Economic, Environmental, and
    Coal Market Impacts of
 SO  Emissions Trading  Under
 Alternative Acid Rain Control
            Proposals
              Prepared for:

        Regulatory Innovations Staff
    Office of Policy, Planning and Evaluation
     U.S. Environmental Protection Agency

        EPA Project Officer: Barry Elman
           In Cooperation With:

         Office of Program Analysis
        U.S. Department of the Interior

       DOI Project Officer: Indur Goklany
              Prepared by:

        ICF Resources Incorporated



              March 1989

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Economic, Environmental, and
    Coal  Market Impacts of
 SO  Emissions Trading  Under
 Alternative Acid  Rain Control
            Proposals
              Prepared for:

        Regulatory Innovations Staff
    Office of Policy, Planning and Evaluation
     U.S. Environmental Protection Agency

        EPA Project Officer: Barry Elman
            In Cooperation With:

         Office of Program Analysis
        U.S. Department of the Interior

       DOI Project Officer: Indur Goklany
              Prepared by:

        ICF Resources Incorporated



              March 1989

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                                    PREFACE
      This  report  presents  the  findings  of  an  analysis performed  by  ICF
Incorporated  for  the Environmental Protection Agency  (EPA)  and the Department
of  Interior  (DOI).    The  assumptions,  findings,  conclusions, and  judgments
expressed in  this report, unless otherwise noted, are those of ICF Incorporated
and should not be interpreted as necessarily representing the official policies
of EPA, DOI,  or other  agencies  of  the  U.S.  government.
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                               TABLE OF CONTENTS

                                                                           PAGE

FOREWORD	    iii

EXECUTIVE  SUMMARY 	   ES-1

CHAPTER ONE:     INTRODUCTION AND BACKGROUND 	  1-1

CHAPTER TWO:     SUMMARY OF FINDINGS	2-1

CHAPTER THREE:   CAVEATS AND UNCERTAINTIES 	  3-1

APPENDIX A:      BASE  CASE  FORECASTS	A-l

APPENDIX B:      PROXMIRE SUMMARY AND  FORECASTS  	 B-l

APPENDIX C:      30 YEAR/1.2 LB.  SUMMARY AND FORECASTS	C-l

APPENDIX D:      BASE  CASE  ASSUMPTIONS	D-l
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                                   FOREWORD
      This analysis examines the impacts of various levels  of  emissions  trading
in the context of  two  representative  proposals  for reducing S02 emissions  from
electric  utilities as part of  an  acid rain control program,  and also in the
absence  of any  such  emission  reduction  program.    The  primary  focus  of the
analysis  is on utility emission levels, utility compliance costs and regional
coal markets.

      The  analysis provides what should be viewed as upper bound estimates of
the potential compliance cost savings and coal market effects  that would result
from each level  of emissions  trading examined.   These  estimates assume  that
utilities  would  achieve  required emission reductions in a least-cost fashion,
by pursuing  the  most  economically efficient combination  of  emissions trades
possible,  subject  to the constraints  noted  in the  report.  However, a range of
practical  considerations would  likely serve  to  limit either the ability or the
desire of utilities to engage  in all of the emissions trades which  are projected
to occur  in this analysis.

      We  call your attention  to this  and other  caveats throughout the  report,
and especially in Chapter Three.   In addition to  discussing the caveats and
uncertainties implicit in the analysis, Chapter Three also highlights a number
of programmatic  issues which  would need  to  be  addressed before  any acid rain
related emissions  trading program  could be  implemented.

      While this report presents  and analyzes  a  range of  emissions   trading
alternatives,  it  does not attempt to address all  possible options.   Nor does this
report draw any conclusions regarding which, if  any,  emissions  trading approach
would be most  suitable for an acid  rain control program.   Any decision regarding
the appropriate level of emissions trading must  take into account  the manner in
which such a program would be implemented and enforced, the magnitude of expected
cost savings,  the ramifications on regional coal mining activity,  and a  complex
array of other technical, environmental and  socioeconomic issues.  This report
is intended to provide useful  information  regarding several  of  these  issues.
It does not, however, set out to address all  the issues relevant to  the selection
of a particular approach.
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                               EXECUTIVE SUMMARY
       This  report examines the ramifications of  different levels of emissions
 trading (which allows  aggregate emission reduction requirements to be achieved
 from multiple sources  in  the most economic  manner,  rather  than  by mandating
 uniform emission  reductions from each source) in  the context of two representa-
 tive electric utility sulfur dioxide emission  reduction  proposals designed to
 control acid rain,  and in the absence  of any new  control program.   The two
 emission reduction proposals  examined are S-316 (the Proxmire bill) and the 30
 Year/1.2 Lb.  proposal.   Some of the key  findings with respect to S02 emission
 reductions,  utility compliance costs, and coal markets are  presented  in this
 summary.  These findings are  followed by a discussion of caveats and uncertain-
 ties that pertain to the reported  results.
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                            SO, EMISSION REDUCTIONS

            Utility S02 emissions are forecast to  increase steadily,
            from 16.3  million tons in 1985 to 21.7 million tons  in
            2010,  under "Base Case"  conditions  (i.e.,  assuming  no
            change in  current emission control requirements).-

            The  Proxmire bill is  forecast  to reduce  utility  S02
            emissions  from  Base  Case levels by:

                   almost 5  million tons by 1995
                   about 9 million tons by 2000 and thereafter.

            The  30 Year/1.2  Lb.  proposal  is  forecast  to   reduce
            utility S02  emissions  from Base  Case  levels by:

                   almost 4  million tons by 1995
                   over 6 million tons by 2000
                   about 11  million tons by 2010.
                      25
       SO2  Emissions
      (millions of tons)
                      20
                      15-
                      10
                       5-
                          — Base Case
                           - -  Proxmire
                          	30 Yr./1.2
                       1985
                                1990
                                         1995
                                                  2000
                                                           2005
                                                                    2010
            Allowing  emissions trading under these proposals would
            have  no  significant effect upon  the  overall amount or
            timing of emission reductions.
I/
      Please note  that these EPA  Base Case forecasts were  developed in  early
      1987; recent developments (e.g. ,  state acid rain laws, SIP revisions,  etc.)
      will be  incorporated into a  newer base case currently being developed by
      IGF for  EPA.   This would likely  result  in  S02  emissions about 1.0  -  1.5
      million tons lower than indicated by the EPA Base Case used for  this study.
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                              UTILITY  COMPLIANCE  COSTS
             As  emission  reduction requirements  increase,   annual
             compliance costs  increase disproportionately.  Assuming
             only intrautility  emissions trading (among currently
             existing  sources)  for  the  proposals analyzed herein,
             costs  increase  rapidly  as   reduction  requirements
             increase:
                 Increase in
                 Annualized
                   Costs
                 Above Base
                 Case Levels

               (billions of 1987
                 $ per year)
                                          SOj Emission Reductions
                                             (millions of tons)

             Utility compliance costs under Proxmire and 30 Year/
             1.2  Lb.  increase  steadily  over time,  reflecting  increasing
             emission reduction requirements over  Base Case levels.
            Increase in
            Annualized
           Costs Above
         Base Case  Levels
          (billions of 1987
            S per year)
                           3-
                           1-
                                   Proxmire
                                   Existing-Existing
                                   Intrastate
                                   30 Yr/1.2
                                   Existing-Existing
                                   Intrastate
                           1995
                                           2000
                                                           2005
                                                                           2010
060)105
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                          ECONOMIC BENEFITS OF EMISSIONS TRADING
                  The Proxmire and 30 Year/1.2 Lb.  proposals were analyzed
                  under various emissions trading schemes to determine  the
                  economic effects of:

                        increasing  the  geographic   scope  of  trading
                        (intrautility, intrastate, and interstate)

                        allowing trading between new and existing sources.

                  In addition, the Base Case was examined with existing-
                  new trading and a 1.2 to 1 trading ratio  (i.e. , each  ton
                  of excess emissions  must  be offset by at  least 1.2 tons
                  of extra reductions elsewhere).

                  The  utility  compliance  costs  associated  with   the
                  alternative levels  of assumed emissions  trading under
                  the analyzed proposals are presented below:
                                 Increase  in  Utility  Costs
                               Relative to Base Case Levels
Proxmire
  No Trades*
  Ex-Ex Intrautility
  Ex-Ex Intrastate
  Ex-New Intrastate
  Ex-New Interstate

30 Year/1.2 Lb.
  Ex-Ex Intrautility
  Ex-Ex Intrastate
  Ex-New Intrastate
                              Annualized
                        (billions of 1987
                         1995    2000    2010
  2-3
  0.8
  0.4
  0.4
  0.4
  0.5
  0.4
  0.4
5-6
2.3
1.8
1.7
1.5
1.3
0.9
0.5
6-7
3.3
2.9
0.9
0.6
4.5
4.1
3.6
       2010
 Cumulative Capital
(billions of 1987 $)

       20-25
          9.7
          7.8
         -8.9
       -11.1
        10.1
         8.6
         2.0
       2010
   Present Value
(billions of 1987 S)

        40-50
         19.6
         16.0
         10.6
          9.0
         17.9
         14.6
         11.7
Base Case
   No Trades
   Ex-New Interstate

            Ex-Ex:
            Ex-New:
         -0.7
       -5.3
              -25.8
Trades between existing sources only
Trades between existing and new sources
                              -15.8
            This case was not  explicitly analyzed as part of  this  study;  the rough
            estimates presented are based on previous analyses conducted for EPA.
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            As  shown in the table on page ES-4,  the greatest single
            increment  of  cost  savings  associated with  emissions
            trading is obtained when expanding the scope of trading
            from   a  "no   trading"   scenario   (i.e.,   unit-by-unit
            compliance  with  uniform  reduction  requirements)   to
            trading  at the  existing-existing intrautility  level.
            Allowing even this relatively restricted form of trading
            reduces  the annual  compliance  costs  of  an acid rain
            program by  30  to  60  percent.-'

            Increasing  the geographic  scope  of emissions  trading
            beyond the  intrautility  level would  further reduce  the
            utility cost impacts of both analyzed emission reduction
            proposals  while  achieving equivalent  overall  national
            emission reductions.  By 2010, expanding the geographic
            scope  of trading:

                   from  intrautility  to intrastate further  reduces
                   present  value  costs by $3.3-$3.6 billion  (or  20
                   percent),  cumulative capital costs by  $1.5-$1.9
                   billion  (or 15-20  percent), and  annualized costs
                   by $0.4  billion (or  10  percent).

                   from  intrastate  to interstate  further  reduces
                   present  value  costs  by  $1.6  billion  (or   15
                   percent), cumulative capital costs by $2.2 billion
                   (or  20  percent),   and annualized  costs  by $0.3
                   billion  (or 30 percent).

            Permitting  emission trades  between existing  and new
            sources (i.e., allowing new sources to  be built without
            scrubbers as  long as any resulting emission  increases
            are offset  by extra reductions  at  existing  sources)
            would  also reduce cost impacts associated with  emission
            reduction  proposals.   As shown  in  the table on the
            opposite page, expanding  the scope of intrastate trading
            to  include  new sources  is projected to reduce  present
            value  costs to  2010 by  $2.9-$5.4 billion (or 20-40
            percent), cumulative capital costs to 2010 by $6.6-$16.7
            billion  (or  80-200 percent), and annualized costs  in
            2010 by $0.5-$2.0 billion  (or 15-70 percent).
      No detailed modeling analysis was conducted in developing this estimate.
      Rather, this  estimate  is approximate and was  derived from previous ICF
      analyses for EPA of acid rain proposals  with no trading provisions.  See,
      for instance,  An Economic Analysis of HR-4567:  The Acid Deposition Control
      Act of 1986, August 1986 (Default Case).
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            The  level  of cost savings resulting from  existing-new
            trades  under   the   two   analyzed  emission   reduction
            proposals  depends  significantly upon  the  amount  of
            reductions that would be  required.  By 2010, the present
            value cost savings attributable to existing-new trading
            range from $5.4 billion  (assuming about 9  million  tons
            of  reductions)  to  $2.9 billion  (assuming  about  11
            million tons of reductions).   Cumulative  capital  cost
            savings attributable to   existing-new  trading by  2010
            range from $16.7 billion  to $6.6 billion assuming about
            9 million  and  11  million. tons  of  reductions respec-
            tively.   Corresponding  annualized cost  savings  range
            from $2.0 billion to  $0.5 billion.

            Most of the savings associated with existing-new trades
            accrue in  the later years of  the analysis.   By 1995,
            there would  be  few additional new coal plants on-line
            to  take  advantage of  such  trading  opportunities,  and
            annualized cost savings are less than $0.1  billion.   3y
            2010, a large amount of new coal plants are forecast  to
            be built,  and annualized  cost  savings range from $0.5 -
            $2.0 billion (up to  70 percent savings).

            Permitting existing-new trades under the Base  Case (wich
            a 1.2:1 trading ratio) would result in a small emission
            reduction by 2010 (about 1.4  million  tons)  with very
            substantial  cost savings:  $15.8 billion present value
            cost  savings,  $25.8  billion  cumulative capital  cost
            savings,' and $5.3 billion annualized cost  savings.

            As  illustrated  on  the  opposite page,  the  greatest
            economic savings could  be provided by an  emissions
            trading  program  which   incorporates  both  increased
            geographic   flexibility    and   existing-new   trades.
            However,  expanding  the scope  of trading opportunities
            would also increase  the  complexity  and administrative
            burden of an acid rain control program, and would raise
            a number of  additional issues which, would need  to be
            addressed before such a  program could  be  successfully
            implemented.
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          Increase in the
          Present Value of
           CoetaOvsr
          the 1887-2010
          Period Above
         Base Case Level*
         (batons of 1967$)
                                            Proxmlre Case*
                                                                        ExWtog-EAJttig ExiiBne-ExWIne  EMMng-Nn>
                                                                           MrMity      MruUto      Mruul*
                                                                                  30Yr/1.2U)CMM
           Increase In
        Annualzed Costs
          In 2010 Above
        Base CAM Levels
     (billions of 1987 Vyear)
                                                      Mmbto     MrnM*     Hraul»y
                                             Proxmire Cases
                                                                                  30 Yr/l. 2 LD Ctaaa
             Changs in
          CunJative Capital
         Costa by 2010 From
          Base Case Levels
          (billions of 1987$)
                                            Proxmire Cases
                                                                                  30 Yr/1.2 Lb Casw
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                                   COAL MARKETS
             Shifts   in   coal  production  away  from  high  sulfur
             producing  regions  (i.e.,  Northern Appalachia and  the
             Midwest)  are forecast  to  increase as  a result of  the
             implementation  of existing-existing trading under both
             the  Proxmire   and  the  30  Year/1.2  Lb.  proposals.
             Allowing existing-new  trading  increases the magnitude
             of such  production shifts.
                 600


                 480-


                 420-
                 380
    Northern
  Appalachian
and Midwestern 340
Coal  Production
(millions of tons)
                 300
                 260-
                 220-
—— Base Case
 ... ... ,. , Proxmire Ex-Ex Intrastate
—— Proxmire Ex-New Intrastate
" - - « 30/1.2 Ex-Ex Intrastate
-"*""-""• 30/1.2 Ex-New Intrastate
                   1985
       1990
1995
2000
2005
2010
             Regional coal  mining employment  trends largely follow
             regional coal  production forecasts.   Under either the
             Proxmire bill   or  the  30 Year/1.2  Ib.  proposal  with
             existing-existing  trading,  the  level of  future  coal
             mining employment declines significantly  in high sulfur
             coal regions and increases in low sulfur coal regions.
             This effect  is more pronounced under the existing-new
             trading cases.  See  table on page ES-9.
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                  A  relatively  small  amount of net national coal mining
                  job slot losses (on the order of 2  percent of  Base Case
                  forecasted levels in 2010) are forecasted to result from
                  the implementation  of  either the Proxmire bill or the
                  30 Year/1.2 Lb. proposal with existing-existing trading,
                  as coal demands shift to lower sulfur Western coal mines
                  that generally have higher productivities.  Since these
                  demand  shifts  are  greater in the existing-new trading
                  cases  (because fewer  plants are  scrubbed),  net coal
                  mining job slot losses^also are  higher (on the order of
                  5 percent of Base Case forecasted levels  in 2010).
                   Changes In Regional and National Coal Mine Employment
                                  (thousands of workers)
Northern Appalachia
Central Appalachia
Southern Appalachia
Midwest

Rest of U.S.
TOTAL U.S.
                       Actual  Actual
                        1980    1985
 70
 91
 12
 35
 23
231
                   Change in Job Slots
                     Relative to Base
                    Proxmire  Proxmire
              Base  In-State  In-State
              2000   Ex-Ex     Ex-New
45
70
9
27
20
170
35
69
6
20
24
154
 -8
+12


 -8

 ±6
 +1
 -9
+12
 ±6
 +1
                      Change in Job Slots
                        Relative to Base
                       Proxmire  Proxmire
                 Base  In-State  In-State
                 2010   Ex-Ex     Ex-New
 54

 95

  9

 29

 47

235
 -7
 +8
 -1
-12

 ±8
 -4
-20
+13
 -2
-16
+14
-11
                  The number  of  current mine workers who  will actually
                  lose their jobs will  be  less  than the job slot losses
                  shown above.  Many currently employed miners will have
                  retired or moved to other jobs by 2000 or 2010.

                  Job losses in  other  industries  and additional adverse
                  economic impacts would occur in regions that experience
                  declines in coal mining employment.  Conversely, other
                  regions would experience  more  generalized job gains and
                  enhanced economic activity as  a result of increases in
                  coal mining  employment.   Further,  regional economies
                  would  be  affected  by  changes  in electricity  costs
                  associated with  varying  levels of  emissions trading.
                  None of these factors were assessed in this report.
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                           CAVEATS AND UNCERTAINTIES
            This   analysis   estimates  the  emission   reductions,
            compliance  costs,  and coal  mining impacts  associated
            with various levels of emissions trading in the  context
            of  two utility  S02 emission reduction proposals.  The
            results  presented herein assume  that  utilities will
            achieve least-cost compliance with acid  rain reduction
            requirements by pursuing all economic  emissions  trading
            opportunities.   However,  a range of  technical,  finan-
            cial,  programmatic  and  institutional   considerations
            could  serve to limit the ability or desire  of utilities
            to  engage  in  certain trades, especially trades  beyond
            the existing-existing intrautility level.  To the extent
            that full scale implementation of emissions trading (as
            envisioned  in this analysis)  is  constrained by these
            considerations,  the  cost savings  and  other   impacts
            projected herein would be reduced  accordingly.

            A number of important issues must be addressed  before
            any acid rain related emissions trading program could
            be  initiated.   These concern  the  structure of such a
            program, the  manner in which  it  would be  implemented
            and enforced, and its relationship to  other environmen-
            tal  objectives   (such  as  attainment  of  the National
            Ambient Air Quality Standards (NAAQS),  the determination
            of  best available control technology (BACT),  and the
            prevention  of significant deterioration  (PSD) in areas
            which are already cleaner  than the NAAQS).  These issues
            are critical  in determining how  such a program would
            work in practice,  how effective and reliable it would
            be  in  producing the required emission reductions, and
            the extent  to  which  the   forecasted  savings would be
            realized.  The assumptions and  uncertainties related to
            these  issues  and  other   aspects  of  this  study  are
            discussed in Chapter Three.

            Note that these analyses  were  conducted using  Interim
            1987 EPA Base Case assumptions developed in late 1986.
            Recent  trends  in energy markets   (e.g.,  declining
            scrubber costs, more likely availability of developing
            technologies, increasing mining productivity) could lead
            to somewhat different quantitative emission reduction,
            cost, and coal market impacts than presented herein (see
            Chapter  Three).   However,  most  of  the   qualitative
            effects of  emissions trading on utility costs and coal
            markets  would  remain largely  as  discussed  in this
            report.
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                                  CHAPTER ONE

                          INTRODUCTION AND BACKGROUND
Purpose of Study

     Legislative interest in the "acid rain" issue has heated up significantly
recently as part of a resurgence in public awareness of environmental concerns.
Many acid rain control proposals have  been  developed  in the past few years in
search of  a  compromise that would be  agreeable to all  parties,  by providing
sufficient sulfur dioxide (S02)  and nitrogen oxide  (NO^) emission reductions to
address  the  problem  at  a  relatively  low  compliance  cost and  without  major
dislocations in regional coal production and employment.

     One manner  in  which  acid rain control proposals can  be  designed to keep
compliance costs to  a minimum  is  through the inclusion of "emissions trading"
provisions.   Emissions  trading enables  multiple  sources  to  trade . emission
reduction requirements, so  that overall emission reductions can be achieved at
a lower cost.  Emissions trading in the context of an acid rain control proposal
can lower compliance  costs  significantly, while still preserving the required
amount of overall emissions reductions.

     There has been a noticeable trend towards consideration of certain emissions
trading schemes (i.e., those permitting trades between sources within the same
utility company or state) in conjunction with acid rain legislation.  However,
there are other trading options that offer  even more  economic flexibility but
have yet to be considered in most  legislative proposals.  Few of the acid rain
bills  or proposals   offered  to date  include  provisions  allowing the  full
interstate trading of emissions. Moreover, no acid  rain bill has considered the
possibility of  exploiting  the  potential  cost savings  associated  with trades
between existing sources and new sources.

     This study,  performed by ICF at the request of  the Environmental Protection
Agency and the  Department of the  Interior,  examines  several  emission trading
schemes,  including relatively unexplored  emission trading possibilities such as
wide-scale interstate trading and  existing-new trades.  These emission trading
schemes  are  examined  in  the context  of two  prototypical acid  rain  control
proposals --  the Proxmire  bill  (S-316,  the Acid Deposition and Sulfur Emissions
Reduction Act of 1987) and  the  30  Year/1.2  Lb.  emission reduction proposal --
as well as in the absence of  any such  reduction program.   The report presents
analyses of  the potential  economic,  environmental,   and coal  market  impacts
associated with  expanding  the scope of emissions trading  under these alternative
control scenarios.   Furthermore, this study  identifies some of the major issues
pertaining to the inclusion of emissions trading provisions, and in.particular
the allowance of existing-new and  interstate trading.

     This introductory chapter  presents  an  overview and historical background
on the subjects  of acid rain and emissions trading.  Chapter Two summarizes the
major findings from  the  analyses  of the different trading variants under the
Proxmire bill  and the  30 Year/1.2 Lb.  proposal.   Chapter Three  presents  a
discussion of caveats and uncertainties pertaining  to these analyses.  Detailed
numerical forecasts under a  baseline reference case ("Base Case"), the Proxmire
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bill, and the 30 Year/1.2 Lb.  proposal  for the years 1995,  2000,  and 2010 are
presented in  Appendices  A,  B, and  C  respectively.    (Appendices B  and C also
provide  detailed  discussions  of  the  Proxmire  and  30 Year  1.2  Lb.  forecasts
respectively.)  Appendix D presents a list of the assumptions used in the Base
Case.

     Only S02 emission reductions from U.S. electric utility powerplants and
emissions trading among  these  sources were examined in this study,  at EPA and
DOI's direction.  This  report does not present  forecasts of the  economic and
environmental impacts associated  with  the reduction or trading of utility NOX
emissions, nor with the reduction or trading of S02  and NOX emissions from non-
utility sources, but such impacts are not expected to be large relative to the
impacts  facing  the  utility  sector in conjunction with S02  emissions.   Never-
theless, these impacts warrant further study.

     Further, it should be noted that the analyses presented  in this report were
conducted during 1987 and 1988 based on EPA Base Case assumptions developed in
late 1986.   (ICF is currently  developing  a new base case for EPA with updated
assumptions.)  Many trends exhibited recently in the  energy industries (notably
higher coal  mining  productivity,  higher electricity  demand  growth,  and lower
pollution control technology costs)  would  likely lead to different baseline and
control  cost  assumptions .than employed in  this study.   Hence,  some  of the
quantitative  cost,  emission,  and coal production  impacts  of  these emission
reduction scenarios would likely be different than presented herein.  However,
most of the qualitative effects of emissions trading on utility costs and coal
markets as discussed in this report would remain largely unaffected.

Background on Acid Rain

     Acid rain, the acidification of natural atmospheric precipitation,  is of
concern because of potential adverse environmental impacts on natural ecosystems
(including  aquatic  life,  wildlife,  vegetation,  forests,  and  agriculture),
materials (such as  metals, wood, paint,  and masonry),  and general public health
and welfare.  In addition, the  gaseous pollutants that are suspected to promote
acid rain are also thought to  be  linked to certain atmospheric problems, such
as local ozone buildup, suspended particulate matter and reduced visibility.

     The effects of  acid  rain are  thought to be magnified  in ecosystems that are
especially sensitive to increased acidity.   Some  such areas of the United States,
upstate New York and New England in particular, have experienced deterioration
of forest and aquatic life,  which is believed by a  number of scientists to be
due to increasingly acidified  rainfall.   However, the rain  that  falls on the
northeastern U.S. may not be acidified predominantly by local sources; acidified
airborne moisture can  travel for  thousands of miles  before  falling to Earth.
Because  of  this,  acid rain  is more  than merely a local,  or  even national,
concern.  Areas of Eastern  Canada  have also witnessed  similar environmental
degradation, and claim that acid rain from the United States  is the major source
of these effects.   Nonetheless,  there is still controversy as  to  the true
underlying cause of these effects, and  it  is  possible  that a number of stresses
are at work.  For example,  some scientists believe local ozone problems rather
than acid deposition may  be  the major cause of the observed stresses on forests
in these areas.
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     It is  generally  believed that three main precursor pollutants,  S02, NOX,
and volatile organic compounds (VOC), participate in the formation of acid rain.
While only about forty percent of VOC emissions originate from man-made sources,
man-made sources contribute the majority of S02 and NOX emissions.  For example,
about  25  million tons  of  S02 is emitted annually  in  the U.S.  from man-made
sources (about 70% from electric generating powerplants), versus less than 500
thousand tons of annual natural S02 emissions.  As for NOX, 22 million tons are
emitted  annually in  the  U.S.  from  man-made sources  (about  one-third  from
powerplants), versus  about  3  million  tons per year  from natural sources.   The
Ohio Valley region (Missouri,  Illinois,  Indiana, Kentucky, Ohio, West Virginia,
Pennsylvania) contributes  about 45 percent of national annual S02 emissions.
Texas  is  the predominant  NOX emitting  state,  followed by California,  Ohio,
Pennsylvania, and Illinois.  Emissions  from these areas are carried long-distance
by prevailing high-altitude wind currents to a number of Eastern states.

     Because of  concern about protecting local  environmental  conditions,  five
states (New Hampshire, Massachusetts,  New York, Wisconsin, and Minnesota) have
passed legislation  in the  past few years requiring curtailments or  caps  on
statewide S02 (and,  in some cases,  NOX)  emissions.   However,  these states and
others recognize that  state laws can only be partially effective  in reducing the
impacts of acid rain.  Because of acid rain's interregional (and international)
nature, the debate concerning acid  rain control has  been and  will continue to
be focused on federal  acid rain legislation.   As a result, various proposals for
reducing emissions,  with attendant differences in forecasted regional economic
impacts,  have been put forth  in Congress over the past  few years.

Costs and Benefits of Acid Rain Control

     Much of  the controversy  surrounding the  acid  rain issue  stems  from the
regional differences in  costs  and benefits that would accrue under any acid rain
control program.    Those  areas  of the  country  with more sensitive  aquatic
ecosystems and/or mountainous  terrains, and that are  downwind of higher emitting
states, are most  likely  to  be deleteriously  affected  by  continued  acidic
rainfall.  These  states (including, most prominently, New York and the New England
region) would receive the greatest benefits  from the implementation of federal
acid rain legislation.  On  the other hand, those areas  of the country that emit
the highest quantities of the suspected precursor pollutants S02 and NOX -- i.e. ,
particularly states in the Ohio Valley area  -- would incur the highest control
costs under acid rain legislation  (either as  a result of switching to cleaner
but more expensive fuels or installing pollution control technologies in order
to reduce emissions).   These costs would result in higher costs to electricity
consumers  (including  residences,   industries,  and commercial  establishments)
which,  in turn, would affect  the economies of  these  areas.   Further,  regional
economic activity, as related to coal production and coal mining employment,
could be significantly affected under  acid rain legislation,  since high sulfur
coal reserves and low  sulfur coal reserves are not uniformly distributed across
the country.  Midwestern and some Eastern states with high sulfur coal deposits
could experience  reduced  economic  activity  (due  to  reduced demand  for these
coals), while other  Eastern states  and many Western states with low sulfur coal
reserves could show  increases  in economic activity (due  to increased demand for
lower sulfur coals).  Thus, the costs and benefits  of acid rain control would
not coincide regionally.
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     A major obstacle in evaluating the attributes of acid rain legislation is
that the benefits resulting from any program are extremely difficult to quantify.
The negative effects of acid rain on  the environment are problematic to isolate
and to measure.  Further, the mitigative effects of emission reductions on the
environment are also quite difficult to assess.  Finally, the value to society
of improvements to the environment is also difficult to measure.  What exactly
is the  social  value  of recreation, or of the  opportunity  to enjoy  a pristine
environment?   In cases where human health may  be concerned,  what is the value
of reduced mortality or morbidity?  Some estimates of acid rain control benefits
have been  made, but are generally quite speculative  given the aforementioned
uncertainties.

     While the benefits  to  society of acid rain legislation are difficult to
quantify,  the  magnitude  of direct costs  to  utilities is  generally easier to
estimate.   Forecasted annual costs  to  electric utilities for  most proposals
(requiring 40-50 percent reduction in S02 emissions) range from about $2 billion
to $6 billion.  However, forecasted annual utility compliance  costs  for very
stringent  proposals  (requiring  70   percent   S02  emission  reductions)  have
approached $14 billion.  These cost estimates do not include  any additional costs
utilities might face in reducing NOX emissions.   By comparison, revenues for the
entire U.S. electric utility industry in 1985  were about $150 billion.   Other
industrial sectors  and mobile sources  could also face significant costs to comply
with potential acid rain legislation; however,  under most proposed legislative
initiatives,  there would be relatively  few  reductions  required  from  these
sources, and thus  costs  would  be low relative to  those  likely  to be  faced by
utilities.

     The indirect impacts and welfare losses due to acid rain controls could also
be significant.  Jobs  may be lost in high sulfur coal  mining  communities of
Northern Appalachia  and  the Midwest, and  general economic  activity  in these
regions of the country could suffer.  Higher electricity prices to consumers as
a result of emissions clean-up could have repercussions on national industrial
and consumer activity, as well as on the international competitiveness of U.S.
industry.   There   could  also be  opportunity  costs associated  with pollution
control technology investments,  since these capital expenditures could be put
to use for other social or private investment purposes.

     The costs and  benefits of  any acid  rain  control  program are  heavily
dependent  upon three  factors:    the  level   of  required national  emission
reductions, the timing of  the  required emission reductions,  and the  regional
distribution of the required emission reductions.  The numerous proposals and
bills issued over  the  past  few years to deal with acid  rain vary widely with
respect  to  these  three  factors,  and consequently would have  quite different
forecasted costs and benefits to the nation and  to the affected regions.

Emissions Trading

     One topic in  the  acid  rain debate  that has generated increasing interest
is the notion  of emissions  trading.   Through the use  of emissions trading, it
may be possible to achieve  the desired level  of emission  reductions  at lower
cost.   By  allowing emissions trading, compliance  with  any emission reduction
proposal would thus become  less  expensive.  However,  the level of air quality
improvement would remain largely unaffected.  Therefore, the cost-benefit ratio
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of the proposal would be  improved  (decreased costs for the same amount of air
quality benefits) by the implementation of emissions trading.

     The  principle  behind  emissions  trading  is  straightforward.    Under the
traditional command-and-control approach to environmental management, Congress,
EPA, or a State regulatory agency assigns  pollution control obligations to each
individual source.  This is generally  accomplished by applying uniform emission
limits or technology requirements to all sources that belong to common industrial
source categories (e.g., existing coal-fired powerplants).  While considerable
analysis may be carried out to ensure that it  is  feasible for the sources in a
given  source  category  to  meet the uniform  requirements,  the  application of
uniform standards can  result  in substantial cost inefficiencies.   As control
costs can differ  significantly  from source  to  source  and from source category
to source category,  these variations  in  control  costs make  emissions trading
economically desirable.

      Instead of mandating fixed uniform emission reductions from each source,
emissions trading permits the  aggregate emission reductions to be achieved from
sources in the most economic manner.  Thus,  those sources that are inexpensive
to control  can reduce  emissions  more  than  necessary.  These  extra emission
reductions can then be  traded  to other sources  that  are more costly to control,
allowing these latter sources to reduce emissions less than would be otherwise
required, so long as the  same  level of aggregate  emission reductions would be
achieved.

     The costs of  compliance with emissions regulations are reduced as the scope
of trading is broadened.   Thus,  uniform emission limits or  caps  imposed on a
unit-by-unit basis  are  more costly and difficult to  satisfy  than  permitting
compliance on a utility  company basis  (and allowing the  utility to use emissions
trading in order to meet overall targets for its generating system in the lowest-
cost manner).  Similarly, an emissions trading scheme  that restricts trades to
an intrastate basis would  offer  fewer trading  opportunities  (and,  hence, less
potential cost savings)  than would  a scheme that permits emission trades across
state  lines.   Further,  a  trading  scheme which  permits emission  trades only
between currently existing sources would be more restrictive,  and compliance
would be more costly, than a program that would sanction trades with new, future
sources.

      The amount of  savings realized by emissions  trading would also depend upon
the nature of  the specific emission control program enacted.   In  particular,
there would be fewer opportunities  for emissions trading, and consequently less
savings, as the amount  of  emission reductions  required by the  control program
increases.  This  is  because, as emission reduction programs become increasingly
stringent, almost all  sources  are required  to  pursue expensive  compliance
options.  As a result,  increased  trading flexibility cannot  lower  costs  as
significantly.

Background History of Emissions Trading

     The emissions trading concept was  originally developed  by  EPA  in 1976 in
the  form  of an  "offset"  program  for new industrial  sources.   This  program
(confirmed by Congress  in  1977,  and revised by EPA in 1980) ensures  that the
addition of new powerplants and other major stationary sources of emissions will
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not  lead  to violation of ambient air  quality standards.   In "non-attainment"
areas (i.e., areas that fail to meet the National Ambient Air Quality Standards
stipulated by the Clean Air Act), existing sources must make offsetting emission
reductions  to compensate for increases  in emissions caused by the construction
of any major new source.  Usually,  these offsets are obtained from other existing
sources on the  same  site  as  the  newly constructed  source  (i.e.,  "internal"
offsets),  although a  number  of offsets have involved the trading of emissions
between different sites (i.e., "external" offsets).  In total, approximately 2000
offsets have been approved throughout  the country to date.

     The notion of emissions trading was then expanded in 1979 to  include trading
between certain existing  sources,  thereby allowing for more  cost-effective
compliance with State  Implementation Plans (SIPs) designed to attain and maintain
ambient air quality  standards.   This  "bubble" policy  allows  selected  sets of
existing  sources  that are  located near each other  and emit the same pollutant
to be treated as though under a giant bubble.  As long as total emissions under
the  bubble  are  not  greater than  the   sum  of the  individual  source  emission
limitations, and other environmental and programmatic requirements are met, an
alternative  combination  of emission  limitations  for  the individual sources is
allowable.  Thus,  sources within the bubble with high control costs  can emit more
as long as  other sources under the bubble emit less.

      In its April 1982 Interim Emissions Trading Policy, EPA expanded the bubble
program by  allowing more widespread  use of  bubbles,  as well as their adoption
by  states under  EPA-approved  "generic  bubble  rules."   However  a number of
controversial  issues  arose in  the  course  of implementing  the 1979 and 1982
policies.   These related to the possible interference of bubbles with air quality
progress  in nonattainment areas, as well as to a number of other technical and
programmatic concerns.

      EPA issued its  Final  Emissions Trading Policy in December 1986.  The final
policy incorporated special "progress requirements"  for bubbles in nonattainment
areas  lacking  approved  SIPs  (including all  areas failing to  meet the 1987
statutory deadline for attainment).  In particular,  it mandated that all bubbles
approved in these areas must contribute to air quality progress by resulting in
a net reduction in actual emissions of at least twenty percent.  The final policy
also clarified and tightened requirements for bubbles in other areas.

      Since adopting its first bubble policy in 1979, over 50 bubbles have been
approved by EPA, with approximate  savings (based on industry estimates) of $300
million.  Further, several  states have  adopted bubbles on their own by applying
EPA-approved generic  bubble rules.  Approved bubbles at electric utility sources
are presented in Table 1-1.

     One of  the  more  controversial  developments  in emissions  trading practice
has been  the recent publication by  EPA of a policy concerning the approval of
bubbles at  certain  new sources.    New Source  Performance  Standards  (NSPS)
compliance  bubbles allow firms to  meet NSPS  by over-controlling  one new NSPS
facility  in  lieu  of more costly control on  another such facility.   These NSPS
compliance  bubbles must  produce actual reductions  at least as  great as those
achieved by traditional unit-by-unit compliance.  This policy has been instituted
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                                         TABLE 1-1

                        Approved Electric Utility Emissions Bubbles
Utility

Narragansett Electric


Kentucky Utilities

Tampa Electric

Burlington Electric

Toledo Edison

Central Illinois Public Service
Powerplant

Manchester Street/
 South Street

Green River

Cannon

Moran

Bay Shore

Newton*
City          State

 Providence    . RI
 Muhlenberg

 Tampa

 Burlington

 Oregon

 Newton
KY

FL

VT

OH

IL
Pollutant

    S02


    S02

    S02

    S02

    TSP

    SO,
*  NSPS Compliance Bubble
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 at Central  Illinois  Public Service Company's two Newton powerplant units as of
 1987.i'

     As implied above,  the first step in developing an emissions trading proposal
 is  to determine  baseline emissions,  or  the  level  of  emissions  from which
 "increases"  and  "decreases"  are  measured.   The Final Emissions Trading Policy
 contains detailed and elaborate criteria for determining baseline emissions from
 different types of emission sources in different types of air quality situations.
 It then must be demonstrated that the proposed trading scheme will not lead to
 local  air  quality violations.   For  bubbles  involving   S02  emissions,  this
 generally  requires  the  use  of  sophisticated  ambient air quality  dispersion
 models.   The  complicated  procedures  for  determining baseline  emissions  and
 modeling air quality impacts reflect the technical and programmatic complexity
 of  emissions  trading  in  the context of  a  SIP  compliance  program.    This
 complexity,  combined  with   the  controversy  surrounding  development of  the
 emissions trading  policy, has  served as a deterrent to full utilization of the
 policy by the  regulated community.

 Emissions Trading  and Acid Rain Control

     Emissions trading schemes in the  context  of acid rain legislation (i.e.,
 legislation  that would require reductions in S02  and NOX emissions from current
 levels) could be structured quite  differently than the trading programs currently
 in effect,  and  could, therefore, avoid many of the complexities  and controversies
 of the current  trading schemes. First,  all current SIP requirements could remain
 in place under acid rain  legislation, so that no increase in SIP emission limits
 at any existing units would occur.  Thus, local non-attainment issues would not
 arise under an acid rain control program allowing emission trades among existing
 units because all required reductions, as well as  all extra  reductions available
-1     The Newton  case  is  an interesting example.  Unit  1,  brought on-line in
      1979, has an advanced scrubber  (a type of S02 pollution control equipment)
      design that  enables  the  unit to emit well below the  original 1971 NSPS
      Subpart D restriction (1.2 Ibs. S02/mmBtu with no minimum sulfur removal
      requirement) under which the unit is regulated.  Unit 2, brought on-line
      in 1982 (also grandfathered in under the NSPS Subpart D regulations, and
      not regulated by  the newer 1979 NSPS Da requirements stipulating a minimum
      level  of  sulfur  removal  through  technological controls)  was completed
      without a pollution control device.  Central Illinois Public  Service (CIPS)
      proceeded to petition EPA for a bubble  at Newton; CIPS  desired to burn less
      expensive local  non-compliance (i.e.,  greater than  1.2  Ibs. S02/mmBtu
      sulfur content) coal  in unit 2 rather than using more expensive compliance
      coals from more distant mines,  in exchange for increasing the scrubber's
      operating efficiencies at unit  1 and  emitting  at-rates  well below those
      required by  the  NSPS.   EPA agreed, with  the stipulation that the plant
      average emission rate not exceed 1.1  Ibs./mmBtu  (i.e.,  more restrictive
      than the NSPS for each individual unit) .  Therefore, the Newton bubble has
      three benefits:   (1)  more  emission  reductions are achieved than otherwise
      required through  conventional stack-by-stack compliance with NSPS Subpart
      D, (2)  overall compliance costs at  the  powerplant are reduced  (by $22
      million  annually,  according  to CIPS estimates),   and  (3)  local  coal
      production and mining employment are enhanced.
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for  credit,  would  be above  and beyond  those required  by SIPs  for ambient
attainment purposes.  Further,  an acid rain emissions trading scheme would focus
on total  atmospheric  loadings of pollutants rather  than  on local ambient air
quality  attainment,  so  that  trades can  occur over  a greater  distance  than
typically associated  with bubbles.   Ambient air  quality  modeling of existing
source  trades  (to  assure equivalent localized  ambient  reductions)  would  be
unnecessary  because  the law  would mandate   state  or  regional,  not  local,
reductions.  Determination  of baseline emissions  (to  calculate  the  amount  of
emission reductions required or available  for trade at each source) would become
a simpler and less controversial  process as  well,  because  new, tighter, clearly
defined emission  limits  or  caps  would be  established for existing units under
state acid rain control plans,  and these would  logically serve as the basis for
determining baseline emissions for  existing units engaging in trades.  In the
case of trades  involving new sources, the  continued operation of the New Source
Review (NSR)  program would ensure that any increases in emissions from new units
as a  result  of a trade would not  jeopardize  applicable  ambient  air quality
standards or  Prevention of Significant Deterioration (PSD)  increments.  However,
both the NSPS and NSR programs (as set out  in the current Clean Air Act) would
need to  be  explicitly modified  in  order  to allow  new source  emission limits
resulting from these programs  to be satisfied through  trading.

     One possible  method  to implement emissions  trading in  the context of an acid
rain control program would be  to initially  allocate to each source or utility
an emission reduction requirement or an emission  target or limit.   Each source
or utility would then be  issued marketable emission permits corresponding to its
emission  target.   Trades could  take place  through the exchange  of  emissions
permits within  a single utility or in a  statewide or interstate emission trading
marketplace.    The  price  of  emissions  permits   would be  determined  in  the
marketplace,  and would be expected to approximate  the marginal cost of reducing
emissions --  the highest  cost of reducing emissions in the  utility system, state
or interstate area.

     Although  certain  institutional and  administrative  costs  (such as  data
collection and verification, enforcement,  and the operation of trading forums)
would be imposed by  the implementation of an acid rain emissions trading scheme,
these costs would likely be small in comparison to the cost savings due to the
increased flexibility offered  through emissions trading.  Furthermore, some  of
these costs  would likely be  incurred  under any  emission reduction  proposal,
irrespective  of the extent of allowable emissions trading.  For example, it would
be necessary  to monitor emissions from each source  to determine compliance under
any acid rain legislation implementation scheme, regardless of whether emissions
trading was  allowed  or  if uniform,  unit-by-unit  emission limits (i.e.,  no
trading) were imposed.

Scope of Emissions Trading

     Emissions  trading schemes can vary by  the geographic extent  of  allowable
trades.   While  the aforementioned bubble and offset concepts usually  correspond
to emissions trading at  the plant level  (or,  in  some  cases,  groups  of plants
located  in  close  geographic  proximity),   emissions trading  under acid  rain
legislation could entail wider-level trading  because  of  the broader  state  or
regional  (rather  than localized) emission  reduction  targets.   Specifically,
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trading in the acid rain context could be allowed to occur at the intrautility,
intrastate, or interstate level.

     While geographic boundaries offer one set of criteria to define the extent
of emissions  trading,  the amount of eraiss.ions trading  is also defined by the
types or classes of sources  involved.  Trades among existing utility sources are
perhaps most  easily envisioned  under  an acid rain control  program because the
emission reduction targets under many such proposals are  established at existing
sources only (new sources often  remain subject only to  NSPS and  other technology
requirements applicable  to new  sources).  However, trades between existing and
new utility sources could also  be  considered.   Such existing-new trades would
allow new powerplants to be  exempted from current NSPS emission regulations and
other technology requirements (e.g., BACT applicable to new sources) requiring
at least  70  to 90  percent  sulfur  removal from  input coal, provided  that any
resulting  emissions increase at these  new sources be  compensated  by further
emission reductions  from existing sources.

