not be tied to energy crops alone, because farmers
could shift those crops to their least sensitive lands. Thus, environmental
control policies would have to be introduced throughout the agricultural
system.
MUNICIPAL SOLID WASTES. The primary institutional issues associated with the
use of municipal solid wastes (MSW) for energy relate to the removal of
barriers to resource recovery. Materials can be recovered from MSW for
recycling in two ways: by collecting wastes that have been kept separate as
they are generated (known as source separation) and by separating mixed wastes
in a central facility (known as centralized waste recovery). Either method
saves energy because less energy is used in the manufacture of products from
recovered materials than from virgin raw materials. Only from centralized
resource recovery, however, can energy be recovered as fuel.
There are a number of technologies at various stages of development for
burning the combustible portion of MSW or for converting it to solid, liquid,
or gaseous fuels. However, the only methods now in commercial operation are
waterwall combustion, small-scale modular incineration to produce steam, and
the production of refuse-derived fuel by wet and dry processes. The most
292
-------
economical approach may be for capital-intensive, centralized facilities to
operate in conjunction with separate collection programs. Federal programs
could encourage such integration.
Because revenues, most from the sale of energy, are expected to be
insufficient to cover the costs of centralized resource recovery plants, a
charge for waste disposal must be made. These charges are expected to be from
about 50 to 100 percent higher per ton than charges for waste disposal at
landfills. Thus, centralized recovery has the greatest potential where both
landfill costs and energy prices are high, as in the urban Northeast.
The federal role in research and development on centralized resource
recovery is expected to be most effective in the identification, evaluation,
and control of environmental and occupational problems; in the
characterization of materials; in the funding of basic studies of processes
for size reduction, materials separation, combustion, and chemical reaction;
and in exploratory design—especially of small-scale systems. Remaining
technical problems probably can be dealt with most effectively in the private
sector during the course of commercial development.
15.3 Conservation
Energy conservation can be achieved in a variety of ways, including
improved lighting and heating efficiencies, insulation, tax incentives, and
changes in personal lifestyle. For purposes of ORBES, however, use of only
one conservation measure—cogeneration—was quantified for use in a
scenario.
COGENERATION. As discussed in chapter 13, cogeneration is the combined
production of power, either mechanical or electrical, and of useful thermal
energy such as process steam.1^ There are three principal institutional
considerations associated with cogeneration: economic factors, environmental
impacts, and regulatory constraints. Of these, economics is the most
significant. Industrial companies have indicated that the economic rate of
return on investment is their single most important criterion for making
15
A number of energy conservation measures are discussed in Cardi,
Harless, and Sweet, Legal and Institutional Issues.
The information on cogeneration is taken from two sources: Robert
Stobaugh and Daniel Yergin, eds., Energy Future (New York: Random House,
1979), and U.S. Comptroller General, Industrial Cogeneration—What It. Is, How
It Works. Its Potential (EMD-80-7, April 29, 1980).
293
-------
investment decisions. The major factors affecting rate of return on
investment include capital costs and availablility and the anticipated cost
savings. The most important cost consideration is the savings realized from
cogeneration when compared with the alternative costs of separate operations
for in-house steam production and purchased electricity.
Another important institutional issue concerning cogeneration is the
effect it may have on the environment, especially on air quality. Due to the
inability of steam to travel long distances, cogeneration facilities must be
located near industry. Therefore, at certain locations there could be
increases in pollutant emissions; the analysis of specific cases must be based
on both current conditions and on federal and state environmental regulations.
For the nation as a whole, however, increased cogeneration should have a
favorable environmental impact. Depending on which fuel is used, the higher
fuel economy per unit of electricity will bring a corresponding reduction in
pollutant emissions from the reduction in generation by electric utilities.
Regulatory considerations center around the reluctance of industry to
become involved in what is considered a highly regulated and capital-intensive
activity, the generation of electricity. Another industry concern is
government regulations that could require plants to deliver cogenerated
electricity to the grid to meet utility reserve or emergency capability, thus
jeopardizing industrial plant operations. However, as discussed in section
15.2.1, under the Public Utility Regulatory Policies Act of 1978, the Federal
Energy Regulatory Commission can exempt on-site generators from certain state
and federal requirements.
