EFFECTS OF ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS FOR
COAL-FIRED ELECTRIC UTILITY BOILERS
ON THE COAL MARKETS AND ON UTILITY
CAPACITY EXPANSION PLANS
September, 1978
Submitted to the
Environmental Protection Agency
under Contract No. 68-01 -3957
ICF INCORPORATED 1850 K Street. Northwest.
Suite 950. Washington. D. C. 20006
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EFFECTS OF ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
FOR COAL-FIRED ELECTRIC UTILITY BOILERS ON THE COAL
MARKETS AND ON UTILITY CAPACITY EXPANSION PLANS
Final Draft
September, 1978
Submitted to the
Environmental Protection Agency
under Contract No. 68-01-3957
ICF
INCORPORATED
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PREFACE
This final draft report was prepared for the Environmental
Protection Agency and is being distributed for purposes of review
and comment. Constructive comments are welcomed.
Further work is being conducted. Refinements and additional
analyses have been completed. A subsequent report will be issued
shortly which will present the results of the additional analyses.
The assumptions, findings, conclusions, judgments, and views
expressed herein are those of ICF Incorporated and should not be
interpreted as necessarily representing the official policies of the
U.S. government.
ICF
INCORPORATED
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TABLE OF CONTENTS
Chapter I:
EXECUTIVE SUMMARY
Summary of Effects of Alternative New Source
Performance Standards — Phase 1 2
Summary of Effects of Alternative New Source
Performance Standards — Phase II 2
Approach
Reference Case Forecasts 10
Effects of Alternative NSPS — Phase 1 19
Effects of Alternative NSPS — Phase II 25
Caveats and Key Uncertainties 32
Chapter II: APPROACH
Model Description 35
Scenario Specifications 47
Chapter III: FINDINGS ~ PHASE I
Coal Production ^4
CQ
Coal Distribution -'^
Coal Prices 60
Generating Capacity 62
Scrubber Capacity 67
Utility Fuel Consumption 72
Chapter IV: FURTHER ANALYSIS — PHASE II
SO Loadings
Utility Capital Expenditures and Annualized Costs. 84
0.8 Ib. SO /MMbtu Emission Limitation Case 86
Impacts of Revised Partial Scrubbing Cost 98
Impacts of Alternative Floors, Ceilings
and Exemptions
Economics of Partial Scrubbing 128
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TABLE OF CONTENTS
Appendix A: IMPLICATIONS OF COAL VARIABILITY AND AVERAGING TIME
CONSIDERATIONS, INCLUDING EFFECTS OF ALTERNATIVE CEILINGS
ON PORTION OF NATION'S COAL RESERVES THAT COULD BE USED
IN NEW UTILITY BOILERS
Appendix B: REFINEMENTS TO ICF COAL AND ELECTRIC UTILITIES MODEL
STRUCTURE
Appendix C: DATA INPUTS
Appendix D: EXHIBITS GIVING MODEL RESULTS FOR THE FOLLOWING ALTERNATIVE
NSPS: 1.2 LBS. SO /MMBTU: 90 PERCENT REMOVAL; 80 PERCENT
REMOVAL: AND 0.5 LB. SO /MMBTU (with initial scrubber cost
estimates)
Appendix E: EXHIBITS GIVING MODEL RESULTS FOR AN ANSPS OF 0.5 LB. S02/
MMBTU (with revised scrubber cost estimates)
Appendix F: EXHIBITS GIVING MODEL RESULTS FOR AN ANSPS OF 0.8 LB. SO2/
MMBTU
Appendix G: COAL SUPPLY CURVES USED IN NSPS ANALYSIS
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CHAPTER I
EXECUTIVE SUMMARY
This report presents the effects of alternative new source performance
standards for coal-fired utility boilers on the coal market and on utility
capacity expansion plans. This study was undertaken to assist the Environ-
mental Protection Agency (EPA) in reviewing the current new source perform-
ance standard (NSPS) pursuant to the 1977 Amendments to the Clean Air Act.
ICF's analysis of the alternative standards was divided into two phases.
The first phase consisted of work ICF performed prior to the National Air
Pollution Control Technology Advisory Committee (NAPCTAC) meeting in December
1977. This work was the basis of the draft version of this report that was
circulated for comment in January 1978. Chapters I and III and Appendices
A and D present Phase I work.
The second phase consisted of work done between the NAPCTAC meeting and
April, 1978. This work expanded on the earlier results by estimating the
SO emissions and annualized cost impacts of the alternative standards,
analyzing additional standards, and employing revised cost estimates for
partial scrubbing. Chapter IV and Appendices E and F present the Phase II
work.
In the first phase of the analysis EPA directed that three alternative
new source performance standards (ANSPS) be assessed. These were (i) a 90
percent removal requirement, (ii) an 80 percent removal requirement, and (iii)
a 0.5 Ibs. SO /mmbtu emission limitation. These standards were treated
as though they applied on an annual averge basis. If shorter term require-
ments are set that would result in lower annual average emissions, the Phase I
findings would not represent the likely effects of the alternative standards.
In the second phase, analyses were done that took into account the
24-hour averaging time being considered by EPA. Also, alternative floors
(i.e., an emission limitation that could be met in lieu of a percent removal
requirement) and ceilings (i.e., maximum 24-hour emissions rate) were analyzed
in addition to percent removal requirements.
All model runs assumed that the emission limitations for ANSPS plants to
be 0.03 pound per million btu for total suspended particulates (TSP) and 0.6
pound per million btu for nitrous oxides
The cost estimates employed herein do not include any cost penalty asso-
ciated with the reduced availability of a generating unit as a result of the
installation of scrubbers.
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SUMMARY OF EFFECTS OF ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS - PHASE I
Table T-1 summarizes the impacts on two reference cases of the alternative
now source performance standards analyzed as part of Phase I. The two cases
differ only in the electricity growth rate assumed for the years beyond 1985.
Reference Case I assumes 3.4 percent per year; Reference Case II assumes 5.5
percent. These impacts are discussed in greater detail in the fifth section
of this chapter and in Chapter III. Model results for these cases are pre-
sented in Appendix D.
The basic conclusion of Phase I was that there was not much a difference
between the three alternative new source performance standards. For example,
national coal production only ranged from 1,710 million to 1,712 million tons
among the standards under the high growth assumptions in 1990. Similarly,
western coal consumed in the East ranged from 297 million to 300 million tons
for the same case. The same conclusion held true for coal-fired generating
capacity (range: 444.3 GW to 444.6 GW ) ; scrubber capacity (constant across
revised standards); utility oil consumption (constant); cumulative utility
capital expenditures (range: $333.9 billion to $336.0 billion); annualized
cost increase (range: $1.57 billion to $1.95 billion); and electricity rate
increase (range: 1 percent to 1.3 percent). The only impact that showed some
variation between standards was SO emissions. The 90 percent standard
showed 1990 emissions of 20.9 million tons with the 0.5 Ib. standard showing
emissions of 21.48 million tons and the 80 percent standard of 22.37 million
tons .
SUMMARY OF EFFECTS OF ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
— PHASE II
The Phase II work focused upon analysis of short term averaging period
standards with alternative floors- and ceilings,- with and without
exemptions from the ceiling, using Reference Case II only. The Phase II
results are summarized in Table 1-2 and presented in detail in Chapter IV and
Appendices E and F.
Phase II results showed significant differences between the standards
examined, unlike Phase I. For example, Northern Great Plains coal production
increased by 30 percent from 652 million tons under a 0.2-lb. floor/ 1. 2-lb. cap
with exemption standard to 852 million tons under a 0.5 Ib. f loor/0 .8-lb. cap
without exemption standard. Similarly, Western coal consumed in the East
ranyed from 299 million tons to 484 million tons. Scrubber capacity ranged
from 120.3 GW for the 0.8-lb. floor case to more than 225 GW for most of the
0.5-lb. floor cases. Utility oil consumption increased by nine percent or 0.6
wtien the floor was lowered from 0.5 Ib. to 0 . 2 Ib.
Thn qeneral conclusions as to impacts of the Phase II scenarios are:
1/ 1-imiWion limitation below which utilities would not be required to reduce
omissions. This provision allows for scrubbing at less than the 85 per-
cent removal level (i.e. allows partial scrubbing).
2/ ^mission limitation that cannot be exceeded on a 24-hour average unless
there are exemptions that permit it to be exceeded three days per month.
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TABLE 1-1
SUMMARY OF 1990 IMPACTS OF ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS ANALYZED IN PHASE I
Coal Production (10 tons)
Appalachia
Midwest
Northern Great Plains
West
National
1,584
Reference Case I—
V
1
.2 Ibs.
408
290
686
201
90%
434
321
586
206
80%
436
326
587
206
0.5 Ib. (Initial)
438
319
580
207
1,547 1,554
1, 544
1, 768
Reference Case II—'
I/
1
.2 Ibs.
441
298
810
218
90%
476
364
651
220
80%
469
370
658
215
0.5 Ib. (Initial)
469
372
653
218
1,711 1,710
1,712
Western Coal Consumed in
East (10 tons) 366
Coal-Fired Generating Capacity (GW) 395.9
Scrubber Capacity (GW)
Existing 37.9
NSPS 28.4
ANSPS 20-3
Total 86.6
Utility Oil/Gas Consumption (10 btu) 5.8-
270 266
379.0 384.5
36.8 36.9
23.9 23.5
86.9 92.7
147.6 153.1
6.4 6.2^
266
378.1
36.5
24.1
85.9
146.5
6.4
455
465.0
40.3
28.7
34.2
298
444.6
36.3
23.4
151.1
300
444.3
36.5
23.1
151.2
297
444.5
36.2
23.2
151.0
103.2
, .
6.4—
210.8 210.8
7.1
210.8
7.1
National SO Emissions
(10 tons/year)
Oil/gas
Coal
Existing
NSPS
ANSPS
Total
2.21
13.94
2.51
2.64
21.31
2.35
13.97
2.57
0.89
2.30
13.93
2.56
1.90
19.78 20.68
2.35
14. 17
2.57
1.10
20.18
2.30
14.25
2.61
4.18
23.33
2.47
14.29
2.63
1.49
20.90
2.46
14.27
2.62
3.01
22.37
2.46
14.54
2.63
1.85
21.48
Regional SO Emissions
(10 tons/year)
East
Midwest
West South Central
West
National
9.63
8. 16
2.38
1.13-
8.99
7.97
1.74
1.08
9.47
8.12
1.96
1 . 1 3-
8.99
8. 18
1.89
1.11
10.78
8.74
2.55
1 . 27-'
9.73
8.27
1.80
1.12
10.53
8.58
2.05
1.21-
9.72
8.54
2.02
1.19
21.31
19.78 20.68
20.18
23.33
20.90
22.37
Cumulative Utility Capital
Expenditures (10 $)
283.2 283.4 285.1
283.0
332.6 336.0 333.9
336.0
Change in Annualized Costs
Absolute (10 S)
Percentage Increase
1.22 1.04
0.80 0.70
1.25
0.80
1.94 1.57
1.30 1.00
1.95
1.30
Average Annualized Cost Per Ton
of SO Removed ($/ton)
800
1,660
1, 100
800 1,640
1, 060
I/ Cases differ in electricity growth rates beyond 1985. Reference Case I uses 3.4 percent; Reference Case II uses 5.5 percent.
2/ A data input error caused the cost of scrubbers in a Western region to be overstated. The result was that less coal-fired generating
~ capacity was built than would be expected with the correct scrubber costs. Thus, coal consumption in 1990 is probably low by 0.2
quad for Reference Case II and oil consumption is high by the same amount. Similarly, the emissions projection is slightly high
because the oil used has a higher emission rate than the coal that would have been used.
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TABLE 1-2
SUMMARY OF 1990 IMPACTS OF ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS ANALYZED IS PHASE II
(Reference Case II only)
0.2 Floor
0.5 Floor
Coal Production ( 10 tons)
Appalachia
Midwest
Northern Great Plains
West
National
".."estern Coal Consumed in
East (10 tons)
Coal-Fired Generating Capacity (GW)
Scrubber Capacity (GW)
Existing
SSPS
ANSPS
Total
Utility Oil/Gas Consumption (10 btu)
Current
NSPS
441
298
810
219
1, 768
456
465.0
40.3
28.7
34.2
103.2
1 .2
With
Exemp.
467
375
652
218
1, 711
299
444.4
36.3
23.4
150.9
210.6
Cap
Without
Exemp.
489
306
706
217
1,718
329
441 .7
35.0
27.3
148.3
210.6
0.8
With
Exemp .
489
306
706
217
1, 718
329
441.7
35.0
23.3
148.3
210.6
Cap
Without
Exemp.
429
303
798
204
1, 733
424
437.8
39.0
32.2
144.4
215.6
1.2
With
Exemp.
464
352
714
224
1, 754
343
459.6
36.5
23.1
166.3
225.9
Cap
Without
Exemp.
473
297
772
224
1, 766
397
457.6
35.3
25.6
164.2
225. 1
0.8
With
Exemp.
473
297
772
224
1, 766
397
457.6
35.3
25.6
164.2
225. 1
Cap
Without
Exemp .
413
290
852
204
1, 764
434
443. 2
33.5
29.1
155.2
223.8
0.8 Floor
1.2 Cap
418
307
826
229
7. 1
7.2
7.2
7.4
6.5
6.5
6.5
6.9
1, 780
431
459.2
37.4
27.7
55.2
120.3
6.5-^
Natiopal SO Emissions
(10 tons/year)
Oil/gas
Coal
Existing
SSPS
ANSPS
Total
Regional SO Emissions
(10 tons/year}
East
Midwest
West South Central
West
National
Cumulative Utility^Capital
Expenditures (10 $)
Change in Annualized Costs
Absolute (10 S)
Percentage Increase
2.30
2.47
2.54
2.54
2.59
2.32
2.33
2.33
2.41
14.25
2.61
4. 18
23. 33
10. 78
8.74
2.55
1.27V
23. 33
332.6
-
14 .52
2.63
1.45
21 .06
9.70
8.45
1.80
1.12
21 .06
336. 1
1.94
1.30
14.48
2.62
0.95
20.59
9.42
8.26
1.79
1.12
20.59
337.0
2.23
1.50
14.48
2.62
0.95
20.59
9.42
8.26
1.79
1.12
20.59
337.0
2.23
1.50
14.57
2.67
0.57
20.40
9.28
8.30
1.72
1 . 10
20.40
336.8
3.05
2.00
14.35
2.50
2.13
21 .30
9.63
3.42
2.02
1 .23
21 .30
343.3
1 .32
0.90
14.40
2.60
2.05
21.38
9.72
8.41
2.03
1.23
21.38
342.2
1.47
1.00
14.40
2.60
2.05
21 .38
9.72
8.41
2.03
1 .23
21 .38
342.2
1 .47
1.00
14.48
2.62
1 .94
21.45
9.81
8.44
2.02
1 . 18
21 .45
337.1
1.83
1.20
2.33
14.20
2.48
3.33
22.34
10.17
8.63
2.29
1 .261'
22.34
335.8
0.30
0.20
Average Annualized Cost Per Ton
of SO Removed ($/ton)
860
820
820
1, 040
640
760
760
1, 000
300
V A data input error caused the cost of scrubbers in a Western region to be overstated. The result was that less coal-fired generating
capacity was built than would be expected with the correct scrubber costs. Thus, coal consumption in 1990 is probably understated by
0.2 quad and oil consumption is high by the same amount. Similarly, the emissions projection is slightly high since the oil used has
a higher emission rate than the coal that would have been used.
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The major impacts of raising the emission floor are 1)
increased emissions, 2) increased shipments of Western
coal to the East, 3) lower utility oil consumption and
4) lower annualized costs.
The major impacts of lowering the ceiling are 1)
increased Western coal shipments to the East, with a
significant decline in Midwestern coal production,
2) higher annualized costs, and 3) sometimes a decrease
in SO emissions.
The major impact areas for the exemption from the
ceiling are the same as for changing the ceiling, since
such an exemption has the effect of raising the average
sulfur content of coal that can be utilized with any
given ceiling. An exemption from the ceiling would
reduce the amount of Western coal shipped to the East,
lead to more Midwestern production, reduce the annual-
ized utility costs by increasing the amount of coal
reserves that the ANSPS plants can burn, and increase
S0 emissions.
APPROACH
ICF's Coal and Electric Utilities Model (CEUM) was employed for this
analysis. This model was initially designed and developed by ICF for the
Federal Energy Administration— and has been refined by ICF for this
study.
Model Description
The model forecasts coal production, consumption, and prices, given
such input parameters as electricity growth rates, nuclear capacity and
oil and gas prices. It was designed to show the effect of alternative
public policies (e.g., changes in the NSPS) on these forecast variables.
It generates equilibrium solutions through a linear program formulation
which balances supply and demand for coal at minimum cost. The model has a
high degree of resolution with 30 supply regions, 35 demand regions, six
consumption sectors, and 40 coal types.
The model is well suited for this particular study because it treats
both the coal supply sector and the electric utility industry. Relative to
coal supply, the model forecasts production by geographic region by coal-type
(defined in terms of five heat content categories and eight sulfur content
V ICF Incorporated, Coal and Electric Utilities Model Documentation (July
1977).
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cateyories). It indicates the effects of alternative NSPS on (a) the sulfur
content of the coal produced (e.g., standards requiring scrubbers generally
result in more high sulfur coal), (b) regional production patterns (e.g.,
standards requiring scrubbers generally result in less Western production,
which is mostly low sulfur), and (c) coal prices by coal type by region. The
coal prices are based upon engineering costs of production which include the
1977 Federal strip mine reclamation legislation.
Relative to the electric utility sector, the model simulates economic
dispatch, which means that it forecasts the construction and utilization of
powerplants by region in a manner that minimizes the present value of genera-
tion costs. In so doing, the model also satisfies load requirements in each
of four load categories: base, intermediate, seasonal peak, and daily peak.
The model incorporates new and existing capacity for the following powerplant
types: nuclear, coal, oil/gas steam, combined-cycle, combustion turbines,
and hydro.
The model accounts for sulfur emission limitations. Existing coal plants
must meet the applicable state implementation plan limitations. New power-
plants must meet the more stringent of federal or state new source perform-
ance standards (NSPS). Further, the new powerplants are separated into those
that would be subject to the current NSPS and those that would be subject to
an ANSPS.
Coal plants can comply with a sulfur emission limitation by (a)
burning compliance coal (which includes the option of conversion to Western
coal at a cost), (b) burning a blend of coals that would be in compliance,
c) deep washing coals to an acceptable level, or (d) scrubbing. The scrubbing
options include scrubbing 100 percent of the flue gas or only a portion of
the flue-gas, i.e., partial scrubbing.
All bituminous coals are assumed to be washed to a moderate degree,
removing up to 35 percent of the sulfur in high sulfur coals and down to
zero percent in low sulfur coals. The model also has the option to "deep
clean" these coals (i.e., use more intensive coal preparation) to remove
more sulfur, but this option is seldom utilized due to the relatively
high costs associated with it.
This level of detail in the utility sector means the model can fore-
cast by region (a) new capacity additions by powerplant type, (b) scrubber
capacity by level of partial scrubbing (up to full scrubbing) and by sulfur
removal efficiency, and (c) utility consumption of oil, gas, and coal by
coal-type. The model's forecasts reflect the effect on new powerplant
capacity, scrubber capacity, and utility fuel consumption of whatever addi-
tional costs are imposed on new coal-fired powerplants by an ANSPS.
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A more complete description of the model appears in Chapter II. A
discussion of recent refinements to the model for this study appear in
Appendix B.
Reference Case
Two reference case forecasts were made for each of the years 1985, 1990,
and 1995. In each case, the current new source performance standard of 1.2
Ibs. SO /mmbtu was assumed to apply to new coal-fired boilers. The only
differences between the two forecasts are in the assumed electricity growth
rates. The first reference case is consistent with the base base reported in
the President's National Energy Plan (1977), with electricity growth at a
compound annual rate of 5.8 percent from 1975 through 1985 and 3.4 percent
thereafter. The second reference case reflects the same growth rate through
1985 (i.e., 5.8 percent) but a higher growth rate thereafter — 5.5 percent.
All the other input assumptions (e.g., nuclear capacity, industrial coal
demand, oil and gas prices, etc.), are the same for the two reference cases.
(A more complete discussion of the reference case assumptions and data inputs
appear in Appendix C.)
The utility coal consumption forecasts are made endogenously by the
model. The non-utility coal demands are exogenous to the model. Table 1-3
shows the non-utility coal demands in terms of tons. Since the model
inputs are in terms of btu's the tonnage estimates vary slightly between runs
as the heat content of the coal changes.
TABLE 1-3
NATIONAL NON-UTILITY COAL CONSUMPTION
(in 10 tons)
1975 1985 1990 1995
Industrial 64 196 358 453
Metallurgical 86 105 109 113
Exports 66 87 92 96
Synthetics - 26 51 101
Residential/Commercial 7 2 1 -
Total 223 416 611 763
These non-utility coal demand estimates are not ICF forecasts. They
are input assumptions provided by various federal agencies. The industrial
coal consumption estimates are less than those initially reported to result
from the President's Energy Program, but were judged by the White House
energy staff to be consistent with the House version (circa August 1977) of
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the President's Energy Program. The estimates for the metallurgical, export,
and residential/ commercial sectors are consistent with the Federal Energy
Administration's PIES^7 model (circa August 1977). The synthetics estimate
came from the Energy Research and Development Administration (circa August
1977).
Other variables that remain constant across scenarios are (1) the price
of oil, (2) nuclear capacity, (3) coal transportation rates, (4) Federal coal
leasing and (5) coal industry labor rates. (Each of these variables is dis-
cussed below.)
• The residual oil price was assumed to be $2.25 per million
btu. This is equivalent to a 1975 price of crude oil
$13 per barrel inflating at the general rate of inflation
throughout the forecast period. Some of the more recent
work for the Department of Energy has indicated that oil
prices are likely to escalate in real terms. Thus, the
oil price used in the NSPS model runs may be low. This
would mean that oil consumption is overstated and coal
consumption is understated.
• Nuclear capacity was set exogenously at 112 GW in 1985,
177 GW in 1990 and 302 GW in 1995. The 1985 and 1990
forecasts were the best estimates of a FEA/NRC/ERDA task
force in 1977. The 1995 estimate was developed to reflect
accelerated nuclear development. Since these estimates
were developed, the projections of nuclear capacity have
continued to decline. This projected decline would trans-
late into more coal-fired capacity in 1990 and 1995. Thus,
the NSPS runs probably understate future coal consumption.
• Coal transportation costs were assumed to increase with the
general rate of inflation. Recent rate filings by railroads
(e.g., Burlington Northern) have made this assumption suspect.
Rail rates probably will increase faster than the general
rate of inflation. Thus, coal prices are somewhat under-
stated. More importantly, however, the NSPS results probably
overstate the amount of Western coal shipped to the East
and to Texas since this coal has the largest transportation
component in its delivered price.
• Federal coal leasing was not considered a constraint on
Western coal development. We assumed that reserves would be
leased to meet projected demands.
• The 1978 UMW labor contract settlement was not included in
the coal costs. Since that agreement increased real wages
by 13 percent over the three years of the contract, the coal
labor costs are understated in the model runs. No real
I/ Project Independence Evaluation System.
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escalation was assumed for labor costs. Since the last
two UMW wage agreements included substantial real escala-
tion, it is probably unrealistic to project constant labor
costs in real terms. Thus, the labor costs (and ultimately
coal prices) are slightly understated.
Alternative New Source Performance Standards
Three alternative new source performance standards for sulfur dioxide
were assessed for each of the two reference cases in Phase I:
— a 90 percent removal requirement with a cap on emission
limitations of 1.2 pounds of sulfur dioxide per million
btu's,
— an 80 percent removal requirement with a cap of 1.2
pounds,
~ an emission limitation of 0.5 pounds of sulfur dioxide
per million btu's.
For each of the three alternatives, the emission limitation for total
suspended particulates (TSP) was 0.03 pounds per million btu's, and for
nitrous oxides (NO ) 0.6 pounds per million btu's. For the 80 percent
and 90 percent removal cases, no credit was given for the sulfur removed
during coal preparation or washing.
Each of these standards was treated as if it applied on an annual
average basis. It was assumed the shorter-term requirements (e.g., 24-
hour averages) would be established to be consistent with these annual
averages.- If the shorter term requirements were to be set so that they
are binding, they would result in lower annual average emissions, and the
findings of these analyses would not represent the likely effects of the
alternative standards. The nine alternative new source performance standards
analyzed in Phase II are all specified explicitly as 24-hour standards.
They require 85 percent sulfur removal, and establish a maximum allowable
daily emissions rate (ceiling) and a floor below which emissions are not
required to go. Appendix A discusses the importance of averaging time and coal
variability on the results of this study.
The pollution control cost estimates were provided by PEDCo through EPA.
(The estimates used are presented in Appendix C.) Both the level of these
costs and their relative differences for alternative degrees of partial
scrubbing have a substantial affect on the findings of this study. Alterna-
tive cost estimates could result in different findings as was demonstrated by
the 0.5-lb. case with revised scrubber costs (see Chapter IV). The costs of
reduced reliability from adding scrubbers are not explicitly accounted for in
this analysis.
T>~"The 74-hour averaging time was addressed in Phase II of ICF's NSPS anal-
ysis for EPA. See Chapter IV.
ICF INCORPORATED
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Below, the reference case forecasts are presented first, followed by
a discussion of the effects of the alternative new source performance
standards.
REFERENCE CASE FORECASTS
The differences in the assumed electricity growth rates are clearly
manifested in the national coal production forecasts. Reference Cases I and
II have the same electricity growth rate through 1985 (i.e., 5.8 percent).
After 1985, the electricity growth rate for Reference Case I was 3.4 percent
and for Reference Case II was 5.5 percent. See Table 1-4.
Table 1-4
NATIONAL COAL PRODUCTION UNDER THE
CURRENT NEW SOURCE PERFORMANCE STANDARD
(in 10 tons)
Reference Case I
Annual Growth Rate
From Previous Period
Reference Case II
1975 1985 1990 1995
647 1218 1584 1763
6.5 5.4 2.2
647 1218 1768 2201
Annual Growth Rate
From Previous Period
6.5
7.7
4.5
Coal production is 25 percent higher in 1995 in the Reference Case II fore-
cast than in Reference Case I, demonstrating the effect of the higher elec-
tricity growth rate assumed for Reference Case II. Note also that there
is no difference in the 1985 forecast. This is because the assumed growth
rate for electricity sales is the same from 1975 through 1985, for each
reference case.
Reference Case I was conceived to be closer to what many would consider
a "best guess" of future coal use. Reference Case II was specified to
provide a high estimate of coal use, which would amplify the effects of the
ANSPS. The discussion below concerns Reference Case II, because the effects
of the ANSPS are more obvious. The effects of Reference Case I are identical
but smaller. The interested reader can find the Reference Case I projections
in Appendix D.
C o a1_P roduet ion
The r»Mj ion.nl production forecast for Reference Case II is shown in Table
l-'j. Those regional coal production estimates are consistent with the coal
-------
-11-
TABLE 1-5
REGIONAL COAL PRODUCTION UNDER THE
CURRENT NEW SOURCE PERFORMANCE STANDARD
(in 10 tons)
Northern Appalachia
Central & Southern Appalachia
Midwest & Central West
Northern Great Plains
Rest of West
National Total
Western Coal Consumed in East
Reference Case II
1975 1985 1990
21
1995
179 172 205 223
218 236 237 241
151 243 298 331
55 424 810 1160
44 143 218 247
647
1218 1768 2201
206
455
601
The majority of the additional production is forecast to occur in the
West, especially the Northern Great Plains (see Figure 1-1 for specification
of supply regions.). There is substantial growth in the West because (a)
the coal is Lw sulfur and can meet most current sulfur emission lotions
without a scrubber, (b) the supply is vast and this coal can be produced at
low prices, (c) much of the growth in coal consumption is in the West, and
(d) about 40 percent of the coal produced west of the Mississippi would be
consumed east of the Mississippi.-
The Western coal consumed in the East is forecast to be primarily
sub-bituminous low sulfur coal from Montana and Wyoming and to a lesser
degree bituminous coal from Colorado. These coals are forecast to be
consumed primarily in the states east of the Mississippi River but west
of the Appalachians. This coal is forecast to be consumed primarily in the
utility sector - both in existing plants that convert to Western coal to
recen analyses (i.e., ICF report titled The Demand for Western Coal
and Its Sensitivity to Key Uncertainties and further work for EPA and DOE
on alternative NSPS) have shown lower western coal production. This
reduction occurs because 1) higher costs for converting existing bitu-
minous boilers to subbituminous coal are being used, 2) recent data
on the rank of coal that planned units are being designed to use
(this generally means bituminous coal east of the Mississippi) has been
added and 3) refined industrial sector coal demand estimates do not
provide for the use of sub-bitumious coal east of the Mississippi.
Further, the effect of real rail rate escalation is to inhibit the use
of western coal in the East. These lower western production estimates
would probably not significantly affect the findings of this study as the
differences between the current NSPS cases and the ANSPS cases would proba-
bly remain about the same. A possible exception to this statemen£ "that
higher rail rates could reduce the attractiveness of partial scrubbing and
hence the cost savings associated with higher floors.
ICF INCORPORATED
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::/AL SUFJ'LY P£3:
0
Tl
2
8
Legend
V"V Bituminous Coal
^Cr Subbituminous
^flfc Lignite
y
K Anthracite
|
1
Coal
1. Northern Appalachia
2. Central Appalachia
3. Southern Appalachia
4. Midwest
5. Central West
6 Gulf
7. Eastern Northern
Great Plains
8. Western Northern
Great Plains
9. Rockies
10. Southwest
11. Northwest
12. Alaska (not stiown)
i
M
(0
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-13-
comply with the emissions limitations of the state implementation plans and in
new plants to comply with the current NSPS. These forecasts do not take into
account any regulations (state or federal) that would ban Western coals from
Eastern markets (e.g., section 125 of the Clean Air Act).
Appalachian production is forecast to remain fairly level, because
the supply of low sulfur coal in Appalachia (primarily in Central Appalachia)
is (a) limited and expensive to produce and (b) generally used for metallur-
gical purposes. The forecast indicates modest growth for Northern Appalachian
high sulfur coals where this growth is limited by modest electricity growth
rates and large increases in nuclear capacity in the geographic markets
for Northern Appalachian coal. There is growth in the Midwest because
Midwestern coals, although high in sulfur, can be mined and transported
to many large markets at competitive prices.
Delivered Coal Prices to Electric Utilities
Delivered coal prices do not change substantially between years.
Prices tend to increase gradually over time and with higher growth rates.
This is because the Nation's coal reserves are so vast that large quantities
can be produced without substantial real price increases. Particularly in
the East, the forecast price increases are greater between 1985 and 1990 than
between 1990 and 1995, because the growth in coal consumption is greater in
the earlier period. See Table 1-6. (Figure 1-2 gives the boundaries of the
demand regions.)
Generation Capacity
Most of the new generation capacity is forecast to be coal and nuclear
used for base load generation. See Table 1-7.
ICF
INCORPORATED
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TABLE 1-6
DELIVERED COAL PRICES TO ELECTRIC UTILITY SECTOR
UNDER THE CURRENT NEW SOURCE PERFORMANCE STANDARD
$/10 btus (1977 S's)
Reference Case II
Middle Atlantic
South Atlantic
• East North Central
• East South Central
• West North Central
West South Central
Mountain
Pacific
Sulfur Level
Medium-
Low-
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
Low
1985
1.12
1.85
1.90
0.95
1.31
1.80
1.04
1.36
1.52
0.97
1.24
1.36
0.97
1.15
1.31
0.94
0.95
0.85
0.84
0.58
1.21
0.63
0.74
0.96
0.94
1990
1.30
1.38
1.98
1.20
1.37
1.60
1.17
1.41
1.62
1.08
1.24
1.37
1.07
1. 15
1.38
1.03
0.83
1.04
1.02
0.62
1.30
0.65
0.82
1.28
1.22
1995
1.31
1.39
1.98
1.22
1.39
1.88
1.22
1.41
1.68
1.11
1.25
1.36
1.11
1.18
1.42
1.07
1.11
1.11
1.03
0.99
1.46
0.78
0.85
1.26
1.08
1/ Greater than 1.67 pounds of sulfur per million btu1s (roughly greater than
two percent sulfur by weight).
2/ 0.61 to 1.67 pounds of sulfur per million btu's (new source performance
standard to roughly two percent sulfur).
3/ Meets new source performance standards (0.6 pounds of sulfur or less).
NOTE:
Certain anomalies in the behavior of prices over time are apparent, such
as medium sulfur prices in New England dropping over time. This is due
to the averaging (consumption weighted) associated with aggregating the
35 demand regions into nine larger regions, where expensive coal in one
demand region (e.g., Maine) is averaged with less expensive coal in another
region (e.g., Massachusetts) and where the relative volumes of these coals
change over time.
-------
Figure 1-2
DEMAND REGIONS
o
CENSUS REGIONS
" NORTH CENTRAL
WEST SOUTH CENTRAL
(-——^ i
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-16-
TABLE 1-7
NATIONAL ELECTRIC GENERATING CAPACITY
DNUKK TIIK CURRENT NEW SOURCE PERFORMANCE STANDARD
(in GW — capability)
Reference Case II
1975 1985 1990 1995
Nuclear* 38.3 108.3 176.7 302.0
Coal»* 183.6 320.4 465.0 577.2
Oil/Gas
- steam** 147.3 145.5 143.5 140.2
- combined cycle 2.7 12.2 15.9 15.9
-turbine 42.1 117.2 142.5 219.2
Hydro and others 66.3 88.2 87.6 _90^5
Total 480.3 791.8 1031.4 1345.1
Coal as percent of Total 38.2 40.5 45.0 42.9
* Nuclear capacity was specified and not the result of the
model's optimization.
** Powerplants under ESECA orders (circa August 1977) to switch
from oil and/or gas to coal (i.e., 21 GW) are assumed to
convert by 1985.
A substantial number of new turbines are forecast to be built for peak-
load generation. In Reference Case II, only 5 GW oil/gas steam capacity is
retired by 1995 since this capacity is required for intermediate load gener-
ation.
Scrubber Capacity
Nearly all the increase in scrubber capacity under the current NSPS is
associated with the generating capacity built after 1982 (i.e., the ANSPS
plants). For existing and NSPS plants, the average percent removal averages
between 65 and 70 percent. However, the average percent removal drops to 56
percent in 1995 for the ANSPS plants since a substantial portion of Western
capacity is forecast to partially scrub Western medium sulfur coal (i.e.,
about one percent sulfur coal) to comply with the current NSPS or more
stringent state requirements. See Table 1-8.
ICF
INCORPORATED
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TABLE 1-8
NATIONAL SCRUBBER CAPACITY UNDER THE
CURRENT NEW SOURCE PERFORMANCE STANDARD
Reference Case II
1985
1990
1995
Capacity Scrubbed (in GW)
- Existing
- NSPS-'
- ANSPS-
73.3 103.2 134.4
37.2 40.3 40.9
27.5 28.7 30.1
8.6 34.2 63.4
Average Percent Removal
- Existing
- NSPS
- ANSPS
69.0
66.8
70.8
73.2
67.0
66.6
70.6
64.5
62.6
67.3
70.1
56.0
V New plants scheduled to come on line through 1982 were con-
sidered subject to the current NSPS.
2/ New plants scheduled to come on line after 1982 were con-
sidered subject to alternative new source performance stan-
dards (in this case the ANSPS is the current NSPS).
Utility Fuel Consumption
The forecasts indicate that most of the growth on utility coal con-
sumption would be in low sulfur coal and that utility oil and gas consump-
tion would not change substantially from present levels. See Table 1-9.
ICF
INCORPORATED
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TABLE 1-9
NATIONAL UTILITY FUEL CONSUMPTION
UNDER THE CURRENT NEW SOURCE
PERFORMANCE STANDARD
(in 10 btu's)
Reference Case II
1975 1985 1990 1995
Coal 9.3 17.0 23.7 28.7
High Sulfur 5.1 3.9 4.1 4.2
Medium Sulfur 3.4 8.0 9.1 10.4
Low Sulfur 0.8 5.1 10.5 14.1
Oil and Gas 6.5 7.3 6.4 7.2
Total Fossil 15.8 24.3 30.1 36.0
Nuclear and Other* 4.7 9.6 13.7 21.1
Total 20.5 33.9 43.8 57.1
Percent of Total
Coal 45 50 54 50
Oil and Gas 32 22 15 13
Nuclear and Other 23 28 31 37
A heat rate of 10,000 btu per kwh was assumed.
The growth occurs primarily in low sulfur coal (and to a smaller
extent in medium sulfur coal) because in many regions it is less expen-
sive to burn low sulfur coal (or partially scrub medium sulfur coal)
than to burn high sulfur coal with a full scrubber.
Uoi.ji.onal Utility Coal Consumption
Tin: qrowth in utility coal consumption is forecast to be spread
relatively evenly between the East and the West. See Table 1-10.
ICF
INCORPORATED
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TABLE 1-10
REGIONAL UTILITY COAL CONSUMPTION UNDER THE
CURRENT NEW SOURCE PERFORMANCE STANDARD
(in 10 btu's)
Reference Case II
New England
Mid-Atlantic
South Atlantic
East North Central
East South Central
East and Midwest
West North Central
West South Central
Mountain
Pacific
West
Total
1975
0.038
1.067
1.878
3.123
1.571
7.677
0.836
0.120
0.627
0.068
1.651
9.328
1985
0.242
1.772
3.157
4.253
2.152
11.576
1.884
2.062
1.360
0.108
5.414
16.990
1990
0.502
2.749
4.432
5.524
2.784
15.991
2.392
3.180
1.600
0.561
7.733
23.724
1995
0.448
2.924
4.318
7.361
3.027
18.087
3.294
4.367
1.973
1.036
10.670
28.748
The West is forecast to grow faster in percentage terms because there is
currently very little coal consumption in the West, and utilities in that
region are shifting their generation from oil and gas to coal and nuclear.
The percentage growth in coal consumption in the East is restrained by modest
electricity growth rates and the rapid planned expansion of nuclear capacity
in the East. Nuclear generation is less competitive with coal generation in
most of the West than in the East due to the lower prices of Western coals.
EFFECTS OF ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS (ANSPS) — PHASE I
In general, each of the three ANSPS was forecast to have the same
effects on the coal markets and electric utility capacity additions and
utilization. (See chapter IV for discussion of impacts of revised scrubber
costs on the 0.5 Ib. SO /mmbtu standard results.)
As noted above, the three alternative NSPS for SO were (1) 90 percent
removal, (2) 80 percent removal, and (3) an emission limitation of 0.5 pounds
of sulfur dioxide per million btu's of heat input. The assumed emission
limitation for TSP was 0.03 pounds per million btus and for NO was 0.6
million btus for each of the three alternative SO standards. Each of
these standards was treated as if it applied on an annual average basis. If
the shorter term standards were set so that they would result in lower annual
average emissions, the findings presented below would not represent the
likely effects of these alternative standards. See Appendix A for a discus-
sion of coal variability and short term averaging times.
ICF
INCORPORATED
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The pollution control cost estimates were provided by PEDCo through
EPA. (The estimates used are presented in Appendix C.) Both the level of
these costs and their relative differences for alternative degrees of
partial scrubbing have a substantial affect on the findings of this study.
Alternative cost estimates could result in different findings, just as the
0.5 floor forecasts changed substantially when the partial scrubbing cost
est invites changed.
Below, these effects are presented for 1990 relative to Reference
Caso 1C. Forecasts were made for both reference cases for 1985, 1990,
and 1995. The projections from these runs are presented in tabular form
in Appendix D. The 1990 forecasts are presented below because (a) 198b
shows very small effects for any of the alternative NSPS because the new
standards would apply only to capacity coming on line in 1983, 1984 and
1985 and (b) 1995 is so far in the future that the uncertainties con-
cerning such key parameters as electricity consumption and nuclear capa-
city are enormous.
National Coal Production
The alternative NSPS are forecast to reduce total coal production
slightly. The reduction in tonnage results from (a) an increase in aver
age btu content (resulting from a shift from lower heat content Western
coals to higher heat content Eastern coals), and (b) an increase in
utility oil and gas consumption. The increased oil consumption results from
increasing the costs of new coal-fired powerplants and thereby tilting the
economics towards the increased use of oil and gas in existing oil and gas
steam plants. See Table 1-11.
TABLE 1-11
1990 NATIONAL COAL PRODUCTION UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Reference Case II
1j2 Ibs. 90% 80% 0.5 Ibs. (Initial)*
Produgtion 1768 1711 1712 1712
(10 tons)
Average Btu Content 21.0 21.4 21.3 21.4
(10 btu/ton)
1M ,Unction 37.1 36.6 36.5 36.5
(11) ' bl;u)
* Insults for the 0.5 Ib. standard that are based upon the initial
estimates of partial scrubbing costs are indicated as here. For
a discussion of the differences between the initial and revised
partial scrubbing costs, see Appendix C. For a discussion of the
differences in impacts between the initial and revised costs, see
Chapter IV.
ICF INCORPORATED
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This increase in utility oil and gas consumption (and corresponding
reductions in coal consumption) would have been greater if new combined-
cycle or other oil burning technologies had not been prohibited outside of
southern California. The prohibition contained in the President's Energy
Program on new oil burning capacity for other than peaking purposes was
assumed to be effective, except in southern California for which several
exemptions passed by the House (circa August 1977) were assumed to nullify
the prohibition.
Regional Coal Production
The forecast effect on regional production is substantial in some
regions, indicating a shift from Western coals to Eastern and Midwestern
coals, as new powerplants with scrubbers burn lower-priced high sulfur coal
rather than higher-priced low sulfur coal.
Less coal is forecast to be shipped from the West to the East.
The coal that is shipped is consumed by existing powerplants, new power-
plants meeting NSPS, and the industrial sector, but generally not by those
plants that would have to meet any of the tighter ANSPS.
Production in Central and Southern Appalachia also is forecast to
be lower under the ANSPS, reflecting a reduced demand for low sulfur
coal. See Table 1-12.
TABLE 1-12
1990 REGIONAL COAL PRODUCTION UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Reference Case II
1.2 Ibs. 90% 80% 0.5 Ibs. (Initial)
Northern Appalachia 205 258 257 258
Central & Southern Appalachia 237 218 212 211
Midwest & Central 298 364 370 372
Northern Great Plains 810 651 658 653
Rest of West 218 220 _2J5 _2J8
Total 1768 1711 1710 1712
Western Coal Consumed in East- 455 298 300 297
V As discussed in the footnote on page 11, subsequent analyses indicate
the levels of these forecasts are too high, although the differences
between standards is representative.
Delivered Coal Prices
The prices of coal delivered to utilities do not change much as
a result of the tighter standards. High sulfur prices tend to increase
slightly, as a result of increased demand for high sulfur coal. Low sulfur
prices tend to decrease slightly, as a result of reduced demand for low
sulfur coal. Medium sulfur prices tend to remain unchanged. See Table 1-13.
ICF
INCORPORATED
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TABLE 1-13
1990 DELIVERED COAL PRICES TO ELECTRIC UTILITY SECTOR
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
$/10 btus (1977 $'s)
Reference Case II
• New England
• Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mmmb.i i ti
Pacific
Sulfur Level
Medium—
Low-
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
Low
High
Medium
l«nw
High
Medium
Low
High
Medium
Low
1.2 Ibs .
1.30
1.38
1.98
1.20
1.37
1.60
1. 17
1.41
1.62
I.Ob
1.24
1.37
1.07
1.15
1.38
1.03
0.83
1.04
1.02
0.62
1.30
0.65
0.82
1.28
1.22
90%
1.30
1.36
2.17
1.28
1.35
1.99
1.31
1.39
1.58
1.15
1.26
1.48
1.15
1. 19
1.35
1.10
0.84
0.98
1.29
0.79
1.25
0.65
0.78
1.34
1.13
80%
1.30
1.37
2.16
1.26
1.35
2.01
1.31
1 .40
1.58
1.15
1.25
1 .48
1.15
1.19
1.35
1.10
0.84
0.98
1.29
0.79
1.25
0.63
0.78
1.04
1. 16
0.5 Ibs. (Initial)
1.30
1.38
2.18
1.26
1.36
2.01
1.29
1.40
1.58
1. 14
1.26
1.48
1. 15
1.20
1.35
1.09
0.83
0.96
1.30
0.81
1.25
0.64
0.79
1.03
1. 10
_!/ Greater than 1.67 pounds of sulfur per million btu's (roughly greater than
two percent sulfur by weight).
2/ 0.61 to 1.67 pounds of sulfur per million btu's (new source performance
standards to roughly two percent).
3/ Meats new uource performance standards (0.6 pounds of sulfur or less).
NOTE: Certain anomalies in the behavior of prices are apparent, such
as low sulfur prices in New England rising with the tighter standards.
This is due to the averaging (consumption weighted) associated with
aggregating the 35 demand regions into nine larger regions, where
expensive coal in one demand region (e.g., Maine) is averaged with
less expensive coal in another region (e.g., Massachusetts) and where
the relative volumes of these coals change between scenarios.
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-23-
Generation Capacity
The changes in generation capacity resulting from the alternative NSPS
are not substantial. See Table 1-14.
TABLE 1-14
1.2 Ibs.
176.7
465.0
143.6
15.3
142.5
87.6
1031.4
45.0
90%
176.7
444.6
143.5
15.3
164.8
86.4
1031.3
43.1
80%
176.7
444.3
143.5
15.9
163.9
86.8
1031.1
43.1
0.5 Ibs. (Initial)
176.7
444.5
143.5
15.9
164.4
86.2
1031.2
43.1
1990 NATIONAL GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(net GW)
Reference Case II
1.2 Ibs. 90%
Nuclear-
Coal
Oil/Gas
- Steam
- Combined Cycle
- Turbine
Hydro and Others
Total
Coal as % of Total
^/ Nuclear capacity was set at 176.7 GW in 1990 and not allowed
to vary between ANSPS because 1) the coal/nuclear tradeoff
is considered more complicated than could be represented in
the model and 2) reasonable estimates of how much nuclear
would be coming on line and where could be made through 1990
because of the long lead time for nuclear plants.
Coal capacity goes down somewhat and oil capacity (i.e., turbines) goes up
somewhat as a result of the ANSPS. The more stringent SO2 standards
increase the costs of new coal-fired capacity. Thus, less coal-fired capa-
city is built, existing oil/gas steam is employed at higher annual capacity
factors, and more turbines are built to meet low capacity factor requirements.
Had new oil plants (e.g., combined cycle) for non-peaking purposes been
permitted (other than in southern California), the increases in oil capacity
and reduction in coal capacity would have been greater.
Scrubber Capacity
The increased scrubber capacity is substantial under the ANSPS cases
which requir4 scrubbers on all new plants after 1982. See Table 1-15.
ICF
INCORPORATED
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TABLE 1-15
1990 NATIONAL SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
Capacity Scrubbed (in
- Existing
- NSPS-
- ANSPS-
1.2 Ibs.
Reference Case II
90%
80%
103.2 210.8 210.8
40.3 36.3 36.5
28.7 23.4 23.1
34.2 151.1 151.2
0.5 Ibs. (Initial)
210.8
36.2
23.2
151.0
Average Percent Removal
- Existing
- NSPS
- ANSPS
67.0
66.6
70.6
64.5
83.2
66.6
68.3
89.8
75.2
66.5
68.5
78.3
77.4
66.7
70.5
81.1
V New plants scheduled to come on line through 1982 were con-
sidered subject to the current NSPS.
2/ New plants schedule to come on line after 1982 were considered
subject to the alternative new source performance standard.
The scrubber capacity on existing plants and plants that would meet
the current NSPS is not forecast to change substantially. The large
increase in scrubber capacity occurs on the plants that would have to
comply with the ANSPS.
For the plants that would have to comply with an 80 or 90 percent
standard, the forecast indicates average removal efficiencies of 78 and 90
percent, respectively. Some partial scrubbing occurs in the 80 percent case
because the SIP standards in several western states were considered tighter
than the ANSPS. These emission standards could be met with less than 80
percent removal on low sulfur coal.
Utility Fuel Consumption
Coal consumption in the utility sector is forecast to be 0.4 quads
lower in 1990 under the ANSPS. The decreased system efficiency caused by
scrubbers increases total fuel use by another 0.3 quad. As result of the
ANSPS making coal consumption more expensive for new powerplants, oil and gas
consumption is forecast to increase by 0.7 quads or about 350 thousand
ICF
INCORPORATED
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barrels per day. A shift from lower sulfur to higher sulfur coals is fore-
cast as the increased use of scrubbers results in the utility sector shifting
to the cheapest coals available (i.e., higher sulfur coals). See Table
1-16.
TABLE 1-16
1990 NATIONAL UTILITY FUEL CONSUMPTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD
(in 10 btu's)
Coal
— High sulfur
— Medium sulur
— Low sulfur
Oil and Gas
Total Fossil
Nuclear and Other*
Total
Coal as % of Total
Nuclear & Other as % of Total
Oil & Gas as % of Total
Reference Case II
1.2 Ibs.
23.7
4.1
9.1
10.5
6.4
30.1
13.7
43.8
54
31
15
90%
23.3
7.4
10.9
5.0
7.1
30.4
13.6
44.0
53
31
16
80%
23.3
7.4
10.6
5.3
7.1
30.4
13.6
44.0
53
31
16
0.5 Ibs. (Initial)
23.3
7.0
10.8
5.5
7.1
30.4
13.6
44.0
53
31
16
* A heat rate of 10,000 btu per kwh was assumed.
EFFECTS OF ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS (ANSPS) — PHASE II
Nine alternative new source performance standards were analyzed as part
of Phase II. These were 24-hour standards requiring 85 percent removal of
SO with a ceiling on emissions (i.e., maximum allowable daily emissions
rate), a floor below which emissions were not required to go (i.e., the
percent removal requirements were no longer applicable once the floor was
achieved) and an allowance or absence of an exemption from the ceiling for
three days per month.
The nine cases were defined as follows:
1. 0.2 Ib. SO /mmbtu floor, 1.2 Ibs. SO2/mmbtu ceiling,
with exemption.
2. 0.2 Ib. SO /mmbtu floor, 1.2 Ibs. SO_/mmbtu ceiling,
without exemption.
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3. 0.2 Ib. SO /mmbtu floor, 0.8 Ibs.
with exemption.
4. 0.2 Ib. SO /mmbtu floor, 0.8 Ibs.
without exemption.
5. 0.5 Ib. SO /mmbtu floor, 1.2 Ibs.
with exemption.
6. 0.5 Ib. SO /mmbtu floor, 1.2 Ibs.
without exemption.
7. 0.5 Ib. SO /mmbtu floor, 0.8 Ibs.
witli exemption.
SO /mmbtu ceiling,
SO /mmbtu ceiling,
SO /mmbtu ceiling.
SO /mmbtu ceiling,
SO /mmbtu ceiling,
8. 0.5 Ib. SO /mmbtu floor, 0.8 Ibs.
without exemption.
9. 0.8 Ib. SO /mmbtu floor, 1.2 Ibs.
with exemption.
SO /mmbtu ceiling.
SO /mmbtu ceiling,
Based on more recent work done by PEDCo Environmental, revised estimates
for partial scrubbing costs were used in the 0.5-lb.-floor cases.
Modeling of Standards
All case runs assumed the high electricity growth rate of 5.8 percent
per year to 1985 and 5.5 percent per year thereafter. The alternative NSPS
requirements are assumed to impact on all coal-fired powerplants scheduled to
come on line after 1982. All nine cases assumed EPA's assumption that scrubbers
can be 90 percent efficient on a 30-day average and 85 percent efficient on a
24-hour basis, with a drop to 75 percent allowed three days per month.
The change in the floors in Cases 1-9 was handled by not allowing
partial scrubbing in the 0.2-lb.-floor cases (Cases 1-4) and by allowing
partial scrubbing ir^the 0.5-lb.-floor cases (Cases 5-8) and the 0.8-lb.-
floor case (Case 9).—
1/ Actually, partial scrubbing on very low-sulfur coal could be used to
moot: the 0.2-lh. -floor, but the magnitude of the cost savings would be
very modest si.nc.-o over 95 percent of the flue gas would have to be
scrubbed t<> iiu-ot ri 24-hour average standard. Subsequent PEDCo work
initic:at;es th.it the cost savings associated with partial scrubbing to a
0.2-lb.-floor would be negligible.
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The ceiling/exemption combination was modeled according to EPA specifi-
cations by limiting the coal types available to the coal-fired plants coming
on line after 1982. When no exemption was allowed, it was assumed that the
utilities would purchase coal that would be in compliance with the cap when
the scrubber efficiency has dropped to 75 percent and the sulfur content of
the coal is.at the high end of the range (i.e., three relative standard
deviations- (RSD's) above the long-run mean sulfur content of the coal), in
order to comply with a no-violations requirement. When an exemption of the
cap was allowed, it was assumed that the utilities would purchase coal (two
standard deviations above the long-run mean sulfur content) relative to an
85-percent scrubber efficiency. This assumption is based on the notion that
a drop in scrubber efficiency to 75 percent is somewhat correlated with
higher-than-average sulfur levels in the coal being burned.
Throughout this analysis, the relative standard deviation for sulfur was
assumed to be 0.15. Since the data on sulfur variability are sparse, it is
possible that the appropriate RSD for a 24-hour averaging period is high as
0.20. However, the 0.15 RSD was specified by EPA.
The calculation of allowable coals is based upon the cap, the desired
confidence level, and the efficiency of the scrubber. For example, for
the case with a 1.2-lb. ceiling with exemption, the maximum allowable coal
was 3.08 Ibs. S/mmbtu. This was calculated by first dividing the 1.2-lbs.-
SO /mmbtu standard (i.e., the cap) by 1.3 (one plus two RSD's of 0.15).
The result was then divided by two to convert into pounds of sulfur from
pounds of SO . The pounds of sulfur were divided by 0.15 (one minus the
scrubber efficiency) to obtain the 3.08 Ibs. S/mmbtu (1.2 / 1.3 / 2 / 0.15 =
3.08). Table 1-17 gives the maximum allowable sulfur content estimated for
Cases 1-8.
TABLE 1-17
MAXIMUM ALLOWABLE SULFUR CONTENT UNDER ALTERNATIVE STANDARDS
Maximum Allowable
Case Emissions Cap Number of Scrubber Sulfur Content
Number (lbs.S02/mmbtu) RSD's Efficiency (Ibs. S/mmbtu)
1 & 5 1.2 2 0.85 3.08
2 & 6 1.2 3 0.75 1.66
3 & 7 0.8 2 0.85 2.05
4 fi, 8 0.8 3 0.75 1.10
1/ Relative Standard Division (RSD) is the standard deviation of sulfur
~ contents of samples of coals divided by the mean sulfur content of the
samples. It is a measure of the variability of coal sulfur content.
See Appendix A for further discussion.
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Cases 1 and 5 were modeled by eliminating the H-sulfur level in the
model (i.e., all coals with greater than 2.5 Ibs. S/mmbtu) . This was done
to be conservative, since some reserves in the H-sulfur category would fall
below the 3.08-lb. S/mmbtu cut-off point while others would not.
Cases 2, 3, 6, and 7 were modeled by eliminating G and H coals (i.e.,
all coals with greater than 1.67 Ib. S/mmbtu). While Cases 2 and 6 fall
at the lower end of the G coal category, Cases 3 and 7 fall in the middle
of the range. Since the information was not available to divide readily the
G coal reserves further, a conservative approach was utilized, eliminating
the entire block of reserves. Thus, the impacts for Cases 3 and 7 are
higher than would be expected.
Finally, Cases 4 and 8 were modeled by eliminating F, G, and H sulfur
levels (i.e., all coals with greater than 0.83 Ib. S/mmbtu). The F sulfur
category ranges from 0.83 to 1.67 Ibs. S/mmbtu. Since the sulfur cut-off
valu.- for Cases 4 and 8 fell in the middle of the range, the entire block
of K coal was eliminated. Again, the impacts presented in this analysis
will be biased on the high side.
Case 9 assumes that coals with an average sulfur content of 0.8 Ibs.
SO /mmbtu do not have to be scrubbed. Since 10 to 30 percent of the sulfur
in2Western coals remains with the ash, coals with a long-run average sulfur
content of 0.4 Ibs. S/mmbtu or less could be capable of complying with a
0.8-lb.-SO /mmbtu standard on a 24-hour average basis. However, this
implies a lower confidence level and/or RSD than assumed above. To burn such
coal without a scrubber, the averaging period would probably have to be longer
than 24-hours.
All coals were allowed in the 0 . 8-lb. -floor case, although the highest-
sulfur-category coal (H) should have been eliminated to be consistent
with the modeling of the 1 . 2- Ibs. -SO /mmbtu ceiling in the other cases.
Since very little of this coal is usld by the ANSPS plants, the impact of
tli is inconsistency is small.
OjiaJAta_ti\/e_ Discussion of Effects
This subsection is divided into three parts which discuss the gen-
eral impacts of alternative floors, ceilings, and exemption provisions,
respectively.
Impact of Alternative Floors — The floor determines whether utilities
,-an l,arTTaTry~s"c"rub lower-sulfur coals. This can be done either by treating
tli.- entire flue gas stream at a lower-percent removal or by treating part of
II,,. ,|.,s stream at .. hU,h-Percent removal and blending it with the untreated
port ion of the stream to achieve the required emission limitations.
Table 1-18 shows that the amount of scrubber capacity built in 1990
int-roases by 15 GW with the 0 . 5-1 b. -SO /mmbtu floor. This is because
partial scrubbing makes new coal-fired powerplants less expensive than plants
with full scrubbing; hence, more are forecast to be built. The average
percent removal for scrubbers in ANSPS plants declines from 89.1 percent to
73.2 percent, because more partial scrubbing is forecast to occur.
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TABLE 1-18
1990 SCRUBBER CAPACITY AND AVERAGE PERCENT
REMOVAL UNDER ALTERNATIVE ENVIRONMENTAL STANDARDS
Scrubber Capacity (in GW)
Existing
NSPS
ANSPS
- full
- partial
Average Percent Removal
Existing
NSPS
ANSPS
- full
- partial
0.2-lb. Floor
1.2 Cap With
Exemptions
210.6
36.3
23.4
150.9
146.2
4.8*
81
,9
64.0
64.0
89.1
90.0
61.6
0.5-lb. Floor
1.2 Cap With
Exemptions
225.9
36.5
23.1
166.3
65.81
100.41
71.5
64.1
70.7
73.2
90.0
62.2
* Partial scrubbing was used in several Western states when the SIP
was set at 0.24-lb.-SO /mmbtu, which was considered more stringent
than 90 percent removal.
The major impacts of raising the floor are (1) increased emissions, (2)
increased shipments of Western coal to the East, (3) lower utility oil
consumption, and (4) lower annualized costs. Emissions increase because (a)
the emission rate from ANSPS plants partially^crubbing lower-sulfur coals
was assumed to be greater than full scrubbing-7 and (b) more coal-fired
capacity is built. These increases are partly offset, however, by reduced
loads on existing and NSPS capacity. Loads on this capacity, which has higher
emission rates than ANSPS capacity, are reduced as loads on ANSPS capacity are
increased when partial scrubbing is permitted, because partial scrubbing is
less expensive. See Table 1-19, which is also discussed below in relation to
utility oil consumption.
Western coal shipments to the East increase as the floor is raised,
because it is the Western low-sulfur coals that are partially scrubbed. The
Northern Great Plains Region is the major supplier of this increased Western
production, with the Midwest showing the largest decline in production.
Utility oil consumption declines as the floor is raised. This occurs
because the higher floor lowers the generation costs for new coal-fired
units. These units are used in baseload, bumping existing coal plants and
units subject to the current NSPS into lower load categories. Those coal
plants bump existing oil plants up the load curve, thereby reducing their
annual average capacity factor and hence oil consumption.
V~Subsequent analysis have indicated this is not necessarily true.
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TABLE 1-19
COMPARISON OF FOSSIL FUEL CAPACITY UTILIZATION
IN 1990 UNDER ALTERNATIVE ENVIRONMENTAL SCENARIOS
(in GW)
Base
0.2 Floor/
1.2 Cap/
Plant Type With Exemp.
Coal
Existing
NSPS
ANSPS
Total
Oil/Gas
Steaai
Combined Cycle
Turbine
Total
Total Fossil*
159.4
80.7
101.9
342.0
2.5
11.9
_
14.4
356.4
0.5 Floor/
1.2 Cap/
With Exemp.
143.0
71.9
127.2
347. 1
1.6
8.2
_
9.8
356.9
Intermediate
0.2 Floor/
1.2 Cap/
With Exemp.
44.
7.
49.
101 .
90.
1 .
.
92.
193.
5
4
7
6
6
7
3
9
0.5 Floor/
1.2 Cap/
With Exemp.
54
17
39
110
82
1
-
83
194
• •
. 1
. 1
.0
.2
. 1
.7
.3
.0
Load Category
Seasonal Peak
0.2 Floor/
1.2 Cap/
With Exemp.
0.7
-
-
0.7
32.1
0.6
56.9
89.6
90.3
0.5 Floor/
1.2 Cap/
With Exemp.
2.5
-
-
2.5
39.0
0.9
48.0
87.9
90.4
Daily Peak
Total
0.2 Floor/ 0.5 Floor/ 0.2 Floor/
1.2 Cap/ 1.2 Cap/ 1.2 Cap/
With Exemp. With Exemp. With Exemp.
204
88
151
444
18.2 20.5 143
1.1 1.1 15
108.3 105.4 165
127.6 127.0 323
127.6 127.0 768
.6
. 1
.6
.3
.4
.3
.2
.9
.2
.
0.5 Floor/
1.2 Cap/
With Exemp.
204.6
89.0
166.2
459.8
143.2
11.9
153.4
308.5
768.3
* Capacity does not remain constant within each load category because of minor shifts in the loading of hydro capacity and small changes in plant
efficiencies caused by differences in scrubbing.
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Table 1-19 compares the utilization of fossil fuel capacity between the
0.2 lb.-floor/1.2-cap/with-exemption case, and the 0.5 Ib.-floor/1.2-cap/
with-exemption case. Note that more ANSPS coal capacity is built and less
combined-cycle and turbine capacity is built with the higher floor. The oil/
gas steam capacity (which remains the same between cases) is operated in
lower load categories.
Annualized costs are reduced as the floor is raised, because more
partial scrubbing can be employed, and partial scrubbing is generally less
expensive than full scrubbing.
Impacts of Alternative Ceilings ~ The ceiling is the maximum level of
emissions that a plant can emit and still be considered in compliance. The
percent removal requirement is the binding constraint for low- and most
medium-sulfur coals, since when they are scrubbed these coals yield emission
levels below the ceiling (or cap) considered in this analysis. However, for
the highest sulfur coals the cap is the binding constraint. Anticipated
sulfur dioxide removal efficiencies of scrubbers (e.g., a minimum of 75
percent on a 24-hour basis) are not high enough to remove enough sulfur
dioxide from the flue gas of high sulfur combustion to comply with a 24-hour
average cap, when the variability of the sulfur content of coal is considered.
Hence, the cap together with the anticipated maximum scrubbers removal effi-
ciency effectively exclude certain high-sulfur coals from utility use.
For example, if we take the "no exemption" case where the minimum sulfur
removal efficiency of a scrubber is 75-percent removal on a 24-hour basis,
the appropriate relative standard deviation (i.e., a measure of the variabi-
lity of the sulfur content) for coal is 0.15 for a 24-hour period, and that
three standard deviations will provide the proper confidence interval for
compliance, the maximum average long-term sulfur content for coal under a
1.2-lb.-SO /mmbtu cap would be 1.66 lbs.~ This would mean that no coal
over about 1.8 percent sulfur could be burned.
The major impacts of lowering the ceiling are (1) increased Western
coal shipments to the East, with a significant decline in Midwestern coal
production, (2) higher annualized costs, and (3) sometimes a decrease in
SO emissions. Western coal increases because the highest-sulfur coals,
which are located in the Midwest, are excluded from utility use by the lower
ceiling and replaced largely by the lower-sulfur Western coals. The higher
annualized costs occur because utilities bid up the price of the allowable
coals for all plants using those coals; in essence, the supply of allowable
coal is reduced, so the price is bid up. Thus, the lower the ceiling the
higher will be the price for the medium- to low-sulfur coals for all plants
77 T.~2~lbs. SO /mmbtu cap = X (the maximum annual average sulfur content
per 18 btu) x 2 (pounds SO per pound sulfur) x (1-0.75) (one
minus the removal efficiency of a scrubber) x 1.45 (one plus three
RSD's of 0.15 to translate annual average sulfur content to peak
daily sulfur content).
X = 1.66 Ibs. S/mmbtu.
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purchasiny these coals. Emissions sometimes decrease because the use of
lower-sulfur coals increases; however, the relationships are complex, and
there are situations where the emissions are forecast to increase. For
example, although the emissions rate of ANSPS plants is reduced, the cost of
operating these plants is increased (as a result of higher coal prices),
so these plants are utilized less and existing coal and oil plants and NSPS
plants, all with higher emissions rates, are forecast to be utilized more.
'"P^J^L Alternative Exemption Provisions — The exemption provisions
studied in~thil analysis would allow the ceiling standard to be violated up
to three days per month. This provision has the effect of raising the
long-term average sulfur content of coal that can be used in conjunction with
a specified cap. If we take the example presented above and alter the
required number of standard deviations to two from the three used previously
and change the expected minimum scrubber removal efficiency for a 24-hour-
average from 75 percent to 85 percent, the maximum average long-term sulfur
content that can be used would be 3.08 Ibs. S/mmbtu rather than the 1.66 Ibs.
S/mmbtu estimated earlier.- This would mean no coals over about 3.4
percent sulfur could be burned.
The major impact areas for the exemption provisions are the same
as for the ceiling, since exemption of the cap has the effect of raising
the average sulfur content of coal that could be utilized with any given
ceiling. An exemption of the cap would reduce the amount of Western coal
shipped to the East, lead to more Midwestern production, reduce the annual-
ized utility costs by increasing the amount of coal reserves for which the
ANSPS plants could bid and in some cases increase SC>2 emissions.
CAVEATS AND KEY UNCERTAINTIES
Below are listed the major caveats and uncertainties surrounding this
NSPS analysis for EPA. These issues are raised throughout the text, but are
collected here to highlight them further.
The analysis of the alternative new source performance standards has
evolved over time, responding to the needs of the Federal Government decision
makers. This report deals with the analysis of the initial regulations
considered by EPA. As a result, most of this report is irrelevant to the
proposals currently (circa August 1978) under consideration or what is
likely to be proposed by EPA.
Further analyses have been conducted of the current proposals using new
scrubber cost estimates provided by Pedco and different base case scenario
specif L<;at ions. Those forecasts will be reported under a separate cover.
Mthou.ih the specific forecasts are different, the qualitative nature of the
e'lT.'i-ts shown in this report are generally similar. The quantitative impacts
,,l Hi,- ANSPS are sensitive to scrubber costs, oil prices, electricity growth
r.it <•;;, and real rail rate escalation.
V "l.'i'lbs. SO /mmbtu cap = Xx2x(1.0-.85)x1.3.
X = 3.08 Ibs. S/mmbtu.
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The scrubber costs estimates have proved to be critical throughout this
study and have undergrone revision several times. The impacts of one such
revision are presented in Chapter IV. The costs have been changed since
Phase II was completed. As of the date of this writing (August 1978), there
is still concern about the scrubber cost estimates, and they may undergo yet
another refinement.
The sensitivity of the model to the data inputs is highlighted by the
data input error which overstated scrubber costs in Arizona and New Mexico in
the 1.2 Ibs., 0.8 Ib. and 80 percent cases. The result was that less coal-
fired capacity was built than would have been if the scrubber costs had been
correct. Coal consumption is understated and oil consumption overstated by
about 0.2 quad or 10 million tons of coal or 100,000 barrels of oil per day
in the high growth cases in 1990.
The treatment of short-term averaging times is what separates the early
work from the most recent work. The Phase I scenarios were based upon long-
term averages. Short-term averages were not considered except to the extent
that PEDCo stated that the scrubbers they costed could handle the short-term
variability of sulfur in coal. The Phase II work was based upon PEDCo1s
claims that the 0.5 Ib. floor could be maintained by a scrubber with the
removal efficiency being adjusted to handle whatever SO concentration
was contained in the coal being burned. Thus, the 0.5 Ib. 24-hour floor was
also assumed to be the annual average emission rate. Subsequent analyses have
determined that 0.32 pounds of sulfur dioxide per million btu is a better
estimate.
Additional issues are presented in brief below:
• Combined cycle capacity was not permitted to be
built except in southern California. Had this
technology been permitted the alternative standards
would have increased utility oil consumption more.
• The impact of scrubbers on powerplant reliability
was not considered. The effect of this omission is
to underestimate the impacts of the alternative
standards.
• EPA directed that an RSD value of 0.15 for sulfur
in coal be used when considering 24-hour averaging
periods. The data on coal variability is sparse and
the proper RSD could be higher. This possible
understatment of the sulfur variability is partially
offset by no credit being given for sulfur removal
through washing and no credit for sulfur leaving the
boiler with the bottom ash.
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The forecasts did not allow for blending of the
highest sulfur coals to enable them to comply with
the emissions ceiling.
The Levels of Western coal production forecast in
the NSPS runs are exaggerated, but the differences
between cases are reasonably representative of
expected impacts. Western production is high
because a) the costs of converting existing bitu-
minous coal boilers to subbituminous coal were
underestimated, b) the ranks of coal for planned new
units were not specified, c) subbituminous coal was
allowed to be shipped long distances to meet indus-
trial demand, and d) rail rates were assumed to
increase at only the general rate of inflation. As
noted above, real rail rate escalation could reduce
the economic attractiveness of partial scrubbing.
The coal supply curves do not reflect the 1978
UMW/BCOA wage agreement or any real wage escalation.
The recent Black Lung tax also is not included in
the production costs.
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CHAPTER II
APPROACH
This chapter is divided into two sections. The first section presents
a description of the model used in this analysis. The discussion is
aimed at helping the reader to assess the strengths and weaknesses of this
forecasting tool. The second section consists of an outline of the basic
assumptions used in the analysis. The discussion attempts to focus the
reader's attention on the scenario specifications underlying the analysis.
MODEL DESCRIPTION
The basic model structure is conceptually straightforward in that
a supply component via a transportation network provides coal to satisfy
the demand from both utility and non-utility consumers at least cost. In
so doing, coal production, consumption and price by region, by consuming
sector and by coal type are established and reported. Figure II-1 outlines
the basic structure of each of the four major components of the ICF Coal
and Electric Utilities Model (CEUM) and Figure II-2 shows how these compon-
ents interrelate.
The supply component offers a variety of coal types (i.e., 40 different
possible combinations of five btu and eight sulfur categories) from 30
supply regions. (See Table II-1 for definitions of the 30 supply regions.)
The price of a specific coal type from a particular region varies directly
with the amount produced. Price-sensitive supply curves have been developed
for each coal type in each region as a function of coal reserves data and
mine-engineering costing algorithms. The cost of producing all bituminous
coal includes a charge for a moderate level of coal preparation. The model
also has the option of deep cleaning (i.e., extensive preparation) at
increased costs for two coal types: 1) one to meet the current new source
performance standard, and 2) a second for meeting a typical one percent
sulfur emission limitation for existing sources.
The transportation component of the model transfers the coal from
the supply regions to coal piles in the 35 demand regions at a price per
ton. (See Table II-2 for the demand region definitions.) These coal piles
are a modeling construct for limiting the overall model to a manageable
size. Instead of tracking all the different coal types from the supply
regions to the final consumer, the coal is transported to piles identified
by rank and sulfur level in each demand region. Each coal pile holds a
single rank of coal (e.g., either bituminous — the three highest btu
categories; sub-bituminous — the second lowest btu category; or lignite
— the lowest btu category) and a single sulfur level.
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Figure IJ-1
KWOk COMPONENTS OT ICr OOA1 ANT5 ELECTRIC UTILITIES MODE!
S'>PLY
• 30 Fsegior:
• 40 Coa: types
— 5 Btu categories
-- 6 sulfur levels
• Existing capacity
• New capacity
-- based upon BOK demonstrated
reser-ve base
-• Reserves allocateJ to model
mint types
-- .".ir.imur. acceptable selling
prices estimated for each
ir.ode] mine type
• Coal washing
-- Basic washing assumed for
all bituninous coals
-- Deep cleaning optior. avail-
able to lower sulfur content
to meet New Source Perfor-
mance Standard or a one per-
cent sulfur emission limita-
tion for existing sources
UTILITY
• 35 Regions
• 19 coal piles
-- 3 Ranks of coal
— 6 Sulfur categories
— Metallurgical pile Includes
only the highest grades of
coal
• Utility Sector
— Point estimates for KHK
sales by region
-- KWh sales allocated to four
load categories (base,
intermediate, seasonal peak,
and daiiy peak)
-- Existing generating capacity
utilized by model on basis
of variable cost
-- New generating capacity
utilized by model or. basis
of full costs (including
capital costs)
-- Air pollution standards
addressee explicitly
— Transmission links between
regions
— Oil and gas prices fixed
— Coal prices determined from
supply sector through trans-
portation network
HO-OTILITY DEXAND
• rive non-utility sectors (metal-
lurgical, exports, industrial,
residential/coKDercial, synthe-
tics)
• Point estimates of Btu's demanded
• Allowable coals specified in
terns of btu and sulfur content
• No price sensitivity
TRANSPORTATION
• Direct links
• Cost based upon unit train or
birae shipaent rates
• Lower bounds used to represent
long-term ccr.tract -
• Upper bounds could be used to
represent transportation bottle-
necks or limited capacity
OJ
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FIGURE I1-2
MODEL STRUCTURE
;•. Sector
a-.: -,<;rtat :~>-
,a. Tvr«es
titiiitv i
Derar.i ??-;z- X
r.= Sector
Purc-^oscc pcwe
anotr.er regior.
Coal-fired capacity
Existing bituminous plar.t
w/o scrubber .(!» SIP standard
Existing bituminous plant
w/ scrubber (U SIF standard)
New sub-bituninous plant
w/o scrubber (NSPS standard!
New sub-bituminous plant
w/ scrubber (NSPS standard)
Non-coal capacity
New nuclear capacity
Existing oil/gas steaa
capacity
New oil/gas turbir.e
capacity
Existing pumped storage
plant capacity
Non-Utility Demand Sectors
^Coking Demand (point estimate
input)
Industrial Demand (point esti-
mate input)
Rcq-Jircd 'caseload-
generatior.
KV- Sales
Forecast
(point esti-
nate ir.put)
Required intermediate'
load generation
Required seasonal
peak generation
U)
•sj
I
Required daily peak1
generation
Met
O
Lignite coal
piles are not
shown.
Residential and Commercial
Synthetics and Export
sectors available for use
but not illustrated here '
Unit cf
Tons/Cuads
Tons/Quads
Quads
Quads
109 KWHs
109 KWHs
•o
O
m
O
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PIES Region
Northern Appalachia
Central Appalachia
Southern Appalachia
Midwest
Central West
Gulf
Eastern Northern
Great Plains
Western Northern
Great Plains
Rockies
Southwest
Northwest
Alaska
TABLE II-1
SUPPLY REGION DEFINITIONS
NCM Region
Pennsylvania (PA)
Ohio (OH)
Maryland (MD)
West Virginia, north (NV)-
West Virginia, south (SV)
Virginia (VA)
Kentucky, east (EK)
Tennessee (TN)
Alabama (AL)
Illinois (IL)
Indiana (IN)
Kentucky, west (WK)
Iowa (IA)
Missouri (MO)
Kansas (KM)
Arkansas (AR)
Oklahoma (OK)
Texas (TX)
North Dakota (ND)
South Dakota (SD)
2/
Montana, east (EM)-'
Montana, west (WM)
Wyoming (WY)
Colorado, north (CN)
Colorado, south (CS)
Utah (UT)
Arizona (AZ)
New Mexico (NM)
Washington (WA)
Alaska (AK)
BOM Districts
1, 2
4
1
3, 6
7, 8
7, 8
8
8, 13
13
10
11
9
12
15
15
14
14, 15
15
21
21
22
22
19
16
17
20
18
17, 18
23
23
V Includes all of Nicholas County.
^/ Includes the following counties: Carter, Daniels, Fallon, McCone,
Prairie, Richland, Roosevelt, Sheridan, Valley, and Widaux.
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TABLE II-2
REGIONAL DEFINITIONS FOR DEMAND REGIONS
Census Region
New England
Middle Atlantic
NCM Region
MV
MC
NU
PJ
State
Counties
Maine
Vermont
New Hampshire
Massachusetts
Connecticut
Rhode Island
New York, upstate
New York, dovmstate
New Jersey
Pennsylvania, east
WP
Pennsylvania, west
All
All
All
All
All
All
All counties not in New York,
downstate
Suffolk, Orange, Putnam, Bronx,
Rockland, Richmond, Nassau,
Weschester, New York, Queens,
Kings
All
Wayne, Pike, Monroe, Northharopton
Bucks, Montgomery, Philadelphia,
Delaware, Chester, York,
Lancaster, Dauphin, Lebanon,
Berks, Schuylkill, Lehigh,
Carbon, Suoquehanna, Wyoming,
Lackawanna, Luzerne, Columbia,
Montour, Northumberland, Union,
Snyder, Juniata, Perry, Cumber-
land, Adams, Franklin
All counties not in Pennsylvania,
east
South Atlantic
East North Central
VM
WV
CA
GF
SF
ON
CM
OS
MI
IL
IN
WI
Virginia
Maryland
Delaware
District of Columbia
West Virginia
North Carolina
South Carolina
Georgia
Florida, north
Florida, south
Ohio, north
Ohio, central
Ohio, south
Michigan
Illinois
Indiana
Wisconsin
All
All
All
All
All
All
All
All counties not in Florida,
south
Nassau, Duval, Baker, Union,
Bradford, Clay, St. Johns,
Putnam, Flagler, Volusia,
Indian River, Okeechobee,
Martin, St. Lucie, Manatee,
Sarasota, DeSota, Charlotte,
Glades, Palm Beach, Lee, Hendry,
Collier, Broward, Monroe, Dads
Lucas, Ottawa, sandusky, Erie,
Lorain, Cuyahoga, Lake,
Aah tabula
All counties not in Ohio, north or
Ohio, south
Hamilton, Clermont, Brown, Highland,
Adams, Pike, Scioto, Lawrence,
Gallia, Jackson, Meigs, Athens,
Washington, Morgan, Noble, Monroe,
Belmont, Harrison, Jefferson,
Columbians
All
All
All
All
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TftDLR 11-2 (Conf d)
REGIONAL DEFINITIONS FOR DEMAND REGIONS
Census Region NCM Region State
East South Central EK Kentucky, east
Counties
WK
ET
West North Central
West South Central
Mountain
Pacific
Kentucky, west
Tennessee, east
WT
AM
DM
KN
IA
MO
AO
TX
MW
CO
UN
AN
Tennessee, west
Alabama
Mississippi
North Dakota
South Dakota
Minnesota
Kansas
Nebraska
Iowa
Missouri
Arkansas
Oklahoma
Louisiana
Texas
Montana
Wyoming
Idaho
Colorado
Utah
Nevada
Arizona
New Mexico
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
All
WO Washington
Oregon
CN California, north
CS California, south
Mason, Lewis, Fleming, Bath, Montgo-
mery, Menifee, Clark, Powell, Madison,
Estill, Jackson, Rockcastle, Pulaski,
Laurel, Clinton, Wayne, McCreary,
Greenup, Rowan, Carter, Boyd, Elliott,
Lawrence, Morgan, Johnson, Martin,
Wolfe, Magoffin, Floyd, Pike, Lee,
Breathitt, Knott, Owsley, Perry,
Letcher, Clay, Leslie, Knox, Bell,
Harlan, Whitley
All counties not in Kentucky, east
Pickett, Fentress, Scott Morgan,
Cumberland, Bledsoe, Sequatchie,
Marion, Hamilton, Rhea, Meigs, Roan,
Campbell, Claiborne, Union, Anderson,
Knox Loudon, Blount McMinn, Monroe,
Bradley, Polk, Hancock, Hawkins,
Grainger, Hamblen, Jefferson, Sevier,
Cocke, Greene, Sullivan, Washington,
Unicoi, Carter, Johbson
All counties not in Tennessee, east
All
All
All counties not in California,
south
San Diego, Imperial, Orange, Santa
Barbara, Ventura, Los Angeles,
San Bernadino, Kern, Inyo, Mono
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In addition, a special pile was designed to satisfy metallurgical demand
which includes only the highest btu content coals with the three lowest
sulfur levels. For a given sulfur level and rank of coal, each pile accumu-
lates coal as btu's rather than tons. Within each demand region, the
consumption demands for coal by sector (utility, industrial, residential/com-
mercial, metallurgical, export, synthetic fuels) are satisfied by drawing
btu's (not tons) from each of the appropriate coal piles.
The non-utility coal component (i.e., demand for metallurgical,
export, industrial, residential/commercial and synthetic fuels sectors) has
regional demands for coal specified as point estimates for a specific
rank and sulfur level. The model seeks to satisfy these at minimum cost.
This is done by drawing the required coal from the appropriate coal piles
or as a specified blend from several coal piles (as the dash-dot line in
Figure II-2 indicates).
The utility demand component begins with a point estimate for elec-
trical energy sales (kwh) by demand region as an input into the model.
This estimate for each region is then split among four load categories:
base, intermediate, seasonal peak, and daily peak. The model then deter-
mines the least cost method for generating electricity for each of these
load categories. On the basis of minimizing the cost of generating elec-
tricity the model determines the extent to which 1) existing powerplants
of various types are operated in each load category, 2) new plants of
various types are built and operated in each load category, and 3) elec-
trical power is transmitted between regions. Powerplant types include
coal, oil, gas, nuclear and hydro. The model explicitly accounts for
the impacts of differing levels of environmental standards. To meet
sulfur emission limitations, the model can (a) burn a single coal type that
meets standards, (b) burn an appropriate blend of low, medium and high
sulfur coal that meets standards, or (c) install a scrubber.
The model generates an equilibrium solution through a linear programm-
ing formulation balancing the supply and demand requirements for each coal
type for each region. The objective function of the linear program is
written to minimize the total delivered costs of energy to the demand
sectors in all regions (i.e., the costs of electricity delivered by
utilities and the costs of coal consumed by the non-utility sectors).
The model solves for a complete supply/demand system. This means that
the decisions to use one type of coal in one region impact on the availabi-
lity and price of that coal to another region. The supply of coal responds
to the needs of the consuming sectors while the demands of the consuming
sectors respond to the costs of various coal types.
Coal Supply Component
The coal supply sector consists of price sensitive coal supply curves
for each coal type that exists within each region. All bituminous coals
are washed, and the option of deep cleaning certain bituminous coals is
provided. Hence, prices are determined by the required level of production
and by whether deep cleaning was employed.
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The following paragraphs discuss the coal types considered in the
model, the coal supply curves and how they are developed, and the model's
treatment of coal preparation.
Coal Types — The choice of coal types relates directly to one of
the coal industry's major characteristics: it produces a non-homogeneous
product- Coal can be differentiated among a number of quality characteris-
tics such as heat content, sulfur and ash content and volatility. These
are only a few of the coal quality characteristics that are important to
boiler designers or operators of coking plants. However, only a limited
number of parameters can be tracked before the number of coal types explodes
out of the manageable realm.
A major limitation in coal analysis is the inability to capture the full
range of coal characteristics. Since utility steam coal is the major market
now and the major growth market, the CEUM was designed to focus primarily on
the coal characteristics important to the utility sector. Therefore, five
btu and eight sulfur categories were selected to define the possible range of
"non-homogeneous coal products." Although the other coal characteristics are
ignored by the model, their level of impact was considered low enough so as
not to weaken the model's results.
The coal supply component of the model consists of 192 price sensitive
supply curves representing the supply of different coal types in 30 coal
supply regions. (See Table II-3 for a summary of the number of coal type
supply curves in each region.)
The Supply Curves — A multi-stepped supply curve is used to simulate
the potential production levels available at various prices. Figure II-3
illustrates such a curve for a particular coal type within a single region.
Each step of the curve represents a different type of mine. The height of
the step illustrates the minimum acceptable selling price for that type of
mine.
These supply curves are composed of two kinds of production: from
existing mines and from new mines. The relevant costs associated with
these two types of production are different and, therefore, the minimum
acceptable selling price used to develop the supply curve reflects these
differences. Since the capital for existing mines has been sunk, the minimum
acceptable selling price must cover only variable costs. (A rational pro-
ducer would choose to continue to operate until his variable operating
expenses exceed his expected revenues.) For new mines, mines for which
capital has not yet been invested, the minimum acceptable selling price
provides for the recovery of and return on invested capital in addition to
covering operating costs. Hence, existing production is priced at variable
costs, and new production is priced at full costs (including a return of and
on capital). Consequently, the first step on the supply curve represents the
coal production from existing mines. The subsequent steps represent the
production from the new mines.
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TABLE II-3
NUMBER OF SUPPLY CURVES FOR EACH MODEL
SUPPLY REGION
Number of Coal Type
Supply Region Supply Curves
I. Northern Appalachia
1. Pennsylvania (PA) 11
2. Ohio (OH) 7
3. Maryland (MD) 5
4. West Virginia, north (NV) 11
II. Central Appalachia
5. West Virginia, south (SV) 8
6. Virginia (VA) 10
7. Kentucky, east (EK) 12
8. Tennessee (TN) 9
III. South Appalachia
9. Alabama (AL) ^
IV. Midwest
10. Illinois (IL) 8
11. Indiana (IN) 8
12. Kentucky, west (WK) 5
V. Central West
13. Iowa (IA) 3
14. Missouri (MO) 4
15. Kansas (KS) <
16. Arkansas (AR) 4
17. Oklahoma (OK) I1
VI. Gulf
18. Texas (TX) 1
VII. Eastern Northern Great Plains
19. North Dakota (ND) 5
20. South Dakota (SD) 3
21. Montana, east (EM) 2
VIII. Western Northern Great Plains
22. Montana, west (WM) 6
23. Wyoming (WY) 11
24. Colorado, north (CN) 2
IX. Rockies
25. Colorado, south (CS) 12
26. Utah (UT) 5
X. Southwest
27. Arizona (AZ) 2
28. New Mexico (NM) 8
XI. Northwest
29. Washington (WA) 7
XII. Alaska
30. Alaska (AK) 1
TOTAL 30 Regions I92
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Tho existing mines portion of the supply curves is generated manually.
Variable costs are estimated for existing production for each region.
Pnxlin:t ion levels for existing production are estimated from existing
product.Lon data minus expected mine closings. The new mines portion of the
supply curves is generated by a reserve allocation and mine costing model
(RAMC). This model assigns the demonstrated coal reserve base from the
Bureau of Mines to various mine types, translates the stock of reserves
into an annual production level (using mine life and recovery factor para-
meters), estimates a minimum acceptable selling price for each mine type
(where price is estimated as a function of reserve characteristics using
engineering mine-costing algorithms), and generates a supply curve by
ordering the annual production levels for each mine type from the least to
the most expensive on a per annual ton basis. (See Appendix G for the coal
supply curves used in this analysis.)
Coal Preparation -- Coal preparation (or washing) is an important
consideration in the overall production of coal. It is a means by which
producers 1) remove waste materials collected with coal during mining, and
2) modify the characteristic of their raw coal (i.e., to lower the ash
and sulfur content of the raw coal). A detailed modelling of coal washing
would be similar to the modelling of a refinery. The level of cleaning
should be a function of the prices of the cleaned coal, the raw coal and
whatever middling output is created as a by-product of cleaning.
CEUM does not now have an extensive washing sector. A more rudimentary
approach has been employed. First, it was assumed that all bituminous coals
would receive a standard level of preparation. This results in the sulfur
level of this coal being adjusted downward as a direct result of the washing
process, where the percent decline in sulfur resulting from washing falls as
the sulfur level of the raw coal declines. Second, two special sulfur level
categories were included in the supply side to allow for more expensive and
costly coal preparation to meet the current new source performance standard
or a one percent sulfur emission limitation for existing sources.
Utility Demand Component .
This portion of the CEUM provides a detailed modelling of the electric
utility sector for each of the 35 demand regions. Since the utility sector
clearly dominates the demand for coal, an accurate representation of the
generation decisions made by utilities was considered necessary in establish-
ing reasonably accurate projections of coal production and consumption.
For each demand region, the model begins with an existing stock of
generating capacities by plant type, the ability to build new capacity at a
cost, and the requirement to satisfy a specified kilowatt-hour consumption
estimate. This overall energy consumption estimate is divided into four
generation load categories -- 1) baseload, 2) intermediate load, 3) seasonal
peak load and 4) daily peak load. These four categories reflect the varia-
tions in electricity demand typically experienced by the utilities in
eacli of the demand regions (i.e., the model approximates the annual load
duration curve for each region).
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The model then chooses the cheapest way of meeting the required gener-
ation levels for each load category for each demand region. The model
has a large array of plants and operating modes to choose from in selecting
the cheapest generation mix — it can use existing plants; it can build
new plants; it can choose from various types of fuel: coal, nuclear, oil,
gas, hydroelectric; it can choose to run plants in different load categories.
Further, the model allows power purchases among demand regions through
transmission line interconnections.
Recognizing the importance of air quality regulations at both the
state and federal level, the model accounts for the impact of state and
federal standards on coal selection and coal powerplant construction and
operation. The model can choose to burn low sulfur coal, blend various
coals, or construct plants with scrubbers as necessary to meet specific
standards.
Each of the provisions described above are discussed in greater detail
in the following paragraphs on load curves, plant types, environmental
compliance alternatives, and transmission considerations.
Load Curves — In analyzing electric utility needs, two numbers are
of importance — electric power demand (the instantaneous requirement
for electricity) which is specified in terms of kilowatts (kw) and electric
energy demand (the requirement for electricity for a period of time) which is
specified in terms of kilowatt-hours (kwh). In meeting the demand for power,
an electric utility will build powerplants to provide a certain capacity for
producing electric power, measured in kw's. In satisfying energy demand, the
electric utility will operate these powerplants for a certain amount of time
at certain levels of output measured in kwh's. The generation requirement
will always exceed the consumption requirement or sales due to energy losses
incurred in the transmission and distribution system.
Since electricity cannot be stored efficiently for future use, the
generation of power must be coincidental with its use. Further, since
the levels of electricity demanded vary widely over the course of a day, a
week, or a year, a utility is faced with the problem of determining the
amount of time that various types of capacity should be operated in order
to minimize total generation costs. This typically means that a utility
will build a variety of generating plants tailored to the specific load
categories.
Four load categories were used — base load, intermediate load, seasonal
peak, and daily peak. These categories are described below:
1. Base Load — All utility systems have a steady level of demand which
is sustained throughout most of the year. This type of demand is commonly
called base load. Although the individual consumers of the energy may vary
from hour to hour or season to season, the utility system can confidently
expect this demand level. Capacity used to meet this base load requirement
typically operates about 65 to 70 percent of the year.
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2. intermediate Load — During the course of a day or a week, the
power demands rise and fall at regular intervals. Typically, night is
the low period for daily electricity demand while late morning and early
evening are high periods. Weekends and holidays are also periods of low
demand. These daily to weekly cycles in demand last from a few hours to a
few days at a time. Utilities must have plants ready to generate power as
the demand level rises. This type of load following generation is called
intermediate load generation. Typically, plants operated to meet inter-
mediate load are generating power for 30 to 50 percent of the year.
3. Seasonal Peak — Seasonal variations in demand are common in
most regions of the country. For the Northeast, summer brings a heavy
demand for power for air-conditioning. For some areas, winter brings a
heavy demand for power for electric heating. This increase in load is not
just for a few hours a day or for a few days in a week; it is a general rise
in power demand for several months of the year. This portion of the load
curve is called seasonal peak. This type of generation typically operates
about 25 percent of the year.
4. Daily Peak — This last load category consists of the short-term
peaks in the generation requirements each day (e.g., late morning, early
evening) as well as unusual spurts in demand (e.g., the air-conditioning
load associated with a summer heat wave). Capacity used to generate
these requirements typically operates less than 8 percent of the year.
Plant Types — CEUM provides a number of different powerplants from
which it can choose to match generation to the variations in load demand at
least cost. For existing coal plants the model can choose oil/gas- steam
plants, oil/gas turbines, combined cycle plants, nuclear plants, hydroelec-
tric/ geothermal, and existing coal plants. For the existing coal plants the
model can select either very old or relatively new coal steam plants (where
the heat rates of the old plants are higher than the relatively new plants).
For building new plants the model can build 12 different types of coal plants
(three ranks of coal without or with scrubber subject to either the current
NSPS or an. ANSPS), nuclear plants, oil/gas combined-cycle (where not assumed
to be prohibited by regulation), and oil/gas turbines. Further, the model can
retrofit a scrubber to an existing coal plant.
Each powerplant type is specified in terms of capacity (existing
capacity and/or new build limits, measured in megawatts) and of capital
costs, heat rates, and operations and maintenance costs. The cost para-
meters are specified for each load category.
Compliance Alternatives — The model allows for the explicit treat-
ment oF up to five different emission limitations for each demand region
(e.g., two limitations for new plants, three others for the existing capa-
city). These limitations are inputted by specifying the coal types that
T/~ No disTinction was made between oil and new gas because it was assumed
they would be priced at btu-equivalency.
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existing or new powerplants may use in generating electricity. To comply
with these limitations the model can choose 1) to burn coal that complies, 2)
to burn a blend of low/medium/high sulfur coals that complies, or 3) to
install a scrubber on either a new plant or an existing plant and burn coal
that would not otherwise comply. If an existing plant was designed to burn
bituminous coal, the model provides for conversion to subbituminous coal at a
cost (for both capital and operating) and penalties in terms of derating
capacity and a higher heat rate.
Power Transmission -- In an effort to improve reliability and to
reduce total generation costs for utilities within relatively large regions,
electrical power exchange agreements among utilities have become common.
Under these arrangements, peaking power and energy can be shifted from one
demand region to another via transmission lines. CEUM assumes that these
exchanges net out to zero over the year, which is the outcome the utilities
try to achieve for these agreements. Hence, these exchange agreements are not
modelled.
However, the model provides for net transmission of baseload generation
from one demand region to another. This is also not an uncommon practice
(e.g., from the Pacific northwest to California or from western Pennsylvania
to eastern Pennsylvania and New Jersey). The ability to build transmission
links provides the model the capability to transport electricity rather
than coal where electricity transmission is cheaper. The model can employ
existing transmission links or build new ones.
Non-Utility Demand Component
The non-utility demand component of CEUM is composed of five sectors:
1) coking or metallurgical demand, 2) industrial demand, 3) residential and
commercial demand, 4) synthetics, and 5) exports. The demand levels are
point estimates and can be satisfied only from a range of allowable coals
specified in terms of sulfur content (based on air pollution standards) and
rank (based on boiler design).
Transportation Component
The transportation component links the 30 supply regions with the
relevant demand regions. The cost of transportation is a per ton charge
based upon unit train or barge shipment rates. Lower bounds are used to
represent the effect of long-term contract commitments.
SCENARIO SPECIFICATIONS
This section presents the scenario specifications that remained constant
across model runs. These assumptions are broken into five categories:
1) electrcity demand, 2) generating capacity, 3) capital costs, 4) finan-
cial parameters, 5) oil and gas prices, and 6) non-utility coal demands.
Each of these categories is discussed below. The model inputs are presented
in Appendix C.
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Electricity Demand
The demand for electricity has two components within CEUM. The first
component is electricity sales. The second is the shape of the annual load
duration curve. Each component will be discussed below.
Electricity Sales — Two projections for kwh sales were developed
and were the only difference between reference cases. Reference Case I
was based upon the national kwh sales projections from the President's
National Energy Plan base case runs of PIES for 1985 and 1990 (circa April,
1977). The 1995 projection is based upon the national growth rate from 1985
to 1990 being continued through 1995. Reference Case II was based upon the
regional reliability councils' April 1, 1977 responses to FPC Order 383-4.
Since these projections only go through 1986, the growth rate at the end of
the forecast period was extended through 1995. Table II-4 gives the pro-
jected kwh sales estimates under the two reference cases. Regional sales
projections for both reference cases were based upon the reliability council
projections.
TABLE II-4
PROJECTED NATIONAL ELECTRICITY SALES
Reference Case I Reference Case II
ft 9
10 Kwh Growth Rate 10 Kwh Growth Rate
1975 1726 - 1726
1985 3036 5.8 3036 5.8
1990 3582 3.4 3968 5.5
1995 4226 3.4 5186 5.5
Load Duration Curve — The 1975 load factors and annual load duration
curves for representative utilities were used as estimates of the 1985,
1990 and 1995 load duration curves. Thus, the dispatching of utility plants
is made to actual annual load duration curves. Implicit in this is the
assumption that load factors will neither increase nor decline over time.
See Appendix C for actual model input parameters.
Generating Capacity
Three assumptions were critical to this analysis. They were: 1)
nuclear capacity builds, 2) effective date for the ANSPS to take effect and
3) restrictions on building new combined cycle plants.
Nuclear Capacity — The decision to build coal or nuclear capacity is
a complex one. Since the economics of the two facilities are close and the
uncertainties involved great, we decided to set nuclear capacity exogenously.
This also meant that the low electricity growth rate has lower utility coal
consumption than would be the case if nuclear builds were reduced in responses
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to the lower growth rate. Similarly coal consumption is higher in the high
growth case than would be the case if nuclear builds increased with the growth
rate. Thus, the impact of letting nuclear capacity respond to the electricity
growth rate would have been to narrow the range of utility coal consumption
estimates. Since this is a parametric analysis looking at the potential range
of coal use, it is reasonable to lock in nuclear capacity and let coal meet
tho remaining capacity requirements.
For 1985 and 1990, limits are region specific and based upon the "best
guoss" estimate in the "Domestic Nuclear Capacity Forecast" prepared jointly
by KEA, NRC and ERDA. These estimates represented what capacity can realis-
tically be expected to be operating by 1985 and 1990. The 1995 estimate was
developed to reflect a rigorous nuclear licensing program that would go into
effect by 1980 and increase the rate of new nuclear plants coming on line in
the post-1990 period. See Table II-5 for the national nuclear capacities
used.
TABLE II-5
NATIONAL NUCLEAR CAPACITY
(in GW)
1975* 38.3
1985 112.0
1990 176.7
1995 302.0
* Actual
ANSPS Plants — All coal-fired plants currently scheduled to come on
line after 1982 were considered subject to the alternative new source perfor-
mance standards under consideration. This approach of specifying plants
subject to the current NSPS probably understates the amount of such capacity.
Some plants coming on-line after 1982 already have permits specifying that
they meet only the 1.2 Ib. SO /mmbtu standard.