     A final factor in determining the  extent of emissions trading is the trading
ratio.   A  one-to-one  trading  ratio  means  that,  for  every   ton of  emission
reduction generated by a  "providing" source,  one ton of  emission  reduction credit
may be used at a  "receiving" source.   Adjusting  the trading ratio can lead to
net increases or decreases in the amount of emission reductions actually achieved
in practice from  levels  otherwise  required by the proposal.   For instance,  a
1.2:1 ratio would require the providing source to reduce emissions by 1.2 tons
for each ton of emissions increase  at  the receiving source.  An increase in the
trading ratio will  lead to more emission reductions (and hence more environmental
benefits), but fewer trades  (and hence  less cost savings) , than with an even one-
to-one ratio.-'

Recent Acid Rain Proposals

     As mentioned previously, several  acid rain  proposals have been put forth
in the past  few years.    Table  1-2 chronologically presents some of  the more
prominent proposals devised during 1987 and 1988, and summarizes some of these
proposals' key provisions.

      Note that some of  these proposals  include language which  allows emissions
trading.   This reflects  widening acknowledgement  that emissions trading has the
potential  to  offer  substantial  economic  cost  savings  at minimal environmental
expense.   This study aims to estimate quantitatively the  value to any particular
sulfur dioxide emission  reduction  proposal of various levels   of S02 emissions
trading,  and  discusses  the   salient issues  and  forecasted effects  on utility
costs, S02 reductions,  and  coal markets  when  considering alternative  forms of
emissions trading design.
-'     Trading among  sectors   (i.e., utility-industrial trades)  has  also been
      considered.  One example of such  inter-sectoral emission trading would be
      trading between  copper  smelters  and utility powerplants  in  the Western
      states.    Interpollutant  trading  (e.g.,  S02 with  NOX)  could also  be
      utilized,  and has been considered in an earlier acid  rain proposal.  These
      trading approaches are not addressed in this analysis.
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Proposal

Proxmire  (S-316)
30 Year/1.2 Lb.



Gregg (HR-2498)


Mitchell (S-1894)
Cooper (HR-4331)
Cuomo-Celeste
UMWA (Draft 4)
                    TABLE  1-2

           Recent Acid Rain Proposals

  Date         Final Phase S02  Requirements

Spring 1987   Statewide targets correspond-
              ing to a 1.2 Ib./mmBtu aver-
              age emission rate and 1980
              fuel consumption.

Summer 1987   Unit-by-unit 1.2 Ib./mmBtu
              limit upon reaching 30 years
              of age.

Summer 1987   Tax based on each unit's emis-
              sion rate.

Winter 1988   NSPS upon reaching 40 years
              of age;  Statewide emission
              targets  to achieve 12 million
              tons of reductions below 1980
              levels,  allocated by state
              share of national 1980 unit-
              by-unit 0.9 Ib./mmBtu "excess"
              emissions.

Spring 1988   Reductions from SIP sources
              equal to historical statewide
              unit-by-unit 1.2 Ib./mmBtu
              "excess" emissions.

Summer 1988   Statewide average 0.9 lb./
              mmBtu limit, or  68% below
              1980 levels.

Summer 1988   Control  technologies at all
              SIP units larger than 150
              megawatts.
Mitchell Compromise  Summer 1988
Bonker (HR-5562)
              Unit-by-unit 1.0 Ib./mmBtu
              emission limit if larger than
              100 megawatts and 1985 emis-
              sion rate greater than 1.2
              Ib./mmBtu.
Fall 1988     Reductions from SIP sources
              equal 1980 statewide unit-by-
              unit 1.2 Ib./mmBtu "excess"
              emissions; SIP emissions cap-
              ped at 1985 levels.
Trading Provisions
Intrastate/Regional
None



Not applicable


Intrastate only
Intrastate, with
intrautility-
interstate
                                                                     Intrastate only
None
None
Intrastate, with
intrautility-
interstate
   NOTE: Unit-by-unit "excess" emissions refer to  those  emissions which resulted
         from a unit emitting in excess of the designated emission limit.
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      This  report  examines  the  utility  S02  emission  reductions,   utility
compliance  costs,  and coal  market impacts of two of  these  recent acid  rain
control proposals (the Proxmire bill and the 30 Year/1.2 Lb. proposal)  assuming
alternative levels of emissions trading within the utility sector.  A representa-
tive set of emissions trading scenarios were analyzed to determine the potential
utility compliance cost savings that could accrue as the level of trading allowed
becomes more  expansive.   With one exception,  all  cases presented herein  were
analyzed assuming a one-to-one trading ratio.
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    o
r1  * *
^^  rt
f  Z

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                                  CHAPTER TWO

                              SUMMARY OF FINDINGS
      This  chapter  summarizes the results of ICF's analyses  of two alternative
 sulfur  dioxide  emission  reduction proposals  designed to control acid rain,  the
 Proxraire bill and the "30 Year/1.2  Lb."  proposal,  as compared to  a base case
 which assumes no federal acid  rain  legislation.   In particular,  this  summary
 indicates  the effects  of changing the  geographic  scope  and programmatic extent
 of emissions  trading under these three  scenarios.  Electric utility  S02 emission
 reductions, utility compliance  costs, and coal market impacts are presented and
 discussed.
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                               EMISSION REDUCTION SCENARIOS
Reduction
Scenario

Base Case
Proxmire
Total S02 Reductions
(Relative to Base Case)

1995:  None
2000:  None
2010:  None

1995:  About 5 mm tons
2000:  About 9 mm tons
2010:  About 9 mm tons
30 Yr/1.2
1995:  About 4 mm tons
2000:  About 6 mm tons
2010:  About 11 mm tons
S02 Reduction Requirements/
Allocation Scheme	

All units comply with current emis-
sion regulations.  No federal, acid
rain legislation is assumed.

Aggregate emissions from SIP power-
plant units in each of the 31-
Eastern states are limited to the
following emission targets:
      1995: 2.0 Ib. S02/mmBtu x 1980
            total fuel consumption
            from all SIP powerplant
            units*
 2000/2010: 1.2 Ib. S02/mmBtu x 1980
            total fuel consumption
            from all SIP powerplant
            units*

All units subject to a 1.2 Ib.
S02/mmBtu limit (enforced on a 30
day average) upon reaching 30 years
of age.
      *Note:      This is also known as a statewide 2.0/1.2 Ib. "excess" emission
                  reduction allocation.
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                         EMISSION REDUCTION SCENARIOS
     Two  sulfur dioxide  emission reduction  proposals and  a base  case were
examined as part of  this  study.  The  two emission reduction proposals examined
were (1) an interpretation of S-316,  the Acid Deposition and Sulfur Emissions
Reduction Act  of 1987 (hereafter  referred  to as "Proxmire"),  and (2)  the 30
Year/1.2 Lb.  ("30Yr/1.2") emission reduction proposal.  These emission reduction
cases  were  analyzed  for  the  forecast  years  1995,  2000,  and  2010,  and then
compared to the Interim 1987 EPA Base Case ("Base Case") which reflects expected
trends in utility sulfur dioxide emission levels, utility compliance costs and
coal production assuming  no changes  in  current  environmental regulations.   A
description of  these  three  cases is provided below:

•     The Base  Case  assumes  that all generating  units would  be  required to
      continue  to meet their sulfur  dioxide  emission  limits as stipulated by
      current  State  Implementation  Plans  (SIPs)  or  New  Source  Performance
      Standards (NSPS), whichever  are  applicable.   In addition, to the extent
      that state "acid rain" legislation has been enacted or  future changes in
      powerplant SIPs have already been approved, the emission limits resulting
      from these changes are  also  assumed.   Detailed Base Case specifications
      and assumptions are presented in Appendix D.

•     Under Proxmire, emission reductions would be required  in two stages from
      SIP units  (i.e., non-NSPS  units)  in each of the 31-Eastern  states.  By
      1993,  (Phase I),  aggregate emissions from all SIP units in each state would
      be required to  meet  a statewide emission  target corresponding to a 2.0
      Ib.S02/mmBtu   statewide  annual   average emission rate and  1980  fuel
      consumption from all  SIP sources within the  state.   By 1998  (Phase II),
      aggregate emissions  from these units  would be  required to meet a target
      corresponding  to  a  statewide   annual   average   emission  rate  of  1.2
      Ib.S02/mmBtu and 1980 fuel  consumption from all SIP sources in the state.
      States would  be responsible for  procuring  sufficient  reductions  from
      utility sources within  the  state  to meet the  mandated emission targets.
      The analyses presented  in  this report assume  that states would allocate
      emission  targets  to   SIP sources  based on 1980  fuel  consumption  and a
      2.0/1.2  Ib.  S02/mmBtu  annual  average  emission  rate.    However,  under
      Proxmire's "Default"  provisions, if a state failed to develop an approvable
      plan for  allocating  reduction requirements, each individual  unit within
      the state  would automatically  be  required  to  meet a  1.2 Ib.  S02/mmBtu
      annual emission limit (i.e., no trading would be' allowed).

•     Under 30  Yr/1.2,  all units  would  be  required to meet current emission
      regulations until the thirtieth  year  of operation, at which time units
      would be required to meet a 1.2  Ib.  S02/mmBtu emission  limit  (on a thirty
      day rolling average).  Because of  the variability of  sulfur  in coal and
      the variability of scrubber  performance, this  is assumed to  result in a
      1.02 lb.S02/mmBtu annual average S02 rate.  Note  that the "thirtieth year
      of operation"  was based on powerplant vintage as of December  31  of the
      forecast year.   Thus, a unit that initially came on-line at any time during
      1970 would be  considered to be  30 years old in 2000.
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                            EMISSION TRADING SCENARIOS

                              Base
Trading Scheme                Case        Proxmire          30 Yr/1.2

No Trading                      X            X*
Intrautility
     Existing-Existing                       X
Intrastate
     Existing-Existing                       X                 X
     Existing-New                            X                 X
Interstate (31-East/17-West)
     Existing-New               X**          X
Note: "Existing" units, as defined herein,  are those units in commercial opera-
      tion by 1985,  and are generally regulated under State Implementation Plans
      (SIPs) of the Clean Air Act.  "New" units are those units which come  (or
      came)  on-line after  1985,   and  are required  to meet  NSPS  Subpart Da
      regulations  (which require  70-90 percent  removal  through  S02  control
      technology -- i.e., scrubbers).

*/    No  detailed  analysis was  conducted for  the  Proxmire No  Trading case.
      Rather, estimates presented herein were derived from previous ICF analyses
      for EPA of similar acid rain proposals with no trading provisions.

**/   Assumes a 1.2-to-l trading ratio.
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                           EMISSION TRADING  SCENARIOS
     The various cases, Base Case, Proxmire, and 30 Yr/1.2,  were examined under
several emission trading schemes which allow for different levels  or  degrees of
trading flexibility.   This included an  assessment of trades within different
geographic bounds.  In order of  increasing  flexibility,  these are:

•     Intrautility Trading.  Sources from within a utility  holding company and
      situated in the  same  state  are permitted to trade with each other to comply
      with a utility emission target.  No trading  between holding companies or
      across state lines is permitted.

•     Intrastate  Trading.   Sources  from different  utility holding companies
      within  a state  can  trade  with  each other  to comply with  a statewide
      emission target.  No trading across state lines is permitted.

•     Interstate Trading.  Sources in the 31-Eastern states  can trade with each
      other  to comply with  a  31-Eastern states  emission  target.   A similar
      trading.arrangement  is assumed  in  the 17-Western states.   No trading is
      assumed to be permitted between the 31-Eastern and the 17-Western states.

      Trades were also examined  among different types of utility sources:

•     Existing-Existing Trading.   "Existing" powerplant units (generally subject
      to SIP  requirements)  can  trade with  other  existing powerplant units to
      comply with new, tighter emission  reduction  requirements.  However, each
      individual powerplant unit remains subject to  its current SIP limits, so
      that no  actual  increase  in emissions occurs  at any unit  as a result of
      trading.

•     Existing-New Trading.   "New" powerplant units can trade  with existing
      units.  New units which  opt to  trade  with existing units are assumed to
      be exempted  from NSPS Subpart Da  regulations  (which  require  a  1.2 Ib.
      S02/mmBtu limit, and scrubbers to meet minimum percent S02 removal require-
      ments).-'   However,  any emission increases at new units above the actual
      level that  would be emitted in a  given year  under NSPS  Subpart  Da (as
      forecasted  in  the Base  Case)  must be  offset by  extra  reductions  from
      existing units.  Moreover,  new units which obtain emission reductions from
      existing units  must  install controls  in order to meet NSPS  Subpart Da
      regulations as soon  as the existing  trading partners  retire.   Existing-
      new trading, in essence,  enables new units to  defer installation of NSPS
      Subpart  Da control  technologies  only  as   long  as  cheaper  offsetting
      reductions from existing sources are available.

      One  final  factor examined in the emissions  trading scenarios  is  the
required trading ratio.   In all but one of the  cases,  for every ton of qualify-
ing emission  reductions  at a  "credit providing"  source, one ton  of emission
reductions could be foregone at  a "credit receiving" source.  In the Base Case
with existing-new interstate trading,  a  1.2:1 trading ratio was examined,  thus
requiring the providing source to reduce emissions by 1.2 tons for each ton of
emission reductions foregone at  the receiving source.
-1     For a discussion  of  additional  technology-based requirements associated
      with New Source Review, and how they relate to the analysis of existing-
      new trading, see Chapter Three.
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                   BASE CASE UTILITY SULFUR DIOXIDE EMISSIONS
    Base Case
  S02  Emissions
 (millions of tons)
                           •*"J Existing Coal

                              New Coal

                         I    I Oil/Gas
                     1985
1990
1995
2000
2005
2010
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                   BASE  CASE  UTILITY  SULFUR DIOXIDE EMISSIONS
      To  determine the  impacts  of  the  emission reduction  proposals  and  the
effects of the various forms of emissions trading,  an assessment is  required of
future emission  trends assuming no changes  in  emissions  regulations.  The  Base
Case  forecasts future utility  emissions, assuming current  emission  regulations
(and  future changes in those regulations which have  already been mandated),  and
uses  EPA specified assumptions  on electricity demand growth, oil prices, nuclear
capacity, powerplant  lifetimes, among other factors.   A detailed list of  Base
Case  assumptions is provided in Appendix D.  The Base Case emission trends shown
on the opposite  page  indicate  the following:

•     Utility sulfur dioxide emissions are  forecast to increase  by  5.4 million
      tons (from 16.3 to 21.7  million tons) between 1.985 and 2010.^

•     Most of the near-term growth in emissions is due to increased  utilization
      of existing coal powerplants (as relatively few new coal and nuclear plants
      are scheduled to  come on-line  over the  next  decade, particularly after
      1990) and  due to  increased use of oil  relative to gas at oil/gas steam
      units  (because  gas prices are  forecast  to rise relative  to  oil  as  the
      current gas  "glut" is reduced).

•     After 2000, most of the  increase in emissions comes  from new  coal power-
      plants.  Nearly 200  gigawatts  of coal capacity is  forecast to be built
      between 2000  and 2010.
-1     Note that projections of future trends  in emissions  are uncertain and are
      dependent upon the  specified base  case assumptions  shown in Appendix D.
      Recently, EPA had ICF  analyze  a "low emissions"  base case which assumed
      very low  growth  in  electricity sales,  more  existing plant retirements,
      significant amounts  of repowering,  and fewer  new  coal plants being built.
      Under these assumptions,  emissions  growth from utilities was forecasted
      to be flat, with S02 emissions  totalling 16.9 million tons by 2005.  See
      ICF report to EPA entitled Analysis  of  a "Low Emissions"  Base Case and 10
      Million Ton SO, Reduction Cases. September 30,  1988, for further detail.
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                       S02 EMISSION REDUCTIONS OVER TIME
                         UNDER PROXMIRE AND 30 YR./1-2
   S02 Emissions
  (millions of tons)
                      25
                      20
                      10
                           ^™  Base Case
                           • •   Proxmire
                           -"30 Yr./1.2
                       1985
1990
1995
2000
2005
2010
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                       S02  EMISSION REDUCTIONS  OVER TIME
                       UNDER PROXMIRE AND  30  YR./1-2 LB.
      Under the Proxmire cases, annual emission reductions below Base Case levels
      would total:

                  4.6 million tons by 1995 under Phase I
                  about 9 million  tons  by 2000 and  by 2010 under
                  Phase II.

      Because there are no additional reductions required from existing sources
      after 2000, and because new plant  emissions are not subject to additional
      controls  (i.e.,  growth  in overall emissions due to  the  addition of new
      sources is not capped), absolute emission levels increase under Proxmire
      between 2000 and 2010.

      Under the  30 Yr/1.2 cases,  annual  emission reductions below Base Case
      levels increase in magnitude over time:

                  3.6 million tons of reductions by 1995
                  6.4 million tons of reductions by 2000
                  11.1 million tons of reductions by 2010.

      This occurs because the capacity  which turns 30  years of age (and which
      is required  to meet a 1.2 Ib.  emission limit) increases  over time.   In
      1995, 73 gigawatts of coal capacity will be 30 years  of age or older; by
      2010, 175 gigawatts of coal capacity would be affected.

      Emission reductions required by either Proxmire or  30 Yr/1.2 would not
      change significantly as a  result  of  implementing any of  the alternative
      levels of  emissions  trading considered herein.   This  is  because  any
      increases in emissions at powerplant units (relative  to levels specified
      under a "no  trading" variant of the  enforced acid  rain program), must be
      counterbalanced by equivalent  reductions  (below  "no  trading" levels) at
      other units.
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                         CHANGE  IN ANNUALIZED COSTS OVER TIME
   Increase in      3-
   Annualized
   Costs Above
Base Case Levels
 (billions of 1987
   $  per year)
                     1-
                              Proxmire
                              ExistinQ-Existing
                              Intrastate
                         	30 Yr/1.2
                              Existing-Existing
                              Intrastate
                     1995
                                       2000
2005
                   2010
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                     CHANGE IN ANNUALIZED COSTS OVER TIME
      The costs under Proxmire and 30 Yr/1.2 Increase steadily with respect to
      the Base Case, reflecting the increasing emission reduction requirements
      over  time.    This  trend  is  illustrated  on  the  opposite  page  for  the
      existing-existing intrastate trading cases.

            In 1995, annualized costs  increase  by  $0.4  billion under Proxmire
            and $0.4 billion under 30 Yr/1.2.

            In 2000, annualized costs  increase  by  $1.8  billion under Proxraire
            and $0.9 billion under 30 Yr/1.2.

            In 2010, annualized costs  increase  by  $2.9  billion under Proxmire
            and $4.1 billion under 30 Yr/1.2.

      The  annualized costs  under  30  Yr/1.2  are  significantly higher  than
      Proxmire by  2010 (about  40  percent  greater for  the  existing-existing
      intrastate cases).    This  reflects greater reductions  (about  20 percent
      more  reductions)  and  increasingly  higher costs  per  ton  removed.   As
      reduction  requirements exceed 8 to  9  million  tons,  compliance  costs
      increase rapidly, reflecting much higher marginal costs  of achieving these
      reductions  -- which  generally  are  obtained  through retrofitting  of
      scrubbers.

      Although the 30 Yr/1.2 cases are  more expensive in annualized cost terms
      than the Proxmire cases in 2010,  the 30 Yr/1.2 existing-existing trading
      cases are less costly in present  value terms  than  their Proxmire counter-
      parts.  This  is because the reduction requirements of the 30 Yr/1.2 cases
      in the  earlier forecast years (1995  and  2000) are  less  stringent,  and
      therefore  less costly, than the  Proxmire requirements.    Because  these
      earlier forecast  year costs are more heavily weighted in the present value
      calculations than costs from later years,  the 30 Yr/1.2 cases have lower
      present value cost  impacts than comparable Proxmire cases.
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            EFFECTS  OF ALLOWING EXISTING-EXISTING  INTRAUTILITY TRADING
        Change In
     Annualized Costs
     from Base Case
     Levels In 2010
     (billions of 1987
       $ per year)
                                       No Trading
Exlstlng-Exlstlng

  Intrautlllty
                                                 Proxmlre Cases
                    Not* that the estimate presented here for the Proxmlre No Trading case does not reflect
                    any specific analysis conducted by ICF for EPA, but represents ICF estimates based on previous

                    analyses of similar acid rain proposals with no trading provisions conducted by ICF for EPA.
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          EFFECTS OF ALLOWING EXISTING-EXISTING INTRAUTILITY TRADING
      The greatest  single  increment of cost savings associated wich emissions
      trading  is  obtained when  "expanding" the  scope  of trading  from  a "no
      trading"  scenario  (i.e.,  unit-by-unit compliance  with uniform emission
      limits) to a scenario that allows trading at the existing-existing intra-
      utility level.  Allowing even  this relatively restricted form of trading
      reduces the annual compliance  costs  of an acid rain program by 30 to 60
      percent.-'

      The cost  savings associated  with allowing even a limited level of emis-
      sions trading are large because the highest-cost compliance measures which
      would result  under  a no trading case  can  be avoided.   Powerplant units
      which would have very high costs  associated with meeting tighter emission
      limits  (e.g., which  would  effectively  have  required scrubbers  to  be
      installed) can  trade  with units  within  the  same  utility  which can make
      offsetting reductions at lower cost.
      No detailed modelling analysis was  conducted in developing the Proxmire
      No Trading case estimate.  Rather, the cost estimate for the Proxmire No
      Trading Case presented on the opposite page is approximate,  and was derived
      from previous  ICF analyses for EPA of acid rain proposals with no trading
      provisions. See,  for instance, An Economic Analysis of HR_4567:  The Acid
      Deposition Control Act of 1986. August  1986  (Default Case).  The relative
      annual  cost savings  estimated  above  are  also  consistent with  rough
      estimates made by ICF of a 30 Yr/1.2 No Trading Case.
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                     EFFECTS OF  GREATER  GEOGRAPHIC  TRADING  FLEXIBILITY:
                             ANNUALIZED AND  CUMULATIVE  CAPITAL COSTS
     Increase In
   •  Annualized
  Coats over Base
 Case Levels in 2010
  (billions of 1987
    $ per year)
                                                                                            4.1
                              3.3
                       Exlstlng-Exlstlng
                          Intrautlllty
  Exlstlng-Exlstlng
     Intrastate
  Exlstlng-Exlstlng
    Interstate *
                                        Proxmlre Cases
 Exlstlng-Exlstlng  Exlstlng-Exlstlng
    Intrautlllty      Intrastate
                                          30Yr/1.2LbCa*»e
  Change in
  Cumulative
 Capital Costs
 from Base Case
 Levels In 2010
(billions of 19870
                    Exlstlng-Exlstlng
                       Intrautlllty
Exlstlng-Exlstlng
   Intrastate
Exlstlng-Exlstlng
  Interstate *
Exlstlng-Exlstlng  Exlstlng-Exlstlng
    Intrautlllty       Intrastate
                                     Proxmlre Cases
                                         30Yr/1.2LbCas«8
             * Note that the estimates presented here for the Proxmlre Exlstlng-Exlstlng Interstate trading case do not
               reflect the results of any speolflo analysis conducted by ICF for EPA, but represent ICF estimates based on
               the analysis of Interstate trading In the Proxmlre exlstlng-new trading context, as well as previous
               analyses conducted by ICF for EPA.

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               EFFECTS OF GREATER GEOGRAPHIC TRADING FLEXIBILITY:
                    ANNUALIZED AND CUMULATIVE CAPITAL COSTS
       Increasing the  geographic  scope of  emissions  trading reduces  emission
       reduction costs.  A greater geographic scope of  trading  results  in more
       trading partners being available.  This in turn allows more opportunities
       for powerplant units with relatively high cost  reduction  requirements to
       obtain emission reductions  from powerplant units with relatively low cost
       reduction opportunities.

       The impact  of  greater geographic  trading  flexibility  among  existing
       sources on annualized costs is  shown on  the opposite page for 2010.   A
       similar pattern of  annualized  cost  savings  due to  increased  geographic
       trading flexibility is forecast in 1995 and 2000, although the  absolute
       cost savings are  generally  less than in  2010  because of lower  overall
       reduction requirements and lower compliance  costs in  the  earlier years.
       The annualized cost impacts  in  2010  reflect:

             An $0.4 billion cost savings associated with  increasing the  scope
             of trading from the  intrautility level  (i.e.,  restricted to within
             utility holding  companies,  with no trades allowed across  state
             lines)  to  the  intrastate  level (i.e.,  permitting  interutility,
             intrastate trading).

             An additional $0.3 billion cost savings associated  with permitting
             interstate trading  (i.e.,  trades  allowed across  the   31-Eastern
             states  and across the  17-Western states, but not between these  two
             broad  regions)  versus intrastate  trading.   (While no explicit
             existing-existing interstate trading case was analyzed,  the  annual-
             ized cost savings associated with  expanding trading to the inter-
             state  level  was  estimated based on  the difference in costs  between
             intrastate and  interstate  trading in  the existing-new   trading
             context.   In addition,  previous analyses  conducted by IGF  for  EPA
             of existing-existing interstate trading cases revealed similar cost
             savings.-')

      Greater  trading  flexibility also   leads  to  lower  cumulative   capital
      expenditures  by utilities,  generally  because less  scrubbers  are built.
      Increasing the scope of trading  from the intrautility to intrastate  level
      is  forecasted to reduce cumulative  capital  costs by  15  to 20 percent.
      Increasing the  scope  of  trading  further  to  the  interstate level   is
      forecasted to reduce cumulative  capital costs (by 2010) by an additional
      10  to  20 percent.
-'     See,  for   instance,   "Preliminary  Analysis  of  'Proxmire-Equivalent'
      Reductions  Allocated Across  the  Continental U.S.  Based on  Total 1980
      Utility Sulfur Dioxide Emissions from SIP Powerplants," July 1, 1987.
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                 EFFECTS OF GREATER GEOGRAPHIC  TRADING FLEXIBILITY:
                                 PRESENT VALUE OF COSTS
     Increase in the
    Present Value of
     Costs over the
      1987-2010
      Period above
   Base Case Levels
   (billions of 1987$)
                              Existing -
                              Existing
                              Intrautility
Existing -
 Existing
Intrastate
Exist! ng-
 Existing
Intrautility
Existing -
 Existing
Intrastate
                                    Proxmire
                                     Cases
                     30Yr/1.2
                       Cases
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              EFFECTS OF GREATER GEOGRAPHIC TRADING FLEXIBILITY:
                            PRESENT VALUE OF COSTS
      Changes  in  the  present  value  of costs reflect the changes in annualized
      costs incurred  over  the forecast period (i.e.,  through 2010) discounted
      back to  1987 using the utilities' real discount rate.

      Similar  to  the  changes  in annualized costs (discussed on page 2-15),  the
      present value of costs  is reduced as trading flexibility increases.   The
      present  value  of  costs  is  reduced  by approximately  20 percent when
      allowing intrastate trading instead of intrautility trading;  in contrast,
      annualized  costs by  2010  are  reduced  by only about 10 percent (as shown
      on page 2-14).  The present value of costs  is reduced  to a greater  extent
      since relative cost savings due to intrastate trading  (i.e.,  cost savings
      as a percentage of compliance  costs)  are higher in the near-term  (which
      are weighted more heavily in present value  calculations) than in the long
      term.   This is  because relatively  fewer opportunities  for cost savings
      through intrastate trading are available by 2010 as emission  requirements
      become more stringent.
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                             EFFECTS OF  EXISTING-NEW TRADING:
                         ANNUALIZED AND  CUMULATIVE CAPITAL COSTS
       Change in
       Annualized
       Costs from
   Base Case Levels
    in 2010 (billions
        of 1987 $
        per year)
                                                                3.6
                                                                                     -5.3
                              Existing-     Existing-     Existing-    Existing-
                              Existing      New       Existing      New
                                   Proxmlre
                                   Intrastate
  30Yr/1.2
  Intrastate
                     No
                   Trading
        Existlng-
          New
        Interstate
        1.2:1 Ratio
     Base
     Case
           Change In
       Cumulative Capital
        Costs from Base
         Case Levels In
             2010
       (billions of 1987 $)
                                Existing -    Existing -  Existing -   Existing •
                                 Existing     New     Existing      New
                 No     Existing -
               Trading      New
                        Interstate
                        1.2:1 Ratio
                                   Proxmlre
                                   Intrastate
30Yr/1.2
Intrastate
Base
Case
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                       EFFECTS OF EXISTING-NEW TRADING:
                    ANNUALIZED AND CUMULATIVE CAPITAL COSTS
      The cost savings associated with expanding the  scope  of  emissions trading
      to  permit  trades between  "existing"  sources  and  "new"  sources is also
      significant.  With existing-new source trades, new powerplants  no  longer
      are  required to  meet NSPS  Subpart Da  and thus  can be  built without
      scrubbers.-'   This  is  permitted  as  long  as  any   resulting  emission
      increases above  the  actual levels projected for these new sources under
      the Base Case (i.e.,  assuming the  operation of  scrubbers  designed to meet
      NSPS-Da) are offset by further reductions at existing units.  Because the
      cost  savings associated with  building a  new  plant  without  a scrubber
      ($1000-2000  savings per  ton increase in emissions) are far more substan-
      tial  than  the cost of  offsetting these  increases at an existing plant
      through coal switching (about $100 to $400 per  ton  removed), the net cost
      savings of building a new plant without a scrubber  and switching coals at
      existing units are considerable.

      The value of existing-new  trading is inversely related to the  amount of
      emission reductions  required.   This  is  primarily because  the marginal
      costs of emission reductions at existing  plants increase  as more emission
      reductions are required.  By 2010:

            Under  the  30  Yr/1.2  intrastate case  with existing-new trades,
            emission  reductions  total 11.1 million  tons,  with net annualized
            cost  savings  of  about  $0.5 billion  and cumulative  capital cost
            savings of about $6.6 billion relative to the 30 Yr/1.2 intrastate
            case with existing-existing trading.

            Under  the  Proxmire   intrastate  case  with  existing-new trades,
            emission reductions equal 9.1 million tons, with greater net annual-
            ized cost  savings  of $2.0 billion and greater cumulative capital
            cost  savings  of  about  $16.7 billion  relative  to  the  Proxmire
            intrastate case with existing-existing trading.

            Under the Base  Case with  existing-new  trades  (1.2:1 trading ratio),
            net emission reductions total only about 1.4 million tons,  with very
            substantial net annualized  cost  savings  of  $5.3  billion  and very
            substantial cumulative capital costs  savings  of  about $25.8 billion
            relative to the Base Case with no trades.

      In 1995 and  2000,  the value of existing-new trades  is  less significant
      than in 2010, reflecting fewer  new  sources  being able to take advantage
      of existing-new trades.  By 1995, only a  few new coal plants  subject to
      current NSPS  regulations are  forecast to  be   constructed  (beyond  those
      plants already partially completed).  By  2000,  about 27 gigawatts of new
      coal plants  are forecast  to  be  built  (beyond those  already  partially
      completed),  versus about 225 gigawatts of new coal capacity in 2010.
-1     For a discussion of additonal technology-based requirements associated with
      New  Source  Review  (i.e,  Best Available  Control  Technology  and  Lowest
      Achievable Emission  Rate), and how thej relate to the analysis of existing-
      new trading, see Chapter Three.
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                           EFFECTS  OF EXISTING-NEW TRADING:
                                 PRESENT VALUE OF COSTS
     Increase in the
    Present Value of
     Costs over the
      1987-2010
     Period above
   Base Case Levels
   (billions of 1987$)
                           16.0
                                                14.6
                                                          11.7
                                                                              -15.8
                          Existing - Existing •
                           Existing    New
Existing - Existing •
 Existing   New
                             Proxmire
                             Intrastate
   30Yr/1.2
   Intrastate
  No   Existing -
Trading    New
       Interstate
       1.2:1 Ratio
     Base
     Case
06C0078A

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                       EFFECTS OF EXISTING-NEW TRADING:
                            PRESENT VALUE OF COSTS
      Expanding  emissions  trading  to allow  existing-new  trades  reduces the
      present value  of  costs  substantially,  by approximately 20 percent  under
      the 30 Yr/1.2 case and about 35 percent under the  Proxraire case, relative
      to the cost of the same emission reduction proposals  with only existing-
      existing trading.  Under Proxmire, this reflects relatively low annualized
      cost  savings  in the early  years  (about  2  percent in  1995  and  about 7
      percent in 2000) and much higher savings (about 70 percent) by 2010.   Under
      30 Yr/1.2, this reflects relatively higher annualized cost savings in the
      earlier years  (about  55  percent in 2000)  and smaller savings  (about 10
      percent) by 2010.

      Allowing existing-new trades reduces the present value  of costs of Proxmire
      more significantly than 30 Yr/1.2  because the net  annualized  cost savings
      in 2010  under Proxmire  are much greater  than the  net annualized cost
      savings under 30 Yr/1.2.

      Note that 1987 Interim EPA Base Case scrubber  cost assumptions were used
      in these analyses. More  recent studies  indicate that  up-to-date scrubber
      cost assumptions  would likely  be  somewhat lower.   Lower  scrubber cost
      assumptions would reduce the forecasted compliance costs of  the emission
      reduction  cases,  and would reduce  the value  (i.e.,  cost  savings)  of
      existing-new trading to a certain extent.
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                                   CHANGE  IN PRESENT VALUE  OF COSTS
                                 WITH  INCREASED TRADING FLEXIBILITY
  Increase in the
 Present Value of
    Costs Over
  the 1987-2010
Period Above Base
    Case Levels
(billions of  1987 $)
                       Exlstlng-Exlstlng Exlstlng-Existing  Exlstlng-New  Exlstlng-New Existlng-Existing  Existlng-Existing  Existing-New
                         intrautility      Intrutate     Intrastate     Interstate     Intrautllity      Intrastate     Intrastate
                                         Proxmire
                                           Cases
             30Yr/1.2
               Cases
      06C0078A

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                        CHANGE  IN  PRESENT  VALUE OF  COSTS
                       WITH  INCREASED TRADING  FLEXIBILITY
      The  changes in the present value  of costs indicate significantly  lower
      costs  as  trading  flexibility  increases:

             Allowing  existing-existing intrautility  trading versus
             no  trading  can  reduce the present  value  of  costs by  30
             to  60  percent  ("no  trading"  case  not  shown  on the
             opposite  page).

             Allowing  intrastate trading further reduces  costs by  20
             percent,  as  compared  to  allowing  only intrautility
             trading.

      --     Allowing  interstate  trading  saves  an additional 10  to
             20  percent, as  compared to allowing  only  intrastate
             trading.

             Expanding trading to allow existing-new  trades reduces
             costs by  20 to 40 percent,  as compared to allowing only
             existing-existing trades.

      The  maximum present  value  cost savings result  from  maximum emissions
      trading flexibility.   Existing-new interstate trading opportunities enable
      roughly  50  percent   present  value  savings over  an  existing-existing
      intrautility emissions trading program.  Total  savings of an existing-new
      interstate  trading program may approach  80 percent when compared to a no
      trading situation.

      However, as the degree of trading flexibility increases, so too would the
      programmatic complexity and administrative burden  of an acid rain control
      program.    The  effect would  be greatest  for  a  program  that  combined
      interstate and existing-new emission  trades.  Increased trading flexibil-
      ity would also  raise  a  number of  additional  design, implementation, and
      enforcement issues that would need to be addressed before such a program
      could be successfully implemented.
UOCUU/oA
?as<> 2-23                                              xcF Resources Incorporated

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                               REGIONAL COAL PRODUCTION
                  270H
                  240
                  210


    Northern
  Appalachian
Coal Production  150-
(millions of tons)

                  120
                   90


                   60


                   30
 Base Case
 Proxmire Ex-Ex Intrastate
 Proxmire Ex-New Intrastate
                    1980
1985
1990
1995
                                                             2000
                                         2005
                                         2010
                  200
                   180-


                   160


                   140


                   120^

   Midwestern
 Coal Production  100-
 (millions of tons)

                    80


                    60-


                    40-


                    20
 Base Case
 Proxmire Ex-Ex Intrastate
 Proxmire Ex-New Intrastate
                    0-
                    1980
                             At 1985Lev«ls
1985
1990
1995
           2000
                               2005
                                                   2010
   06C0076A

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                           ICF Resources Incorporated

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                           REGIONAL COAL PRODUCTION
      Coal production in high sulfur regions declined during  the early 1980s as
      new nuclear  plants  were brought on-line, electricity  demand growth was
      slow, and emissions  regulations  were  tightened in certain states.  High
      sulfur coal  production  is  forecast  to grow  only slowly through the mid-
      1990s in the Base Case,  as existing coal capacity is gradually utilized
      more to meet  growing electricity demand.  High sulfur coal production is
      forecast in  the  Base Case  to expand  rapidly after  2000  as  new scrubbed
      high sulfur  coal plants are brought on-line.

      Under the Proxmire  cases,  national coal production  levels  remain rela-
      tively unaffected,  but there will be significant  shifts in  regional coal
      production.    High  sulfur coal producing regions,  including  the Midwest
      (Illinois,   Indiana  and   Western   Kentucky)   and  Northern  Appalachia
      (Pennsylvania, Maryland,  Ohio  and  Northern West Virginia),  lose  coal
      production as utilities shift from higher sulfur  to lower sulfur coals in
      order to  meet the  emission reduction  requirements.   High  sulfur  coal
      production  is reduced  significantly  below  both  current and  Base  Case
      levels by 1995 and 2000. After 2000,  the addition of new coal plants and
      the  absence  of  additional  reduction  requirements  at  existing  plants
      results in an increase in high sulfur coal production.   However, produc-
      tion still  remains  well below  forecasted Base Case levels  and,  in the
      Midwest, production remains well below current levels as well.

      Similar coal production impacts are  exhibited in  the 30 Yr/1.2 forecasts,
      although there are less shifts away from higher sulfur coals by 1995 and
      2000 because fewer  reductions  are required,  and more  shifts by  2010
      because more reductions are required.

      Allowing existing-new emission trading results in further  increases in low
      sulfur coal  production at  the  expense  of  high  sulfur  coal  production.
      This occurs  because  (1) utilities choose to build new  unscrubbed power-
      plants which use low  or medium sulfur coals  in lieu of new scrubbed
      powerplants  which are forecast in the Base Case  to use higher sulfur coals
      in some instances, and  (2)  in order to  offset  emission increases  at new
      powerplants,  utilities  must  further  reduce  emissions  from  existing
      powerplants, usually through increased fuel  switching.
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                                     COAL MINING EMPLOYMENT
                      CHANGES IN REGIONAL AND NATIONAL COAL MINE EMPLOYMENT
                                       (Thousand Workers)
Northern Appalachia
   Pennsylvania
   Ohio
   Maryland
   Northern W. Va.
      TOTAL

Central Appalachia
   Southern W. Va.
   Virginia
   Eastern Kentucky
   Tennessee
      TOTAL

Southern Appalachia
   Alabama
      TOTAL

Midwest
   Illinois
   Indiana
   Western Kentucky
      TOTAL

Rest of U.S.

TOTAL U.S.
                        Actual Actual  Base
                        1980   1985    2000
 I!
 12
 23
231
  9
  9
 20
170
                     Change  in Job  Slots
                      Relative to Base
                     Proxmire  Proxmire
                     In-State  In-State
                                Ex-New
                                   Base
                                   2010
                                 Change in Job Slots
                                  Relative to Base
                                 Proxmire  Proxmire
                                 In-State  In-State
                                  Ex-Ex     Ex-New
36
15
1
18
70
22
9
1
il
45
18
5

12
35
-5
-2

^1
-8
-5
-2

-1
-9
30
7

18
54
-3
-2

^2
-7
-12
-3

Jj
-20
36
16
35
4
91
24
13
30
_3
70
24
13
29
_3
69
+4
+2
+5

+12
+4
+2
+6

+12
33
18
41
_4
95
+3
+2
+4

+8
+4
+3
+6

+13
  6
  6
 24
154
+6

+1
+6

+1
                    9
                    9
 47
235
                 -1
+8
-4
                   -2
18
5
12
35
14
5
8
27
13
2
5
20
-7

-1
-8
-7
--
-1
-8
17
4
8
29
-8
-2
-2
-12
-10
-2
-4
-16
+14
-11
         06C0078A
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                                     ICF Resources Incorporated

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                            COAL MINING EMPLOYMENT
      While overall national coal production under the Base Case is forecasted
      to increase at a relatively high rate of growth (roughly 2 percent per year
      between 1985 and 1995), national coal mining  employment  grows at a much
      slower rate (and,  in fact,  declines overall by 1995).  This is because of
      (1) the expected continuation of productivity improvements  (i.e. , more coal
      produced per  miner),  due  to  advances  in  technology and  increasingly
      efficient work forces, and (2)  expected shifts in production towards higher
      productivity (i.e.,  less labor intensive)  mines in the West.

      Regional coal mining employment impacts  under Proxmire and 30 Yr/1.2 are
      similar to  the regional coal  production impacts discussed earlier,  with
      declines in high  sulfur regions  and increases  in low sulfur  regions,
      relative to Base Case levels.

      Expanding the geographic scope of trading under  Proxmire and 30 Yr/1.2 to
      the intrastate  or  interstate  level is forecasted to have relatively small
      effects  on regional  and  national coal  mining  employment,  beyond  the
      employment  impacts  of  Proxmire  and  30  Yr/1.2  with only  intrautility
      trading.

      Through 2000, the option  of  existing-new  trading  is  forecasted  to  have
      relatively minor effects on coal mining employment  (beyond those resulting
      from existing-existing trading),  as  few  new coal plants that  can utilize
      such trading opportunities  are forecasted to be built.  By 2010,  however,
      significant shifts in regional coal mining employment are forecasted under
      existing-new trading.

      Nationally, coal mining employment in 2010 under existing-new trading falls
      by 11 thousand (5 percent) relative to the Base Case, as compared to a drop
      of 4  thousand (2  percent) with  just existing-existing  trading.    The
      additional  reduction in employment associated with existing-new trading
      occurs because  (1) many new plants are built without scrubbers, resulting
      in decreased coal consumption (because  unscrubbed powerplants  are  more
      efficient), and (2)  new plants use more lower sulfur coals, much of which
      is from Western mines of higher productivity.

      Note that  the losses  in raining employment relative to Base  Case levels
      that are  estimated herein  (i..e., "job slot" losses) reflect losses in the
      number of coal mining jobs.   They do not reflect  the  number  of  existing
      miners who will lose their jobs.  Some of  the job slot losses represent
      opportunity losses (i.e. , new jobs that are  forecasted  to be created under
      the Base Case but not under   the emission reduction  scenario examined).
      Moreover, many  of  the currently employed coal miners may retire or change
      jobs voluntarily prior  to 2000 or 2010.  Accordingly, the number of miners
      actually thrown out  of  work  under an acid rain program would likely be
      considerably lower than the "job slot" losses shown on the opposite page.
      Further,  it should  be noted  that the shifts  in  coal  mining employment
      discussed  herein, while significant  (gross job  slot losses  of up  to
      38 thousand jobs),  are eclipsed by the losses  that have occurred in the
      industry over the  1980-85 period (61  thousand job slot losses).
06C0078A
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                           NET AND GROSS MINING JOB  SLOT  LOSSES


                         	Change From Base Case:   2010	                Change:
                             Proxmire                 Proxmire               Existing-New
                            Intrastate               Intrastate                  vs.
                         Existing-Existing         Existing-New          Existing-Existing

U.S. Net Mining                  -4                      -11                      -7
Job Slot Losses
(thousand workers)

U.S. Gross Mining               -20                     -38                     -18
Job Slot Losses
(thousand workers)

U.S. Total Gross                 ?                       ?                       ?
Job   Slot   Losses
(Including Non-Coal
Mining Jobs)

Utility Annualized             +2.9                    +0.9                     -2.0
Compliance Costs
(billions of
 1987 $/yr)
      06C0078A
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                   NET AND GROSS COAL MINING JOB SLOT LOSSES
      Net national coal mining  job  slot losses discussed on page 2-27 reflect
      the  losses  in overall U.S.  coal mining  employment.   While  this  is an
      important measure  of coal mining employment,  it does not indicate the
      extent of regional job losses or dislocations.  This concept is represented
      by gross coal mining job  slot losses  (or the sum of regional mining job
      slot losses).

      Gross coal mining job slot losses in the U.S. under Proxmire are roughly
      17-18 thousand workers by 2000 with  either existing-existing or existing-
      new  trading  at the  intrastate  level.-'   By 2010,  this  range increases
      significantly:   20  thousand job  slots  are  lost under existing-existing
      trading versus 38 thousand job slots under existing-new trading.  In other
      words, there are  18  thousand more gross job slot  losses assuming existing-
      new trading by 2010.  Because annualized utility compliance costs are fore-
      casted to be $2.0 billion higher under existing-existing trading than under
      existing-new trading by 2010,  the cost  per gross coal mining job slot saved
      by restricting  trading  to  the existing-existing  level  can  be  roughly
      estimated at $100,000 per year.  However, as discussed below, the cost per
      total gross job  saved (including non-coal  mining jobs)  could  be  quite
      different.

