AN ECONOMIC ANALYSIS OF HR-4567
THE ACID DEPOSITION CONTROL ACT OF 1986
Prepared for
The Environmental Protection Agency
By
ICF Incorporated
August 1986
ICF INCORPORATED International Square
1850 K Street, Northwest, Washington, D. C. 20006
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AN ECONOMIC ANALYSIS OF HR-4567:
THE ACID DEPOSITION CONTROL ACT OF 1986
PREPARED FOR
THE ENVIRONMENTAL PROTECTION AGENCY
BY
ICF INCORPORATED
AUGUST 1986
-------
PREFACE
This report presents the findings of an analysis performed by ICF,
Incorporated for the Environmental Protection Agency (EPA). 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 or other agencies of
the U.S. government.
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TABLE OF CONTENTS
INTRODUCTION
EXECUTIVE SUMMARY
CHAPTER ONE: SUMMARY OF FINDINGS
CHAPTER TWO: UTILITY COMPLIANCE STRATEGIES AND COSTS
CHAPTER THREE: RATE IMPACTS, SUBSIDIES AND TAXES
CHAPTER FOUR: CAVEATS AND UNCERTAINTIES
APPENDIX A: HR-4567 FORECASTS - 1995
APPENDIX B: HR-4567 FORECASTS - 2000
APPENDIX C: SUMMARY MEASURES AND CEUM DEMAND
AND SUPPLY REGIONS
APPENDIX D: DETAILED BASE CASE ASSUMPTIONS
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INTRODUCTION
This report summarizes findings of an analysis of the version of HR-4567,
the Acid Deposition Control Act of 1986, that was reported out of the
Subcommittee on Health and the Environment (of the House Energy and Commerce
Committee) on May 23, 1986. This bill requires sulfur dioxide and nitrogen
oxide emission reductions from several sectors including electric utilities,
industrial boilers,, industrial processes and motor vehicles. For this report,
the impacts of HR-4567 on sectors other than the electric utility sector were
not analyzed. The report also analyzes electric utility rate subsidies
permitted under the bill for statewide average rate impacts greater than ten
percent. In addition, the report analyzes funding for the subsidies based on
a tax on fossil electricity generation and power imports between 1989 and 1996.
Emission reductions at electric utilities are required under HR-4567
beginning in 1993 in Phase One. Phase One mandates that utilities meet a
statewide annual average sulfur dioxide emission limit for fossil fuels of 2.0
lbs/MMBtu. Phase Two beginning in 1997 requires utilities to meet a tighter
sulfur dioxide statewide annual average limit for fossil fuels of 1.2
lbs/MMBtu and also requires utilities to meet a statewide average annual
nitrogen oxide limit for fossil fuels of 0.6 lbs/MMBtu. NSPS nitrogen oxide
limits for powerplants that begin construction after the bill is passed are
tightened to 0.4 lbs/MMBtu for bituminous coal-fired powerplants and to 0.35
lbs./MMBtu for subbituminous coal-fired powerplants.
States are given considerable flexibility in implementing the bill.
However, if states fail to develop an implementation plan or if their plan is
rejected by the Administrator of EPA, individual unit limits are imposed
automatically ("default limits"). These limits are numerically the same as
the statewide average limits and for some utility powerplant units are very
costly to meet.
This analysis of HR-4567 examines two cases with different assumptions
regarding how the bill would be implemented and a third case which assumes a
higher cost implementation plan not specifically stipulated by the bill. The
first two cases were chosen because they establish reasonable upper and lower
bound estimates of possible utility cost and emission impacts. In the Low
Cost case, states are assumed to allocate reductions to utilities and utility
-powerplants to minimize compliance costs. In the Default case, individual
uti~Mty_powerplant unit limits are assumed to be imposed. In addition, a
third case -- the High Cost Default case -- was analyzed. This case is a less
likely outcome than the Low Cost and Default cases and assumes that the
tighter individual limits required under Phase Two of the bill would also
apply (though not required by the bill) in Phase One. This case reflects the
possibility that the same limits would apply or be met in Phases One and Two.
This could occur owing to administrative ease and/or the possibility that
utilities would avoid shifting coal suppliers after only a few years of
compliance in Phase One.
Chapter One summarizes the key findings of this analysis including
forecasts of electric utility sulfur dioxide and nitrogen oxide emissions,
costs, compliance strategies, coal production and coal mining employment,
electricity rate impacts, subsidies and taxes.
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-2-
Chapter Two discusses forecasts of utility compliance strategies on a
national basis and for Pennsylvania in the Low Cost case in 2000. This
discussion explains utility compliance decisions in light of the relative cost
effectiveness of these options.
Chapter Three describes the measurement of utility rate impacts, and
forecasts of subsidies and taxes.
Chapter Four discusses some of the key assumptions, caveats and
uncertainties associated with this analysis. This chapter also contains a
detailed discussion of assumptions regarding utility nitrogen oxide emission
controls.
Appendices A and B contain detailed forecasts on a national and regional
basis for 1995 and 2000 of utility emissions, costs, compliance decisions,
utility fuel consumption, coal production and mining employment, and statewide
average electricity rate increases.
Appendix C describes summary measures used in this report and contains
maps of demand and supply regions in ICF's Coal and Electric Utilities Model
(CEUM), the principal tool used in this analysis. Appendix D presents the EPA
Base case assumptions.
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Executive Summary
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EXECUTIVE SUMMARY
HR-4567, the Acid Deposition Control Act of 1986, would reduce electric
utility sulfur dioxide and nitrogen oxide emissions in two phases beginning in
1993 and 1997. HR-4567 also would reduce sulfur dioxide and nitrogen oxide
emissions from the industrial sectors and nitrogen oxide emissions from motor
vehicles, but only the utility provisions of HR-4567 were analyzed for this
report. HR-4567 differs from some other recent legislative emission reduction
alternatives in that:
Sulfur dioxide and nitrogen oxide emission rate
targets are required to be met rather than specific
tonnage reduction requirements.
States have considerable flexibility in developing
implementation plans for compliance with utility
emission limits. However, if the State fails to
submit a plan or if the plan is not approved by the
EPA Administrator, individual utility powerplant unit
limits are imposed automatically ("default limits").
Significant nitrogen oxide emission reductions are
also required from utilities. The bill also contains
default provisions mandating strict individual unit
nitrogen oxide emission limits.
Utility residential rate impacts in excess of ten
percent are to be subsidized with funding for the
subsidy to be provided by a tax on fossil electricity
generation and power imports. In order to qualify for
subsidies, rate impacts must be calculated in a manner
which represents a significant departure from current
electric rate-making.
These points are developed in detail and forecasts of utility emissions,
costs, rate impacts, coal production and mining employment are presented in
the following report. A few brief summary comments are provided on the
following pages.
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S-2
CASES EXAMINED
Two cases (Low Cost and Default) were examined with different assumptions
regarding HR-4567's implementation. These two scenarios were analyzed because
they represent likely upper and lower bounds on the bill's emission and
utility cost impacts. A third case the High Cost Defaultwas also examined
and reflects less likely implementation assumptionsthat tighter limits than
stipulated under the Bill would be met in Phase One. The cases examined are
described below:
Low Cost -- Utilities are required to meet the
emission limits shown below on a statewide average
annual basis for fossil fuels.
Phase One (1995): S02: 2.0 lbs./MMBtu
NO : No Limit
x
Phase Two (2000): S02: 1.2 lbs./MMBtu
N0x: 0.6 lbs./MMBtu
In meeting the average statewide emission rate
requirements, states are assumed to allocate
reductions to utilities and utility powerplants in the
least cost manner possible. Also, NSPS nitrogen oxide
emission standards are tightened for bituminous and
subbituminous coal powerplants that begin construction
after the bill's passage to 0.4 and 0.35 lbs./MMBtu,
respectively.
For purposes of this analysis, Phase One was assumed
to begin in 1995 instead of 1993 and Phase Two was
assumed to begin in 2000 instead of 1997. This was
done to simplify the analysis since EPA's base case
forecasts already existed for 1995 and 2000.
Default -- Individual utility powerplant units
are assumed to meet the Phase One and Phase Two
emission limits for sulfur dioxide and nitrogen
oxides. No statewide or any other averaging across
powerplant units is allowed. As in the Low Cost case,
NSPS nitrogen oxide limits are tightened.
High Cost Default -- Sane as the Default case
except in Phase One the sulfur dioxide individual unit
limit is assumed to be 1.2 lbs./MMBtu. This case
reflects the possibility that (1) states would require
the 1.2 lb. limit to be met in Phase One in addition
to Phase Two of the program to simplify the
administration of the program, and/or (2) many
utilities might prefer to meet only one emission
limit, rather than having to shift coal suppliers
again within only a few years.
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S-3
UTILITY S02 REDUCTIONS UNDER HR-4567
12
10-
Million
Tons of
Reductions
Relative to
the Base
Case
6-
2-
Low
Cost
7.3
10.1
ฆ
ฆm.
w
%ssss
%S!'<
K"Z<-
v>. %,
Default
High Cost
Default
8.1
Low
Cost
10.4
Default
Cases
1995
2000
The forecasted amount of utility sulfur dioxide emission reductions
depends on the bill's implementation:
In Phase One, in 1995, emissions are reduced from 4.1 to 7.3
million tons and as high as 10.1 million tons under the less
likely, High Cost Default Case.
In Phase Two, in 2000, emissions are reduced 8.1 to 10.4 million
tons.
More reductions occur in the Default cases because every powerplant unit
must meet the individual limits. This is unlike the Low Cost case which
allows averaging across plants and units in a given state. As such, in
the Default cases, emissions from powerplants such as oil and gas steam
units or scrubbed plants which already emit at less than the required
emission limit cannot be averaged with emissions from other plants to
achieve the required emission rate targets.
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S-4
UTILITY NITROGEN OXIDE EMISSION REDUCTIONS -- 2000
Million
Tons
1-
2.7
2.0
'''
- '/vv- *
. vv ; -
v
N ฆ-''!,/ - -
''-v.-.'ฆ>/.'v.'."
Low
Cost
Default
Cases
In Phase Two, utilities are also required to reduce nitrogen oxide
emissions. The forecasted amount of reductions ranges from 2.0 to 2.7
million tons depending on the bill's implementation. More reductions are
achieved in the Default cases because emissions cannot be averaged across
powerplants to meet the reduction requirements. In other words, no credit
is given for powerplants which emit at less than the required emission
limit.
Of the total reductions shown above, about 0.3 million tons are
associated with tighter NSPS NOx limits under the bill.
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S-5
CHANGES IN UTILITY ANNUAL CDSTS -- 2000
In 2000, utility annual costs increase $2.8-7.0 billion. The Default
cases are much more costly than the Low Cost case oecause:
More sulfur dioxide reductions are required in the Default cases.
The marginal costs of incremental emission reductions under the
Default cases relative to the Low Cost case are higher.
The Default cases impose sulfur dioxide and nitrogen oxide
limits on individual units which for sorre coal-fired powerplant
units, especially those with cyclones and uet bottom boilers,
are very costly to meet.
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S-6
CHANGES IN COAL MINING EMPLOYMENT -- LOW COST CASE -- 2000
- SELECTED STATES
40
30
20
Changes
in Job Slots
from 1984
(Thousands
of Job 10
Slots)
0
-10
Only a few states experience net decreases in the number of coal mining
job slots available relative to current (1984) levels: Ohio, Illinois,
and Indiana. These states mine primarily high sulfur coals and lose
markets as utilities shift to lower sulfur coals.
Virtually all states are forecast to increase the number of coal mining
job slots relative to 1984 in the Base case in 2000. Most states are
forecast to experience gains in coal mining job slots relative to 1984
under the Low Cost case. This reflects expected growth in coal production
between 1984 and 2000 in spite of the emission reduction requirements.
The number of coal mining job slots is estimated to be about the same
nationally under the Low Cost case as in the Base case in 2000.
Net increases in coal mining job slots mask decreases in certain
substate regions. For example, overall Kentucky coal mining employment
increases relative to 1984 levels under the Low Cost case. However, in
the western section of the state where primarily higher sulfur coals are
mined, the number of job slots would decrease under the Default case.
''tKW'S.
-6.1
-2.4
-0.9
7.9
ฆ'SSSS;
14.2
W%%
'/>, /. v>.
16.1
''t
OH
IL
IN
PA
WV
KY
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S-7
PRESENT VALUE OF SUBSIDIES
Billions
of Early
1985 Dollars
50
40
30-
20
10
0-1
3.7
2.4
SSSi
Statewide Utility
Levelized Traditional1
Low Cost
18.4
H
'*1,
m
Statewide Utility
Levelized Traditional1
High Cost Default
Note that the bill stipulate* that subsidies would nniy be provided if rate
Impacts were calculated on a "statewide levelized" basis
HR-4567 provides for subsidies if rate increases exceed ten percent.
The bill also specifies that cost impacts be spread across the state and
capital charges be levelized over time (i.e. be passed through to rate
payers in equal increments referred to above as "statewide levelized").
Under the provisions of the bill, no subsidies are required in the Low
Cost case since no states' rates increase more than ten percent. Under
the High Cost Default case, the present value of subsidies is ง2.4 billion.
The present value of subsidies under the Default case would be less
equaing $2.0 billion. It is important to note however, that it is
unlikely that a state which defaults under the bill would be considered
eligible for subsidies.
If utilities could receive subsidies for rate increases calculated using
current utility rate-making procedures referred to above as "utility
traditional" as opposed to being levelized and spread across the state as
stipulated by the bill, much higher subsidies would be required. In the
Low Cost case, the present value of subsidies would be $3.7 billion (in
comparison to the present value of total program costs for Low Cost case
of $28.7 billion) and in the High Cost Default case, the present value of
subsidies would be $18.4 billion (in comparison to the present value of
total program costs of $81.6 billion). (For more discussion on the rate
impacts, subsidies and taxes, See Chapter 3.)
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S-8
REQUIRED
ELECTRICITY
TAXES
1989-1996
GENERATION
2-
Nominal
Mills/Kwh
1-
0.5
QJ1.
0
Statewide Utility
Levelized Traditional1
Low Cost
0.29
2.25
%
mm
sm
it
'Wis
Statewide Utility
Levelized Traditional1
High Cost Default
1 Note that the bill stipulates that subsidies and thus taxes would only
be required if statewide levelized ratemaking were employed.
HR-4567 provides for a tax on utility fossil electricity generation and
power imports beginning in 1989 and ending in 1996 in order to provide
funding for the subsidies. The bill stipulates that this tax cannot
exceed 0.5 mills per kilowatt hour.
This tax would be more than adequate to fully fund the subsidies if
statewide levelized (i.e., the rate-making practice required by the bill
in order to receive subsidies) rate impacts were subsidized in either the
Low Cost, Default or High Cost Default cases. An 0.5 mill per kilowatt
hour tax would also be more than enough to fund subsidies in the Low Cost
case even if utility by utility rate impacts were subsidized. The tax,
however, would not generate enough funds if utility traditional rate
impacts above 10 percent were subsidized under a High Cost Default
scenario. (Note that the bill as currently written does not require
subsidies on this basis). Although the required taxes would be lower
under the Default case than under the High Cost Default case (which
represents a likely upper bound on costs), they would still be well above
0.5 mills/Kwh and would probably be about 1.5 to 1.8 mills/Kwh.
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Chapter One
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CHAPTER ONE
SUMMARY OF FINDINGS
This chapter summarizes the key findings of an analysis of HR-4567, the
Acid Deposition Control Act of 1986, performed by ICF for the Environmental
Protection Agency. The scope of the analysis was limited to the bill's
provisions concerning the electric utility industry. It should be emphasized
that the bill also has provisions affecting other industrial sectors and motor
vehicles that could also have significant emission and cost impacts. However,
based on EPA's assessment, these are not expected to be large relative to the
utility sector impacts.
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1-2
SUMMARY DESCRIPTION OF HR-4567
ELECTRIC UTILITY PROVISIONS
Sector
Electric
Utility
Phase 1:
Pollutant Source 1993 Requirement
S02 All 2.0 lb. Annual State-
wide Average Rate For
Fossil Fuels
Phase 2:
1997 Requirement
1.2 lb. Annual State-
wide Average Rate For
Fossil Fuels
Default: 2.0 lb.
Individual Unit Limit
Default: 1.2 lb.
Individual Unit Limit
NOx
All
None
0.6 lb. Annual State-
wide Average Rate
for Fossil Fuels
Default: 0.6 lb.
Individual Unit
Limit.
NSPS* 0.4-Bituminous
0.35-Subbituminous
Same
* NSPS plants "commencing construction" after the bill's passage
(i.e. "commencing construction" is generally defined as the date on
which the boiler is ordered)
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1-3
SUMMARY DESCRIPTION OF HR-4567 -- ELECTRIC UTILITY PROVISIONS
HR-4567, the Acid Deposition Control Act of 1986, seeks to control acid
rain by reducing emissions of sulfur dioxide, nitrogen oxide and other
pollutants. The required emission reductions are allocated to the electric
utility, industry boiler, industrial process sectors and to motor vehicles.
The bill also contains provisions that mitigate the electric utility rate
impacts associated with the costs of complying with the bill's reduction
requirements. The key provisions of the bill are summarized below:
Electric Utility
S02 Emission Limits -- The bill requires that
beginning in 1993, utility annual statewide average
sulfur dioxide emission rates for all fossil fuels
must be at or below 2.0 lbs per MMBtu. Beginning in
1997, utility annual statewide average sulfur dioxide
emission rates must be at or below 1.2 lbs. per MMBtu.
NOx Emission Limits -- The bill also requires
that beginning in 1997, utility annual statewide
average nitrogen oxide emission rates for all fossil
fuels must be at or below 0.6 lbs. per MMBtu.
Default Limits -- If a state is unable to develop
an implementation plan for meeting these limits or if
the plan is rejected by the Administrator of the EPA,
then the bill's default provisions would apply. In
such a case, each utility powerplant unit would have
to meet the sulfur dioxide and nitrogen oxide limits
described above.1-1
NSPS Revisions for NOx Emissions -- The bill
modifies the New Source Performance Standards (NSPS)
such that NOx emission limits for new utility power-
plants burning bituminous coals would be tightened
from 0.6 to 0.4 lbs./MMBtu. For new utility power-
plants burning subbituminous coals, NOx emission
limits would be reduced from 0.5 to 0.35 lbs./MMBtu.
These limits would apply to plants that "commence
construction" after the bill is passed.
Subsidies -- The bill provides subsidies in order
to limit rate increases to ten percent above those
rates that would have been applicable in the absence
of the bill. In order to qualify, states must
"levelize" capital charges over time (pass through to
ratepayers in equal increments) and spread impacts
across the state.
Tax -- HR-4567 directs EPA to impose a tax from
1989-1996 on fossil generation and electricity imports
to provide funding for the electricity rate subsidies.
The tax cannot exceed 0.5 mills per kilowatt hour.
lJNote since powerplants generally have more than one unit, these limits
cannot be averaged across a powerplant.
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1-4
SUMMARY DESCRIPTION OF HR-4567
INDUSTRIAL AND OTHER SECTOR IMPACTS
Sector
Industrial
Pollutant Source
S02
Industrial
Boiler
Phase 1:
1993 Requirement
None
Phase 2:
1997 Requirement
1.2 lb. Annual State-
wide Average For
Fossil Fuels
Default: 1.2 lb.
Individual Unit Limit
S02
Industrial
Process
None
To Be Determined by
EPA Administrator
NOx
Industrial
Boiler
None
0.6 lb. Annual State-
wide Average for
Fossil Fuels
Default: 0.6 lb.
Individual Unit
Limit.
Industrial
Process
None
To Be Determined by
EPA Administrator
Motor Vehicle Standards
Motor
NOx Passenger Cars
0.7 gpm a/
Model
Year
1989
and
After
Gasoline Trucks
1.2 gpm
Model
Year
1988
and
(<8,500 lbs)
After
Gasoline Trucks
1.7g/Bhp-hr b/
Mode 1
Year
1988
and
(8,500-14,000lbs)
After
Diesel Trucks
1.2 gpm c/
Model
Year
1988
and
(<6,000 lbs)
After
Diesel Trucks
1.7/gpm c/
Model
Year
1988
and
(6-8,5001bs)
After
Hydrocarbons Trucks (ฃ6,000
lbs) 0.41 gpm
Model
Year
1990
and After
Trucks (6-8,500
lbs) 0.53 gpm
Model
Year
1990
and
After
a/ grams per mile
b/ grams per brake horsepower hour
c/ Represents a reaffirmation of current standards
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1-5
SUMMARY DESCRIPTION OF HR-4567 - INDUSTRIAL AND OTHER SECTOR IMPACTS
In addition to electric utility requirements, the bill requires reductions
from other sectors. These were not examined for this analysis. A description
of these provisions is provided below:
Industrial Boiler -- The bill mandates that starting
in 1997, statewide annual average sulfur dioxide and
nitrogen oxide emission rates for fossil fuels must be
at 1.2 lbs. and 0.6 lbs., respectively. These rates
are the same as required for the electric utility
industry. However, there is no averaging permitted
between industrial boilers and utilities. There is
also a default provision which would apply if states
fail to submit or fail to have their implementation
plans approved by the Administrator of EPA. In such a
case, every fossil fuel steam generating unit would
have to meet these limits.
Industrial Process -- Starting in 1997, the bill
requires process emission reductions that are
economical and technically feasible. The EPA
administrator will determine a minimum amount of such
reductions.
Motor Vehicles -- The bill schedules the tightening
of nitrogen oxide emission limits for new passenger
cars (model year 1989 and after) and gasoline and
diesel trucks (model year 1988 and after). The limits
are based on current California nitrogen oxide
standards. It also sets standards for hydrocarbon
emission limits for certain types of trucks and directs
EPA to issue regulations to lower the sulfur content
of diesel fuel to 0.05 percent by 1989. For certain
classes of vehicles (i.e., diesel trucks), current EPA
regulations are assumed to remain in effect.
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1-6
IMPLEMENTATION OF HR-4567 -- UTILITY SECTOR
Implementation
Least Cost-State
Bas is
Least Cost-Utility
Basis
Least Cost-Local
Coal Protection
Default 1.2 lb
Case
Analyzed
"Low Cost"
No
No
Default 2.0/1.21b "Default"
"High Cost
Default"
Attributes Costs
Reductions Allocated Low
On Statewide Basis
To Minimize Costs
Reductions Allocated
on Utility System
Basis to Minimize
Costs
Reductions Allocated
to Minimize Costs
Subject to Scrubbing
Requirements to Protect
Local Coal Production
Individual Unit S02
Limits of 2.0 lbs.
in 1995 and 1.2 lbs.
in 2000
Individual Unit S02 High
Limits of 1.2 lbs
in 1995 and 2000
Administration
and Enforcement
More
Difficult
Less
Difficult
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1-7
IMPLEMENTATION OF HR-4567 -- UTILITY SECTOR
Under the bill's provisions, there are a variety of possible plans for
meeting the utility reduction requirements. In order to demonstrate the
sensitivity of emission, cost, coal production and fuel use forecasts to
implementation assumptions and to identify likely upper and lower bounds for
the cost estimates, two cases were analyzed -- the Low Cost and the Default
cases. A third case, the High Cost Default was also examined and reflects
less likely implementation assumptions -- that tighter limits than stipulated
under the bill would be met in Phase One. Other implementation schemes
noted on page 1-6 such as local coal protection were not analyzed. The three
cases that were analyzed are discussed below.
Low Cost -- In this case, states are assumed to
allocate reductions to utilities and utility
powerplants in the least cost manner possible, in
meeting the statewide average emission rate
requirements in Phase I and Phase II of the bill.
These requirements are identical to those noted on
pages 1-2 and 1-3 except that for this analysis Phase
I requirements were assessed in 1995 (not 1993) and
Phase II was examined in 2000 (not 1997). It was also
assumed that States would phase these reductions in
such a manner such that no powerplant would be
required to switch compliance strategies between Phase
One and Phase Two (i.e., in Phase One, a plant would
either be required to meet its eventual Phase Two
limit or continue to meet its current SIP).
Default -- This case assumes that states either
do not meet compliance schedules under the bill and
thus the default provisions of the bill apply or that
the default provisions are viewed by states as an
easier to administer, albeit a high cost option, for
meeting the bill's requirements. As such, every
utility powerplant unit is required to meet annual
sulfur dioxide emission limits of 2.0 and 1.2
lbs./MMBtu in 1995 and 2000, respectively and a
nitrogen oxide emission limit of 0.6 lbs./MMBtu in
2000. Similar to the Low Cost case, NSPS NOx emission
limits are also tightened.
High Cost Default -- This case is the same as the
previous "default" case except that in 1995 all utility
powerplants are required to meet a 1.2 lb. limit
rather than a 2.0 lb. limit. This case reflects the
possibility that states would require the 1.2 lb.
limit to be met in Phase One as well as Phase Two of
the program owning to ease of administration, coupled
with the possibility that utilities might prefer to
meet only one compliance plan, rather than having to
shift coal suppliers again within only a few years.
Note, however, that there may be difficulties in
meeting the 1.2 lb. limit at each plant in Phase One
by 1993, given existing scrubber manufacturing
constraints, and other potential near term bottlenecks.
See Chapter Four for further discussion.
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1-8
FORECASTED UTILITY S02 EMISSIONS
AND EMISSION REDUCTIONS
yซar
12-
Million
Tons of
Reductions
Relative to
the Base
Case
10-
8-
6-
4-
2-
0-L
4.1
Low
Cost
7.3
'h. V.ฆ'
A'V%%
10.1
sx?