294
-------
CONCLUDING NOTE
It is clear why a unit of the U.S. Congress directed the Environmental
Protection Agency to carry out the Ohio River Basin Energy Study. A group of
citizens had discovered in 1974 that no private or public entity was
responsible for coordinating the location of new power plants in their part of
the Ohio River valley. They wanted to know why this condition existed and
what might be done about it. As EPA pursued its congressional mandate to come
up with answers, agency officials decided that the energy and environmental
problems stimulating the concerns of this group represented only some of the
issues centered around power plants in the broad Ohio Basin.
Perhaps more important than the final verdict on ORBES is the learning
process it stimulated. Reports, even the best of them, gather dust, but ideas
exchanged in the classroom and the marketplace stay alive. If a new learning
and teaching process, centered on the problems of the Ohio River Basin, has
begun, the ORBES experiment will have been worthwhile.
One important insight gained by the researchers is that the ORBES region,
part of which is known popularly as the Ohio River valley, is far more diverse
than they had suspected and probably more so than most public officials
realize. Failure to recognize this diversity most certainly will doom to
failure any attempt at basinwide institutional innovations. For example, the
organization responsible in part for the study—Save the Valley, which is
centered around Madison, Indiana, between Cincinnati and Louisville—includes
individuals who fear that power plants and related installations will
transform the area into one of heavy industry. Their spokesmen often extoll
the natural beauty and rural advantages of their section of the valley. They
speak of a desire to keep it from becoming "another Gary, Indiana, or a
Youngstown, Ohio," filled with factories and dirty air.
It is indeed ironic that most members of a movement known as Save Our
Valley are residents of Youngstown. The major objective of these citizens is
to "save" jobs from being lost by the closing of steel mills in the area.
Church leaders and others argue for the development of more industry. In
efforts to save jobs and to maintain a desirable quality of life from their
perspective, at times they have contended that air quality standards must be
relaxed. Equally committed individuals in Save The Valley call for the
imposition of stricter air quality standards.
295
-------
The diversity of the ORBES region and the complexity of its economic and
environmental problems are well illustrated by the presence of organizations
such as Save The Valley and Save Our Valley. They function in adjacent states
but are separated in their views on what is in the best interest of their
communities and of the broad region. There is indeed balkanization within the
ORBES region, and with a continued emphasis on coal, ideological divisions
probably will become more pronounced.
The single issue within the broad context of continued (and perhaps
increased) reliance on coal that could produce the most conflict is the long-
range and transboundary movement of air pollutants across state lines. Since
ORBES began in 1976, this issue has become perhaps the most prominent one in
the region. It affects employment levels in the coal-mining industry as well
as in industry in general. It triggers emotions that are easily translated
into political controversy. Some feel that such political controversy, both
intrastate and interstate, could threaten the stability of the American
federal system.
But many of the ORBES researchers—air pollution experts, economists,
lawyers, political scientists, and others—believe that institutional
mechanisms can be devised that will permit the region to enjoy the benefits of
both reasonably clean air and a degree of economic growth. The creation of
such mechanisms will require the highest technological competance, as well as
social and political imagination. If there is any single finding of the Ohio
River Basin Energy Study, it is that steps toward both clean air and economic
growth in the region can be taken only if ways can be found to unite the
various factions. Many residents of the region have recognized this reality,
but they remain separated by ideology. Some believe that the steps should be
initiated by government, while others favor action within the private sector.
It is not the responsibility of ORBES researchers to recommend which path
should be followed. But it is our responsibility to warn that inaction could
result in economic stagnation and accompanying social problems capable of
draining much-needed vitality from the region and from the nation at-large.
296
-------
Appendices
-------
APPENDIX A
ORBES Phase II Participants
Project Management Team
Lowell Smith, ORBES Project Officer and Director, Program Integration and
Policy Staff, Office of Environmental Engineering and Technology, Office
of Research and Development, U.S. Environmental Protection Agency,
Washington, D.C.
James J. Stukel, Professor of Environmental Engineering and Mechanical
Engineering and Director, Office of Energy Research, University of
Illinois at Urbana-Champaign, Urbana, Illinois
Boyd R. Keenan, Professor of Political Science, University of Illinois at
Chicago Circle and Institute of -Government and Public Affairs, Chicago,
Illinois
David Hopkins, U.S. Environmental Protection Agency, Region IV, Atlanta,
Georgia
Victor F. Jelen, Industrial Environmental Research Laboratory, U.S.