      Gross coal mining job slot losses presented herein-indicate only a portion
      of the total gross job losses or dislocations which could occur  as a result
      of regional mining  employment losses.   Other jobs  dependent  upon  local
      mining activity could also be lost as a result of mine shutdowns, and could
      lead to  a significantly  larger number  of  total  gross  job losses.   In
      addition, lost investments  in mines that are closed, in  firms  that are
      adversely affected by coal mining  job  losses, and in regional infrastruc-
      ture abandoned  (particularly  in  mining  towns  which experience  severe
      economic hardship due to  mine shutdowns)  could  also be  significant,  and
      have not been  estimated herein.  On  the other hand,  lower  electricity
      costs resulting from existing-new trading (as opposed to existing-existing
      trading) would result in higher regional economic activity in many parts
      of the country.  Furthermore,  there would  likely  be new  jobs  created to
      support  increased   mining activity  in  regions which  experience  coal
      production and mining employment gains.    These  impacts  were  also  not
      assessed herein.
-1     These analyses were  conducted using  1987  Interim EPA Base  Case  mining
      productivity assumptions developed in late 1986.   However,  recent trends
      in mining  productivity have  indicated  higher productivity  growth  than
      assumed in  these analyses. Higher assumed productivity growth would result
      in lower future base  case employment forecasts,   and  smaller  impacts  on
      forecasted employment under  Proxmire  and 30 Yr/1.2, since productivity at
      incremental mines  would be higher.
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                           CAVEATS AND UNCERTAINTIES
      Many assumptions and uncertainties underlie the findings presented in this
chapter concerning the effects of emissions trading under alternative acid rain
control proposals.   Of particular importance are  those factors that relate to
the implementation of intrastate, interstate or existing-new  trades.  These are
discussed  in  detail  in  Chapter  Three.    Some of the  key  assumptions  and
uncertainties  are noted below:

•     The  analyses  presented herein  assume  that  the  emissions  baseline  for
      determining  "extra"  reductions at  existing  powerplant  units  under  the
      Proxmire and 30 Yr/1.2 proposals would be the new,  tighter emission targets
      imposed  under  these emission reduction proposals.   For new powerplant
      units, the  baseline was assumed to  be the  actual emissions  that would
      result from NSPS-Da  requirements, as projected under the Base Case.   In
      the case of existing-new trades, it was also assumed that new units that
      rely on emission.reductions from existing units must develop other existing
      trading partners or install scrubbers (or other equivalent controls) once
      the existing units retire.

•     The results presented in  this report assume  that utilities  will achieve
      compliance with emission reduction requirements in least-cost fashion, by
      pursuing the most economically efficient combination of ^missions trades
      possible, subject to noted constraints.   However,  a  range of technical,
      financial,  programmatic,  and institutional  considerations  would likely
      serve to limit either the ability or the desire of utilities to engage in
      all of the emission  trades which are projected to  occur,  especially in the
      case of  trading beyond the existing-existing intrautility level.  To the
      extent that full scale implementation of emission trading (as envisioned
      in these  analyses) is constrained by these considerations, the cost savings
      and other impacts presented herein would be reduced accordingly.

      Also discussed in Chapter Three are the assumptions made in these analyses
regarding a number of other important emissions trading issues.  These pertain
to the structure of an emissions trading program and the manner in which  it would
be monitored and enforced.   They  also  pertain  to the relationship  between
emission trading and other environmental objectives, such as attainment of the
National Ambient Air Quality Standards  (NAAQS),  determination of best available
control technology (BACT),  and prevention  of significant deterioration  (PSD) in
areas already attaining the NAAQS.  These issues are critical  in determining how
an emission trading program would work in practice, how effective  and reliable
it would be  in producing  the  required emission reductions,  and the  extent to
which the projected savings would be achieved.

      There are also many  analytical assumptions and uncertainties of note that
do not relate  solely to the use  of emissions trading.   These include cost  and
technology  assumptions for  S02  control   options,   site-specific  constraints
affecting  alternative  emission  reduction  strategies,  and  major  assumptions
incorporated into the  Base Case  (such  as  electricity demand  growth rates,  oil
and gas prices, coal mining productivity,  etc.).   These  assumptions  have very
important effects on the utility cost and coal market impacts presented herein.
These assumptions and uncertainties are also addressed in Chapter  Three.
06C0078A
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   o

   3"
   P


r'"H

"  s
fD  ">



?  ?
   "I

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                                 CHAPTER THREE

                           CAVEATS AND UNCERTAINTIES


      This chapter discusses a number of caveats,  assumptions and uncertainties
which have important effects on the  findings of this analysis, including:

•     Implementation Assumptions and Uncertainties Regarding Emission Trading  -
       This section discusses the assumptions and  uncertainties associated with
      the implementation of emission trades, particularly those trades between
      existing and new sources.  This includes issues regarding administrative
      and transaction costs,  the determination of baseline emissions, powerplant
      retirements, PSD and new source review,  monitoring and enforcement, and
      barriers to implementation.

•     Sulfur Dioxide Control Assumptions - This section presents generic scrubber
      costs,  describes  site-specific retrofit  scrubber costs,  and discusses
      assumptions regarding  such  issues as  new control technologies,  removal
      efficiencies and scrubber lifetimes,  and the impacts of these assumptions
      on emission reduction costs  and on the value  of existing-new plant trades.

•     Site-Specific Constraints Affecting Alternative Reduction Strategies - This
      section discusses the site-specific costs and constraints that can signifi-
      cantly affect individual powerplant compliance decisions.

•     Base Case  Assumptions  -  This  section highlights  some key.EPA Base Case
      assumptions, such as electricity growth rates, world oil and gas prices,
      powerplant lifetimes, and coal mining productivity and reserves.

•     Restricting Utility Forecasts Between Scenarios  -  This section identifies
      key variables  (such as gas consumption, interregional power flows, and new
      coal and. nuclear powerplant  builds)  that  are restricted  in the emission
      reduction cases to Base Case levels.

•     Direct  Costs  and  Near-Term  Constraints  Not  Analyzed  -  This  section
      identifies certain costs  of the emission reduction cases  that were not
      analyzed,   such as  oil  and gas price  changes  associated with  changes in
      utility fuel demands.

•     Indirect Costs Not Measured  -  This  section  discusses  the  indirect costs
      of the emission reduction cases that were not analyzed.  These include the
      administrative and transaction costs  of  emissions trading,  the indirect
      and  regional  economic  impacts associated  with  the  different  control
      options, the costs  of abrogating long-term coal contracts, and the oppor-
      tunity  costs  of  capital  due  to  increased  investments  in  control
      technologies.
06C0174
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      A number of assumptions were made regarding emission trades between utility
sources, and in particular between existing and new sources.  Further, there are
important caveats and implementation uncertainties associated with these emission
trades:

•     Administrative and Transaction Costs  - Emission trades between individual
      powerplant units and,  in certain cases, between utilities and across state
      lines,  would  likely  result   in  additional  administrative  costs  for
      establishing regulatory  mechanisms  to  oversee  and enforce  the  trades.
      Transaction  costs  (including  brokerage-type commissions  and costs  to
      utilities  for preparing new operating .permit applications) could also be
      incurred  if an emissions  trading  program  were established.    These
      administrative and transaction costs were not estimated as  part  of this
      analysis but could be  significant.   To  the  extent there  are transaction
      costs, the amount of emissions trading and net cost savings associated with
      trading as estimated for this analysis would be reduced.

•     Baseline Requirements - In permitting emissions trading between "existing"
      powerplant units under the  Proxmire and  30 Yr/1.2 proposals, the emission
      baseline from which  relative  increases and decreases in  emissions were
      calculated was each existing unit's allocated emission target (under the
      respective emission reduction proposal) .  For example, under Proxmire, each
      "existing" SIP unit was subject to an emission target corresponding to a
      2.0 Ib. S02/mmBtu emission  rate (Phase I) or  a 1.2  Ib. S02/mmBtu emission
      rate (Phase II), and  its historical  1980 fuel consumption.   In the case
      of the 30 Yr/1.2  proposal, Base Case projected fuel consumption and a 1.02
      Ib.  S02/mmBtu  annual  average emission  rate served  as  the basis  for
      calculating each existing SIP unit's emission target.

      For "new" units,  forecasted "actual" emissions  from the  Base Case (assuming
      the  application of  NSPS  requirements)  were  used as the baseline  for
      trading. Under  the Base Case,  most new units scrubbed low or medium sulfur
      coals, resulting in relatively low forecasted actual emission rates.  The
      average emission rate  forecasted  in  the Base Case by 2010  for new coal
      powerplants is 0.3 Ib. S02/mmBtu (on  an annual average).

      However, in implementing specific existing-new trades under an actual acid
      rain control program, it would be difficult to define  baseline emissions
      for  new units   in  terms  of  forecasted actual  emissions.    Baseline
      requirements for new units  would likely  have  to be  related in some way to
      source-specific  allowable  emissions  or based on some  other  objective
      criterion,  such  as average actual emission rates associated with applicable
      new source control requirements (e.g. , a  common baseline for all new units,
      reflecting average new source emission rates, or different baselines for
      different  subcategories of new units based on geographic location and other
      criteria).
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      To  the  extent  that  these baseline levels are established  closer to the
      maximum  emission rates  allowable  for  new  units  (i.e.,  0.6-0.8  Ibs.
      S02/mmBtu,  which are typical annual average rates  for  high or very high
      sulfur  coals subject  to  the 90 percent total removal  requirement), the
      number  of  existing-new trades  and the associated  cost  savings  would be
      greater than forecasted herein,  but fewer emission reductions would result.
      To  the  extent much  lower emission rates were  used to establish baseline
      requirements for new plants, there would be less existing-new trades and
      hence lower cost savings, but more emission reductions would be achieved.

      Poverplant Retirements -- Powerplant retirements can have a very important
      impact on the value of emissions trading  (especially existing-new trading)
      since they partly determine how many new plants are built, as well as how
      many existing plants are  available to engage in trades. In this analysis,
      few coal burning units are  assumed to retire  through 2010  (the forecast
      horizon of  this study), given  the 60-year  lifetime assumption for coal-
      fired units and the fact that  few existing coal  units  were built before
      1950. Hence, powerplant retirements constitute a relatively insignificant
      factor in this analysis.   (For a discussion of the effects  of powerplant
      retirements.in the long-term,  see Very Long Term Impacts of Existing-New
      Trades.  below.)

      The treatment of emission reductions resulting from powerplant retirements
      (i.e., the extent to which  they are considered creditable for purposes of
      trading) can also have  a very  important  impact  on the results  of this
      analysis.

      For existing-new  trades  under  the Proxmire bill  and the  30  Yr/1.2 Lb.
      proposal, it was assumed that powerplants  that engage in emission trades
      must develop other "existing" trading partners  or  install controls to meet
      new source requirements on-site once the initial trading partners retire.
      For existing-existing  trades under the 30 Yr/1.2 Lb. proposal, it was also
      assumed that powerplants that engage in trades must  obtain reductions from
      other partners or reduce  further from on-site once  the  initial  trading
      partners retire.   To the  extent that  sources were allowed to continue to
      rely  on emission  reductions  from  existing  powerplants  beyond  their
      retirement, there would be more emission trades  and  lower  costs.  There
      would also be higher emissions because no further emission reductions would
      be required to replace reductions from retired plants.

      In contrast, for existing-existing trades under  the  Proxmire  bill,  this
      analysis assumed that powerplant retirements did receive emission reduction
      credits. As existing powerplants retire, the overall emission target that
      must be met across all existing plants  does not  change  or is not reduced
      to account  for fewer existing  sources.  However,  this  interpretation of
      the Proxmire bill has  minimal effects  on the resulting forecasts because
      of the few powerplant retirements by  2010.
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGAPJ>ING EMISSIONS TRADING
      Technology Requirements Under NSPS  - EPA has twice promulgated an NSPS for
      electric utilities.   The original NSPS, promulgated  in  1971,  imposed a
      uniform national emission limit of  1.2 Ib. S02/mraBtu.   This limit could be
      met either by using low sulfur coal, or  by using any combination of high,
      medium, and low sulfur coal in conjunction with add-on  control technology.
      In most cases, the use of low sulfur coal provided the least-cost method
      of compliance, and add-on controls were generally not installed.

      The new  NSPS  (Subpart  Da),  promulgated pursuant  to  the Clean Air Act
      Amendments of  1977, was conceived in part to counter long-term potential
      adverse impacts to high sulfur coal producing  regions  associated with the
      original NSPS.  By stipulating  that (in addition to meeting the  1.2 Ib.
      S02/mmBtu standard) a fixed  percentage  of  S02 emissions  must be  removed
      from input coal burned at new coal powerplants,  NSPS Subpart Da effectively
      mandates  the  use  of scrubbers.   NSPS Subpart  Da   has  the effect  of
      (1) requiring  more  emission  reductions  from  new  units  than under the
      original NSPS, and (2) making high sulfur coal use more  economic  at new
      units relative to the original NSPS.

      For the existing-new trading envisioned in this analysis to be  possible,
      statutory and regulatory amendments would be required in order to eliminate
      the scrubber requirements, and to allow the emission reductions associated
      with NSPS Subpart Da to be met by means  of fuel switching and trades with
      existing sources.

      Since any emission increases from new sources  above the levels they would
      have been forecasted  to emit  (assuming the operation of scrubbers designed
      to meet NSPS Subpart Da)  must be offset  by extra reductions from existing
      units, the overall level of emission reductions resulting from NSPS Subpart
      Da would not  change because  of  existing-new trading.   Further,  as noted
      in Chapter Two, utility costs would be reduced.   However, as also discussed
      in Chapter Two, existing-new trading would result in  significant  shifts
      in coal  production  and  coal mining  employment  from high  sulfur  coal
      producing regions to low sulfur coal producing regions.
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      Other Technology-Based Requirements Under NSR  - In addition to NSPS, new
      powerplant  units may be  subject  to  other technology-based requirements
      under New Source Review  (NSR).-'  The  NSR program mandates that major new
      units locating in areas attaining the ambient air quality standards apply
      Best Available Control Technology (BACT).  Most areas of the country are
      currently designated "attainment"  for  S02, and virtually all new powerplant
      units are expected  to be located  in these areas.   BACT is determined on
      a case-by-case basis for individual units following a detailed evaluation
      of alternative control options,  but must  be at least as  stringent as NSPS.
      As with  NSPS,  the current NSR  regulations would need  to  be modified to
      allow BACT  requirements  to be satisfied  by trades with existing sources.

      Because it is difficult to estimate BACT requirements  for future unplanned
      coal units,  actual Base  Case emissions for unplanned units were forecast
      based on current or expected emission  requirements for planned coal units,
      and were used as the baseline  for•new units  engaging  in  trades.   For a
      number of states, state  NSPS limits or BACT requirements were assumed to
      be more stringent than NSPS Subpart Da.  Nevertheless,  it is likely that
      future BACT  determinations in these as well as  other states will commonly
      result in tighter emission limits than assumed for new unplanned coal units
      in this  analysis.   To the  extent that  tighter  BACT  requirements would
      result in lower actual emissions,  Base Case emissions would be lower, and
      additional compensating reductions from existing sources would have to be
      provided in  the  existing-new  trading  cases  in order  to achieve the same
      overall emission reductions as  under  the current NSR program.

      However,  tighter BACT  requirements  would  raise the  marginal cost  of
      emissions control  at new sources,  thereby increasing the  cost savings
      enabled by  each  existing-new trade -- even  with  actual  emissions under
      BACT  used   as   the   baseline.     Since  further  existing-new  trading
      opportunities would  also be  created,  the total savings  resulting from
      existing-new trading could  be  somewhat higher than  estimated  herein.
      Therefore,  to  the extent that  the actual emissions forecasted  in this
      analysis for unplanned new units (based on BACT/NSPS for  planned coal
      units) are greater than the actual emissions that would  result from future
      BACT requirements, a more conservative (i.e.,  lower)  estimate of the value
      of existing-new trades would result.
-'     New units constructed at an existing plant may avoid the requirements of
      NSR by offsetting  their  emissions  with reductions at other units within
      the plant, such that no significant increase  in "net" plantwide emissions
      occur.  This regulatory procedure  is called  "netting."
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      Ambient Air Quality Standards/PSD Increments - For this analysis, existing-
      existing trades were permitted only  if  SIP emission limits continued to
      be met (and hence  ambient air quality standards were not violated).-'  For
      existing-new trades, it was assumed that new units would not be required
      to meet NSPS or BACT control requirements  on  site,  but would be located
      such  as  not to  violate ambient air quality  standards,  Prevention of
      Significant Deterioration  (PSD)  increments, or other  local  air quality
      requirements.   Most new units engaging  in  existing-new trades under the
      Proxmire or 30 Yr/1.2  proposals  are forecasted to  use low sulfur coals
      without  scrubbing,   and thus  are  not  very   likely  to  violate  these
      requirements.

      The average annual emission rates  forecasted  in 2010 for new units that
      trade with existing units  under  the  Proxmire  and 30 Yr/1.2 existing-new
      trading cases  are 0.8-0.9  Ib.  S02/mmBtu.  While  the  emission rates at new
      units  engaging   in   existing-new  trades  are   forecast   to  increase
      significantly (from a Base  Case average  of  0.3  Ib. S02/mmBtu), nearly all
      of these units  (94  percent under Proxmire  intrastate,  97  percent under
      Proxmire interstate, and 100  percent under 30  Yr/1.2 intrastate)  would
      still  satisfy  the  requirements  of  the original  1971  NSPS  (1.2  Ibs.
      S02/mmBtu on a 30-day average).  Moreover, any emission  increases relative
      to current NSPS and  BACT  requirements  would have to  be  offset by extra
      reductions at  existing units, and these  offsetting reductions would often
      be made at  other  units  in the same  plant or  in the same general vicinity.
      Due to these considerations, and  to the fact that background levels of S02
      are generally  expected to decline significantly in most parts  of the
      country under Proxmire  or  30  Yr/1.2, local air quality  constraints are
      not (in most cases) expected to be a limiting factor  in  the implementation
      of existing-new trades under these emission reduction proposals.

      Local air quality  constraints are  more likely to be a  limiting factor under
      the Base Case  with  existing-new trading and  a 1.2  to 1  trading ratio.
      Under this scenario,  the average  annual emission rate forecasted by 2010
      for new units  that trade with existing units is  1.6  Ibs. S02/mmBtu.  Only
      61 percent of the new units that trade  would  satisfy the original NSPS,
      while  33  percent are  forecasted  to have  emission  rates  of  2.8  Ibs.
      S02/mmBtu or higher.   Even  under  this scenario,  however,  the majority of
      new units that engage in existing-new trading are not expected  to face air
      quality constraints, because of low sulfur coal use,  offsetting reductions
      from  nearby units,  or a combination of these  factors.   There  may be,
      however, a much greater incentive for utilities  to locate new units at or
      near existing powerplants.
-1     It should be noted that  the  emissions  "increases"  that would be allowed
      at  existing powerplants  as  part  of a  trade are  not  increases  above
      allowable SIP levels.   Rather,  they are increases  relative  to the new,
      tighter limits that would be imposed under the acid rain control program
      in a  unit-by-unit  (no trading)  framework,  and would  be  compensated by
      further reductions from other sources beyond their new, tighter limits.


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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      To  the  extent  that  local ambient air quality constraints would serve as
      a limiting factor in the implementation of individual  existing-new trades
      under Proxmire, 30 Yr/1.2,  or the Base Case, these constraints  could often
      be  overcome  (while  still preserving most of the cost savings associated
      with trading) by using even lower sulfur fuels  for the units in question,
      down-scaling  the  size  of  the units,  or siting them in an  alternative
      location.

      It should also be noted that the long-term economic growth management goals
      of  the  PSD program (i.e.. maximizing  the availability of  air quality
      increment  over the long-run)  would not be  jeopardized by existing-new
      trading, since  existing-new trades  cannot extend beyond the  lifespan of
      the existing source,  and new sources would be  required  to meet NSPS and
      BACT requirements on-site  once existing  source trading partners retire.

      Nevertheless,  for existing-new trades  to occur,  local communities would
      have to accept a new unscrubbed unit with higher emissions in exchange for
      additional reductions  at existing units.   The  existing units providing
      extra reductions  would not necessarily be  located  at the  same plant or
      general vicinity as the new unit,  but could be located  at other distant
      powerplants and even  in  other  states.  Given the general difficulties in
      siting new polluting sources, and given that well  over 100 scrubbers have
      now been installed, it could be  difficult to convince local  communities
      to accept a new powerplant unit without a scrubber.

      With these considerations in mind, further review and analysis is necessary
      to  fully assess  the extent to which ambient air  quality standards,  PSD
      increments, and  other  local  air  quality requirements  might  reduce  the
      amount and value of existing-new trading,  particularly  in  the long term
      (i.e.,  beyond 2000) .2/
-'     In addition to local air quality  issues,  issues related to the generation
      and disposal  of  solid waste can also be important  in  the  siting of new
      powerplants.  However, solid waste issues have not been considered in this
      analysis.
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      Structure of an Acid Rain Program - An emissions trading program could be
      structured in a number of ways under an acid rain control proposal.  These
      relate to the manner in which emission reduction requirements are initially
      allocated  and   the   procedures  for  reallocating  emission  reduction
      requirements over time.

      For example,  an acid  rain  control proposal could  mandate that uniform
      emission  reduction  requirements be initially allocated to sources on a
      unit-by-unit basis.  Intrautility,  intrastate or interstate trading could
      then  be  accomplished by  allowing two  or  more units to  alter  their
      allocations  in  tandem,  so long  as  the same amount of overall reductions
      are provided.  Each trade would be  approved by the appropriate regulatory
      agency (or agencies),  so that the legally binding emission limits for each
      source can be revised.  While the specific limits applicable to the sources
      would change as  a  result of the trade,  each source would continue to be
      subject to its own enforceable  limit.

      Alternatively,  the  initial emission  reduction  requirements  could  be
      allocated  in the  form  of   a  utility,  statewide  or  regional  emission
      reduction requirement or emission cap.  Under this approach, the utility
      or state would  be  given discretion in initially allocating unit-by-unit
      reduction requirements,  as  well as in reallocating  them in the future.
      Reduction requirements for the individual units would be allowed to change
      (or "float") freely over time without case-by-case regulatory review,  as
      long as the overall utility, statewide or regional reduction requirements
      are met.

      The modeling methodology and assumptions used in the analyses presented
      herein are consistent with both  of these general  approaches  for allocating
      emission reduction requirements. Utility, statewide,  or regional emission
      targets were derived  from emission reduction requirements stipulated in
      the Proxmire bill and the 30 Yr/1.2 proposal,  and then imposed in ICF's
      Coal and Electric Utilities Model  (CEUM)  for utility sources to satisfy
      in a least-cost  manner (i.e., analogous to the "floating" bubble approach)
      in each forecast year.   However, the five/ten  year  periods between the
      forecast years  shown herein should be  more  than adequate  time  for the
      revision  procedures  of a  more  formal allocation/reallocation  system
      involving case-by-case regulatory reviews to occur, and the results of the
      modeling efforts should  therefore  be  representative  of this approach as
      well.
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    IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      Monitoring  and Enforcement  -  This analysis  assumes  that  an  acid rain
      related trading program could be designed to  be  fully enforceable so that
      the  emission  reductions  projected herein would be  reliably  obtained.
      Monitoring and enforcement procedures would have to be designed to ensure
      compliance on whatever time scale is necessary.   One way of  accomplishing
      this would be  to mandate the use of continuous emissions monitors, which
      would  provide  an effective means  of  monitoring and  enforcing reduction
      requirements.  Such an approach would be particularly important in the case
      of a "floating" bubble (discussed above),  and would alleviate the special
      difficulties associated with simultaneously measuring emissions from all
      units  in order to determine compliance with an overall emissions cap.

      Special concerns, however,  may arise with respect to the ability to enforce
      future  retrofit  requirements under  existing-new trading.   As  existing
      source trading partners retire and new unscrubbed units would be required
      to  retrofit control  equipment, utilities  may  attempt  to  assert  that
      installation of expensive  scrubbers (or equivalent controls) would cause
      economic hardship or,  because the once new units  have a shorter remaining
      life, that such controls would no longer be cost-effective.  However, these
      concerns  can  be mitigated by  requiring new  units,  as  a  condition for
      trading, to preserve retrofit space and waive all equity arguments in light
      of the savings realized through trading.   These concerns  can be further
      mitigated by incorporating into  an acid rain control bill severe statutory
      penalties for failure to meet retrofit control obligations.
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      Barriers to  Implementation  -  While the trading schemes analyzed in this
      report have  the potential to reduce  costs  significantly,  the extent to
      which such cost reductions would be realized in practice would  depend upon
      the degree to  which trading mechanisms can be successfully implemented.
      A  number  of  technical,   economic,   administrative,   and  institutional
      considerations  may serve  to  limit  trading  activity  under  an emission
      reduction program.  For example:

            While state public utility commissions (PUCs) and state environmental
            agencies are both concerned with economic and environmental factors,
            the purview of  state  PUCs is economic  and financial issues,  while
            the  primary  focus  of state  environmental agencies  is pollution
            control.  Emission trades  involve elements of both, and will require
            a greater degree and a different type of cooperation than currently
            practiced.

            Utility managers and operators may be reluctant to engage  in trading,
            due to uncertainty  about  the regulatory treatment of revenues and
            costs associated with trades.

            Imperfect  and incomplete information  on  other  potential  trading
            partners and on source emission levels   may inhibit or prevent full
            exploitation  of emission  trading opportunities.

            The time allowed for the state or utility planning process under some
            acid  rain  control  proposals may  not  be  sufficient for  trading
            arrangements  to be completed before federal approval of particular
            control strategies is required.

            As discussed above,, ambient standards,  PSD increments,  and other
            local air quality requirements can prevent the approval of existing-
            new trades  in certain situations, or require  new sources  to take
            additional  steps (e.g., using even lower sulfur  fuels) in order to
            effectuate  an existing-new trade.

      A number  of approaches exist  to  overcome  some  of  these implementation
      problems.    Nevertheless,  the extent  to  which  trading  activity  is
      constrained by such impediments  will be critical in determining the degree
      to which the savings forecasted in this analysis will be achieved.
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   IMPLEMENTATION ASSUMPTIONS AND UNCERTAINTIES REGARDING EMISSIONS TRADING
      Very Long Term Impacts of Existing-New Trades - This analysis  examined the
      impacts of existing-new trades through 2010,  but did not assess the impacts
      beyond 2010.  After 2010, many existing powerplants are likely to retire
      and the value of existing-new trades would decline, as  fewer existing unit
      trading partners would be available.   By 2040, all existing units would
      retire (assuming a 60 year lifetime),  and new units  which did not install
      scrubbers (i.e., because they  purchased emission  reductions from existing
      units) would have to  install controls in order to meet NSPS  and BACT.

      Existing-new  trading  can  thus  be thought of  as  an optional  program for
      deferring  installation of  a  scrubber  as  long  as  cheaper equivalent
      reductions from existing sources are available.  The costs of installing
      a scrubber or equivalent controls at new sources  will ultimately be faced
      by those utilities opting to engage in existing-new trades,  and these post-
      2010 costs were  not  addressed herein.  Further,  to the  extent costs of
      retrofitting controls  at already built  facilities would be greater than
      installing controls at these  facilities  when they were new,  total costs
      could be  somewhat  greater.   However,  if new  facilities  were built such
      that a  scrubber  could be added  at a  late date  (e.g., by  designing and
      leaving in the appropriate space during construction),  then  retrofit costs
      would be minimized.   Moreover,  by deferring  the installation  of hardware,
      the utility  could  benefit from  potential development  and  deployment of
      alternative, lower cost control  technologies.  In any case,  the deferral
      option provided  by existing-new trades is  likely  to be  attractive  to
      utilities because future capital  expenditures  are more heavily discounted
      than current investments.
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            SULFUR DIOXIDE CONTROL EQUIPMENT COSTS AND ASSUMPTIONS
      Sulfur  dioxide  control  costs,  removal efficiencies,  retrofit factors,
scrubber types, and new  control  technology assumptions have important impacts
on the forecasted costs  and coal production of the various emission reduction
cases and,  in particular, the value or net cost savings associated with existing-
new trades.  The costs of retrofitting a scrubber at  an existing unit are shown
in Table 3-1.  The costs  of scrubbers plus  particulate  control equipment at new
powerplants meeting-NSPS  Subpart Da regulations  (70 - 90 percent required total
removal including washing  credits  and  a 1.2 Ib. ceiling,  all enforced on a 30
day average) are shown in Table 3-2.  The costs of particulate  controls at new
unscrubbed plants (e.g.,  new plants which obtain emission offsets from existing
plants) are  shown in Table  3-3.   The costs, removal  efficiencies,  and other
assumptions are discussed below:

      •     Costs - The level of retrofit scrubber costs will affect
            the forecasted costs of reducing emissions from existing
            sources.   Higher or  lower  scrubber  costs will accord-
            ingly raise or lower the forecasted cost impacts.

            The costs of  scrubbing a new powerplant have a substan-
            tial  impact  on  the  net cost  savings  associated with
            existing-new trades.   Lower scrubber  costs would tend
            to reduce the net cost savings associated with existing-
            new plant trades since the savings associated with not
            scrubbing these plants  would be lower.   Higher new plant
            scrubber costs would result in  greater  net  cost savings
            associated with existing-new trades.

            The relative  costs  of scrubbing high versus  lower sulfur
            coals could influence forecasted coal production.  Many
            new plants are  forecasted  to scrub  lower sulfur coals
            because the  costs  of  scrubbing lower  sulfur  coals are
            lower than scrubbing high  sulfur coals  in order to meet
            NSPS.   If  the costs of scrubbing lower sulfur coals were
            more expensive  (relative to scrubbing high sulfur coals)
            than assumed  currently, more medium or high  sulfur coals
            might be  scrubbed, potentially resulting in  more high
            sulfur coal production in the Base Case.

            In  general,  lower scrubber costs would result  in a
            reduction in  the costs and would alter forecasted coal
            production.   Lower scrubber costs  would induce power-
            plants to retrofit  more   scrubbers and scrub  higher
            sulfur coals  rather than switching to low sulfur coals.
            High  sulfur   coal  production   would   likely  benefit.
            Higher scrubber costs would have the opposite but less
            significant effects because relatively  few scrubbers are
            forecast  to  be  retrofitted in  most  of the  emission
            reduction cases examined herein.
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                                          TABLE 3-1

                                 RETROFIT SCRUBBER COSTS FOR
                          EXISTING UTILITY POWERPLANTS (1.1 FACTOR)

                                       	Sulfur Level
Scenario Specifications

A.  Annual S02 Emission
    Limit (Ibs./mmBtu)
B.  Annual S02 Removed
    (Ibs./mmBtu)
C.  Percent Removal
D.  Scrubber Type

Scenario Cost (early 1986 $'s)
                                        Very
                                        Low  Low
                         Low-
                         Medium
            0.16  0.22   0.34

            0.64  0.86   1.32
             80%   80%    80%
             Dry   Dry    Dry
                         Medium
                         0.25

                         2.25
                          90%
                          Wet
High-
Medium
0.33

3.00
 90%
 Wet
0.50   0.67

4.50   6.00
 90%    90%
 Wet    Wet
A.  Capital ($/kw)
B.  O&M
    -- Fixed ($/kw-yr)
    -- Variable (mills/kwh)
C.  Capacity Penalty (%)
D.  Energy Penalty (%)
E.  Reliability Penalty (%)
         207.40 210.90 224.90   238.70   246.10   261.90 270.50
5.67
1.49
1.54
2.56
2.70
5.
1.
1.
2.
2.
78
68
54
21
70
5.
1.
1.
2.
2.
95
97
60
76
70
9
1
1
4
2
.63
.89
.96
.42
.70
9,
2,
2,
4,
2,
,98
,04
,06
.51
,70
10
2
2
4
2
.42
.28
.22
.68
.70
10.75
2.50
2.38
4.70
2.70
Sulfur Level
Lbs.  S02/mmBtu:
  Very Low Sulfur
  Low Sulfur
  Low-Medium Sulfur
  Medium Sulfur
  High-Medium Sulfur
  High Sulfur
  Very High Sulfur
         Less than 0.80
                  0.80-1.08
                  1.09-1.66
                         .50
                         ,33
          1.67-2.
          2.51-3.
          3.34-5.00
More than 5.00
  Dry:  Spray Dryer Flue Gas Desulfurization (FGD) System
  Wet:  "Wet" Limestone FGD System

Source:  EPA estimates.  Capital and fixed O&M costs shown above reflect a retrofit factor of
1.1  (i.e.,  the capital  cost  of retrofitting  a scrubber  is  1.1  times  the capital  cost of
installing a scrubber at a new powerplant,. and the fixed O&M cost is 1.075 times the O&M cost
of a  new  scrubber reflecting a  ten percent escalation  for  three-quarters of  the  fixed O&M
costs).  Most  existing powerplants have higher  retrofit costs.  Powerplants  with  no plant-
specific estimates were treated as follows:
      Size
Greater than 400 Mw
Between 150 and 399 Mw
Less than 150 Mw
         Capital Cost
         Relative to a
         New Scrubber

         110%
         140%
         200%
                            Fixed O&M
                         Cost Relative to
                          a New Scrubber

                              107.5%
                              130.0%
                              175.0%
      06C0174
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                                          TABLE 3-2

                     POLLUTION CONTROL COSTS FOR NEW UTILITY POWERPLANTS
                        (Scrubbers and Particulate Control Equipment)


                           	Sulfur Level	
                           Very
                           Low
           Low
          Low-               High-
          Medium    Medium   Medium
                              HiEh
Capital Costs
(early '86 $/kw)

Fixed O&M Costs
(early '86 $kw/yr)

Variable O&M Costs
(early '86 mills/kwh)
181.20   185.20

  4.91     5.00
  1.42
1.61
1.92
1.92     2.10
  Very Low Sulfur
  Low Sulfur
  Low-Medium Sulfur
  Medium Sulfur
  High-Medium Sulfur
  High Sulfur
  Very High Sulfur
      Less than 0.80
                0.80-1.08
                1.09-1.66
                1.67-2.50
                2.51-3.33
                3.34-5.00
      More than 5.00
Dry:  Spray Dryer FGD System
Wet:  "Wet" Limestone FGD System
BH  :  Baghouse
ESP:  Electrostatic Precipitation
                             Very
                             High
        193.60    277.00   279.80    283.60   292.60

          5.13      9.36     9.80     10.20    10.54
2.35     2.55
Energy Penalty (%)
Capacity Penalty (%)
Reliability
Penalty (%)
Scrubber Type
Particulate Control
Sulfur Level
2.23 2
1.51 1
2.7
Dry
BH
Lbs S02/mmBtu
.07
.52
2.7
Dry
BH
2.31
1.57
2.7
Dry
BH
4.41
1.94
2.7
Wet
ESP
4.60
2.15
2.7
Wet
ESP
4.83
2.39
2.7
Wet
ESP
4.93
2.53
2.7
Wet
ESP
      06C0174
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                                          TABLE 3-3

                     POLLUTION CONTROL COSTS FOR NEW UTILITY POWERPLANTS
                           (For New Plants Built Without Scrubbers)
                           	Sulfur Level	
                           Very              Low-               High-               Very
                            Low    Low       Medium    Medium   Medium    High      High
Capital Costs
 (early '86 $/kw)        82.80    82.80

Fixed O&M Costs           2.25     2.25
(early '86 $kw/yr)

Variable O&M Costs        0.40     0.40
(early '86 mills/kwh)

Energy Penalty (%)        0.95     0.95

Capacity Penalty (%)      0.95     0.95
                      82.80     82.80    62.10     48.30    48.30

                       2.25      2.25     0.77      0.61     0.61
                       0.40
0.40     0.14
0.11     0.11
                       0.95      0.95     0.21      0.21     0.21

                       0.95      0.95     0.21      0.21     0.21
Sulfur Level
Lbs.  S02/mmBtu:
  Very Low Sulfur
  Low Sulfur
  Low-Medium Sulfur
  Medium Sulfur
  High-Medium Sulfur
  High Sulfur
  Very High Sulfur
        Less than 0.80
                  0.80-1.08
                  1.09-1.66
                  1.67-2.50
                  2.51-3.33
                  3.34-5.00
        More than 5.00
Dry:  Spray Dryer FGD System
Wet:  "Wet" Limestone FGD System
BH  :  Baghouse
ESP:  Electrostatic Precipitation
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              SULFUR DIOXIDE  CONTROL EQUIPMENT COSTS  AND  ASSUMPTIONS
            The scrubber .cost assumptions used in the EPA Base Case
            were developed  in the  early 1980s using  the  TVA/EPA
            scrubber model.   Recent analyses performed by  ICF on
            behalf of EPA employ  scrubber cost assumptions that are
            40 percent lower in capital costs and 25 percent lower
            in O&M costs than the aforementioned EPA Scrubber cost
            assumptions.  This was  done  on EPA's  request  in order
            to bring the scrubber cost assumptions more  in line with
            current industry estimates.

            Retrofit  Factors  -   Unit-specific  retrofit  factors
            ranging from 1.1 to  2.0 were used in this  analysis to
            capture the  difficulties  and  constraints  inherent in
            retrofitting  a  scrubber   on  an  existing  unscrubbed
            powerplant.  All capital costs were escalated by these
            factors, but only three-quarters of fixed O&M costs, the
            portion directly related to maintenance, were escalated.
            Other costs, such as operating and landfill  labor and
            supervision, were not  considered to be  significantly
            affected by spacing limitations and congestion problems
            (i.e.,  those  factors which result  in  higher  retrofit
            costs) .  Differences among units in scrubbing costs have
            important impacts on selected compliance options.  These
            site-specific retrofit factors  were  developed  for EPA
            on a unit-by-unit basis for  the  200 highest  emitting
            powerplants  in 1980.    For  other  powerplant  units,
            alternative  estimates  were used  based on unit  size.
            (See Table 3-1).

            Table  3-4   shows  the  retrofit factors  for  existing
            unscrubbed coal capacity under current EPA assumptions.
            Currently,  there are  81 gigawatts  of utility coal-fired
            powerplants  with  retrofit costs  assumed  to be  10-20
            percent higher than the  costs of a new scrubber.  About
            59 gigawatts of this  capacity is non-NSPS  capacity.

            Higher or  lower retrofit  factors than  assumed  herein
            will accordingly  raise  or  lower  the  forecasted cost
            impacts,  and  will   result   in different  powerplants
            retrofitting scrubbers.

            Scrubber Types Assumed  -  Conventional  limestone  "wet"
            scrubbers and spray  dryer "dry" scrubbers  were assumed
            for this  analysis.   Wet  scrubbers are most  commonly
            used, although dry scrubbers are being increasingly used
            at newer  powerplants.    Based on  the scrubber  cost
            assumptions, wet scrubbers are more cost-effective than
            dry scrubbers  to  retrofit on  existing plants  burning
            high and medium  sulfur coals, in light of the assumption
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                                   TABLE 3-4

                    DISTRIBUTION OF POtfERPLANT CAPACITY BY
                        RETROFIT SCRUBBER COST FACTORS *•'
                                     (Gff)

                                 Retrofit Factor Categories-7

                                    1.1-1.2     1.3-1.6     1.7-2.0

Unscrubbed Coal Capacity (Gw)        81.0        59.7        67.8
            that baghouses also would  have  to be installed if dry
            scrubbers  were  retrofitted.   Dry scrubbers  are  more
            cost-effective in  those  rarer instances when existing
            plants are retrofitted with scrubbers using lower sulfur
            coals.

            For new  powerplants,  the  total  costs  (including fuel
            costs)  of  installing  dry scrubbers plus baghouses are
            generally cheaper than wet  scrubbers plus electrostatic
            precipitators (ESPs),  even when taking into account the
            higher prices  for low sulfur coal (which is  used at
            powerplants with dry scrubbers).

            Scrubber Lifetime  - For  this  analysis,  it was assumed
            that retrofit  and new scrubbers would have  a useful
            lifetime  of 30  years.   Given   the  limited  operating
            experience with scrubbers and retrofit applications to
            date,  it is uncertain how  long  retrofit scrubbers are
            likely to  last  and/or what additional  costs  might be
            required to keep them running  for 30 years.   To the
            extent retrofit scrubbers have a shorter  useful lifetime
            than 30  years,  the annual capital charges  and total
            costs incurred would be higher.
-'     Retrofit factors represent the percent increase of capital costs and three-
      quarters of fixed O&M costs for retrofit scrubbers relative to the costs
      of new  powerplant scrubbers.   Hence,  a powerplant in  the  1.2  retrofit
      factor  category which retrofits a  scrubber will experience  20  percent
      higher capital costs and 15  percent  higher  fixed O&M costs than the costs
      of new scrubber.

-'     Eight categories are used in the analysis.  The  total number  of plants and
      capacity reflect the top 200 emitting powerplants evaluated for EPA plus
      all other existing unscrubbed capacity (on-line as of end-1985)  which could
      potentially be  affected  by  retrofit scrubbers.   Note  that this capacity
      includes unscrubbed NSPS capacity,  which comprises a significant portion
      (22.4 Gw) of the 1.1-1.2 retrofit categories.
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            SULFUR DIOXIDE CONTROL EQUIPMENT COSTS AND ASSUMPTIONS
            Removal Efficiencies - A maximum annual average removal
            efficiency of 90 percent was assumed for retrofit "wet"
            scrubbers and a  maximum of 80 percent was assumed for
            "dry"  scrubbers.   Assuming  greater  scrubber removal
            capabilities (at a reasonable cost) might result in more
            reduction  through  scrubbing  and  less   through  coal
            switching.   This could result  in greater high sulfur
            coal  production.   Assuming  a  lower maximum removal
            efficiency  (such as  85 percent  for  "wet"  scrubbers)
            would have the opposite effects.

            New Control  Technologies  - New sulfur dioxide control
            technologies were  not  assumed for this  analysis.   New
            "retrofit"   control   technologies  (such   as  sorbent
            injection)  could  result  in  lower  costs  for meeting
            emission reduction requirements.  Some view new emission
            control  technologies  as quite  promising,  and believe
            that  they  are   likely to  be  available  for use  by
            utilities by 1995  at  significantly  lower  costs  than
            conventional  scrubbers.   However,  given the limited
            operating experience  and  uncertainty surrounding  the
            costs and performance  of  new control technologies,  it
            is unlikely that  many utilities would pursue  this option
            by  1995.    By   2000  or  2010,   new  emission control
            technologies are likely to be more promising however.

            On balance,  the  assumption of no new control technol-
            ogies or no control technology improvements by 1995 is
            probably conservative and the assumption of new technol-
            ogies in 2000 or  2010 is even more conservative.  To the
            extent  some  improvements  do  occur,  the  costs  of  the
            emission reduction cases would be lower.  On  the other
            hand, the  value  or  net cost savings of  existing-new
            plant trades could be less  with  new  technologies.  This
            is because new control  technologies could also be used
            at new plants (if the minimum 70 percent removal could
            be achieved), This would result in lower costs--but less
            net  savings--associated  with  avoiding  the  percent
            removal  requirement  at these  plants by negotiating
            existing-new plant trades.
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                SITE-SPECIFIC CONSTRAINTS AFFECTING ALTERNATIVE
                         EMISSION REDUCTION STRATEGIES
      Site-specific limitations exist which will affect the  ability of specific
units to  pursue certain alternative emission reduction strategies.   For this
particular analysis, plant-specific retrofit scrubber costs and coal switching
costs have been captured through specific constraints in ICF's  Coal and Electric
Utilities Model  (CEUM).  The forecasted cost and coal production impacts under
the emission reduction cases will  be affected by these  assumptions, as outlined
below:

      •     Retrofit Scrubbers  - As discussed earlier, unit-specific
            retrofit  factors  were  applied  to   the  cost of  a new
            scrubber in order to account for  site-specific difficul-
            ties in retrofitting scrubbers on existing powerplants.