$fa
'A%X%%
\%SSfr
w#
SSSSfr
SX*t%
SS^i,
Default
High Cost
Default
8.1
10.4
%
":v
ft
Low
Cost
Default
Cases
1995
2000
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1-9
FORECASTED UTILITY S02 EMISSIONS
AND EMISSION REDUCTIONS
In the EPA Base case, S02 emissions are forecasted to increase by about
three million tons by 2000 from 1980 levels. This reflects emissions from
new powerplants and increased utilization of existing coal powerplants.
HR-4567 results in different levels of reduction in sulfur dioxide
emissions in 1995 and 2000 depending on the implementation of the bill:
In the Low Cost case, less emission reductions are required than
under the Default cases because states and/or utilities are
permitted to meet the 2.0 lb. and 1.2 lb. emission rates in 1995
and 2000, respectively, on a statewide average. This permits
states to average emission rates from powerplants already below
a 2.0 lb. limit in 1995 or a 1.2 lb. limit in 2000 (such as gas
plants or new scrubbed powerplants) with other plants. In the
default cases, however, each individual powerplant unit must
meet a 2.0 lb. or 1.2 lb. limit and no credit is provided for
powerplants already required to emit or already emitting below
these levels.
In the Default case, less reductions occur in 1995 than in the
High Cost Default because of the tighter 1.2 lb. limit imposed
in 1995 in the High Cost Default case. In 2000, since all
powerplants are required to meet a 1.2 lb. limit under both
cases there is no difference in emission reductions.
As noted before, this analysis assumed that Phase I begins in 1995
rather than 1993 and Phase II begins in 2000 rather than 1997. If KR-4567
requirements are met in 1993 and 1997 reductions would occur earlier than
shown in the graph.
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1-10
FORECASTED UTILITY NOx EMISSIONS
AND EMISSION REDUCTIONS
3-
Million
Tons of
Reduction
Below
2000 Base
Case
Levels
2.0
sS&S&SSS, ฆ
r, V/. f'
Low
Cost
2.7
w\wi^
%X'".
> VfeWW>
Default
Cases
ICF
INCORPORATED
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1-11
FORECASTED UTILITY NOx EMISSIONS
AND EMISSION REDUCTIONS
NOx emissions are forecast to increase about 3 million tons between 1980
and 2000 in the EPA Base case, with nearly all the increase associated
with emissions from new coal-fired powerplants.
In the Low Cost case, electric utility NOx emissions are forecast to
decrease 2 million tons in 2000 as a result of the 0.6 lb. NOx/MMBtu
statewide average emission limit and the tighter NSPS NOx limits required
under HR-4567.
About 1.7 million tons of reductions are associated with
utilities retrofiting NOx combustion controls on existing plants
such as distributed mixing burners on existing wall-fired coal
units and enriched fireball technology on tangentially-fired
coal units.
An additional 0.3 million tons of reductions are forecast due to
tightened NSPS NOx limits which are also assumed to be achieved
through combustion modifications.
In the Default cases, total NOx reductions are forecast to be 2.7
million tons or 0.7 million tons greater than in the Low Cost case. This
occurs because every utility powerplant unit must meet the 0.6 lb. limit
and thus, in contrast to the Low Cost case, states would not receive
credit for powerplants already emitting below 0.6 in the Base case (such
as oil and gas plants).
About 2.2 million tons of reductions are forecast to come from
existing (pre-NSPS) plants.
About 0.5 million tons of reductions are forecast to come from
new plants. This not only includes reductions from NSPS Subpart
Da sources1-1 due to the tighter 0.4/0.35 lb. limits, but also
includes NSPS Subpart D2J sources which currently must meet a
0.7 lb. limit, but under the Default would have to meet a 0.6
lb. limit.
1JSources required to meet tht 1979 revised NSPS (0.6 lbs. NOx per
million Btu for bituminous, coals).
2JSources required to meet the 1971 NSPS (0.7 lbs. NOx per million Btu
for bituminous coals).
ICF INCORPORATED
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1-12
TOTAL UTILITY ANNUAL COSTS -- 1995 (PHASE ONE) AND 2000 (PHASE TWO)
1995
.8
7
6
Billions of 5
Early 1985
Dollars
4
3
2
1
0
5.6
Low Cost Default High Cost
Default
2000
Billions of
Early 1985
Dollars
7.0
7.0
-
'*'X*
-------
1-13
TOTAL UTILITY ANNUAL COSTS -- 1995 (PHASE ONE) AND 2000 (PHASE TWO)
In 1995 under Phase One of the bill, total utility annual costs range
between $0.8 and $5.6 billion depending on the bill's implementation.
Costs are $3.0 billion more in the Default case relative to the Low Cost
case because:
Total emission reductions are almost double (7.3 million tons of
reduction versus 4.1 million tons of reductions).
Since there are more reductions, the marginal and average costs per
ton of sulfur dioxide removed are higher. This is because
incremental emission reductions are more expensive as utilities use
up the least cost reduction strategies first in meeting lower levels
of reduction requirements.
The Default case requires each unit to meet an emission limit
regardless of the costs of compliance. The Low Cost case assumes
reductions will be allocated in a least cost manner such that the
most cost effective reductions will occur.
In 1995, under Phase One, costs are significantly higher under the High
Cost Default than the Default case because of the tighter emission limits
(1.2 lb. versus 2.0 lb.) and accordingly the greater level of reductions
(10.1 versus 7.3 million tons).
Under Phase Two of the bill in 2000, annual costs in the Low Cost case
are significantly higher at $2.8 billion than in Phase One. This reflects:
NOx controls, which are required in 2000 but not in 1995,
increase costs by $0.3 billion,
Required S02 emission reductions are much greater (8.1 million
tons in 2000 vs. 4.1 million tons in 1995). As a result, costs
are disproportionately higher because the marginal costs of
reduction are much higher at 8 million tons than at 4 million
tons.
The costs of the Default case and High Cost Default in 2000 reach $7.0
billion. This is because of:
High levels of required sulfur dioxide emission reductions.
NOx controls which add $1.5 billion in costs. NOx control costs
are high because the 0.6 lb. nitrogen oxide limit cannot be met
using conventional NOx controls at certain powerplants such as
cyclones and wet bottom pulverizers. These powerplants are
assumed to retrofit Selective Catalytic Reduction (SCR) systems,
which are more expensive than conventional NOx controls. SCR
costs account for $1.1 billion of the total nitrogen oxide
control costs of $1.5 billion. The costs of SCR are very
uncertain because the technology has not been demonstrated on
cyclone and wet bottom boilers. Also, for wet bottom boilers,
it is possible that reburning technology could be used in the
future at lower cost than SCR to achieve the same emission
limit. A fuller discussion of SCR issues is found in Chapter
Four.
ICF INCORPORATED
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1-14
TOTAL UTILITY ANNUAL S02 AND NOx CONTROL COSTS
PHASE TWO-2000
Billions of 5
Early 1985
Dollars
4
Low Cost
Default
High Cost
Default
] O & M
E3 Fuel
I Capital
PRESENT VALUE OF UTILITY ANNUALIZED COSTS
Millions of
Early 1985
Dollars
90
80
70
60
50
40
30
20-
10-
0-
81.6
76.1
ฆ. %. %. . v
, <, k
i
Low Cost
Default
High Cost
Default
ICF INCORPORATED
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1-15
TOTAL UTILITY S02 AND NOx ANNUALIZED COSTS
Capital, O&M, and fuel costs are all significantly higher in the Default
case than the Low Cost case in 2000:
Operation and maintenance costs are about 4 times as large reflecting
(1) greater use of SCR (39.5 Gw versus 5.7 Gw in the Low Cost case)
which has high O&M costs due to the high cost of the catalyst and (2)
greater use of retrofit scrubbers (40-51.4 Gw in the Default cases
versus 4.1 Gw in the Low Cost case.)
Capital costs are almost three times as large mostly due to more
retrofit scrubbing and SCR in the Default cases. The difference in
capital costs is less than for O&M because SCR systems are less
capital intensive than scrubbers.
Fuel costs are only about twice as large, which is a smaller increase
relative to the proportionately large increase in operation and
maintenance and capital costs. This is because in the Default cases
proportionally more scrubbers are used and proportionately less coal
switching is used to meet the reduction requirements.
The present value of costs in the Default cases are almost three times
the amount of the Low Cost case. This reflects the higher annual costs of
the Default cases. Importantly, the calculation of the prevent value of
costs was based on other conservative assumption that annualized costs
from 2001-2029 would not decline from 2000 levels, since no analysis of
later years was conducted. For further discussion, see Chapter 3.
Note that if the bill is assumed to require reductions starting in 1993
and 1997 rather than 1995 and 2000 as assumed by EPA, then the present
value of costs in all cases would be approximately ten percent higher.
ICF INCORPORATED
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1-16
UTILITY S02 REDUCTION STRATEGIES - 2000
(Million Tons)
6.7
(83%)
(1%)
Low Cost
Total Reductions: 8.1 Million Tons
High Cost
Default
Total Reductions: 10.4 Million Tons
IX'1 Fuel Switching
[111 Utilization Shifts
[ I Oil & Residual Fuel Shits
| Retrofit Scubbing
ICF INCORPORATED
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1-17
UTILITY S02 REDUCTION STRATEGIES - 2000
There is significantly more retrofit scrubbing in the Default cases
(41-51 Gw) than in the Low Cost case (4 Gw). Retrofit scrubbing accounts
for 36 percent of total emission reductions in the High Cost Default case
in 2000 (and only a slightly lower percentage in the Default case) versus
only 4 percent in the Low Cost case. More retrofit scrubbing occurs in
the Default cases because:
More sulfur dioxide emission reductions are required. This results
in higher marginal costs of reductions through fuel switching, as low
sulfur coal prices increase because of greater demand. Therefore
retrofit scrubbing becomes more attractive relative to coal switching.
Some coal-fired utility powerplants, such as those with cyclone and
wet bottom boilers, are assumed to be unable to obtain low sulfur
coals with the correct ash fusion characteristics because of the
scarcity of those reserves, and thus, are effectively forced to scrub
under the Default. In the Low Cost case, greater reductions are
obtained at other plants in order to avoid the high costs of
scrubbing.
A few coal-fired powerplants are faced with transportation related
constraints (e.g., inadequate coal handling facilities or lack of
rail or barge access) and often scrub under the Default. In the Low
Cost case, these powerplants generally do not reduce their emissions
and reductions are achieved at other plants more cost effectively.
To the extent there exist concerns about local coal mining losses
associated with coal switching, states could mandate that more scrubbers
be retrofitted than the amount shown. As we noted earlier in the chapter,
this is one very possible implementation plan that was not examined for
this analysis. Based on indications from analysis of other proposed
reduction alternatives conducted by ICF for EPA,<,J about 20-30 gigawatts
of retrofit scrubbers (representing about 2.5 million tons of reductions)
could be added in the Low Cost case without significantly increasing the
costs of compliance. Additional retrofit scrubbing beyond that amount
would significantly add to the cost forecasts.
In addition to retrofit scrubbing and shifts to lower sulfur coals,
there are other emission reduction options including shifts to lower
sulfur residual fuel oils and increased utilization or operation of
scrubbed or low sulfur coal powerplants and decreased utilization or
operation of unscrubbed high sulfur coal units. Cost-effective compliance
strategies vary considerably by region. For a more detailed discussion of
compliance choices, see Chapter Two.
UJSee ICF, Analysis of 6 and 8 Million Ton and 30 Year/NSPS and 30
Year/1.2 lb. Sulfur Dioxide Emission Reduction Cases, February 1986.
ICF INCORPORATED
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1-18
1800-r
REGIONAL COAL PRODUCTION -- 2000
1600-
1400-
1200-
Millions 1000-
of
Tons
800-
600-
400-
200-
0-L
830
. %%%'*<
251
259
134
185
150ซ
711
402
174
219
SSSSi
438
1505 1508 1508
760 l-mm 799
120
188
437
105
167
790
439
106
172
1980
2000 Low Cost Default High Cost
Base Default
II West
~ Central & Southern Appalachia
iXI Midwest
I Northern Appalachia
ICF INCORPORATED
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1-19
REGIONAL COAL PRODUCTION -- 2000
Reflecting shifts to lower sulfur coals under HR-4567, coal production
increases in the Default and Low Cost cases in the low sulfur producing
regions - Central Appalachia and the West. Conversely, coal production
decreases in the Midwest and Northern Appalachia since these regions
produce mostly high sulfur coals.
The changes in coal production are greater in the Default cases than in
the Low Cost case in most regions reflecting more fuel switching in the
Default case because of higher reduction requirements. Most of the low
sulfur coal production increases in the Default cases occur in the West.
This is because:
A higher proportion of emission reductions in the Default case
relative to the Low Cost case occur in regions or states closer
to the West than to Central Appalachia, and
The costs to mine additional low sulfur coal in Central
Appalachia in order to meet the additional reduction
requirements are generally higher than the costs of incremental
low sulfur production in the West. This is particularly true
for the 1.2 lb. compliance coals required under the Default.
The shifts in coal production by aggregate supply region mask significant
changes forecasted to occur on a more local level. For example, Ohio coal
production is forecast to decrease from 37 million tons in the Base case
in 2000 to 17 million tons in the Default case in 2000.
ICF INCORPORATED
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1-20
COAL MINING EMPLOYMENT - 2000
Change in Job Slots Relative to 1984
(thousand workers)
Actual Base Low Cost -- 2000 Default -- 2000
States 1980 1984 2000 Decrease Increase Decrease Increase
PA
36.2
24.8
33.6
+ 7.9
+ 3.9
OH
14.7
9.8
9.8
-6.1
-5.3
VV
53.7
39.6
51.5
--
+14.2
+13.7
VA
16.1
14. 1
15.7
--
+ 2.4
+ 3.1
KY
46.8
37.9
50.6
--
+16.1
+ 12.0
AL
11.8
8.6
9.3
--
+ 1.5
+ 1.7
IL
17.7
13.3
20.8
-2.4
-2.4
-
IN
5.3
5.5
6.2
-0.9
-1.4
_ _
TX
1.8
2.3
11.7
--
+ 10.0
+ 10.1
WY
4.8
4.5
10.4
--
+ 6.3
--
+ 6.6
CO
3.9
2.8
11.3
--
+ 13.9
--
+18.7
UT
3.5
2.5
5.9
+ 3.9
+ 4.5
NM
1.6
1.8
4.2
+ 3.3
+ 3.9
217 .9
167.5
241.0
-9.4
+79.5
-9.1
+78.2
irs
12.2
10.3
30.2
+19.8
+18.6
il U.S.
230.1
177.8
271.2
-9.4
+99.3
-9.1
+96.8
ICF INCORPORATED
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1-21
COAL MINING EMPLOYMENT - 2000
Reflecting the growth in coal production forecast in the EPA Base case
in most states, coal mining employment is expected to increase in most
states by 2000 in the Base case relative to 1984 levels. However, because
of the expectation of continued gains in mining productivity and shifts in
coal production to the West (with generally higher productivity mines),
employment growth is anticipated to be slower than production growth.
Because of the forecasted shifts in coal production under the Low Cost
and Default cases mining "job slots" are expected to decline relative to
1984 levels in several high sulfur producing states and increase in low
sulfur producing states. While the losses in "job slots" are a reasonable
indication of losses in regional economic activity, the number of existing
miners who will actually lose their jobs in 2000 will be less than shown
on page 1-20, because some miners working in 1984 will have retired by
2000. (See mining employment tables in Appendix A and B for more detail.)
Job losses shown above are net losses at the state level. Gross losses
at the local level will be somewhat greater. For example, increases in
net job slots in West Virginia mask some losses in the northern part of
the state where mostly higher sulfur coals are produced.
Decreases in job slots in 1995 relative to 1984 (i.e., under Phase One
of the program) are somewhat lower in the Low Cost case (Total: 5.8
thousand job slots decline) and somewhat higher in the Default (Total:
11.9 thousand job slots decline). See Table A-10 in Appendix A for more
detail.
ICF INCORPORATED
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1-22
CHANGES IN UTILITY ANNUAL COSTS AND ELECTRICITY RATES -
SELECTED STATES -- 2000
Statewide Average Levelized Electricity Rate Impacts 2000
Before Subsidies
IN WV OH KY PA TN MO U.S.
Average
Changes in Utility Annual Costs
Selected States 2000
(3iIlions of Early 1985 Dollars)
Low Cost
Default Cases
OH
0.5
WV/KY/TN
0.2/0.2/0.2
Others
0.6
GA/FL.MO
0.1/0.1.0.1
Others
2.9
WV/KY/TN
0.4/0.3/0.3
GA/FL/MO
0.3/0.3/0.4
Total U.S. = 2.8
Total U.S. = 7.0
ICF
INCORPORATED
-------
1-23
CHANGES IN UTILITY ANNUAL COSTS
AND ELECTRICITY RATES - SELECTED STATES - 2000
In the Low Cost case nearly all utility costs in 2000 occur in the
31-Eastern states where nearly all the emission reductions occur. Almost
half the costs are concentrated in three states: Ohio, Indiana and
Pennsylvania. In the Default case, costs are spread somewhat more evenly
because even states with low average emission rates in the Base case have
to reduce emissions significantly due to the unit by unit limits.
Levelized rate impacts on a state basis are generally proportional to
the state levelized cost impacts divided by statewide electricity sales.
Pre-subsidy rate impacts experienced by individual utilities are often
significantly higher or lower than the average state level impacts. This
is because some utilities generate most electricity from high emitting
coal fired powerplants which are disproportionately affected under the
emission reduction cases and other utilities rely mostly on low emitting
or non-polluting sources (e.g., hydro, nuclear or gas) which are largely
unaffected.
It is important to note that states or individual utilities can have
higher percentage rate impacts than another state or utility but can have
lower absolute rate impacts (increase in mills per kilowatt-hour) or vice
versa. For example, Kentucky has percentage rate impacts of 4.8% in the
Low Cost case in 2000 which is higher than Pennsylvania's average 3.6%
rate impact in the same case. However, Pennsylvania has absolute rate
increases of 2.5 mills per kwh which is higher than Kentucky's 2.3 mills
per kwh. This occurs because Pennsylvania's current rates (without acid
rain legislation) are higher on average than Kentucky's, and thus its
percent change in rates would tend to be lower.
ICF INCORPORATED
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1-24
PRESENT VALUE OF COMPLIANCE COSTS, SUBSIDIES
AND TAXES BY REGION -- LOW COST CASE 1/
Statewide "Levelized" Subsidies Utility "Traditional" Subsidies2J
Compliance
Costs + Tax - Subsidy =
Net
Impact
Compliance
Costs
+ Tax -
Subsidy =
Net
Tr;"
New York
0.1
0.1
0.1
0.1
0. z
Pennsylvania
3.4
3.4
3.4
0.2
-
3.6
West Virginia
1.9
1.9
1.9
0.1
0.1
1.9
Georgia
0.9
0.9
0.9
0.1
-
1.0
Florida
1.0
1.0
1.0
0.2
-
1.2
Ohio
5.3
5.3
5.3
0.2
1.0
4.5
Indiana
4.1
4.1
4.1
0.2
1.4
2.9
Kentucky
1.6
1.6
1.6
0.1
0.2
1.5
Tennessee
1.7
1.7
1.7
0.1
-
1.8
Missouri
1.3
1.3
1.3
0.1
0.1
1.3
Texas
0.3
0.3
0.3
0.1
-
0.4
2/
Total 11-States
21.6
21.6
21.6
1.5
2.8
20.3
2/
Total 31-Eastern 27.6
27.6
27.6
2.6
3.5
26.o
2/
Total 17-Western 1.0
1.0
1.0
1.2
0.2
1.9
2/
Total U.S.
28.7
28.7
28.7
3.7
3.7
28. 7
1_/See Appendix C for a description of the
present
value measure. Present value
of
costs was calculated using a 4.26 percent discount rate.
2/Note that the bill stipulates that subsidies and thus taxes would only be
provided if rate impacts were calculated on a "statewide levelized" basis.
3/Totals may not add due to independent rounding.
ICF INCORPORATED
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1-25
PRESENT VALUE OF COMPLIANCE COSTS, SUBSIDIES
AND TAXES BY REG ION--LOW COST CASE
HR-4567 provides subsidies to limit electricity rate impacts to 10
percent. In order to qualify for subsidies states must ensure that rate
increases are made "substantially equivalent" across the state and are
"substantially levelized" over time. In the Low Cost case, such
ratemaking would result in no regions having rate impacts greater than ten
percent in either 1995 or 2000.
Statewide levelized ratemaking would be a substantial departure from
traditional electricity rate determination. Typically, rates are set on a
utility by utility basis reflecting each utilities' costs rather than
statewide costs. Also, the capital cost component of utility rates is not
usually "levelized" (i.e., passed through to ratepayers in equal
increments) over the life of the equipment. Instead, owing to the
treatment of taxes, interest payments, dividends and depreciation under
current ratemaking practices, the "traditional" revenue requirements
approach results in higher capital charges passed through to customers in
the early years and lower charges in the later years than under th$
"levelized" capital charges (for a discussion of ratemaking procedures see
Chapter Three). Under traditional rate making practices, rates would
exceed ten percent more frequently, and if subsidies were provided in this
case, the present value of these subsidies would be $3.7 billion.
Taxes are spread more evenly across states than either compliance costs
or subsidies, which are concentrated in the eastern states with high
emitting powerplants. This is because taxes are applied to all fossil
fuels including gas, oil, low sulfur coal and scrubbed coal generation as
well as higher polluting sources.
ICF INCORPORATED
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1-26
PRESENT VALUE OF COMPLIANCE COSTS, SUBSIDIES
AND TAXES BY REGION -- HIGH COST DEFAULT 1/
Statewide "Levelized" Subsidies Utility "Traditional" Subsidies2-1
Compliance
Net
Compliance
Ne^
Costs
+ Tax -
Subsidy =
Impact
Costs
+ Tax
- Subsidy =
Irrr.
New York
1.7
0.1
1.8
1.7
0.7
2.4
Pennsylvania
6.1
0.1
-
6.2
6.1
0.9
1.0
6.0
West Virginia
4.7
0.1
0.6
4.2
4.7
0.7
0.9
4.5
Georgia
3.5
0.1
-
3.6
3.5
0.6
0.1
4.0
Florida
4.1
0.1
-
4.2
4.1
0.8
0.2
4.7
Ohio
11.1
0.1
0.3
10.9
11.1
1.1
5.7
6.5
Indiana
7.8
0.1
1.5
6.4
7.8
0.9
4.0
4.8
Kentucky
3.4
0.1
-
3.5
3.4
0.7
1.5
2.6
Tennessee
3.9
0.1
-
4.0
3.9
0.6
-
4.5
Missouri
4.7
-
-
4.7
4.7
0.3
0.9
4.1
Texas
2.2
0.1
-
2.3
2.2
0.4
-
2.6
3/
Total 11-States
53.2
1.0
2.4
51.8
53.2
7.7
14.3
46.6
3/
Total 31-Eastern 75.2
1.7
2.4
74.5
75.2
12.8
18.2
69.8
3/
Total 17-Western 6.4
0.8
-
7.2
6.4
5.7
0.1
12.0
3/
Total U.S.
81.6
2.4
2.4
81.6
81.6
18.4
18.4
81.-
1/See Appendix C for a
description of the
present
value measure.
2/Note that the bill stipulates that subsidies and thus taxes would only be
provided if rate impacts were calculated on a "statewide levelized" basis.
3/Totals may not add due to independent rounding.
ICF INCORPORATED
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1-27
PRESENT VALUE OF COMPLIANCE COSTS, SUBSIDIES
AND TAXES BY REGION -- HIGH COST DEFAULT
Under statewide levelized ratemaking in the High Cost Default case, West
Virginia, Ohio and Indiana have rate impacts greater than 10 percent in
1995 and/or 2000, and thus, receive subsidies of $2.4 billion on a present
value basis. Under the Default case not shown here, somewhat less
subsidies of $2.0 billion on a present value basis would be required.
Under traditional utility ratemaking in the High Cost Default case, and
if subsidies were provided, the present value of subsidies would be $18.4
billion or nearly one-quarter of total compliance costs ($18.4 billion
versus $81.6 billion). Nearly all subsidies are for states within the
31-Eastern States region, and thus the net impact of HR-4567 on these
states is mitigated by the subsidy/tax scheme. Although not calculated
rigorously for his analysis, under the Default case, the subsidies
required would be estimated to be approximately 20-30 percent lower than
in the High Cost Default or roughly $13-$15 billion in present value terms.
It is important to note that it is unlikely that a state which defaults
could be considered eligible for subsidies. The ianguage in HR-4567 is
unclear about this point.
ICF INCORPORATED
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1-28
REQUIRED ELECTRICITY GENERATION TAX
1989-1996
3
2
Nominal
Mills/Kwh
1
0.5
0
i Note that the bill stipulates that subsidies and thus taxes would only
be required if statewide levelized ratemaking were employed.
ICF INCORPORATED
(L4S
2.25
$ 1
1 .
mm
W$M
0
v-y,
ssfrsa
0.29
W4?<$
...
Statewide Utility Statewide Utility
Levelized Traditional1 Levelized Traditional1
Low Cost High Cost Default
-------
1-29
REQUIRED ELECTRICITY GENERATION TAX
1989-1996
HR-4567 provides for a tax on utility fossil electricity generation and
power imports beginning in 1989 and ending in 1996 in order to provide
funding for the subsidies. The bill stipulates that this tax cannot
exceed 0.5 mills per kilowatt hour. This tax would be more than adequate
to fully fund the subsidies if statewide levelized (i.e., the ratemaking
practice required by the bill in order to receive subsidies) rate impacts
were subsidized in either the Low Cost or High Cost Default cases.