Environmental Protection Agency, Cincinnati, Ohio
James H. Phillips, U.S. Environmental Protection Agency, Region V, Chicago,
Illinois
Project Office Staff
Stephanie L. Kaylin, Staff Associate, Office of Energy Research, University of
Illinois at Urbana-Champaign, Urbana, Illinois
Cathy Coffman, Assistant Editor, Office of Energy Research, University of
Illinois at Urbana-Champaign, Urbana, Illinois
299
-------
Core Team
Robert E. Bailey, Professor of Nuclear Engineering and Director, Program on
Energy Research, Education, and Public Service, The Ohio State
University, Columbus, Ohio
Donald A. Blome, Research Scientist, Institute for Mining and Mineral
Research, Energy Research Laboratory, University of Kentucky, Lexington,
Kentucky
Vincent P. Cardi, Professor of Law, West Virginia University, Morgantown, West
Virginia
Gary L. Fowler, Associate Professor of Geography and Associate Director,
Energy Resources Center, University of Illinois at Chicago Circle,
Chicago, Illinois
Steven I. Gordon, Assistant Professor of City and Regional Planning, The Ohio
State University, Columbus, Ohio
James P. Hartnett, Professor of Energy Engineering and Director, Energy
Resources Center, University of Illinois at Chicago Circle, Chicago,
Illinois
Boyd R. Keenan, Professor of Political Science, University of Illinois at
Chicago Circle and Institute of Government and Public Affairs, Chicago,
Illinois
Walter P. Page, Associate Professor of Economics, West Virginia University,
Morgantown, West Virginia
Harry R. Potter, Associate Professor of Sociology, Purdue University, West
Lafayette, Indiana
James C. Randolph, Associate Professor of Ecology and Director of
Environmental Programs, School of Public and Environmental Affairs,
Indiana University, Bloomington, Indiana
Maurice A. Shapiro, Professor of Environmental Health Engineering, University
of Pittsburgh, Pittsburgh, Pennsylvania
Hugh T. Spencer, Associate Professor of Environmental Engineering, University
of Louisville, Louisville, Kentucky
James J. Stukel, Professor of Environmental Engineering and Mechanical
Engineering and Director, Offiqe of Energy Research, University of
Illinois at Urbana-Champaign, Urbana, Illinois
Persons who made substantial contributions working with individual core
team members include Anna S. Graham, The Ohio State University; Rita Harmata
300
-------
and Steven D. Jansen, University of Illinois at Chicago Circle; W.W. Jones,
Indiana University; Clara Leuthart, University of Louisville; and A.A. Sooky,
University of Pittsburgh.
Support Researchers
Dwight B. Billings, Assistant Professor, Appalachian Center, University of
Kentucky, Lexington, Kentucky
E. Downey Brill, Jr., Associate Professor of Civil Engineering, University of
Illinois at Urbana-Champaign, Urbana, Illinois
Duane Chapman, Associate Professor of Agricultural Economics, Cornell
University, Ithaca, New York
Doug Gilmore, Research Engineer, University of Illinois at Urbana-Champaign,
Urbana, Illinois
Geoffrey Hewings, Associate Professor of Geography, University of Illinois at
Urbana-Champaign, Urbana, Illinois
Orie Loucks, Science Director, The Institute of Ecology, Holcomb Research
Institute, Indianapolis, Indiana
Patrick C. Mann, Professor of Economics, West Virginia University, Morgantown,
West Virginia
James A. McLaughlin, Professor of Law, West Virginia University, Morgantown,
West Virginia
Thomas P. Milke, Westat Corporation, Rockville, Maryland
Richard Newcomb, Professor of Mineral Economics, West Virginia University,
Morgantown, West Virginia
Edward P. Radford, M.D., Professor of Environmental Epidemiology, University
of Pittsburgh, Pittsburgh, Pennsylvania
Teknekron Research, Inc., Berkeley, California, and Waltham, Massachusetts
Burkhard von Rabenau, Associate Professor of City and Regional Planning, The
Ohio State University, Columbus, Ohio
David S. Walls, Assistant Professor, Appalachian Center, University of
Kentucky, Lexington, Kentucky
E. Earl Whitlatch, Associate Professor of Civil Engineering, The Ohio State