Restriction on Combined Cycle Plants — Although Congress had not
completed consideration of the President's National Energy Plan when these
scenario specifications were developed in August, 1977, parts of the expected
package were included in this analysis. One such provision was the ban on
combined cycle plants for other than peaking purposes, except where environ-
mental restrictions prevented the use of coal. New combined cycle plants
were allowed to be built only in Southern California where environmental
considerations could preclude the construction of coal-fired powerplants.
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The capital costs used for new generating units are presented in Table
II-6. These estimates include AFDC and are in beginning-of-1975 dollars.
The coal plant cost estimates include cooling towers and TSP controls
meeting the proposed standard of 0.03 pounds per million btu. (See Appendix
C for a more complete discussion.)
TABLE II-6
UTILITY CAPITAL COSTS
(in dollars per kw — in 1975 dollars)
Nuclear 75°
Bituminous coal plant
w/o scrubber 433
Sub-bituminous coal plant
w/o scrubber 504
Lignite plant w/o scrubber 515
Combined-cycle plant 267
Oil/gas turbine 150
The initial estimates of scrubber costs developed by PEDCo are presented in
Table TI-7. These capital costs do not include replacement capacity. For
retrofitted scrubbers the effective capacity of the plant is reduced within
the model. For new plants the cost of the plant is increased to reflect the
capacity penalty for the scrubber (see Appendix C). The capital costs are
for scrubbers handling 100 percent of the flue gas and removing the design
efficiency. The capacity of the scrubber is such that it can handle some
variation in sulfur content. Each of the four modules was reported to have 90
percent reliability with a fifth module included in the design to increase
the-overall reliability to above 90 percent.
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TABLE II-7
SCRUBBER COSTS FOR HIGH SULFUR COAL
FOR LIME SYSTEM FOR A 500 MW UNIT
Removal Efficiency
80% 90%
Capital Cost (excluding replacement 86* 96
capacity)
(SAw in 1975 dollars)
Operating Costs 2.1 2.2
(mills/kwh in 1975 dollars)
Capacity Penalty (percent) 3.3 3.3
Heat Rate Penalty (percent) 5.3 5.3
* An additional $20 per kw was added for retrofit units.
Financial Variables
The general inflation rate was assumed to be 5.5 percent per year.
Coal mine capital costs were assumed to inflate at 6.0 percent per year.
Utility capital costs were assumed to inflate at 7.5 percent per year
through 1985 and at 6.0 percent per year thereafter. All other factor
costs were assumed to increase at the general rate of inflation, i.e.,
no real escalation.
The coal industry's after tax nominal rate of return was set at 15
percent. The utility industry's after tax nominal weighted average cost of
capital was set at eight percent but a 10 percent discount rate was used in
pricing calculations (10 percent rate results from valuing interest before
tax and equity after tax). A real fixed charge rate (the factor by which
capital costs are translated into a real annuity revenue requirement) of 10
percent was used.—
Oil and Gas Prices
The price of oil in all demand regions and for all plant types was
$2.25 per million btu's in 1975 dollars. It was assumed to increase with
the general rate of inflation. This single price does not reflect the
different environmental standards around the country or the difference in
1/ A lower real fixed charge rate of five percent was used in Tennessee
(CEUM regions ET and WT) reflecting the capital charges facing TVA, a
public agency.
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cost between distillate and residual oils. Gas was assumed to be unavail-
able to utilities in 1990 and 1995. A limit on the amount of gas available
in 1985 was based on PIES estimates developed in the President's National
Energy Plan. It was priced at $1.95 in 1975 dollars.
Non-Utility Coal Demands
The non-utility coal demands were held constant for all scenarios.
These demand estimates came from a number of sources. The residential/com-
mercial, domestic coking and export demands are from the National Energy
Plan Project Independence Evaluation System Model runs made by the Federal
Energy Administration (circa April, 1977). The industrial demands were
developed from estimates provided by the White House Office of Energy Policy
reflecting the House version of the President's program (circa August, 1977).
The synthetics estimate came from ERDA (circa August, 1977). (See Table
II-8.) The actual input values by region and year are given in Appendix
C.
TABLE II-8
NATIONAL NON-UTILITY COAL DEMANDS
(in 10 btu)
1985 1990 1995
Domestic Coking 2.83 2.94 3.05
Industrial 4.20 6.66 7.90
Existing 1.39 1.39 1.39
New without scrubbers 1.42 2.64 3.26
New with scrubbers 1.42 2.64 3.26
Residential and Commercial 0.04 0.02 0.01
Synthetics 0.45 0.87 1.38
Exports 2.35 2.46 2.58
Total 9.87 12.95 14.92
Other Variables
Other variables that remain constant across scenarios are (1) coal
transportation rates, (2) Federal coal leasing and (3) coal industry labor
rates.
• Coal transportation costs were assumed to increase with the
general rate of inflation. Recent rate filings 0*1 railroads
(e.g., Burlington Northern) has made this assumption suspect.
Rail rates probably will increase faster than the general
rate of inflation. Thus, coal prices are somewhat under-
stated. More importantly, however, the NSPS results probably
overstate the amount of Western coal shipped to the East and
to Texas since this coal has the largest transportation compo-
nent in its delivered price.
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Federal coal leasing was not considered a constraint on
Western coal development. We assumed that reserves would be
leased to meet projected demands.
The 1978 UMW labor contract settlement was not included in
the coal costs. Since that agreement increased real wages
by 13 percent over the three years of the contract, the coal
labor costs are understated in the model runs. No real
escalation was assumed for labor costs. Since the last
two UMW wage agreements included substantial real escala-
tion, it is probably unrealistic to project constant labor
costs in real terms. Thus, the labor costs (and ultimately
coal prices) are understated.
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CHAPTER III
FINDINGS — PHASE I
This chapter presents the impacts of the three alternative new source
performance standards analyzed as part of Phase I (i.e., the preliminary
findings presented at the NAPCTAC meetings). The results from Phase II
(including subsequent analysis of alternative standards using revised partial
scrubbing cost estimates) are presented in Chapter IV. As in the executive
summary, the impacts discussed in this chapter are divided into six categories:
1) coal production, 2) coal distribution, 3) coal prices, 4) utility generat-
ing capacity, 5) scrubber capacity, and 6) utility fuel consumption. However,
unlike the executive summary, these impacts are presented here for 1985 and
1995 as well as for 1990. Further details on these measures are also presented.
As in the executive summary, the impacts are presented for only Refer-
ence Case II, because the effects of the alternative new source performance
standards are amplified by higher electricity growth rates. The effects of
Reference Case I are of the same nature but smaller. These are presented
in tabular form in Appendix D, together with a great deal more detail on
the effects of the alternative new source performance standards under
Reference Case II.
The 0.5 Ib. case results presented in this chapter are based upon
initial estimates of partial scrubbing costs. These results show only
a small cost saving for the 0.5 Ib. standard because the scrubber costs
did not vary significantly with sulfur content or required percent removal.
Revised scrubber cost estimates were analyzed as part of Phase II. The
revised costs reduced the cost of the 0.5 Ib. standard significantly. These
model findings are presented in Chapter IV and Appendix E. The model results
based upon the initial estimates of partial scrubbing are indicated by
the heading "0.5 Ib. (Initial)."
COAL PRODUCTION
Coal production impacts will be discussed in terms of changes in
national and regional production levels, in coal quality, and in method
of mining.
National and Regional Production Levels
The effect of the alternative new source performance standards is
to reduce coal use nationally by a modest amount. However, some regions
(i.e., those which produce medium and high sulfur coal) show gains in
production. These gains are more than offset by the decline in low sulfur
Western production.
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Table III-1 gives the national production estimate in tons for each of
the cases examined. These declines in tonnage under the revised standards
result from both a decline in total btu's of coal being produced (see Table
III-2) and an increase in coal heat content (see Table III-3). The decline
in btu's is the result of oil being substituted for coal in the utility
sector because of the increased cost of using coal. With the revised stan-
dards less new coal-fired capacity is built, existing oil-fired capacity
is used at higher capacity factors and additional combustion turbine capacity
is built for peaking. Under the current NSPS, coal bumps existing oil-fired
units out of intermediate load and into peaking generation, lowering the
capacity factors for existing oil steam units and reducing the need for
TABLE III-1
NATIONAL COAL PRODUCTION IN TONS UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II
1.2 Ibs. 90% 80% 0.5 Ibs. (Initial)
1985 1218 1204 1202 1195
1990 1768 1711 1712 1712
1995 2201 2123 2127 2113
TABLE III-2
NATIONAL COAL PRODUCTION IN QUADS UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II
1985
1990
1995
1.2 Ibs.
26.7
37.0
45.0
90%
26.4
36.6
44.3
80%
26.4
36.5
44.3
0.5 Ibs. (Initial)
26.3
36.6
44.2
TABLE III-3
NATIONAL HEAT CONTENT OF COAL UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(10 btu/tons)
Reference Case II
1.2 Ibs.
1985 21.9
1990 21.0
1995 20.4
90%
22.0
21.4
20.8
80%
22.0
21.3
20.8
0.5 Ibs. (Initial)
22.0
21.4
20.9
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combustion turbines. The increase in heat content is the result of production
shifting from Western subbituminous coals, which generally are low in heat
content, to the higher heat content bituminous coals of the East.
The national shifts in production amount to at most a four percent
decline in tonnage and less than a two percent decline in btu's. The
major differences occur between the 1.2 Ibs. standard and the more strin-
gent standards. Among the more stringent standards, 80 percent removal
generally has the smallest impact on production with the 0.5 Ib. standard
producing the greatest change.
Throughout the analysis the regions experiencing the greatest impacts
are: Northern Appalachia, Central Appalachia, the Midwest and the Western
Northern Great Plains. The tighter regulations lead to increased high
sulfur coal production in Northern Appalachia and the Midwest regions and a
more than offsetting decline in low sulfur coal production in Central
Appalachia and the Northern Great Plains.
TABLE II1-4
COAL PRODUCTION IN SELECTED REGIONS
UNDER NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II
1.2 Ibs. 90% 80% 0.5 Ibs.(Initial)
Northern Appalachia
1985 172 172 172 172
1990 205 258 257 258
1995 222 302 300 302
Central Appalachia
1985 216 214 214 215
1990 219 197 196 196
1995 223 187 187 189
Midwest
1985 235 244 244 244
1990 291 364 352 364
1995 323 412 411 410
Western Northern Great Plains
1985 396 374 374 367
1990 763 614 621 615
1995 1089 873 882 882
Exhibits D-1 through D-5 in Appendix D give the regional production
estimates in tons and btu's for all cases and years.
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C ha in ^eji _i.1_Cga.l Quality
Medium and high sulfur coal production increases as a result of the
tighter standards. However, the decline in low sulfur coal production more
than offsets the increases in the higher sulfur coals. Table III-5 presents
the national changes in coal production by sulfur content. These changes by
sulfur content are closely related to the regional shifts discussed in the
previous section since Northern Appalachia and the Midwest are the largest
producers of medium and high sulfur coals and the Western Northern Great
Plains is the largest producer of low sulfur coal. A further decline in low
sulfur coal production occurs in Central and Southern Appalachia.
TABLE II1-5
COAL PRODUCTION BY SULFUR CONTENT UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II __^_
1.2 Ibs. 90% 80% 0.5 Ibs. (Initial)
High Sulfur
1985 223 236 238 237
1990 266 384 383 376
1995 302 443 441 432
Medium Sulfur
1985 496 501 501 494
1990 631 729 721 709
1995 766 928 932 864
Low Sulfur
1985 325 294 292 292
1990 666 420 431 449
1995 909 572 573 634
The shifting of sulfur content within production regions is limited.
Only the Western Northern Great Plains has large enough reserves of both
low and medium sulfur coal to have a significant shift between them. Tables
III-6 shows the shifts between sulfur levels in the four high impact regions
discussed earlier. Note that Northern Appalachia and the Midwest both had
minimal low sulfur production. Thus, the gain in high sulfur production was
not offset by declines to the region's low sulfur production but declines in
production elsewhere in the country. Low sulfur coal production declines in
Central Appalachia but the medium and high sulfur coal production remains
unchanged. In the Western Northern Great Plains, the increased medium sulfur
coal production is offsetting about one-quarter of the large decline in low
sulfur coal production.
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TABLE III-6
SHIFTS IN 1990 COAL QUALITY IN SELECTED REGIONS UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II
1.2 Ibs. 90% 80% 0.5 Ibs. (Initial)
Northern Appalachia
Metallurgical &
Low Sulfur 28 20 20 20
Medium Sulfur 111 128 128 137
High Sulfur _66 121 12i !°!
Total 205 258 257 258
Central Appalachia
Metallurgical &
Low Sulfur 168 152 151 151
Medium Sulfur 31 28 28 28
High Sulfur 20 _T7 JT7 _1_7
Total 219 197 196 196
Midwest
Low Sulfur 1 1 "! 1
Medium Sulfur 96 98 96 96
High Sulfur 194 265 265 267
Total 291 364 352 364
Western Northern Great Plains
Low Sulfur 536 315 328 343
Medium Sulfur 228 299 293 271
High Sulfur
Total 763 614 621 615
Exhibits D-1 through D-5 in Appendix D give the regional production
estimates by sulfur content for both cases and the three years.
Changes In Method of Mining
The shift in production from the West to the East also leads to
an increase in production from deep mines and a decrease in surface mine
production on a national basis. Since deep mining is the predominant
method of mining in the East (accounting for 80 to 95 percent of total
production in 1990) and surface mining is predominant in the West (account-
ing for more than 95 percent of total production in 1990), the regional
shifts lead to a national decline in the role of surface mining. However,
within a region, deep and surface production generally change in the same
direction, i.e., if surface production declines, deep production does also.
Table III-7 gives the percent of production that is surface mined for the
East, the West and the Nation.
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1.2 Ibs.
20.0
95.4
55.4
8.7
95.2
59.0
5.2
95.7
63.1
90%
20.5
94.4
54.2
8.9
95.8
52.9
4.0
95.7
56.1
80%
20.6
94.4
54.1
8.9
95.6
53.2
4.1
96.6
56.3
0.5 Ibs. (Initial)
20.5
94.3
53.8
8.9
96.0
53.2
4.0
96.6
56.0
T/U5LK Jll-7
SURFACE MINING SHARE OF TOTAL PRODUCTION UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in percent)
Reference Case II
1985 East
West
National
1990 East
West
National
1995 East
West
National
Exhibits D-6 through D-10 in Appendix D give the regional production
estimates by method mining for all cases and years.
COAL DISTRIBUTION
The amount of Western coal shipped to the East declines under the
alternative new source performance standards. Table III-8 gives the amount
of coal produced in the West and shipped east of the Mississippi. Such
shipments decline by about one-third in 1990 and by about 40 percent in 1995.
Since all new coal-fired powerplants must install scrubbers under the ANSPS,
low sulfur coal loses its market premium. Utilities would purchase the
cheapest coal available, which for the plants in the East would be medium and
high sulfur coals from Northern Appalachia and the Midwest.
TABLE II1-8
WESTERN COAL SHIPPED EAST UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II
1.2 Ibs. 90% 80% 0.5 Ibs. (Initial)
1985 206 190 190 189
1990 455 298 300 297
1995 601 358 350 374
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The quantity of western subbituminous coal used east of the Mississipi
tends to be high in the EPA runs for two reasons. First, the cost of
converting existing plants from bituminous to subbituminous coal was a low
estimate. Subsequent analysis has shown that the capacity penalty should
have been closer to 10 percent than to the 5 percent that was used. Second,
the EPA runs did not lock in the ranks of coal planned for the units currently
under construction. Since subbituminous coal cannot be used in plants
designed for bituminous coal without significant penalties, we would be
overstating subbituminous coal consumption if this coal was burned in plants
designed for bituminous. Third, the industrial sector in the East was
forecast to burn substantial quantities of western coal in these forecasts,
whereas subsequent analyses have indicated this would not occur. Finally,
recent analyses indicated that rail rates are likely to escalate faster than
the rate of inflation. Real rail rate escalation inhibits the use of
Western coal in the East since rail transportation costs are a substantial
portion of the total delivered coal costs for Western coal in the East.
Hence, the level of Western coal production and of Western coal con- ^
sumed in the East is higher in these forecasts than we currently forecast.-
However, the differences between cases presented here are representative
of the differences that are forecast under more recent and refined assump-
tions .
Exhibits D-11 through D-30 in Appendix D give the distribution of coal
from supply regions to consuming regions for all cases and years. Note that
the total amount shipped does not equal total coal production. For example,
in 1985 under the current 1.2 Ibs. standard, 1,216 million tons of coal are
shipped but 1,218 million tons are produced. The difference of two million
tons is the loss from deep cleaning. This difference between production
and shipments will vary between scenarios depending on the amount of deep
cleaning that is forecast to occur.
COAL PRICES
The price of coal can be measured at either the mine or delivered to
the consumer. The f.o.b. mine price is the marginal price paid for a
specific quality of coal in a specific region. The delivered price in-
cludes transportation costs and represents the marginal prices a consumer
must pay for coal of a specific quality delivered to his facility. Utili-
ties consider both the cost of the fuel and the cost of environmental con-
trols for that fuel when deciding upon which fuel to purchase. Thus, a
utility may reduce its total generation cost by purchasing a high cost fuel
tli.it requires few controls rather than an inexpensive fuel that requires
substantial controls.
Exhibits D-31 through D-33 in Appendix D give the f.o.b. mine prices by
supply region and sulfur level for all cases and years. Exhibits D-34
througli D-36 give delivered prices to electric utilities by consuming region
and sulfur content for all cases and years.
T/~Dem'a'nd'~For Western Coal and Its Sensitivity To Key Uncertainties, prepared
for DOE and DOI by ICF, August, 1978.
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Average prices can be deceptive since they are comprised of prices
for different coals weighted by the volume of coal. Thus, an apparent
increase in price can result from either an increase in the individual
prices with no change in weights or no change in prices but a change
in weights. For example, between 1985 and 1990 the average price of low
sulfur coal drops in the Middle Atlantic region from $1.80 per million
btu's to $1.60 per million btu's. Looking at the smaller regions within
the larger Middle Atlantic region, the price of low sulfur coal in upstate
New York increases from $1.82 to $1.90 over the same period. The price of
low sulfur coal in New Jersey also increases over the same period from
$1.80 to $1.99. However, western Pennsylvania, which consumes no low
sulfur coal in 1985, begins consuming a considerable amount of it in 1990
at $1.33. The price in western Pennsylvania pulls down the regional
average price in 1990, creating what on the surface appears to be an
anomalous result.
The national average f.o.b. mine price for coal varies by at most
two cents per million btu's. See Table III-9. This change may appear
small given the amount of production shifting from the West to the East
(i.e. from a low production cost area to a high production cost area).
Since several of the supply curves for coal are highly elastic, significant
changes in regional production levels as shown above can result from only
small changes in price. Nationally, the alternative standards reduced
production by at most five percent and shifted at most another five percent
from the West to the East. The prices of medium and high sulfur coals
increase as a result of the ANSPS; the prices for low sulfur coals decrease,
Thus, the weighted average price for all coal remains about the same. See
Exhibits D-31 through D-33 in Appendix D for the f.o.b. mine prices by
region and sulfur levels for all cases and all years.
TABLE III-9
NATIONAL AVERAGE COAL PRICES UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(in dollars per million btu's - 1977 dollars)
Reference Case II
1.2 Ibs. 90% 80% 0.5 Ibs. (Initial)
FOB Mine
1985 0.89 0.90 0.90 0.90
1990 0.88 0.90 0.90 0.90
1995 0.91 0.92 0.91 0.92
Delivered to Utilities
1985 1.11 1-11 1-11 1'1,1
1990 1.21 1.17 1.17 1.17
1995 1.27 1.21 1.20 1.21
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The national average delivered coal price to utilities decreases by
at most seven cents per million btu's. See Table III-9. The decline in
delivered prices under the ANSPS results from the use of more locally
available coal; i.e., less transportation cost. Again, only the coal being
consumed by ANSPS plants was shifting, and this accounted for only a small
portion of total coal demand.
GENERATING CAPACITY
Coal-fired generating capacity declines under the alternative NSPS.
Table 111-10 shows the amount of coal-fired capacity under each of the
alternative new source performance standards. The impacts increase over
time since more new capacity is subject to the revised NSPS in the later
years, particularly at the high electricity growth rate.
TABLE 111-10
NATIONAL COAL-FIRED GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in GW)
Reference Case II
1985
1990
1995
Table III-11 gives the oil-fired capacity under the alternative
new source performance standards. Note that the increase in oil-fired
capacity generally offsets the decline in coal-fired capacity.
TABLE 111-11
NATIONAL OIL-FIRED GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in GW)
Reference Case II
1985
1990
1995
1.2 Ibs.
320.4
465.0
577.1
90%
314.0
444.6
549.5
80%
313.8
444.3
550.7
0.5 Ibs. (Initial)
311.3
444.4
547.4
1.2 Ibs.
274.8
301.9
377.8
90%
279.8
323.5
404.6
80%
280.0
323.3
403.6
0.5 Ibs. (Initial)
280.8
323.7
406.6
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The substitution of oil for coal occurs because the alternative NSPS
increase the costs of burning coal relative to oil. Hence, less coal-fired
capacity is built, and more oil-fired capacity is built. The dynamics of
this shift are a) the fewer coal units operate at a higher average capacity
factor since the coal capacity that was not built was the marginal coal
capabity, b) the average capacity factor of existing oil steam units is
increased to fill in for the marginal coal units that did not get built, and
c) more turbines are built to fill in for the existing oil steam units. See
Figure III-1.
FIGURE III-1
Table 111-12 shows the increase in both coal-fired and oil-fired plant
capacity factors. Note that the average capacity factor for oil declines
over time as turbines operating in peak load assume a larger portion of oil
capacity.
TABLE III-12
NATIONAL AVERAGE COAL-FIRED AND OIL-FIRED PLANT CAPACITY FACTORS
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in percent)
Reference Case II
Coal
Oil
0.5 Ibs. 0.5 Ibs.
1.2 Ibs. 90% 80% (Initial) 1.2 Ibs. 90% 80% (Initial)
1985 60.8 61.1 61.0 61.1
1990 59.1 60.1 60.1 60.1
1995 57.7 58.6 58.6 58.7
27.7 27.9 28.0 28.0
21.9 22.6 22.7 22.6
19.8 21.0 21.0 21.0
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Regional shifts of capacity also result from the alternative NSPS.
For example, under the current NSPS standard in 1990 the model transmits
78.1 billion kwh from western Pennsylvania (WP) to Virginia/Maryland/
Delaware (VM). Under the 90 percent removal standard the amount of elec-
tricity transmitted along the same link is 28.4 billion kwh. This shift in
transmission is the result of siting the ANSPS plants in region VM under the
90 percent removal scenario rather than remotely siting them in region WP,
as was done in the current NSPS case. See Table 111-13.
TABLE III-13
COMPARISON OF 1990 ANSPS CAPACITY FOR WESTERN
PENNSYLVANIA AND VIRGINIA/MARYLAND/DELAWARE
Western Pennsylvania Virginia/Maryland/Delaware
ANSPS Coal Type ANSPS Coal Type
Capacity (GW) Used Capacity (GW) Used
Current NSPS
90 Percent Removal
0.260
13.188
0.799*
14.247
4.376*
1.565*
5.940
BB
SA
BG
BG
BG
3.181
0.128*
0.044*
3.353
8.491*
3.181*
0.113*
11.785
BB
BG
BH
BG
BG
BH
Difference in totals
(8.307)
8.432
* Capacity built with scrubber.
Note that the amount of ANSPS capacity in western Pennsylvania goes down
between the two standards by roughly the same amount that the ANSPS capacity
in Virginia/ Maryland/Delaware goes up. The 8.3 GW decline in ANSPS capacity
in WP accounts for the entire decline in electricity transmission of 49.7^
billion kwh (8.3 GW x 8760 hours in year x 0.7 base load capacity factor -
50.9 billion kwh). Note that the remote-sited plants in western Pennsylvania
are using low sulfur subbituminous coal. A cost comparison of using the
western coal versus the western Pennsylvania coal is presented in Table
111-14. A small change in transportation costs would have shifted the source
of the coal but the basic finding that the two coals are close in terms
of cost would remain.
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TABLE III-14
COMPARISON OF 1990 GENERATION COST IN WESTERN
W PLANTS MEETING A 1.2 LBS
(In mills/kwh - 1977 S's)
PENNSYLVANIA OF PLANTS MEETING A 1.2 LBS. SO^MMBTU NSPS
Coal sulfur content (Ibs. S/ranbtu)
Annualized Capital Costs-
OS M Costs-
Fuel Costs-
Total
Bituminous
0.6
1.67 2.50 >2.50
10.40 12.51 12.67 12.82
2.70 4.85 5.01 5.17
15.47 11.80 11.27 12.26
28.57 29.16 28.95 30.25
Subbi-
tuminous
0.4
11.97
2.94
12.68
27.59
I/ Annuallzed capital cents are calculated AS follows:
Coal Type
BF
BG
SA
Base cost of ANSPS plant with TSP control
and cooling towers but without scrubber
(these estimates include five years of
real escalation at 0.5 percent per year
for 1985 through 1990) in S/kv
Base cost of full scrubber - in 5/kw
Partial scrubbing cost factor
Cost of scrubber - in $/kw
Base cost of replacement capacity with
scrubber - in S/kw
Capacity penalty
Partial scrubbing cost factor
Cost of replacement capacity - in S/kw
Full cost of ANSPS plant in 1975 dollars '
- in S/kw
Cost inflator to restate 1990 costs (with
2 percent annual real escalation through
1985) in late 1977 dollars (1.075 /
1.055 = 1.417)
Regional cost adjuntment factor
Full cost of ANSPS plant in late 1977 S's
- in S/kw
Times 1000 to convert to mills from
dollars
Real fixed charge factor
Kwh's per kw (8760 x baseload capacity
factor of 0.7)
Annualized capital cost - in mills/kwh
450
450
450
86
0.87
75
450
86
0.94
81
450
1.00
86
561 561 561
- 0.033 0.033 0.033
0.87 0.94 1.00
16
541
17
548
19
617
518
518
1.417 1.417 1.417 1.417 1.417
1.00 1.00 1.00 1.00 1.00
638
767
777
786
734
1000 1000 1000 1000 1000
0.1 0.1 0.1 0.1 0.1
6132 6132 6132 6132 6132
10.40 12.51 12.67 12.83 11.97
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Footnotes to Table III-9
2/ O&M costs are calculated as follows:
Base OSM costs for ANSPS plant at base
load - in mills/kwh
Base OSM cost for scrubber - in millsAwh
Part In 1 Bcrubbing coat factor
Scrulihor OfcM - In ml lln/kwh
Full OSM costs of ANSPS plant in 1975 $'a
- in mills/kwh
Cost inflator to restate in late 1977
S's (1.055 = 1.174)
Full OSM costs for ANSPS plant in late
1977 $'s - in mills/kwh
Coal Type
BD BF BG BH SA
2.30 2.30 2.30 2.30 2.50
2.10 2.10 2.10
- 0.87 0.94 1 .00 -
1.83 1.97 2.10
2.30 4.13 4.27 4.40 2.50
1.174 1.174 1.174 1.174 1.174
2.70 4.85 5.01 5.17 2.94
3/ Fuel costs are calculated as follows:
Base heat rate for ANSPS plant at base
load without scrubber
Energy penalty for scrubber
Partial scrubbing coat factor
Adjusted energy penalty
Heat rate adjustment factor ( 1 +
adjusted energy penalty)
Fuel heat rate for ANSPS plant with
scrubber
1990 delivered price of coal in 1977
$'s - in S/mmbtu
Fuel cost in 1977 $'s - mills/kwh
Coal Type
BD
BF
BG
SA
9100 9100 9100 9100 9532
- 0.053 0.053 0.053
- 0.87 0.94 1.00 -
- 0.046 0.050 0.053
1.000 1.046 1.050 1.053 1.000
9100 9519 9555 9582 9532
1.70 1.24 1.18 1.28 1.33
15.47 11.80 11.27 11.26 12.68
-------
-67-
The shift in transmission can be attributed to a change in the relative
cost of building a plant in western Pennsylvania and transmitting the power
relative to the cost of building the plant in Virginia/Maryland/Delaware.
Table 111-15 compares the costs of the two alternatives for the current NSPS
and 90 percent removal cases. Note that the remote siting strategy is the
cheaper under the current NSPS but is the more expensive under the 90 percent
removal standard. However, part of the cost advantage for remote siting is
the result of the higher capacity factor for baseloaded units in western
Pennsylvania. If a 0.70 capacity factor had been used for plants in VM or
the capacity factor in WP reduced to 0.65, the remote siting of power plants
in the current NSPS case would no longer be the cheaper alternative (If the
VM capacity factor had been 0.70, the annualized capital costs would have
been 12.67 mills/kwh making the total cost 30.14 mills/kwh or 0.14 mills
cheaper than the remote siting option).
This example illustrates well how the "knife-edge" economics operate
in an optimization model. Hence, we report findings on the basis of aggre-
gate regions (in which the knife-edges tend to be dulled by offsetting
results) rather than at the lowest level of disaggregation. However, it is
important to understand that such knife-edges are not a modeling phenomenon.
They exist in the real world. Simulation techniques that in essence assume
them away are not closer to being correct than optimization techniques that
provide for them explicitly. Indeed, we prefer the optimization approach
because it enables one to identify the knife-endge situations where substan-
tial uncertainty exists. Such situations are generally not recognized when
simulation approaches are employed.
Exhibits D-37 through D-41 in Appendix D give the projected generating
capacity and capacity factor by plant type and region for all cases and
years.
SCRUBBER CAPACITY
Scrubber capacity increases to about the same level under all three
ANSPS. In 1985 scrubber capacity goes up by 14 percent from the current NSPS
case, in 1990 by 104 percent and in 1995 by 135 percent. This growth in
scrubber capacity comes in the ANSPS plant category. Table 111-16 shows the
scrubber capacity under the various standards.
The percent of flue gas scrubbed is about the same for the 90 per-
cent and 80 percent standards increasing from about 86 percent to 90 percent
in 1985, from 83 percent to 90 percent in 1990 and from 77 percent to 95
percent in 1995. The 0.5-lb. standard has lower percents throughout,
although the difference is not large until 1995. This is because partial
scrubbing would be permitted under a 0.5-lb. emissions limitation. See
Table 111-16.
Average removal efficiency changes with the standard being examined,
going from a low of 81.1 percent with the current standard to a high of 87.2
percent under the 90 percent removal standard in 1990. Note that the 0.5-lb.
standard has average removal efficiencies very close to the 90 percent
standard.
ICF
INCORPORATED
-------
-68-
TABLE 111-15
COMPARISON OF REMOTE AND LOCAL SITING OF PCWERPLANTS
IN 1990 FOR VIRGINNIA/MARYLAND/DELAWARE
(milla/kwh - 1977 $'s)
Current NSPS
Plant Sited
Plant Sited in Virginia/
in Western Maryland/
Pennsylvania Delaware
Annualized Capital
Costs- 11-97 13.65
OSM Costs-7 2.94 5.01
FuRl Costs-/ 12.6B^ 12.46^
Total Generation
Cost 27.59 31.12
Capital cost of
long distance & .
transmission line- 1.66
Line losses for remote
site- 1.03
Total Cost 30.28 31.12
90 Percent
Plant Sited
in Western
Pennsylvania
13.06
5.28
11.88^
30.22
1.66
1.12
33.00
I/ Annualized capital costs are calculated as follows:
Current NSPS
WP
Base cost of ANSPS plant with TSP control
and cooling towers but without scrubber
(these estimates include five years of
real escalation at 0.5 percent per year
for 1985 through 1990) in S/kw 518
Base cost of full scrubber - in S/kw
Partial Hcrubbina cost factor
Cost of scrubber - in $/kw
Base cost of replacement capacity with
scrubber - in S/kw
Capacity penalty
P/irtial Bcrubblna cost factor -
Cost of replacement capacity - in S/kw
Full cost of ANSPS plant in 1975 dollars
- in S/kw 518
Cost inflator to restate 1990 costs (with
2 percent annual real escalation through
1985) in late 1977 dollars (1.075 /
1.055 - 1.417) 1.417
Regional cost adjustment factor 1.00
Full cost of ANSPS plant in late 1977 S's
- in S/kw 734
Times 1000 to convert to mil Is from
dollars 1000
Real fixer! clinrye factor 0.1
Hours In yoar 8760
rapacity factor for baseload 0.70
Annualized capital cost - in mills/kwh 11.97
VM
450
86
0.94
81
561
0.033
0.94
17
548
1.417
1.00
777
1000
0.1
8760
0.65
13.65
Removal
Plant Sited
in Virgina/
Maryland/
Delaware
14.07
5.28
13.18V
32.53
-
32.53
90 Percent
WP
450
96
1.00
96
561
0.033 0
1.00
19
565
1.417 1
1.00
801
1000
0.1
8760
0.70
Case
VM
450
96
1.00
96
561
.033
1.00
19
565
.417
1.00
801
1000
0. 1
8760
0.65
13.06 14.07
-------
-69-
Kootnotos to Table 111-15.
2/ OSM costs are calculated as follows:
Base OSM costs for ANSPS plant at base
load - in mills/kwh
Base OSM cost for scrubber - in mills/kwh
Partial scrubbing cost factor
ScrublK-r OSM - in mllls/kwli
[•Mil OSM costs of ANSPS plant in 1975 $'s
- in mills/kwh
Cost inflator to restate in late 1977
$'s ( 1.055 = 1.174)
Full OSM costs for ANSPS plant in late
1977 $'s - in mills/kwh
Current NSPS
1.94
90 Percent Case
WP VM
2.50 2.30
2. 10
0.94
WP
2.30
2.20
1.00
VM
2.30
2.20
1.00
2.20
2.20
2.50 4.27 4.50 4.50
1.174 1.174 1.174 1.174
2.94 5.01 5.28 5.28
3/ Kucl costs art- calculated nn followa:
Current NSPS
WP VM
90 Percent Case
" WP VM
llaso heat rate for ANSPS plant at base
load without scrubber
Eneryy penalty for scrubber
Partial scrubbing cost factor
Adjusted energy penalty
Heat rate adjustment factor ( 1 +
adjusted energy penalty)
Fuel heat rate for ANSPS plant with
scrubber
1990 delivered price of coal in 1977
S's - in $/mmbtu
9532
1.000
9532
1 .33
9200
0.053
0.94
0.050
1.050
9660
1.29
9100
0.053
1.00
0.053
1.053
9582
1.24
9200
0.053
1 .000
0.053
1.053
9688
1 .36
Fuel cost in 1977 $'s - mills/kwh
12.68 12.46
11 .88
13. 18
-------
-70-
Footnotes to Table 111-15.
4/ Plant fired with subbituminouo coal with 0.4 Ib. S/tnmbtu (SA coal).
5/ Plant fired with bituminous coal with 2.5 Ibs. S/mmbtu (BG coal).
6/ The normalized per mile capital cost of a 500 kv line in the East was
estimated to be $330,034. This line would carry 5.58 billion kwh
(910,000 MW capacity of line at SIL equal fo one x 8760 hours in year
x 0.7 baseload capacity factor - 5.58 x 10 kwh). The normalized
cost per kwh mile would be 0.059 mill in 1975 dollars. All capital
costs were subject to 2 percent real escalation from 1975 through
1985 and 1.055 / 1.055 - 1 from 1985 to 1990). The normalized cost
in 1977 dollars becomes 0.0836 mills per kwh-mlle. This value is trans-
lated into a cost per kwh by multiplying by the length of the link (238
miles), dividing by the surge impedance loading factor (1.2) and multi-
plying by the capital charge rate (0.1). The resulting cost is 1.658
mUls/kwh (0.0836 x 238 / 1.1 x 0.1 - 1.658). See Memo X of Appendix E
of ICF's Coal and Electric Utility Model Documentation (July 1977) for
explanation of transmission coot methodology.
7/ Line losses for transmitting power from Pennsylvania to Virginia/Maryland/
~ Delaware (238 miles) along a new 500 kv line were estimated to be 3.4
percent. This estimate was develoepd using Formula 5 in Memo X of Appendix
E of ICF's Coal and Electric Utilities Model Documentation (July 1977).
The mills/kwh cost in Table 8 was estimated by 0.966 and subtracting the
previously estimated coats. For example, for the current NSPS case the
generation cost was 27.59 mills/kwh and the transmission capital cost was
1.66 mills/kwh. The line lose cost was 1.03 mills/kwh ((27.59 + 1.66) /
0.966 - (27.59 + 1.66) • 1.03).
-------
-71-
TABLK 111-16
NATIONAL SCRUBBER CAPACITY UNDEK
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Reference Case II
1985
Capacity Scrubbed (in GW)
Existing Plants
NSPS Plants
ANSPS Plants
Average Percent Scrubbed
Existing Plants
NSPS Plants
ANSPS Plants
Average Kemoval Efficiency
Existing Plants
NSPS Plants
ANSPS Plants
Average Percent Removal
Existing Plants
NSPS Plants
ANSPS Plants
1990
Capacity Scrubbed (in GH)
Existing Plants
NSPS Plants
ANSPS Plants
Average Percent Scrubbed
Existing Plants
NSPS Plants
ANSPS Plant.i
Avtirmji.: lUimoViil Ef f ic len<:y
Exlstlny Plants
NSPS Plants
ANSPS Plants
Average Percent Removal
Existing Plants
NSPS Plants
ANSPS Plants
1995
Capacity Scrubbed (in GW)
Existing Plants
NSPS Plants
ANSPS PlnntR
Average Percent Scrubbed
Existing Plants
NSPS Plants
ANSPS Plants
Average Removal Efficiency
Existing Plants
NSPS Plants
ANSPS Plants
Average Percent Removal
Existing Plants
NSPS Plants
ANSPS Plnntfi
1.2 Ibs.
73.3
37.2
27.5
8.6
86.0
83.5
88.5
88.7
U0.3
80.0
80.0
82.5
69.0
69.0
70.8
73.2
103.2
40.3
28.7
34.2
82.7
83.3
88.2
77.3
HI . 1
80.0
80.0
83.4
67.0
66.6
70.6
64.5
134.4
40.9
30. 1
63.4
77.2
84.1
87.7
67.8
81.2
80.0
80.0
82.6
62.6
67.3
70.1
56.0
90%
82.6
34.5
23.7
24 .4
89.6
84. 1
88.4
99.6
83.0
80.0
80.0
90.0
74.4
67.3
70.7
89.6
210.8
36.3
23.4
151.1
95.4
83.3
85.4
99.8
87. '1.
80.0
80.0
90.0
83.2
66.6
68.3
89.8
316.2
38.4
23.2
254.6
96.6
83.6
84.2
99.7
88. 1
80.0
80.0
90.0
85. 1
66.9
67.4
8S. 7
80%
82.6
34.7
23.5
24.4
89.8
83.9
88.3
99.6
81.3
80.0
80.0
84.3
73.1
67.1
70.6
84.0
210.8
36.5
23.1
151.2
93.3
81.3
85.6
97.0
HO. 6
80.0
80.0
80.8
75.2
66.5
68.5
78.3
316.0
37.3
22.6
256.1
95.3
83.5
84.1
98.0
80.6
80.0
80.0
80.7
76.8
66.8
67.3
79. 1
0.5 Ibs.
(Initial)
79.9
34.4
23.9
21.7
89.0
84.0
88.4
97.3
82.7
80.0
80.0
89.7
73.6
67.2
70.7
87.3
210.8
36.2
23.6
151.0
90.4
83.4
88.1
92.4
85.6
80.0
80.0
87.8
77.4
66.7
70.5
81 .1
313.1
36.9
23.7
252.5
87.5
83.9
87.0
88.1
85.2
80.0
80.0
86.4
74.5
67.1
69.6
76.1
-------
-72-
The average percent removal (i.e., average percent scrubbed times
the average removal efficiency) varies considerably between the cases.
The lowest average percent removal is for the current NSPS. This is the
result of having the lowest percent of flue gas scrubbed and the lowest
removal efficiency. The 90 percent standard has the highest average percent
removal, since it has both the highest percent scrubbed and the highest
removal efficiency. The 80 percent and 0.5-lb. standards do not maintain
the same order, since one has the higher percent scrubbed while the other has
the higher removal efficiency. The 80 percent case has the higher percent
scrubbed because ANSPS capacity must be fully scrubbed (except in a few
western regions with tight SIP's) while the 0.5-lb. case allows for partial
scrubbing. The 0.5-lb. case has the higher removal efficiency since 90
percent scrubbers are available in this scenario and were not available in
the 80 percent case. See Table 111-16.
The scrubber capacity estimates for all cases and years are presented in
Exhibits D-42 through D-46 of Appendix D.
UTILITY FUEL CONSUMPTION
The increase in oil use is the result of existing oil steam plants
being used at higher capacity factors and additional turbines being built
for peaking, as discussed earlier. Table 111-17 shows the national utility
oil consumption. The increase in oil consumption resulting from the alterna-
tive NSPS becomes greater with time. By 1995, the tighter regulation would
increase utility oil consumption by roughly 500,000 barrels per day.
TABLE III-17
NATIONAL UTILITY OIL CONSUMPTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 btu's)
Reference Case II
1
.2
8
6
7
Ibs.
.2
.4
.2
90%
8.
7.
8.
6
1
3
80%
8.
7.
8.
7
1
2
0.5 Ib. (
8
7
8
Initial)
.7
.1
.3
1985
1990
1995
The utility oil and gas consumption estimates for all cases and all
years are presented in Exhibits D-52 through D-56 of Appendix D.
The more stringent new source preformance standards result in a decline
in the use of coal by electric utilities and an increase in the consumption
of oil. Table 111-18 shows the projected levels of utility coal consumption.
ICF
INCORPORATED
-------
-73-
TABLE 111-18
NATIONAL UTILITY COAL CONSUMPTION
BY SULFUR LEVEL UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD
(in 10 btu's)
Sulfur Reference Case II
Year Level
1985 High
Medium
Low
Total
1990 High
Medium
Low
Total
1995 High
Medium
Low
Total
Utility consumption of medium and high sulfur coals increases, but this
is more than offset by the decrease in low sulfur coal consumption. The
utility coal consumption projections for all cases and all years are pre-
sented in Exhibits D-47 through D-51 in Appendix D.
The model results show an increase in 1990 of 0.3 quad in the consump-
tion of low sulfur coal under the 80 percent standard when compared with
the 90 percent standard. Since there is no apparent reason for such a shift,
we pursued its cause. The increase in low sulfur coal consumption is the
result of the Pacific Region's increased use of low sulfur coal. This shift
occurs in northern California with the ANSPS plants shifting out of medium
sulfur bituminous coal- and completely into low sulfur subbituminous
coal.- No coal plants exist or are built in southern California and the
shifts in coal in the Washington/Oregon region are minor.
1 . 2 Ibs .
3.9
8.0
5.1
17.0
4.1
9.1
10.5
23.7
4.2
10.4
14.1
28.7
90%
4.2
8.1
4.5
16.8
7.4
10.9
5.0
23.0
8.4
13.9
5.8
28.1
80%
4.2
8.1
4.4
16.8
7.4
10.6
5.3
23.3
8.3
13.9
6.0
28.2
0.5 Ib. (Initial)
.4.2
8.0
4.4
16.6
7.0
10.8
5.5
23.3
7.7
13.3
7.0
28.1
I/ BD coal is bituminous coal with 0.83 Ib. S/mmbtu.
2/ SA coal is sub-bituminous coal with 0.40 Ib. S/mmbtu.
ICF
INCORPORATED
-------
-74-
The shifts are due largely to the standards for northern California
being generally tighter than the national NSPS. Under the 1.2 Ibs. SO /
mmbtu case, the northern California standard was 0.67 Ib. SO /mmbtu. This
was based upon the coal emission standard in nearby states.— A 90 percent
removal requirement was imposed in the 90 percent case and a 0.5 Ib. SO2/
mmbtu standard used in the 0.5 Ib. case. In the 80 percent case the northern
California standard was set at the 0.67 Ib. standard, which is more stringent
than 80 percent removal in high sulfur coal.
Table 111-19 gives the generation costs associated with using BD and SA
coals in the current NSPS case, the 90 percent case and the 80 percent case.
Note that the costs of generation are nearly identical in the NSPS case.
(Since the model output rounds delivered coal prices to the nearest cent per
million btu, the fuel costs presented here are only approximate and could be
as much as 0.5 mills different from the value actually used in the model
solution.) The model showed both coals being used in that case. In the 90
percent removal case BD coal has the lower cost of generation. This confirms
the model's shift away from SA coal in this case. In the 80 percent removal
case SA coal has the lower cost of generation. This confirms the model's
shift from BD to strictly SA coal.
The apparent anomaly between the 90 percent and 80 percent standard
cases is that the model shifted away from BD coal for which the price decre-
ased from $1.38/mmbtu to $1.32/mmbtu to SA coal for which the price did
not change. Table 111-18 compares the generation costs using BD and SA coals
in the two cases. The model shifted to SA coal because the capital costs of
burning BD coal increased. The cost of a scrubber was inputted to.be greater
in the 80 percent case than the 90 percent case. The model minimized the
cost of generation in each case given the input assumptions that it was
given.
In retrospect the 80 percent removal case was probably misspecified in
northern California in two ways. First, the wrong partial scrubbing cost
factors were inputted into the model for ANSPS plants meeting a 0.67 Ib.
SO /mmbtu standard. The costs that were specified were too high. An 80
percent scrubber should have been cheaper than a 90 percent scrubber.
Second, the 0.67 Ib. standard should have been replaced by the 80 percent
removal requirement since it would have been the tighter standard for the low
sulfur coals available in the West. Although this misspecification for the
ANSPS plants' shifted roughly 0.25 quads or about 14 million tons of coal, the
overall impact on the model solution is small. The shift represents a one
percent change in utility coal consumption and judging from the generation
cost differences in Table 111-19,. the cost impacts are trivial.
V Kecent information indicates that California may set a more stringent
sulfur emissions limitation.
ICF
INCORPORATED
-------
-75-
TABLE 111-19
COMPARISON OF ANNUAL COSTS IN 1990 FOR AN ANSPS
PLANT IN NORTHERN CALIFORNIA
(in raills/kwh - 1977 dollars)
Coal Type
Annualized Capital Costs—
OSM Costs-
Fuel Costs-
Tota 1
Current NSPS Case 90 Percent Removal
(0.67 Ib. SO /rnnbtu (90 percent removal
specified for specified for Northern
Northern California California)
80 Percent Removal
(0.67 Ib. SO /mmbtu
specified for Northern
California)
BD
11.76
5.28
12.94
29.98
SA
12.83
5. 15
11.96
29.94
BD
11.42
4.92
13. 14
29.48
SA
12.83
5.15
11 .66
29.64
BD
11.76
5.28
12.65
29.69
SA
12.83
5.15
11.66
29.64
V Annualized capital costs are calculated as follows:
90 Percent Case
BD
SA
Current NSPS Case and
80 Percent Case
BD
SA
Base cost of ANSPS plant with TSP control
and cooling towers but without scrubber
(these estimates include five years of
real escalation at 0.5 percent per year
for 1985 through 1990) in S/kw
450
518
450
518
Base cost of full scrubber - in S/kw
Partial scrubbing cost factor
Cost of scrubber - in S/kw
96
0.86
83
96
O.B6
83
96
1.00
96
96
0.86
83
Base cost of replacement capacity with
scrubber - in S/kw 561 561 561 561
Capacity penalty 0.033 0.033 0.033 0.033
Partial scrubbing cost factor _0 ._86 JL:^6. 1 .00 0.86
Cost of replacement <:.i |>ac I t-.y - in S/kw 16 1& 19 16
Full cost of ANSPS plant in 1975 dollars
- in S/kw
549
617
565
617
Cost inflator to restate 1990 costs (with
2 percent annual real escalation through
1985) in late 1977 dollars (1.075 /
1.055 = 1.417)
Regional cost adjustment factor for
Northern California
1.417
0.9
1.417
0.9
1.417
0.9
1.417
0.9
Full cost of ANSPS plant in late 1977 S's
- in $/kw
Times 1000 In convert to mill;; from
linll.iru
Ki-.il flx.M cli.inje f.ictor
Kwlt ' :i per kw ( H7t>0 x hn;u'lo
-------
-76-
l-'ootnotes to Tnblo 111-19.
2/ OSM coots are calculated as follows:
Base OSM costs for ANSPS plant at base
load - in mills/kwh
Base OSM cost for scrubber - in mills/kwh
Partial scrubbing cost factor
Scrubber OSM - in mills/kwh
Full OSM costs of ANSPS plant in 1975 $'3
- in mills/kwh
Cost inflator to restate in late 1977
$'s (1.055 = 1.174)
Full O&M coats for ANSPS plant in late
1977 $'s - in mills/kwh
3/ Fuel costs are calculated as follows:
Base heat rate for ANSPS plant at base
load without scrubber
Energy penalty for gcrubbr
Partial scrubbing cost factor
Adjusted energy penalty
Heat rate adjustment factor ( 1 +
adjusted energy penalty)
Fuel heat rate for ANSPS plant with
scrubber
1990 delivered price of coal in 1977
$'s - in S/mmbtu
Fuel cost in 1977 S's - mills/kwh
Current NSPS Case and
90 Percent Case 80 Percent Case
BD
2.30
wh 2.20
0.86
1.89
'3
4.19
1.174
4.92
Current NSPS
Caae
BD SA
9100 9532
0.053 0.053
0.86 0.86
0.046 0.046
1.053 1.046
9582 9970
1.35 1.20
12.94 11.96
SA
2.50
2.20
0.86
1.89
4.39
1.174
5.15 '
BD
2.30
2.20
1.00
2.20
4.50
1.174
5.28
90 Percent Case
BD
9100
0.053
0.86
0.046
1.046
9519
1.38
13.14
SA
9532
0.053
0.86
0.046
1.046
9970
1.17
11.66
SA
2.50
2.20
0.86
1.89
4.39
1.174
5.15
80 Percent
BD
9100
0.053
1.00
0.053
1.053
9582
1.32
12.65
Case
SA
9532
0.053
0.86
0.046
1.046
9970
1.17
11.66
-------
-------
-77-
CHAPTER IV
FURTHER ANALYSIS — PHASE II
This chapter presents the second phase of ICF's analysis of alternative
new source performance standards. This work was done after the NAPCTAC
meeting in December 1977. The chapter is broken into six sections with each
section addressing a different aspect of the Phase II analysis. These
sections are: 1) SO loadings, 2) cumulative utility capital expenditures
and annualized costs, 3) the impacts of a 0.8 Ib. SO2/mmbtu emission
limitation, 4) the impacts of revised partial scrubbing costs, 5) the
impacts of alternative floors, ceilings and exemptions, and 6) the economics
of partial scrubbing.
SO LOADINGS
SO loadings were estimated for the scenarios analyzed in Phase I.
The discussion below first presents the emission forecast under the current
NSPS and then under the three alternative standards analyzed in Phase
I.
National Sulfur Dioxide Emissions Under the Current NSPS
Sulfur dioxide emissions are forecast to increase by about 10 percent by
1985, because compliance with the current state implementation plan emissions
limitations for existing sources was assumed to occur by 1985. This reduces
emissions from existing sources by about four million tons per year, and
this reduction offsets most of the increased emissions from new sources
subject to the current NSPS.
ICF
INCORPORATED
-------
-78-
TABLE IV-1
NATIONAL ELECTRIC UTILITY
SULFUR DIOXIDE EMISSION UNDER THE
CURRENT NSPS
(10 tons per year)
1975 1985 1990 1995
RC I
Oil and Gas 1.79 2.68 2.21 1.92
Coal
Existing 16.78 14.58 13.94 13.64
New - 3.31 5.15 5.45
Total 18.57 20.57 21.31 21.00
RC II
Oil and Gas 1.79 2.68 2.30 2.42
Coal
Existing 16.78 14.58 14.25 14.01
New - 3.31 6.79 9.43
Total 18.57 20.57 23.33 25.85
After 1985, sulfur emissions under current standards are projected to
continue to increase, modestly under the RC I electricity growth rates and
less modestly under the higher RC II rates. Between 1990 and 1995 under RC I
growth rates, emissions are forecast to stay about level as a result of the
assumed large increases in nuclear capacity relative to the assumed electricity
growth rates. Hence, forecasts of sulfur emissions after 1985 are very
sensitive to assumed electricity growth rates and nuclear capacity.
Even in 1995 in RC II, the majority of emissions are forecast to be
from existing sources. This means that alternative NSPS can affect only
the smaller portion of total emissions, although this is not to say the
absolute amount is not significant. As noted below, the alternative NSPS
act to moderate the growth in emissions.
After 1995 existing sources will be reaching the ends of their economic
lives and will begin to be replaced by new sources. Hence, total emissions
can be expected to fall off rapidly beginning in about 2000.
From a historical perspective, one might expect emissions from existing
sources to decrease over time (prior to replacement) as new capacity is
added. This is because new capacity has typically been more efficient and
less costly to operate. Hence, it was operated at high capacity factors,
causing existing capacity to be operated at lower capacity factors. This
practice will continue in the case of nuclear plants, which will be base-
loaded, pushing all other capacity to lower capacity factors. However, it
will probably not continue in the case of coal plants.
ICF
INCORPORATED
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-79-
New coal plants without pollution controls are generally not more
efficient than most existing plants without pollution controls. The tech-
nology is mature and efficiency improvements are no longer being developed
at a rapid pace, as was the case through the 1960's. However, new plants
due to the NSPS will generally have to emit less than existing plants under
the SIP'S. These tighter emissions limitations for new plants require more
pollution control and tend to make new plants more expensive to run (even on
a variable cost basis) than existing plants. Hence, contrary to historical
practice, existing coal plants will tend to have higher capacity factors
than new coal plants. This can be illustrated by the 1990 forecast for the
Virginia/Maryland/Delaware region (Reference Case II, current NSPS) where
the forecast indicates the existing coal plants would have an average
capacity factor of .64 while the new coal plants would average .37.
Regional Emissions Under the Current NSPS
Under the electricity growth assumption, sulfur dioxide emissions are
forecast to remain relatively constant in the East with modest growth in
some regions and a large decrease in the Midwest. This is due to relatively
small increases in coal consumption in the East (as a result of modest
electricity growth rates and substantial increases in nuclear capacity).
This is also due to the effect of compliance with existing SIP's (partic-
ularly in the East North Central region).
However, in the West South Central regions, sulfur emissions are
projected to grow rapidly in percentage terms. This results from large
increases in coal consumption as western utilities shift from oil and gas
generation to coal and nuclear. See Table IV-2.
The 1995 regional estimates should be heavily discounted due to the
huge uncertainties associated with forecasting emissions at the regional
level so many years in the future.
SO Emissions Under Alternative NSPS
2
The effects of alternative NSPS on SC>2 emissions are presented in
Table TV-3 through IV-5.
for sulfur dioxide, the 90 percent removal requirement results in the
least emissions on a national basis of the cases tested, followed in order
of increasing emissions by 0.5 pounds, 80 percent removal, and 1.2 pounds.
The effect of these alternatives is illustrated well in terms of the
categories of plants that would be affected. Except for small differences
in the utilization of existing plants, emissions for all plants subject to
SIP's and current NSPS would be constant. Only emissions from plants coming
on line in 1983 or thereafter would be affected. See Table IV-6.
ICF INCORPORATED
-------
-80-
TABLE IV-2
REGIONAL ELECTRIC UTILITY SULFUR DIOXIDE
EMISSIONS UNDER THE CURRENT NSPS
(10 tons per year)
Reference Case I Reference Case II
Region
^/
East-
Midwest—
West South Central-
West-
1975
9.
9.
0.
0.
19
42
41
51
1985
9.43
7.96
2.07
1.12
1990
9.63
8.16
2.38
1.13
1995
9.
8.
2.
1.
05
35
56
03
1985
9
7
2
1
.43
.96
.07
.12
1990
10.
8.
2.
1.
78
74
55
27
1995
10.83
10.07
3.35
1.60
National 18.57 20.57 21.31 21.00 20.57 23.33 25.85
1/ Includes census regions New England, Middle Atlantic, South Atlantic,
and East South Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
4/ Includes census regions Mountain and Pacific. These emissions estimates
~ are slightly low since a data input error for Arizona and New Mexico
overstated the cost of meeting the state new source performance standards
there. Thus, less coal was built that would have been with correct (i.e.,
lower) scrubber costs.
ICF
INCORPORATED
-------
-81-
TABLE IV-3
1985 REGIONAL UTILITY SCK EMISSIONS
UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS
(10 tons per year)
Reqion
East-
2/
Midwest-
West South Central-'
4/
West-
Nat ional.
3/
29.43
Reference Case I & II
1.2 Ibs.
9.43
7.96
2.07
1.12
90%
9.22
7.98
1.78
1.11
80%
9.32
8.06
1.90
1.12
0.5 Ib. (Initial)
9.22
8.06
1.81
1.12
20.08 20.37
20.22
V includes census regions New England, Middle Atlantic, South Atlantic,
and East South Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
4/ Includes census regions Mountain and Pacific. These emissions estimates
~ are slightly low since a data input error for Arizona and New Mexico
overstated the cost of meeting the state new source performance standards
there. Thus, less coal was built that would have been with correct (i.e.,
lower) scrubber costs. This error applies only to the 1.2 Ibs. and 80
percent caes.
ICF INCORPORATED
-------
TABLE IV-4
1990 REGIONAL UTILITY SO EMISSIONS
UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS
(10 tons per year)
National
Reference Case II
Census Region
East-
Midwest—
West South.
Central—
4/
West-
1 .2
9
8
2
1
Ibs.
.63
.16
.38
.13
90%
8.99
7.97
1.74
1 .08
80%
9.47
8.12
1.96
1 .13
0.5 Ib.
8
8
1
1
( Initial)
.99
. 18
.89
.11
1.2 Ibs.
10.78
8.74
2.55
1.27
90%
9.73
8.27
1 .80
1.12
80%
10.53
8.58
2.05
1.21
0.5 Ib.
9
8
2
1
(Initial)
.72
.54
.02
.19
i
00
to
21.31
19.78 20.68
20. 18
23.33
20.90 22.37
21 .48
V Includes census regions New England, Middle Atlantic, South Atlantic, and East South Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
4/ includes census regions Mountain and Pacific. These emissions estimates are slightly low since a data input
~ error for Arizona and New Mexico overstated the cost of meeting the state new source performance standards
there. Thus, let's coal was built that would have been with correct (i.e., lower) scrubber costs. This
error applies only to the 1.2 Ibs. and 80 percent cases.
o
-n
I
3
I
O
-------
TABLE IV-5
National
1935 ?_E:GIO;:AL UTILITY so EMISSIONS
WDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS
( 10 tons per year)
Reference Case II
East-
2/
Midwest-
West South
Central—
4/
West-
1 .2
9
8
2
1
Ibs.
.05
.35
.56
.03
Refer
90%
8.68
7.91
1.83
0.96
eriCe t_as
80%
9.09
8. 14
2.07
0.99
;es J.
0.5 lb.
8
8
1
1
(Initial)
.69
.06
.97
.10
1.2 Ibs.
10.83
10.07
3.35
1 .60
90%
9.79
8.57
2.03
1.25
80%
10.66
9.35
2.38
1.33
0.5 lb.
9
9
2
1
(Initial)
.83
.13
.45
.40
21 .00
19.38 20.29
19.82
25.85 21.56 23.73
22.81
oo
LO
I
V includes census regions New England, Middle Atlantic, South Atlantic, and East South Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
there. Thus, less coal was built that would have been with correct (i.e., lower) scrubber costs
error applies only to the 1.2 Ibs. and 80 percent cases.
o
•n
I
o
-------
-84-
TABLE IV-6
1990 SULFUR EMISSIONS
(10 tons per year)
REFERENCE CASE II
1.2 Ibs.
90%
80%
0.5 Ib. (Initial)
Coal Plants
Existing
NSPS*
ANSPS**
Oil/Gas
Total
14.25
2.61
4.18
2.30
23.33
14.29
2.63
1.49
2.47
20.90
14.27
2.62
3.01
2.46
22.37
14.54
2.63
1.85
2.46
21.48
* Plants subject to current NSPS (coming on line by 1983).
** Plants that would be subject to alternative NSPS (coming
on line in 1983 and thereafter).
UTILITY CAPITAL EXPENDITURES AND ANNUALIZED COSTS
Cumulative utility capital expenditures were estimated for the scenarios
employed in Phase I. These estimates include the capital cost of most plants
and equipment projected to come on line between 1976 and 1990. Excluded from
the estimates were the costs of new hydro capacity, new local transmission and
distribution equipment and lines, and new oil steam plants currently under
construction. Since these capital expenditures would have been constant
across scenarios because the capacities involved were locked into the model,
their omission does not bias the results of the analysis.
Under Reference Case I the capital expenditure increased by at most $1.9
billion with a small decrease in the 0.5-lb. case. The decrease occurs
because less coal-fired capacity is built. However, total costs increase
under the 0.5-lb. case because fuel costs are higher because of the increased
oil consumption. Under Reference Case II, capital expenditures increase by
$1.3 billion to $3 billion. See Table IV-7 for the cumulative utility capital
expenditures.
Annualized utility costs- also were estimated for the scenarios analyzed
in Phase I. These costs include O&M and fuel costs for all plants (existing and
new) and annualized costs for capital expenditures made after 1975. These costs
1/ Annualized utility costs are an annuity with the same present value as the
actual, stream of costs the utility would experience. They differ from
rates in that rates reflect the actual costs for the utility which change
over time. The annualized costs are constant in real terms and are a good
measure of the present value of consumer costs.
ICF
INCORPORATED
-------
TABLE IV-7
CUMULATIVE UTILITY CAPITAL EXPENDITURES
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
FROM 1976 THROUGH 1989-
(in 109 $ - in late 1977 $'s)
Reference Case II
Coal
Scrubber
Convert— .
3/
Nuclear— ,
Oil/Gas-
Long-Distance
Transmission
Local Transmission
and Distribution —
Total
1.2 Ibs.
283.2
10.7
1.1
131.0
20.3
4.3
*
283.2
1/ Hydro electric and capital costs
related capital
2/ Capital cost of
90%
283.
19.
0.
131.
23.
2.
283.
80%
4 108.7
9 19.5
8 0.8
0 131.0
4 22.5
8 2.6
* *
4 285.1
are not included.
expenditures would not
vary among
0.5 Ib.
(Initial) 1
105.
19.
0.
131.
23.
2.
283.
0
5
8
0
7
9
*
0
.2 Ibs
158.7
12.6
1.2
131.0
25.9
3.1
*
332.6
However, since this
90%
143.2
29.2
1.1
131.0
29.6
1 .8
*
336.0
capacity
80%
143.
27.
0.
131.
29.
1 .
333.
was
(
5
2
9
U
6
6
*
9
0.5 Ib.
Initial)
143.5
28.7
1.0
131.0
29.8
• 0
336.0
fixed the
scenarios.
converting existing bituminous boilers to western
3/ Nuclear expenditures do not vary
{} 4/ Oil/gas steam capacity currently
Tl
z
o
included in this
related capital
across scenarios
under
subbituminous
because the amount of
construction was
estimate. However since this capacity
expenditures would not
vary among
them.
nuclear
coal.
capacity
treated as existing capacity
remained
fixed
and
across scenarios,
was fixed
is not
the
03
cn
l
5/ Not estimated.
-------
-86-
are only for the utility sector and comprise only a portion of the model's
objective function.
The annualized costs are presented as increases from the current NSPS
case in billions of dollars and as percentage increase in electricity rates
from the current NSPS case. The cost of the alternative standards is roughly
$2 billion per year in 1990 under the high electricity growth rate (Reference
Case II) and $1 billion per year under the low growth rate (Reference Case I).
The annualized costs decrease in the West because this area of the country
already has tight environmental standards and the tighter ANSPS had little
effect on capital costs. In fact, the tighter ANSPS makes Western coal less
attractive to the rest of the country, thus, lowering the fuel costs for the
Western utilities. The lower fuel costs lead to the lower annualized costs in
the West. See Tables IV-8 through IV-10 for the annualized utility costs.
IMPACTS OF 0.8 lb._SO /MMBtu EMISSION LIMITATION
This section summarizes the 1990 forecast for a 0.8 lb.S02 /mmbtu
emission limitations for coal-fired plants coming on line after 1982.
We assumed that the 0.8-lb. standard was an annual average and thus, did
not require that the lowest sulfur coals be scrubbed. Reference Case II
electricity growth rates were employed. Complete model results for this
case are presented in Appendix F.
The 0.8-lb. case increased coal production in tons is above that for the
current NSPS case. This occurred because of the significant increase in
Western low btu coals. Northern Great Plains production was forecast to be
826 million tons in 1990 compared to 810 million tons under the current NSPS.
The total btu's of coal mined decreased slightly, from 37.1 quads under the
current NSPS to 37.0 quads. Western coal shipped East increased to 481 million
tons in 1990 compared to 456 million tons under the current NSPS. The cause
of this boom in Western production was the development of substantial reserves
of the lowest sulfur coals in Montana. That coal could be burned in ANSPS
plants without scrubbers. Oil consumption increased from the current NSPS
only slightly (0.1 quad) and was 0.6 quad less than the level projected under
the 90 percent standard. Emissions were only slightly lower than under the
current NSPS, falling by 4 percent. Annualized costs increase by only $0.3
billion per year compared with the $1.94 billion per year increase under the
90 percent ANSPS.
Nat^ional Coal Production
Relative to current standards, national coal production in tons would
increase somewhat but in btu's would decrease slightly. This decrease in
the average heat content would result from increased use of Midwestern and
Western coals. The slight decrease in btu's results from a slight increase
in utility oil consumption. See Table IV-11.
ICF INCORPORATED
-------
TABLE IV-8
1985 INCREASES IN ANNUALIZED UTILITY COSTS
UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS
(109 $ - in late 1977 $'s)
Reference Cases I & II
Increase In Annualized Cost
From the Current NSPS Percentage Increases
MO < i« I-*-" 1^77 S's) In Electricity Rates
0
Tl
INCORPORATED
Census Region
East-
Midwest—
West South Central-
4/
West-
National
"\/ Includes census
Central.
2/ Includes census
3/ Includes census
4/ Includes census
90% 80% 0.5 Ib. (Initial) 90% 80% 0.5 ib
0.11 0.10 0.10 0.2 0.2
0.06 0.03 0.09 0.2 0.1
0.26 0.22 0.22 1.7 1.5
<0. 01) (0.02) (0.01) (0.1) (0.1)
0.43 0.34 0.42 0.4 0.3
regions New England, Middle Atlantic, South Atlantic, and East
regions East North Central and West North Central.
region West South Central.
regions Mountain and Pacific.
. (Initial)
0.2
0.3
1.5
(0.1)
0.4
South
-------
-88-
TABLE IV-9
1990 INCREASES IN ANNUALIZED UTILITY COSTS
AND ELECTRICITY RATES UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(109 $ - in late 1977 S's)
Reference Caae I
increase In
From the
( 10 S in
East-
Midwest-
West South Central—
4/
National
90%
0.49
0.35
0.40
(0.04)
1.22
80%
0.42
0.30
0.36
(0.04)
1.04
Increase In
East-
Midwest-
West South Central-
west*''
National
Fr
( 10
90%
0.94
0.63
0.42
(0.07)
1.94
om the
^ $ in
80%
0.76
0.51
0.36
(0.08)
1.57
Annualized Cost
Current NSPS
late 1977 S'e)
0.5 Ib. (Initial)
0.50
0.37
0.42
(0.05)
1.25
Reference
Annualized Cost
Current NSPS
late 1977 $'a)
0.5 Ib. (Initial)
0.96
0.64
0.45
(0.10)
1.95
Percentage Increases
In Electricity Rates
90% 80% 0.
0.8 0.7
1.0 0.8
2.0 1.8
(0.2) (0.2)
0.9 0.7
Case II
Percentage
5 Ib. (Initial)
0.8
1.0
2.1
(0.2)
0.9
Increases
in Electricity Rates
90% 80% 0,
1.4 1.1
1.6 1.3
2.0 1.7
(0.3) (0.4)
1.3 1.0
.5 Ib. (Initial)
1.4
1.6
2.1
(0^4)
1.3
\J includes census regions New England, Middle Atlantic, South Atlantic, and East South
Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
4/ Includes census regions Mountain and Pacific.
-------
-89-
TABLE IV-10
1995 INCREASES IN ANNUALIZED UTILITY COSTS
AND ELECTRICITY RATES UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
(109 S - in late 1977 $'s)
Increase In
From the
(10 S in
East-
Midwest-
West South Central—
West-
National
90%
0.49
0.39
0.71
(0.02)
1.57
80%
0.22
0.34
0.69
(0.04)
1.21
Increase In
From the
(10 S in
East-
Midwest-
West South Central-
west*'
National
90%
1.09
1.32
0.62
0.22
3.25
80%
0.90
1.13
0.50
0.14
2.67
Annualized Cost
Current NSPS
late 1977 $'s)
0.5 Ib. (Initial)
0.22
0.38
0.64
(0.02)
1.26
Reference
Annualized Cost
Current NSPS
late 1977 $'s)
0.5 Ib. (Initial)
0.95
1.34
0.72
0.18
3.19
Percentage Increases
In Electricity Rates
90% 80% 0.
0.6 0.3
0.8 0.7
2.8 2.7
(0.1) (0.2)
0.9 0.7
Case II
5 Ib. (Initial)
0.3
0.8
2.5
(0.1)
0.7
Percentage Increases
In Electricity Rates
90% 80* 0
1.2 1.0
2.4 2.1
2.1 1.7
0.7 0.5
1.6 1.3
.5 Ib. (Initial)
1.0
2.5
2.4
0.6
K5
\J Includes census regions New England, Middle Atlantic, South Atlantic, and East South
Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
4/ Includes census regions Mountain and Pacific.
-------
-90-
TABLE IV-11
1990 NATIONAL COAL PRODUCTION
Reference Case II
1.2 Ibs. 0.8 Ib. 90%
Production
(10^ tons) 1,768 1,780 1,711
(10 btu's) 37.1 37.0 36.6
Average Heat Content
(10 btu/ton) 21.0 20.8 21.4
Relative to the 90 percent case, tons and btu's would be up, as a
result of .a lower average heat content (more Western coal) and reduced oil
consumption in the utility sector (the increased cost of coal relative to oil
in intermediate load is substantially reduced from the 90 percent case).
Regional Production
Relative to current standards, regional production would not change
substantially. Eastern low sulfur coal production, primarily from Central
Appalachia, would be down somewhat because the quantity of low sulfur coal
in the East that could meet a 0.8-lb. standard without a scrubber is
extremely limited, and most of this would go for metallurgical purposes.
Correspondingly, high sulfur coal production in Appalachia and the Midwest
would be up somewhat. Western production would be increased slightly and
more Western coal would be consumed in the East since the lower sulfur con-
tent of Western coal would permit some of it to be burned without scrubbers
and most of it to be burned with only partial scrubbing. See Table IV-12.
TABLE IV-12
1990 REGIONAL COAL PRODUCTION
(10 tons)
Reference Case II
1.2 Ibs. 0.8 Ib. 90%
Northern Appalachia 205 208 258
Central and Southern
Appalachia 237 210 218
Midwest and Central 298 307 364
Northern Great Plains 810 826 651
Rest of West 218 229 220
Total 1,768 1,780 1,711
Western Coal
Consumed in East 455 481 299
ICF
INCORPORATED
-------
-91-
Relative to a 90 percent standard, production would be down in the
East and up in the West. Under a 0.8-lb. standard the lower sulfur content
of Western coal would have value in eliminating or reducing the need for
scrubbers, whereas a 90 percent removal requirement would eliminate most of
this value.
Coal Prices
The effect on coal prices of a 0.8-lb. standard would be insignificant
relative to either current standards or a 90 percent standard, with the
exception of a slight drop in the price of low sulfur coal in the East.
See Table IV-13.
Generation Capacity
Relative to current standards, coal generation capacity would be down
slightly, because new coal capacity would be more expensive. Correspondingly,
oil capacity would increase slightly. See Table IV-14.
Relative to a 90 percent standard, coal capacity would be up and oil
capacity would be down, because the cost of new coal capacity would not
increase as much. The 0.8-lb. case is much closer to the 1.2-lbs. case
than the 90 percent case.
Scrubber Capacity
Relative to current standards, scrubber capacity would increase by
nearly 20 percent, because eastern low sulfur coal could generally not be
consumed without a scrubber. The average percent removal would increase to
meet the reduced emission limitations. See Table IV-15.
Relative to a 90 percent removal requirement, scrubber capacity would
be less by about 20 percent because no scrubber would be required on the
lowest sulfur coals, and the average percent removal would be lower as well.
ICF INCORPORATED
-------
-92-
TABLE IV-13
DELIVERED COAL PRICES TO ELECTRIC UTILITIES
SECTOR IN 1990 ALTERNATIVE NSPS
S/10 btu's (1977 $'s)
REFERENCE CASE II
1.2 Ibs.
0.8 Ibs.
90%
Northeast . .
- High Sulfur-
- Medium Sulfur—
- Low Sulfur—
1.30
1.38
1.98
1.28
1.38
2.20
1.30
1.36
2.17
Mid-Atlantic
- High Sulfur
- Medium Sulfur
- Low Sulfur
1.20
1.37
1.60
1.20
1.35
1.43
1.28
1.35
1.99
South Atlantic
- High Sulfur
- Medium Sulfur
- Low Sulfur
1.17
1.41
1.62
1.25
1.41
1.47
1.31
1.39
1.58
East North Central
- High Sulfur 1.08 1.08 1.15
- Medium Sulfur 1.24 1.23 1.26
- Low Sulfur 1.37 1.37 1.48
East South Central
- High Sulfur 1.07 1.08
- Medium Sulfur 1.15 1.17
- Low Sulfur 1.38 1.33
1.15
1.19
1.35
West North Central
- High Sulfur 1.03 1.03 1.10
- Medium Sulfur 0.83 0.81 0.84
- Low Sulfur 1.04 1.05 0.98
Wost South Central
- High Sulfur 1.02 1.05 1.29
- Medium Sulfur 0.62 0.71 0.79
- Low Sulfur 1.30 1.30 1.25
Mountain
- High Sulfur
- Medium Sulfur
- Low Sulfur
0.65
0.82
0.66
0.81
0.65
0.78
Pacific
- High Sulfur
- Medium Sulfur
- Low Sulfur
1.28
1.22
1.33
1.19
1.34
1.13
I/ Greater than 1.67 pounds of sulfur per million btu's (roughly greater than two
percent sulfur by weight).
2/ 0.61 to 1.67 pounds of sulfur per million btu'e (new source performance stan-
~ dards to roughly two percent).
3/ Moots new source performance standards (0.6 pounds of sulfur or less).
NOTE; Certain anomalies in the behavior of prices between scenarios are
apparent, such as low sulfur prices in the Northeast region rising
with the tighter standards. This is due to the averaging (consumption
weighted) associated with aggregating the 35 demand regions into nine
larger regions, where expensive coal in one demand region (e.g.,
Maine) is averaged with less expensive coal in another region (e.g.,
Massachusetts) and where the relative volumes of these coals change
between scenarios.
-------
-93-
TABLE IV-14
1990 GENERATION CAPACITY
(GW)
Nuclear
Coal
Oil/Gas
Steam
Combined Cycle
Turbine
Hydro and Others
Total
Percent of Total
Nuclear
Coal
Oil/Gas
Other
Reference Case II
1.2 Ibs.
176.7
465.0
301.4
143.6
15.3
142.5
87.6
1030.7
17
45
29
8
0.8 Ib.
176.7
459.2
307.9
143.5
15.9
148.5
86.8
1030.6
17
45
30
8
90%
176.7
444.6
322.7
143.5
15.3
163.9
86.4
1030.4
17
43
31
8
TABLE IV-15
1990 SCRUBBER CAPACITY
Capacity Scrubbed (GW)
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
REFERENCE CASE II
1.2 Ibs.
103.4
40.4
28.7
34.2
66.1
64.5
70.6
64.5
0.8 Ib.
120.3
37.4
27.7
55.2
71.7
64.5
69.4
77.8
90%
147.6
36.8
23.9
86.9
80.3
64.2
69.8
90.0
ICF INCORPORATED
-------
-94-
Utility Fuel Consumption
increased relative to oil. See Table IV-16.
TABLE IV-16
1990 UTILITY FUEL CONSUMPTION
(quadrillion btu's)
Reference Case II
Hi," Sulfur
Medium Sulfur
Lo. Sulfur
1.2 Ibs.
23.7
4.1
9.1
10.5
6.4
13.7
43.8
0.8 Ib.
23.7
4.7
9.2
9.8
6.5
13.6
43.8
90%
23.3
7.4
10.6
5.3
7.1
13.6
44.0
Total Fossil
Nuclear and Other
Total
Percent of Total
S4 54 3J
Coal ..--
Oil and Gas 15
Nuclear and Others 31 31
Relative to a 90 percent removal requirement, less high sulfur coal
requirement.
Emissions
Relative to current standards, national sulfur emissions would be
reduced about five percent. Relative to a 90 percent standard, sulfur
emissions would be up about 10 percent. See Table IV-17.
ICF
INCORPORATED
-------
-95-
TABLE IV-17
1990 SO EMISSIONS
6
10 tons per year
West South Central
1.2 Ibs. 0.8 Ibs. 90%
10.78 10.17 9.73
8.74 8.63 8.27
2.55 2.29 1.80
1.27 1.26 1.12
23.33 22.34 20.90
Oil/Gas 2.30 2.33 2.47
Coal
Existing 14.25 14.20 14.29
NSPS 2.61 2.48 2.63
ANSPS 4.18 3.33 1-49
National 23.33 22.34 20.90
Cumulative Utility Capital Expenditures and Annualized Costs
The cumulative utility capital expenditures increase by $3.2 billion
from the current NSPS level of $332.6 billion. This increase is almost as
much as the increase under the 90 percent standard but has different com-
ponents. Coal-fired capacity investments are $14.4 billion greater under
the 0.8-lb. standard than under the 90 percent standard. Scrubber and
oil/gas capacity expenditures are $14.8 billion and $2.46 billion less
respectively, under the 0.8-lb. standard than under the 90 percent standard,
Lomj-distance transmission expenditures increased by $1.7 billion under
the 0.8-lb. scenario from the 90 percent scenario. See Table IV-18.
Annual ize.l utility costs would increase by $0.27 billion per year
in 1990 from the current NSPS level and decreases under a 90 percent
standard by $1.62 billion. Electricity rates would increase by 0.2 percent
under the 0.8-lb. standard compared with a 1.3 percent increase under the
90 porcent standard. The declines in annualized costs in the Midwest and
the West result from lower fuel costs for plant using Western coal. The
west South Central region is forecast to have the greatest rate increases.
See Table IV-19.
ICF INCORPORATED
-------
-96-
TABLE IV-18
CUMULATIVE CAPITAL EXPENDITURES UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE
STANDARDS FROM 1976 THROUGH 1989-
(in 109 $ - in late 1977 $'s)
1.2 Ibs. 0.8 Ib. 90%
Coal
Scrubber
2/
Convert—
Nuclear—
Oil/Gas-/
Long-Distance
Transmission 3.1 3.5 1.8
Local Transmission
and Distribution- * *_ *
158.7
12.6
1.2
131.0
25.9
157.6
15.4
1.0
131.0
27.2
143.2
29.2
1.1
131.0
29.6
Total 332.6 335.8 336.0
I/ Hydro electric capital costs are not included. However, since this
capacity was fixed, the related capital expenditures would not vary
among scenarios.
2/ Capital cost of converting existing bituminous boilers to Wesern sub-
bituminous coal.
3/ Nuclear expenditures do not vary across scenarios because the amount of
nuclear capacity was fixed.
4/ Oil/gas capacity currently under construction was treated as existing
capacity and is not included in this estimate. However, since this
capacity remained fixed across scenarios, the related capital expendi-
tures would not vary among them.
5/ Not estimated.
ICF
INCORPORATED
-------
-97-
TABLE IV-19
1990 INCREASES IN ANNUALIZED UTILITY COSTS
AND ELECTRICITY RATES UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
Midwest-
West South
Central-
4/
West-
National
Increase in Annualized Costs
From the Current NSPS
(10 $ - in late 1977 $'s)
Percentage Increases In
Electricity Rates
0.8 Ib.
0.14
(0.05)
0.26
(0.08)
0.27
90%
0.94
0.63
0.42
(0.07)
1.94
0.8 Ib.
0.2
(0.1)
1.2
(0.4)
0.2
90%
1.4
1.6
2.0
(0.3)
1.3
1/ Includes census regions New England, Middle Atlantic, South Atlantic and
East South Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
4/ Includes census regions Mountain and Pacific.
ICF
INCORPORATED
-------
-98-
IMPACTS OF REVISED PARTIAL SCRUBBING COSTS
After the Phase I model runs were completed, PEDCo Environmental per-
formed further work which lead to a refinement of the scrubber costs esti-
mates. This section explains the revisions made and analyzes their effect on
several factors: scrubber capacity; removal percentages; shifts of capacity
between load categories; regional shifts in coal production and consumption;
changes in oil consumption levels; SC>2 emissions; capital expenditures; and
annualized costs. The results of the revised case are compared with the
results from the initial scrubber cost estimates, the current NSPS case and
the 90 percent case. See Appendix E for complete results for the 0.5 Ib.
SO /rnmbtu case with revised scrubber costs.
Revised Scrubber Costs
Table IV-20 gives the initial scrubber cost estimates used in Phase I
and the revised estimates used in Phase II. The old estimates assumed that
partial scrubbing costs were related to the required removal efficiency and
not to the sulfur in the coal. Since those estimates were made, PEDCo
provided information that showed that partial scrubbing costs are related to
both. Thus, the new estimates show a greater correlation between capital
costs and the sulfur level of the coal being scrubbed than do the old
estimates. See Appendix C for a more complete discussion of the scrubber
cost estimates.- The key diference between the initial and revised esti-
mates is that the costs of scrubbing the lowest sulfur coals was reduced by
about $20/kw or by about 25 to 30 percent. This change turned out to have
a substantial impact, since partial scrubbing became much more attractive and
was forecast to be utilized to a much greater extent.
Table IV-21 shows the increase in scrubber capacity and decrease in
average percent removal (i.e., more partial scrubbing) that occurs with the
revised scrubber cost estimates. The ANSPS plants account for the bulk of
these shifts, with scrubber capacity going up by 15.3 GW (from 151 GW to
166.3 GW) and percent removal dropping by 10 percent (from 81.1 percent to
73.2 percent). The increase in scrubber capacity is due to more coal capacity
forecast to be built because the costs of burning coal relative to oil in
intermediate load were reduced by the revised partial scrubbing cost esti-
mates. The average percent removal drops because more partial scrubbing is
forecast to be employed.
I/ PEDCo has since -developed scrubber costs for each of the culfur levels
used in CEUM. These estimates fall between the initial and revised esti-
mates reported here but are closer to the revised estimates. The complete
set of PEDCo estimates has been used to make further forecasts. These
forecasts will be presented in a separate document. As of August 1978
(when this footnote was drafted), there was a possibility that the partial
scrubbing costs developed by PEDCo would be revised.
ICF
INCORPORATED
-------
-99-
TABLE IV-20
INITIAL AND REVISED CAPITAL COST ESTIMATES
FOR PARTIAL SCRUBBING FOR ANSPS PLANTS
($/kw - in 1975 $'s)
Standard
(Ibs. SO /mmbtu)
Coal Sulfur Level"'
V
0.50
0.33^
0.24^
Estimate
Initial
Revised
61
41
Initial 83
Revised- 83
Initial . 96
Revised- 96
B_
77
57
96
96
96
96
D
83
72
96
96
96
96
92
91
96
96
X
X
96
96
X
X
X
X
X
X
X
X
X
X
1/ Sulfur level definitions are:
A up to 0.4 Ib. S/mmbtu
B 0.41 to 0.60 Ib. S/mmbtu
D 0.61 to 0.83 Ib. S/mmbtu
F 0.84 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.50 Ibs. S/mmbtu
2/ These costs applied in regions with SIP's tighter than the Federal
new source performance standard.
3/ The model actually saw costs 12 percent higher than those specified
here because of a programming error. This error is expected to make
little or no difference in forecasts.
ICF
INCORPORATED
-------
-100-
TABLE IV-21
IMPACT OF REVISED PARTIAL SCRUBBING ESTIMATES ON 1990
SCRUBBER CAPACITY AND AVERAGE PERCENT REMOVAL
(0.5-lb. SO /mmbtu standard
assumed for ANSPS plants)
Scrubber Capacity (in GW)
Existing
NSPS
ANSPS
- full
- partial
Average Percent Removal
Existing
NSPS
ANSPS
- full
- partial
Initial Estimates
210.8
36.2
23.6
151.0
80.3
70.8
77.4
66.7
70.5
81.1
90.0
70.9
Revised Estimates
225.9
36.5
23.1
166.3
65.81
100.41
71.5 .
64.1
70.7
73.2
90.0
62.2
Table IV-22 shows the shifts of capacity between load categories.
ANSPS capacity increases by 15.2 GW,-' with baseload capacity increasing by
27.4 GW and intermediate-load capacity decreasing by 12.2 GW. The increase
in ANSPS baseload capacity causes existing and NSPS coal capacity (and
some oil/gas capacity) to operate in intermediate rather than baseload, which
in turn bumps oil/gas capacity into seasonal peak load. The final result is
that 4 GW of combined cycle and 11 GW of turbine capacity that was built in
the case with the initial partial scrubbing estimates are no longer built.
The substitution of coal for oil/gas capacity leads to a decrease in oil/gas
consumption of 0.6 quad (about 300 thousand barrels per day).
The increase in partial scrubbing and ANSPS capacity and the resulting
reduction in oil capacities and consumptions are caused by the reduced
cost for partial scrubbing.
1> T~h"o" "difference between ANSPS capacity in Table IV-19 and ANSPS scrubber
capacity in Table IV-20 is caused by rounding.
ICF
INCORPORATED
-------
TABLE IV-22
IMPACT OF REVISED ESTIMATES ON CAPACITY PLANNING AND UTILIZATION IN 1990*
(in GW)
Plant Type
Coal
Existing
NSPS
ANSPS
Total
Oil/Gas
Steam
Combined Cycle
Turbine
Total
Total Fossil**
Ba
Initial
160.7
81.3
99 8
341 .8
20.0
12.5
14.5
356.3
se
Revised
Estimates
148.0
71.9
127.2
347.1
1.6
8.2
9.8
356.9
Intermediate
Initial Revised
Estimates Estimates
42.8
7.5
51.2
101.5
90.7
1.7
92.4
193.9
54.1
17.1
39.0
110.2
82.1
1.7
83.8
194.0
_ a — «-
Initial Revised
Estimates Estimates
1.1 2.5
1.1
31.8
0.6
56.9
89.3
90.4
2.5
39.0
0.9
48.0
87.9
90.4
Initial
Estimates
19.0
1.1
107.5
127.6
127.6
Peak
Revised
Estimates
20.5
1.1
105.4
127.0
127.0
Initial
Estimates
204.6
88.8
151.0
444.4
143.5
15.9
164.4
323.8
768.2
Revised
Estimates
204.6
89.0
166.2
459.8
143.5
11.9
153.4
308.5
768.3
* 0.5-lb. SO /mmbtu standard assumed for ANSPS plants.
•* capacity does not remain constant with each load category because of minor shifts in the loading of hydro capacity and small
changes in plant efficiencies caused by differences in scrubbing.
-------
-102-
Tables IV-23 through IV-26 compare summary results of the 0.5-lb.-SC>2/
mmbtu standard case under the revised scrubber cost estimates with the
current NSPS case (1.2 Ibs.), the 90-percent scrubber requirement case (90
percent), and the 0.5-lb. case, under the initial estimates of 0.5-lb.
scrubber costs. These are summarized below.
1990 Coal Production
The revised scrubber costs had a significant impact on coal production.
National production increases by 43 million tons from the previous 0.5-lb.
case, with large increases in the West (67 mmtpy) and decrease in the Midwest
(19 mmtpy), as Western low-sulfur coals are partially scrubbed in the Midwest
rather than Midwestern high-sulfur coals being fully scrubbed.
Part of the large increase in tonnage in the West results from the
lower heat content of Western subbituminous coals, with 17.3 mmbtu/ton
replacing Midwestern bituminous coals with 20 to 26 mmbtu/ton. The rest of
the increases result from reduced oil consumption (discussed below), and
hence increased coal consumption. See Table IV-23.
1990 Western Coal Shipments to the East
western coal shipments to the East increase significantly from the
previous 0.5-lb. level. This increase of 46 mmtpy or 15.5 percent is the
result of increased partial scrubbing of low-sulfur Western coals in the
Midwest. See Table IV-23.
Table IV-24 compares the regional consumption of subbituminous by ANSPS
plants between the 0.5-lb. case, with the initial scrubber costs, and the
one with the revised costs. Note that the largest increase in subbituminous
coal consumption is in the lowest sulfur category (0.4 Ib. S/mmbtu or less),
which increases from 0.637 to 1.336 quads (roughly 40 million tons).
1990 Utility Coal Consumption
Utility coal consumption increases by 0.6 quadrillion btu's, or roughly
30 million tons, from the previous 0.5-lb. case to the revised 0.5-lb. case.
This increase compensates for an equivalent decrease in utility oil con-
sumption (discussed below). The other 13-million-ton gain in production
results from the substitution of Western low-heat-content coals for
Eastern high-heat-content coals.
The gains in coal consumption occur in four regions — 0.25 quads in
the Mountain Region (see comment concerning scrubber-cost input error under
"1990 SO Emissions"); 0.24 quads in the East North Central Region; 0.4
quads in2the West North Central Region; and 0.03 quads in the East South
Central Region. The increased coal consumption in the Mountain Region
occurs in the Arizona/New Mexico area and is used to replace oil consump-
tion in California via the transmission of electricity. See Tables IV-25
and IV-26.
ICF INCORPORATED
-------
-103-
TABLE IV-23
1990 COAL PRODUCTION
(106 tons)
Reference Case II
Census Reqion
Northern Appalachia
Central Appalachia
Southern Appalachia
Total Appalachia
Midwest
Central West
Total Midwest
Eastern Northern Great Plains
Western Northern Great Plains
Total Northern Great Plains
Gulf
Rocky Mountain
Southwest
Total Rest of West
itional
1.2 Ibs.
204.8
218.5
18.0
441.3
290.6
7.4
298.0
46.1
763.5
809.6
90.0
49.1
73.7
6.2
219.0
1,767.9
456.0
90%
257.6
196.8
15.0
469.4
364.2
8.2
372.4
37.8
613.6
651.4
103.0
42.1
65.4
7.2
217.7
1,710.8
297.7
0.5 Ib.
Initial
258.0
195.7
15.2
468.9
364.2
7.8
372.0
38.9
614.4
653.3
103.0
39.0
68.3
7.2
217.6
1,711.7
296.8
0.5 Ib.
(Revised)
254 3
195.2
14.4
463.9
346.4
6. 1
352.5
38.9
675.6
714.5
103.0
38.6
74.8
7.2
223.6
1,754.5
342.8
ICF INCORPORATED
-------
-104-
TABLE IV-24
COMPARISON OF 1990 SUBBITUMINOUS COAL CONSUMPTION
BY ANSPS PLANTS BETWEEN INITIAL SCRUBBER COST CASE
AND REVISED SCRUBBER COST CASE
(in Quads)
Region
Western Pennsylvania
Northern Ohio
Michigan
Illinois
Western Tennessee
Alabama/Mississippi
North Dakota/South
Dakota/Minnesota
Kansas/Nebraska
Iowa
Arkansas/Oklahoma/
Louisiana
Montana/Wyoming/
Idaho
Utah/Nevada
Colorado
Washington/Oregon
Northern California
National
Sulfur Level
of Coal
(Ibs. S/mmbtu)
0.40
0.40
0.40
0.40
0.40
0.83
0.40
0.40
0.83
0.40
0.83
0.40
0.83
1.67
0.83
0.83
0.83
0.40
0.40
0.40
0.83
1.67
Initial
Estimate
Case
_
_
_
0.014
-
0.132
_
0.141
0.131
_
0.475
-
0.144
0.013
0.140
0.085
0.406
0.637
1.044
Revised
Estimate
Case
0.057
0.008
0.309
0.166
0.018
0.101
0.130
0.059
0.085
0.062
0.085
0.056
0.541
0.026
0.144
0.012
0.141
0.085
0.386
1.336
1.109
TOTAL
1.681
0.026
2.471
ICF
INCORPORATED
-------
-105-
TABLE IV-25
1990 UTILITY COAL CONSUMPTION
(in quadrillion btu's)
Reference Case II
Census Region
New England
Middle Atlantic*
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mountain
Pacific
1.2
0
2
4
5
2
2
3
1
0
Ibs.
.502
.749X
7.181
.524
.784
.392
.180
.600
.561
0.5 Ib. 0.5 Ib.
90% (Initial) (Revised)
0
2
4
5
2
2
3
1
0
.509
.211.
6.980
.274
.755
.345
.236
.629
.557
0
2
4
5
2
2
3
1
0
.509
.223.
6.970
.747'
.276
.764
.355
.223
.590
.600
0.
2.
4.
5.
2.
2.
3.
1.
0.
508
785'
512
798
393
254
840
616
6.979
Nat ionnl
23.722
23.284
23.287
23.899
* Decline in Middle Atlantic coal consumption results largely from increased
electricity transmission from West Virginia to Pennsylvania and thus, a
shift in consumption from one region to the other.
ICF
INCORPORATED
-------
-106-
TABLE IV-26
1990 UTILITY OIL CONSUMPTION
(in quadrillion btu's)
Census Region
New England
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mountain
Pacific
National
1.2 Ibs.
0.406
0.754
1.059
0.605
0.267
0.277
1.376
0.153
1.474
Reference
90%
0.411
0.848
1.252
0.907
0.325
0.337
1.391
0.161
1.435
Case II
0.5 Ib.
(Initial)
0.411
0.850
1.252
0.907
0.314
0.346
1.391
0.161
1.438
0.5 Ib.
(Revised)
0.411
0.845
1.252
0.650
0.279
0.280
1.376
0.157
1.219
6.369
7.066
7.069
6.469
ICF
INCORPORATED
-------
-107-
1990 Utility Oil Consumption
The revised scrubber costs lead to a decline in oil consumption of 0.6
quads or roughly 0.3 million barrels per day from the previous 0.5-lb. case
to the revised 0.5-lb. case. The largest declines occur where coal consumption
increases, in the East North Central Region (0.26 quads), the East South
Central Region (0.04 quads) the West North Central Region (0.07 quads), and
the Pacific Region (0.22 quads).
The decline in the Pacific Region is the result of a modeling error,
since additional coal-fired capacity is being built in Arizona/New Mexico to
replace the oil-fired capacity in Southern California. However, as discussed
above, the increase in coal-fired capacity is the result of the scrubber
costs for the tighter standard being less than the costs used for the other
cases.
The decline in oil consumption elsewhere is the result of reducing the
cost of using low-sulfur coal in ANSPS plants. These plants are used in
baseload, bumping the NSPS and existing plants into intermediate load, which
in turn pushes existing oil/gas capacity to lower capacity factors, reducing
the amount of combined cycle and turbine capacity that is built. The existing
steam plants are operated at lower capacity factors, reducing the amount of
oil/gas that is consumed. See Table IV-20 for changes in capacity and loadings.
See Table IV-26 for utility oil consumption.
^990 SO Emissions
The revised scrubber costs show essentially the same national SC>2
emissions as did the initial scrubber estimates in the 0.5-lb. case.
See Table IV-27.
There are slightly lower emissions in the East, because more partial
scrubbing with a 0.5-lb. emission limitation is used with the revised scrubber
cases, rather than full scrubbing on high-sulfur coal with an emissions rate
greater than 0.5 pound. Also, more ANSPS capacity is built and operated at
baseload, so that NSPS and existing capacity, with higher emission rates than
ANSPS capacity, is operated at lower loads and hence emits less.
These emission reductions are partially offset by a small increase
in emissions in the West. The emissions are up in the West
because 1) low-sulfur coal is being partially scrubbed rather than fully
scrubbed and 2) coal use there is increased to generate electricity for trans
mission to southern California where it reduces the loads of oil plants.
This increased coal use in the West is probably the result of a data input
error causing scrubber costs in the Arizona/New Mexico region to decline with
the tighter 0.5-lb. SO /mmbtu standard. Thus, coal-fired generation becomes
cheaper under the tighter standards, and the model builds more coal-fired units
in that region. Correcting this data error would cause the 0.5-lb. revised case
to stay the same while emissions in the 1.2-lb. case to decrease because more
coal-fired capacity would have been built given the correct (i.e., lower)
scrubber costs and the emissions from ANSPS coal plants would have been less
than those from existing oil plants.
ICF
INCORPORATED
-------
-108-
TAUI..I-J IV-27
1990 SO EMISSIONS
(10 tons)
Midwest-
West South Central-
West—
National
-
Reference Case II
1.2 Ibs.
10.78
8.74
2.55
1.27
90%
9.73
8.27
1.80
1.12
0.5 Ib.
(Initial)
9.72
8.54
2.02
1.19
0.5 Ib.
(Revised)
9.63
8.42
2.02
1.23
23.33 20.90 21.48
21.30
1/ Includes census regions New England, Middle Atlantic, South
Atlantic, and East South Central.
2/ Includes census regions East North Central and West North
Central.
3/ Includes census region West South Central.
4/ Includes census regions Mountain and Pacific. These emissions
~ estimates are slightly low since a data input error for Arizona
and New Mexico overstated the cost of meeting the state new
source performance standards there. Thus, less coal was built
that would have been with correct (i.e., lower) scrubber costs.
This error applies only to the 1.2-lbs. case.
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Cumulative Utility Capital Expenditures and Annualized Costs
The revised scrubber costs increased cumulative capital expenditures con-
siderably. The $7.3 billion increase from the 0.5-lb. case with the initial
scrubber costs is caused by a $10.6 billion increase in coal-fired capacity
expenditures with a $3.2 billion decline in oil/gas expenditures. Scrubber
costs decreased by only $0.8 billion. See Table IV-28.
The annualized cost increase for their revised scrubber cost case is
only two-thirds of the increase experienced with the initial scrubber costs.
The national increase in electricity rates decreased from 1.3 percent to 0.9
percent. The West South Central region experienced the largest increase in
rates (1.7 percent) with the West experiencing a decline in rates. The
decline stems from the decline in demand for Western coal in the East. The
reduction in demand lowers the cost of coal to the Western utilities. See
Table IV-29.