A 0.5 mill per kilowatt hour tax would also more than enough to fund
subsidies in the Low Cost case if utility traditional rate impacts were
subsidized. The tax, however, would not generate enough funds for the
required subsidies if utility traditional rate impacts were subsidized in
the High Cost Default case or in the Default case. In the Default case,
an electricity generation tax of approximately 1.5-1.8 mills per
kilowatt-hour would be required.
ICF INCORPORATED
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1-30
PRESENT VALUE OF TAX, SUBSIDY AND FUND OVER TIME
- HIGH COST DEFAULT CASE (STATEWIDE LEVELIZED RATES)
Billions of
Early
1986 Dollars
1989
2030
Tax rate Is 0.291 mills/kwh, the rate necessary to ensure that revenues cover outlays. All numbers
are In early 1985 dollars and in present value terms. Present values were calculated using a
4.26 percent discount rate.
ICF INCORPORATED
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1-31
PRESENT VALUE OF TAX, SUBSIDY AND FUND OVER TIME
- HIGH COST DEFAULT CASE (STATEWIDE LEVELIZED RATES)
The year by year cash flows under the subsidy/tax scheme are illustrated
above for the High Cost Default case under statewide levelized ratemaking
(i.e., the ratemaking practice required by the bill in order to receive
subsidies). Initially, tax revenues are greater than required outlays and
the fund shows a positive balance. In the later years the fund has been
fully expended. Note that for the Low Cost case under equivalent
ratemaking, no subsidies would be required and hence the tax and fund
would be zero throughout.
ICF INCORPORATED
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1-32
CAVEATS AND UNCERTAINTIES
There are a number of caveats, assumptions and uncertainties which have an
important effect on the findings of this analysis. These are discussed in
Chapter Four and briefly noted below:
Nitrogen Oxide Control Assumptions -- Assumptions
made about nitrogen oxide control technologies such as
combustion modifications and Selected Catalytic
Reduction (SCR), have important impacts on utility
costs especially in the Default cases.
Sulfur Dioxide Control Assumptions -- Scrubber
costs, site-specific retrofit scrubber costs and
assumptions regarding such issues as new control
technologies, removal efficiencies and scrubber
lifetimes can affect cost and coal production
forecasts.
Uncertainties in Implementation, Electric Rate and
Subsidy Forecasts -- There are uncertainties
associated with implementation of HR-4567, individual
electric utility rate increase estimates and the
calculation of subsidies.
Site-Specific Constraints Affecting Alternative
Reduction Strategies -- Site-specific costs and
constraints can significantly affect individual
powerplant compliance decisions.
Base Case Assumptions -- Changes in some key EPA
Base case assumptions such as electricity growth rates
and world oil and gas prices could affect the reported
forecasts.
Restricting Utility Forecasts Between Scenarios
-- Variables such as gas consumption, new powerplant
builds and interstate transmission are restricted in
the HR-4567 cases to levels in the Base case in order
to better isolate the effects of the bill. Allowing
these variables to change could change forecast
compliance strategies, costs, etc.
Direct Costs and Near-Term Constraints Not
Analyzed -- Certain costs were not analyzed such as
impacts associated with industrial and motor vehicle
emission controls, oil and gas price changes
associated with forecast changes in utility oil and
gas demand and near-term constraints that might affect
compliance decisions and forecasted impacts in 1993.
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Impact of Higher Electricity Rates on Electricity
Demand -- were not analyzed. This could result in
somewhat lower electricity demand and thus lower
utility costs. However, there would also be a loss to
consumers (i.e. a loss in consumer surplus in
economists terms) which would have to be added to
overall costs.
Indirect Costs Not Measured -- Some indirect
costs of HR-4567 were also not analyzed such as
administrative and transaction costs.
Benefits Not Measured -- The benefits of emission
reductions in terms of the potential mitigation of
acid deposition, health related affects, agricultural
and materials damage, improvement of visibility among
other factors were not measured or analyzed.
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Chapter Two
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CHAPTER TWO
UTILITY COMPLIANCE STRATEGIES AND COSTS
This chapter analyzes utility compliance strategies and costs under
HR-4567 both on a generic national basis and on a state specific basis.
First, the range of costs for a variety of different compliance strategies are
discussed nationally. Second, in order to provide an example of regional
compliance options for a relatively large, high emitting state, Pennsylvania's
compliance strategies and costs are discussed for the Low Cost case in 2000.
The purpose of this chapter is to provide perspective on typical compliance
strategies and issues such as the extent to which coal switching is preferred
by utilities to retrofit scrubbing and the relative costs of each. This
chapter has four sections:
National Sulfur Dioxide Compliance Strategies and
Costs -- This section discusses sulfur dioxide
compliance strategies and costs on a national basis.
Pennsylvania Sulfur Dioxide Reduction Requirements
-- This section briefly estimates the amount of
Pennsylvania's required utility sulfur dioxide
emission reductions in the Low Cost case.
Pennsylvania Sulfur Dioxide Emission Reduction
Strategies -- This section analyzes utility sulfur
dioxide compliance decisions in Pennsylvania.
Pennsylvania Nitrogen Oxide Reduction Requirements
-- This section briefly estimates the amount of
Pennsylvania's required utility nitrogen oxide
emission reductions in the Low Cost case.
Pennsylvania Nitrogen Oxide Emission Reduction
Strategies -- This section discusses utility nitrogen
oxide compliance decisions.
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2-2
NATIONAL SULFUR DIOXIDE COMPLIANCE STRATEGIES
The costs of sulfur dioxide emission reduction strategies vary across
regions and across powerplants within regions. Representative costs are shown
on Table 2-1 and discussed below:
Switching From High Sulfur Coals -- The costs of
switching from high to medium and low sulfur coals
range from $100-900 per ton of sulfur dioxide
removed. For most plants with adequate rail or barge
access and rail handling facilities, the costs range
from about $100 to $600 per ton removed. Thus,
switching away from high sulfur coals is often the
most cost-effective strategy. There are three factors
which account for the wide variance in costs:
Low sulfur coal premiums vary considerably
between regions because some regions have much
better access to low cost, low sulfur coal
reserves. For example, in western regions and in
regions along the Mississippi River, such as
Missouri, Iowa and Illinois, low sulfur coal
premiums are small relative to many east coast
regions reflecting better access to coals from
the Rockies and the Powder River Basin.
Costs associated with upgrading transportation
and coal handling facilities in order to get new
low sulfur coal supplies can be significant and
vary considerably among powerplants within the
same region. Such costs can add 30 percent or
more to the annualized costs of coal switching.
Particulate emission control equipment often must
be upgraded if powerplants switch to lower sulfur
coals. The extent of required modifications and
hence the costs vary depending partly on the
sulfur and mineral content of the coal burned
before and after switching.
Switching From Medium to Low Sulfur Coals -- It
is generally less cost effective to switch from medium
to low sulfur coals than to switch from high sulfur to
lower sulfur coals. This reflects lower sulfur
dioxide removal reducing the costs per ton removed.
Retrofit Scrubbing High Sulfur Coal -- Retrofit
scrubbing of high sulfur coals can be more
cost-effective in certain cases than coal switching.
This situation usually occurs when:
The costs of switching from higher to lower
sulfur coals are high reflecting (1) strict
emission reduction requirements which result in
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2-3
TABLE 2-1
REPRESENTATIVE COSTS OF UTILITY S02
EMISSION REDUCTION
STRATEGIES-NATIONAL BASIS
Switching
Switching From High to Low Sulfur Coal
Switching From High to Medium Sulfur Coal
Switching From Medium to Low Sulfur Coal
Early 1985 $ per ton of
Sulfur Dioxide Removed
100-600
100-600
600-1700
Switching with Upgrade Costs
Switching From High to Low Sulfur Coal
With Facility Upgrade Costs 2J
Switching From High to Medium Sulfur Coal
With Facility Upgrade Costs 2J
Switching From Medium to Low Sulfur Coal
With Facility Upgrade Costs 2J
400-900
400-900
1000-2100
Retrofit Scrubbing
Retrofit Scrubbing High Sulfur Coal
Retrofit Scrubbing Medium Sulfur Coal
Retrofit Scrubbing Low Sulfur Coal
300-800
900-1700
1800-3000
Switching From High to Low Sulfur Residual Fuel Oils
450-800
Shifts in Utilization
200-500
lJNote that these are representative costs only. In certain regions and
at certain plants, costs per ton can be significantly different. For example,
a number of plants can achieve a limited number of reductions through shifts
from low to very low sulfur coals at costs per ton below $100.
2JFacility upgrade costs are for the refurbishment or construction of
rail or barge access for powerplants and the upgrade of coal handling
equipment.
ICF
INCORPORATED
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2-4
utilities bidding up low sulfur coal prices and
(2) the regional scarcity of low cost, low sulfur
coal reserves.
Coal switching is costly due to high
transportation and coal handling equipment
upgrade costs.
Retrofit scrubbing is relatively inexpensive
because of favorable site conditions. Much of
the variation in high sulfur coal retrofit
scrubbing costs shown in Table 2-1 is caused by
substantial differences in the costs of retrofit
scrubbing for different powerplants. In some
cases, the difference in capital and fixed O&M
costs between high and low retrofit difficulty
sites are 100 percent and 75 percent,
respectively.
Retrofit Scrubbing Medium and Low Sulfur Coals --
The costs on a dollar per ton removed basis of
retrofit scrubbing medium and low sulfur coals are
much higher than for retrofit scrubbing high sulfur
coals. This is because the high capital and fixed
costs of scrubbing are not significantly lower as the
amount of sulfur dioxide removed is decreased. Thus,
less reductions result in generally higher costs per
ton.
Switching From High to Low Sulfur Residual Fuel
Oils -- Residual fuel oil shifts are medium cost
options relative to other alternatives. In cases
where there are strict emission requirements,
utilities will opt to switch to lower sulfur residual
fuel oil. However, it should be noted that low sulfur
oil premiums are related to assumptions about world
crude oil prices.. To the extent they will be lower in
the late 1990s than assumed in the EPA Base case, more
switching to lower sulfur residual oils would occur.
Shifts in Utilization -- Examples of utilization
shifts that reduce sulfur dioxide emissions include
reduced use of unscrubbed medium and high sulfur
coal-fired powerplants and increased utilization of
scrubbed coal-fired capacity, NSPS capacity, low
sulfur coal-fired capacity and oil or gas capacity.
In such cases, the costs of utilization shifts are the
incremental fuel and O&M costs at the lower emitting
powerplants. In general, shifts in utilization among
coal plants are very cost effective relative to other
reduction strategies but are limited in the amount of
reductions they provide. This is because most coal
plants are operated at relatively similar capacity
factors (50-70 percent).
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2-5
PENNSYLVANIA SULFUR DIOXIDE EMISSION REDUCTION REQUIREMENTS
In 1985, the average utility fossil sulfur dioxide emission rate in
Pennsylvania was estimated at 2.38 lbs per MMBtu (see Figure 2-1). By 2000,
this rate is forecast to decline slightly to 2.28 lbs per MMBtu reflecting
primarily increased use of existing scrubbed capacity. This average base case
emission rate is well above the average rate forecast for the entire country
of 1.56 lbs per MMBtu in 2000.
Imposing the 1.2 lb. statewide average sulfur dioxide per million Btu rate
requirement in 2000 reduces Pennsylvania sulfur dioxide emissions by about 0.5
million tons (see Table 2-2). This forecast reflects a reduction in fossil
fuel use from about 1.1 quads in 1985 to 1.0 quads in 2000. This reflects
relatively low growth in sales forecast in Pennsylvania and the increased use
of nuclear power.
FIGURE 2-1
PENNSYLVANIA ANNUAL AVERAGE UTILITY FOSSIL
SULFUR DIOXIDE EMISSION RATES
3
2.38
2.25
2-
Lbs SO2
MMBtu j 2
1985
2000
Base
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2-6
TABLE 2-2
PENNSYLVANIA UTILITY SULFUR DIOXIDE EMISSION REDUCTIONS
S02 Emissions
(Millions of tons)
Fossil Fuel Consumption
(Quads)1J
S02 Emission Rate
(lbs/MMBtu)
Base Case Low Cost Changes
1985 2000 2000 from Base
1.32
1.11
2.38
1.16
1.02
2.28
0.62
1.03
1.20
-0.54
+0.01
-1.08
ij
Quad = 10^ Btus
ICF INCORPORATED
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2-7
PENNSYLVANIA SULFUR DIOXIDE EMISSION REDUCTION STRATEGIES
Pennsylvania utility compliance choices in the Low Cost case in 2000
involve more retrofit scrubbing than other regions (see Figure 2-2). These
choices are shown in detail in Table 2-3 and are discussed below:
Coal switching accounts for about 56 percent of the state's total
sulfur dioxide emission reductions. In most cases, utilities switch
from coals with sulfur content of about two percent to coals with
sulfur content of about one percent and one and one-half percent.
Retrofit scrubbing occurs at 3.38 GW of capacity and accounts for 40
percent of total sulfur dioxide emission reductions. As is discussed
below, the scrubbers are built on large powerplants where
installation is relatively easy.
Utilization shifts account for four percent of total reductions and
involve increased utilization of existing scrubbed capacity and
reduced utilization of unscrubbed coal capacity. Utilization shifts
are less important in Pennsylvania than other regions because there
is little new NSPS capacity and most existing unscrubbed powerplants
have the same emission limits.
There are no shifts from high to low sulfur residual oils at
Pennsylvania oil steam plants. This is because, as is discussed
below, such shifts are slightly less cost effective than retrofit
scrubbing. There is, however, an increase in residual oil use to
compensate for the capacity and energy penalties associated with
scrubbing. An increase in total required reductions, or a decrease
in forecast residual oil price premiums might trigger shifts to low
sulfur residual oil.
Generally the cost effectiveness or costs per ton removed vary
considerably depending on the compliance strategies. However, as shown in
Figure 2-3, the costs of the available reduction strategies are quite close.
The difference in costs between scrubbing and coal switching on a dollar per
ton of sulfur dioxide removed basis is small for the 3.38 Gw that are
scrubbed. The costs of switching to lower sulfur coal are $700 per ton
removed when the the costs of facility upgrade are included. In contrast,
retrofit scrubbing is ง650-675 per ton of sulfur dioxide removed for capacity
with 1.1-1.2 retrofit factors. This means that small changes in price
premiums, upgrading or retrofit scrubbing costs could change utility
compliance decisions. Also, if more retrofit scrubbing is mandated for units
with low retrofit factors, the costs would not be significantly higher than if
the plants were allowed to switch coals. However, if more than a few units
are forced to retrofit scrubbers or if the scrubbers are forced on more costly
powerplants, the costs could significantly exceed fuel switching costs. Note
that in the case of a plant with a 2.0 retrofit factor scrubbing is nearly
twice as costly as coal switching on a dollar per ton removed basis.
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2-8
FIGURE 2-2
S02 COMPLIANCE STRATEGIES
(tons)
Coal
Total Reductions (545,000)
FIGURE 2-3
REPRESENTATIVE S02 REDUCTION COSTS - PENNSYLVANIA
1000-r
900-
800-
700-
600-
500-
400-
300-
200-
100-
0--
490
WS
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iSSS
'*XZ*S
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Upgrade Upgrade
of
Facilities
Coal Switching
1.1
Retrofit
Factor
2.0
Retrofit
Factor
Retrofit Scrubbing Oil Switching
Utilization
Shifts
ICF INCORPORATED
Retrofit Scrubbing (220,000)
40.4%
Utilization Shifts (15,000)
2.7%
Switching (310,000)
56.9%
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2-9
TABLE 2-3
PENNSYLVANIA UTILITY S02
REDUCTION STRATEGIES - 2000
Base Case
EXISTING COAL CAPACITY
Existing Scrubbed Coal Capacity
B i turn i nous
High-Medium Sulfur
H i gh-SuI fur
Very-High Sulfur
Total Existing Scrubbed
Existing Unscrubbed Coal Capacity
B iturn i nous
Very Low-Sulfur
Low-Medium Sulfur
Med i um-SuI fur
H igh-Med ium SuI fur
Total Existing Unscrubbed
Total Existing Coal
EXISTING OIL STEAM CAPACITY
Low-Sulfur Residual
High-Sulfur Residual
TotaI Existing Oi I
TOTAL EXISTING CAPACITY
NEW (POST 1980) CAPACITY
New NSPS Coal Capacity (Subpart Da)
Low-Medium Sulfur
High-Medium Sulfur
Tota I
TotaI New
TOTAL EXISTING AND NEW CAPACITY
Coa I
Very-Low Sulfur
Low-SuI fur
Low-Medium Sulfur
Med i um-SuI fur
High-Medium Sulfur
H i gh-SuI fur
Very-High Sulfur
Oi l
S02
Emi ss ions
Capacity 6
(Gwl Quads (10 tonsl
Low Cost Case
0.187
4.212
0.009
0.225
0.004
0.054
Capac i ty
(Gwl Quads
4.982
2.647
-
-
-
0. 150
4.399
0.234
0.058
7.779
-
.
0.628
-
-
-
3.252
1. 176
0.060
0.069
3.417
12.327
0.660
0.994
2.826
13.503
0.720
1 .063
10.123
17.902
0.954
1.121
17.902
1.180
0.003
0.001
1. 180
1 .640
0.050
0.040
1 .640
2.820
0.053
0.041
2.820
20.722
1.007
1.162
20.722
0.121
0.006
0.001
-
-
-
0. 121
0.121
0.006
0.001
0.121
0.121
0.OQ6
0.001
0. 121
20.843
1.013
1.163
20.843
Sulfur Dioxide
Leve I
Less
than 0.80
lbs. per
mi II ion Btu
0.80-
1.08 lbs.
per mill
ion
Btu
1.08-
1.67 lbs.
per mi I I
i on
Btu
1.67-
2.50 lbs.
per mill
ion
Btu
2.50-
3.33 lbs.
per mill
i on
Btu
3.33-
5.00 lbs.
per mill
ion
Btu
Greater than 5
00 lbs.
per
mi 1 1 ion Btu
0.294
0.156
0.009
0.459
0.036
0. 157
0. 163
0. 138
0.494
0.953
0.008
0-053
0.061
1.014
0-007
0.007
0.007
1.021
S02
Emi ssIo<
6
(10 tons)
0.055
0.037
0.003
0.095
0.012
0.109
0.172
0. 184
0.477
0.572
0.002
0.042
0.044
0.616
0.002
0.002
0.00?
0.6is
Low-Sulfur Residual
High-Sulfur Residual
0.5 lbs. S02 per million Btu (0.5% Sulfur)
1.6 lbs. S02 per million Btu (1.5% Sulfur)
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2-10
Pennsylvania retrofits scrubbers on more capacity (3.38 Gw) than any other
region. This reflects the combination of several circumstances including:
Pennsylvania has several large utility powerplants
where the cost of scrubber installation is relatively
low reflecting favorable spacing and sizing conditions
at the site. Typically, the cost of retrofit
scrubbers are compared to the cost of installing
scrubbers on new powerplants. Pennsylvania has 3.31
Gw of capacity where the capital and most fixed O&M
costs of retrofit scrubbers are assumed to be about
ten percent higher than scrubbers built on new plants
and 3.89 Gw where the costs are about twenty percent
higher. Thus, Pennsylvania has 7.20 Gw of capacity
with relatively low retrofit costs. These cost
estimates were developed for EPA based on engineering
cost assessments but do not reflect detailed on-site
inspections.1J
3.38 Gw of the 7.2 Gw of capacity with low scrubbing
costs also have significant costs associated with coal
switching. As a result of these high costs, retrofit
scrubbing becomes relatively attractive. These
powerplants lack adequate rail and/or barge facilities
and coal handling equipment to receive low sulfur coal
shipments. Upgrade costs necessary to receive these
shipments are estimated at about $69/kw. These cost
estimates were not based on on-site assessments, but
reflect preliminary costing work performed by ICF for
EPA. See Chapter Four for more detail.
More significant low and medium sulfur coal price
premiums are forecast to develop in Pennsylvania under
HR-4567 relative to the Base case (see Table 2-4).
These premiums are high reflecting the limited
availability of low cost, low sulfur coal reserves in
nearby coal fields.
Most of the scrubbing that is forecast in the Low Cost case occurs in
Pennsylvania. Other states retrofit no scrubbers or fewer scrubbers than
Pennsylvania in the Low Cost case, and meet the reduction requirements through
more coal switching. This is because the cost of coal switching is generally
much cheaper than scrubbing in these states. There are several reasons for
this:
In most states, more powerplants have adequate coal
transportation and handling facilities than in
Pennsylvania, which makes switching to lower sulfur
coals in these states less costly.
lJSee report prepared by Energy Ventures Analysis for EPA. Evaluation
of Sulfur Dioxide Emissions and FGD Retrofit Feasibility at the 200 Top
Emitting Generating Stations, April 3, 1985.
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2-11
TABLE 2-4
FORECASTED DELIVERED COAL PRICES --
PENNSYLVANIA 2000 lJ
(early 1985 dollars/10* Btu)
Bituminous
Base Case Low Cost
Very-Low Sulfur - 2.65
Low Sulfur
Low-Medium Sulfur 2.08 2.38
Medium Sulfur 2.02 2.11
High-Medium Sulfur 1.86 1.85
High Sulfur 1.82 1.81
Very-High Sulfur - 1.71
Coal
Very-Low Sulfur
Low-Sulfur
Low-Medium Sulfur
Medium-Sulfur
High-Medium Sulfur
High-Sulfur
Very-High Sulfur
Sulfur Dioxide Level
Less than 0.80 lbs. per million Btu
0.80-1.08 lbs. per million Btu
1.08-1.67 lbs. per million Btu
1.67-2.50 lbs. per million Btu
2.50-3.33 lbs. per million Btu
3.33-5.00 lbs. per million Btu
Greater than 5.00 lbs. per million Btu
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2-12
In a number of states that do have powerplants which
have high costs associated with coal switching, often
the sulfur dioxide reductions are moderate enough that
they can be achieved through coal switching at other
plants.
In some states, retrofit scrubbers are very costly
to install because of lack of space or other
constraints.
In other states, the difference in forecast coal
prices between high and low sulfur coals is more
favorable to coal switching than in Pennsylvania
because of better access to low sulfur coals.
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2-13
PENNSYLVANIA NITROGEN OXIDE REDUCTION REQUIREMENTS
In 1985, the average utility fossil nitrogen oxide emission rate in
Pennsylvania was 0.77 lbs per MMBtu (see Figure 2-4). By 2000, this rate is
forecast to decline slightly to 0.75 lbs. per MMBtu. Note that the rate
forecast for Pennsylvania in 2000 in the base case is very close to the
national average rate forecast for 2000 of 0.73. The 0.6 lb. nitrogen oxide
per million Btu State average rate in 2000 would result in about 0.1 million
tons of nitrogen oxide reductions (see Table 2-5).
FIGURE 2-4
PENNSYLVANIA ANNUAL AVERAGE UTILITY FOSSIL
NITROGEN OXIDE EMISSION RATES
li
Lbs NOx
MMBtu
0.77
0.75
' t I
> Jt ,/ 'ฆ
t ' / '
%S - '%% sss
. '>
' " 4 *,S S
ฆ/,. %. %. %. %. %. %%. //,. % %
. '//. ,f//t % ฆ$ :<'/,. //,:%ฆฆ%. %//>.
1985
2000
TABLE 2-5
PENNSYLVANIA NOx EMISSION REDUCTIONS
1985
Base Case Low Cost Changes
2000 2000 from Base
NOx Emissions
(Millions of tons)
0.43
0.38
0.31
ฆ0.07
Fossil Fuel Consumption
(Quads)1J
1.11
1.02
1.03
+0.01
NOx Emission Rate
(lbs/MMBtu)
0.77
0.75
0.60
-0.15
lJ Quad = 1015 Btus
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2-14
Pennsylvania Nitrogen Oxide Emission Reduction Strategies
Most nitrogen oxide emission reductions, 66 percent of the total, are
associated with utility retrofits of enriched fireball combustion modifications
on tangentially fired coal powerplants (see Figure 2-5). All available
tangentially fired units (8.76 Gw) are modified reflecting the low cost of
these reductions (see Figure 2-6 on the next page). 34 percent of total
Pennsylvania reductions are due to utility retrofits of distributed mixing
burners on wall-fired coal powerplants (0.7 Gw of capacity are affected).
There are very few forecast reductions associated with reduced utilization
of high emitting powerplants and increased utilization at controlled power-
plants. The total utilization shifts are small because Pennsylvania has only
one small wet bottom powerplant and no cyclones, (i.e., powerplants which emit
at very high NOx rates and would probably be operated less). The lack of
cyclone or wet bottom capacity also results in relatively low costs for
Pennsylvania utilities to comply with the NOx limit under the Default cases.
This is because wet bottom pulverizers and cyclones cannot reduce nitrogen
oxide emissions by adjusting their combustion process and thus must retrofit
very costly SCR systems. For a further discussion of NOx controls, see Chapter
Four.
FIGURE 2-5
PENNSYLVANIA NITROGEN OXIDE COMPLIANCE STRATEGIES
Distributed
Burners
Retrofit
Mixing
(34%)
Retrofit of
Enriched Fireball
(66%)
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2-15
FIGURE 2-6
REPRESENTATIVE NOx REDUCTION COSTS -- PENNSYLVANIA
140
120
100
Early 1985
$/Ton
60
40
20
0
-
120
-
60
/ / / ' ' J, -
w%%X^
-
V v/.-.