University, Columbus, Ohio
301
-------
Daniel E. Willard, Associate Professor, Environmental Systems Application
Center, School of Public and Environmental 'Affairs, Indiana University,
Bloomington, Indiana
Tom S. Witt, Associate Professor of Economics, West Virginia University,
Morgantown, West Virginia
Advisory Committee
John P. Apel, Vice President, Columbus and Southern Ohio Electric Company,
Columbus, Ohio
Charles Bareis, Illinois Archaeological Society, Urbana, Illinois
Hugh A. Barker, Chairman and Chief Executive Officer, Public Service Indiana,
Plainfield, Indiana
Frank Beal, Director, Illinois Institute of Natural Resources, Chicago,
Illinois
Harold G. Cassidy, Save The Valley, Madison, Indiana
Thomas Duncan, President, Kentucky Coal Association, Lexington, Kentucky
C. Wayne Fox, Chief Electrical Engineer, Illinois Commerce Commission,
Springfield, Illinois
John D. Geary, President, Ohio River Company, Cincinnati, Ohio
W.C. Gerstner, Executive Vice President, Illinois Power Company, Decatur,
Illinois
Oscar Geralds, Secretary, Kentucky Department of Environmental Protection,
Louisville, Kentucky
Benjamin C. Greene, President, West Virginia Surface Mining and Reclamation
Association, Charleston, West Virginia
Major General Harry A. Griffith, Division Engineer, U.S. Army Corps of
Engineers, Cincinnati, Ohio
Damon W. Harrison, Commissioner, Kentucky Department of Energy, Frankfort,
Kentucky
Fred Hauck, Save The Valley, Shelbyville, Kentucky
Rebecca Hanmer, Regional Administrator, U.S. Environmental Protection Agency,
Region IV, Atlanta, Georgia
302
-------
L. John Hoover, Assistant Director, Energy and Environmental Systems Division,
Argonne National Laboratory, Argonne, Illinois (through May 1980)
Brian Kiernan, Assistant Director for Research, Kentucky Legislative Research
Commission, Frankfort, Kentucky
Fred J. Krumholtz, Chairman, Ohio River Basin Commission, Cincinnati, Ohio
Eugene Land, International Legislative Representative, United Auto Workers,
Region III, Lexington, Kentucky
Owen Lentz, Executive Manager, East Central Area Reliability Council, Canton,
Ohio
Ed Light, Appalachian Research and Defense Fund, Charleston, West Virginia
Walter A. Lyon, Deputy Secretary, Pennsylvania Department of Environmental
Resources, Harrisburg, Pennsylvania
Ralph Madison, President, Kentucky Audubon Council, Louisville, Kentucky
James S. McAvoy, Director, Ohio Environmental Protection Agency, Columbus,
Ohio
Mitch McConnell, Judge, Jefferson County, Louisville, Kentucky
Dandridge McDonald, Chairman, West Virginia Public Service Commission,
Charleston, West Virginia
John McGuire, Regional Administrator, U.S. Environmental Protection Agency,
Region V, Chicago, Illinois
Representative Daniel Pierce, Illinois Energy Resources Commission, Highland
Park, Illinois (through December 1979)
A. Jenifer Robison, Project Director, Dispersed Electric Generating Tech-
nologies, Office of Technology Assessment, U.S. Congress, Washington,
D.C.
Senator Walter Rollins, West Virginia Commission on Interstate Cooperation,
Kenova, West Virginia
Greg Rowe, Environmental Planner, OKI Regional Council of Governments,
Cincinnati, Ohio
Robert Ryan, Director, Ohio Energy and Resource Development Agency, Columbus,
Ohio
Jack Schramm, Regional Administrator, U.S. Environmental Protection Agency,
Region III, Philadelphia, Pennsylvania
William B. Stanbury, Mayor, City of Loiiisville, Louisville, Kentucky
303
-------
Charles C. Tillotson, Rising Sun, Indiana
Carl B. Vance, Executive Vice-President for Operations, Indianapolis Power and
Light Company, Indianapolis, Indiana
Leo Weaver, Executive Director, Ohio River Valley Water Sanitation Commission,
Cincinnati, Ohio
David Whaley, Louisville, Kentucky (through June 1980)
W.S. White, Chairman of the Board, American Electric Power, New York, New York
John H. Williams, Office of Utility Systems, Division of Power Supply and
Reliability, Economic Regulatory Administration, U.S. Department of
Energy, Washington, D.C.
