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

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                                   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

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                                                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

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                                  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

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                               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-

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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

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    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

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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

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                                   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

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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

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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

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     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.

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                                   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

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     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

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     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

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     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

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     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

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                          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

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                          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

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 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

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 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

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 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

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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,

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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

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Executive Summary

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                            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.

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                     Figure ES-1
               ORBES-Region Coalfields
Interior
Coal Province
Appalachian
Coal Province
                      Figure ES-2
     Ohio River Basin Energy Study (ORBES) Region

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     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

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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.

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     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

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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

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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

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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

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Figure ES-1 2
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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
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              •Strict Environmental Controls (SEC)
              -SIP Noncompliance (SIP-N)
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              •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

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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

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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

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-------
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

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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

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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

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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.

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     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

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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.

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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

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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

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                                    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

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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

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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

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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.

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     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

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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.

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Main Report

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                                 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

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     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

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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.

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                       Figure 1-1
      Ohio River Basin Energy Study (ORBES) Region
                       Rgure1-2
                ORBES-Region Coalfields
-Eastern
 Interior
 Coal Province
Appalachian
Coal Province

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                              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

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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.
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     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

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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
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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.
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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.

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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

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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.
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               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
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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).


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                                   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).
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     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.
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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


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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.
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                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

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     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).

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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.
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                                  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).
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     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).
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                                    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

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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.

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     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

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                                    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

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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

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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

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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

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                                   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

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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

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                           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

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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

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               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

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     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

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                                  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

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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

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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

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     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

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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

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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

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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

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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.

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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

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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

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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

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                          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

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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



•

•
•




•
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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

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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.





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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

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     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

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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

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     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

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     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

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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

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 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

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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

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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.
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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

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     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.
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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

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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.
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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.
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     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
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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


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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.
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                            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.
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     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.
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                 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

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                                   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

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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

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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

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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

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                                  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

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                                   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

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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

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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

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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

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           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

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                             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

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     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

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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

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                                   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

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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

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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

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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

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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

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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

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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

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                                    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

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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

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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

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Figure 6-7
Cumulative Capital Costs, Coal-Dominated Scenarios, 1976-2000
130-
120-
110-
100-
90-
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« 80-
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ulat ve capital costs to install new
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ulative costs for sulfur dioxide
ro I, 1976-2000
ulative costs for paniculate 1 '
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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

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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

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                                   Rgure 6-8
        Electricity Prices in the ORBES Region, Coal-Dominated Scenarios
     .G

     ^

     in

     o>
     0)
     E
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     c.
     o
     o
     O
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     *
        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

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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

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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

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                                                 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

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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

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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

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                         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)).

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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

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 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

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     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

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                              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

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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

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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).

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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

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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

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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

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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

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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

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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

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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

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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

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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

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	 _ 	 	 	 	 	
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

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     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.

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             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

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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

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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
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2 5-
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	 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
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yWyjfif
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SEC

8-1 c. Electricity Prices
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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

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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

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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

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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

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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

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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

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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

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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

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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

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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?

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                  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

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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

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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

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                              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

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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

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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

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            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

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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

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                                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
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                           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

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                              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

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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

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                                  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
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                 -20-

                 -30-

                 -40-

                 -50-
                                                          HEG
                                                                 HEG
                                                                         •BC
                                                    Increase over Base Case
                                                    Cumulative SO2 Control Costs

                                                    Increase over Base Case
                                                    SO2 Emissions in 2000

     10
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                                                            /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

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                              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

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     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

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                                  Figure 10-7
           Electric Utility Sulfur Dioxide Emissions in the ORBES Region,
                       High Electrical Energy Growth Case
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                                             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

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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

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                              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

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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

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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

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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

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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

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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

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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.

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     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.
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                  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

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     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.


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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-
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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

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 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.

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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.
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                          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

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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.

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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
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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.

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     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

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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).

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     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.

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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.


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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).

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     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).
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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
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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.
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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).
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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
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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
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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

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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

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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

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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

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                  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

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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

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     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

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                                  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.

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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

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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

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                                  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

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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

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                                    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

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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

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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

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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

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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

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       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

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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

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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

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                              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

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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

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 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

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                                     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

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 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

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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

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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

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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

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                                   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

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                                      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

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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

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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

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                      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).
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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.


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     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
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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).
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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
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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).
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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

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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.


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     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.
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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.


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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.
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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).
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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.
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     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
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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
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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
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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).


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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).
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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
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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.
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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
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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

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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.
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                               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.
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     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.
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Appendices

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                                  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
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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

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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
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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
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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

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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

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                                  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

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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

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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

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  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

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   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

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                                 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

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