. </.-. '
V7;. M/OT
: Still
mmrnm
a;"-''/ amv "
wmw#
Enriched Distributed Mixing
Fireball Burners
ICF INCORPORATED
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hoptsr Throe
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CHAPTER THREE
RATE IMPACTS, SUBSIDIES AND TAXES
This chapter discusses electric utility rate impacts associated with
HR-4567 and the bill's subsidy and tax programs. As noted earlier in this
report, if certain conditions are met, HR-4567 provides subsidies to electric
utilities whose rate impacts exceed ten percent. In order to qualify for the
subsidies, states must develop utility rates by spreading cost impacts across
the state and levelizing capital charges over time. Funding for the subsidies
would be generated by a tax on fossil electricity generation and electricity
imports from 1989 to 1996. This tax may not exceed 0.5 mills per kilowatt
hour.
This chapter discusses the issues surrounding the rate impacts, subsidies
and taxes in five sections:
Ratemaking -- This section compares the
ratemaking procedures required by the bill for
utilities to qualify to receive subsidies versus more
traditional ratemaking practices. This section also
discusses the implications of permitting rates to be
calculated in a different manner than stipulated in
the bill (i.e., closer to traditional practices) on
the amount of required taxes and subsidies.
Measurement of Statewide Rate Impacts -- This
section discusses the measurement of statewide
electricity rate increases.
Subsidies -- This section presents estimates of
required subsidies nationally and by state and
discusses their calculation.
Taxes -- This section presents estimates of
required taxes and the impact at the state level.
ICF INCORPORATED
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3-2
RATEMAKING
HR-4567 provides subsidies to utilities in order to limit residential
electric utility rate increases associated with the bill's emission reductions
to ten percent. The bill also requires that in order for the utilities to
qualify for the subsidy, these rate increases are to be made "substantially
equivalent" across each state and are to be "substantially levelized" over
time. This type of ratemaking would be a major departure from traditional
electricity rate determination. Typically, rates are set on a utility by
utility basis reflecting each utilities' costs rather than statewide costs.
Also, the capital cost component of utility rates is not usually "levelized"
(i.e., passed through to ratepayers in equal increments) over the life of the
equipment. Instead, owing to the treatment of taxes, interest payments,
dividends and depreciation under current ratemaking practices, the
"traditional" revenue requirements approach results in higher capital charges
passed through to customers in the early years and lower charges in the later
years than under the "levelized" approach.
ILLUSTRATION OF CAPITAL CHARGES
\
\
^-REVENUE
\
\
\
\
\
\
\
\,
REQUIREMENTS
LEVELIZED
\
I I II I I I I I I I 1 1 I II I I I I I I I I ฆ t i ฆ i t
YEAR
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3-3
The ratemaking procedure required under HR-4567 in order to receive
subsidies would result in less subsidies than if traditional ratemaking (i.e.
based on utility revenue requirements) were permitted. This is because within
states some utilities may have rate impacts greater than ten percent, but will
not receive subsidies if the statewide average impact is less than ten
percent. A second reason is that capital charges are levelized lowering rate
impacts in early years.
MEASUREMENT OF STATEWIDE RATE IMPACTS
Under the ratemaking specified by HR-4567, no state is forecast to have
rate increases greater than ten percent in the Low Cost case. In the High
Cost Default case only Ohio, Indiana, and West Virginia are forecast to have
rate increases above ten percent.
The calculation of percent change in average statewide rates in 2000 is
shown below:
2000 "Reduction Case" 2000 "Base Case" 1982 Average
Statewide Annualized Costs - Statewide Annualized Costs * Electricity
2000 Electricity Sales by State Rates by State
A similar calculation is performed to calculate 1995 rate impacts using 1995 *
cost estimates and 1995 electricity sales in each state or region.
The above calculation procedure is similar to the ratemaking specified in
HR-4567 in that capital charges are annualized in equal increments over the
lifetime of the equipment (i.e., levelized over time) and costs are spread
evenly over the state.
However, there are a number of practical impediments in measuring the
percent rate impacts as stipulated in the bill. In the first place, the
change in costs need to be measured. While equipment costs for scrubbers, NOx
controls, particulate equipment or rail facilities associated with shifts to
lower sulfur coals can be measured relatively easily, it is more difficult to
calculate the change in fuel costs to utilities associated with switching to
lower sulfur fuels. This is because this change in fuel costs is equal to the
costs of fuel under H.R. 4567 versus those costs that would have occured in
the absence of such legislation. It is not clear as a practical matter how
such costs would be measured.
A similar problem occurs when attempting to measure the base rate from
which percent rate impacts are measured. This is the electricity rate that
would exist in the future in the absence of acid rain legislation. For this-
study, 1982 actual average electricity rates were used as base rates by
state. It is not clear what base rates would be used in practice.
Another issue with respect to measurement problems is that the bill
stipulates that subsidies be provided based on residential rate increases
above 10 percent. The calculations noted herein develop average rate impacts
and assume subsidies are provided across all customer classes. This will
result in more subsidies than if just residential customers were subsidized.
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3-4
Further, since residential rates are generally higher than for other customer
classes, percentage rate impacts averaged across all customer classes would
generally be higher than percentage rate impacts for residential customers.
As such, for this reason as well, less subsidies may be required than noted
herein. Unfortunately, it is very difficult to estimate percentage rate
impacts for residential customers only, since it will depend on how the rate
impacts are allocated across customers. Further, by providing subsidies based
on residential rate increases only, the bill would create strong incentives to
load most or all rate increases on residential customers in order to obtain
more subsidies. For these reasons and in order to simplify the analysis, the
rate impacts averaged across all customer classes were used in order to
calculate the subsidies.
SUBSIDIES
The present value of subsidies under the ratemaking required by HR-4567
(i.e. "statewide levelized") ranges from zero to $2.4 billion depending on the
bill's implementation (see Figure 3-1). Note that the present value of the
subsidies under the High Cost Default case represents less than three percent
of the present value of utility compliance costs (i.e., $2.4 billion out of
$81.6 billion), As noted before, it is unlikely that a state which defaults
would be considered eligible for subsidies.
If subsidies were provided based on traditional utility ratemaking under
the bill, the present value of subsidies would range from $3,7 to $18.4
billion (see Figure 3-1). If permitted on this basis, subsidies would be
higher because subsidies would be provided to utilities with rate increases
greater than ten percent but located in states where the average levelized
rate increase is less than ten percent. Subsidies would also be higher under
traditional rate practices than on a levelized basis because some utilities
with high capital costs have higher rate increases than ten percent in the
early years under revenue requirements based rates but not under levelized
rate increases. In the Low Cost case, the present value of the subsidies are
thirteen percent of the present value of utility costs ($3.7 out of $28.7
billion). In the High Cost Default, the subsidies are twenty three percent of
costs on a present value basis ($18.4 out of $81.6 billion).
State level subsidies in present value terms are shown for these four
cases and compared with the present value of compliance costs (See Table 3-3).
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3-5
FIGURE 3-1
PRESENT VALUE OF SUBSIDIES
50
40
Billions an
of Early
1985 Dollars
20
10
0
* Note that the bill stipulates that subsidies would only be provided if rate
impacts were calculated on a "statewide levelled" basis
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Statewide Utility
Levelized Traditional1
Statewide Utility
Levelized Traditional
l
Low Cost
High Cost Default
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3-6
In calculating the subsidies, it was assumed that Phase One requirements
would be met in 1995 and Phase Two requirements would be met in 2000. Because
no year by year modeling of compliance costs was performed for the study and
no additional forecasts were developed after 2000 it was assumed that the cost
forecasts would be the same from 1995 through 1999 and the forecasts in 2000
would continue to be the same for thirty years to 2029. Thirty years was
selected because a 60 year powerplant lifetime was assumed and by 2000, most
existing (non-NSPS) powerplants required to reduce emissions would be 25-45
years old (i.e., most existing non-NSPS plants were brought on line between
1955 and 1975). Hence, compliance costs for a number of plants would be
expected to continue for about 30 years after 2000. However, it is probably
conservative to assume that total costs would be the same in 2029 as in 2000,
since the increasing mix of new NSPS plants will lower average emission rates
over time and thereby lower reduction requirements and costs by 2029.
Subsidies were assumed to be provided for rate impacts greater than ten
percent for all customer classes even though the bill specifies subsidies for
residential customers only. This assumption was made in part because it is
difficult to predict how costs will be allocated to the different classes of
ratepayers. This difficulty is increased because the bill as currently
structured creates incentives to load a large portion of cost impacts onto
residential ratepayers in order to receive the maximum level of subsidies.
TAXES
HR-4567 taxes utility fossil electricity generation and power imports
beginning in 1989 and ending in 1996 in order to provide funding for the
subsidies (see Figure 3-2). The bill stipulates that this tax cannot exceed
0.5 mills per kilowatt hour. This tax would be more than adequate to fully
fund the subsidies if statewide levelized (i.e., the ratemaking practice
required by the bill in order to receive subsidies) rate impacts were
subsidized in the Low Cost or Default cases. A 0.5 mill per kilowatt hour tax
would also be more than enough to fund subsidies in the Low Cost case if
utility by utility (as opposed to a statewide average) rate impacts were
subsidized. The tax, however, would not generate enough funds for the
required subsidies if utility traditional rate impacts were subsidized in the
Default cases. The present value of required taxes over the 1989 to 1996
period is shown by region for these four cases in Table 3-4.
The year by year cash flows under the subsidy/tax scheme are illustrated
below for the High Cost Default case under statewide levelized ratemaking
(i.e., the ratemaking practice required by the bill in order to receive
subsidies) (see Figure 3-3). Initially, tax revenues are greater than
required outlays and the fund shows a positive balance. In the later years
the fund has been fully expended. Note that for the Low Cost case under
equivalent ratemaking, no subsidies would be required and hence the tax and
fund would be zero throughout.
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3-7
FIGURE 3-2
REQUIRED ELECTRICITY GENERATION TAX
1989-1995
Statewide Utility
Levelized Traditional
Statewide Utility
Levelized Traditional
Low Cost
High Coit Default
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3-8
FIGURE 3-3
PRESENT VALUE OF TAX, SUBSIDY AND FUND OVER TIME1
High Cost Default
Year
Tax rate Is 0.291 mllls/kwh, the rate necessary to ensure that revenues cover outlays. All numbers
are In early 1985 dollars and In present value terms. Present values were calculated using a
4.2S percent discount rate.
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3-9
TABLE 3-3
PRESENT VALUE OF COMPLIANCE COSTS AND SUBSIDIES'-1
(Billions of Early 1985 Dollars)
Low Cost
High Cost Default
Subsidies
Subsidies
Subsidies
Subsidies
Compliance
Statewide
Utility
Compliance Statewide
Utility-
Costs
Levelized
Traditional8-1
Costs
Levelized
Traditional
MV
+0.3
+0.7
MC
+0.5
-
-
+1.6
-
NY 1/
+0.1
-
-
+1.7
-
PA
+3.4
-
-
+6.1
-
+1.0
NJ
+0.2
-
-
+1.2
-
.
MD
+0.3
-
-
+1.9
-
+0.4
VA
+0.2
-
-
+1.3
-
-
WV
+1.9
-
+0.1
+4.7
+0.6
+0.9
CA
+0.6
-
-
+4.2
-
+0.8
GA
+0.9
-
-
+3.5
-
+0.1
FL
+1.0
-
-
+4.1
-
+0.2
OH 2/
+5.3
-
+1.0
+11.1
+0.3
+5.7
MI
+0.6
-
+0.1
+3.0
-
+0.1
IL
+2.0
-
+0.4
+4.5
-
+1.8
IN
+4.1
-
+1.4
+7.8
+ 1.5
+4.0
WI
+0.5
-
-
+1.6
-
+0.2
KY 3/
+1.6
-
+0.2
+3.4
-
+1.5
TN 4/
+1.7
-
-
+3.9
-
-
AL
+0.6
-
-
+1.9
-
+0.1
MS
+0.3
-
+0.2
+0.7
-
+0.3
MN
-
-
-
+0.5
-
+0.1
IA
+0.1
-
-
+0.8
-
+0.1
MO
+1.3
-
+0.1
+4.7
-
+0.9
AR
-
-
-
+0.3
-
-
LA
-
-
-
+0.1
-
-
Total 31-Eastern
States 7/
+27.6
-
+3.5
+75.2
+2.4
+18.2
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3-10
TABLE 3-3 (Continued)
PRESENT VALUE OF COMPLIANCE COSTS AND SUBSIDIES8-1
(Billions of Early 1985 Dollars)
Low Cost High Cost Default
Subsidies Subsidies Subsidies Subsidies
Compliance Statewide Utility Compliance Statewide Utility
Costs
Levelized Traditional8-1
Costs
Levelized
Traditional
DA
+0.1
+1.4
_
+0.1
KN
+0.1
+0.1
+0.8
-
-
OK
+0.1
-
+1.0
-
-
TX 5/
+0.3
-
+2.2
-
-
MT
-
-
-
-
-
WY
+0.1
-
+0.3
-
-
ID
-
-
-
-
-
CO
+0.1
+0.1
+0.3
-
-
NM
-
-
-
-
-
UT
-
-
+0.1
-
-
AZ
+0.1
-
+0.1
-
-
NV
+0.1
-
+0.2
-
-
WO
-
-
+0.2
-
-
Cal. 6/
-
-
+0.1
-
-
Total 17-Western
States 7/
+ 1.0
+0.2
+6.4
-
+0.1
Total U.S. 7/
+28.7
+3.7
+81.6
+2.4
+18.4
2/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
8/ Note that the bill stipulates that subsidies and.thus taxes would only be
provided if rate impacts were calculated on a "statewide levelized1 basis.
9/ Present values were calculated using a 4.26 percent discount rate.
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3-11
TABLE 3-4
PRESENT VALUE OF FOSSIL GENERATION
AND POWER IMPORT TAXES9-1
(Billions of Early 1985 Dollars)
Low-Cost
Statewide
Levelized
Utility
Traditional8-1
High Cost Default
Statewide
Levelized
Utility
Traditional8-1
MV
MC
NY 1/
PA
NJ
MD
VA
WV
CA
GA
FL
OH 2/
MI
IL
IN
WI
KY 3/
TN 4/
AL
MS
MN
IA
MO
AR
LA
Total 31-Eastern
States 7/
+0.1
+0.1
+0.1
+0.2
+0.1
+0.1
+0.1
+0.2
+0.1
+0.2
+0.2
+0.1
+0.1
+0.2
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+2.8
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+1.6
+0.3
+0.3
+0.7
+0.9
+0.2
+0.3
+0.2
+0.7
+0.8
+0.6
+0.8
+1.1
7
.5
.9
.4
.7
+0.
+1.
+0.
+0.
+0.
+0.6
+0.4
+0.3
+0.3
+0.3
+0.5
+0.2
+0.4
+13.1
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3-12
TABLE 3-4 (Continued)
PRESENT VALUE OF FOSSIL GENERATION
AND POWER IMPORT TAXESSJ
(Billions of Early 1985 Dollars)
Low-Cost
DA
KN
OK
TX 5/
MT
WY
ID
CO
NM
UT
AZ
NV
WO
Cal.
Statewide
Levelized
6/
Total 17-Western
States 7/
Total U.S. 7/
Utility
Traditional8-1
+0.1
+0.1
+0.5
+0.1
+0.1
+0.1
+0.1
+0.1
+0.1
+1.3
+3.7
High Cost Default
Statewide
Levelized
+0.1
+0.1
+0.3
+0.1
+0.6
+2.4
Utility
Traditional8-1
+0.2
+0.4
+0.5
+2.3
+0.1
+0.3
+0.3
+0.2
+0.3
+0.3
+0.2
+0.1
+0.6
+5.8
+18.4
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
2/ Totals may not add due to independent rounding.
8/ Note that the bill stipulates that subsidies and thus taxes would only
be provided if rate impacts were calculated on a "statewide levelized"
basis.
9/ Present values were calculated using a 4.26 percent discount rate.
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Chopter Four
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CHAPTER FOUR
CAVEATS AND UNCERTAINTIES
There are a number of caveats, assumptions and uncertainties which have an
important effect on the findings of this analysis. These are discussed in the
following eight sections:
Nitrogen Oxide Control Assumptions -- This
section discusses assumptions made about nitrogen
oxide control technologies including combustion
modifications and Selective Catalytic Reduction (SCR),
a post-combustion technology.
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.
Uncertainties in Implementation, Electric Rate and
Subsidy Forecasts -- The section discusses the
uncertainties associated with implementation of
HR-4567, individual electric utility rate increase
estimates and uncertainties in the calculation of
subsidies.
Site-Specific Constraints Affecting Alternative
Reduction Strategies -- This section discusses
site-specific costs and constraints which can
significantly affect individual powerplant compliance
decisions.
Base Case Assumptions -- This section highlights
some key EPA Base Case assumptions such as electricity
growth rates and world oil and gas prices.
Restricting Utility Forecasts Between Scenarios
-- This section identifies variables such as gas
consumption and interregional power flows and new coal
and nuclear powerplant builds that are restricted in
the HR-4567 cases to levels in the Base Case.
Direct Costs and Near-Term Constraints Not
Analyzed -- This section identifies certain costs
not analyzed such as impacts associated with
industrial and motor vehicle controls, oil and gas
price changes associated with forecast changes in
utility oil and gas demand and near-term constraints
that might affect compliance decisions and forecasted
impacts in 1993.
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4-2
Indirect Costs Not Measured -- This section
discusses indirect costs of HR-4567 not analyzed such
as administrative and transaction costs.
Benefits Not Measured -- This section discusses
the benefits of emission reductions associated with
HR-4567 which were not analyzed.
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4-3
NITROGEN OXIDE CONTROL ASSUMPTIONS
The nitrogen oxide emission limits of HR-4567 are implemented differently
in the Low Cost and Default cases, and therefore, the nitrogen oxide control
technologies and cost assumptions differ between cases. The most important
difference is that in the Default case many utilities are assumed to retrofit
Selective Catalytic Reduction (SCR), a post-combustion control technology that
is far more costly than the other nitrogen oxide controls. The NOx control
assumptions are summarized below:
Low Cost Case -- Utility annual statewide average
nitrogen oxide emission rates for all fossil fuels must
be at or below 0.6 lbs./MMBtu by 2000. In general,
utilities are assumed to comply by retrofitting
combustion modification controls on existing coal-fired
powerplants (see Table 4-1). In a few states,
utilities would retrofit SCR systems because combustion
modifications would not achieve the necessary
reductions. NSPS revisions are also required and are
assumed to be met with combustion modifications.
Default Cases -- Individual utility fossil
powerplant units must emit NOx at or below 0.6
lbs./MMBtu by 2000. Most existing powerplants are
assumed to comply through combustion modifications.
Units with cyclone furnaces and wet bottom pulverizer
designs are assumed to retrofit SCR because they
cannot significantly modify their combustion processes
to achieve the necessary NOx reductions. NSPS
revisions are the same as in the Low Cost case.
However, unlike the Low Cost case, other NSPS
powerplants, such as Lignite NSPS units and NSPS
Subpart D units (subject to the first version of NSPS
passed in 1971), must control emissions because the
0.6 unit-by-unit limit is lower than their current
limits. This amounts to 0.2 million tons of
reductions in 2000.
SCR -- SCR is a post-combustion technology which
combines ammonia with nitrogen oxide in the presence
of a catalyst to remove nitrogen oxide. SCR has the
advantages of being able to achieve higher nitrogen
oxide removal efficiencies than combustion controls
and being able to be used on any type of powerplant,
even those whose combustion systems cannot be changed.
SCR can remove 70-90 percent of nitrogen oxide while
combustion controls can only achieve 40-50 percent
removal. SCR was assumed to be retrofit on coal-fired
powerplants with cyclone furnances or wet bottom
pulverizer designs in the Default cases where these
units were required to meet a 0.6 lb/MMBtu nitrogen
oxide emission limit. SCR was necessary because these
units emit at high NOx rates and cannot use more
conventional Nox controls involving combustion
modifications.
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TABLE 4-1
NOX CONTROLS -- HR-4567
Case
Low Cost
Low Cost
DefauIt
DefauIt
Affected Capacity
Ex IstIng
New NSPS Bituminous 1/
New NSPS Subbiturninous 1/
Exi sting
New NSPS Bituminous
New NSPS Subbiturninous
NSPS Lignite 2/
NSPS Subpart D 3/
NOX Limit
t lbs NOX/MMBtu)
0.6 Statewide
Ave rage
0.4 unit-by-unit
0.35 unit-by-unit
0.6 unit-by-unit
0.14 unit-by-unit
0.35 unit-by-unit
0.6 unit-by-unlt
0.6 unit-by-unlt
Coal Powerplant Firing/Control Technology
Tangential/Enriched Fireball
Wa I I-fired/Distributed Mixing Burner
Distributed Mixing Burner
Distributed Mixing Burner
Tangent I a I/Over Fired Air Posts
Comme rc i a I Iy Ava iI a bIe
WaI I-fired/Low NOX Burners
Cyclones, Wet Bottoms/SCR
Distributed Mixing Burner
Distributed Mixing Burner
Commercially Available Low NOx
Commercially Available Low NOx
Burner
Burner
1/ Defined as beginning construction after the bill's passage.
2/ AM subparts D and Da-1.3. 1971 and 1978 versions of NSPS.
1/ 1971 version of NSPS.
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4-5
Nitrogen oxide reductions using SCR are far more
costly on a dollar per ton reduced basis than
reductions achieved using combustion modifications
(See Figure 4-1). SCR costs around 1030 dollars per
ton removed versus 60-120 dollars per ton removed for
combustion modifications. SCR costs were a
significant portion (16 percent) of total annual
utility costs in the Default cases in 2000.
SCR costs are uncertain reflecting a lack of
experience with the technology. SCR systems are in
use in the Federal Republic of Germany and Japan, but
since the inlet concentrations of nitrogen oxide and
sulfur dioxide abroad are far lower than those of
cyclones and wet bottom pulverizers used in the United
States this experience may not be germane. The cost
estimates for SCR in this analysis are based on work
done in the U.S. by the Electric Power Research
Institute (EPRI).lJ EPRl's estimates of $85/kw of
capital cost and $21.5/kw-yr of fixed operation and
maintenance costs (all O&M costs were assumed to be
fixed) were based on very limited experience with
units using high sulfur coal. Nitrogen oxide inlet
concentrations tested by EPRI were well below those
experienced in cyclones and wet bottom pulverizers.
The highest nitrogen oxide inlet concentration
examined, and the basis for the cost estimate used,
was about two-thirds of that which would occur in
cyclones. Thus, costs could be even higher than
assumed here.
Based on the EPRI experience, there are concerns about
potential technical problems caused by using SCR on
powerplants that burn high sulfur coals. Chemical
components of these coals may "poison" the catalyst
reducing catalyst lifetimes (assumed to be one year)
and increasing costs. High nitrogen oxide concentra-
tions combined with variable loads might also lead to
ammonia breakthrough which could damage downstream
equipment, especially scrubbers. Note that units
assumed to retrofit SCR are also forecast to retrofit
scrubbers in many cases.
Combustion Modifications --In both the Low Cost
and Default cases, combustion modifications achieve
most nitrogen oxide reductions. These are relatively
low cost adjustments to burner and boiler operations.
Cost and performance assumptions for combustion
modification controls were provided by EPA and are
summarized in Tables 4-1, 4-2 and 4-3.
1JEPRI report CS-3603 prepared by Stearns-Roger entitled Selective
Catalytic Reduction for Coal-Fired Powerplants: Feasibility and Economics
October 1984.
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4-6
FIGURE 4-1
NITROGEN OXIDE EMISSION REDUCTION COSTS
1000-
800-
1030
Early 1985
Dollars per 600-
Ton Removed
400-
200-
120
Distributed
Mixing Burners
210
SCR
Combustion Modifications
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TABLE 4-2
COMBUSTION MODIFICATION ASSUMPTIONS FOR EXISTING POWERPLANTS
. Technology
DMB 1/
Enriched F f rebaI I
Low NOX
Bu rne r-Comme rcI a 11y
Ava iI able
Ove r-F i red
Ai r Ports
Add I I cat ion
Powerolant Type
Wa I I - F I red
Tangent i a I-F i red
WaIl-Fi red
Case(s)
Low Cost
Low Cost
DefauIt
TangentiaI-Fired Default
ControI led
Emi ss i on
Rate
0.5
0.1
0.6
0.6
Costs (Early 1985 S)
Capital Fixed O&M
fS Per kw) (S Per kw-yr)
13.8
ซป.28
7.37
Z.ZU
0.55
0.17
1.07
0.13
1/ Distributed Mixing Burner
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4-8
In the Low Cost case, utilities choose the most cost
effective nitrogen oxide controls reflecting the
implementation flexibility of this case. It is
assumed that by 2000 "second generation" nitrogen
oxide controls can be retrofitted onto existing
coal-fired powerplants. Powerplants with tangentially
fired burners are assumed to retrofit enriched
fireball technology reducing nitrogen oxide emission
rates from 0.68 to 0.4 lbs/MMBtu. (See Table 4-2).
Wall-fired powerplants are assumed to retrofit
distributed mixing burners reducing nitrogen oxide
emissions from 0.95 to 0.5 lbs MMBtu.
In the Default case each existing coal-fired
powerplant must meet an 0.6 lb per MMBtu nitrogen
oxide limit. As discussed earlier, cyclones and wet
bottom pulverizers are assumed to retrofit SCR
reducing emissions to 0.6 lbs/MMBtu. Tangentially
fired units are assumed to install over-fired airports
reducing emissions to 0.6 lbs/MMBtu. Wall-fired coal
units are assumed to retrofit commercially available
low nitrogen oxide burners reducing emissions to 0.6
lbs/MMBtu.