IMPACTS OF ALTERNATIVE FLOORS. CEILINGS AND EXEMPTIONS
As part of the Phase II analysis, ICF analyzed a set of nine alterna-
tive new source .performance standards requiring 85 percent removal on a
24-hour basis.- The structure for each case included a specified floor
(the emissions rate below which 85 percent removal is no longer required
and ceiling (i.e., maximum average emissions rate over a 24-hour period) in
pounds of S00 per million btu's of coal burned by power plants. Each case
also includea either the allowance or the absence of an exemption from the
ceiling during three days per month. The nine cases were defined as follows:
1. 0.2 floor, 1.2 ceiling, with exemption.
2.
3.
4.
5.
6.
7.
8.
0.
0.
0.
0.
0.
0.
0.
2
2
2
5
5
5
5
floor,
floor,
floor,
floor,
floor,
floor,
floor,
1
0
0
1
1
0
0
.2
.8
.8
.2
.2
.8
.8
ceiling,
ceiling,
ceiling,
ceiling,
ceiling,
ceiling,
ceiling,
without exemption
with exemption.
without exemption
with exemption.
without exemption
with exemption.
without exemption
9. 0.8 floor, 1.2 ceiling, with exemption,
Because of more recent work done by PEDCo Environmental, we used the
revised estimates for scrubber costs in the 0.5-lb.-floor cases.
T/'Note "that the standards modelled in Phase I were treated as long term
" standards. This analysis was the first attempt to address explicitly a
short term averaging period, e.g., 24-hours. The difference between
long term and short term averaging periods appears in both a decline in
the minimum removal efficiency of the scrubber and the increased varia-
bility of the sulfur content of coal with shorter averaging periods.
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TABLE IV-28
CUMULATIVE UTILITY CAPITAL EXPENDITURES UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
FROM 1976 THROUGH 1989-
g
(in 10 $ - in late 1977 $'s)
Reference Case II
Coal
Scrubber
2/
Convert—
Nuclear—
4/
Oil/Gas-
Long-Distance
Transmission
Local Transmission
and Distribution-
Total
5/
0.5 Ib.
1.2 Ibs. 90% (Initial)
158.7 143.2 143.5
12.6 29.2 28.7
1.2 1.1 1.0
131.0 131.0 131.0
25.9 29.6 29.8
3.1
1.8
2.0
0.5 Ib.
(Revised)
154.1
27.9
0.9
131.0
26.6
2.6
332.6
336.0
336.0
343.3
1/ Hydro electric capital costs are not included. However, since this
capacity was fixed, the related capital expenditures would not vary
among scenarios.
2/ Capital cost of converting existing bituminous boilers to Western sub-
bituminous coal.
3/ Nuclear expenditures do not vary across scenarios because the amount of
nuclear capacity was fixed.
4/ Oil/gas capacity currently under construction was treated as existing
capacity and is not included in this estimate. However, since the
capacity remained fixed across scenarios, the related capital expendi-
tures would not vary among them.
5/ Not estimated.
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TABLE IV-29
1990 INCREASES IN ANNUALIZED COSTS AND
ELECTRICITY RATES UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARDS
Increases In Annualized Costs
From The Current NSPS
Percentage Increase In
East-
2/
Midwest-
West South
Central—
West-
National
(in 10
90%
0.94
0.63
0.42
(0.07)
1.94
$ - in late
0.5 Ib.
(Initial)
0.96
0.64
0.45
(0.10)
1.95
1977 $'s)
0.5 Ib.
(Initial)
0.73
0.38
0.36
(0.16)
1.32
Electricity
0.5 Ib.
90% (Initial)
1.4
1.6
2.0
(3.0
1
1.4
1.6
2.1
) (0.4)
.3 1.3
Rates
0.5 Ib.
(Initial)
1.1
1.0
1.7
(0.7)
0.9
V Includes census regions New England, Middle Atlantic, South Atlantic, and
East South Central.
2/ Includes census regions East North Central and West North Central.
3/ Includes census region West South Central.
4/ Includes census regions Mountain and Pacific.
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This section has three subsections. The first part discusses how the
standards were modeled The second and third subsections present the effects
observed, first qualitatively and then quantitatively.
Modeling of Standards
All case runs assumed the high electricity growth rate of 5.8 percent
per year to 1985 and 5.5 percent per year thereafter. The alternative NSPS
requirements are assumed to impact on all coal-fired powerplants scheduled to
come on line after 1982. All nine cases were based on the assumption
that scrubbers can be 90 percent efficient on a 30-day average and 85 percent
efficient on a 24-hour basis, with a drop to 75 percent allowed three days
por month. Th.is was the first attempt to explicitly model a short term
sf.anda rd.
The change in the floors in Cases 1-9 was handled by.not allowing
partial scrubbing in the 0.2-lb.-floor cases (Cases 1-4)- and by allowing
partial scrubbing in the 0.5-lb.-floor cases (Cases 5-8) and the 0.8-lb.-
floor case (Case 9). Emissions were estimated assuming that full scrubbers
removed 90 percent of the SO on a long-term basis. Thus, a coal that
averaged 1.67 Ibs. S/mmbtu (long term) would emit 0.33 Ib. SO2/mmbtu on an
annual basis (1.67 x 2 x (1-0.9) = 0.33). The emissions for partial scrubbing
assumed that the efficiency of the scrubber could be adjusted to maintain
the floor level. Thus, the emissions from a plant meeting a 0.5 Ib. floor
were assumed to be 0.5 Ib. SO /mmbtu on an annual basis.-
The ceiling/exemption combination was modeled by limiting the coal
types available to the coal-fired plants coming on line after 1982- when
no exemption was allowed, it was assumed that the utilities would purchase
coal that would be in compliance with the cap when the scrubber efficiency
has dropped to 75 percent and the sulfur content of the coal is at the high
end of the range (i.e., three relative standard deviations (RSD's) above the
long-run mean sulfur content of the coal), in order to comply with a no-
violations requirement. When an exemption of the cap was allowed, it
was assumed that the utilities would purchase coal (two standard deviations
above the long-run mean sulfur content) relative to an 85-percent scrubber
efficiency. This assumption is based on the notion that a drop in scrubber
efficiency to 75 percent is somewhat correlated with higher-than-average
sulfur levels in the coal being burned.
^/ Actually, partial scrubbing on very low-sulfur coal could be used to meet
the 0.2-lb. floor, but the magnitude of the cost savings would be very
modest since over 95 percent of the flue gas would have to be scrubbed to
meet a 24-hour average standard. Subsequent PEDCo work indicates that the
cost savings associated with partial scrubbing to a 0.2-lb. floor would be
negligible.
2/ Subsequent work has indicated that the efficiency of scrubbers cannot be
adjusted to maintain a specific emission rate. Thus, the long term
emission rate is now assumed to be lower than the floor. This is because
the floor must be met when the peak sulfur concentration is met and the
scrubber efficiency is at its minimum.
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Throughout this analysis, the relative standard deviation for sulfur was
assumed to be 0.15. Since the data on sulfur variability are sparse, it is
possible that the appropriate RSD for a 24-hour averaging period is 0.20.
However, the 0.15 RSD was specified by EPA.
The calculation of allowable coals is based upon the cap, the desired
confidence level, and the efficiency of the scrubber. For example, for the
case with a 1.2-lb. ceiling with exemption, the maximum allowable coal was 3.08
Ibs. S/mmbtu. This was calculated by first dividing the 1.2-lbs.-SO2/mmbtu
standard (i.e., the cap) by 1.3 (one plus two RSD's of 0.15). The result was
then divided by two to convert into pounds of sulfur from pounds of S02. The
pounds of sulfur were divided by 0.15 (one minus the scrubber efficiency) to
obtain the 3.08 Ibs. S/mmbtu (1.2 / 1.3 / 2 / 0.15 - 3.08). Table IV-30 gives
the maximum allowable sulfur content estimated for Cases 1-8.
TABLE IV-30
MAXIMUM ALLOWABLE SULFUR CONTENT UNDER ALTERNATIVE STANDARDS
Case
Number
1 & 5
2 & 6
3 & 7
4 & 8
Emissions Cap
(Ibs.SO /mmbtu)
1.2
1.2
0.8
0.8
Number of
RSD's
3
2
Scrubber
Efficiency
0.85
0.75
0.85
0.75
Maximum Allowable
Sulfur Content
(Ibs. S/mmbtu)
3.08
1.66
2.05
1.10
Cases 1 and 5 were modeled by eliminating the H-sulfur level in the
model (i.e., all coals with greater than 2.5 Ibs. S/mmbtu). This was done
to be conservative, since some reserves in the H-sulfur category would fall
below the 3.08-lb. S/mmbtu cut-off point while others would not.
Cases 2, 3, 6, and 7 were modeled by eliminating G and H coals (i.e.,
all coals with greater than 1.67 Ib. S/mmbtu). While Cases 2 and 6 fall
at the lower end of the G coal category, Cases 3 and 7 fall in the middle
of the range. Since the information was not available to readily divide the
G coal reserves further, a conservative approach was utilized, eliminating
the entire block of reserves. Thus, the impacts for Cases 3 and 7 are
higher than would be expected.
Finally, Cases 4 and 8 were modeled by eliminating F, G, and H sulfur
levels (i.e., all coals with greater than 0.83 Ib. S/mmbtu). The F sulfur
category ranges from 0.83 to 1.67 Ibs. S/mmbtu. Since the sulfur cut-off
value for Cases 4 and 8 fell in the middle of the range, the entire block
of F coal was eliminated. Again, the impacts presented in this analysis
will be biased on the high side.
Case 9 assumes that coals with an average sulfur content of 0.8 Ibs.
SO /mmbtu do not have to be scrubbed. Since 10 to 30 percent of the sulfur
in2Western coals remains with the ash, coals with a long-run average sulfur
content of 0.4 Ibs. S/mmbtu or less could be capable of complying with a
ICF INCORPORATED
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0.8-lb.-SO /mmbtu standard on a 24-hour average basis. However, this
implies a ?ower confidence level than used above. To burn such coal without
a scrubber, the averaging period would probably have to be longer than 24 hours.
All coals were allowed in the 0.8-lb. floor case, although the highest-
sulfur-category coal (H) should have been eliminated to be consistent
with the modeling of the 1.2-lbs.-SO /mmbtu ceiling in the other cases.
Since very little of this coal is used by the ANSPS plants, the impact of
this inconsistency is small.
Qualitative Discussion of Effects
This section is divided into three subsections which discuss the gen-
eral impacts of alternative floors, ceilings, and exemption provisions,
respectively.
Impact of Alternative Floors — The floor determines whether utilities can
partially scrub lower-sulfur coals. This can be done either by treating the
entire flue gas stream at a lower-percent removal or by treating part of the
gas stream at a high-percent removal and blending it with the untreated
portion of the stream to achieve the required emission limitations. Table
IV-31 shows that the amount of scrubber capacity built in 1990 increases by
15 GW with the 0.5-lb.-SO /mmbtu floor relative to the 0.2-lb. S02/mmbtu
floor. This is because partial scrubbing makes new coal-fired powerplants
less expensive than plants with full scrubbing; hence, more are forecast to
be built. The average percent removal for scrubbers in ANSPS plants declines
from 89.1 percent to 73.2 percent, because more partial scrubbing is forecast
to occur.
TABLE IV-31
1990 SCRUBBER CAPACITY AND AVERAGE PERCENT
REMOVAL UNDER ALTERNATIVE ENVIRONMENTAL STANDARDS
Scrubber Capacity (in GW)
Existing
NSPS
ANSPS
- full
- partial
Average Percent Removal
Existing
NSPS
ANSPS
- full.
- partial
0.2-lb. Floor
1.2 Cap With
Exemptions
210.6
36.3
23.4
150.9
146.2
4.8*
0.5-lb. Floor
1.2 Cap With
Exemptions
225.9
36.5
23.1
166.3
65.8
100.4
81
.9
64.0
64.0
89. 1
90.0
61.6
71
.5
G4.1
70.7
73.2
90.0
62.2
* Partial scrubbing was used in several Western states when
the SIP was set at 0.24-lb.-SO2/mmbtu, which was considered
more stringent than 90 percent removal.
ICF
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The major impacts of raising the floor are (1) increased emissions,
(2) increased shipments of Western coal to the East, (3) lower utility
oil consumption and (4) lower annualized costs. Emissions increase because
(a) the emission rate from ANSPS plants partially scrubbing lower-sulfur
coals increases and (b) more coal-fired capacity is built. These increases
are partly offset, however, by reduced loads on existing and NSPS capacity.
Loads on this capacity, which has higher emission rates than ANSPS capacity,
are reduced as loads on ANSPS capacity are increased when partial scrubbing
is permitted, because partial scrubbing is less expensive. See Table IV-30,
which is also discussed below in relation to utility oil consumption.
Western coal shipments to the East increase as the floor is raised,
because it is the Western low-sulfur coals that are partially scrubbed.
The Northern Great Plains Region is the major supplier of this increased
Western production, with the Midwest showing the largest decline in produc-
t ion.
Utility oil consumption declines as the floor is raised. This occurs
because the higher floor lowers the generation costs for new coal-fired
units. These units are used in baseload, bumping existing coal plants and
units subject to the current NSPS into lower load categories. Those coal
plants bump existing oil plants up the load curve, thereby reducing their
annual average capacity factor and hence oil consumption.
Table IV-32 compares the utilization of fossil fuel capacity between the
0.2 lb.-floor/1.2-lbs--cap/with-exemption case, and the 0.5 Ib.-floor/1.2-lbs.
-cap/ with-exemption case. Note that more ANSPS coal capacity is built and
less combined-cycle and turbine capacity is built with the higher floor. The
oil/ gas steam capacity (which remains the same between cases) is operated in
lower load categories.
Annualized costs are reduced as the floor is raised, because more
partial scrubbing can be employed, and partial scrubbing is generally less
expensive than full scrubbing. See section on the Economics of Partial
Scrubbing at the end of this chapter.
lmpacts_of Alternative Ceilings — The ceiling is the maximum level of
emissions that a plant can emit and still be considered in compliance. The
percent removal requirement is the binding constraint for low- and most
medium-sulfur coals, since when they are scrubbed these coals yield emission
levels below the caps considered in this analysis. However, for the highest
sulfur coals the cap is the binding constraint. Anticipated sulfur dioxide
removal efficiencies of scrubbers (e.g., a minimum of 75 percent on a 24-
hour basis) are not high enough to remove enough sulfur dioxide from the
flue gas of high sulfur combustion to comply with a 24-hour average cap,
when the variability of the sulfur content of coal is considered. Hence,
the cap together with the anticipated maximum scrubber removal efficiency
effectively exclude certain high sulfur coals from utility use.
For example, if we take the "no exemption" case where the minimum sulfur
removal efficiency of a scrubber is 75-percent removal on a 24-hour basis,
that- the appropriate relative standard deviation (i.e., a measure of the
variability of the sulfur content) for coal is 0.15 for a 24-hour period, and
that three standard deviations will provide the proper confidence interval
ICF INCORPORATED
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TABLE IV-32
COMPARISON OF FOSSIL FUEL CAPACITY UTILIZATION
IN 1990 UNDER ALTERNATIVE ENVIRONMENTAL SCENARIOS
In GH
Load Category
Base
Plant Type
Coal
Existing
NSPS
ANSPS
Total
Oil/gas
Steam
Combined Cycle
Turbine
0.2 Floor/
1.2 Cap/
With Exemp.
159.4
80.7
101 .9
342.0
2.5
11.9
-
0.5 Floor/
1 . 2 Cap/
With Exemp.
148.0
71.9
127.2
347.1
1.6
8.2
-
Intermediate
0.2 Floor/
1.2 Cap/
With Exemp.
44.5
7.4
49.7
101.6
90.6
1.7
-
0.5 Floor/
1.2 Cap/
With Exemp.
54.1
17. 1
39.0
1 10.2
82.1
1.7
-
Seasonal Peak
0.2 Floor/
1.2 Cap/
With Exemp.
0.7
-
-
0.7
32.1
0.6
56.9
0.5 Floor/
1.2 Cap/
With Exemp.
2.5
-
-
2.5
39.0
0.9
48.0
Daily
0.2 Floor/
1.2 Cap/
With Exemp.
-
-
-
-
18.2
1. 1
108.3
Peak
0.5 Floor/
1.2 Cap/
With Exemp.
-
-
-
-
20.5
1.1
105.4
Total
0.2 Floor/
1.2 Cap/
With Exemp.
204.6
88. 1
151.6
444.3
143.4
15.3
165.2
0.5 Floor/
1.2 Cap/
With Exemp.
204.6
89.0
166.2
459.8
143.2
11.9
153.4
Total
14.4
9.8
92.3
83.3
89.6
87.9
127.6
127.0
323.9
308.5
Total Fossil*
356.4
356.9
193.9
194.0
90.3
90.4
127.6
127.0
768.2
768.3
Capacity does not remain constant within each load category because of minor shifts in the loading of hydro capacity and small changes in plant
efficiencies caused by differences in scrubbing.
-------
-117-
for compliance with a never-to-exceed standard, the maximum average long-term
sulfur content for coal under a 1 .2-lb. -SO /mmbtu cap would be 1.66 Ibs.
sCbtu-? "his would mean that no coal over about 1.8 percent sulfur
could be burned.
coal
The major impacts of lowering the ceiling are ( 1 ) increased Western
IhiPrents to the East, with a significant decline in Midwestern coal
' •-^^'C "
co *-
ceilinq the higher will be the price for the medium- to low sulfur coals tor
an plants purchasing these coals. Emissions sometimes decrease because the
use of lower-sulfur coals increases; however, the relationships are complex,
and there are situations where the emissions are forecast to increase.
lmp_act of .1 *--».•. <»» Demotion Provisions - The ^^^^
studied i~th7s~a7alysis would allow the ceiling standard to be violated
— - - ttz ~ ~- -
;ed would be J.UB IDS. S/HUHLIL.U i-cn-..^ •
.ier.-7 This would mean no coals over about 3.4 percent
sulfur coal be burned.
The major impact areas for the exemption provisions are the same
as for an increased ceiling, since exemption of the cap has i,h« effect of
ANSPS plants could bid, and in some cases increase SO,, emissions.
Discussion of Effects
This section discusses the impacts of the ten alternative standards
^^^
JJ western ^ua-i- om.ft'— — —
tion 5) utility oil consumption, 6) utility costs, and 7) cost per ton
removed. Each of thse impact areas is discussed below.
V"f rite™ SO /mmbtu cap = X (the maximum long term average sulfur content
per 106 btu? x 2 (pounds SO,, per pound sulfur) x (1-0.75) (one minus^ ^
X = 1.66 Ibs. S/mmbtu.
2/ 1.2 Ibs. S02/106 btu cap = X x 2 x (1-.85) x 1.3
X = 3.08 Ibs. S/mmbtu-
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TABLE IV-33
1990 COAL PRODUCTION UNDER
ALTERNATIVE STANDARDS
(10 tons)
Census Reqion
Northern Appalachia
Central Appalachia
Southern Appalachia
Total Appalachia
Midwest
Central West
Total Midwest
Eastern Northern
Great Plains
Western Northern
Great Plains
Total Northern
Great Plains
Gulf
Rocky Mountain
Southwest
Northwest
Total Rest of
West
National
Western Coal
Shipped East
Current
NSPS
204.8
218.5
18.0
441.3
290.6
7 4
298.0
46.1
763 5
809.6
90.0
49.1
73.7
6 2
219.0
1, 767.9
456.0
1 .2
With
I/
Exemp—
254.8
196.8
15.0
466.6
366.7
8. 1
374.8
37.8
614.4
652.2
103.0
41.8
65.4
7.2
217.5
1,711.1
299.4
0.2 Floor
Cap 0.8
Without
Exemp~
273.9
198.8
16.1
488.8
299.8
6.1
305.9
37.8
668.5
706.3
103.0
41.0
65.4
7.2
216.6
1, 717.6
329.3
With
Exemp^
273.9
198.8
16.1
488.8
299.8
6.1
305.9
37.8
668.5
706.3
103.0
41.0
65.4
7.2
216.6
1, 717.6
329.3
Cap
Without
Exemp—
199.9
211 .4
17.3
428.6
295.8
6.9
302.8
48.5
749.0
797.5
64.8
41.9
90.2
7.2
204. 1
1,733.0
424.1
1 .2
With
c,xem.4/
254.3
195.2
14.4
463.9
346.4
6.1
352.5
38.9
675.6
714.5
103.0
38.6
74.8
7.2
223.6
1,754.5
342.8
Cap 0.8
Without
Exemp~
258.7
199.4
15.0
473.2
291.1
6.1
297.2
38.9
732.8
771.7
103.0
38.7
74.8
7.2
223.7
1,765.8
397.3
cl without
With
Exemp~
258.7
199.4
15.0
473.2
291 . 1
6.1
297.2
38.9
732.8
771.7
103.0
38.7
74.8
7.2
223.7
1,765.8
397.3
H coals.
Cap
Without
192.9
209.6
16.1
418.5
282.6
6.9
289.5
42.9
809.3
852.2
60.9
42.6
92.9
7.2
203.5
1, 763.8
483.6
0.8 Floor
1 . 2 Cap
With
Exemp
207.6
195.2
15.0
417.9
300.8
6.0
306.8
46. 1
780.1
826.2
103.0
47.8
71.6
6.2
228.6
1, 779.5
480.9
2/ Modelled as 90 percent removal requirement (85 percent removal on a 24
3/ Modelled as 90 percent removal requirement (85 percent removal on a 24
4/ Modelled as 0.5 Ib. SO2/nmbtu floor without H coals.
5/ Modelled as 0.5 Ib. SO2/mnbtu floor without G and H coals.
6/ Modelled as 0.5 Ib. SO2/mmbtu floor without F, G and H coals.
-hour basis) without G and H coals.
-hour basis) without F, G and H coals.
-------
TABLE IV-34
1990 UTILITY COAL CONSUMPTION UNDER
ALTERNATIVE STANDARDS
(10 tons)
Standard
0.2 Floor
Census Region
New England
Middle Atlantic
South Atlantic
East North Central
East South Central
west North Central
West South Central
Mountain
National
Current
NSPS
0.502
2.749
4.432
5.524
2.784
2.392
3.180
1.600
0 .561
23.722
1.2
With
V
Exemp—
0.509
2.224
4.755
5.275
2.755
2.345
3.236
1.623
0.557
23.279
.Cap
Without
2/
Exemp-
0.508
2.223
4.657
4.969
2.780
2.651
3.240
1.623
0.557
23.208
O.B
With
Exemp^
0.508
2.223
4.657
4.969
2.780
2.651
3.240
1.623
0.557
23.208
Cap
Without
Exemp—
0.501
2.709
4.210
4.992
2.770
2.528
3.200
1.593
0.568
23.072
With
Exemp—
0.508
2.194
4.785
5.512
2.798
2.393
3.254
1.840
0.616
23.899
0.5 Floor
Without
Exemp—
0.509
2.223
4.752
5.502
2.783
2.386
3.257
1.840
0.616
23.867
With
5/
Exemp—
0.509
2.223
4.752
5.502
2.783
2.386
3.257
1.840
0.616
23.867
Without
6/
0.506
2.723
4.312
5.369
2.786
2.378
3.212
1.597
0.592
23.475
0.8 Floor
1.2 Cap
With
Exemp
0.501
2.847
4.298
5.503
2.787
2.392
3.219
1.590
0.555
23.693
2/ Modelled as 90 percent removal requirement (85 percent removal on a
3/ Modelled as 90 percent removal requirement (85 percent removal on a
4/ Modelled as 0.5 Ib. SO2/mmbtu floor without H coals.
5/ Modelled as 0.5 Ib. SO /mmbtu floor without G and H coals.
6/ Modelled as 0.5 Ib. SO2/ninbtu floor without F, G and H coals.
24-hour basis) without G and H coals.
24-hour basis) without F, G and H coals.
-------
TABLE IV-35
1990 UTILITY OIL CONSUMPTION UNDER
ALTERNATIVE STANDARDS
(10 btu)
Standard
0.2
1.2 Cap
Census Reqion
New England
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mountain
Pacific
National
Current
NSPS
0.406
0.754
1.059
0.605
0.267
0.277
1.376
0. 153
1.474
' 6.369
With
Exemp—
0.41 1
0
1
0
0
0
1
0
1
7
.850
.252
.907
.325
.337
.391
.166
.435
.074
Without
Exem^
0.413
0.856
1.387
0.925
0.325
0.340
1.391
0.166
1 .435
7.238
Floor
0.8 Cap
With
2/
0.413
0.856
1.387
0.925
0.325
0.340
1.391
0.166
1.435
7.238
Without
Exemp—
0.419
0
1
0
0
0
1
0
1
7
.856
.466
.925
.335
.405
.391
.151
.471
.419
0.5
Floor
1.2 Cap
With
4/
0.411
0.
1.
0.
0.
0.
1.
0.
1.
6.
845
252
650
279
280
376
157
219
469
Without
Exemp—
0.411
0.
1.
0.
0.
0.
1.
0.
1.
6.
856
252
661
311
290
376
157
219
533
0.8 Cap
With
Exe-np^
0.411
0.
1.
0.
0.
0.
1.
0.
1.
6.
856
252
661
311
290
376
157
219
533
Without
Exemp6/
0.413
0
1
0
0
0
1
0
1
6
.586
.252
.816
.311
.295
.376
. 151
.444
.914
0 . 8 Floor
1 .2 Cap
With
Exerop
0.411
0.845
1.098
0.624
0.270
0.274
1.375
0.162
1 .465
6.523
V Modelled as 90 percent removal requirement (85 percent removal on a 24-hour basis) without H coals.
2/ Modelled as 90 percent removal requirement (85 percent removal on a 24-hour basis) without G and H coals.
3/ Modelled as 90 percent removal requirement (85 percent removal on a 24-hour basis) without F, G and H coals.
4/ Modelled as 0.5 Ib. SO /mmbtu floor without H coals.
5/ Modelled as 0.5 Ib. SO /mmbtu floor without G and H coals.
6/ Modelled as 0.5 Ib. SO /mmbtu floor without F, G and H coals.
-------
TABLE IV-36
1990 SO EMISSION UNDER
ALTERNATIVE STANDARDS
(3
(10 tons)
Standard
0.2 Floor
Census Region
New England
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mountain
Pacific
National-
Current
NSPS
0.49
2.57
4.64
6.20
3.08
2.54
2.55
0.58
0.69
23.33
1.2
With
1/
Exemp—
0.38
2.15
4.28
6.05
2.89
2.40
1 .80
0.58
0.54
21.06
Cap
Without
2/
0.37
2.12
4.13
5.85
2.80
2.41
1.79
0.58
0.54
20.59
0.8
With
Exemp—
0.37
2.12
4. 13
5.85
2.80
2.41
1.79
0.58
0.54
20.59
Cap
Without
Exemp—
0.36
2. 13
4.00
5.74
2.79
2.56
1.72
0.56
0.54
20.40
1 .2
With.
Exemp—
0.38
2. 15
4.22
5.95
2.88
2.47
2.02
0.63
0.60
21.30
0.5 Floor
Cap
Without
Exemp—
0.38
2.17
4.27
5.92
2.89
2.49
2.03
0.63
0.60
21.38
0.8
With
Exemp~
0-39
2.17
4.27
5.92
2.89
2.49
2.03
0.63
0.60
21.38
Cap
Without
Exemp—
0.41
2.30
4.27
5.96
2.90
2.48
2.02
0.56
0.62
21.45
0.8 Floor
1 .2 Cap
With
Exemp
0.43
2.51
4.24
6.13
2.99
2.50
2.29
0.58
0.68
22.34
1/ Modelled as 90 percent removal requirement (85 percent removal on a 24-hour basis) without H coals.
2/ Modelled as 90 percent removal requirement (85 percent removal on a 24-hour basis) without G and H coals.
3/ Modelled as 90 percent removal requirement (85 percent on a 24-hour basis) without F, G, and H coals.
4/ Modelled as 0.5 Ib. SO /mmbtu floor without H coals.
5/ Modelled as 0.5 Ib. SO /mmbtu floor without G and H coals.
6/ Modelled as 0.5 Ib. SO /mnbtu floor without F, G, and H coals.
7/ 1975 SO emissions were 18.6 million tons.
-------
TABLE IV-37
1990 NATIONAL SO EMISSIONS BY PLANT TYPE UNDER
ALTERNATIVE NEB SOURCE PERFORMANCE STANDARDS
(in 10 tons per year)
0.2 Floor
Current 1.2 Cap 1.2 Cap 0.8 Cap 0.8 Cap
Plant Type NSPS With Exemp. Without Exemp. With Exemp. Without Exemp.
Coal
Existing 14.85 14.52 14.48 14.48 14.57
NSPS 2.61 2.63 2.62 2.62 2.67
ANSPS 4.18 1.45 0.95 0.95 0.57
Oil/ Gas 2.30 2.47 2.54 2.54 2.59
Other - -
0.5 Floor 0.8 Floor
1.2 Cap 1.2 Cap 0.8 Cap 0.8 Cap 1.2 Cap
With Exemp. Without Exemp. With Exemp. Without Exemp. With Exemp.
14.35 14.40 14.40 14.48 14.20
2.50 2.60 2.60 2.62 2.48
2.13 2.05 2.05 1.94 3.33
2.32 2.33 " 2.33 2.41 2.33
Total
23.33
21.06
20.59
20.59
20.40
21.30
21.38
21.38
21.45
22.34
-------
TABLE IV-38
CUMULATIVE UTILITY CAPITAL EXPENDITURES UNDER
ALTERNATIVE SEW SOURCE PERFORMANCE STANDARDS
FROM 1976 THROUGH 1989-
(10 S - in late 1977 $'s)
0.2 Floor
Coal
Scrubber
Convert—
Nuclear—
Oil/Gas
Long-Distance
Transmission
Local Transmission
and Distribution-
Total
4/
1.2 Cap.
0.8 Cap.
Current With Without With Without
NSPS
25.9
3.1
131.0 131.0 131.0
30.0 30.0 31.0
2.2
2;2
3.4
1.2
with
Exemp
154
27
0
131
. 26
2
.1
.9
.9
.0
.6
.6
*
0.5 Floor
Cap. 0.8 Cap.
Without With Without
Exemp Exemp Exemp
154.9 154.9 150.1
25.5 25.5 22.2
1.0 1.0 1.1
131.0 131.0 131.0
27.1 27.1 29.5
2.7 2.7 3.1
* * *
0.8 Floor
1.2 Cap.
With
Exemp
157.6
15.4
1.0
131.0
27.2
3.5
*
332.6 131.0 337.0 337.0 336.8 343.3 342.2 342.2 33.7.1
335.8
V Hydro electric and new oil/gas steam capital costs are not included. However, these capacities were fixed and
~ related capital expenditures would not very among scenarios.
2/ Capital cost of converting existing bituminous boilers to Western subbituminous coal.
3/ Nuclear expenditures do not vary across scenarios because the amount of nuclear capacity was fixed.
4/ Not estimated.
-------
TABLE IV-39
1990 INCREASES IN ANNUALIZED UTILITY COST UNDER
ALTERNATIVE SEX SOURCE PERFORMANCE STANDARDS
(10 S - in late 1977 S's)
Standard
0.2 Floor
Increase In ;•_-.- -il:. zed Costs
Fron The Curre.-.- NSPS
(10 S - ir. late 1=f77 S7s)
East-
Midwest-7'
West South Central-
West
National
Percentage Increases In
Electricity Rates
East^
Midwest-
West South Cer.tral— '
West
National
1 .2
With
Exemp
0.96
0.62
0.42
(0.09)
1.94
1.4
1.6
2.0
(0.4)
1.3
Cap.
Without
Exemp
1.27
0.62
0.41
(0.09)
2.23
1.9
1.6
1.9
(0.4)
1 .3
0.8
With
Exemp
1.27
0.62
0.41
(0.09)
2.23
1.9
1.6
1.9
(0.4)
1 .5
Cap.
Without
Exemp
1.92
0.61
0.51
(0.02)
3.05
1.9
1.6
1.9
(0.1)
2.0
1.2
With
Exemp
0.73
0.38
0.36
(0.16)
1.32
1.1
1.0
1.7
(0.7)
0.9
0.5 Floor
Cap.
Without
Exemp
0.88
0.39
0.34
(0.15)
1.47
1.3
1.0
1.6
(0.7)
1 .0
0.8
With
Exemp
0.88
0
0
(0
1
1
1
1
(0
1
.39
.34
.15)
.47
.3
.0
.6
iJ)
.0
Cap.
Without
Exemp
1.05
0.50
0.38
(0.06)
1.88
1.5
1.3
1.8
(0.3)
1 . 1
0.8
1 .2
Floor
Cap.
With
Exemp
0.14
(0
0
(0
0
0
(0
1
(0
0
.05)
.26
.08)
.30
.2
.1)
.2
^4)
.2
J/ Includes census regions New England, Middle Atlantic, South Atlantic and East South Central.
2/ Includes census regions East North Central and West North Central.
V Includes census region West South Central.
4_/ Includes census regions Mountain and Pacific.
-------
-125-
1990 Coal Production — National production in tonnage increases as
1) tlio floor is raised. 2) the cap is lowered, or 3) exemptions from the
.-,,, ,r,- n..i .illowr.l. Tho increase in production when the floor is raised
,.. ,,,,. ,.,..,„ M ,,i U,.- I..W.T co-,1. or coal and the shifting of oil-generated
,..,,„„-i,y out ..I iMt,M-,ii«.Uate load. Thus, more coal is used with the higher
floor. further, tonnage increases as Western coals with higher heat con
tent-. an. I lower sulfur levels are substituted for Eastern coals.
The increase in coal production from lowering the cap or not allowing
exemptions is the result of substituting low-sulfur, low-btu Western coals
for high-sulfur, high-btu Midwestern and Eastern coals, which are prohibited
for new plants because they could not comply with the cap.
The regional tonnage production shifts between the standards are sig-
nificant. The Midwestern, high-sulfur coals are what are forecast to be
replaced with Northern Great Plains production as the floor is raised or the
ceiling is lowered. See Table IV-33.
1990 Western Coal Shipped to the East — Under the current NSPS, Western
coal shipped east of the Mississippi is forecast to reach 456 million tons in
1990.- These shipments decline as the floor is lowered or the ceiling
raised. Thus, the lowest volume of Western coal shipped east (299 million
tons) occurs under the 0.2-lb.-floor, 1.2-lb.-cap-with-exemption scenario.
The volume of shipments goes above the NSPS level to 484 million tons
under the 0.5-lb.-floor, 0.8-lb.-cap-without-exemption scenario. The
increase in shipments occurs because under the higher floor, generation costs
can be reduced by partially scrubbing the low-sulfur Western coal, and the
lower ceilings eliminate the higher-sulfur Midwestern and Appalachian coals
from use because they cannot be scrubbed to meet the lower ceiling. See
Table IV-33.
1990 Utility Coal Consumption — Utility coal consumption in btu's
increases and less oil is consumed as the floor is raised, because coal
becomes cheaper to use. See Table IV-34. The ANSPS plants are baseloaded,
shifting existing and NSPS plants into intermediate load, which in turn bumps
existing oil capacity further up the load curve. As was shown in Table IV-31
more coal capacity is build with the higher floor.
Table IV-40 gives the consumption of subbituminous coal by ANSPS plants
east of the Mississippi under the various environmental standards. Note
that the consumption of Western coal increases as the floor is raised or the
ceiling lowered. As the cap is lowered or when exemptions are not allowed,
however total utility consumption of coal declines in btu's, because the
prire of lower-sulfur coal is bid up to levels where it is not always the
chcMpost Fuel choice. The replacement of high-btu Eastern coals by low-btu
Western coals lends to an increase in tonnage consumed despite a drop in
htu's consumed.
^/ se<> .li.scussion on paye 60 concerning why this level is too high, although
l |U. Miffrtronces between cases are likely representative, of what would
ICF INCORPORATED
-------
TABLE IV-40
1990 CONSUMPTION OF SUBBITUMINOUS COAL IN ANSPS PLANTS
EAST OF THE MISSISSIPPI UNDER ALTERNATIVE NSPS STANDARDS
(in quads)
Region
Upstate New York
Western Pennsylvania
West Virginia
Georgia/Florida
Southern Florida
Northern Ohio
Southern Ohio
Michigan
Illinois
Wisconsin
Eastern Kentucky
Western Kentucky
Eastern Tennessee
Western Tennessee
Alabama/Miss issippi
Total
0.2 Floor
Sulfur Level
(Ib. S/mmbtu)
0.40
0.40
0.83
0.40
0.83
0.40
0.83
0.40
0.83
0.40
0.40
0.83
0.40
0.40
0.83
0.40
0.40
0. 83
0.40
0.83
0.40
0.83
0.40
0.60
0.40
0.60
0.83
0.40
0.60
0.83
All Levels
1.2 Cap
Current Wit'r. Without
NSPS Exec£ Exemp
0.771
0.401
0
0
0
0
0
0
0
0
0
2
0
0
2
_
.013
. 144
0
.438
.451
_
-
-
_
. 187
_
. 143
.019
.003
_
_
.169
.567
.003
. 169
.739
0.307
_
_
-
_
_
-
0.033
-
-
„
_
0.092
_
0.102
-
-
_
-
0.358
_
_
0.892
0.892
0.8 Cap
With Without
Exemp Exemp
0.307
-
-
-
-
-
-
0.033
-
—
_
-
0.092
-
0. 102
-
-
_
-
0.358
-
-
0.358
0.892
0.820
0.081
0.318
0.311
-
-
0.037
0.021
-
0.069
-
-
0.039
-
0.092
-
0.089
-
-
-
-
0.208
0.841
-
1.202
2.043
0.5 Floor
1 .2 Cap
With without
Exemp Exemp
0.057
-
0.008
-
-
0.309
0. 166
-
-
-
-
-
-
-
-
0.018
-
-
-
0.208
0.841
-
0.101
0.659
0.322
0.295
-
0.010
-
-
0.379
0.487
-
-
—
-
0. 162
-
0. 100
-
0.018
-
-
0.101
0. 101
0.558
-
0. 101
0.659
0.8 Cap
With Without
Exemp Exemp
0.322
0.295
-
0.010
-
-
0.379
0.487
-
-
•
-
0.162
-
0.100
-
0.018
~
0.005
0.318
-
1.778
0.318
-
2.096
1.022
0.026
0.069
0.267
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
1 .
1.
507
010
096
—
084
350
-
-
~
013
145
-
084
017
018
~
-
-
326
904
-
, 130
3.034
0.8 Floor
1.2 cap
with
Exenp
0.005
1 . 134
0.117
0.544
0.248
-
0.011
0.193
~
0.437
0.462
~
0.010
~
-
0.215
~
0. 143
-
0.023
~
-
0.292
—
3.834
-
-
3.834
-------
-127-
1990 Utility Oil Consumption — Where the floor is raised from 0.2-
to 0.5"~lbr SO /mmbtu, oil consumption decreases nationally by 0.5-0.7
quad, because2the costs of burning coal are reduced. Oil consumption under
the current NSPS is overstated by about 0.2 quad due to an input error in
the costs of meeting the state standards in Arizona/New Mexico. Had the
correct costs been used coal-fired generation would become cheaper, and more
would be built to replace oil-fired capacity in southern California. However,
the oil consumption estimates for the 0.2-lb. and 0.5-lb. floor cases are
correct and the increase between them accurately represents the impact of the
standards.
In general, utility oil consumption increases as the cap is lowered or
when exemptions are not allowed, because these provisions increase the cost
of burning coal. See Table IV-35.
1990 SO Emissions — National SO emissions from electric utili-
ties under tne current NSPS are projected to be 23.3 million tons in 1990
an increase of 25 percent, or 4.7 million tons, above the 1975 level of 18.6
million tons. Under the alternative standards, SO2 emissions range from
20.4 million to 22.3. See Table IV-36.
SO emissions increase as the floor is raised. National emissions
in 19902are projected to be from 20.4 to 21.06 million tons with a 0.2-lb.-
SO floor; from 21.3 to 21.5 million tons with a 0.5-lb. floor; and 22.3
million tons with a 0.8-lb. floor.
SO emissions decrease as the ceiling is reduced when there is a
0.2-lb.2floor, but not when there is a 0.5-lb. floor. Under the 0.2-lb.
floor, a tighter ceiling results in lower-sulfur coals being consumed in
ANSPS plants. The loading of other types of coal-fired capacity changes only
slightly, causing few changes in SO loadings for existing and NSPS plants
(see Table IV-32). Under the 0.5-lB. floor a lower ceiling also causes ANSPS
plants to shift to lower-sulfur coal, but increase the utilization of existing
and NSPS plants as the ceiling is lowered. The result of reducing the cap
while holding the follor constant at 0.5-lb. is that the reduced emissions
from ANSPS plants are more than offset by the increased emissions from
existing and NSPS plants. See Table IV-37.
Although the emissions from coal-fired plants under the 0.5-lb. floor,
1 2-lb cap with exemption exceed the emissions from coal plants under the
0 2-lb. floor, 1.2-lbs. cap with exemption, this is because of increased
co(1 I use rather than a higher emissions rate. See Table IV-37. The average
omissions rate declines from 1.60 Ibs. SO /mmbtu with the 0.2-lb. floor to
1.59 Ibs. SO / mmbtu with the 0.5 Ib. floor. These emission rates are
roughly 60 plrcent below the emission rate under the current NSPS or 1.77
Ibs. SO /mmbtu.
ICF INCORPORATED
-------
-128-
Cumulative Utility Capital Expenditures and Annualized Costs
The cumulative utility capital expenditures increase from the current
NSPS by $4.2 to 4.4 billion with the 0.2-lb. floor and by $4.5 to $10.7
billion with the 0.5-lb. floor. The major difference between the two floors
is that more coal-fired capacity is built under the 0.5-lb. floor increas-
ing capital expenditures for coal plants by $7 to 11 billion. Less turbine
capacity is built under the 0.5-lb. floor reducing.oil plant expenditures
by $1.5 to 3.4 billion. See Table IV-38.
When the floor is raised from 0.2-lb. to 0.5-lb., annualized costs
decrease by $0.6 to $1.2 billion. The capital cost savings resulting from
partial scrubbing are more than enough to offset the increased cost of the
lower-sulfur coals that are used in the 0.5-lb. case. As the cap is lowered
or when exemptions are not allowed, annualized costs increase, because ANSPS
plants bid up the prices of medium- to low-sulfur coals for all-utility
plants. See Table IV-39 for incremental annualized costs from the current
NSPS and percentage increases in electricity rates.
1990 Cost Per Pound Removed — The average cost per pound of SO.
removed declines as the floor is raised. Table IV-41 shows the average cost
of moving from the current NSPS to one of the alternative standards.
Table IV-42 shows that the marginal cost (i.e., the cost of moving from a
1.2-lb. to 0.8-lb. standard then to 0.5-lb. standard, and then to 0.2-lb.
standard) increases as the floor is lowered, going from $0.15 per mmbtu for a
0.8-lb.-SO /mmbtu floor, to $0.49 per mmbtu for a 0.5-lb. floor, to $1.29
per million btu for a 0.2-lb. floor.
The effect of lowering the ceiling is to increase the average cost per
pound removed (as would be expected from a more stringent standard), with one
•exception. The average cost declines when the cap is lowered from 1.2 Ibs.
with exemption to either 1.2 Ibs. without or 0.8 Ib. with the exemption
(where the modeling of these two alternative standards is identical, i.e.,
includes no G or H coal). In this case the tighter standard forces the model
to shift from burning basically 2.5-lb. S/mmbtu coal in ANSPS plants to
burning 0.83- and 1.67-lb. S/mmbtu coals in ANSPS plants. See Table IV-43.
The 1.67-lb. coal and the 0.83-lb. are generally priced similarly. For
example, in model region CA (North Carolina/ South Carolina), the prices for
these coals were $1.32 and $1.38 per million btu, respectively. The tighter
standard causes the prices of the lower-sulfur coals to be bid higher by the
ANSPS .plants. However, the costs of the shift are small since the shift of
ANSPS plants away from 2.5-lb. coal lowers its price to existing and NSPS
plants. The resulting impact on annualized cost is small compared to the
larqe drop in SO emissions that occurs with the shift.
ECONOMICS OF PARTIAL SCRUBBING
This section examines the economic considerations involved in the
utility company's decision between scrubbing a high-sulfur coal fully or
scrubbing a low-sulfur coal partially. These considerations will be examined
from two aspects: first, a direct comparison of the costs of fully scrubbing
hiqh .sulfur coal versus partially scrubbing low-sulfur coal; and second, the
of'foiTt of partial scrubbing on oil consumption.
ICF
INCORPORATED
-------
-129-
TABLE IV-41
AVERAGE COST PER POUND OF SO REMOVED UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
K_l 0£r Cap
0.2 Ib. 1.2 Ib.
0.8 Ib.
0.5 Ib.
0.8 Ib.
1.2 Ib.
0.8 Ib.
1.2 Ib.
Exemption
with
without
with
without
with
without
with
without
with
$/lb.-in late 1977 $'s
0.43
0.41
0.41
0.52
0.32
0.38
0.38
0.50
0.15
ICF
INCORPORATED
-------
TABLE IV-42
Base Standard
MARGINAL COST PER POUND OF SO REMOVED
Incremental Standard
Reduction SO
Emissions (10 tons)
Increase In Annual-
ized Costs (10 $)
Xarginal Cost
(5/lb.)
Current NSPS
0.8 Floor/1.2 Cap/
With Exemption
0.5 Floor/1.2 Cap/
With Exemption
0.8-lb. Floor/1.2-lbs. Cap/
With Exemption
0.5-lb. Floor/1.2-lbs. Cap/
With Exemption
0.2-lb. Floor/1.2-lbs. Cap/
With Exemption
0.99
1 .04
0.24
0.30
1.02
0.62
0.15
0.49
1 .29
I
t-1
o
O
o
o
a
•o
O
3D
5!
m
o
-------
-131-
TABLE IV-43
1990 COAL USE BY ANSPS PLANTS
(in quads)
0.2-lb. Floor
Sulfur Level of Coal
0.40
0.60
0.83
1.67
2.50
Total
1.2-lbs. Cap 0.8-lb. Cap
With Exemp With Exemp
0.086
0. 128
1.890
1.149
4.298
7.551
0.086
0.127
3.219
3.935
7.367
ICF INCORPORATED
-------
-132-
Full Scrubbing versus Partial Scrubbing
The model does not forecast much partial scrubbing of medium-sulfur coals.
This point is illustrated by the revised 0.5-lb. case in Illinois. In the
1985 run, Illinois builds 89 MW of ANSPS capacity for intermediate load.
This capacity fully scrubs a high-sulfur bituminous coal (see Table IV-44).
In the 1990 run, the model builds only plants that partially scrub low-sulfur
subbituminous coals.
TABLE IV-44
USE Of ANSPS CAPACITY UNDER A 0 .5-LB.-SC>2/MMBTU
EMISSION STANDARD IN ILLINOIS
(in GW)
Baseload Intermediate Load
Coal Used Coal Used
High Low High Low 2/
Year Sulfur- Sulfur- Sulfur- Sulfur-
1985 - - 0.089
1990 - 5.662 0.088 4.906
1/ BG - bituminous coal with 2.5 Ibs. S/mmbtu.
2/ SA - subbituminous coal with 0.4 Ib. S/mmbtu.
Table IV-45 shows the costs upon which the model based its decision. In
1985, the lowest cost of new coal-fired generation in intermediate load
involves fully scrubbing high-sulfur bituminous coal. The next best alterna-
tive (at 0.5 mills more per kwh) was partially scrubbing low-sulfur Western
coal. In 1990 the price of the high-sulfur coal has increased to the point
that it is no longer the cheapest form of generation. The delivered price of
western low-sulfur coal does not change from 1985 to 1990. This lack of
ch.-in.n* in Western coal results from the high elasticity of the Western supply
curvws and the negligible requirement for replacing closed mines just to hold
ICF
INCORPORATED
-------
TABLE IV-45
ANNUAL COSTS FOR AN ANSPS PLANT IN INTERMEDIATE LOAD
TO MEET A 0.5-LB.-SO /MMBTU EMISSION STANDARD IS
ILLINOIS USING ALTERNATIVE COALS
(in nills/kwh - 1977 $'s)
Coal Used
o
Tl
o
i
s
1985
Annualized Capital
Cost-
2/
O&M Costs-
Fuel Costs-
Total
1990
Annualized Capital
Cost-
O&M Costs-
Fuel Costs-
Total
0.83 Ibs.
S/nunbtu
21.2
5.4
13.6
40.2
21.2
5.4
13.8
40.4
Bituminous
1.67 Ibs.
S/mmbtu
21.9
5.8
1 1 .8
39.5
21.9
5.8
12.3
40.0
Subbituminous
2.50 Ibs.
S/mmbtu
22.2
5.9
9.9
38.0
22.2
5.9
11.1
39.2
0.40 Ibs.
S/mmbtu
22.3
4.7
11.5
38.5
22.3
4.7
11.5
38.5
0.60 Ibs.
S/mmbtu
23.1
5.2
11 .6
39.9
23.1
5.2
11.6
39.9
0.83 Ibs.
S/mmbtu
23.8
5.6
10.5
39.9
23.8
5.6
10.8
40.2
Footnotes on following pages.
m
o
-------
-134-
Footnote to Table IV-45.
V Annualized capital costs are calculated as follows (note that the capital coats for
costed for 1990 for all model run years (i.e., 1985, 1990 and 1995):
Bituminous
Base cost of ANSPS plant with TSP control and
cooling towers but without scrubber (these
estimates include five years of real escala-
tion at 0.5 percent per year for 1985 through
1990) - S/kw
Base cost of full scrubber ($86/kw for 80 per-
cent removal; $96/kw for 90 percent removal)
Partial scrubbing cost factor
Cost of scrubber - S/kw
Base cost of replacement capacity with scrubber
- $/kw
Capacity penalty
Partial scrubbing cost factor
Cost of replacement capacity - S/kw
Full cost of ANSPS plant in 1975 dollars S's -
S/kw
Cost inflator to restate 1990 costs (with 2 per-
cent annual real escalator through, 1985) in
late 1977 dollars (1.075 / 1.055 =
1.417)
H«!i| Ion.i I fiijll .nl julilUHMit rm:tnr I'"'" Illinois
Kull cost of ANSPS pl;int - S/kw
in 1977 S's
Times 1000 to convert to mills from dollars
Real Fixed charge rate
KWH's per KW (8760 x intermediate load
capacity factor of .37)
Annualized capital cost-mills/kwh
ANSPS plants were
Subbituminous
0.83 Ibs.
450
86
0.84
72
561
0.033
0.84
16
538
1.417
O.'J
686
1000
0.1
3241
21.17
1.67 Ibs.
450
96
0.94
90
561
0.033
0.94
17
557
1.417
0.9
710
1000
0.1
3241
21.91
2.50 Ibs.
450
96
1 .00
96
561
0.033
1.00
19
565
1.417
u.y
721
1000
0.1
3241
22.25
0.40 Ibs.
518
86
0.48
41
561
0.033
0.48
9
568
1.417
0_.9
724
1000
0.1
3241
22.34
0.60 Ibs.
518
86
0.66
57
561
0.033
0.66
12
587
1.417
0_.9
749
1000
0.1
3241
23.11
0.83 Ibs.
518
86
0.84
72
561
0.033
0.84
16
606
1.417
0.9
773
1000
0.1
3241
23.85
-------
-US-
Footnotes to Table IV-45 - cont'd.
2/ O&H costs are calculated as follows:
Base O&M cost for ANSPS plant at intermediate
load - mills/kwh
Base OSM cost for scrubber-mills/kwli
Partial scrubbing costs factor
Scrubber O&M-mills/kwh
Full OSM cost of ANSPS plant in 1975 $'s -
mills/kwh
Cost inflator restate in late 1977 dollars
(1.055 = 1.174)
Full OSM cost for ANSPS plant in late 1977 $'
- mills/kwh
Bituminous
Subbituminous
n ai ih,. r-BTlbs. 2.50 IbsT 0.40 Ibs. 0.60 Iba. 0.83 Ibs.
2.8
2.1
0.64
1.8
4.6
1 .174
5.4
2.8
2.2
0.94
2.1
4.9
2.8
2.2
5.0
1.174 1.174
3.0
2.1
0.48
1.0
4.0
3.0
1.4
4.4
5.8
5.9
4.7
5.2
3.0
1.8
4.8
1.174 1.174 1.174
5.6
3/ Fuel costs are calculated as follows:
Base heat rate for ANSPS plant at intermediate
load without scrubber
Energy penalty for scrubber
Partial scrubbing costs factor
Adjustment factor £or heat rate (1 + energy
penalty x partial scrubbing cost factor)
Full heat rate for ANSPS plant with scrubber
1985 delivered price of coal in
1977 $'s - in S/mmbtu
1985 fuel cost in 1977 S's - mills/kwh
1990 delivered price of coal in 1977 $'s -
S/mmbtu
1990 fuel cost in 1977 $'s - mills/kwh
Bituminous
Subbi tuminous
0.83 Ibs. 1.67 Ibs.2.50 Ibs. 0.40 Ibs. 0-60 Ibs. 0.83 Ibs.
9760 9760 9760
0.053 0.053 0.053
0.84 0.94 1-00
1.045 1.050 1.053
10199 10248 10277
10192 10192 10192
0.053 0.053 0.053
0.48 0.66 0.84
1.025 1.035 1.045
10447 10549 10651
1
13
1
13
.33
.56
.35
.77
1 .
11.
1.
12.
15
79
20
30
0
9
1
11
.96
.87
.08
. 10
1
1 1
1
1 1
. 10
.49
.10
.49
1
11
1
11
.10
.60
.10
.60
0
10
1
10
.99
.54
.01
.76
-------
-136-
the regional production level (unlike the Midwest and Appalachia, where
substantial new mine capacity is required to replace closed mines). As a
result of these fuel price patterns, partially scrubbing low-sulfur subbitu-
minous coal becomes most economic.
Medium-sulfur coals never are cost effective. This is probably the
result of the high demand for medium-sulfur coals from existing plants to
meet their SIP's without scrubbers, and of the modest cost savings estimated
to be associated with partially scrubbing medium sulfur coals.-
Impact of Partial Scrubbing on Oil Consumption
Although the increase in ANSPS capacity in baseload beyond what is
required to meet incremental load growth lowers total generation costs,
it does not necessarily lower baseload generation costs. The total costs
(i.e., capital, O&M, and fuel costs) of a new coal-fired powerplant may
exceed the variable costs (i.e., O&M and fuel costs) of existing capacity in
all load categories in a one-on-one comparison yet reduce system generation
costs. Since this is a complex optimization problem, we have developed an
example from two model runs to illustrate the tradeoffs involved.
Table IV-46 shows the loading of utility capacity in Michigan in 1990
under two environmental standards: 0.2-lb. floor/ 1.2-lb. cap/with exemption,
and 0.5-lb. floor/1.2-lb. cap/with exemption. The amount of electricity
generated in the two cases varies by less than 18 million kwh, or less than
0.01 percent. Thus, any variation in loading from changing the environmental
standard is confined to the specific state. Note that most capacity is
dispatched similarly under the two standards.
Table IV-47 isolates that capacity that changes either load or level
between the two standards. Only four plant-types are affected: existing
coal (SIP 2), ANSPS coal, existing oil/gas steam, and new turbines. Note
that ANSPS capacity increases by 2.388 GW, with 2.037 GW of the increase
occurring in baseload. Since the total capacity in each of the load cate-
gories does not change, 2.040 GW of existing coal capacity shifts out
of baseload and into intermediate load. Similarly, 2.392 GW of existing
oil/gas steam capacity shifts out of intermediate and into seasonal peak.
with the 2.392 GW of new turbine capacity built under the 0.2-lb. floor not
built at all under the 0.5-lb. floor.
Table IV-48 gives the generation costs for each of the plant types in
Table IV-49 and for the three load categories in which they operate. The
costs are for the 0.5-lb. floor case. Note that the ANSPS plant using SA
con I is more expensive than the existing oil steam plant in intermediate,
arxi more expensive than the existing coal plant in baseload. Thus, on a
ono-on-one comparison basis, adding the additional ANSPS capacity to reduce
the use of existing oil steam in intermediate load, to reduce the use of
existing coal in intermediate load, or to reduce the use of existing coal
in baseload appears to be unjustified. Table IV-49, however, shows otherwise.
1/ Subsequent estimates by PEDCo indicated no cost savings from partially
scrubbing medium sulfur coals.
ICF
INCORPORATED
-------
TABLE IV-46
1990 CAPACITY UTILIZATION IN MICHIGAN
UNDER ALTERNATIVE ENVIRONMENTAL STANDARDS
Plant Type
Existing Coal
Old Plant
SIP 1 w/o FGD
SIP 1 Convert
SIP 2 w/o FGD
SIP 3 w/o FGD
Total
NSPS Coal
ANSPS Coal
Total
Oil/Gas Steam
Tur bine
Existing
New
Total
Nuclear
Existing
New
Total
Hydro
Coal
Type
BD
BB
SA
BD
BF
SA
BG
SA
—
—
__
--
_
0.2
Base
-
-
0.629
5.384
0. 1 10
6. 123
1.431
3.696
_
3.696
-
-
_
-
2.200
4.600
6.800
0.105
-Ib. Floor/1 .2-lbs. Cap/With Exemption
Intermediate Seasonal" Peak Daily Peak
0.490
2.519
- -
1. 118
- -
4.127
-
0.259
-
0.259
4.237
0.280 0.900
2.392
2.672 0.900
- -
_ - -
- -
0.105 - 0.955
0.5-]
Base
-
-
0.629
3.344
0.110
4.083
1.431
0.583
5.150
5.733
-
-
-
-
2.200
4.600
6.800
0. 105
Lb. Floor/1 .2-lbs. Cap/with Ex<
Intermediate Seasonal Peak
0.490
2.519
-
3.158
-
6.167
-
0.610
-
0.610
1.845 2.392
0.280
- —
0.280
-
-
-
0.105
smption
Daily Peak
-
—
—
-
—
-
-
~
~
-
0.900
~
0.900
~
~
—
0.955
Total Capacity
18.155
8.728
2.672
1.855
18.152
8.727
2.672
1.855
-------
TABLE IV-47
Plant Type
Existing Coal
SIP 2 w/o FGD
ANSPS Coal
Existing Oil/Gas Steam
New Turbine
Total
Coal
Type
BD
BG
SA
CHANGES IN CAPACITY LOADINGS IN MICHIGAN
UNDER ALTERNATIVE ENVIRONMENTAL STANDARDS
in GW
0.2-lb. Floor/1.2-lbs. Cap/with Exemption
Base Intermediate Seasonal Peak
5.384
3.696
9.080
1.118
0.259
4.237
5.614
2.392
2.392
0.5-lb. Floor/1 .2-lbs. CapA'ith Exemption
Base Intermediate Seasonal Peak
3.344
0.583
5.150
9.077
3.158
0.610
1.845
5.613
2.392
2.392
I
M
Ul
I
o
Tl
o
o
a
•o
§
S
O
-------
TABLE IV-48
1990 GENERATION COSTS IN ^ICHIGAN BY LOAD CATEGORY
AND PLANT-TYPE UNDER A 0.5-FLOOR/1.2 CAP/WITH EXEMPTION
NSPS STANDARD
Existing Coal SIP2 BD Coal
A::SPS Coal
BG Coal
SA Coal
in mills/kwh
Baseload
Existing Oil Steam
New Turbine
Intermediate
O&M
Fuel
Total
Capital
O&M
Fuel
Total
Capital
O&M
Fuel
Total
O&M
Fuel
Total
Capital
O&M
Fuel
Total
2. 11
14.27
16.38
11.75
5.28
10.97
28.00
11.81
4.09
11.86
27.76
1.76
29.55
31.31
X
X
X
X
2.70
15.12
17.82
20.56
5.87
11 .71
38.14
20.67
4.68
12.70
38.05
2.35
31.11
33.46
X
X
X
X
Seasonal Peak
3.29
15.56
18.85
X
X
X
X
X
X
X
2.94
31 .90
34.84
7.86
2.70
30.65
41 .21
ui
10
Assumptions
o
I
20
s
30
9
o
Fuel Prices:
Coal Type $/mmbtu-late 1977 $'s
BD 1.43
BG 1.17
SA 1.22
Oil 2.64
NOTE: X is used in those load categories where a plant type was not allowed to operate.
-------
TABLE IV-49
COMPARISON OF 1990 SYSTEM GENERATION COSTS IN
MICHIGAN UNDER ALTERNATIVE LOADING PATTERNS
Plant Loading from 0.2-lb. Floor/
1.2-lbs.
Plant Loading from 0.5-lb. floor/
1.2-lbs. Cap/ with Exemption Case
Load
Category
Base
Plant
Type
Existing Coal
ANSPS Coal
ANSPS Coal
Total Base
Coal
Type
BD
BG
SA
Generation
(106 kwh)
33.01
22.66
_
55.67
Unit Cost
(mills/kwh)
16.38
28.00
-
Total Cost
no9 $)
0.541
0.634
-
1. 175
Generation
(109 kwh)
20.51
3.57
31 .58
55.66
Unit Cost
(mills/kwh)
16.38
28.00
27.76
Total Cost
(1C) $)
0.336
0.100
0.877
1.313
Intermediate
Seasonal Peak
Existing Coal
ANSPS Coal
Oil Steam
Total Intermediate 19.68
0.7 Steam
Turbines
Total Seasonal Peak
Total System 80.59
BD
BG
-
3.92
0.91
14.85
17.82
38. 14
33.46
0.070
0.035
0.497
11.07
2. 14
6.46
17.82
38.14
33.46
0.197
0.082
0.216
41.21
24.73
0.602
0.216
0.216
1.993
19.67
5.24
5.24
80.57
34.84
24.71
0.495
0.183
0.183
1.991
O
NOTE: Costs are from the 0.5-lb. floor/1.2-lbs. cap/with exemption case in 1990.
O
-n
1
a
3
o
-------
-141-
When the total system costs are considered, the increased costs of
adding ANSPS capacity in baseload are more than offset by the reduction
in intermediate and seasonal peak generation costs. Table IV-49 shows the
costs that would be entailed if the plants were loaded as in the 0.2-lb.
floor case with the generation costs of the 0.5-lb. floor case. The total
generation cost for the plants would be $1.993 billion. When additional
ANSPS capacity is added in baseload, loads are reduced for existing coal and
existing oil steam capacity and the new turbine capacity is not built. The
resulting total generation cost for the plants is $1.991 billion, or $2
million less. Note that the baseload generation costs increase from $1.175
billion to $1.313 billion or by $138 million. This increase is offset by
declines in intermediate load generation costs (by $107 million) and in
seasonal peak costs of (by $33 million). Thus, the savings achieved by using
existing oil steam plants rather than new turbines in seasonal peak, and
using existing coal-fired plants instead of existing oil steam plants in
intermediate, make it cost effective for additional ANSPS capacity to be
built and operated in baseload.
However, this occurs only because the ANSPS plant costs have been
reduced by the higher floor that permits partial scrubbing. The costs of
full scrubbing are such that total generation costs are optimized by building
new turbine capacity and operating the existing oil steam capacity in inter-
mediate load.
ICF INCORPORATED
-------
g.
x
>
-------
APPENDIX A
IMPLICATIONS OF COAL VARIABILITY AND AVERAGING
TIME CONSIDERATIONS, INCLUDING EFFECTS OF
ALTERNATIVE CEILINGS ON PORTION OF NATION'S COAL
RESERVES THAT COULD BE USED IN NEW UTILITY BOILERS
As indicated in the executive summary, all of the Phase I forecasts were
based on the assumption that the alternative NSPS would be stated as annual
averages (or that shorter term averages consistent with the annual averages
would be specified). However, the alternative NSPS presented to the National
Air Pollution Control Technology Advisory Committee was stated in terms of
24-hour averages (i.e., 90 percent removal of potential emissions plus a 1.2
pound of sulfur dioxide per million BTU emission limitation, both for a
24-hour average and no violations per year).
Whether this difference in averaging periods would affect the Phase I
forecasts has subsequently been investigated. This investigation led to
consideration of a) the variability of the sulfur emissions from coal, b)
the variability in scrubber removal efficiency, and c) scrubber reliability.
Based on this investigation, the following conclusions were reached:
• The Phase I forecasts presented would probably be
indicative of the standard presented to NAPCTAC if a
scrubber can be installed at the costs provided by EPA
that will comply with a requirement to remove 90 percent
of potential sulfur emissions on a 24-hour average with
no violations per year. (This requirement would also
have to be met for any day during which malfunctions
occurred.)—
• The Phase I forecasts presented would not be indica-
tive of the likely effects if a scrubber cannot comply
with this requirement.—
The bases for these conclusions are presented below.
Coal Variability
The sulfur content (percent by weight) of coal is variable within a coal
seam and within any sample tonnage. Further, the pounds of sulfur dioxide
emissions per million BTU's will vary as a result of variations in heat content
and alkaline content as well as in percent sulfur by weight.
\J Subsequent to the NAPCTAC meeting EPA staff revised their assessment of
best available control technology for SO to a minimum of 85 percent
removal on a 24-hour basis for 90 percent of the periods measured and
a minimum^of 75 percent removal for the remaining 10 percent of the
periods. This interpretation of best available control technology was
examined as part of the Phase II work and is discussed in Chapter IV.
ICF
INCORPORATED
-------
A-2
This variability is very high for small tonnages and becomes quite
low with large tonnages. For example, the ICF interpretation of the
available data- is that the relative standard deviation (RSD) — i.e.,
standard deviation as a percent of mean — for the pounds of sulfur dioxide
per million BTU's resulting from coal combustion is about .40 for 600 tons
(i.e., about a three hour burn for a 500 MW baseload plant), about .20 for
4,800 tons (i.e., about a one day burn for a 500 MW baseload plant), about
.10 for about 150,000 tons (i.e., about a one month burn), and about .01
for about 1.4 million tons (i.e., about a one year burn for a 500 MW
baseload powerplant).
Hence, an RSD of 0.20 is reasonable to use for a 24-hour average
standard for a 500 megawatt baseload plant (EPA has taken the position that
an RSD of 0.15 is appropriate for a 24-hour averaging period). However, the
24-hour average RSD for smaller and/or cycling units would be higher (i.e.,
perhaps .25) because the RSD is an inverse function of the number of tons in
the sample. A smaller and/or cycling unit would burn less coal in a day.
This phenomenon coupled with a 24-hour average cap could create incentives
for larger units and against using coal in lieu of oil at lower capacity
factors. This is because higher RSD's mean lower annual average sulfur
content coals are required to comply with emission limitations. Since lower
sulfur coals are more expensive, higher RSD's mean higher coal costs, and
vice versa for lower RSD's.
Ninety Percent Removal
Given 90 percent removal (24-hour average) and an RSD of 0.2 (or
0.25 for a smaller or cycling plant), the following logic was employed.
To comply with the 1.2 pound cap with over 99.9 percent confidence (with an
expected number of violations per year less than 0.2 but greater than zero),
utilities would have to purchase coal with an .annual average emission rate
after scrubbing four RSD's below 1.2 pounds.- This would amount to an
annual average emissions rate of 0.67 pounds of SO (i.e., 1.2 pounds /
(1 + (4 x 0.2)) = 0.67) for a .2 RSD. For a .25 RSD, the annual average
emission rate would be 0.6 pounds. EPA has taken the position that three
standard deviations would be adequate to meet EPA's compliance requirements.)
With EPA's specification of 0.15 RSD and three standard deviations, the
annual average emission rate would be 0.82 Ib. SO /mmbtu.
For a RSD of 0.2, this would correspond to an annual average sulfur
content of the delivered coal of about 3.8 percent by weight (i.e., 0.67
pounds of SO / (1 - 90 percent removal efficiency) = 6.7 pounds of S02
T/ ~PEUCo Environmental Preliminary Evaluation of Sulfur Variability in Low
Sulfur Coals From Selected Mines (November 1977).
2/ This uses a one-tail test and assumes a normal distribution.
ICF
INCORPORATED
-------
A-3
/ 2 pounds of SO, per pound of sulfur =3.3 pounds of sulfur 10 BTU x
23 million BTU's per ton =75.9 pounds per ton / 2,000 pounds per ton - 3.8
percent). For an USD of 0.25, this would correspond to an annual average
sulfur content of 3.0 pounds or about 3.5 percent by weight. For EPA's
specification, the annual average sulfur content would be 4.1 pounds or
about 4.5 percent by weight.
Hence, 90 percent removal with a 1.2 pound 24-hour average cap is
equivalent to the 90 percent case as run since only coals in excess of 3.3
Ibs. S/mbtu should be excluded from potential use by ANSPS plants. Note that
when the 24-hour scrubber efficiency is reduced to 85 percent (as was done
in Phase II) the highest sulfur category must be eliminated from potential
use. See discussion of alternative floors, ceilings and exemptions in
Chapter IV.
Eighty Percent Removal
However, the effects reported would not be valid if EPA cannot sustain
a 90 percent removal requirement on a 24-hour average, where this require-
ment included the effects of malfunction on the 24-hour average.
For example, if scrubbers were capable of an 80 percent removal require-
ment on a 24-hour average, then utilities would have to purchase coal with
half the sulfur content of the coal that would comply with the 1.2 pound
cap with 90 percent removal. This is because 80 percent removal would
result in twice the emissions as 90 percent removal for any coal type.
Hence, utilities would have to purchase coal with an annual average sulfur
content of about 1.7 to 1.9 percent by weight. (For an RSD of 0.25 and 80
percent removal: 1.2 pound cap / (1 + (4 x .25)) = 0.6 pound annual
average / (1 - .8) = 3 pounds of SO per million BTU's / 2 pounds of
SO per pound of sulfur = 1.5 pounds of sulfur per million BTU's x 23
million BTU's per ton =34.5 pounds per ton / 2,000 pounds per ton - 1.7
percent.)
Hence, 80 percent removal with a 1.2 cap (24-hour average) would
be equivalent to an annual average cap of 0.3 to 0.33 pounds (assuming that a
scrubber that will attain 80 percent removal on a 24-hour average with no
violations per year would remove 90 percent on an annual average). Such an
annual average would limit the maximum sulfur content of coal to coals less
than two percent by weight, which would eliminate much of the Nation's higher
sulfur reserves as a source of fuel for powerplants. This case was run and
is equivalent to the 0.2-lb. floor, 0.8-lb. cap, without exemption case
presented in Chapter IV. (The cases are equivalent because the 0.8-lb. cap is
with an 85 percent efficient scrubber while the 1.2-lb. cap is with a 90
percent efficient scrubber. In both cases, coals with average sulfur contents
in excess of about two percent would be excluded from new powerplant consump-
tion.)
ICF INCORPORATED
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A-4
Sulfur Content of Reserves
Table A-1 presents the Nation's coal reserve base with known sulfur
characteristics broken down into the eight states with substantial high
sulfur reserves and into six minimum average sulfur content categories.
The Nation's coal reserve base according to the Bureau of Mines is
431 billion tons. Of this total, the sulfur characteristics of 322 billion
tons (about 75 percent) are known. The table deals with the 322 billion
tons.
The table reflects the sulfur content of reserves after a moderate
level of washing. Such a level of washing will remove substantial propor-
tions of pyritic sulfur. The percentage of pyritic sulfur is large in high
sulfur coals and much smaller in lower sulfur coals. Hence, such washing
will reduce the sulfur content of raw high sulfur coal by as much as
35 percent, but will reduce the sulfur content of raw lower sulfur coals
by much less. We assumed that raw coals with more than 2.5 Ib. S/mmbtu
could have their sulfur content reduced by 35 percent; coals between 0.84 and
2.5 Ib. S/mmbtu by 15 percent; coals between 0.61 and 0.84 Ib. S/mmbtu by 5
percent; and coals less than 0.61 Ib. S/mmbtu not at all. These reductions
in sulfur are based upon the washability studies conducted by the Bureau of
Mines and spot checks with coal producers.
Of course, such a table prepared for raw coal would indicate more
reserves in the high sulfur categories.
More extensive coal preparation than assumed would reduce the sulfur
content of raw coals somewhat further, but the marginal decreases in
sulfur content would be associated with large cost increases, in terms of
capital costs, operating costs, and substantially reduced yields of both
tons and BTU's.
The source of the information presented in Table A-1 is data summaries
previously taken off the Bureau of Mines demonstrated reserve base tape.
Since these summaries did not contain all the information required, interpo-
lation was used in a few cases to fill in Table A-1. It is believed these
interpolations are not misleading. But due to the interpolations and the
uncertainties associated with the raw data, the table should be interpreted as
being indicative of the sulfur content of reserves but not as being precise.
If there is a bias in these numbers, it is one that underestimates the
quantity of higher sulfur reserves (and overestimates the quantity of lower
sulfur reserves). There is limited information that the Bureau of Mines
data have some bias toward lower sulfur contents and that the assumed
effectiveness of washing in removing sulfur may be higher than can be
achieved in practice.
Significantly, the alternative of blending the higher sulfur coal with
lower sulfur coals is not reflected in these numbers. Blending could be
practiced at the expense of higher coal handling costs, posibly higher relative
standard deviations, and coal prices for lower sulfur coals above those for
ICF
INCORPORATED
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TABLE A-1
o
Tl
o
O
3D
§
O
COAL RESERVES BY AVERAGE SULFUR CONTENT
AFTER MODERATE WASHING
billions of tons
(percent known reserves)
Total Known Reserves With
Minimum Average Sulfur Content
(pounds of sulfur per million BTU)
National
Illinois
Indiana
Iowa
Kentucky, West
Missouri
Pennsylvania
Ohio
West Virginia, North
Other
Known Sulfur Characteristics
322
66
11
3
13
10
24
21
22
152
4.00
1
( — )
0
( 0)
0
( 0)
1
(33)
0
( 0)
0
( 0)
0
( 0)
0
( 0)
0
( 0)
0
( 0)
3.50
2
( 1)
1
( 2)
0
( 0)
1
(33)
0
( 0)
0
( 0)
0
( 0)
0
( 0)
0
( 0)
0
( 0)
3.00
8
( 2)
5
( 8)
0
( 0)
1
(33)
0
( 0)
1
(10)
0
( 0)
1
( 5)
0
( 0)
0
( 0)
2.50
18
( 6)
12
(18)
1
( 9)
1
(33)
0
( 0)
2
(20)
0
( 0)
2
(10)
0
( 0)
0
( 0)
2.00
48
(15)
27
(41)
3
(27)
2
(66)
5
(38)
3
(30)
1
( 4)
5
(24)
3
(14)
0
( 0)
1 .67
79
(25)
33
(50)
5
(45)
2
(66)
7
(54)
4
(40)
5
(21)
15
(71)
6
(27)
2
( 1 )
>
-------
A-6
higher sulfur coals. For the higher sulfur coals that are marginally above
the required sulfur content, blending is clearly a viable alternative. For
those that exceed the required sulfur content by a large margin, the costs
of blending could become prohibitive. Also, the possibility of blending a
coal with a particular average sulfur content to reduce the RSD was not
considered. Qualitatively, there is the possibility that the biases (dis-
cussed above) in underestimating sulfur contents offset the biases of not
incorporating the blending options.
Table A-1 indicates that after a moderate level of washing, only about
one billion tons of reserves would have an average sulfur content greater
than four pounds of sulfur per million BTU's (or in excess of about 4.5
percent sulfur by weight). All of these reserves are in Iowa.
However, about 79 billion tons of reserves (about 25 percent) would
have an average sulfur content in excess of 1.67 pounds of sulfur per
million BTU's (or in excess of about two percent by weight). Such reserves
compose major proportions (over 40 percent) of total reserves in Illinois,
Indiana, Iowa, Missouri, and Ohio.
Based on our review of the coal variability data, the average sulfur
contents presented in the table can be interpreted as annual averages.
Portions of Reserve Base Eliminated
The following assumptions would require that new coal-fired units
would have to burn coal with a maximum annual average sulfur content of
three pounds per million BTU's in order to comply with a cap of 1.2 pounds
of sulfur dioxide per million BTU's on a 24-hour average: a) coal vari-
ability relative standard deviation (RSD) of 0.25-', b) a scrubber that can
comply with a 90 percent removal requirement on a 24-hour average (with
no violations per year), and c) a 99.9 percent confidence level (i.e., four
RSD's).
With these assumptions, the 1.2 cap (24-hour average, no violations
per year) would eliminate about eight billion tons (about two percent of
total reserves) from the market for new powerplants subject to the new
NSPS. This is because coal with an average sulfur content in excess of
three pounds could not meet the 1.2 pound limit with no violations per
year (1.2 / (1 + 4 x 0.25) / 0.1 / 2 = 3). Most of this tonnage would be
in Illinois, where about eight percent of the reserves would be eliminated.
However, under the assumption that a scrubber will remove 80 percent
(instead of 90 percent) of the sulfur dioxide on a 24-hour average (and
leaving the other assumptions unchanged), then the maximum annual average
T7"~This~Telatively high RSD would be appropriate for a relatively small unit
" at baseload or a larger unit operating in cycling mode (i.e., 0.5 capa-
city factor). A larger baseload unit would have an RSD of about 0.2,
according to the ICF interpretation of the PEDCo data. EPA believes
that 0.15 is the best estimate of the RSD for a 24-hour averaging period.
ICF INCORPORATED
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A-7
sulfur content of coal would have to be about 1.5 pounds per million
BTU's. In such a case, over 79 million tons (about 25 percent) of the
Nation's reserves would be eliminated. These reserves would be concentra-
ted in Illinois, Ohio, and other Midwestern states, where 40 to 71 percent
of total reserves in these, states would be eliminated.
Using the original assumptions (including 90 percent removal), a
lower cap of 0.8 pounds of sulfur dioxide per million BTU's would require
coal with an annual average of two pounds of sulfur per million BTU's.
This would eliminate about 48 million tons (about 15 percent) of the
Nation's reserves. These reserves would be concentrated in the Midwest,
where 24 to 66 percent of the reserves in these states would be eliminated.
As of August, 1978, the most frequent assumptions employed by EPA were
1.2 cap on a 24-hour average with exemptions (meaning two RSD's), 85 percent
removal and an RSD of 0.15. These assumptions would limit the maximum
annual average sulfur content of coal to three pounds (1.2 / 1.3 / 0.15 / 2
=3). See Table A-1 for impact on reserves.
Sensitivity Analysis
Table A-2 illustrates the amount of reserves that would be eliminated
from the market for new powerplants under alternative assumptions concern-
ing (a) the cap, (b) scrubber removal efficiency, (c) coal variability RSD,
and (d) confidence level.
Four RSD assumptions are employed (i.e., 0.10, 0.15, 0.20, and 0.25).
The 0.20 is what ICF believes is appropriate to use for a 500 MW baseload
powerplant, given the uncertainties and 0.25 for a smaller and/or cycling unit.
unit. EPA believes that 0.15 is the best estimate. Significantly, the PEDCo
coal variability data include only two observations that might be Midwestern
coals (e.g., C-2 and C-3 from Kentucky). However, neither of these is
typical of Midwestern coals since they are both for low sulfur coal (about
0.7 pounds of sulfur). They are probably from Eastern Kentucky which would
be an Appalachian coal rather than a Midwestern coal (such as from Illinois).
Three confidence levels are shown: 2, 3, and 4 RSD's. These corre-
spond to about 97.7, 99.8 and 99.9 percent confidence respectively.
These, in turn, correspond to about 8, 1, and less than one expected
violations per year, respectively.
The following conclusions can be drawn from Table A-2:
• The 1.2 cap with 90 percent removal would eliminate a small
percentage of reserves if high confidence levels (4 RSD's)
were required. Almost no reserves would be eliminated if
lower confidence levels (i.e., less than four) were required.
Even with four RSD's, if the coal variability RSD is 0.15 or
lower for high sulfur coal, almost no reserves would be
eliminated.
ICF
INCORPORATED
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TABLE A-2
COAL RESERVES ELIMINATED BY ALTERNATIVE ASSUMPTIONS
Alternative Assumptions
RESERVES ELIMINATED (%)
Scrubber
Coal
24-Hour Removal Variability
Cap,
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
0.8
0.8
0.8
0.8
0.8
0.8
Efficiency*
90
90
90
90
90
90
90
90
90
80
80
80
80
80
80
80
80
80
80
80
90
90
90
90
90
90
RSD*
.25
.20
.15
.10
.20
.20
. 15
.15
.10
.20
.20
.15
.15
.10
.10
.25
.25
.20
.15
.10
.25
.20
.20
.15
.15
. 10
Required
Confidence Annual
Level
4
4
4
4
3
2
3
2
3
4
3
4
3
4
3
3
2
2
2
2
3
4
3
4
3
3
Average**
3.0
3.5
4.0
4.5
4.0
4.5
4.0
4.5
4.5
1.5
2.0
2.0
2.0
2.5
2.5
1.5
2.0
2.0
2.5
2.5
2.5
2.0
2.5
2.5
3.0
3.0
Nation
2
1
-
0
-
0
-
0
0
25
15
15
15
6
6
25
15
15
6
6
6
15
6
6
2
2
Illinois
8
2
0
0
0
0
0
0
0
50
41
41
41
18
18
50
41
41
18
18
18
41
18
18
8
8
Indiana
0
0
0
0
0
0
0
0
0
45
27
27
27
9
9
45
27
27
9
9
9
27
9
9
0
0
Iowa
33
33
33
0
33
0
33
0
0
66
66
66
66
33
33
66
66
66
33
33
33
66
33
33
33
33
Kentucky
West
0
0
0
0
0
0
0
0
0
54
38
38
38
0
0
54
38
38
0
0
0
38
0
0
0
0
Missouri
10
0
0
0
0
0
0
0
0
40
30
30
30
20
20
40
30
30
20
20
20
30
20
20
10
10
Pennsylvania
0
0
0
0
0
0
0
0
0
21
4
4
4
0
0
21
4
4
0
0
0
4
0
0
0
0
Ohio
5
0
0
0
0
0
0
0
0
71
24
24
24
10
10
71
24
24
10
10
10
24
10
10
5
5
West
Virginia
0
0
0
0
0
0
0
0
0
27
14
14
14
0
0
27
15
15
0
0
0
15
0
0
0
0
0.8
80
.10
1.5
25
50
45
66
54
40
21
71
27
24-hour average
Rounded to nearest 0.5.
-------
A-9
The 1.2 cap with 80 percent removal would eliminate large
amounts of reserves in the Midwest:
— this is particularly true if the coal variability
RSD is 0.15 or greater and three or four RSD's are
required.
— if the coal variability RSD is 0.10 or if only two
confidence levels were required, substantially
fewer reserves would be eliminated.
The 0.8 cap with 90 percent removal would eliminate substan-
tial reserves in the Midwest if the RSD is 0.2 or greater and
if 4 RSD's were required. Less reserves would be eliminated
if the RSD is less than 0.2 or if less than 3 RSD's were
required.
The 0.8 cap with 80 percent removal would eliminate very
large amounts of reserves, even with a 0.1 RSD and only 2
RSD's.
As indicated on Table A-1 by itself and by the cases on
Table A-2, it appears that so long as the required annual
average sulfur content is not less than 2.5 to 3.0 pounds
of sulfur per million BTU's, the amount of reserves that
would be eliminated is relatively modest.
ICF INCORPORATED
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T3
T3
Q.
x
C3
-------
APPENDIX B
REFINEMENTS TO THE COAL AND ELECTRIC
UTILITIES MODEL STRUCTURE
A number of changes were made to the structure of the ICF Coal and
Electric Utilities Model for the analysis of alternative new source per-
formance standards. These modifications fall into three categories: 1)
extensions of model, 2) multiple-period forecast capability, and 3) addi-
tional reports. Each of these categories will be discussed in a section
below.
EXTENSIONS OF MODEL
The model was modified for the NSPS study for two reasons. First,
changes were necessary to model properly the proposed standards. For
example, the model's original treatment of new coal-fired capacity did not
provide some new capacity subject to one emissions standard and other new
capacity subject to another standard. This was necessary for the NSPS
analysis since the revised standard would not apply to new plants already
licensed and under construction. Similarly, the model did not initially
provide for partial scrubbing. This was considered critical to the analysis
of alternative NSPS since alternative emission floors were to be considered.
Second, changes were made to improve the model's representation of the coal
and electric utility sectors and their interaction.
Below we discuss each of the changes that were made.
Marginal New Mines — The supply curve methodology was changed to
reflect the information presented in Memo D of Appendix E of the Documenta-
tion.!" The marginal deep mine initially was identified within a region by
aTn^le estimates of marginal seam thickness and mine size for all seam
depths. In reality we would expect to see smaller mines being developed
in the thicker seams near to the surface and larger mines being developed
in the thinner and deeper seams since the total production costs for such
mines would be roughly equal. The smallness of the one set of mines would be
the result of previous development of the larger reserves in thick seam or
close to the surface. The largeness of the other set of mines would offset
the cost penalties of being in thin seams or far below the surface.
The RAMC program was modified to accept the marginal mine specifica-
tion in terms of both mine size and seam thickness by seam depth (see
Appendix C). The reserve base was allocated to seam depth as presented in
the Documentation. However, reserves were assigned to seam thickness and
ViciTlncorporated Coal and Electric Utilities Model Documentation (July
1977).
ICF INCORPORATED
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B-2
mine size based upon the new data. For example, if the marginal mine in a
depth category occured in the 48-inch category, the thick deep reserves were
uniformally distributed from 42-inches (the minimum thickness for thick
reserves) through 59 inches (the maximum thickness in the 48-inch category).
If the marginal mine size was one million tons per year, reserves were
allocated uniformly to the three smallest mine sizes 1,000,000 tons; 500,000
tons; and 100,000 tons.
Surface Mine Reclamation -- The costs of the Surface Mining Control
and Reclamation Act of 1977 were included in the coal supply curves. The
costs of the bill were estimated in terms of both fixed and variable costs
by overburden category. These costs were added to the mining costs as an
operating expense. See Appendix C for the estimates that were used.
Two Types of New Coal Plants — New coal-fired capacity was divided
into two categories: 1) those plants that currently are planned to be on
line before 1983 and 2) those plants due on line in 1983 on later. The
first category of new coal-fired capacity was subject to the current new
source performance standard. This capacity was upper bounded so that
at most a specified amount of such capacity could be built. The second
category was subject to whatever the alternative new source performance
standard was. Except for the 1985 model runs, no upper bounds were placed
on the amount of this capacity.
Partial Scrubbing — Inclusion of partial scrubbing meant that the
costs associated with scrubbing varied with the sulfur content of the coal
being used and the applicable sulfur emission limitation. One scrubbing cost
adjustment factor was developed (based upon scrubber capital costs) to adjust
all costs associated with scrubbers (capital cost, capacity penalty, O&M and
heat rate penalty). See Appendix C for complete discussion of the factors
used.
Conversion of Existing Bituminous Boilers to Subbituminous Coal — Memo
R of Appendix E of the Documentation was implemented for the ANSPS analysis.
Combined Cycle Capacity — This plant type (both existing and new) was
added to the utility sector and new oil-fired steam capacity was eliminated.
This was done since combined cycle plants have generation costs below tra-
ditional oil/gas steam plants. Oil/gas steam plants that are currently under
construction and scheduled to come on line through 1981 were included under
existing oil/gas steam capacity.
Regional Variation In Capital Charge Rate — The capital charge rate
was changed from a global parameter to a region specific one. This was
done to represent better those regions that are dominated by public rather
than private utilities (e.g., TVA dominates in Tennessee).
Pumped Storage Use of Baseload Electricity ~ Pumped storage is a gen-
eration technology that utilizes more electricity than it generates. It
uses cheap baseload electricity during off-peak hours to pump water up hill
to provide generation during peak hours. The model structure initially
ignored this link between baseload generation and pumped storage. The model
now consumes 1.4 kwh of baseload electricity for every kwh of pumped hydro
generation.
ICF
INCORPORATED
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B-3
Intermediate Load Generation Used to Meet Baseload Generation ~
Since hydro capacity dominates the plant types in the Northwest, the model-
ing of hydro is important to that region. In preliminary model runs a
significant amount of hydro capacity in region WO (Washington/Oregon) was
not being utilized. The model had excess capacity in intermediate load
and was short on capacity to meet baseload requirements. Since hydro
capacity was locked into specific load categories, the model could not use
the "excess" hydro capacity to meet baseload demands. This was considered
an error in the model's representation of reality. The model was changed
to allow hydro generation at intermediate load capacity factors to meet
baseload generation requirements in region WO.
New Industrial Coal Demand Split — The industrial sector initially
was specified to accept only one maximum sulfur level for new industrial
demand by region. However, this did not allow for the use of scrubbers by
large new sources and of low sulfur coal by small new sources. Thus, new
industrial demand was respecified to allow two estimates of demand and
maximum sulfur level by region. See Appendix C for the values used.
MULTIPLE-PERIOD FORECAST
The EPA analysis was to include forecasts for 1985, 1990 and 1995.
However, the ICF Coal and Electric Utilities Model was structured to analyze
only one year at a time. Thus, a methodology was developed to enable the
model to make forecasts that are internally consistent for the three years
specified. The methodology consisted of setting lower bounds for the 1990
run based upon the 1985 model solution and lower bounds for the 1995 run
based upon the 1990 solution. However, not all activities were bounded and
even those that were bounded were not necessarily set at their previous
level.
The coal supply curves were modified in the 1990 and 1995 runs by
reducing the production level from existing mines to account for mine clos-
ings due to reserve depletion. The minimum acceptable selling prices for
these "new existing" mines should have been changed to reflect only variable
costs. However, they were not. This omission would only create problems
if the production of a coal type in a region declined and "new existing"
capacity was closed. This phenomenon was not observed in these NSPS runs.
The transportation links were bounded on a coal type specific basis
to 80 percent of the utility coal shipped to account for long-term contracts.
The 80 percent figure was used to reflect the tendency of utilities to rely
on the spot market for 10 to 20 percent of their demand. Only utility demand
was bounded since the other demand sectors do not usually sign long-term
contracts for their coal. If the production of a specific coal in a supply
region falls below the production level called for by the 80 percent rule
because of the closing of existing mines, the transportation bounds are
reduced further to the level of existing production. The lower bounds on
transportation will not force the opening of a new mine.
Within a demand region, the coal flow from the coal piles to the
plant types also are bounded at the 80 percent level to account for long-
term contracts.
ICF INCORPORATED
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B-4
All new utility capacity built in 1985 is treated as the lower bound on
new utility capacity in 1990 (by plant type). The same holds true for 1990
and 1995. Plants that built scrubbers in 1985 are treated as having scrubbers
in 1990 and 1995. Existing plants can add scrubbers in any forecast year and
scrubbers that are built in 1985 may not be operated in 1995 if high sulfur
coal prices increase substantially faster than low sulfur coal prices increase.
Plants are not locked into specific load categories.
Electricity transmission in 1990 and 1995 were locked into the 1985
transmission flows.
ADDITIONAL REPORTS
Two new reports were developed for this analysis. They are the compli-
ance report and the capital report. Examples of each are presented in
Exhibits B-1 and B-2.
The compliance report shows how each utility plant type was operated
(load category, fuel and use of a scrubber) and the emissions it generated
(SO , TSP and NO ). The first column of the report identifies both the
plant type and whether coal plants operated with a scrubber or converted to
western coal. The second column gives the capacity for each plant type in
gigawatts. The third and fourth columns give the loading of the plant by
load category (B is baseload; I is intermediate; P is seasonal peak; and Z
is daily peak) and by capacity factor. The sixth column is the fuel con-
sumed (Bx is bituminous coal with sulfur level x; Sx is subbituminous
coal with sulfur level x; Lx is lignite with sulfur level x; PG is oil or
gas; NU is nuclear and HG is hydro). The seventh column is the amount of fuel
consumed in quadrillion btu's. The eighth column is the variable operating
cost (O&M plus fuel costs). The ninth and tenth columns show whether a full
scrubber is being used and how many GW of scrubber capacity was built. The
eleventh column gives the SO emission standard in Ibs. SO2/mmbtu. The
last three columns give the annual emission loadings in thousands of tons
for SO , NO and TSP, respectively. See Exhibit B-1.
The capital report shows the amount of capital required and the incre-
mental annualized costs for the region. The annualized costs do not include
the costs associated with existing capital or administration of the utility.
The capital costs are reported in billions of dollars by category of expendi-
ture. Since new oil/gas steam capacity planned through 1981 was included
under existing capacity, no capital cost is associated with that capacity.
There also is no capital cost associated with "Other" capacity (hydro, pumped
storage, geothermal, etc.) since the building of this capacity is locked into
the model solution. "Convert" includes the capital costs associated with
converting existing bituminous coal plants to subbituminous coal. "Trans"
includes the capital cost of long distance transmission lines. No estimate
was made for local transmission and distribution facilities. The inputed
mills per kwh estimate results from total annualized costs (fuel, O&M and
annualized capital costs) being divided by kwh sales. However, since the
annualized costs are for kwh's generated within the region, the calculation
may overstate or understate the cost to consumers in that region because of
transmission of electricity out-of or into the region. See Exhibit B-2.
ICF
INCORPORATED
-------
NEP 8T06 (l/JO/76 )
REGION MICHIGAN
0985
1. 14.
TYPE
OLD
NO SCRUBBER
EXISTING
NO 8CRU8I SIP1
NO SCRUBI 8IP2
NO SCRUBI 9IP1
CONVERT! 8IP1
NSP9 COAL,
NO SCRUBI NSP8
B»CT COAL
OIL/OA8
EX TURBINE
EX TURBINE
NEW TURBINE
EX 8TEA**
EX 8TEAH
OTHER
EX NUCLEAR
NEM NUCLEAR
ex HYDRO
EX HYDRO
EX HYDRO
TOT»L
FACILITY
616" LOAD
0.490 I
0.490
2.589 I
6.502 B
0.110 B
0.559 B
9.760
1.431 B
1.411
0.729 P
0.451 Z
0.494 P
3.434 I
0.803 P
5.911
2.200 B
3.400 B
0.105 B
0,105 I
0.955 Z
6.764
FACTOR
.400
.400
,400
,700
,700
.665
.'618
.700
.'700
,250
,080
,250
,400
.250
.324
,700
,700
.726
,369
.080
.608
BKNH
1.717
1.717
9.072
39.870
0.675
3.257
52.874
8.775
8.775
1.596
0.316
1.081
12.033
I .759
16.785
13.490
20.809
0.668
0.339
,06'
36,015
FUEL
TYPE
BO
B8
BO
Bf
SA
QUADS
0.022
0.096
0.397
0,007
0.034
VAR COST
21.090
19.179
16.819
10.598
15.451
SCRUBBER EMISSIONS
'ART 616" 8TD 802
1.660 18.509
18.51
1.200 57.480
1,660 .32C01
3.360 11.256
1*200 1J.*40
NOX
8.162
8.36
35.915
.14E01
2.512
411.97 187.35
9A
P6
P6
PG
PC
NU
NU
HG
HG
HC
0.084
0.023
0,005
0.012
0,142
0.021
14.602
40.994
01.581
33.349
33.458
34.819
7.613
8.220
1.200 11.440
«mM
• *••»
0,335
0.625
7,085
1.060
in IS
1 w. »•
aTi.10
25.080
».08
6.815
1.163
1.875
56.805
8.798
77.66
298.45
T8P
1,115
1,11
0.790
19,655
0.315
1.705
26.68
4.160
0.16
0.70S
0.141
0.175
4.251
0.616
6.11
38.09
M
CD
CD
24.356
.540 116.166
-------
NEP STD6 (1/10/78 )
REGION NlCMlGAN
0085
GIGA*ATT8
CAPITALCI*")
SUB-TOTALS
TOTAL* 0505.17
CAPITAL REPORT
I.
CONVERT TRANS
NUCLEAR
BITU*
3.000 0.
3251.62 0.
1251.62
SAITOH LIGNITE JSftfc TURBINE ^ -•• «TRO
1.031 0. 0. 0.093 0. 0. 0.
919.66 0.' 0. ««.30 0. 0. ^0.
919.66 »«.»° «• °'
0.559
39.60
39.60
0.
0.
0.
ANNUAL COST REPORT (SHM)
NUCLEAR
co»t
OIL
GAS
OTHER
9C»UBBER
CONVERT
TRANSMIT
TOTAL
IMPUTED MIL/KW
PUEL
895. 9«9
U33.B66
M 15.373
0 AND H
270.346
109.261
ao.565
060.173
o.S2«
CAPITAL
325.162
9)030
5.960
030.517
0.015
TOTAL
599.510
1137,175
S67.913
5.960
2326.556
21.717
w
s
M
03
M
H
03
I
to
-------
Q.
X
n
-------
APPENDIX C
DATA INPUTS
This appendix presents the changes made to the Coal and Electric
Utilities Model (CEUM) data base for the NSPS analysis. Very little of the
1980 data base developed for the Federal Energy Administration was usable
since this study focused on the years 1985, 1990, and 1995. Thus, consider-
able resources had to be devoted to the establishment of the new data base.
This documentation of changes does not dwell on the model structure or
the reasoning behind specific data requirements. This material is covered in
ICF's Coal and Electric Utilities Model Documentation. Since the changes
are quite extensive, we have not elaborated on the rationale for each change
or provided extensive backup. However, we have attempted to provide the
reader with enough information to follow what we did and to understand why it
was done.
This appendix is divided into four major sections. They are: coal
supply, utility coal demand, non-utility coal demand and coal transportation.
The data inputs are grouped under each of these headings, just as they appear
in the Documentation.
COAL SUPPLY
The coal supply component of the model consists of coal supply curves
for 30 coal supply regions and up to 40 coal types (five btu levels and
eight sulfur levels) per region. The supply curves are represented as step
functions with each step representing a different mine type, the length of
each step the potential annual production for that mine type and the height
of each step the minimum acceptable selling price for that mine type. These
coal supply curves interact with the demand components of the model to esti-
mate regional coal production and coal prices (FOB mine). The supply curves
contain production from existing mines and new mines. The portion of the
curve for existing mines is generated manually. For new mines, the Reserve
Allocation and Mine Costing Program (RAMC) is used to allocate the reserve
base to various types of mines, cost those mines, and translate the reserves
into an annual potential production levels. See the Documentation for a de-
scription of the methodology used to develop the coal supply curves.
For this set of model runs, some data inputs specified in the Docu-
mentation have been changed. Portions of the data base concerning existing
and new mine production were changed. A number of new factors were taken
into consideration when costing the mines. Coal preparation costs and yields
were changed for some regions, and inflation rates were specified. Each of
these modifications in the coal supply data base is discussed in a section
below.
ICF INCORPORATED
-------
C-2
KX I STING M_INE_Pl«.)_p_lJC_TlpN
Existing mines dre those mines that produced coal in 1975. For this
set of model runs, the treatment of existing production over time in both the
East and the West was specified. Spot and surge production were eliminated
from the existing portion of.the supply curves. Finally, existing production
was altered in two specific regions. Each of these changes is discussed
separately below.
• Depletion of Existing Mines - Production from existing
mines decreases over time as their reserves are
depleted. Since 20-year mine lives were assumed for
new mines, we assumed that existing mines would have
the same expected life. Therefore, all existing mines
would be depleted and existing production would go to
zero by 1995. The factors used to decrease existing pro-
duction in 1985 and 1990 differ in the East and the West,
because existing mines in the East have generally been
in operation longer than mines in the West.