Jack Wilson, Commissioner, Bureau of Environmental Protection, Kentucky
Department of Natural Resources and Environmental Protection, Frankfort,
Kentucky
Willis Zagrovich, President, Indiana AFL-CIO, Greenwood, Indiana
304
-------
APPENDIX B
ORBES Publications
Phase II
Donald A. Blome, University of Kentucky, Coal Mine Siting for the Ohio River
Basin Energy Study. Grant No. EPA R805590
E. Downey Brill, Jr., Shoou-Yuh Chang, Robert W. Fuessle, and Randolph M.
Lyon, University of Illinois at Urbana-Charapaign, Potential Water Quantity
and Water Quality Impacts of Power Development Scenarios on Major Rivers in
the Ohio Basin. Subcontract under Prime Contract EPA R805588
Vincent P. Cardi, West Virginia University, editor, West Virginia Baseline.
Grant No. EPA R805585
Vincent P. Cardi, Larry Harless, and Thomas Sweet, West Virginia University,
Legal and Institutional Issues in the Ohio River Basin Energy Study, Grant
No. EPA R805585 and Subcontract under Prime Contract EPA R805588
Duane Chapman, Kathleen Cole, and Michael Slott, Cornell University, Energy
Production and Residential Heating: Taxation. Subsidies, and Comparative
Costs. Subcontract under Prime Contract EPA R805588
Comments on the Ohio River Basin Energy Study, Cooperative Agreement No. EPA
CR807395
Control Data Corporation, International Research and Technology Corporation,
and the MITRE Corporation, Environmental Residual Trends in the Ohio River
Basin
Gary L. Fowler, University of Illinois at Chicago Circle; J.C. Randolph,
Indiana University; Robert E. Bailey, The Ohio State University; Steven I.
Gordon, The Ohio State University; Steven D. Jansen, University of Illinois
at Chicago Circle; and W.W. Jones, Indiana University, The Ohio River Basin
Energy Facility Siting Model. Grant Nos. EPA R805588, R805589, and R805609
and Subcontract under Prime Contract EPA R805588
Vol. I. Methodology
Vol. II. Sites and On-Line Dates
305
-------
Steven I. Gordon and Christopher Badger, The Ohio State University, A Model of
Migration in the Ohio River Basin Energy Study Region. Subcontract under
Prime Contract EPA R805588
Steven I. Gordon and Anna S. Graham, The Ohio State University, Regional
Socioeconomic Impacts of Alternative Energy Scenarios for the Ohio River
Basin Energy Study Region. Grant No. EPA R805589
Steven I. Gordon and Anna S. Graham, The Ohio State University, Site-Specific
Socioeconomic Impacts: Seven Case Studies in the Ohio River Basin Energy
Study Region. Grant No. EPA R805589
James P. Hartnett and Jan L. Saper, University of Illinois at Chicago Circle,
Energy Consumption Patterns: Illinois, Indiana, Kentucky, Ohio,
Pennsylvania, and West Virginia (1975). Grant No. EPA R805588
Steven D. Jansen, University of Illinois at Chicago Circle, Electrical
Generating Unit Inventory, 1976-1986: Illinois. Indiana. Kentucky, Ohio.
Pennsylvania, and West Virginia. Grant No. EPA R805588
Steven D. Jansen, James P. Hartnett, R. Mastaniah, and Dan Merilatt,
University of Illinois at Chicago Circle; Robert E. Bailey, The Ohio State
University; J.C. Randolph, Indiana University; Maurice A. Shapiro,
University of Pittsburgh; and Hugh T. Spencer, University of Louisville,
Nuclear Energy Risks and Benefits. Grant Nos. EPA R804816, R805588,
R805608, and R805609 and Subcontracts under Prime Contract EPA R805588
Boyd R. Keenan, University of Illinois at Chicago Circle, Ohio Basin
Interstate Energy Options: Constraints of Federalism, Grant No. EPA
R805588
Clara Leuthart and Hugh T. Spencer, University of Louisville, Fish Resources
and Aquatic Habitat Impact Assessment Methodology for the Ohio River Basin
Energy Study Region. Grant No. EPA R804816
Orie Loucks, Thomas V. Armentano, Roland Usher, and Wayne Williams, The
Institute of Ecology; Richard W. Miller, The Institute of Ecology and
Butler University; and Larry Wong, Indiana University, Crop and Forest
Losses Due to Current and Projected Emissions from Coal-Fired Power Plants
in the Ohio River Basin, Subcontract under Prime Contract EPA R805588
Patrick C. Mann and Tom S. Witt, West Virginia University, An Economic
Analysis of the Electric Utility Sector in the Ohio River Basin Region.