      •     Coal  Switching  Costs  -   Coal   switching   costs  were
            developed by ICF for EPA and included in this analysis.
            These estimates were  used  in  this  analysis to capture
            approximately  the  added  coal  transportation  capital
            costs (e.g., refurbishment of existing or the building
            of  new  rail  spurs)  and coal  handling capital costs
            (e.g., new  rotary  dumpers,  dethawing equipment, etc.)
            that specific powerplants  would incur  if  they shifted
            to  lower  sulfur coals.   About  15  gigawatts of power-
            plants are estimated to  incur significant costs  if they
            shift to  lower  sulfur coals.    Of  these,  11 gigawatts
            incur costs associated with refurbishing existing rail
            spurs  and  upgrading  coal  handling equipment.    The
            remaining  4  gigawatts  of  capacity  might  have  to
            construct entirely  new rail spurs and purchase new coal
            handling equipment.   The cost  estimates are  shown in
            Table 3-5 for 200 and 500 megawatt powerplants.   These
            estimates tend to be conservatively high.   Powerplants
            requiring new rail lines (especially smaller ones) might
            find it more economic  to unload  coal off trains, reload
            it onto trucks and then transport it to the plant.  To
            the extent that this is true,  switching costs would be
            lower than noted herein.  Higher or lower  coal switch-
            ing costs influence which powerplants choose to switch
            coals and  how much fuel switching  occurs  relative to
            retrofit scrubbing, although only a relatively limited
            amount of capacity is  affected by these constraints.
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                                   TABLE 3-5

                              COAL SWITCHING COSTS
                               (early 1986 $/kw)
                                                              Plant Size
                                                          200            500

Medium Cost  - Refurbishing  Existing Rail  Lines            115             70
                 and Coal  Handling  Equipment-'

High Cost    - Constructing  a New Rail  Spur,               265            130
                 Purchasing  New Coal Handling
                 Equipment-'
Source:  ICF estimates
-1     Assumes 15 mile spur refurbishment  at  $1  million/mile.

-'     Assumes 15 mile spur construction at $3 million/mile.
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                SITE-SPECIFIC CONSTRAINTS AFFECTING ALTERNATIVE
                         EMISSION REDUCTION STRATEGIES
            Utility  System Constraints -  For  any utility, system
            operating  constraints  such  as  area protection and
            specific  unit  turn-down  rates  limit  a  utility's
            flexibility to change the operation of its powerplants.
            Such  an  assessment could  be  made  through  the use of
            ICF's utility-specific capacity planning and dispatching
            model  (IPM-Integrated Planning Model).   However, the
            development of such  constraints were beyond the  scope
            of  this  study,  and  hence no such  constraints  were
            incorporated.

            Particulate Control Equipment  Upgrade  Costs  -  Particu-
            late  upgrade  costs for powerplant  units switching to
            lower  sulfur  coals were developed  for EPA to capture
            approximately  the  added  electrostatic  precipitation
            equipment costs  incurred  because of the inherent high
            resistivity  of  ash   from  lower  sulfur  coals.    The
            equipment is upgraded most commonly through the instal-
            lation of a flue gas conditioning system (injection of
            sulfur trioxide into the flue  gas)  or by  increasing the
            plate collection area.  The costs presented in  Table 3-
            6 are average costs,  which  assume  75 percent of the
            units  that  switch to lower sulfur  coals will install
            flue  gas conditioning,  while  the remaining 25 percent
            will  add new  plate  area.   Particulate  upgrade   costs
            influence which  units choose  to switch  coals  and how
            much   fuel  switching  occurs  relative   to   retrofit
            scrubbing.

            Mine-Mouth  Powerplants -  Mine-mouth  powerplants (or
            plants burning only local coals) often have limited coal
            handling.and transportation facilities.  These limita-
            tions  are  captured  to a  certain  extent  in  CEUM  by
            requiring some local coal  to be supplied  to the utility
            sector.  These quantities  are  relaxed over time so that
            CEUM is free to substitute non-local coals in increasing
            proportions, if this is more economic.
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                                      TABLE 3-6

                   PARTICULATE REMOVAL EQUIPMENT UPGRADE COSTS FOR
                EXISTING UTILITY COAL-FIRED POWERPLANTS  SWITCHING TO
                                 LOWER-SULFUR  COALS
                                  (early 1986 S/kw)
                              Coal Used After Switching
Original Coal
Used
Low
Low-Medium
Medium
High-Medium
High
Very High
Sulfur Level
Very Low
Low Low Medium
11
12 10
14 12 10
15 14 12
17 15 14
17 15 14
Lbs. S02/mmBtu:
                                                                High-
                                                        sdium   Medium   High
  Very Low Sulfur
  Low Sulfur
  Low-Medium Sulfur
  Medium Sulfur
  High-Medium Sulfur
  High Sulfur
  Very High Sulfur
Less than 0.80
      0.80-1.08
      1.09-1.66
      1.67-2.50
      2.51-3.33
      3.34-5.00
More than 5.00
                                                        10

                                                        11

                                                        11
Note that for the above assumed particulate upgrade costs:

            Costs are applied to all existing powerplants which shift  to
            lower-sulfur coals.

            Costs are also applied to existing powerplants which retrofit
            scrubbers and shift coals.

Source:  Energy Ventures Analysis estimates developed for EPA.
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                SITE-SPECIFIC CONSTRAINTS AFFECTING ALTERNATIVE
                         EMISSION REDUCTION STRATEGIES
            Long-Term  Contracts  -  Existing  long-term contracts may
            restrict  the  flexibility of utilities  to  switch to
            different  coals  under  various regulatory alternatives.
            To the extent that public  information on these contracts
            is available,  these  contracts were  incorporated within
            CEUM.  Similar to the constraints for mine-mouth plants,
            these  are  relaxed  over  time,   reflecting  the  known
            duration of these contracts.  In addition, fifty percent
            of  these  contracts for medium  or  higher sulfur coals
            were  assumed  to  be  abrogated  under  the  emission
            reduction  cases, reflecting the exercising  of "force
            majeure" provisions.   Aside from these constraints and
            this modelling treatment,  no costs were included in this
            analysis  for abrogating  existing  or newly negotiated
            long-term  coal contracts.

            Boiler Specifications  - Certain  boiler types (primarily
            cyclones or wet-bottom pulverizers)  require the use of
            low-ash fusion coals.  There is  a relative  scarcity of
            low-sulfur,  low-ash   fusion  coals,  particularly  in
            Appalachia and the Midwest.   In an attempt to capture
            this  scarcity,  wet-bottom  and  cyclone boilers  were
            restricted from shifting to low-sulfur coals.  There are
            a few existing unscrubbed plants with wet-bottom boilers
            or  cyclone burners  and  low  sulfur  dioxide  emission
            limits.   These  units  were  presumed  to  have obtained
            sufficient reserves of low-sulfur,   low-ash fusion coal
            to continue to meet their emission  limits and were not
            restricted from  using  low-sulfur coal.

            Coal Rank  Specifications  -  Existing coal-fired power-
            plant units designed to burn bituminous coals were not
            permitted  to shift  to lower rank coals  (e.g.,  from
            bituminous  to  subbiturainous) unless such plans  have
            already been announced.   Because of the design of the
            boilers  and particulate  removal  equipment  of  these
            powerplants, burning lower rank  coals  typically results
            in capacity  deratings,  increased  forced outage rates,
            and higher operating  costs.  At present, little reliable
            information  is  available  to   estimate  these  costs.
            Further, these costs are  likely to be very  site- and
            boiler-specific.  To avoid these problems, all existing
            units designed to burn  bituminous coals were restricted
            to  bituminous  coals  when  considering  shifting  coal
            supplies  unless, as mentioned  above,  plans  to  this
            effect have already been announced.   To the extent that
            subbituminous  coal  compliance  options  prove  to  be
            economic,   the   increase  in  Western  regional   coal
            production would be  spread  among more regions  and the
            cost impacts would decrease.
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                SITE-SPECIFIC CONSTRAINTS AFFECTING ALTERNATIVE
                         EMISSION REDUCTION STRATEGIES
            Coal Transportation - ICF estimates coal rail rates as
            the  long-run variable  costs  of  rail transportation.
            This cost-based rate  is  the lowest rate a railroad would
            offer  to  avoid losing the traffic.   The  use of cost-
            based  rates will  result in  forecasting  the  correct
            compliance  coal  option  (i.e.,  the least-cost option).
            However, the actual rate the railroad will charge will
            generally be just less than the next-best alternative  -
            -which may be another carrier, another mode, coal from
            another region, or another fuel.   Where the markets are
            competitive, the rate will be quite close to the cost-
            based rate.  However, where little competition exists,
            this charge may be higher than the cost-based rate, up
            to the cost of the next-best alternative.

            In economists'  terms,  this difference  between the cost-
            based  rate and  the   actual  rate  is  not  a "cost  to
            society" but a  "wealth transfer" from utility ratepayers
            to railroad stockholders or ratepayers  (depending on
            Interstate Commerce Commission regulations).  The costs
            presented  in  the EPA Base Case  and  changes  in costs
            presented  under  the emission  reduction  cases  thus
            represent  "costs to  society".   Costs  to  utility rate-
            payers  could be higher  in  some  but  not  all  circum-
            stances.  However, rates between the carrier's costs and
            the costs  of the next-best alternative have little or
            no effect on the source  of the transported coal. -1

            In general,  recent  ICF analyses  (including  detailed
            examination of rail costs and rates to the AEP and TVA
            utility systems, as  well as  examination  of  costs and
            rates to other  utilities and individual plants) suggest
            that many  rail rates are  close  to long-run variable
            costs.    Further,  the number of  "captive"  powerplants
            (i.e.,   powerplants with  little  or no  transportation
            competition) has dwindled in the past several years as
            rail deregulation and market forces in  the coal industry
            has fostered considerable competition among railroads.
            This trend  is  expected  to continue.   Also,  most "cap-
            tive"  powerplants  are generally  located  in the  West
            and/or are already  using lower sulfur  coals.  Thus, the
            implications of using cost-based rates for these plants
            are relatively  insignificant when analyzing electricity
            rate impacts under the emission reduction cases.
-1     See  memorandum  to  Rob  Brenner,  EPA  entitled  "Transportation  Rate
      Assumptions for Coal Market Modeling," June 26, 1984; see also memorandum
      to Rob Brenner entitled "Response to Comments  Received on July 26,  1984
      Memo  entitled  'Transportation  Rate  Assumptions  for  Coal  Marketing
      Modelling,"1 April 5, 1985.
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                SITE-SPECIFIC CONSTRAINTS AFFECTING ALTERNATIVE
                         EMISSION REDUCTION STRATEGIES
            ICF's assessment of long-run variable costs  is based on
            engineering  analyses  of rail, barge  and truck costs.
            These costs  have  been developed  for and reviewed by a
            number of  railroads and electric utilities.  The cost
            estimates  are  regularly  compared  with tariffs  and
            contract announcements  in  order  to ensure  the reason-
            ableness of  the estimates.  Nonetheless, the estimates
            should be  still viewed as  approximate to any specific
            movement.
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                             BASE CASE ASSUMPTIONS
      As noted in Chapter One,  EPA  specified a base case for this analysis.  EPA
Base  Case  assumptions  are  presented  in Appendix  D.    Important assumptions
pertaining to forecasted emissions: and cost impacts are discussed below.  Note
that the EPA Base Case used in this study was originally analyzed in early 1987,
incorporating assumptions developed in late 1986.  More up-to-date assumptions
(e.g.,  higher  electricity/High Oil  levels,  higher coal  mining  productivity,
lower oil and gas prices, etc.) would likely lead to some important changes in
the quantitative forecasts.   However,  the general qualitative results presented
herein  likely would not change appreciably.

      •     Electricity  Growth Rates  -  Lower  electricity growth
            rates  would lower  the utilization of some  existing
            powerplants in the Base Case and would lower Base Case
            sulfur dioxide  emissions.   This would  also lower the
            emission reductions required under the Proxmire and 30
            Yr/1.2 scenarios,  and thus  would  lower the  costs  of
            meeting the  targeted emissions  levels  under the cases
            examined.   On the other hand, lower electricity growth
            rates would reduce the number of new coal plants built
            in the future, and  thus would lower the amount of net
            cost  savings  associated with  permitting  existing-new
            source  trades.    Higher  growth rates  (as  evidenced
            recently)  would tend to have the opposite effects.

      •     Nuclear Capacity.  Availability  and  Lifetimes  -  EPA
            assumed for  this analysis  that nuclear capacity would
            be built based on current utility plans and schedules.
            This  includes  the  assumption that  all existing  TVA
            nuclear units would  be brought back on-line.   In the
            longer term (after 1995),  no additional  new nuclear
            capacity is  assumed to  be built and nuclear plants begin
            to retire  (a 35 year lifetime was assumed) .  The nuclear
            capacity and retirement assumptions  have  an important .
            impact on  the amount of new coal plants built (particu-
            larly after  2000),  and  hence  the amount of existing-new
            trading opportunities  and the net cost savings associ-
            ated with  these trades.  Also, future emission levels,
            required reductions and utility costs would be affected.

            In  addition,  the  availability of  nuclear plants  is
            assumed to  improve by  1995.   Nuclear capacity factors
            were assumed to  increase  from current  levels  of about
            60 percent  to  67 percent by 1995.   This  increase  in
            capacity  factors assumes  that  low capacity  factors
            experienced  currently --   resulting   in   part  from
            increased Nuclear Regulatory Commission (NRC)  scrutiny
            following  the accident  at  Three Mile Island in 1979 and
            other technical problems - - will be resolved and there
            will be relatively few new NRC regulatory requirements.
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                             BASE CASE ASSUMPTIONS
            Lower estimates of  the  future  availability of nuclear
            plants would have similar  impacts  as reducing assumed
            nuclear capacity,  and would result in increased utili-
            zation of existing  fossil  fuel powerplants  and more
            construction  of  new  coal  powerplants.    Base  Case
            emission  forecasts  would  be  higher,  and  required
            reductions from existing plants and costs would also be
            higher, although not significantly. More new coal-fired
            powerplants would be built,  and the net cost savings of
            existing-new trades  would be greater.   Higher nuclear
            estimates would have the opposite effects.

            Fossil   Powerplant   Lifetimes   -  Fossil   powerplant
            lifetimes and assumed retirements will have  an important
            effect on the amount  of new  coal plants built,  the
            amount of existing  capacity available  for  trades,  and
            thus existing-new trades.   The EPA  Base  Case assumes
            that all  fossil  steam units are refurbished  when  the
            units reach 30 years  of age,  and that such refurbishment
            activity extends the useful life of  these  units by an
            additional 30 years.  EPA's 60-year lifetime assumption
            was based on several factors.   While history suggests
            that a fossil steam powerplant will  retire after roughly
            40 to  50  years  of service if  no major  life  extension
            efforts are pursued,  utilities  are currently refurbish-
            ing many  existing powerplants (and will likely refurbish
            many more powerplants in the future).  This  is primarily
            because of  the  lower costs and risks  associated with
            refurbishing existing capacity in lieu of building new
            powerplants.     Electric  Power   Research  Institute
            estimates suggest that  refurbishment  activities could
            extend the life of a powerplant by about 20 years,  and
            that perhaps as many as three-quarters of. the  fossil
            steam  units would  be  plausible  candidates   for  life
            extension.  Based  on these and  other estimates, EPA has
            assumed a 60-year average lifetime.  Some units  may in
            fact have their lifetimes extended well beyond 60 years,
            while other units less  suited  to refurbishment  may be
            retired  earlier  (possibly  without any  refurbishment
            efforts at all).

            This assumption should be  investigated  further.   This
            should include assessments  of  the potential  scope of
            powerplant refurbishments and review of those that might
            not be  suitable  for refurbishment (e.g.,  units  with
            supercritical boilers or units which have been frequent-
            ly cycled are not likely to be refurbished because of
            the greater operating  stresses which such units  have
            experienced).
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                             BASE CASE ASSUMPTIONS
            Advanced Generating Technologies and Cogeneration  - New
            plant technologies and cogeneration will have important
            impacts  on the  amount of new  coal-fired powerplants
            built  and thus  the  amount and value  of existing-new
            plant   trades.     Innovative  electricity  generation
            technologies such as solar, geothermal, wind, advanced
            combined   cycle,   combined  cycle  gasification,   and
            fluidized bed combustion (FBC) units, are incorporated
            into the  EPA  Base Case to the  extent  that  such units
            have been planned (e.g., the Ocean States Power combined
            cycle project in New England) or are in operation (e.g. ,
            Black  Dog 2 of Minnesota and  Nucla of  Colorado FBC
            units).  The most significant penetration of new plant
            technologies is  likely to be in the burgeoning area of
            small power production or  cogeneration.   Estimates of
            new  technologies  in   this  area  are also  explicitly
            incorporated into the  forecasts.

            World Oil  Prices and Gas Prices - EPA  Base  Case world
            oil prices  and gas prices have  an important long-run
            effect on the amount of new coal capacity built (in lieu
            of new  oil/gas  plants).   Lower long-term oil  and gas
            prices would reduce the amount of  new coal plants built
            (and thus the amount of existing-new trades).  Oil and
            gas prices by 1995 are  unlikely to have a very signifi-
            cant impact on  the utilization of existing coal plants
            versus oil or gas plants.  The EPA Base Case assumes $24
            per barrel prices  in 1995  in .1987 dollars.   Even with
            prices at $13-17 per barrel in 1995, most existing coal-
            fired powerplants would still be  dispatched  ahead of
            oil/gas steam plants, and hence sulfur dioxide emissions
            from  existing   sources  would  be   affected  only  to  a
            limited extent.  Further, even, at  this oil price range,
            the costs of switching  from coal to oil  or  gas are still
            likely to be much higher than other compliance options,
            and therefore will have relatively little  impact on the
            cost and  coal  production  impacts  of the cases.   Oil
            prices significantly below  $13 per barrel  could lead to
            the back-out of coal by oil  and gas in some areas and
            greater  cost-effectiveness  associated with  switching
            from coal to oil or gas use to reduce emissions.  This
            could have large impacts on  costs and  coal  production
            forecasts.
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                             BASE CASE ASSUMPTIONS
            Availability of Very Low Sulfur Coal Reserves - The  cost
            and availability of very low sulfur coal reserves  (i.e. ,
            below  0.8  Ibs.  S02 per  million  Btu)  are an  important
            factor in assessing the  cost and coal production effects
            of achieving  emission reductions and,  importantly,  in
            achieving  cost  effective  existing-new  trades.     In
            analyzing the 30 Yr/1.2  cases,  ICF conducted additional
            analysis  of the  costs   and  availability of  very low
            sulfur bituminous  coal  reserves.  This assessment was
            based  on discussions with  low  sulfur coal  producers
            throughout the U.S.,  a review of published geologic  data
            in candidate regions, and analysis of  electric utility
            coal shipments over the  past 15 years.  This  preliminary
            assessment  determined  that  effectively  no  very  low
            sulfur coal reserves  are located in  the East;  signifi-
            cant quantities can  be  found  in the West.  It must  be
            stressed that, given the very short period of  time  over
            which this analysis was  conducted, this assessment was
            quite  preliminary  and   not   comprehensive.   Further
            analysis is needed to  fully examine the costs,  availabi-
            lity and quality of very low  sulfur Eastern  and Western
            reserves,  and  to  develop  modelling  treatments   more
            appropriate for these scarce resources.

            Availability of  Import  Coals -  This  analysis did not
            assess the potential penetration of import coals in the
            East.  Given  the  relatively  high transportation costs
            to ship Western very  low sulfur coals to the Gulf and
            Atlantic states, import  coals (particularly those with
            very low sulfur content, such  as  Colombian coals) could
            prove  to  be very  competitive.    The  extent  to  which
            foreign coal  use  is  enhanced  and domestic  production
            reduced by the emission  reduction requirements of these
            proposals should be the  subject  of additional  analysis.
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                             BASE CASE ASSUMPTIONS
            Coal  Mining Productivity  - A  key component  of coal
            supply, and thus coal prices,  is coal raining productiv-
            ity (measured as tons produced per machine shift for new
            deep mines, tons per man-day for new surface mines, and
            tons per man-year for existing deep and surface mines).
            For most of the 1970s,  productivity declined due  to new
            health  and safety regulations,  new state and federal
            strip  mine  regulations,   1974  United  Mine  Workers
            Association union work rules, an influx of younger and
            inexperienced workers, and  deteriorating labor-manage-
            ment  relations.   However,  productivity  has  improved
            dramatically since  1978.   In particular,  between 1982
            and early  1986,  deep mining productivity increased at
            a 10 percent annual  rate, while  surface mining produc-
            tivity  grew by 5 percent annually.   Estimates of the
            future gains in coal  mining productivity (i.e. ,  tons per
            worker-year) have an important  impact  on the  costs of
            producing  coals and  hence future coal prices.   For the
            EPA Base Case,  gains in  productivity  were expected to
            continue.  To  the  extent  there are larger gains, coal
            prices  (and  thus the  costs of  coal  switching)  would
            generally  be  lower.   Further,  coal mining employment
            levels would also be lower.   Smaller  gains would have
            the opposite effects.

            For the EPA Base Case,  it  is expected that productivity
            in the  industry will continue  to improve  at  about a 3
            percent per year rate for  deep mines and at a 2 percent
            per year rate for surface mines, reflecting an assess-
            ment of historical data and  underlying long-term trends
            on productivity gains and  technological  improvement.
            This rate  of the growth in productivity will be offset
            somewhat by  annual  real  wage  increases.   Given the
            recent historical evidence,  this rate of annual produc-
            tivity growth is likely to be achieved if technological
            efficiency gains continue at their current pace and if
            no major   institutional changes (i.e., no  unexpected
            regulations) are enacted.   In fact, recent ICF assess-
            ments would suggest higher assumed rates of productivity
            growth than were used in the EPA Base  Case.  Historic-
            ally,  coal mining productivity has grown by about 5-10
            percent  per  year  between  1986 and  1988 (since  the
            development of the EPA Base Case in 1986).
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                RESTRICTING UTILITY FORECASTS BETWEEN SCENARIOS
      In analyzing  the  emission reduction cases,  certain activities were held
at forecasted Base Case levels.   This was done to facilitate  comparison  of costs
and emissions between scenarios.

      •     Gas  Consumption -  was held  at  Base Case  levels for
            utilities.   To the  extent utility  users  can shift to
            more  gas,   utility  compliance costs  could  be  lower.
            However, the effect  of this increase in demand  for gas
            on  gas  prices could  increase  national  consumer costs
            substantially.  Lower gas prices than assumed herein for
            the  EPA Base Case  (as recent  analyses  might suggest)
            would have  an  important effect on forecasted base case
            emission levels, and hence on utility compliance costs
            and  the value  of  emissions  trading under an acid rain
            control program.

      •     Electricity Transmission  -   was  constrained   to  the
            interregional flows which were forecast  to occur in the
            Base  Case.    If powerpool  arrangements  of long-term
            transmission agreements permit changes in these flows,
            the  forecasted costs of the  emission  reduction cases
            could be  moderately reduced,  especially  in the West.
            Additional  cost reductions could accrue if additional
            power could be  imported  to the U.S. from Canada.   The
            extent  to   which  the  emission  reduction cases might
            create incentives for greater interregional transmission
            flows  from  Canada  has   not  been explored in  this
            analysis.

      •     Coal and Nuclear Poverplant Builds  - were also held to
            Base Case  levels.    Different powerplant  builds would
            affect  the  forecasted changes  in  costs,  though  only
            slightly.
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              DIRECT  COSTS AND  NEAR-TERM CONSTRAINTS  NOT  ANALYZED
      Some of the direct costs of the emission reduction alternatives were not
measured for  this  analysis.   These potential costs  could be significant, but
their exact magnitude is uncertain.  These costs were beyond the scope of this
particular analysis,  although they have been the  subject  of other analytical
efforts by ICF.

      •     Emission  Reductions  From   and   Trading  Uith  Other
            Sectors - were not assessed at EPA's  direction.   The
            costs of  emission reductions  from other sectors could
            be significant. The value of intersector trading could
            also be important, and is worthy of further investiga-
            tion.

      •     Low Sulfur Oil Prices - were assumed not  to increase in
            response to greater forecasted demand by utilities for
            low-sulfur  residual  oil.    However,  these prices  may
            increase, resulting in higher costs for all users of low
            sulfur residual oil.

      •     Gas  Prices  - were  not assumed  to  increase  for this
            analysis.   Gas  consumption was  also  assumed not  to
            increase.   To the extent utilities  are able  to obtain
            additional gas supplies, the forecasted costs under some
            of the cases may be overstated somewhat.  However,  gas
            prices would also increase  in response to  increased
            demand for  gas and for competing fuels  (such  as low-
            sulfur oils).

      •     Short-Run Production  and Transportation Bottlenecks -
            were not assumed  in this analysis.  Rather, the analysis
            assumed that market prices  would come into equilibrium
            and  excluded  any short-run  disequilibrium  effects.
            Short-run production or transportation constraints could
            influence the  costs  of any major emission  reduction
            program in the near-term,  although they are not likely
            to have any  significant impact under  the Proxmire  and
            30 Yr/1.2 as  described  herein,  since  only  moderate
            reductions  are required under both of  these  cases  in
            1995.

      •   '  Scrubber Manufacturing Constraints  - were  not assumed
            in this analysis.  However,  none of the cases forecasts
            a significant amount  of retrofit  scrubber  activity  in
            the near-term, and thus no constraints to building these
            scrubbers .would be expected.
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                          INDIRECT COSTS NOT MEASURED

      Many of the indirect costs of the emission reduction  and emission trading
cases were not measured for this analysis,  including:

      •     Administrative and Transaction  Costs - associated with
            establishing  regulatory  mechanisms  to  implement  a
            trading program could be significant.

      •     Lost  Investments  in  Existing Mining Operations - will
            depend on the extent to which regional coal production
            falls below existing levels.  Some losses, particularly
            in  the  Midwest and  Northern Appalachia,  could occur
            under several  of the  emission  reduction alternatives
            examined because of shifts  in regional coal production.

      •     Indirect and Regional Impacts of Lost Mining Jobs - will
            depend on the shifts  in regional coal production and the
            attendant changes in coal mining employment.

      •     Costs of Abrogating Long-Term Contracts - Fifty percent
            of current medium and  high sulfur  long-term coal con-
            tracts still in effect in 1995 and 2000 were assumed to
            be abrogated  as  a  result  of "force  majeure"  clauses
            under the emission reduction cases.   Costs of abrogating
          .  these long-term contracts could  be significant, depend-
            ing on the specific provisions of various existing coal
            contracts.  These costs have not been addressed  in this
            analysis.   To  the extent  these become  important,  the
            cost  impacts identified  in this analysis would under-
            state the actual  impacts.

      •     Indirect and Regional Impacts of New Mining. Transpor-
            tation,  and  Manufacturing  Jobs  -  will vary  with  the
            forecasted increases and decreases  in regional mining
            employment, shifts in coal shipments, and increases in
            manufacturing (e.g., retrofit scrubbers).

      •     Impact  of  Higher  Electricity  Rates  on  Electricity
            Demand - This analysis did not  examine  the effects of
            higher electricity rates on the  demand for electricity,
            in that when  the  price of  electricity  increases,  the
            demand for consumption of electricity is reduced.  Not
            incorporating this price elasticity of  demand has  the
            effect of overstating compliance costs somewhat in that
            some  of  the  required reductions would be  achieved by
            producing less electricity.  However, there would also
            be  a loss  to  consumers   (i.e.,  a  loss in  consumer
            surplus, in economists' terms) as a result of the higher
            rates and  reduced consumption.   This loss  would also
            have to  be added to  the reported costs of the programs.

      •     Opportunity Costs  of  Capital  - An acid rain program will
            likely lead to increased investments  in control technol-
            ogies.  These funds  could  be put to other  social uses
            (with possibly higher returns), and hence  there could
            be opportunity costs.  These costs were not measured for
            this analysis.

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n
L!
in
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B
M

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                                   APPENDIX A

                              BASE CASE FORECASTS
      This  appendix  presents  detailed  forecasts  of utility  sulfur  dioxide
 emissions and regional coal production assuming no implementation of federal acid
 rain  legislation.  Also included are forecasts of emissions, changes in utility
 compliance costs,  and coal market effects were  existing-new  trading (at a 1.2
 to  1  trading ratio)  to be  instituted.
06C0022
Page A-l

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                                                            TABLE A-1

                                                    SULFUR DIOXIDE FORECASTS
                                                         EPA BASE CASES
UtlIItV SO? Emissions
  (mill ions of tons)
   31-Eastern States
       Coal
         Ex I sting
         New
       TOTAL COAL
       OIL/GAS
   TOTAL 31-EASTERN STATES

   17-Western States
       Coal
         Existing
         New
       TOTAL COAL
       OIL/GAS
   TOTAL 17-WESTERN STATES

   United States
       Coal
         Ex I s 11 ng
         New
       TOTAL COAL
       OIL/GAS
   TOTAL UNITED STATES

1980
14.92
0.0
14.92
1.27
16.19
1.10
0.0
1.10
0.09
1.19
16.02
16!o2
1.36
17.38

1965
14.21
0.0
14.21
0.57
14.78
1.48
0.0
1.48
0.01
171*9
15.69
0.0
15.69
0.58
16.27

EPA
BASE
CASE
1995
15.26
0.15
15.41
~T6743
2.00
0.05
2.05
0.12
2. 17
17.26
0.20
17.46
1.14
18.60
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1995
0.0
0.0
0.0
0.0
0.0
-0.03
0.02
0.0
0.0
-0.00
-0.03
0.03
0.0
o.o
0.0

EPA
BASE
CASE
2000
15.85
0.34
16.20
17.39
2.05
0.09
2.13
0.13
2.26
17.90
0.43
18.33
1.32
19.65
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000
-1.96
1.65
-0.30
-0.02
-0.33
-0.18
-0.03
0.0
-0.03
-2. 14
1.80
-0.33
-0.02
-0.36

EPA
BASE
CASE
2010
16.76
is!23
0.82
19.05
2.01
-HI
0.11
2.67
18.77
20! 79
0.93
21.72
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
-7.37
6. 19
-1. 18
-0.06
-1.24
-0.78
0.71
-0.07
-0.07
-0. 14
-8.14
6.90
-1.24
-0.13
-1.38
Note:   Totals may not add due to Independent rounding.

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                                                            TABLE A-2

                                            UTILITY SULFUR DIOXIDE CONTROL COST FORECASTS
                                                        EPA BASE CASE WITH
                                                  EXISTING-NEW INTERSTATE TRADING







Utility Annual Costs
(bl 1 1 Ions or mid-1987 S/yr. )
Capl ta 1
O&M
Fuel
TOTAL
Utility Cumulative Capital Costs
(bll lions of mid-1987 5)
31-Eastern States
17-Western States
Total U.S.
S02 Retrofit Scrubber Capacity
(GW)
31-Eastern States
17-Western States
Total U.S.
New Capacity Trading with Exlstlnq
(GW)
31-Eastern States
17-Western States
Total U.S.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1995

-0.0
-0.0
-0.0
-0.0


0.0
-o.i
-0.1


0.0
0.0
0.0
Capacity

0.0
0,3
0.3
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000

-0.3
-0.3
-0.2
-0.7


-2.3
-0.8
-3.1


0.0
o.o
0.0


15.5
6.?
22. U
CHANGE
FROM
£PA BASE
EX. -NEW
•MTER.
TRADING
2010

-2.5
-2.2
-0.6
-5.3


-21.0
-H.8
-25.8


0.0
7.9
7.9


1U9.U
H7.9
197.3
Note:   Totals may not add due to Independent  rounding.

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31 EASTERN STATES
                                                           TABLE A-3

                                              UTILITY FUEL CONSUMPTION FORECASTS
                                                          (IN QUADS)
                                                        EPA BASE CASES
                                            1985

EPA
BASE
CASE
1995
CHANGE
FROM
EPA BASE
EX. -NEW
•NTER.
TRADING
1995

EPA
BASE
CASE
2000
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000

EPA
BASE
CASE
2010
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL

OIL
GAS

17 WESTERN STATES
 0.87
 1.61
 3.18
 3.86

 9753

 1.99
 1.01
   89
   56
   66
   90
11.01

 0.93
 0.92
 2.63
 2.08
 3.83
 3.80

12715

 1.51
 0.79
-0.07
 0.09
-0.01
 0.02
 0.00

 0.00
 0.0
   36
   65
   78
 1.12

1T790

 1.98
 0.71
-0.25
 0.11
-0.27
 0.10
-0.00

-0.02
 0.0
 6.81
 3.82
 1.85
 5.08

207F?

 1.79
 0.11
 1.31
 0.18
 0.21
-2.13
-0. 12

-0.09
 0.0
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS

TOTAL U.S.
 1.11
 0.13
 0.71
 0.01

 2759

 0.18
 2.58
 1.61
 0.91
 0.96
 0.07

 T758

 0.06
 2.28
 2.12
 0.85
 1.11
 0.07

 iTll

 0.21
 1.61
 0.02
 0.03
-0.01
-0.01
 0.00

 0.0
 0.0
 2.70
 0.95
 1.22
 0.06

 IT793

 0.28
 1.90
 0.06
 0.02
-0.11
 0.02
-0.01

 0.00
 0.0
 5.56
 1.55
 1.21
 O.C8

 8~7lO

 0.31
 0.99
 0.56
-0.51
-0.09
 0.00
-0.01

-0.01
 0.0
COAL
OIL
GAS
     LOW .SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
   28
   01
   92
   87
12.12

 2.17
 3.59
 3.50
 2.19
 1.62
 3.97
11758

 0.99
 3.20
 5.06
 2.93
 1.91
 3.87

16779

 1.79
 2.13
-0.05
 0.12
-0.08
 0.01
-0.01

 0.00
 0.0
 6.06
 3.60
 1.99
 1.18

18~781

 2.26
 2.61
-0.18
 0.13
-0.37
 0.12
-0.01

-0.02
 0.0
12.38
 5.37
 6.06
 5.16

28796

 2.13
 1.11
 1 .87
-0.02
 0.13
-2.13
-0.16

-0.11
 0.0

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                                                            TABLE A-U

                                             COAL PRODUCTION AND SHIPMENT  FORECASTS
                                                     (IN MILLIONS OF TONS)
                                                         EPA BASE CASES
Coal Production
 NORTHERN APPALACHIA
 CENTRAL APPALACHIA
 SOUTHERN APPALACHIA
 MIDWEST
 WEST

 TOTAL COAL REGIONS

Coal Transportation
 WESTERN COAL TO EAST
                                   I960
185.
233.
 26.
131.
251.

8307
                                   N.A.
          1985
166.
2145.
 26.
133.
316.

8817
          N.A.

EPA
BASE
CASE
1995
CHANGE
FROM
E?A BASE
EX. -NEW
INTER.
TRADING
1995

EPA
BASE
CASE
2000
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000

EPA
BASE
CASE
2010
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRAD 1 NG
2010
 180.
 282.
  23.
 125.
 «428.

10387
                                                        55.
 1.
-1.
-0.
 0.
-1.
                               -0.
                               -1.
 188.
 330.
  25.
 1U3.
 179.

lT65~7
                               70.
 11.
-12.
 -0.
 -3.
                                                                                        1.
 258.
 U07.
  36.
 175.
 777.

16537
                                                                                                183.
 28.
-11.
 -2.
-55.
 29.
                                                                        15.

-------
                                                           TABLE A-5

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    (IN THOUSANDS OF TONS)
                                                        EPA BASE CASES
    ME
    NH
    VT
    MA
    Rl
    CT
    NY
    PA
    NJ
    MD
    DE
    DC
    VA
    WV
    NC
    SC
    GA
    FL
    OH
    Ml
    IL
    IN
    Wl
    KY
    TN
    AL
    MS
    MN
    IA
    MO
    AR
    LA





19BO
17.
80.
0.
258.
5.
29.
479.
1423.
103.
222.
51.
4.
157.
984.
445.
210.
704.
692.
2185.
608.
1110.
1672.
488.
1029.
910.
535.
122.
159.
236.
1227.
27.
21.





1985
10.
71.
1.
230.
2.
56.
420.
1320.
97.
217.
63.
1.
131.
969. .
337.
162.
976.
501.
2193.
401.
1073.
1198.
367.
745.
802.
563.
113.
124.
219.
997.
69.
67.


EPA
BASE
CASE
1995
3.
64.
3.
272.
0.
17.
481.
1275.
130.
315.
60.
4.
240.
961.
504.
184.
874.
937.
2572.
449.
955.
1710.
273.
893.
856.
512.
146.
169.
302.
1058.
125.
86.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER
TRADING
1995
0.
0.
0.
0.
0.
0.
-0.
-4.
0.
0.
0.
0.
0.
0.
0.
0.
16.
-14.
-18.
0.
3.
4.
69.
-13.
-31.
-8.
-5.
-2.
3.
-6.
4.
	 3 .


EPA
BASE
CASE
2000
4.
63.
3.
299.
2.
36.
518.
1186.
127.
332.
60.
4.
293.
1007.
520.
209.
946.
968.
2677.
477.
1096.
1782.
267.
935.
922.
565.
153.
218.
368.
1118.
151.
84.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER
TRADING
2000
0.
0.
0.
152.
-0.
-1.
444.
0.
-18.
37.
10.
0.
221.
-177.
19.
28.
-111.
325.
-365.
-1.
-149.
-186.
8.
-18.
-103.
-66.
-43.
-14.
-119.
-210.
4.
	 4.


EPA
BASE
CASE
2010
5.
73.
3.
363.
0.
13.
543.
1232.
191.
344.
62.
3.
341.
1037.
660.
308.
1021.
910.
2849.
516.
1407.
2007.
327.
941.
1056.
595.
168.
216.
438.
1196.
131.
89.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER
TRADING
2010
-0.
57.
-2.
674.
-0.
-1.
1017.
-263.
559.
268.
48.
0.
7.
-481.
118.
84.
-294.
21.
-738.
514.
-425.
-908.
32.
-'109.
-260.
-168.
-24.
-59.
-203.
-426.
8.
16.
TOTAL 31-EASTERN STATES
16191.
1'»798.
                                                    16431.
-0.
17386.
                                                   -327.
19047.
                                                                                                      -1237.

-------
                                                           TABLE A-5

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    (IN THOUSANDS OF TONS)
                                                        EPA BASE CASES
    NO
    SD
    KS
    NE
    OK
    TX
    MT
    WY
    ID
    CO
    NM
    UT
    AZ
    NV
    WA
    OR
    CA
    AK

TOTAL 17-WESTERN STATES

TOTAL U.S.





158Q
79.
30.
102.
1)8.
'15.
295.
23.
128.
0.
71.
79.
25.
8'4.
38.
68.
i|.
70.
	 0_._
1189.
17380.





1985.
12«4.
32.
166.
15.
80.
«430.
22.
135.
0.
8U.
11U.
27.
10«4.
35.
85.
2.
3.
0.
1'488.
16286.


EPA
BASE
CASE
1995
177.
50.
22«4.
116.
209.
695.
145.
62.
0.
130.
56.
69.
126.
76.
111.
16.
0.
0.
2166.
18597.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER
TRADING
1995
-7.
-19.
-6.
-0.
0.
23.
0.
0.
0.
1 .
0.
-2.
7.
0.
0.
1.
0.
0.
-l».
-14.


EPA
BASE
CASE
2000
188.
51.
230.
122.
225.
710.
«48.
70.
0.
137.
56.
70.
130.
79.
128.
20.
0.
	 0_._
2263.
196U9.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER
TRADING
2000
-50.
-23.
-13.
-114.
U.
-8.
20.
26.
0.
1.
0.
-214.
21.
10.
20.
-0.
0.
0.
-30.
-357.


EPA
BASE
CASE
2010
2'4t4.
58.
232.
133.
225.
890.
6U.
68.
0.
1<45.
57.
77.
138.
78.
217.
20.
20.
	 
-------
                                                           TABLE A-6

                                              CHANGE IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION i
                                                 (Millions of Mid 1987 Dollars)
                                                        EPA BASE CASES
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1995
0.
-0.
2.
7.
-0.
1.
1.
U.
-1.
-5.
1.
3.
0.
-1.
-1.
-1.
-3.
-3.
-1.
2.
-1.
-0.
-0.
-0.
1 .
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000
1.
-62.
-1«46.
d1.
0.
-17.
-87.
12.
-17.
-16.
-153.
21.
8.
-23.
-6.
2.
-32.
-9.
-10.
1.
-3.
0.
-11.
2.
0.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRAD I NG
2010
-33.
. -308.
-337.
-10.
-183.
-116.
-186.
-58.
-170.
-1714.
-2MB.
-519.
-183.
-389.
-1'I6.
-112.
-91.
-350.
-12.
-67.
-23.
-68.
-210.
-1.
-5. .
                                    1.
                                           -537.
-4305.
I/ Includes transfer costs for emissions rights.

-------
                                                           TABLE A-6

                                              CHANGE  IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION I/
                                                 (Millions of Mid 1987 Dollars)
                                                        EPA BASE CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASH INGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.

JV  Includes transfer costs for emissions rights.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1925
1 .
-2.
-1 .
-20.
-0.
0.
0.
-1.
-0.
-0.
-1 .
-0.
-1.
-26.
-2't.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000
1 .
-10.
-9.
-73.
-214.
-7.
0.
-7.
5.
-3.
-8.
-18.
-146.
-200.
-737.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
-123.
-1147.
-68.
-1)2(4 .
-30.
11 .
0.
-17.
-15.
-90.
2U.
-6.
-103.
-985.
-5291.