East - 1985 production was set at 60 percent of
contract production levels presented in the Docu-
mentation (Table 111-11) for 1980. 1990 production
is one-third of 1985 production levels. 1995
production is zero.
West - In Texas, the Dakotas, Montana, Colorado,
Utah, Arizona, New Mexico, and Washington,
production remains constant at the 1975 level
through 1990. 1995 production is zero.
• Small Mine Production - Assigning existing small mine
production to specific coal types as was done in the
original data base misrepresents the small mine
sector. Small mines generally have short lives (two
to five years), allowing the quality of coals to
change over a decade in response to market demands.
Thus, the spot production estimates (from small mines)
developed in the Documentation were eliminated from
the existing portion of the coal supply curves. It
was assumed that small mines would still be develop-
ed, but that they are implicit in the new mine portion
of the coal supply curves. Table C-1 gives the amount
of small mine production that was deleted.
• Surge Production - The original data base included
surge production in the existing portion of the supply
curves for 1985, 1990, and 1995. Surge production is
usually production from small mines opened in response
to specific market conditons, i.e. high spot prices.
It is relevant only in the short term when new large
ICF
INCORPORATED
-------
03
TABLE C-1
1975 SMALL MINE PRODUCTION
(10 tons)
Total
Pennsylvania
Ohio
Maryland
West Virginia, North
West Virginia, South
Virginia
Kentucky, East
Tennessee
Alabama
Illinois
Indiana
Kentucky, West
Iowa
Missouri
Kansas
Arkansas
Oklahoma
NATIONAL
(PA)
(OH)
(MD)
(NV)
(SV)
(VA)
(EK)
(TN)
(AL)
(IL)
(IN)
(WK)
(IA)
(MO)
(KS)
(AR)
(OK)
24,748
5,274
1,970
5,300
12,680
14,814
32,308
4, 148
2,294
602
492
1,076
252
1,096
—
264
202
107,520
mines cannot be developed to meet increased
demand. Since the NSPS forecasts allowed enough
lead time to develop large mines, surge produc-
tion was not appropriate and was eliminated.
Regional Changes in Supply Curves - Changes were also
made in the existing production of two specific
regions, Alaska and Iowa. These are listed below:
— Existing Alaskan production was removed from
the Alaskan supply curves because all exist-
ing production in that region is committed to
Alaska, and Alaska is not one of the model's
demand regions.
— It was found that existing Iowa sub-bitu-
minous production was really low quality
bituminous coal. Therefore, existing Iowa
production of high sulfur sub-bituminous
coal was changed to high sulfur bituminous
coal and costed at $9.13 per ton in 1975
dollars.
ICF INCORPORATED
-------
C-4
NEW MINE PRODUCTION
New mine production is estimated through the RAMC program as summarized
in the Documentation (pg. 111-35). Several additions and modifications
were made in this portion of the model. Since, the Surface Mining Control
and Reclamation Act of 1977 increased the amount of illegal reserves, these
reserves had to be removed from the data base. Further changes were made in
the distribution of surface mines. For deep mines, the methodology for
allocation of reserves was altered. These modifications in the new mine
portion of the supply curves are discussed below.
Illegal Reserves
The reserve estimates presented in Appendix C of the Documentation were
used for the NSPS analyses with adjustments to take into account the passage
of the Surface Mining Control and Reclamation Act of 1977. This bill limited
the areas that could be strip mined and thus, reduced the amount of mineable
reserves. The bill was analyzed to develop estimates of the effect it would
have on reducing the size of the reserve base. The analysis of the effect of
the 1977 Act was based upon the provisions of the original Surface Mining
Control and Reclamation Act of 1976, evaluated by ICF in a report submitted
to the EPA and the Council on Environmental Quality.- Where changes were
made in the 1977 legislation, the estimates were updated.
The bill stipulated four areas where mining is legally or technically
restricted. These restrictions are listed below:
1) Alluvial Valley Floors - excluded land that is
important to the maintenance of the level and
quality of the water table.
2) Surface Owner Protection - required consent from
certain specified surface owners be obtained be-
fore federal coal beneath private land is mined.
3) National Forests - excluded national forests from
mineable areas. (Eighty percent of these ex-
cluded reserves are beneath Montana's Custer Na-
t ional Forest.)
4) Extremely Steep Slopes - specified that slopes
whose angles are greater than 20° must be re-
turned to their approximate original contour,
while slopes with angles greater than 37° are
technologically infeasible to mine.
1/ ICK Inc. Enoryy and Economic Impacts of H.R. 13950 (Surface Mining
Control and Reclamation Act of 1976), Washington, D.C.: ICF Inc.,
September, 1976.
ICF
INCORPORATED
-------
C-5
These criteria were used to estimate losses to the total reserve base
in each region, as shown in Table C-2. The tonnage losses were translated
into percentage losses in the total strippable reserves present in each state.
See Table C-3. In Missouri, Utah, and New Mexico, where the loss percentages
were relatively insignificant (less than 0.5 percent) no reserve data base
change was made. The percentages in Table C-3 were added to the original
estimates of surface reserves illegal to mine to get the values used in the
RAMC data base. These values are presented in Table C-4.
TABLE C-4
ILLEGAL SURFACE RESERVE ADJUSTMENT FACTORS
FOR SELECTED REGIONS
(percent of reserves)
Region Factor Region Factor
OH .21 ND .15
NV .25 SD .16
SV .18 EM .14
VA .20 WM .30
EK .23 WY .14
AL .17 CN .11
IN .29 CS .11
Adjustments were also made for deep reserves under highway urban areas
or beneath parks, all of which are included in the BOM data base. Adjustment
factors were developed to account for such reserves. It was assumed that
urban development would be the greatest in the Midwestern regions of Illinois,
Indiana, and Western Kentucky, where a 0.2 adjustment factor was used. In
Appalachia, where urban development is less, a 0.1 adjustment factor was
used.
SURFACE MINES
Review of announced new mines in the West led to revision in the mine
size distribution. The distribution of surface mines was moved to larger
mines such that 40 percent was allocated to the 4 million tons/year category,
30 percent to the 3 million tons/year category, 20 percent to the 2 million
tons/ year category and 10 percent to the 1 million tons/year category.
These changes took place in surface mines in Texas, the Dakotas, Montana,
Wyoming, and Northern Colorado.
Analysis of additional information on western reserves- resulted in
a change in the allocated overburden ratio categories for lignite and sub-
bituminous coals. The majority of the surface mineable reserves in those
T/""Ro'be"rt"¥7~Matson and John W. Blumer, Quality and Reserves of Strippable
Coal, Selected Deposits, Southeastern Montana, Bulletin 91. Montana
Bureau of Mines and Geology, December 1973.
ICF
INCORPORATED
-------
PIES Region
Northern Appalchia
Central Appalachia
C-6
TABLE C-2
STRIPPABLE RESERVE BASE IMPACT OS SURFACE
MINING CONTROL AND RECLAMATION ACT OF 1977
(millions short tons)
Alluvial Surface
NCM Valley Owner National
Region Floors -Consent Forests
PA
OH 187.00
MO
NV 100.00
SV
VA 15.00
EK 77.00*
TN
Southern Appalachia AL 2.50
Midwest
Central West
Gulf
Eastern Northern
Great Plains
Western Northern
Great Plains
*
Rockies
SOlltllWOKt
Northwest:
Alaska
TOTAL
IL
IN 50.00
WK
IA
MO 6.50
KN
AR
OK
TX
ND 462.96 116.00
SD 12.48
EM 49.26 13.24
MW 1,182.18 317.76 5,900.00
WY 690.00 194.50
CN 0.45 0.44
CS 2.91 2.86
UT 0.20
AZ
NM 9.10
WA .
A'K
U.S. 2,400.24 654.10 6,338.00
Extremely
Steep
Slopes Total
0.00
187.00
0.00
100.00
84.20 84.20
15.70 30.70
80.10 157.10
0.00
2.50
0.00
50.00
0.00
0.00
6.50
0.00
0.00
0.00
0.00
578.96
12.48
62.50
7,399.90
884.50
0.89
5.77
0.20
0.00
9.10
0.00
0.00
180.0 9,572.34
* Initially, 500 million tons were estimated to have been removed from the reserve
base. However, BOM data indicate that only 77 million tons of reserves exist in
the counties affected. All of these reserves were removed.
ICF
INCORPORATED
-------
C-7
TABLE C-3
RESERVE BASE ADJUSTMENTS DUE TO THE
SURFACE MINING CONTROL AND RECLAMATION ACT OF 1977
Region
OH
NV
SV
VA
EK
AL
IN
MO
ND
SD
EM
WM
WY
CN
CS
UT
MM
Total
Total Estimated Losses
Due to SMCR Act
(millions of short tons)
187.0
100.0
84.2
30.7
157. 1
2.5
50.0
6.5
579.0
12.
62.
7,399.9
884.5
0.9
5.8
0.2
9.1
9,572.4
Surface Mineable
Demonstrated Reserve Base*
(millions of short tons)
3,280.7
961.4
2,672.8
586.3
1,927.2
112.4
1,317.7
1,497.6
12,576.0
200.0
1,529.7
36,833.4
23,410.1
115.0
743.0
244.0
2,258.3
90,265.5
Losses as a Percent
of Surface Mineable
Reserves
5.7
10.4
3.2
5.4
8.2
2.2
3.8
0.4
4.6
6.2
4.1
20.1
3.8
0.8
0.8
0.1
0.4
10.6
* Rounded to the nearest 100,000 tons.
NOTE: For those regions where reserve losses represented less than 0.5
percent of total reserves, no change was made in the reserve base.
ICF
INCORPORATED
-------
5:1
60
60
60
60
80
80
80
10:1
40
40
40
40
15
15
15
15:1
0
0
0
0
5
5
5
20:1
0
0
0
0
0
0
0
C-8
regions were assigned to the 5 yards of overburden per ton of coal category,
as can be seen in Table C-5.
TABLE C-5
OVERBURDEN DISTRIBUTION FOR SURFACE MINES
FOR SELECTED REGIONS IN THE WEST
(percent of reserves)
"Overburden Ratio
Region
TX
ND
SD
EM
WM
WY
CN
Deep Mines - The supply curve methodology was changed to reflect the
information presented in Memo D of Appendix E of the Documentation. The •
marginal deep mine initially was identified within a region by depths. In
reality we would expect to see smaller mines being developed in the thicker
seams near to the surface and larger mines being developed in the thinner
and deeper seams since the total production costs for such mines would be
roughly equal. The smallness of the one set of mines would be the result
of previous development of the larger reserves in thick seam or close to
the surface. The largeness of the other set of mines would offset the cost
penalties of being in thin seams or far below the surface.
The RAMC program was modified to accept the marginal mine specifica-
tion in terms of both mine size and seam thickness by seam depth. The
reserve base was allocated to seam depth as presented in the Documentation
(see Table 111-19 of the Documentation). However, reserves were assigned
to seam thickness and mine size based upon the new data. For example, using
Table C-6 we can see that the marginal mine size in Ohio at the 400-foot
depth and 48 inch seam is 1,000,000 tons per year. Since no mines are
identified for thicker seams, reserves assigned to the 400-foot depth are
located uniformly between 59 inches (the upper end of the 48-inch thickness
category) and 42 inches (the lower end of the BOM definition of thick reserves).
The reserves then are uniformly distributed to the mine size categories.
Since the maximum mine size in the 48-inch seam category was 1.0 mmtpy, the
reserves are allocated uniformly to 1.0 mmtpy mines, 0.5 mmtpy mines and 0.1
mmtpy mines.
MINE COSTING
A series of refinements were made to the methodology for costing mines.
Tlirso refinements are presented in a series of memoranda included in Appen-
dix K of the Documentation. They will be summarized below (the model inputs
also are included):
ICF
INCORPORATED
-------
C-9
Minimum
Seam
Thickness
Depth (inches)
Drift 72
60
48
36
28
400' 72
60
48
36
28
700' 72
60
48
36
28
1000' 72
60
48
36
28
TABLE C-6
MAXIMUM ALLOWABLE MINE SIZE
(millions of tons/year)
NCM Region
East
PA,MD
0
0
0
0.1
0.5
0
0
0.1
0.5
0.5
0.5
0.5
1.0
1.0
0.5
0.5
0.5
1.0
1.0
0.5
OH
0
0
1.0
1.0
0.5
0
0.1
1.0
1.0
0.5
0
0.5
2.0
1.0
0.5
0
3.0
2.0
1.0
0.5
NV
0
0.5
0.5
1.0
0.5
0
0.5
1.0
1.0
0.5
0
0.5
1.0
1.0
0.5
0
0.5
2.0
1.0
0.5
SV,EK
0.1
0.1
0.5
1.0
0.5
0.5
0.5
1.0
1.0
0.5
1.0
1.0
2.0
1.0
0.5
2.0
2.0
2.0
1.0
0.5
VA
1.0
2.0
2.0
1.0
0.5
1.0
2.0
2.0
1.0
0.5
1.0
2.0
2.0
1.0
0.5
1.0
2.0
2.0
1.0
0.5
TN,AL
0.5
1.0
2.0
1.0
0.5
0.5
1.0
2.0
1.0
0.5
0.5
1.0
2.0
1.0
0.5
0.5
1.0
2.0
1.0
0.5
IL,IN
_
-
-
-
-
3.0
3.0
2.0
1.0
0.5
3.0
2.0
2.0
1.0
0.5
3.0
3.0
2.0
1.0
0.5
WV
0
0
1.0
1.0
0.5
0
0
2.0
1.0
0.5
0
0
2.0
1.0
0.5
0
0
2.0
1.0
0.5
West
0
0
0
0
0
3.0
3.0
2.0
1.0
0.5
3.0
3.0
2.0
1.0
0.5
3.0
3.0
2.0
1.0
0.5
ICF INCORPORATED
-------
C-10
• Productivity Estimates - The 10 percent adjustment
factor for the productivity of a drift mine was
dropped from the cost adjustment factor table. See
Memo E of the Documentation.
• Base case surface mine productivity was changed to
45 tons per manday. See Memo E.
• Wage Rates - Wage rates for surface and deep mines
were changed to $71.00 per manday for surface mines
and $63.00 per manday for deep mines. See Memo F.
• Exposure Insurance Premiums - Insurance premiums for
Black Lung Disease and for traumas were incorporated
in the model. Coal mining exposure rates vary by type
of mine and location and are applicable only to those
persons actually working in the mines. These rates
were calculated by state and by mine type. The min-
ing exposure factors listed in Memo G in the Docu-
mentation were updated and are presented in Table C-7.
• UMW Welfare Fund - The UMW agreements (National Bit-
uminous Coal Wage Agreement of 1974 and the Western
Surface Coal Wage Agreement of 1975) included pro-
visions for welfare fund payments. A new algorithm
was developed to treat these contributions which
covers annual output after cleaning losses and esti-
mates the output per union manday assuming a super-
visor contract worker ratio of 1:5. The result is
higher per ton union welfare contribution for mines
with low productivity than for mines with high pro-
ductivity. The welfare fund cost for small deep
mines is $1.63/ton, while for large surface mines in
the West the cost is $0.80/ton. See Memo I.
• Average Manday Adjustment Factors - The number of
mandays worked per year varies by the type of mine
and the location of the mine. Thus, the output of
the mines being costed were adjusted accordingly.
Regional cost adjustment factors were developed for
surface and deep mines based upon the ratio between
the average mandays for mines in that region and
the mandays for the base case model mines. These
factors are presented in Table C-8. See Memo K.
• State Severance Taxes - State coal severance taxes
are included in the model when costing mines (see
Memo L). These severance taxes have been updated
and are included in Table C-9.
• Reclamation Costs - Cost estimates were developed
for total reclamation costs resulting from H.R. 2,
the Surface Mining Control and Reclamation Act of
1977. The bulk of the analysis was done for H.R.
ICF
INCORPORATED
-------
C-11
TABLE C-7
COAL MINING EXPOSURE FACTORS*
Type of Mine
PIES Region
Northern Appalachia
Central Appalachia
Southern Appalachia
Midwest
Central West
Gulf
Eastern Northern Great Plains
Western Northern Great Plains
Rockies
Southwest
Region
PA
OH
MD
NV
SV
VA
EK
TN
AL
IL
IN
WX
IA
MO
KN
AR
OK
TX
ND
SD
EM
WM
WY
CN
CS
UT
AZ
NM
Underground
.34
.34
.31
.18
.18
.31
.23
.25
.23
.32
.21
.23
.26
.33
.33
.22
.23
N/A
N/A
N/A
N/A
.26
.24
.22
.22
.31
.39
.23
Surface
.18
.18
.10
.06
.06
.16
.09
.06
.05
.20
.14
.09
.07
.10
.08
.09
.06
.16
.09
.09
.07
.07
.14
.08
.08
.08
.14
.07
Northwest WA .23 .13
*Coal Mine Exposure Cost by Region = (CME Factor) x (Director Labor Cost).
N/A - not applicable.
ICF INCORPORATED
-------
C-12
TABLE C-8
ADJUSTMENT FACTORS FOR DAYS WORKED
PIES Region for Surface Mines
1972-1973 Surface 1972-1973 Deep /
Averaye Mandays Adjustment Average Mandays Adjustment
Factors for Deep Mines Factors
Northern Appalachia
Central Appalachia
Southern Appalachia
Midwest
Central West
Gulf
Eastern Northern Great
Plains
Western Northern Great
Plains
Rockies
Southwest
Northwest
Alaska
230
180
230
260
260
300
250
280
280
280
260
300
0.92
0.72
0.92
1.04
1.04
1.20
1.00
1. 12
1. 12
1. 12
1.04
1.20
230
220
230
250
250
-
—
240
240
240
200
240
1.05
1.00
1.05
1. 14
1. 14
—
__
1.09
1.09
1.09
0.91
1.09
-------
C-13
TABLE C-9
STATE SEVERANCE TAX INPUTS
Dollars Per Ton
_ Percent of Sales (1975 $'s)
PA ~
OH - °-04
MD -
NV 3.85
SV 3.85
VA ~
EK 4.5
ipN — 0.18
AL - 0.31
IL ~
IN ~
WK 4.5
IA -
MO -
KS -
AR - 0.02
OK -
TX -
ND - 0.58
SD 0.6
EM 2°'°1/
WM 30.0-
WY 10.5 -,/
CN - 0.26-'
CS - 0.26-'
UT -
AZ -
NM - 0.34
WA - f
AK 1.00-
V This value is for surface mines. There is a different tax for deep
mines, (i.e., 20 percent), however, the structure of the program only
allows for a single input. Since the cheapest to mine reserves are
surface, the surface severance tax was used for all mines.
2/ This value is for deep mines. There is a different tax for surface
mines (i.e., $0.60 per ton in 1977 dollars). Since deep reserves
account for the bulk of Colorado's reserves, the deep mine severance
tax was used.
3/ This value was improperly inputted as 2 percent. However, the error
~ was small and probably did not prevent Alaskan coal from being used.
ICF INCORPORATED
-------
C-14
13950, the Surface Mining Control and Reclamation
Act of 1976.— This work was updated based up-
on the changes made in the legislation as passed by
Congress. The approach to this analysis and the
development of the associated costs is presented in
Attachment I to this Appendix. The fixed costs for
reclamation activities are presented in Table C-10,
while variable costs are presented in Table C-11.
Fixed costs are inflated to the year that the mine
is brought on line; variable costs are inflated
throughout the forecast period.
• Abandoned Mine and Reclamation Fee - The Surface
Mining Control and Reclamation Act of 1977 also
added the Abandoned Mine and Reclamation Fee.
The following values were added to the appropriate
annual price in 'nominal dollars before it is dis-
counted and converted into an annuity: for surface
bituminous and sub-bituminous mines, $0.35 per ton;
for surface lignite mines, $0.10 per ton; for deep
mines, $0.15 per ton. Although this tax expires in
August, 1992, it is contained in the mine costs for
the entire life of the mines.
• Federal Royalties - Recent legislation on federal
coal leases made payment of royalties on all new
Federal coal leases and existing leases that come
up for renewal a requirement. These royalties
amounted to 12.5 percent of the sales price on
coals from surface mines and 8 percent on coals
.from deep mines. To implement this increase in
cost, the royalties were applied to all mines in
Montana, Wyoming, Colorado, and New Mexico, where
more than half of the coal lands are federally
owned.
COAL PREPARATION
Two types of coal cleaning are permitted for bituminous coals within
the structure of the model: 1) a basic level of cleaning for all bitumi-
nous coals which is done within RAMC, and 2) a deep level of cleaning to
lowi>r C and E sulfur level coals to B and D coals, respectively, provided for
within the model structure. This is modeled by reducing the number of tons
shipped from a mine (see Memo O in the Documentation). Yield factors are
associated with mine output to account for losses due to coal cleaning. In
addition, cleaning costs are assessed. The model inputs are given in Table
C-12.
I/ ICF Inc. "Energy and Economic Impact of H.R. 13950 (Surface Mining
Control, and Reclamation Act of 1976)," Draft Final Report, February,
1977.
ICF
INCORPORATED
-------
C-15
TABLE C-10
FIXED COSTS FOR RECLAMATION ACTIVITIES
(1975 $/annual ton)
Overburden Ratio
Northern Appalachia
Central Appalachia
Southern Appalachia
Midwest
Central West
Gulf
Eastern Northern
Great Plains
Western Northern
Great Plains
Rockies
Southwest
Northwest
Alaska
PA
OH
MD
NV
SV
VA
EK
TN
AL
IL
IN
WK
IA
MO
KN
AR
OK
TX
ND
SD
EM
MW
WY
CN
CS
UT
AZ
NM
5:1
1.74
1.59
1.74
1.74
1.56
1.56
1.56
1.24
1.15
.13
.14
.13
.19
.15
.19
.18
.15
.11
.14
.14
.11
.11
.11
.15
.15
—
.11
.13
10:1
2.77
2.63
2.77
2.78
2.90
2.91
2.90
2.28
2.18
.19
.20
.20
.25
.21
.25
.225
.21
.17
.21
.21
.17
.17
.17
.21
.22
— —
.17
.19
15:1
3.63
3.49
3.63
3.63
4.28
4.29
4.28
3.14
3.04
.25
.26
.26
.31
.27
.31
.31
.27
.23
.26
.26
.23
.23
.23
.27
.27
— —
.23
.25
20:1
4.61
4.46
4.61
4.61
5.65
5.65
5.65
4.12
4.02
.29
.30
.30
.35
.31
.35
.35
.31
.27
.30
.30
.27
.27
.27
.31
.31
~""
.27
.29
25:1
5.44
5.29
5.43
5.44
7.10
7.10
7.10
4.94
4.84
.34
.35
.34
.40
.36
.40
.39
.36
.31
.35
.35
.32
.32
.32
.36
.36
"™ — "
.32
.34
30:1
6.39
6.24
6.38
6.39
8.48
8.48
8.48
5.89
5.80
.37
.37
.37
.43
.38
.42
.42
.38
.34
.38
.38
.34
.34
.35
.39
.39
.35
.36
45:1
9.25
9.10
9.25
9.25
12.64
12.64
12.64
8.75
8.65
.40
.41
.40
.46
.42
.46
.45
.41
.37
.41
.41
.38
.38
.38
.42
.42
.38
.39
WA
AK
.12
.16
,18
.22
.24
.28
.28
.32
.33
.37
.35
.39
.39
.42
ICF INCORPORATED
-------
C-16
TABLE C-1 1
VARIABLE COSTS FOR RECLAMATION ACTIVITIES
(1975 $/annual ton)
Overburden Ratio
Northern Appalachia
Central AppaInch in
Southern Appalachia
Midwest
Central West
Gulf
Eastern Northern
Croat Pla i ns
Western Northern
Great Plains
Rouk.i es
Southwest
Northwest
Alaska
PA
OH
MD
NV
SV
VA
EK
TN
AL
IL
IN
WK
IA
MO
KN
AR
OK
TX
NO
SD
EM
MW
WY
CN
CS
UT
AZ
NM
5:1
1.33
1.31
1.32
1.26
1.57
1.61
1.54
1.31
1.34
.22
.25
.22
.24
.27
.40
.40
.42
.17
.14
.14
.09
.09
.09
.17
.17
--
.11
.13
10: 1
2.08
2.06
2.07
2.01
2.54
2.58
2.51
2.06
2.09
.27
.29
.27
.28
.31
.44
.44
.46
.22
.19
.19
.14
. 14
. 13
.21
.22
—
.16
.17
15:1
2.69
2.67
2.69
2.63
3.53
3.58
3.50
2.67
2.70
.31
.33
.31
.32
.35
.48
.48
.30
.25
.22
.22
.18
.18
. 17
.25
.26
—
.20
.21
20:1
3.40
3.38
3.39
3.33
4.51
4.56
4.48
3.38
3.41
.33
.35
.30
.35
.38
.51
.51
.52
.28
.25
.25
.20
.20
.20
.28
.28
.22
.24
25: 1
3.99
3.97
3.98
3.92
5.55
5.60
5.52
3.97
4.00
.36
.39
.34
.38
.41
.54
.54
.56
.31
.28
.28
.24
.24
.23
.31
.32
.25
.27
30:1
4.68
4.65
4.67
4.61
6.55
6.59
6.52
4.66
4.68
.38
.40
.37
.40
.43
.56
.56
.57
.33
.30
.38
.25
.25
.25
.33
.33
•~ —
.27
.29
45: 1
6.74
6.71
6.73
6.67
9.55
9.59
9.52
6.71
6.74
.40
.43
.40
.42
.45
.58
.58
.60
.35
.32
.32
.28
.28
.27
.35
.36
__
.29
.31
WA
AK
.10
.10
.15
.14
19
,18
.21
.21
.25
.24
.26
.26
.29
.23
ICF
INCORPORATED
-------
C-17
TABLE C-12
COAL CLEANING FACTORS FOR BITUMINOUS COAL
Incremental Incremental Incremental
Type of Coal Cleaning Level Yield Fixed Cost ($/ton) O&M Costs ($/ton)
Steam Basic .800 1.14 0.56
Deep* .920 2.03 1.67
**
Metallurgical
Appalachia Basic .600 3.17 2.23
Deep* .920 2.03 1.67
Rest of Country Basic .700 3.17 2.23
Deep* .920 2.03 1.67
~~Th~e"de~ep cleaning level costs are the incremental costs above basic prepar-
ation. Thus, the combined yield for deep cleaned steam coal would be .736
(.8 x .92 = .736).
** Metallurgical coals included coals with more than 26 million btus per
ton and less than 0.83 Ib. S/mmbtu (i.e., ZA through ZD coals).
Basic cleaning yield factors are less for metallurgical coals because seams
are usually thinner and the mining process is such that more dilution of the
coal occurs. Consequently, greater cleaning is necessary to bring the coal
back to its in situ quality. See Memo A in the Documentation.
INFLATION
For capital, a real escalation of 0.5 percent per year was assumed above
the general rate of inflation of 5.5 percent. Labor and power and supplies
were inflated at the general rate of inflation. The internal rate of return
for coal companies was assumed to be 15 percent.
UTILITY COAL DEMAND
Changes were made in a number of the model inputs to the electric utili-
ties sector of the model. The growth rates for electricity consumption were
altered. Load duration curves and capacity factors for each load category in
each region were developed from actual annual load duration curves from
utilities. Data on the existing and planned electrical generation capacity
were updated, including development of new cost estimates. Oil and gas
prices and availability data were brought up to date. Electricity transmis-
sion links and costs were specified in greater detail, and pollutant emission
factors were developed. Each of these changes to the model inputs will be
discussed in a section below.
ICF
INCORPORATED
-------
C-18
ELECTRICITY SALES PROJECTIONS AND GROWTH RATES
Projections of future electricity sales vary widely. For the NSPS
analysis, an attempt was made to frame the range of likely electricity sales.
Thus, two sets of model runs were made based upon alternative electricity
growth rates, a low growth rate (Reference Case I) and a high growth rate
(Reference Case II). Two sources were used to obtain these alternative
yrowth rates. For the low growth rate case, the PIES base case model runs
for the President's National Energy Plan were used. For the high case, the
National Electric Reliability Council reports were utilized.
The NSPS runs required sales projections for three years: 1985, 1990,
and 1995. For 1985 the sales forecast for both sets of runs was the same
since PIES and NERC had essentially the same national electricity sales
forecast for that year. For Reference Case I, the PIES 1990 national projec-
tion of 3.4 percent growth rate in electricity sales from 1985 was used.
This was extended through 1995 since no PIES forecast existed for 1995. The
national growth rate for Reference Case II was obtained from the FPC's
Electric Power Supply and Demand 1977-1986 As Projected by the Regional
Electric Reliability Councils In Their April 1, 1977 Responses to FPC Order
383-4 Docket R-362 (May 16, 1977). This source provided electricity generation
forecasts through 1986. The 5.5 percent growth rate between 1980 and
1985 was continued through 1990 and 1995. These National growth rates and
resulting national electricity sales projections for both reference cases
are given in Table C-13.
TABLE C-13
NATIONAL ELECTRICITY GROWTH RATES
Reference Case I Reference Case II
Sales Growth Rate Sales Growth Rate
9 9
(10 Kwh) (Percent) (10 Kwh) (Percent)
1975 1,726 - 1,726
1985 3,036 5.8 3,036 5.8
1990 3,582 3.4 3,968 5.5
1995 4,226 3.4 5,186 5.5
The regional sales projections were developed using the NERC regional
growth forecasts to obtain the national level developed above. This process
consisted of four steps. First, each CEUM region was assigned the same
growth as was forecasted for the NERC region in which it falls. If a CEUM
region falls in more than on NERC region, NERC growth rates were weighted
by the kwh sales. Second these rates were adjusted by the ratio of the
national NERC forecasted growth rate and the desired national growth rate.
For example, the initial regional growth rates were based upon a national
ICF
INCORPORATED
-------
C-19
NERC growth rate of 5.8 percent. When the national growth rate was reduced
to 3.4 percent, all required growth rates were multiplied by 0.59 (3.4 / 5.8
= 0.59). Third, projected regional sales using these adjusted growth rates
were calculated and summed to get a national total. Finally, the regional
sales forecasts were multiplied by the ratio of the summed initial regional
forecasts and the previously estimated national sales forecast. For example,
if the initial regional forecasts for 1990 (Reference Case I) summed to
3 500, all regional sales estimates would be multiplied by 1.023 (3,852
national sales forecast / 3,500 sum of initial regional forecasts = 1.023).
This approach would yield the national electricity sales forecasts developed
previously. The resulting regional growth rates are presented in C-14,
and the resulting regional sales projections are presented in Tables C-15 and
C-16.
LOAD DURATION CURVES
Electricity demand in each region is divided into four categories: base,
intermediate, seasonal peak and daily peak. Each load category is character-
ized by the percent of total kwh's accounted for by that category and the
average capacity factor for plants generating electricity for that load. The
average capacity factor for all load categories weighted by the kwh's in each
category equals the system load factor divided by one plus the fractional re
serve margin. Thus system load factors, reserve margins and annual load du
ration curves are required to develop the model inputs. The sources for each
of these data elements and the methodology used to develop the inputs are dis-
cussed below.
To develop the model inputs, load factors were obtained from representa-
tive utility companies in each region. Using these load factors and estimated
reserve margins for each utility, average annual capacity factors could be
projected. The estimated regional reserve margins were developed from FPC
information and yield roughly a 20 percent national reserve margin. Table
C-17 presents the representative utility load factors, the estimated regional
reserve margins, and the projected average system capacity factors for each
CEUM region.
Load duration curves for 1975 also were obtained from many of the repre-
sentative utility companies. For those regions where we did not obtain the
load duration curve from the representative utility, the load duration curve
for a utility company with a similar load factor in a nearby region was used.
Table C-18 lists utility load duration curves that were used and the regions
for which they were used.
The curves were divided into the four load categories, where the load
categories were defined by a percent of hours in a year, as follows:
Daily Peak — load present 15 percent of the year or less
Seasonal Peak — load present 16 percent to 40 percent of the year
Intermediate — load present 41 percent to 80 percent of the year
Baae — load present more than 80 percent of the year
ICF INCORPORATED
-------
C-20
TABLE C-14
REGIONAL ELECTRICITY GROWTH RATES
(percent)
Reference Cases I & II Reference Case I Reference Case II
Ke^j i on
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SV
ON
OM
OS
MI
IL
IN
WI
WK
ET
WT
AM
DM
KN
IA
MO
AO
TX
MW
UN
CO
AN
WO
CN
C.S
1975-1985
5.5
5.6
3.8
4.5
5.0
6.8
6.1
7.0
6.5
5.2
6.1
6.1
6.1
6.1
5.9
5.8
6.0
5.2
5.2
5.8
5.8
8.0
6.4
6.0
6.4
6.2
6.5
5.7
5.5
5.3
4.9
5.2
5.3
5.2
5.2
1985-1990
3.2
3.2
2.1
2.4
2.8
3.3
4.0
4.0
3.8
3.2
3.3
3.3
3.3
3.3
3.5
3.3
3.5
3.3
3.3
3.2
3.2
4.5
.3.9
3.8
3.9
3.8
3.8
3.4
3.1
3.1
3. 1
3.1
3.1
3.1
3.1
1990-1995
3.2
3.2
2.1
2.4
2.7
3.3
4.0
4.0
3.8
3.1
3.3
3.3
3.3
3.3
3.5
3.3
3.5
3.3
3.3
3.2
3.2
4.5
3.8
3.8
3.8
3.8
3.8
3.4
3.1
3.1
3.1
3. 1
3.1
3. 1
3.1
1985-1990
5.0
5. 1
3.4
4. 1
4.6
6.4
5.7
8.1
6.0
4.7
5.6
5.6
5.6
5.7
5.5
5.4
5.5
4.8
4.8
5.3
5.3
7.6
6.0
5.6
5.6
5.7
6.0
5.2
5.1
4.5
4.8
4.8
4.8
4.8
4.8
1990-1995
5.0
5.1
3.4
4.0
4.5
6.3
5.6
8.0
6.0
4.6
5.6
5.6
5.6
5.6
5.5
5.3
5.5
4.7
4.7
5.3
5.3
7.5
5.9
5.5
5.5
5.7
6.0
5.2
5.0
4.7
4.5
4.7
4.8
4.8
4.8
ICF
INCORPORATED
-------
C-21
TABLE C-15
ELECTRICITY SALES PROJECTIONS FOR REFERENCE CASE I
(Low Growth)
(in 10 kwh)
Region 1975 1985 1990 1995
MV
MC
New Enijland
NU
PJ
WP
Middle Atlantic
VM
WV
CA
GF
SF
South Atlantic
ON
OM
OS
MI
IL
IN
WI
East North Central
EK
WK
ET
HT
AM
East South Central
DM
KN
IA
MO
West North Central
AO
TX
West South Central
MW
UN
CO
AN
Mountain
WO
CN
CS
Pacific 235.08 392.37 457.23 532.62
NATIONAL 1,725.86 3,035.93 3,582.01 4,226.22
14.27
52.62
55.89
50.63
132.47
43.98
227.08
77.18
16.95
80.04
69.53
42.59
286.29
24.68
33.20
46.64
62.64
84.98
47.51
31.16
330.81
10.28
36.54
32.41
32.57
60.80
172.60
33.53
29.66
20.05
32.69
115.93
78.78
128.37
207.15
26.18
15.19
15.67
26.99
84.03
91.71
60.17
83.20
24.32
90.32
114.64
73.81
206.35
71.71
351.87
149.09
30.76
156.77
130.51
70.45
537.58
44.58
59.95
84.24
113.71
151.45
83.61
55.62
593.16
17.07
60.66
56.71
57.00
131.42
322.86
62.51
53.26
37.13
59.48
212.38
147.86
222.89
370.75
44.82
25.46
25.17
44.87
140.32
153.34
100.31
138.72
28.42
105.55
133.97
81.92
232.63
82.16
396.71
175.67
37.40
190.60
157.46
82.30
643.43
52.53
70.64
99.26
133.99
179.93
98.52
66.08
700.95
20.12
71 .48
66.44
66.78
163.74
388.56
75.53
64.20
44.87
71.69
256.29
178.22
263.14
441.36
52.23
29.67
29.33
52.28
163.51
178.69
116.89
161.65
33.20
123.27
156.47
90.86
262.19
94.08
447.13
206.90
45.43
231.50
189.84
96.03
769.70
61.87
83.02
116.91
157.81
213.54
116.04
78.42
827.79
23.70
84.19
77.79
78.19
203.93
467.80
91.21
77.34
54.18
86.37
309.10
214.69
310.45
525.14
60.84
34.56
34.17
60.90
190.47
208.16
136.16
188.30
-------
C-22
TABLE C-16
ELECTRICITY SALES PROJECTIONS FOR REFERENCE CASE II
(High Growth)
(in 10 kwh)
Region 1975 19B5 1990 1995
MV
MC
New Enyland
NU
PJ
WP
Middle Atlantic
VM
WV
CA
GF
SF
South Atlantic
ON
CM
OS
MI
IL
IN
WI
East North Central
EK
WK
ET
WT
AM
East South Central
DM
KN
IA
MO
West North Central
AO
TX
West South Central
MW
UN
CO
AN
Mountain
WO
CN
CS
pacific 235.08 392.37 496.31 626.34
NATIONAL 1,725.86 3,035.93 3,967.82 5,185.72
14.27
52.62
66.89
50.63
132.47
43.98
227.08
77.18
16.95
80.04
69.53
42.59
286.29
24.68
33.20
46.64
62.64
84.98
47.51
31.16
330.81
10.28
36.54
32.41
32.57
60.80
172.60
33.53
29.66
20.05
32.69
115.93
78.78
128.37
207.15
26.18
15.19
15.67
26.99
84.03
91 .71
60.17
83.20
24.32
90.32
114.64
73.81
206.35
71.71
351.87
149.09
30.76
156.77
130.511
70.45
537.58
44.58
59.95
84.24
113.71
151.45
83.61
55.62
593.16
17.07
60.66
56.71
57.00
131.42
322.86
62.51
53.26
37.13
59.48
212.38
147.86
222.89
370.75
44.82
25.46
25.17
44.87
140.32
153.34
100.31
138.72
31.09
115.88
146.97
87.25
252.14
89.65
429.04
202.87
40.57
231.36
175.06
88.59
738.45
58.66
78.87
110.84
150.00
197.96
108.60
72.75
777.68
21 .54
76.52
73.44
73.83
189.17
434.50
83.56
69.89
49.47
78.55
281.47
198.32
287.54
485.86
57.42
31.71
31.77
56.64
177.54
194.13
126.81
175.37
39.64
148.32
187.96
102.91
307.40
111.81
522.12
275.42
53.38
340.66
234.28
111.13
1, 014.87
77.01
103.52
145.51
197.40
258.14
140.72
94.93
1,017.23
27.10
96.31
94.90
95.41
271.67
585.39
111.44
91.46
65.75
103.50
372.15
265.40
370.09
635.49
73.38
39.89
39.56
71.34
224.17
245.20
159.93
221.21
-------
C-23
TABLE C-17
PROJECTED AVERAGE REGIONAL CAPACITY FACTORS
Actual
1975 Estimated Average Projected Average
CEUM
Region
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
OM
OS
MI
IL
IN
WI
EK
WK
ET
WT
AM
DM
KN
IA
MO
AO
TX
MW
UN
CO
AN
WO
CN
CS
Load
Long Run
Representative Utility System Factor Reserve Margin*
Public Service Co. of New Hampshire
Boston Edison Co.
Niagara Mohawk Power Corp.
Public Service Electric S Gas Co.
Pennsylvania Electric Co.
Virginia Electric Power Co.
Monongahela Power Co.
Carolina Power and Light
Georgia Power Co.
Florida Power and Light
The Cleveland Electric Illuminating Co.
Ohio Edison Co.
The Ohio Power Co.
Consumers Power Co.
Commonwealth Edison Co.
Public Service Company of Indiana, Inc.
Wisconsin Electric Power Co.
Kentucky Utilities Co.
Louisville Gas and Electric Co.
Tennessee Valley Authority
Tennessee Valley Authority
Alabama Power Co.
Northern States Power Co.
The Kansas Power & Light Co.
Iowa Power and Light Co.
Union Electric Co.
Arkansas Power and Light Co.
Texas Power and Light Co.
The Montana Power Co.
Utah Power and Light Co.
Public Service Company of Colorado
Arizona Public Service co.
Pacific Power and Light Co.
Pacific Gas and Electric Co.
Southern California Edison Co.
.564
.579
.673
.533
.642
.550
.649
.581
.568
.599
.652
.664
• oby
.661
.560
.611
.599
.604
.525
.647
.647
CQ-l
• DO J
.534
.488
.481
.515
.509
.500
.689
.628
.662
.544
.642
.623
.603
* Developed from Table 15 of FPCfs Electric Power Supply
by the Regional Electric Reliability Councils in their
.20
.20
.30
ft c
• 25
.20
.20
. 20
. 20
.1 5
. 20
.20
.20
.20
.20
.15
.20
.15
.20
.20
.20
.20
.15
.20
.15
. 15
. c
. 1 J
.20
.20
.25
.15
.20
.30
.25
.25
.20
Regional
Capacity Factor
.471
.481
coo
« J L J
.426
.536
.457
.542
.483
.494
.499
. 542
C 1 1
. 553
.560
. 552
.487
.507
c ft i
. 503
C A(\
• D4U
.510
.454
. 424
A 1 "7
• 4 1 /
.449
.427
A 1 Q
.4IO
. 554
.551
. 554
A 1 C
. 4 ID
.513
• 498
. 502
.nrt Demand 1977-1986 as Projected
April 1, 1977
Responses to FPC
_ n^ .
Order 383-4 Docket R-362 (May 16,
-------
C-24
TABLE C-18
LOAD CURVES USED TO DETERMINE
DISTRIBUTION OF KWH TO LOAD CATEGORIES
REGION
MV Public Service Company of New Hampshire
MC Boston Edison Company
WP Pennsylvania Electric Company
pj Public Service Electric and Gas Company
NU Niagara Mohawk Power Corporation
VM Virginia Electric Power Company
WV Monongahela Power Company
CA Carolina Power and Light
GF Georgia Power Company
SF Florida Power and Light Company
ON Ohio Edison Company
OM Ohio Edison Company
OS Ohio Edison Company
MI Consumers Power Company
IL Commonwealth Edison Company
WK Commonwealth Edison Company
IN Public Service Company of Indiana, Inc.
WI Public Service Company of Indiana, Inc.
EK Public Service Company of Indiana, Inc.
ET Tennessee Valley Authority
WT Tennessee Valley Authority
AM Alabama Power Company
DM Northern States Power Company
KM The Kansas Power and Light Company
IA The Kansas Power and Light Company
MO Union Electric Company
AO Arkansas Power and Light Company
TX Arkansas Power and Light Company
MW Public Service Company of Colorado
UN Public Service Company of Colorado
CO Public Service Company of Colorado
AN Arizona Public Service Company
wo Pacific Gas and Electric Company
CN Pacific Gas and Electric Company
CS Southern California Edison Company
ICF
INCORPORATED
-------
C-25
A sample load duration curve for Boston Edison Company is presented in
Figure C-1. This curve was used for CEUM region MC. Using the definitions
of the load categories presented above, we can calculate that 72.4 percent of
the total kwh's is accounted for in baseload, 20.6 percent in intermediate
load, 5.6 percent in seasonal peak and 1.4 percent in daily peak. The
capacity factor for each load category is estimated based upon the average
system capacity factor previously developed and the percent of kwh's in each
load category. The capacity factor for each load category was limited to a
specified range:
Daily Peak : 0.05-0.09
Seasonal Peak: 0.20-0.25
Intermediate : 0.30-0.42
Base : 0.65-0.70
For seasonal peak or base load the capacity factor was rounded to the near-
est 0.05 to limit the number of possible combinations that would result in
the same system average. The capacity factors for base, seasonal peak, and
daily peak were initialized at 0.65, 0.25 and 0.08 with the intermediate
capacity factor solved for given the system average capacity factor and the
distribution of kwh's to load categories. If the resulting capacity factor
falls outside of the permissible range of 0.30-0.42, the capacity factors in
the other load categories were adjusted. The process was repeated until all
capacity factors fell within the ranges given above. This process is illu-
strated below for CEUM Region MC.
Assume that the following values for capacity factors are chosen initi-
ally:
Percent Capacity
Load Category of Kwh Factor
Base 72.4 .65
Intermediate 20.6 x
Seasonal Peak 5.6 .25
Daily Peak 1.4 .05
We know that the sum of the kwh's weighted by the capacity factors must equal
the inverse of the average system capacity factor of 0.481 (see Table C-17).
Given this, we solve for the capacity factor for the intermediate as demon-
strated below.
.724 .206 .056 .OV4 1_
.65 x .25 .05 .481
1.618 + = 2.080
x
x = .445
ICF INCORPORATED
-------
Figure C-l
100
75
CALCULATION OF LOAD
CATEGORIES FROM LOAD DURATION'
CURVES
(Example from Boston Edison Co. 1975)
Caily Peak 1.4% of Total Load
0)
IX
I
d
OP
50
25
I 2000
15%
Seasonal Peak - 5.6% of Total Load
Intermediate - 20.6% of
Total Load
Base - 72.4% of
Total Load
4000 6000
Annual Hours
42%
8,000 '8,760 hrs.
which is present 15% of the year or less is Daily Peak.
which Is Present 15% to 40% of the year is Seasonal Peak.
Load which is present 40% of the year is Intermediate.
Load which is present over 80% of the year is Base.
-------
C-27
The value "x, " or the capacity factors for intermediate load category, is
greater than the permitted maximum of .42. Therefore, we increase the base
load capacity factor to .70 and repeat the calculation:
.724 .206 .056 .014 1
.70 x . 25 . 05 .481
1.538 .206 _ 2.080
+ —
x
x = .38
This value for the intermediate capacity factor falls within the permitted
range. Thus, the capacity factors for each load category have been determined.
Table C-19 gives the percent of kwh in each load category and the capacity
factor for each load category for the 35 demand regions.
Note that the solution is not unique. Other combinations of capacity
factor could have been used and still meet the requirement of equalling the
average system capacity factor. However, the impact of alternative capacity
factors would be small given the narrow range of possible capacity factors
for each load category and the requirement of having a single system average.
GENERATING CAPACITY
In general, generating capacity is characterized in the model by the
date of operation of the plant and by the type of fuel used by the power-
plants. In the former case, there are both existing and new plants. Exist-
ing capacity is that capacity in operation as of December 31, 1975. This is
based upon the FEA Inventory of Powerplants in the United States (July 1977)
as well as the Regional Electric Reliability Council Reports to the FPC in
1977. New capacity is capacity scheduled to come on line after December 31,
1975. For some types of powerplants, this capacity is limited to the
announced plans of utility companies. These limits on new capacity and
existing capacity figures will be discussed further below.
In addition to categorizing generating capacity by date of operation,
powerplants are characterized according to the type of fuel they use.
There are six types of powerplants: coal-fired plants, oil/gas steam plants,
oil/gas turbines, combined cycle plants, nuclear plants and hydroelectric
and other (geothermal) plants.
Existing and new generating capacity and the sources of that capacity
for each fuel type will be discussed in the paragraphs that follow. For
most plant types, both existing and new capacity figures were updated from
the inputs presented in the Documentation.
National existing capacity is presented by plant type in Table C-20.
All generation calculations for existing steam plants are based upon capa-
bility rather than nameplate capacity, with capability estimated to be 95
percent of nameplate capacity for steam plants. Capability is the relevant
basis for all planning and associated capacities and cost estimates for new
pi
ICF
INCORPORATED
-------
C-28
TABLE C-19
LOAD CURVES
Sea sona1 Peak
Daily Peak
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
OM
OS
MI
IN
IL
WI
EK
WK
ET
WT
AM
DM
KN
IA
MO
AO
TX
MW
CO
UN
AN
WO
CN
CS
Base Loac
Percentage of
Total Load
72.2
72.4
78.8
74.9
78.4
77.6
81 .3
76.2
76.0
73.3
78.0
78.0
78.0
76.8
75.7
76.2
76.2
76.2
75.7
85.3
85.3
76.8
75.7
76.6
76.6
77.0
76.0
76.0
79.4
79.4
79.4
76.6
79.9
79.9
77.1
1
Capacity
Factor
.70
.70
.6b
.65
.70
.65
.70
.65
.70
.70
.70
.70
.70
.70
.65
.70
.70
.70
.65
.65
.65
.70
.65
.65
.65
.65
.65
.65
.70
.70
.70
.65
.70
.70
.70
i !iut:i uieu.La 1.1
Percentage of
Total Load
21 .2
20.6
16.3
18.5
16.3
15.7
14.4
17.5
16.8
18.6
16.9
16.9
16.9
18.8
18.5
17.9
17.9
17.9
18.5
10.0
10.0
16.1
18.5
14.5
14.5
15.5
14.3
14.3
16.7
16.7
16.7
12.8
15.0
15.0
17.7
; uvsavt
Capacity
Factor
.35
.38
.39
.32
.37
.36
.34
.38
.34
.39
.36
.39
.41
.40
.37
.35
.39
.34
.33
.38
.38
.41
.36
.35
.36
.36
.36
.32
.40
.40
.39
.34
.36
.35
.35
Percentage of
Total Load
5.2
5.6
3.9
4.4
3.9
4.9
3. 1
4. 1
5.2
6.6
4.3
4.3
4.3
3.6
4.1
4.3
4.3
4.3
4. 1
3.5
3.5
4.3
4.1
4.9
4.9
3.7
6.5
6.5
2.6
2.b
2.6
7.0
3.5
3.5
3.6
Capacity
Factor
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
.20
.25
.25
.25
.25
.25
.20
.25
.25
.25
.25
.25
.25
.25
.25
.25
.25
Percentage of
Total Load
1.4
1.4
1.0
2.2
1.2
1.8
1 . 1
2.2
1.9
1.5
0.7
0.7
0.7
0.8
1.8
1.6
1.6
1.6
1.8
1.1
1.1
2.7
1.8
4.0
4.0
3.7
3.1
3. 1
1.2
1.2
1.2
2.7
1.5
1.5
1.6
Capacity
Factor
.05
.05
.08
.05
.08
.05
.08
.08
.08
.07
.08
.08
.08
.08
.08
.08
.08
.08
.05
.08
.08
.09
.05
.08
.08
.08
.06
. 06
.08
.08
.08
.05
.06
.05
.06
-------
C-29
TABLE C-20
EXISTING GENERATING CAPACITY AS OF
DECEMBER 31, 1975
(GW)
Nameplate Capability
Coal-Steam
High heat rate plants 7.8 7.4
Existing plants with scrubbers* 6.0 5.7
Existing plants without scrubbers 178.5 169.6
Total 192.3 182.7
Oil/gas steam plants** 156.1 148.3
Oil/gas turbines 42.1 42.1
Nuclear 38.3 38.3
Combined Cycle 2.7 2.7
Hydro, Pumped Storage and Other 65.8 65.8
TOTAL 497.3 479.9
* Includes existing plants that do not currently have scrub-
bers but are building or have signed a letter of intent for
a scrubber.
** This figure includes 23.1 GW of capacity under ESECA orders
to convert to coal. This capacity was treated as coal-
fired capacity in the NSPS model runs since the conversions
were assumed to have taken place by 1985. Thus, existing
coal-fired capability in the model runs was 204.6 GW
((192.3 + 23.1) x .95 = 204.63). An additional 19.3 GW of
oil/gas steam capacity is planned to come on line by 1981
and was treated as existing plants in the coal model runs.
Thus, existing oil/gas steam capability In the model runs
was 145.6 GW ((156.6 - 23.1) x .95 + 19.3 = 145.6).
ICF
INCORPORATED
-------
C-30
Coa 1 -_F i red_ P^Lant s_
Existing coal-fired plants are specified by five plant types: old
plants with high heat rates (greater than 12,000 btu/kwh), plants that have
scrubbers, and plants that do not have scrubbers but must meet one of three
SIP standards. Existing coal-fired capacity (including ESECA conversion) is
presented in Table C-21 along with the rank of coal and maximum sulfur
content of coal the existing plants can burn without SO controls. Plants
with scrubbers include plants that have retrofitted scrubbers, plants that
have scrubbers under construction and plants that have contracts for scrubbers
to be built or have signed letters of intent saying that a scrubber will be
installed. Existing plants without scrubbers are restricted according to the
types of coal they are allowed to burn by SIP standard. The SIP restrictions
are based upon the EPA document entitled "The SASD Interpretation of the
State Implementation Plan SO Regulations for Coal-Firing as of July 15,
1977." For those states without emission standards or with ambient air
standards, it was assumed the plants burn the same type of coal they burned
in 1976. Table C-22 gives the SO emission standard specified for each
category of existing coal plant.
Some utility companies are considering the possibility of switching
some of their existing bituminous powerplants to sub-bituminous coal. The
costs and penalties associated with this change in coal type were developed
and added to the model. These values are discussed in Memorandum R (Docu-
mentation, Appendix E) and summarized below in Table C-23.
TABLE C-23
EFFECT OF CONVERSION FROM BITUMINOUS TO
SUB-BITUMINOUS COAL IN EXISTING PLANTS
Parameter Impact
Capital Cost $50/kw
Capacity 5 percent lower capacity factor
O&M Cost 0.46 mills/kwh
Heat Rate 5 percent higher heat rate
Conversions to subbituminous coal were not permitted in those regions
furthest from the Western coalfields where the conversion would be least
economic or in the West where the availability of low sulfur subbituminous
coal was taken into account in the original fuel decision. These regions
include: MV, MC, WP, PJ, VM, CA, GF, AO, TX, MW, UN, CO, AN, WO, CN and
CS.
Heat rates were also adjusted to reflect the change in capacity factors.
.In general, heat rates for coal plants increase as the capacity factor
declines. For every percentage point decline in the capacity factor, the
he.it rate was increased from the base heat rates in Table 111-35 of the
Documentation by 20 btus per kwh.
ICF
INCORPORATED
-------
BLE
EXISTING COAL-FIRED NAMEPLATE CAPACITY AS OF DECEMBER 31, 1975
BY RANK AND SIP STANDARD (INCLUDES ESECA CONVERSIONS)
New England
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Rockies
Pacific
Capacity
w/ Scrubber —
MW Rank
HV
MC
NU 100 B
PJ 325 B
WP 704 B
VM
WV
GF
SF
ON
CM
OS
MI
IL 1,081 B
IN 115 B
WI
EK
WK 795 B
AM 550 B
DM
KN 987 B
LA
MO 256 B
AO
TX
MW 333 S/B
UN 228 B
CO
AN 443 B
wo
CN
CS
Capacity w/o Scrubber -
> 12, 000 Heat Rate
MW
99
111
211
562
80
193
312
-
-
275
395
222
516
988
852
536
-
301
496
499
631
40
_
86
69
362
-
-
-
Highest
Rank S Level
B
B
B
B
B
B
B
-
—
B
B
B
B
B
B
B
-
B
L/S/B
B
B
B
-
L/S/B
B
S/B
-
-
-
D
B
F
F
F
D
D
-
— '
F
F
D
D
D
B
G
-
D
F
F
G
H
-
D
D
B
-
-
-
Capacity
SIP
KW
560
1,696
728
8,052
1,504
4,464
10,536
11,933
2,689
"
2,906
480
2,587
3,314
5,048
7,207
819
176
3,098
1, 700
1, 486
3,395
460
977
2,624
2, 082
63
1, 168
738
1,422
1,698
3, 776
35
Standard
A
Highest
Rank S Level
B
B
B
B
B
B
B
B
B
B
B
B
B
S/B
B
S/B
B
B
B
B
B
L/S/B
B
B
B
B
L/S/B
S/B
S/B
S/B
S/B
B
-
G
A
D
I/
y
D
D
D
3/
B
B
B
B
D
B
B
D
B
B
B
B
B
D
G
D
F
B
A
A
A
B
D
-
w/o Scrul
SIP
MW
1,356
1,935
919
124
4, 204
1,632
2,553
2,521
1,586
56
6,687
6,844
4,494
2,391
2,073
354
113
2,013
990
2,945
2,791
903
619
1, 186
1,977
189
249
~
1,330
-
Dber - <1
Standard
2,000 H
B
Highest
Rank S Level
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
S/B
B
B
VS/B
S/B
S/B
S/B
~
S/B
-
B
F
D
0
F
F
F
D
D
F
F
D
D
F
F
F
D
F
F
D
F
F
F
D
B
D
B
F
-
leat Rate
SIP Standard
C
Highest
MW Rank S Level
438 B
4, 149 B
7,581 B
-
8, 553 B
139 B
1,802 B
4,614 B
116 B
4,577 B
2, 266 B
1,915 B
1,513 B
4,952 B
3,856 B
3,576 B
837 L/S/B
5, 294 B
-
643 B
322 B
-
-
D
F
F
-
G
H
H
H
F
H
H
G
G
G
G
F
F
H
-
D
B
-
-
Total
MW
659
3,601
2,974
14, 007
9,994
8,861
12,480
14,486
13, 763
4,906
2,733
14, 110
10,790
16, 871
12,831
5, 343
2,043
8,958
3,713
6,332
10, 767
4, 584
3, 366
3 255
10,767
63
2,354
3, 134
2,551
2,631
4 219
1, 365
-
NATIONAL
5,953
7,836
89, 241
55,035
57,143
V Existing Plants with scrubbers were allowed to burn any sulfur level of coal.
2/ Must fully scrub sulfur level F (80 percent removal) or partially scrub lower sulfur coals.
3/ Must fully scrubb sulfur level D (80 percent removal) or partially scrub lower sulfur coals.
215,388
-------
C-32
TABLE C-22
SO STANDARD SPECIFIED FOR
EXISTING COAL-FIRED PLANTS WITHOUT SCRUBBERS
(Ibs SO /mmbtu)
Plant Category
igign
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
OM
OS
MI
IL
IN
WI
EK
WK
ET
WT
AM
DM
KN
IA
MO
AO
TX
MW
UN
CO
AN
WO
CN
CS
>12, 000
1
1
3
3
3
1
1
3
3
1
1
1
1
5
1
3
3
5
6
1
1
1
Heat Rate
.66
.2
.36
.36
.36
.66
.66
-
-
-
.36
.36
.66
.66
.66
.2
.0
-
-
-
-
.66
.36
.36
.0
.0
-
-
.66
.66
.2
-
-
-
-
SIP A
5.
0.
1.
0.
0.
1.
1.
1.
0.
1.
1.
1.
1.
1.
1.
1.
1.
1.
1.
1.
1.
1.
1.
5.
1.
3.
1.
0.
0.
0.
1.
1.
0
8
66
332
672
66
66
66
332
-
2
2
2
2
66
2
2
66
2
2
2
2
2
66
0
66
36
2
8
8
8
2
66
-
-
SIP B
1
3
1
1
3
3
3
1
1
3
3
1
1
3
3
3
1
3
3
1
3
3
3
3
1
1
1
3
_
.2
.36
.66
.66
.36
.36
.36
.66
-
.66
.36
.36
.66
.66
.36
.36
.36
.66
.36
.36
.66
.36
.36
-
.36
-
.36
.2
.66
.2
-
.36
-
-
SIP C
1.
3.
3.
6.
6.
6.
3.
6.
6.
5.
5.
5.
5.
3.
3.
6.
1.
1.
_
66
-
36
36
-
-
-
-
-
0
0
0
36
0
0
0
0
0
-
0
36
36
-
-
0
-
-
-
66
2
-
-
-
-
ICF
INCORPORATED
-------
C-33
was
limited according to the environmental rd*f™£2 were assumed
is presented in Table C-24.
scrubber capacity for »SPS ^^^^
NSPS is lover bounded. These estimates are based upon
region in Table C-25.
Environ»ent,l standards also are set «*££**%££
•« MSPS
scenario is specified in Table C-26.
Oil and Gas Plants
plants were allowed to be built by the model.
its, 1976-
(FPC, January 1977): "Summary Report -
Boilers" Kidder-Peabody and Co. (March
ICF
INCORPORATED
-------
C-34
TABLE C-24
PLANNED COAL STEAM CAPACITY ADDITIONS
(MW)
Region
MV
MC
NU
WP
VM
WV
CA
GF
ON
CM
OS
MI
IL
IN
WI
EK
WK
AM
DM
KN
IA
MO
AO
TX
MW
CO
UN
AN
WO
CN
CS
SK
PJ
ET
WT
NSPS
Additions
through 1982
-
-
700
'3,077
400
2,552
1,280
4, 582
-
1,350
1, 115
1,431
2,686
7, 793
2, 814
880
4, 085
3, 865
5,692
5, 173
2,377
3, 580
7, 718
14,641
4,960
2,970
2, 082
4, 358
500
-
-
-
-
-
-
ANSPS
Additions
1983-1985
-
-
1,700
800
800
-
1, 720
4,393
-
975
806
2, 154
550
1, 100
-
500
2,445
683
1,700
980
-
300
5,090
7, 500
1, 230
1,430
750
680
-
-
750
—
—
-
-
Total
(MW)
-
—
2,400
3,877
1,200
2,552
3,000
8,975
—
2,325
1,921
3, 585
3,236
8,893
2,814
1,380
6,530
4, 548
7,392
6, 153
2, 377
3,880
12, 808
22, 141
6, 190
4, 400
2,832
5, 038
500
—
750
— •
—
—
—
Nat ional
93,041
39,186
132,227
ICF
INCORPORATED
-------
C-35
TABLE C-25
LOWER BOUNDS ON SCRUBBERS
FOR NEW COAL PLANTS
(in MW)
Region
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
DM
OS
MI
IL
IN
WI
EK
NSPS
Plants
2,427
1,252
280
750
1,100
770
880
Region
WK
ET
WT
AM
DM
KN
IA
MO
AO
TX
MW
UN
CO
AN
WO
CN
CS
National
NSPS
Plants
1,120
780
2,728
1,360
200
4, 150
2,730
932
2,092
23,561
ICF INCORPORATED
-------
C-36
TABLE C-26
SO., STANDARD SPKC 1 I-'IEI) IN NKW
COAL-!•'! UKI) PLANTS
(Ibs. So /mmbtu)
Standard
Reckon
MW
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
OM
OS
Ml
IL
IN
WI
EK
WK
ET
WT
AM
OM
KN
IA
MO
AO
TX
MW
UN
CO
AN
WO
CN
CS
1.2 Ibs/mmbtu 90% Removal*
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1 .2
1.2
1.2
1.2
1.2
1 .2
1.2
1.2
1.2
1 .2
1.2
1.2
1.2
0.24 0.24
0.24 0.24
0.24 0.24
0.672
1.2
0.672
0.24 0.24
50% Removal** 0.5 Ibs/mmbtu
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0-24 0.24
0.24 0.24
0.24 0.24
0.672 0.5
0.5
0.672 0.5
0.24 0.24
0 . 8 Ibs/mmbtu
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.24
0.24
0.24
0.672
0.8
0.672
0.24
* Must scrub all coals with 90 percent efficient scrubber, except in speci-
I ieil western regions.
** Must scrub all coals with BO percent efficient scrubber, except in speci-
fied western regions.
ICF INCORPORATED
-------
C-37
plants have converted to coal,-' these plants were removed from the oil/gas
steam category and included in the coal-fired steam category. Regional exist-
ing oil and gas steam capacity is given in Table C-27 along with the ESECA
capacity, the new plant capacity and the oil/gas steam inputted into the
model.
Oil/gas steam plants were allowed to function in daily peaking cate-
gories, because recent work; indicate that they can be used in this load
category. The heat rate for oil/gas steam plants used in daily peak load
categories is set 10 percent higher than the heat rate for existing turbines
in the same region to encourage the model to use the existing turbines before
existing oil/gas steam plants.
Oil and gas turbines are only allowed in daily and seasonal peaking
loads. The heat raes and capacity factors have not changed from those
given in the Documentation (pg. Ill - 85).
Combined Cycle Plants
For these model runs a new type of plant was added to the generating
capacity. In the previous model data base, combined cycle capacity was
included as part of the oil and gas steam capacity. However, the PIES model
identified combined cycle plants as a major competitor with coal-fired
plants for intermediate load electricity. Thus, a separate category for
combined cycle plants was created.
A ban on new combined cycle plants was assumed to be a likely part
of the National Energy Plan and was included in this analysis. The proposed
legislation prohibits combined cycle plants except in regions where environ-
mental restrictions could prohibit the construction of coal plants. New
combined cycle was limited to those plants that are scheduled to be on line
by 1982, since construction has already begun. Only in Southern California
was the model allowed to build more combined cycle capacity than is currently
planned. Existing and new combined cycle capacity is given in Table C-28.
The following heat rates were specified for these plants:
• existing combined cycle plants in baseload — 9, 600
btu/kwh, with 20 btu increase in the heat rate for
each percentage point decrease in the capacity factor.
• new combined cycle plants in baseload — 8,200 btu/kwh.
• existing and new combined cycle in daily peaking —
same heat rate as new oil/gas turbines.
V This was still the case as of February 28, 1978, at which time expected
ESECA conversions were reduced to 14,672 MW, or 8,461 MW less than the
amount specified in the NSPS model runs.
ICF INCORPORATED
-------
C-38
TABLE C-27
OIL AND GAS STEAM CAPACITY
(MW)
Kocjion
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
OM
OS
MI
IL
IN
WI
EK
WK
ET
WT
AM
DM
KN
IA
MO
AO
'['X
MW
CO
UN
AN
WO
CN
CS
NATIONAL
Namepiate Capacity
Total
Existiny
1, 092
9, 218
884
18,883
263
9,809
1,651
5, 112
8,362
442
188
284
3,232
2,311
540
481
476
176
2,481
400
4, 190
1, 164
1,443
19, 014
37, 038
160
317
760
3, 334
149
7, 489
14,733
ESECA
169
3,490
400
7,451
142
4,982
646
1,316
—
—
—
—
358
740
—
75
—
::
25
82
1,503
598
1,018
63
—
—
75
—
—
—
—
—
Remaining
Existing
923
5,728
484
11,432
121
4,827
1,005
3,796
8,362
442
188
284
2,874
1,571
540
406
476
176
2,456
318
2,687
566
425
18,951
37,038
160
242
760
3,334
149
7,489
14,733
Capability*
Remaining
Existing
877
5,442
460
10,860
115
4,586
955
3,606
7,944
420
179
270
2,730
1,492
513
386
452
167
2, 333
302
2,553
538
404
18,003
35, 186
152
230
722
3, 167
142
7, 115
13,996
New
Through
1981
600
643
1,700
2,421
—
1,840
—
1,331
2,355
—
—
—
1,507
2,504
—
—
—
~~
~™
—
—
—
—
1,429
2,633
—
—
—
—
53
—
292
Total
1,477
6,085
2, 160
13,281
115
6,426
955
4,937
10,299
420
179
270
4,237
3,996
513
386
452
167
2,333
302
2,553
538
404
19,432
37,819
152
230
722
3, 167
195
7, 115
14,288
156,076
23,133
132,943 126,296
19,308
145,604
Capability is 95 percent of nameplate capacity.
ICF
INCORPORATED
-------
C-39
TABLE C-28
COMBINED CYCLE CAPACITY
(in MW)
Region
MC
PJ
WP
CA
SF
ON
MO
AO
TX
AN
WO
CN
CS
NATIONAL
Existing As Of
12/31/75
90
246
160
135
217
85
510
543
290
410
Planned Through
1982
310
484
315
225
168
298
262
2,686
2,062
ICF
INCORPORATED
-------
C-40
Nuclear Plants
Tho model inputs for existing and new nuclear capacity were altered from
those given i.n the Documentation. Existing nuclear capacity was developed
from the FEA Inventory of Powerplants and the NERC information. New nuclear
capacity was locked in the model based on planned capacity additions through
1990 and expected national nuclear capacity in 1995 because of the complexity
of the planning, licensing and construction processes for nuclear plants.
For 1985 and 1990 new nuclear capacity was specified by CEUM region.
These estimates were based upon the "best" estimate of the "Domestic Nuclear
Capacity Forecast" by NRC, FEA, and ERDA. Since the projections were aggre-
gated by the agencies involved, ICF used its lists of projected nuclear capa-
city to disaggregate the projections to CEUM regions. For 1995, nuclear ca-
pacity was limited to a national increase by 125 GW over the 1990 case. The
model was allowed to distribute this capacity to the individual regions based
upon the relative costs of coal-fired capacity and nuclear capacity.
The existing and new nuclear build limits are presented for each region
in Table C-29.
Hydro Electric and Geothermal Capacity
Existing hydroelectric and geothermal capacities were extended to be the
same as the data given in the Documentation. However, a data input error
lead to an increase of 0.7 GW of hydro capacity and 1.8 GW of pumped storage
capacity in western Pennsylvania. Thus, the model results are based upon
existing hydro capacities that are too high in western Pennsylvania.
The new hydro capacity through 1985 is presented in Table C-30.—
Capacity factors for the hydroelectric and geothermal powerplants are given in
Table 111-41 of the Documentation. However, changes were made to the hydro
capacity factors in regions MW, WO and CN because the new capacity being added
in these regions is to existing dams to allow for greater intermediate load
generation (see discussion in Memo P of Appendix E in the Documentation).
Thus, baseload and intermediate capacity factors for existing and new plants
in those regions were changed to:
I/ Subsequent review of the raw data indicates that an error in addition
was made in the original model hydroelectric capacity inputs for the ET,
WO and GK regions.
The original model input were: These inputs should have been
(In MW) (In MW)
In 1985 In 1985
~HY PS HY PS
ET (existing) 0 0 ET (existing) 1,161 106
GK (new) 412 1,015 GF (new) 412 1,112
WO (new) 8,375 200 WO (new) 5,508 200
ICF
INCORPORATED
-------
C-41
TABLE C-29
NUCLEAR BUILD LIMITS
Existing as of
New
Region December 31, 1975 1976-1985
MV
MC
New England
NU
PJ
WP
Middle Atlantic
VM
WV
CA
GF
SF
South Atlantic
ON
CM
OS
MI
IL
IN
WI
East North Central
EK
WK
ET
WT
AM
East South Central
DN
XN
IA
MO
West North Central
AO
TX
West South Central
MW
CO
UN
AN
Mountain
WO
CN
CS
Pacific
TOTAL UNITED STATES
CUMULATIVE
1.4
2.8
4.2
1.6
5.0
-
6.6
2.2
-
3.9
0.7
2.0
8.8
-
-
-
2.2
4.5
-
2.0
8.7
-
-
-
-
2.0
2.0
2.0
1.2
0.6
-
3.8
0.8
_
0.8
-
-
-
-
-
2.0
1.0
0.4
3.4
38.3
38.3
_
1 .2
1.2
1.1
0.2
1.7
13.0
4.4
-
7.2
2.6
0.8
15.2
2.1
-
0.8
3.4
7.6
1.1
-
15.0
-
-
4.6
-
6.4
11 .0
-
1.2
-
1. 1
2.3
4.2
4.8
9.0
-
0.3
-
1.2
1.5
1.417
2.2
2.2
5.8
74.0
112.3
1986-1990
2.4
3.5
5.9
2.4
4.4
-
6.8
-
-
9.0
1.1
-
10.1
5.5
-
1.2
1.2
-
1.8
3.0
12.7
-
-
2.5
5.3
3.8
11.6
-
-
1 /
2.2-
2.2
2.1
1.2
3.3
-
-
-
2.5
2.5
6.3
- ,
3.0—
9.3
64.4
176.7
V Only 1.2 QW were identified.
2/ Unidentified portion of Region V was assumed to be located in CS.
-------
C-42
Region
'['ABLE C-30
NEW HYDRO AND OTHER CAPACITY
(in MW)
Hydro
Pumped Storage
Other
Total
J
MV
MC
NLI
PJ
WP
VM
WV
CA
GF
SK
ON
OM
OS
MI
IL
IN
WI
EK
WL
ET
WT
AM
DM
KN
IA
MO
AO
TX
MW
CO
UN
AN
WO
CN
CS
A
12
-
-
-
-
-
-
-
412
-
-
-
40
-
-
-
-
-
-
-
-
422*
-
-
-
27
-
80
910
43
131
-
0, 375
182
639
_
-
1,000
-
-
2,200
1,000
480
1,015
-
-
-
-
-
-
-
-
-
-
1,336
-
-
1,002
-
-
166
-
-
-
200
-
250
200
1,053
777
12
- -
1,000
— —
— —
2,200
1,000
480
1,427
— —
— —
- -
40
— —
- -
— —
— —
— —
-
1m336
- -
422
1,002
— —
-
193
- -
80
910
243
131
250
8,575
2,300 3,535
1,416
National 11,273
10,479
2,300
23,05^
* Includes 55 MW actually in Florida that belong to
Alabama Power Company.
SOURCE: federal Energy Administration, Inventory of Power
Plants in the United States. Washington, D.C.,
July 1977.
ICF
INCORPORATED
-------
C-4J
Baseload
Region Capacity Factor
MW .650
WO .650
CN .763
Intermediate
Capacity Factor
.367
.349
.413
All hydroelectric plants operating in daily peak are assumed to be pump-
ed storage plants. There may be some storage dams operated in this load
category, but the bulk of this capacity is pumped storage. For those plants,
1.38 kwh of baseload electricity are necessary to generate 1.0 kwh of daily
peak electricity.
OPERATION AND MAINTENANCE COSTS
The operation and maintenance costs originally specified in the model
were changed. New costs for all types of plants except coal-fired plants
with scrubbers are given in Table C-31. These costs are based upon esti-
mates by EPRI and United Engineers, as explained in Memo T of the Documen-
tation.
TABLE C-31
OPERATION AND MAINTENANCE COSTS BY PLANT TYPE
mills/kwh - in 1975 dollars
Load Category
Base
Intermediate
Seasonal
Peak
Daily
Peak
Coal Plants Without Scrubbers
Existing
New
Bituminous
Subbituminous
Lignite
Nuclear
Existing
New
1.80
2.30
2.50
2.70
6.50
7.00
2.30
2.80
3.00
3.20
2.80
Combined Cycle
Existing
New
Oil/Gas Steam
Oil/Gas Turbine
Existing
New
1.70
2.20
1.50
2.20
2.70
2.00
2.70
3.20
2.50
2.70
3.30
3.20
3.70
2.20
2.80
Hydro
ICF INCORPORATED
-------
C-44
NKW COAI .-!•' I HEP PLANT ECONOMICS AND CONSTRAINTS
KxJ.ons ive work w.js roqui.ro«l to develop the capital costs for new
<•<>,11 -I' i roii plants and scrubber costs. The methodology used to develop these
costs is presented in these sections: coal-fired plant capital costs/ full
scrubbing costs; and partial scrubbing costs.
Coal-Fired Plant Capital Costs
Table C-32 gives the costs for TSP control and cooling towers that we
received from Tom Schrader, EPA. The western and eastern coal control costs
were assumed to be representative of low sulfur and high sulfur control costs,
respectively.
Table C-33 gives the estimates of coal-fired plant capital cost with TSP
controls and cooling tower but without a scrubber. The Coal and Electric
Utilities Model was not structured to account for TSP control costs varying
with the sulfur content of coals. Thus, high sulfur capital costs were used
for bituminous and lignite plants'and low sulfur plant costs were used for
subbituminous plants. These assignments introduce a small bias in favor of
low sulfur bituminous coals since the TSP control cost estimate for these
coals would be low. This should have only minor implications since low sulfur
bituminous coal (particularly in the East) is generally priced out of the uti-
lity market because of the high demand for such coals by the industrial,
metallurgical and export sectors. Similarly, the TSP control costs would be
high for high sulfur subbituminous coals. However, this makes very little
difference since most subbituminous coals have a relatively low sulfur con-
tent. Finally, while the Texas lignites are generally high in sulfur content,
many of the Dakota lignites are low sulfur. Thus, the powerplant costs for
the Dakota lignites could be slightly understated.
A two percent real escalation rate in plant capital costs was assumed
from 1975 through 1985 with plants subject to the revised NSPS standard
undergoing 0.5 percent real escalation from 1985 to 1990. All plant capital
costs were regionally adjusted by the factors presented in Table C-34. These
regional adjustment factors accounted for local variation in construction costs.
Full Scrubbing Costs
Tables C-35 through C-37 are the scrubber cost information that we re-
coivod from PEDCo Environmental. These values were not in a report but con-
t.tinod in handwritten notes given to us through Tom Schrader of EPA. The
capital cost estimates differ only slightly from those PEDCo later reported
in Particulate and Sulfur Dioxide Emission Control Costs for Large Coal-Fired
Boilers (preliminary draft). For example, PEDCo1s report gives the capital
cost of $125.92/kw (in 1980 $'s) for 90 percent control on a 3-hour averag-
ing time for a 500 kw plant using coal that averages 3.5 percent sulfur.
The estimate provided in September was $124.05/kw (in 1980 $'s) for the
same plant using the same coal. The O&M costs are roughly 0.8 mills/kwh
lower than those in the draft report. The partial scrubbing estimates in
Table C-37 were done specifically for the ICF analysis at the request of Tom
Schrader of EPA. Thus, the sulfur levels used do not match those used in
other PEDCo work.
ICF
INCORPORATED
-------
C-45
TABLE 032
COSTS OF TSP CONTROL AND COOLING TOWERS
Control
Standard
(Ibs./mmbtu)
Capital Cost ($/kw)*
Precipitator
Fabric Filter
O&M (mills/kwh)*
Precipitator
Fabric Filter
Capacity Penalty (%)
Precipitator
Fabric Filter
Western, 8% Ash
0.10 0.03
37** 61
40**
0.19** 0.30
0.18**
0.82** 1.36
0.32**
Eastern, 14% Ash
0.10 0.03
11** 17**
36
0.08** 0.10**
0. 15
0.16** 0.25**
0.26
Cooling Tower
Capital Cost ($/kw)*
Natural Draft
Mechanical Draft
O&M (mills/kwh)*
Natural Draft
Mechanical Draft
Capacity Penalty (%)
Natural Draft
Mechanical Draft
All Plants
13
8**
0.20
0.14**
2.50
3.00**
* In 1975 dollars.
** Estimates used in the analysis.
Source: Tom Schrader, Policy Planning Division, EPA.
ICF INCORPORATED
-------
C-46
TABLE C-33
CAPITAL COST OF COAL PLANTS (WITH TSP CONTROLS
AND COOLING TOWER; WITHOUT SCRUBBER)
(S/kw - 1975 S's)
Rank of Coal Used
Low
Sulfur
High
Sulfur
NSPS Plants
BJ tuminous
Subbituminous
Lignite
463
504
546
433
474,
5156
ANSPS Plants
ill tuminoun
Subbituminous
Lignite
475
Ull,
560
NOTE- The underlined values were used as input to the model since the
model is not currently structured to handle variation in plant
capital cost by sulfur level of coal.
The cost of coal plants without any pollution control equipment are
given below:
Plant Type
Bituminous
Subbituminous
Lignite
Construction
310
340
370
AFDC
90
100
110
Total
400
440
480
Tlu- Plant ivipltal costs with pollution control equipment were calcu-
late! by a.ldimj the cost of TSP control and a cooling tower to the
basic plant cost and dividing this by one minus the capacity penal-
ties associated with TSP control and a cooling tower. The NSPS
plants are costed to meet a 0.1 Ib./mmbtu particular standard. The
ANSPS plants are costed to meet a 0.03 Ib./mmbtu particulate stan-
dard. The ANSPS plants include five years of real capital cost
escalation at 0.5 percent per year.
463
504
5/
400 +37+8
1 - 0.0082 - 0.03
_ 440 +37+8
1 - 0.0082 - 0.03
480 +37+8
1 - 0.0082 - 0.03
7/ 400 +40+8
2/
400
11+8
1 - 0.0016 - 0.03
= 433
4/ 440 + 1 1 + B
T - 0.0016 - 0.03
6/ 480 +11+8
7 - 0.0016 - 0.03
474
515
1 - 0.0032 - 0.03
(1.005) = 475
8/
400
17
8
1 - 0.0025 - 0.03
439 * (1.005) = 450
9/
440
40
1 - 0.0032 - 0.03
505 * (1.005)"
518
.if.P_.1_12_+-...8-— . _- 4H1 • (LOOS) = 493
1 - 0.0025 - U.03
LV _ 48-° + 40 + 8
1 "- 0.0032 - 0.03
127 400 + 17 + B
_ ___ _ -
1 - 0.0025 - 0.03
. (1.0o5) = 560
- = 522 * (1.005) = 535
-------
C-47
Census Region
New England
Middle Atlantic
South Atlantic
East North Central
TABLE C-34
REGIONALIZED ADJUSTMENT FACTORS
FOR UTILITY CAPITAL COSTS
Model
Region
MV
MC
NU
WP
PJ
VM
WV
CA
GF
SF
1.00
1.00
1.00
1.00
1.00
1.00
1.00
0.80
0.80
0.80
ON
OM
OS
MI
IL
IN
WI
0.90
0.90
0.90
0.90
0.90
0.90
0.90
Census Region
East South Central
West North Central
West South Central
Mountain
Pacific
Model
Region
EK
WK
ET
WT
AM
DM
KN
IA
MD
AO
TX
MW
UN
CO
AN
WO
CN
CS
0.80
0.80
0.80
0.80
0.80
0.90
0.90
0.90
0.90
0.90
0.90
0.95
0.95
0.95
0.90
0.90
0.90
0.90
SOURCE: "PIES Electric Utility Data" Table X, Federal Energy Administration,
December 7, 1976.
ICF INCORPORATED
-------
TABLE C-35
D COSTS FOR 80 AND 90 PERCENT SO REMOVAL AT A 500 MW COAL-FIRED UNIT
Lime FGD
Sulfur Content
(%
Design
1. 10
4.61
9.23
1 . 10
4.61
9. 23
)
Average
0.8
3.5
7.0
0.8
3.5
7.0
Capital
S/kw
105.93
124.05
140.13
119. 14
138.90
156.28
OSM
mills/kwh
1.93
3.10
4.39
2.14
3.45
4.90
Fixed*
mills/kwh
4.17
4.97
5.71
4.69
5.57
6.37
Energy
Penalty*
mills/kwh
0.85
0.85
0.85
0.85
0.85
0.85
Total*
mills/kwh
80% Regulation
6.95
8.92
10.95
90% Regulation
7.68
9.87
12. 12
Capital
$/kw
140.95
155.94
184.28
1 56 . 76
174. 10
204.54
OSM
mills/kwh
2.50
3.49
4.77
2.75
3.89
5.30
Mag-OX FGD
Fixed*
mills/kwh
5.42
5.85
6.81
6.03
6.53
7.55
Energy
Penalty*
mills/kwh
1.00
0.98
0.95
1 .00
0.97
0.95
Total*
mills/kwh
8.92
10.32
12.53
9.78
11 .39
13.80
NOTE: PEDCo estimated all costs in mid-1980 dollars with an assumed inflation rate of seven percent per year from 1975. PEDCo's
estimates were to be for scrubbers capable of meeting the specified percent removal regulation on a three-hour averaging
time basis.
* These PEDCo estimates were not used in the ICF analysis because they are calculated endogenously by the Coal and Electric
Utilities Model.
Source: PEDCo Environmental.
-------
C-49
TABLE C-36
CAPACITY AND ENERGY PENALTIES
ASSOCIATED WITH 80 AND 90 PERCENT S02 REMOVAL
AT A 500 MW COAL-FIRED UNIT
Sulfur Content
Average
Lime FGD
Capacity
Penalty
Energy
Penalty
80% Regulation
Mag-ox FGD
Capacity
Penalty
Energy
Penalty
1.10
4.61
9.23
0.8
3.5
7.0
3.29
3.29
3.30
5.30
5.31
5.34
4.15
4.15
4.16
6.15
6.15
6.16
90% Regulation
1.10
4.61
9.23
0.8
3.5
7.0
3.34
3.34
3.34
5.31
5.34
5.38
4.18
4.18
4.18
6.17
6.20
6.22
NOTE:PEDCo's estimates were to be for scrubbers capable of meeting
the specified percent removal regulation on a three-hour aver-
aging time basis.
SOURCE: PEDCo Environmental.
ICF INCORPORATED
-------
TABLE C-37
SCRUBBER COSTS FOR 1.2 AND 0.5 POUND EMISSION STANDARDS AT A 500 MW COAL-FIRED UNIT
Average
Sulfur Content
of Coal
(Ibs. S/mmbtu)
2.50
1.65
0.85
Capital
Cost
(S/kw)
124.27
115.88
71. 17
1 .2
OSM
(mills/kwh)
2.83
2.32
1.27
Capacity
Penalty
(%)
3.34
2.71
1.77
Energy
Penalty
(%)
5.38
4.37
2.85
Capital
Cost
($/kw)
139.23
130.55
104.54
0.5
O&M
(mills/kwh)
3.23
2.64
1.78
Capacity
Penalty
(%)
3.34
3.34
3.34
Energy
Penalty
(%)
5.38
5.38
5.38
o
I
Sote:
estimated all costs in mid-1980 dollars with an assumed inflation rate of seven percent per year from 1975.
PEDCo's estimates were to be for scrubbers capable of meeting the specified emission limitation on a three-hour
averaging time basis. Sulfur categories are different from other PEDCo estimates because these were specified
by Too Schrader of EPA for use in calibrating the ICF data inputs.
SOURCE: PEDCo Environmental
These estimates were for lime FGD systems.
-------
C-51
Table C-38 gives the capital costs from Table C-35 translated into 1975
dollars (mid- 1980 cost / (^.Q^) y6arS = 1975 cost-') and the coal
500
.
quality translated into pounds of sulfur per million btu (percent sulfur x
2,000 pounds / heat content = Ibs. S/mmbtu) .
PEDCo designed their scrubbers to handle higher sulfur coals than
would be experienced on average. This is done to account for the inherent
variability of the sulfur content in coal. PEDCo 's costs were to allow for
the level of coal variability expected for three-hour averaging periods,
PEDCo1 s estimate of the appropriate relative standard, deviation for a -c'
MW unit over a three hour averaging period is 0.194.- PEDCo designed
the scrubber to handle a peak sulfur variability of 1.63 relative standard
deviation above the mean (4.61 percent sulfur peak / 3.5 percent sulfur
average = 1.317; 0.317 / 0.194 RSD estimate =1.63 standard deviations or
non-compliance during 5.16 percent of the averaging periods assuming a
normal distribution and a one tail test). Hence, PEDCo was assuming that
the scrubbers would not be able to remove the specified percent of emissions
because of coal variability during five percent of the averaging periods
146 violations a year (8,760 hours in year / 3 hour average period x .05
fraction of violations = 146). If it were assumed that PEDCo's cost are
appropriate for 24-hour averages, then the confidence level would correspond
to about 1.5 violation per month. This exceeds the initial proposal (i.e.,
no violations) but is less than the three violations per month now being
proposed.
We used the PEDCo costs for the 2.9 Ibs. S/mmbtu coal (average sulfur
content) as the cost of fully scrubbing H coals (which have an average sulfur
content of greater than 2.5 Ibs. S/mmbtu). See Table C-38.
EPA instructed us to assume that mag-ox systems would be used in the
Northeast (i.e., CEUM regions MV, MC, NU, and PJ) because of the difficulty
and cost of developing sludge disposal sites. Lime systems were assumed
to be used throughout the rest of the country. The cost of full scrubbers
in our analysis are described in Table C-39.
We assumed that retrofitted systems would have a capital cost penalty
of $20 per kw for adapting the system to an existing structure. Thus,
the base capital cost for a retrofitted system (80 percent removal effi-
ciency) is $106/kw for lime and $128/kw for mag-ox. The capacity factor for
an existing unit with a scrubber was reduced by the appropriate capacity
penalty. For example, an existing plant which operates at a 0.70 capacity
factor without a scrubber would operate at a 0.677 capacity factor (0.7 x
(1 - .033) « 0.677) when retrofitted with a full lime FGD system. The heat
rate for the plant would increase by 5.3 percent to account for the energy
penalty.
V Tom Schrader of EPA reported that the assumed inflation rate was 7 percent
per year; however, PEDCo's report states that a 7.5 percent inflation
rate was used.
2/ Ibid, page 5-7. In our judgement, this RSD (0.194) is appropriate for a
24-hour averaging period but understates the variation that would occur
over three-hour averaging periods.
ICF
INCORPORATED
-------
C-52
TABLE C-38
CAPITAL COST OF SCRUBBERS
in 1975 $'s
Sulfur Content
(Percent)
Average
Sulfur Content
(Ibs. S/mmbtu)
Average
80% Removal
Lime
1.10
4.61
9.23
0.8
3.5
7.0
1.1*
3.8**
7.7**
0.8*
2.9**
5.8**
73.01
85.50
96.59
97.15
107.48
127.02
90% Removal
1.10
4.61
9.23
0.8
3.5
7.0
1.1*
3.8**
7.7**
0.8*
2.9**
5.8**
82.12 108.05
95.74 120.00
107.72 140.98
* PEDCo assumed a heat content of 20 nunbtu/ton for
subbituminous coal.
** PEDCo assumed a heat content of 24 mmbtu/ton for
bituminous coal.
TABLE C-39
BASE COSTS FOR FULL SCRUBBING
Lime
Percent Removal
80
90
Mag-Ox
Capital Cost ($/kw)*
OSM (mills/kwh)*
Capacity Penalty (Percent)
Heat Rate Penalty (Percent)
86
2. 1
3.3
5.3
96
2.2
3.3
5.3
108
2.4
4.2
6.2
123**
2.9
4.2
6.2
* In 1975 dollars.
k* This estimate differs from that given in Table C-38 for a 90
percent mag-ox system scrubbing 2.9 Ibs. S/mmbtu coal
because of rounding differences in deflating the 1980 dol-
lar PEDCo estimates to 1975 dollars.
ICF
INCORPORATED
-------
C-53
The capacity factor was not reduced for NSPS plants. The capital cost
of the scrubber was increased to account for the capacity needed to run the
scrubber. We assumed an average cost of $536 per kw ($450/kw for a plant
without scrubber and $86 per kw for an 80 percent efficient scrubber) for
replacement capacity. Thus, a full scrubber for a NSPS plant would cost
$103/kw ($86 per kw for a scrubber and 0.033 x 536 = $17 for replacement ca-
pacity). No replacement capacity for the replacement capacity was included.
This refinement would have added only $0.6/kw (0.033 x 0.033 x 536 = $0.6)
to the cost of a new plant. The heat rate is increased by the energy penalty
percentage of 5.3 percent, (e.g., 10,000 btu per kwh becomes 10,530).
ANSPS plants are treated the same as NSPS plants except that the assumed
replacement capacity coat is $561 per kw ($475/kw-/ for the plant and
$86/kw for the scrubber). Thus, a full scrubber for an ANSPS plant would
cost $104Aw ($86 for the scrubber and 0.033 x 561 = 18 for replacement capa-
city). Scrubber costs were not increased to reflect real escalation after
1985 (assumed to be 0.5 percent through 1990). The real escalation assumed
from 1975 to 1985 (assumed to be 2 percent per year) is handled within the
model. The heat rate is increased by the energy penalty percentage of 5.3
percent, (e.g., 10,000 btu per kwh becomes 10,530).
The PEDCo cost data indicated that even when full scrubbing was required
for all coals, the costs for the lower sulfur coals would be less than for
the high sulfur coals. See Table C-38. Since the data provided were very
sparse on this relationship, we initially assumed that there would be no
change in scrubber costs, as presented above, for coals with more than 0.83
Ib. sulfur per million btu. We assumed that costs would decline for all
coals with 0.83 Ibs. S/mmbtu or less by 15 percent for 80 percent removal
scrubbers (e.g., $73/kw cost of scrubber using 0.8 Ib. S/mmbtu coal / $86/kw
cost of scrubber using 2.9 Ib. S/mmbtu coal = .85 or a 15 percent decline in
capital cost for 80 percent removal efficiency scrubber) and by 14 percent
for 90 percent removal scrubbers. Thus, all lower sulfur coals (i.e. less
than one percent sulfur coals) had the one set of scrubbers costs, and the
higher sulfur coals had another set. See Table C-38 for cost factors for full
scrubbing.
V Includes cost of tighter TSP controls and 0.5 percent real escalation
for five years.
ICF
INCORPORATED
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C-54
TABLE C-40
COST FACTORS FOR FULL SCRUBBING
(in percent of full scrubber cost)
Sulfur Level*
A B D
80-i Efficient 85 85 85 100 100 100
Scrubber
90* Efficient
Scrubber 86 86 86 100 100 100
* Sulfur level definitions are:
A up to 0.4 Ibs. S/mmbtu
B 0.41 to 0.60 Ibs. S/mmbtu
D 0.61 to 0.83 Ibs. S/mmbtu
F 0.84 to 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.5 Ibs. S/mmbtu
Partial Scrubbing Costs
Two sets of partial scrubbing cost estimates have been used in the NSPS
analysis for EPA. The initial estimates were based upon the PEDCo scrubber
cost estimates supplied by EPA in September 1977. The revised estimates were
developed based upon further analysis by ICF and additional work by PEDCo in
1978. This section is divided into three subsections. The first subsection
discusses the initial partial scrubbing cost estimates for existing and NSPS
plants. The second subsection outlines the development of the initial
estimates for ANSPS plants. The final subsection presents the revised
partial scrubbing cost estimates.
Initial Partial Scrubbing Cost Estimates: SIP and NSPS Plants — PEDCo pro-
vTded~the estimates of partial scrubbing in Table C-36. These values were
used to develop the costs for the wider range of standards and sulfur levels
needed by the model. Since PEDCo1s cost estimates for 80 and 90 percent re-
moval scrubbers did not vary significantly with sulfur content of the coal
used, we assumed for the initial estimates that partial scrubbing capital
costs were related only the percentage removal required. (This assumption
was subsequently revised, as discussed below, where we estimated scrubber
costs as a function of both percent removal and the sulfur content of coal.)
Table C-41 gives the average percent removal requirements for scrubbing the
model's six sulfur content categories down to the nine emission standards
used in the model for existing and NSPS plants. The wide range of standards
stems from the variation of SIP standards throughout the country. The 1.2 Ibs.
SO /mmbtu is the current national new source performance standard.
ICF
INCORPORATED
-------
60
16
0
0
0
0
0
0
72
44
33
0
0
0
0
0
80
60
52
28
0
0
0
0
X
80
76
64
50
0
0
0
X
X
X
76
67
33
0
0
X
X
X
82
75
55
25
0
C-55
TABLE C-41
AVERAGE PERCENT REMOVAL REQUIREMENTS*
Emissions Standard Sulfur Level of Coal**
(in Ib. S02/mmbtu) A_ B_ D_ F_ G_ H_
0.24 70 80 X X X X
0.33
0.67
0.80
1.20
1.67
3.33
5.00
6.67
* This table presents the average percent removal require-
ments. Since the sulfur content of coal varies, scrub-
bers would have to be designed to absorb high peak concen-
trations of SO and still meet the specified emissions
standard. Thus, the peak removal requirements would be
greater than the averages presented here.
** Sulfur level definitions are:
A up to 0.4 Ibs. S/mmbtu
B 0.41 to 0.60 Ibs. S/mmbtu
D 0.61 to 0.83 Ibs. S/mmbtu
F 0.84 to 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.5 Ibs. S/mmbtu
Since the data available from PEDCo on the relationship of partial
scrubbing costs to percent removal required was limited, a methodology of
assigning specific capital costs to ranges of percent removal was developed.
The methodology consisted of three stages. First, we developed a set of
capital cost estimates for specific percent removal levels. Next, these cost
estimates were assigned to ranges of percent removal. These ranges were
developed by grouping similar percentages in from Table C-41. Finally, the
scrubber capital costs were assigned to the sulfur level/emission stan-
dard categories based upon Table C-41 and the ranges developed in step two.
The first step was to develop capital costs for various levels of
removal eficiency. We assumed that only 80 percent efficient scrubbers would
be used on existing and NSPS plants. The costs of full scrubbing with an 80
percent efficient scrubber already had been estimated at $86/kw. PEDCo had
ICF INCORPORATED
-------
C-56
provided the costs of meeting the 1.2 Ibs. SO /mmbtu standard with partial
scrubbing, but PEDCo's estimate of partially scrubbing 2.5 Ibs. S/mmbtu coal
was the same as the full scrubber cost being used for our highest sulfur
category coal (i.e., greater than 2.5 Ibs. S/mmbtu) which we represented for
purposes of scrubber costs as averaging 3.33 Ibs. This apparent anomaly in
the data was resolved by maintaining the $86/kw estimate for 3.33 Ib. coal
and scaling the other PEDCo cost estimates by 94 percent (roughly the propor-
t. ion of percent removal required for 2.5 Ibs. S/mmbtu coal to a full 80
percent efficiency) to achieve a range of scrubber costs consistent with the
$8G/kw cost of a full scrubber.- The values developed for 80 percent
efficient capital costs are presented in Table C-42 along with their associated
percent removal requirements.
TABLE C-42
SCRUBBER CAPITAL COSTS AND ASSOCIATED
PERCENT REMOVAL REQUIREMENTS FOR THE
1.2 LBS. SO /MMBTU STANDARD
Average
Average Sulfur Percent Estimated Capital Capital Cost
Level of Coal Removal Cost of Scrubber Provided by Pedco
(Ibs. S/mmbtu) Requirement ($/kw - 1975 $'s) ($/kw 1975 $'s)
0.83 28 47 49
1.67 64 75 80
2.50 76 81 86
3.33 82* 86
*~~We assumed that the cost of 80 percent removal equipment was appropriate
for use with the H sulfur category despite the 82 percent average removal
requirement because the broad range of sulfur content in the H category
(i.e., all levels greater than 2.5 Ibs. S/mmbtu) and the uncertainty in
the scrubber estimates themselves.
Subsequent analysis has shown that there was no anomaly in the data.
PEDCo's scrubber capacity for systems meeting an emission standard was
greater than for systems using the same coal but only meeting a percent
removal requirement. The emission standard scrubbers must be able to
increase their percent removal to maintain the specified cap when high
concentrations of SO are encountered. Thus, the $86/kw estimate for
partially scrubbing 2.5 Ibs S/mmbtu coal to meet a 1.2 Ibs. SO2/mmbtu
si ,iu;;t iin.it.c-s for further discussion.
ICF
INCORPORATED
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C-57
The next step was to assign these four capital cost estimates for 80
percent efficient scrubbers (i.e., full scrubbing plus three partial scrub-
bing estimates for meeting a 1.2 Ibs. SO /mmbtu emission standard) to
ranges of percent removal. The ranges were developed using Table C-41 to
identify relevant ranges of removal requirements. Table C-43 gives the
assignments of capital cost to percent removal categories.
TABLE C-43
SCRUBBER CAPITAL COSTS ASSIGNED TO
PERCENT REMOVAL CATEGORIES
Capital Cost
Percent Removal ($/kw - 1975 $'s)
80-82 86
70-79 81
40-69 75
<40 47
Finally, Table C-44 gives the capital costs for partial scrubbing esti-
mated using the percent removal requirements (Table C-41) and the capital cost
assignments (Table C-43). Table C-45 gives the cost factors used in the model
for existing and NSPS plants.