New NSPS Powerplants -- Both bituminous and
subbituminous NSPS powerplants that begin construction
after the bill is passed are assumed to use
distributed mixing burners to meet the 0.4 and 0.35
lb. limits, respectively. Cost assumptions are shown
in Table 4-3. It should be noted that the required
limits are very stringent and may be difficult to
achieve given current experience with conventional
controls.
In the Default cases, all powerplants including NSPS
units must meet the 0.6 lb. NOX/MMBtu limit. Lignite
NSPS units and other NSPS units subject to subpart D
(1971 NSPS limits) must therefore reduce emissions.
Assumptions for these powerplants are contained in
Table 4-3.
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TABLE 4-3
COMBUSTION MODIFICATION ASSUMPTIONS FOR NSPS POWERPLANTS
o
o
39
T3
O
5
si
o
Technology
OMB 1/
0MB
DMB
Low NOX Burner
Commerc iaIly
AvaI lable
Powerplant Type
Add I 1 cat ion
Case(s)
New NSPS Bituminous 2/ All
New NSPS Subbiturninous 2/ All
NSPS Lignite Default
NSPS Subpart 0 Default
Controlled Costs (Early 1985 S)
Emission Capital Fixed O&M
Rate t $ Pe r kw) (S Per kw-vrl
O.U
0.35
0.6
0.6
5.21
5.21
5.21
7.37
0.21
0.21
0.21
1 .07
I
VO*
o
1/ Distributed Mixing Burner
2/ 'Powerplants which begin construction after the bill's passage
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4-10
SULFUR DIOXIDE CONTROL EQUIPMENT COSTS AND ASSUMPTIONS
Sulfur dioxide control costs, removal efficiencies, retrofit factor,
scrubber types, new control technology assumptions have an important impact
on the forecasted costs and coal production of the various emission reduction
cases. These costs for retrofit scrubbers are shown in Table 4-4 on page 4-11
are discussed below:
Costs -- The level of scrubber costs will affect
the forecasted costs of HR-4567, particularly in the
Default cases. Higher or lower scrubber costs will
accordingly raise or lower the forecasted cost impacts.
The relative costs of scrubbing high versus lower
sulfur coals could influence forecasted coal
production. If the costs of scrubbing lower sulfur
coals were much cheaper than assumed currently, more
medium or low sulfur coals might be scrubbed with
shifts away from high sulfur coal production as a
result.
An important assumption affecting the relative costs
of scrubbing low versus scrubbing high sulfur coals is
that retrofitting dry scrubbers would also require the
installation of a baghouse. If existing ESPs
(electrostatic precipitators) could be used with dry
scrubbers without added costs and/or technical
difficulties, the costs of scrubbing medium and
perhaps higher sulfur coals would be lower. (Note dry
scrubbing was assumed to be limited to 80 percent
removal but could be used with coals of all sulfur
contents).
Lower scrubber costs would result in a reduction in
the costs particularly under the Default cases and
would alter forecasted coal production. Lower
scrubber costs would induce powerplants to retrofit
more scrubbers and scrub higher sulfur coals rather
than switching to lower sulfur coals. High sulfur
coal production would likely benefit.
Higher scrubber costs would have the opposite effects
under the Default cases. However, higher scrubber
costs have little effect on the Low Cost case because
very few scrubbers are forecast to be retrofitted.
Retrofit Factors -- Plant-specific retrofit
factors ranging from 1.1 to 2.0 (applied to capital
and fixed O&M of a new scrubber) were used in this
analysis to capture the difficulties and constraints
inherent in retrofitting a scrubber on an existing
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TABLE 4-4
RETROFIT SCRUBBER COSTS FOR
EXISTING UTILITY POWERPLANTS - 1.1 FACTOR
Coal After Preparation
0.80
1.08
1.67
2.50
3.33
5.00
6.67
Scenario Specifications
A. Annual S02 Emission Limit
ฃ
(lbs./lO Btu)
0.16
0.22
0.34
0.25
0.33
0.50
0.67
B.
Annual S02 Removed
ฃ
0
(lbs./10 Btu)
0.64
0.86
1.32
2.25
3.00
4.50
6.00
C.
Percent Removal
80%
80%
80%
90%
90%
90%
90%
D.
Scrubber Type
Dry
Dry
Dry
Wet
Wet
Wet
Wet
Scenario Cost (early 1980 $'s)
A.
Capital ($/kw)
134.3
152.6
162.2
161.7
167.6
180.2
186.7
B.
O&M
-- Fixed ($/Kw-yr.)
Variable (mills/Kwh)
3.86
1.07
3.98
1.23
4.09
1.69
6.95
1.37
7.21
1.48
7.75
1.65
7.82
1.81
C.
Capacity Penalty (%)
1.67
1.67
1.67
1.96
2.06
2.22
2.38
D.
Energy Penalty (%)
2.70
2.70
2.70
4.42
4.51
4.68
4.70
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 costs of a
new scrubber reflecting a ten percent escalation for three-quarters
of the fixed O&M costs). Most existing powerplants have higher
costs. Powerplants with no plant-specific estimates were treated as
follows:
Size
Capital Cost
Relative to a
New Scrubber
Fixed O&M
Cost Relative to
a New Scrubber
Greater than 400 Mw
Between 150 and 399 Mw
Less than 150 Mw
110%
140%
200%
107.5%
130.0%
175.0%
Powerplants retrofitting scrubbers are also assumed to incur a reliability
penalty of 2.7 percent.
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4-12
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 plants in scrubbing costs have an
important impact 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 powerplants,
alternative estimates were used based on powerplant
unit size. (See Table 4-4).
Table 4-5 shows the retrofit factors for existing
unscrubbed coal capacity under current EPA assumptions.
Currently, there are 81 gigawatts of utility power-
plants with retrofit costs assumed to be 10-20 percent
higher than the costs of new scrubbers. About 59
gigawatts of this category is non-NSPS capacity.
Higher or lower retrofit factors than assumed herein
will accordingly raise or lower the forecasted cost
impacts and result in different powerplants
retrofitting scrubbers.
Scrubber Lifetime -- For this analysis, it was
assumed that retrofit 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. If a fifteen
year life is used, annualized capital costs would
increase by about 75 percent. As shown in Figure 4-2
total incremental costs of scrubbing (i.e., scrubber
capital, scrubber 0&M and additional fuel and power
costs associated with scrubbing) would increase by 36
percent. This would have a similar effect on
forecasted costs and coal production as the increase
in the level of scrubber costs discussed previously on
page 4-10.
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TABLE 4-5
EPA's
RETROFIT SCRUBBER COST FACTORS
BY POWERPLANT CAPACITY1J2J
(GW)
Retrofit Factors
1.1-1.2 1.3-1.6 1.7-2.0 Total
81.0 59.7 67.8 208.5
lJ Retrofit factors represent the rate of escalation of capital and a
portion of fixed O&M costs of retrofit scrubbers relative to the costs of new
powerplant scrubbers.
2JEight 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 and new unscrubbed capacity on-line as of end-1980
potentially 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 category.
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FIGURE 4-2
INCREMENTAL RETROFIT SCRUBBING COSTS^
20 n
is H
Early IMS
MIUa/Kwh
10 ^
5-4
17.3
1 3.7
8.0
0.3
0.7
M
10.6 Annualliad Scrutator
Capital
0.3 Additional Powor Costa
d o. Capacity NNlly)
0.7 AddlMonal Puol Coat
(i.o. Energy Pa natty)
M Sorubfeor OtM
A taunting 30 Voa#
Rotrotlt Scnifebor
Litatlmo
Aaaumlng 16 Vaar
Rotrotlt Serubbor
Lilotimo
1JMedium cost retrofit scrubbing of a 3% West Virginia, North coal
assuming a 55% capacity factor.
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Removal Efficiencies -- A maximum annual average
removal efficiency of 90 percent was assumed for
retrofit "wet" scrubbers and a maximum 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.
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 that baghouses also had to be installed
if dry scrubbers were retrofitted. Dry scrubbers are
more cost effective in those rarer instances when low
sulfur coals are scrubbed.
New Control Technologies -- New sulfur dioxide
control technologies were not assumed for this
analysis. For example, new "retrofit" control
technologies such as LIMB (Limestone Injected Multistage
Burner) or Fluidized Bed Combustion technology could
result in lower costs in meeting emission reduction
requirements in 1995. Some view new emission control
technologies as quite promising and believe they are
likely to be available at significantly lower costs than
conventional scrubbers for use by utilities by 1995.
However, given the limited operating experience and
uncertainty surrounding the costs and performance of new
control technologies (such as LIMB or fluidized bed), it
is unlikely that many utilities would pursue this option
by 1995 and uncertain whether any savings would result.
By 2000 or 2010, new emission control technologies are
likely to be more promising however.
On balance, the assumption of no new control
technologies or no control technology improvements by
1995 is probably slightly conservative and the
assumption of no new technologies in 2000 or 2010 is
more conservative. To the extent some improvements do
occur, the costs of the bill would be lower.
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UNCERTAINTIES IN IMPACTS MEASURED
Some of the impacts measured in this analysis are uncertain due to the
limited scope of this analysis. These are discussed below:
Uncertainties in Implementation -- The specific
implementation of HR-4567 is uncertain. Three cases
with different assumptions about the bill's
implementation were analyzed, establishing reasonable
upper and lower bounds of possible emission and cost
impacts.
Uncertainties in Rate Impacts -- As discussed in
Chapter Three, utility specific electricity rate
impacts were forecasted to calculate subsidies needed
to mitigate individual utility rate impacts. Certain
utility and plant specific factors were not captured
in this analysis (as discussed later in this chapter)
and individual utility and utility systems were not
modelled separately as these efforts were beyond the
scope of this analysis. Instead, CEUM was used even
though the model's focus is primarily regional and
national. As such, the required subsidies under the
various programs assessed should be viewed as
approximate estimates. As discussed in Chapter Three
electricity rate impacts will also depend on
interutility electricity purchases, transmission
agreements and other factors.
Uncertainties in Subsidy Calculations -- The cost
and subsidy forecasts made in 2000 were assumed to
continue through 2029. To the extent costs and
subsidies decrease in later years, the present value
of subsidy estimates are overstated. Subsidies were
also assumed to be provided for all rate impacts
greater than ten percent even though the bill
specifies subsidies for residential customers only.
This assumption was made because it is difficult to
predict how costs will be allocated among classes of
rate payers, and there are incentives for states to
allocate all the costs to residential ratepayers in
order to maximize the portion of costs subsidized. If
rate impacts were spread to industrial and commercial
classes, the subsidy estimates would be lower than
reported.
Uncertainties in Employment Estimates -- 1985
mining employment figures used in the analysis were
estimates. Also, adjustments for miner retirements
were estimated regionally from national 1980 UMWA age
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4-17
data assuming each region's age profile was similar to
the national miner age profile. As such, the
estimates of changes in mining employment and
particularly miners displaced should be viewed as
approximate.
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, power-
plant specific retrofit factors were applied to the
cost of a new scrubber to account for site-specific
difficulties in retrofitting scrubbers on existing
powerplants.
Coal Switching Costs -- Coal switching costs were
developed recently 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., refurbishing existing or building
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 powerplants
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 4-6
for 200 and 500 Mw 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 this is true, switching costs would be
lower than noted herein. Higher or lower coal
switching costs influence which powerplants choose to
switch coals and how much fuel switching occurs
relative to retrofit scrubbing, although as noted only
a relatively limited amount of capacity is affected by
these constraints.
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TABLE 4-6
COAL SWITCHING COSTS
(Early 1985 $/KW)
Medium Cost - Refurbishing
Existing Rail Lines and
Coal Handling Equipment1-1
Plant Size (MW)
200 500
115 70
High Cost - Constructing a new 265 130
Rail Spur, Purchasing New Coal
Handling Equipment2-1
^Assumes 15 mile spur refurbishment at $1 million/mile.
2J Assumes 15 mile spur construction at $3 million/mile.
Source: ICF estimates.
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Particulate Upgrade Costs -- Particulate upgrade
costs for powerplants switching to lower sulfur coals
were developed for EPA. The estimates were designed
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 installation 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 4-7 are average costs which assume
75 percent of the powerplants that switch to lower
sulfur coals will install flue gas conditioning, while
the remaining 25 percent will add new plate area.
Higher or lower particulate upgrade costs influence
which powerplants 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
limitations 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.
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 were
assumed to be abrogated, reflecting the exercising of
"force majeure" provisions. Aside from these
constraints and 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 very
low-sulfur coals. There are a few existing unscrubbed
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TABLE 4-7
PARTICULATE REMOVAL EQUIPMENT UPGRADE COSTS FOR
EXISTING UTILITY COAL-FIRED POWERPLANTS GOING TO
LOWER-SULFUR COALS
(early 1985 $/kw)
Coal-Type* 0.08 1.08 1.67 3.33 2.50 5.00 6.67
0.80 . . . . . . .
1.08 12 . . . . .
1.67 13 10 ....
2.50 15 13 10 . . .
3.33 16 15 13 10 . .
5.00 18 16 15 12 9
6.67 18 16 15 12 9 4
* lbs. SO,,/10^ Btu cleaned coal.
is ic if iflr * tfr
Note that for the above assumed particulate upgrade costs.
Costs are applied to all existing powerplants
which shift to lower-sulfur coals.
Costs are also applied to existing powerplants
which retrofit scrubbers and shift coals.
Source: Energy Ventures Analysis estimates developed for EPA.
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4-21
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
powerplants designed to burn bituminous coals were not
permitted to shift to lower rank coals (e.g., from
bituminous to subbituminous or lignite) 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 regional coal production in the West would be
spread among more regions and the cost impacts would
decrease.
Railroad Pricing Practices -- ICF estimates rail
rates as the long-run variable costs of rail
transportation (although ICF's estimates of long-run
variable costs are approximate and should be
improved). This cost-based rate is the lowest rate a
railroad would offer. The use of cost-based rates
will result in forecasting the correct compliance
option (i.e., the least-cost option). However, the
railroad will not offer the cost-based rate. The
railroad will charge just less than the next best
alternative. Where little competition exists, this
charge will be much higher than the cost-based rate
because the cost of the next best alternative will be
much higher. 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 stock- holders or
ratepayers (depending on ICC regulations). The costs
presented herein then represent "costs to society".
Costs to utility ratepayers would be higher in some
but not all circumstances. Utility ratepayer cost
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impacts could be estimated, but were not. This
subject and the potential effect of railroad pricing
behavior on the impacts forecast for the emission
reduction cases is worthy of investigation.2-1
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. However, the development of such
constraints were beyond the scope of this study, and
hence, no such constraints were incorporated.
BASE CASE ASSUMPTIONS
As noted in Chapter One, EPA specified a Base case for this analysis.
Base case assumptions are presented in Appendix D. Important assumptions
pertaining to emissions and cost impacts forecasted herein are discussed below.
Electricity Growth Rates -- Lower electricity
growth rates would lower the utilization of some
existing powerplants in the Base case and lower Base
case sulfur dioxide and nitrogen oxide emissions. This
would also tend to lower the required reductions of
sulfur dioxide and nitrogen oxide emissions, although
not significantly in the case of HR 4567 and thus lower
the costs of meeting the targeted emissions levels under
the cases examined. Higher growth rates would tend to
have the opposite effects.
Nuclear Capacity and Availability -- The
assumptions used by EPA for this analysis specified that
nuclear capacity would be built based on current
schedules and the availability and reliability of
nuclear plants would improve by 1995. Nuclear capacity
factors were assumed to increase from 1984 levels of
below 60 percent to 67 percent by 1995. This increase
in capacity factors assumes that low capacity factors
experienced currently resulting in part from increased
NRC scrutiny following the accident at Three Mile Island
in 1979 and other technical problems will be resolved
2JSee memorandum to Rob Brenner, EPA entitled Transportation Rate
Assumptions for Coal Market Modeling, June 26, 1984; also see memorandum to
Rob Brenner entitled Response to Comments Received on July 26, 1984 Memo
Entitled "Transportation Rate Assumptions for Coal Market Modelling", April 5,
1985.
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and there will be relatively few, new NRC regulatory
requirements after the post-TMI requirements are
completed. Lower estimates of t>he future availability
and reliability of nuclear plants and of nuclear
capacity would result in increased utilization of
existing fossil fuel powerplants and more new coal
powerplants built. Base case emission forecasts would
be higher, and required reductions from existing
plants and costs would also be higher, although not
significantly. Higher nuclear estimates would have
the opposite effects.
World Oil Prices and Gas Prices -- The world oil
prices and gas prices used in this analysis were
developed about two years ago when EPA developed its
current Base case. In light of the recent decline in
prices, EPA has decided to analyze the sensitivity of
the base case forecasts to lower oil and gas prices.
This analysis is currently underway. Lower oil prices
below 20-25 dollars per barrel range would slow the
replacement of existing oil steam powerplants with new
coal-fired powerplants (i.e. accelerated replacement)
particularly in the Gulf states. However, even with
prices at 13-17 dollars per barrel, 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, 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, this range of prices
will have relatively little impact on the cost and
coal production impacts of the cases. Oil prices
significantly below 13 dollars 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 cost and
coal production forecasts.
Coal Mining Productivity -- Estimates of the
future gains in coal mining productivity (i.e. tons
per worker-year) have an important impact on the coal
mining employment forecasts and 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
would generally be lower and thus the costs of coal
switching would also be lower. Further, coal mining
employment levels would also be lower. Smaller gains
would have the opposite effects.
Stack Height Regulations -- The effect of the
stack height regulations were not included as part of
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the Base case for this analysis. Recent analysis
conducted by ICF3J indicates that based on
assessments by EPA regional authorities and state air
pollution officials the promulgated regulations could
result in utility sulfur dioxide emissions being about
0.4 million tons lower in 1995. Overall costs to
utilities of meeting both the emission reduction
program and the stack height regulations would be
higher than meeting the emission reduction program
only. This is because the stack height regulations
require emission reductions which are not cost-
effective in many instances.
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 costs could be lower. However,
the effect of this increase in demand for gas on gas
prices could increase national consumer costs
substantially.
Electricity Transmission -- was constrained to
the interregional flows occurring 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 Powerplant Builds -- were also
held to Base case levels. Different powerplant builds
would affect the forecasted changes in costs, though
only slightly.
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 were beyond the scope of this
particular analysis, although they have been the-subject of other analytical
efforts by ICF.
3jSee ICF report submitted to EPA entitled Analysis of the Promulgated
Stack Height Regulations, August, 1986.
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Industrial and Motor Vehicles Provisions -- As noted
earlier, at EPA's direction, emission reduction require-
ments in the industrial boiler and industrial process
sectors and emission limits for motor vehicles were not
analyzed. These requirements could result in significant
costs but it is believed by EPA that most of the costs
of HR 4567 would be borne by the utility sector.
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 this low sulfur
product.
Gas Prices -- were not assumed to increase for this
analysis. Gas consumption was also assumed to not
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 unless the Default is required by 1993.
Scrubber Manufacturing Constraints -- were not assumed
in this analysis. However, in the Default cases 30-51 Gws
of retrofit scrubbers are forecast to be constructed by
1995, and could be required as early as 1993. It may be
difficult to build this many scrubbers over so short a
period of time and could' therefore drive up the costs of
building a scrubber. Thus, scrubber costs may be greater
than estimated.1'-1
INDIRECT COSTS NOT MEASURED
Many of the indirect costs of the emission reduction programs were not
measured for this analysis. These include the following types of costs:
Administrative Costs -- could be significant for
HR-4567 because of the tax and subsidy programs. Also,
-------
4-26
under the Low Cost case, regulatory mechanisms would
be needed to implement a trading or least cost
allocation program.
Lost Investment 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 long-term coal contracts 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 depending 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
understate the expected impacts.
Indirect and Regional Impacts of New Mining,
Transportation, and Manufacturing Jobs -- will vary
with the forecasted increases in regional mining
employment, shifts in coal shipments, and increases in
manufacturing (e.g., retrofit scrubbers and nitrogen
oxide control equipment).
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 in that some of the required reductions would be
achieved by producing less electricity. This effect
would be most important in the Default cases because
of the programs' high compliance costs. However,
there would also be a loss to consumers (i.e. a loss
in consumer surplus, in economist's 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.
ICF INCORPORATED
-------
4-27
Impact of Taxes -- This analysis did not assess
the impacts of taxes on utility behavior between 1989
and 1996. A tax on kilowatt-hours would tend to
reduce the demand for electricity and economic growth
(as it would raise utility costs and hence electricity
prices). Lower electricity demand would reduce
compliance costs but also would reduce consumer
surplus as discussed before. However, the impact of a
0.5 mill per Kwh tax or less would be much less than
the effect of the overall program costs noted before.
BENEFITS NOT MEASURED
Benefits of Emission Reductions -- should be weighed
against the costs of these reductions. Most appropriately, the
marginal benefits of the last ton of reduction should be
compared with the marginal costs. The cost-effectiveness of the
emission reduction program should be considered in light of the
acid deposition, health related effects, visibility
improvements, agricultural and materials damage improvements,
and other benefits forecasted to result.
ICF INCORPORATED
-------
- 'Appendix A
-------
APPENDIX A --
HR-4567 FORECASTS - 1995
ICF INCORPORATED
-------
TABLE A-l
SULFUR DIOXIDE EMISSION FORECASTS -- 1995
1980
Changes from Base
Base High Cost
1995 Low-Cost Default Default
(millions of tons)
31-Eastern States
Existing
Coal
Oil/Gas
14.92
1.27
15.61
1.03
-4.17
-7.06
-0.16
-9.45
-0.37
New
16.19
16.64
0.79
-4.17
+0.09
-7.22
+0.10
-9.82
+0.14
Total 31-Eastern States
16.19
17.43
-4.08
-7.12
-9.68
17-Western States
Existing
Coal
Oil/Gas
1.10
0.09
1.19
1.57
0.16
1.73
-0.01
-0.01
-0.17
-0.04
-0.21
-0.31
-0.09
-0.40
New
.
0.49
+0.01
+0.01
Total 17-Western States
1.19
2.22
-0.21
-0.39
Total U.S.
Existing
Coal
Oil/Gas
New
16.02
1.36
17.38
17.18
1.19
18.37
1.28
-4.17
-0.01
-4.18
+0.10
-7.23
-0.20
-7.43
+0.10
-9.76
-0.46
-10.22
+0.15
Total U.S.
17.38
19.65
-4.08
-7.33
-10.07
Note: Totals may not add
due to independent
rounding.
ICF INCORPORATED
-------
A-2
TABLE A-2
UTILITY SULFUR DIOXIDE CONTROL COST FORECASTS -- 1995
Changes from Base
Low-Cost
High Cost
Default Default
Utility Annual Costs
(billions of early-1985 $/yr.)
Capital
O&M
Fuel
Total
Utility Cumulative
Capital Costs
(billions of early-1985 $)
31-Eastern States
17-Western States
Total U.S.
Average Cost Per Ton
of S02 Removed
(early-1985 $/ton)
S02 Retrofit Scrubber Capacity (Gtf)
31-Eastern States
17-Western States
Total U.S.
+0.1
+0.2
+0.5
+0.8
+1.2
+1.2
185
+0.9
+0.8
+2.1
+3.8
+0.2
+0.2
+12.1
+0.6
+12.7
519
+27.0
+2.7
+29.7
+1.2
+1.1
+3.3
+5.6
+15.9
+ 1.1
+17.0
563
+46.1
+4.6
+50.7
Note: Totals may not add due to independent rounding.
ICF INCORPORATED
-------
A-3
TABLE A-3
UTILITY FUEL CONSUMPTION FORECASTS -- 1995
(in quads)
Utility Fuel Consumption
31-Eastern States
Coal
Low Sulfur
Low-Medium Sulfur
High-Medium Sulfur
High Sulfur
Total
Base
1995
2.60
2.43
3.99
3.98
13.00
Changes from Base
Low-Cost
+0.87
+0.38
-0.13
-1.11
+0.01
Default
-0.03
+4.89
-2.73
-2.11
+0.02
High Cost
Default
+5.89
-1.80
-2.06
-2.01
+0.01
Oil
Gas
1.39
0.96
+0.04
+0.07
17-Western States
Coal
Low Sulfur
Low-Medium Sulfur
High-Medium Sulfur
High Sulfur
Total
2.49
0.98
1.54
0.04
5.04
-0.06
+0.09
-0.04
+0.02
+0.01
-0.01
-0.03
+0.04
+0.01
+0.02
-0.08
+0.07
-0.01
Oil
Gas
26
29
-0.01
Total U.S.
Coal
Low Sulfur
Low-Medium Sulfur
High-Medium Sulfur
High Sulfur
Total
5.08
3.41
5.53
4.02
18.04
+0.81
+0.47
-0.17
-1.09
+0.02
-0.04
+4.85
-2.69
-2.09
+0.03
+5.91
-1.88
-1.99
-2.01
+0.02
Oil
Gas
1.65
3.25
-0.01
+0.04
+0.07
ICF INCORPORATED
-------
A-4
TABLE A-4
COAL PRODUCTION AND SHIPMENT FORECASTS -- 1995
(in millions of tons)
Changes from Base
Base
High Cost
1980
1995
Low-Cost
Default
Default
Coal Production
Northern Appalachia
185.1
197.5
-24.1
-67.7
-64.1
Central Appalachia
232.8
306.6
+26.8
+74.4
+43.4
Southern Appalachia
26.4
25.2
+0.4
+4.4
+4.7
Midwest
134.4
150.5
-15.1
-43.0
-51.2
West
251.0
515.9
+10.2
+28.0
+63.1
Total U.S.