-------
                                                           TABLE A-7

                                         PERCENT CHANGE IN ELECTRICITY RATES BASED ON
                                          ANNUALIZED COSTS (I.e., LEVELIZED BASIS) J./
                                                          (PERCENT)
                                                        EPA BASE CASES
MAINE/VT/WI
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1995
0.0
0.0
0.0
0.1
0.0
0.0
0.0
0.1
-0.0
-0.1
0.0
0.0
0.0
-0.0
-0.1
-0.1
-0.1
-0.0
-0.0
0.2
-0.0
-0. 1
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000
0.1
-1.0
-1.2
0.1
0.0
-0.1
-2.3
0.3
-0.5
-0.3
-1.5
0.2
0.1
-0.3
-0.1
0.0
-0.8
-0.1
-0.2
0. 1
-0.1
0.0
-0.2
0.1
0. 0
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
-2.0
-3.7
-2.0
-0.1
-2.5
-2.2
-3.7
-1.1
-14.1
-2.1
-2.3
-1.1
-2.0
-3.0
-2.3
-2.9
-2.1
-1.2
-0.2
-2.9
-1.2
-3.1
-'1.1
-0.1
-0.1
TOTAL 31-EASTERN STATES
0.0
-0.1
-2.6

-------
                                                           TABLE A-7

                                         PERCENT CHANGE IN ELECTRICITY RATES BASED ON
                                          ANNUAL I ZED COSTS (I.e., LEVEL I ZED BASIS) I/
                                                          (PERCENT)
                                                        EPA BASE CASES
                                 CHANGE    CHANGE    CHANGE
                                  FROM      FROM      FROM
                                EPA BASE  EPA BASE  EPA BASE
EX. -NEW
INTER.
TRADING
1995
0. 1
-0.0
-0. 1
-0.1
0.0
0.0
0.0
-0.0
0.0
0.0
-0.0
0.0
-0.0
0.0
-0.1
-0.0
1995 as
se Annua
ua 1 i zed
EX. -NEW
INTER.
TRADING
2000
0.1
-0.5
-O.t
-OJl
-2.7
-0.5
0.0
-0.3
0.3
-0.3
-0.2
-1 .3
-1.0
0 . 0
-o.u
-0.»4
an example)
1 ized Cost
Cost
EX. -NEW
INTER.
TRADING
2010
-2.9
-14.8
-1.9
-1.9
-3.2
0.7
0.0
-0.6
-0.8
-3.8
0.14
'- 0 . 'J
- 1 . <4
0. 0
-1.5
-2.3
:
_-|
1 --- 1
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
                                                              1982 Average
    I          1995 Base Case Annua I i zed Cost	 I
                1995 Electricity Sales              _j

-------
                                                           TABLE A-8

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                      EPA BASE CASE WITH
                                                 EX I STING-NEW  INTERSTATE TRADING
HAINE/VT/NH
MASS/CONN/RHOOE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

-------
                                                           TABLE A-8

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                      EPA BASE CASE WITH
                                               EXISTING-NEW  INTERSTATE TRADING
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANCE
FROM
EPA BASc
EX. -NEW
INTER.
1 RAD ING
1225
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
.EX. -NEW
INTER.
TRADING
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
1.5
0.2
0.0
3.14
0.0
0.0
0.0
0.0
0.0
0.0
1 . 1
0.5
1 .2
0.0
7.9
7.9

-------
                                                           TABLE A-9

                                            NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                          (GIGAWATTS)
                                                      EPA DASE CASE WITH
                                                 EX I STING-NEW INTERSTATE TRADING
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1993
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRAD 1 NG
2000
0.0
1.5
1.0
0.0
0.0
0.6
2.6
0.0
0.8
0.0
5.3
0.0
0.0
0.0
0.0
0.0
0.6
0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
1.3
11.1
11.8
0.5
9.6
6.9
8.1
0.0
11.7
5.1
11.6
12.1
11.1
10.2
0.0
5.1
0.6
16.3
0.0
3.7
0.0
0.8
3.8
0.2
1.2
TOTAL 31-EASTERN STATES
                                   0.0
                                            15.5
119.1

-------
                                                              TABLE A-9

                                           NEW CAPACITY  TRADING WITH EXISTING CAPACITY
                                                             (GIGAWATTS)
                                                         EPA BASE CASE WITH
                                                 EXISTING-NEW INTERSTATE TRADING
N. & S.  DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN  STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
1995
0.0
0.0
0.0
0.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.3
0.3
CHANGE
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2000
0.0
0.0
0.3
0.7
1.0
1.2
0.0
0.6
0.0
0.0
0.6
0.6
2.0
	 CL_Q
6.9
22. U
CHANG£
FROM
EPA BASE
EX. -NEW
INTER.
TRADING
2010
2. 1
0.2
<4.6
22.3
1.0
1.2
0.0
1.0
0.0
2. 1
3. 1
1.5
2.0
	 
-------
                                        TABLE A-10

                                  Coal Mining Employment
                                     (Thousand Workers)

                                       Chg from Base
                                        Interstate
Chg from Base
 Interstate
Chg from B&-.
 Interstate

Northern Appalachia
Pennsylvania
Ohio
Maryland
Northern West Virginia
TOTAL
Central Appalachia
Southern West Virginia
Virginia
Eastern Kentucky
Tennessee
TOTAL
Southern Appalachia
Alabama
TOTAL
TOTAL APPALACHIA
Midwest
Illinois
Indiana
Western Kentucky
TOTAL
TOTAL MIDWEST
Central West
Iowa
Missouri
Kansas
Northern Arkansas
Oklahoma
TOTAL
Gulf
Texas
Louisiana
Southern Arkansas
TOTAL
Actual
1985
22.3
9.0
0.7
12.8
44.7
23.8
13.3
29.8
_2^6
69.5
8,6
8.6
122.8

13.9
5.2
-L2
26.8
26.8

0.1
1.1
0.2
0.0
i^
2.5

2.4
0.1
P_o
2.4
Base
1995
18.0
6.2
0.5
13.5
38.2
21.8
12.2
27.3
-U*
63.6
5.8
5.8
107.7

10.1
3.0
-L.2
19.4
19.4

0.1
0.9
0.3
0.1
•0.7
2.0

2.1
0.8
P_o
2.9
Existing-New Base
1995 2000
-1-0.2 17.8
5.3
0.4
11.7
+0.2 35.2
23.6
13.2
-0.1 29.5
- 2.6
-0.1 68.8
- 5.9
5.9-
+0.1 109.9

12.8
2.1
_^ _5_1
20.5
20.5

0.1
0.6
0.2
0.1
0.6
1.7

1.9
0.7
0.0
2.6
Existing-New
2000
+1.2
+0.1
+0.8
+2.1
-0.9
-0.5
-1.1
-2.5
^1
-0.1
-0.5

-1.1
+0.3
+0.1
-0.7
-0.7

-
-
-
-
-

-
-
.
Base
" 2010
30.1
6.7
0.3
17.8
54.3
32.5
18.2
40.7
3^6
94.9
Ui
9.4
158.6

16.6
4. -2
_i^2
29.0
29.0

0.1
0.4
0.2
0.1
0.5
1.4

1.9
0.7
0.0
2.6
Existing-N'e
2010
+9.0
-1.8
+TT^
-0.9
-0.5
-1.1
-2.5
-0.6
-0.6
+2.8

-7.1
rl.2
-10.1
-10.1

-
-
-
-
-

-
-
.
20C0282

-------
                                        TABLE A-10
Rockies/Northern Plains
  Colorado
  Wyoming
  Montana
  Utah
  New Mexico
  Arizona
  North Dakota
       TOTAL

Northwest
  Washington
       TOTAL

Alaska
  Alaska
       TOTAL

TOTAL WEST

TOTAL U.S.
                                   Coal  Mining  Employment
                                     (Thousand  Workers)
                                        (continued)-

                                       Chg from Base      Chg from Base      Chg from Base
                                        Interstate         Interstate         Interstate
Actual Base Existing-New Base Existing-New Base Existing-New
1985
2.4
4.5
1.2
2.6
1.9
0.8
14.5
CLI
0.7
OJ,
0.1
20.3
169.9
. 1995
4.7
4.1
1.4
4.5
1.9 .
0.7
18.3
0,6
0.6
OJ,
0.1
24.0
151.0
1995 2000 2000
5.1
3.6 +0.2
1.6
4.8 +0.3
2.2
0.6
0.9
18.8 +0.5
- - 0.5 -
0.5
0.1
0.1
23.7 +0.5
0.1 154.2 -0.7
2010
19.0
5.5
2.4
10.4
3.5
0.7
0.9
42.4
0.5
0.5
0^3
0.3
47.2
234.8
2010
+4.2
-0.2
-0.1
+1.0
-0.1
-
.
+4.8
— ^—

-
+4.8
-2.5
20C0282

-------
3

-------
                                   APPENDIX B

                        PROXMIRE SUMMARY AND FORECASTS
      This  appendix presents and  discusses  the results of  the  analyses of  the
 Proxmire bill under various trading scenarios.   This  includes  a discussion of
 the  changes  in  utility  sulfur  dioxide emissions,  utility  costs,  and coal
 production.   Detailed forecasts from the Proxmire analyses  are presented  at  the
 end  of the  Appendix.
06C0022
Page B-l

-------
                 S02  EMISSION REDUCTIONS UNDER THE PROXMIRE CASES
 SOz Emissions
(millions of tons)
                   25
                   20
                   15
                   10
                    1985
                                                                Base Case
1990
                                  Proxmire
                                  Intrastate
1995
2000
2005
2010
                                      Utility
                                   S02 Emissions
                                   (million tons)
      1995
    2000
                       2010
Existing
New
Total
Base Proxmire Reductions Base Proxmire
18.4 13.8 -4.6 19.2 10.3
0.2 0^2. +0.0 0.4 0.6
18.6 14.0 -4.6 19.6 10.9
Reductions Base Proxmire Reduccio;
-8.9 19.7 10.0 -9.7
+0.1 2.0 2.7 +0.6
-8.8 21.7 12.6 -9.1
06C0022
Page B-2

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                S02  EMISSION REDUCTIONS  UNDER THE  PROXMIRE  CASES
            The  Proxmire  bill requires emission reductions  in  two
            phases:

                   In  the  first phase,  S02  emissions would  be
                   reduced by approximately 4.6 million  tons
                   below Base Case  levels by  1995.

                   When   Phase   II  is   imposed,   emission
                   reductions would total about 9 million  tons
                   below 2000 Base  Case levels.

            Under  Phase  II of Proxmire,  emission reductions below
            Base Case levels increase slightly between 2000 and 2010
            (from  8.8 to 9.1 million  tons).   This occurs because
            emission  levels  from  existing  non-NSPS  sources   are
            capped  at a constant  level by the Proxmire reduction
            requirements,  while  Base  Case  emissions from  existing
            non-NSPS  sources are  forecast to  increase  over that
            period  (as  electricity demand growth  leads  to  higher
            utilization of  coal powerplants).

            Despite the slightly higher level of emission  reductions
            in 2010 than in 2000, total emissions under the  Proxmire
            increase  between  2000 and  2010.    This is  because
            emissions from  new powerplants are not limited by  the
            bill.  Thus,  increases  in emissions from new powerplants
            lead to a net  increase  in total emissions of 1.8 million
            tons over this  period  (as  can  be seen in the  table on
            the  opposite  page).    Note   that approximately   200
            gigawatts of new coal capacity is forecast  to  be brought
            into service during the 2000-2010 period.
06C0022
Page B-3

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                     S02 EMISSIONS BY  PLANT  TYPE  -- PROXMIRE CASES IN  2010
                    25
                    20-
                    15-
  S02  Emissions
     in 2010
(millions of  tons)
                    10-
                      5-
                              \\VsS
                                                                                     New

                                                                                     Existing
Base Case    Existing-Existing    Existing-Existing
                Intrautillty        Intrastate
                                                                         Existlng-N»w
                                                                           Intrastate
Existing-New
 Interstate
                                                               Proxmire Cases
      06C0022

      Page B-4

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             S02 EMISSIONS BY PLANT TYPE -- PROXMIRE CASES IN 2010
             Emission reductions under the Proxmire bill by 2010 are
             forecast to  total about 9 million tons.  Reductions are
             slightly greater in the intrautility trading case (about
             9.3  million  tons versus  9.1 million  tons  in  the  other
             trading cases).  This is because Base Case emissions for
             some utilities  are  forecast  to  be  lower than  their
             maximum allowable  emission levels under Proxmire,  and
             these   utilities  are  assumed  to  be  unable  or  not
             permitted to trade these "unused" emission  reductions
             to another utility.

             Allowing existing-new trades  results  in substantial
             emission shifts  between  new  and  existing  sources.
             Emissions from new sources in 2010 are 2.3  million tons
             higher  in the existing-new intrastate trading case (than
             in   the  comparable  existing-existing  trading  case),
             reflecting  about 190  gigawatts  of  new coal  capacity
             which is built  without scrubbers.   On  the other  hand,
             the  existing-new intrastate trading case  requires  2.3
             million tons  more reductions from  existing powerplants
             to compensate for the increase  in new emissions.   To
             achieve these reductions, utilities in the  existing-new
             intrastate   trading  case  are  forecast  to   build  38
             gigawatts of  retrofit  scrubbers, or about  33  gigawatts
             more retrofit scrubbers  than in the  existing-existing
             intrastate trading case. •
06C0022
Page B-5

-------
                  CHANGE IN ANNUALIZED  COSTS IN 2010 -- PROXMIRE CASES
    Change in
Annualized  Costs
   in  2010 from
Base Case Levels
(billions of 1987 $
    per year)
                         Existing-Existlng
                            Intrautllity
Existing-Existlng
   Intrastate
Existlng-New
 Intrastate
Exlsting-New
  Interstate
    06C0022
    Page B-6

-------
              CHANGE IN ANNUALIZED COSTS IN 2010 --  PROXMIRE CASES
       The  costs of  the Proxmire bill  are highly  dependent upon  the  trading
 scheme;  as  more trading flexibility is  allowed,  costs  are reduced.

       •     Allowing more  trading  on  a  geographic basis  enables
            significant cost reductions:

                   Expanding trading from  the  intrautility to
                   intrastate level  leads  to  annualized  cost
                   savings  of $0.4 billion by  2010.

                   Permitting trading on the interstate level
                   leads to  estimated further savings of $0.2-
                   0.4 billion by 2010.x

       •     Existing-new trading reduces  costs substantially:

                   Comparing  the  two  intrastate  cases  in  2010,
                   existing-new trading  is about $2.0  billion  per
                   year  less expensive than the analogous  existing-
                   existing  trading  case.

       •     The    annualized   cost   components   are    affected
            substantially by existing-new trading:

                   Capital and O&M costs in 2010  are actually
                   lower in the existing-new trading cases than
                   Base  Case  levels because of  the significant
                   savings  on  new  scrubber capital  and  O&M
                   expenditures  as many  new plants are built
                   without scrubbers.

                   On   the    other   hand,   fuel   costs   are
                   substantially higher  for the  existing-new
                   cases than for the existing-existing  cases.
                   This  occurs because  (1) more  switching  to
                   lower  sulfur  fuels   is  necessary  in  the
                   existing-new cases in order to obtain more
                   emission  reductions  from existing sources
                   to offset new plant emission increases,  and
                   (2) new  unscrubbed powerplants choose  to
                   burn   low  sulfur  fuels  as   opposed   to
                   scrubbing  high  sulfur  coals   as  some  new
                   plants do  in the  Base Case.
     :A Proxmire bill interstate existing-existing trading case was not
      examined for this analysis.  However, based on previous analyses
      conducted for EPA, annualized costs for this case are es-timated to be
      about $0.2-$0.4 billion less than the intrastate trading case.  As shown
      on the opposite page, the existing-new interstate trading is about ?0.3
      billion less costly than the comparable intrastate trading case.
06C0022
Page B-7

-------
                  CHANGES IN ANNUALIZED COSTS  OVER TIME -- PROXMIRE CASES
       Increase in
    Annualized Costs
Above Base Case Levels  9-
    (billions of  1987 $
        per year)
                                  Proxmire Cases
                                  ^^~ Ex-Ex Intrautility
                                  ~°°°~~ Ex-Ex Intrastate
                                  '""" Ex-New Intrastate
                                  ~~~ Ex-New Interstate
                           1995
2000
2005
2010
     06C0022
     Page B-8

-------
            CHANGES IN ANNUALIZED COSTS OVER TIME -- PROXMIRE CASES
             Annualized costs increase  over  time relative  to  Base
             Case  levels for  the  existing-existing trading cases.
             Between 1995 and  2000, much of the relative increase in
             cost  is  due to rising  fuel costs, as more fuel switching
             is  forecast  (because  of the  more stringent  emission
             requirements  of Phase II).  After  2000, costs  continue
             to  increase,  reflecting (1) somewhat greater  emission
             reductions being  required, and (2) greater depletion of
             lower sulfur coal reserves,  resulting in increased fuel
             price premiums.

             When  existing-new trading is permitted  under Proxmire,
             annualized costs are  much  lower  than in  comparable
             existing-existing trading cases.   This  is  particularly
             true  over  time  (e.g., by 2010) as  more  new capacity is
             built without scrubbers, thereby  taking  advantage  of
             existing-new   trading  opportunities.     Existing-new
             trading  at the intrastate level lowers annualized costs
             by  $2.0 billion  in 2010  from  levels  forecast  under
             existing-existing trading.    In  earlier  years,   the
             savings  are substantially less  (less  than  $0.1  billion
             in  1995  and only about  $0.1  billion in 2000)  because
             much  less  new coal capacity is expected to be built by
             that  time.
06C0022
Page B-9

-------
                          PRESENT VALUE OF COSTS -- PROXMIRE CASES
 Increase in the
 Present Value of
 Costs Over the
 1987-2010 Period
Above Base  Case
 Levels (billions
    of 1987 $)
                           Existing-Existing
                              Intrautllity
Existing-Existing
   Intrastate
Existing-New
 Intrastate
Existing-New
 Interstate
    06C0022
    Page B-10

-------
                    PRESENT  VALUE  OF  COSTS  --  PROXMIRE CASES
             The  change  in present  value  of costs  reflects  the
             increase  in annualized costs incurred over the forecast
             period  (i.e., through  2010)  discounted  back to  1987
             using the utilities' real discount rate.  Similar to the
             changes   in  annualized  costs,  as   the  scope   and
             flexibility of trading permitted increases,  the present
             value of costs are reduced.   For example,  expanding the
             scope  of  emissions  trading  from  intrautility  to
             intrastate or from intrastate to interstate  reduces the
             increase  in the  present value  of costs by roughly  20
             percent each.

             Existing-new  trading  also  significantly  reduces  the
             present   value   of   costs  associated  with   reducing
             emissions under Proxmire.  At the intrastate level, the
             present value of costs  with existing-new  trading  is
             about $10 billion,  or about  35  percent less  than the
             present value  of  costs under the equivalent  existing-
             existing  trading  scheme.    While  this  represents  a
             substantial net  cost savings,  it is  less  significant
             than the annualized  cost  savings realized in 2010  (about
             70 percent  lower costs  than  in the existing-existing
             trading case).  This is because  costs are  only somewhat
             lower in earlier forecast years  (i.e., 10  percent lower
             in 2000 and effectively equal  in 1995),  as  much less new
             coal capacity has been built  to engage  in existing-new
             trades by that time.    As  noted earlier,  changes  in
             annualized  costs  in the  earlier  years  have a greater
             impact on the changes in the present value  of  costs.
06C0022
Page B-ll

-------
              CHANGES  IN CUMULATIVE  CAPITAL  COSTS AND SCRUBBER CAPACITY
                                  UNDER THE PROXMIRE CASES
     Change in
Cumulative Capital
    Costs from
Base Case Levels
      by 2010
(billions of 1987 $)
                                 9.7
                                                 7.8
                                                               -8.9
                                                                             £ •'"irooT mnmml

                                                                              -11.2
                           Existing-Existing
                              Intrautilily
Exis ting-Existing
   Intrastate
Exlstlng-New
 Intrastate
Exlstlng-New
 Interstate
    Change in
Scrubber Capacity
 from Base Case
  Levels in 2010
    (gigawatts)
                                  Retrofit

                                  New
                                                                  -188
                                                                                   -197
                           Existing-Existing
                             Intrautility
Existing-Existing
   Intrastate
 Existlng-Nev
  Intrastate
  Existing-New
   Interstate
06C0022
Page B-12

-------
           CHANGES IN CUMULATIVE CAPITAL COSTS AND SCRUBBER CAPACITY
                            UNDER THE PROXMIRE CASES
             Increases  in  cumulative  capital  costs  under the  two
             existing-existing trading cases range from  $8  billion
             to  $10  billion by 2010.   This range in costs is  due to
             the difference  in retrofit  scrubber  capacity.    More
             retrofit  scrubbers  are  built  under the  intrautility
             trading case  than in the  intrastate case because there
             is  less flexibility  in  meeting the emission  require-
             ments.  Thus,  capital costs  are higher.   In addition,
             in  both cases, much  of  the increase in  capital costs
             relative  to  the  Base  Case  occurs because  utilities
             choose  to   scrub  more  high  sulfur   coals  at  new
             powerplants.   Although this  strategy leads  to  higher
             capital and O&M  costs,  it enables utilities to  take
             advantage   of   inexpensive  high   sulfur  coals   which
             experisnce greatly lowered levels of demand (and,  hence,
             lower prices) under Proxmire,  and to avoid lower  sulfur
             coals which experience price  increases.

             Existing-new  trading lowers  cumulative  capital  costs
             substantially.   By 2010,  the cumulative  capital costs
             for the existing-new intrastate   trading  case   are  $9
             billion less than Base Case  levels,  and $17 billion less
             than  the  existing-existing  intrastate  trading  case.
             This  reflects  sizable capital  savings  on avoided  new
             scrubber  capacity.    While  much  less   new scrubbed
             capacity is forecast in the existing-new trading  cases,
             somewhat more  retrofit  scrubber capacity is  forecast.
             This occurs because (as discussed on the  next page)  the
             cost  per  ton  removed of  retrofit  scrubbing  at  some
             existing units  is lower than the  incremental cost  of
             scrubbing a new powerplant  (versus using a  low  sulfur
             coal without scrubbing.)
OoC.0022
Page B-13

-------
                       VALUE OF  EXISTING-NEW TRADES FOR PROXMIRE  CASES
                                     Representative Costs of Emission
                                            Reduction Alternatives
Annualized  Costs
 (1987 mills/kwh)
                               New Coal Powerplant
         Total Annual Costs       40.6
         (mills/kwh)

         Incremental Costs
         (mills/kwh)

         Emission Rate           1.0
         (Ibs. S02/mm Btu)

         Reduction in Emission     -
         Rate (Ibs. S02/mm Btu)

         $ Per Ton S02 Removed  -
43.4


2.8


0.6


0.4


1400
                 Existing Coal Powerplant
17.3         22.7          26.3


             5.4           9.0


5.0           1.0           0.5


             4.0           4.5


             270           400
       06C0022
       Page B-14

-------
                VALUE OF EXISTING-NEW TRADES FOR PROXMIRE CASES
            Allowing  existing-new emissions  trading  in meeting the
            Proxmire  reduction requirements results in much  lower
            costs  than is forecast under a more restrictive trading
            scheme which  limits  trades  among  existing  sources.
            These  lower  costs  result  from utilities  building  new
            powerplants   without  scrubbers  and  offsetting   the
            emission   increases   through   more    cost-effective
            reductions at existing sources.

            In  most  instances, the incremental costs  of  scrubbing
            a  new coal  powerplant unit  (relative  to  burning  low
            sulfur coal  unscrubbed at a new plant)  is more costly
            (on a cost  per  ton  removed  basis)   than   reducing
            emissions at existing units.  For instance, an existing
            unscrubbed unit can  shift to lower  sulfur coals  and
            reduce emissions at a .cost of $100-400 per ton removed
            or  can add a scrubber at a  cost  of  $300-600 per  ton
            removed.     By   comparison,  reductions   obtained  by
            scrubbing  a  new  powerplant unit  (versus  burning  low
            sulfur coal unscrubbed at  the new plant) can  cost  over
            $1000.per ton.  Reductions at new scrubbed powerplants
            are  more  expensive  because  scrubbed  new powerplants
            generally  have  slightly   lower  emissions   than   new
            unscrubbed low  sulfur  plants,  but  have significantly
            higher costs.   In  contrast,  many  more reductions  are
            achieved at a comparable or lower cost when an existing
            high   sulfur  plant  switches  to  low  sulfur  coal or
            retrofits a scrubber.   As  a result of these underlying
            economics, nearly 200 gigawatts of new  coal capacity is
            forecast  to be  built without  scrubbers by 2010 in  the
            existing-new Proxmire  cases.
06C0022
Page B-15

-------
                      REGIONAL COAL  PRODUCTION IN 2010  FOR PROXMIRE CASES
                       2100
                       1800
                       1500-
   Regional Coal
Production in 2010   1200-
 (millions of tons)


                        900-
                       600-
                       300-
N. Appalachia
C. & S. Appalachia
Midwest
West
                                     :!:;SS*

                                  \\xv
                                  wvSXN
              X
Base Case    Exi«1ing-Exi*tlng   Exiiting-Exlsting
               Intnutllity        Intrastate
                                         Existing-N»w
                                          Intrastate
                                                                                          Existmo-New
                                                                                           Interstate
                                                                 Proxmire Cases
      06C0022
      Page B-16

-------
              REGIONAL COAL PRODUCTION IN 2010 FOR PROXMIRE CASES
             Most of the required reductions  in  the  Proxmire cases
             are achieved through switching to lower sulfur coals.
             This is because coal switching in  many instances is more
             cost-effective (in terms of incremental  cost per ton of
             emissions  removed) in meeting  the emission requirements.
             As a result,  production  from low sulfur  coal  regions
             increases  from Base Case levels in all trading variants
             of  the  Proxmire  bill.   However,  high  sulfur  coal
             producing  regions lose production to  the  low sulfur coal
             producing  regions.

             The existing-new trading cases lead to even more shifts
             in production from high  sulfur  regions to  low sulfur
             regions.  While production from high sulfur coal regions
             (the Midwest and  Northern Appalachia)   is forecast  to
             fall by about 80-90 million tons (from Base Case levels)
             in  2010   for   the existing-existing   trading  cases,
             production from these regions is estimated  to  decline
             by almost  180  million tons --or  twice  as  large a drop
             --  in the  existing-new cases.  This  occurs because (1)
             even more  fuel shifting  occurs  in  the  existing-new
             trading cases, since more emissions must be reduced from
             existing sources in order to  offset emissions increases
             at  new  unscrubbed  powerplants, and (2)  new  unscrubbed
             powerplants  burn  low sulfur  coals  (as  opposed  to new
             scrubbed plants burning high  sulfur  coals in  the  Base
             Case and  the  existing-existing  trading  cases).    In
             earlier forecast years, there are  much smaller regional
             coal production shifts because there are fewer existing-
             new trades.
06C0022
Page B-17

-------
                       COAL PRODUCTION OVER TIME --  PROXMIRE CASES
     Northern
   Appalachian
 Coal Production  150
(millions of tons)
                   120
                    90-


                    60


                    30
                                 Base Case
                                 Proxmire Ex-Ex Intrautility
                                 Proxmire Ex-Ex Intrastate
                                 Proxmire Ex-New Intrastate
                                 Proxmire Ex-New Interstate
                     1980
1985
1990
1995
2000
2005
                                                                                    2010
                   200-r

                   180-

                   160-

                   140-

                   120i
   Midwestern
Coal Production  100
(millions of tons)
                    80

                    60

                    40-

                    20J
                    0-
                    1980
 Base Case
 Proxmire Ex-Ex Intrautility
 Proxmire Ex-Ex Intrastate
 Proxmire Ex-New Intrastate
 Proxmire Ex-New Interstate
1985
1990
1995
2000
2005
2010
   06C0022
   Page B-18

-------
                  COAL PRODUCTION OVER TIME -- PROXMIRE CASES
             Coal  production  in  the high  sulfur  coal  producing
             regions   (the   Midwest   and   Northern   Appalachia)   is
             forecast  to experience  substantial declines  from  Base
             Case   levels   under   the Proxmire  bill.     By   1995,
             production  in  these two regions is forecast to be about
             50  million  tons less  than levels  suggested by the  Base
             Case,  and about 110  million  tons less than  Base  Case
             levels by 2000, with the declines from  Base Case  levels
             split  roughly  equally between  these  two regions.   By
             2010,  the  Midwest  is   forecast  to   experience  more
             significant declines than Northern Appalachia under the
             Proxmire  bill.  This occurs  because  there is still  a
             sizable market for medium sulfur coals (which  can  be
             mined  in  Northern Appalachia), while  demand for  high
             sulfur  coals  (which  are predominant  in the Midwest)
             decreases, significantly.

             The Proxmire existing-new trading cases  result in  even
             further reductions in high sulfur coal production  from
             the  Midwest and  Northern Appalachia  by  2010.    This
             effect is more  pronounced in Northern Appalachia because
             (1)  utilities  in  the  East  build  unscmbbed  new
             powerplants  under  existing-new  trading  (instead  of
             scrubbed higher sulfur coal plants) and use low  sulfur
             coals  at  these new  unscrubbed  plants  in  order  to
             minimize the number of existing-new emission trades, and
             (2) existing powerplants shift more from high and  medium
             sulfur coals  to low  sulfur  coals in  order to  offset
             emission increases from unscrubbed new powerplants.
06C0022
Page B-19

-------
                                                           TABLE 3-1A

                                                    SULFUR DIOXIDE FORECASTS
                                                   PROXMIRE CASES VS.  EPA BASE
UtiI Ity S02 Emissions
  (mill Ions or tons)
   31-Eastern States
       Coal
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 31-EASTERN STATES

   17-Western States
       Coal
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 17-WESTERN STATES

   United States
       Coal
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL UNITED STATES

1960
114.92
0.00
114.92
1.27
16. 19
1.10
0.00
1. 10
0.09
1.19
16.02
0.00
16.02
1.36
17.38

1985
114.21
0.00
11*. 21
0.57
114.78
1.148
0.00
1.148
0.01
1.149
15.69
0.00
15.69
0.58
16.27

EPA
BASE
CASE
1995
15.26
15.41
1.02
16.143
2.00
2! 05
0.12
2.17
17.26
0.20
17! «46
^e.60
CHANGE
FROM
EPA BASE
PROXH 1 RE
INTRA-
UTILITY
1995
-14.66
0.01
-14.65
-0.3U
-14.99
-0.01
0.00
-0.01
0.0
-0;01
->».66
0.01 '
-14.66
-0.3M
-5.00
CHANGE
FROM
EPA BASE
PROXMIRE
IN- STATE
EX-EX
1995
-14.53
-I4i52
-*g
-0.01
0.00
-0.01
0.0
-0.01
-14.514
0.01
-14.53
-0.02
-14.55
CHANGE
FROM
EPA BASE
PROXMIRE
IN- STATE
EX-NEW
1995
-14.53
0.01
-«4.52
-0.03
-14.55
-0.014
0.02
-0.01
0.0
-0.01
-14.57
0.03
-14.53
-0.03
-14.56
CHANGE
FROM
EPA BASE
PROXMIRL
INTER.
EX-NEW
1995
-14.55
0.01
-14.514
-0.00
-14.514
-0.03
0.02
-0.01
0.0
-0.01
-14.58
-*»
-0.00
-14.55
Note:   Totals may not add due to Independent rounding.

-------
                                                           TABLE B-1B

                                                    SULFUR DIOXIDE FORECASTS
                                                   PROXMIRE CASES VS. EPA BASE
  11 II t.v S02 Emissions
  (mill Ions or tons)
   31-Eastern States
       Cos I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 31-EASTERN STATES

   17-Western States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 17-WESTERN STATES

   United States
       Coal
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL UNITED STATES
                                   I960
1. 19

1985
1i».21
0.00
114.21
1l4!78
1.148
0.00
1.H8
0.01
1 .»49
15.69
0.00
15.69
0.58
16.27

EPA
BASE
CASE
2000
15.85
16!20
17^39
2.05
0.09
2.13
0. 13
2.26
17.90
0.«43
18.33
1 .32
19.65
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
-8.56
0.09
-8.147
-9.014
0.01
0.03
0.014
0.0
0.014
-8.5«4
-8. 'l43
-9! oo
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2000
iii i
OOOODOOO
~j jru> O £•
vou>-jKo o\
0.01
0.03
0.0*4
0.0
0.04
-8.1(5
0.12
-8.33
-0.143
-8.75
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
-8.7«4
0.52
-8.22
-0.58
-8.79
-O.H4
o.i?
0.05
oToTi
-8.88
0.72
-8.17
-a!75
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
2000
-8.76
0.56
-8.20
-0.60
-8.80
-0.18
0.2M
0.06
oTou
-8.9'4
-e!i3
-0.62
-8. 76
Note:   Totals may not add due to independent rounding.

-------
                                                           TABLE B-1C

                                                    SULFUR DIOXIDE FORECASTS
                                                   PROXMIRE CASES VS. EPA BASE
                                                                CHANGE    CHANGE
                                                                 FROM      FROM
                                                               EPA BASE  EPA BASE
 CHANGE    CHANGE
  FROM      FROM
EPA BASE  EPA BASE
Utl I I t.v S02 Emissions
  (mill ions or tons)
   31-Eastern States
       Coal
         EX IST ING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 31-EASTERN STATES

   17-Western States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 17-WESTERN STATES

   United States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL UNITED STATES
1980
H4.92
0.00
11.92
ie! 19
1.10
0.00
1.10
0.09
1. 19
16.02
0.00
16.02
17^38
1985
14.21
0.00
14.21
0.57
11.78
1.148
0.00
1.48
Tt^9
15.69
0.00
15.69
ie!27
EPA
BASE
CASE
2010
16.76
1.47
18.23
0.82
19.05
2.01
0.55
2.56
2767
18.77
20! 79
0.93
21.72
PROXMIRE
INTRA-
UTILITY
2010
-9.66
0.62
-9.04
-0.29
-9.33
0.00
0.00
0.00
0.00
0.00
-9.66
0.63
-9.04
-0.29
-9.32
PROXMIRE
IN-STATE
EX-EX
2010
-9.63
0.61
-9.02
-0.09
-9.11
0.00
0.03
0.03
0.0
0.03
-9.63
0.64
-8.99
-0.09
-9.09
PROXMIRE
IN-STATE
EX-NEW
2010
-10.88
2.20
-8.68
-0.44
-9.11
-0.76
0.81
0.05
-0.04
0.01
-"11.64
3.01
-8.63
-0.48
-9.10
PROXMIRE
INTER.
EX-NEW
2010
-•i0.87
-e'.ei
-0.44
-9.11
-0.79
0.89
0.10
-0.07
0.03
-11.70
3.08
-8.57
-0.52
-9.09
Note:   Totals may not add due to independent  rounding.

-------
                                                         TABLE B-2-A

                                            UTILITY SULFUR DIOXIDE CONTROL COST FORECASTS
                                                       PROXHIRE CASES
Utility Annual Costs
 (billions of mid-1987 $/yr.)
   Cap ItaI
   O&M
   Fuel
     Total

Utility Cumulative Cap ItaI  Costs
 (billions of m!d-1987~5)
   31-Eastern States
   17-Western States
     Total U.S.

Average Cost Per Ton S02 Removed

S02 Retrofit Scrubber Capacity
 (GW)
   31-Eastern States
   17-Western States
     Total U.S.
New Capacity Trading with Existing Capacity
 (GW)
   31-Eastern States
   17-Western States
     Total  U.S.
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
1993
0.1
0. 1
o'.s
1.2
o.o
1 .2
15-
0.8
~ote
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
EX-EX
IN- STATE
1995
0.1
0.1
~07T|
0.8
0.0
0.9
98
0.1
0.0
0. 1
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
EX- NEW
IN-STATE
1995
1
0.1
0.1
O.'l4
0.9
0.9
96
0.0
0.0
0.0
0.0
0.3
CHANGE
FROM
EPA BASE
PROX.
EX-NEW
INTER.
1993
0.1
0.1
~074
0.9
lO+l
0.8
87
0.0
0.0
0.0
0.0
0.3
0.3
Note:   Totals may not add due to independent  rounding.

-------
                                                         TABLE B-2-B

                                            UTILITY SULFUR DIOXIDE CONTROL COST FORECASTS
                                                       PROXMIRE CASES
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
2000
Utility Annual Costs
(billions of mid-1987 S/yr. )
Cap! ta 1
O&M
Fuel
Total
Utility Cumulative Capital Costs
(bill Ions or mid-1987 $)
31-Eastern States
17-Western States
Total U.S.
Average Cost Per Ton S02 Removed
S02 Retrofit Scrubber Capacity
(CW)
31-Eastern States
17-Western States
Total U.S.
New Capacity Trading with Existing Capacity
(GW)
31-Eastern States
17-Western States
Total U.S.
0.5
0.1
2.3
5.8
"379
253
7.9
7.'9
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
EX- EX
IN-STATE
2000
0.3
0.3
• 1.2
1.9
1.0
0.1
1.1
212
1.2
0.0
0.0
0.0
0.0
CHANGE ,
FROM
EPA BASE
PROX.
EX-NEW
IN-STATE
2000
0.2
0.1
_LJt
1.7
2.7
2.3
195
7.5
0.6
8.3
15.5
6.0
21.5
CHANGE
FROM
EPA BASE
PROX.
EX- NEW
INTER.
2000
0.1
0.1
l'.5
2.1
-0.8
1.6
171
6.1
0.0
6.1
15.5
22 !l
Note:   Totals may not add due to independent  rounding.

-------
                                                         TABLE B-2-C

                                            UTILITY SULFUR DIOXIDE CONTROL COST  FORECASTS
                                                       PROXMIRE CASES
Utility Annual Costs
 (billions of mid-1987 $/yr.)
   Cap I ta I
   O&M
   Fuel
     Tota I

klLLi ty Cumulative Cap!taI  Costs
 (bl ilions of mid-1987~$)
   31-Eastern States
   17-Western States
     Total U.S.

Average Cost Per Ton S02 Removed

S02 Retrofit Scrubber Capacity
 (CW)
   31-Eastern States
   17-Western States
     Total U.S.
New Capacity Trading wi th _E_xj_s t in
-------
                                                          TABLE B-3A

                                              UTILITY FUEL CONSUMPTION  FORECASTS
                                                          ( IN QUADS)
                                                  PROXMIRE CASES VS. EPA BASE
31 EASTERN STATES

COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL

OIL
GAS

17 WESTERN STATES
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS

TOTAL U.S.
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOIAL
OIL
GAS
                                  1980
 0.87
 1.61
 3.18
 3.86

 9753

 1.99
 1.01
 1.11
 0.13
 0.71
 0.01

 2759

 0.18
 2.58
 2.28
 2.01
 3.92
 3.87

12.12

 2.17
 3.59
           1985
   89
   56
   66
   90
11.01

 0.93
 0.92
 1.61
 0.91
 0.96
 0.07
 3.58

 0.06
 2.28
   50
   19
   62
   97
11.58

 0.99
 3.20

EPA
BASE
CASE
1995
2.63
2.08
3.83
3.80
127114
1.51
0.79
2.12
0.85
1.11
0.07
1711
0.21
1.61
5.06
2.93
1.91
3.87
16.79
1.79
2.13
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
1995
1.26
0.68
-0.55
-1.37 -
0.02
0.00
0.0
-0.01
0.03
0.00
0.01
0.00
0.0
0.0
1.21
0.70
-0.51
-1.35
0.02
0.00
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
IN- STATE
EX- EX
1995
1.21
0.62
-0.58
-1.25
0.01
0.00
0.0
-0.07
0.06
0.00
0.01
0.00
0.0
0.0
1.13
0.68
-0.57
-1.23
0.01
0.00
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- NEW
1995
1.22
0.60
-0.51
-1.28
0.00
0.00
0.0
-0.08
0.08
-0.01
0.01
-0.00
0.00
0.0
1.11
0.67
-0.51
-1.26
-0.00
0.00
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
1995
1.17
0.76
-0.77
-1.15
0.00
0.0
0.0
-0.10
0.10
-0.02
0.01
-0.00
0.0
0.0
1.07
0.86
-0.79
-1.13
0.00
0.0
0.0

-------
                                                           TABLE  B-3B

                                               UTILITY  FUEL CONSUMPTION FORECASTS
                                                           (IN  QUADS)
                                                   PROXMIRE CASES VS.  EPA BASE
31 EASTERN STATES

COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL

OIL
GAS

17 WESTERN STATES
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
01 L
GAS

TOTAL U.S.
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULIUR
     HIGH SULFUR

     TOTAL
OIL
GAS
                                   1980
 0.87
 1.61
 3. 18
 3.86

 9753

 1.99
 1.01
 1.11
 0.13
 0.74
 0.01

 2759

 0.18
 2.58
 2.28
 2.0'4
 3.92
 3.87

127T2

 2.17
 3.59
           1985
 1.89
 1.56
 3.66
 3.90

lT7bT

 0.93
 0.92
 1.61
 0.91
 0.96
 0.07
 3.58

 0.06
 2.28
 3.50
 2.19
 1.62
 3.97

11758

 0.99
 3.20

EPA
BASE
CASE
2000
3.36
2.65
3.78
1. 12
13.90
1 .98
0.71
2.70
0.95
1.22
0.06
1.93
0.28
1.90
6.06
3.60
1.99
1. 18
18.81
2.26
2.61
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
3.62
0.37
-1.89
-2.08
0.02
0.03
0.0
-0.31
0.37
-0.05
0.02
0.00
0.00
0.0
3.28
0.71
-1.91
-2.06
0.02
0.03
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2000
1.02
0.11
-1.92
-2. 18
0.03
0.01
0.0
-0.38
0.13
-0.06
. 0.02
0.00
0.00
0.0
3.63
0.51
-1.98
-2.16
0.03
0.01
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
1.31
0.03
-2.04
-2.28
0.03
-0.01
0.0
-0. 19
0.26
-0.09
0.02
-0.01
-0.00
0.0
1. 12
0.29
-2.12
-2.26
0.02
-0.01
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
2000
1.31
-0.06
-1.93
-2.29
0.03
-0.01
0.0
-0.37
0.19
-0.15
0.02
-0.01
-0.00
0.0
3.91
0.13
-2.08
-2.27
0.02
-0.01
0.0

-------
                                                           TABLE B-3C

                                               UTILITY FUEL CONSUMPTION FORECASTS
                                                           (IN QUADS)
                                                   PROXMIRE CASES VS. EPA BASE
31 EASTERN STATES

COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
   '  HIGH SULFUR

     TOTAL

OIL
GAS

17 WESTERN STATES
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS

TOTAL U.S.
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS
 0.87
 1.61
 3.18
 3.86

 9753

 1.99
 1.01
 1.41
 O.'l3
 0.71
 0.01

 2759

 0.148
 2.58
 2.28
 2.0'l
 3.92
 3.. 87

12. 12

 2.47
 3.59
                                             1985
 1.89
 1.56
 3.66
 3.90

iTToT

 0.93
 0.92
 1.61
 0.94
 0.96
 0.07
 3.58

 0.06
 2.28
 3.50
 2.49
 t|.62
 3.97
14.58

 0.99
 3.20

EPA
BASE
CASE
2010
6.81
3.82
4.85
5.08
20.57
1.79
0.44
5.56
1.55
1.21
0.08
8.40
0.34
0.99
12.38
5.37
6.06
5.16
28.96
2.13
1.14
CHANGE
FROM
EPA BASE
PROXM 1 RE
INTRA-
UTILITY
2010
0.79
2.07
-1;23
-1.60
0704
0.03
0.0
-0.17
0.09
0.08
0.0
0.00
0.00
0.0
0.62
2.17
-1.15
-1.60
oTou
0.03
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2010
1.33
1.78
-1.26
-1,80
0.04
0.01
. 0.0
-0.32
0.24
0.08
0.0
0.00
0.00
0.0
1.02
2.01
-1.18
-1.80
0.05
0.01
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
IN- STATE
EX-NEW
2010
6.00
-0.51
-2.42
-3.06
0.01
-0.05
0.0
0.22
-0.15
-0.10
0.00
-0.03
-0.01
0.0
6.21
-0.66
-2.52
-3.06
-0.02
-0.07
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
2010
6.48
-0.91
-2.63
-2.94
0.00
-0.06
0.0
0.24
-0.24
-0.04
-0.00
-0.04
-0.01
0.0
6.71
-1.14
-2.67
-2.94
-0704
-0.07
0.0

-------
                                                           TABLE B-4A

                                             COAL PRODUCTION AND SHIPMENT  FORECASTS
                                                     i  IN MILLIONS OF TONS)
                                                   PROXMIRE CASES VS. EPA  BASE
CoaI  Product Ion
 NORTHERN APPALACHIA
 CENTRAL APPALACHIA
 SOUTHERN APPALACHIA
 MIDWEST
 WEST

 TOTAL COAL REGIONS

Coal  Transportation
 WESTERN COAL TO EAST
                                   1980
185.
233.
 26.
13<4.
251.

8307
                                   N.A.
          1985
166.
245.
 26.
133.
316.

88TT
          N.A.

EPA
BASE
CASE
1995
180.
282.
23.
125.
1428.
1038.
55.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTiLITY
1995
-2«4.
•40.
1 .
-28.
7.
-1 .
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
1995
-25.
39.
1 .
-23.
5.
-3.
-2.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
1995
-25.
39.
1.
-2«4.
5.
~=1T
-2.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
1995
-22.
26.
1 .
-19.
11.
-3.
5.

-------
                                                           TABLE B-1B

                                             COAL PRODUCTION AND SHIPMENT FORECASTS
                                                     (IN MILLIONS OF TONS)
                                                   PROXMIRE CASES VS. EPA BASE
Coal Production
 NORTHERN APPALACHIA
 CENTRAL APPALACHIA
 SOUTHERN APPALACHIA
 MIDWEST
 WEST

 TOTAL COAL REGIONS

Coal Transportation
 WESTERN COAL TO EAST
830.
                                   N.A.
                                             1985
166.
2U5.
 26.
133.
316.

8817
                                             N.A.

EPA
BASE
CASE
2000
188.
330.
25.
113.
179.
1165.
70.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
-56.
58.
2.
-55.
15.
29.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2000
-50.
52.
2.
-58.
51.
34.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
-55.
51.
2.
-58.
51.
~^T
38.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
2000
-51.
50.
2.
-56.
51.
~=57
36.

-------
                                                            TABLE  B-1C

                                             COAL  PRODUCTION AND  SHIPMENT  FORECASTS
                                                      (IN MILLIONS OF TONS)
                                                    PROXMIRE CASES VS.  EPA  BASE
CoaI  Product Ion
 NORTHERN APPALACHIA
 CENTRAL APPALACHIA
 SOUTHERN APPALACHIA
 MIDWEST
 WEST

 TOTAL COAL REGIONS

Coa^]_Transportat Ion
 WESTERN COAL TO EAST
                                   1980
185.
233.
 26.
13t.
251.

83~67
                                   N.A.
                                              1985
166.
2U5.
 26.
133.
316.

8817
          N.A.

EPA
BASE
CASE
2010
258.
1407.
36.
175.
777.
1653.
183.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UT i L I TY
2010
-28.
17.
-5.
-U8.
72.
7.
U9.
CHANCE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2010
-26.
21.
-6.
-63.
80.
7.
59.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2010
-91.
13.
-7.
-85.
152.
11.
128.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
2010
-92.
38.
-10.
-81.
156.
11 .
132.

-------
                                                          TABLE B-5A

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    ( IN THOUSANDS OF TONS)
                                                  PROXHIRE CASES VS. EPA BASE
    ME
    Nil
    VT
    MA
    Rl
    CT
    NY
    PA
    NJ
    MD
    DE
    DC
    VA
    WV
    NC
    SC
    CA
    FL
    Oil
    Ml
    IL
    IN
    Wl
    KY
    TN
    AL
    MS
    MN
    IA
    MO
    AR
    LA





1980
17.
80.
0.
258.
5.
29.
i|79.
1122.
103.
222.
51.
it.
157.
9814.
115.
210.
70i» .
692.
2185.
608.
1110.
1672.
188.
1029.
910.
535.
122.
159.
236.
1227.
27.
21.