Initial Partial Scrubbing Cost Estimates: ANSPS Plants — Six partial
scrubbing estimates were required for the ANSPS plants. These were the three
lowest SIP standards (0.24 lb., 0.33 Ib. and 0.67 Ib. SO /mmbtu), the cur-
rent NSPS standard of 1.2 Ibs. SO /mmbtu and two standards specified by EPA:
0.8 Ibs. SO /mmbtu and 0.5 Ibs. SO /mmbtu. We assumed that both 80 percent
and 90 percent efficient scrubbers were available to ANSPS plants. Eighty per-
cent removal systems were used when the required average removal efficiency was
80 percent or less. Ninety percent removal systems were used when more than 80
percent average removal was required. The 80 percent removal cost factors for
the three SIP standards, the 1.2 and 0.8 standards developed for existing and
NSPS plants were used for the ANSPS plants. However, the 90 percent removal
costs for these standards and all other costs for the 0.5 lb. standard had not
been estimated previously.
The full cost if 90 percent removal was estimated previously as $96/kw.
This value was used for those average removal requirements above 85 percent.
An additional estimate was developed for the 84 percent removal requirement
since neither the full 80 percent nor full 90 percent removal cost seemed
appropriate. The cost of 84 percent removal was set at $92/kw ($96/kw x 0.955
the ratio of percent removal requirements for H and G coals (i.e., 84%:88%)
= $92/kw).
ICF
INCORPORATED
-------
C-58
TABLE C-44
CAPITAL COSTS OF PARTIAL SCRUBBING FOR
EXISTING AND NSPS PLANTS
(lime system)
($/kw - 1975 $'s)
Emissions Standard
(in Ib. SO /mmbtu)
Sulfur Level of Coal—
V
B
D
0.24
0.33
0.67
0.80
1.20
1.67
3.33
5.00
81
75
47
0
0
0
0
0
86
81
75
47
0
0
0
0
X
86 ,
75^
75
47
0
0
0
X
X
86
81
75
75^
0
0
X
X
X
X
81
75
47
0
X
X
X
X
86
81
75
47
1_/ Sulfur level definitions are:
A up to 0.4 Ibs. S/mmbtu
B 0.41 to 0.60 Ibs. S/mmbtu
D 0.61 to 0.83 Ibs. S/mmbtu
F 0.84 to 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.5 Ibs. S/mmbtu
2/ Although $75/kw should have been used given the percent
removal required, $81/kw was inputted into the model to
prevent the same capital cost from being used for a sin-
gle sulfur level meeting two emission standards.
3/ Although $75/kw should have been used given the percent
removal required, $47/kw was inputted into the model to
prevent the same capital cost from being used for a sin-
gle sulfur level meeting two emission standards.
NOTE: We judge that the combined effect of the input errors
noted above on the model forecasts were insignificant.
In general, the model solution is not sensitive to
P.Irt Lai scrubbing cost estimates for the medium sulfur
coals (i.e., D and F' sulfur levels) and fo- the two
emission standards at issue (i.e., 0.67 and 1.67 Ibs.
SO /irunbtu) which are not common.
ICF
INCORPORATED
-------
C-59
TABLE C-45
COST FACTORS FOR PARTIAL SCRUBBING
OF EXISTING AND NSPS PLANTS
(in percent of full scrubber cost)
Emissions
Standard—
(in Ibs. SO /mmbtu)
Sulfur Level of Coal -'
2/
80% Efficient
Scrubber
(Full scrubber
cost of $86/kw)
0.24
0.33
0.67
0.80
1.20
1.67
3.33
5.00
94
87
55
0
0
0
0
0
100
94
87
55
0
0
0
0
X
100
94
87
55
0
0
0
X
X
100
94
87
55
0
0
X
X
X
X
94
87
55
0
X
X
X
X
100
94
87
55
V PEDCo's scrubber cost estimates, upon which these values are based, were
to be for scrubbers capable of meeting the specified emission standard
on a three-hour averaging time basis.
2/ Sulfur level definitions are:
A up to 0.4 Ibs. S/mmbtu
B 0.41 to 0.60 Ibs. S/mmbtu
D 0.61 to 0.83 Ibs. S/mmbtu
F 0.84 to 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.5 Ibs. S/mmbtu
NOTE: X's are used in the table to indicate that a standard cannot be
achieved with the specified sulfur level and scrubber efficiency.
O's are used to indicate that no scrubbing is required.
ICF
INCORPORATED
-------
C-60
The methodology used to develop the partial scrubber costs for the
existing and NSPS plants was not used to develop the 0.5 Ib. standard costs.
The 0.5 standard costs were estimated by averaging the costs of the 0.33
Ib. and 0.67 Ib. standards (e.g., $75/kw cost of scrubbing 0.4 Ib. S/mmbtu
coal to a 0.33 Ib. SO /mmbtu standard + $47/kw cost of scrubbing 0.4 Ib.
coal to a 0.67 Ib. standard / 2 = $61/kw for scrubbing 0.4 Ib., sulfur coal
to a 0.5 Ib. SO standard). Table C-46 gives the partial scrubbing capital
coats for ANSPS2Plants and Table C-47 gives the cost factors used in the model.
Tho estimates PEDCo made for scrubbing 2.50 and 1.65 Ib. S/mmbtu coal
lino.l up well with these estimates. However, as shown in Table C-48 the
capital cost estimate for 0.83 Ib. S/mmbtu coal did not line up well. The
production schedule for doing the initial model runs did not allow sufficient
time to reanalyze the scrubber cost estimates. Thus, it was not until after
the National Air Pollution Control Technology Advisory Committee (NAPCTAC)
meeting in December that the costs were reviewed and revised estimates made.
TABLE C-48
COMPARISON OF PARTIAL SCRUBBING CAPITAL
COSTS FOR A 0.5 LB. SO /MMBTU STANDARD
($/kw - 1975 $'s)
Sulfur Level in Coal PEDCo Initial
(Ibs. S/mmbtu Estimates Estimates
0.40 NA 61
0.60 NA 78
0.83 72 83
1.67 90 92
2.50 96 96
NA - not available.
Revised Estimates — Additional analysis since December and an additional
estimate of partial scrubbing costs from PEDCo for a lower sulfur coal showed
that the cost of scrubbing lower sulfur coals was less than originally estimated.
Tom Schrader of EPA obtained from a PEDCo an estimate for scrubbing 0^ Ib. sul-
fur coal to meet a 0.5 Ib. SO standard on a long term average basis.-
Since the other partial scrubbing costs assumed a short averaging period, we
assumed that this increased coal variability over the shorter averaging period
would make this estimate equivalent to 0.4 Ib. S/mmbtu coal scrubbed to a
0.5 Ib. SO /mmbtu standard (0.6 Ib. S/mmbtu / 1.45 assuming a three RSD con-
fidence level and a 24-hour RSD value of 0.15 = 0.41). The PEDCo estimate re-
stated in 1975 dollars becomes $41.48. This is significantly lower than the
$ source of this estimate was subsequently learned to be D. Froste's (PEDCo)
memo to Dick Jenkins dated February 14, 1978 and titled "FGD Costs - 0.5 and
0.2 Ib./SO,, MMtu Recj."
ICF
INCORPORATED
-------
C-61
TABLE C-46
CAPITAL COST OF PARTIAL SCRUBBING FOR
ANSPS PLANTS
(lime system)
($/kw - 1975 $'s)
Emissions Standard Sulfur Level of Coal-
(in Ib. 80,/mmbtu) A B D_ F_ G_ H_
2
0.24 81 86 96 X X X
0.33
0.50
0.67
0.80
1.20
75
61
47
0
0
81
78
75
47
0
86
832/
75-'
75
47
96
92
86
81
75
X
963/
92-'
92
81
X
96-
96
86
V Sulfur level definitions are:
A up to 0.4 Ibs. S/itmxbtu
B 0.41 to 0.60 Ibs. S/mmbtu
D 0.61 to 0.83 Ibs. S/mmbtu
F 0.84 to 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.5 Ibs. S/mmbtu
2/ A value of $81/kw as actually used to provide for
a slightly higher cost than was used for B sulfur
level coal meeting the same standard.
3/ A value of $93/kw was actually used to provide a slight
cost differentiation from scrubbing the same sulfur
level to meet the less stringent emission standard of
0.8 Ibs. SO /mmbtu.
4/ A 90 percent scrubber should have been allowed to scrub
H coal to meet a 0.67 Ib. SO /mmbtu standard on a
long-term average basis. However, it was omitted from
the initial cost estimates.
ICF
INCORPORATED
-------
C-62
TABLE C-47
COST FACTORS OK FACIAL SCHUliDING KOR
ANSPS PLANTS
(lime system)
($/kw - 1975 $'s)
80% Efficient
Scrubber (full
scrubber cost
of $86/kw)
90% Efficient
Scrubber (full
scrubber cost
of $96/kw)
Emissions Standard-
fin Ib. S02/mmbtu)
0.24
0.33
0.50
0.67
0.80
1.20
0.24
0.33
0.50
0.67
0.80
V
2/
Sulfur Level of Coal-
A
94
87
71
55
0
0
B
100
94
90
87
55
0
D
X
100
97
94
87
55
F_
X
X
X
100
94
75
G_
X
X
X
X
X
81
H
X
X
X
X
X
100
- 100 X X X
- 100 x x
- - 96 100 X
- 100 X
96 100
NOTE":" X's "are "used to indicate that a standard cannot be achieved with the
specified sulfur level and scrubber efficiency. O's are used to
indicate that no scrubbing is required, -'s are used to indicate
that an 80 percent efficient scrubber can meet the standard and
a 90 percent system is not required.
1/ PEDCo's scrubber cost estimates, upon which these values are based,
~ were to be for scrubbers capable of meeting the specified emission
standard on a three-hour averaging time basis.
2/ Sul.Eur level definitions are:
A up to 0.4 Ibs. S/mnbtu
D 0.41 to 0.60 Ibs. S/mmbtu
IJ 0.61 to 0.83 Ibs. S/mmbtu
. r O.U4 to 1.67 Ins. S/mmbtu
c; 1.6U ti> 2.50 Ibs. S/mmbtu
II grunter than 2.5 Ibn. S/mmbtu
3/ The following values wero mistakenly inputted to the model for 90
percent scurbbers without 80 percent removal being available:
Standard
0.24
0.33
0.67
Sulfur Level of Coal
A
100
86
86
B
100
100
86
D
100
100
100
V
X
100
100
G
X
X
100
H
X
X
X
effect of those input cirrors i« insignificant.
-------
C-63
The data from Table C-25 (translated into 1975 $'s) and the additional
estimates were then plotted on a graph showing sulfur in coal versus capital
cost of a scrubber. Using the 1.2 Ib. and 0.5 Ib. standard curves for cali-
bration, curves representing the costs of meeting other standards could also
be plotted and the associated capital costs estimated. See Figure C-1. The
new capital costs estimates are compared with the previous estimates in Table
C-48. The cost factors are compared in Table C-49.
These revised scrubber costs were used in subsequent runs of the ICF
Coal and Electric Utilities Model (i.e., runs made since the NAPCTAC meeting),
Other Costs
The Coal and Electric Utilities Model was not structured to handle
separate input factors for partial scrubbing on O&M costs, capacity penal-
ties and heat rate penalties. Therefore, a single value was used: the
capital cost factor. The error introduced by this approach is small. For
example, PEDCo estimated that the O&M cost for meeting a 1.2 Ib. S02/mmbtu
standard would decline by 55 percent when the sulfur content of the coal
used dropped from 2.5 Ibs. S/mmbtu to 0.85 Ibs. S/mmbtu. PEDCo estimated
a 47 percent drop in both the capacity and energy penalty. The Coal and
Electric Utilities Model would have seen a 43 percent decline in O&M costs
and penalties because 43 percent was the decline in estimated capital costs.
Thus, CEUM would understate the decline in O&M costs by less than 0.3 mill/kwh
(2.1 mill/kwh O&M costs x (.55 - .43) = 0.25 mill/kwh in 1975 dollars) and the
decline in the capacity and energy penalties by roughly 0.04 mill/kwh (in 1975
dollars).—
CAPITAL CHARGE RATES
Capital charge rates are used to levelize capital costs over the life of a
powerplant. These were developed in Memo V in the Documentation. Though a
nine percent real fixed charge rate was recommended in this memo, a 10 per-
cent rate was used in this analysis to be conservative. This was applied in
all regions except Tennessee where the Tennessee Valley Authority (TVA), a
public ageny, dominates electricity generation. Since this is a publicly
owned firm, it is not subject to the same tax levels and capital costs as
private firms. Therefore, the capital charge rate does not have to be as
high. In ET and WT a five percent capital charge rate was used.
V Capital Penalty
$562/kw for replacement capacity x .033 full capacity penalty x (0.47 -
0.43) decline in capacity penalty x 0.1 capital charge rate x 6,132 kwh
per kw of capacity at baseload = 0.01 mill/kwh.
Heat Rate Penalty
10,000 btu/kwh heat rate x 0.053 heat rate penalty x (0.47 - 0.43) decline
in heat rate penalty x $1.25/mmbtu cost of coal = 0.03 mill/kwh.
ICF
INCORPORATED
-------
C-64
C.'ipi.tal Cost
of Scrubber
($/kwh -
1975 $'s)
100
95
90
85
8Q
75
70
65
60
55
50
45
40
35
30
25
2Q
15
10
5
Q
FIGURE C-1
PARTIAL SCRUBBING COST RELATIONSHIPS FOR
ALTERNATIVE STANDARDS
Q.50 lb
0,67 lb.. S02/nm±>tu
0,80 lb%
1.20 lb. S02/mmbtu
0.5
1,0 1,5 2.0
Average Sulfur Content of
-------
C-65
TABLE C-48
REVISED ESTIMATES OF PARTIAL SCRUBBING
CAPITAL COSTS
($/kw - in 1975 $'s)
Emissions Standard
(in Ib. S02/iranbtu)
Sulfur Level of Coal*
80% Efficient
Scrubber
90% Efficient
Scrubber
0.50
0.67
0.80
1.20
0.50
0.67
0.80
1.20
Initial
Revised
Initial
Revised
Initial
Revised
Initial
Revised
Initial
Revised
Initial
Revised
Initial
Revised
Initial
Revised
A
61
41
47
35
0
0
0
0
_
-
_
-
0
0
0
0
B
77
57
75
51
47
38
0
0
—
-
—
-
_
-
0
0
D
83
72
81
67
75
58
47
49
_
-
—
-
_
-
—
-
F
X
X
86
87
81
83
75
80
92
90
_
-
_
-
—
-
G
X
X
X
X
X
X
81
86
96
96
96
93
92
91
-
-
H
X
X
X
X
X
X
86
X
X
X
108
96
97
-
97
* Sulfur level definitions are:
NOTE:
A up to 0.4 Ibs. S/mmbtu
B 0.41 to 0.60 Ibs. S/mmbtu
D 0.61 to 0.83 Ibs. S/mmbtu
F 0.84 to 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.5 Ibs. S/mmbtu
X's are used in the table to denote that a standard cannot be achieved
with the specified sulfur level and scrubber efficiency. O's are used
to indicate that no scrubbing is required. Hyphens are used to show that
an 80 percent efficient scrubber can meet the standard and that a 90
percent system is not required.
ICF INCORPORATED
-------
C-66
TABLE C-49
REVISED ESTIMATES OF COST FACTORS
FOR PARTIAL SCRUBBING
(in percent of full scrubber cost)
Sulfur
Standard*
(in Ibs. SO /mmbtu)
Sulfur Level of Coal**
B D F G
80% Efficient
Scrubber
0.50 Original 71 90 97 X X X
Revised 48 66 84 X X X
0.67 Original 55 87 94 100 X X
Revised 41 59 78 101 X X
0.80 Original 0 55 87 94 X X
Revised 0 44 67 97 X X
1.20 Original 0
Revised 0
55
57
87
93
94
100
100
90% Efficient
Scrubber
0.50 Original
Revised
0.67 Original
Revised
0.80 Original
Revised
96
94
100
100
100
97
96
95
X
X
X
112
100
101
1.20
Original
Revsied
0
0
101
PEDCo's scrubber cost estimates, upon which these values are based, were
to be for scrubbers capable of meeting the specified emission standard
on a three-hour averaging time basis.
Sulfur level definitions are:
A up to 0.4 Ibs. S/mmbtu
B 0.41 to 0.60 Ibs. S/mmbtu
D 0.61 to 0.83 Ibs. S/mmbtu
F 0.84 to 1.67 Ibs. S/mmbtu
G 1.68 to 2.50 Ibs. S/mmbtu
H greater than 2.5 Ibs. S/mmbtu
ICF
INCORPORATED
-------
C-67
INFLATION
All prices and factor costs are subject to an inflation rate of 5.5
percent per year. Capital costs increase at a rate greater than the infla-
tion rate, with a real escalation rate of 2.0 percent from 1975 to 1985 and
0.5 percent per year from 1985 through 1990.
OIL AND GAS PRICES AND AVAILABILITY
For the model runs, it is necessary to specify the prices of oil and
gas, the availability of those fuel sources, and the types of plants the
fuels can be used in.
For the base case scenario, prices (in 1975 dollars) are $2.25/mmbtu
for oil and $1.95/mmbtu for natural gas. No distinction was made between
residual oil and distillate. Oil was assumed to have unlimited availability.
Natural gas, however, was assumed to have limited availability based upon a
1985 PIES run. In 1990 and 1995, natural gas availability to the utility
sector was assumed to be zero reflecting an expected ban on utility use of
such fuel beginning in 1990 as part of the National Energy Plan. The limits
on natural gas availability in 1985 are presented in Table C-50 below.
TABLE C-50
UPPER BOUND ON NATURAL GAS
AVAILABLE IN 1985
(in 10 btu)
Amount
WP 0.14
VM 5.95
WV 0.84
AO 553.74
TX 1,073.92
UN 7.14
AN 56 .46
CN 61.40
CS 23.32
Total 1,785.91
ANNUAL EMISSIONS FACTORS
Annual emission estimates are based upon annual emission factors for
three types of pollutants, SO , NO , and TSP for every plant type in each
region. These annual emission factors were developed from the SASD "Interpre-
tation of State Implementation Plan SO and TSP Regulations as of July 15,
1977" and from EPA's Compilation of Air Pollution Emission Factors. The
annual emissions factors were developed based on the assumption that the
specified standards would be enforced on a long-term average basis. Assuming
enforcement of SIP's and the current NSPS on short-term averages would result
in reduced annual emissions factors.
ICF INCORPORATED
-------
C-68
Tlio factors for o.ich of these pollutants will be discussed below:
so., -
• Coal-Fired Plants
Existing Plants - Emission factors are based upon the State Im-
plementation Plan (SIP) requirement for each powerplant, which
varies by plant-type. Utilities are assumed to just meet the SIP
standard, thus emitting the highest SO level allowed as shown in
Table C-22. Those plants that do not Have emission limitations or
have standards in the form ambient air quality restrictions are
assumed to burn the same sulfur level of coal that they burned in
1976.
New Plants - Emission factors are based upon the federal stan-
dard or the state standard, whichever is tighter. This varies
by scenario and according to the type of plant as explained in
the previous section.
NSPS Plants - Subject to 1.2 Ibs./mmbtu federal
standard or the state standard, whichever is tighter.
These remain the same across all scenarios.
ANSPS Plants - Subject to the alternative Federal NSPS
or the state standard, whichever is tighter. These
vary by scenario.
Emissions factors for new plants are presented in Table C-26.
• Oil/Gas Plants
Steam Plants - 1.00 Ib./mmbtu-
Combined Cycle Plants - 0.26 Ib./mmbtu-
Turbines - 0.26 Ib./mmbtu—
TSP
• C qa]-K ircd Plants
Exist tmj PJLants - The TSP SIP standards for existing plants
were weiqhted by capacity to obtain a weighted average TSP
omission factor for finch category of existing coal plant.
Sue Tabl.o C-!31 .
1/ A delta input error caused these emission factors to be 0.1 Ib. SO /mmbtu
for all model runs in this report. As a result, some memorandum from ICF
to EPA contain SO loading estimates that are incorrect and understate
tho emissions from oil-fired generating capacity. These errors were sub-
sequently corrected by hand and do not affect the emissions estimates in
this report.
ICF
INCORPORATED
-------
C-69
TABLE C-51
TSP EMISSION FACTORS FOR
EXISTING COAL-FIRED PLANTS
(Ib./tnmbtu)
Existing Plants Without Scrubbers Existing Plants
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
OM
OS
MI
IL
IN
WI
EK
WK
ET
WT
AM
DM
KN
IA
MO
AO
TX
MW
CO
UN
AN
WO
CN
CS
Old
.26
.10
.30
.11
.17
.09
.05
-
-
-
.10
.10
.10
.45
.11
.26
.51
-
-
-
-
.12
.60
.17
.70
.23
-
-
.31
.11
.17
-
-
-
-
SIP A
.25
.20
.20
.10
.10
.12
.05
.12
.27
-
.10
.11
.10
.10
.10
.37
.26
.23
.12
.10
.10
.12
.10
.15
.48
.19
.20
.10
.19
.10
.07
.09
.36
-
-
SIP B
_
.12
.20
.10
.20
.14
.05
.33
.11
-
.10
.11
.10
.22
.10
.43
.18
.22
.27
.11
.11
.15
.41
.15
-
.14
-
.30
.18
.10
.17
-
.36
-
-
SIP C
_
.12
-
.10
.10
-
-
-
.24
-
.10
.10
.10
.30
.10
.33
.38
.14
.14
-
.10
.12
.78
-
-
.14
-
-
-
.11
.17
-
-
—
-
With Scrubbers
_
-
.24
.10
.10
—
—
—
—
—
-
-
-
—
.10
.24
—
—
.13
—
—
.12
-
.13
—
-
—
-
.10
—
.17
.06
—
~
—
ICF
INCORPORATED
-------
C-70
New Plants - 0.1 ib./mmbtu for NSPS plants, 0.03 Ibs./mmbtu
for ANSPS plants.
Oil/Gas Plants
Oil Plants - 0.06 Ib./mmbtu
Gas Plants - 0.01 Ib./mmbtu
NO
These factors are based upon the type of fuel burned. No controls were
assumed for existing plants. New plants had to meet the NSPS for NO^.
The factors are presented in Table C-52.
TABLE C-52
NO EMISSION FACTORS
x
Plant-Type
Fuel
Ibs. NOx/mjnbtu
Existing Steam Plants
Coal - Bituminous
Coal - Subbituminous*
Coal - Lignite
Oil (Residual)
Gas
.75
.89
1.00
.83
.66
New Coal-Fired Steam
Plants
NSPS
PACT
F:\ist.i nq Turbines and
Combined Cycle
Now Turbines and
Combined Cycle
Oil (Residual)
Gas
Oil (Residual)
Gas
.70
.60
.58
.39
.30
.20
* Subbituminous is assumed to fall halfway between bituminous and
lignite in Ibs. NO /mmbtu.
ICF
INCORPORATED
-------
C-71
ELECTRICITY TRANSMISSION
Long distance electricity transmission is modelled explicitly in the
Coal and Electricity Utilities Model. The model structure provides for
baseload electricity generation to flow between demand regions on either
existing links or new links. The existing links represent existing links
with limited capacity and only an efficiency loss charged for their use.
New links represent the construction of new lines with both a capital cost
and an efficiency loss charged for their use.
Below we discuss the changes that were introduced to the existing link
data inputs and then to the new link data inputs.
Existing Links
Four changes to existing transmission links were implemented for the
NSPS runs. These were: (1) addition of four existing links, (2) the dis-
tance for the link from UN to CS was shortened, (3) the upper bound on kwh
transmission from WO to CS was lowered, and (4) the efficiencies for all
links were reestimated using the methodology represented in Memo X of the
Documentation. Each of these changes is discussed below.
Additional Existing Links — The original data base neglected the
electricity flows from mine mouth plants. Thus, no transmission link was,
provided from West Virginia to Virginia/Maryland/Delware despite the re-
mote siting of Vepco's Mt. Storm plant in West Virginia to supply elec-
tricity to consumers in Virginia. This problem became apparent after ini-
tial model runs showed that demand region VM was having extreme difficulty
in meeting its forecast demand. Therefore, the remote sited powerplants
belonging to utilities in VM were identified and their transmission lines
added to the model.
The plants included are presented in Table C-53. The lower bound on
transmission was estimated as the share of plant capacity belonging to
utilities in region VM operated at the 1975 plant capacity factor. The
upper bound on transmission was estimated as the same share of plant ope-
rated at a 0.70 capacity factor. The unlimited upper bounds were set
between VM and PJ to reflect the sizable transmission capacity of the PJM
System.
ICF INCORPORATED
-------
TABLE C-53
ADDITIONAL EXISTING TRANSMISSION' LINKS
Source Destination
WV
PJ
VM
VM
V.'-i
PJ
Distance
(adjusted
miles)
233
412
128
128
Size of
Line (>.v) Plant
500
500
500
500
Keystone
Conemaugh
Mt. Storm
Peach Bottom
Nameplate
Capacity ( in .MW)
1, 872
1, 872
1, 662
2, 304
Portion of Plant
Belonging to
a VM Utility
0.25
0.24
1.00
0.07
Lower
Bound
2.522
2.086
4.608
6.377
0.724
Upper
Bound
(10 kwh)
2.726
2.616
5.342
9.682
Unlimited
Unlimited
O
-j
ro
O
Z
O
O
a
s
m
D
-------
C-73
Other remotely sited existing plants are not explicitly modelled. These
would include Joppa Steam in Illinois, E.G. Gaston in Alabama, Colstrip 1 in
Montana, Mohave in Nevada, Four Corners in New Mexico and Navajo in Arizona.
Shortened Distance — The centroid for region UN in the Documentation was
Salt Lake City, Utah. However, Salt Lake City is not located near the generat-
ing capacity that supplies power to southern California. Therefore, the cen-
troid was shifted to near Lyman, that which is about 242 miles (249 miles ad-
justed for terrain) south of Salt Lake City. Thus, the new transmission dis-
tance was set at 578 miles (827 - 249 = 578).
Bound on Transmission from WO to CS - The upper bound in the Documenta-
tion for electricity transmitted from Washington/Oregon (WO) to southern Cali-
fo7n~ia (CS) was set at 14.862 billion kwhs. A review of transmission agreements
between the Northwest and the Southwest showed that a reduction in net trans-
mission flows from the Northwest was planned. By 1985, we identified 1.414 GW
of generating capacity that was available to California. This capacity would
generate 8.496 billion kwh (1.414 GW x 8,760 hours in year x 0.686 hydro
capacity factor-!-7 = 8.496 billion kwh). The bound on transmission from WO to
CN was maintained at 1.229 billion kwh, leaving 7.267 billion kwh for transmis-
sion to CS. This amount was locked into the model since the costs for this
electricity are below the marginal new plant costs used by the model to decide
on whether electricity should be transmitted or not.
Efficiencies Reestimated — Memo X in the Documentation outlines a new
methodology for calculating the efficiency of transmission lines. This approach
was implemented for the NSPS model runs.
New Links
Three changes were made to the data inputs for the new links. They were:
(1) additional new links were added, (2) the efficiencies of all new links were
reestimated and (3) the capital costs of all new links were reestimated. Each
of these changes are presented below:
Additional New Links — Table C-54 presents the new links that were added
to the model. An analysis of planned new capacity and demand growth showed
that additional transmission links were required. For example, the Documenta-
tion provided no transmission links from Colorado to surrounding regions.
Initial model runs, however, showed that Colorado's planned generating capacity
exceeded its internal requirements. This result may have been due to a low
electricity growth rate for Colorado but did point out the need for more flexi-
bility in siting plants in the West. The distance for new lines from UN to CS
was revised to the 578 mile length developed above.
T7~~This capacity factor was subsequently changed to 0.65. Thus, the trans-
mission estimate is slightly overstated.
ICF INCORPORATED
-------
C-74
TABLE C-54
ADDITIONAL NEW TRANSMISSION LINKS
.Source Destination Distance
Region _ Region _ (in adjusted miles)
WP ON 176
WP VM 238
GF SF 592
UN AN 358
GO AN 702
CO MW 542
GO UN 516
CN CS 398
Efficiencies Reestimated .-•?•- The methodology in Memo X of the Documentation
was again implemented. However, the size of new transmission lines was no
longer held constant at 765 kv. The size of line was determined by the distance
of the transmission link.
The capacity requirement and the distance of transmission are the primary
determinant of line size. For a .given size plant, a increase in transmission
distance will require an increase in line size because surge impedence loading
reduces the line's capacity. With distance. Thus, the size of line should be
related to the size of powerplant being serviced and the distance of the trans-
mission link. We assumed that the basic new plant would be comprised of three
500 MW units or total 1,500 MW. We also assumed that two lines of one size
(e.g., 500 kv) were preferrable to one line of the next larger size (e.g.,
765 kv) for system reliability .reasons. Using the relationships pre-
sented in Memo X, we estimated that the 345 kv line was preferrable up to 170
miles; the 500 kv line from 171 to 320 miles; and the 765 kv line over 320
miles.
Capital Costs of New Links —The capital costs were estimated using the
methodology presented in Memo X. However, the size of the line was not held
constant but was varied with the length of the link.
The capital cost estimates are from the Project Independence Blueprint
l-'acilities Task Force Report. The PIB report gives regional cost estimates
for 345 kv lines. Thus,, costs were inflated to 1975 dollars and restated on
.1 normalized per mile cost basis. See Table C-55 (the second footnote to
thir> table gives the algorithm for translating the PIB total cost estimate
into the normal {.zed per mile cost estimate). Memo X shows how the PIB
e:,t inidtos were manipulated to obtain the capital costs for 765 kv lines. Two
of the 500 kv capital cost estimates came from the PIB Facilities report. The
third estimate is based upon ratios of 345 kv and 500 kv line costs for the
two regions for which they were given.
As indicated in Memo X, the normalized per mile capital costs given
above are used to develop the normalized capital cost per input kwh-mile for
each region, given an 0.7 capacity factor and an SIL factor for a specified line
ICF
INCORPORATED
-------
C-75
TABLE C-55
NORMALIZED PER MILE CAPITAL COSTS*
(1975 dollars)
Line Size
345 kv 500 kv 765 kv
EAST (MV, MC, NU, PJ, WP, 204,336** 330,034** 588,240**
VM, WV, CA, GF, SF, ON,
OM, OS, MI, WI, EK, WK,
ET, WT, AM)
CENTRAL (DM, IA, MO, KN, 126,936** 227,246 365,328
AO, TX)
WEST (MW, CO, UN, AN, WO, 143,035** 291,643** 411,768
CN, CS)
~~*These estimates do not represent a physical relationship.
They are simply an intermediate step in the calculation
of transmission costs.
** From Tables 4-4 through 4-6 of Federal Energy Administra-
tion Project Independence Blueprint; Final Task Force
Report; Facilities (November 1974). FEA estimate was
divided by 250 miles, multiplied by an SIL factor of 1.2
and inflated by 29 percent to restate in normalized per
mile cost in 1975 dollars.
size. For example, the normalized per mile capital cost of a 500 kv line in
the East (from Pennsylvania to Virginia/Maryland/Delaware) is estimated to be
$330,034. Using the methodology in Memo X, we can see that this line would
carry 5.58 million kwh (910,000 kw capacity of line at SILgequal to one *
8760 hours/year * 0.7 baseload capacity factor = 5.58 x 10 kwh). The
normalized cost per kwh made would be 0.059 millg as can be seen in Table
C-56. ($330,034 at SIL equal to one / 5.58 x 10 kwh = .059 mills/
kwh). The normalized capital cost per kwh mile is in 1975 dollars, which are
subject to a 2 percent real escalation from 1975 to 1985. Thus, to translate
the 1990 line costs into late 1977 dollars, we multiply the costs by 1.417
(1.075 / 1.055 = 1.417). The estimate becomes 0.0836 mills per
kwh. The total cost of the line is estimated by multiplying the normalized
per kwh capital cost by the length of the link (238 miles), dividing by the
surge impedance loading factor (1.2) and multiplying by the capital charge
rate (0.1). The resulting cost is 1.658 mills/kwh (0.0836 x 238 / 1.2 x 0.1
= 1.658).
The normalized kwh per mile capital costs before they are subject to
inflation on the capital charge rates are presented in Table C-56. These
costs are the model inputs for developing total costs.
ICF INCORPORATED
-------
C-76
TABLE C-56
NOKMAI.I '/Kit kwh I'KK MILK CAIM'I'AI,
( i n mi II:; - 1T/5 do l..Ld rs )
Line Size
Key ion
East
Central
West
345 kv
0.085
0.053
0.060
500 kv
0.059
0.041
0.052
765 kv
0.045
0.027
0.031
NON-UTILITY COAL DEMAND
The estimates for non-utility coal demand are specified in terms of
live- consuming sectors: domestic coking coal, existing and new industrial
di-m.md, residential and commercial demand, synthetic demand and exports.
Thrs<- fstinuites remained constant, through all scenarios. The sources of
l.hrso estimates .ire specified in the matrix below:
Sector
Industrial
Metallurgical
Res Ldential/
Commerc ial
Expor t~
Syn t hot i cs
SOURCES OF NON-UTILITY COAL DEMAND ESTIMATES
Source
Level of
Estimate
Regional Allocation
Jim Dern (EPA)-'' National 1973 BOM coal distribution data
PIES Model (FEA)-/ National 1973 BOM coal distribution data
PIES Model (FEA)— National
2/
PIES Model (KEA)- National
EKDA/Jim Dern
(EPA)
National
(i large
reg ions
1973 BOM coal distribution data
1973 BOM coal distribution data
1C !•'
I/ Reviewed by White House energy staff.
2/ 1985 estimates: PIES Run A158569C;
1990 estimates: PIES Run A149042C. There are small differences
in inputs due to rounding.
ICF
INCORPORATED
-------
C-77
INDUSTRIAL DEMAND
The national industrial projections were provided by Jim Dern of EPA.
These estimates reflect the House version of the National Energy Plan. The
regional estimates were developed using the 1973 BOM distribution data found
in Bituminous Coal and Lignite Distribution-Calendar Year 1973 according to
the methodology specified in the Documentation (pg. III-108). Industrial
demand is assigned to specific ranks of coal according to the state implemen-
tation plan (SIP) standards (see Documentation).
The new industrial demand was allocated to scrubbed and non-scrubbed
categories. Large boilers were assumed to use scrubbers to comply with
clean air standards while small boilers would use low sulfur coal (i.e., 0.6
Ib. S/MMBtu or less), since scrubber technology is such that it is not economical
for small industrial users to install scrubbers. No analysis was available at
the time the inputs were generated regarding the split of consumption between
large and small boilers. Therefore, demand was divided equally between the
scrubbed and non-scrubbed categories. The scrubbed demand could use any
sulfur level while the non-scrubbed demand was required to use coal with less
than 1.2 Ibs. SO /mmbtu (i.e., sulfur levels A and B).
RESIDENTIAL/COMMERCIAL DEMAND
The national estimate of coal demand for this sector is based on the
PIES model runs for the Federal Energy Administration. Regional assignments
were made according to the 1973 BOM distribution data using a methodology
similar to that utilized for the industrial sector. Allowable sulfur content
was based on the SIP standards. (See Documentation, pg. III-110).
METALLURGICAL DEMAND AND EXPORTS
National estimates for these two sectors also come from the PIES model
runs, with regional distributions based on the 1973 BOM distribution data.
The coal blends are specified in the footnotes to Tables C-57 to C-59.
The source of these blends is found in the Documentation (pg. III-107, 108,
111).
SYNTHETICS DEMAND
Synthetics demand was provided for large geographic regions (e.g.,
Appalachia) by ERDA through Jim Dern of EPA. ICF sited the synthetics
facilities in model demand regions within the larger geographic regions
specified by ERDA. It was assumed that any type of coal could be used by
the synthetics sector.
Non-utility coal demand is presented for each sector on a regional
basis for 1985, 1990, and 1995 respectively in Tables C-57, C-58, and C-59.
ICF
INCORPORATED
-------
TABLE C-57
1985 NON-UTILITY COAL DEMAND AND ALLOWABLE COAL TYPES
Industrial
Region
MV
MC
NU
PJ
WP
VK
WV
CA
GF
SF
ON
OM
OS
MI
IL
IN
WI
EK
WK
ET
vrr
AM
DM
KN
IA
MO
AO
TX
MW
UN
CO
AN
WO
CN
CS
Domestic
Coking-
1012 btu
179.2
757.8
139.3
150.0
210.4
210.4
154.9
94.5
428.6
7.8
37.0
2.9
2.9
228.9
26.3
7.6
26.3
60.4
37.0
71. 1
Existing
1012 btu
1.4
3.3
55. 1
47.2
94.5
90.6
106.3
57.2
8.4
63.6
63.6
57.8
121.6
86.8
104. 1
52.0
23.2
19.0
25.4
25.4
52.8
28.9
11.3
31.7
32.5
38.0
17.9
15.8
15.8
8.7
25.7
Rank
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B,S,L
B
B
B
L
B,S
B
B,S
B,S
B,S
Sulfur
Level
D
B
F
A
F
B
D
D
F
B
B
B
F
D
D
D
D
D
F
F
F
D
F
G
D
F
B
D
D
A
F
10 12 btu
0.9
2.2
77.3
66.5
132.5
126.9
149.4
96.7
14.7
80.7
80.7
73.8
154.5
1 10. 1
132. 1
66. 1
39.3
32.4
42.7
42.7
89.4
36.7
6.9
19.0
19.0
332.4
96.3
85.0
85.0
144.6
165.8
New
Rank
B, S
B,S
B,S
B,S
B,S
B,S
B,S
3,5
B,S
B,S
3,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S,L
B,S
B,S
B,S
B,S,L
B,S,L
B,S
B,S
B,S
B,S
Residential
and
Commercial Synthetics
Sulfur
Level—
G
G
G
G
G
G
G
G
G.
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
D
D
D
D
G
10 12 btu
0.5
0.5
1.2
3.0
1.2
3.4
0.5
1.7
1.7
2.5
2.5
4.7
2.5
2.5
1.7
0.5
0.5
2.5
0.5
0.5
0.5
1.7
0.5
Rank
B
B
3
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
Sulfur Sulfur
Level 10 btu Rank Level
F
A
F 5.5 B H
B
D 5.5 B H
D
F
B
B
B 4.8 3 H
F
D 136.4 B H
D
D
D
F
F
D 124.6 L H
G
D
B
D
D
168.8 B,S H
2 /
Exports-
1012 btu
1,535.2
707. 1
5.9
3.5
50.5
28.2
16.4
National 2,833.4 1,385.6
2,603.0
37.3
445.6
2,346.8
See footnotes following Table C-59.
-------
TABLE C-58
1990 NON-UTILITY COAL DEMAND AND ALLOWABLE COAL TYPES
Industrial
MV
MC
NU
PJ
HP
VM
HV
CA
GF
SF
ON
OM
OS
MI
II.
IN
WI
EK
WK
ET
WT
AM
DM
KN
IA
MO
AO
TX
MM
ON
CO
AN
MO
CN
CS
Domestic
Coking-7
10 btu
185.8
785.7
144.4
155.5
218.2
218.2
160.6
98.0
444.4
8.1
38.4
3.0
3.0
237.3
27.3
8.1
27.3
62.6
38.4
Existing
10 12 btu
1.4
3.3
55.1
47.2
94.5
90.6
106.3
57.2
8.4
63.6
63.6
57.8
121.6
86.8
104.1
52.0
23.2
19.0
25.4
25.4
52.8
28.9
11.3
31.7
32.5
38.0
17.9
15.8
15.8
8.7
25.7
Rank
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B,S,L
B
B
B
L
B,S
B
B,S
B,S
B,S
Sulfur
Level
D
B
F
A
F
B
D
D
F
B
B
B
F
D
D
D
D
D
F
F
F
D
F
G
D
F
B
D
D
A
F
10 btu
1.8
4.3
165.2
142.1
283.4
271.7
319.7
206.4
31.3
172.6
172.6
158.1
330.7
235.5
282.0
141.4
84.2
68.9
91.3
91.3
191.1
78.5
14.6
40.5
42.3
710.8
206.0
181.9
181.9
309.4
354.4
New
Rank
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S,L
B,S
B,S
B,S
B,S,L
B,S,L
B,S
B,S
B, S
B,S
Sulfur
Level-
G
G
G
G
G
G
G
G
G.
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
D
D
D
D
G
Resxc
Co
1012 btu
0.2
0.2
0.6
1.4
0.6
1.6
0.2
0.8
0.8
1.2
1.2
2.2
1.2
1.2
0.8
0.2
0.2
1.2
0.2
0.2
0.2
0.8
0.2
lential
•ercia]
Rank
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
and
L
Sulfur
Level
F
A
F
B
D
D
F
B
B
B
F
D
D
D
D
F
F
D
G
D
B
D
D
v. • f .- 2/
Synthetics Exports-
Sulfur
1012 btu Rank Level 10 btu
17.4 B H
1,610.0
17.4 B B
741.6
15.3 B H
6.2
255.2 B H 3.7
53. 0
267.0 L H
29.6
22.5 L H 17.2
276.2 B,S H
National 2,937.9 1,385.6
See footnotes following Table C-59.
5,566.7
17.5
871.1
2,461.2
-------
TABLE C-59
1995 NON-UTILITY COAL DEMAND AND ALLOWABLE COAL TYPES
Industrial
Region
MV
MC
NU
PJ
WP
VM
WV
CA
GF
SF
ON
OM
OS
HI
IL
IN
WI
EK
WK
ET
AM
DM
KN
IA
KO
AO
TX
MW
UN
CO
AN
WO
CN
CS
Domestic
Coking-
10 btu
192.7
814.7
149.7
161 .2
226.3
226.3
166.5
101 .6
460.8
8.4
39.8
3.1
3.1
246. 1
28.3
8.4
28.3
64.9
39.8
Existing
10 btu
1 .4
3.3
55.1
47.2
94.5
90.6
106.3
57.2
8.4
63.6
63.6
57.8
121.6
86.8
104.1
52.0
23.2
19.0
25.4
25.4
52.8
28.9
11.3
31.7
32.5
38.0
17.9
15.8
15.8
8.7
25.7
Rank
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B,S,L
B
B
B
L
B,S
B
B,S
B,S
B,S
Sulfur
Level
D
B
F
A
F
B
D
D
F
B
B
B
F
D
D
D
D
D
F
F
F
D
F
G
D
F
B
D
D
A
F
1012 btu
2. 1
5.8
217.3
186.7
372.6
357.3
420.1
271.8
40.9
226.8
226.8
207.8
435.0
309.8
371.4
185.9
110.7
90.9
120.2
120.2
251.2
103.3
19.0
53.3
55.8
934.8
271.0
239.6
239.6
407.3
466.4
New
Rank
B,E
B,S
B,S
B,S
B,S
B, S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S
B,S,L
B,S
B,S
B,S
B,S,L
B,S,L
B, S
B,S
B,S
B,S
Sulfur
Level-7
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
D
D
D
D
G
io12
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
Residential and
Commercial Synthetics Exports—
btu
. 1
. 1
.3
.7
.3
.7
. 1
.4
.4
.6
.6
.0
.6
.6
.4
. 1
. 1
.6
. 1
. 1
. 1
.4
. 1
Rank
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
Sulfur Sulfur
Level 10 btu Rank Level 10 btu
F
A
F 60.7 B H
B 1,688.5
D 60.7 B H
D
F
B 777.8
B
B 53.4 B H
F 6.5
D 477.6 B H 3.9
D
D
D
F S
55.6
D 571.9 L H
G
D 31.0
72.4 L H 18.0
B
D
D 452.2 B,S H
National 3,046.3 1,385.6
See footnotes on following page.
7,322.2
8.2
1,748.9
2,581.2
-------
C-81
FOOTNOTES TO TABLES C-57 THROUGH C-59
_V Domestic coking consumption must be met with the following blend:
.70 ZA, ZB, ZC or ZD
.30 ZF,HF or MF
1.00
2/ Export consumption must be met with the following blend:
.84 ZA, ZB, ZC or ZD
.05 ZF, HF or MF
.11 ZG, HG or MG
1.00
Note the definitions of the sulfur level codes are:
SULFUR LEVEL CATEGORIES AND CODES
Pounds Sulfur per
Million BTU's Code Justification
0.00-0.40 A can be blended with higher sulfur coals to meet
Federal new source performance standard
0.41-0.60 B meets Federal new source performance standard
0.61-0.83 D roughly one percent sulfur (.01 x 2,000 pounds
per ton 4. 24 mmbtu/per ton = .833 pounds/mmbtu)
0.84-1.67 F roughly two percent sulfur
1.68-2.50 G roughly three percent sulfur
>2.50 H greater than three percent sulfur
V Half of the new industrial demand was assumed to have scrubbers with the
other half meeting its emission standard by using low sulfur coal. Thus,
half of the new industrial demand used the sulfur level indicated while the
other half burned either sulfur levels A or B.
ICF
INCORPORATED
-------
C-02
COAL TRANSPORTATION
Several changes were made in the model's treatment of coal transporta-
tion. The costing methodology in the Northeast was altered; several new links
were added to transfer coal from the supply regions to the demand regions; and
transportation bounds were developed to lock in mine mouth supplies and announced
new long-term contracts, forcing the model to transport certain volumes of coal
to specific regions. Each of these changes is discussed below.
TRANSPORTATION COSTS TO THE NORTHEAST
Coal transportation costs in the CEUM documentation were based on unit
train and/or barge rates. Further analysis indicated that this method of cost
estimation misrepresented costs for regions in the Northeast. In model regions
MV, MC, PJ, NU and VM only single or multiple car rates are available to coal
consumers. When "unit train" rates are offered, they are as high as the smaller
unit shipment rates. Thus, no low cost unit train rates exist and the use of
unit train rates (as estimated in the Documentation) in these regions understates
costs. New costs were developed to reflect single car rates. This costing
methodology is presented in ICF Memorandum "NCM Transportation Costs" (Memor-
andum Y, 12.oc_umer^ta_tion). The new costs are presented in Table C-60.
ADDITIONAL TRANSPORTATIONS LINKS
The following transportation links were added to the model since new
contract information showed that coal is to be shipped along these links.
Destination Cost ($/ton)
WK AO 5.07
CN KN 5.48
UT AM 15.21
MM TX 6.79
TRANSPORTATION BOUNDS
Two types of lower bounds can be specified for the model. The first type
of bound is coal type specific. This bound specifies the quantity of a specific
co.il type (e.g., DA or SD) that must flow from supply region X to demand region
Y. Tito aggregate bound simply requires that a specified number of tons be
transported from supply region X to demand region Y. The coal types that are
transported are determined by the model and may change from one run to another.
Coal Type Specific Bounds - Transportation bounds are set for the existing
mine mouth plants listed in Table C-61. These bounds specify the amount, heat
content category and sulfur content category of the coal used by mine mouth
plants. This information was developed using the FPC's Electric Utilities
Captive Coal Operations and the National Coal Association's Steam Electric
Plant Factor 1976 (Washington, D.C., 1976). We assumed that a plant's 1976
coal consumption represented its minimum expected consumption in future years.
Thus the amount of coal burned in 1976 was aggregated for each relevant link
and locked into the model. When the coals that are consumed were not available
from existing mines in the appropriate supply region, the coal type was
changed to the closest btu content and/or sulfur content that was available.
When the demand level was greater than the amount of coal produced from
i-xistLnij mines, the demand level was lowered. The coal type specific bounds
in Tnble C-G2 are the mine mouth plant shipments.
ICF
INCORPORATED
-------
PA
OH
MD
NV
SV
VA
EK
TN
WM
WY
PA
MD
NV
SV
VA
EK
TN
WM
WY
PA
OH
MD
NV
SV
VA
EK
TN
WK
WM
WY
C-83
TABLE C-60
TRANSPORTATION COSTS TO THE NORTHEAST
Source Destination Cost ($/ton)
MV
MC
PJ
Source Destination Cost ($/ton)
9.38
10.61
9.66
10.37
11.31
12.14
13.24
12.82
21.74
22.21
8.63
8.62
9.32
10.58
11.09
12.54
11.77
20.99
21.46
7.04
8.42
6.98
7.69
8.95
9.46
11.09
10.14
11.54
19.40
19.87
PA
OH
MD
NV
SV
VA
EK
TN
WM
WY
PA
OH
MD
NV
SV
VA
EK
TN
WM
WY
NU
VM
7.32
8.05
7.86
8.55
9.35
10.76
10.68
11.00
10.68
20.15
6.72
7.87
6.22
6.93
7.35
8.19
10.47
8.87
19.08
19.55
ICF INCORPORATED
-------
C-84
TABLE C-61
MINE-MOUTH POWERPLANTS
Key ion
Utility Company
VM
WV
OM
OS
t L
IN
EK
WK
AM
DM
KN
MO
TX
MW
UN
ro
AN
WO
SOU KGE:
Allegheny Power
Pennsylvania Electric
Duquense Light
Penn-New Jersey-Maryland Sys.
Appalachian Power
Virginia Electric
Allegheny Power
Ohio Power
Columbus and Southern
Ohio Power
Ohio Edison
Cincinnati., Columbua, Dayton Pool
Commonwealth Edison
Illinois Power
Central Illinois
Public Service Co. of Indiana
Public Service Co. of New Mexico
Kentucky Power
TVA
Alabama Power
Basin Electric Power
Basin Electric Power
Minnkota Power
Kansas City Power & Light
Kansas City Power & Light
Texas Utilities
Pacific Power & Light
Pacific Power S Light
Utah Power & Light
Montana Power
Utah Power (i Light
CoLorado-Ute
Arizona Public Service Co.
Public Service Co. of New Mexico
Pacific Power & Light
_ Plant
Hatfields Ferry
Homer City
Seward
Cheswick
Conemaugh
Keystone
Clinck River
Mt. Storm
Fort Martin
Harrison
Mitchell
Kammer
Conesville
Gavin
Muskingum
Samis
Toronto
J.M. Stuart
Kincaid
Baldwin
Coffeen
Gibson Station
Cayuga
wabash River
Galliagher
Big Sandy
Paradise
Gorgas
Leland Olds
Wm. J. Neal
Square Butte
La Lygne
Montrose
Big Brown
Dave Johnson
Jim Bridger
Naughton
Colstrip
Huntington Canyon
Ha yd en
Four Corners
San Juan
Centralia
Buren of Power, Electric Utilities Captive Coal
Operations Federal Power Commission (June 1977).
ICF
INCORPORATED
-------
C-85
TftBLE C-62
LOWER BOUNDS ON TRANSPORTATION LINKS FOR 1985
(in 10 tana)
Transportation
Link
Source
Region
PA
OH
OH
OH
NV
VA
EK
EK
EK
EK
EK
EK
AL
IL
IL
IL
IL
IL
IN
IN
IN
WK
WK
WK
MO
MO
MO
TX
ND
WM
WM
WM
WM
WM
WY
WY
WY
WY
WY
WY
WY
CN
CN
CS
CS
UT
UT
AZ
NM
NM
WA
Use
Region
WP
WP
CM
OS
WV
VM
CA
GF
OM
OS
EK
AM
AM
GF
IL
IN
IA
MO
GF
IN
WK
GF
WK
AO
IA
MO
KN
TX
DM
MI
DM
AO
TX
MW
WI
KN
AO
TX
MM
CO
WO
KN
CO
KN
CO
AM
UN
AN
TX
AN
WO
1985
Aggregate
Lower
Bound
15,070
6,000
3,400
9,189
10,706
783
520
2,317
850
600
2,420
1,535
8,713
317
13,851
4,300
20
4,500
917
11,688
312
1,219
10,419
3,001
20 .
1,651-^
1,131
45,127
17,837
2,000
6,600
4,000
7,712
9,405
1,230
14,026
17,910
10,841
18, 286
1,729
1,200
16
4, 176
16
930
890
6,513
5,885
6, 000^'
13,470
3,660
Coal Type Specific Bound
Coal
Type
HG
MH
HG
HF
HD
HD
HF
MH
MG
MG
MH
MH
LF
LB
SB
SB
MB
HB
MD
SD
Coal Coal
Bound Type Bound Type Bound
13,770
2,650
784 MH 7,730
764 HG 9,942
783
2,420
5,650
9,060
8,320
6,000
1,651
1,131
10,007
290 LD 67 LF 1,580
8,070
8,070
930
910
8,020
3,660
V
tons was not included. The aggregate bound should have been 2,101
thousand tons.
2/ Subsequent analysis indicates these contracts do not begin until after
our cutoff data and should not have been included.
-------
C-86
Aggregate Bounds — Transportation bounds were developed for the planned
coal-fired powerplants based upon data concerning long-term coal contracts
for these plants.
Most of the raw data were collected by the FPC and presented in "Status
of Coal Supply Contracts for New Electric Generating Units," (FPC, January
1977). This report lists each coal-fired unit due on-stream between 1976 and
19B5, antl presents its location, capacity, and contracted tonnage in 1985.
l-'rom the unpublished backup to this report, the contracted BOM coal supply
reyion for each new unit was obtained. After discussions with the report's
authors and examination of other data sources, a few minor changes were made
to the data base in order to correct errors in the printed FPC report.
Using this corrected data base, the 1985 contracted tonnage for each NCM
supply-demand region combination was identified. The FPC data indicate new
units by state and coal supply by Bureau of Mines District, rather than NCM
region. Where a state was modelled as two or more NCM demand regions, the
unit was placed according to town and/or county data given in "Steam-Electric
Plant Factors" (NCA, 1977). When a BOM District represented part or all of
two or more NCM coal supply regions, the NCM region chosen was the one
presently providing most of that demand region's tonnage, according to
"Annual Summary of Cost and Quality of Steam-Electric Plant Fuels, 1976"
(FPC, 1977).
After the NCM supply and demand region had been identified for each new
unit, the 1985 contracted tonnages were aggregated for each supply-demand
region pair for plants coming on line before 1983 (i.e., plants subject
to the current NSPS) and those coming on line in 1983 or later (i.e., plants
subject to the revised NSPS). Tonnage for new units in 1985 totalled more
than 243 million tons. Table C-63 indicates the NCM supply-demand region
pairs having contracted tonnage in 1985, along with the quantities contracted.
Contracts for plants coming on line in the 1983 to 1985 period were not
locked in since the revised new source performance standard could be used as
a force majeure to cancel them. Thus, only the contracts to NSPS plants
(i.e., those plants scheduled to be on line by 1983) were used to develop the
lower bounds.
Since the coal type was not available, an aggregate bound is specified
so Hit* modol is allowed to determine the type of coal to be shipped. The
lomi term contracts are combined with the coal type specific bounds to form
tin- ,n|(|HM|,it o .lower txiunds as presented in Table C-62. These bounds specify
tluv mini mum amount- .ol" coal the model must ship from a supply region to a
lU'inand ri>
ICF
INCORPORATED
-------
TOTAL
C-87
TABLE C-63
1985 CONTRACTED COAL FROM NEW UNITS
NCM
Supply
""rf I
PA
OH
OH
OH
EK
EK
EK
EK
EK
AL
IL
IL
IL
IL
IL
IN
IN
IN
WK
WK
WK
MO
MO
TX
ND
WM
WM
WM
WM
WM
WY
WY
WY
WY
WY
WY
WY
WY
CN
CN
CS
UT
UT
AZ
NM
NM
(thousand
Regions
Demand
WP
WP
OM
OS
CA
GF
OM
OS
AM
AM
GF
IL
IN
IA
MO
GF
IN
WK
GF
WK
AO
IA
MO
TX
DM
MI
DM
AO
TX
MW
WI
KN
IA
AO
TX
MW
CO
WO
KN
CO
KN
AM
UN
AN
TX
AN
short tons)
Contracted Coal in
1976-82
1,300
6,000
750
675
520
2,317
850
600
1,535
3,063
317
4,791
4,300
20
4,500
917
3,368
312
1,219
4,419
3,001
20
450
39,120
15,100
2,000
6,600
4,000
7,712
1,335
1,230
14,026
3,300
17,910
10,841
10,216
1,729
1,200
16
4,176
16
890
5,603
5,885
-
5,450
200,399
1983-85
_
-
-
675
1,088
2,000
850
-
-
-
-
1,134
-
-
-
-
400
624
-
1,219
-
-
-
4,000
2,200
2,000
-
2,000
-
-
-
2,097
-
4,759
-
4,583
-
-
-
-
-
-
6,986
-
6,000
-
42,615
1985
1976-85
1,300
6,000
750
1,350
1,608
4,317
1,700
600
1,535
3,063
317
5,925
4,300
20
4,500
917
3,368
936
1,219
5,638
3,001
20
450
39,120
18,100
4,000
6,600
6,000
7,712
1,335
1,230
16,123
3,300
22,669
10,841
14,729
1,729
1,200
V16
4,176
16
890
12,589
5,885
6,000
5,014
243,014
ICF INCORPORATED
-------
ICF INCORPORATED 1850 K Street, Northwest, Suite 950, Washington, D.C. 20006 (202) 862-1100
ATTACHMENT I
August 18, 1977
MEMORANDUM
TO : Jerry Eyster
FROM : Dan Klein
SUBJECT: Reclamation Costs for ICF'a Coal and Electric
Utilities Model
This memorandum develops estimates of reclamation costs to be incorpora-
ted into ICF's coal and electric utilities model. These cost estimates are
of total reclamation costs, that is, all cost relating to reclamation and
environmental protection which are not required as part of the basic mining
operation. The performance standards assumed are those specified in H. R. 2,
the Surface Mining Control and Reclamation Act of 1977. Hence, the estimates
represent the cost of going from no reclamation to full reclamation, and in-
clude those costs presently incurred under existing state laws and federal
regulations.
The estimates developed here are based primarily upon the cost estimates
developed in our recent report, "Energy and Economic Impacts of H.R. 13950"
(ICF Draft Final Report, February 1977). H.R. 2 was compared to H.R. 13950
to ascertain areas of difference. Other changes were made to reflect diffe-
rent coal supply regions, different mine-types, and different base years.
An important difference was that the analysis of H.R. 13950 estimated incre-
mental reclamation costs above and beyond present laws, whereas this memo-
randum estimates total reclamation costs assuming no reclamation in the basic
mining operation.
These estmates should be considered as only approximate. Time and re-
sources available for this task were quite limited, and this necessitated
many shortcuts and assumptions. Although I consider these estimates to be
reasonable, it is clear that further efforts could improve the quality of
the analysis.
The remainder of this memorandum is organized into three major sections.
The first section describes the general approach and the major assumptions
used throughout the analysis. The second section describes the approach used
in developing each of the component costs. The third section presents the
estimates of total reclamation costs.
-------
JERRY EYSTER -2- August 18, 1977
GENERAL APPROACH
The objective of this analysis was to develop estimates of (1) fixed
costs and {2) variable costs for each combination of 30 coal supply regions
and seven overburden ratios. Fixed costs were taken as the total of front-
end and capital costs, and do not inflate. Variable costs, were taken as
operating costs, and are assumed to increase with inflation.
Since there were many more mine-types examined in the analysis of H.R.
13950 than there are in the coal and electric utilities model, it was neces-
sary to select a "representative" surface mine for each region. This was
done as follows:
• Size category was taken from Table 2-8 of the H.R.
13950 analysis. In Appalachia, the mine size was
assumed to be 150,000 tons per year, except for
600,000 tons per year in Ohio.
• The slope categories assigned were "very steep" to
sourthern West Virginia, eastern Kentucky, and Vir-
ginia; "steep" to other Appalachian regions; and
"not steep" elsewhere.
• Mining methods were assumed to be contour mining
in Appalachia and area mining elsewheree.
• The estimates of acres mined per year, acres af-
fected per year, additional land disturbance, and
recovery percentage were taken as shown in the
appropriate mine-types in Appendix B of the H.R.
13950 analysis.
Average mine life was assumed to be 20 years. All mines were assumed
to be new mines. Costs were expressed in 1975 dollars, and inflated or de-
flated as necessary using Table 2-2 of the H.R. 13950 analysis.
COMPONENT COSTS
The analysis of H.R. 13950 developed incremental reclamation costs for
seven major components, not including fees paid into the Abandoned Mine Re-
clamation Fund. The adaptation to total reclamation cost estimates of each
of these seven components is discussed below.
Permit Application Fees
The permit application fees necessary under H.R. 13950 were assumed to
bo the same under H.R. 2. These costs were deflated to 1975 dollars, and
assumed to be fixed (front-end) costs.
ICF
INCORPORATED
-------
JERRY EYSTER
-3- August 18, 1977
Permit Planning Activities
Total permit planning costs related to environmental activities were
developed from Table 2-9 of the H.R. 13950 analysis. Blanks in the table,
indicating that such activities were already required in that state, were
filled in using the methodology described in the text. Since larger mines
are being used in this analysis, small mine cost exemptions were disregard-
ed. The total costs per mine were divided by the annual mine capacity, and
deflated to 1975 values. The resulting estimates are of front-end costs in
terms of dollars per annual ton.
Bonding Fees
The bonding fees per acre were the same as in the H.R. 13950 analysis.
These fees were deflated to 1975 values, and multiplied by the acres affect-
ed per year. The resulting estimates are dollars per ton, a variable cost
since only part of the mine site would be under bond at any time..
Backfilling Costs
These regrading costs are the major components of total reclamation
costs. Different methodologies were used for Appalachian (contour) and non-
Appalachian (area) mines.
In Applachia, the cost per acre of going from no regrading to approxi-
mate original contour was taken from Table 2-13 of the H.R. 13950 analysis.
These costs were then deflateed to 1975 values. The midpoint of each over-
burden depth category in that table was used in conjunction with the seven
permissable overburden ratio categories to derive an estimate of seam thick-
ness. Using these seam thicknesses, estimates of recoverable coal per acre
were made for each overburden ratio. These were divided into the costs per
acre to estimate operating cost per ton. As in the H.R. 13950 analysis,
operating costs per ton were multiplied by 1.39 to estimate capital costs
per annual ton.
In non-Applachian regions where area mining predominates, the regrad-
ing cost is not directly a function of overburden depth. A uniform operating
cost of $1,000 per acre regraded was assumed. An overburden depth between
60 and 10 feet was assumed for each overburden ratio between five and 45.
From this, the implied seam thickness could be calculated. Using an assumed
recoverage percentage between 80 and 90 percent (depending upon seam thick-
ness), the recoverable tons per acre were estimated. These estimates were
divided into $1,000 per acre to yield estimates of operating cost per ton.
Capital costs per annual ton were estimated as 1.5 times the operating cost
per ton.
ICF INCORPORATED
-------
JERRY EYSTER -4- August 18, 1977
Water Pollution Control Costs
Costs for water pollution control were based upon the estimates made
in "Economic Impact of Interim Final and Proposed Effluent Guidelines:
Coal Mining" prepared for EPA in May 1976 (EPA-230/1-75-058b). Cost esti-
mates were based upon the total costs of the BPT and BAT requirements as
shown in Tables 60 through 65 of that document. The estimates for medium
size mines were used in Appalachia; estimates for large mines elsewhere.
The annual operating costs included 15 percent of the capital investment;
this was deducted from our estimates. When a range of costs was presented,
the midpoint was selected. Finally, the 1974 costs were inflated to 1975
values.
Topsoil Handling Costs
The costs per acre for removing, saving, and restoring the topsoil were
the same as those used in page 11-50 of the H.R. 13950 analysis. These costs
were assumed for all coal regions. The costs were then divided by the annual
tonnage, multiplied by the acres affected per year, and deflated to 1975
dollars.
Revegetation Costs
Revegetation costs were assumed to average $100 per acre in the Interior
and Washington state, and $500 per acre in the rest of the West. In Appala-
chia, a revegetation cost of $200 per acre was assumed for steep slopes, and
$300 per acre for very steep slopes. These costs were then divided by the
annual tonnage and multiplied by the acres affected per year to express costs
as dollars per ton.
TOTAL RECLAMATION COSTS
The preceding costs were then summed for each overburden ratio in each
coal supply region. These are presented as fixed costs and variable costs.
The Abandoned Mine Reclamation Fee was not included in these estimates.
As passed in H.R. 2, the fee would start in October 1977 and end in August
1992. The fee would be $.10/ton on lignite, $.35/ton on all other surface-
mined coal, and $.15/ton on deep mined coal. There are no provisions for
inflation.
ICF
INCORPORATED
-------
a
X
Ci
-------
APPENDIX D
MODEL RESULTS
The exhibits in this appendix present the model results for both
reference cases for 1985, 1990 and 1995 under all four environmental
standards examined (i.e., the current NSPS of 1.2 Ibs.of SC>2 and the
three ANSPS: 90 percent removal, 80 percent removal and 0.5 Ibs.).
Although the model generates results for 30 supply regions, 35 demand
regions and 40 coal types, all forecasts are presented in a more aggregated
form. The 30 supply regions are aggregated to the 12 PIES coal supply
regions, (see Figure 1-1) and the 35 demand regions are aggregated to the
nine census regions (see Figure 1-2). The 4" coal types are aggregated into
metallurgical- , low sulfur— , medium sulfur- , and high sulfur-
categories.
The results are aggregated for two reasons. First, the lower number
of regions and coal type categories make the results easier to present
since the number of variables is reduced dramatically. Second, it is
not considered good practice by modelers to believe forecasts at the
lowest level of model disaggregation. The forecasts for individual regions
can be subject to random variations which tend to average out at higher
levels of aggregation. Thus, the model results by census region tend to be
more stable and reliable than the forecasts for each of the 35 demand
regions.
J/ Metallurgical coal is defined as coal with more than 26 million btu's
per ton and less than 0.83 Ibs. sulfur per million btu's.
2/ Low sulfur coal is defined as that coal meeting the current NSPS
standard of 1.2 Ibs. of SO per million btu's (i.e. 0.6 Ibs. or less
sulfur per million btu's). The coal meeting the definition of metal-
lurgical coal is not included under low sulfur coal.
3/ Medium sulfur coal is defined as having between 0.61 and 1.67 Ibs.
sulfur per million btu's.
4/ High sulfur coal is defined as having more than 1.67 Ibs. sulfur per
million btu's.
ICF
INCORPORATED
-------
TABLE OF CONTENTS
APPENDIX D EXHIBITS
Reference Exhibit
Case Number
Regional Coal Production by Sulfur Content Under ANSPS
in 1985
in 1990
in 1990
in 1995
in 1995
Coal Production by Mining Method Under ANSPS
in 1985
in 1990
in 1990
in 1995
in 1995
1985 Coal Distribution
for current NSPS of 1.2 IbSi
for ANSPS of 90% removal
for ANSPS of 80% removal
for ANSPS and 0.5 Ibs. (Initial)
1990 Coal Distribution
for current NSPS of 1.2 Ibs.
for ANSPS of 90% removal
for ANSPS of 80% removal
for ANSPS of 0.5 Ibs. (Initial)
1990 Coal Distribution
for current NSPS of 1.2 Ibs.
for ANSPS of 90% removal
for ANSPS of 80% removal
for ANSPS of 0.5 Ibs. (Initial)
1995 Coal Distribution
for current NSPS of 1.2 Ibs.
for ANSPS of 90% removal
for ANSPS of 80% removal
for ANSPS of 0.5 Ibs. (Initial)
1995 Coal Distribution
for current NSPS of 1.2 Ibs.
for ANSPS of 90% removal
for ANSPS of 80% removal
for ANSPS of 0.5 Ibs. (Initial)
I & II
I
II
I
II
I & II
I
II
I
II
I & II
I & II
I & II
I & II
I
I
I
I
II
II
II
II
II
II
II
II
D-1
D-2
D-3
D-4
D-5
D-6
D-7
D-8
D-9
D-10
D-11
D-12
D-1 3
D-14
D-15
D-16
D-17
D-18
D-19
D-20
D-21
D-22
D-23
D-24
D-25
D-2 6
D-27
D-28
D-2 9
D-30
ICF INCORPORATED
-------
TABLE OF CONTENTS - cont'd.
APPENDIX D EXHIBITS
Reference Exhibit
Case Number
Mine Mouth Prices Under ANSPS
1985
1990
1995
Delivered Coal Prices to Electric Utilities Sector
Under ANSPS
1985
1990
1995
I & II
I & II
I & II
I & II
I & II
I & II
U-31
D-32
D-33
D-34
D-35
D-36
Electric Generating Capacity Under ANSPS
1985
1990
1990
1995
1995
I & II
I
II
I
II
D-37
D-38
D-39
D-40
D-41
Scrubber Capacity Under ANSPS
1985
1990
1990
1995
1995
I & II
I
II
I
II
D-42
D-43
D-44
D-45
D-46
Utility Coal Consumption Under ANSPS
1985
1990
1990
1995
1995
Utility Oil/Gas (consumption by plant type and region
under ANSPS)
1985
1990
1990
1995
1995
I & II
I
II
I
II
I & II
I
II
I
II
D-47
D-48
D-49
D-50
D-51
D-52
D-53
D-54
D-55
D-56
ICF
INCORPORATED
-------
Exhibit D-l
1985 REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
References Cases I and II
Coal
legion Type
Northern Metallurgical
Appalachia High Sulfur
Medium Sulfur
Low Sulfur
Total
Central Metallurgical
Appalachia High Sulfur
Medium Sulfur
Low Sulfur
Total
Southern Metallurgical
Appalachia Medium Sulfur
Low Sulfur
Total
Midwest High Sulfur
Medium Sulfur
Low Sulfur
Total
Central West Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Eastern High Sulfur
Northern Medium Sulfur
Great Plains Low Sulfur
Total
Western Medium Sulfur
Northern Low Sulfur
Great Plains Total
Gulf
Rocky
Mountain
Southwest
Northwest
National
Medium Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
17.892
56.983
96.241
0.420
171.509
147.021
9.312
41.466
18.030
215.829
4.348
11.013
4.320
19.681
151.284
83.119
0.640
235.043
0.450
5.256
1.793
0.240
7.739
0.341
21.071
7.440
28.852
154.557
241.041
395.598
55.711
55.711
3.782
10.026
16.773
30.581
15.166
35.728
50.894
6.168
6.168
173.493
223.176
496.305
324.632
1217.604
106
90%
17.574
60.965
92.736
0.340
171.615
145.636
9.312
41.466
18.030
214.444
4.348
11.013
4.320
19.681
160.514
83.294
0.480
244.288
0.450
5.256
1.575
0.240
7.521
0.341
18.699
4.711
23.751
157.352
217.050
374.402
63.903
63.903
3.782
10.026
17.647
31.455
15.166
31.157
46.323
6.168
6.168
171.789
236.388
501.398
293.974
1203.548
tons
80%
17.543
61.783
92.736
0.340
172.403
145.442
9.312
41.466
18.030
214.250
4.348
11.013
4.320
19.681
. 161.006
82.922
0.480
244.408
0.450
5.256
1.575
0.240
7.521
0.341
18.699
4.711
23.751
157.487
216.702
374.189
63.903
63.903
3.782
10.026
17.647
31.455
15.166
29.511
44.677
6.168
6.168
171.565
237.698
501.161
291.981
1202.405
0.5 Ibs.
17.574
61.942
92.161
0.011
172.018
145.912
9.312
41.466
18.030
214.720
4.348
11.013
4.320
19.681
159.745
83.889
0.480
244.115
0.450
5.256
1.575
0.240
7.S21
0.341
18.699
4.711
23.751
150.453
216.651
367.104
63.848
63.848
3.782
10.026
17.647
31.455
15.66
29.511
44.677
6.168
6.168
172.066
236.597
494.465
291.930
1195.056
1015 Btiu'a
1.2 Ibs.
0.481
1.380
2.544
0.340
4.415
4.059
0.233
1.074
0.450
5.817
0.119
0.281
0.109
0.509
3.393
1.968
0.014
5.375
0.012
0.119
0.049
0.006
0.186
0.005
0.281
0.098
0.383
2.744
4.334
7.077
0.916
0.916
0.100
0.246
0.396
0.742
0.329
0.821
1.151
0.100
0.100
4.772
5.130
10.532
6.238
26.672
90%
0.473
1.477
2.448
0.009
4.406
4.022
0.233
1.074
0.450
5.780
0.119
0.281
0.109
0.509
3.594
1.972
0.011
5.576
0.012
0.119
0.043
0.006
0.180
0.005
0.249
0.062
0.316
2.792
3.923
6.714
1.051
1.051
0.100
0.246
0.417
0.763
0.329
0.722
1.052
0.100
0.100
4.726
5.428
10.586
5.708
26.447
80%
0.472
1.497
2.448
0.009
4.425
4.017
0.233
1.074
0.450
5.774
0.119
0.281
0.109
0.509
3.605
1.963
0.011
5.578
0.012
0.119
0.043
0.006
0.180
0.005
0.249
0.062
0.316
2.794
3.917
6.711
1.051
1.051
0.100
0.246
0.417
0.763
0.329
0.685
1.015
0.100
0.100
4.720
5.458
10.579
5.665
26.422
0.5 Iba.
0.473
1.501
2.434
0.009
4.416
4.030
0.233
1.074
0.450
5.787
0.119
0.281
0.109
0.509
3.577
1.986
0.011
5.574
0.012
0.119
0.043
0.006
0.180
0.005
0.249
0.062
0.316
2.673
3.916
6.589
1.050
1.050
0.100
0.246
0.417
0.763
0.329
0.685
1.015
0.100
0.100
4.733
5.435
10.467
5.664
26.300
-------
Exhibit D-2
1990 REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Reference Case I
Coal
Type
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
Hiqh Sulfur
Mntlium Sulfur
Low Sulfur
Total
Eastern High Sulfur
Northern Medium Sulfur
Great Plains Low Sulfur
Total
Western Medium Sulfur
Northern Low Sulfur
Great Plains Total
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central West
Gulf
Rocky
Mountains
Southwest
Northwest
National
Medium Sulfur
Total
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
14.213
62.264
103.744
0.353
189.766
153.199
3. 104
26.781
18.623
201.707
6.169
4.331
5.920
16.420
189.226
92.592
1.200
283.018
0.644
3.620
2.086
0.640
6.990
0.341
33.438
9.020
42.800
206.144
436.681
642.826
79.450
79.450
10.102
28.345
42.649
16.766
55.730
72.496
6.168
6.168
187.618
25B.555
581.602
556.513
106
90%
19.058
93.819
112.578
0.353
225.809
146.299
3.104
26.781
16.783
192.967
4.669
5.697
5.040
15.407
221.856
92. 132
0.640
314.628
0.337
3.620
1.895
0.240
6.092
0.341
31.071
6.291
37.708
244.701
303.484
548. 185
103.007
103.007
11.702
23.145
39.049
16.766
40.385
57.151
7. 168
7. 168
174.565
322.739
653.498
396.367
tons
80%
19.036
93.819
113.873
0.353
227.082
146.299
3.104
26.781
17.024
193.208
4.669
5.697
5.040
15.407
227.412
91.558
0.640
319.610
0.337
3.620
1.B95
0.240
6.092
0.341
31.071
6.296
37.708
250.198
298.977
549.175
103.007
103.007
10.102
25.945
40.249
16.766
38.740
55.506
7. 168
7.168
174.543
328.296
658.115
393.255
0.5 Ibs.
19.172
91.198
117.133
0.353
227.857
146.299
3.104
27.581
17.103
194.487
4.669
5.697
5.040
15.407
218.707
93.668
0.640
313.015
0.337
3.620
1.917
0.240
6.114
0.341
31.071
7.440
38.852
227.607
313.579
541.186
103.007
103.007
10.102
22.345
36.649
16.766
43.234
60.000
7.168
7. 160
174.679
316.969
642.117
409.975
1584.288
1547.170
1554.210
1543.741
1015 Btu's
1.2 Ibs.
0.630
1.584
2.749
0.009
4.971
4.227
0.078
0.709
0.465
5.479
0. 169
0.111
0.149
0.429
4.185
2.190
0.027
6.401
0.017
0.080
0.057
0.016
0.170
0.005
0.444
0.119
0.568
3.635
7.746
11.381
1.307
1.307
0.248
0.682
1.042
0.362
1.274
1.637
0.100
0.100
5.154
5.930
11.912
10.487
33.482
90%
0.630
2.424
2.976
0.009
5.922
4.040
0.078
0.709
0.419
4.245
0.128
0. 143
0.127
0.402
4.916
2.178
0.014
7.108
0.009
0.080
0.052
0.006
0.146
0.005
0.413
0.083
0.500
4.295
5.419
9.714
1.694
1.694
0.287
0.553
0.952
0.362
0.931
1.294
0.116
0.116
4.801
7.501
13.231
7.561
33.094
80%
0.512
2.424
3.008
0.009
5.953
4.040
0.078
0.709
0.425
5.251
0.128
0.148
0.127
0.402
5.036
2.165
0.014
7.215
0.009
0.080
0.052
0.006
0.146
0.005
0.413
0.083
0.500
4.389
5.341
9.731
1.694
1.694
0.248
0.623
0.983
0.362
0.894
1.256
0.116
0.116
4.800
7.621
13.305
7.523
33.249
0.5 Ibs
0.516
2.358
3.088
0.009
5.971
4.040
0.078
0.742
0.427
5.287
0.128
0.146
0.127
0.402
4.848
2.216
0.014
7.078
0.009
0.080
0.052
0.006
0.147
0.005
0.413
0.098
0.5)5
4.002
5.592
9.594
1.694
1.694
0.248
0.533
0.892
0.362
0.996
1.358
0.116
0.116
4.804
7.368
13.082
7.801
33.055
-------
Exhibit D-3
1990 REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Reference Case II
Coal
Type
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
Higher Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
!astern High Sulfur
Northern Medium Sulfur
Great Plains Low Sulfur
Total
Jestern Medium Sulfur
Northern Low Sulfur
Great Plains Total
Northern
Appalachia
:entral
Appalachia
douthern
Appalachia
Midwest
Central West
5ulf
Rocky
Mountains
Southwest
Northwest
National
Medium Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
27.483
65.548
111.237
0.513
204.783
164.554
3.104
30.541
20.303
218.502
7.189
4.497
6.320
18.007
193.841
95.532
1.200
290.572
0.687
3.620
2.375
0.720
7.402
0.341
34.354
11.440
46.135
227.607
535.845
763.453
90.007
90.007
4.262
11.702
33.145
49.109
16.766
56.959
73.725
6.168
6.168
204.175
266.453
630.785
666.445
1767.859
106
90%
19.813
109.462
127.995
0.353
257.624
148.901
3.104
27.981
16.783
196.769
5.269
4.337
5.430
15.037
265.456
97.790
0.960
364.205
0.337
5.615
1.095
0.320
8.177
0.341
31.139
6.296
37.777
298.776
314.804
613.580
103.007
103.007
4.202
11.702
26.169
42.073
16.766
48.664
65.430
7.168
7.166
178.522
383.977
728.566
419.779
1710.844
tons
80%
19.936
109.211
127.811
0.353
257.311
147.499
3.104
27.981
17.103
195.687
5.269
4.657
5.223
15.105
265.456
95.550
0.880
351.886
0.337
5.220
1.895
0.320
7.772
0.341
31.139
6.296
37.777
292.954
327.568
620.523
103.007
103.007
4.202
11.702
26.187
42.091
16.766
47.015
63.781
7.168
7.168
177.243
383.330
720.630
430.945
1712.150
0.5 Ibs.
19.927
100.619
137.118
0.353
258.018
147.505
3.104
27.981
17.103
195.693
5.269
4.657
5.223
15.105
267.055
96.484
0.640
364.180
0.337
5.220
1.924
0.320
7.800
0.341
31.139
7.440
38.920
271.406
343.014
614.523
103.007
103.007
4.202
11.702
23.145
39.039
16.766
51.561
68.327
7.168
7.168
177.240
376.338
709.352
448.799
1711.730
1.2 Ibs.
0.739 .
1.671
2.942
0.013
5.365
4.538
0.078
0.811
0.507
5.934
0.197
0.115
0.159
0.471
4.288
2.258
0.927
6.572
0.018
0.080
0.065
0.018
0.191
0.005
0.456
0.151
0.612
4.002
9.460
13.462
1.481
1.481
0.113
0.287
0.798
1.198
0.362
1.302
1.664
0.100
0.100
5.606
6.121
12.880
12.434
37.040
ID15 Btu1
90%
0.533
2.827
3.367
0.009
6.736
4.110
0.078
0.742
0.419
5.349
0.144
0.111
0.137
0.392
5.896
2.310
0.021
8.227
0.009
0.122
0.052
0.008
0. 191
0.005
0.414
0.083
0.501
5.222
5.612
10.834
1.694
1.694
0.111
0.287
0.629
1.027
0.362
1.119
1.481
0.116
0.116
4.907
8.927
14.678
8.037
36.549
8
80%
0.536
2.820
3.362
0.009
6.727
4.072
0.076
0.742
0.427
5.319
0.144
0.120
0.131
0.395
5.896
2.258
0.020
8.173
0.009
0. 114
0.052
0.008
0.182
0.005
0.414
0.296
0.501
5.122
5.831
10.953
1.694
1.694
0.111
0.287
0.629
1.028
0.362
1.081
1.441
0.116
0.116
4.873
8.911
14.530
8.220
36.534
0.5 Ibs.
0.536
2.595
3.612
0.009
6.752
4.072
0.078
0.742
0.427
5.319
0.144
0.120
0.131
0.395
5.934
2.279
0.014
8.227
0.009
0.114
0.052
0.008
0.183
0.005
0.414
0.098
0.516
4.753
6.096
10.848
1.694
1.694
0.111
0.287
0.553
0.951
0.362
1.184
1.547
0.116
0.116
4.873
8.725
14.432
8.520
36.551
-------
Exhibit D-4
1995 REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Reference Case I
Coal
Type
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
Higher Sulfur
Medium Sulfur
Low Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Eastern High Sulfur
Northern Medium Sulfur
Great Plains Low Sulfur
Total
Western Medium Sulfur
Northern Low Sulfur
Great Plains Total
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central West
Gulf
Rocky
Mountains
Southwest
Northwest
National
Medium Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Su.l fur
Total
1.2 Ibs.
24.529
68.958
105.672
0.480
199.639
159.413
18.780
18.880
197.073
6.900
2.887
6.320
16.107
210.436
92.527
1.200
304.164
0.630
2.830
3.241
0.722
7.423
4.000
54.928
1 1.000
69.928
232.523
518.254
750.778
93.000
93.000
1.714
10.212
25.252
37.178
5.885
78.400
84.285
3.660
3.660
193. 186
286.223
623.315
660.507
io6
90%
22.380
90.513
115.918
0.320
229.132
148.332
18.380
17.200
183.913
5.880
2.640
6.073
14.953
234.084
94.514
1.040
329.638
0.630
3.683
3.374
0.320
8.008
4.000
52.560
7.237
63.798
336.535
346.290
682.816
93.000
93.000
1.714
11.651
19.018
32.384
5.885
67.133
73.018
3.660
3.660
178.937
332.280
738.108
464.632
tons
80%
21.734
93.182
116.305
0.320
231.542
147.929
18.380
17.200
183.509
5.880
2.640
6.073
14.953
239.042
93.760
0.960
333.761
0.630
3.683
3.201
0.321
7.836
4.000
52.560
7.237
63.798
339.034
346.382
685.417
93.000
93.000
1.714
11.563
20.737
34.014
5.885
67.933
73.818
3.660
3.660
177.887
339.907
739.988
467.163
0.5 Ibs.
22.036
84.183
122.908
0.320
229.448
148.445
19.100
17.200
184.745
5.880
2.720
5.993
14.593
230.039
93.760
1.040
324.839
0.630
3.684
3.352
0.320
7.986
4.000
52.560
9.183
65.744
310.072
364.983
675.055
93.000
93.000
1.714
10.051
19.723
31.489
5.885
63.300
69.185
3.660
3.660
178.705
321.906
717.068
482.062
10 Btu's
1.2 Ibs.
0.660
1.797
2.801
0.012
5.269
4.397
0.507
0.471
5.375
0.189
0.077
0.159
0.424
4.656
2.188
0.027
6.871
0.017
0.016
0.089
0.018
0.184
0.053
0.727
0. 145
0.925
4.075
9.120
13.195
1.530
1.530
0.045
0.253
0.610
0.909
0.121
1.791
1.911
0.059
0.059
5.308
6.567
12.426
12.353
90%
0.602
2.364
3.053
0.008
6.028
4.094
0.497
0.430
5.020
0.161
0.070
0.153
0.384
5.184
2.234
0.023
7.441
0.017
0.079
0.092
O.OOB
0.196
0.053
0.696
0.096
0.844
5.856
6.122
11.978
1.530
1.530
0.045
0.289
0.459
0.793
0.121
1.537
1.658
0.059
0.059
4.919
7.680
14.498
8.834
80%
0.585
2.432
3.063
0.008
6.088
4.082
0.497
0.430
5.009
0.161
0.070
0.153
0.384
5.305
2.217
0.012
7.544
0.017
0.079
0.087
o.ooa
0.191
0.053
0.696
0.096
0.844
5.899
6.119
12.019
1.530
1.530
0.045
0.285
0.500
0.831
0.121
1.555
1.676
0.059
0.059
4.890
7.869
14.525
8.890
O.S Ibs.
0.593
2.196
3.238
0.008
6.035
4.097
0.517
0.430
5.034
0.161
0.072
0.151
0.384
5.093
2.217
0.023
7.333
0.017
0.079
0.092
0.008
0.19S
0.053
0.696
0.121
0.870
5.403
6.438
11.841
1.530
1.530
0.045
0.250
0.474
0.770
0.121
1.450
1.571
0.059
0.059
4.913
7.421
14. 195
9.102
1763.232
1713.957
1724.945 1699.741
36.654
35.931
36.175
35.631
-------
Exhibit D-5
1995 REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Reference Case II
Coal
^jgion Type
jrthern Metallurgical
Appalach.la High Sulfur
Modium Sulfur
Low Sulfur
Total
sntral Metallurgical
Appalachia Medium Sulfur
Low Sulfur
Total
outhern Metallurgical
Appalachia Medium Sulfur
Low Sulfur
Total
nidwest Higher Sulfur
Medium Sulfur
Low Sulfur
Total
Central West Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Eastern High Sulfur
Northern Medium Sulfur
Great Plains Low Sulfur
Total
estem Medium Sulfur
Northern Low Sulfur
Great Plains Total
ulf
Rocky
Mountains
Southwest
Northwest
lational
Medium Sulfur
Total
Metallurgical
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Low Sulfur
Total
Medium Sulfur
Total
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
30.773
72.645
117.603
0.480
221.501
182.980
20.129
20.160
223.269
7.860
1.600
8.455
17.915
223.030
98.497
1.360
322.887
0.980
2.831
3.270
0.802
7.882
4.000
54.932
12.377
71.308
355.295
733.390
1088.687
93.000
93.000
1.714
11.651
31.985
45.351
5.885
100.000
105.885
3.660
3.660
224.307
302.505
765.522
909.008
2201.343
106
90%
22.526
120.271
158.628
0.320
301.774
149.301
19.640
17.680
186.629
6.000
2.241
6.472
14.713
310.799
100.202
1.040
412.041
0.630
7.517
3.382
0.560
12.090
4.000
74.426
7.236
85.663
453.718
419.312
873.031
93.000
93.000
1.714
13.251
25.037
40.002
5.885
94.160
100.045
3.660
3.660
180.179
442.586
928.032
571.818
2122.616
tons
80%
22.380
118.643
158.670
0.320
300.012
149.911
19.640
17.680
187.231
5.979
2.281
6.431
14.692
310.799
99 . 360
1.040
411.199
0.630
7.442
3.382
0.561
12.015
4.000
73.622
7.237
84.860
460.718
421.153
881.872
93.000
93.000
1.714
11.651
24.960
38.326
5.885
93.869
99.754
3.660
3.660
180.614
440.883
931.870
573.252
2126.620
0.5 Ibs.
23.065
116.006
162.001
0.480
301.552
151.286
20.040
18.080
189.407
6.600
2.673
6.431
15.705
309.299
99.760
1.040
410.099
0.630
6.550
3.651
0.560
11.391
4.000
56.560
11.000
67.560
404.708
477.513
882.222
93.000
93.000
1.714
11.651
22.206
35.572
5.885
97.148
103.033
3.660
3.660
183.295
431.856
863.589
634.458
2113.200
10 Btu'8
1.2 Ibs.
0.828
1.896
3.095
0.012
5.831
5.043
0.545
0.503
6.091
0.215
0.042
0.213
0.470
4.939
2.326
0.030
7.295
0.026
0.061
0.089
0.019
0.196
0.053
0.727
0.163
0.943
6.180
12.823
19.003
1.530
1.530
0.045
0.289
0.776
1.111
0.121
2.303
2.424
0.059
0.059
6.157
6.948
15.004
16.843
44.952
90%
0.606
3.128
4.165
0.008
7.907
4.120
0.533
0.441
5.094
0.164
0.059
0.163
0.386
6.961
2.365
0.023
9.349
0.017
0.163
0.092
0.014
0.285
0.053
0.984
0.096
1.133
7.875
7.373
15.248
1.530
1.530
0.045
0.328
0.605
0.979
0.121
2.163
2.284
0.059
0.059
4.953
10.304
18.112
10.866
44.255
80%
0.602
3.088
4.166
0.008
7.864
4.136
0.533
0.441
5.110
0.163
0.060
0.162
0.386
6.961
2.347
0.023
9.331
0.017
0. 161
0.092
0.014
0.283
0.053
0.974
0.096
1.122
7.995
7.405
15.400
1.530
1.530
0.045
0.289
0.603
0.938
0.121
2.156
2.277
0.059
0.059
4.964
10.262
18. 166
10.908
44.300
0.5 Ibs.
0.621
3.018
4.254
0.012
7.094
4.173
0.543
0.451
5.167
0.180
0.071
0.162
0.413
6.925
2.356
0.023
9.304
0.017
0.142
0.100
0.014
0.272
0.053
0.749
0.145
0.894
7.035
8.373
15.408
1.530
1.530
0.045
0.289
0.535
0.869
0.121
2.223
2.354
0.059
0.059
5.037
10.085
17.106
11.948
44.175
-------
Exhibit D-6
1985 COAL PRODUCTION BY MINING METHOD
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Cases I and II
Region
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central
West
Eastern
Northern
Great Plains
Western
Northern
Great Plains
Gulf
Rocky
Mountains
Southwest
Northwest
National
Mining Method
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
1.2 Ibs.
31.683
139.826
171.509
32.524
183.306
215.829
7.555
12.126
19.681
53.173
181.870
235.043
5.241
2.498
7.739
28.852
28.852
394.004
1.594
395.598
55.712
55.712
13.716
16.865
30.581
43.464
7.429
50.894
6.168
6.168
672.091
545.513
90%
31.683
139.932
171.615
32.524
181.920
214.444
7.555
12.126
19.681
58.112
186.176
244.288
5.241
2.280
7.521
23.751
23.751
372.808
1.594
374.402
63.903
63.903
13.716
17.739
31.455
36.565
9.758
46.323
6.168
6.168
652.023
551.524
80%
31.683
140.720
172.403
32.524
181.726
214.250
7.555
12.126
19.681
58.605
185.804
244.408
5.241
2.280
7.521
23.751
23.751
372.808
1.594
374.402
63.903
63.903
13.716
17.739
31.455
34.920
9.758
44.677
6.168
6.168
650.658
551.746
0.5 Ibs.
31.683
140.335
172.018
32.524
182.197
214.720
7.555
12.126
19.681
57.980
186.135
244.115
5.241
2.280
7.521
23.751
23.751
365.510
1.594
367.104
63.903
63.848
13.716
17.739
31.455
34.920
9.758
44.677
6.168
6.168
642.894
552.162
Total
1217.604 1203.548 1202.405 1195.056
ICF
INCORPORATED
-------
LI- /
1990 COAL PRODUCTION BY MINING METHOD
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 Btus)
Reference Case I
Region
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central
West
Eastern
Northern
Great Plains
Western
Northern
Great Plains
Gulf
Rocky Mountains
Southwest
Northwest
National
Mining Method
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
1.2 Ibs.
10.560
179.206
189.766
14.174
187.534
201.707
2.518
13.902
16.420
31.590
251.429
283.018
1.747
5.244
6.990
42.800
42.800
636.432
6.394
642.826
79.450
79.450
13.716
28.933
42.649
65.064
7.432
72.496
6.168
6.168
904.217
680.071
90%
12.960
212.849
225.809
14.174
178.794
192.967
2.518
12.889
15.407
35.990
278.639
314.628
1.747
4.345
6.092
37.708
37.708
546.591
1.594
548.185
103.007
103.007
15.316
23.733
39.049
47.391
9.760
39.049
7.168
7.168
824.569
722.601
80%
12.960
214.122
227.082
14.174
179.035
193.208
2.518
12.889
15.407
36.746
282.864
319.610
1.747
4.345
6.092
37.708
37.708
547.581
1.594
549.175
103.007
103.007
13.716
26.533
40.249
45.746
9.760
40.249
7.168
7.168
823.070
731.140
0.5 Ibs.
11.938
215.919
227.857
14.174
180.314
194.487
2.518
12.889
15.407
35.990
277.026
313.015
1.747
4.367
6.114
38.852
38.852
539.592
1.594
541.186
103.007
103.007
13.716
22.933
36.649
50.240
9.760
36.649
7.168
7.168
818.941
724.800
Total
1584.288 1547.170 1554.210
ICF
INCORPORATED
-------
Exhibit D-8
1990 COAL PRODUCTION BY MINING METHOD
I INNER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II
Region
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central
West
Eastern
Northern
Great Plains
Western
Northern
Great Plains
Gulf
Rocky
Mountains
Southwest
Northwest
National
Mining Method
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
1.2 Ibs.
10.560
194.223
204.783
17.328
201.174
218.502
2.518
15.489
18.007
31.975
258.589
290.572
1.747
5.655
7.402
46.135
46.135
753.979
9.474
763.453
90.007
90.007
16.916
32.193
49.109
66.293
7.432
73.725
6.168
6.168
1043.625
724.234
90%
12.960
244.664
257.624
14.174
182.595
196.769
2.518
12.519
15.037
43.190
321.016
364.205
1.747
6.430
8.177
37.777
37.777
611.986
1.594
613.580
103.007
103.007
15.316
26.757
42.073
55.670
9.760
65.430
7.168
7.168
905.510
805.334
80%
12.960
244.351
257.311
14.174
181.514
195.687
2.518
12.632
15.150
43.190
318.696
361.886
1.747
6.025
7.772
37.777
37.777
618.929
1.594
620.523
103.007
103.007
15.316
26.775
42.091
54.021
9.760
63.781
7.168
7.168
910.804
801.345
0.5 Ibs.
12.960
245.058
258.018
14.174
181.519
195.693
2.518
12.632
15.150
43.190
320.990
364.180
1.747
6.053
7.800
38.920
38.920
612.826
1.594
614.420
103.007
103.007
15.316
23.733
39.049
58.567
9.760
68.327
7.168
7.168
910.392
801.338
Total
1767.859 1710.844 1712.150 1711.730
ICF INCORPORATED
-------
Exhibit D-9
1995 COAL PRODUCTION BY MINING METHOD
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case I
Region
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central
West
Eastern
Northern
Great Plains
Western
Northern
Great Plains
Gulf
Rocky
Mountains
Southwest
Northwest
National
Mining Method
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
1.2 Ibs.
2.880
196.759
199.639
10.354
186.719
197.073
16.107
16.107
24.800
279.364
304.164
0.002
7.421
7.423
69.928
69.928
741.386
9.392
750.778
93.000
93.000
14.560
22.617
37.178
76.285
8.000
84.285
3.660
3.660
1036.855
726.377
90%
2.880
226.252
229.132
5.493
178.420
183.913
14.593
14.593
28.400
301.238
329.638
0.000
8.008
8.008
63.798
63.798
680.624
2.192
682.816
93.000
93.000
14.932
17.452
32.384
64.285
8.733
73.018
3.660
3.660
957.071
756.886
80%
3.016
228.526
231.542
5.480
178.029
183.509
14.593
14.593
28.800
304.962
333.761
0.001
7.834
7.836
63.798
63.798
683.226
2.192
685.417
93.000
93.000
15.291
18.722
34.014
65.085
8.733
73.818
3.660
3.660
961.356
763.589
0.5 Ibs.
2.880
226.568
229.448
5.605
179.140
184.745
14.593
14.593
28.400
296.439
324.839
7.986
7.986
65.744
65.744
672.864
2.192
675.055
93.000
93.000
14.000
17.489
31.489
60.452
8.733
69.185
3.660
3.660
946.604
753.137
Total
1763.232 1713.957 1724.945
ICF INCORPORATED
-------
Exhibit D-10
1995 COAL PRODUCTION BY MINING METHOD
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 tons)
Reference Case II
Region
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central
West
Eastern
Northern
Great Plains
Western
Northern
Great Plains
Gulf
Rocky
Mountains
Southwest
Northwest
National
Mining Method
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
1.2 Ibs.
3.180
218.321
221.501
10.354
212.915
223.269
17.915
17.915
28.000
294.888
322.887
0.002
7.881
7.882
71.308
71.308
1076.948
11.739
1088.687
93.000
93.000
16.000
29.351
45.351
85.885
20.000
105.885
3.660
3.660
1388.336
813.007
90%
2.880
298.864
301.744
5.793
180.837
186.629
14.713
14.713
28.800
383.242
412.041
0.000
12.089
12.090
85.663
85.663
870.598
2.433
873.031
93.000
93.000
15.600
24.402
40.002
84.045
16.000
100.045
3.660
3.660
1190.038
932.573
80%
2.880
297.133
300.012
5.913
181.318
187.231
14.692
14.692
28.800
382.399
411.199
0.001
12.041
12.051
84.860
84.860
879.422
2.450
881.872
93.000
93.000
15.600
22.726
38.326
83.885
15.869
99.754
3.660
3.660
1198.020
928.600
0.5 Ibs.
3.009
298.594
301.552
5.780
183.627
189.407
15.705
15.705
28.800
381.300
410.099
11.391
11.391
67.560
67.560
879.188
3.034
882.222
93.000
93.000
15.600
19.972
35.572
85.885
17.148
103.033
3.660
3.660
1182.481
930.719
Total
2201.343 2122.616 2126.620 2113.200
ICF
INCORPORATED
-------
EXHIBIT D-11
1985 COAL DISTRIBUTION
FOR CURRENT NEW SOURCE PERFORMANCE STANDARDS
OF 1.2 IBS. FOR REFERENCE CASES I AND II
Northern
CONSUMING REGION Appalachia
New England 6.24
Middle Atlantic 92.63
South Atlantic 41.83
East North
Central 30.55
East South
Central
TOTAL EAST 171.25
West North
Central 0.86
West South
Central 0.88
Mountain 0.20
Pacific
(10 tons)
SUPPLY REGION
Eastern
Northern
Central Southern Central Total Great
Appalachia Appalachia Midwest West East Gulf Plains
3.50 - - - 9-74
24.41 - - - '".04
107.50 6.62 26.82 - 182.77
66.82 - 131.79 0.24 229.40
11.65 13.06 53.45 0.20 78.36
213.88 19.68 212.06 0.44 617.31
19.99 5.18 26.03 - 28.85
3.00 1.56 5.44 55.71
_ 0.20
- - 0.45 0.45
22.99 7.19 32.12 55.71 28.85
Western
Northern
Great
Plains
6. 13
44.44
86.53
52.94
190.04
71.07
53.14
69.74
11 .63
205.58
TOTAL WEST
NATIONAL
Rockies Southwest Northwest
15.24
0.89
16.13
1.21
11.03
2.22
14.46
21.64
28.05
49.69
173.19
213.88
19.68
235.05 7.63 649.43 55.71 28.85
395.62 30.59 49.69
6.17
6.17
6.17
Total
West
6.13
44.44
101.77
53.83
206.17
101.13
74.78
108.82
20.02
359.92
National
9.74
123.17
227.21
331.17
132.19
823.48
127.16
80.22
109.02
20.47
392.04
566.09 1,215.52
-------
EXHIBIT D-12
1985 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 90% REMOVAL FOR REFERENCE CASES I AND II
(10 tons)
SUPPLY REGION
Northern Central Southern Central Total
Eastern Western
Northern Northern
Great Great
Plains
Rockies Southwest
Total
West National
CONSUMING REGION Appalachia
New England 6.10
Middle Atlantic 94.38
South Atlantic 43.02
East North
Central 27.92
East South
Central
TOTAL EAST 171.42
West North
Central
West South
Central
Mountain
Pacific ~
TOTAL WEST
Appalachia Appaiacnia niowest west naai. VJU.LJ- **.*.*....,
3.50 - 9-&0
24.16 - - - 118.54
104.27 6.62 29.28 - 183.19
67.31 - 134.29 0.24 229.76
12.58 13.06 54.52 0.02 80.18
211.82 19.68 218.09 0.26 621.27
0.86 - 23.20 3.23 27.29 - 24.00
1.34 - 3.00 3.71 7.05 63.90
0.40 - - ' 0.40 -
- - 0.24 0.24
2.60 - 26.20 7.18 34.98 63.90 24.00
9.60
4
37
78
51
172
68
52
69
11
202
.62
.20
.64 16.95
.64 0 . 89
.10 17.84
.73 0.37
.21 - 16.28
.74 10.82 29.70
.63 2.43
.31 13.62 45.98
4.