Subcontract under Prime Contract EPA R805588
James A. McLaughlin, West Virginia University, Legal and Institutional Aspects
of. Interstate Power Plant Development in the Ohio River Basin Energy Study
Region. Subcontract under Prime Contract EPA R805588
Richard Newcomb and Bruce Bancroft, West Virginia University, Capital
Requirements and Busbar Costs for Power in the Ohio River Basin. 1985
2000. Subcontract under Prime Contract EPA R805588
306
-------
ORBES Core Team, Ohio River Basin Energy Study (QRBES): Main Report. Grant
Nos. EPA R804618, R805585, R805588, R805589, R805590, R805603, R805608,
R805609, and R806451 and Cooperative Agreement No. EPA CR807395
Walter P. Page, West Virginia University, An Economio Analysis of Coal Supply
in the Ohio River Basin Energy Study Region. Grant No. EPA R805585
Walter P. Page, West Virginia University, Energy Consumption in the Ohio River
Basin Energy Study Region. 1974, ^y. End User and Fuel Type. Grant No. EPA
R805585
Walter P. Page, James Ciecka, and Gary Arbogast, West Virginia University, and
Robert G, Fabian, Estimating Regional Losses to Agricultural Producers from
Airborne Residuals in the Ohio River Basin Energy Study Region. 1976-2000.
Grant No. EPA R805585 and Subcontract under Prime Contract EPA R805588
Walter P. Page, West Virginia University, and Doug Gilmore and Geoffrey
Hewings, University of Illinois at Urbana-Champaign, An Energy and Fuel
Demand Model for the Ohio River Basin Energy Study Region. Grant No. EPA
R805585 and Subcontract under Prime Contract EPA R805588
Walter P. Page and John Gowdy, West Virginia University, Gross Regional
Product in the Ohio River Basin Energy Study Region, 1960-1975, Subcontract
under Prime Contract EPA R805588
Walter P. Page and John M. Gowdy, West Virginia University, Economic Losses in
the Columbus SMSA Due to Long-Range Transport of Airborne Residuals in the
Ohio River Basin Energy Study Region, Grant No. EPA R805585
Harry R. Potter and Heather Norville, Purdue University, Ohio River Basin
Energy Study: Social Values and Energy Policy, Grant No. EPA R806451 and
Subcontract under Prime Contract EPA R805588
Edward P. Radford, University of Pittsburgh, Impacts on Human Health from the
Coal and Nuclear Fuel Cycles and Other Technologies Associated with
Electric Power Generation and Transmission, Subcontract under Prime
Contract EPA R805588
J.C. Randolph and W.W. Jones, Indiana University, Ohio River Basin Energy
Study; Land Use and Terrestrial Ecology, Grant No. EPA R805609
Jan L. Saper and James P. Hartnett, University of Illinois at Chicago Circle,
editors; Vincent P. Cardi and Thomas Sweet, West Virginia University; and
Gary L. Fowler, Rita Haraata, Steven D. Jansen, and Boyd R. Keenan,
University of Illinois at Chicago Circle, The Current Status of the
Electric Utility Industry in the Ohio River Basin Energy Study States,
Grant Nos. EPA R805585 and R805588
Maurice A. Shapiro, University of Pittsburgh, editor, Pennsylvania Baseline,
Grant No. EPA R805608
307
-------
j Maurice A. Shapiro and A.A. Sooky, University of Pittsburgh, Ohio River Basin
_-/!/ Energy Study; Health Aspects. Grant''No. EPA R805608 and Subcontract under
Ks Prime Contract EPA R805588
James J. Stukel, University of Illinois at Urbana-Champaign, editor, Ohio
River Basin Energy Study: Air Quality and Related Impacts
Vol. I. James J. Stukel and Brand L. Niemann, University of Illinois
at Urbana-Champaign, Documentation in Support of Key. ORBES Air Quality