1985
10.
71.
1.
230.
2.
56.
<420.
1320.
97.
217.
63.
1.
131.
969.
337.
162.
976.
501.
2193.
'101.
1073.
1198.
367.
715.
802.
563.
113.
121.
219.
997.
69.
67.


EPA
BASE
CASE
1995
3.
61.
3.
272.
0.
17.
•481.
1275.
130.
315.
60.
14.
2140.
961.
501.
18(4.
871.
937.
2572.
119.
955.
1710.
273.
893.
856.
512.
116.
169.
302.
1058.
125.
86.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
1995
0.
-8.
-3.
-31.
0.
-2.
-125.
-196.
-29.
-98.
-1.
0.
-93.
-212.
-28.
21.
-275.
-266.
-1l4i«5.
-13.
-111.
-795.
58.
-339.
-3U9.
-1.
-3»4.
-1.
-57.
-518.
-10.
Q.
CHANGE
FROM
EPA BASE
PROXMIRE
IN- STATE
EX- EX
1995
0.
-9.
-2.
-11.
0.
1.
0.
-170.
-27.
-96.
1.
0.
-98.
-201.
-30.
25.
-271.
-150.
-1117.
-0.
-135.
-797.
69.
-283.
-350.
6.
-5.
2.
-56.
-198.
-11 .
	 0.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
1995
-0.
-9.
-2.
-11.
0.
1.
0.
-170.
-27.
-96.
1.
.0.
-98.
-201.
-30.
25.
-271.
-150.
-1117.
-0.
-135.
-797.
69.
-283.
-350.
6.
-5.
2.
-56.
-198.
-11 .
-Q.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
1995
0.
-20.
0.
0.
0.
0.
-13.
-71.
-17.
-23.
0.
0.
-100.
-333.
-29.
-18.
-228.
-211.
-1233.
-16.
-205.
-638.
-13.
-212.
-139.
-121.
-82.
-18.
-171.
-215.
3.
3.
TOTAL 31-EASTERN STATES
16191.
11798.
16131.
-1992.
-1515.
-1517.
-1515.

-------
                                                          TABLE  B-5A

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    (IN THOUSANDS OF TONS)
                                                  PROXMIRE CASES VS.  EPA BASE
    ND
    SO
    KS
    NE
    OK
    TX
   , MT
    WY
    ID
    CO
    NM
    UT
    AZ
    NV
    WA
    OR
    CA
    AK

TOTAL 17-WESTERN STATES

TOTAL U.S.






1980
79.
30.
102.
U8.
'45.
295.
23.
128.
0.
71.
79.
25.
B'l.
38.
68.
'1.
70.
0.
1 189.
17380.






1985
1214.
32.
166.
i45.
80.
«430.
22.
135.
0.
814.
111.
27.
^Q^.
35.
85.
2.
3.
0.
T488.
16286.



EPA
BASE
CASE
1995
177.
50.
221.
116.
209.
695.
145.
62.
0.
130.
56.
69.
126.
76.
11'i.
16.
0.
0.
2166.
18597.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
1995
0.
0.
-1.
-2.
0.
-14.
0.
0.
0.
-1 .
0.
0.
0.
0.
0.
0.
0.
0.
-8.
-5000.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
1995
0.
0.
0.
-2.
0.
->4.
0.
0.
0.
-2.
0.
0.
0.
0.
0.
0.
0.
	 0_..
-7.
-M552.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
1995
-0.
0.
-0.
-2.
0.
-14.
-0.
-0.
0.
-2.
-0.
-0.
0.
0.
-5.
0.
0.
0.
-114.
-14561.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
1995
-9.
-20.
14.
-3.
0.
23.
0.
0.
0.
1.
0.
-13.
7.
0.
-2.
M.
0.
0.
-7.
-U552.

-------
                                                          TABLE B-5B

                                            TOTAL SULFUR DIOXIDE EMISSIONS  BY  STATE
                                                    (IN THOUSANDS OF  TONS)
                                                  PROXMIRE CASES VS.  EPA BASE
    ME
    Nil
    VT
    MA
    Rl
    CT
    NY
    PA
    NJ
    MO
    DE
    DC
    VA
    WV
    NC
    SC
    GA
    FL
    Oil
    Ml
    IL
    IN
    VII
    KY
    ™
    AL
    MS
    MN
    IA
    MO
    AR
    LA





1980
17.
80.
0.
258.
5.
29.
1479.
1'l22.
103.
222.
51.
1*.
157.
98<4.
I4'i5.
210.
70«4.
692.
2185.
608.
1110.
1672.
'188.
1029.
910.
535.
122.
159.
236.
1227.
27.
21.





1985
10.
7«4.
1.
230.
2.
56.
«I20.
1320.
97.
217.
63.
1 .
- 131.
969.
337.
162.
976.
501.
2193.
«»01.
1073.
1«498.
367.
7«45.
802.
563.
113.
12«4.
219.
997.
69.
67 .


EPA
BASE
CASE
2000
4.
63.
3.
299.
2.
36.
518.
1186.
127.
332.
60.
U.
293.
1007.
520.
209.
9M6.
968.
2677.
U77.
1096.
1782.
267.
935.
922.
565.
153.
218.
368.
1118.
151.
84.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
-2.
-30.
-3.
-12«1.
0.
-7.
-109.
-556.
-26.
-162.
-6.
0.
-123.
-532.
-97.
-614.
-5146.
-382.
-1993.
-68.
-562.
-1166.
-35.
-519.
-616.
-209.
-140.
-61.
-202.
-765.
-36.
0.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2000
-2.
-30.
-2.
-97.
0.
-7.
-39.
-536.
-ZH.
-165.
-H.
1.
-12«4.
-523.
-98.
-62.
-516.
-291.
-1993.
-67.
-567.
-1161.
-36.
-523.
-617.
-209.
-9.
-61.
-202.
-765.
-36.
0.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
-2.
-30.
-2.
-97.
-0.
-7.
-39.
-536.
-21.
-165.
-<4.
1.
-12U.
-523.
-98.
-62.
-516.
-291.
-1993.
-67.
-567.
-1161.
-36.
-523.
-617.
-209.
-9.
-61.
-202.
-765.
-36.

CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
2000
-3.
-27.
-1.
-38.
2.
37.
it.
-523.
-51.
-1M7.
-22.
0.
-99.
-191.
-86.
-15.
-567.
-371.
-1963.
-63.
-706.
-1079.
-68.
-197.
-580.
-228.
-88.
-76.
-231.
.-787.
-20.
-5.
TOTAL 3 I-EASTERN STATES
                                16191.
11798.
17386.
                                                              -9039.
-8792.
                                        -8792.
-8796.

-------
                                                          TABLE B-5B

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    ( IN THOUSANDS OF TONS)
                                                  PROXMIRE CASES VS. EPA BASE
    SD
    KS
    NE
    OK
    TX
    MT
    WY
    ID
    CO
    NM
    UT
    AZ
    NV
    WA
    OR
    CA
    AK

TOTAL 17-WESTERN STATES

TOTAL U.S.






128Q
79.
30.
103.
18.
15.
295.
23.
128.
0.
71.
79.
25.
8U.
38.
68.
l|.
70.
0.
1189.
17380.






12S5
12«4.
32.
166.
15.
80.
130.
22.
135.
0.
81.
111.
27.
101.
35.
85.
2.
3.
	 0.
1188.
16286.



EPA
BASE
CASE
2000
188.
51.
230.
122.
225.
710.
(48.
70.
0.
137.
56.
70.
130.
79.
128.
20.
0.
0.
2263.
19619.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
0.
0.
5.
1.
1 .
6.
13.
0.
0.
0.
0.
0.
0.
0.
16.
0.
0.
0.
HI.
-8998.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2000
0.
0.
1.
-5.
5.
6.
13.
0.
0.
0.
0.
0.
0.
0.
16.
0.
0.
0.
38.
-8751.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
-0.
0.
1.
-5.
5.
6.
13.
0.
0.
0.
0.
-0.
0.
0.
16.
-0.
0.
0.
38.
-8751.
CHANGE
FROM
EPA BASE
PROXMIRF.
INTER.
EX-NEW
2000
-50.
-22.
-7.
-13.
-10.
27.
35.
30.
0.
3.
0.
-21.
21 .
0.
16.
-0.
0.
0.
38.
-8759.

-------
                                                          TABLE  B-5C

                                            TOTAL SULFUR  DIOXIDE EMISSIONS BY STATE
                                                    ( IN THOUSANDS OF TONS)
                                                  PROXHIRE CASES VS.  EPA BASE
    ME
    NH
    VT
    MA
    Rl
    CT
    NY
    PA
    NJ
    MD
    DE
    DC
    VA
    WV
    NC
    SC
    GA
    FL
    OH
    Ml
    IL
    IN
    Wl
    KY
    TN
    AL
    MS
    MN
    IA
    MO
    AR
    LA





1980
17.
80.
0.
258.
5.
29.
479.
1422.
103.
222.
51.
4.
157.
984.
415.
210.
704.
692.
2185.
608.
1110.
1672.
488.
1029.
910.
535.
122.
159.
236.
1227.
27.
21 .





1985
10.
74.
1.
230.
2.
56.
420.
1320.
97.
217.
63.
1.
131.
969.
337.
162.
976.
501.
2193.
101.
1073.
1498.
367.
745.
802.
563.
113.
124.
219.
997.
69.
67.


EPA
BASE
CASE
2010
5.
73.
3.
363.
0.
13.
543.
1232.
191.
344.
62.
3.
341.
1037.
660.
308.
1021.
910.
2849.
516.
1407.
2007.
327.
941.
1056.
595.
168.
216.
438.
1196.
131.
	 82^
CHANGE
FROM
EPA BASE
PROXHIRE
INTRA-
UTILITY
2010
0.
-24.
-2.
-78.
1.
10.
-23.
-627.
15.
-106.
-0.
0.
-115.
-569.
-171.
-108.
-526.
-267.
-1996.
-46.
-772.
-1363.
-56.
-524.
-586.
-235.
-26.
-74.
-258.
-788.
-13.
0.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2010
0.
-24.
-2.
-30.
0.
2.
43.
-605.
16.
-107.
1.
0.
-116.
-569.
-165.
-120.
-536.
-207.
-1996.
-43.
-769.
-1356.
-56.
-526.
-583.
-235.
1 .
-75.
-258.
-788.
-13.
0.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2010
0.
-24.
-2.
-30.
0.
2.
43.
-605.
16.
-107.
1.
-0.
-116.
-569.
-165.
-120.
-536.
-207.
-1996.
-43.
-769.
-1356.
-56.
-526.
-583.
-235.
1.
-75.
-258.
-788.
-13.
-0.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
F.X-NEW
2010
-3.
-21.
-2.
-23.
1.
20.
-20.
-762.
70.
-114.
-21 .
0.
-18.
-551.
-80.
-85.
-615.
-196.
-1963.
33.
-820.
-1423.
-28.
-520.
-459.
-301 .
-45.
-93.
-261.
-818.
-4.
10.
TOTAL 31-EASTERN STATES
16191.
                                          14798.
19047.
-9329.
-9114.
-9114.
                                                            -9114.

-------
                                                          TABLE B-5C

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    (IN THOUSANDS OF TONS)
                                                  PROXMIRE CASES VS. EPA BASE
    ND
    SD
    KS
    NE
    OK
    TX
    MT
    WY
    ID
    CO
    NM
    UT
    AZ
    NV
    WA
    OR
    CA
    AK

TOTAL 17-WESTERN STATES

TOTAL U.S.






1980
79.
30.
102.
'18.
'45.
295.
23.
128.
0.
71 .
79.
25.
8i|.
38.
60.
'(.
70.
0.
1189.
17380.






1985
1214.
32.
166.
45.
80.
»430.
22.
135.
0.
8«4.
11't.
27.
10M.
35.
85.
2.
3.
0.
1U88.
16286.



EPA
BASE
CASE
2010
2t4l4.
58.
232.
133.
225.
890.
6'l.
68.
0.
1145.
57.
77.
138.
78.
217.
20.
20.
0.
2668.
21716.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2010
-1.
-0.
1.
1.
2.
-3.
0.
0.
0.
0.
0.
0.
0.
0.
6.
0.
0.
	 o.
«4.
-93214.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2010
1.
0.
1 .
1.
6.
11.
0.
0.
0.
0.
0.
0.
0.
0.
6.
0.
0.
0.
28.
-9086.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2010
1 .
0.
1 .
-15.
6.
1'4.
0.
-0.
0.
0.
-0.
-0.
-0.
0.
6.
-0.
-0.
	 (L_
10.
-91014.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW
2010
9.
-2'4.
-61.
-55.
-7.
-30.
2.
19.
0.
-0.
-0.
19.
65.
2»4.
-68.
-15.
152.
0.
28.
-9087.

-------
                                                          TABLE B-6A

                                              CHANGE IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions of Mid 1987 Dollars)
                                                  PROXMIRE CASES VS. EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
1995
1|.
22.
72.
-0.
10.
15.
31.
32.
'16.
46.
81.
222.
50.
-31.
53.
-11.
15.
21.
1.
5.
-1.
-3.
11.
6.
1 _
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
1995
2.
7.
-5.
-22.
5.
37.
32.
22.
12.
12.
8.
203.
15.
-11.
31.
-15.
-1.
22.
1.
0.
-1.
-9.
22.
6.
2.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- NEW
1995
3.
7.
-1.
-18.
5.
37.
32.
23.
13.
12.
6.
201.
11.
-11.
38.
-16.
-8.
21 .
-0.
-0.
-2.
-11.
25.
9.
3 .
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW I/
1995
3.
6.
2.
-13.
1.
33.
27.
11. .
10.
27.
11.
215.
38.
-68.
18.
-30.
-8.
29.
-20.
-7.
-6.
-12.
36.
5.
	 2.
TOTAL 31-EASTERN STATES
763.
                                            132.
136.
                                                                350.

-------
                                                           TABLE B-6A

                                               CHANGE  IN ANNUALIZED UTILITY SULFUR
                                                 DIOXIDE CONTROL COSTS BY REGION
                                                  (Millions of Mid 1987 Dollars)
                                                   PROXMIRE CASES VS. EPA BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 I DAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASHINGTON/OREGON
 CALIFORNIA

 TOTAL 17-WESTERN STATES

 TOTAL U.S.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
1995
0.
-10.
1.
-5.
-2.
3.
0.
3.
-0.
2.
11.
2.
3.
0.
8.
772.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
1995
0.
-9.
2.
-3.
1.
3.
0.
5.
0.
2.
11.
2.
3.
0.
17.
M«49.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
1995
0.
-12.
-2.
-20.
-1.
3.
0.
6.
1.
2.
21.
2.
3.
0.
It.
««(40.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW I/
1995
5.
-7.
-2.
15.
-1 .
16.
0.
5.
-0.
2.
12.
2.
0.
	 Qj_
i«e.
397.
I/  Includes transfer costs for omission trades.

-------
                                                          TABLE B-6B

                                              CHANGE IN ANNUAL I ZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions or Mid 1987 Dollars)
                                                  PROXMIRE CASES VS. EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA  '
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
16.
79.
58.
173.
8.
83.
65.
111.
71.
122.
100.
507.
19.
28.
259.
19.
156.
131.
51.
-2.
-6.
21.
178.
56.
-5.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2000
12.
17.
11.
11*2.
0.
83.
63.
131.
63.
113.
36.
506.
10.
21.
203.
6.
61.
139.
36.
-5.
-13.
18.
172.
56.
-6.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
12.
11.
-51.
111.
-1 .
71.
17.
135.
17.
121.
-66.
511.
17.
27.
229.
17.
57.
118.
10.
-1.
0.
27.
181.
50.
10.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW I/
2000
12.
31.
-17.
111.
-2.
71.
26.
139.
37.
125.
-58.
517.
19.
15.
221.
12.
58.
117.
11.
-12.
1.
18.
182.
28.
	 5.
TOTAL 31-EASTERN STATES
                                 2361.
                                           1910.
1852.
1710.

-------
                                                           TABLE B-6B

                                               CHANGE IN ANNUALIZEO UTILITY SULFUR
                                                 DIOXIDE CONTROL COSTS BY REGION
                                                  (Millions or Mid 1987 Dollars)
                                                   PROXMIRE CASES VS. EPA BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASHINGTON/OREGON
 CALIFORNIA

 TOTAL 17-WESTERN STATES

 TOTAL U.S.
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UT 1 L 1 TY
3000
-0.
-36.
-11.
-21 .
-26.
-3.
0.
7.
-6.
1 .
27.
1 .
-22.
-0.
-90.
2270.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2000
0.
-HI.
-12.
-2«4.
-29.
1 .
0.
10.
-6.
2.
32.
1.
-25.
	 
-------
                                                          TABLE B-6C

                                              CHANGE  IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions or Mid 1987 Dollars)
                                                  PROXMIRE CASES VS. EPA BASE
HAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2010
9.
38.
39.
285.
31.
75.
70.
21«4.
51.
155.
112.
552.
51.
162.
128.
11.
252.
161.
103.
13.
19.
62.
231.
15.
3.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2010
7.
10.
-8.
282.
27.
70.
72.
215.
12.
151.
69.
553.
19.
156.
371.
28.
113.
163.
89.
11.
16.
57.
221.
15.
3.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2010
-3.
-81.
-159.
235.
-15.
22.
57.
230.
-98.
128.
-101.
160.
-52.
1.
390.
-19.
137.
91.
95.
-72.
-12.
55.
161.
10.
8.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW M
2010
-5.
-91.
-171.
195.
-55.
11.
36.
237.
-100.
130.
-91.
158.
-61.
22.
388.
-25.
137.
86.
78.
-78.
-12.
56.
159.
21.
	 9.
TOTAL 31-EASTERN STATES
                                 3177.
                                           2815.
1167.
1331.

-------
                                                           TABLE B-6C

                                               CHANGE  IN ANNUALIZED UTILITY SULFUR
                                                 DIOXIDE CONTROL COSTS BY REGION
                                                  (Millions or Mid 1987 Dollars)
                                                   PROXMIRE CASES VS. EPA BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASH INGTON/OREGON
 CALIFORNIA

 TOTAL 17-WESTERN STATES

 TOTAL U.S.
CHANGE
FROM
EPA BASE
PliOXMIRE
INIRA-
UTILITY
2010
5.
-5.
9.
51.
1 .
10.
0.
8.
1 .
-12.
1 .
1 .
M.
1 .
75.
3252.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2010
5.
-5.
10.
57.
1 .
10.
0.
9.
2.
-1 1.
1.
2.
14.
2.
87.
2902.
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2010
-76.
-39.
-87.
-172.
-38.
-5.
0.
-6.
-17.
-91.
(41.
-11 .
-67.
3 .
-565.
902.
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW I/
2010
-95.
-137.
-82.
-183.
-39.
-3.
0.
«4.
-21 .
-91.
50.
-13.
-92.
-33 .
-735.
598.
J7  Includes transfer costs for emission trades.

-------
                                                          TABLE B-7A

                                         PERCENT CHANGE IN ELECTRICITY RATES BASED ON
                                          ANNUAL IZED COSTS (I.e., LEVELI ZED BASIS) i/
                                                          (PERCENT)
                                                  PROXMIRE CASES VS. EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
1995
0.2
0.1
0.6
0.0
0.3
1.1
1.2
0.9
0.6
0.9
1.0
2.7
0.8
-0.3
0.9
-0.1
o.i
0.5
0.0
0.1
0.0
-0.2
1.2
0.3
0.0
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
1995
0.1
0.1
-0.0
-0.2
0.1
1.2
1. 1
0.6
0.5
0.8
0.1
2.5
0.7
-0.5
0.6
-0.5
-0.1
0.5
0.0
0.0
0.0
-0.6
0.6
0.3
0. 1
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
1995
0.1
0. 1
-0.0
-0.2
0.1
1.2
1.1
0.6
0.5
0.8
0.1
2.5
0.7
-0.5
0.7
-0.5
-0.2
0.5
-0.0
-0.0
-0.1
-0.7
0.6
0.1
'. 0. 1
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW 2/
1995
0.1
0.1
0.0
-0.1
0.1
1.2
1.0
0.1
0.1
0.1
0.2
2.7
0.6
-0.7
0.8
-1.0
-0.2
0.7
-0.1
-0.6
-0.3
-0.7
0.9
0.2
0. i
TOTAL 31-EASTERN STATES
0.6
                                             0.3
                                                       0.3
                              0.3

-------
                                                            TABLE  B-7A

                                           PERCENT CHANGE  IN ELECTRICITY  RATES  BASED ON
                                           ANNUALIZED COSTS (I.e.,  LEVELIZED BASIS) I/
                                                            (PERCENT)
                                                    PROXMIRE CASES VS.  EPA  BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOM I NR
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASHINGTON/OREGON
 CALI FORM I A

 TOTAL 17-WESTERN STATES

 TOTAL U.S.

 y  Calculated as follows:
     I  _ 1995 Base Case _______
     1           1995 Electric'ity Sales
CHANGE
FROM
EPA BASE
PROXMIRE
IN1RA-
UflLITY
1295.
0.0
-0.3
0.1
-0.0
-0.2
0.2
0.0
0.2
-0.0
0. 1
0.2
0.2
0.1
0 . 0
0.0
0.5
se Annna I
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
1995
0.0
-0.3
0. 1
-0.0
0. 1
0.2
0.0
0.3
0.0
0.1
0.2
0.1
0.1
0.0
0.0
0.3
ized Cost
ma I izcd Cost
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
1995
0.0
-0.3
-0.1
-0.1
0.0
0.3
0.0
0.3
0.1
0.1
0.5
0.1
0.1
0. 0
0.0
0.3
-"1 .
1 --- E
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW 2/
1995
0.3
-0.2
-0.1
0.1
-0. 1
1.2
0.0
0.3
0.0
0.1
0.2
0.2
0.0
0. 0
0.1
0.2
1982 Averac
lectrlclty R<
2/  Includes transfer costs for emission trades.

-------
                                                          TABLE B-7B

                                         PERCENT CHANGE IN ELECTRICITY RATES BASED ON
                                          ANNUALIZED COSTS (I.e., LEVELIZED BASIS) i/
                                                          (PERCENT)
                                                  PROXMIRE CASES VS. EPA BASE
MAINE/VT/NM
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA  .
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
0.9
1.3
0.5
1.6
0.2
2.3
1.7
3.5
0.8
2.2
1.0
5.8
0.7
0.3
«».3
0.6
3.7
3.0
0.9
-0. 1
-0.2
1. 1
1.1
2. It
-0.2
1.7
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX- EX
2000
0.6
0.8
0.1
1.3
0.0
2.3
1.6
3.1
0.7
2. 1
O.U
5.8
0.6
0.2
3.14
0.2
1.5
3.1
0.7
-0.3
-0.5
1.0
1.2
2.1
-0. 2
1.1
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
0.7
0.8
-0.1
1.3
-0.0
2.0
1.2
3.1
0.5
2.2
-0.7
5.9
0.7
0.3
3.8
0.5
1.1
3.3
0.7
-0.3
0.0
1.1
1.5
2.2
0.3
1.3
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW 2/
2000
0.7
0.5
-0.1
1.3
-0.0
2.0
0.7
3.1
0.1
2.2
-0.6
6.0
0.7
0. 1
3.7
0.1
1.1
3.3
0.8
-1.2
0.0
1.0
1.5
1.2
0.2
1.3

-------
                                                           TABLE B-7B

                                          PERCENT CHANGE  IN ELECTRICITY RATES BASED ON
                                           ANNUALIZED COSTS (i.e., LEVELIZED BASIS) J_/
                                                           (PERCENT)
                                                   PROXMIRE CASES VS. EPA BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASHINGTON/OREGON
 CALIFORNIA

 TOTAL  17-WESTERN STATES

 TOTAL U.S.

 V  Calculated as follows:
                 2000 Electricity Sales
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2000
0.0
-1 . 1
-O.'l
-0. 1
-2.9
-0.2
0.0
0.3
-0.3
0. 1
0.5
0. 1
-0.5
0.0
-0.2
1 .2
su Annua 1
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2000
0.0
-1.2
-0.5
-0.1
-3.2
0. 1
0.0
0.5
-0.3
0.2
0.6
0. 1
-0.5
0. 0
-0.2
1.0
Ized Cost
na 1 1 zed Cost
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2000
• 0.3
-1.0
-O.t
-0. 1
-It. I*
0.7
0.0
0.2
-0.2
0. 1
0.5
-1 .3
-1.6
0.0
-0.3
0.9
-~l .
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW 2/
2000
0.9
-1.1
-0.5
-0.1
-1.7
0.7
0.0
0.2
-0.2
-0.5
0.3
-1.3
-1.5
0. Q
-o.u
0.8
1982 Averac
1 	 Electricity Re
2/  Includes transfer costs for emission trades.

-------
                                                          TABLE B-7C

                                         PERCENT CHANGE IN ELECTRICITY RATES BASED ON
                                          ANNUAL I ZED COSTS (I.e., LEVEL I ZED BASIS) J./
                                                          (PERCENT)
                                                  PROXMIRE CASES VS. EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
UTILITY
2010
0.6
0.5
0.2
3.0
0.1
1.U
1.1*
5.2
0.5
2.2
1.0
it. 6
0.6
1.3
6.7
1. 1
5.9
1.9
1.9
0.5
1 . 1
2.6
n.i
0.8
0. 1
1.9
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2010
O.I)
0.1
0.0
2.9
0.1
1.3
1.U
5.2
O.I*
2.1
0.6
1.6
0.5
1.2
5.8
0.7
3.3
1.9
1.6
O.i*
0.9
2.i»
1.2
0.8
0. 1
1.7
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-MEW
2010
-0.1
-1.0
-1.0
2.1
-0.6
0.1
1.1
5.6
-0.8
1.8
-0.9
3.8
-0.6
0.0
6.1
-0.5
3.2
1.1
1.7
-3.1
-0.7
2.3
3.2
2. 1
0. 2
0.9
CHANGE
FROM
EPA BASE
PROXMIRE
INTER.
EX-NEW 2/
2010
-0.3
-1. 1
-1.0
2.0
-0.8
0.3
0.7
5.7
-0.9
1.8
-0.9
3.8
-0.7
0.2
6.0
-0.6
3.2
1.0
1.1
-3.2
-0.7
2.1
3.1
1.2
0.3
0.8

-------
                                                           TABLE B-7C

                                          PERCENT CHANGE  IN  ELECTRICITY  RATES  BASED  ON
                                           ANNUALIZED COSTS  (i.e.,  LEVELIZED BASIS)  J./
                                                           (PERCENT)
                                                   PROXMIRE  CASES VS.  EPA  BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASHINGTON/OREGON
 CALIFORNIA

 TOTAL 17-WESTERN STATES

 TOTAL U.S.

I/  Calculated as follows:
     |  	2010 Piise Case Annua	
     1           2010 Electricity Sales
CHANGE
FROM
EPA BASE
PROXMIRE
INTRA-
Ul ILITY
2010
0. 1
-0.2
0.3
0.2
0. 1
0.6
0.0
0.3
0.1
-0.5
0.0
0. 1
0.0
0.0
0. 1
1.1
ase Annua
ruia 1 1 zed
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-EX
2010
0. 1
-0.2
0.3
0.3
0.1
0.6
0.0
0.3
0. 1
-0.5
0.0
0. 1
0.1
	 (L_Q
0.1
1.2
1 Ized Cost
Cost
CHANGE
FROM
EPA BASE
PROXMIRE
IN-STATE
EX-NEW
2010
-1 .8
-1.3
-2.5
-0.8
-4.0
-0.3
0.0
-0.2
-1.0
-3.9
0.7
-0.7
-1. 1
°-Q
-0.8
O.I
-~l •
CHANGE
FROM
EPA BASE
PROXM 1 RE
INTER.
EX-NEW 2/
2010
-2.2
-1.5
-2.3
-0.8
-1.1
-0.2
0.0
0.2
-1.1
-3.9
0.8
-0.8
-1.1
— -Q.3
-1 .1
0.3
1982 Averai
1 	 Electricity Ri
2/  Includes transfer costs for omission trades.

-------
                                                          TABLE B-8-A

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                         PROXMIRE CASES
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UT 1 L 1 TY
1995
0.0
0.0
0.0
0.0
0.0
0.1
0.0
0.0
0.0
0.0
0.0
0.1
0.0
0.0
0.14
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.2
0.0
0.0
0.8
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-EX
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.1
CHANGE
FROM
EPA BASE
PROX.
IN- STATE
EX-NEW
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
. 0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX- NEW
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

-------
                                                         TABLE B-8-A

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                        PROXMIRE CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASH INGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UflLITY
1225.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.8
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-EX
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0. Q
0.0
0. 1
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
1993
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
1993
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

-------
                                                           TABLE B-8-B

                                                   RETROFIT SCRUBBER CAPACITY
                                                           (GIGAWATTS)
                                                          PROXMIRE CASES
MAINE/VT/NII
MASS/CONN/RIIODE  I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLOR IOA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA
CHANGE
FROM
EPA BASE
PROX.
INTRA-
IIT 1 L 1 TY
2000
0.0
O.'l
0.0
0.1
0.0
0.2
0.0
0.0
0.6
0.1
0.0
1 .1
0.0
0.2
1 .8
0.3
1.<4
0.1
0.1
0.0
0.0
0.0
l.'l
0.0
	 OJ)
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-EX
2000
0.0
0.3
0.0
0.1
0.0
0.0
0.0
0.0
0.3
0.0
0.0
1.0
0.0
0.5
0.3
0.0
O.ll
0.0
0.0
0.0
0.0
0.0
1.3
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
2000
0.0
0.3
0. 1
0.6
0.0
0.1
0.1
0.0
0.5
0.0
0.0
1.«»
0.2
• 0.8
0.8
0.0
O.'l
0.1
0.0
0.0
0.0
0.0
1.6
0.7
	 fl^Q
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2000
0.0
0.0
0.1
O.ll
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.0
0.2
1.8
O.t
0.1 '
O.U
0.1
0.0
0.0
0.0
0.1
1.8
0.0
0.0
TOTAL 31-EASTERN STATES
                                   7.9
tt.2
                                                       7.5
6.14

-------
                                                         TABLE B-8-B

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                        PROXMIRE CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASH INGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANCE
FROM
EPA BASE
I'ROX.
INTRA-
DTILITY
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
7.9
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX- EX
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
U.2
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.7
0.0
0.0
0. 0
0.8
8.3
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
6.U

-------
                                                          TABLE B-8-C

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                         PROXMIRE CASES
MAINE/VT/NII
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
2010
0.0
0.1
0.0
0.1
0.0
0.2
0.0
0.0
0.6
0.1
0.0
1.1
0.0
0.5
2.0
0.3
1.5
0.0
0.1
0.0
0.1
0.3
1.5
0.0
o.o
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX- EX
2010
0.0
0.3
0.0
0.1
0.0
0.0
0.0
0.0
0.1
0.0
0.0
1.0
0.0
0.5
0.3
0.0
0.1
0.0
0.0
0.0
0.0
0.3
1.3
0.0
	 0,0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
2010
0.1
0.9
0.1
2.0
1.1
1.1
2.3
0.0
3.7
0.6
0.6
•4.0
1.3
2.7
0.8
0.6
0.9
2.1
0.0
0.0
0.0
O.U
2.2
0.7
	 0,0
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2010
0.0
0.1
0.1
3.8
0.6
1.7
0.7
0.0
2.9
2.2
0.1
1.0
0.8
3.6
1.7
0.3
1.0
1.0
0.0
0.0
0.1
O.I
2.8
0.0
0.0
TOTAL 31-EASTERN STATES
8.8
1.5
                                                      28.8
                             27.9

-------
                                                         TABLE B-8-C

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                        PROXMIRE CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UIAM
ARIZONA
NEVADA
WASH INGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
8.8
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-EX
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
•4.5
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
2010
0.9
0.0
0.0
3.2
0. 1
0. 1
0.0
0.5
. 0.0
O.M
2.3
0.6
1 .2
0.0
9.3
38.1
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2010
1.3
0.2
0.0
3.7
0.0
0.0
0.0
0.6
0.0
0.0
0.0
0.0
1.8
0. 0
7.6
35.5

-------
                                                          TABLE B-9-A

                                           NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                          (GIGAWATTS)
                                                         PROXMIRE CASES
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-EX
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-- STATE
EX- NEW
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0,0
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX- NEW
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
TOTAL 31-EASTERN STATES
                                   0.0
0.0
                                                       0.0
                    0.0

-------
                                                            TABLE B-9-A

                                           NEW CAPACITY TRADING WITH  EXISTING CAPACITY
                                                             (GIGAWATTS)
                                                           PROXMIRE CASES
N. & S.  DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
1993
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-EX
1993
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
1993
0.0
0.0
0.0
0.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
• 0. 0
0.3
0.3
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX- NEW
1993
0.0
0.0
0.0
0.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.3 '
0.3
 Reflects new coal powerplants built without control  technologies to meet HSPS-Da requirements.

-------
                                                          TABLE B-9-B

                                           NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                          (GIGAWATT5)
                                                         PROXMIRE CASES
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX- EX
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX- NEW
2000
0.0
1.5
1.0
0.0
0.0
0.6
2.6
0.0
0.8
0.0
5.3
0.0
0.0
0.0
0.0
0.0
0.6
0.1
0.0
0.0
•o.o
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2000
0.0
1.5
u.o
0.0
0.0
0.6
2.6
0.0
0.8
0.0
5.3
0.0
0.0
0.0
0.0
0.0
0.6
0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
TOTAL 31-EASTERN STATES
0.0
                                             0.0
                   15.5
15.5

-------
                                                            TABLE B-9-B

                                           NEW CAPACITY  TRADING WITH EXISTING CAPACITY
                                                             (GIGAWATTS)
                                                           PROXMIRE CASES
N. & S.  DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO .
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASH INGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX- EX
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
2000
0.0
0.0
0.3
0.7
1.0
0.3
0.0
0.6
0.0
0.0
0.6
0.6
2.0
0.0
6.0
21.5
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2000
0.0
0.0
0.3
0.7
1.0
1.2
0.0
0.6
0.0
0.0
0.6
0.6
0.0
0.0
6.9
22.1
Reflects new coal powerplants built without control technologies to meet NSPS-Da  requirements.

-------
                                                          TABLE B-9-C

                                           NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                          (GIGAWATTS)
                                                         PROXMIRE CASES
MAINE/VT/NH
MASS/CONN/RIIODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-EX
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX-NEW
2010
0.7
7.7
11.8
0.5
9.5
6.9
l».1
0.0
13.0
5.1
11.6
11.9
11.1
10.2
0.0
5.1
0.6
13.5
0.0
3.7
0.0
0.8
3.8
0.2
0.6
135.5
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2010
0.7
6.U
13.0
0.5
9.6
6.9
8.t|
0.0
1U.7
5.1
11.6
11.9
11. U
10.2
0.0
5.1
0.6
16.3
0.0
3.7
0.0
0.8
3.8
0.2
0.6
1«41.5

-------
                                                         •   TABLE B-9-C

                                           NEW CAPACITY  TRADING WITH EXISTING CAPACITY
                                                             (GICAWATTS)
                                                           PROXMIRE CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IOAMO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL  17-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
PROX.
INTRA-
UTILITY
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
	 0.0
0.0
0.0
CHANGE
FROM
EPA BASE
PROX.
IN-STATE
EX- EX
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
	 
52.14
187.9
CHANGE
FROM
EPA BASE
PROX.
INTER.
EX-NEW
2010
7.8
0.2
14.6
22.1
1.0
1.3
0.0
2.3
0.0
2.1
3.1
1.5
2.l|
6.8
55.1
196.6
Reflects new coal powerplants built without control technologies to meet NSPS-Oa requirements.

-------
                                       TABLE  B-10-A

                                   Coal Mining Employment
                                     (Thousand Workers)
                                                           Proxmire Cases
                                                        Chanse From Base 1995



Northern Appalachia
Pennsylvania
Ohio
Maryland
Northern West Virginia
TOTAL
Central Appalachia
Southern West Virginia
Virginia
Eastern Kentucky
Tennessee
TOTAL
Southern Appalachia
Alabama
TOTAL
TOTAL APPALACHIA
Midwest
Illinois .
Indiana
Western Kentucky
TOTAL
TOTAL MIDWEST
Central West
Iowa
Missouri
Kansas
Northern Arkansas
Oklahoma
TOTAL
Gulf
Texas
Louisiana
Southern Arkansas
TOTAL

Actual
1985

22.3
9.0
0.7
12.8
44.7

23.8
13.3
29.8
2 . 6
69.5

8^
8.6
122.8

13.9
5.2
-LI
26.8
26.8

0.1
1.1
0.2
0.0
1.0
2.5

2.4
0.1
0^0
2.4

Base
1995

18.0
6.2
0.5
13.5
38.2

21.8
12.2
27.3
2 .4
63.6

5.8
5.8
107.7

10.1
3.0
6.2
19.4
19.4

0.1
0.9
0.3
0.1
0.7
2.0

2.1
0.8
0^0
2.9

Proxmire
Intrautilitv

-0.3
-2.6
-
-1.1
-4.1

+3.2
+1.8
+4.6
.
+9.6

+0^5
+0.5
+5.9

-1.9
-0.5
-1.3
-3.8
-3.8

-
-0.2
-
-
.
-0.2

-
-
-
.
Proxmire
In- State
Ex -Ex

-0.5
-2.6
-
-1.3
-4.4

+3.1
+1.7
+4.2
.
+9.0

+0.5
+0.5
+5.1

-1.8
-0.1
-1.3
-3.2
-3.2

-
-0.2
-
-
.
-0.2

-
-
	 ;_
-
Proxmire
In-State
Ex -New

-0.5
-2.7
-
-1.3
-4.5

+3.1
+1.7
+4.3
.
+9.1

+0.3
+0.3
+4.9

-1.8
-0.1
-1.3
-3.2
-3.2

-
-0.2
-
-
.
-0.2

-
-
	 ;_
-
Proxmi
Inter .
Ex-Ne-

-0.3
-2.1
-
-1.4
-3.8

+2.1
+1.1
+2.9
.
+6.1

+0.4
+0.4
+2.7

-1.6
-
-0.9
-2.5
-2.5

-
-0.2
•
-
.
-0.2
1
' -
-
	 ;_
-
20C0282

-------
                                        TABLE B-10-A

                                   Coal  Mining Employment
                                     (Thousand Workers)
                                        (continued)
                                                           Proxmire Cases
                                                        Change From Base 1995
Rockies/Northern Plains
  Colorado
  Wyoming
  Montana
  Utah
  New Mexico
  Arizona
  North Dakota
       TOTAL

Northwest
  Washington
       TOTAL

Alaska
  Alaska
       TOTAL

TOTAL WEST

TOTAL U.S.
                             Actual  Base
                              1985   1995
2.4
4.5
1.2
2.6
1.9
0.8
_LJ,
14.5

-------
                                       TABLE B-10-B

                                  Coal Mining Employment
                                    (Thousand Workers)
                                                           Proxmire  Cases
                                                        Change  From  Base  2000



Northern Appalachia
Pennsylvania
Ohio
Maryland
Northern West Virginia
TOTAL
Central Appalachia
Southern West Virginia
Virginia
Eastern Kentucky
Tennessee
TOTAL
Southern Appalachia
Alabama
TOTAL
TOTAL APPALACHIA
Midwest
Illinois
Indiana
Western Kentucky
TOTAL
TOTAL MIDWEST
Central West
Iowa
Missouri
Kansas
Northern Arkansas
Oklahoma
TOTAL
Gulf
Texas '
Louisiana
Southern Arkansas
TOTAL

Actual
1985

22.3
9.0
0.7
12.8
44.7

23.8
13.3
29.8
2 . 6
69.5

L£
8.6
122.8

13.9
5.2
-L2
26.8
26.8

0.1
1.1 •
0.2
0.0
1 0
2~5

2.4
0.1
0.0
2.4

Base
2QOO

17.8
5.3
0.4
1LJ.
35.2

23.6
13.2
29.5
2 . 6
68.8

5.9
5.9
109.9

12.8
2.1
5.5
20.5
20.5

0.1
0.6
0.2
0.1
0.6
1.7

1.9
0.7
0.0
2.6

Proxmire
Intrautilitv

-5.0
-2.3
-
-2.0
-9.4

+4.7
+2.5
+5.8
-
+13.0

+0.6
+0.6
+4.2

-6.7
-
-1.5
-8.3
-8.3

-
-0.1
-
-
.
-0.3

-
-
.
-
Proxmire
In-State
Ex -Ex

-4.6
-2.3
-
-1. 2
-8.3

+4.1
+2.2
+5.4
^^^^H^B
+11.7

+0.4
+0.4
+3.9

-6.9
-0.1
-1.4
-8.5
-8.5

-
-0.1
-
-
.
-0.3

-
-
.
-
Proxmire
In-State
Ex -New

-5.3
-2.3
-
-1.4
-9.0

+4.2
+2.3
+5.6
^^^^^^_
+12.1

+0.4
+0.4
+3.5

-7.0
-
-1.4
-8.4
-8.4

-
-0.2
-0.1
-
-0.1
-0.4

-
-
-
-
Proxmin
Inter.
Ex -New

-4.6
-2.4
-
-1.2
-8.2

+3.9
+2.1
+5.1
^^^^^_
+11.1

+0.6
+0.6
+3.5

-6.7
-
-1.4

-8.1
-8.1

-
-0.2
-0.1
-
-0.1
-0.4

-
-
-
-
20C0282

-------
                                       TABLE B-10-B

                                  Coal Mining Employment
                                     (Thousand Workers)
                                        (continued)
                                                           Proxmire Cases
                                                        Change From Base  2000
Rockies/Northern Plains
  Colorado
  Wyoming
  Montana
  Utah
  New Mexico
  Arizona
  North Dakota
       TOTAL

Northwest
  Washington
       TOTAL

Alaska
  Alaska
       TOTAL

TOTAL WEST

TOTAL U.S.
Actual
1985
2.4
4.5
1.2
2.6
1.9
0.8
1.1
14.5
0.7
0.7
0.1
0.1
Base
2000
5.1
3.6
1.6
4.8
2.2
0.6
0.9
18.8
0.5
0.5
0.1
0.1
Proxmire
Intrautilitv
+4
+0
+0
+0
+0


+5




.7
.2
.1
.1
.4
.
.
.5

-

.
Proxmire
In-State
Ex -Ex
+5.
+0.
+0.
+0.
+0.
-
.
+6.

-

•
2
3
1
1
5


2




Proxmire
In-State
Ex-New
+5.1
+0.7
+0.1
+0.3
+0.6
.
_
+6.8

-

.
Proxmire
Inter .
Ex - New
+ 5.1
+0.1
+0.4
+0.1
+0.7
-
.
+6.4

-

.
 20.3   23.7      +5.2

169.9  154.2      +0.9
+5.8

+1.2
+6.4

+1.5
+6.0

+ 1.4
20C0282

-------
                                       TABLE B-10-C
                                  Coal Mining Employment
                                     (Thousand Workers)
                                                           Proxmire  Cases
                                                        Change  From  Base 2010
Northern Appalachia
  Pennsylvania
  Ohio
  Maryland
  Northern West Virginia
       TOTAL

Central Appalachia
  Southern West Virginia
  Virginia
  Eastern Kentucky
  Tennessee
       TOTAL

Southern Appalachia
  Alabama
       TOTAL

TOTAL APPALACHIA

Midwest
  Illinois
  Indiana
  Western Kentucky
       TOTAL

TOTAL MIDWEST

Central West
  Iowa
  Missouri
  Kansas
  Northern Arkansas
  Oklahoma
       TOTAL

Gulf
  Texas
  Louisiana
  Southern Arkansas
       TOTAL

Actual
1985
22.3
9.0
0.7
12.8
44.7
23.8
13.3
29.8
JUi
69.5
8^6
8.6
122.8
13.9
5.2
7.7
26.8
26.8
0.1
1.1
0.2
0.0
1.0
2.5

2.4
0.1
0.0
2.4

Base
2010
30.1
6.7
0.3
ILJ
54.3
32.5
18.2
40.7
3.6
94.9
9.4
9.4
158.6
16.6
4.2
L£
29.0
29 . 0
0.1
0.4
0.2
0.1
Q.5
1.4

1.9
0.7
.
2.6

Proxmire
Intrautilitv
-2.8
-2.0
-
^L2,
-7.0
+2.1
+1.2
+2.8
-
+6.1
zP_2
-0.9
-1.-8
-6.3
-1.5
-0.8
-8.6
-8.6
.
-
-
-
.
-

_
-
.
.
Proxmire
In-State
Ex -Ex
-2.5
-2.1
-
^2
-6.8
+2.6
+1.5
+3.6
-
+7.7
^L2
-1.2
-0.3
-7.6
-2.2
^!
-11.6
-11.6
_
-
-
-
.
-

.
-
.
-
Proxmire
In-State
Ex -New
-12.1
-3.3
-
-5.0
-20.4
+4.4
+2.5
+5.8
	 -__
+12.7
J~i
-1.9
-9.6
-9.8
-2.4
^6.
-15.8
-15.8
.
-
-
-
-
-

-
-
.
-
Proxmi:
Inter.
Ex-Nev
-12.1
-3.3
-
-5.2
-20.6
+4.1
+2.2
+5.4
^^^^^^^
+11.7
^1
-2.5
-11.4
-9.4
-2.4
zlU
-15.1
-15.1
_
-
-
-

-
i
-
-
-
-
 20C0282

-------
                                        TABLE B-10-C

                                   Coal Mining Employment
                                     (Thousand Workers)
                                         (continued)
                                                           Proxmire Cases
Rockies/Northern Plains
  Colorado
  Wyoming
  Montana
  Utah
  New Mexico
  Arizona
  North Dakota
       TOTAL.

