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
-------
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
-------
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
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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.
06C0078A
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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
06C0078A
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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.
06C0078A
Page 2-11
ICF Resources Incorporated
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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.
06C0078A
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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.
06C0078A
Page 2-13 ICF Resources Incorporated
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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.
05C0078A
Page 2-14
ICF .Resources Incorporated
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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 $0.3 billion cost savings associated with permitting
interstate trading (i.e., trades allowed across the 31-Eastern
states and across the 17-Western states, but not between these two
broad regions) versus intrastate trading. (While no explicit
existing-existing interstate trading case was analyzed, the annual-
ized cost savings associated with expanding trading to the inter-
state level was estimated based on the difference in costs between
intrastate and interstate trading in the existing-new trading
context. In addition, previous analyses conducted by IGF for EPA
of existing-existing interstate trading cases revealed similar cost
savings.-')
Greater trading flexibility also leads to lower cumulative capital
expenditures by utilities, generally because less scrubbers are built.
Increasing the scope of trading from the intrautility to intrastate level
is forecasted to reduce cumulative capital costs by 15 to 20 percent.
Increasing the scope of trading further to the interstate level is
forecasted to reduce cumulative capital costs (by 2010) by an additional
10 to 20 percent.
-' See, for instance, "Preliminary Analysis of 'Proxmire-Equivalent'
Reductions Allocated Across the Continental U.S. Based on Total 1980
Utility Sulfur Dioxide Emissions from SIP Powerplants," July 1, 1987.
06COO/8A
Page 2-is icF Resources Incorporated
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EFFECTS OF GREATER GEOGRAPHIC TRADING FLEXIBILITY:
PRESENT VALUE OF COSTS
Increase in the
Present Value of
Costs over the
1987-2010
Period above
Base Case Levels
(billions of 1987$)
Existing -
Existing
Intrautility
Existing -
Existing
Intrastate
Exist! ng-
Existing
Intrautility
Existing -
Existing
Intrastate
Proxmire
Cases
30Yr/1.2
Cases
06C0078A
Page 2-16
ICF Resources Incorporated
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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.
06C0078A
Page 2-17 ICF Resources Incorporated
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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
OEC0078A
Page 2-18
ICF Resources Incorporated
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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 $25.8 billion
relative to the Base Case with no trades.
In 1995 and 2000, the value of existing-new trades is less significant
than in 2010, reflecting fewer new sources being able to take advantage
of existing-new trades. By 1995, only a few new coal plants subject to
current NSPS regulations are forecast to be constructed (beyond those
plants already partially completed). By 2000, about 27 gigawatts of new
coal plants are forecast to be built (beyond those already partially
completed), versus about 225 gigawatts of new coal capacity in 2010.
-1 For a discussion of additonal technology-based requirements associated with
New Source Review (i.e, Best Available Control Technology and Lowest
Achievable Emission Rate), and how thej relate to the analysis of existing-
new trading, see Chapter Three.
06C0078A
Page 2-19 ICF Resources Incorporated
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EFFECTS OF EXISTING-NEW TRADING:
PRESENT VALUE OF COSTS
Increase in the
Present Value of
Costs over the
1987-2010
Period above
Base Case Levels
(billions of 1987$)
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
Page 2-20
ICF Resources Incorporated
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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.
06C0078A
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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
Page 2-22
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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
Pag. 2-24
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.
06C0078A
Paso 2-25 ICF Resources Incorporated
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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
Page 2-26
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
Page 2-27 ICF Resources Incorporated
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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
Page 2-28 ICF Resources Incorporated
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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.
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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.
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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%
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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
06C017A
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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.
06C0174
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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.
06C0174
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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.
06C0174
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ICF Resources Incorporated
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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.
06C0174
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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.
OEC0174
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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.
06C0174
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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.
oecom
Page 3-25 ICF Resources Incorporated
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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.
06C0174
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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.
06C0174
Page 3-28 ICF Resources Incorporated
-------
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.
06C0174
Pa8e 3-29 ICF Resources Incorporated
-------
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).
06C0174
Page 3-30 ICF Resources Incorporated
-------
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.
06C0174
Page 3-31 ICF Resources Incorporated
-------
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.
o scorn
Page 3-32 ICF Resources Incorporated
-------
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.
06C0174
Page 3-33 ICF Resources Incorporated
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n
L!
in
rt>
n
B
M
-------
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
-------
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.
-------
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.
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
------- |