829.7
1195.7
-1.9
-4.0
-3.9
Coal Transportation
Western Coal Shipped
East
36.7
59.0
+7.8
+24.8
+57.2
ICF INCORPORATED
-------
A-5
TABLE A-5
CHANGE IN TOTAL SULFUR DIOXIDE EMISSIONS BY REGION -- 1995
(Thousands of Tons)
Changes from Base
Base
High Cost
1995
Low-Cost
Default
Default
MV
100
-21
-35
-54
MC
309
-
-42
-119
NY 1/
455
-
-68
-117
PA
1290
-Ill
-508
-706
NJ
136
+ 1
-41
-63
MD
357
-3
-94
-170
VA
296
-
-31
-129
WV
1056
-307
-449
-621
CA
681
+13
+18
-207
GA
834
-57
-170
-393
FL
975
-21
-320 -
-455
OH 2/
2738
-1468
-1660
-1997
MI
476
+5
-11
-47
IL
947
-244
-469
-548
IN
1810
-768
-1122
-1270
WI
494
-34
-177
-247
KY 3/
998
-207
-528
-610
TN 4/
880
-277
-326
-522
AL
483
-7
-144
-239
MS
228
-45
-85
-127
MN
185
+1
-27
-61
IA
226
+14
-16
-64
MO
1268
-560
-824
-920
AR .
121
+12
+7
+2
LA
94
+5
+2
+2
Total 31-Eastern States 7/ 17435
-4079
ฆ7121
-9684
ICF INCORPORATED
-------
A-6
TABLE A-5 (Continued)
CHANGE IN TOTAL SULFUR DIOXIDE EMISSIONS BY REGION -- 1995
(Thousands of Tons)
Changes from Base
DA
KN
OK
TX 5/
MT
WY
ID
CO
NM
UT
AZ
NV
WO
Cal.
6/
Total 17-Western States 7/
Total U.S. 7/
Base
1995
228
315
211
799
38
69
121
56
66
122
72
119
4
2220
19655
Low-Cost
ฆ11
+9
-3
+6
-4
-2
-4081
High Cost
Default Default
-40
-42
-7
ฆ107
+1
+6
-4
-18
-212
7333
-85
-109
-31
-101
-3
+4
-9
-53
^1
-386
-10070
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
A-7
TABLE A-6
CHANGE IN ANNUALIZED UTILITY SULFUR
DIOXIDE CONTROL COSTS BY REGION -- 1995
(Millions of Early 1985 Dollars)
Changes
from Base
High Cost
Low-Cost
Default
Default
MV
+7
+32
+46
MC
-1
+55
+116
NY 1/
+6
+83
+129
PA
+28
+385
+483
NJ
+2
+56
+73
MD
+11
+105
+ 166
VA
+6
+41
+106
WV
+51
+216
+363
CA
+15
+173
+330
GA
+15
+ 120
+285
FL
+15
+191
+297
OH 2/
+262
+593
+828
MI
+22
+89
+224
IL
+57
+198
+236
IN
+107
+400
+498
WI
+5
+102
+114
KY 3/
+20
+142
+196
TN 4/
+39
+169
+243
AL
+7
+97
+158
MS
+2
+37
+75
MN
-
+16
+24
IA
+6
+42
+51
MO
+39
+258
+283
AR
+4
+7
+11
LA
+3
+3
+3
Eastern States 7/
+728
+3609
+5339
ICF
INCORPORATED
-------
A-8
TABLE A-6 (Continued)
CHANGE IN ANNUALIZED UTILITY SULFUR
DIOXIDE CONTROL COSTS BY REGION -- 1995
(Millions of Early 1985 Dollars)
Changes from Base
High Cost
Low-Cost Default Default
DA - - +68
KN - +25 +42
OK +5 +6 +25
TX 5/ - +91 +90
MT -
WY +4 +10 +2
ID -
CO +11 +16 +28
NM -
UT +2
AZ +2 +2
NV - +1 +15
WO - +4 +21
Cal. 6/
Total 17-Western States 7/ +22 +154 +294
Total U.S. 7/ +750 +3763 +5633
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TV, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
A-9
TABLE A-7
CHANGES IN RETROFIT SCRUBBER CAPACITY -- 1995
(Gw)
Changes from Base
High Cost
Low-Cost Default
Default
MV
+0.5
+0.5
MC
+0.3
+0.9
NY 1/
+0.4
+0.7
PA
+3.6
+8.6
NJ
+0.9
+0.9
HD
+0.4
+2.0
VA
-
+0.7
WV
+0.6
+0.6
CA
+1.4
+1.4
GA
+0.2
+3.8
FL
+1.9
+1.9
OH 2/
+2.6
+6.9
MI
-
+ 1.6'
IL
+3.7
+3.7
IN
+3.5
+3.5
WI
+0.7
+0.7
KY 3/
+1.2
+1.2
TN 4/
+1.1
+1.1
AL
-
+1.0
MS
-
-
MN
+0.1
+0.3
IA
+0.5
+0.5
MO
: +3.4
+3.4
AR
-
-
LA
Total 31-Eastern States 7/ - +27.0 +46.1
ICF INCORPORATED
-------
A-10
TABLE A-7 (Continued)
CHANGES IN RETROFIT SCRUBBER CAPACITY -- 1995
(Gw)
Changes from Base
DA
KN
OK
TX 5/
MT
WY
ID
CO
NM
UT
AZ
NV
WO
Cal. 6/
Total 17-Western States 7/
Total U.S. 7/
Low-Cost
+0.2
+0.2
+0.2
Default
+0.4
+2.3
+2.7
+29.7
High Cost
Default
+1.6
+0.4
+2.3
+0.2
+4.6
+50.7
JL/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
A-11
TABLE A-8
PERCENT CHANGE IN ELECTRICITY RATES BASED ON
ANNUALIZED COSTS (i.e., LEVELIZED BASIS) -- 1995 1/
(percent)
Changes from Base
CEUM
High Cost
Region
Low-Cost
Default
Default
MV
+0.4
+1.7
+2.5
MC
-
+1.1
+2.3
NY 2/
+0.1
+0.9
+1.3
PA ~
+0.3
+3.6
+4.5
NJ
-
+1.3
+1.7
MD
+0.3
+3.3
+5.3
VA
+0.2
+1.4
+3.7
WW
+1.5
+6.6
+11.1
CA
+0.2
+1.4
+4.1
GA
+0.3
+2.2
+5.2
FL .
+0.2
+2.3
+3.6
OH 3/
+3.6
+8.0
+11.1
MI
+0.4
+1.5
+3.8
IL
+0.6
+2.2
+2.6
IN
+2.1
+2.2
+9.7
WI
+0.2
+7.8
+3.8
KY 4/
+0.6
+3.5
+5.7
TN 5/
+0.8
+4.1
+5.2
AL
+0.1
+3.6
+3.1
MS
+0.2
+1.9
+5.7
MN
-
+2.8
+1.3
IA
+0.3
+0.9
+2.9
MO
+1.0
+2.4
+7.5
AR
+0.2
+0.3
+0.5
LA
+0.1
+0.1
+0.1
ICF INCORPORATED
-------
A-12
TABLE A-8 (Continued)
PERCENT CHANGE IN ELECTRICITY RATES BASED ON
ANNUALIZED COSTS (i.e., LEVELIZED BASIS) -- 1995 1/
(percent)
Changes from Base
CEUM High Cost
Region Low-Cost Default Default
DA - - +3.8
KN - +0.9 +1.5
OK +0.2 +0.2 +0.9
TX 6/ - +0.5 +0.5
MT ...
WY +0.2 +0.7 +0.2
ID ...
CO +0.6 +0.9 +1.5
NM ...
UT - - +0.1
AZ ...
NV - +0.1 +0.9
W0 - +0.1 +0.5
Cal. 7/ ...
Calculated as follows:
1995 Emission Reduction Case Annualized Cost -
1995 Base Case Annualized Cost
1995 Electricity Sales
New York: CEUM Regions NU and NY.
Ohio: CEUM Regions ON and OS.
Kentucky: CEUM Regions EK and WK.
Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
Texas: CEUM Regions TE, TW, and TS.
California: CEUM Regions CN and CS.
Totals may not add due to independent rounding.
1982 Average
Electricity Rates
1CF INCORPORATED
-------
A-13
TABLE A-9
PERCENT CHANGE IN ELECTRICITY RATES
BASED ON FIRST-YEAR REVENUE REQUIREMENTS
(i.e., TRADITIONAL BASIS) -- 1995 1/
(percent)
Changes from Base
High Cost
CEUM Region
Low-Cost
Default
Default
MV
+0.4
+3.1
+3.8
MC
-
+1.5
+3.2
NY 2/
+0.1
+1.3
+2.0
PA
+0.3
+5.3
+7.7
NJ
-
+2.4
+2.7
MD
+0.3
+4.0
+8.0
VA
+0.2
+1.6
+4.4
WV
+1.7
+8.6
+13.3
CA
+0.2
+3.1
+5.2
GA
+0.3
+2.7
+6.7
FL
+0.2
+3.4
+4.6
OH 3/
+4.1
+10.7
+15.7
MI
+0.4
+1.5
+4.6
IL
+0.8
+4.4
+4.9
IN
+3.0
+13.4
+15.3
VI
+0.2
+5.3
+5.8
KY 4/
+1.8
+7.2
+8.7
TN 5/
+1.1
+5.2
+6.9
AL
+0.1
+2.7
+4.0
MS
+0.3
+3.0
+5.8
MN
-
+1.1
+2.1
IA
+0:5
+4.4
+4.9
MO
+1.8
+12.2
+12.7
AR
+0.2
+0.3
+0.5
LA
+0.1
+0.1
+0.1
ICF INCORPORATED
-------
A-14
TABLE A-9 (Continued)
PERCENT CHANGE IN ELECTRICITY RATES
BASED ON FIRST-YEAR REVENUE REQUIREMENTS
(i.e., TRADITIONAL BASIS) -- 1995 1/
(percent)
Changes from Base
High Cost
CEUM Region Low-Cost Default Default
DA - +0.3 +6.4
KN +0.3 +1.7 +2.5
OK +0.2 +0.2 +0.9
TX 6/ - +0.8 +0.8
MT ...
WY - +0.7 +0.2
ID ...
CO +0.6 +1.0 +1.6
NM ...
UT - - +0.2
AZ ...
NV - +0.2 +1.0
W0 - +0.2 +0.7
Cal. 7/
2/ Calculated as follows:
1995 Emission Reduction Case
First Year Revenue Requirements -
1995 Base Case First Year Revenue Requirements
1995 Electricity Sales
2/ New York: CEUM Regions NU and NY.
3/ Ohio: CEUM Regions ON and OS.
4/ Kentucky: CEUM Regions EK and WK.
5/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
6/ Texas: CEUM Regions TE, TW, and TS.
7/ California: CEUM Regions CN and CS.
8/ Totals may not add due to independent rounding.
1982 Average
Electricity Rates
ICF INCORPORATED
-------
TABLE A-10
COAL MINING EMPLOYMENT -- 1995
(Job Slots)
(thousand workers)
Low-
Cost Case
Oefau1t
Ca se
Basฃ
Change
Change in
Chanqe i
SuDDly Reqion
1984
1995
from 1984
Job Slots
Job Slots a/
Job Slots
Job
SlOt!
Northern ADDalachia
PC
16. 1
17.4
+ 1.3
17.2
+ 1.1
15. 1
-
1 .0
PW
8.7
13.6
+ 4.9
13.8
+ 5.1
11.0
+
2.3
OH
9.8
9.4
- 0.4
3.7
- 5.7
2.4
-
7.0
MD
0.8
0.5
- 0.3
0.5
--
0. 3
-
0.2
WN
12.2
14.3
+ 2.1
14.0
+ 1.8
8.6
-
3,6
Tota 1
4 7.6
55.2
+ 7.6
49.2
+ 1.6
37.4
-
10.2
Central ADDalachia
WS
27.4
30.4
+ 3.0
32. 1
+ 4.7
38.0
+ 10.6
VA
14.1
16.3
+ 2.2
17.3
+ 3.2
18.4
+
4.3
KE
29.8
32.0
+ 2.2
36.2
+ 6.4
42.0
+ 12.2
TN
2.6
4.2
+ 1.6
4.1
+ 1.5
4.0
+
1 . 4
Tota 1
73.9
82.9
+ 9.0
89.7
+ 15.8
102.4
+28.5
Southern ADDalachia
AL
8.6
9. 1
+ 0.5
9-3
+ 0.7
10.7
+
2. 1
Tota 1
8.6
9. 1
+ 0.5
9. 3
+ 9.7
10. 7
+
2. 1
TOTAL APPALACHIA
130.1
147.2
+17.1
148.2
+ 18. 1
150.5
+20. *4
Midyest
IL
13.3
15.7
+ 2.4
13.4
+ 0. 1
9.7
-
3.6
IN
5.5
6.3
+ 0.8
5.4
- 0. 1
4.4
-
1. 1
KW
8.1
9.2
+ 1.1
9,2
+ 1.1
7.9
-
0.2
Tota 1
26.9
31.2
+ 4.3
28.0
+ 1.1
22.0
4.9
TOTAL MIDWEST
26.9
31.2
+ 4.3
28.0
+ 1.1
22.0
-
4.9
Central West
IA
0.1
- 0.1
-
~ ""
MO
1.3
1 . 1
- 0.2
0.9
- 0.2
0.6
-
0. 3
KS
0.3
0.6
+ 0.3
0.5
+ 0.2
0.5
+
0.2
AN
0.9
+ 0.9
0.9
+ 0.9
1.2
+
1.2
OK
1.3
1.2
- 0.1
1.2
1.3
Tota 1
3.0
3.8
+ 0.8
3.5
+ 0.5
3.8
+
0.8
o
T1
z
o
o
3
ฆo
o
?
nl
O
-------
TABLE A-10 (Continued)
COAL MINING EMPLOYMENT -- 1995
(Job Slots)
(thousand workers)
Low-Cost Case
Defau11 Case
Supply Region
Gul r
TX
LA
AS
Tota I
Rockies/Northern Plains
CO
WY
MT
UT
NM
AZ
NO
Tota I
Northwest
WA
Tota I
Alaska
AK
Tota I
TOTAL WEST
TOTAL UNITED STATES
Base
Change
Change in
Change in
1984
1995
from 1984
Job Slots
Job Slots a/
Job Slots
Job Slots a/
2.3
7.9
+
5.6
7.9
+
5.6
7.9
+
5.6
::
3.8
+
3.8
3.8
+
3.8
3.8
+
3.8
2.3
11.7
+
9.4
11.7
+
9.4
11.7
+
9.4
2.8
7.0
+
4.2
9. 3
+
6.5
12.4
+
9.6
4.5
8.8
+
4.3
8.6
+
4.1
8.9
+
4.4
1.1
2.4
+
1.3
2.4
+
1. 3
2.4
+
1 . 3
2.5
5.0
+
2.5
4.9
2.4
5.2
+
2.7
1.8
3.3
+
1.5
3.3
+
1.5
3.9
+
2. 1
0.9
1.2
+
0.3
1.3
+
0.4
1. 3
+
0.4
1.2
1.7
+
0.5
1.7
+
0.5
1. 7
+
0.5
14.8
29.4
+ 14.6
31.5
+16.7
35.8
+21 .0
0.6
1.0
+
0.4
1.0
+
0.4
0.4
_
0.2
0.6
1.0
+
0.4
1.0
+
0.4
0.4
"
0.2
0.1
0.5
+
0.4
0.5
+
0.4
0.5
+
0.4
0.1
0.5
+
0.4
0.5
+
0.4
0.5
+
0.4
20.8
46. 4
+25.6
48.2
+27.4
52.2
+31.4
177.8
224.8
+47.0
224.4
+46.6
224.7
+46.9
I
ป-*
ON
NOTE: Absolute totals may not add due to independent rounding. Changes will not add as they are calculated on an individual
region basis.
a/ Changes in job slots are defined as being equal to changes from 1984 levels except when 1995 Base is forecasted to
decline below 1984 levels, in which case changes from 1995 Base are presented. Note a positive sign indicates an
increase in job slots; a negative sign a decrease.
-------
TABLE A-11
COAL MINING EMPLOYMENT -- 1995
(Jobs)
(thousand workers)
Supply Region
Northern Appalachla
PC
PW
OH
MO
WN
Tota I
Central Appalachia
WS
VA
KE
TN
Tota I
Southern Appalachia
AL
Tota I
TOTAL APPALACHIA
Midwest
IL
IN
KW
Tota I
TOTAL MIDWEST
Central West
1984
16.1
8.7
9.8
0.8
12.2
47.6
27. 4
VI. 1
29.8
2.6
73.9
8.6
8.6
130.1
13.3
5.5
8.1
26.9
26.9
Assumed
M i ne r
Ret i rements
t).v 1995
1.9
1.0
1.2
0.1
5.7
3.3
1.7
3.6
0.3
8.9
Low-Cost Case
Default Case
1.0
1.0
15.6
1.6
0.7
_L_0
3.3
3.3
Net
Base
Change in
Change in
1984 a/
1995
Jobs
Jobs a/
Jobs
Jobs a/
14.2
17.4
17.2
+ 3.0
15.1
+ 0.9
7.7
13.6
13.8
+ 6.1
11.0
+ 3.3
8.6
9.4
3.7
- 4.9
2.4
- 6.2
0.7
0.5
0.5
--
0.3
- 0.2
10.7
14. 3
14.0
+ 3.3
8.6
- 2. 1
41.9
55.2
49.2
+ 7.3
37.4
- 4.5
24. 1
12. 4
26.2
2.3
65.0
7.6
7.6
111.5
30. 4
16.3
32.0
4.2
82.9
9.1
9. 1
1M7.2
32. 1
17.3
36.2
'1.1
89.7
9-3
9.3
148.2
+ 8.0
+ 4.9
+ 10.0
~ 1.8
+24.7
+ 1.7
+ 1.7
+ 33.7
38.0
18.4
42.0
4.0
102. <~
10,7
10.7
150.5
+ 13.9
+ 6.0
+ 15.8
+ 1.7
+37.4
+ 3.1
+ 3.1
+36.0
11.7
15.7
13.4
+
1.7
9.7
- 2.0
4.8
6.3
5.4
+
0.6
4.4
- 0.4
7.1
9.2
9.2
+
2,1
7.9
+ 0.8
23.6
31.2
28.0
+
4.4
22.0
- 1.6
23.6
31.2
28.0
+
4.4
22.0
-1.6
IA
0.1
0. 1
--
-
0.1
-
0. 1
MO
1.3
0.2
1. 1
1 . 1
0.9
-
0.2
0.8
-
0.3
KS
0.3
0.3
0.6
0.5
+
0.2
0.5
+
0.2
AN
0.9
0.9
+
0.9
1.2
+
1.2
OK
1-3
0.2
1. 1
1.2
1.2
+
0.1
1.3
+
0,2
Tota 1
3.0
0.4
2.6
3.8
3.5
+
0.9
3.8
+
1.2
-------
TABLE A-11 (Continued)
COAL MINING EMPLOYMENT
(Jobs)
(thousand workers)
1995
Assumed
Mi ner
Low-
Cost Case
Default Case
Ret i rements
Net
Base
Change in
Change in
SuddIv Region
1984
by 1995
1984 a/
1995
Jobs
Jobs a/
Jobs
Jobs a/
Gulf
TX
2.3
0.3
2.0
7.9
7.9
+
5.9
7.9
+
5.9
LA
--
3.8
3.8
+
3.8
3.8
+
3.8
AS
--
Tota 1
2.3
0. 3
2.0
11.7
11.7
+
9.7
11.7
+
9.7
Rockies/Northern Plains
CO
2.8
0.3
2.5
7.0
9.3
+
6.8
12.4
+
9.9
WY
4.5
0.5
4.0
8.8
8.6
4.6
8.9
+
4.9
MT
1.1
0. 1
1.0
2.4
2.4
+
1.4
2.4
+
1.4
UT
2.5
0.3
2.2
5.0
4.9
+
2.7
5.2
+
3.0
NM
1.8
0.2
1.6
3.3
3.3
+
1.7
3.9
+
2.3
A Z
0.9
0. 1
0.8
1.2
1.3
+
0.5
1.3
+
0.5
ND
1.2
0.1
1.1
1.7
1.7
+
0.6
1 .7
+
0.6
Tota 1
14.8
1.8
13.0
29.4
31.5
+ 18.5
35.8
+22.8
Northwest
WA
0.6
0. 1
0.5
1.0
1.0
+
0,5
O.H
+
0.1
Tota 1
0.6
0. 1
0.5
1.0
1.0
+
0.5
0.4
+
0. 1
Alaska
AK
0.1
0. 1
0.5
0.5
+
0.4
0.5
+
0.4
Tota 1
0.1
0.1
0.5
0.5
+
0.4
0.5
+
0.4
TOTAL WEST
20.8
2.5
18.3
46.4
48.2
+29.9
52.2
+33.9
TOTAL UNITED STATES
177.8
21. 3
156.5
224.8
224.4
+67.9
224. 7
+68.2
>
ฆ
NOTE: Absolute totals may not add due to independent rounding. Changes will not add as they are calculated on a regional
bas i s.
a/ "1984" miners employed are adjusted for "assumed miner retirements" between 1984 and 1995 (equal to 12% of 1984 jobs)
to calculate "Net 1984." "Net 1984" is equivalent to those miners employed in 1984 who would still be in the work
force in 1995. "Changes in Jobs" are defined as changes from "Net 1984" levels except when the 1995 Base is forecasted
to be less than 1984 levels. In this case, changes are calculated from the 1995 Base. Note a positive sign indicates
an increase in jobs (I.e. new workers are employed); a negative sign indicates a decrease (i.e. "Net 1984" workers lose
the i r jobs).
-------
Appenoii 0
-------
APPENDIX B --
HR-4567 FORECASTS - 2000
ICF INCORPORATED
-------
TABLE B-l
SULFUR DIOXIDE EMISSION FORECASTS -- 2000
1980
Changes from Base
Base High Cost
2000 Low-Cost Default Default
Utility S02 Emissions
(millions of tons)
31-Eastern States
Existing
Coal
Oil/Gas
New
Total 31-Eastern States
17-Western States
Existing
Coal
Oil/Gas
New
Total 17-Western States
14.92
1.27
16.19
1.10
0.09
1.19
1.19
15.95
0.78
16.73
1.30
16.19 18.03
1.56
0.08
1.64
0.86
2.50
-8.22
-0.09
-8.'31
+0.17
-8.14
-0.08
-0.08
+0.08
10.05
-0.29
-10.34
+0.30
-10.04
-0.35
-0.03
-0.38
+0.05
-0.34
-10.03
-0.28
-10.31
+0.29
-10.02
-0.35
-0.03
-0.38
+0.05
-0.34
Total U.S.
Existing
Coal
Oil/Gas
New
Total U.S.
16.02
1.36
17.38
17.51
0.87
18.38
2.16
17.38 20.53
-8.30
-0.09
-8.39
+0.25
-8.14
-10.41
-0.32
-10.73
+0.35
-10.38
-10.39
-0.31
-10.70
+0.34
-10.36
Note: Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-2
TABLE B-2
NITROGEN OXIDE EMISSION FORECASTS -- 2000
1980
Base
2000
Changes from Base
Utility NOx Emissions
(millions of tons)
31-Eastern States
Existing
Coal
Oil/Gas
New
Total 31-Eastern States
17-Western States
Existing
Coal
Oil/Gas
New
Total 17-Western States
4.55
0.57
5.12
5.12
0.89
0.61
1.50
1.50
5.14
0.29
5.43
1.36
6.79
1.03
0.38
1.41
1.43
2.84
Low-Cost
-1.62
-1.62
-0.14
-1.76
-0.14
-0.14
-0.14
-0.28
High Cost
Default Default
-2.03
+0.01
-2.02
-0.15
-2.17
-0.20
-0.20
-0.31
-0.50
-2.02
+0.01
-2.01
-0.15
-2.16
-0.20
-0.20
-0.31
-0.50
Total U.S.
Existing
Coal
Oil/Gas
New
Total U.S.
5.44
1.18
6.62
6.62
6.17
0.67
6.84
2.80
9.63
-1.76
-1.76
-0.28
-2.04
-2.22
+0.01
-2.21
-0.45
-2.66
-2.22
+0.01
-2.21
-0.46
-2.67
Note: Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-3
TABLE B-3
TOTAL UTILITY S02 & NOX CONTROL COST FORECASTS -- 2000
Changes from Base
Low-Cost
Default
High Cost
Default
Utility Annual Costs
(billions of early-1985 $/yr.)
Annualized Capital Costs
0&M
Fuel
Total
Utility Cumulative
Capital Costs
(billions of early-1985 $)
31-Eastern States
17-Western States
Total U.S.
Average Cost Per Ton
of S02 & NOx Removed
(early-1985 $/ton)
Retrofit Scrubber Capacity (GW)
31-Eastern States
17-Western States
Total U.S.
+0.6
+0.6
+1.6
+2.8
+6.4
+0.8
+7.2
277
+4.1
+1.6
+2.3
+3.1
+7.0
+4.1
+20.0
+2.9
+22.9
539
+36.3
+4.2
+40.5
+1.7
+2.4
+2.9
+7.0
+21.5
+2.8
+24.3
540
+47.0
+4.4
+51.4
Capacity with NOx Controls (GW)
31-Eastern States
17-Western States
Total U.S.