Northwest  •
  Washington
       TOTAL

Alaska
  Alaska
       TOTAL

TOTAL WEST

TOTAL U.S.

Actual
1985
2.4
4.5
1.2
2.6
1.9
0.8
-Ll
14.5

Base
2010
19.0
5.5
2.4
10.4
3.5
0.7
0.9
42.4

Proxmire
Intrautility
+4.4
+1.1
-
+1.2
-
.
.
+6.7
Proxmire
In- State
Ex -Ex
+4.9
+1.4
-
+1.3
-
.
.
+7.6
Proxmire
In-State
Ex -New
+8.6
+0.9
+0.6
+3.9
+0.2
.
_
+14.2
Proxmire
Inter .
Ex -New
+8.5
+0.5
+0.6
+4.2
+0.2
_
_
+14.0
0.7
0.7
0.5
oj.
0
20,
169,
.1
.3
.9
0,
0,
47,
234.
,.3
.3
.2
8


+6
-3
.
-
.7
.7
.
-
+7.
-4.


6
3


+14,
-11.


.2
,2


+14.
-12,


.0
,5
20C0282

-------
h-  . '

K>  -,
.0   f.
n   (J
f»   ••
in

-------
                                   APPENDIX C

                     30 YEAR/1.2 LB.  SUMMARY AND  FORECASTS
      This  appendix presents and discusses the findings of the  30 Yr/1.2 analyses
 under various  trading scenarios.  The text highlights the key  effects on utility
 sulfur  dioxide emissions, utility costs,  and  coal  production when alternative
 levels  of  emissions trading under  the  30  Yr/1.2  proposal are  considered.
 Detailed  forecasts  from  the  30  Yr/1.2 cases  are  presented at the  end  of the
 appendix.
06C0022
Page C-l

-------
              S02 EMISSION REDUCTIONS AND  COAL CAPACITY AFFECTED UNDER

                             THE  30 YEAR/1.2  LB. PROPOSAL
   S02 Emissions
  (millions of tons)
                    25
                    20
                    15-
                    10-
                     1985
                                                                Base Case
                                                                30 Yr/1.2
                                                                Intrastate
1990
1995
2000
2005
                                                                        2010
 Coal Capacity
  Affected by
30 Yr./1.2 Cases
   (gigawatts)
                                      2000
                                                      2005
                                                                        2010
  06C0022
  Page C-2

-------
            S02 EMISSION REDUCTIONS AND COAL CAPACITY AFFECTED UNDER
                          THE 30 YEAR/1.2 LB.  PROPOSAL
             The   30  Yr/1.2  cases  result  in  steadily  increasing
             amounts  of emission reductions (from Base Case levels)
             over time.   Emission reductions are forecast to equal:

                   3.6  million tons  by 1995
                   6.4  million tons  by 2000
                   11.1  million tons by 2010.

             The  amount  of reductions are forecast to increase over
             time because  the  amount of  capacity affected by  the
             regulations and thus required to meet a 1.2 Ib.  emission
             rate increases over time.   As shown in  the figure  on
             the  -opposite page,  there  is a steady, increase  in  the
             amount of coal capacity  (which is not currently meeting
             a  1.2 Ib.  limit)  which  reaches 30  years  of age:
                   73  gigawatts  by 1995
                   114 gigawatts by 2000
                   175 gigawatts by 2010.
            After  2010,  emission reductions from Base  Case  levels
            (although not forecasted) would be expected to decline.
            This  is because (1) no  non-NSPS capacity  was brought
            into service after 1980,  so no additional capacity would
            reach  30 years of age after 2010 and be  affected  by the
            1.2 Ib. emission limit,  and  (2)  some  units  meeting the
            1.2  Ib.  limit begin to  retire.    (Based on a 60  year
            lifetime  assumption,  units built  in the early  1950's
            would begin  to retire after  2010.)
06C0022
Page C-3

-------
                 S02  EMISSIONS BY PLANT TYPE  -- 30  YEAR/1.2  LB.  CASES IN  2010
                     25
                     20
                     15
  S02 Emissions
      in  2010
(millions  of tons)
                     10
                      5-
                   V\\VV
                    ''/, '•/, \ \ \ '
                                                   \\\\.\\
                                                                    \
BaS6  Case       Existlng-Exlsting       Existing-Existlng
                    Intrautility             Intrastate
                                                                                       New

                                                                                       Existing
                                                                                        :::v::x-:::':.:.::.v.
                                                                                        SmSi:' ' '''
                                                                                       ^SfS*S:SS:SSSw'




                                                                                       :
                                                                                       ''V % \ \ •', ••
                                                                                       J\X\:\\
                                                                                       Exist ing-New
                                                                                        Intraslate
                                                                30 Yr/1.2 Lb. Cases
     06C0022

     Page C-4

-------
         S02  EMISSIONS  BY  PLANT  TYPE  --  30  YEAR/1.2  LB.  CASES  IN 2010
            As noted previously, the 30 Yr/1.2 cases result in peak
            emission reductions in 2010 of approximately 11 million
            tons.  Under the existing-existing trading cases (e.g.,
            30   Yr/1.2   intrastate),   virtually   all   emissions
            reductions  come  from existing  plants.   There  is little
            change  in emissions from new plants.

            Under existing-new emissions trading on the  intrastate
            level,  there is  a  substantial shift  in emissions  at
            existing and new sources.   Emissions from new sources
            increase by 1.9  million tons  over Base Case  levels  as
            131 gigawatts of new plants are built without  scrubbers
            (as permitted under existing-new trading).  As a result,
            emissions  from  existing powerplants are  reduced by  a
            total of 13 million tons,  or 1.9 million tons  more than
            in  the  existing-existing  intrastate  case.     These
            substantial   reductions   from  existing  sources  are
            achieved through shifts to very  low  sulfur  coals and
            through  the  addition  of  47   gigawatts   of   retrofit
            scrubbers at  existing plants.
06C0022
Page C-S

-------
               CHANGE IN ANNUALIZED COSTS IN  2010 -- 30 YEAR/1.2 LB. CASES
      Change in
 Annualized Costs in
2010 from Base Case
  Levels  (billions of
   1987 $ per year)
                             Existing-Existing
                                Intrautility
Existing-Existing
   Intrastate
Existing-New
  Intrastate
     06C0022

     Page C-6

-------
              CHANGE IN ANNUALIZED COSTS IN 2010 -- 30 YEAR/1.2 LB. CASES


   While the national level of emissions  is  largely unaffected by emissions trading, the
costs associated with  the  30  Yr/1.2  cases are significantly affected  by  the extent of
trading permitted.
                                   •

   •     To  the  extent a  greater  geographic scope  for emissions  trading  is
         permitted, costs are  significantly reduced:

               Under existing-existing trading on  an  intrautility basis
               (but not across state lines),  the  change in annual costs
               in 2010 totals  $4.5 billion, or roughly  20  to 30 percent
               lower costs than assuming no trading.2

               Under   existing-existing    trading   on   an   intrastate
               (interutility)  basis,  the  increase in annual costs of $4.1
               billion in  2010 are  approximately 10 percent  lower than
               costs assuming  intrautility trading only.

         The costs  are reduced because  more cost-effective  emission reductions
         occur as the scope of trading increases.  More trading possibilities
         increases  the  likelihood that a powerplant unit  with high cost emission
         reductions can obtain reductions from a powerplant  unit with lower cost
         emission reductions.  Permitting any trading (i.e. ,  intrautility trading
         versus no  trading) results  in  the most  substantial savings.

   •      The annualized costs are reduced even further when existing-new trades
         are permitted.  Of the 30 Yr/1.2 trading schemes  analyzed, the existing-
         new intrastate trading case is  the least costly,  costing about  $3.6
         billion per year  by  2010  or  about  $0.5  billion less  than  if  only
         existing-existing  trading  is permitted.   These savings  occur  because
         the costs  of meeting the  current  NSPS  (e.g., scrubbing a new plant) are
         more expensive than the costs of emission reductions at existing units.

   •      Capital and O&M  costs are  substantially lower  in  the  existing-new
         trading case than  in the  other  cases.  This reflects much less scrubber
         capacity,  as new capacity is built without scrubbers  and the  increases
         in new powerplant  emissions are largely offset by emissions reductions
         through fuel switching at existing powerplants.   Fuel costs  for the
         existing-new trading  case are  higher, because more switching to lower
         sulfur fuels  occurs  at  existing  units  in  order  to  achieve  these
         additional emission reductions,   and  new units  choose  to burn  lower
         sulfur coals unscrubbed.
        2 A 30 Yr/1.2 case with no trading  (unit-by-unit  limits) was not analyzed
        for this study.  However, previous analysis of  similar cases conducted
        by ICF for EPA suggests costs of  about $5.5-6.5 billion  in 2010.
  U6C.U022
  Page C-7

-------
               CHANGES  IN ANNUALIZED  COSTS OVER TIME --  30 YEAR/1.2  LB.  CASES
    Increase in
Costs Above Base
   Case Levels
 (billions of 1987
    $ per year)
                      3-
                       1-
                           30 Yr./1.2 Cases
                                 Ex-Ex Intrutility
                                 Ex-Ex Intrastate
                                 Ex-New Intrastate
                      1995
                                         2000
2005
                  2010
    OKJUOZZ

    Page C-S

-------
          CHANGES IN ANNUALIZED COSTS OVER TIME  -- 30 YEAR/1.2 LB. CASES
       Annualized costs increase significantly over time relative to Base Case
       levels  for  the 30  Yr/1.2  cases because  the  amount  of  reductions
       increases,  and  because the  marginal and  average costs  per ton  of
       emission  reductions  increase as greater  reductions are  required.

       The annualized cost savings associated with  existing-new trading at the
       intrastate level,  as  compared  to existing-existing  trading at  the
       intrastate level,  increase  significantly between 1995  and  2000.

            In  1995,  savings  are  limited because  there is-very  little
            new capacity built which can trade with  existing sources
            and take  advantage  of   the   exemption   from  building
            scrubbers.

            By  2000,  the existing-new  intrastate case  is about  $0.5
            billion  per  year  less  costly than its  existing-existing
            trading counterpart,  as  more new plants  are built without
            scrubbers.

       Although  there are more  existing-new trading opportunities by 2010,  the
       cost  savings relative  to  the  existing-existing trading  case remain
       roughly  the  same  as  in 2000,  reflecting  a  lower incremental value
       associated with existing-new  trades.   This  occurs because  of  the
       substantial  emission reductions  required by  2010,  resulting in  few
       additional  opportunities  for  further cost-effective  reductions  at
       existing  sources.
06C0022
Page C-9

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                       PRESENT VALUE OF  COSTS --30  YEAR/1.2 LB.  CASES
 Increase in the
 Present  Value of
 Costs Over the
 1987-2010 Period
Above Base Case
Levels (billions of
     1987 $)
                                   17.9
                             Existing-Existing
                               Intrautility
                                                      .14.6
Existing-Existing
   Intrastate
                                                                           11.7

Exlstlng-Naw
  Intrastate
    06C0022

    Page C-10

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                  PRESENT VALUE OF  COSTS  --  30 YEAR/1.2  LB.  CASES
      The change in present value of costs reflects the increase in annualized
      costs incurred over the forecast period  (i.e., through 2010) discounted
      back to  1987  using the utilities'  real  discount  rate.   Similar to the
      changes  in annualized  costs,  the changes  in  present  value of  costs
      increase  as  emissions  trading becomes more  restricted,  because  cost-
      effective  reductions become  more difficult to  obtain and hence  the
      average  reduction  becomes more  expensive.   For example,  the existing-
      existing  intrautility  trading case has  a  present  value of costs  which
      is  $3.3  billion  (or  20  percent) higher  than the  existing-existing
      intrastate trading case.

      In  present value  terms, existing-new  trading  costs $2.9  billion (or
      about  20  percent)  less  than  existing-existing  trading  under  the
      intrastate 30 Yr/1.2 cases.   Note that the percentage cost savings are
      more substantial  than the annualized cost savings in 2010  (about  10
      percent  lower costs  as  noted  before).   This is because the annualized
      cost savings  are  greater  in earlier forecast years  (about 50  percent
      in 2000)  , and these costs  savings  are more significant in present  value
      terms than those cost  savings that accrue  in later forecast years.
06C0022
Page C-ll

-------
                   CHANGES IN CUMULATIVE  CAPITAL COSTS AND  SCRUBBER CAPACITY
                         UNDER 30 YEAR/1.2 LB.  CASES  -- 2010
      Change in
  Cumulative Capital
     Costs from
  Base Case Levels
       by 2010
  (billions of 1987 $)
                                    10.1
                              Existing-Existing
                                 Intrautility
Existing-Existing
   Intrastate
Existing-New
  Intrastate
Changes  in Scrubber
 Capacity from Base
 Case Levels  in 2010
     (gigawatts)
                              14
                        JiM  Retrofit
                        I     I  New
                                                                                -131
                            Existing-Existing
                               Intrautility
Existing-Existing
   Intrastate
Existing-New
  Intrastate
     06C0022
     Page C-12

-------
             CHANGES  IN  CUMULATIVE  CAPITAL COSTS -AND  SCRUBBER CAPACITY
                        UNDER  30  YEAR/1.2  LB.  CASES  --  2010
       Cumulative  capital  costs  (from Base Case levels) by 2010  increase  by
       about  $10  billion  for the  30 Yr/1.2  case with  the  least  flexible
       emissions  trading scheme  --  existing-existing intrautility  trading.
       This  increase  reflects about 14 gigawatts of existing capacity  being
       retrofitted with scrubbers in order to achieve the emission reductions
       required from existing powerplants.  Expanding the scope  of trading  to
       the existing-existing intrastate level reduces cumulative capital  costs
       (to a $9 billion  increase  over  the  Base  Case),  as  fewer  scrubbers are
       retrofitted and more cost-effective fuel  switching  is used to achieve
       the required emission  reductions.

       Cumulative  capital  costs  are  substantially affected by existing-new
       trading.  Existing-new  trading enables utilities to build many new  units
       without scrubbers, thereby substantially  lowering capital  costs.  The
       change  in  cumulative  capital  costs  in 2010  for  the  existing-new
       intrastate  trading case is only about $2 billion higher than Base Case
       levels  (and is  actually  lower  than Base Case levels in  2000)  because
       less new scrubber capacity is built.

       New scrubber capacity  decreases by over 131 gigawatts from Base Case
       levels  by  2010,  due  to  the ability to  offset  these  new  emissions
       increases with further  reductions from existing sources.   Some of  these
       reductions  are forecast to come  from installing retrofit scrubbers  at
       about 47 gigawatts of existing plants, which  is a more cost-effective
       strategy  (on a  cost per  ton  removed basis)  than scrubbing new plants
       to meet NSPS.    Thus,  the net decrease  in scrubber capacity is  84
       gigawatts.
06C0022
Page C-13

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                     VALUE OF EXISTING-NEW  TRADES FOR 30 YEAR/1.2 LB.  CASES
                                     Representative Costs of Emission
                                            Reduction Alternatives
Annualized Costs
 (1987 mills/kwh)
                               New Coal Powerplant
         Total Annual Costs       40.6
         (mills/kwh)

         Incremental Costs
         (mills/kwh)

         Emission Rate           1.0
         (Ibs.  S02/mm Btu)

         Reduction in Emission
          Rate (Ibs. S02/mm Btu)

         $ Per Ton S02 Removed
43.4


2.8


0.6


0.4


1400
                 Existing Coal Powerplant
17.3          22.7         26.3


             5.4          9.0


5.0           1.0          0.5


             4.0          4.5


             270          400
      06C0022
      Page C-14

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              VALUE OF EXISTING-NEW TRADES FOR 30 YEAR/1.2 LB.  CASES
      As noted previously, existing-new trading on the intrastate level under
      30 Yr/1.2 leads  to  substantial annualized and  cumulative  capital cost
      savings  over the existing-existing  intrastate counterpart.   Much  of
      these  savings  result  from  allowing  utilities  to  build  new  coal
      powerplants  without scrubbers,  provided that  the resulting  increases
      in emissions  from these unscrubbed new powerplants  are  compensated  by
      commensurate  decreases in emissions  from existing sources.

      The  table  on  the   opposite  page  reveals  the  favorable  economics
      associated  with building  new unscrubbed powerplants  and  obtaining
      offsetting  emission reductions  from existing plants.   Although the
      economics presented are  only  representative,  they  indicate  that coal
      switching or retrofit scrubbing at an existing coal unit generally leads
      to much  more cost-effective emission reductions (in terms of dollars
      per ton  removed) than the  incremental  costs of scrubbing high  sulfur
      coal (versus burning low sulfur coal without scrubbing) at a new  plant.
06C0022
Page C-15

-------
                     REGIONAL  COAL PRODUCTION IN 2010 FOR  30 YEAR/1.2  LB.  CASES
                      2100-
                      1800-
                      1500-
   Regional Coal
Production in  2010  1200
 (millions of tons)

                       900-
                        600
                       300-
  ] N. Appalachia
 H C. & S. Appalachia
• Midwest
CD West
                                   Base Case
                      Existlng-Exlstlng
                        Intrautility
Exlsting-Exiiting
  Intrastate
                                                                                       mii
Exitting-N«w
 Intrastat*
                                                                  30 Yr/1.2 Lb. Cases
       06C0022
       Page C-16

-------
            REGIONAL COAL PRODUCTION IN 2010 FOR 30 YEAR/1.2 LB. CASES
       Total national coal production levels are forecast to shift relatively
       little as a result of the emission reductions required by the 30 Yr/1.2
       proposal.

       However, regional coal production is affected considerably by requiring
       emission reductions and by allowing emissions trading. High sulfur coal
       producing regions  (such as  Northern Appalachia  and  the  Midwest)  would
       register significant declines in production as a result of the 30 Yr/1.2
       proposal.    Conversely, low sulfur coal producing  regions  in  Central
       Appalachia  and  in the  West would experience large  production  gains.
       These swings in coal production occur as  existing coal powerplants shift
       towards low sulfur coals and away from high sulfur  coals  in order  to
       reduce emissions.  Typically, these fuel shifts are the first  type  of
       strategy pursued  in  reducing emissions  since they  lead to  more  cost-
       effective reductions  than does  retrofit scrubbing.

       Existing-new  trading  schemes  lead to  further production declines from
       high sulfur coal regions  (and further increases in production from low
       sulfur coal  regions)  by stimulating more fuel  shifting activity from
       higher  to   lower  sulfur  coals  at .existing  powerplants.   This  fuel
       shifting serves to further reduce emissions  at  existing  powerplants  so
       as  to  offset increased emissions  from  new  (unscrubbed) sources.
       Moreover, some new  scrubbed powerplants use  high  sulfur  coals  when
       there is no existing-new trading.   Many of  these  powerplants shift  to
       low  sulfur  coals without   scrubbing  when  existing-new  trading  is
       permitted.
06C0022
Page C-17

-------
                   COAL  PRODUCTION  OVER TIME  --  30 YEAR/1.2  LB.  CASES
                    270


                    240
                    180
     Northern
   Appalachian
 Coal Production   15°
(millions  of tons)
                    120

                     90-


                     60


                     30
^^™ Base Case
xaamxm 30/1.2 Ex-Ex Intrautility
"•««« 30/1.2 Ex-Ex Intrastate
 ... ,., •„ 30/1 _2 Ex-New Intrastate
                      1980
     1985
1990
1995
2000
2005
                   2010
                    200

                    180

                    160-

                    140-


   Midwestern      12°"
 Coal Production
(millions of tons)   10°-

                     80

                     60

                     40

                     20-I
      Base Case
      30/1  2 EX_EX mtrautility
      30/1.2 Ex-Ex Intrastate
      30/1.2 Ex-New Intrastate
                      1980
     1985
1990
                                                 1995
2000
2005
                                                   2010
06C0022
Page C-18

-------
                COAL PRODUCTION OVER TIME -- 30 YEAR/L.2 LB. CASES


       High  sulfur coal producing  regions are  adversely affected by proposed
       sulfur dioxide  emission reduction requirements.   Production from both
       the Midwest and from Northern Appalachia falls significantly as a result
       of the 30 Yr/1.2 proposal.  The Midwest would experience a much larger
       decline (well below current levels) , while Northern Appalachia's decline
       would not  result in production  being  significantly below 1985 levels.
       This  is because  demand for  medium sulfur coals  (which can be found in
       Northern Appalachia,  but not  in the Midwest)  does not fall as much as
       demand for  high sulfur  coals  under  the  30 Yr/1.2  proposal.    More
       significant coal production losses below Base Case  levels  occur over
       time  because emission  reduction  requirements become more  stringent,
       resulting  in lower demand  for  higher (and eventually medium)  sulfur
       coals.

       Similar to  the Proxmire case,  existing-new trading under the 30 Yr/1.2
       results in even greater production losses from high sulfur coal regions
       (particularly from Northern Appalachia), as  new  powerplants are built
       without scrubbers and use lower  sulfur coals.  However, the incremental
       impact of existing-new trading  on high  sulfur coal production is much
       less  under  the 30 Yr/1.2 than under the  Proxmire  case (as discussed on
       page  B-19)  because  there  are  fewer existing-new  trades.
06C0022
Page C-19

-------
                                                           TABLE C-1A

                                                    SULFUR DIOXIDE FORECASTS
                                                  30 YR/1.2 CASES VS. EPA BASE
UtlIItv S02 Emissions
  (mill Ions or tons)
   31-Eastern states
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 31-EASTERN STATES

   17-Western States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 17-WESTERN STATES

   United States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL UNITED STATES

I960
11.92
0.00
11.92
1.27
16.19
1.10
0.00
1.10
0.09
1.19
16.02
0.00
16.02
w'.za

1985
11.21
0.00
114.21
1l!78
1.18
l!l8
0.01
1.19
15.69
0.00
15.69
0.58
16.27

EPA
BASE
CASE
1995
15.26
15il1
1.02
16. t3
2.00
0.05
2.05
0.12
2.17
17.26
0.20
17.16
18.60
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
1995
-3.15
0.00
-3.15
-3!57
-0.05
0.00
-0.05
-0.07
-3.51
0.00
-3.50
-0.11
-3.61
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX
1995
-3.50
0.01
-3.19
-0.08
-3.57
-0.06
0.00
-0.06
-0.01
-0.07
-3.56
-3!55
-0.08
-3.61
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
1995
-3.50
0.01
-3.19
-0.08
-3.57
-0.08
0.02
-0.06
-0.01
-0.07
-3.59
0.01
-3.55
-*«
Note:   Totals may not add due to Independent rounding.

-------
                                                           TABLE C-1B

                                                    SULFUR DIOXIDE FORECASTS
                                                  30 YR/1.2 CASES VS. EPA BASE
Utl I It.V SO2 Emissions
  (mill Ions of tons)
   31-Eastern States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 31-EASTERN STATES

   17-Western States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 17-WESTERN STATES

   United States
       Coa I
         EXIST ING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL UNITED STATES
1280
14.92
0.00
I'l. 92
1 .27
16.19
1 . 10
0.00
1. 10
0.09
1.19
16.02
0.00
16.02
1.36
17.38
1983
. 14.21
0.00
11.21
UK78
1 .MS
0.00
1.18
fTl9
15.69
0.00
15.69
0.58
16.27
EPA
BASE
CASE
2000
15.85
0.314
16.20
~f7739
2.05
0.02
2.13
0. 13
2.26
17.90
0.13
18.33
1 .32
19.65
CHANGE
FROM
EPA BASE
30YR/1.2
.NTRA-
UTILITY
2000
-6.13
0.02
-6.11
-0.23
-6.31
-0.10
0.01
-0.09
-0.02
-0. 11
-6.23
0.01
-6.20
-6!l5
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2000
-6.11
0.01
-6.10
-0.22
-6.33
-0.10
-o!o9
-0.02
-0. 11
-6.25
0.05
-6.20
-0.21
-6.11
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
-6.26
0.19
-5.77
-6.ZZ
-0.26
0.15
-0.10
-o!n
-6.52
0.61
-5.87
-0.58
-6.11
Mote:   Totals may not add due to Independent rounding.

-------
                                                           TABLE C-1C

                                                    SULFUR DIOXIDE FORECASTS
                                                  30 YR/1.2 CASES VS. EPA BASE
Utl I It.V S02 Emissions
  (mill ions or tons)
   31-Eastern States
       Coal
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL 31-EASTERN STATES

   17-Western States
       Coa I
         EXISTING
         NEW
       TOTAL COAL
       OIL/CAS
   TOTAL 17-WESTERN STATES

   United States
       Coal
         EXISTING
         NEW
       TOTAL COAL
       OIL/GAS
   TOTAL UNITED STATES

1980
114.92
0.00
14.92
1 .27
16. 19
1.10
0.00
1.10
0.09
1.19
16.02
0.00
16.02
1.36
17.38

1985
14.21
0.00
14.21
0.57
11.78
1.48
0.00
1.48
0.01
1.49
15.69
0.00
15.69
0.58
16.27

EPA
BASE
CASE
2010
16.76
1.47
18.23
0.82
19.05
2.01
2^56
0. 11
2.67
18.77
2.01
20.79
0.9J
21.72
CHANGE
FROM
EPA BASE
30YR/1.2
1 NTRA-
UTILITY
2010
-10.53
0.22
-10.31
-0.33
-10.63
-0.41
0.00
-0.41
-0.02
-0^42
-10.94
0.22
-10.71
-1..06
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2010
-10.54
-1o!22
-0.41
-10.63
-0.34
0.02
-0.36
-0.43
-10.89
-loise
-0.48
-11.06
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2010
-11.57
1.38
-10.18
-0.45
-10.63
-0.88
0.53
-0.35
-0.07
-0.43
-12.45
1.91
-10.54
-0.52
-11.06
Note:   Totals may not add due to independent rounding.

-------
                                                         TABLE C-2-A

                                            UTILITY SULFUR DIOXIDE CONTROL COST  FORECASTS
                                                    30 YEAR/1.2 LB. CASES
Utility Annual Costs
 (billions of mid-1987 S/yr.)
   CapltaI
   O&M
   Fuel
     Total

Utility Cumulative Capital Costs
 (bill ions of mid-1987?)
   31-Eastern States
   17-Western States
     Total U.S.

Average Cost Per Ton SO2 Removed

S02 Retrofit Scrubber Capacity
 (GW)
   31-Eastern States
   17-Western States
     Total U.S.
New Capacity Trading with Exist i rig Capac I ty
 (GW)
   31-Eastern States
   17-Western States
     Total U.S.
CHANGE
FROM
EPA BASE
30/1.2
INTRA-
U'MI 1 TY
1995
0.2
0.2
0.2
0.5
1 .8
~T79
138
2.5
0.0
2.5
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-EX
IN-STATE
1995
0. 1
0.1
0.2
O.U
0.7
o!a
98
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
1995
0. 1
0.1
0.2
O.U
0.7
_1LJ2
0.8
97
0.0
JO^
0.0
0.0
0.3
Note:   Totals may not add due to Independent rounding.

-------
                                                         TABLE C-2-B

                                            UTILITY SULFUR DIOXIDE CONTROL COST FORECASTS
                                                    30 YEAR/1.2 LB. CASES
Utl11tv AnnuaI  Costs
 (bill ions or mid-1987 $/yr.|
   Capital
   O&M
   Fue I
     Tota I

Utility Cumulative Capital Costs
 (billions or mid-1987 $)
   31-Eastern States
   17-Western States
     Total U.S.

Average' Cost Per Ton S02 Removed

S02 Retrofit Scrubber Capacity
 (GW)
   31-Eastern States
   17-Western States
     Total U.S.
New Capacity Trading with Existing Capacity
 (CW)
   31-Eastern States
   17-Western States
     Total U.S.
CHANGE
FROM
EPA BASE
30/1.2
INTRA-
UTILITY
2000
O.M
0.3
0.7
1.3
3.6
O.U
«».1
203
«4.9
0.2
5.1
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX- EX
IN-STATE
2000
0.2
0.2
o!9
1.9
0. 1
2.0
137
0.9
_0^0
0.9
0.0
676
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
2000
-0.0
-0.1
0.6
0.5
-0.1
rP^l
-O.U
7H
1.0
_LO
2.1
15.5
5-2
20.7
Note:   Totals may not add due to independent rounding.

-------
                                                         TABLE C-2-C

                                            UTILITY SULFUR DIOXIDE CONTROL COST FORECASTS
                                                    30 YEAR/1.2 LB. CASES
UtlI Itv Annua I Costs
 (billions or mid-1987 S/yr.)
   Cap Ita I
   O&M
   Fuel
     Tota I
        Cumulat I ve C a pi ta I
              mid-19871)
                           Costs
Utl I I tv
 (bill Ions of
   31-Eastern States
   17-Western States
     Total U,S.
Average Cost Per Ton S02 Reihovod

S02 Retrorit Scrubber Capacity
 (GW)
   31-Eastern States
   17-Western States
     Total U.S.
New Capacity Trading with Exist! mi CapacIty
 (GW)
   31-Eastern States
   17-Western States
     Total  U.S.
CHANGE
FROM
EPA BASE
30/1.2
INTRA-
UTILITY
2010
1 .0
0.8
2.8
H.5
9.0
1 . 1
10. 1
'107
11.3
2.7
13.9
0.0
0.0
0.0
CHANGE CHANGE
FROM FROM
EPA BASE tPA BASE
30/1.2 30/1.2
EX- EX EX-NEW
IN-STATE IN-STATE
2010 2010
0.8 0.1
0.7 0.0
2.6 3.1
H.1 3.6
8.2 2.14
176 2.0
372 323
7.2 33.5
l'.a U7.0
0.0 96.2
0.0 31.6
0.0 130.8
Note:   Totals may not add due to independent rounding.

-------
                                                           TABLE C-3A

                                               UTILITY FUEL CONSUMPTION  FORECASTS
                                                           (IN QUADS)
                                                  30 YR/1.2 CASES VS.  EPA  BASE
31 EASTERN  STATES

COAL
     LOW  SULFUR
     LOW-MEDIUM  SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL

OIL
GAS

17 WESTERN  STATES
COAL
     LOW SULFUR
     LOW-MEDIUM  SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS

TOTAL U.S.
COAL
     LOW SULFUR
     LOW-MF.DIUM SULFUR
     MIGII-Hi:i)IUM SULFUR
     HIGH SULFUR

     TOTAL
                                   I960
 0.87
 1.61
 3. 18
 3.86

 9751

 1.99
 1.01
 1.11
 O.i|3
 0.7'l
 0.01

 2759

 O.'lS
 2.58
 2.28
 2.0'l
 3.92
 3.07
OIL
GAS
12. 12

 2.'l7
 3 . 'J9
           1985
   89
   56,
   66
   90
11.01

 0.93
 0.92
 1.61
 0.91
 0.96
 0.07
 3.58

 0.06
 2.28
 3.50
 2 49
 u!62
 3.97

1U.58

 0.99
 3.20

EPA
BASE
CASE
1995
2.63
2.08
3.83
3.80
12.3«1
1.51
0.79
2.»42
0.85
1.11
0.07
on*
0.214
1.6'l
5.06
2.93
<4.9<4
3.87
16.79
1.79
2.1(3
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
1995
1.05
0.149
-0.77
-0.76
0.01
0.01
0.0
-0.06
0.07
-0.02
0.00
-0.00
0.00
0.0
0.99
0.56
-0.79
-0.76
0.01
0.01
0.0
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
1995
0.83
0.61
-0.61
-0.86
-0.00
0.00
0.0
-0.03
0.04
-0.03
0.01
0.00
0.00
0.0
0.80
0.68
-0.6U
-0.8'4
-0.00
0.00
0.0
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
1995
0.86
0.59
• -0.60
-0.86
-0.00
0.00
0.0
-0.05
0.05
-0.02
0.01
-0.00
0.00
0.0
0.82
0.6<4
-0.62
-0.85
-0.00
0.00
0.0

-------
                                                            TABLE  C-3B

                                               UTILITY  FUEL  CONSUMPTION FORECASTS
                                                            (IN  QUADS)
                                                  30 YR/1.2  CASES VS. EPA BASE
31 EASTERN  STATES

COAL
     LOW SULFUR
     LOW-MEDIUM  SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL

OIL
GAS

17 WESTERN  STATES
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS

TOTAL U.S.
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MLDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS
                                   I 9 BO
 0.87
 1.61
 3. 18
 3.86

 97"53

 1.99
 1.01
 l.'ll
 0 . '( 3
 0.7'l
 0.01
 O.'l8
 2.58
 2.28
 2.0'l
 3.92
 3.87

\?~. 17?

 2.'I 7
 3. 59
           1985
   89
   56
   66
   90
11.01

 0.93
 0.92
 1.61
 0.9'l
 0.96
 0.07
 3.58

 0.06
 2.28
 3.50
 2. M9
 11.62
 3.97

li(758

 0.99
 3.20



EPA
BASE
CASE
2000
3.36
2.65
3.78
'1.12
13.90
1.98
0.71
2.70
0.95
1 .22
0.06
14.93
0.28
1 .90
6.06
3.60
'4.99
14. 18
18.8K
2.26
2.61
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
2000
2.09
0.50
-0.87
-1.69
0.02
0.01
0.0
-0.13
0.23
-0. 12
0.02
-0.00
0.00
0.0
1.96
0.73
-1.00
-1.68
0.02
0.02
0.0
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2000
2.19
0.59
-0.97
-1.81
0.01
0.00
0.0
-0. 12
0.23
-0.13
0.02
-0.00
-0.00
0.0
2.08
0.82
-1. 10
-1.79
0.01
0.00
0.0
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
2.13
0.80
-1.03
-1.88
0.02
-0.02
0.0
0.02
0. 11
-0.15
0.02
-0.00
-0.00
0.0
2. 15
0.91
-1. 17
-1 .87
0.01
-0.02
0.0

-------
                                                           TABLE C-3C

                                               UTILITY  FUEL CONSUMPTION FORECASTS
                                                           (IN QUADS)
                                                  30  YR/1.2 CASES VS. EPA BASE
31 EASTERN STATES

COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL

OIL
GAS

17 WESTERN STATES
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
OIL
GAS

TOTAL U.S.
COAL
     LOW SULFUR
     LOW-MEDIUM SULFUR
     HIGH-MEDIUM SULFUR
     HIGH SULFUR

     TOTAL
                                   1980
 0.87
 1.61
 3.18
 3.86

 9753

 1.99
 1.01
 2.59

 0.1(8
 2.58
   28
   0'l
   92
   07
OIL
GAS
1271 2

 2.'l7
 3.59
           1985
   89
   56
   66
   90
11.01

 0.93
 0.92
           1.61
           0.9'l
           0.96
           0.07
 3.58

 0.06
 2.28
1H. 58

 0.99
 3.20

EPA
• BASE
CASE
2010
6.81
3.82
1.85
5.08
20.57
1.79
O.H1
5.56
1.55
1.21
0.08
8. HO
0.31
0.99
12.38
5.37
6.06
5.16
28.96
2.13
l.'l'l
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
2010
U.15
0.11
-1.88
-2.70
0.01
0.03
0.0
-0.09
0.17
-0.09
-0.01
-0.01
0.01
0.0
1.37
0.31
-1.97
-2.71
0.00
0.05
0.0
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2010
1.33
0.12
-1.65
-2.77
0.03
0.02
0.0
0.10
-0.01
-0.09
0.0
-0.00
-0.00
0.0
1.13
0.11
-1.71
-2.77
0.03
0.02
0.0
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2010
7.05
-1.81
-2.28
-2.91
0.03
-0.02
0.0
0.09
-0.05
-0.01
-0.00
0.00
-0.00
0.0
7.13
-1.88
.-2.32
-2.91
0.03
-0.02
0.0

-------
                                                            TABLE  C-UA

                                             COAL  PRODUCTION  AND  SHIPMENT FORECASTS
                                                      ( IN  MILLIONS OF TONS)
                                                   30  YR/1.2 CASES VS.  EPA BASE
CoaI Product Ion
 NORTHERN APPALACHIA
 CENTRAL APPALACHIA
 SOUTHERN APPALACHIA
 MIDWEST
 WEST

 TOTAL COAL REGIONS

Coal Transportation
 WESTERN COAL TO EAST
830.
                                   N.A.
                                              1985
166.
2*45.
 26.
133.
316.

88T7
                                             N.A.

EPA
BASE
CASE
1225
180.
282.
23.
125.
1128.
1038.
55.
CHANGE
FROM
tPA BASE
30YR/1.2
INTRA-
UTILITY
1995
-17.
22.
0.
-15.
7.
-2.
6.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-EX
1225
-15.
22.
1.
-15.
6.
-2.
6.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
1995
-15.
22.
1.
-16.
5.
-3.
6.

-------
                                                           TABLE C-1B

                                             COAL PRODUCTION AND SHIPMENT FORECASTS
                                                     ( IN MILLIONS OF TONS)
                                                  30 YR/1.2 CASES VS. EPA BASE
Coal Production
 NORTHERN APPALACHIA
 CENTRAL APPALACHIA
 SOUTHERN APPALACHIA
 MIDWEST
 WEST

 TOTAL COAL REGIONS

Coal Transportation
 WESTERN COAL TO EAST
                                   1980
185.
233.
 26.
131.
251.

8307
                                   N.A.
          1985
166.
215.
 26.
133.
316.

881.
                                             N.A.

EPA
BASE
CASE
2000
188.
330.
25.
113.
179.
1165.
70.
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
2000
-26.
11.
3.
-16.
23.
-6.
12.
CHANGE
FROM
EPA BASE
30YR/1 . 2
IN-STATE
EX-EX
2000
-31.
16.
3.
-16.
22.
-5.
11.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
-33.
50.
3.
-18.
21.
-5.
13.

-------
                                                            TABLE C-»4C

                                             COAL  PRODUCTION  AND SHIPMENT FORECASTS
                                                      (IN  MILLIONS OF TONS)
                                                   30  YR/1.2 CASES VS.  EPA BASE
Coal Production
 NORTHERN APPALACHIA
 CENTRAL APPALACHIA
 SOUTHERN APPALACHIA
 MIDWEST
 WEST

 TOTAL COAL REGIONS

Coal Transportation
 WESTERN COAL TO EAST
                                   1280
185.
233.
 26.
13'4.
251 .

83fT
                                   N.A.
          1985
166.
2'I5.
 26.
133.
316.

88T7
                                             N.A.

EPA
BASE
CASE
2010
258.
1)07.
36.
175.
111.
165T7
183.
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
2010
-66.
142.
-6.
-78.
115.
7.
93.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX
2010
-60.
37.
-7.
-83.
122.
10.
99.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-NEW
2010
-88.
17.
-7.
-77.
176.
20.
1«47.

-------
                                                          TABLE C-5A

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    (IN THOUSANDS OF TONS)
                                                 30 YR/1.2 CASES VS. EPA BASE
    ME
    NH
    VT
    MA
    Rl
    CT
    NY
    PA
    NJ
    MD
    DE
   •DC
    VA
    WV
    NC
    SC
    GA
    FL
    OH
    Ml
    IL
    IN
    Wl
    KY
    TN
   . AL
    MS
    MN
    IA
    MO
    AR
    LA
 1980

  17.
  80.
   0.
 258.
   5.
  29.
 179.
 103.
 222.
  51.
   1.
 157.
 981.
 210.
 701.
 692.
2185.
 608.
1110.
1672.
 188.
1029.
 910.
 535.
 122.
 159.
 236.
1227.
  27.
  21.






1985
10.
71.
1.
230.
2.
56.
120.
1320.
97.
217.
63.
1.
131.
969.
337.
162.
976.
501.
2193.
101.
1073.
1198.
367.
715.
802.
563.
113.
121.
219.
997.
69.



EPA
BASE
CASE
1995
3.
61.
3.
272.
0.
17.
181 .
1275.
130.
315.
60.
1.
210.
961.
501.
181.
871.
937.
2572.
119.
955.
1710.
273.
893.
856.
512.
116.
169.
302.
1058.
125.
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
1995
-1.
-15.
-2.
-38.
0.
0.
-158.
-232.
-51.
-88.
-11.
0.
-71.
-230.
-61.
-31.
-107.
-111.
-689.
-51.
-230.
-563.
-38.
-98.
-316.
-117.
-5.
-30.
-65.
-96.
-2.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
1995
-1.
-15.
-2.
-37.
0.
0.
-158.
-232.
-19.
-88.
-11.
-0.
-71.
-230.
-60.
-31.
-107.
-111.
-689.
-51.
-230.
-563.
-38.
-98.
-316.
-117.
-5.
-30.
-65.
-96.
-2.
CHANGE
FROM
EPA BASE
30YR/1.2
IN- STATE
EX-NEW
1995
-1 .
-15.
-2.
-37.
0.
0.
- 1 58 .
-232.
-19.
-88.
-11 .
-0.
-71.
-230.
-60.
-31.
-107.
-111.
-689.
-51.
-230.
-563.
-38.
-98.
-316.
-117.
-5.
-30.
-65.
-96.
-2.
TOTAL 31-EASTERN STATES
                                16191.
         11798.
16131.
                                                              -3572.
-3568.
-3568.

-------
                                                           TABLE C-5A

                                             TOTAL SULTUR DIOXIDE EMISSIONS BY  STATE
                                                     (IN THOUSANDS OF TONS)
                                                  30 YR/1.2 CASES VS. EPA BASE
    ND
    SD
    KS
    NE
    OK
    TX
    MT
    WY
    ID
    CO
    NM
    UT
    AZ
    NV
    WA
    OR
    CA
    AK

TOTAL 17-WESTERN STATES

TOTAL U.S.
                                   .128Q
  1285

  12').
   32.
  166.
   45.
   80.
  '»30.
   22.
  135.
    0.
   8D.
  11').
   27.
  10').
   35.
   85.
    2.
    3.
    (K
 1109.

1738(1.
16286.



EPA
BASE
CASE
1225
177.
50.
22M.
116.
209.
695.
'15.
62.
0.
130.
56.
69.
126.
76.
114.
16.
0.
2166.
18597.
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
1995
-9.
-3.
-23.
-11.
-0.
-0.
-1.
-0.
0.
-1.
0.
-12.
-0.
0.
. -5-
0.
0.
-68.
-3639.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX
1995
-8.
-3.
-23.
- 14 .
0.
-0.
-1 .
-0.
0.
-1.
0.
-12.
-0.
0.
-5.
0.
0.
-67.
-3636.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
1995
-8.
-3.
-23.
- 14.
0.
-0.
-1.
-0.
0.
-1.
0.
-12.
-0.
0.
-5.
0.
0.
-67.
-3636.

-------
                                                          TABLE C-5B

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    (IN THOUSANDS OF TONS)
                                                 30 YR/1.2 CASES VS.  EPA BASE
    ME
    NH
    VT
    MA
    Rl
    CT
    NY
    PA
    NJ
    MD
    DE
    DC
    VA
    WV
    NC
    SC
    GA
    FL
    OH
    Ml
    IL
    IN
    Wl
    KY
    TN
    AL
    MS
    MN
    IA
    MO
    AR
    LA





1980
17.
80.
0.
258.
5.
29.
179.
1122.
103.
222.
51.
ll.
157.
981.
115.
210.
701.
692.
2185.
608.
11 10.
1672.
188.
1029.
910.
535.
122.
159.
236.
1227.
27.
	 2J_._





1985
10.
71.
1.
230.
2.
56.
120.
1320.
97.
217.
63.
1.
131.
969.
337.
162.
976.
501.
2193.
101.
1073.
1198.
367.
715.
802.
563.
113.
121 .
219.
997.
69.
67.