Findings, Grant No. EPA R805588
Vol. II. Teknekron Research, Inc., Air Quality and Meteorology in the
Ohio River Basin: Baseline and Future Impacts, Subcontract under
Prime Contract EPA R805588
Vol. III. Teknekron Research, Inc., Selected Impacts of Electric
Utility Operations in the Ohio River Basin (1976-2000); An
Application of the Utility Simulation Model. Subcontract under Prime
n Contract EPA R805588
Symposium on Energy and Human Health: Human Costs of Electric Power
Generation. Grant No. EPA R805608 and Subcontract under Prime Contract EPA
R805588
David S. Walls, Dwight B. Billings, Mary P. Payne, and Joe F. Childers, Jr.,
University of Kentucky, A Baseline Assessment of Coal Industry Structure in
the Ohio River Basin Energy Study Region, Subcontract under Prime Contract
EPA R805588
Elbert E. Whitlatch and John A. Aldrich, The Ohio State University, Energy
Facility Siting Procedures, Criteria, and Public Participation in the Ohio
River Basin Energy Study Region. Grant Nos. EPA R805589 and R805603
Daniel E. Willard, Michael A. Ewert, Mary Ellen Hogan, and Jeffrey D. Martin,
Indiana University, A Land Use Analysis of Existing and Potential Coal
Surface Mining Areas in the Ohio River Basin Energy Study Region,
Subcontract under Prime Contract EPA R805588
\ NOTE: Copies of the above reports can be obtained from Office of Research and
Development Publications, U.S. Environmental Protection Agency, Center for
1 Environmental Research Information, 26 West St. Clair, Cincinnati, Ohio 45268
(513/684-7562).
R.E. Bailey, R.G. Barile, D.D. Gray, R.B. Jacko, P. O'Leary, R.A. Rao, and
J.E. Reinhardt, Purdue University, Pollutant Transport Models for the ORBES
Region, vol. III-H, Grant No. EPA R804849
308
------- OCR error (C:\Conversion\JobRoot\000002NA\tiff\20006NYF.tif): Unspecified error
-------
Findings, vol. I-A, Grant No. EPA R805848; also published as U.S.
Environmental Protection Agency, Interagency Energy-Environmental Research
and Development Program Report, EPA-60077-77-120 (November 1977)
Nicholas L. White and John F. Fitzgerald, Indiana University, Legal Analysis
of Institutional Accountability for the Ohio River Basin, vol. III-E, Grant
No. EPA R804849
310
-------
APPENDIX C
Alternative Scenario Designations
Number
Other Designation
Scenarios Discussed in Main Report
Base Case (BC) 2
Strict Environmental Controls (SEC) 1
SIPNoncompliance(SIP-N) 2d
High Electrical Energy Growth (HEG) 7
Electrical Exports (EX) 2a
Natural Gas Substitution (NG) 4
Nuclear Fuel Substitution (NF) 2c
Alternative Fuel Substitution (AF) 3
Conservation Emphasis (CON) 6
Scenario Variations Discussed in Main Report
Agricultural Land Protection,
Dispersed Siting 1c
Agricultural Land Protection,
Concentrated Siting 1d
Once-through Cooling 2i
High Electrical Energy Growth, Least
Emissions Dispatch 7a
High Electrical Energy Growth,
35-year Plant Life 7b
Specialized Scenarios Discussed in Other ORBES Reports
Very Strict Air Quality,
Dispersed Siting 1 a
Very Strict Air Quality,
Concentrated Siting
Business as Usual (BAU)
Lax Environmental Controls
Coal-fired Exports; "Wheeling"
Very Low Energy Growth
Electrical Exports, Dispersed Siting
in Western ORBES Region
Electrical Exports, Nuclear-Fueled
Electrical Exports, Nuclear-Fueled,
Once-through Cooling
on Ohio Main Stem
Low Economic Growth
Very High Economic Growth
1b
2a1
2b
2b1
5
5a
"Wheeling"
"Wheeling"
311
i US GOVERNMENT PRINTING OFFICE 1981 -757-064/0225
-------
|