37.
95.
52.
189.
93.
132.
62
20
59
53
94
10
,39
110.26
6.17 20.23
6.17 355.98
123
220
325
132
811
120
139
110
20
390
. 16
.39
.35
.71
.21
.39
.44
.66
.47
.96
NATIONAL
171.42
214.42
19.68 244.54 7.44 656.25 63.90 24.00
374.41 31.46
45.98
6. 17
545.92 1,202.17
-------
EXHIBIT D-13
1985 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 80% REMOVAL FOR REFERENCE CASES I AND II
(10 tons)
SUPPLY REGION
CONSUMING REGION
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL EAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
Appalachia Appalachia
6.14 3-50
93.77 24.38
44.42 104.14
27.89 66.68
12.93
172.22 211.63
0.86
1.34
0.40
_
2.60
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
9.64
- 118.15
6.62 29.28 - 184.46
134.72 0.24 229.53
13.06 54.15 0.02 80.16
19.68 218.15 0.26 621.94
23.26 3.11 27.23 - 24.00
3.00 3.71 8.05 63.90
- 0.40
0.24 0.24
26.26 7.06 35.92 63.90 24.00
Western
Northern
Great
Plains Rockies Southwest Northwest
-
4.62 -
37.08 - - -
78.64 17.03
51.55 0.89
171.89 17.92
68.93 0.29
52.36 - 16.28
69.39 10.82 28.01
11.63 2.43 - 6.17
202.31 13.52 44.29 6.17
Total
West
-
4.62
37.08
95.67
52.44
189.81
93.22
132.54
108.22
20.23
354.21
National
9.64
122.77
221.54
325.20
132.60
811.75
120.45
140.59
108.62
20.47
390.13
NATIONAL
172.22
214.53
19.68
244.41 7.32 657.86 63.90 24.00 374.20 31.46 44.29
6.17
544.02 1,201.88
-------
EXHIBIT D-14
1985 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 0.5 LBS. FOR REFERENCE CASES I AND II
CONSUMING REGION
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL EAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
ADDS letch i.d Appcilsch is
6.30 3.50
94.93 24.37
42.11 107.80
28.48 64.41
12.03
171.82 212.11
0.86
1.34
— 0 *40
~ ~~
2.60
(10 tons)
SUPPLY REGION
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
- 9.80
119.30
6.62 25.84 - 182.37
136.42 0.24 229.55
13.06 55.20 - 80.29
19.68 217.46 0.24 621.31
23.65 3.23 27.74 - 23.75
3.00 3.73 8.07 63.85
_ 0.40
— — 0.24 0.24 — ~
26.65 7.20 36.45 63.85 23.75
Western
Northern
Great
Plains Rockies Southwest Northwest
3.87 -
37.08 -
78.64 16.95
51.64 0.89
171.23 17.84
69.29 0.37
45.23 - 16.28
69.74 10.82 28.05
11.63 2.43 - 6.17
195.89 13.62 44.33 6.17
Total
West
3.87
37.08
95.59
52.53
189.07
93.41
125.36
108.61
20.23
347.61
National
9.80
123.17
219.45
325.14
132.82
810.38
121. 15
133.43
109.01
20.47
384.06
NATIONAL
171.82 214.71
19.68
244.11 7.44 657.76 63.85 23.75 367.12 31.46 44.33
6.17
536.68 1,194.44
-------
EXHIBIT D-15
1990 COAL DISTRIBUTION
FOR CURRENT NEW SOURCE PERFORMANCE STANDARDS
OF 1.2 LBS. FOR REFERENCE CASE I
CONSUMING REGION
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL EAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
Appalachia Appalachia
14.14 0.93
98.49 23.14
46.32 102.75
30.48 67.02
6.41
189.43 200.25
0.92
0.30
-
-
1.22
(10 tons)
SUPPLY REGION
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
15.07
121.63
1.54 39.17 - 189.78
162.25 0.64 260.39
14.88 58.06 - 79.35
16.42 259.48 0.64 666.22
20.54 3.54 25.00 - 42.80
3.00 2.25 5.55 79.45
-
0.41 0.41
20.54 6.20 30.96 79.45 42.80
western
Northern
Great
Plains Rockies Southwest Northwest
0.12 -
44.39 - - -
92.09 - - -
132.90 17.96
77.99 0.89
347.49 18.85
86.33 4.95
80.25 - 34.89
102.82 11.38 34.97
25.91 7.47 - 6.17
295.31 23.80 69.86 6.17
Total
West
0.12
44.39
92.09
150.86
78.88
366.34
134.08
194.59
149.17
39.55
517.39
National
15.19
166.02
281.87
411.25
158.23
1,032.56
159.08
200.14
149.17
39.96
548.35
NATIONAL
189.43 201.47
16.42
283.02 6.84 697.18 79.45 42.80 642.80 42.65 69.86
6.17
883.73 1,580.91
-------
EXHIBIT D-16
1990 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 90% RtXOVAL FOR REFERENCE CASE I
( 10 tons)
SUPPLY REGION
Northern
CONSUMING REGION Appalachia
New England 14.55
Middle Atlantic 102.53
South Atlantic 80.31
East North
Central 27.16
East South
Central
TOTAL EAST 224.55
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Central
Appalachia
0
22
101
57
8
190
0
0
0
-
1
.93
.77
.32
.68
.09
.79
.92
.88
.07
.87
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
15,
125
2.02 40.52 - 224
177.95 0.24 263
13.38 70.04 - 91
15.40 288.51 0.24 719
21.28 2.93 25
4.85 2.46 8
0
0.34 0
26.13 5.73 33
.48 -
.30
.17 -
.03
.51
.49
.13 - 37.71
.19 103.01
.07
.34 -
.73 103.01 37.71
Western
Northern
Great
Plains Rockies Southwest
Total
Northwest West National
_ - - 15.48
18
55
117
63
254
91
79
102
20
294
.00
.51
.55 15.80
.04
.10 15.80
.93
.15 - 19.91
.35 11.67 36.62
.68 10.39
.11 22.06 56.53
18
55
133
63
.00
.51
.35
.04
269.90
129
202
150
7.17 38
7.17 520
.64
.07
.64
.24
.59
143.30
279
396
154
989
154
210
ISO
38
554
.68
.38
.55
.39
.77
.26
.71
.58
.32
NATIONAL
224.55
192.66
15.40
314.64 5.97 753.22 103.01 37.71 548.21 37.86 56.53
7.17
790.49 1,543.71
-------
EXHIBIT D-17
1990 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOORCE PERFORMANCE STANDARDS
OF 80% REMOVAL FOR REFERENCE CASE I
Northern
fYyNSUMING REGION Appclltich i.3
New England 14.56
Middle Atlantic 102.29
South Atlantic 81.13
Bast North
Central 28.17
East South
Central
TOTAL EAST 226.15
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Central
Appalachia
0.93
23. 13
101.64
57.52
8.01
191.23
0.92
0.89
0.07
-
1.88
(10 tons)
SUPPLY REGION
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
- - - 15.49
- - - 125.42
2.02 40.40 - 225.19
182.74 0.24 268.67
13.38 69.88 - 91.27
15.40 293.02 0.24 726.04
21.74 2.91 25.57 - 37.71
4.85 2.46 8.20 103.01
0.07
0.34 0.34 -
26.59 5.71 34.18 103.01 37.71
Western
Northern
Great
Plains Rockies Southwest Northwest
18.00 - -
54.33 -
115.47 17.72
64.63 0.89
252.43 18.61
91.64 1-77
79.29 - 19-91
102.45 11.30 34.97
23.39 8.57 - 7.17
296.77 21.64 54.88 7.17
Total
West
18.00
54.33
133.19
65.52
271.04
131. 12
202.21
148.72
39.13
521.18
National
15.49
143.42
279.52
401.86
156.79
997.08
156.69
210.41
148.79
39.47
555.36
NATIONAL
226.15
193.11
15.40
319.61 5.95 760.22 103.01 37.71
549.20 40.25
54.88
7.17
792.22 1,552.44
-------
EXHIBIT D-18
1990 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 0.5 LBS. FOR REFERENCE CASE I
(10 tons)
SUPPLY REGION
Eastern Western
Northern Northern
Northern Central Southern Central Total Great Great
CONSUMING REGION Appalachia Appalachia Appalachia Midwest West East Gulf Plains Plains Rockies Southwest
New England 14.62 0.93 - 15.55 - - - - -
Middle Atlantic 104.93 22.82 - 127.75 - - 17.25
South Atlantic 81.84 102.65 2.02 40.45 - 226.96 - - 48.62
Central 26.13 57.82 - 176.93 0.24 261.12 - - 115.06 19.40
East South
Central - 8.09 13.38 68.60 - 90.07 - - 64.66 0.89
TOTAL EAST 227.52 192.31 15.40 285.98 0.24 721.45 - - 245.59 20.29
West North
Central - 0.92 - 22.16 2.93 26.01 - 38.85 90.30 0.75
West South
Central - 0.86 - 4.87 2.49 8.22 103.01 - 72.25 - 24.40
Mountain - 0.07 - - - 0.07 - - 100.06 13.17 34.97
pacific _ 0.34 0.34 - - 32.88 2.44
TOTAL WEST - 1.85 - 27.03 5.76 34.64 103.01 38.85 295.49 16.36 59.37
Total
Northwest West National
-
17.25
48.62
134.46
65.55
265.88
129.90
199.66
148.20
7.17 42.49
7.17 520.25
15
145
275
395
155
987
155
207
148
42
554
.55
.00
.58
.58
.62
.33
.91
.88
.27
.83
.89
NATIONAL
227.52
194.16
15.40
313.01 6.00 756.09 103.01 38.85 541.08 36.65 59.37
7.17
786.13 1,542.22
-------
EXHIBIT D-19
1990 COAL DISTRIBUTION
FOR CURRENT NEW SOURCE PERFORMANCE STANDARDS
OF 1.2 LBS. FOR REFERENCE CASE II
CONSUMING REGION
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL BAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
Appalachia Appalachia
19.31 0.93
104.70 25.39
51.67 117.43
28.50 68.21
5.61
204.18 217.57
0.92
0.30
- -
_ _
1.22
(10 tons)
SUPPLY REGION
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West Bast Gulf Plains
20.24 -
_ - - 130.09
2.11 32.79 - 204.00
171.84 0.72 269.27
15.90 62.06 - 83.57
18.01 266.69 0.72 707.17
20.88 3.54 25.34 - 46.14
3.00 2.56 5.86 90.01
~
0.35 0.35
23.88 6.45 31.55 90.01 46.14
Western
Northern
Great
Plains Rockies Southwest Northwest
0.17 - - -
62.25 - - -
107.66 - - -
170.35 14.12
99.83 0.89
440.26 15.01
94.31 7.67
89.53 - 36.24
108.59 11.38 34.75
30.75 15.06 - 6.17
323.18 34.11 70.99 6.17
Total
West
0.17
62.25
107.66
184.47
100.72
455.27
148.12
215.78
154.72
51.98
570.60
National
20.41
192.34
311.66
453.74
184.29
1,162.44
173.46
221.64
154.72
52.33
602.15
NATIONAL
204.18 218.79
18.01
290.57 7.17 738.72 90.01 46.14
763.44 49.12 70.99
6.17 1,025.87 1,764.59
-------
EXHIBIT D-20
1990 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 90% REMOVAL FOR REFERENCE CASE II
(10 tons)
SUPPLY REGION
Northern Central
CONSUMING REGION Appalachia Appalachia
New England 19.80 0.93
Middle Atlantic 115.28 23.07
South Atlantic 91.50 105.20
East North
Central 30.72 58.14
East South
Central - 7.56
TOTAL EAST 257.30 194.90
West North
Central - 0.92
West South
Central - 0.88
Mountain - 0.70
Pacific
TOTAL WEST - 2.50
Eastern Western
Northern Northern
Southern Central Total Great Great Total
Appalachia Midwest West East Gulf Plains Plains Rockies Southwest Northwest West National
20.73 ----- - - 20.73
- 138.35 - - 18.00 _ - - 18.00 156.35
1.05 56.87 - 254.62 - - 64.32 - 64.32 318.94
196.53 0.32 285.71 - - 133.44 11.75 - - 145.19 430.90
13.98 84.93 - 106.47 - - 69.89 0.89 - - 70.78 177.25
15.03 338.33 0.32 805.88 - - 285.65 12.64 - - 298.29 1,104.17
21.98 4.53 27.43 - 37.78 104.31 0.45 - - 142.54 169.97
3.88 2.87 7.63 103.01 - 89.52 - 28.43 - 220.96 228.59
0.70 - - 107.39 11.86 36.40 - 155.65 156.35
0.34 0.34 - - 26.72 17.12 - 7.17 51.01 51.35
25.86 7.74 36.10 103.01 37.78 327.94 29.43 64.83 7.17 570.16 606.26
NATIONAL
257.30
197.40
15.03
364.19 8.06 841.98 103.01 37.78 613.59 42.07
64.83
7.17
868.45 1,710.43
-------
EXHIBIT D-21
1990 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OP 80% REMOVAL FOR REFERENCE CASE II
(10 tons)
SUPPLY REGION
CONSUMING REGION
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL EAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
Appalachia Appalachia
19.79 0.93
114.05 23.13
93.31 104.08
29.25 58.14
7.44
256.40 193.72
0.92
0.89
0.07
-
1.88
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
20.72
- - - 137.16
1.17 56.87 - 255.43
194.33 0.32 282.04
13.98 84.85 - 106.27
15.15 336.05 0.32 801.64
22.05 4.53 27.50 - 37.78
3.78 2.46 7.13 103.01
- 0.07
0.34 0.34
25.83 7.33 35.04 103.01 37.78
Western
Northern
Great
Plains Rockies Southwest Northwest
_
18.00 - - -
63.06 -
128.83 19.64
69.50 0.89
279.39 20.53
102.98 2.10
90.16 - 28.42
107.81 11.30 34.75
40.20 8.17 - 7.17
341.15 21.57 63.17 7.17
Total
West
-
18.00
63.06
148.47
70.39
299.92
142.86
221.59
153.86
55.54
573.85
National
20.72
155. 18
318.49
430.51
176.66
1,101.56
170.36
228.72
153.93
5S.88
608.89
NATIONAL
256.40
195.60
15.15 361.88 7.65 836.68 103.01 37.78 620.54 42.10 63.17
7.17
873.77 1,710.55
-------
EXHIBIT D-22
1990 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 0.5 LBS. FOR REFERENCE CASE II
(10 tons)
SUPPLY REGION
Northern
Central
Southern
Central Total
Eastern Western
Northern Northern
Great Great
Total
Plains Plains Rockies Southwest Northwest West National
CONSUMING REUION Appaiacnia
New England 19.97
Middle Atlantic 116.52
South Atlantic 90.52
East North
Central 30.86
East South
Central
TOTAL EAST 257.69
West North
Central -
West South
Central
Mountain
Pacific
TOTAL WEST
0
23
104
58
7
193
0
0
0
-
1
.93
. 13
.09
. 16
.52
.83
.92
.86
.07
.85
20
- - - 139
1.17 56.38 - 252
194.66 - 283
13.98 85.75 - 107
15.15 336.78 - 803
22.49 4.53 27
4.87 2.49 8
_ 0
0.34 0
27.36 7.36 36
.72
.65
.16 -
.68
.25
.46
.94 - 38.92
.22 103.01
.07
.34 -
.57 103.01 38.92
-
17
63
124
69
275
101
82
105
50
339
-
.52
.93
.23 20.40
.75 0.89
.43 21.29
.75 1.97
.01 - 32.97
.13 13.34 34.75
.39 2.46
.28 17.77 67.72
-
17
63
144
70
296
142
217
153
7.17 60
7.17 573
.52
.93
.63
.64
.72
.64
.99
.22
.02
.87
20
157
316
428
177
1,100
170
226
153
60
610
.72
.17
.09
.31
.89
.18
.58
.21
.92
.36
.44
NATIONAL
257.69
195.68
15.15
364.15 7.36 840.03 103.01 38.92 614.71 39.06 67.72
7.17
870.59 1,710.62
-------
EXHIBIT D-23
TOTAL WEST
NATIONAL
1995 COAL DISTRIBUTION
FOR CURRENT NEW SOORCB PERFORMANCE STANDARDS
OF 1.2 LBS. FOR REFERENCE CASE I
D .
Northern
CONSUMING REGION Appsl3Cnl3
New England 13.07
Middle Atlantic 99.52
South Atlantic 54.80
East North
Central 31.95
East South
Central
TOTAL EAST 199.34
West North
Central
West South
Central
Mountain
Pacific
(10 tons)
SUPPLY REGION
Eastern Western
Northern Northern
Central Southern ^^^ t^^"1 T^ ^lf p"tL Pl^Le Rockies Southwest
_ 13.07 - - °'17
22.49 . - - 122.01 - - 49.80
97.21 0.50 37.84 - 190.35 - - 89.47
68. 18 - 183.22 0.72 284.07 - - 158.83 11.51
6.24 15.16 59.97 - 81.82 - - 77.28 0.89
194.12 16.11 281.03 0.72 691.32 - - 375.55 12.40
0.96 - 20.15 2.80 23.91 - 69.93 110.14 8.59
0.97 - 3.00 1.70 5.67 93.00 - 86.29 - 42.41
, „. i 03 127.40 10.38 38.59
1.03 - ~ i.uj
1.97 1.97 - - 51.38 5.81
, « - 23.15 6.47 32.58 93.00 69.93 375.21 24.78 81.00
Total
Northwest West
0.17
49.80
89.47
170.34
78.17
387.95
188.66
221.70
176.37
3.66 60.85
3.66 647.58
National
13.24
171.81
279.82
454.41
159.99
1,079.27
212.57
227.37
177.40
62.82
680.16
199.34
197.08
16. 11
304.18 7.19 723.90 93.00 69.93 750.76 37.18 81.00
3.66
1,035.53 1,759.43
-------
EXHIBIT D-24
1995 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 90% REMOVAL FOR REFERENCE CASE I
(10 tons)
SUPPLY REGION
Northern
New England 14.00
Kiddle Atlantic 105.59
South Atlantic 81.59
East North
Central 27.66
Bast South
Central
TOTAL EAST 228.84
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Eastern
Northern
Central Southern Central Total Great
Appalachia Appalachia Midwest West East Gulf Plains
- 14.00
22.33 - - - 127.92
89.94 - 38.65 - 210.18
61.47 - 194.28 0.32 283.73
7.23 14.59 69.35 - 91.17
180.97 14.59 302.28 0.32 727.00
0.96 - 21.90 3.60 41.05 - 63.20
0.97 - 5.47 1.88 8.32 93.00
1.03 - - - 1.03 -
1.97 1.97
2.96 - 27.37 7.45 37.78 93.00 63.20
Western
Northern
Great
Plains Rockies Southwest
0.17
23.42
75.89
132.48 10.97
68.58 0.89
300.54 11.86
115.03 0.97
104.74 - 28.76
130.98 10.70 43.36
31.55 8.87
382.30 20.54 72.12
Total
Northwest West
0.17
23.42
75.89
143.45
69.47
312.40
179.20
226.50
185.04
3.66 44.08
3.66 634.82
National
14. 17
151.34
286.07
427.18
160.64
1,039.40
205.66
234.82
186.07
46.05
672.60
NATIONAL
228.84
183.93
329.65 7.77 764.78 93.00 63.20 682.84 32.40 72.12
3.66
974.22 1,712.00
-------
EXHIBIT D-25
1995 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 80% REMOVAL FOR REFERENCE CASE I
(10 tons)
SUPPLY REGION
CONSUMING REGION
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL EAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
Appalachia Appalachia
14.10
103.97 22.34
82.36 90.81
30.80 60.00
7.23
231.23 180.38
0.96
1.14
1.03
-
3.13
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
14.10-
126.31
38.55 - 211.72
196.15 0.32 287.27
14.59 71.05 - 92.87
14.59 305.75 0.32 732.27
22.50 3.60 27.06 - 63.80
5.47 1.73 8.34 93.00
- 1.03
1.97 1.97
27.97 7.30 38.40 93.00 63.80
Western
Northern
Great
Plains Rockies Southwest Northwest
23.42 -
74.84 -
132.78 13.44
69.03 0.89
300.07 14.33
115.07 2.33
104.87 - 31.29
131.13 10.31 41.70
34.26 7.04 - 3.66
385.33 19.68 72.99 3.66
Total
West
23.42
74.84
146.22
69.92
314.40
181.20
229.16
183.14
44.96
638.46
National
14.10
149.73
286.56
433.49
162.79
1,046.67
208.26
237.50
184.17
46.93
676.86
NATIONAL
231.23
183.51
14.59
333.72 7.62 770.67 93.00 63.80 685.40 34.01 72.99
3.66
952.86 1,723.53
-------
EXHIBIT D-26
1995 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 0.5 LBS. FOR REFERENCE CASE I
Northern Central
CONSUMING REGION Appalachia Appalachia
New England 14.02
Middle Atlantic 106.02 22.46
South Atlantic 79.52 92.64
East North
Central 29.59 59.46
East South
Central - 7.23
TOTAL EAST 229.15 181.79
West North
Central - 0.96
West South
Central - 0.97
Mountain - 1.03
Pacific
TOTAL WEST - 2.96
(10 tons)
SUPPLY REGION
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
- 14.02
- - - 128.48
38.60 - 210.76
190.24 0.32 279.61
14.59 68.74 - 90.56
14.59 297.58 0.32 723.43
21.77 3.60 26.33 - 65.74
5.49 1.86 8.32 93.00
- - - 1.03
1.97 1.97
27.26 7.43 37.65 93.00 65.74
Western
Northern
Great
Plains Rockies Southwest Northwest
0.17 _ - -
22.67 -
73.52 -
132.64 14.75
69.70 0.69
298.70 15.64
105.99 3.16
97.87 - 26.59
128.71 11.81 41.69
43.85 0.87 - 3.66
376.42 15.84 68.28 3.66
Total
West
0. 17
22.67
73.52
147.39
70.59
314.34
174.89
217.46
182.21
48.38
622.94
National
14. 19
151. 15
284.28
427.00
161. 15
1,037.77
201.22
225.78
183.24
50.35
660.59
NATIONAL
229. 15
184.75
14.59
324.84 7.75 761.08 93.00 65.74 675.12 31.48
68.28
3.66
937.28 1,698.36
-------
EXHIBIT D-27
1995 COAL DISTRIBUTION
FOR CURRENT NEW SOURCE PERFORMANCE STANDARDS
OF 1.2 LBS. FOR REFERENCE CASE II
Northern
CONSUMING REGION Appalachia
New England 18.19
Middle Atlantic 109.09
South Atlantic 60.99
East North
Central 32.60
East South
Central
TOTAL EAST 220.87
West North
Central
West South
Central
Mountain -
Pacific
TOTAL WEST
( 1 0 tons )
SUPPLY REGION
Eastern
Northern
Central Southern Central Total Great
Appalachia Appalachia Midwest West East Gulf Plains
- - - 18.19
24.08 - - - "3.17
119.86 1.34 36.13 - 218.32
71.48 - 199.42 0.80 304.30
5.27 16.57 63.51 - 85.35
220.69 17.91 299.06 0.80 759.33
0.95 - 20.82 2.80 24.57 - 71.31
0.59 - 3.00 2.07 5.66 93.00
1.03 - - - 1-03
1.98 1.98 -
2.57 - 23.82 6.85 33.24 93.00
Western
Northern
Great
Plains Rockies Southwest Northwest
82.69 - - -
103.39 - - -
279.99 12.03
122.03 0.89
588.10 12.92
145.64 9.78
136.04 - 61.91
149.58 10.38 39.99
69.31 12.26 - 3.66
500.57 32.42 101.90 3.66
Total
West
82.69
103.39
292.02
122.92
601.02
226.73
290.95
199.95
85.23
802.86
National
18. 19
215.86
321.71
596.32
208.27
1,360.35
251.30
296.61
200.98
87.21
836.10
NATIONAL
220.87
223.26
17.91
322.88 7.65 792.57 93.00 71.31 1,088.67 45.34
101.90
3.66
1,403.88 2,196.45
-------
EXHIBIT D-28
1995 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 90% REMOVAL FOR REFERENCE CASE II
CONSUMING REGION
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL EAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
Appalachia Appalachia
18.85
126.31 22.33
103.58 93.53
52.69 60.71
7.10
301.43 183.67
0.96
0.97
1.03
-
2.96
( 1 0 tons )
SUPPLY REGION
Eastern
Northern
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
18.85
- 148.64
53.17 - 250.28
239.07 0.56 353.03
14.71 94.85 - 116.66
14.71 387.09 0.56 887.46
21.97 5.60 28.53 - 85.66
3.00 3.72 7.69 93.00
- - - 1.03
1.97 1.97 -
24.97 11.29 39.22 93.00 85.66
Western
Northern
Great
Plains Rockies Southwest Northwest
0.17 -
23.42 -
81.31 -
152.32 12.32
87.31 0.89
344.53 13.21
161.26 0.27
148.72 - 57.25
150.95 10.90 42.79
67.57 15.63 - 3.66
528.50 26.80 100.04 3.66
Total
West
0.17
23.42
81.31
164.64
88.20
357.74
247.19
298.97
204.64
86.86
837.66
National
19.02
172.06
331.59
517.67
204.86
1,245.20
275.72
306.66
205.67
88.83
876.88
NATIONAL
301.43
186.63
14.71 412.06 11.85 926.68 93.00 85.66 873.03
40.01
100.04
3.66
1,195.40 2,122.08
-------
EXHIBIT D-29
1995 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 80% REMOVAL FOR REFERENCE CASE II
(1CT tons)
SUPPLY REGION
Eastern Western
Northern Northern
Northern
CONSUMING REGION Appalachia
New England 18.65
Kiddie Atlantic 125.67
South Atlantic 104.32
Bast North
Central 51.06
East South
Central
TOTAL EAST 299.70
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Central
Appalachia
22.47
92.50
62.18
7.12
184.27
0.96
0.97
1.03
-
2.96
Southern Central Total Great
Appalachia Midwest West East Gulf Plains
- - - 18.65
- 148.14
53.16 - 249.98
234.84 0.56 348.64
14.69 98.17 - 119.98
14.69 386.72 0.56 885.39
22.01 5.60 28.57 - 84.86
3.00 3.65 7.62 93.00
- - - 1.03
1.97 1.97
25.01 11.22 39.19 93.00 84.86
Great
Plains Rockies Southwest Northwest
0.13 -
23.42 -
81.10 -
146.74 16.40
81.01 0.89
332.40 17.29
171.12 4.09
148.92 - 57.23
148.39 10.33 42.36
81.03 6.63 - 3.66
549.46 21.05 99.59 3.66
Total
West
0.13
23.42
81.10
136.14
81.90
349.69
260.07
299.15
201.08
91.32
851.62
National
18.78
171.56
331.08
511.78
201.88
1,235.08
288.64
306.77
202.11
93.29
890.81
NATIONAL
299.70
187.23
14.69
411.18 11.78 924.58 93.00 84.86 881.86 38.34 99.59 3.66
1,201.31 2,125.89
-------
EXHIBIT D-30
1995 COAL DISTRIBUTION
FOR ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
OF 0.5 LBS. FOR REFERENCE CASE II
Northern
CONSUMING REGION Appalachia
New England 18.95
Middle Atlantic 127.20
South Atlantic 103.17
East North
Central 51.90
East South
Central
TOTAL EAST 301.22
west North
Central
West South
Central
Mountain -
Pacific
TOTAL WEST
( 10 tons)
SUPPLY REGION
Eastern Western
Northern Northern
Central Southern Central Total Great Great
Appalachia Appalachia Midwest West East Gulf Plains Plains Rockies Southwest Northwest
18.95 - - -
22.34 - - - 149.54 - - 22.67 -
95.09 0.39 53.12 - 251.77 - - 74.59 -
62.49 - 230.49 0.56 345.44 - - 177.11 17.61
6.49 15.31 98.21 - 120.01 - - 81.44 0.89
186.41 15.70 381.82 0.56 885.71 - - 355.81 18.50
0.96 - 23.72 5.85 30.53 - 67.56 145.05 4.45
0.97 - 4.56 2.78 8.31 93.00 - 142.86 - 60.78
,.03 _ 1.03 - - 147.41 11.75 42.25
1.97 1.97 - - 91.01 0.87 - 3.66
2.96 - 28.28 10.60 41.84 93.00 67.56 526.33 17.07 103.03 3.66
Total
West
-
22.67
74.59
194.72
82.33
374.31
217.06
203.64
201.41
95.54
717.65
National
18.95
172.21
326.36
540.16
202.34
1,260.02
247.59
211.95
202.44
97.51
759.49
NATIONAL
301.22
189.37
15.70
410.10 11.16 927.55 93.00 67.56 882.14 35.57 103.03 3.66
1,091.96 2,019.51
-------
Exhibit D-31
1985 MINE MOUTH PRICES
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
$/106 Btu's (in 1977 $'s)
Reference Case I
Reference Case II
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central West
Eastern
Northern
Great Plains
Western
Northern
Great Plains
Gulf
Rocky
Mountains
Southwest
Northwest
National
Coal
Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
1.2 Ibs.
0.87
1.02
1.41
0.85
1.12
1.37
1.20
1.35
0.82
1.12
1.39
0.91
1.18
1.25
0.41
0.41
0.47
0.42
0.57
0.32
0.87
0.90
0.56
0.70
0.85
0.83
0.80
0.68
90%
0.89
1.02
1.40
0.89
1.12
1.37
1.19
1.34
0.84
1.11
1.38
0.97
1.17
1.24
0.41
0.41
0.44
0.42
0.58
0.36
0.88
0.91
0.56
0.77
0.85
0.86
0.80
0.70
80%
0.89
1.02
1.40
0.89
1.12
1.37
1.19
1.34
0.84
1.11
1.38
0.97
1.17
1.24
0.41
0.41
0.44
0.42
0.58
0.36
0.88
0.91
0.56
0.78
0.85
0.86
0.79
0.70
0.5 Ibs.
0.88
1.02
1.40
0.90
1.12
1.37
1.19
1.34
0.83
1.11
1.38
0.99
1.17
1.24
0.41
0.41
0.44
0.43
0.58
0.36
0.88
0.91
0.56
0.78
0.85
0.85
0.80
0.70
1.2 Ibs.
0.87
1.02
1.41
0.85
1.12
1.37
1.20
1.35
0.82
1.12
1.39
0.91
1.18
1.25
0.41
0.41
0.47
0.42
0.58
0.32
0.87
0.90
0.56
0.70
0.85
0.83
0.80
0.68
90%
0.89
1.02
1.40
0.89
1.12
1.37
1.19
1.34
0.84
1.11
1.38
0.97
1.17
1.24
0.41
0.41
p. 44
0.42
0.58
0.36
0.88
0.91
0.56
0.77
0.85
0.86
0.80
0.70
80%
0.89
1.02
1.40
0.89
1.11
1.37
1.19
1.34
0.84
1.11
1.38
0.97
1.17
1.24
0.41
0.41
0.44
0.42
0.58
0.36
0.88
0.91
0.56
0.78
0.85
0.86
0.79
0.70
0.5 Ibs.
0.88
1.02
1.40
0.90
1.12
1.37
1.19
1.34
0.83
1.11
1.38
0.99
1.17
1.24
0.41
0.41
0.44
0.43
0.58
0.36
0.88
0.91
0.56
0.78
0.85
0.85
0.80
0.70
-------
Exhibit D-32
1990 MINE MOUTH PRICES
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
S/106 Btu's (in 1977 $'s)
Reference Case I
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central West
Eastern
Northern
Great Plains
Western
Northern
Great Plains
Gulf
Rocky
Mountain
Southwest
Northwest
National
Coal
Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Higher Sulfur
Medium Sulfur
Low Sulfur
1.2 Ibs.
0.98
1.05
1.46
1.02
1.20
1.46
1.26
1.46
0.89
1.13
1.50
1.00
1.24
1.35
0.41
0.41
0.49
0.41
0.56
0.39
0.89
1.01
0.63
0.71
0.90
0.92
0.77
0.66
90%
1.03
1.05
1.43
1.10
1.20
1.43
1.40
1.40
0.93
1.15
1.42
1.05
1.24
1.27
0.41
0.41
0.44
0.43
0.56
0.51
0.90
0.96
0.62
0.76
0.92
0.96
0.77
0.68
80%
1.03
1.05
1.43
1.10
1.20
1.43
1.40
1.40
0.93
1.14
1.42
1.05
1.23
1.27
0.41
0.41
0.44
0.42
0.56
0.51
0.90
1.00
0.62
0.77
0.92
0.96
0.77
0.69
0.5 Ibs.
1.01
1.06
1.43
1.09
1.22
1.43
1.40
1.40
0.93
1.14
1.42
1.05
1.24
1.27
0.41
0.41
0.46
0.43
0.56
0.56
0.90
0.95
0.62
0.75
0.92
0.96
0.79
0.67
Reference Case II
1.2 Ibs.
1.00
1.06
1.50
1.04
1.23
1.49
1.28
1.50
0.90
1.15
1.53
1.00
1.25
1.38
0.41
0.41
0.50
0.41
0.58
0.42
0.91
1.04
0.67
0.74
0.90
0.93
0.78
0.68
90%
1.04
1.07
1.45
1.11
1.21
1.44
1.29
1.44
0.97
1.17
1.43
1.06
1.24
1.28
0.41
0.41
0.44
0.42
0.56
0.52
0.93
0.99
0.63
0.74
0.92
0.99
0.77
0.68
80%
1.04
1.07
1.44
1.11
1.21
1.44
1.29
1.44
0.97
1.15
1.43
1.05
1.24
1.28
0.41
0.41
0.44
0.42
0.55
0.52
0.90
1.00
0.63
0.75
0.92
0.99
0.76
0.68
0.5 Ibs.
1.03
1.07
1.44
1.12
1.23
1.44
1.30
1.44
0.97
1.15
1.43
1.06
1.24
1.28
0.41
0.41
0.46
0.42
0.55
0.57
0.91
0.96
0.63
0.74
0.92
0.99
0.79
0.66
-------
Exhibit D-33
1995 MINE MOUTH PRICES
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
S/106 Btu's (in 1977 $'s)
Reference Case I
Reference Case II
Northern
Appalachia
Central
Appalachia
Southern
Appalachia
Midwest
Central West
Coal
Type
High Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
Eastern High Sulfur
Northern Medium Sulfur
Great Plains Low Sulfur
Western
Northern
Great Plains
Gulf
Rocky
Mountains
Southwest
Northwest
National
Medium Sulfur
Low Sulfur
Medium Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Low Sulfur
Medium Sulfur
Higher Sulfur
Medium Sulfur
Low Sulfur
1.2 Ibs.
1.01
1.05
1.49
1.23
1.62
1.44
1.50
0.93
1.14
1.54
1.06
1.31
1.39
0.41
0.41
0.51
0.42
0.57
0.52
0.90
1.07
1.08
0.81
1.04
0.95
0.77
0.69
90%
1.04
1.06
1.47
1.22
1.60
1.43
1.47
0.95
1.15
1.45
1.05
1.31
1.31
0.41
0.41
0.49
0.41
0.55
0.90
0.92
1.03
1.08
0.76
1.04
0.98
0.77
0.68
80%
1.04
1.06
1.46
1.22
1.55
1.42
1.47
0.96
1.14
1.44
1.05
1.31
1.31
0.41
0.41
0.49
0.41
0.55
0.90
0.91
1.05
1.08
0.78
1.04
0.98
0.77
0.68
0.5 Ibs.
1.03
1.06
1.47
1.23
1.60
1.43
1.47
0.95
1.14
1.45
1.05
1.31
1.30
0.41
0.41
0.49
0.41
0.54
0.90
0.91
1.03
1.08
0.74
1.04
0.97
0.78
0.67
1.2 Ibs.
1.02
1.07
1.54
1.26
1.66
1.40
1.67
0.94
1.16
1.60
1.06
1.32
1.43
0.41
0.41
0.58
0.41
0.60
0.90
0.94
1.12
1.08
0.98
1.04
0.96
0.77
0.72
90%
1.07
1.08
1.47
1.23
1.61
1.40
1.54
1.04
1.18
1.46
1.10
1.31
1.32
0.41
0.41
0.49
0.44
0.53
0.94
1.01
1.07
1.08
0.92
1.04
1.05
0.77
0.70
80%
1.07
1.08
1.47
1.23
1.61
1.40
1.51
1.04
1.17
1.46
1.10
1.31
1.32
0.41
0.41
0.49
0.44
0.53
0.94
0.93
1.07
1.08
0.91
1.04
1.05
0.76
0.70
0.5 Ibs.
1.07
1.09
1.48
1.24
1.57
1.40
1.51
1.04
1.17
1.46
1.09
1.30
1.32
0.41
0.51
0.44
0.55
0.94
0.93
1.05
1.08
0.96
1.04
1.07
0.79
0.71
-------
Exhibit D-34
1985 DELIVERED COAL PRICES TO ELECTRIC UTILITIES SECTOR
UNDER ALTERNATIVE HEW SOURCE PERFORMANCE STANDARDS
Mid-Atlantic
South
Atlantic
East North
Central
Bast South
Central
West North
Central
West South
Central
Mountain
Pacific
National
Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
tow Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
S/106 Btu's ( 1977 S
Reference Case I
1.2 Ibs.
1. 12
1.85
1.90
.95
1.31
1.80
1.04
1.36
1.52
.97
1.24
1.36
.97
1.15
1.31
.94
.83
.95
.84
.58
1.21
.63
.74
.96
.94
0.98
1.10
1.23
90%
1.18
1.39
1.90
1.05
1.29
1.78
1.07
1.37
1.51
1.00
1.25
1.44
.99
1.14
1.28
.97
.84
.94
1.10
.64
1.21
.64
.73
.96
.94
1.02
1.09
1.23
80%
1.18
1.39
1.89
1.05
1.29
1.78
1.07
1.37
1.51
1.00
1.24
1.44
.99
1.14
1.23
.97
.84
.94
1.10
.64
1.21
.63
.74
.96
.94
1.02
1.09
1.23
0.5 Ibs.
1.18
1.39
1.90
1.03
1.30
1.79
1.06
1.37
1.51
.99
1.25
1.44
.99
1. 14
1.28
.96
.83
.94
1.13
.61
1.21
.63
.73
.96
.94
1.01
1.09
1.23
Reference Case II
1.2 Ibs.
1.12
1.85
1.90
.95
1.31
1.80
1.04
1.36
1.52
.97
1.24
1.36
.97
1.15
1.31
.94
.83
.95
.84
.58
1.21
.63
.74
.96
.94
0.98
1.10
1.23
90%
1.18
1.39
1.90
1.05
1.29
1.78
1.07
1.37
1.51
1.00
1.25
1.44
.99
1.14
1.28
.97
.84
.94
1.10
.64
1.21
.64
.73
.96
.94
1.02
1.09
1.23
80%
1.18
1.39
1.89
1.05
1.29
1.78
1.07
1.37
1.51
1.00
1.24
1.44
.99
1.14
1.28
.97
.84
.94
1.10
.64
1.21
.63
.74
.96
.94
1.02
1.09
1.23
0.5 Ibs.
1. 18
1.39
1.90
1.03
1.30
1.79
1.06
1.37
1.51
.99
1.25
1.44
.99
1. 14
1.28
.96
.83
.94
1.13
.61
1.21
.63
.73
.96
.94
1.01
1.09
1.23
-------
Exhibit D-35
1990 DELIVERED COAL PRICES TO ELECTRIC UTILITIES SECTOR
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Mid-Atlantic
South
Atlantic
East North
Central
East South
Central
West North
Central
West South
Central
Mountain
Pacific
National
Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
S/106 Btu's (1977 S
Reference Case I
1.2 Ibs.
1.33
1.37
1.92
1.19
1.35
1.62
1.17
1.39
1.60
1.07
1.24
1.37
1.06
1.17
1.36
1.02
.82
1.00
1.01
.62
1.27
.60
.80
.99
1.23
1.10
1.10
1.31
90%
1.30
1.36
1.98
1.25
1.34
1.97
1.28
1.39
1.54
1.11
1.26
1.47
1.10
1.18
1.26
1.07
.84
.98
1.25
.75
1.25
.63
.79
1.28
1.14
1. 15
1.18
1.26
80%
1.30
1.36
1.98
1.25
1.34
1.99
1.28
1.40
.547
1.11
1.25
1.47
1.11
1.18
1.26
1.07
.84
.98
1.25
.75
1.25
.62
.79
1.01
1.25
1.18
1.08
1.26
0.5 Ibs.
1.29
1.36
1.98
1.24
1.34
1.98
1.26
1.40
1.54
1.11
1.25
1.47
1.10
1.18
1.126
1.05
.84
.97
1.25
.78
1.25
.62
.79
1.01
1. 12
1. 16
1.10
1.25
1.2 Ibs.
1.30
1.38
1.98
1.20
1.37
1.60
1.17
1.41
1.62
1.08
1.24
1.37
1.07
1.15
1.38
1.03
.83
1.04
1.02
.62
1.30
.65
.82
1.28
1.22
1.11
1.11
1.35
Reference Case II
90%
1.30
1.36
2.17
1.28
1.35
1.99
1.31
1.39
1.58
1.15
1.26
1.48
1.15
1.19
1.35
1.10
.84
.98
1.29
.79
1.25
.65
.78
1.34
1.13
1.21
1.09
1.27
80%
1.30
1.37
2.16
1.26
1.35
2.01
1.31
1.40
1.58
1.15
1.25
1.48
1.15
1.19
1.35
1.10
.84
.98
1.29
.79
1.25
.63
.78
1.04
1. 16
1.21
1.09
1.27
0.5 Ibs.
1.30
1.38
2.18
1.26
1.36
2.01
1.29
1.40
1.58
1.14
1.26
1.48
1.15
1.20
1.35
1.09
.83
.96
1.30
.81
1.25
.64
.79
1.03
1. 10
20
1 1
1.26
-------
Exhibit D-36
1995 DELIVERED COAL PRICES TO ELECTRIC UTILITIES SECTOR
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
$/106 Btu's (1977 S'S)
Kid-Atlantic
South
Atlantic
East North
Central
East South
Central
West North
Central
West South
Central
Mountain
Pacific
National
Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
Reference Case I
1.2 Ibs.
1.33
1.36
1.93
1.21
1.34
2.17
1.21
1.38
1.51
1. 11
1.25
1.36
1.10
1.18
1.33
1.06
.84
1.05
.99
.72
1.35
.75
.80
1.25
1.05
1.13
1.11
1.32
90%
1.30
1.38
1.94
1.25
1.32
3.76
1.29
1.38
1.58
1.14
1.27
1.48
1.12
1.18
1.29
1.08
.83
1.00
1.28
.99
1.28
.69
.78
1.31
1.02
1.19
1.11
1.34
80%
1.30
1.36
1.91
1.25
1.32
3.31
1.23
1.38
1.57
1.14
1.27
1.48
1.13
1.18
1.30
1.09
.83
1.00
1.28
.99
1.28
.68
.79
1.28
1.15
1.17
1.11
1.31
0.5 Ibs.
1.31
1.36
1.94
1.25
1.32
3.83
1.20
1.39
1.52
1.14
1.27
1.48
1.12
1.18
1.29
1.08
.83
.97
1.28
.98
1.28
.66
.80
1.04
1.11
1.16
1.13
1.32
Reference Case II
1.2 Ibs.
1.31
1.39
1.98
1.22
1.39
1.88
1.68
1.41
1.22
1.11
1.25
1.36
1.11
1.18
1.42
1.16
.85
1.00
1.32
1.07
1.31
.80
.80
1.43
1.00
1.14
1.15
1.40
90%
1.33
1.38
1.93
1.28
1.36
3.90
1.35
1.41
1.61
1.22
1.29
1.49
1.20
1.19
1.30
1.16
.84
1.00
1.32
1.07
1.31
.78
.80
1.28
1.04
1.25
1.14
1.31
80%
1.33
1.39
1.92
1.28
1.36
4.21
1.35
1.42
1.60
1.22
1.28
1.49
1.20
1.19
1.34
1.07
.84
1.11
1.03
.99
1.46
.78
.85
1.26
1.08
1.25
1.13
1.31
0.5 Ibs.
1.33
1.39
1.92
1.28
1.36
3.32
1.33
1.42
1.59
1.21
1.28
1.39
1.20
1.21
1.33
1.16
.86
.99
1.35
1.08
1.33
.81
.83
1.08
1.06
1.24
1.17
1.26
-------
EXHIBIT D-37
1985 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASES I S II
Generation Capacity (In GW)
1.2 Ibs.
90%
80%
0.5 Ibs.
Average Capacity Factor
1.2 Ibs.
90%
80%
0.5 Ibs.
New England
Coal
Existing 4.0 4.0 4.0 4.0
NSPS - - - -
ANSPS ~
Total 4.0
Oil and Gas
Steam 7.6
Combined Cycle 0.4
Turbines and Internal Combustion 9.B
Total 17.7
Nuclear, Hydro and Other 8.3
Total 30.1 30.2 30.2 30.2
4.0
7.6
0.4
9.9
17.8
8.3
4.0
7.6
0.4
9.9
178
8.3
4.0
7.6
0.4
9.9
17.8
8.3
.570
.570
.420
.517
.477
.667
.667
.416
.517
.478
.667
.667
.416
.517
.478
.667
.667
.416
.517
.478
Middle Atlantic
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
25.7
3.8
2.5
31.9
15.5
0.4
18.9
34.9
27.6
25.7
3.8
2.3
31.8
15.5
0.4
19.2
35.2
27.6
25.7
3.8
2.3
31.8
15.5
0.4
18.9
34.9
27.5
25.7
3.8
2.3
31.8
15.5
0.4
19.5
35.4
27.5
94.3
94.6
94.2
94.8
.601
.691
.666
.617
.233
.610
.493
.604
.691
.667
.619
.233
.610
.473
.601
.691
.667
.616
.233
.610
.472
.609
.691
.667
.623
.235
.610
.474
South Atlantic
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
47.1
8.8
5.6
61.6
22.6
0.6
22.8
46.0
34.3
47.1
8.8
1.2
57.9
22.6
0.6
25.9
49.0
34.3
47.1
8.8
2.5
58.4
22.6
0.6
25.9
49.1
34.2
47.1
8.8
1.7
57.6
22.6
0.6
25.9
49.1
34.2
.629
.643
.412
.611
.290
.536
.613
.644
.650
.621
.301
.536
.615
.633
.650
.619
.301
.536
.615
.633
.650
.619
.301
.536
Total
141.9
141 .9
141.8
141.0
.489
.489
.489
.489
-------
EXHIBIT D-37 (Cont'd)
1985 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASES I & II
East North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
East South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
West North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Generation Capacity (in GW)
1.2 Ibs.
63.5
14.0
4.5
82.0
10.0
0.2
19. 1
29.3
25.4
136.8
30.2
8.8
2.0
41.1
3.0
16.5
19.5
18.2
78.7
18.5
16.8
2.2
37.6
3.8
0.1
12.1
16.0
9.2
90%
63.5
14.8
3.0
81.5
10.0
0.2
19.7
29.9
25.4
136.8
30.2
8.8
1.7
40.7
3.0
17.0
20.0
18.2
78.9
18.5
16.8
-
35.3
3.8
0.1
13.5
17.4
10.2
80%
63.5
14.8
3.0
81.5
10.0
0.2
19.5
29.8
25.4
136.6
30.2
8.8
1.7
40.7
3.0
17.0
19.9
18.2
78.8
18.5
16.8
0.1
35.0
3.8
0. 1
13.0
16.9
10.2
0.5 Ibs.
63.5
14.8
3.0
81.5
10.0
0.2
19.7
29.9
25.4
136.8
30.2
8.8
1.7
40.7
3.0
17.0
20.0
18.2
78.9
18.5
16.8
0.3
35.6
3.8
0. 1
13.0
16.9
10.2
Average Capacity Factor
1.2 Ibs.
.586
.570
.607
.584
.231
.641
.519
.598
.677
.401
.605
. 193
.605
.504
.546
.604
.356
.561
.121
.544
90%
.590
.571
.646
.589
.234
.641
.520
.585
.677
.685
.609
.198
.605
.504
.557
.571
-
.564
.131
.554
80%
.589
.571
.646
.587
.233
.641
.520
.585
.677
.685
.609
. 197
.605
.504
.557
.571
.357
.563
.135
.554
0.5 Ibs.
.589
.571
.646
.587
.234
.641
.520
.585
.677
.685
.609
.198
.605
.504
.561
.571
.360
.564
.135
.554
Total
62.8
62.5
62.5
62.8
.447
.446
.446
.447
-------
EXHIBIT D-37 (Cont'd)
1985 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASES I & II
Generation Capacity (in GW)
West South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Mountain
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Pacific
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
1.2 Ibs.
2.3
22.3
12.5
37.2
57.2
1.4
3.0
61.7
10.4
109.3
11.9
9.1
2.1
23.1
4.4
0.5
2.8
7.8
9.4
40.0
1.3
0.5
—
1.8
21.6
8.7
12.1
42.4
53.7
90%
2.3
22.3
12.5
37.1
57.2
1.4
3.1
61.7
10.4
109.3
11.9
9.1
2.8
23.8
4.1
0.5
2.8
7.4
9.4
40.7
1.3
0.5
—
1.8
21.6
7.9
12.1
41.6
53.7
80%
2.3
22.3
12.5
37.2
57.2
1.4
3.1
61.7
10.4
109.3
11.9
8.9
2.1
22.9
4.2
0.5
2.8
7.6
9.4
40.0
1.3
0.5
—
1.8
21.6
8.5
12.1
42.2
53.7
0.5 Ibs.
2.3
22.3
10.4
35.0
57.2
1.4
3.1
61.7
10.9
109.1
11.9
9.1
2.1
23.1
4.1
0.5
2.8
7.4
9.4
40.0
1.3
0.5
—
1.8
21.6
8.5
12.1
42.2
53.7
Average Capacity Factor
1.2 Ibs.
.641
.650
.650
.649
.262
.542
.420
.648
.668
.699
.661
.163
.458
.520
.700
.700
~
.700
.412
.528
90%
.641
.650
.650
.649
.262
.542
.420
.648
.668
.687
.660
.168
.458
.523
.700
.700
~
.700
.408
.528
80%
.641
.650
.650
.649
.262
.542
.420
.654
.667
.699
.663
.168
.458
.520
.700
.700
~*
.700
.412
.528
0.5 Ibs.
.641
.650
.650
.649
.262
.558
.420
.64fi
.668
.699
.661
.163
.458
.520
.700
.700
.700
.412
.528
Total
97.8
97.1
97.8
97.8
.481
.480
.481
.481
-------
EXHIBIT D-37 (Cont'd)
1985 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASES I & II
National
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
204.6
84.2
31.6
320.4
145.9
12.3
117.2
274.8
196.5
204.6
85.0
24.4
314.0
145.4
11.5
123.3
279.8
197.5
204.6
84.8
24.4
313.8
145.4
12.2
122.5
280.0
197.5
204.6
85.0
21.7
311.3
145.4
12.2
123.1
280.8
199.3
Total
Generation Capacity (in GW) Average Capacity Factor
1.2 Ibs. 90% 80% 0.5 Ibs. 1.2 Ibs. 90% 80% 0.5 Ibs.
.603 .599 .599 .601
.634 .627 .625 .625
.570 .658 .657 .655
.608 .611 .610 .611
.277 .279 .280 .280
.560 .561 .561 .562
791.7 791.3 791.3 791.3 .481 .481 .481 .481
-------
EXHIBIT D-38
1990 ELECTRIC GENERATIHG CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE I
Generation Capacity (in GW)
1.2 Ibs.
90%
80%
0.5 Ibs.
Average Capacity Factor
1.2 Ibs.
90%
80%
0.5 Ibs.
Mew England
Coal
Existing 4.0 4.0 4.0 4.0
NSPS - -
ANSPS 2.4 2.5 2.5 2.5
Total 6.4 6.5 6.5 6.5
Oil and Gas
Steam 7.6 7.6 7.6 7.6
Combined Cycle 0.4 0.4 0.4 0.4
Turbines and Internal Combustion 8.0 8^2 8.2 8.2
Total 16.0 16.2 16.2 16.2
Nuclear, Hydro and Other 12.6 12.4 12.4 12.4
Total 35.1 35.2 35.2 35.2
.632
.686
.652
.257
.662
.476
.629
.694
.654
.255
.671
.476
.629
.694
.654
.255
.671
.476
.629
.694
.654
.255
.671
.476
Kiddle Atlantic
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
25.7
3.8
14.2
43.6
15.5
0.4
18.2
34.2
32.9
25.7
3.8
6.5
35.9
15.5
0.4
21.9
37.8
32.5
25.7
3.8
6.1
35.6
15.5
0.4
21.5
37.5
32.9
25.7
3.8
6.7
36.1
15.5
0.4
22.1
38.1
32.3
110.7
106.3
106.0
106.4
.537
.544
.666
.579
.201
.641
.481
.579
.691
.546
.585
.210
.648
.472
.579
.643
.586
.587
.211
.641
.471
.579
.691
.569
.589
.209
.652
.472
South Atlantic
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
47.1
8.8
19.4
75.3
19.9
0.6
24.0
44.6
44.5
47.1
8.8
19.4
75.3
19.9
0.6
28.2
48.7
44.5
47.1
8.8
20.0
75.8
19.9
0.6
28.2
48.7
44.5
47.1
8.8
19. 1
75.0
19.9
0.6
28.2
48.7
44.5
.611
.614
.518
.587
.222
.562
.605
.609
.621
.609
.232
.562
.605
.609
.620
.609
.232
.562
.605
.609
.618
.609
.232
.562
Total
164.4
168.5
169.0
168.2
.483
.488
.488
.488
-------
EXHIBIT D-38 (Conf d)
1990 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE I
East North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
East South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
West North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Generation Capacity (in GW)
1.2 Ibs.
63.5
15.2
18.0
96.8
10.0
0.2
17.2
27.4
38.1
162.3
29.3
8.8
10.3
48.5
3.0
13.3
16.6
30.0
95.0
18.5
16.8
8.0
43.3
4.0
0.1
15.7
17.0
12.4
90%
63.5
17.2
9.8
90.6
10.1
0.2
23.3
33.6
38.1
162.2
29.3
8.8
8.9
17.0
3.0
15.3
18.2
30.0
95.2
18.5
16.8
6.0
41.3
4.0
0. 1
17.4
21.3
12.4
80%
63.5
17.2
13.7
94.4
10.0
0.2
19.3
29.6
38.1
162.1
29.3
8.8
10.2
48.3
3.0
13.9
16.9
30.0
95.2
18.5
16.8
7.0
42.3
4.0
0.1
16.4
20.3
12.4
0.5 Ibs.
63.5
17.2
9.6
90.3
to.o
0.2
23.6
33.8
38.1
162.2
29.3
8.8
8.9
47.1
3.0
15.3
18.2
30.0
95.3
18.5
16.8
6.1
41.5
4.0
0.1
17.5
21.3
12.4
Average Capacity Factor
1.2 Ibs.
.559
.572
.560
.561
.190
.661
.520
.535
.677
.502
.554
.136
.626
.504
.544
.631
.424
.556
.120
.571
90%
.572
.583
.579
.574
.220
.661
.521
.559
.677
.476
.565
.146
.626
.504
.555
.610
.458
.563
.139
.571
80%
.568
.582
.533
.565
.199
.661
.521
.551
.677
.471
.557
.138
.626
.504
.533
.603
.524
.559
.129
.571
0.5 Ibs.
.575
.582
.565
.575
.221
.661
.521
.559
.677
.476
.565
.146
.626
.504
.565
.604
.456
.565
.140
.571
Total
75.3
75.0
75.0
75.3
.445
.444
.445
.445
-------
EXHIBIT D-38 (Cont'd)
1990 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE I
Generation Capacity ( in GW)
West South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Mountain
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Nuclear, Hydro and Other
Total
Pacific
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
1 . 2 Ibs .
2.3
22.3
26.3
51.0
57.2
1.4
4.8
63.4
15.6
130.0
11.9
9.9
4.0
25.8
4.3
0.5
3.9
8.7
13.6
48.1
1.3
0.5
3.3
5.2
21.6
8.5
13.0
43.1
63.0
90%
2.3
22.3
26.0
50.6
57.2
1.4
5.1
63.7
15.6
130.0
11.9
10.1
4.5
26.5
4.3
0.5
3.9
8.7
13.6
48.8
1.3
0.5
3.3
5.2
21.6
7.9
13.0
42.5
63.0
80%
2.3
22.3
26.0
50.7
57.2
1.4
5.1
63.7
15.6
130.0
11.9
9.7
4.0
25.7
4.3
0.5
4.1
8.9
13.6
48.1
1.3
0.5
3.3
5.1
21.6
8.5
13.0
43.1
63.0
0.5 Ibs.
2.3
22.3
25.8
50.4
57.2
1.4
5.1
63.7
15.6
129.7
11.9
10.1
3.8
25.8
4.3
0.5
3.9
8.7
13.6
48.1
1.3
0.5
3.5
5.3
21.6
8.5
13.0
43.0
63.0
Average Capacity Factor
1.2 Ibs .
.641
.650
.650
.649
.198
.578
.421
.638
.665
.683
.655
.158
.508
.523
.537
.700
.700
.659
.361
.553
90%
.641
.650
.650
.649
.200
.578
.420
.638
.659
.692
.655
.158
.508
.525
.537
.700
.700
.659
.356
.553
80%
.641
.650
.650
.649
.200
.578
.421
.638
.670
.682
.657
.163
.508
.523
.537
.700
.700
.659
.361
.553
0.5 Ibs.
.641
.650
.650
.649
.200
.578
.420
.637
.659
.699
.655
.158
.508
.523
.537
.700
.700
.659
.360
.553
Total
111.3
110.7
111.3
111.3
.483
.482
.483
.483
-------
EXHIBIT D-38 (Cont'd)
1990 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE I
Generation Capacity (in GW) Average Capacity Factor
1.2 Ibs. 90% 80% 0.5 Ibs. 1.2 Ibs. 90% 80% 0.5 Ibs.
National
Coal
Existing 203.7 203.7 203.7 203.7 .571 .583 .578 .585
NSPS 86.2 88.4 88.0 88.4 .628 .631 .629 .630
ANSPS 106.0 86.9 92.8 85.9 .585 .603 .597 .601
Total 395.9 379.0 384.5 378.1 .588 .599 .594 .599
Oil and Gas
Steam 143.0 143.0 143.0 143.0
Combined Cycle 12.2 11.5 12.1 12.2
Turbines and Internal Combustion 118.6 136.3 129.9 136.9
Total 273.7 290.8 285.0 292.0 .220 .226 .224 .227
Nuclear, Hydro and Other 262.6 262.0 262.4 261.8 .595 .596 .595 .596
Total 932.2 931.9 931.9 931.9 .481 .481 .482 .482
-------
EXHIBIT D-39
1990 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
New England
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
REFERENCE CASE II
Generation Capacity (in GW)
Average Capacity Factor
1.2 Ibs.
4.0
5.0
9.1
7.6
0.4
8.1
16.0
13.4
38.5
90%
80%
4.0
5.0
9.1
7.6
0.4
8.9
16.8
12.6
38.6
0.5 Ibs.
1.2 Ibs.
90%
80%
0.5 Ibs.
4.0
5.0
9.1
7.6
0.4
8.9
16.8
12.6
38.6
4.0
5.0
9.1
7.6
0.4
8.9
16.8
12.6
38.6
.587
.672
.634
.262
.625
.476
.575
.683
.629
.251
.663
.566
.690
.635
.251
.663
.477 .477
.566
.690
.635
.251
.663
.477
Middle Atlantic
Coal
Existing 25.7
NSPS 3.8
ANSPS 24.0
Total 53.5
Oil and Gas
Steam 15.5
Combined Cycle 0.4
Turbines and Internal Combustion 20.7
Total 36.7
Nuclear, Hydro and Other 33.4
Total 123.5
25.7
3.8
12.7
42.2
15.5
0.4
23.9
39.9
33.0
25.7
3.8
12.4
41.8
15.5
0.4
23.6
39.5
33.4
25.7
3.8
12.9
43.4
15.5
0.4
24.2
40.1
32.8
115.1
114.7
115.3
.531
.613
.651
.591
.201
.633
.487
.569
.691
.596
.588
.208
.640
.471
.569
.643
.608
.587
.210
.633
.470
.569
.691
.597
.574
.208
.644
.471
South Atlantic
Coal
Existing 47.1
NSPS 8.8
ANSPS 34.6
Total 90.5
Oil and Gas
Steam 20.5
Combined Cycle 0.6
Turbines and Internal Combustion 28.7
Total 49.9
Nuclear, Hydro and Other 44.5
47.1
8.8
39.8
95.7
20.5
0.6
34.4
55.5
44.5
47.1
8.8
37.7
93.6
20.5
0.6
34.4
55.5
44.5
47.1
8.8
36.9
92.8
20.5
0.6
34.4
55.5
44.5
.631
.647
.505
.584
.213
.562
.645
.647
.546
.604
.227
.562
.647
.647
.547
.607
.227
.562
.647
.647
.545
.606
.227
.562
Total
184.9
193.2
193.7
192.9
.479
.487
.487
.487
-------
EXHIBIT D-39 (Cont'd)
1990 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE II
East North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
East South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
West North Central
Coal
Exis _ing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Generation Capacity
1.2 Ibs.
63.5
17.2
30.9
111.7
10.0
0.2
20.3
30.6
30.1
180.3
30.2
8.8
18.4
57.5
3.0
15.8
18.8
30.1
106.3
18.5
16.8
13.1
48.4
3.8
0. 1
17.7
21.6
12.4
90% 80%
63.5
17.2
22.9
103.6
10.0
0.2
28.4
38.7
38.1
180.4
30.2
8.8
16.4
55.4
3.0
18.1
20.0
30.7
106.5
18.5
16.8
11.2
46.5
3.8
0.1
19.4
23.3
12.4
(in GW)
0.5
63.5
17.2
23.0
103.8
10.0
0.2
28.2
38.4
38.1
180.2
30.2
8.8
16.3
55.4
3.0
18.1
21.0
30.1
106.5
18.5
16.8
11.5
46.9
3.8
0.1
19.4
23.0
12.4
Ibs. 1.2
63.5
17.2
22.9
103.6
10.0
0.2
28.4
38.7
38.1
180.4
30.2
8.8
16.8
55.9
3.0
17.7
20.6
30.1
106.5
18.5
16.8
11.2
46.6
3.8
0. 1
19.7
23.5
12.4
Average
Capacity
Ibs. 90% 80%
.559
.551
.581
.563
.187
.661
.521
.544
.665
.542
.562
.137
.624
.504
.552
.647
.450
.557
.119
.571
.585
.623
.531
.579
.226
.661
.521
.591
.677
.489
.535
.149
.624
.505
.572
.623
.462
.564
.136
.571
Factor
0.5
.592
.623
.512
.579
.224
.661
.521
.591
.677
.488
.574
.149
.624
.504
.547
.623
.501
.563
.133
.571
Ibs.
.592
.621
.515
.580
.226
.661
.521
.589
.677
.487
.572
.147
.624
.505
.575
.623
.462
.565
.138
.571
Total
82.5
82.2
82.2
82.5
.445
.444
.444
.444
-------
EXHIBIT D-39 (Cont'd)
1990 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE II
West South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Mountain
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Pacific
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Generation Capacity
1.2 Ibs.
3.0
22.3
32.8
57.4
57.3
1.4
11.4
70.0
15.6
143.0
11.9
10.3
5.4
27.6
4.3
0.5
4.7
9.5
13.9
50.9
1.3
0.5
7.6
9.4
21.6
12.3
15.0
48.9
63.0
90% 80%
3.0
22.3
32.4
57.1
57.3
1.4
11.7
70.3
15.6
143.0
11.9
10.6
5.5
28.0
4.3
0.5
4.9
9.7
13.9
51.6
1.3
0.5
7.6
9.4
21.6
11.7
15.0
48.3
63.0
(in GW)
0.5
3.0
22.3
32.5
57.1
57.3
1.4
11.7
70.3
15.6
143.0
11.9
10.2
5.1
27.2
4.3
0.5
5.0
9.8
13.9
50.9
1.3
0.5
7.6
9.4
21.7
12.3
15.0
49.0
63.0
Ibs. 1.2
3.0
22.3
32.2
56.9
57.3
1.4
11.7
70.3
15.6
142.7
11.9
10.6
4.8
27.3
4.3
0.5
4.9
9.7
13.9
50.9
1.3
0.5
8.1
9.9
21.6
12.3
14.5
48.4
63.0
Average
Capacity
Ibs. 90% 80%
.641
.650
.650
.650
.198
.578
.421
.633
.660
.680
.652
.155
.504
.520
.696
.700
.700
.699
.363
.553
.641
.650
.650
.650
.200
.578
.421
.633
.658
.693
.654
.160
.504
.521
.700
.700
.700
.700
.359
.553
Factor
0.5
.641
.650
.650
.650
.200
.578
.421
.633
.671
.679
.656
.164
.504
.520
.700
.700
.700
.700
.363
.553
Ibs.
.641
.650
.650
.650
.200
.578
.420
.633
.658
.699
.654
.160
.504
.520
.700
.700
.700
.700
.360
.553
Total
121.3
120.7
121.3
121.3
.488
.487
.488
.488
-------
EXHIBIT D-39 (Cont'd)
1990 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE II
Generation Capacity (in GW)
National
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
1.2 Ibs.
204.6
38.5
171.9
465.0
143.5
15.9
142.5
301.9
264.4
90%
204.6
88.9
151.1
444.6
143.5
15.9
164.7
323.5
263.2
80% 0.5
204.6
88.4
151.2
444.3
143.6
15.9
163.9
323.3
263.5
Ibs. 1.2
204.6
88.9
150.9
444.4
143.5
15.9
164.3
323.7
262.9
Average Capacity
Ibs. 90%
.577
.631
.586
.591
.219
.592
80%
.600
.645
.576
.601
.226
.594
Factor
0.5
.600
.644
.576
.601
.227
.593
Ibs.
.603
.645
.573
.601
.226
.595
Total 1,030.9 1,031.2 1,031.1 1,031.0 .482 .482 .482 .482
-------
EXHIBIT D-40
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOORCE PERFORMANCE STANDARDS
REFERENCE CASE I
Generation Capacity (in GW)
1.2 Ibs.
90*
80%
0.5 Ibs.
Average Capacity Factor
1.2 Ibs.
90%
80%
0.5 Ibs.
New England
Coal
Existing 3.9
NSPS
ANSPS 2.4
Total 6.4
Oil and Gas
Steam 7.6
Combined Cycle 0.4
Turbines and Internal Combustion 8.1
Total 16.1
Nuclear, Hydro and Other 18.6
Total 41.1
Middle Atlantic
Coal
Existing 25.7
NSPS 3.8
ANSPS 14.2
Total 43.6
Oil and Gas
Steam 15.5
Combined Cycle 0.4
Turbines and Internal Combustion 17.8
Total 33.7
Nuclear, Hydro and Other 47.1
Total 124.5
4.0
2.6
41.2
4.0
2.6
41.2
4.0
2.6
6.6
7.6
0.4
8.2
16.1
18.5
6.6
7.6
0.4
8.2
16.1
18.5
6.6
7.6
0.4
8.2
16.1
18.5
41.2
25.7
3.8
6.5
35.9
15.5
0.4
22.4
38.3
45.8
25.7
3.8
6.1
35.6
15.5
0.4
21.1
37.0
47.1
25.7
3.8
6.7
36.1
15.5
0.4
22.2
38.1
46.0
120.0
119.7
120.2
.532
.629
.569
.264
.627
.476
.521
.556
.565
.538
.190
.632
.479
.507
.679
.574
.264
.629
.477
.534
.691
.513
.547
.203
.636
.471
.507
.679
.574
.264
.629
.477
.522
.543
.533
.536
.201
.632
.470
.524
.654
.574
.264
.629
.477
.530
.691
.518
.545
.201
.639
.471
South Atlantic
Coal
Existing 47.1 47.1 47.1 47.1 .547 .580 .579 .580
NSPS 8.8 8.8 8.8 8.8 .586 .541 .541 .541
ANSPS 19.7 19.4 19.9 19.1 .408 .465 .469 .463
Total 75.7 75.3 75.8 75.0 .515 .546 .546 .546
Oil and Gas
Steam 15.5 16.7 16.7 16.7
Combined Cycle 0.6 0.6 0.6 0.6
Turbines and Internal Combustion 24.7 30.8 30.7 30.8
Total 40.8 48.2 48.7 48.2 .173 .199 .199 .199
Nuclear, Hydro and Other 80.4 77.6 77.7 77.6 .611 .609 .609 .609
Total
196.9
201.1
201.6
200.8
.483
.487
.487
.487
-------
EXHIBIT D-40 (Cont'd)
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE I
East North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
East South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
West North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Generation Capacity
1.2 Ibs.
63.5
15.2
23.4
102.1
8.0
0.2
20.9
29.1
61.0
192.2
30.2
8.S
10.3
49.4
2.5
15.3
17.8
47.5
114.7
18.5
16.8
17.7
53.1
3.8
0.1
20.0
23.9
13.4
90% 80%
63.5
17.2
9.8
90.5
10.0
0.2
26.9
37.1
64.5
192.2
30.2
8.8
9.1
48.1
3.0
17.3
20.3
46.5
114.9
18.5
16.8
14.3
49.6
3.8
0.1
22. 1
26.0
14.5
(in GW)
0.5
63.5
17.2
13.7
94.4
10.0
0.2
24.3
34.5
62.1
192.0
30.2
8.8
10.1
49.2
2.5
17.3
19.8
45.8
114.8
18.5
16.8
15.6
50.9
3.8
0.1
20.8
24.7
14.5
Ibs. 1.2
63.5
17.2
9.6
90.3
10.0
0.2
27.6
37.9
64.0
192.2
30.2
8.8
9.1
48.1
3.0
17.3
20.3
46.5
114.9
18.5
16.8
12.8
48.1
3.8
0. 1
22.0
25.9
16.4
Average
Capacity
Ibs. 90% 80%
.531
.503
.545
.530
.168
.674
.521
.515
.549
.448
.507
.116
.644
.504
.555
.647
.473
.557
.119
.577
.550
.551
.497
.544
.206
.672
.522
.519
.651
.428
.526
.135
.641
.504
.574
.623
.477
.563
.138
.583
Factor
0.5
.554
.555
.467
.541
.194
.672
.522
.529
.646
.411
.526
.131
.642
.504
.543
.623
.505
.558
.126
.583
Ibs.
.552
.551
.500
.546
.209
.671
.522
.515
.665
.428
.526
.135
.641
.504
.572
.623
.456
.559
.137
.591
Total
90.4
90.1
90.1
90.4
.444
.443
.443
.444
-------
EXHIBIT D-40 (Cont'd)
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
West South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Mountain
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Pacific
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
REFERENCE CASE I
Generation Capacity
1.2 Ibs.
2.3
22.3
30.7
55.3
57.3
1.4
17.2
75.8
23.3
154.5
11.9
11.3
4.0
27.2
4.3
0.5
5.3
10.1
17.7
55. 1
1.3
0.5
7.9
9.7
7.1
8.5
14.9
30.5
82.0
90% 80%
2.3
22.3
29.6
54.3
57.3
1.4
17.2
75.8
24.3
154.4
11.9
11.3
6.8
30.0
4.3
0.5
6.1
10.9
14.9
55.7
1.3
0.5
3.4
5.2
16.4
7.9
15.1
39.4
84.1
(in GW)
0.5
2.3
22.3
30.7
55.4
60.3
1.4
17.2
78.8
23.3
154.5
11.9
10.7
6.4
29.0
4.3
0.5
6.4
11.2
14.8
55.0
1.3
0.5
3.4
5.2
14.2
8.5
15.1
37.8
86.3
Ibs . 1.2
2.3
22.3
26.7
51.3
57.3
1.4
17.2
75.8
27.1
154.2
11.9
11.0
6.2
29.1
4.3
0.5
6. 1
10.9
15.1
55.1
1.3
0.5
3.5
5.3
20.9
8.5
15.1
44.6
79.4
Average
Capacity
Ibs. 90* 80%
.641
.650
.650
.650
.198
.602
.421
.628
.657
.655
.644
.151
.541
.520
.693
.700
.690
.691
.224
.587
.641
.650
.650
.650
.198
.604
.421
.647
.651
.672
.654
.164
.516
.522
.700
.700
.700
.700
.244
.590
Factor
0.5
.641
.650
.650
.650
.198
.602
.421
.648
.659
.670
.657
.170
.516
.520
.700
.700
.700
.700
.225
.593
Ibs.
.641
.650
.650
.650
.198
.609
.420
.648
.646
.681
.654
.165
.519
.520
.700
.700
.700
.700
.297
.583
129.3
128.7
129.3
129.3
.489
.488
.489
.489
-------
EXHIBIT D-40 (Cont'd)
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE I
National
Generation Capacity (in GW) Average Capacity Factor
1.2 Ibs. 90% 80* 0.5 Ibs. 1.2 Ibs. 90% 80% 0.5 Ibs.
.542 .559 .557 .559
.604 .617 .616 .618
.547 .551 .547 .546
.556 .570 .567 .569
.184 .199 .194 .207
.618 .618 .618 .618
Total 1,091.5 1,098.3 1,101.2 1,098.2 .482 .482 .482 .482
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combir.ed Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
204.5
87.6
130.4
422.5
121.5
12.1
144.2
277.8
391.2
204.6
89.6
101.4
395.6
134.5
11.5
166.0
321.0
390.7
204.6
89.0
108.5
402.1
134.9
12.1
161.0
308.6
391.1
204.6
89.2
96.3
390.1
139.1
12.1
166.5
317.8
390.3
NOTE:
The nuclear capacity was locked in by region in 1985 and 1990 based upon a study by the NRC, PEA and white
House Energy Staff. However, no such estimates were able for 1995. Rather than assign nuclear capacity
arbitrarily to specific regions we chose to set a national build limit for nuclear capacity and let the
model allocate it between regions. The capacity built through 1990 was locked in and only the 125 GW of
incremental capacity from 1990 to 1995 was "sited" where the model achieved the greatest reduction in
cost. The imposition of BACT requirements increases the cost of coal-fired generation disproportionately
among regions. Thus, the global objective function value can be reduced by shifting nuclear capacity out
of regions where the incremental cost of BACT is small to regions where the incremental cost is large.
This leads to the lower nuclear capacity under BACT in some regions and higher nuclear capacity in other
regions.
We also should point out that the national limit on nuclear capacity was held constant between the low and
the high growth cases and this limit was always binding. This led to changes in regional nuclear capaci-
ties between the base cases. In the high electricity growth cases nuclear capacity tended to increase
where coal was most expensive (e.g., the Atlantic and Pacific Cases) and to decline where coal was the
least expensive (e.g.. Midwest).
We do not believe that the model currently has the structure to make coal/nuclear tradeoff decisions well
since the distributions of potential costs for the two forms of generation overlap and the model's treat-
ment of baseload generation is not adequately detailed. However, we felt that assigning capacity to
specific regions in 1995 and locking it in would be no more precise or reliable. We feel that the national
limit was a reasonable assessment of what capacity can be built by 1995 and the model simply showed which
regions have the strongest economic incentive to build that capacity.
-------
EXHIBIT D-41
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE II
Generation Capacity (in GW)
1.2 Ibs.
90%
80%
Average Capacity Factor
0.5 Ibs. 1.2 Ibs.
90%
80%
0.5 Ibs.
New England
Coal
Existing 4-0
NSPS
ANSPS 5.5
Total 9.5
Oil and Gas
Steam 7.6
Combined Cycle 0.4
Turbines and Internal Combustion 9.7
Total 17.7
Nuclear, Hydro and Other 22.1
Total 49.3
4.0
5.5
9.6
7.6
0.4
9.8
17.8
22.1
4.0
5.5
9.6
7.6
0.4
9.8
17.8
22.1
4.0
5.5
9.6
7.6
0.4
9.9
17.9
22.1
49.4
49.4
49.4
.426
.611
.532
.254
.631
.477
.616
.484
.540
.254
.631
.477
.395
.644
.539
.254
.631
.477
.610
.488
.539
.254
.631
.477
Middle Atlantic
Coal
Existing 25.7
NSPS 3.8
ANSPS 2B.4
Total 57.9
Oil and Gas
Steam 15.5
Combined Cycle 0.4
Turbines and Internal Combustion 27.5
Total «.5
Nuclear, Hydro and Other 47.4
Total 148.8
25.7
3.8
17.1
46.5
15.5
0.4
28.8
44.8
48.9
25.7
3.8
16.9
46.3
15.5
0.4
28.1
44.1
49.7
25.7
3.8
17.3
46.7
15.5
0.4
29.1
45.0
48.7
140.2
140.0
140.4
.521
.494
.649
.582
.203
.619
.483
.520
.691
.581
.556
.200
.634
.470
.520
.643
.590
.555
.202
.625
.469
.521
.691
.582
.557
.199
.637
.470
South Atlantic
Coal
Existing 47.1
NSPS 8.8
ANSPS 4'-0
Total 96-9
Oil and Gas
Steam 17.2
Combined Cycle 0.6
Turbines and Internal Combustion 43.4
Total 61.2
Nuclear, Hydro and Other 98.2
47.1
8.8
39.9
95.7
22.6
0.6
49.4
72.7
96.3
47.1
8.8
40.3
96.2
22.1
0.6
49.4
72.2
96.7
47.1
8.8
39.5
95.4
22.6
0.6
49.4
72.7
96.2
.595
.586
.437
.527
.180
.619
.611
.638
.488
.562
.212
.615
.612
.638
.490
.563
.208
.616
.612
.638
.487
.563
.212
.615
Total
256.4
264.7
265.1
264.3
.480
.485
.486
.485
-------
EXHIBIT D-41 (Cont'd)
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
East North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
East South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
West North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
REFERENCE CASE II
Generation Capacity (in GW)
1.2 Ibs.
63.5
17.2
68.8
149.6
10.0
0.2
29.3
39.6
47.6
236.7
30.2
8.8
26.1
65.2
3.0
25.4
28.4
52.3
143.6
18.5
16.8
31.5
67.8
3.8
0.1
25.2
29.1
12.4
90%
63.5
17.2
48.4
129.2
10.0
0.2
38.3
48.6
52.6
230.4
30.2
8.8
26.2
65.3
3.0
25.1
28.0
50.6
143.9
18.5
16.8
34.6
70.0
3.8
0.1
28.5
32.4
12.4
80% 0.5
63.5
17.2
46.1
126.8
10.0
0.2
39.2
49.4
52.1
227.5
30.2
8.8
26.1
65.2
3.0
25.0
27.9
50.6
143.7
18.5
16.8
39.7
75.0
3.8
0.1
26.3
30.2
12.4
Ibs. 1.2
63.5
17.2
54.4
135.2
10.0
0.2
38.3
48.6
53.0
236.8
30.2
8.8
26.0
65.1
3.0
25.1
28.1
50.7
143.8
18.5
16.8
27.7
63.0
3.8
0.1
29.1
33.0
12.4
Average Capacity
Ibs. 90%
.545
.514
.599
.566
.178
.669
.522
.529
.631
.516
.538
.136
.647
.505
.577
.650
.502
.552
.118
.571
80%
.592
.673
.503
.569
.216
.672
.518
.624
.677
.418
.548
.145
.647
.505
.588
.626
.549
.578
.142
.571
Factor
0.5
.589
.672
.500
.570
.216
.671
.517
.594
.677
.453
.549
.144
.647
.505
.569
.626
.554
.574
.127
.571
Ibs.
.592
.673
.519
.573
.216
.672
.522
.595
.677
.452
.549
.145
.647
.505
.605
.636
.513
.673
.146
.571
108.3
114.8
117.6
108.4
.443
.454
.459
.443
-------
EXHIBIT D-41 (Cont'd)
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
West South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Mountain
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
Pacific
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines and Internal Combustion
Total
Nuclear, Hydro and Other
Total
REFERENCE CASE II
Generation Capacity (in GW)
1.2 Ibs.
2.3
22.3
54.7
79.4
57.3
1.4
33.2
91.9
15.6
186.8
11.9
11.7
10.3
33.8
4.3
0.5
9.0
13.8
15.2
62.8
1.3
0.5
16.3
18.1
21.6
12.3
18.8
52.6
81.6
90%
2.3
22.3
54.3
79.0
57.3
1.4
33.6
92.2
15.6
186.7
11.9
12.0
12.2
36.1
4.3
0.5
8.7
13.4
13.9
63.5
1.3
0.5
16.3
18. 1
21.6
11.6
21.5
54.8
78.9
80% 0.5
2.3
22.3
54.4
79.0
57.3
1.4
33.6
92.2
15.6
186.8
11.9
11.7
11.0
34.5
4.3
0.5
9.6
14.4
13.9
62.8
1.3
0.5
16.3
18.1
21.6
12.3
21.5
55.4
78.9
Ibs. 1.2
2.3
22.3
54.1
78.8
57.3
1.4
33.6
92.2
15.6
186.5
11.9
12.0
11.1
35.0
4.3
0.5
9.0
13.8
13.9
62.8
1.3
0.5
16.8
18.6
21.6
12.3
21.5
55.4
78.4
Average Capacity
Ibs. 90%
.641
.650
.648
.648
.198
.578
.421
.658
.660
.649
.657
.175
.516
.516
.692
.700
.674
.676
.293
.586
80%
.641
.650
.650
.650
.198
.578
.421
.647
.654
.655
.652
.170
.504
.517
.700
.700
.700
.700
.301
.583
Factor
0.5
.641
.650
.650
.650
.198
.578
.421
.660
.672
.649
.661
.183
.504
.516
.700
.700
.700
.700
.305
.583
Ibs.
.641
.650
.650
.650
.198
.578
.421
.658
.648
.661
.655
.175
.504
.516
.700
.700
.700
.700
.305
.582
152.4
151.8
152.4
152.8
.496
.495
.496
.496
-------
EXHIBIT D-41 (Cont'd)
1995 ELECTRIC GENERATING CAPACITY UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
REFERENCE CASE II
Generation Capacity (in GW) Average Capacity Factor
1.2 Ibs. 90% 80% 0.5 Ibs. 1.2 Ibs. 90% 80% 0.5 Ibs.
National
Coal
Existing 204.6 204.6 204.6 204.6 .561 .597 .587 .595
jjSPS 89.9 90.3 89.9 90.3 .611 .654 .654 .655
ANSPS 282.6 254.6 256.1 252.5 .578 .554 .562 .556
Total 577.1 549.5 550.7 547.4 .577 .586 .586 .587
Oil and Gas
Steam 140.3 145.6 145.1 145.6
Combined Cycle 15.9 15.3 15.9 15.9
Turbines and Internal Combustion 221.6 243.7 242.5 245.1
Total 377.8 404.6 403.6 406.6 .198 .210 .210 .210
Nuclear, Hydro and Other 392.5 391.2 392.0 391.0 .616 .617 .616 .617
Total 1,347.5 1,345.3 1,346.3 1,345.0 .482 .482 .482 .482
NOTE:
The nuclear capacity was locked in by region in 1985 and 1990 based upon a study by the NRC, FEA and White
House Energy Staff. However, no such estimates were able for 1995. Rather than assign nuclear capacity
arbitrarily to specific regions we chose to set a national build limit for nuclear capacity and let the
model allocate it between regions. The capacity built through 1990 was locked in and only the 125 GW of
incremental capacity from 1990 to 1995 was "sited" where the model achieved the greatest reduction in
cost. The imposition of BACT requirements increases the cost of coal-fixed generation disproportionately
among regions. Thus, the global objective function value can be reduced by shifting nuclear capacity out
of regions where the incremental cost of BACT is small to regions where the incremental cost is large.
This leads to the lower nuclear capacity under BACT in some regions and higher nuclear capacity in other
regions•
We also should point out that the national limit on nuclear capacity was held constant between the low and
the high growth cases and this limit was always binding. This led to changes in regional nuclear capaci-
ties between the base cases. In the high electricity growth cases nuclear capacity tended to increase
where coal was most expensive (e.g., the Atlantic and Pacific Cases) and to decline where coal was the
least expensive (e.g.. Midwest).
We do not believe that the model currently has the structure to make coal/nuclear tradeoff decisions well
since the distributions of potential costs for the two forms of generation overlap and the model's treat-
ment of baseload generation is not adequately detailed. However, we felt that assigning capacity to
specific regions in 1995 and locking it in would be no more precise or reliable. We feel that the national
limit was a reasonable assessment of what capacity can be built by 1995 and the model simply showed which
regions have the strongest economic incentive to build that capacity.