EPA
BASE
CASE
2000
1.
63.
3.
299.
2.
36.
518.
1186.
127.
332.
60.
1.
293.
1007.
520.
209.
916.
968.
2677.
.177.
1096.
1782.
267.
935.
922.
565.
153.
218.
368.
1118.
151.
81.
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
2000
-2.
-10.
-2.
-72.
-0.
-0.
-171.
-522.
-65.
-123.
-21.
-0.
-91.
-303.
-96.
-67.
-196.
-286.
-1258.
-73.
-501.
-866.
-38.
-278.
-385.
-173.
-30.
-63.
-116.
-158.
-2.
-0.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2000
-2.
-10.
-2.
-71.
-0.
-0.
-171.:
-522.
-63.
-123.
-21 .
-0.
-91.
-303.
-91.
-69.
-196.
-286.
-1258.
-73.
-501.
-866.
-38.
-278.
-385.
-173.
-21.
-63.
-116.
-158.
-2.
-0.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
-2.
-10.
-2.
-71 .
-0.
-0.
-171.
-522.
-63.
-123.
-21.
-0.
-91.
-303.
-91.
-69.
-196.
-286.
-1258.
-73.
-501.
-866.
-38.
-278.
-385.
-173.
-21.
-63.
-116.
-158.
-2.
-0.
TOTAL 31-EASTERN STATES
16191.
                                          11798.
17386.
-6336.
-6326.
-6326.

-------
                                                           TABLE C-5B

                                             TOIAL SULFUR DIOXIDE EMISSIONS  BY  STATE
                                                     (IN THOUSANDS OF TONS)
                                                  30 YR/1.2 CASES VS. EPA BASE
    NO
    .SD
    KS
    NE
    OK
    TX
    MT
    WY
    ID
    CO
    NM
    UT
    AZ
    NV
    WA
    OR
    CA
    AK

TOTAL 17-WESTERN STATES

TOTAL U.S.
  I28Q

   79.
   30.
  102.
   '18.
   '15.
  295.
   23.
  128.
    0.
   71 .
   79.
   25.
   O'l.
   30.
   68.
    ll.
   70.
	fK

 1189.

17380.
  1985

  12'4.
   32.
  166.

   80'.
  H30.
   22.
  135.
    0.
   27.
  1014.
   35.
   85.
    2.
    3.
 	0^
16286.



EPA
BASE
CASE
2000
188.
51.
230.
122.
225.
710.
'18.
70.
0.
137.
56.
70.
130.
79.
122.
27.
0.
0.
2263.
19609.
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UT 1 L 1 TY
2000
-«»0.
-l».
-35.
-18.
0.
-1.
-1 .
-0.
0.
-1.
0.
-12.
0.
-0.
1.
-1.
0.
0.
-111.
-6W7.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2000
-HI.
-3.
-35.
-18.
0.
-0.
-1 .
-0.
0.
-1 .
0.
-12.
0.
-0.
1 .
-1 .
0.
0.
-Ill .
-6137.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
-U1.
-3.
-35.
-18.
0.
-0.
-1 .
-0.
0.
-1 .
0.
-12.
0.
-0.
1.
-1.
0.
0.
-111.
-6'I37.

-------
                                                          TABLE C-5C

                                            TOTAL SULFUR DIOXIDE EMISSIONS BY STATE
                                                    (IN THOUSANDS OF TONS)
                                                 30 YR/1.2 CASES VS. EPA BASE
    ME
    NH
    VT
    MA
    Rl
    CT
    NY
    PA
    NJ
    MD
    DE
    DC
    VA
    WV
    NC
    SC
    CA
    FL
    OH
    Ml
    IL
    IN
    Wl
    KY
    TN
    AL
    MS
    MN
    IA
    MO
    AR
    LA





i960
17.
80.
0.
258.
5.
29.
'179.
1022.
103.
222.
51.
't.
157.
98'i.
1H5.
210.
70M.
692.
2185.
608 .
11 10.
1672.
'188.
1029.
910.
535.
122.
159.
236.
1227.
27.
21 .





1985
10.
714.
1 .
230.
2.
56.
120.
1320.
97.
217.
63.
1 .
131.
969.
337.
162.
976.
501.
2193.
101.
1073.
1198.
367.
715.
802.
563.
1 13.
121.
219.
997.
69.
67.


EPA
BASE
CASE
2010
8.
70.
3.
363.
0.
13.
513.
1232.
191.
311.
62.
3.
311.
1037.
660.
308.
1021.
910.
2819.
516.
1107.
2007.
327.
911.
1056.
595.
168.
216.
138.
1196.
131.
89.
CHANGE
FROM
EPA BASE
30YR/ 1 . 2
1 NTRA-
UTILITY
2010
-3.
-12.
-2.
-101.
0.
-0.
-157.
-767.
-70.
-161.
-19.
0.
-112.
-608.
-232.
-111.
-603.
-395.
-2077.
-99.
-872.
-1120.
-65.
-529.
-631.
-273.
-66.
-86.
-257.
-812.
-1.
0.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX
2010
-3.
-12.
-2.
-101.
0.
0.
-155.
-767.
-70.
-159.
-20.
-0.
-112.
-608.
-232.
-110.
-603.
-395.
-2077.
-99.
-872.
-1120.
-65.
-529.
-631.
-273.
-66.
-86.
-257.
-812.
-1.
-0.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX- NEW
2010
-3.
-12.
-2.
-101.
0.
0.
-155.
-767.
-70.
-159.
-20.
-0.
-112.
-608.
-232.
-110.
-603.
-395.
-2077.
-99.
-872.
-1120.
-65.
-529.
-631.
-273.
-66.
-86.
-257.
-812.
-1.
-0.
TOTAL 31-EASTERN STATES
16191.
11798.
19017.
-10635.   -10629.   -10629.

-------
                                                           TABLE C-5C

                                             TOTAL  SULFUR DIOXIDE EMISSIONS BY STATE
                                                     ( IN THOUSANDS OF TONS)
                                                 30  YR/1.2 CASES VS. EPA BASE
    ND
    SD
    KS
    NE
    OK
    TX
    MT
    WY
    ID
    CO
    NM
    ur
    AZ
    NV
    WA
    OR
    CA
    AK

TOTAL 17-WESTERN STATUS

TOTAL U.S.
  1980

   79.
   3d.
  102.
   '18.
   '15.
  295.
   23.
  128.
    0.
   71 .
   79.
   25.

   38.
   68.

   70'.
	0_.

 1189.

1 738(1.
   32.
  166.

   80.
  H30.
   22.
  135.
    0.

  114!
   27.
  lO'l.
   35.
   85.
    2.
    3.
    0.
16286.



EPA
BASE
CASE
2010
2I|I|.
58 !
232.
133.
225.
890.
6'l .
68.
0.
1'I5 .
57.
77.
138.
78.
16*4 .
73.
20.
0.
2668.
21716.
CHANGE
FROM
EPA BASE
30YR/1 .2
INTRA-
UTILITY
2010
-614.
-29.
-77.
-32.
-18.
-111.
-5.
-0.
0.
-1 .
-0.
-20.
0.
-0.
-67.
3.
0.
0.
-«425.
-11059.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-EX
2010
-63.
-30.
-77.
-32.
-18.
-116.
-5.
0.
-0.
-1 .
-0.
-20.
0.
-0.
-67.
3.
0.
0.
-«426.
-11055.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-NEW
2010
-63.
-30.
-78.
-32.
-18.
-116.
-5.
0.
-0.
-1 .
-0.
-20.
0.
-0.
-67.
3.
0.
0.
-1425.
-11055.

-------
                                                          TABLE C-6A

                                              CHANGE IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions or Mid 1987 Dollars)
                                                 30 YR/1.2 CASES VS. EPA BASE
MAINE/VT/NII
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANCE
FROM
r.PA BASE
30YR/1 .2
INTRA-
111 ILI TY
1225
5.
21.
71.
17.
16.
H3.
23.
27.
'11.
14.
30.
59.
50.
5.
55.
1.
-35.
8.
22.
-0.
6.
-3.
-50.
9.
2.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX- EX
1995
5.
20.
66.
15.
15.
37.
21 .
35.
16.
2.
1.
17.
51.
-5.
-3.
5.
-13.
11 .
23.
-1.
5.
-1 .
-52.
7.
	 3_._
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
1995
5.
20.
66.
13.
15.
37.
22.
35.
16.
2.
1.
17.
51.
-3.
-2.
5.
-12.
11 .
23.
-0.
6.
-1.
-51.
10.
3.
TOTAL 31-EASTERN STATES
                                  132.
                                            286.
                                                      296.

-------
                                                          TABLE C-6A

                                              CHANGE IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions of Mid 1987 Dollars)
                                                 30 YR/1.2 CASES VS. EPA BASE
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL J7-WESTERN STATES

TOTAL U.S.
CHANCE
FROM
EPA DASE
30YR/1 .2
INTRA-
UTILITY
1225
0.
7.
3.
36.
-3.
5.
0.
8.
-0.
?..
26.
2.
1 .
Hi.
100.
533.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-EX
1225
0.
5.
5.
20.
-3.
6.
0.
9.
-0.
2.
22.
2.
1 .
0.
69.
355.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX -NEW
1995
0.
8.
6.
2.
-3.
8.
0.
9.
-0.
2.
22.
2.
1 .
0.
56.
352.

-------
                                                          TABLE C-6B

                                              CHANGE IN ANNUAL IZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions or Mid 1987 Dollars)
                                                 30 YR/1.2 CASES VS. EPA BASE
HAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINI A
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTILITY
2000
25.
15.
109.
173.
35.
76.
DO.
11.
87.
-5.
67.
165.
50.
1 .
157.
1'».
13.
39.
25.
-0.
2.
7.
'16.
1.
20.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX
2000
25.
36.
107.
137.
32.
65.
17.
30.
89.
-7.
51.
96.
53.
-18.
76.
7.
-33.
38.
23.
-1.
2.
1.
6.
2.
	 20.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
25.
12.
39.
111.
30.
50.
-5.
31.
71.
-6.
-37.
96.
52.
-18.
77.
8.
-52.
31.
23.
-2.
1.
1.
3.
3.
6.
TOTAL 31-EASTERN STATES
1216.
887.
587.

-------
                                                          TABLE C-6B

                                              CHANGE IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions of Mid 1987 Dollars)
                                                 30 YR/1.2 CASES VS. EPA BASE
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WCSTERN STA1ES

TOTAL  U.S.
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
UTI I.ITY
£000
21 .
-7.
-8.
-16.
- 17.
1 .
0.
ft.
-14.
3.
33.
3.
-11 .
55.
61.
1307.
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-EX
2000
11.
-9.
-7.
-19.
-17.
ll.
0.
10.
-2.
3.
29.
2.
-9.
-0.
-'«.
883.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
1 1.
-10.
-15.
-98.
-19.
0.
0.
-3.
-'1.
1 .
21.
-17.
-59.
-0.
-189.
398.

-------
                                                          TABLE C-6C

                                              CHANGE IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions or Mid 1987 Dollars)
                                                 30 YR/1.2 CASES VS. EPA BASE
HAINE/VT/NM
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA
CHANGE
FROM
EPA DASE
30YR/1.2
INTRA-
u r i L I TY
2010
35.
27.
193.
416.
171.
11'l.
82.
269.
106.
205.
224.
602.
86.
23*).
<458.
34.
164.
206.
121.
25.
21.
62.
26'l.
16.
13.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2010
35.
36.
108.
392.
107.
136.
79.
267.
101.
200.
212.
627.
83.
218.
440.
29.
1143.
206.
119.
21.
18.
59.
261.
11.
12.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2010
36.
2.
119.
393.
110.
117.
54.
278.
42.
202.
204.
563.
49.
157.
463.
2.
143.
168.
127.
18.
12.
•54.
220.
14.
14.
TOTAL 31-EASTERN STATES
                                 4146.
                                           3917.
3561.

-------
                                                          TABLE C-6C

                                              CHANGE  IN ANNUALIZED UTILITY SULFUR
                                                DIOXIDE CONTROL COSTS BY REGION
                                                 (Millions or Mid 1987 Dollars)
                                                 30 YR/1.2 CASES VS. EPA BASE
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMINC
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANCE
I:ROM
EPA BASE
30YR/1 .2
IN1RA-
iirn. ITY
2JLLQ
55.
100.
38.
8'l.
-9.
5.
0.
20.
-6.
-0.
i'i.
5.
16.
	 31^
3-36.
'1501 .
CHANGE
FROM
EPA BASE
30YR/ 1 . 2
IN-STATE
EX-EX
2010
52-
5'l.
27.
35.
-11 .
1.
-6.
17.
-7.
-8.
1U.
U.
1'l.
6.
193.
•ll 10.
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2010
U9.
56.
-37.
-50.
-214.
-3.
-6.
5.
-17.
-39.
17.
-8.
32.
1 U .
20.
3581.

-------
                                                          TABLE C-7A

                                         PERCENT CHANGE IN ELECTRICITY RATES BASED ON
                                          ANNUAL I ZED COSTS (I.e., LEVEL IZED BASIS) I/
                                                          (PERCENT)
                                                 30. YR/1.2 CASES VS. EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
30YR/1.2
INTRA-
IITILITY
1995
0.2
O.M
0.6
0.1
0. M
1.3
0.8
0.7
0.5
0. 1
O.'i
0.7
0.8
0.1
0.9
0.2
-1.0
0.2
O.M
0.0
0.3
-0.2
-1.3
O.'l
0. 1
0. 3
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX .
1995
0.3
0.3
0.6
0.1
O.M
1.2
0.8
0.9
0.6
0.0
0.0
0.2
0.9
-0.1
-0. 1
0.2
-1.2
0.3
0.5
0.0
0.3
-0. 1
-l.'l
0.3
0. 1
0.2
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
1995
0.3
0.3
0.6
0.1
O.M
1.2
0.8
0.9
0.6
0.0
0.0
0.2
0.9
0.0
0.0
0.2
-1.2
0.3
0.5
0.0
0.3
-0.1
-1.3
0.5
0. 1
0.2

-------
                                                           TABLE C-7A

                                          PERCENT CHANGE' IN ELECTRICITY RATES BASED ON
                                           ANNUAL I ZED COSTS (I.e., LEVEL I ZED BASIS) I/
                                                           (PERCENT)    '
                                                  30 YR/1.2 CASES VS. EPA BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASHINGTON/OREGON
 CALIFORNIA

 TOTAL 17-WESTERN STATES

 TOTAL U.S.

J7  Calculated as follows:
                 1995 Electric!ty Sales
CHANGE
FROM
EPA BASE
30YR/1 .2
INTRA-
1)1 II 1 TY
1225
0.0
0.2
0. 1
0.2
-O.H
O.'l
0.0
O.'l
0.0
0. 1
0.6
0. 1
0.0
0. 1
0.2
0.2
an On r,o AmHi;i 1
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
1225
0.0
0.2
0.2
0.1
-O.M
O.'l
0.0
0.5
0.0
0.1
0.5
0. 1
0.0
0.0
0. 1
0. 1
i zed Cost
3 Annnn 1 i zed Cost
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
1225
0.0
0.2
0.2
0.0
-O.'l
0.6
0.0
0.5
0.0
0.1
0.5
0. 1
0.0
	 
-------
                                                          TABLE C-7B

                                         PERCENT CHANGE IN ELECTRICITY RATES BASED ON
                                          ANNUALIZED COSTS (I.e., LEVELIZED BASIS) I/
                                                          (PERCENT)
                                                 30 YR/1.2 CASES VS. EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA

TOTAL 31-EASTERN STATES
CHANGE
TROM
EPA BASE
30YR/ 1 . 2
INTRA-
UTILITY
2000
1.4
0.8
0.9
1.6
0.7
2. 1
1.3
1 .0
0.9
-0. 1
0.7
1.9
0.7
0.0
2.6
O.'l
0.3
0.9
0.5
0.0
0.1
0.4
1. 1
0.2
0.5
0.9
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX
2000
1.4
0.6
0.8
1.3
0.6
1.8
1.2
0.8
1.0
-0. 1
0.5
1. 1
0.8
-0.2
1.3
0.2
-0.8
0.8
0.4
-0.1
0. 1
0.3
0.2
0. 1
0. 5
0.6
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2000
1.4
0.2
0.3
1.3
0.6
1.4
-0.1
0.8
0.8
-0. 1
-0.4
1. 1
0.8
-0.2
1.3
0.2
-1.2
0.8
0.4
-0.2
0.0
0.2
0.1
0. 1
0. 1
0.4

-------
                                                            TABLE C-7B

                                           PERCENT  CHANGE  IN ELECTRICITY RATES BASED ON
                                           ANNUALIZED  COSTS (i.e.,  LEVELIZED BASIS) I/
                                                            (PERCENT)
                                                   30 YR/1.2 CASES VS.  EPA BASE
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASHINGTON/OREGON
 CALIFORNIA

 TOTAL 17-WESTERN STATES

 TOTAL U.S.

J./  Calculated as follows:

     T 2000 Emission Rodnctlor
     I	2000 Base Case
     1           2000 Electric:! i.y Sales
CHANCE
FROM
EPA BASE
3UYR/1.2
INFRA-
III ILITY
?.OQQ
1 . 1
-0.2
-0.3
-0. 1
-1.9
0. 1
0.0
0.1
-0.2
0.2
0.7
0.2
-0.2
	 0..6
0. 1
0. 7
sc Aimna 1
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-EX
2000
0.5
-0.3
-0.3
-0. 1
-1.8
0.3
0.0
0.5
-0. 1
0.2
0.6
0.2
-0.2
	 OJ]
0.0
0.5
i zed Cost
ua 1 izod Cost
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-NEW
2000
0.5
-0.3
-0.6
-0. 1
-2. 1
0.0
0.0
-0. 1
-0.2
0.1
0.5
-1.3
-1.3
	 9_^Q
-0.2
0.2
-~l .
I --- E
1982 Average

-------
                                                          TABLE C-7C

                                         PERCENT CHANGE  IN ELECTRICITY RATES  BASED  ON
                                          ANNUAL IZEO COSTS (I.e., LEVELIZED BASIS)  1_/
                                                          (PERCENT)
                                                 30 YR/1.2 CASES VS. EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
30YR/1 .2
INTRA-
U I 1 L 1 TY
2010
2.2
0.3
1.2
'1.3
2.3
2.1
1.6
6.5
0.9
2.9
2.0
5.0
1.0
1 .8
7.2
0.9
3.8
2.5
2.2
1.0
1 .2
2.6
5.1
0.8
n.u
2.5
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX- EX
2010
2.2
0.14
0.7
U.1
1.M
2.6
1.6
6.5
0.9
2.8
1.9
5.2
0.9
1.7
6.9
0.7
3.3
2.4
2. 1
0.9
1.0
2.5
5.0
0.6
0.3
2.3
CHANGE
FROM
EPA BASE
30YR/1 .2
IN-STATE
EX-NEW
2010
2.2
0.0
0.7
1.1
1.5
2.2
1.1
6.7
o.«*
2.9
1.9
«4.7
0.5
1.2
7.2
0.0
3.3
2.0
2.3
0.7
0.6
2.3
'1.2
0.7
0.«4
2.1

-------
                                                            TABLE  C-7C

                                           PERCENT CHANGE  IN ELECTRICITY  RATES BASED ON
                                           ANNUAL I ZED  COSTS (I.e.,  LEVEL I ZED  BASIS) I/
                                                            (PERCENT)
                                                  30 YR/1.2 CASES VS.  EPA  BASE
CHANGE
FROM
EPA BASE
30YU/1 .2
INIHA-
UT ILITY
2010
1.2
3.2
1. 1
O.'l
-1.0
0.3
0.0
0.7
-0.3
0.0
0.2
0.3
0.3
0.3
O.M
1.9
CaKO Annna 1
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-EX
2010
1.2
1 .8
0.8
0.2
-1.1
0.1
-1.9
0.6
-0.14
-0.3
0.2
0.3
0.2
0. 1
0.2
1.7
izcd Cost
\rinna 1 i zed Cost
CHANGE
FROM
EPA BASE
30YR/1.2
IN-STATE
EX-NEW
2010
1. 1
1.8
-1.1
-0.2
-2.5
-0.2
-1.9
0.2
-0.9
-1.7
0.8
-0.5
0.5
0. 1
0.0
1.5
-~l -
I --- El
 N. & S. DAKOTA
 KANSAS/NEBRASKA
 OKLAHOMA
 TEXAS
 MONTANA
 WYOMING
 IDAHO
 COLORADO
 NEW MEXICO
 UTAH
 ARIZONA
 NEVADA
 WASH INGTON/OREGON
 CALIFORNIA

 TOTAL 17-WESTERN STATES.

 TOTAL U.S.

I/  Calculated as follows:

     T 2010 Emission Reduction Case Annualizcd Cost - I   .      1982 Average
     I          2010 Qnse Ca	'     _!'	 ' ~	'
     1           2010 Electric!ty Sales              _|

-------
                                                           TABLE C-8-A

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                     30 YEAR/1.2 LB. CASES
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
30/1.2
INTRA-
uriLITY
1995
0.0
0.0
0.2
0.2
0.0
0.2
0.0
0.0
0.0
0.0
0.0
0.7
0.0
0.0
1 .2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
?.. !>
CHANGE
FROM
EPA BASE
30/1.2
EX-EX
IN-STATE
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

-------
                                                           TABLE C-8-A

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                     30 YEAR/1.2 LB. CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
I DAIIO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANGE
TROH
TPA BASE
30/1.2
IN'IRA-
U 1 1 L 1 TY
J925
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
o.u
0.0
0.0
0.0
0.0
2.5
CHANGE
FROM
CPA BASE
30/1.2
EX-EX
IN-STATE
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
J325
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0

-------
                                                           TABLE C-8-B

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GIGAWATTS)
                                                     30 YEAR/1.2 LB. CASES
                                  CHANGE    CHANGE    CHANGE
                                   FROM      FROM      FROM
                                 EPA BASE  EPA BASE  EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORI DA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
30/ 1 . 2
INTRA-
UTILITY
2000
0.2
0.0
0.2
0.2
0.3
0.3
0. 1
0.0
0.5
0.0
0.0
0.7
0.0
0.1
1.3
0. 1
0.1
0.0
0.0
0.0
0.0
0.0
0.5
0.0
0.0
1.9
30/1.2
EX-EX
IN-STATE
2000
0.2
0.0
0.0
0.0
0.2
0.0
0.0
0.0
0.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.9
30/1.2
EX- NEW
IN-STATE
2000
0.2
0.0
0.0
0.0
0.2 .
0.0
0.0
0.0
0.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.0

-------
                                                           TABLE C-8-B

                                                  RE I ROMT SCRUBBER CAPACITY
                                                          (CIGAWATTS)
                                                     30 YEAR/1.2 LB. CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMINC
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
30/1.2
I NIRA-
UTILITY
2000
0. 1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.2
5. 1
CHANCE
FROM
EPA BASE
30/1.2
EX-EX
IN- STATE
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0 . 0
0.0
0.9
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.7
0.0
0.3
0.0
1 .0
2. 1

-------
                                                           TABLE C-8-C

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GICAWATTS)
                                                     30 YEAR/1.2 LB. CASES
                                  CHANGE    CHANGE    CHANGE
                                   FROM      FROM      FROM   .
                                 EPA BASE  EPA BASE  EPA BASE
MAINE/VT/NH
MASS/CONN/RIIODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORI DA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA
30/1.2
INTRA-
DTILITY
2010
0.2
0.0
0.2
0.8
0.3
. 0.6
0. 1
0.1
0.8
0.2
0.8
1.1
0.0
1 .2
1.8
0.2
0.6
0.0
0.0
0.0
0.0
0.3
2.0
0.0
0.0
30/1.2
EX- EX
IN-STATE
2010
0.2
0.0
0.0
0.5
0.2
0. 1
0.0
0.0
0.5
0.0
0.3
0.5
0.0
1.1
0.7
0.0
0.7
0. 1
0.0
0.0
0.0
0.1
1.7
0.0
0. 0
30/1.2
EX-NEW
IN-STATE
2010
0.2
0.9
0.5
1.8
1.6
2.6
1.2
0.2
2.8
0.5
3.2
1 1
1.6
3.1
1.5
0.8
1. 1
1.2
0.0
0.6
0.0
0.1
3.1
0.0
0. 0
TOTAL 31-EASTERN STATES
11.3
                                             7.2
                    33.5

-------
                                                           TABLE C-8-C

                                                  RETROFIT SCRUBBER CAPACITY
                                                          (GICAWATTS)
                                                     30 YEAR/1.2 LB. CASES
N. & S. DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORM I A

TOTAL 17-WF.STERN STATES

TOTAL U.S.
CHANGE
FKOM
EPA RASE
30/1 .2
INFRA-
IIT 1 L 1 TY
2010
0.3
0.7
0.3
1 . 3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2.7
13.9
CHANGE
FROM
I:PA BASE
• 30/1.2
EX-EX
IN-STATE
2010
0.2
0.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0 . 0
0.5
7.8
'CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
2010
1 .2
O.U
0.1)
5.3
0.0
0.0
0.0
0.6
0.0
0.9
2.3
0.7
1.8
0.0
13.6
l|7.0

-------
                                                           TABLE C-9-A

                                           NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                          (GIGAWATTS)
                                                     30 YEAR/1.2 LB. CASES
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA
CHANGE
FROM
CPA BASE
30/1 .2
INTRA-
DTILITY
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-EX
IN-STATE
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
1995
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
TOTAL 31-EASTERN STATES
                                   0.0
                                             0.0
                                                       0.0

-------
                                                              TABLE  C-9-A

                                              NEW CAPACITY TRADING  WITH EXISTING CAPACITY
                                                             (GIGAWATTS)
                                                        30 YEAR/1.2  LB.  CASES
N. &  S.  DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
I DAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 1/-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
30/1 .2
INTRA-
UTILITY
1295
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
(1.0
0.0
0.0
0.0
0.0
0.0
o.o
0.0
CHANGE
FROM
EPA I1ASE
30/1.2
EX-EX
IN-STATE
1993
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
1225
0.0
0.0
0.0
0.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.3
0.3
Reflects new coal  powerplants built without control  technologies to meet NSPS-Oa requirements.

-------
                                                           TABLE C-9-B

                                           NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                          (GIGAWATTS)
                                                     30 YEAR/1.2 LB. CASES
MAINE/VT/NH
MASS/CONN/RHODE I.
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHIGAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOUISIANA

TOTAL 31-EASTERN STATES
CHANGE
FROM
EPA BASE
30/1.2
INTRA-
UTILITY
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
	 0^0
0.0.
CHANGE
FROM
EPA BASE
30/1.2
EX-EX
IN-STATE
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN- STATE
2000
0.0
1.5
H.O
0.0
0.0
0.6
2.6
0.0
0.8
0.0
5.3
0.0
0.0
0.0
0.0
0.0
0.6
0. 1
0.0
0.0
0.0
0.0
0.0
0.0
	 
-------
                                                              TABLE C-9-B

                                              NEW  CAPACITY TRADING WITH  EXISTING CAPACITY
                                                             (GIGAWATTS)
                                                        30 YEAR/1.2 LB. CASES
N. & S.  DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAHO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL IT-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
F.I'A BASE
30/1.2
INIRA-
U f 1 L 1 TY
2000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-EX
IN-STATE
2000
0.0
O.O
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BAS
30/1.2
EX-NEW
IN-STATE
2000
0.0
0.0
0.3
0.7
0.2
0.3
0.0
0.6
0.0
0.0
'0.6
0.6
2.0
0. 0
5.2
20.7
Reflects new coal  powerplants built without  control technologies to meet NSPS-Oa requirements.

-------
                                                           TABLE C-9-C

                                           NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                          (GIGAWATTS)
                                                     30 YEAR/1.2 LB. CASES
                                  CHANGE
                                   FROM
                                 EPA BASE
         CHANGE
          FROM
        EPA BASE
         CHANGE
          FROM
        EPA BASE
MAINE/VT/NH
MASS/CONN/RHODE I .
NEW YORK
PENNSYLVANIA
NEW JERSEY
MARYLAND/DELAWARE
VIRGINIA
WEST VIRGINIA
N.&S.CAROLINA
GEORGIA
FLORIDA
OHIO
MICHI CAN
ILLINOIS
INDIANA
WISCONSIN
KENTUCKY
TENNESSEE
ALABAMA
MISSISSIPPI
MINNESOTA
IOWA
MISSOURI
ARKANSAS
LOU ISI ANA
                                 30/1.2    30/1.2    30/1.2
                                  IN1RA-    EX-EX    EX-NEW
                                 UTILITY  IN-STATE  IN-STATE
                                  2010      2010      2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
TOTAL 31-EASTERN STATES
                                   0.0
                                             0.0
                   96.2

-------
                                                              TABLE C-9-C

                                              NEW CAPACITY TRADING WITH EXISTING CAPACITY
                                                             (GIGAWATTS)
                                                        30 YEAR/1.2 LB. CASES
N. & S.  DAKOTA
KANSAS/NEBRASKA
OKLAHOMA
TEXAS
MONTANA
WYOMING
IDAIIO
COLORADO
NEW MEXICO
UTAH
ARIZONA
NEVADA
WASHINGTON/OREGON
CALIFORNIA

TOTAL 17-WESTERN STATES

TOTAL U.S.
CHANGE
FROM
EPA BASE
30/1.2
INTRA-
tlTILITY
2010
0.0
0.0
0.0
o.o-
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX- EX
IN-STATE
2010
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CHANGE
FROM
EPA BASE
30/1.2
EX-NEW
IN-STATE
2010
1.7
0.0
U.6
17.9
0.2
0.3
0.0
2.2
0.0
1.3
2.6
1.5
2.U
0. 0
34.6
130.8
Reflects new coal powerplants built without control technologies to meet NSPS-Oa requirements.

-------
                                       TABLE C-10-A
                                  Coal Mining Employment
                                     (Thousand Workers)
Northern Appalachia
  Pennsylvania
  Ohio
  Maryland
  Northern West Virginia
       TOTAL

.Central Appalachia
  Southern West Virginia
  Virginia
  Eastern Kentucky
  Tennessee
       TOTAL

Southern Appalachia
  Alabama
       TOTAL

TOTAL APPALACHIA

Midwest
  Illinois
  Indiana
  Western Kentucky
       TOTAL

TOTAL MIDWEST
Central West .
  Iowa
  Missouri
  Kansas
  Northern Arkansas
  Oklahoma
       TOTAL

Gulf
  Texas
  Louisiana
  Southern Arkansas
       TOTAL
                                                          30  Yr/1.2  Ib.  Cases
                                                         Change  From Base  1995
                             Actual  Base    30 Yr/1.2 Ib   30  Yr/1.2  Ib    30 Yr/1.2  Ib
                              1985   1995    Intrautilitv   Intra.  Ex-Ex    Intra.  Ex-New
22.3
9.0
0.7
12.8
44.7
23.8
13.3
29.8
_2^
69.5
8^6
8.6
122.8
13.9
5.2
7.7
26.8
26.8
0.1
1.1
0.2
0.0
2~5
2.4
0.1
0.0
2.4
18.0
6.2
0.5
13^5
38.2
21.8
12.2
27.3
2.4
63.6
5^8
5.8
107.7
10.1
3.0
6 .2
19.4
19.4
0.1
0.9
0.3
0.1
n 7
U • '
2.0
2.1
0.8
o.o
2.9
                                                -0.8
                                                -0.8
                                                -2.7
                                                +2.1
                                                +1.1
                                                +2.9

                                                +6.1
                                                +0.1
                                                +0.1

                                                +3.5
-1.1
                                                -1.9
-0.2
-0.2
                -0.3
                -1.3

                -0.9
                -2.5
                +2.1
                +1.1
                +2.9

                +6.1
                +0.2
                +0.2

                +3.8
                -1.5

                -0.6
                -2.1

                .-2.1
                -0.2
                -0.2
                               -0.3
                               -1.3

                               -Q.9
                               -2.5
                               +2.1
                               +1.1
                               +2.9

                               +6.1
                               +0.2
                               +0.2

                               +3.8
                                                                               -1.5
                               -2.1

                               -2.1
20C0282

-------
                                        TABLE C-10-A

                                   Coal Mining Employment
                                     (Thousand Workers)
                                        (continued)
Rockies/Northern Plains
  Colorado
  Wyoming
  Montana
  Utah
  New Mexico
  Arizona
  North Dakota
       TOTAL

Northwest
  Washington
       TOTAL

Alaska
  Alaska
       TOTAL

TOTAL WEST

TOTAL U.S.
Actual
1985
2.4
4.5
1.2
2.6
1.9
0.8
J-i
14.5
0.7
0.7
SLI
0.1
Base
1995
4.7
4.1
1.4
4.5
1.9
0.7
1.0
18.3
0.6
0.6
0.1
0.1
                                                          30 Yr/1.2 Ib. Cases
                                                         Chanee From Base 1995
30 Yr/1.2 Ib
Intrautilitv
+0.5
+0.1
-0.2
+0.3
+0.3
30 Yr/1.2 Ib
Intra. Ex- Ex
+0.4
+0.1
-0.1
+0.3
+0.3
30 Yr/1.2
Intra. Ex
+0.4
+0.1
-0.1
+0.2
+0.3
Ib
-New





+1.0.
SLI
0.1
20.3
169.9
0.1
0.1
24.0
151.0
-^—
+0.8
+2.4
+1.0
                +0.8

                +2.5
+0.9
               +0.9

               +2.6
20C0282

-------
                                        TABLE C-10-B
Northern Appalachia
  Pennsylvania
  Ohio
  Maryland
  Northern West Virginia
       TOTAL

Central Appalachia
  Southern West Virginia
  Virginia
  Eastern Kentucky
  Tennessee
       TOTAL

Southern Appalachia
  Alabama .
       TOTAL

TOTAL APPALACHIA
                                   Coal Mining Employment
                                     (Thousand Workers)
                             Actual  Base
                                   .  >000

                              22.3   17.8
                               9.0    5.3
                               0.7    0.4
                              12.8   11.7
                              44.7   35.2
23.8
13.3
29.8
                                     23.6
                                     13.2
                                     29.5
                              69.5   68.8
                                                          30 Yr/1.2 Ib.  Cases
                                                         Change From Base 2000
               30 Yr/1.2 Ib
               Intrautility

                  -2.5
                  -1.5

                  -0.4
                  -4.4
          +3.3
          +1.8
          +4.1

          +9.2
8^6
8.6
122.8
5,9
109.9
+0.6
+0.6
+5.4
                      30 Yr/1.2 Ib
                      Intra.  Ex -Ex

                          -2.6
                          -2.0
                          -5.1
                +3.7
                +2.0
                +4.5

               +10.2
                                  +0.7
                                  +0.7

                                  +5.8
                                             30 Yr/1.2 Ib
                                             Intra.  Ex-New

                                                 -3.2
                                                 -2.0

                                                 -0.4
                                                 -5.6
                                                 +3.9
                                                 +2.2
                                                 +4.9
                                                +11.1-
                                                                               +6.2
Midwest
.  Illinois
  Indiana
  Western Kentucky
       TOTAL

TOTAL MIDWEST
13.9
 5.2
-L2
26.8
                                     12.8
                                      2.1
                                     20.5
26.8   20.5
-6.0

JL2
-6.9

-6.9
                                  -6.0

                                  JL2
                                  -6.9

                                  -6.9
                                         -6.5
                                         -7.3

                                         -7.3
Central West
  Iowa
  Missouri
  Kansas
  Northern Arkansas
  Oklahoma
       TOTAL    "  -

Gulf
  Texas
  Louisiana
  Southern Arkansas
       TOTAL
 0.1
 1.1
 0.2
 0.0
 2.5
 2.4
 0.1
 0.0
 2.4
                                      0.1
                                      0.6
                                      0.2
                                      0.1
                                      0.6
                                      1.7
1.9
0.7
0.0
2.6
          -0.2
          -0.1

          JL1
          -0.4
                                  -0.2
                                  -0.1

                                  •0.1
                                  -0.4
20C0282

-------
                                       TABLE C-10-B

                                  Coal Hining Employment
                                    (Thousand Workers)
                                        (continued)
                                                          30  Yr/1.2  Ib.  Cases
                                                         Change  From Base  2000
Rockies/Northern Plains
  Colorado
  Wyoming
  Montana
  Utah
  New Mexico
  Arizona
  North Dakota
       TOTAL

Northwest
  Washington
       TOTAL

Alaska
  Alaska
       TOTAL

TOTAL WEST

TOTAL D.S.
Actual
1985
2.4
4.5
1.2
2.6
1.9
0.8
1. 1
14.5
0.7
0.7
0.1
0.1
Base
2000
5.1
3.6
1.6
4.8
2.2
0.6
0.9
18.8
0.5
0.5
P^l
0.1
30 Yr/1.2 Ib
Intrautilitv
+2.5
-
-
+0.3
+0.3
30 Yr/1.2 Ib
Intra. Ex- Ex
+2.2
+0.2
-
+0.2
+0.3
30 Yr/1.2
Intra. Ex
+2.0
+0.2
+0.1
+0.2
+0.3
Ib
-New





+3.1
0.1
0.1
20.3
169.9
0_
0
23
154
J,
.1
.7
.2
.
-
+2.7
+1.2
+2.9
                +2.5

                +1.4
+2.8
               +2.4

               +1.3
20C0282

-------
                                       TABLE C-10-C
Northern Appalachia
  Pennsylvania
  Ohio
  Maryland
  Northern West Virginia
       TOTAL

Central Appalachia
  Southern West Virginia
  Virginia
  Eastern Kentucky
  Tennessee
       TOTAL

Southern Appalachia
  Alabama
       TOTAL

TOTAL APPALACHIA

Midwest
  Illinois
  Indiana
  Western Kentucky
       TOTAL

TOTAL MIDWEST
                                   Coal Mining Employment
                                     (Thousand Workers)
 22.3   30.1
  9.0    6.7
  0.7    0.3
 12.8   17.8
 44.7   54.3
23.8
13.3
29.8
        32.5
        18.2
        40.7
 69.5   94.9
  8.6    9.4

122.8  158.6
                                                          30 Yr/1.2 Ib.  Cases
                                                         Change From Base  2010
13.9
5.2
7.7
26.8
26.8
16.6
4.2
. 8^2
29.0
29.0
-9.5
-2.2
-2.9
-14.6
-14.6
30 Yr/1.2 Ib
Intrautilitv
-8.2
-2.9
-15.2
+4.4
+2.4
+5.9
+12 . 7
il*fc
-1.6
-4.1
-9.5
-2.2
^1
-14.6
30 Yr/1.2 Ib
Intra. Ex- Ex
-7.0
-2.8
-4.0
-13.8
+3.9
+2.1
+5.3
+11.3
ii-i
-1.8
-4.3
-9.9
-1.9
-3.7
-15.5
30 Yr/1.2 Ib
Intra. Ex -New
-11.7
-3.3
-20.0
+2.3
+1.2
+3.1
+6.6
J^i
-1.9
-15.3
-8.8
-2.4
-3.4
-14.6
                                  -15.5
                                                -14.6
Central West
  Iowa
  Missouri
  Kansas
  Northern Arkansas
  Oklahoma
       TOTAL
  0.1
  1.1
  0.2
  0.0
  1.0
  2.5
        0.1
        0.4
        0.2
        0.1
        0.5
        1.4
Gulf
  Texas
  Louisiana
  Southern Arkansas
       TOTAL
  2.4
  0.1
  0^0
  2.4
        1.9
        0.7
20C0282

-------
                                        TABLE  C-10-C

                                   Coal  fining Employment
                                     (Thousand Workers)
                                        (continued)
                                                          30 Yr/1.2 Ib.  Cases
                                                         Change From Base 2010
Rockies/Northern Plains
  Colorado
  Wyoming
  Montana
  Utah
  New Mexico
  Arizona
  North Dakota
       TOTAL

Northwest
  Washington
       TOTAL

Alaska
  Alaska
       TOTAL

TOTAL WEST

TOTAL U.S.
                             Actual  Base
                                     >010
2.4
4.5
1.2
2.6
1.9
0.8
14^5

-------
tr
K  >
'« i.
   '

-------
                                        APPENDIX D

                                  BASE CASE ASSUMPTIONS


   This  appendix presents a detailed list of  1987  Interim EPA Base Case assumptions and
specifications.
06C0022
Page D-l

-------
                    INTERIM 1987 EPA BASE CASE ASSUMPTIONS
Critical Parameter
ELECTRIC UTILITY ENERGY DEMAND

U.S. Imported Crude Oil Prices
   (Early-1986 $/barrel)
Electricity Growth Rate
  (% Per Year)
 Interim  1987  EPA  Base
1990
1995
2000
2010

1987
1988
1990
1995
2000
2010
- 17.80
= 23.60
= 27.40
= 36.80

= 2.7
- 2.5
= 2.0
= 2.0
- 2.0
- 2.0
                                               1987-L990 = 2.2
                                               1991-2010 - 2.1
Total U.S. Nuclear Capacity
Nuclear Capacity Factors
Utility Capital Costs
   (Early-1986 $/Kw)
Power Plant Lifetime (Years)
Repowering/Refurbishment
   Assumptions
1990
1995
2000
2010

1990
1995
2000
2010
- 103
- 106
= 106
-  79

-  67
-  67
-  67
=  67
Coal           =    900 - 1,010
Nuclear        =  1,725-1,960
Turbine        =    275 -   315
Scrubbers, Dry =     99 -   112-
Scrubbers, Wet =    204 -   245
Coal Steam
Oil/Gas Steam
Nuclear
Oil/Gas Turbine
       60 years
       60 years
       35 years
       20 years
All coal capacity refurbishes
06C01B7
                                                    ICF Resources Incorporated

-------
                    INTERIM 1987 EPA BASE CASE ASSUMPTIONS
                                  (continued)
Critical Parameter
Coal Powerplant Heat Rates
   Over Time
Minimum Turndown Rates
Canadian Power Imports
   (billions of kwhrs)
Cogeneration (billions of Kwhrs)
FINANCIAL PARAMETERS

Tax Depreciation Life (years)
   Retrofit Pollution Control
   Others

Real Discount Races
   (% Per Year)

Real Capital Charge Rates
   Coal/Nuclear/Combined Cycle
   New Scrubbers/Particulate Equip
   Combustion Turbines
   Retrofit Scrubbers

Book Life (years)
   Coal/Nuclear/Combined Cycle
   Combustion Turbine
   Pollution Control-Retrofit
   Pollution Control-New

Input Year Dollars

Output Year Dollars

Escalation Input to Output
Dollars
Interim 1987 EPA Base

0.25% per year increase over
current levels .  After refurbish-
ment  heat  rates   are   improved
(decreased) by five percent from.
previous forecast  levels.

Coal                 35%
Oil/Gas Steam        20%
      -  68
      -  64
      -  76
      -  75

      =  85
      = 117
      = 154
      = 194
1990
1995
2000
2010

1990
1995
2000
2010
15
15
Coal Mine
Utility
 9.4%
 9.4%
11.3%
 9.0%
  30
  20
  30
  30

Early 1986

Mid 1987

1.045
            6.00%
            4.27%
06C0187
     ICF Resources Incorporated

-------
                    INTERIM 1987 EPA BASE CASE ASSUMPTIONS
                                  (continued)
Critical Parameter
NON-UTILITY COAL DEMAND

Industrial/Retail Coal Use
   (millions of tons)
Coal Exports (millions of tons)

   - - Steam Coal
   - - Metallurgical Coal Exports
Domestic Metallurgical Coal Use
   (millions of tons)
Synthetics
   (Coal Input in millions of tons)
COAL SUPPLY PARAMETERS

Coal Transportation Rates

   -- Rail


   -- Truck;  Barge
Mining Costs
   (% Annual Real Escalation)
Interim 1987 EPA Base
1990
1995
2000
2010
 87
 91
 98
137
1990
1995
2000
2010
1990
1995
2000
2010
1990
1995
2000
2010
1990
1995
2000
2010
- 24
- 46
= 67
- 67
= 49
- 53
= 61
- 65
- 37
- 35
- 32
= 29
- 6
= 6
= 6
- 6
Long-run marginal costs based on
engineering analysis.

Long-run marginal costs based on
engineering analysis.
Capital
0.0%
                                               Labor = 2%
                                               Materials =0.0%
                                               Deep Productivity - 3%
                                               Surface Productivity - 2%
06C0187
                                                    ICF Resources Incorporated

-------
                     INTERIM 1987  EPA BASE CASE ASSUMPTIONS
                                  (continued)
 Critical  Parameter
OTHER GOVERNMENTAL REGULATIONS

Federal  Leasing  Policy

Air Pollution Regulations
Interim 1987 EPA  Base-
Enough

Most  recent federal  and  state
rules, including proposed changes
in SIPs, state acid rain programs.
No changes  in limits associated
with proposed federal tall stacks
regulations.   Large industrial
boilers must scrub by  1995.
06C0187
                                                    ICF Resources Incorporated

-------