+165.9
+47.4
+213.3
+287.2
+110.4
+397.6
+287.2
+110.4
+397.6
Note: Totals may not add due to independent rounding.
N.A. = Not Applicable.
ICF INCORPORATED
-------
B-4
TABLE B-4
UTILITY S02 CONTROL COST FORECASTS -- 2000
Changes from Base
High Cost
Low-Cost Default Default
Utility Annual Costs
(billions of early-1985 $/yr.)
Annualized Capital Costs
0&M
Fuel
Total
Utility Cumulative
Capital Costs
(billions of early-1985 $)
31-Eastern States
17-Western States
Total U.S.
Average Cost Per Ton
of S02 Removed
(early-1985 $/ton)
S02 Retrofit Scrubber Capacity (Gtf)
31-Eastern States
17-Western States
Total U.S.
+0.5
+0.4
+1.6
+2.5
+4.7
+0.5
+5.2
306
+4.1
+1.2
+1.2
+3.1
+5.5
+4.1
+15.8
+1.6
+17.4
534
+36.3
+4.2
+40.5
+1.3
+1.3
+2.9
+5.5
+17.3
+1.5
+18.8
536
+47.0
+4.4
+51.4
Note: Totals may not add due to independent rounding.
N.A. = Not Applicable.
ICF INCORPORATED
-------
B-5
TABLE B-5
UTILITY NOX CONTROL COST FORECASTS -- 2000
Utility Annual Costs
(billions of early-1985 $/yr.)
Capital Costs
0&M
Fuel
Total
Utility Cumulative
Capital Costs
(billions of early-1985 $)
31-Eastern States
17-Western States
Total U.S.
Average Cost Per Ton
of NOx Removed
(early-1985 $/ton)
Capacity with NOx Controls (GW)
31-Eastern States
17-Western States
Total U.S.
Changes from Base
High Cost
Low-Cost Default Default
+0.1 +0.4 +0.4
+0.2 +1.1 +1.1
+0.3 +1.5 1/ +1.5 1/
+1.7 +4.2 +4.2
+0.3 +1.3 +1.3
+2.0 +5.5 2/ +5.5 2/
167 558 559
+165.9 +287.2 +287.2
+47.4 +110.4 +110.4
+213.3 +397.6 3/ +397.6 3/
Note: Totals may not add due to independent rounding.
N.A. = Not Applicable.
1/ Includes $1.1 billion in annual costs associated with retrofitting
SCR on wet bottom and cyclone boilers.
2/ Includes $3.4 billion in cumulative capital costs associated with
retrofitting SCR on wet bottom and cyclone boilers.
3/ Includes 39.5 gigawatts of capacity retrofitting SCR.
ICF INCORPORATED
-------
B-6
TABLE B-6
UTILITY FUEL CONSUMPTION FORECASTS -- 2000
(in quads)
Utility Fuel Consumption
Base
2000
Changes from Base
Low-Cost
Default
High Cost
Default
31-Eastern States
Coal
Low Sulfur
Low-Medium Sulfur
High-Medium Sulfur
High Sulfur
Total
3.36
3.29
4.60
4.21
15.46
+2.18
+1.02
-1.13
-2.03
+0.03
+5.86
-1.45
-2.33
-2.07
+0.01
+5.27
-1.10
-2.14
-2.04
Oil
Gas
1.12
0.78
+0.02
+0.05
+0.07
17-Western States
Coal
Low Sulfur
Low-Medium Sulfur
High-Medium Sulfur
High Sulfur
Total
3.96
1.15
2.10
0.04
7.24
-0.46
+0.26
+0.18
+0.01
-0.01
-0.31
+0.11
+0.23
-0.02
+0.01
-0.30
+0.09
+0.23
-0.02
+0.01
Oil
Gas
0.26
1.98
+0.01
+0.01
Total U.S.
Coal
Low Sulfur
Low-Medium Sulfur
High-Medium Sulfur
High Sulfur
Total
7.32
4.44
6.70
4.24
22.70
+1.72
+1.28
-0.95
-2.02
+0.03
+5.55
-1.34
-2.10
-2.09
+0.02
+4.98
-1.00
-1.91
-2.05
+0.01
Oil
Gas
1.37
2.76
+0.02
+0.06
+0.07
Note: Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-7
TABLE B-7
COAL PRODUCTION AND SHIPMENT FORECASTS -- 2000
(in millions of tons)
1980
Base
2000
Changes from Base
Low-Cost
High Cost
Default Default
Coal Production
Northern Appalachia
185.1
218.9
-30.9
-52.2
-46.8
Central Appalachia
232.8
374.5
+33.2
+32.2
+34.6
Southern Appalachia
26.4
27.5
+2.4
+3.0
+2.6
Midwest
134.4
174.0
-54.1
-69.0
-67.9
West
251.0
711.1
+48.7
+88.4
+79.1
Total U.S.
829.7
1506.0
-0.7
+2.4
+1.6
Coal Transportation
Western Coal Shipped
East
36.7
90.0
+36.0
+74.8
+64.9
Note: Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-8
TABLE B-8
CHANGE IN TOTAL UTILITY SULFUR DIOXIDE EMISSIONS
BY REGION -- 2000
(Thousands
of Tons)
Changes from
Base
Base
High Cost
2000
Low-Cost
Default
Default
MV
104
-29
-49
-49
MC
301
-73
-112
-112
NY 1/
490
-7
-124
-125
PA
1162
-543
-643
-644
NJ
153
-17
-65
-65
MD
368
-68
-174
-166
VA
375
-9
-150
-148
WV
1083
-604
-641
-641
CA
763
-121
-266
-267
GA
933
-420
-495
-495
FL
979
-197
-449
-449
OH 2/
2816
-1836
-1997
-1996
MI
473
-4
-54
-49
IL
998
-530
-597
-597
IN
1866
-1223
-1291
-1292
WI
456
-211
-232
-231
KY 3/
987
-521
-609
-609
TN 4/
1074
-535
-622
-619
AL
463
-191
-239
-238
MS
195
-98
-106
-106
MN
184
-21
-62
-62
IA
214
-41
-63
-63
MO
1347
-851
-1004
-1004
AR
124
+5
-5
-5
LA
124
+3
+3
+3
Total 31-Eastern States 7/
18031
-8135
-10045
-10028
ICF INCORPORATED
-------
B-9
TABLE B-8 (Continued)
CHANGE IN TOTAL UTILITY SULFUR DIOXIDE EMISSIONS
BY REGION -- 2000
(Thousands of Tons)
Changes from Base
Base
2000
DA 268
KN 236
OK 247
TX 5/ 994
MT 40
WY 75
ID
CO 130
NM 64
UT 72
AZ 120
NV 65
W0 181
Cal. 6/ 6
Total 17-Western States 7/ 2498
Total U.S. 2/ 20529
High Cost
Low-Cost Default Default
-30 -85 -86
-2 -68 -68
+10 -33 -33
+29 -66 -67
+5 -5 -4
-4 -7 -7
+1 +1 +1
+1 -11 -11
-1 -1 -1
-6 -61 -60
-1 -1
+2 -336 -336
-8133 -10381 -10364
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B -10
TABLE B-9
CHANGE IN TOTAL UTILITY NITROGEN OXIDE EMISSIONS
BY REGION -- 2000
(Thousands of Tons)
Base
2000
MV 100
MC 309
NY 1/ 455
PA 1290
NJ 136
MD 357
VA 296
WV 1056
CA 681
GA 834
FL 975
OH 2/ 2738
MI 476
IL 947
IN 1810
WI 494
KY 3/ 998
TN 4/ 880
AL 483
MS 228
MN 185
IA 226
MO 1268
AR 121
LA 94
Total 31-Eastern States 7/ 17435
Changes from Base
High Cost
Low-Cost Default Default
-17 -20 -20
-4 -24 -24
-16 -52 -52
-73 -87 -87
-39 -52 -52
-39 -63 -62
-32 -57 -57
-117 -124 -124
-110 -127 -127
-55 -71 -72
-70 -148 -148
-208 -252 -252
-94 -102 -102
-174 -174 -174
-186 -189 -189
-54 -55 -55
-146 -148 -148
-89 -123 -122
-34 -29 -29
-8 -12 -12
-38 -39 -39
-32 -33 -33
-115 -152 -152
-5 -11 -11
- -22 -22
-1755 -2166 -2165
ICF INCORPORATED
-------
B-ll
TABLE B-9 (Continued)
CHANGE IN TOTAL UTILITY NITROGEN OXIDE EMISSIONS
BY REGION -- 2000
(Thousands of Tons)
Changes from Base
Base High Cost
2000
Low-Cost
Default
Default
DA
228
-53
-61
-61
KN
315
-47
-54
-54
OK
211
-14
-27
-27
TX 5/
799
-73
-189
-189
MT
38
-5
-9
-9
WY
69
-11
-24
-24
ID
-
-
-
-
CO
121
-24
-44
-44
NM
56
-9
-16
-16
UT
66
-9
-14
-14
AZ
122
-12
-25
-25
NV
72
-3
-9
-9
WO
119
-19
-24
-24
Cal. 6/
4
-4
-5
-5
Total 17-Western States 7/
2220
-283
-503
-503
Total U.S. 7/
19655
-2036
-2669
-2667
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TV A plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-12
TABLE B-10
CHANGE IN TOTAL UTILITY ANNUALIZED COSTS
BY REGION -- 2000
(Millions of Early 1985 Dollars)
Changes from Base
High Cost
Low-Cost
Default
Default
MV
+30
+59
+61
MC
+56
+129
+136
NY 1/
+6
+140
+143
PA
+350
+509
+511
NJ
+24
+104
+109
MD
+30
+132
+150
VA
+24
+103
+108
WV
+191
+395
+391
CA
+54
+354
+350
GA
+99
+284
+291
FL
+103
+353 .
+342
OH 2/
+483
+939
+936
MI
+58
+246
+251
IL
+199
+415
+413
IN
+401
+683
+682
WI
+51
+142
+141
KY 3/
+164
+308
+304
TN 4/
+173
+335
+337
AL
+62
+167
+151
MS
+37
+52
+52
MN
+5
+50
+50
IA
+12
+73
+72
MO
+122
+409
+405
AR
+1
+30
+30
LA
-
+9
+9
Total 31-Eastern States 7/
+2734
+6423
+6422
ICF INCORPORATED
-------
B -13
TABLE B-10 (Continued)
CHANGE IN TOTAL UTILITY ANNUALIZED COSTS
BY REGION -- 2000
(Millions of Early 1985 Dollars)
Changes from Base
DA
KN
OK
TX 5/
MT
WY
ID
CO
NM
UT
AZ
NV
WO
Cal. 6/
Total 17-Western States ]_/
Total U.S. 7/
Low-Cost
+8
+8
+4
+29
-1
+10
+12
-2
+6
+10
+10
-7
+3
+90
+2824
Default
+123
+76
+89
+207
+2
+27
+25
+9
+11
+ 13
+17
+8
+612
+7035
High Cost
Default
+126
+77
+89
+207
+2
+27
+26
+6
+10
+13
+18
+6
+618
+7040
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B -14
TABLE B-11
CHANGE IN UTILITY ANNUALIZED S02 CONTROL COSTS
BY REGION -- 2000
(Millions of Early 1985 Dollars)
Changes from Base
High Cost
Low-Cost Default Default
MV
+16
+44
+46
MC
+56
+ 117
+124
NY If
+4
+121
+124
PA
+345
+487
+489
NJ
+13
+68
+73
MD
+27
+113
+131
VA
+20
+96
+101
WV
+179
+353
+349
CA
+35
+290
+286
GA
+97
+265
+272
FL
+97
+281
+270
OH 2/
+462
+843
+840
MI
+49
+202
+207
IL
+69
+231
+229
IN
+382
+544
+543
WI
+46
+110
+109
KY 3/
+150
+216
+212
TN 4/
+167
+290
+292
AL
+59
+158
+142
MS
+36
+49
+49
MN
-
+23
+23
IA
+8
+50
+49
MO
+114
+306
+302
AR
+1
+11
+11
LA
-
+2
+2
Total 31-Eastern States 7/ +2430 +5273 +5272
ICF INCORPORATED
-------
B -15
TABLE B-11 (Continued)
CHANGE IN UTILITY ANNUALIZED S02 CONTROL COSTS
BY REGION -- 2000
(Millions of Early 1985 Dollars)
Changes from Base
Low-Cost
Default
High Cost
Default
DA
+3
+56
+59
KN
+1
+16
+17
OK
+2
+27
+27
TX 5/
+20
+123
+123
MT ~
-1
-1
-1
WY
+9
+4
+4
ID
-
-
-
CO
+10
+ 11
+12
NM
-3
-1
-4
UT
+5
+8
+7
AZ
+9
+7
+7
NV
+10
+15
+16
WO
-9
+4
+6
Cal. 6/
+2
+5
+5
17-Western States 7/
+58
+273
+279
U.S. 7/
+2485
+5545
+5550
1/ New York: CEUM Regions N'U and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B -16
TABLE B-12
CHANGE IN UTILITY ANNUALIZED NOx CONTROL COSTS
BY REGION -- 2000
(Millions of Early 1985 Dollars)
MV
MC
NY 1/
PA
NJ
MD
VA
WV
CA
GA
FL
OH 2/
MI
IL
IN
WI
KY 3/
TN 4/
AL
MS
MN
IA
MO
AR
LA
Total 31-Eastern States 7/
Changes from Base
Low-Cost
+14
+2
+5
+ 11
+3
+4
+12
+ 19
+2
+6
+21
+9
+130
+19
+5
+14
+7
+3
+1
+5
+4
+8"
+304
Default
Default
+15
+15
+12
+12
+19
+19
+22
+22
+36
+36
+19
+19
+7
+7
+42
+42
+64
+64
+19
+19
+72
+72
+96
+96
+44
+44
+184
+184
+139
+139
+32
+32
+92
+92
+45
+45
+9
+9
+3
+3
+27
+27
+23
23
+103
+103
+19
+19
+7
+7
+1150
+1150
ICF INCORPORATED
-------
B -17
TABLE B-12 (Continued)
CHANGE IN UTILITY ANNUALIZED NOx CONTROL COSTS
BY REGION -- 2000
(Millions of Early 1985 Dollars)
Changes from Base
DA
KN
OK
TX 5/
MT
WY
ID
CO
NM
UT
AZ
NV
WO
Cal. 6/
Total 17-Western States 7/
Total U.S. 7/
Low-Cost
+5
+7
+2
+9
+1
+2
+1
+1
+1
+2
+1
+32
+339
Default
+67
+60
+62
+84
+3
+23
+14
+10
+3
+6
+2
+4
+1
+339
+1490
High Cost
Default
+67
+60
+62
+84
+3
+23
+14
+10
+3
+6
+2
+4
+1
+339
+1490
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TV, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B -18
TABLE B-13
CHANGES IN S02 RETROFIT SCRUBBER CAPACITY 2000
(Gw)
Changes from
Base
High Cost
Low-Cost
Default
Default
MV
+0.5
+0.5
MC
-
+0.3
+0.9
NY 1/
-
+0.7
+0.7
PA
+3.4
+7.9
+8.8
NJ
-
+2.5
+0.9
MD
-
+0.4
+2.0
VA
-
-
+0.7
WV
-
+0.6
+0.6
CA
-
+1.4
+1.4
GA
-
+0.2
+3.8
FL
-
+1.9
+1.9
OH 2/
+0.2
+6.3
+7.6
MI
-
-
+1.6
IL
-
+3.7
+3.7
IN
+0.5
+3.5
+3.5
WI
-
+0.7
+0.7
KY 3/
-
+1.2
+1.2
TN 4/
-
+1.1
+1.1
AL
-
-
+1.0
MS
-
-
_
MN
-
+0.3
+0.3
IA
-
+0.5
+0.5
MO
-
+3.4
+3.4
AR
-
-
_
LA
-
-
-
Eastern States 7/
+4.1
+36.3
+47.0
ICF INCORPORATED
-------
B -19
TABLE B-13 (Continued)
CHANGES IN S02 RETROFIT SCRUBBER CAPACITY -- 2000
(Gw)
Changes from Base
High Cost
Low-Cost Default Default
DA - +1.6 +1.6
KN - +0.2 +0.2
OK -
TX 5/ - +2.3 +2.3
MT -
WY ...
ID ...
CO ...
NM ...
UT ...
AZ ...
NV ...
W0 ...
Cal. 6/ - - -
Total 17-Western States 7/ - +4.2 +4.4
Total U.S. 7/ +4.1 +40.5 +51.4
2/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
]_/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-20
TABLE B-14
CHANGES IN CAPACITY WITH NOx CONTROLS -- 2000
(Gw)
Changes from Base
High Cost
Low-Cost Default Default
MV
+1.7
+1.9
+1.9
MC
+0.7
+4.2
+4.2
NY 1/
+3.0
+9.7
+9.7
PA
+9.0
+18.0
+18.0
NJ
+4.2
+5.1
+5.1
MD
+4.9
+10.2
+10.2
VA
+6.1
+10.4
+10.4
WV
+10.4
+15.5
+15.5
CA
+5.1
+20.2
+20.2
GA
+6.3
+15.7
+15.7
FL -
+9.6
+16.3
+16.3
OH 2/
+21.5
+30.4
+30.4
MI
+8.0
+12.3
+12.3
IL
+7.3
+18.0
+18.0
IN
+15.2
+19.5
+19.5
WI
+4.4
+7.6
+7.6
KY 3/
+12.1
+14.5
+14.5
TN 4/
+12.3
+11.5
+11.5
AL
+4.1
+8.7
+8.7
MS
+0.6
+2.2
+2.2
MN
+4.5
+5.4
+5.4
IA
+2.8
+5.9
+5.9
MO
+11.5
+16.1
+16.1
AR
+0.6
+3.6
+3.6
LA
-
+4.3
+4.3
Total 31-Eastern States 7/ +165.9 +287.2 +287.2
ICF INCORPORATED
-------
B-21
.TABLE B-14 (Continued)
CHANGES IN CAPACITY WITH NOx CONTROLS -- 2000
(Gw)
Changes from Base
DA
KN
OK
TX 5/
MT
WY
ID
CO
NM
UT
AZ
NV
WO
Cal.
6/
Total 17-Western States l_l
Total U.S. 7/
Low-Cost
+6.1
+6.6
+3.9
+15.5
+0.7
+ 1.6
+3.2
+1.5
+1.3
+1.9
+0.4
+3.7
+1.0
+47.4
+213.3
Default
+9.1
+9.2
+8.3
+43.6
+2.8
+6.3
+6.4
+5.2
+3.5
+7.0
+2.4
+5.6
+1.0
+110.4
+397.6
High Cost
Default
+9.1
+9.2
+8.3
+43.6
+2.8
+6.3
+6.4
+5.2
+3.5
+7.0
+2.4
+5.6
+1.0
+110.4
+397.6
1/ New York: CEUM Regions NU and NY.
2/ Ohio: CEUM Regions ON and OS.
3/ Kentucky: CEUM Regions EK and WK.
4/ Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
5/ Texas: CEUM Regions TE, TW, and TS.
6/ California: CEUM Regions CN and CS.
7/ Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-22
TABLE B-15
PERCENT CHANGE IN ELECTRICITY RATES BASED ON
ANNUALIZED COSTS (i.e., LEVELIZED BASIS) -- 2000 1/
(percent)
Changes from Base
Region
High Cost
Low-Cost
Default
Default
MV
+1.4
+2.7
+2.8
MC
+1.1
+2.6
+2.7
NY 2/
+0.1
+ 1.2
+1.2
PA
+3.6
+5.2
+5.2
NJ
+0.6
+2.6
+2.7
MD
+0.8
+3.3
+3.8
VA
+0.5
+2.3
+2.4
WV
+5.5
+11.4
+11.3
CA
+0.6
+4.0
+4.0
GA
+ 1.7
+4.8
+4.9
FL
+1.0
+3.5
+3.4
OH 3/
+4.9
+9.6
+9.6
MI
+1.0
+4.1
+4.1
IL
+2.1
+4.3
+4.3
IN
+7.6
+12.9
+12.9
WI
+1.9
+5.3
+5.2
KY 4/
+4.8
+9.1
+9.0
TN 5/
+2.8
+5.4
+5.5
AL
+1.3
+3.4
+3.1
MS
+3.1
+4.3
+4.3
MN
+0.2
+2.7
+2.7
IA
+0.8
+4.5
+4.5
MO
+2.7
+9.2
+9.1
AR
+0.1
+1.5
+1.5
LA
-
+0.2
+0.2
ICF INCORPORATED
-------
B-23
TABLE B-15 (Continued)
PERCENT CHANGE IN ELECTRICITY RATES BASED ON
CEUM Region
DA
KN
OK
TX 6/
MT
WY
ID
CO
NM
UT
AZ
NV
WO
Cal. 7/
(i.e., LEVELIZED BASIS)
-- 2000 1/
(percent)
Changes from
Base
High Cost
Low-Cost
Default
Default
+0.3
+4.0
+4.1
+0.3
+2.8
+2.9
+0.1
+2.6
+2.6
+0.1
+0.9
+0.9
-0.1
+0.2
+0.2
+0.6
+1.6
+1.7
+0.5
+1.1
+1.1
-0.1
+0.3
+0.2
+0.3
+0.4
+0.4
+0.2
+0.3
+0.3
+0.6
+1.1
+1.1
-0.1
+0.2
+0.2
-
+0.1
+0.1
1/. Calculated as follows:
2000 Emission Reduction Case Annualized Cost -
2000 Base Case Annualized Cost
2/
3/
y
5/
6/
1/
8/
1982 Average
Electricity Rates
2000 Electricity Sales
New York: CEUM Regions NU and NY.
Ohio: CEUM Regions ON and OS.
Kentucky: CEUM Regions EK and WK.
Tennessee: CEUM Regions ET and WT. Includes TVA plants in Alabama.
Texas: CEUM Regions TE, TW, and TS.
California: CEUM Regions CN and CS.
Totals may not add due to independent rounding.
ICF INCORPORATED
-------
B-24
TABLE B-16
PERCENT CHANGE IN ELECTRICITY RATES
BASED ON REVENUE REQUIREMENTS
(i.e., TRADITIONAL BASIS) -- 2000 1/
(percent)
Changes from Base
Region
High Cost
Low-Cost
Default
Default
MV
+2.8
+4.4
+4.4
MC
+1.2
+2.8
+3.0
NY 2/
+0.2
+1.6
+1.4
PA
+5.5
+6.9
+5.7
NJ
+1.7
+4.4
+3.7
MD
+2.6
+5.6
+6.0
VA
+0.6
+2.5
+2.6
WV
+7.5
+13.2
+12.9
CA
+0.9
+4.6
+4.5
GA
+2.8
+5.2
+5.5
FL
+1.3
+4.2
+4.0
OH 3/
+5.5
+11.9
+10.8
MI
+1.2
+4.7
+4.6
IL
+2.8
+5.4
+5.3
IN
+9.0
+14.6
+14.5
WI
+2.4
+6.0
+6.0
KY 4/
+5.4
+10.4
+10.4
TN 5/
+3.1
+6.1
+6.1
AL
+1.6
+3.7
+3.3
MS
+3.3
+4.5
+4.5
MN
+0.5
+4.0
+3.5
IA
+1.1
+5.5
+5.4
MO
+3.0
+10.8
+10.6
AR
+0.1
+1.9
+1.9
LA
-
+0.4
+0.4
ICF INCORPORATED
-------
B-25
TABLE B-16 (Continued)
PERCENT CHANGE IN ELECTRICITY RATES
BASED ON REVENUE REQUIREMENTS
(i.e., TRADITIONAL BASIS) -- 2000 1/
(percent)
Changes from Base
High Cost
CEUM Region Low-Cost Default Default
DA +0.7 +6.2 +5.1
KN +0.8 +4.0 +4.0
OK +0.3 +3.4 +3.4
TX 6/ +0.4 +1.5 +1.5
MT +0.2 +0.8 +0.5
WY +0.7 +2.4 +2.5
ID ...
CO +0.9 +1.7 +1.7
NM -0.1 +0.6 +0.3
UT +0.3 +0.6 +0.5
AZ +0.3 +0.4 +0.4
NV +0.8 +1.3 +1.4
W0 - +0.8 +0.7
Cal. 7/ - +0.1 +0.1
JL/ Calculated as follows:
2000 Emission Reduction Case
Revenue Requirements -
2000 Base Case Revenue Requirements
2000 Electricity Sales
2/ New York: CEUM Regions NU and NY.
3/ Ohio: CEUM Regions ON and OS.
4/ Kentucky: CEUM Regions EK and WK.
5/ Tennessee: CEUM Regions ET and WJ. Includes TVA plants in Alabama.
6/ Texas: CEUM Regions TE, TW, and TS.
7/ California: CEUM Regions CN and CS.
8/ Totals may not add due to independent rounding.
1982 Average
Electricity Rates
ICF INCORPORATED
-------
TABLE B-17
COAL MINING EMPLOYMENT -- 2000
(Job Slots)
(thousand workers)
SuodIv Realon
1981
Base
2000
Change
from 1984
Low-
Job Slots
ฆCost Case
Change in
Job Slots a/
Defau1t
Job Slots
Case
Change
Job Slot!