-------
Exhibit D-42
1985 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
Reference Cases I & II
New England
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Middle Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
1.7
1.7
95.6
95.6
80.0
80.0
76.5
76.5
15.8
11.9
3.1
0.8
87.9
85.5
95.0
95.0
80.0
80.0
80.0
80.0
70.3
68.4
76.0
76.0
90%
1.7
1.7
87.2
87.2
80.0
80.0
69.8
69.8
17.2
11.9
2.9
2.4
89.2
85.6
95.0
100.0
81.4
80.0
80.0
80.0
72.8
68.5
76.0
90.0
80%
1.7
1.7
87.2
87.2
80.0
80.0
69.8
69.8
17.2
11.9
2.9
2.4
89.0
85.3
95.0
100.0
80.0
80.0
80.0
80.0
71.2
68.2
76.0
80.0
0.5 Ibs.
1.7
1.7
87.2
87.2
80.0
80.0
69.8
69.8
17.1
11.6
3.1
2.4
89.1
85.3
95.0
100.0
81.4
80.0
80.0
80.0
72.7
68.2
76.0
90.0
ICF INCORPORATED
-------
Exhibit D-42
1985 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Cases I & II
South Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
East North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
16.1
14.4
1.5
0.2
74.8
72.3
95.0
100.0
80.0
80.0
80.0
80.0
59.8
57.8
76.0
80.0
8.5
3.2
4.3
1.0
95.7
96.8
95.0
95.0
80.0
80.0
80.0
80.0
76.5
77.4
76.0
'76.0
90%
15.3
11.7
1.6
2.0
78.8
72.9
95.0
100.0
81.3
80.0
80.0
90.0
64.3
58.3
76.0
90.0
8.9
3.2
2.6
3.1
97.4
96.8
95.0
100.0
83.5
80.0
80.0
80.0
81.4
77.4
76.0
90.0
80%
15.9
11.8
1.6
2.5
79.3
72.8
95.0
100.0
80.0
80.0
80.0
80.0
63.4
58.2
76.0
80.0
8.9
3.2
2.6
3.1
97.4
96.8
95.0
100.0
80.0
80.0
80.0
80.0
77.9
77.4
76.0
80.0
0.5 Ibs.
15.1
11.8
1.6
1.7
78.2
72.8
95.0
100.0
81.1
80.0
80.0
90.0
63.7
58.2
76.0
900
8.9
3.2
2.6
3.1
97.4
96.8
95.0
100.0
83.5
80.0
80.0
80.0
81.4
77.4
76.0
90.0
ICF
INCORPORATED
-------
Exhibit D-42
1985 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
East South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
West North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
5.9
2.9
2.8
0.2
94.9
97.2
95.0
61.3
80.0
80.0
80.0
80.0
76.0
77.8
76.0
49.0
1.4
1.2
0.2
-
99.3
100.0
95.0
-
80.0
80.0
80.0
-
79.4
80.0
76.0
_
Reference
90%
7.4
2.9
2.8
1.7
96.0
97.2
92.4
100.0
82.3
80.0
80.0
90.0
79.1
77.8
73.9
90.0
1.4
1.2
0.2
-
99.3
100.0
95.0
-
80.0
80.0
80.0
-
79.4
80.0
76.0
_
Cases I &
80%
7.4
2.9
2.8
1.7
96.0
97.2
92.4
100.0
80.0
80.0
80.0
80.0
76.9
77.8
73.9
80.0
1.5
1.2
0.2
0.1
99.3
100.0
95.0
100.0
80.0
80.0
80.0
80.0
79.5
80.0
76.0
80.0
II
0.5 Ibs.
7.4
2.9
2.8
1.7
97.0
97.2
95.0
100.0
82.3
80.0
80.0
90.0
79.9
77.8
76.0
90.0
1.7
1.2
0.2
0.3
99.4
100.0
95.0
100.0
81.8
80.0
80.0
90.0
81.3
80.0
76.0
90.0
ICF INCORPORATED
-------
Exhibit D-42
1985 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
West South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Mountain
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
12.0
1.1
6.6
4.3
80.6
80.4
80.4
84.1
80.0
80.0
80.0
80.0
64.8
64.3
64.3
67.3
12.2
1.0
9. 1
2.1
88.7
100.0
85.9
95.0
81.7
80.0
80.0
90.0
72.5
80.0
68.7
85.5
Reference
90%
18.1
1.1
4.5
12.5
93.9
80.4
80.4
100.0
86.9
80.0
80.0
90.0
82.0
64.3
64.3
90.0
12.9
1.0
9.1
2.8
89.2
100.0
85.9
95.0
82.2
80.0
80.0
90.0
73.5
80.0
68.7
86.6
Cases I
80%
18.1
1.1
4.5
12.5
93.9
80.4
80.4
100.0
80.0
80.0
80.0
80.0
75.1
64.3
64.3
80.0
12.0
1.0
8.9
2.1
88.5
100.0
85.7
95.0
81.8
80.0
80.0
90.0
72.5
80.0
68.6
85.5
& II
0.5 Ibs.
16.0
1.1
4.5
10.4
90.2
80.4
80.4
95.4
86.1
80.0
80.0
89.4
80.0
64.3
64.3
85.3
12.2
1.0
9.1
2.1
88.6
100.0
85.9
95.0
81.7
80.0
80.0
90.0
72.5
80.0
68.7
85.5
ICF
INCORPORATED
-------
Exhibit D-42
1985 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Ref prence Cases I & II
1.2 Ibs.
90%
80%
0.5 Ibs.
Pacific
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
National
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
73.3
37.2
27.5
8.6
82.6
34.5
23.7
24.4
82.6
34.7
23.5
24.4
79.9
34.4
23.9
21.7
86.0
83.5
88.5
88.7
89.6
84.1
88.4
99.6
89.8
83.9
88.3
99.6
89.0
84.0
88.4
97.3
80.3
80.0
80.0
82.5
83.0
80.0
80.0
90.0
81.3
80.0
80.0
84.3
82.7
80.0
80.0
89.7
69.0
69.0
70.8
73.2
74.9
67.3
70.7
89.6
73.1
67.1
70.6
84.0
73.8
67.2
70.7
87.3
ICF INCORPORATED
-------
Exhibit D-43
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
Reference Case I
New England
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Middle Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
3.8
2.8
1.0
95.4
95.4
95.3
80.0
80.0
80.0
76.3
76.3
76.2
15.8
11.9
3.1
0.8
89.3
87.5
95.0
95.0
80.0
80.0
80.0
80.0
71.5
70.0
76.0
76.0
90%
5.3
2.8
2.5
94.9
90.4
100.0
84.7
80.0
90.0
80.6
72.3
90.0
21.4
11.9
3.0
6.5
91.9
86.7
95.0
100.0
83.0
80.0
80.0
90.0
76.6
69.4
76.0
90.0
80%
5.3
2.8
2.5
94.9
90.4
100.0
80.0
80.0
80.0
75.9
72.3
80.0
20.9
11.9
2.9
6.1
91.7
86.6
95.0
100.0
80.0
80.0
80.0
80.0
73.4
69.3
76.0
80.0
0.5 Ibs.
5.3
2.8
2.5
94.9
90.4
100.0
84.7
80.0
90.0
80.6
72.3
90.0
21.4
11.6
3.1
6.7
89.5
86.6
95.0
99.7
83.1
80.0
80.0
90.0
84.1
69.3
76.0
89.7
ICF
INCORPORATED
-------
Exhibit D-43
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
South Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
East North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
15.6
13.8
1.6
0.2
77.0
74.6
95.0
96.3
80.0
80.0
80.0
80.0
61.6
59.7
76.0
77.0
10.4
3.2
4.3
2.9
95.6
96.8
95.0
95.0
80.0
80.0
80.0
80.0
76.4
77.4
76.0
76.0
90%
33.8
12.8
1.6
19.4
88.2
69.4
95.0
100.0
85.7
80.0
80.0
90.0
76.3
55.5
76.0
90.0
15.5
3.2
2.5
9.8
93.6
96.7
94.5
100.0
86.3
80.0
80.0
90.0
85.1
77.4
75.6
90.0
80%
34.5
13.0
1.6
19.9
88.2
69.4
95.0
100.0
85.8
80.0
80.0
90.0
76.3
55.5
76.0
90.0
19.6
3.2
2.7
13.7
98.7
96.7
94.4
100.0
80.0
80.0
80.0
80.0
79.0
77.4
75.5
80.0
0.5 Ibs.
33.4
12.7
1.6
19.1
87.0
69.5
95.0
98.4
85.7
80.0
80.0
90.0
75.4
55.6
76.0
88.6
15.4
3.2
2.6
9.6
98.4
96.8
95.0
99.9
86.2
80.0
80.0
90.0
85.0
77.4
76.0
89.9
ICF INCORPORATED
-------
Exhibit D-43
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
East South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
West North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
6.4
3.0
2.8
0.6
92.1
95.4
95.0
62.2
80.0
80.0
80.0
80.0
73.7
76.3
76.0
49.8
1.4
1.2
0.2
-
99.3
100.0
95.0
-
80.0
80.0
80.0
-
79.4
80.0
76.0
_
90%
13.8
2.9
2.0
8.9
97.2
97.2
84.7
100.0
86.4
80.0
80.0
90.0
84.2
77.8
67.8
90.0
7.4
1.2
0.2
6.0
99.9
100.0
95.0
100.0
88.1
80.0
80.0
90.0
88.0
80.0
76.0
90.0
80%
15.1
2.9
2.0
10.2
97.4
97.2
84.5
100.0
80.0
80.0
80.0
80.0
77.9
77.8
67.6
80.0
8.4
1.2
0.2
7.0
99.9
100.0
95.0
100.0
80.0
80.0
80.0
80.0
79.9
80.0
76.0
80.0
0.5 Ibs.
13.8
2.9
2.0
8.9
97.2
97.2
84.7
100.0
86.4
80.0
80.0
90.0
84.2
77.8
67.8
90.0
7.5
1.2
0.2
6.1
75.6
100.0
95.7
70.1
80.4
80.0
80.0
80.5
77.0
80.0
76.6
76.4
ICF
INCORPORATED
-------
Exhibit D-43
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
West South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Mountain
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
15.0
1.1
6.6
7.3
81.4
80.4
80.4
82.5
80.0
80.0
80.0
80.0
65.1
64.3
64.3
66.0
14.9
1.0
9.9
4.0
88.8
100.0
85. 1
95.0
82.7
80.0
80.0
90.0
73.6
80.0
68.1
85.5
90%
31.6
1.1
4.5
26.0
96.5
80.4
80.4
100.0
88.2
80.0
80.0
90.0
85.4
64.3
64.3
90.0
15.6
1.0
10.1
4.5
89.5
100.0
85.6
95.8
82.9
80.0
80.0
90.0
74.3
80.0
68.5
86.2
80%
31.6
1.1
4.5
26.0
96.5
80.4
80.4
100.0
80.0
80.0
80.0
80.0
77.2
64.3
64.3
80.0
14.7
1.0
9.7
4.0
88.8
100.0
85.1
95.0
82.7
80.0
80.0
90.0
73.6
80.0
68.1
85.5
0.5 Ibs.
31.4
1.1
4.5
25.8
90.4
80.4
80.4
92.6
80.9
80.0
80.0
86.6
77.4
64.3
64.3
80.2
14.9
1.0
10.1
3.8
89.5
100.0
86.4
95.0
82.6
80.0
80.0
90.0
74.0
80.0
69.1
85.5
ICF INCORPORATED
-------
Exhibit D-43
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
1.2 Ibs.
90%
80%
0.5 Ibs.
Pacific
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
National
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
3.4
3.4
3.4
3.4
3.4
37.9
37.9
90.0
90.0
34.1
34.1
86.6
37.9
28.4
20.3
85.0
85.3
88.2
80.0
80.8
80.0
80.0
83.6
68.7
68.2
70.6
66.9
3.4
100.0
100.0
90.0
90.0
90.0
90.0
147.6
36.8
23.9
86.9
93.6
83.2
87.3
99.8
85.9
80.0
80.0
90.0
80.8
66.6
69.8
89.8
3.4
41.9
41.9
90.0
90.0
37.7
37.7
153.1
36.9
23.5
92.7
92.9
84.3
87.1
97.7
80.5
80.0
80.0
80.8
74.7
67.4
69.7
78.9
3.4
46.9
46.9
80.0
80.0
37.5
37.5
146.5
36.5
24.1
85.9
89.7
83.3
87.8
92.9
84.6
80.0
80.0
87.9
76.0
66.6
70.2
81.6
ICF
INCORPORATED
-------
Exhibit D-44
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
Reference Case II
New England
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Middle Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
6.0
2.6
3.4
95.2
95.4
95.0
80.0
80.0
80.0
76.1
76.3
76.0
15.8
11.9
3.1
0.8
90.6
89.2
95.0
95.0
80.0
80.0
80.0
80.0
72.5
71.4
76.0
76.0
90%
7.7
2.6
5.1
95.3
89.9
100.0
86.6
80.0
90.0
83.9
71.9
90.0
27.5
11.9
2.9
12.7
92.3
86.7
81.6
100.0
84.6
80.0
80.0
90.0
78.5
69.4
65.3
90.0
80%
7.7
2.6
5.1
95.3
89.9
100.0
80.0
80.0
80.0
77.3
71.9
80.0
27.2
11.9
2.9
12.4
92.4
86.5
84.3
100.0
80.0
80.0
80.0
80.0
73.9
69.2
67.4
80.0
0.5 Ibs.
7.7
2.6
5.1
95.3
89.9
100.0
86.6
80.0
90.0
83.9
71.9
90.0
27.6
11.9
3.1
12.9
92.7
86.7
95.0
97.5
84.7
80.0
80.0
90.0
78.8
69.4
76.0
87.8
ICF
INCORPORATED
-------
Exhibit D-44
1990'SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
South Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
East North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
18.4
16.6
1.6
0.2
72.7
70.3
95.0
96.3
80.0
80.0
80.0
80.0
58.1
56.2
76.0
77.0
11.9
3.2
4.3
4.4
95.2
96.7
95.0
94.3
80.0
80.0
80.0
80.0
76.2
77.4
76.0
75.4
90%
51.2
12.6
1.3
37.3
93.1
69.5
95.0
100.0
88.0
80.0
80.0
90.0
81.1
55.6
76.0
90.0
28.8
3.2
2.7
22.9
99. 1
96.7
94.5
100.0
88.0
80.0
80.0
90.0
87.3
77.4
75.6
90.0
80%
51.8
12.7
1.4
37.7
92.2
69.5
95.0
100.0
80.0
80.0
80.0
80.0
73.8
55.6
76.0
80.0
28.9
3.2
2.7
23.0
99.1
96.7
94.5
100.0
80.0
80.0
80.0
80.0
79.3
77.4
75.6
80.0
0.5 Ibs.
51.0
12.7
1.4
36.9
91.0
69.5
95.0
98.3
87.2
80.0
80.0
90.0
80.0
55.6
76.0
88.5
28.5
3.1
2.5
22.9
99.6
98.2
98.5
99.9
88.0
80.0
80.0
89.9
87.9
78.6
78.8
89.8
ICF
INCORPORATED
-------
Exhibit D-44
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
East South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
West North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
1.2 Ibs.
9.3
2.9
2.8
3.6
75.3
97.2
95.0
42.4
80.0
80.0
80.0
80.0
60.3
77.8
76.0
33.9
1.4
1.2
0.2
-
99.3
100.0
95.0
-
80.0
80.0
80.0
-
79.4
80.0
76.0
90%
20.8
2.9
1.5
16.4
98.2
97.2
81.0
100.0
87.9
80.0
80.0
90.0
86.5
77.8
64.8
90.0
12.4
1.2
—
11.2
100.0
100.0
—
100.0
89.0
80.0
—
90.0
89.0
80.0
—
80%
20.7
2.9
1.5
16.3
98.2
97.2
81.0
100.0
80.0
80.0
80.0
80.0
78.6
77.8
64.8
80.0
12.7
1.2
"~
11.5
100.0
100.0
~
100.0
80.0
80.0
~
80.0
80.0
80.0
—
0.5 Ibs.
f\ » 4
21.1
2f\
.9
1 .4
16.8
97.6
98.0
84. 1
98.7
87.8
80.0
80.0
89.8
85.8
78.4
67.2
88.6
4 ** jt
12.4
1*^
. 2
11.2
75.9
100.0
~
73.3
81.3
80.0
™
81.4
61.7
80.0
~
ANSPS
90.0
80.0
59.7
ICF
INCORPORATED
-------
Exhibit D-44
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
West South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Mountain
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
18.0
1.1
6.6
10.3
81.3
80.4
80.4
81.9
80.0
80.0
80.0
80.0
65.0
64.3
64.3
65.5
16.7
1.0
10.3
5.4
89.3
100.0
85.3
95.0
83.2
80.0
80.0
90.0
74.5
80.0
68.2
85.5
90%
38.0
1.1
4.5
32.4
97.1
80.4
80.4
100.0
88.5
80.0
80.0
90.0
86.2
64.3
64.3
90.0
17.1
1.0
10.6
5.5
89.8
100.0
85.8
95.7
83.2
80.0
80.0
90.0
74.9
80.0
68.6
86.1
80%
38.1
1.1
4.5
32.5
97.1
80.4
80.4
100.0
80.0
80.0
80.0
80.0
77.7
64.3
64.3
80.0
16.5
1.0
10.2
5.3
. 89.2
100.0
85.2
95.0
83.2
80.0
80.0
90.0
74.5
80.0
68.2
85.5
0.5 Ibs.
37.8
1.1
4.5
32.2
89.9
80.4
80.4
91.6
84.5
80.0
80.0
85.3
76.1
64.3
64.3
78.1
16.4
1.0
10.6
4.8
89.8
100.0
86.5
95.0
81.0
80.0
80.0
90.0
74.6
80.0
69.2
85.5
ICF
INCORPORATED
-------
Exhibit D-44
1990 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
1.2 Ibs.
90%
80%
0.5 Ibs.
Pacific
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
National
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
6.2
7.6
7.6
8.1
6.2
50.2
50.2
90.0
90.0
45.2
45.2
103.2
40.3
28.7
34.2
82.7
83.3
88.2
77.3
81.1
80.0
80.0
83.4
67.0
66.6
70.6
64.5
7.6
100.0
100.0
90.0
90.0
90.0
90.0
210.8
36.3
23.4
151.1
95.4
83.3
85.4
99.8
87.2
80.0
80.0
90.0
83.4
66.6
68.3
89.8
7.6
42.9
42.9
90.0
90.0
38.6
38.6
210.8
36.5
23.1
151.2
93.3
83.1
85.6
97.0
80.6
80.0
80.0
80.8
75.0
66.5
68.5
78.3
8.1
46.9
46.9
80.0
80.0
37.5
37.5
210.8
36.2
23.6
151.0
90.4
83.4
88.1
92.4
85.6
80.0
80.0
87.8
77.4
66.7
70.5
81.1
ICF
INCORPORATED
-------
Exhibit D-45
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
Reference Case I
New England
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Middle Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
4.4
3.3
1.1
95.2
95.3
95.0
80.0
80.0
80.0
76.1
76.2
76.0
15.7
11.8
3.1
0.8
89.7
87.9
95.0
95.0
80.0
80.0
80.0
80.0
72.1
70.3
76.0
76.0
90%
5.9
3.3
2.6
95.0
91.1
100.0
84.4
80.0
90.0
77.4
72.9
90.0
21.3
11.9
2.9
6.5
92.2
87.2
95.0
100.0
83.7
80.0
80.0
90.0
76.8
69.8
76.0
90.0
80%
5.9
3.3
2.6
95.0
91.1
100.0
80.0
80.0
80.0
76.0
72.9
80.0
20.6
11.6
2.9
6.1
92.8
88.4
95.0
100.0
80.0
80.0
80.0
80.0
74.2
70.7
76.0
80.0
0.5 Ibs.
5.9
3.3
2'. 6
95.0
91.1
99.9
84.4
80.0
90.0
76.0
72.9
79.9
21.3
11.5
3.1
6.7
92.7
87.8
95.0
99.6
83.1
80.0
80.0
90.0
77.1
70.2
76.0
89.6
ICF
INCORPORATED
-------
Exhibit D-45
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
South Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
East North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
15.6
13.9
1.5
0.2
76.4
74.1
95.0
94.9
80.0
80.0
80.0
80.0
61. 1
59.3
76.0
75.9
10.5
3.2
4.3
3.0
94.3
93.2
95.0
94.6
80.0
80.0
80.0
80.0
75.5
74.6
76.0
75.7
90%
33.5
12.6
1.5
19.4
88.5
70.0
95.0
100.0
85.8
80.0
80.0
90.0
76.6
56.0
76.0
90.0
15.5
3.1
2.6
9.8
98.5
96.7
95.0
100.0
86.3
80.0
80.0
90.0
85.1
77.4
76.0
90.0
80%
34.3
12.8
1.5
20.0
88.5
69.9
95.0
100.0
80.0
80.0
80.0
80.0
70.8
55.9
76.0
80.0
19.5
3.2
2.6
13.7
98.8
96.7
95.0
100.0
80.0
80.0
80.0
80.0
79.0
77.4
76.0
80.0
0.5 Ibs.
33.2
12.6
1.5
19.1
87.5
70.0
95.0
98.4
85.8
80.0
80.0
90.0
75.7
56.0
76.0
88.6
15.4
3.2
2.6
9.6
98.5
96.7
95.0
99.9
86.2
80.0
80.0
89.9
84.9
77.4
76.0
89.8
ICF
INCORPORATED
-------
Exhibit D-45
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
East South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
West North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
6.6
3.2
2.8
0.6
90.5
91.9
95.0
62.2
80.0
80.0
80.0
80.0
73.1
73.5
76.0
49.8
1.4
1.2
0.2
-
99.3
100.0
95.0
-
80.0
80.0
80.0
-
79.4
80.0
76.0
_
90%
14.0
2.9
2.0
9.1
97.5
96.4
87.8
100.0
86.5
80.0
80.0
90.0
84.6
77.1
70.2
90.0
15.7
1.2
0.2
14.3
99.9
100.0
95.0
100.0
89.1
80.0
80.0
90.0
89.2
80.0
76.0
90.0
80%
14.9
2.9
1.9
10.1
98.0
97.2
87.5
100.0
80.0
80.0
80.0
80.0
78.3
77.8
70.0
80.0
17.0
1.2
0.2
15.6
99.9
100.0
95.0
100.0
80.0
80.0
80.0
80.0
79.9
80.0
76.0
80.0
0.5 Ibs.
13.9
2.9
1.9
9.1
97.6
96.4
87.5
100.0
86.5
80.0
80.0
90.0
85.5
77.1
70.0
90.0
14.2
1.2
0.2
12.8
99.9
100.0
95.0
100.0
89.0
80.0
80.0
90.5
89.0
80.0
76.0
90.0
ICF
INCORPORATED
-------
Exhibit D-45
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
West South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Mountain
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
16. 1
1.1
6.6
8.4
81.4
80.4
80.4
82.4
80.0
80.0
80.0
80.0
65.1
64.3
64.3
65.9
16.3
1.0
11.3
4.0
87.9
100.0
84.4
94.9
82.5
80.0
80.0
90.0
72.7
80.0
67.5
85.4
90%
35.2
1.1
4.5
29.6
96.9
80.2
80.4
100.0
88.4
80.0
80.0
90.0
85.9
64.2
64.3
90.0
19.1
1.0
11.3
6.8
89.4
100.0
84.4
96.1
83.6
80.0
80.0
90.0
74.9
80.0
67.5
86.5
80%
36.3
1.1
4.5
30.7
97.0
80.2
80.4
100.0
80.0
80.0
80.0
80.0
77.6
64.2
64.3
80.0
18.1
1.0
10.7
6.4
87.7
100.0
84.6
91.0
83.5
80.0
80.0
90.0
73.3
80.0
67.7
81.9
0.5 Ibs.
32.3
1.1
4.5
26.7
88.6
80.2
80.4
90.3
84.4
80.0
80.0
85.3
75.0
64.2
64.3
77.0
18.2
1.0
11.0
6.2
88.8
100.0
85.0
93.9
82.9
80.0
80.0
88.6
73.5
80.0
68.0
83.2
ICF INCORPORATED
-------
Exhibit D-45
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case I
1.2 Ibs.
90%
80%
0.5 Ibs.
Pacific
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
National
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
3.4
3.4 •
3.4
3.4
3.4
44.2
44.2
90.0
90.0
39.8
39.8
90.1
38.8
29.8
21.5
84.9
84.8
87.7
81.1
80.8
80.0
80.0
83.4
68.5
67.8
70.2
67.6
3.4
100.0
100.0
90.0
90.0
90.0
90.0
163.5
37.1
25.0
101.4
94.2
83.8
87.0
99.7
86.2
80.0
80.0
90.0
81.5
67.0
69.6
89.7
3.4
50.2
50.2
90.0
90.0
45.2
45.2
170.0
37.0
24.4
108.6
87.0
84. 1
87.1
97.9
80.6
80.0
80.0
80.9
75.2
67.3
69.7
79.2
3.4
46.9
46.9
90.0
90.0
37.5
37.5
157.8
36.8
24.9
96.1
88.8
83.9
87.3
91.2
84.5
80.0
80.0
87.4
75.2
67.1
69.8
79.7
ICF
INCORPORATED
-------
Exhibit D-46
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS
Reference Case II
New England
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Middle Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
6.7
3.3
3.4
95.3
95.3
95.2
80.0
80.0
80.0
76.2
76.2
76.2
15.8
11.9
3.1
0.8
91.5
90.4
95.0
95.0
80.0
80.0
30.0
80.0
76.9
72.3
76.0
76.0
90%
8.9
3.3
5.6
96.6
91.0
100.0
86.3
80.0
90.0
83.6
72.8
90.0
31.9
11.9
2.9
17.1
93.6
87.6
80.4
100.0
85.4
80.0
80.0
90.0
80.2
70.1
64.3
90.0
80%
8.9
3.3
5.6
96.6
91.0
100.0
80.0
80.0
80.0
78.9
72.8
80.0
31.7
11.9
2.9
16.9
93.5
87.5
80.4
100.0
80.0
80.0
80.0
80.0
74.8
70.0
64.3
80.0
0.5 Ibs.
8.9
3.3
5.6
96.4
91.1
99.5
86.3
80.0
90.0
83.4
72.9
89.6
31.9
11.5
3.1
17.3
93.6
88.4
95.0
96.8
85.4
80.0
80.0
90.0
80.1
70.7
76.0
87.1
ICF INCORPORATED
-------
Exhibit D-46
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
South Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
East North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
17.9
16.2
1.5
0.2
73.4
71.2
95.0
88.7
80.0
80.0
80.0
80.0
58.7
57.0
76.0
71.0
17.4
3.2
4.3
9.9
95.3
96.7
95.0
94.9
80.0
80.0
80.0
80.0
76.2
77.4
76.0
75.9
90%
53.5
12.6
1.1
39.8
92.4
69.5
30.4
100.0
87.4
80.0
80.0
90.0
81.4
55.6
64.3
90.0
53.1
3.2
1.5
48.4
99.7
96.7
95.0
100.0
89. 1
80.0
80.0
90.0
88.8
77.4
76.0
90.0
80%
53.9
12.7
0.9
40.3
92.5
69.5
80.4
100.0
80.0
80.0
80.0
80.0
74.0
55.6
64.3
80.0
50.8
3.2
1.5
46.1
99.7
96.7
95.0
100.0
80.0
80.0
80.0
80.0
79.7
77.4
76.0
80.0
0.5 Ibs.
53.5
12.7
1.3
39.5
91.1
69.5
95.0
97.9
87.4
80.0
80.0
90.0
80.1
55.6
76.0
88.1
59.1
3.2
1.5
54.4
91.0
96.8
95.0
90.6
87.6
80.0
80.0
88.3
79.8
77.4
76.0
80.0
ICF
INCORPORATED
-------
Exhibit D-46
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
East South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
West North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
9.3
2.9
2.8
3.6
75.6
97.2
95.0
43.5
80.0
80.0
80.0
80.0
60.6
77.8
76.0
34.8
7.4
1.2
0.2
6.0
46.8
100.0
95.0
34.6
80.0
80.0
80.0
80.0
37.5
80.0
76.0
27.7
90%
30.3
3.0
1.1
26.2
99.3
94.8
95.0
100.0
88.6
80.0
80.0
90.0
88.1
75.8
76.0
90.0
35.8
1.2
-
34.6
100.0
100.0
-
100.0
89.7
80.0
-
90.0
89.7
80.0
-
90.0
80%
30.2
3.0
1.1
26.1
99.3
94.9
95.0
100.0
80.0
80.0
80.0
80.0
79.4
75.9
76.0
80.0
40.9
1.2
-
39.7
100.0
100.0
-
100.0
80.0
80.0
-
80.0
80.0
80.0
-
80.0
0.5 Ibs.
30.2
2.9
1.3
26.0
94.6
96.7
86.5
94.8
87.7
80.0
80.0
89.0
83.1
77.4
69.2
84.4
28.9
1.2
-
27.7
76. 1
100.0
-
75.1
81.6
80.0
-
81.7
62.2
80.0
-
61.4
ICF INCORPORATED
-------
Exhibit D-46
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
West South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Mountain
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.2 Ibs.
30.9
1.1
6.6
23.2
61.9
80.2
80.4
55.8
80.0
80.0
80.0
80.0
49.5
64.2
64.3
44.6
23.2
1.2
11.7
10.3
85.5
34.6
84.5
92.6
84.4
80.0
80.0
90.0
72.5
27.7
67.6
83.3
90%
59.9
1.1
4.5
54.3
98.2
80.2.
80.4
100.0
89.1
80.0
80.0
90.0
87.6
64.2
64.3
90.0
25.2
1.0
12.0
12.2
89.6
100.0
84.5
93.8
84.8
80.0
80.0
90.0
76.2
80.0
67.6
84.4
80%
60.0
1. 1
4.5
54.4
98.2
80.2
80.4
100.0
80.0
80.0
80.0
80.0
78.5
64.2
64.3
80.0
23.6
1.0
11.7
10.9
88.1
100.0
84.4
91.0
84.6
80.0
80.0
90.0
74.7
80.0
67.5
81.9
0.5 Ibs.
59.7
1.1
4.5
54.1
88.9
80.2
80.4
89.8
82.9
80.0
80.0
83.2
73.7
64.2
64.3
74.7
24.1
1.0
12.0
11.1
89.8
100.0
85.7
93.4
84.1
80.0
80.0
88.9
75.7
80.0
68.6
83.0
ICF
INCORPORATED
-------
Exhibit D-46
1995 SCRUBBER CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARDS (Cont'd)
Reference Case II
1.2 Ibs.
90%
80%
0.5 Ibs.
Pacific
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
National
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
6.2
16.3
16.3
16.8
6.2
55.8
55.8
90.0
90.0
50.2
50.2
134.4
40.9
30.1
63.4
77.2
84.1
87.7
67.8
81.2
80.0
80.0
82.6
62.6
67.3
70.1
56.0
16.3
100.0
100.0
90.0
90.0
90.0
90.0
316.2
38.4
23.2
254.6
96.6
83.6
84.2
99.7
88.1
80.0
80.0
90.0
85.3
66.9
67.4
89.7
16.3
74.3
74.3
83.8
83.8
62.3
62.3
316.0
37.3
22.6
256.1
95.3
83.5
84. 1
98.0
80.6
80.0
80.0
80.7
76.8
66.8
67.3
79.1
16.8
46.9
46.9
80.0
80.0
37.5
37.5
313.1
36.9
23.7
252.5
87.5
83.9
87.0
88.1
85.2
80.0
80.0
86.4
74.5
67.1
69.6
76.1
ICF
INCORPORATED
-------
EXHIBIT D-47
1985 UTILITY COAL CONSUMPTION UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS
(in 1015 Btu)
Region
Northeast
Mid-Atlantic
South
Atlantic
East North
Central
East South
Central
West North
Central
West South
Central
Mountain
Pacific
National
Reference Cases I and II
Type
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
Higher Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
.136
.004
.101
.242
.306
1.076
.391
1.772
.670
1.975
.513
3.157
1.350
1.744
1.158
4.253
.886
.742
.524
2.152
.489
.841
.554
1.884
.060
1.112
.890
2.062
.427
.933
1.360
.038
.070
.108
3.897
7.959
5.134
16.990
90%
.111
.029
.101
.241
.380
1.075
.326
1.780
.762
1.711
.534
3.008
1.366
1.838
1.025
4.229
.937
.739
.470
2.147
.511
.795
.478
1.784
.128
1.450
.514
2.091
.464
.933
1.397
.038
.070
.108
4.195
8.141
4.451
16.787
80%
.111
.029
.101
.241
.380
1.064
.326
1.770
.792
1.728
.518
3.038
1.366
1.833
1.025
4.224
.937
.739
.469
2.145
.512
.797
.478
1.787
.128
1.453
.514
2.094
.427
.927
1.354
.038
.070
.108
4.225
8.109
4.427
16.761
0.5 Ibs.
.111
.029
.101
.241
.393
1.062
.332
1.787
.747
1.729
.517
2.994
1.366
1.838
1.025
4.229
.937
.739
.470
2.147
.520
.803
.478
1.801
.128
1.330
.514
1.972
.427
.933
1.360
.038
.070
.108
4.202
7.996
4.444
16.639
ICF INCORPORATED
-------
Exhibit D-48
1990 UTILITY COAL CONSUMPTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Region
Northeast
Mid-Atlantic
South
Atlantic
East North
Central
East South
Central
West North
Central
West South
Central
Mountain
Pacific
National
(in 1015 Btu)
Reference Case I
Type
•*-jy-
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
Higher Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
.191
.074
.105
.370
.251
1.075
.903
2.229
.737
1.881
1.113
3.730
1.443
1.685
1.639
4.767
.731
.732
.855
2.318
.461
.885
.797
2.142
.060
1.291
1.465
2.816
—
.535
.971
1.506
—
.031
.262
.292
3.874
8.189
8.109
20.172
90%
.249
.099
.032
.380
.528
1.081
.291
1.900
1.579
1.736
.552
3.867
1.650
1.860
1.075
4.585
1.034
.744
.528
2.306
.462
1.112
.510
2.085
.128
2.236
.514
2.877
—
.564
.979
1.543
—
.169
.118
.287
5.630
9.602
4.598
19.830
80%
.249
.099
.032
.380
.477
1.128
.277
1.882
1.605
1.775
.517
3.897
1.790
1.840
1.070
4.710
1.060
.746
.526
2.332
.472
1.143
.501
2.116
.128
2.238
.514
2.880
—
.536
.964
1.500
—
.031
.258
.289
5.783
9.538
4.664
19.985
0.5 Ibs.
.249
.099
.032
.380
.545
1.058
.309
1.912
1.280
2.030
.542
3.852
1.627
1.875
1.074
4.576
1.034
.744
.528
2.306
.481
1.020
.596
2.098
.129
2.220
.514
2.862
—
.527
.977
1.504
—
.031
.271
.301
5.345
9.603
4.843
19.791
ICF INCORPORATED
-------
Exhibit D-49
1990 UTILITY COAL CONSUMPTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
(in 10 Btu)
Reference Case II
Region
Northeast
Mid-Atlantic
South
Atlantic
East North
Central
East South
Central
West North
Central
West South
Central
Mountain
Pacific
National
Type
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
Higher Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
.330
.059
.113
.502
.248
1.133
1.369
2.749
.631
2.108
1.692
4.432
1.534
1.780
2.210
5.524
.801
.909
1.074
2.784
.461
.908
1.023
2.392
.060
1.465
1.655
3.180
—
.617
.983
1.600
—
.156
.405
.561
4.064
9.135
10.523
23.722
90%
.393
.084
.032
.509
.462
1.477
.272
2.211
2.294
1.825
.650
4.769
2.231
1.943
1.100
5.274
1.412
.744
.600
2.755
.506
1.321
.518
2.345
.113
2.610
.514
3.236
—
.629
1.000
1.629
—
.266
.291
.557
7.410
10.897
4.978
23.285
80%
.396
.081
.032
.509
.429
1.506
.259
2.194
2.321
1.741
.731
4.793
2.205
1.972
1.100
5.277
1.407
.744
.600
2.750
.508
1.330
.518
2.356
.102
2.623
.514
3.239
—
.601
.986
1.S86
—
.031
.536
.567
7.367
10.628
5.275
23.270
0.5 Ibs.
.396
.081
.032
.509
.610
1.333
.279
1.223
1.716
2.321
.711
4.747
2.193
1.988
1.094
5.276
1.416
.744
.605
2.764
.516
1.174
.665
2.355
.129
2.581
.514
3.223
—
.591
.999
1.590
—
.031
.569
.600
6.975
10.844
5.468
23.287
ICF INCORPORATED
-------
Exhibit D-50
1995 UTILITY COAL CONSUMPTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Mid-Atlantic
South
Atlantic
East North
Central
East South
Central
West North
Central
West South
Central
Mountain
Pacific
Nnt. tonal
(in 1015 Btu)
Reference Case I
Type
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
Higher Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
.157
.103
.063
.323
.224
1.033
.828
2.085
.681
1.665
.959
3.305
1.438
1.609
1.741
4.788
.725
.684
.771
2.180
.429
.946
1.235
2.610
.063
1.352
1.635
3.051
—
.510
1.051
1.561
—
.097
.472
.570
3.718
8.000
8.756
20.474
90%
.241
.096
.005
.343
.468
1.062
.238
1.768
1.351
1.652
.493
3.496
1.588
1.734
1.046
4.369
1.039
.701
.468
2.208
.489
1.499
.513
2.501
.128
2.436
.514
3.077
—
.688
1.050
1.739
—
.206
.098
.304
5.305
10.975
4.425
19.805
80%
.241
.096
.005
.343
.449
1.051
.224
1.724
1.376
1.688
.459
3.523
1.734
1.759
1.033
4.527
1.062
.719
.474
2.255
.503
1.527
.511
2.541
.128
2.496
.514
3.137
—
.673
1.022
1.695
—
.120
.186
.307
5.493
10.130
4.429
20.051
0.5 Ibs.
.239
.099
.005
.343
.519
.998
.251
1.768
1.091
1.956
.433
3.480
1.577
1.774
1.024
4.376
1.034
.692
.482
2.207
.486
1.198
.727
2.411
.128
2.269
.514
2.911
—
.675
1.014
1.689
—
.025
.294
.319
5.075
9.686
4.744
19.505
ICF INCORPORATED
-------
Exhibit D-51
1995 UTILITY COAL CONSUMPTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Mid-Atlantic
South
Atlantic
East North
Central
East South
Central
West North
Central
West South
Central
Mountain
Pacific
National
(in 1015 Btu)
Reference Case II
Tvoe
•"•j^
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
Higher Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
1.2 Ibs.
.296
.067
.086
.448
.206
1.126
1.592
2.924
.654
1.942
1.722
4.318
1.837
1.782
3.743
7.361
.750
.893
1.383
3.027
.434
1.319
1.540
3.294
.063
2.189
2.115
4.367
—
.788
1.184
1.973
—
.300
.736
1.036
4.241
10.406
14.101
28.749
90%
.311
.150
.006
.468
.622
1.457
.223
2.301
2.020
1.923
.635
4.577
3.206
1.993
1.236
6.435
1.568
.837
.709
3.115
.550
2.546
.520
3.617
.110
3.838
.514
4.462
—
.902
1.185
2.087
—
.299
.788
1.087
8.386
13.946
5.816
28.148
80%
.350
.106
.006
.462
.583
1.497
.208
2.288
2.029
1.900
.671
4.601
3.091
1.992
1.222
6.305
1.632
.838
.634
3.104
.551
2.778
.521
3.849
.108
3.842
.514
4.463
—
.851
1.169
2.020
—
.081
1.017
1.098
8.344
13.884
5.962
28.190
0.5 Ibs.
.316
.144
.007
.467
.626
1.457
.227
2.310
1.565
2.400
.595
4.560
1.741
2.177
2.863
6.781
1.645
.742
.715
3.103
.593
1.684
.949
3.226
.121
3.821
.514
4.456
—
.878
1.161
2.038
—
.025
1.102
1.127
7.730
13.329
7.010
28.069
ICF INCORPORATED
-------
Exhibit D-52
1985 OIL AND GAS CONSUMPTION BY PLANT AND BY REGION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Region Plant Type
New England Steam
Combined Cycle
Turbines and Internal Comb
Total
Middle Steam
Atlantic Combined Cycle
Turbines and Internal Comb
Total
South steam
Atlantic Combined Cycle
Turbines and Internal Comb
Total
East North Steam
Central Combined Cycle
Turbines and Internal Comb
Total
East South Steam
Central Combined Cycle
Turbineo and Internal Comb
Total
West North Steam
Central combined Cycle
Turbines and Internal Comb
Total
Meat South Steam
Central Combined Cycle
Turbines and Internal Comb
Total
Mountain Steam
Combined Cycle
Turbines and Internal Comb
Total
Pacific Steam
Combined Cycle
Turbines and Internal Comb
Total
National Steam
Combined Cycle
Turbines and Intern
Total
(in 1015
. Comb.
L Comb.
L Comb.
1 Comb.
1 Comb.
1 Comb.
,1 Comb.
il Comb.
il Comb.
il comb.
Btua)
Reference Cases I and II
1.2 Ibs.
0.405
0.020
0.268
0.693
0.495
0.012
0.315
0.822
0.896
0.029
0.382
1.307
0.307
0.007
0.405
0.719
0.066
0.280
0.346
0.074
0.002
0.134
0.210
1.359
0.021
0.022
1.402
0.080
0.015
0.032
1.270
0.892
0.433
0.140
1.465
4.574
0.539
3.121
8.234
90%
0.409
0.020
0.272
0.701
0.495
0.012
0.349
0.856
0.956
0.029
0.459
1.444
0.318
0.007
0.411
0.736
0.069
0.287
0.356
0.074
0.003
0.168
0.254
1.514
0.021
0.023
1.557
0.080
0.015
0.032
1.270
0.886
0.398
0. 140
1.424
4.801
0.505
3.292
8.598
80%
0.409
0.020
0.272
0.701
0.495
'0.012
0.335
0.842
0.956
0.029
0.460
1.445
0.318
0.007
0.406
0.731
0.084
0.320
0.404
0.074
0.003
0.168
0.254
1.514
0.021
0.023
1.557
0.087
0.015
0.032
1.340
0.886
0.428
0.140
1.454
3.823
0.527
4.378
8.728
0.5 Ibs.
0.409
0.020
0.272
0.701
0.496
0.012
0.357
0.865
0.956
0.029
0.460
1.445
0.318
0.007
0.411
0.736
0.085
0.322
0.407
0.074
0.003
0.168
0.254
1.514
0.021
0.023
1.557
0.082
0.015
0.032
1.290
0.886
0.428
0.140
1.454
4.820
0.535
3.354
8.709
-------
Exhibit D-53
1990 OIL AND GAS CONSUMPTION BY PLANT AND BY REGION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Plant Type
New England Steam
Combined Cycle
Turbines and Inter
nal Cocnb.
Total
Middle Steam
Atlantic Combined Cycle
Turbines and Inter
nal Comb.
Total
South Steam
Atlantic Combined Cycle
Turbines and Inter-
nal Comb.
Total
East North Steam
Central Combined Cycle
Turbines and Inter-
nal Comb.
Total
East South Steam
Central Combined Cycle
Turbines and Inter-
nal Comb.
Total
West North Steam
Central Combined Cycle
Turbines and Inter
nal Comb.
Total
West South Steam
Central Combined Cycle
Turbines and Inter
nal Comb.
Total
Mountain Steam
Combined Cycle
Turbines and Inter
nal Comb.
Total
Pacific Steam
Combined Cycle
Turbines and Inter
nal Comb.
Total
National Steam
Combined Cycle
Turbines and Inter
nal Comb.
Total
(in 1015 Btu)
1.2 Ibs.
0.271
0.012
0.116
0.399
0.482
0.0t2
0.205
0.699
0.633
0.029
0.324
0.986
0.275
0.007
r-
0.275
0.575
0.082
r-
0.154
0.236
0.078
0.002
r-
0.172
0.252
1.216
0.015
r-
0.032
1.263
0.088
0.014
r-
0.042
0.144
0.779
0.413
ir-
0.120
1.312
3.904
0.504
:r-
1.440
5.848
Reference
90%
0.271
0.012
0.116
0.399
0.504
0.012
0.291
0.807
0.668
0.029
0.428
1.125
0.401
0.007
0.360
0.768
0.084
0.193
0.277
0.119
0.003
0.192
0.314
1.224
0.021
0.034
1.279
0.088
0.014
0.042
0.144
0.776
0.378
0.120
1.274
4.135
0.476
1.776
6.387
Case I
80%
0.271
0.012
0.116
0.399
0.504
0.012
0.288
0.804
0.668
0.029
0.428
1.125
0.311
0.007
0.301
0.619
0.082
0.161
0.243
0.095
0.003
0.180
0.278
1.224
0.021
0.034
1.279
0.092
0.014
0.043
0.149
0.776
0.408
0.120
1.304
4.023
0.506
1.671
6.200
0.5 Ibs.
0.271
0.012
0.116
0.339
0.504
0.012
0.293
0.809
0.668
0.029
0.428
1.125
0.408
0.007
0.364
0.779
0.084
0.193
0.277
0.117
0.003
0.199
0.319
1.224
0.021
0.034
1.279
0.084
0.018
0.042
0.144
0.770
0.408
0.119
1.297
4.130
0.510
1.728
6.368
-------
Exhibit D-54
1990 OIL AND GAS CONSUMPTION BY PLANT AND BY REGION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Plant Type
New England Steam
Combined Cycle
Turbines and Inter-
nal Comb.
Total
Middle Steam
Atlantic Combined Cycle
Turbines and Inter-
nal Comb.
Total
South Steam
Atlantic Combined Cycle
Turbines and Inter-
nal Comb.
Total
East North steam
Central Combined Cycle
Turbines and inter
nal Comb.
Total
East South Steam
Central Combined Cycle
Turbines and Inter
nal Comb.
Total
West North steam
Central Combined Cycle
Turbines and Inter-
nal Comb.
Total
West South Steam
Central Combined Cycle
Turbines and Inter-
nal Comb.
Total
Mountain Steam
Combined Cycle
Turbin»B and Inter
nal Comb.
Total
Pacific Steam
Combined Cycle
Turbines and Inter
nal Comb.
Total
National Steam
Combined Cycle
Turbines and Inter
nal Comb.
Total
(in 1015 Btu)
1.2 Ibs.
0.271
0.012
0.122
0.405
0.439
0.012
r-
0.253
0.754
0.649
0.027
r-
0.383
1.059
0.296
0.007
r-
0.309
0.612
0.082
r-
0.184
0.266
0.080
0.002
ir-
0.192
0.274
1.287
0.015
jr-
0.073
1.375
0.090
0.015
sr-
0.049
0.154
0.726
0.600
ar-
0.147
1.473
3.970
0.690
er-
1.712
6.372
Reference Case II
90%
0.271
0.012
0.271
0.435
0.508
0.012
0.328
0.848
0.698
0.029
0.524
1.251
0.392
0.007
0.508
0.907
0.084
0.217
0.301
0.119
0.003
0.214
0.336
1.295
0.021
0.075
1.391
0.096
0.015
0.051
0.162
0.725
0.599
0.147
1.471
4.188
0.698
2.216
7.102
80%
0.271
0.012
0.128
0.411
O.S08
0.012
0.325
0.845
0.698
0.029
0.524
1.251
0.388
0.007
0.501
0.896
0.084
0.241
0.325
0.109
0.003
0.211
0.323
1.295
0.021
0.075
1.391
0.098
0.015
0.055
0.168
0.725
0.593
0.147
1.465
4.176
0.692
2.207
7.075
0.5 Ibs.
0.271
0.012
0.128
0.411
0.508
0.012
0.330
O.B50
0.714
0.029
0.508
1.251
0.508
0.007
0.508
0.907
0.084
0.230
0.314
0.119
0.003
0.223
0.345
1.295
0.021
0.075
1.391
0.096
0.015
0.051
0.162
0.700
0.593
0.144
1.437
4.295
0.692
2.081
7.068
-------
Exhibit D-55
1995 OIL AND GAS CONSUMPTION BY PLANT AND BY REGION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Region Plant Type
New England Steam
Combined Cycle
Turbines and Internal Comb
Total
Middle Steam
Atlantic Combined Cycle
Turbines and Internal Comb
Total
South Steam
Atlantic Combined Cycle
Turbines and Internal Comb
Total
East North Steam
Central Combined Cycle
Turbines and Internal Comb.
Total
East South Steam
Central Combined Cycle
Turbines and Internal Comb
Total
West North Steam
Central Combined Cycle
Turbines and Internal Comb
Total
West South Steam
Central Combined Cycle
Turbines and Internal Comb
Total
Mountain Steam
Combined Cycle
Turbines and Internal Comb
Total
Pacific Steam
Combined Cycle
Turbines and Internal Comb
Total
National Steam
Combined Cycle
Turbines and Internal Comb
Total
(in 1015 Btus)
1.2 Ibs.
0.271
0.012
L Comb. 0.129
0.412
0.460
0.012
L Comb. 0. 1B3
0.655
0.418
0.017
1 Comb. 0.278
0.713
0.212
0.007
1 Comb. 0.296
0.515
0.066
1 Comb. 0. 152
0.218
0.084
0.002
1 Comb. 0.218
0.304
1.352
0.015
1 Comb. 0. 108
1.475
0.092
0.015
.1 Comb. 0.054
0.161
0.388
0.218
il Comb. 0.150
0.756
3.343
0.361
il Comb. 1.505
5.209
Reference
90%
0.271
0.012
0.130
0.413
0.495
0.012
0.285
0.792
0.526
0.017
0.418
0.961
0.342
0.007
0.447
0.796
0.066
0.184
0.250
0.123
0.003
0.251
0.377
1.352
0.015
0.108
1.475
0.111
0.015
0.058
0.184
0.465
0.234
0.151
0.850
3.751
0.315
2.032
6.098
Case I
80%
0.271
0.012
0.130
0.413
0.489
0.012
0.258
0.759
0.524
0.017
0.416
0.957
0.311
0.007
0.383
0.701
0.066
0.202
0.268
0.102
0.003
0.224
0.329
1.352
0.015
0.108
1.475
0.120
0.020
0.060
0.200
0.392
0.217
0.151
0.760
3.627
0.303
1.932
5.862
0.5 Ibg.
0.271
0.012
0.130
0.413
0.493
0.012
0.276
0.781
0.526
0.017
0.418
0.961
0.350
0.007
0.467
0.824
0.066
0.202
0.268
0.117
0.003
0.254
0.374
1.352
0.015
0.108
1.475
0.113
0.015
0.058
0.186
0.619
0.362
0.151
1.132
3.907
0.645
1.357
5.909
-------
Exhibit D-S6
1995 OIL AND GAS CONSUMPTION BY PLANT AND BY REGION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARDS
Plant Type
New England Steam
Combined Cycle
Turbines and Inter-
nal Comb.
Total
Middle Steam
Atlantic Combined Cycle
Turbines and Inter1
nal Comb.
Total
South Steam
Atlantic Combined Cycle
Turbines and Inter
nal Comb.
Total
Eaet North Steam
Central Combined Cycle
Turbines and Inter-
nal Comb.
Total
Eaet South Steam
Central Combined Cycle
Turbines and Inter
nal Comb.
Total
West North Steam
Central Combined Cycle
Turbines and Inter
nal Comb.
Total
West South Steam
Central Combined Cycle
Turbines and Inter
nal Comb.
Total
Mountain Steam
Combined Cycle
Turbines and Inter
nal Comb.
Total
Pacific Steam
Combined Cycle
Turbines and Ir
nal Comb.
Total
National Steam
Combined Cycle
Turbines and Inter
nal Comb.
Total
(in 1015 Btu)
Reference Case II
1.2 Ibs.
0.271
0.012
•v
0.125
0.408
0.506
0.012
0.380
0.900
0.509
0.017
r-
0.609
1.135
0.274
0.007
r-
0.487
0.768
0.081
r-
0.285
0.366
0.090
0.002
ir-
0.271
0.363
1.509
0.028
>r-
0.206
1.743
0.126
0.015
jr-
0.105
0.246
0.645
0.482
Br-
0.185
1.312
4.500
0.575
er-
2.166
7.241
90%
0.271
0.012
0.157
0.440
0.508
0.012
0.393
0.913
0.767
0.029
0.736
1.532
0.399
0.007
0.681
1.087
0.084
0.334
0.418
0.140
0.003
0.341
0.484
1.513
0.028
0.214
1.755
0. 122
0.015
0.095
0.232
0.654
0.514
0.225
1.393
4.458
0.620
3.176
8.254
80*
0.271
0.012
0.157
0.440
0.508
0.012
0.385
0.905
0.748
0.019
0.736
1.503
0.399
0.007
0.681
1.087
0.084
0.332
0.416
0.114
0.003
0.287
0.404
1.513
0.028
0.214
1.755
0.133
0.015
0.119
0.267
0.654
0.545
0.225
1.424
4.424
0.641
3.136
8.201
0.5 Ibs.
0.271
0.012
0.157
0.440
0.508
0.012
0.395
0.915
0.767
0.029
0.736
1.532
0.399
0.007
0.681
1.087
0.084
0.335
0.419
0.146
0.003
0.355
0.504
1.513
0.028
0.214
1.755
0.126
0.015
0.105
0.246
0.654
0.545
0.225
1.424
4.468
0.651
3.203
8.322
-------
a
-------
TABLE OF CONTENTS
APPENDIX E EXHIBITS
TABLES FOR ANSPS OF 0.5 LB. SO /MMBTU (Revised)
Reference Case II
Regional Coal Production by Sulfur Content
in Tons
in Quadrillion Btu's
Regional Coal Production by Mining Method
Coal Distribution
in 1985
in 1990
in 1995
Mine Mouth Prices
Delivered Coal Prices to Electric Utilities by Coal Type
Electric Generating Capacity by Region
Scrubber Capacity by Region
Utility Coal Consumption by Sulfur Content
Oil and Gas Consumption by Plant and by Region
Exhibit
Numbers
E-1
E-2
E-3
E-4
E-5
E-6
E-7
E-8
E-9
E-10
E-11
E-12
ICF INCORPORATED
-------
EXHIBIT E-1
REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE
STANDARD OF 0.5 LB. SO/MMBTU (REVISED)
(10 tons)
Region
1985
1990
1995
Northern Appalachia
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Central Appalachia
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Southern Appalachia
Metallurgical
Medium Sulfur
Low Sulfur
Total
17.6
62.5
92.8
0.3
173.3
145.5
9.3
41.5
18.0
214.3
4.3
11.0
4.3
19.7
19.5
97.3
137.1
0.4
254.3
146.3
3.1
28.7
17.1
195.2
4.7
4.7
5.0
14.4
22.8
102.7
152.4
0.3
278.3
150.4
19.9
17.6
188.0
6.6
2.2
6.7
15.5
Midwest
High Sulfur
Medium Sulfur
Low Sulfur
Total
157.7
82.7
0.5
240.9
250.3
95.5
0.6
346.4
278.9
97.4
1.0
377.3
Central West
Metallurgical 0.5 0.3 0.6
High Sulfur 5.3 3.6 5.2
Medium Sulfur 1.6 1.9 3.4
Low Sulfur 0.2 0.2 0.6
Total 7.5 6.1 9.8
Eastern Northern Great Plains
High Sulfur 0.3 0.3 4.0
Medium Sulfur 18.7 31.1 52.6
Low Sulfur 4.7 7.4 11.0
Total 23.8 38.9 67.6
Western Northern Great Plains
Medium Sulfur 155.4 275.2 406.5
Low Sulfur 244.8 400.4 583.3
Total 380.2 675.6 989.8
Gulf
Medium Sulfur
Total
63.9
63.9
103.0
103.0
93.0
93.0
Rocky Mountains
Metallurgical
Medium Sulfur
Low Sulfur
Total
3.8
10.0
17.6
31.5
4.2
10.1
24.2
38.6
1.7
10.6
23.8
36.1
Southwest
Medium Sulfur
Low Sulfur
Total
15.2
31.2
46.4
16.8
58.1
74.8
5.9
97.1
103.0
Northwest
Medium Sulfur
Total
6.2
6.2
7.2
7.2
3.7
3.7
National
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
171.7
235.2
498.9
301.8
1,207.6
175.0
354.6
711.3
513.6
1,754.5
182.1
391.0
847.5
741.6
2,162.2
-------
EXHIBIT E-2
REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD
OF 0.5 LB. SO /MMBTU (REVISED)
(1015 BTU)
Region
Northern Appalachia
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Central Appalachia
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Southern Appalachia
Metallurgical
Medium Sulfur
Low Sulfur
Total
Midwest
High Sulfur
Medium Sulfur
Low Sulfur
Total
Central West
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
Eastern Northern Great Plains
High Sulfur
Medium Sulfur
Low Sulfur
Total
Western Northern Great Plains
Medium Sulfur
Low Sulfur
Total
Gulf
Medium Sulfur
Total
Rocky Mountains
Metallurgical
Medium Sulfur
Low Sulfur
Total
Southwest
Medium Sulfur
Low Sulfur
Total
Northwest
Medium Sulfur
Total
National
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
1985
1990
1995
0.5
1.5
2.5
0.0
4.5
4.0
0.2
1.1
0.5
5.8
0.1
0.3
0.1
0.5
3.5
2.0
0.0
5.5
0.0
0.1
0.0
0.0
0.2
0.0
0.2
0.1
0.3
2.B
4.1
6.8
1.1
1.1
0.1
0.2
0.4
o.a
0.3
0.7
1.1
0.1
0.1
4.7
5.4
10.5
5.8
26.5
0.5
2.5
3.6
0.0
6.7
4.0
0.1
0.8
0.4
5.3
0. 1
0.1
0.1
0.4
5.6
2.3
0.0
7.8
0.0
0. 1
0.1
0.0
0.1
0.0
0.4
0.1
0.5
4.6
7.1
11.9
1.7
1.7
0.1
0.2
0.6
0.9
0.4
1.3
1.7
0.1
0.1
4.B
8.2
14.5
9.7
37.2
0.6
2.7
3.9
0.0
7.3
4.2
-
0.5
0.4
5.1
0.2
0.1
0.2
0.4
6.2
2.3
0.0
8.6
0.0
0.1
0.1
0.0
0.2
0.1
0.7
0.1
0.9
7. 1
10.2
17.3
1.5
1.5
0.0
0.3
0.6
0.9
0.1
2.2
2.4
0.1
0.1
5.0
9.1
16.7
13.8
44.6
-------
EXHIBIT E-3
REGIONAL COAL PRODUCTION BY MINING METHOD
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE
STANDARD OF 0.5 LB. SO /MMBTU (Revised)
(ID6 tons)
Region
Northern Appalachia
Central Appolachia
Southern Appalachia
Midwest
Central West
Eastern Northern Great Plains
Western Northern Great Plains
Gulf
Rocky Mountains
Southwest
Northwest
National
Mining
Method
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
1985
31.7
141.7
173.3
32.5
161.8
214.3
7.6
12.1
v 19.7
56.4
184.5
240.9
5.2
2.3
7.5
23.8
-
23.8
378.6
1.6
380.2
63.9
-
63.9
13.7
17.7
31.5
36.6
9.8
46.4
6.2
-
6.2
656. 1
551.5
1,207.6
1990
13.0
241.3
254.3
14.2
181 .0
195.2
2.5
11.9
14.4
41.9
304.5
346.4
1.7
4.3
6.1
38.9
-
38.9
673.9
1.6
675.6
103.0
-
103.0
14.9
23.7
38.6
65.1
9.B
74.8
7.2
-
7.2
976.4
778.0
1,754.5
1995
2.9
275.3
278.3
5.8
182.2
188.0
-
15.5
15.5
28.8
348.5
377.3
-
9.8
9.8
67.6
-
67.6
986.4
3.4
9B9.8
93.0
-
93.0
14.6
21.6
36.1
85.9
17.2
103.0
3.7
-
3.7
1,288.6
873.5
2,162.2
-------
EXHIBIT E-4
1985 COAL DISTRIBUTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STAKDARD OF 0.5 lb.
SO /MMBTU (Revised)
(10 tons)
Eastern
Northern
New England 6.30
Middle Atlantic 93.75
South Atlantic 43.92
East North Central 29.14
East South Central
Total East 173.11
West North Central
West South Central
Mountain
Pacific ~
Total west
Central
Appalachia
3.50
24.29
105.91
65.51
12.93
212.14
0.86
0.88
0.40
-
2. 14
Southern Central
Appalachia Midwest West
-
6.62 25.24
136.28 0.24
13.06 53.10 0.02
19.68 214.62 0.26
23.25 3.23
3.00 3.71
-
0.24
26.25 7.18
Northern
Total Great
East Gulf Plains
9.80
118.04
181.69
231.17
79.11
619.81
27.34 - 23.75
7.59 63.89
0.40
0.24
35.57 - 23.75
Western
Northern
Great
Plains
-
4.81
39.35
77.27
53.15
174.58
72.83
52.92
64.06
11.63
201.44
Total
Plains Rockies Southwest Northwest West National
National
173.11
214.28
19.68
240.87
7.44 635.38 63.89 23.75
376.02
16.44
0.89
17.33
0.02
11.68
2.43
14. 11
31.44
16.28
29.73
46.01
46.01
6.17
6.17
6.17
4.81
39.35
93.71
54.04
191.91
96.60
133.09
111.64
14.06
335.39
9.80
122.85
221.04
324.88
133. 15
811.72
123.94
140.68
112.04
14.30
390.96
547.30 1,202.68
-------
EXHIBIT E-5
1990 COAL DISTRIBUTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD OF 0.5 LB.
SO /MMBTU (Revised)
(10 tons)
Northern Central Southern Central Total
Gulf
Eastern Western
Northern Northern
Great Great
Plains
Total
Plains Rockies Southwest Northwest West National
New England 19. 79
Middle Atlantic 112.98
South Atlantic 89.95
East North Central 31.19
East South Central
Total East 253.91
West North Central
West South Central
Mountain
Pacific
Total West
0.93
23.11
101 .98
59.18
8.09
193.29
0.92
0.86
0.07
-
1.85
- - - 20.72
- 136.09
1.06 62.07 - 255.06
177.07 - 267.44
13.38 81.66 - 103.13
14.44 320.80 - 782.44
22.22 2.93 25.87 - 38.92
3.40 2.47 6.73 103.01
0.70 -
0.34 0.34 -
25.62 5.74 33.64 103.01 38.92
21.53
61.61
163.52 17.67
77.30 0.89
323.96 18.56
103.53 4.18
91.73 - 28.35
107.23 11.90 45.81
49.14 3.94
351.61 20.02 74.16
21.53
61.61
181.19
78.19
342.52
146.63
223.09
164.94
7.17 60.25
7.17 594.91
20.72
157.67
316.67
448.63
181.32
1, 124.96
172.50
229.82
165.64
60.59
628.55
National
253.91
195. 14
14.44
346.42
5.74
816.08 103.01 38.92
675.59
38.58
74.16
7.17
937.43 1,753.51
-------
EXHIBIT E-6
1995 COAL DISTRIBUTION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD OF 0.5 LB.
SO /MMBTU (Revised)
(10 tons)
Central Southern Central Total
Eastern Western
Northern Northern
Great Great
Total
West National
Northern
Consuming Region Appalachia
Sew England 18.95
Kiddle Atlantic 115.83
South Atlantic 106.58
East North Central 36.59
East South Central
Total East 277.95
West North Central
West South Central
Mountain
Pacific
Total West
22. 33
92.42
63.76
6.54
185.05
0.96
0.97
1.03
2.96
0.24 55.66
207.68
15.29 93.31
15.53 356.65
17.23
3.25
20.48
West East Gulf Plains
18.95
138.16
254.9
0.56 308.59
115.15
0.56 835.18
5.20 23.39 - 67.56
1.87 6-09 93.00
- 1 03 ~
1.97 1.97
9.04 32.48 93.00 67.56
Plains Rockies southwest
26.90
68.10
238.91 13.23
85.69 0.89
419.60 14.12
152.84 8.83
162.39 - 48.54
147.95 10.80 54.50
107.03 2.39
570.21 22.02 103.22
26.90
68.10
252.14
86.58
433.72
229.23
303.93
213.25
3.66 113.08
3.66 855.83
18.95
165.06
323.00
560.73
201.72
1,268.90
252.62
310.02
214.28
115.05
888 . 3 1
National
277.95
188.01
15.53 355.69 9.60 867.66 93.00 67.56 989.81 30.85 103.22
3.66
1,289.55 2,157.21
-------
EXHIBIT E-7
MINE MOUTH PRICKS UNDER
ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD
OF 0.5 LB. SO /MMBTU (Revised)
S/106 Btu's
(1977 S'e)
1985 1990
1995
Region
Northern Appalnchla
Central Appalachia
Southern Appalachia
Midwest
Central West
East Northern Great
Plains
West Northern Great
Plains
Gulf
Rocky Mountains
Southwest
Northwest
National
WW« J> * J >"-"
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
0.89
1.02
1.40
0.88
1.11
1.36
1.19
1.34
0.83
1.11
1.38
0.95
1.17
1.24
0.41
0.41
0.44
—
0.42
0.57
0.36
~™
0.87
0.91
—
0.56
0.77
—
0.85
—
0.85
0.80
0.70
1.03
1.07
1.43
1.11
1.22
1.43
1.30
1.41
0.95
1. 14
1.42
1.06
1.24
1.27
0.41
0.41
0.46
—
0.42
0.53
0.54
~ ™
0.89
0.96
~
0.66
0.75
—
0.92
~~
0.98
0.78
0.64
.. 1.05
1.08
1.48
1.23
1.57
1.38
1.51
1.02
1 . 15
1.46
1.07
1.31
1.32
0.41
0.41
0.51
—
0.44
0.54
0.94
"
0.91
1.06
—
1.08
0.96
—
1.04
"
1.02
0.78
0.68
-------
EXHIBIT E-8
DELIVERED COAL PRICES TO UTILITIES SECTOR
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD
OF 0.5 LB.
SO /MMBTU (Revised)
($710 Btu's)
Region
Northeast
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Coal Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
1985
1990
1995
1.18
1.39
1.90
1.02
1.29
1.77
1.07
1.36
1.51
0.99
1.24
1.44
0.99
1.14
1.28
0.95
0.81
0.95
1.06
0.62
1.20
1.30
1.38
2.17
1.25
1.36
1.86
1.28
1.40
1.55
1.12
1.25
1.33
1.13
1.18
1.33
1.07
0.83
1.00
1.30
0.80
1.25
1.32
1.38
1.91
1.27
1.35
1.91
1.32
1.41
1.57
1.19
1.28
1.31
1.18
1.20
1.34
1.14
0.86
1.03
1.32
1.07
1.32
Mountain
High Sulfur
Medium Sulfur
Low Sulfur
0.64
0.74
0.70
0.80
0.88
0.82
Pacific
National
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
0.96
0.94
1.01
1.08
1.23
1.03
1.12
1.19
1.10
1.23
1.16
1.09
1.23
1.16
1.24
ICF INCORPORATED
-------
EXHIBIT E-9
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. SO /MMBTU (Revised)
Generation Capacity
(in GW)
1985
1990
1995
Average Capacity
Factor
1985
1990
1995
North East
Coal
Existing 4.0 4.0 4.0 0.67 0.57 0.47
NSPS - - - ~
ANSPS - 5.1 5.6 - 0.69 0.59
Total 4.0 9.1 9.6 0.67 0.64 0.54
Oil and Gas
Steam 7.6 7.6 7.6
Combined Cycle 0.4 0.4 0.4 -
Turbines 9.9 8.9 9.8 ^_ i_ i_
Total 17.9 16.9 17.8 0.42 0.25
Nuclear, Hydro, Other 8.3 12.6 22.0 0.52 0.66
Total 30.2 38.6 49.4 0.48 0.48
0.25
0.63
0.48
Mid-Atlantic
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines
Total
Nuclear, Hydro, Other
Total
25.7
3.8
2.4
31.9
15.6
0.4
18.9
34.9
28.6
25.7
3.8
12.4
41.9
15.6
0.4
23.5
39.5
33.4
25.7
3.8
13.4
42.9
15.6
0.4
28.0
44.0
53.2
0.59
0.69
0.67
0.61
-
-
-
0.23
0.61
0.57
0.56
0.64
0.59
-
-
-
0.21
0.63
0.52
0.40
0.63
0.54
-
-
-
0.20
0.63
95.4
114.8
140. 1
0.47 0.47
0.47
South Atlantic
Coal
Existing 47.1 47.1 47.1
NSPS 8.8 8.8 8.8
ANSPS 2.4 37.6 39.4
Total 58.3 93.5 95.3
Oil and Gas
Steam 22.6 20.5 22.1
Combined Cycle 0.6 0.6 0.6
Turbines 25.8 34.3 48.5
Total 49.0 55.4 71.2
Nuclear, Hydro, Other 34.3 44.5 98.4
Total 141.6 193.4 264.9
0.61
0.63
0.65
0.61
0.30
0.54
0.49
0.61
0.58
0.61
0.61
0.23
0.56
0.61
0.63
0.49
0.56
0.21
0.62
0.49 0.49
ICF INCORPORATED
-------
EXHIBIT E-9 (Cont'd)
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. SO2/MMBTU (Revised)
East North Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines
Total
Nuclear, Hydro, Other
Total
East South Central
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines
Total
Nuclear, Hydro, Other
Total
West North Central
Coal
Existing
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines
Total
Nuclear, Hydro, Other
Total
Generation Capacity
(in GW)
1985
63.6
14.8
1 .7
80.1
10.0
0.2
19.7
29.9
25.3
135.3
30.2
8.8
1.7
40.7
3.0
17.1
20. 1
18.2
79.0
18.5
16.8
1.0
36.3
3.8
0.1
13.1
17.0
9.2
1990
63.6
17.2
29.5
110.2
10.0
0.2
21.8
31.8
38.0
180.0
30.2
8.8
18.2
57.2
3.0
16.2
19.2
30.1
106.5
18.5
16.8
12.8
48.1
3.8
0.1
17.9
22.7
12.4
1995
63.6
17.2
55.4
136.2
10.0
0.2
38.4
48.6
51.9
236.7
30.2
8.8
25.8
64.8
3.0
24.4
27.4
51.6
143.8
18.5
16.8
30.4
65.7
3.8
0.1
26.0
29.9
12.4
Average Capacity
Factor
1985 1990
0.23
0.64
0.58
0.68
0.69
0.61
0.58
0.56
0.35
0.57
0.19
0.66
0.52 052
0.57
0.63
0.52
0.56
0.20 0.14
0.61 0.62
0.50 0.51
0.60
0.61
0.43
0.56 0.56
62.5
83.2
108.0
_ _
0.14 0.12
0.54 0.57
0.44 0.44
1995
0.57
0.55
0.59
0.58
0.52
0.58
0.63
0.48
0.55
0.14
0.65
0.51
0.60
0.61
0.51
0.56
0.12
0.57
0.44
ICF INCORPORATED
-------
EXHIBIT E-9 (Cont'd)
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. SO2/MMBTU (Revised)
Generation Capacity
(in GW)
1985
1990
1995
Average Capacity
Factor
1985 1990
1995
West South Central
0.64
0.65
0.65
0.65
Coal
Existing 2.3 2.3 2.3 0.64 0.64
NSPS 22.4 22.4 22.4 0.65 0.65
ANSPS 12.5 32.8 54.4 0.65 0.65
Total 37.2 57.5 79.1 0.65 0.65
Oil and Gas
Steam 57.3 57.3 57.3
Combined Cycle 1.4 1.4 1.4
Turbines 3.1 11.4 33_.6 _I_ __^_
Total 61-8 70.1 92.3 0.26 0.20
Nuclear, Hydro, Other 10.4 15.6 15.6 0.54 0.57
Total 109.4 143.2 187.0 0.42 0.42 0.42
Mountain
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines
Total
Nuclear, Hydro, Other
Total
11.9
9.1
2.5
23.5
4.3
0.5
2.9
7.7
9.4
11.9
10.5
9.5
31.9
4.3
0.5
4.7
9.5
13.9
11.9
12.0
16.2
40.1
4.3
0.5
8.3
13. 1
13.9
0.66
0.66
0.68
0.66
-
-
-
0.17
0.46
0.65
0.64
0.68
0.66
-
—
-
0.16
0.50
0.64
0.64
0.66
0.65
-
~
—
0. 17
0.50
40.6
55.3
67. 1
0.52 0.53
0.53
Pacific
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines
Total
Nuclear, Hydro, Other
Total
1.3
0.5
7.0
8.8
21.6
7.9
12.1
41.6
53.7
1.3
0.5
8.5
10.3
21.2
8.3
14.6
44. 1
63.0
1.3
0.5
22.2
24.0
21 .6
8.3
21.6
51.5
72.9
0.70
0.70
-
0.70
-
—
-
0.40
0.53
0.70
0.70
0.70
0.70
-
—
-
0.33
0.55
0.70
0.70
0.70
0.70
-
—
—
0.30
0.57
104.1
117.4
148.4 0.48 0.48 0.49
ICF INCORPORATED
-------
EXHIBIT E-9 (Cont'd)
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. S02/MMBTU (Revised)
Generation Capacity
(in GW)
1985
1990
1995
Average Capacity
Factor
1985 1990
1995
National
Coal
Existing
NSPS
ANSPS
Total
Oil and Gas
Steam
Combined Cycle
Turbines
Total
Nuclear, Hydro, Other
Total
204.6
85.0
25.5
204.6
88.8
166.2
204.6
90.3
262.9
0.60
0.62
0.65
0.58
0.61
0.60
0.58
0.61
0.58
315.1
459.6
557.8
0.61 0.59
791.3 1,031.6 1,345.2
0.48 0.48
0.58
145.6
11.6
122.5
279.7
196.5
143.2
11.9
153.4
308.5
263.5
145.1
11.9
238.4
395.4
392.0
-
0.28
0.56
-
0.22
0.59
-
0.20
0.61
0.48
ICF INCORPORATED
-------
EXHIBIT E-10
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. SO2/MMBTU (Revised)
Region
1985
1990
1995
New England
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Middle Atlantic
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.7
7.7
8.9
1.7
-
88.0
88.0
-
80.0
80.0
-
70.4
70.4
-
17.0
11.8
2.8
2.4
88.0
84.0
95.0
100.0
81.4
80.0
80.0
90.0
71.9
67.2
76.0
90.0
2.6
5. 1
96.8
90.5
100.0
86.6
80.0
90.0
84.0
72.4
90.4
27.0
11.8
2.8
12.4
89.5
85.1
95.0
92.5
84.1
80.0
80.0
89.0
75.4
68. 1
76.0
82.3
3.3
5.6
95.
91.5
98.4
86.
80.0
90.0
82.
73.2
88.6
28.
11.8
2.8.
13.4
90.
87.1
95.0
91.8
84.
80.0
80.0
88.8
75.
69.7
76.0
81 .5
8
3
9
0
1
2
9
ICF
INCORPORATED
-------
EXHIBIT E-10 (Cont'd)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. S02/MMBTU (Revised)
Region
1985
1990
1995
South Atlantic
Capacity Scrubbed (in GW)
Existing
MS PS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
East North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
15.7
11.7
1.6
2.4
79.4
73.0
95.0
100.0
81.5
80.0
80.0
90.0
65.0
58.4
76.0
90.0
8.8
3.1
2.6
3.1
96.7
95.0
95.0
100.0
83.5
80.0
80.0
90.0
80.9
76.0
76.0
90.0
51.9
12.7
1.6
37.6
90.5
69.4
95.0
97.5
92.6
80.0
80.0
97.5
55.1
55.5
76.0
54.1
35.2
3.1
2.6
29.5
75.1
95.0
97.0
71.1
83.9
80.0
80.0
84.6
63.3
76.0
77.6
60.7
52.
12.3
0.5
39.4
91.
70.6
95.0
98.0
87.
80.0
80.0
90.0
80.
56.5
76.0
88.2
61.
3.1
2.5
55.4
70.
95.0
95.0
67.7
83.
80.0
80.0
83.9
58.
76.0
76.0
56.8
2
5
5
6
0
2
5
6
ICF INCORPORATED
-------
EXHIBIT E-10 (Cont'd)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. SO2/MMBTU (Revised)
1985
1990
1995
East South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
West North Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
6.9
2.9
2.3
1.7
95.2
95.0
92.0
100.0
82.5
80.0
80.0
90.0
78.8
76.0
74.0
90.0
2.4
1.2
0.2
1.0
78.3
100.0
95.0
49.0
90.5
100.0
80.0
81.2
72.9
100.0
76.0
39.8
22.2
2.9
1.2
18.1
85.4
95.0
99.9
82.9
86.7
80.0
80.0
88.2
73.8
76.0
79.9
73.1
14.0
1.2
-
12.8
59.8
100.0
-
56.0
89.4
100.0
—
80.0
49.5
100.0
-
44.8
29.
2.9
1.2
25.7
92.
95.0
97.7
92.0
86.
80.0
80.0
87.8
80.
76.0
78.1
80.7
31.
1.2
—
30.4
64.
100.0
—
63.0
8
5
7
1
6
4
80.7
100.0
~
80.0
52.3
100.0
—
50.4
ICF INCORPORATED
-------
EXHIBIT E-10 (Cont'd)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. SO /MMBTU (Revised)
Region
1985
1990
1995
West South Central
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
Mountain
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
18.1
1.1
4.5
12.5
84.6
80.0
80.0
86.8
85.4
80.0
80.0
87.8
72.4
64.0
64.0
76.2
12.6
1.0
9.1
2.5
88.6
100.0
86.1
93.1
83.1
100.0
80.0
87.5
73.8
100.0
68.8
81.5
38.4
1. 1
4.5
32.8
88.4
80.0
80.0
89.8
84.6
80.0
80.0
85.1
74.6
64.0
64.0
76.4
21.0
1.0
10.5
9.5
88.6
100.0
85.7
90.8
83.1
100.0
80.0
84.7
73.8
100.0
68.6
76.9
59.
1.1
4.5
54.3
87.
80.0
80.0
88.8
82.
80.0
80.0
83.1
72.
64.0
64.0
73.8
30.
1.0
12.8
16.2
88.
100.0
85.1
91.0
83.
100.0
80.0
85.7
74.
100.0
68.1
77.9
9
9
8
9
0
8
7
4
ICF
INCORPORATED
-------
EXHIBIT E-10 (Cont'd)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW
SOURCE PERFORMANCE STANDARD OF 0.5 LB. SO /MMBTU (Revised)
Region
Pacific
Capacity Scrubbed (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
National
1985
1990
1995
Capacity Scrubbed (in GW) 83.3
Existing 34.7
NSPS 23.1
ANSPS 25.5
225.9
36.5
23.1
166.3
322.3
36.8
22.6
262.9
Average Percent Scrubbed 85.8
Existing 80.9
NSPS 88.3
ANSPS 90.3
84.5
80.1
88.4
84.9
81.1
83.9
86.9
80.2
Average Removal Efficiency 82.5
Existing 80.0
NSPS 80.0
ANSPS 88.3
84.6
80.0
80.0
86.2
83.8
80.0
80.0
84.7
Average Percent Removal
Existing
NSPS
ANSPS
70.9
64.7
70.6
79.7
71.5
64. 1
70.7
73.2
67.9
67.1
69.5
67.9
ICF
INCORPORATED
-------
EXHIBIT E-11
UTILITY COAL CONSUMPTION UNDER ALTERNATIVE NEW SOURCE
,/MMBTU (Revised)
PERFORMANCE STANDARDS OF 0.5 LB. SO /
(10 Btu's)
Region
Coal Type
1985
1990
1995
Northeast
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mountain
Pacific
National
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
0.111
0.029
0.101
0.241
0.377
1.066
0.327
1.771
0.783
1.629
0.617
3.029
1.367
1.838
1 .025
4.230
0.910
0.752
0.485
2.147
0.512
0.819
0.512
1.842
0.117
1.352
0.623
2.092
-
0.447
0.945
1.392
-
0.038
0.070
0.103
4. 176
7.971
4.706
0.395
0.081
0.032
0.508
0.520
1.332
0.342
2.194
1.873
2.382
0.529
4.785
1.806
1.850
1.856
5.512
1.322
0.858
0.618
2.798
0.469
1.085
0.839
2.393
0.093
2.568
0.592
3.254
-
0.827
1 .013
1.840
-
0.031
0.585
0.616
6.479
11.013
6.407
0.020
0.022
-
0.043
0.409
1.399
0.275
2.083
0.567
2.315
1.649
4.530
2.062
1.885
2.907
6.853
1.515
0.808
0.742
3.064
0.439
1.659
1.199
3.298
0.075
3.827
0.568
4.469
-
1.119
1.183
2.302
-
0.038
1.402
1 .439
6.465
13. 193
8.849
Total 16.852 23.899 28.507
-------
EXHIBIT E-12
OIL AND GAS CONSUMPTION BY PLANT AND BY REGION
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE OF 0 5 LB.
SO /MMBTU (Revised)
(10 Btu
Region
Northeast Steam
Combine Cycle
Turbines
Total
Mid Atlantic Steam
Combine Cycle
Turbines
Total
South Atlantic Steam
Combined Cycle
Turbines
Total
East North Central Steam
Combined Cycle
Turbines
Total
East South Central Steam
Combined Cycle
Turbines
Total
West North Central Steam
Combined Cycle
Turbines
Total
west South Central Steam
Combined Cycle
Turbines
Total
Mountain Steam
Combined Cycle
Turbines
Total
Pacific Steam
Combined Cycle
Turbines
Total
National Steam
Combined Cycle
Turbines
Total
•s)
1985
0.41
0.02
0.27
0.70
0.50
0.01
0.34
0.85
0.96
0.03
0.46
1.45
0.32
0.01
0.41
0.74
0.09
~
0.32
0.41
0.07
—
0.17
0.24
1.50
0.02
0.02
1.54
0.09
0.02
0.30
0.41
0.89
0.40
0.14
1.43
4.83
0.51
2.43
7.77
1990
0.27
0.01
0.13
0.41
0.51
0.01
0.33
0.85
0.70
0.03
0.53
1.25
0.30
0.01
0.34
0.65
0.08
--
0.19
0.28
0.08
—
0.20
0.28
1.29
0.02
0.07
1.36
0.09
0.01
0.05
0.16
0.68
0.40
0.14
1.22
4.02
0.49
1.98
6.47
1995
0.27
0.01
0.16
0.44
0.51
0.01
0.39
0.91
0.74
0.02
0.71
1.47
0.40
.01
0.68
1.09
0.08
—
0.32
0.40
0.10
—
0.29
0.39
1.50
0.03
0.21
1.74
0.12
0.02
0.09
0.23
0.66
0.35
0.23
1.24
4.38
0.45
3.08
7.91
-------
Q.
-------
TABLE OF CONTENTS
APPENDIX F EXHIBITS
TABLES FOR ANSPS OF 0.8 LB. SO^MMBTU
Regional Coal Production by Sulfur Content
in tons
in quadrillion Btus
Regional Coal Production by Mining Method
Coal Distribution
in 1985
in 1990
in 1995
Mine Mouth Prices
Delivered Coal Prices to Electric Uitlies Sector
Electric Generating Capacity by Region
Scrubber Capacity by Region
Utility Coal Consumption by Sulfur Content
Oil and Gas Consumption by Pland and by Region
Exhibit Number
F-1
F-2
F-3
F-4
F-5
F-6
F-7
F-8
F-9
F-10
F-11
F-1 2
ICF INCORPORATED
-------
EXHIBIT F-1
REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD OF
0.8 LB. SO /MMBTU
(106 Tons)
Region
Northern Appalnchia
Central Appalachia
Southern Appalachia
Midwest
Coal Type
Metallurgical
High Sulfur
Medium
Low Sulfur
Total
Metallurgical
High Sulfur
Medium
Low Sulfur
Total
Metallurgical
High Sulfur
Low Sulfur
Total
Metallurgical
High Sulfur
Low Sulfur
Total
1985
Reference
Case I S II
17.600
56.983
94.166
.420
169.170
146.282
9.312
41.466
18.030
215.090
4.348
11.013
4.320
19.681
17.600
56.983
.480
236.145
1990
Reference
Case I
18.761
62.418
107.178
.353
188.711
145.596
3.104
27.581
16.943
193.224
4.669
5.217
5.040
14.927
18.761
62.418
.640
285.974
1990
Reference
Case II
20.179
71.675
115.420
.353
207.628
147.183
3.104
27.981
16.943
195.211
5.269
4.727
5.040
15.037
20.179
71.675
.640
300.810
Central West
Eastern Northern
Great Plains
Western Northern
Great Plains
Gulf
Rocky Mountains
Southwest
Northwest
National
Metallurgical
High Sulfur
Medium
Low Sulfur
Total
Metallurgical
High Sulfur
Low Sulfur
Total
Metallurgical
Low Sulfur
Total
Low Sulfur
Total
Metallurgical
Medium
Low Sulfur
Total
Medium
Low Sulfur
Total
Medium Sulfur
'Total
Metallurgical
High Sulfur
Medium
Low Sulfur
Total
.450
5.256
1.575
.240
.337
3.620
1.744
.240
.337
3.620
1.744
.320
7.521
.341
21.071
7.440
28.852
150.166
244.463
394.630
63.821
63.821
3.782
10.026
16.773
30.581
15.166
29.511
44.677
6.168
6.168
172.462
225.067
497.129
321.677
1,216.334
5.940
.341
33.438
9.020
42.800
200.186
458.549
658.736
103.007
103.007
4.202
10.102
28.179
42.483
6.020
.341
34.354
11.440
46.135
222.926
557.140
780.067
103.007
103.007
4.202
11.702
31.945
47.849
41.154 16.766
/ 16.766 54.831
57.920 71.597
6.168 6.168
6.168 6.168
173.565 177.170
265.329 285.366
600.874 638.337
560.119 678.652
1,599.888 1,779.526
-------
EXHIBIT F-2
REGIONAL COAL PRODUCTION BY SULFUR CONTENT
UNDER ALTERNATIVE NEW SOURCE PERFORMANCE STANDARD OF
0.8 LB. SO /MMBTU
(1015 Tons)
Region
Northern Appalachia
Coal Type
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
1985
Reference
Case I s II
.473
1.380
2.487
.011
4.351
1990
Reference
Case I
.505
1.590
2.832
.009
4.936
1990
Reference
Case II
.543
1.839
3.046
.009
5.436
Central Appalachia
Metallurgical
High Sulfur
Medium Sulfur
Low Sulfur
Total
4.039
.233
1.074
.450
5.797
4.020
.078
.731
.423
5.252
4.063
.078
.742
.423
5.306
Southern Appalachia
Metallurgical
Medium Sulfur
Low Sulfur
Total
.119
.281
.109
.509
.128
.135
.127
.390
.144
.122
.127
.393
Midwest
High Sulfur
Medium Sulfur
Low Sulfur
Total
3.434
1.953
.011
5.397
4.334
2.117
.014
6.446
4.581
2.213
.014
6.808
Central West
Metallurgical
High Sulfur
Medium
Low Sulfur
Total
.012
.119
.043
.006
.180
.009
.080
.048
.006
.142
.009
.080
.048
.008
.144
Eastern Northern
Great Plain*
High Sulfur
Medium Sulfur
Low Sulfur
Total
.005
.281
.098
.383
.005
.444
.119
.568
.005
.456
.151
.612
Western Northern
Great Plains
Medium Sulfur
Low Sulfur
Total
2.669
4.392
7.061
3.533
8.060
11.593
3.922
9.764
13.686
Gulf
Low Sulfur
Total
1.050
1.050
1.694
1.694
1.694
1.694
Rocky Mountains
Metallurgical
Medium Sulfur
Low Sulfur
Total
.100
.246
.396
.742
.111
.248
.675
1.035
.111
.287
.768
1.166
Southwest
Medium Sulfur
Low Sulfur
Total
.329
.685
1.015
.362
.955
1.317
.362
1.274
1.636
Northwest
Mddium Sulfur
Total
.100
.100
.100
.100
.100
.100
Northern Appalachia
Metallurgical
High Sulfur
Medium
Low Sulfur
Total
4.744
5.170
10.513
6.157
26.585
4.773
6.086
12.245
10.368
33.492
4.870
6.582
12.992
12.537
36.982
-------
EXHIBIT F-3
COAL PRODUCTION BY MINING METHOD UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
(10 Tons)
Reqion
Northern Appalachia
Central Appalachia
Southern Appalachia
Midwest
Central West
Eastern Northern Great Plains
Western Northern Great Plains
Gulf
Rocky Mountains
Southwest
Northwest
National
1985
Mining Reference
Method Cases I S. II
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
Surface
Deep
Total
31.683
137.487
169.170
32.524
182.566
215.090
7.555
12.126
19.681
53.173
182.972
236.145
5.241
2.280
7.521
28.852
28.852
393.036
1 .594
394.630
63.821
63.821
13.716
16.865
30.581
34.920
9.758
44.677
6.168
6.168
670.687
545.647
1,216.334
1990
Reference
Case I
10.560
178.151
188.711
14. 174
179.051
193.224
2.518
12.409
14.927
33.190
252.784
285.974
1.747
4.193
5.940
42.800
42.800
657.120
1.594
658.736
103.007
103.007
14.916
27.567
42.483
45.064
12.855
57.920
6.168
6.168
931.284
668.604
1,599.888
1990
Reference
Case II
10.560
197.068
207.628
14.174
181 .037
195.211
2.518
12.519
15.037
34 . 389
266.420
300.810
1.747
4.273
6.020
46.135
46.135
778.473
1 .594
780.067
103.007
103.007
16.516
31.333
47.849
53.767
17.829
71.597
6.168
6.168
1,067.454
712.073
1,779.526
ICF
INCORPORATED
-------
EXHIBIT F-4
1985 COAL DISTRIBUTION UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
(106 tons)
SUPPLY REGION
Central Total
Eastern Western
Northern Northern
Great Great
Total
CONSUMING REGION Appalachia Appalachia Appalachia Midwest West Bast Gulf Plains Plains Rockies Southwest Northwest West National
New England 6.26
Middle Atlantic 93.15
South Atlantic 42.07
East North
Central 27.36
East South
Central -
TOTAL EAST 168.84
West North
Central
West South
Central
Mountain —
Pacific -
TOTAL WEST
3.50
24. 17
108.06
65.56
11.65
212.94
0.86
0.88
0.40
-
2.14
9.76 -
117.32
6.62 26.09 - 182.84
119.34 0.24 212.50
13.06 67.74 - 92.45
19.68 213.17 0.24 614.87
19.99 5.18 26.03 - 28.85
3.00 1.57 5.45
- - - 0.40
0.24 0.24
22.99 6.99 32.12 63.82 28.85
_
5.81
40.57
86.03 14.13
55.19 0.89
187.60 15.02
69.92 2.32
56.07 - 16.28
69.39 10.82 28.05
11.63 2.43
207.06 15.57 44.33
-
5.81
40.57
100.16
56.08
202.62
101.14
136.17
108.26
6.17 20.23
6.17 365.80
9. .76
123. 13
223.41
3 1 2 . 66
148.53
817.49
127. 17
141.62
1 08 . 66
20.47
397.92
NATIONAL
168.81
214.08
19.68
236.16 7.23 646.99 63.82 28.85
394.66 30.59
44.33
6.17
568.42 1,215.41
-------
EXHIBIT F-5
1990 COAL DISTRIBUTION UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
FOR REFERENCE CASE I
(10 tons)
SUPPLY REGION
Consuming Region
New England
Middle Atlantic
South Atlantic
East North
Central
East South
Central
TOTAL EAST
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Northern Central
Appalachia Appalachia
14.60 0.93
96.70 22.21
48.27 99.72
28.74 60.39
8.09
188.31 191.34
0.92
0.86
0.09
-
1 .87
Southern Central Total
Appalachia Midwest West East
- 15.53
- - - 118.91
1.54 36.22 0.02 185.77
165.79 0.24 255.16
13.38 60.46 - 81.93
14.92 262.47 0.26 657.30
20.54 3.54 25.00
3.00 1.71 5.57
0.09
0.37 0.31
23.54 5.56 30.97
Eastern Western
Northern Northern
Great Great
Gulf Plains Plains
-
48.77
100.46
140.71
80.13
370.07
42.80 85.43
103.01 - 79.75
101.85
21.63
103.01 42.80 288.66
Total
Rockies Southwest Northwest West
_
48.77
100.46
13.70 - - 154.41
0.89 - - 81.02
14.59 - - 384.66
5.82 - - 134.05
22.08 - 204.84
11.68 34.97 - 148.50
10.39 - 6.17 38.19
27.89 57.05 6.17 525.58
National
15.53
167.68
286.23
409.57
162.95
1,041.96
159.05
210.41
148.59
38.50
556.55
NATIONAL
188.31
193.21
14.92
286.01 5.82 688.27 103.01 42.80
658.73 42.48
57.05
6.17
910.24 1,598.51
-------
EXHIBIT F-6
1990 COAL DISTRIBUTION
UNDER ALTERNATIVE HEW SOURCE PERFORMANCE STANDARDS OF 0.6 ~i. SC2/MMBTU
FOR REFERENCE CASE II
(10 tons)
Eastern Wester-
Northern Nortr.err.
Great Great
CONSUMING REGION Apoalachia
Sev England 14.6C
Kiddle Atlantic 101.57
South Atlantic 57. 11
East North
Central 28.74
East South
Central
TOTAL EAST 207.24
West North
Central
West South
Central
Mountain
Pacific
TOTAL WEST
Appalachia
0.
22.
103.
59.
7.
193.
0.
0.
0.
-
1.
93
21
56
12
50
32
92
86
09
87
Appalachia Midwest West East Gulf Plains
20.
123.
1.05 47.75 0.02 207.
168.14 0.32 256.
13.98 60.70 - 82.
15.03 276.59 0.34 692.
21.24 3.54 25.
3.00 1.71 5.
0.
0.31 0.
24.24 5.56 31.
75 -
78 -
59 -
32 -
18 -
52 -
70 - 46. 14
57 103.01
09 -
31 -
67 103.01 46.14
Plair.i nOTkies Southwest
-
77.53
101 .12
165.23 11.30
103.38 0.89
467.86 12.69
96. 92 5.14
81.97 - 35.16
105.86 12.80 34.75
27.47 17.21
312.22 35. 15 69.91
Northwest West National
20.
--.53 201.
•.:i.22 • 310.
•,;7.;i 453.
i;4.77 136.
430.55 1,173.
K3.20 173.
22C.14 225.
153.41 153.
S.i7 I-..-- 51.
6.17 572.60 604.
75
31
71
35
95
07
90
71
50
16
27
KATIONAL
207.24
195.19
15.03
300.83 5.90 724.19 103.01 46.14 409.14 47.84
69.91
6.17 1,053.15 1,777.34
-------
EXHIBIT F-7
MINE MOUNTH PRICES UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
$/106 BTU's (1977 $'s)
Re_yi on _
Northern Appalachia
Central Appalachia
Southern Appalachia
Midwest
Central
Eastern Northern
Great Plains
Western Northern
Great Plains
Coal Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
1985
Reference
Cases I & II
0.87
1.02
1.42
0.85
1.12
1.37
1.35
1.44
0.81
1.11
1.38
0.91
1.17
1.24
0.41
0.41
0.48
0.43
0.57
1990
Reference
Case I
0.97
1.05
1.43
1.07
1.21
1.42
1.36
1.40
0.90
1.13
1.42
1.00
1.22
1.26
0.41
0.41
0.49
0.41
0.54
1990
Reference
Case II
1.00
1.06
1.45
1.08
1.22
1.43
1.30
1.41
0.92
1. 14
1.43
1.01
1.23
1.28
0.41
0.41
0.50
0.41
0.55
Gulf
Rocky Mountains
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
0.36
0.87
0.90
0.52
0.88
1.00
0.56
0.90
1.05
Southwest
High Sulfur
Medium Sulfur
Low Sulfur
0.56
0.78
0.61
0.80
0.63
0.82
Na tional
Na t.ional
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
0.85
0.83
0.80
0.69
0.90
0.92
0.78
0.64
0.90
0.94
0.78
0.65
-------
EXHIBIT F-8
DELIVERED COAL PRICES TO UTILITIES UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO /MMBTU
$/106 BTU's (1977 $'s)
Region
Northeast
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mountain
Pacifi c
National
Coal Type
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
High Sulfur
Medium Sulfur
Low Sulfur
1985
Reference
Cases I & II
1.13
1.85
1.92
.95
1.32
1.81
1.04
1.39
1.51
0.96
1.24
1.40
0.97
1.15
1.28
0.94
0.80
1.00
0.83
0.60
1.21
0.62
0.74
1.00
0.94
0.98
1.10
1.23
1990
Reference
Case I
1.26
1.36
1.99
1. 19
1.35
1.49
1.18
1.40
1.50
1.07
1.23
1.37
1.07
1.17
1.28
1.02
0.80
1.01
1.03
0.68
1.26
0.59
0.79
1.26
1.23
1.10
1.09
1.27
1990
Reference
Case II
1.28
1.38
2.20
1.20
1.35
1.43
1.25
1.41
1.47
1.08
1.23
1.37
1.08
1.17
1 .33
1.03
0.81
1.05
1.05
0.71
1.30
0.66
0.81
1.33
1. 19
1.14
1.10
1.29
ICF
INCORPORATED
-------
EXHIBIT F-9
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO /MMBTU
Generation Capacity (in GW)
New England
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
Total
Mid-Atlantic
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
o
Tl
I
31
•a
O
30
3
o
1985
Reference
Cases I & II
'4.0
—
4.0
7.6
0.4
9.8
17.7
8.3
30.1
25.7
3.8
2.5
32.0
15.6
0.4
18.9
34.9
27.6
1990
Reference
Case I
4.0
2.4
6.4
7.6
0.4
8.3
16.2
12.5
35.1
25.7
3.8
12. 1
41.6
15.6
0.4
21.5
'37.5
32.9
1990
Reference
Case II
4.0
4.9
8.9
7.6
0.4
8.9
16.9
12.6
38.4
25.7
3.8
23.5
53.0
15.6
0.4
23.5
39.5
33.4
Total
94.3
111.9
125.8
1985
Reference
Cases I & II
.665
Average Capacity Factor
1990
Reference
Case I
.627
.694
1990
Reference
Case II
.565
.690
.665
.652
.634
.415
.517
.477
.600
.691
.666
.616
,255
.671
.475
.578
.638
.644
.063
.251
.663
.476
.567
.577
.669
.613
.233
.610
.473
.211
.641
.483
.210
.633
.492
-------
EXHIBIT F-9 (Continued)
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
Generation Capacity (in GW)
South Atlantic
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
Total
East North Central
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
o
I
3D
•0
i
S
O
1985
Reference
Cases I & II
47. 1
8.8
4.3
60.2
22.6
0.6
24.1
47.3
34.3
141.8
63.6
13.9
4.5
82.0
10.0
0.2
19.1
29.3
25.4
1990
Reference
Case I
47. 1
8.8
18.3
74.2
19.9
0.6
23.9
44.4
44.5
163.1
63.6
14.2
18.0
95.8
10.0
0.2
18.0
28.3
38.1
1990
Reference
Case II
47.1
8.8
30.8
86.7
20.5
0.6
29.8
51.0
44.5
182.2
63.6
16.2
30.9
110.7
10.0
0.2
21.2
31.4
38.1
Total
136.6
162.1
180.1
Average Capacity Factor
1985
Reference
Cases I & II
.630
.530
.563
1990
Reference
Case I
.589
.511
.631
.611
.590
1990
Reference
Case II
.583
.511
.61 1
.586
,300
.536
.489
.591
.568
.607
.588
.222
.562
.482
,563
.568
.555
.562
,217
.562
.477
.563
,569
.576
.568
.231
.641
.520
.192
.661
.521
.189
.661
.521
-------
EXHIBIT F-9 (Continued)
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE
MEW SOORCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
Generation Capacity (in GW)
East South Central
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
Total
West North Central
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines S Internal Combustion
Total
Nuclear, Hydro & Other
O
1985
Reference
Cases I & II
30.2
8.8
1.7
40.7
3.0
16.8
19.8
18.2
78.7
18.5
16.8
2.2
37.5
3.8
0. 1
12.1
16.0
9.2
1990
Reference
Case I
30.2
8.8
10.2
49.2
3.0
14.0
16.9
28.9
95.0
18.5
16.8
8.0
43.3
3.8
0.1
15.7
19.6
12.4
1990
Reference
Case II
30.2
8.8
8.3
57.3
3.0
16.0
19.0
30.1
106.3
18.5
16.8
13.1
48.4
3.8
0.1
17.8
21 .6
12.4
1985
Reference
Cases I & II
.585
.667
.663
Average Capacity Factor
1990
Reference
Case I
.560
.620
.497
1990
Reference
Case II
.570
.636
.515
.608
,558
.563
.196
.605
.504
.570
,575
.356
.560
.138
.625
.504
.563
.600
.438
.554
.137
.624
.504
.576
.611
.455
.556
Total
62.8
75.3
82.4
.121
.544
.446
.120
.571
.444
.119
.571
.444
3
o
-------
EXHIBIT F-9 (Continued)
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
Generation Capacity (in GW)
West South Central
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
Total
Mountain
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
o
1985
Reference
Cases I & II
2.3
22.4
12.6
37.3
57.3
1.4
3.1
61.7
10.4
109.4
11.9
8.9
2.1
22.9
4.3
0.5
2.8
7.6
9.4
1990
Reference
Case I
2.3
22.4
26.4
51.1
57.3
1.4
4.8
63.4
15.6
130.0
11.9
9.7
4.1
25.7
4.3
0.5
4.1
8.9
13.6
1990
Reference
Case II
2.3
22.4
32.8
57.5
57.3
1.4
11.4
70.0
15.6
143.0
11.9
10.0
5.4
27.3
4.3
0.5
4.9
9.7
13.9
I
a
I
o
Total
40.0
48. 1
50.9
1985
Reference
Cases I 6. II
.641
.650
.650
Average Capacity Factor
1990
Reference
Case I
.641
.650
.650
1990
Reference
Case II
.641
.650
.650
.649
.650
.650
.262
.542
.421
.654
,667
.699
.663
. 198
.578
.421
.638
.670
.683
.657
.198
.578
.421
.633
.666
.680
.654
.168
.458
.520
.163
.508
.523
.160
.504
.520
-------
EXHIBIT F-9 (Continued)
ELECTRIC GENERATING CAPACITY UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO2/MMBTU
Generation Capacity (in GW)
Pacific
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
Total
National
Coal
Existing
NSPS
ANSPS
Total
Oil & Gas
Steam
Combined Cycle
Turbines & Internal Combustion
Total
Nuclear, Hydro & Other
o
1985
Reference
Cases I & II
1.3
.5
_
1.8
21.6
8.5
12.1
42.2
53.7
97.8
204.6
83.8
29.9
318. 1
145.6
12.2
118.8
267.7
196.5
1990
Reference
Case I
1.3
.5
3.4
5.2
21.6
8.5
13.0
43.1
63.0
111.3
204.6
85.0
102.6
392.2
143.0
12.2
123.2
278.3
261.4
1990
Reference
Case II
1.3
.5
7.6
9.4
21.6
12.3
15.1
48.9
63.0
121.3
204.6
87.3
167.3
459.2
143.5
15.9
148.5
307.9
263.5
Total
3
3)
791.5
931.9
1,030.0
1985
Reference
Cases I s, II
.700
.700
Average Capacity Factor
1990
Reference
Case I
,537
.700
.700
1990
Reference
Case II
.696
.700
.700
.700
.659
.699
.412
.528
.481
,361
.553
.483
,363
.553
.488
.604
.616
.615
.608
.577
.611
.602
.591
.576
.611
.607
.594
.278
.560
.481
.221
.595
.482
.220
.593
.482
m
o
-------
EXHIBIT F-10
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS OF 0.8 LB. SO2/MMBTU
Region
1985 1990 1990
Reference Reference Reference
Case I & II Case I Case II
NEW ENGLAND
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Remocal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1.7 5.2 7.6
1.7 2.8 2.6
80.0
80.0
76.2
76.2
2.4
82.3
77.8
5.0
95.3 95.0
95.3 95.0 95.2
82.9
80.0
80.0
I
76.0
80.0
80.0
79.5
78.4
76.2
79.5
MIDDLE-ATLANTIC
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing.
NSPS
ANSPS
Average Remocal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
15.8
11.9
3.1
0.8
91.4
90.4
95.0
93.3
80.5
80.0
80.0
90.0
73.6
72.3
76.0
84.0
16.7
11.8
3.1
1.8
91.9
91.0
95.0
92.7
80.3
80.0
80.0
83.0
73.8
72.8
76.0
76.9
18.0
11.9
3.1
3.0
91.8
90.3
95.0
94.7
80.4
80.0
80.0
82.7
73.8
72.2
76.0
78.3
ICF
INCORPORATED
-------
EXHIBIT F-10 (Cont'd)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS OF 0.8 LB. S02/MMBTU
SOUTH ATLANTIC
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
EAST NORTH CENTRAL
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1985
Reference
Case I & II
15.1
13.2
1.6
0.3
75.9
73.1
95.0
96.3
80.2
80.0
80.0
90.0
60.9
58.5
76.0
86.7
9.2
3.1
5.1
1.0
95.4
96.8
95.0
93.3
81.1
80.0
80.0
90.0
76.3
77.4
76.0
74.6
1990
Reference
Case I
16.2
12.8
1.6
1.8
78.3
74.0
95.0
93.7
81.0
80.0
80.0
89.3
63.6
59.2
76.0
83.7
10.9
3.1
5.1
2.7
95.2
97.3
95.0
93.3
82.5
80.0
80.0
90.0
78.5
77.8
76.0
84.0
1990
Reference
Case II
28.0
13.6
1.6
12.8
82.9
71.7
95.0
93.3
84.9
80.0
80.0
89.9
70.6
57.4
76.0
83.9
12.01
3.1
5.1
3.8
94.9
96.8
95.0
93.3
83.2
80.0
80.0
90.0
75.9
77.4
76.0
74.6
ICF INCORPORATED
-------
EXHIBIT F-10 (Cont'D)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS OF 0.8 LB. SO2/MMBTU
EAST SOUTH CENTRAL
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
WEST NORTH CENTRAL
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
1985
Reference
Case I & II
6.2
2.9
2.8
.5
94.7
97.2
92.4
93.3
80.8
80.0
80.0
90.0
75.8
77.8
73.9
74.7
1.4
1.2
.2
99.3
100.0
95.0
80.0
80.0
80.0
79.4
80.0
76.0
1990
Reference
Case I
8.6
3.3
2.8
2.5
86.9
90.7
89.7
78.9
82. 1
80.0
80.0
89.3
71.3
72.6
71.8
68.9
1.4
1.2
.2
99.3
100.0
95.0
80.0
80.0
80.0
79.4
80.0
76.0
1990
Reference
Case II
8.9
2.9
3.2
2.8
87.2
97.2
72.8
93.3
83.1
80.0
80.0
89.9
69.8
77.8
58.2
74.7
1.4
1.2
.2
99.3
100.0
95.0
80.0
80.0
80.0
79.4
80.0
76.0
ICF INCORPORATED
-------
EXHIBIT F-10 (Cont'd)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS OF 0.8 LB. SO2/MMBTU
1985
Reference
Case I & II
1990
Reference
Case I
1990
Reference
Case II
WEST SOUTH CENTRAL
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
14.2
21.5
21.7
89.
80.
72.
1.1
4.5
8.6
2
80.4
80.4
95.0
8
80.0
80.0
81.3
1
64.3
64.3
77.2
1.1
4.5
15.9
91.1
80.4
80.4
94.9
80.5
80.0
80.0
80.7
73.4
64.3
64.3
76.6
1.1
4.5
16.1
91.1
80.4
80.4
94.8
80.5
80.0
80.0
80.7
73.4
64.3
64.3
76.6
MOUNTAIN
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
12.0
14.8
16.4
88
81
72
1.0
8.9
2.1
.5
100.0
85.7
, 95.0
.8
80.0
68.6
85.5
.5
80.0
68.6
85.5
1.0
9.7
4.1
89.0
100.0
85.3
95.0
82.8
80.0
68.2
85.5
73.8
80.0
68.2
85.5
1.0
10.0
5.4
89.8
100.0
86.0
95.0
83.3
80.0
68.8
85.5
75.0
80.0
68.8
85.5
ICF INCORPORATED
-------
EXHIBIT F-10 (Cont'd)
SCRUBBER CAPACITY UNDER ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS OF 0.8 LB. S02/MMBU
1985 1990 1990
Reference Reference Reference
Case I & II Case I Case II
PACIFIC
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
3.4
3.4
58.2
53.2
90.0
90.0
47.9
47.9
6.2
6.2
58.2
58.3
90.0
90.0
52.4
52.4
NATIONAL
Capacity Scrubber (in GW)
Existing
NSPS
ANSPS
Average Percent Scrubbed
Existing
NSPS
ANSPS
Average Removal Efficiency
Existing
NSPS
ANSPS
Average Percent Removal
Existing
NSPS
ANSPS
75.6
98.5
120.2
88
80
71
36.1
26.2
13.3
.4
85.7
89.0
94.7
.8
80.0
80.0
84.4
.5
68.6
71.2
79.9
37.2
27.0
34.3
87.9
86.0
88.5
89.5
81.7
80.0
80.0
84.8
71.8
68.8
70.8
75.9
37.4
27.7
55.1
87.9
85.3
86.8
90.2
82.9
80.0
80.0
86.4
72.9
68.2
69.4
77.9
ICF
INCORPORATED
-------
EXHIBIT F-11
UTILITY COAL CONSUMPTION JNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. S02/MMBTU
Region
Northeast
Middle Atlantic
South Atlantic
East North Central
East South Central
West North Central
West South Central
Mountain
do15
Coal Type
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
BTU)
1985
Reference
Cases I & II
.136
.004
.101
.242
.306
1.096
.370
1.772
.675
1.876
.535
3.086
1.400
1.747
1.907
4.245
.869
.739
.533
2.142
.489
.834
.562
1.884
.060
1.295
.733
2.088
-
.427
.927
1.354
1990
Reference
Case I
.196
.145
.032
.373
.251
1.137
.835
2.224
.764
1.734
1.198
3.695
1.479
1.657
1.610
4.745
.815
.717
.849
2.381
.461
.868
.813
2.142
.060
1.728
1.087
2.875
-
.546
.953
1.4999
1990
Reference
Case II
.250
.219
.032
.501
.241
1.203
1.403
2.847
1.272
1.787
1 .239
4.298
1.556
1.761
2.186
5.503
.835
.767
1.185
2.787
.462
.895
1 .035
2.392
.060
1.693
1 .466
3.219
-
.656
.934
1.590
Pacific
National
High Sulfur
Medium Sulfur
Low Sulfur
Total
High Sulfur
Medium Sulfur
Low Sulfur
Total
.096
.013
.108
3.936
8.031
4.954
.060
.227
.287
4.026
8.592
7.603
.207
.347
.555
4.676
9.188
9.829
16.921
20.221
23.693
-------
EXHIBIT F-12
OIL AND GAS CONSUMPTION BY PLANT AND BY REGION UNDER ALTERNATIVE
NEW SOURCE PERFORMANCE STANDARD OF 0.8 LB. SO /MMBTU
(10tS BTU)
Region
1985
Reference
Cases I & II
1990
Reference
Case I
1990
Reference
Case II
Northeast
Steam .405
Combined Cycle .020
Turbines S Internal Combustion .268
Total .693
.226
.012
.117
.355
.271
.012
.127
.410
Middle Atlantic
Steam .496
Combined Cycle .012
Turbines & Internal Combustion .335
Total .843
.505
.012
.269
.806
.508
.012
.325
.845
South Atlantic
Steam .941
Combined Cycle .029
Turbines & Internal Combustion .416
Total 1.386
.633
.027
.318
.978
.931
.029
.409
1.369
East North Central
Steam .304
Combined Cycle .007
Turbines & Internal Combustion .402
Total .713
.293
.007
.271
.571
.296
.007
.321
.624
East South Central
Steam .082
Combined Cycle
Turbines & Internal Combustion .316
Total .398
.082
.161
.243
.082
.188
.270
West North Central Steam .074
Combined Cycle .002
Turbines & Internal Combustion .134
Total ' .210
.078
.002
.172
.252
.080
.002
.192
.274
West South Central Steam 1.514
Combined Cycle .021
Turbines & Internal Combustion .022
Total 1.557
1.216
.012
.032
1.260
1.287
.015
.073
1.375
Mountain
Steam
Combined Cycle
Turbines fi Internal Combustion
Total
.087
.015
.022
.124
.096
.011
.043
.150
.096
.015
.051
.162
Pacific
Steam .886
Combined Cycle .428
Turbines & Internal Combustion .140
Total 1.454
.776
.408
.120
1.304
.725
.593
.147
1.465
National
Steam 4.789
Combined Cycle .534
Turbines & Internal Combustion 2.065
Total 7.388
3.905
.491
1.523
5.919
4.005
.685
.1833
6.523
-------
Q.