Northern Apoalachia
19.8
15.9
- 0.2
PC
16.1
19.1
+
3.3
+
3.7
PW
8.7
11.2
+
5.5
12.9
+
1.2
12.8
+ 1. 1
OH
9.8
9.8
3.7
-
6.1
1.5
- 5.3
MD
0.8
0.1
-
0.1
0.1
0.1
--
WN
12.2
16.6
+
1.1
15.3
+
3.1
12.8
+ 0.6
Tota 1
17.6
60.1
+ 12.8
52. 1
+
1.5
16.1
- 1.2
Central Aopalachia
10.5
+ 13.1
WS
27. 1
31.9
+
7.5
38.5
+11.1
VA
11. 1
15.7
+
1.6
16.5
+
2.1
17.2
+ 3.1
KE
29.8
11.1
+ 11.6
15.1
+ 15.3
13.1
+ 13.6
TN
2.6
3.9
+
1.3
1.2
+
1.6
3,3
+ 0.7
Tota 1
73.9
95.9
+22.0
101. 3
+30.1
101.1
+ 30.5
Southern Aopalachia
1.5
10.3
AL
8.6
9.3
+
0.7
10. 1
+
+ 1.7
Tota 1
8.6
9. 3
+
0.7
10. 1
+
1.5
10.3
+ 1.7
TOTAL APPALACHIA
130. 1
165.6
+35.5
166.5
+36.1
161 . 1
+31.0
Midwest
10.9
IL
13.3
20.8
+
7.5
10.9
-
2.1
- 2.1
IN
5.5
6.2
+
0.7
1.6
-
0.9
1. 1
- 1.1
KW
8.1
9.2
+
1.1
8.9
+
0.8
6.5
- 1.6
Tota 1
26.9
36.2
+
9.3
21.1
-
2.5
21.5
- 5.1
TOTAL MIDWEST
26.9
36.2
+
9.3
21.1
-
2.5
21.5
- 5.1
Central West
IA
0. 1
-
0. 1
MO
1.3
1.0
-
0.3
0.9
-
0. 1
0.9
- 0. 1
KS
0.3
0.6
+
0.3
0.5
+
0.2
0.1
+ 0. 1
AN
1.2
+
1.2
1. 3
+
1 . 3
0.9
+ 0.9
OK
1.3
1. 1
-
0.2
1.2
+
0. 1
1.1
--
Tota 1
3.0
3.9
+
0.9
3.9
+
0.9
3.3
+ 0.3
-------
TABLE B-17 (Continued)
COAL MINING EMPLOYMENT -- 2000
(Job Slots)
(thousand workers)
Low-
ฆCost Case
Defau1t
Ca se
Base
Change
Change in
Change in
suddIv Reaion
1984
2000
from 1984
Job Slots
Job Slots a/
Job Slots
Job Slots a/
GUI f
TX
2.3
11.7
+ 9.4
12.3
+ 10.0
12.4
+ 10.1
LA
--
12.7
+ 12.7
12.7
+ 12.7
12.7
+ 12.7
AS
--
Tota I
2.3
24.4
+22.1
25.0
+22. 7
25. 1
+22.8
Rockies/Northern Plains
CO
2.8
11.3
+ 8.5
16.7
+ 13.9
21.5
+ 18.7
WY
4.5
10.4
+ 5.9
10.8
+ 6.3
11.1
+ 6.6
MT
1.1
4.2
+ 3.1
4.0
+ 2.9
4.2
+ 3.1
UT
2.5
5.9
+ 3.4
6.4
+ 3.9
7.0
+ 4.5
NM
1.8
4.2
+ 2.4
5. 1
+ 3.3
5.7
+ 3.9
AZ
0.9
1.6
+ 0.7
1.7
+ 0.8
1.7
+ 0.8
ND
1.2
1.9
+ 0.7
1.6
+ 0.4
1.8
+ 0.6
Tota I
14.8
39.5
+24.7
46.3
+31.5
53.0
+ 38.2
Northwest
+ 0.3
WA
0.6
1.0
+ 0.4
1.0
+ 0.4
0.9
Tota I
0.6
1.0
+ 0.4
1.0
+ 0.4
0.9
+ 0.3
Alaska
AK
0. 1
0.6
+ 0.5
0.6
+ 0.5
0.6
+ 0.5
Tota 1
0.1
0.6
+ 0.5
0.6
+ 0.5
0.6
+ 0.5
TOTAL WEST
20.8
69.4
+48.6
76.8
+56.0
82.9
+62. 1
TOTAL UNITED STATES
177.8
271.2
+93.4
267.7
+89.9
265.5
+87.7
w
I
to
O
-n
z
o
0
2)
1
O
NOTE: Absolute totals may not add due to independent rounding,
region basis.
Changes will not add as they are calculated on an individual
a/ Changes in job slots are defined as being equal to changes from 1984 levels except when 1995 Base is
decline below 1984 levels, in which case changes from 1995 Base are presented. Note a positive sign
increase in job slots; a negative sign a decrease.
forecasted to
indicates an
-------
TABLE B-18
COAL MINING EMPLOYMENT -- 2000
(Jobs)
(thousand workers)
SuddI.v Reaion
1981
Assumed
Mi ner
Ketirements
bv 2000
Net
1984
Base
2000
LOV-
Jobs
Cost Case
Change in
Jobs a/
Default Case
Change
Jobs Jobs ai
Northern ADDalachia
15.9
PC
16.1
3.1
13.0
19.4
19.8
+ 6.8
+ 2.9
PW
8.7
1.7
7.0
14.2
12.9
+ 5.9
12.8
+ 5.8
OH
9.8
1.9
7.9
9.8
3.7
- 4.2
4.5
- 3.4
MO
0.8
0.2
0.6
0.4
0.4
--
0.4
--
WN
12.2
2.3
9.9
16.6
15,3
+ 5.4
12.8
+ 2.9
Tota 1
47.6
9.0
38.6
60.4
52. 1
+ 13.5
46.4
+ 7.8
Central ADDalachia
+16.3
40.5
+ 18.3
WS
27.4
5.2
22.2
34.9
38.5
VA
14.1
2.7
11.4
15.7
16.5
+ 5.1
17.2
+ 5.8
KE
29.8
5.7
24.1
41.4
45.1
+21 ,0
43.4
+ 19. 3
TN
2.6
0.5
2.1
3.9
4,2
+ 2,1
3.3
+ 1.2
Tota 1
73.9
14.0
59.9
95.9
104. 3
+44.4
104.4
+44.6
Southern Aooalachia
+ 3,1
10.3
AL
8.6
1.6
7.0
9,?
10,1
+ 3.3
Tota 1
8.6
1.6
7.0
9.3
10. 1
+ 3.1
10.3
+ 3.3
TOTAL APPALACHIA
130.1
r-
jr
CM
105.4
165.6
166.5
+61. 1
161. 1
+55.7
Midwest
10.9
+ 0.1
IL
13.3
2.5
10.8
20.8
10.9
+ 0.1
IN
5.5
1.0
4.5
6.2
4.6
+ 0.1
4. 1
- 0.4
KW
8.1
1.5
6.6
9.2
8,9
+ 2.3
6.5
- 0. 1
Tota l
26.9
5.1
21.8
36.2
24.4
+ 2.6
21.5
-0.3
TOTAL MIDWEST
26.9
5.1
21.8
36.2
24.4
+ 2.6
21.5
- 0.3
Central West
IA
0.1
0.1
- 0.1
- 0.1
MO
1.3
0.2
1.1
1.0
0.9
- 0.1
0.9
- 0. 1
KS
0.3
0. 1
0.2
0.6
0.5
+ 0.3
0.4
+ 0.2
AN
--
1.2
1. 3
+ 1.3
0.9
+ 0.9
OK
1.3
0.2
1,1
1.1
1.2
+ 0.1
1.1
Tota 1
3.0
0.6
2.4
3.9
3.9
+ 1.5
3.3
+ 0.9
-------
TABLE B-18 (Continued)
COAL MINING EMPLOYMENT -- 2000
(Jobs)
(thousand workers)
Supply Region
Gulf
TX
LA
AS
Tota I
Rockies/Northern Plains
CO
WY
MT
UT
NM
AZ
ND
Tota I
Northwest
WA
Tota I
Alaska
AK
Tota l
TOTAL WEST
TOTAL UNITED STATES
Assumed
M i ne r
Ret i rements
1984 by 2000
2.3
2.3
2.8
4.5
1 . 1
2.5
1.8
0.9
1.2
14.8
Q,$
0.6
0.1
0.1
20.8
177.8
o. a
0.4
0.5
0.9
0.2
0.5
0.3
0.2
0.2
2.8
0. 1
0. 1
4.0
33.8
N6t a/ Base
1984 2000
Jobs
Low-Cost Case
Change in
Jobs a/
1.9
11.7
12.3
+ 10.4
Jobs
DefauIt Case
Change in
Jobs a/
12. 4
+ 10.5
12.7
12.7
+ 12.7
12.7
+12. 7
1.9
24.4
25.0
+23. 1
25. 1
+23.2
2.3
11.3
16.7
+ 14.4
21.5
+ 19.2
3.6
10.4
10.8
+ 7.2
11.1
+ 7.5
0.9
4.2
4.0
+ 3.1
4.2
+ 3.3
2.0
5.9
6.4
+ 4.4
7.0
+ 5.0
1.5
4.2
5.1
+ 3.6
5.7
+ 4.2
0.7
1.6
1.7
+ 1.0
1.7
+ 1.0
1.0
1.9
1.6
+ 0.6
1.8
+ 0.8
12.0
39.5
46.3
+34.3
53.0
+41.0
0.5
1.0
1.0
+ 0.5
0-9
+ 0.4
0.5
1.0
1.0
+ 0.5
0.9 .
+ 0.4
0.1
0.6
0.6
+ 0.5
0.6
+ 0.5
0.1
0.6
0.6
+ 0.5
0.6
+ 0.5
16.8
69.4
76.8
+60.0
82.9
+66.1
144.0
271.2
267.7
+123.7
265.5
+ 121.5
w
to
\o
NOTE: Absolute totals may not add due to independent rounding. Changes will not add as they are calculated on a regional
bas i s.
a/ "1984" miners employed are adjusted for "assumed miner retirements" between 1984 and 1995 (equal to 19% of 1984 j'obs)
to calculate those miners employed in 1984 who would still be in the workforce in 1995 referred to as "Net 1984,"
"Changes in Jobs" are defined as changes from Net 1984 levels except when the 1995 Base is forecasted to be less than
1984 levels. In this case, changes are calculated from the 1995 Base. Note a positive sign indicates an increase in
jobs (i.e. new workers are employed); a negative sign indicates a decrease (i.e. "Net 1984 workers lose their jobs).
-------
Appendix C
-------
APPENDIX C --
SUMMARY MEASURES AND CEUM DEMAND
AND SUPPLY REGIONS
ICF INCORPORATED
-------
APPENDIX C
SUMMARY MEASURES AND CEUM DEMAND
AND SUPPLY REGIONS
This appendix describes and explains the summary measures used in this
report and the demand and supply regions in ICF's Coal and Electric Utilities
Model (CEUM).
Measures used to present the findings in this report are:
Geographic Regions
31 Eastern States -- 31 states east of or
bordering the Mississippi River (see Figure C-l on
page C-2).
-- West -- Other states in the United States
(excluding Alaska and Hawaii), consisting of the
remaining 17 Western States outside the 31 Eastern
States region (see Figure C-l on page C-2).
-- Aggregate CEUM Supply Regions (see Figure C-2 on
page C-3).
-- CEUM Demand Regions (see Figure C-l on page C-2).
-- Census Regions (see Figure C-l on page C-2).
Powerplants by Vintage and Type
Existing Oil/Gas -- Oil/gas steam powerplants in
operation before December 31, 1980 less all assumed
coal reconversions by 1995.
Existing Coal -- Coal-fired powerplants in
operation before December 31, 1980 plus any coal
reconversions.
-- New -- All coal-fired powerplants scheduled to
begin or which have begun operation after December
31, 1980.
ICF INCORPORATED
-------
C-2
FIGURE C-1
MAP OF DEMAND REGIONS
New England
Maine/Vermont/New Hampshire (MV)
Massachusetts/Connecticut/
Rhode lilud (MC)
Middle Atlantic
New York. Upstate (NU)
New York, Downstate (NY)
Pennsylvania (PA)
New Jeney (NJ)
Upper South Atlantic
Maryland/Delaware/D.C. (MD)
Virginia (VA)
West Virginia (WV)
Lower South Atlantic
North suid South Carolina (CA)
Georgia (GA)
Florida (FL)
East North Central
Ohio. North (ON)
Ohio, South (OS)
Michigan (MI)
Indiana (IN)
Illinois (IL)
Wisconsin (WI)
East South Central
Kentucky, East (EK)
Kentucky. West (WK)
Tennessee, East (ED
Tennessee, West (WT)
Alabama (AL)
Mississippi (MS)
West North Central
Minnesota (MN)
North and South Dakota (DA)
Iowa (IA)
Missouri (MO)
Kansas/Nebraska (KN)
West South Central
Arkansas (AR)
Oklahoma (OK)
Louisana (LA)
Texas. East (TE)
Texas. South (TS)
Texas. West (TW)
Mountain
Montana (MT)
Wyoming (WY)
Idaho (ID)
Colorado (CO)
New Mexico (NM)
Utah (UT)
Arizona (AZ)
Nevada (NV)
Pacific
Washington/Oregon (WO)
California, North (CN)
California. South (CS)
Alaska (AK)
ICF INCORPORATED
-------
C-3
FIGURE C-2
COAL SUPPLY REGIONS
Northwest
Western Northern
Great Plains
Eli tern Northern
Great Plaint
Central West
Midwest
Northern
Appalachia
Rockiej'
. Central
Appalachia
Southwest
Southern
Appalachia
Alaska
Shaded areas not incorporated
into coal supply regions
Northern Appalachia
Pennsylvania, Central (PC)
Pennsylvania, West (PW)
Ohio (OH)
Maryland (MD)
West Virginia, North (WN)
Central Appalachia
West Virginia, South (WS)
Virginia (VA)
Kentucky, East (KE)
Tennessee (TN)
Southern Appalachia
Alabama (AL)
Midwest
Illinois (IL)
Indiana (IN)
Kentucky, West (KW)
Central West
Iowa (IA)
Missouri (MO)
Kansas (KS)
Arkansas, North (AN)
Oklahoma (OK)
Gulf
Texas (TX)
Louisiana (LA)
Arkansas South/Mississippi (AS)
Eastern Northern Great Plains
North Dakota (ND)
Montana, East (ME)
Western Northern Great Plains
Montana, Powder River (MP)
Montana, West (MW)
Wyoming, Powder River (WP)
Rockies
Wyoming, Green River (WG)
Colorado, Green River (CG)
Colorado, Denver (CD)
Colorado, Raton (CR)
Colorado, Uinta (CU)
Colorado, San Juan (CS)
Utah, Central (UC)
Utah. South (US)
New Mexico, Raton (NR)
Southwest
New Mexico, San Juan (NS)
Arizona (AZ)
Northwest
Washington (WA)
Alaska
Alaska (AK)
Imports
Imports (IM)
lOr INCORPORATED
-------
C-4
Coal by Sulfur Content
Low Sulfur -- less than 1.08 pounds sulfur
dioxide per million Btu on a cleaned coal basis.
Low-Medium Sulfur -- 1.08-1.67 pounds sulfur
dioxide per million Btu on a cleaned coal basis.
High-Medium Sulfur -- 1.67-3.33 pounds sulfur
dioxide per million Btu on a cleaned coal basis.
High Sulfur Greater than 3.33 pounds sulfur
dioxide per million Btu on a cleaned coal basis.
Cumulative Capital Costs refer to all capital
costs incurred for powerplants, equipment, scrubbers or
other capital equipment completed after December 31,
1980. These costs will also include any expenditures
occurring prior to December 31, 1980 for equipment not
finally completed until after this date.
Annual Costs are presented in real terms (early
1985 dollars) and consist of annualized capital costs
(levelized using real capital charge rates), annual fuel
costs (based on real annuity prices for coal), and
annual operating and maintenance costs.
Costs-Per-Ton-Sulfur-Dioxide-Removed are the
increases in annualized costs divided by the decrease in
annual tons of sulfur dioxide emissions. Costs per ton
removed are shown for national average values unless
otherwise indicated. Marginal costs, which reflect the
costs incurred to achieve the last ton of sulfur dioxide
emission reduction, usually are significantly higher
than the average costs shown.
Present Value of Costs -- the present value of
compliance costs is the present value at the beginning
of 1985 in early-1985 dollars of all annualized costs
incurred or subsidies received through the year 2030. A
4.26 percent real discount rate was assumed to
calculate the present value of utility costs and
electricity rate subsidy costs. The present value of
taxes was also calculated using the utility real
discount rate of 4.26 percent.
ICF INCORPORATED
-------
C-5
Percent Change in Regional Electricity Rates was
calculated using two separate methods:
-- "Annualized" Percent Change in Rates is the
difference in utility annualized costs in mills per
kilowatt hour between the rollback scenarios and
base case levels for the particular forecast year
divided by the 1982 estimated average electricity
prices for each state.
-- "First Year Revenue Requirements" Percent Change in
Rates is calculated in the same manner except that
the approximate differences in first year revenue
requirements are divided by the 1982 estimated
average electricity prices.
(Note that a more appropriate electricity price for
measuring the percentage change in electricity rates
would be the forecasted price in the future years in
which the cost impacts are measured. In some regions,
these prices will be higher in real terms than the 1982
prices, while in others they will be lower. However,
forecasting such prices was beyond the scope of this
analysis.
ICF INCORPORATED
-------
Appendix 0
-------
APPENDIX D --
DETAILED BASE CASE ASSUMPTIONS
ICF INCORPORATED
-------
TABLE D-1
MAJOR ASSUMPTIONS IN THE EPA BASE CASE
Critical Parameter
Global Energy and Economic Conditions
o GNP (% Per Year Real Growth)
o World Oil Prices (mid-1985 4/bbl)
o Natural Gas Prices and Availability
Electric Utility Energy Demand
o Electricity Growth Rate (% Per Tear)
o Nuclear Capacity (Gw)
EPA Base Case
Comments
1983-1985
1986-1990
1991-1995
1996-2000
2001-2010
5.0
3.5
3.0
3.0
3.0
GNP growth is forecasted to be higher during the
current recovery and slow to a 3 percent average
per annun growth rate by 1990.
1985
1990
1995
2000
2010
28.10
29.20
34.10
38.90
49.80
ICF forecasts assume that oil prices will remain
constant in ncminal terms through 1985 due to near
term market conditions. Prices are assumed to
recover scmewhat by 1990, with 2.5-3.0 percent
increases per year in real terms thereafter.
1985 deregulation is assumed
1980-1984
-
2.2
1984-1985
a
2.4
1986-1990
a
2.5
1991-1995
m
2.5
1996-2000
m
2.5
2001-2010
2.5
1985
m
67
Capacity estimates through 2000 reflect most recent
1990
m
105
announcements, postponements and delays of currently
1995
m
108
planned powerplants. Nuclear capacity in 2010
2000
0
109
reflects an assumed upturn in nuclear capacity
2010
m
120
additions after 2000 more than offsetting the
forecasted retirement of 27 gigawatts of nuclear
powerplants expected between 2001 and 2010.
-------
TABLE D-1 (Continued)
MAJOR ASSUMPTIONS IN THE EPA BASE CASE
Critical Parameter
EPA Base Case
Commen ts
o Nuclear Capacity Factors (%)
1985
1990
1995
2000
2010
60
64
67
67
67
Improvement in the availability of nuclear
units is expected as recent regulatory and
technical problems resulting primarily from the
Three-Hile Island experience are resolved.
o Substitution of Coal for Oil and Gas
-------
TABLE D-1 (Continued)
MAJOR ASSUMPTIONS IN THE EPA BASE CASE
Critical Parameter
EPA Base Case
Comments
o Powerplant Lifetime (Years)
o Coal Pcwerplant Heat Rates Over Time
Coal Steam - 60 years
Oil/Gas Steam - 45 years
Nuclear - 35 years
Oil/Gas Turbine - 20 years
0.25% per year increase
over current levels.
After refurbishment Improves
heat rates are Improved
(decreased) by five percent
fran previous forecasts
levels .
Pcwerplant units are assumed to retire based on the
assumed nunber of years after their initial date of
commercial operation except for announced retire-
ments. Coal powerplants are refurbished after 30
years for $200/Kw (early-1985 $). This is assumed
to extend their useful lifetime from 45 to 60
years. Reconversions are assumed to retire 30
years after their reconversion date.
Based on empirical studies and engineering assess-
ments of heat rate deterioration over time and the
effects of powerplant refurbishment.
o Minimum Turndown Rates
Coal - 35%
Oil/Gas Steam - 20%
Coal and oil/gas steam units must operate at or
above minimum load during the week. Minimum load
levels assumed herein are based on various
empirical studies of operating practice and
constraints .
o Canadian imports of Electricity
(BKWH transmitted)
1985
1990
1995
2000
2010
45
69
89.9
86.8
96.9
imports reflect current contracts and announced
plans.
Financial Parameters
o Inflation Rate (% Per Tear)
1984
1985
1986-2010
3.8
4.0
5.0
Latest forecasts anticipate a small increase in
average annual Inflation rates.
o Real Discount Rate (% Per Year)
Coal Mine
Utility
6.00%
4.27%
-------
TABLE D-1 (Continued)
MAJOR ASSUMPTIONS IN THE EPA BASE CASE
Critical Parameter
o Real Capital Charge Rates
Coal/Nuclear/Combined Cycle
Pollution Control-Mew
Pollution Control-Retrofit
Combustion Turbine
o Book Life (years)
Coal/Nuclear/Combined Cycle
Combustion Turbine
Pollution Control-Retrofit
Pollution Control-Hew
o Tax Depreciation Life (years)
Retrofit Pollution Control
Others
o Input Tear Dollars
o Output Year Dollars
o Escalation Input to Output Dollars
Real Cost Escalation Parameters
o Coal Transportation Rates
(% Tbtal Real Escalation)
EPA Base Case Comments
9.0% The retrofit pollution control capital charge rate
9.0% is lower than the new pollution control rate due to
6.5% the rapid tax write-off provision that is available
10.5% to retrofits only. Use of industrial revenue bond
financing was not assumed.
30 Longer book life for pollution control equipment
20 assumed in the previous EPA base is the major reason
30 for lwer real capital charge rates for this
30 equipnent.
5 Tax depreciation based on Accelerated Cost Recovery
15 System (ACRS) under Economic Recovery Tax Act of
1981.
early 1980
early 1985
1.34
Rail
1981 - 1985 ป -5.0%
1986 - 2000 - 0.0%
Truck and Barge
1981 - 1985 ป 5.0%
1986 - 2000 - 0.0%
Growing competition will hold down the marginal rail
rates to levels below current average rail rates.
Truck and barge rates are assumed to escalate in
real terms to account for long-term fuel price
increases .
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TABLE D-1 (Continued)
MAJOR ASSUMPTIONS IN THE EPA BASE CASE
Critical Parameter
EPA
Base
Case
Coal
Hining Productivity
o
Mining Costs (t Annual Real Escalation)
Capital
a
1.0%
Labor
1.0%
in 1984;
2.0ซ/3 yrs
thereafter
Materials
n
0.0%
o
Mining Productivity Base Level (1985)
UMWA
80
(% of Standard)
Non-UMWA
a
95
Mixed
-
90
% Annualized Productivity Increase
Surface
a
1.0
(1985-95)
Deep-Con tinous
Mine
o
1.0
Deep-Longwall
a
2.0
o
Utility PcMerplant Capital Costs
1980-1985
-
10.0%
(% Ibtal Real Escalation)
1985-2000
n>
0.0%
Other
Governmental Regulations
o
Federal Leasing Policy
Bioagh
Ccxranents
Expected real escalation In nuclear plant costs is
higher and is incorporated in base nuclear cost
estimates.
Federal leasing is assumed to be sufficient to
avoid artificially driving up market prices.
o Air Pollution Regulations
Most recent federal and
state rules.
S02 emission limits assumed to be tightened in New
York and Wisconsin over the next ten years in light
of recent state legislation aimed at acid rain
and/or ambient air quality concerns. Certain
variances are assumed to expire and revisions are
assumed occur. No other changes assumed beyond
current emission limitations.
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TABLE D-1 (Continued)
MAJOR ASSUMPTIONS IN THE EPA BASE CASE
Critical Parameter
Non-Utility Coal Demand
o Industrial/Retail Coal Use
(106 tons)
o Steam Coal Exports (10ฎ tons)
o Metallurgical Coal Use (10s tons)
Export
Domestic
o Synthetics (Coal Input in 10ฎ tons)
(Million Tons)
EPA Base Case Comments
1985
1990
1995
2000
2010
82
109
135
170
220
Reflects recent forecasts of industrial boiler
coal demand combined with forecast of the kiln and
residential/commercial coal markets. Low oil prices
and increased reliance on waste products and
conservation are expected to dampen near term coal
demand.
1985
1990
1995
2000
2010
28
25
48
69
120
Reflects low growth in worldwide electricity demand
and less market share going to U.S. producers,
particularly in 1985 and 1990. Reduction in longer
term demands concentrated mainly in the Pacific Rim.
1985
1990
1995
2000
2010
53
49
53
61
65
Reflects sluggish growth expected in world markets.
1985
1990
1995
2000
2010
54
61
62
62
62
Continuing trends in steel substitution limit
forecasted domestic metallurgical coal use
throuc/h most of the 1980's. Steel's recovery
from the present slump is not yet complete by
1985.
1985
1990
1995
2000
2010
4
8
8
8
8
Outlook for coal-based projects continues to be
unfavorable. Some slippage seen in on-line dates
of major near-term projects. Great Plains Gasifi-
cation Project assumed to stay on schedule.
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