-------
APPENDIX G
COAL SUPPLY CURVES
This appendix contains the supply curves used in the new source perfor-
mance standard analysis for EPA. These supply functions are generated by
the Reserve Allocation and Mine Costing (RAMC) program using the methodology
presented in the ICF's Coal and Electric Utilities Model Documentation (July
1977) and Appendices B and C of this report. This introduction explains the
codes and information presented in this appendix.
Individual supply curves exist for each coal type in each of 30 supply
regions. Figure G-1 shows the locations of the 30 supply regions. The coal
types are a function of heat content and sulfur content. Heat content is
specified as one of five btu levels — three for bituminous coal, one for
sub-bituminous coal and one for lignite. Although the heat content value
chosen for each type of coal varies by region (see Table III-6 in the
Documentation for values used), the range of values for each category is
consistent for all regions. See Table G-1.
TABLE G-1
BTU CONTENT CATEGORIES AND CODES
Millions of Approximate
Btu's Per Ton Code Rank of Coal
> 26 2 bituminous
23-25.99 H bituminous
20-22.99 M bituminous
15-19.99 S sub-bituminous
< 15 L lignite
Sulfur content is specified as one of eight sulfur categories. These
categories approximate the sulfur levels necessary to meet the various Federal
and state emission standards, as explained in the Documentation (p. III-5).
The sulfur level categories are listed in Table G-2.
ICF
INCORPORATED
-------
FIGURE G-l
\ f . ^_ . : S^
-* y ;oo -Jj 601 «iLC«--•:- = --s
1-0
COAL SUPPLY' REGIONS
o
•n
8
3
s
3)
m
O
NOTE: Alaska (AK) not shown.
-------
0.00
0.41
0.61
0.64
0.84
0.93
1.68
- 0.40
-0.60
- 0.63
-0.83
-0.92
-1.67
- 2.50
> 2.50
G-?
TABLE G-2
SULFUR LEVEL CATEGORIES AND CODES
Pounds Sulfur Per
Million BTU's Code
A
B
C
D
E
F
G
H
A coal type is identified by a two-digit code. The first digit gives the
btu content category, and the second digit gives the sulfur level category.
Thus, a ZA coal has at least 26 million btu's per ton (Z btu category) and at
most 0.4 Ibs. S/mmbtu (A sulfur category).
The supply curves present the production levels and prices associated
with existing and new mine production. Existing mine production is presented
under a single mine-type heading. New mine production is presented on a
mine-type basis for surface and deep mines. Each new mine type is described
by a code in the first column of the supply curve table. The code differs
for surface and deep mines, which are differentiated by an "S" and "D." The
numerical code that follows presents the relevant descriptive parameters for
that mine type. These are explained as follows:
o deep mines - the six columns following the letter "D"
present information on the seam thickness, seam depth
and mine size.
Columns 1-2 - seam thickness in inches
Columns 3-4 - seam depth in hundreds of feet with
"00" representing a drift mine
Columns 5-6 - mine size in 100,000 tons
o surface mines - the four columns following the letter
"S" present information on the overburden ratio and
the mine size.
Columns 1-2 - overburden ratio
Columns 3-4 - mine size in 100,000 tons
For example, a D481001 mine is a deep mine in a 48 inch seam, 1000
foet below the surface producing 100,000 tons per year. An S1020 mine is a
surface mine with a 10:1 overburden ratio producing two million tons per
ICF
INCORPORATED
-------
G-4
The second column gives the price of the coal in late 1977 dollars/ton.
These prices vary slightly (by roughly 7-8 cents a ton) from those in the
model solutions because of rounding when deflated from 1985 dollars. The
mines are presented in order of increasing price.
The next four columns list the potential production in millions of
tons per year. Annual production estimates for each mine type are given, in
addition to cumulative production for 1985, 1990, and 1995. Cumulative
production is the sum of the annual potential production estimates for the
individual mine types and simply show how much production would be available
in the specified year at a given price. Note that cumulative production of
existing mines decreases over time because of mine closings. Existing
mines are totally depleted by 1995.
The curves presented in this appendix do not necessarily account for
the entire reserve base because the curves have been truncated after 35
steps. This was done to reduce the size of the model and does not affect the
model solution since none of the model solutions reached the last step of any
coal type.
The order of the supply curves is presented below.
ICF
INCORPORATED
-------
CEUM Region
Region
insylvania (PA)
io [OH)
ryland (MD)
:st Virginia, North (NV)
-'•sst Virginia, South (SV)
Virginia (VA)
"entucky. East (EK)
Coal
Type
Code
ZB
ZD
ZE
ZF
ZG
HD
HE
HF
HG
HH
ZG
MF
MG
MH
ZD
ZF
ZG
HD
HG
ZA
Z8
ZC
ZD
ZF
ZG
HB
HD
HE
HF
HG
ZA
ZB
ZD
ZE
ZF
HB
HD
HG
ZA
ZB
ZC
ZD
ZE
ZF
HA
HB
HC
HD
ZB
ZC
ZD
ZE
ZF
ZG
HD
HB
HC
HE
Page
G-6
G-7
G-8
G-9
G-10
G-11
G-11
G-12
G-13
G-14
G-15
G-16
G-17
G-18
G-19
G-19
G-20
G-20
G-20
G-21
G-21
G-22
G-22
G-23
G-24
G-25
G-25
G-26
G-27
G-28
G-29
G-29
G-30
G-31
G-32
G-33
G-34
G-34
G-35
G-36
G-37
G-37
G-37
G-38
G-38
G-38
G-39
G-39
G-40
G-41
G-42
G-43
G-44
G-44
G-45
G-46
G-46
G-47
CEUM Supply
Region
Kentucky, East (EK)
Kentucky, West (WK)
Tennessee (TN)
Alabama (AL)
Illinois (ID
Indiana (IN)
Iowa (IA)
Missouri (MO)
Kansas (KN)
Arkansas (AR)
Oklahoma (OK)
Coal
Type
Code
HF
HG
HG
HF
MF
MG
MH
ZH
ZC
ZF
ZD
ZG
HD
HF
HG
ZB
ZD
ZE
ZF
HR
HD
HF
HD
HE
HF
HG
HH
MF
MG
HH
HE
HG
HH
MB
HD
ME
MF
MG
MG
MH
SH
HG
HH
MG
MH
ZG
HF
HG
MH
ZB
ZE
ZE
ZF
ZA
ZB
ZC
ZE
ZF
HA
Page
G-47
G-47
G-48
G-48
G-49
G-49
G-49
G-50
G-50
G-50
G-51
G-51
G-52
G-52
G-52
G-53
G-53
G-54
G-54
G-55
G-55
G-56
G-57
G-58
G-59
G-60
G-60
G-61
G-62
G-63
G-64
G-65
G-66
G-66
G-67
G-68
G-68
G-69
G-70
G-71
G-72
G-73
G-73
G-74
G-75
G-76
G-76
G-76
G-76
G-77
G-77
G-78
G-78
G-79
G-79
G-79
G-79
G-80
G-80
CEUM Supply
Region
Oklahoma (OK)
Texas (TX)
North Dakota (ND)
South Dakota (SD)
Montana, East (EM)
Montana, West (WM)
Wyoming (WY)
Colorado, North (CN)
Colorado, South (CS)
Utah (OT)
Arizona (AZ)
New Mexico (MM)
Washington (WA)
Alaska (AK)
Coal
Type
Code
HB
HG
MG
If
LA
LB
LD
LF
LG
LD
LB
LD
MB
MF
MG
SA
SB
SF
HB
MB
MD
MF
MH
SA
SB
SD
SF
SA
SD
ZA
ZB
ZD
ZF
H*
HB
HC
HD
HF
MA
MB
MF
HA
MB
HF
SD
SF
MD
SF
HA
MB
MC
MD
MF
MA
SD
SG
SA
Page
G-ao
G-81
G-81
G-B2
G-83
G-83
G-83
G-84
G-84
G-85
G-86
G-86
G-87
G-88
G-89
G-90
G-91
G-92
G-93
G-94
G-95
G-96
G-96
G-97
G-98
G-99
G-100
G-101
G-101
G-102
G-102
G-102
G-103
G-104
G-105
G-105
G-106
G-107
G-108
G-109
G-109
G-110
G-110
G-110
G-111
G-111
G-112
. G-112
G-113
G-114
G-115
G-116
G-116
G-117
G-117
G-117
G-118
-------
G-6
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COAL TYPE Zb
TVPE
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37.02
37.93
38.86
41.01
•17.09
51,47
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6c?.09
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0.7A
0.60
0,60
0.50
0.30
0.30
0.48
0.30
0.30
0.30
0.30
1.44
1.0?
0.72
0.48
0,48
0.18
1.02
0,36
0,46
0.48
0.24
0.36
0,24
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0.8
1.4
2.0
2«3
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2.9
3.4
3.7
4.0
4.3
4.6
6.0
7.0
7.7
8.2
8.7
8.9
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tO. 3
10.7
11.2
11.3
11. a
12.1
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CIM90
n.S
0.9
1 .^
1.8
2.1
2.4
2.6
3.1
3.4
3.7
4.0
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6,5
7.8
7.7
H.2
8,0
9.4
9.7
10.?
10,7
10.9
11.3
11. *
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1.2
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2.1
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2.9
3.2
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5.2
6.2
7.0
7.4
7.9
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9.1
9.5
10.0
10.<»
10.7
11.0
11.3
-------
G-7
PwlCE
>• jv.fr TvPf (JR/TO^O ANNUAL C"^**1? Cu**90 CUM9«i
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Ml -.r)7,»r>70«, 36.12 0.60 2.6 1.3 0.6
^i.-. 07 21005 37.02 0.60 3.2 1.9 1.2
"JtV. 0600705 37.93 0.30 i.5 2.2 I.*
38.2,? 0.60 4.1 2.0 2.1
«.75 O.bO 4.7 3.4 2.7
Mr«.Ci(i010n*i 38.86 -1.30 5.0 3.7 7.0
New.0480705 39.88 0.30 5.3 4.0 3.3
Nfew.n3*»r»00 J 40,36 0,78 ' 6.1 4,0 4,1
Nf-w. 0481005 40.84 0.30 6.4 5.1 4.4
^rw,0360405 41.01 1.20 7.6 6.3 *«6
Ntu.0360705 41.99 1.20 8.8 7.5 6.8
Nfc*.oS6l005 42.99 1.20 10,0 8.7 8,0
NK».D280001 43.12 0.42 10.4 9.1 8.4
Nfcfc.0280405 43.30 0.9Q 11.3 10.0 9.3
Mfw.0280705 44.32 1.50 12.8 1J.5 10.8
45.33 1.50 14.3 13.0 1?.3
46.45 1.62 16.0 14.6 13.9
47,09 1.2C 17.2 15.8 15.1
46.97 1.00 19.0 )7.6 16.0
1.0600701 49.20 0.60 19,6 18.2 17.5
51.47 0.6!> 20.2 18,8 1^,1
51.86 1,56 21.7 ?0.4 1«J,7
52,26 1.20 22.9 21.6 2f>,9
54.00 1.50 24.4 23.1 22.4
54.39 0.60 25.0 23.7 ?3.0
56.67 0.60 25.6 24.3 23.6
NfcW.0280701 56.88 2.10 27.7 26.4 25.7
Ntw.0361001 59.PI 1.50 29.2 27.9 ?7.2
Nfc*. 1)281001 62.09 2.10 11.3 30.0 29,3
188.07 0.18 31.5 30.1 29,5
-------
G-8
Cf'AL TYPE Zfc
P^TCE »OTKNTIAL
IM£ TYPE (J/TON) ANNUAL CUM*5 CU«90 CUM95
.3460710 38.22 0.60 0.6 0,6 0,6
.03M010 36.75 0,60 1.2 1.2 1.2
.0360001 40.36 0,48 1.7 1.7 1.7
,r>3
-------
G-9
V AMI*
Nt
* *.03607 10
». -1,0361010
-J.OShO/05
W. 0361005
'*ew. 0280405
M *,D280705
Nf -.07*0701
Mt*.lVSh040l
Mr -.0600701
W.P360701
(*/TilN)
25,56
25.94
29.02
29.77
30.52
30.68
30. 77
M ,5?
32.30
33.18
3J.6H
35,09
36,99
57!58
54.90
41.09
45!o2
63.12
68.79
81.08
7,
-------
G-10
PENNSYLVANIA
Ntw.3360710
Nf. *. 0361 "MO
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17.66
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27.30
27.86
2H.17
30.68
30.77
SI.52
32.30
33.18
S3.68
55.0?
35.28
37.28
37.58
41.09
42.84
45.0?
68.79
81.08
143I29
CIHL TYPE ZG
PDTEMT
1.2.5
0.40
0,40
0.80
0,80
O.'JO
1.04
0.40
2.40
2.40
0.48
2.00
2.80
2.80
1.36
0,96
2.48
0.64
0.3?
2.40
0.96
2.00
0.64
0.32
3.36
2.00
3.36
0.08
0.08
0.08
0.3?
TAL, P«*OrHiCTIUN CHMT/VB)
CUM8S
1.2
1.6
2.0
2.8
3.6
4.0
4.4
5.3
5.0
7.5
9.9
12.3
12.7
14.7
17.5
20.5
21.7
22.7
25.1
25. «
26.1
26.5
29.5
31.5
32.1
32. u
35.8
37. 9
41.1
41.2
41.3
41 .4
41.7
CUH90
0.4
0.6
1.?
2.0
2.8
3.2
3.6
4.6
•5.0
6.6
9.0
11.4
11. 9
13.*
16.7
19.5
20.9
21.8
24.3
?S.O
25.3
27.7
26.6
30.6
31.3
31.6
35.0
37.0
40.3
40.4
40.5
40.6
40.9
CUM95
o.
0.4
o.a
l.A
?.4
2.6
3.2
4.2
4.6
6, 2
8,6
11.0
11.5
13.5
16.3
19.1
20.5
21.4
23.9
24.6
24,9
27.3
28.2
30.2
30,9
31.2
34.6
36.6
39,9
40. 0
40.1
40,?
40,5
-------
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PF.MK.SYLVAWIA
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37.?8
CUAL TYPE HD
PPPPUCTIUN
ANNt.iAL
0.19
0.24
0.32
0,3?
0.40
0.32
0.40
CUM 85
0,2
0,«
0.6
1.1
1.5
1."
2,2
CUM «»0
0.1
0,3
0.6
0.9
1.3
l.T
2.1
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0,2
0,6
0,9
1.3
1.6
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MKM.S5001
33.
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U2.84
4S.02
81.06
94.16
COAI. TYPE HE
POTENTIAL
0.08
0,06
0.08
0,24
0.32
0.24
0,32
0.08
0.08
0.24
0.1
0.2
0.4
0.6
0,7
1.0
1.3
1.5
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(WMT/YS)
CUM 90
0.1
0.2
o.a
0.6
n.7
1.0
1.3
1.5
2.1
2.3
0.1
0.2
P.4
0.6
P.7
1.0
1.3
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1.9
-------
G-12
COAL
MF
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16.17
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27 41
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26.90
29.02
29.77
50.52
50.68
30.77
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33.16
33.68
3S.09
56 ,99
47 28
37!ba
56.90
39.19
40.92
41 09
42. H4
45.02
^ft|yq
61 ,P8
9<*.16
POTENTIAL PKODUCTIOU (MMT/rP)
ANNUAL
6.36
7.60
2.40
2.40
7,60
3.6'*)
2.40
2.40
3.60
3.20
3.20
5.60
2,60
2.60
0.56
1.20
2.00
2.00
16.32
9.60
6. 60
4.96
3.26
9.60
3.04
4.96
3.2*
2.80
3.04
2. AO
o.uo
0.1*
0.24
0.24
CUM AS
6.4
14.0
16.4
16.6
26.4
30.0
32.4
34,6
38.4
41.6
47.1
50.3
55.9
58,7
61,5
62.0
6J.2
65.2
67.2
63.6
93.2
100.0
104.9
106.2
110.4
120. 0
123.0
126.0
131.2
134.0
137.1
139.9
140.3
140.4
140.7
140.9
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-------
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COAL TVPf HG
PWICE
C',JM9fl
16.17 i:5.77 " 13.8 4.6 0.
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26.01 «?.00 17.8 A.6 4.0
i.060070*' «»6.68 0.80 1«,6 9,4 4,A
.0360710 26,89 1.60 20,2 11.0 6.4
.H361010 *f.30 1.60 21.* l?.fc ft«°
27.41 O.AO 22.6 13.<» *•*
27.86 0.40 23.0 13,b 9.2
26.17 l.?C> 24.? 15,0 10.4
?8.5S 2.1*. 26.3 17.1 12.6
28.90 1.20 27.5 1A.3 13.*
29,02 ?»AO 30.3 21.1 16,6
Nfe^0360705 29.77 2.SO 33.1 23.9 19.4
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30.68 0.64 36.6 27.4 22.A
30.77 2.40 39.0 29.B 25.2
.11.5? 3.20 42.2 33.0 2A.4
3P.30 3.20 43.4 36.2 3i,6
Mf*.04*0401 33.18 «.7? 50.1 40,9 36.3
33.6A 2.96 53.0 43.9 59,S
<5.09 3.9? 57,0 47.A 4S.2
35.2H 1.60 «,B.6 49.4 44.8
Mt-!D4f070l 36.9Q 1.2A 59.A 50.7 46.1
wfw P2H0401 37.2» 2,Ah 62.7 53.5 49.0
Nt/.n7?100J 37.5A 2.96 65.7 56.5 51.9
NF.w. 0360701 3H.90 2.64 68.3 59.1 54.6
Kk".0601001 39.19 1.60 69.9 60.7 56.2
Kt«.r«MQ01 40.92 1.2A 71.2 62.0 57.4
N^!n,?fl070t «1.09 4.1ft 75.4 66.2 61.6
c».E »i 0 36 I <'0 1 42.84 2«6" 7A.O 6A.B 64,2
4S.02 4.16 02.2 73.0 68.4
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•»tfc.i2^01 6A.79 O.lh A2.7 73.3 69,0
*t--!s^Si»l AJ.OS 0.24 63.0 73.8 6«»,?
Mf , «H001 94.16 0.24 A3.2 74.0 6^.4
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55.29
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0.10
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0.80
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0.80
1.20
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1.36
1.60
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0,96
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1.5?
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0.1
0.9
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2.5
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7.7
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10,1
10,9
12.1
13.3
14.1
16.0
17,2
1A.4
19.5
20.9
22.5
23.4
26.4
27.4
26.3
29.9
31.4
33.0
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24.66
25,19
25.57
25.96
26. SI
26.70
26.91
27.32
27.42
27.46
20.16
26.92
29.04
29,78
30.54
30.70
30.78
31.48
31.54
32.32
J3.19
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55.29
35. S7
37.01
57.30
Jfl.92
39,21
40.93
40.99
41.10
42.06
4S.04
48.26
POTENTIAL Pr'OPUCTlUM (MMT/YW)
ANNUAL
1 .00
1.60
1.60
2,40
2.40
0.80
2.40
1.60
1.60
1.60
2.00
2.40
2.40
2.40
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2.40
0.80
1 .20
4.M
1.60
1.60
2.16
2.16
1.52
1.20
2.16
2.00
2.52
1.60
2.16
1.20
2.16
2.32
2.16
1.60
CUrtflS
1 • *•
3.2
4,3
7.2
9.6
10. a
12.8
14.4
16.0
17.6
19.6
22.0
24. a
26. 8
39.2
31 m*
32.4
33. fc
38.2
39. *
41.4
43,6
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49.3
50.5
52.6
54.6
57.0
56.6
60.7
61.9
64.1
66.4
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70,2
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1.6
3.2
4,8
7.2
9.6
1U.4
12.6
14.4
16,0
17. b
19,6
22.0
24.4
26,8
29,2
31, b
32.4
33.6
38.2
39.0
41.4
43,6
45.0
49,3
50.5
52.6
54,6
57,0
••8.6
60,7
61.9
64.1
66.4
60,6
70.2
CUMV5
1 ,6
3.2
4,8
7.2
9,6
10.4
1?,8
14.4
16.0
17.6
19.6
22.0
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26.6
29,2
31 .6
32,4
33.6
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39. A
41.4
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49, "5
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52.6
54,6
57.0
56.6
6P.7
61.9
6<». 1
66,4
66.6
70,2
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(S/THN)
f * I MI -il. 12.45
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MLw.S2blO 27.96
26.16
26.92
29.OU
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40.70
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31.46
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32.32
33.19
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35.57
37.01
37.30
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POTFNTIAL PHOliUCTIOM 1
ANNUAL
0.78
2. UP
4.80
4.60
4.60
2.40
5.60
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6.4P
6.40
6.4P
10.00
7.20
7,20
5.60
7.60
3.20
7,20
7,20
6.00
9,60
9.60
3.60
7,20
17,20
8.40
3.20
6,40
6,04
8.56
12.08
4, Of
7,20
6.72
10,00
5,36
CHM65
0.8
3.2
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17.6
20.0
25,6
31.2
37,6
44,0
50.4
60.4
67 ,6
74.4
80.4
88.0
91.2
98.4
105.6
113.6
123.2
132.8
134.4
143.6
160.8
169.2
172.4
1 6 0 . ft
168.9
197.4
209. 5
213,2
220.7
224,4
? 3^,4
244,8
CiJWO
0.3
2.7
7.5
12.3
17.1
I1*, 5
25.1
30.7
37.1
43.3
«9.9
59.9
67.1
74.3
79.9
87.5
90. 7
"7.9
105.1
113.1
122.7
132.3
135.9
145.1
160.3
166.7
171.9
160.1
1*6.3
196.9
209.0
?13.0
220.2
226.9
236.9
244.3
;MMT/VK)
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19,?
24.6
30.4
36.6
43,?
49.6
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66.6
74.0
79,6
87.2
90. 4
97.6
104.6
112.6
122.4
13?. P
135. h
14?, ft
160,0
16*. 4
1M.6
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16B.1
196,6
(?U8. 7
?18.7
219.9
^26,6
?3* .6
244.0
-------
G-18
TYPfc HM
PHTHNTJAL
(S/TON)
12.4) 3.44 3.4 1.1 0.
... 26.51 0.80 4,2 1.9 P.H
*if *.rt»0070S 26.70 0,40 4.6 2.3 1.2
Mfv,.n3fr0710 26.91 0.80 5.4 3.1 ?.f»
MKn.03f.1010 «?7.32 0.80 6.2 3.9 P.*
M-.V. 06.-) 1005 27.4? 0,80 7,0 4,7 3.6
?7.46 0.40 7.4 5.1 1.0
«>8.18 0.80 4.2 5.9 4.8
28,92 0.80 9.0 6.7 «i.6
29.04 0.80 9.8 7.5 «>.4
29.78 1.20 11.0 8.7 7.*
•MCP.wjriwvj 30.54 1.20 12.2 9,9 H.R
Nln.32005 30.70 0.40 12,6 10.3 *.2
Ntw,0*80405 30.78 1,20 iS.B 11.5 10,4
Nfcw.0600401 31,48 0.96 !«.« 12.* ^'-J
"'••-,riZJ»0705 31.54 1.60 16.4 14.1 U.O
.02S1005 32.38 1,60 l&.O l^.T J4.J
.04H0401 33.19 0,78 J8.7 lh,4 15.3
*.0160401 35.11 1.36 20.1 17.6 16. ft
H.0600701 35.29 P.80 20.9 lji.6 J7.4
35,57 0.80 21.7 19.a 18.2
37.01 0.56 *8.2 19.9 1H.R
NC*.W*OM..VI 37,30 1.92 24.2 21.9 70.7
N6W.03607P1 38.92 1.58 25.7 23. <• ^?.?
MEW.0601001 39.21 0.48 26.2 23.9 *?2.7
an.9S 0.56 Z6.7 24,4 23.3
40.49 0.80 27.5 25.2 84.1
<»1,10 2.08 29.6 27.3 2*.2
42.86 1.52 31.1 28.* 27-7
45.04 2,0* 33.2 30.9 J?9,8
a».26 0.80 34.0 31.7 lo.ft
62.99 2,00 36,0 33.7 3P.6
68.68 0.80 36,8 3«.* 33.4
60.07 0,80 37,6 35,3 34.a
Nfcw.SJOOl 94.04 0,80 3«,4 3ft.1 35.»
143.17 2.08 40.5 3ft.2 37.0
-------
G-19
fl'JAI. TYPl *K
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•MINE TvPh (I/TON) ANNi-AL CM US Cl'M<»0 CH*9
fxisri'ic 12.1? O.M n.l ".0 f.
MI- v ,n3h040b 29.04 0.40 O.S 0.4 fi.«
•ir >• .13607CS 29.78 0.40 0.9 0,^ O.fi
••'t » .D361005 30.^J4 0.40 1.5 J.2 li''
Sl.aS 0,40 \,7 1,6 1.6
M.Sft 0.4n 2.1 2.0 2.0
<2..32 0.40 r?.b 2.4 2,4
.. .. . 33.19 O.flft c',9 2.A ?.*
,0360401 55.11 0.40 J.3 3.2 S.2
,0600701 3^,29 0.40 3.7 3.h ?*.6
17.01 0.48 4.2 4.1 4,1
37.30 0.64 *.9 4.8 4.7
38.92 0.48 S.3 5.2 *>.P
we*.P6.'l)(i01 59.21 0.40 5.7 i.6 5.«»
MEw.O.AAlOOl 40.93 0.48 6.2 6.1 *. 1
Mfw,02^0 701 <«1,10 Otafl 6.7 6,6 *••»»
Mt*J.0361001 a2.B6 0.4H 7.2 7.1 7.0
4b,04 0.4« 7.6 7.6 7.S
68.66 O.OA 7.7 7.6 7.*
HP.97 0.08 7.8 7.7 7.7
94.04 0.03 7.9 7.H 7.H
145.17 0,40 «.S B.2 H.2
-------
G-20
OMJIJ
UL PWUniJCTlON (MMT/YB)
•1TME
f V I HTI-JU
Nt w. 0*007 OS
Ml »'. 0*0100^
Kit*. «"»<*» 07 05
wfcu. 0360705
»'tH.03M005
\e>'.P600401
Kt*'.04ftOtt01
(A/TOM)
2b.70
30.54
32.32
33.19
35.11
35,29
37.01
37,30
38.9,?
wl*. 52^01
Mfc^.53001
80.97
143J17
ANNUAL
O.ttO
O./JO
0.40
0.40
O.ttO
O.ttO
0.40
0.40
0.72
0.40
O.ttO
O.ttO
O.Sb
0.46
0.56
0.72
0.72
0.4A
0,«8
0.72
0.49
0.60
0.32
0,40
0.40
0.72
2.4
2.8
3.2
3.6
4.0
4.4
4.6
5,2
5.6
6.3
6.7
7.1
a!i
6.6
10.6
11.0
11.6
12.1
12.»
13.3
14.1
14.4
14.8
15.2
15.9
O.tt
1.2
1.6
2.0
2.4
2.8
3.2
3.6
4.0
4.7
5.1
5.5
5.9
7*.0
T.5
H.2
9,0
9.4
10.0
10.5
11.2
11.7
12.5
12.6
13.2
13.6
14.3
U.
0.4
0.*
1.2
1.6
2.0
2.4
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4.3
s!i
5.7
6.2
6.7
7.a
8.2
6.6
9^7
10.4
10,9
11.7
12.0
12.8
13,5
-------
MM 10
G-21
CfUU TYPF
KjNf TYPf
EX IbT INI;
. 0360405
. 0360705
MI ..
Mt-i.i'360701
i. 5*001
(S/TQM)
27.42
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G-22
COAL TYPE ZO
MJNE TYPF-
kJEw.0720705
NCw. 0721005
kt ft JA| A % 44 O A rt ^
™ w ™ A v » «* W *• W J
NEw. 0360705
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ME*. 0280705
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M? V ,i")7 ?070l
Nt*. 03b0401
N-t *.. 0600701
N*:»>. 0480701
^t ^.0280401
Mfcw. 0721001
vj*w. 0360701
MEM. 0601001
Mfcn, 0481001
WE-. 0280701
ME '.'.036 1001
Nfc ^,0261 001
Nt».. 84505
Nf w.52001
Nt»J.S250l
Mb 'J. 3 5001
NC^. S4S01
PKICE
(S/TON)
35,fl9
36.80
40.74
41.72
42.71
43.01
44.01
45.03
46,15
46.85
48,66
48,94
51,19
51, -SI
52,03
53,69
54.13
56.39
•Sh.53
58.90
61.75
80.09
40.66
1 n*».u8
1 £*.?*>
165. (H
PDTf NT
AMNOAL
0.30
0,10
0,30
0,30
0,30
0,30
0,30
0,30
0,90
0.54
0,78
0,36
0.36
0.42
0.54
0.54
0.56
0.36
0.54
0.54
0,54
0,31
0.12
0,18
0,18
0.4A
1AL
PWOOUCTION ('
CUM85 TMM90
0,3
0.6
0.9
1.2
1.5
1.8
2.1
2.4
5.5
3.8
4.6
5.0
5.3
5.8
6.3
6.8
7.2
7.6
S.I
8.6
9.2
9.5
9.6
9.8
10.0
10.4
0.3
0.6
0.9
1.2
1.5
1.8
2.1
2.4
3.3
3.8
4.6
5.0
5.3
5.8
6.3
6.8
7.2
7.6
8.1
8,6
9.2
9.b
9.6
9.8
10.0
10.4
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CUM95
0.3
0.*
0.9
1.2
l.S
1.8
2.1
2.4
3.3
3.8
4.*
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5.3
5.8
6.3
6.6
7.2
7.6
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8.8
9.?
9,5
9.6
9.8
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10,o
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wtw.pbOlOOl
MP w. 048 1001
w. 52501
PtfJCfc
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28, ei
29.S6
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50.S4
31,30
32.08
32.96
33.53
36.78
JJ7.01
38.6B
59.00
40.7J
40. 8<
42.61
44. 77
68.1'J
80.54
93.32
101,bl
COAL TYPE If
POTENTIAL PRODUCTION
AMW'IAL
0,40
0,40
0.40
0.40
0.40
0.40
0.32
0.24
0.64
0.08
0.08
0.64
i).64
0,0*
0.06
0.80
0,64
0,80
0.08
0.16
0.16
0.56
0.4
0.8
1.2
1.6
2.0
2.4
2.7
i.O
3.6
l.'l
4.0
4.6
5.3
5.4
5.4
6.2
6.9
7.7
7.8
7.9
H.I
0.4
0.6
1.2
1.6
2.0
2.4
2.7
3.0
3.6
3.8
4.4
4.6
5.4
5.4
6.2
7!7
V.H
7.9
8.6
0,4
0.8
1.2
1.6
2.0
2.4
2.7
3.0
3.6
3.7
3.8
4.4
4.*
5.3
5.4
6l?
7,7
7.A
7.9
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03^1001
(.* / T n N) A M N i' A (,
47.01
3H.6K
uu. 77
141.61
COAL TYPf; H
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Cl
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1 ' f i "
0.1ft
0.16
O.ort
0,0ft
0.7
0.*
1.1
1.2
1.3
1."
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CUM9«i
0.2
0.3
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0."
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U7
0,7
ill
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1)7
TVPF
t '» 1ST I
(A/T.1N)
1P.OS
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CUHflS CLJM90
0.1 0.0 0,
H6
N't*. 0360701
MC1-I.02M0701
ML'J.,1361001
N.F'1.0281001
(ft/TJN)
57.01
0. ?2
0,24
0.24
0.24
0.52
0,24
0.3?
0.3
0.6
O.fl
1.0
1.4
1.6
1.9
0.1
0.3
0.6
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l.l
1.4
1.7
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0.5
0.7
1 .0
1.3
1.6
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G-24
TYPE
fc X 1ST
NE*. 0280401
*Ew.OJ60701
vgw. 0280701
18.08
SU97
54.43
57.23
93.BO
t10.19
COAL TYPE ZA
POTFMTIAL REDUCTION CMMT/Y*)
Nt U.S5001
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0,
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0.
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1.4
1.7
2.0
2.3
2.6
2.J
2J8
3.1
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0.3
0.5
0.8
1.0
lib
8.0
«!l
2!u
0,
0.2
n.4
0.7
1.0
1.3
1,6
1,7
1.7
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wfcW, 0480710
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N.fc.*,O
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Nt.W.P?AO«05
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NK.I.S300S
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18,08
35,74
36.19
36.71
57.15
37.24
37.24
57.83
57.91
38.12
38.46
59.02
59.06
59.10
40.06
40.16
4] .06
41 .12
41.81
42.14
42.83
43.18
43.37
44.41
<»4.46
45.49
46.68
48.01
49. 16
SlNb
51 .97
54.43
54.87
55.14
57.23
POTENT
AMMLJAl
0,b6
0,42
O.bO
0.60
0.90
1.20
0.30
0.4?
O.bO
1.20
1 .20
1.2n
0.90
1.20
1.50
0.42
1.50
1.50
0,30
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2,10
1.20
1.80
1.56
1.80
1.38
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1.8b
2,?2
1.92
1.92
2.40
0.60
2.22
2.64
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0.7
1,1
1.7
2,3
3,2
4.4
4.7
5.1
5,7
6.9
8.1
9.3
10.2
11.4
12.9
13.3
14.4
16.3
16,6
18,7
1 9,?
21.3
22.5
?4,3
25.9
27.7
29.0
29.6
31. b
33.7
35.6
^7,b
4U.O
40.6
42.8
45.4
(MMT/YB)
CUK90
0.2
0.6
1.2
1.8
2.7
3.9
4.2
4.7
5.1
7^7
«!»
ll.o
IP.5
12.9
14.4
15.9
16.2
18.3
22.1
23.9
25.4
?7.2
28.6
3l!l
33.3
35.2
37.1
39,5
40.1
42.3
45.n
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0,4
1.0
1.6
2.5
4.0
5*,0
6.2
7.4
8,ft
9.5
10.7
12.2
12.7
11.2
15.7
16.0
20.*
21.8
25!?
«»7,0
26.4
29.0
30, B
33.1
3?.fi
36.9
39.3
39.9
42.1
44.8
-------
G-25
M^'fc TYPE
i«.ij 360001
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EXISTING
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NEW.D600001
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MEM.P260705
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TYPE Z
POTENTIAL PHOPUCTION
-.0580/01
(»/T'"»SO
lb,82
20.66
23.17
24 .69
25.01
25.28
25JM
26.03
26 .09
26 13
26.59
26 .59
26.77
27.01
27.47
27. 52
28,36
29.01
29.03
29.61
30,40
30.62
30.74
31.40
31,5«
31.61
32.36
33.30
35,17
35.61
36.39
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37.30
39.17
AMM'AL
0.26
1.6C
0.40
0.40
0.56
1.60
1.60
2.00
1.60
0.40
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0,80
2.80
0.80
0.80
1.60
2.80
3.20
0,32
2,40
1.20
2.00
0,16
2.00
0.40
0.40
0,40
2.80
0,40
2.24
3J92
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2 8A
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2.24
CUM85
0.3
1 .9
2.3
2.7
3.2
4.8
6.4
8.4
10.0
10.4
11.1
11.9
14.7
15.5
16.3
17,9
20.7
23.9
24,2
26.6
27.8
29.8
29.9
31.9
32.3
32.7
33.1
35.9
36.3
38.6
40.2
44,1
44,5
47,4
48. 1
50.3
CUH90
0,1
1.7
2.1
2.5
3,0
4.6
6.2
8.2
9,8
10.2
10.9
11.7
14. 5
15.3
16.1
17.7
20.5
23.7
24,0
26.4
27.6
29.6
29.6
31.8
32.2
32.6
33.0
35.8
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38.4
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44,3
47.2
47,9
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CUM95
0.
1,6
2.0
2.4
3.0
4.6
6.2
8.2
9.6
10.2
10.4
11.6
lft.4
15.2
16.0
17,6
20.4
23.6
23.9
26.3
27,5
29.5
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31. T
32.1
32,9
32.9
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36,1
38,3
39,9
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44.2
47.1
47,8
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-------
G-27
COAL TYPE ZC
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(S/TON)
15.H2
25,01
25,26
25.68
26.03
26.09
26.15
26,59
26J77
27,01
27.44
27.47
27.52
£0.23
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2«.01
29.03
30.62
31 .40
51 ,61
53.30
35.17
35,61
36.39
<7.30
59.17
39.69
41.30
4U93
0.1?
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0,80
0.80
1.28
3.2C
4,80
4.60
4,80
0.40
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1.60
6.80
2.40
2.4Q
4.40
6.60
6.00
0.7?
4,80
2.40
3.80
3,20
0.40
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4.56
2.32
8.40
0.40
6.32
0.32
3.?6
8.40
0.40
4.8H
0.40
0.1
3.3
4.1
4,9
6.2
9,4
14,2
19.0
23.8
24.2
85.7
27.3
34.1
36.5
36.9
43.3
50.1
56.1
56.8
61.6
64.0
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70.4
70. A
76. *
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83.7
92.1
92. S
4A.A
99.2
102.4
1 10.8
111.2
116.1
116.5
0,0
3.2
4.8
6.1
9.3
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23.7
24.1
25.6
27.2
34.0
36.4
38.ft
43.2
50.0
56.0
56.«
61.6
64.0
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70.4
70.8
76.8
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83.6
92.0
92.4
98.8
102I4
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11 1.2
116.0
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-------
G-28
W.VIRGINIA,
TYPE HB
"IN| TYPF
EXISTING
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NEW. 0160401
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NEX.DJ60701
. 0601001
rt. 0361001
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14.80
31.61
33.30
3h.l7
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J7.30
57.30
?9. 1 7
39,69
41.30
41 ,«0
43,28
45.42
70.50
83.14
96.56
146. 3S
PPTtM I AL PPPP'ICTION (HMT/VK)
ANfciijAl
o.io
0.08
0.06
0.06
o.o*
O.OM
O.Ofl
0.16
P. OR
n. 16
0.0ft
0.16
0.16
o.oe
0.16
0.16
0.56
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0.1
0.2
0.3
0.3
0,4
0.5
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0. '
0.*
1.0
1.1
1.2
l.a
1.5
1.6
l.B
2.3
CUH90
0.0
n.i
0,2
0.3
0.4
0.4
0,5
0.7
0,8
0.9
1.0
1,2
1.3
\ .4
1.6
1.7
2.3
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0.1
0.2
0.2
0.3
C.ft
o.s
0,6
0,7
0,9
1.0
1.1
t.3
1.4
1.5
1.7
2.2
f X
Nt«. 06007 01
Mtw. 04^0701
ME*. 0360701
Nfw .060 1001
(4/TON)
14.80
33.iO
37,30
39,17
39.69
41.40
COAL TYPE Hi)
POTENTIAL
— w y •*
146.35
0.46
0,0*
0.09
O.OB
0.08
0,08
0.0«
o.e*
O.OP
0.5
0.-5
0.6
0.4
0.9
0,9
1.0
1.1
1.2
0.5
0,6
0,6
0.7
f.l
o!s
0.6
0)7
-------
G-29
COAL TYPE HE
POTENTIAL PRODUCTION (MMT/YiO
Ml Mf TYPE
M w. 06*1005
Mfc -I. 04*0705
ML n,n3f»0001
k>. 04*0401
ME -..0600 701
MF.W.P4*0701
\f\01
Me. rt .
ME -l.
Mfe-i.SiOOl
25.01
26.03
26.77
27.U7
2«.3b
30,6?
31 ,bl
33.30
35,17
37J30
37,30
39,17
41..50
as..
0,40
0,80
0,80
0.80
1.20
0.16
O.BO
0.40
0.80
0.80
1.04
0.80
0.64
1.2*
1,12
0,24
0,72
1.28
0,40
0.80
0,72
0.40
0,08
0.08
0,0ft
0,40
0.?
0,6
1.4
1.7
2.5
3.3
4.1
5.3
5.4
6.6
7.4
8.2
9.3
10.1
10.7
12.0
13.1
13,4
14,1
15,4
16.S
17.J
17.7
17.H
17,6
17.9
18,3
0.2
0,6
U7
2.5
3.3
4.1
5,3
5.a
6.2.
6.6
7.4
9/3
10.1
10.7
1P.O
13.1
13.4
14,1
15.4
15,8
lb.6
17.S
17.7
17.H
17.8
17.9
18.3
0.2
0.6
U7
3!3
4.1
5.3
6?2
6.6
9.3
10.1
10.7
13.4
14.1
15.4
15.8
16.6
17,3
17,7
17,8
IT!«
-------
G-30
Mint TYPE
P. x IST IMG
Nit*.
MEH.04A1010
W-W.D460405
. 0601005
NiEw. 0360705
MI K.r^doooi
ft h .0361 GO*
Nf.*i.Dft>OOa01
ME*. 0*81005
MtH, 0360401
MFX. 06007 01
Fri. 0601 001
Krt.0i?fl()701
fc *.i>aftinoi
k*-1. 03*. 1001
t«(.0^»ln01
h-.sasos
t. -.82001
PHICE
f*/TON)
2s!oi
25.26
25.66
26.03
26,77
?7,01
CfUU, TYPE HF
TTAL
26.56
29!o3
Jo!40
30.62
31.b4
31.61
32.36
33.30
Sl'.b\
37.30
37,10
39,17
39,69
41.30
43J2*
45.42
64.04
70.50
0.5f>
0.60
0.60
1.20
2.40
0.64
2.00
0.60
1.60
2 . 00
2.40
0.40
1.60
1.20
1,20
0.06
1.20
0.40
2.16
0,40
1,44
1.26
2.60
2.16
0.72
1.52
2.60
0.72
1.60
J.52
0.7?
0.40
0.24
0.32
0.6
1.3
2.1
«!l
f U
*• • J
7.2
10)0
10.A
12.4
14.4
16.§
17.2
18.6
20.0
21.?
21.2
22.4
22. *
85.0
25.4
26.6
26.1
30.9
33.1
33.6
3*. 3
36.1
38.8
40.4
42.0
42.7
43.)
43.3
43. h
0.3
0.6
1.6
2.4
3.6
6.0
6.7
8.7
9.5
10,3
11.9
13.9
lt>,3
16.7
16.3
19.5
20J7
21.9
22.3
24.5
24,9
26.3
30.4
32.
33.
34.
37.
S^!
41.
42.2
42.6
<.2.A
43.1
CMM95
0.6
1.4
2.2
3.4
5.6
6.4
6.4
9.8
10,0
!?!*>
16.0
16.4
16.0
19.2
20.4
20.5
21.*
22.1
24,6
26,1
27,4
30,2
32.3
33.0
34.6
37,a
31.1
39.7
41.2
41.9
49.3
42.6
4?.9
-------
G-31
COAL TVPf
PRICE PmFNTIAL PHDDtl
(,<./TON) A^N'IAL CUM85
F.XTSUMG 14.80 9.94 9,0 3.3 0,
Mf*. 1^600001 25.01 0.56 1^,5 3.9 0,6
10 25.28 0.80 11.3 4.7 1.4
JO 25.68 0.80 12 • 1 5.5 2.2
26.OJ 1.20 13.1 6.7 3.4
?^.09 1.60 14,9 H.3 5.0
26,59 0.56 15.5 «.* S.li
26.77 1,60 17.1 10.4 7.1
JM60710 ?7.01 0.80 17.9 11.2 7.9
27.44 0.80 16.7 12.0 8.7
27.47 1.20 19.9 13.2 9.9
27.52 1.60 21.5 14.8 11.5
28.23 2.00 ?3.5 lfc,8 13.5
28.36 0.40 ?3.9 17.2 13.9
29.01 1.60 25.5 1«.8 15.5
_ . 29.03 1.20 26.7 20.0 16.7
,t". 0360705 ?9.81 1,20 27.9 21.2 17.9
!O.U() 0,16 28.0 21.4 l«.l
30.62 1.20 29,? 22.6 19,3
30.74 0.40 29,6 23,0 19,7
31.54 0,40 30,0 21.« Zfl.l
11.61 1.84 31.9 25.2 21.9
32.36 0.40 32.3 25,6 22.3
35.30 l.Sb 33.6 27.0 23.7
55.17 1.18 34.7 28.1 «<»,*
35.61 2.64 37.a 30.8 27.fl
17,30 2.00 39.4 32.8 89,4
37,30 0.4ft 39.9 33.2 89.9
39.17 1.36 41.2 ?a.b 31.3
39.69 2.64 43.9 37.2 33.9
41.30 0.80 44.7 38.0 34,7
41.40 1.68 46.3 39.7 36,4
43.28 1.36 47.7 41,1 37.8
4b,42 0,80 ttP.5 «1.9 38,6
t»ii.04 0,80 49.3 42.7 39.4
.^52001 70.50 ^,32 49.6 43.0 39.7
-------
G-32
COAL
FK 1ST I MI;
H»ICt
f*/TON)
25,69
103.63
1 2 $ ,ffi
144.4-5
167.66
P71.43
pn
ANN'.I
10.64
0.06
0.06
0.08
0,06
0,30
POTENTIAL PRODUCTION CMMT/YM)
CU185 CUH90 (
10.7 3.6 I
10,7
10,"
10.9
10.9
11.2
3.6
3.7
3.7
3.8
4.1
0.1
0.)
0.?
0.5
COM, TYPE ZB
TYPF.
f . ils
. f)7«!1020
tHi, 0720710
F ^.0721 010
N&M.036U010
. 0600710
NEw. 0601010
Me *.
r, 10
•Jt ta. 0721005
'lt«. 0600705
tk .0601005
Kt ...SI
•>ife -.
PBTCF
(S/TPM)
29,32
30,18
30,52
31.76
34.05
34.52
35.70
36.15
36,20
36,57
ST.09
37,25
3?!97
(MMT/YP)
39.25
39,29
39.65
39,97
40,08
40.75
41.08
41,86
42,07
42.51
6.75
3.60
1.20
1.20
1,20
i.ao
4, 80
5,40
2.28
0,60
2.40
3.70
3.00
0.30
1.80
7^0
2.40
3.00
3,00
6.60
2.70
0,90
3.00
3,60
0.96
4.80
4.80
3.30
2.70
0.90
3.30
3.00
1,20
3.30
5.in
CUMftS
•>.*
10.4
U.fc
12*4
14.P
15.A
20.6
26.0
31.*
36.9
39.9
40.2
42.0
43.2
50.7
53.1
56.1
59.1
fcft.fj
69.3
72.3
75.9
76.0
Ml.6
86.4
9ij!u
95. *
96.b
99. fe
100.8
104.1
109.?
CIIM9H
2.3
5.9
7,1
».3
9,5
11.3
16,1
21.5
24'.3
26.7
32.4
35.4
35.7
37.5
3*.7
46.2
48.6
51.6
54.fr
61.2
63.9
64.6
67.8
71.4
72.5
77.1
85.2
87.9
92!l
95.1
96.3
99.6
104.7
0.
3.6
4.«
6.0
7.2
9.0
13,8
19,2
21.5
2 4'.5
30.2
33.2
33.5
35.3
36.a
43.9
46.3
40,5
52.3
61.6
62.5
65.5
69.1
70,1
79^
03.0
85,7
86.6
89.9
92.9
94.1
97,4
-------
G-33
r.OAl TYPE 70
PKL'OUCTIfJM (MMT/VW)
Mp'fc T
e XJST IK,
Mfr i». 07^0710
VF ».ny,?l'">1 0
*•*... ,07e "001
* t- ,0b'ii'7 J ?N
Ml *'. 0*00001
M£-.n7?070c3
•it *.ouao7lP
Mk w. 0560005
Mf ^.D5sn«ic>
Nf »i. 0600705
\Fv.o«^onoi
MK*-.nSfii>7 J 0
M t ^ w , n a « o 'i o b
\f- ^.oiflonns
sit w,r>ufUi70S
Mt'«.SlbOS
Nt •-. 03^0001
M t k.. , C1 7 r> I) <» P I
(S/TON)
3 4 . 8 7
Sh.lS
J6J91
37.09
37^97
3H.03
3fi.au
41.08
41./5
42!o7
4,»..M
*., 1*80705
4a.9«i
45.84
ANNUAL
4.09
l.flO
] ,80
l.UO
0,60
0.36
2.70
l!20
0.90
0.30
1.20
1.50
0.36
1.20
0.90
1.20
0.60
0.54
1.20
1.80
3,Oh
1.80
o.*a
1.50
2.40
5.3
7.1
10.3
n!?
13.9
21.7
?5.6
27!2
2».4
29.6
30.5
30.8
32.0
52.6
33.1
34,3
36.1
36.H
46.4
46.9
4.4
h.2
6.9
I".5
M.l
11.5
15*.4
16.6
19.0
19.9
20.2
21,4
22. *
21.3
25J7
26.9
27.8
28.1
29.3
29.9
30.4
31.h
33.4
39'.2
43^7
44.2
0.
1.2
3.0
fl.8
5.6
6.2
9!2
P.8
n.t
u.*
15)2
17.6
18.A
20.0
21.5
21.9
23.1
c>5.5
26.4
26.7
27.9
20.5
29.0
32.0
34.7
37.9
40.5
a*.3
46.7
-------
G-34
••'.VT»ISTNIA,SOUTH
r.n/a TYPE ZE
PTiTRMTIAL PftDOUCTIQN (Mr»T/yfi)
i*Fn.r,7 20001
fit-. 07*0705
MH. 0721005
Mw.03bOOOt
/.D36P70S
«.07,»OU01
*.03MOOV
,,.^600401
•if *', 06007 01
*fc *,pi»60fi01
Mtu .naaorot
ME «. 0721 001
•.'F -I. 038 1001
N.t-.OgHlP
Mfc».SlIJOJ
(J./TON)
57!o9
3ft.Oi
41,66
42,31
46.90
a?.06
46.62
50.82
50. fl*
Su.OO
5U.01
Mfc»i,8JOOi
58.71
103,61
123.26
167.66
271,43
0.06
0.30
0.30
0.12
0.30
0.4ft
0.30
O.JO
0.12
0.24
0.30
0.30
daft
0.30
0.42
0.30
O.Uft
0,46
0.66
0.30
0.30
0.72
0,66
0.7*
0.12
0.12
0.12
0.12
0.42
CUHflS
0,1
0.4
0,7
0,B
1.1
1.4
2!2
2.5
l'.*
3.1
3.4
3.6
4.1
4.4
4,6
5!6
6.1
6,7
7.0
7.3
6.0
9.5
9!b
9.9
10.3
CUM90
o!4
0.7
O.H
1.1
U9
2.2
2.5
2J6
3.1
3.4
3.6
4.1
4,4
5.6
6.1
6,7
7.0
7.3
fl.O
M.7
«.4
9.5
9|«
9.9
10.3
P.I
0,4
o.e
1.1
1.4
1,9
s!s
2.6
2.ft
3.1
3.4
3.6
4.1
4,4
6.1
6,7
7,0
7.3
9.a
9,5
9,7
9J9
10.3
-------
G-35
t SOUTH
COAL
If
PPICE.
PRODUCTION
'••f. W.&3M010
,f;7?0u01
.r.JhlOOS
.D?AOanlS
.w. 02*0001
»• f.w.Q JfeOUOJ
^Fl•'. 0600701
»'fc w.C7i»1 01) 1
Nt ui.p2«0«01
vf- .J.O 5^0701
i»7.63
2e!o6
28.19
29,00
29.95
30.81
3U8J
32^48
32.62
35.43
3«|78
56.44
36.45
3M.86
40,41
42J41
i,90
0,80
0.80
0,40
0,80
0.08
0.60
0.4P
0,40
0.40
0.40
1.20
1.1?
1.20
0.80
0.7?
U20
0.40
1.12
1.04
0.72
0.7?
0.80
1.52
1.20
n.7?
0.7?
2.OP
3.9
4*.9
5.5
5.4
6.*
7.4
7.6
A.6
9,9
10.3
10.7
11.1
11.b
12.7
11.9
15.0
16.2
17.0
17.4
18.1
19.3
20)9
22,1
23.1
23.8
2s|j
26.9
28.1
?8.8
29. •»
31.6
1.3
2.1
2*. 7
4.0
4.8
6.0
b«9
7J7
b.1
a|9
10.1
11.3
1^.4
!«•»
16.7
17.9
1B.3
19.5
20,5
21.2
21.9
22,7
24.3
25.5
26.2
29.0
0.
O.A
1.0
1.5
2.7
3.5
3.9
4,7
4,8
5.6
6.0
6,4
7 ".2
7.6
8.8
10,0
11.1
12.3
13.1
13.5
14.2
15.4
16.6
17,0
18.2
19.2
19,9
20,6
21.4
23.0
24,2
24.9
27,7
-------
G-36
COAL TVPfc: Hg
POTENTIAL
ANNUAL. CUM85 COM90 CUH9S
20.«1 0.79 0.8 0.3 0.
24.03 ".80 1.6 1.1 n.ft
24.34 0.24 1.8 1.3 1*0
,?5.?8 O.ao 2.2 1.7 l.o
i.r>600001 ^b.90 O.OH 2.3 1.8 1.5
Mfe *,07207O'j ?5.V9 1.20 3.5 3.0 ?.7
Mr:-.'>7?l005 £6.7? 0.40 3.° 3.4 3.1
«»J.45 0.4* 4.3 3.8 3.5
27.68 0,08 4,4 3.9 3.6
28.19 0.40 4.8 4.3 4.0
ME ..'.")UPOo05 28.26 0.40 5.2 4.7 <».4
Mfc •l,n<«fl07i>S 29.0G 0.40 5.6 5.1 <».8
MF".."> 380001 29.67 0.08 5.7 S.I 4.9
•v.e/.D4«1005 29.78 0,40 6,1 5.5 5.3
Mtl».i>3bO«('5 29.95 0.40 6.5 5.9 5,7
Nt^.0.l80f05 30.72 0.40 6.9 6,3 6.1
N£ w..T7?oa01 30.81 1.^4 7.9 7.4 7,1
Mtw.si'jOS 31.39 0.40 8.3 7.8 7.5
31,52 0,00 d.7 8,2 7,9
32.00 0.06 6.8 A.3 #.G
32.48 0,64 9.4 8.9 8.6
34.35 O..J2 9,7 9.2 9.0
34.78 0.88 10.6 10.1 9.A
36.44 0.40 1U" 1<*«3 10»2
36.45 0.56 11.6 11.1 10.8
ME'.*'.s?no5 37.41 0.80 12.4 11.9 \\ .6
NE».naA0701 36.32 0.56 12.9 12.4 12.2
wtw.0721001 3B.84 O.Aft U.K 13.3 13.0
is>fc'»i. 0280401 38.86 0.48 14.3 13.8 13.5
NEW.0380701 40.41 0.72 15.0 14.5 14.2
NE.W. 0601001 40.52 0.56 15.6 15.1 14.8
42.41 0.56 16.1 15.6 15.4
42.82 0.72 !*•' !*>•* I**1
(15.90 0.80 17.7 17.1 16.9
44.50 0.72 18.a 17.9 17.fc
46.91 0.7? 19,| 18.6 1*,3
-------
G-37
lAf SOUTH
CDAI. 1VPE
PBTTE POTENTIAL
TVPf. (S/TIJN') ANNUAL CUMtt1'' CUM90
0*il 3.*>S «.« 1.3
PWTfF POTPMIIAL PPODUCTIlifJ (MN«T/V(?)
TVPF (S/TON) ANNUAL Cl'^dS C"N«0
K 20. ai S.95 b.« ?.0 0.
-------
G-38
l-IMb TYPE
EM9TING
\Ew.n360ftOl
. 0360701
. 0280701
MIL*
NF.fc
. SI 501
.fl2 00 1
PRICE
(•/TON)
20. BO
50.39
5*.61
60.56
63.79
102.26
121.43
142.20
165.oa
268.77
COAL TYPE ZA
POTENTIAL PaPOUCTIO"
ANNUAL CUSP'S C'.'MQO
1.M9 1,9 0,6
O.li? 2.0 0,7
0.1 ft
o!lft
0.06
0.06
0.06
0.06
0.30
2.4
2.6
3.0
3.1
3.1
3.2
3.3
3.6
1.1
1.3
1.8
2^0
0.
c.i
ols
0.7
0.9
1.1
1.2
1.3
1.3
U7
-------
G-39
V T P T, T N I &
TYPfc ZH
PttJCE Pfm.NTTAL PrfPDUCTTON (wNl/Yrt)
MJM; TYPF
KXlSTU'fi 2C.HO l.*4 1.2 n.fl *,
dtw.0720001 34.72 0.12 l.« n»* °»)
N^.072ij405 35,79 0.30 1.7 O.h 0.4
N£*I, 07207.05 36,fr9 0,60 2,3 1,tt I*'1
Nf".0600001 36.79 0.06 2.3 I.1* *•'
Nf*.0721005 37.59 0.60 2.° ^.1 1«7^
wt*.H360005 ^fl.25 0,50 3.2 2,** ••
,„.. - / . in '.T481005 41.64 O.iO 6,6 5.6 5,3
Nfc*. 0360001 41.81 0.24 6.^ 6,0 5,6
Kifto. 0360405 41.97 0.90 7.7 6.* O.5
NE>'.D72040i 42.*» 0.4A *.? 7.« 7.1
»fc«. 0360705 «2,96 1 .«0 10.•" 9.2 ?,^
.t 22.7
K*. 0360701 55.37 !.*•? P^.1* 2**.^ ?/1»5
-------
G-40
IA
TYPE
bO.!>6
COAL
•: zc
ANNUAL
O.Ob
O.Ob
0,06
0.06
O.Pfc
O.l,'
o.l
0.1
O.u
",1
o|z
ojs
fMMT/YR)
0.1
O.J
f • . 3
CHAL TYPf
NF. w.[:3fc0001
'-'tw.nJ6040S
Nfc*. 03607 0*1
. 0280705
NP.W.D560T01
Mpw, 0280701
>Jtw.S3001
PWJCF. PUTFK'TJAL PRODUCTION (HMT/YW
(4/TCIN)
20. HO
4 1 , ft 1
41.97
42.96
43. 9«
44. M
4(4 .92
45.49
4ft. 50
50.39
C>3.b4
S*i.S7
Sfl.bl
60. bb
b3.79
100.^0
10P.P6
121. ««
142. iM
\ b^ ,o
-------
G-41
»JMt TYPh
^ «i9Ti.-JG
NE*.SISOI
Nfc*.saoni
M4.s2sni
*?«.s3oi)i
MF4.SUl!i01
(A/ UV
1ft.21
77.19
92.14
Irt D 1 4i
V O • ii*™
126.12
COAL TYPE ZF
POTENTIAL
CUNH3
3.3
3.3
3.4
3.5
3.6
5.26
O.Ofl
O.Ofl
0.08
0.0«
0.24
3.8
ION
CHM90
1.1
1.2
1.2
1.4
1.6
0.1
0.6
COAl. TYPE MA
•Nit ». 0360701
MF.«.02*0701
{S/TDN)
lh.28
39.96
42.41
43.87
46.32
ANMUAL
0.26
O.Ofl
O.Ofl
0,08
0.08
CUHi
0.?
0,5
0.4
0.5
0.6
PHQOUCTIDN fMMT/Y*)
CUM90
0.1
0.2
0.2
0,3
0.4
0.
o.l
0.2
0.*
0.3
NF.w.r>720001
Nt -i.f>72P7f'l
Mir w. 0600701
M *. 05*0401
N, I: *, m n u ^ 0 1 0 1
Mt w.r;7?lP01
. 060100V
roi
001
(S/TIlN)
25.07
25.7S
26.45
sail/
54.06
37.8'?
?*.! 7
43.f7
COAL
POTEN
ANNUAL
0,56
0,06
0.40
0.40
O.ftO
0.40
0.32
O.U8
0.3?
0.16
O.ttS
0.40
o.afl
0.24
0.40
0.24
H8
TIAL
0.6
0.6
1.0
1.4
l.«
2.2
2.6
2.9
3.9
4.0
4.3
4.0
5.4
5.6
6.1
6.5
7.0
7.2
7.6
0.2
0.3
0.7
1.1
1.5
2)2
3^1
3.6
4)4
5.1
'j!7
6.6
6.»
7.2
7.5
0.1
O.S
0.9
1.3
1.7
2.0
2.3
3.0
3.4
«.*
5.9
7,0
7.3
-------
G-42
MINE TVPF
. 0360401
. 0280401
001
(J/TON)
36.17
38.63
42J41
43.87
COAL TYPE HC
POTENTIAL P-300I.ICTJQN (MrtT/VH)
ANNUAL
O.n
-------
G-43
Y.E'AST
Mfc w.0b007 10
*t.w. 0720405
Nfc*. 0601010
(.%/TON)
1 7.79
..0721010 35.11
36.81
36.62
37.57
37,69
37,76
3A.62
3».70
39!22
40, 0*
40.54
. 04*0710
Ni*.r>4MOJ o
Mfx.07.MQ05
.Mfc*. 0380005
w£ w.l) 360410
NF w. 0600705
NEH.P36P710
Mr.
40. *3
41 .60
41.83
42.27
42.77
42,8?
44.16
45.19
45.66
45.92
40.40
46.72
CUAI. TVPf
PTTtNT
ANNtUL
5,03
1.20
1 .6P
2.40
0.90
0.60
2,10
1.20
0.60
0.42
1.00
1.20
1.20
2.UO
0,90
0,60
l.SO
1.50
2,40
0,'»2
2.40
1.50
0.90
0.60
1.50
0.60
0,7fl
1.50
2.70
3.90
? . 50
3.90
3.00
o.aa
1.74
4.20
7*
1AL PflOfMICTIUN
CU*fl5
•5."
6.2
A.n
10. u
11.3
11.9
14.0
15.2
15. «
U.3
19.4
20.5
21.7
24. 1
25.0
?5,6
27.4
2rt.s
31.1
31.7
34.1
*5.6
36.5'
37.1
36.6
39, ?
40.0
41. S
44.2
46,1.
51. «
55.3
58.3
59. 1
60.4
65.0
CMM90
T.7
2.9
4.7
'.1
H,0
6. ft
in, 7
11.9
IH.b
1^.^
1"»,9
17.1
1 **. 3
?ft. 7
21.6
22.2
24.1)
25.5
87.9
28.3
30.7
32.2
33.1
33.7
35.2
35.*
36. *
3ft. 1
40, b
44,7
4A.O
SI. 9
54. *
bb.7
?>7 ,5
61.7
(MrtT/VAJ
0.
1.?
3.0
5.4
6.3
6.9
9.0
10.2
10. »
U.2
14.?
15.4
16.6
19.0
19,9
20.b
22.3
23.A
26.2
26.6
29.0
30.5
31.
-------
G-44
COAI. TYPF. ZC
*IM£ TVPI-
w.l^T?J010
w. 0720001
-O720405
w. 0600001
Nt».f)600705
Nt-1. 03607)0
^E*. £4*0001
Nf>.r)360001
MF.W. 0360705
NEi-'.07?0401
c-tw. 036 1005
K. 0600401
*. "2*0705
wg i^.O 7 207 01
^Fw.nb0070l
. 060 1001
f.WTON)
35.11
36.Al
57^6
3H.70
40.08
w • -"
41.A!
42.77
42.63
43.12
44.15
44.16
45.19
45.66
45.92
46.40
46.72
47.78
48,94
49.40
51.66
51.77
54.19
54.81
55.06
57,05
57,09
59.63
60.50
62.47
0.30
0.06
0.60
0,30
0.30
0,60
0,06
0,60
0.50
O.JO
0,2"
0,50
0.60
0.60
0.66
P.60
0,60
O.iO
0.4J
0.90
0,90
0,42
0,7A
0,36
0,96
0.42
0.66
1.14
1.14
0.42
0.42
1.56
1.14
|AL PRODUCTION (
Cilf A5
0.6
0.7
1."
1.1
1.7
2.0
2J9
2.9
3.5
3. A
4.1
4. 4
4.7
5,3
5.9
6.5
7.1
7.7
6.0
a. 5
9.4
10.3
10.7
11.5
11. A
12. A
13.2
13.9
15.0
16.1
16.6
17.0
18. 5
19.7
CLIM^O
0.6
0.7
l.o
Ul
1.7
2,0
2!9
2,9
3. b
3.8
a. i
4.4
*.7
5.3
S,%
6.5
7.1
7.7
f ,0
*,b
9.4
10.3
10.7
11.5
11, A
iz.e
13.2
13.9
15,0
16,1
16.6
17,0
1 A, 5
19,7
MMT/VB)
0.7
1.0
1.1
2.«
2.3
2.9
4,/i
4.7
5.3
6.5
7.1
7.7
ft.Q
A.5
10.3
10,7
11.5
11.A
12.A
13.2
IS.9
15.0
16.1
16.6
17.0
19!7
-------
G-45
P&1CE POTENTIAL PBHOlit TIOM (MMT/Y4«n001 40.0ft 0,06 4.) 3.1 2.6
upw.0561010 40.54 0.6fi 4.7 3.7 3.2
NF ".1)601005 40.69 0.30 5.0 4.0 3,5
Mln.D 480705 41.83 0.30 5.3 4.3 3.S
Nt-.SlSOS 4r?,27 0.30 5.6 4,to 4,1
,v»w.0360001 42.77 0.24 5.8 4,9 4,a
Nt-'.04*1005 42.83 0.30 6.1 5,2 4,7
Nfc.M.D3Ml405 45.12 0.90 7*0 6.1 5,6
NEw.0360705 44.15 0.90 . 7.9 7.0 6.5
•"(w.0720401 44,16 0,54 fi.-j 7.5 7.0
*.*•:*. 0361005 45.19 0.90 9.fl B.fl 7.9
Mt*.02*0405 45.66 0,60 10,0 9,0 »,5
Nk»i. 02*0001 45.92 0.30 10,3 9,3 ft.8
wfcw.0600401 46.40 0.36 10.6 9.7 9,?
U6.72 1,20 11.fl 10.9 10.4
47.78 1.20 13.0 12.1 11.6
4A.94 0.36 13. 'J 12.« 11.9
49.40 0.66 14.1 13.1 12.6
49.57 O.Jft 14.4 13.4 12.9
51.66 0.30 14.7 13.7 13.2
"FW.D360U01 51.77 0.9Q 15.6 14.* 14,1
Mfcw.0480701 54.19 0.30 J5.9 14.9 10,4
ME-.D721001 54.81 0.66 16.5 15.5 15.1
Nf.u).n2«0401 55.06 1.3? 17,A 16.9 16,4
Nfe^.0360701 57.03 1.14 19,0 1«,0 17,5
57.09 0.30 19,3 1«,3 17,8
57.4h 0.3* 19,6 1*.6 18,1
59.63 0.30 19.9 18,9 1ft.4
-------
G-46
KENTl.lCKV.EA3r
MEw.D720705
MEw. 0721005
*. 0480705
u. 0360001
*'. 04 9 1005
fc'w. 0720401
Nt>. 0280405
Ntt». 02*0001
(S/TONJ
Ntw.0720403 56.81
37.76
38.70
40.08
41 |*3
42.77
42.83
43.13
44.J5
45.19
45^92
46.40
46.72
47.78
48.94
49.40
51 .66
51 .77
54.19
54.81
55.06
57.03
57.09
59.63
60.30
62.47
65.74
103.30
105.11
124.97
. 02*0705
MC.J. 02*1005
N**, 04*0401
ME*. 3720701
WEH.D600701
i. 0721001
ME*. 0601001
Mfc*.04MOOl
»'F.*(. 0590701
Mf.»(. 02*1001
M£«*. 34505
Nf ^. SI 501
Mf « .SiOOl
COAL TVP
PPTFM
ANNUAL
0.12
0.30
0.06
0.30
0.60
0.06
o.sn
0. Jrt
0.12
0.30
0.30
0.60
0.42
0.60
0.30
0.12
0.30
0.30
0.30
0.30
0.66
0.42
O.u2
0.24
O.S4
0.48
0.54
0.24
0.24
0.72
0.54
0,72
0.60
0.50
0.36
t ZP
TIAL i
Cum
o.l
0.«
0.5
O.ft
1.4
1.1
1.7
2.0
2.2
rf.S
2.8
3.4
J.8
4.4
4.7
4.0
5.1
5.4
5.7
6.0
6.7
7.1
7.5
7.7
0.3
A.*
9.3
v.s
9. A
10.5
11.0
11.8
12.4
12.7
13,0
CUM90
0.1
0.4
0,5
1.4
l'.7
2.0
2.S
2.8
3.4
3.e
4.4
4.7
5!l
5.4
5.7
6.0
6.7
7.1
7.5
7.7
6.8
9.3
9.5
9.8
10.5
11.0
11.«
12. "
.13.7
U.O
0.4
0.5
0.8
1.4
1.4
1.7
2!*
2.5
3)4
3.8
4.4
4.7
4.6
5.1
5.4
5.7
6.0
6.7
7.1
7.5
7.7
0.3
6.8
9.3
9,5
9.8
10.5
11.0
11.8
12.4
12.7
13.0
-------
EXISTING
-j.sasoi
G-47
KENTUCKY,EAST
rim.. TYPE l*
POTENTIAL
(MM7/Y9J
15.57
9a, Ai
lll.S*
129.8*
211.80
1 »^>8
0.08
0,09
0.0*
0.2a
1.6
1.7
1.7
1.8
2.1
0.*
n.b
".7
O.h
1.0
0.
P.I
0.2
0.2
0.5
COAL 1VPE 26
vf.w. 02*1001
POJTE
O/TON)
37.1 a
3Q 63
ai .1 3
an. 61
as. 33
*»7 , f 1
79.3?
94,81
1 1 .5"
29.88
U.80
POTEN
ANNUAL
0.08
0,08
0,08
0.16
0.08
0,16
0,08
O.OP
0.08
0.08
0.3?
TIAL P»on
CUM65
0.1
0.2
0.2
o.a
0.9
0.6
0.7
0.8
0.9
1.0
US
UCTIOM
CIJM90
o.i
0,2
0.2
o.a
0.5
0,6
0.7
0,0
0,9
1.0
1.3
(MMT/YB!
0.1
0.2
0.2
o.a
o.s
0,6
0,7
n,8
0.9
1.0
1.3
-------
G-48
KENTUCKY.EAST
COAL TYPE HI)
iINfc TYPE
FX 1ST I MB
Nhrf. 07 20001
*£•>/. 03*0001
NEW. 0360405
"-LW. 0720401
Nt»i.D600401
Mfcw. 02*0705
•MEW.D2B1005
WK-. 0720701
wF*. 0600701
M" J. 0360401
NEw.i)2fl0401
. 0*60701
NEHI.02A0701
WE -1. 036 100!
PPTCE
( J/TQN)
14.37
24.64
26.46
27.20
10,34
30,54
31.32
3J.37
3?. 10
32.74
33, 08
33.27
34.09
34.99
35.35
37.06
37 . 1 fl
38.99
39.4.J
39.63
41.13
41.16
43.09
45.61
45.23
47.71
PPTENT
ANNUAL
3,76
o.oa
0.40
0.4ft
O.OB
0,40
0,4ft
0,56
0,40
O.OA
0.24
0,40
0.40
0.24
0,40
0.32
0.24
0,32
0.40
0.64
0.5*
0.32
0.32
0.56
0,56
0.56
i*u pkooucTioN (HMT/YR;
GUMPS
3,8
3. A
4.2
4.6
A. 7
5.1
5.5
6.1
6.5
6.6
b.fl
7.2
7.6
7.d
a.i
8.6
a. A
9.1
9.5
10.2
10.7
11.0
11.4
1 1 •**
12.5
1'5.0
CHM90
1.3
1.3
1.7
2.1
2.2
2.6
J.G
3.6
4.0
4.1
4.3
4.7
5.1
5.3
5.7
6.1
6.3
b.6
7.0
7.7
A. 2
A,*j
A. 9
<»,a
lo.n
10.5
cum
o.
o.l
0,5
0.9
1.0
1.4
1 .^
2*3
2,7
2. A
3.0
3.4
3. A
4.1
<».5
4. A
5.0
5. a
5. A
fc.4
7.0
7.3
7.6
A. 2
A .7
9.3
-------
G-49
KENTUCKY,?AST
COAL
MH
PPUOUCTIC'N fMMT/YR)
NP.W.r>7?i)P01
M£^.DT,M')70S
l>'. 07*100*
*if: «. SI
. 0600701
. 0360401
Nt*. 04*070]
uEu. 0280401
MF*. 0360701
MC*.0601 001
Mb i«. 0481001
Mt~. 0280701
s>Ew.D2'l A01
\'fc.-.S3:>05
MO. SI ^01
Nfcw. 34505
ME.-I.S2S01
Ml*. 33001
(s/TON)
14,37
24.88
31.37
31.77
33.08
15'.35
37.0b
37.14
37.85
39.63
4l!l6
45.25
47.71
51.46
59.63
79.J2
HI .44
m!b4
129.88
211.80
0.08
0.40
0.40
0.64
0.40
0.3?
0.32
0.56
0.40
0.12
0.80
0.40
0.56
0.24
0.4ft
0.40
0.40
0.3?
0.80
0.48
0.32
0.80
0.80
0.64
1.60
0.64
0.64
0.64
1.92
CHMB5
2.7
2.7
3.1
3.5
-------
G-50
KENTUCKY,F.A3T
J*F. TYPfr'
.1)4110701
COAL TYPE Hfc
P«IC* POTENTIAL PRODUCTION
(WTC1N) ANNUAL CUMS5
ai.b] 0,08 0.1 0.1
47.71 0.06 0.2 0.2
11,80 Q.lfc 0.5 0.3
0.1
0.2
0.3
exISTiMU
COAL
HF
PRICE POTENTIAL PRODUCTION
f*/THN) ANNUAL
MJMP TYPE
HTST1MU
COAL TYPE HG
PRICE POTENTIAL PflUDUCTIOr1
(S/TOM) ANNUAL CUH*5
1«.37 2.11 2. a
211. AO 0.16 2.6
P. ft
1.0
CUH95
n.
0.?
-------
G-51
COAL TYPE HO
KXTSTlMb
Mt *.I
Nt 1.1.04*0720
. 52*05
w. M60410
w. 1)3607 10
sEn. 04*0705
M...I.D560U05
*c*i. 048 1005
NEW. 0360705
NE*. 34520
Mt w.l) Shi 005
"t -I.S3005
Fw. 05607 01
PRTTE
(S/TONl
10.70
17.80
£0.54
25.73
(i o A j '
C* O f O O
27.01
27J63
29.08
29.25
31.50
3P.43
34)26
35.90
36.49
38.14
39.97
40.63
4?.30
44.14
47.74
61 .29
72.37
POTfr^riAL PHOOUCTICIM
ANNUAL
3.06
1.60
4.80
b.40
1.60
6.40
1.60
1.20
7,20
8.00
8.00
4.00
4.80
7.60
il.HO
1 ,?o
8.80
5.20
8.80
b.OO
3.20
6.00
1.20
7.68
b.44
2.40
0.16
8.72
6.24
0.24
8.7?
6.24
0.24
2,80
0.96
0.96
CUM85
3.1
4,7
9.5
15.9
17.5
23.9
25. b
?6.7
33.9
41.9
49.9
53,9
58.7
66.3
71.1
72.3
81.1
86.3
95.1
101.1
104.3
110.3
11 1.5
119,1
1 24,6
127.0
127.1
135,9
142.1
1 42.3
151.1
157.3
157.5
160.3
161.3
1*>2.3
CUM 90
1.0
2.6
7.4
13.8
15.4
Pl.b
23.4
?4.6
3J.fi
39.8
47.8
51.8
56.6
h4,2
69,0
70.2
79.0
R4 ,2
93.0
99.0
102.2
108,2
109.4
117,1
122.5
124.9
125.1
133.8
140.1
140.3
149.0
l?>b, 3
155,5
151.3
15P.3
160.2
CUM95
0.
1.*
12.8
14,4
20.ft
22.4
23.6
30.*
46.8
50.*
55.6
63.2
68.0
69.2
78.0
83.2
92,0
98,0
101,2
107,2
108, 4
116,1
181.5
123.9
124,1
132.8
139,0
139,3
148,0
154.2
154,5
157,3
158,2
159.2
ClUl TYPE
M]Mh TYPE
°*ICE
fa/in*)
10.70
61.29
72.37
fl .5 . « b
125.37
PITKMl
AN.Ml.IAt
o.ll
0.0*
0.0«
0,06
o.ao
r T*L P9
CUH85
0.1
0.2
0. 3
0.4
0.8
CUM90
0.0
0.1
0.2
0.3
0.7
(rtMT/YR)
CUM9?
0.
0.1
0.2
0.2
0.6
-------
G-52
KENTUCKY,WEST
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o.ao
0.32
0.56
1 .04
TAl I
CU^
O.u
O.fl
1.1
1.5
1 .9
2,3
2.5
2.9
1,0
3.4
3.9
4,1
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4,0
5.2
9.*
5.9
b.6
6.0
7.4
a.i
0.9
9.2
9, S
10. a
P.4
0.6
1.1
1.5
1.9
2.3
3.0
3.4
4.6
5!2
5.8
5.9
6.6
6.B
7.4
9.2
9.8
10. 6
CUH95
0.4
o.a
1.1
1.5
1.9
2.3
2,5 '
2,9
3.0
4.1
4.6
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5,2
5, a
5,9
6,6
6,9
9,2
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COAL
J ME
Mfc
t*. 0^60701
. 028
33.25
35.05
47.10
'15,76
ME"..53001 ftO.22
NF W.SU501 119,94
POTENTIAL
ANNUAL CUMA5
0.1
0.2
0.4
0.0ft
0.16
0.16
0.16
0.16
0.16
0.96
0.9
1.7
2.0
s!a
0.1
0.2
0.4
0.6
0.7
0.9
1.7
2.0
2.5
3.4
i i ^ i
CUH95
0.1
o,s
0,4
0.6
0.7
0.9
1,7
2,0
2.5
3,4
-------
G-77
FHlf.E P'lTfNTIAl
r] v,r TYPK C*/TOM) ANN.IAI. CUMHS C»M40 C'.'
»'.'i7P0401 ?*»,7? O.OS O.I 0.1 n.1
'•" .'^7 j>0701 <2.b^> O.Ofl 0.? 0,i* 0«?
- J ?AOU01 3«<,OS 0.4« J.O 1.0 1.0
«6.47 0.0A 1.1 . 1.1 1.1
37.111 G.41 1.6 1.6 1.6
3A.91. 0,56 ?.? «?.2 ?.?
41.07 0.4* 5.6 «?.b 2.6
4?.88 0.56 4.2 3.2 3.2
45,76 0,40 3.6 3.6 3.6
69.2
-------
G-78
CIUL. TVPE MM
POTt-'MJAI. PWHOUCTirvJ (MHT/V!?)
(V/TdN) AMMUAI. CUMfl=> Cl.i*90 (
F. *I5TINC. 9.09 2.35 2.3 0.8 0,
''£''.0720410 2P.05 0.80 5.1 1.6 O.fl
2?.39 1.60 4.7 3.?. 2.4
23,SI O.flO 7.1 S.6 4,fl
23.68 1.20 H.3 6.6 6.0
•^.-w.0601010 23.68 O.flO 9,t 7.6 6.6
MK*.0720705 2a.37 u.80 9.9 0,4 7.*
MF.«J. 0600405 ,?<1.92 O.flO 10.7 9.^ «,U
Mt •».0721005 25.09 O.flO U.S JO.O 9.2
Ne--.0360410 £5,4<* O.flO 12.3 10.ft 10.0
.gF'.'.Oh007OS 25.6-< O.ao 12.7 \\ .1 \0.a
Np;^.03hC710 25.90 O.HO 13.S 12.0 U.2
MF..'.nufl0405 i?ft,23 O.flft 14.3 l?.ft 12.0
"I i« ,Ti361 01 0 r'fr.Sl OfflO 15,1 13.6 12,ft
2ft.37 ,0.«C Ib.S itt.O 13.?
26.41 n.40 1«>.9 14.4 13.6
:i.lifl«0705 26.96 O.flO 16.7 15.? Ifl.tt
27.63 P.DO i*.7 17.2 ifr.fl
?.7.72 0.*^ 19.5 18.n 17,2
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2«!l4 2^00 £4.6 £3!3 2?!^
49.15 2.40 87,2 25.7 20.9
-------
G-79
KANSAS
^ TM. TV PF.
H .33001
AO
COAL TVPE /G
POTENTIAL P&0&UCT JOM
ANNUAL. CUM6S CUM90
0.06 0.1 ",1
0.2U 0.3 0.3
CUM95
O.I
0.3
HP
P*TTE
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8Q.^7
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o.l
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119.
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33
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COAL TVPf HG
PHTf-.MTlAL PftODUmiOM
AMN.IAL CU*85 CUH90
O.a« O.S 0,i
O.«n 1.3 1.0
0.32 1.6 1.3
O.Sfe 2.2 1.«
l.Oa 3.2 2.9
CUM9?
0,
n.R
I.I
COAL
POTENTIAL
0.2a
o.l
-------
G-80
TYPF
TVPF
(h*"T/»R)
HI. HI 0.07
159|
-------
G-81
COAL'
7E
••'.07 20405
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w .07^1005
w.nh0070J
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119.92
POTtNT
0.24
0.40
0.16
0.24
0.48
CUMftS
0.2
0.6
0.8
1.0
1.5
TIOM
CUM90
0.1
0.5
0.6
0.9
CUM95
0.
0.6
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1.3
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G-82
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MISTING
COAL
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(J./ION) ANNUAL
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0.^2
0.315
0.42
POTfNTTAL PftDOUCTIl^ (MM1/YR)
CUM95
0.0 0.0 0.
0.1 0.3 0.3
• w —
0.07
1.0
1.4
1.8
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n.o
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0.8
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2.3
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COAL TYPE ZC
^QTEMTIAL P«UPlJCTIilM (MMT/V«)
ANNJAL CUM85 P.IM90
0.07 O.t 0.1
Tvpfc
(S/TON)
«l|59
COAL TYPE ZO
POTENTIAL PWniHICTlOfc (MHT/YP)
ANNUAL CUH85 C'IKPO CUMM
O.Ofi 0.1 0.0 0.
0.07 O.J n|l ^.t
0.07 0.2 0.2 0.1
O.iS O.1! 0,5 O.b
-------
G-83
HKLAMflHA
I'HTTF
14.86
•,. 17^0401
h.w. 0600401
r .0
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32. b'!
33.37
3'«.30
30.8S
5S.94
SH.17
a o. o 0
POTENT,
ANNUAL
0.16
0.24
0.0*
0.0*
0.08
0.0*
O.OA
0.0*
O.lh
0.08
CUH85
0.2
0.2
0.3
0.6
0.6
0.7
oil
1.1
1.3
l.S
1.7
1.8
0.2
0,2
0.3
0.6
o!7
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l.l
1.3
1 o
lit
l.H
0.2
o.i?
0.3
0.6
0.6
0.7
n.B
i.l
1.3
I .u
US
1.7
1.8
-------
G-84
•if i4
Nf-.W.n7iloOl
Nf. .1.0380701
.ofcoiooi
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COAL TYPt HG
TAL
32.01
$4,30
34.85
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1:3.21 1.68
28.17 0.3£
0.40
0.24
0.18
0.18
0.18
0^24
O.lb
0.24
0.18
2.0
2.1
2.3
2.7
3.8
4.2
4.'fe
4,9
5.1
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0.8
0.0
1.0
1.2
lift
2.7
s!i
0.3
0.5
0.8
1.0
1.3
1.4
1.6
1.8
2.4
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Mfci. .0721001
j
32.01
COAL Tvpf HG
PIJHNTTAL
0,0% 0,1
0.0?
0.08
O.'J
0.1
0^2
0.3
O.l
0.2
0.2
0.3
-------
G-85
C1AL
) AMMI-AI, Cl'M&*» C'JN'0 CUM9S
••MSTJM, tf.frfl 1°.^1 10,0 10.0 0,
•Jt J.S'iSUO a.5« 20.00 *0.o 3f',0 20,0
«r".^QS.*0 tt.Hb 1«,00 <|r»,0 aft.O 3^.0
•Jr •i.SOSi'fl b.i« 12.00 hO.O ^0,0 50.0
^.99 12.00 72.0 7?.0 «>2,0
6.?/? 6.0ft 7fl,o 7A.O 64.0
h,an 12.00 00,0 I'l.O *0,0
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7.97 S.OO 103.0 10.5.0 93.0
-------
G-86
DIAL TVPF; LA
"I'-lfe TVPt
Nf; w.SO'iOO
Nf
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5.4h
5.8h
6,48
7.6?
7.74
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a.oo
4.0
7.0
11.0
17.0
19.0
21.0
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4,0
7,0
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17
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0
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7.ft
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7.74
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PWnoiJCTHIM (MMf/YP)
C'lMQO (
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'3.4 3.4 3.0
COAL TVPt LO
m*it TYPF
F.kTSTT*J(i
N&M.S1010
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(S/TON)
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7.6*
7,74
•
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POTENTIAL PPfmiiCTIU
ANNUAL CUH85 CV.IH
0.07 0,1 P.I
40, On 40,1 00,1
33.00 73.
eft'.oi 1*3.
?l,10 !««•
11. On J«S5.
14.00 1*9.
6. 00 177,
73.
12s!
\
-------
G-87
MOUTH ruKn
COAU TYPE LF
PpTfNUAl.
i"!*'!: TYPE (*/Tl.lN) ANNUAL CU"*fl5 rilM9r> CU*95
FMSHNG 2.68 7.PI 7.2 *,2 0,
"Kw.3053ft 5.86 33.00 *4.2 *4.,? 77.0
M^Ai.SCSP'i 6.48 22.00 106.2 106.« 9«*.0
7.12 ?8.00 134.2 134,2 127.0
7.6? 21,00 Ib5.2 15S.2 14«,n
7.74 U.OO lhf>,2 1bfr.<2 l^Q.O
B.35 Ift.i.O 1*2,2 1B2.2 17?>.0
9,77 fl.no 190.2 19O.2 1«3.0
CiU'. TYPE Lft
yOT^NTT&L
'il'it TvPfc (WTQN) A'l^MAu C'IM85 C'.lH90
KklSTTMC 2,68 0,<4 0.3 0.3 0.
S.46 4.00 4.3 4.3 4.0
5.M6 9.00 13.3 1J.3 13,0
I.90520 6.4fl 4,00 \7,3 17,3 17,0
i. Si 040 7.12 a, 00 *»t.3 ?1.3 21,0
7 .(>?. 3.00 24.3 24.3 24.0
t.74 ?.no 26.3 26.3 2»»,0
8.35 4.n..i ?o.* 30.3 30.0
9.77 2.00 3?.* 32.3 32,0
-------
G-88
S'lllT'l
THAI 1VPF LD
.»
vICL
«i.S7
8,37
2.0
3.0
5.0
S.O
-------
G-89
* n M T A f J 4 , F A S T
COAL
P'UfK'MAL P^II'UtTIl'N (MMT/YlO
IVFF (*/TON) ANM'iAl. CUM85
7.81 2.00 2.0 ?.0 2.0
9.afl 2.00 fc.o a.o «.P
0.26 2.on 6.P 6.0 6.0
COAL Ty^>E LO
PHTFNTTAI.
CS/TON) A'-^iiAL CUM85
^'TSTIMU H.^7 0.50 n.b 0.5 0.
•11! iisO'^0 7|ob 9.00 17.5 17.5 17.0
nr
-------
G-90
COAL. TYPE
iriAir
TYPi-
'•it «. -V/ 207 30
MP ,-i.i>72 1030
Mi
Nfw.rtT?lorirj
oi. n
Mf. >.'. 03^0710
33.50
3b,77
S7.0U
37,10
37.73
47.89
3*.02
3^.95
41.11
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2. an
2.40
3.20
3.20
3.20
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Uo
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3.2"
3.20
3,20
2.40
2.40
3.60
2.40
1.60
3.60
2.00
3.60
1 .60
0.80
2. or
O.flO
?.40
O.Bu
I .20
2.4
4.A
10.4
13. *
16,A
1*.4
?0.0
21.6
23.2
24.A
26.4
32. ft
36.0
38.4
40.A
44.a
46.A
52|o
S3.6
60.A
61.6
66,H
69!r»
73J2
76.«
CUM90
i.4
4.8
10.4
13.6
16.8
18.4
?0,0
21.6
23.2
26,4
32|fi
36.0
38.4
40,*
44,ti
53,6
60.e
61 ,*»
63.6
64.4
68.8
69.6
72.0
73.2
7!i.6
76.8
8.4
4.H
7,2
10.4
13,6
16.8
18.4
20.0
21.6
23,2
24.A
26.
-------
G-91
MIJuTA ''*, --IF
MF
II 1*1 PymilCTTON MMT/YH)
(WTCJN) AMNiJAI, CU'185 r:il*9P CUM95
M»: ,.;.;>7'>7?1005 !<7.04 1,20 6,ft ft,^ 6."
ME *i. 06007 05 57.«9 O.«0 7.ft 7.6 7,6
Mfw,0480405 ^8.79 O.*0 «.4 *.'i *>.*
v'Kw)p4fl0705 *9!<>5 0.80 10.0 10.0 10.0
\,E*,t 0360405 40.97 0.40 1'1,4 10.4 10.4
*it! '* ,04R 1005 4i.ll O.dO Tl.2 1'.2 11.3
*i£w.i)3*»OTo5 42.16 0.40 ll.fr H .6 11«6
wfw.0720401 42.4ft 0.*8 12.5 12.5 1*.5
45.55 0.40 12.9 12.* 1?«9
44.66 0.56 15.4 U.4 13.«
47.02 0.56 14,0 14.u 14.C
Nf-.u.OT?0701 48.5^ 0.8P \ '•. 9 14, «* 1<1.9
49.59 0,72 15.6 iS.h lrS.6
••0.7* 0.5b Jb.2 lh.2 1^.2
52.47 0.5ft 16.7 lh.7 1^.7
S2.97 0.5fr 17.1 If.i 17,3
55.01 O.flfl 1».? 1».2 1*^2
55.57 0.7? 16.9 18.9 1*.9
57.24 0.56 19.4 \9.4 \9.«
58.28 0.56 20.0 20.0 20.0
59.52 0.56 20.6 20.6 20.6
f: w^i)5ft 1001 61.98 0.7? 21.3 21.3 41.3
0.56 21.0 21.8 21.A
-------
G-92
ANA, WF
_,_ ....... JIIAL PR&OUCTTOr (HMT/Y'J)
TVPf r.WTOfl) ANNU*L C'JMfl^ CMrt^O CUM9S
54.Hh n.ao O.a 0.4 o.«
%s.9s 0.40 O.H o.rt ^.*
37.04 0.4-T t.2 1.2 U2
42.4« 0,5ft 1.* l.H ^«ft
44.*6 0.40 2§!» 2.2 2.2
47.0? 0,40 £.«> 2.b 2.6
««.S3 n.^>6 3.1 3.1 3.1
J i- Ik ^(*
\>fr ^ 0^60401 49.S'? 0.48 5,o -'• J,"
-30.75 0.4,1 4.0 4.0 «iO
rj2.47 °.S2 a»^ a»5 *'3
Si?!^ 0.40 4.7 4.7 1.T
SS.OV 0.5ft b.J -5.3 b.J
•>S.S7 0.4« S.S ^.«* 5»8
wt v. fib ft 1001 57.24 0.40 ft.2 6.2 *•«
• r • •% ^ I •* ^k O fc4 fc • Q
iluq/i nlU 7*.4 7)4 7,4
MI.90 -1.32 r.' 7»7 7«7
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G-93
MQN7
ST
f= -.80S4-1
vf-:*. .si
Mr ii. SOS 10
51 0*0
S1 010
07*07 30
.:>7 21030
0600430
0
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(*/TiJN)
9.08
U.7?
13!
-------
G-94
COAL
•ilNf TV P|
F. X 1ST I MR
MR w.go'iuo
MF.J. 50550
M?v. 80520
M" n. Si 030
K'En.S1023
Mr w. SI 550
f.'E n.D7?0430
** "*. 07*0730
f>. 060] 030
JO
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(J./TON)
7.70
b.26
9.08
10.67
10.78
11.72
15.46
UJS'?
16.7U '
1/I21
17!«1
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19.08
19|65
20.06
20.36
?U06
21J70
24.23
2s|lO
26?06
26.21
26.^2
27.02
27.09
POTENTIAL PRODUCTION CMMT/VIO
ANNUAL
1 J.77
60.00
46.00
30.00
8. CO
17.00 ,
12.00
6.00
6.00
3.00
2,00
1,00
15,00
15.00
IS, 00
6.00
6.00
6.00
14.00
14,00
14.00
6.00
6.00
8,00
8.00
6.00
8,00
16.00
16.00
16.00
8,00
8,00
15.50
6,00
10,00
15,50
CUM85
13.6
73.6
121.6
151.8
159. 8
1 7t».P
IMA. 6
1 94.8
200.8
203.6
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206.
221.
236.
251.
457.
263.
269.6
2*3.1
297.8
311.6
319.0
327.8
335. A
343.8
551.6
359.8
375.8
391 .8
407.6
4)5.6
423.8
439.3
4fl7.3
*»57,S
-------
G-95
COAL TYPE SF
'Mf TyPP (J/TON) ANNUAL CUMftS CUH90 CUM95
52.3S O.SO O.S 0.5 0.5
*«,10 0.20 0.7 0.7 0.7
Mff w,i)4ftOu01 36.05 0.20 0,9 0,9 0,9
J7.«<> O.SO i.tt l.U 1-4
38.11 O.«0 1.8 l.M U«
59.1<* 0.^0 8.0 2,0 3.0
U0.4U 0.40 2.4 £.4 2.4
i.04fl0701 11.08 0.20 2.b 2.b *•*
i,07? 1001 a?,b*« 0,50 3,1 3,1 3.1
uallfc 0^20 l!7 3.7 3.7
(tS.Jb 0,^0 4,1 4.1 ".1
a6.2J 0.20 a,3 4,5 4,3
4ft.3« 0.40 4.7 4,7 4,7
•bO.5* 0,40 5.1 5,1 5.1
-------
G-96
TVPE-:
TV PC
. SI 020
Nf.i-.5H JO
MF 4.51010
ME -rf.51520
Mf w.82050
. 32530
Mf «i.S2010
w£w. 32520
ME.J.S3030
ME*. 32510
NEW. 33 020
Nfcw. 0720410
. 0720710
n. D721010
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. 07 20 7 Ob
ME l«i.06004Qli
MEK.D460405
N£«. 0601005
ME". S«530
(S/TON)
9.66
10.47
12.03
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14,51
14.73
IS. 63
17.01
I7.f>4
I ft .34
19.60
20.62
g\ § 14
«??. 26
23.79
?4.06
26.03
26.45
26. 86
27.1?
2P.10
2P .94
29.66
29.77
30.52
31.33
31.37
31.77
32.20
33.08
^3.11
54.02
3a!92
AHN»UA
2.40
1,60
2.4«
1.60
2.40
1.60
1.60
2,40
1,60
1.60
2.40
1.60
1.60
2.40
1.60
1,60
0.60
0.60
0.60
1,60
0.60
0.60
0,60
0.80
0.80
0,40
0,60
2.40
0.40
0.40
0.40
0.40
n.uo
CUM 8 5
6.4
8.0
10.4
12,0
13.6
16.0
17.6
19.2
21.6
23.2
24.6
27.2
26.6
30.4
31.2
32.0
32, *
34.4
35.2
36,0
36.8
37.6
38.4
39^6
42,0
42.4
42.8
43.2
43.6
44.3
44.7
47.9
CTTQN (hHT/r»)
CIJMQO
2.4
4.0
6.4
8.0
10.4
12.0
13.6
16.0
17.6
19.8
21.6
23.2
24,6
27,2
29.6
30.4
31.2
32.0
32.6
34.4
35,2
36,0
36,6
37.6
38.4
38.8
39.6
42.0
42.4
42.8
43.2
43,6
44,3
44.7
47.9
CUM95
?•*
4,0
6,4
8,0
10.4
12.0
13.6
16.0
17.6
19.2
21.6
23.2
24,6
27.2
26.6
30.4
31.2
32.0
32.1
34.4
35.2
36.0
36.6
37.6
36.4
36.6
39.6
42.0
42.4
42.6
43.2
43.6
44.3
44.7
47.9
-------
G-97
ri)Al
MB
TJAL P900HCTJON
I- X JST I -Jt
- I- . S2ot o
V.07?Oii
.w.,D7«>P7
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Mf *..(': 720405
Nfc»'. 0.5*0005
^F.»Hf
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12.OS
17.bO
2o!89
21.17
21.03
P3.79
27.00
27.80
28.10
28.94
29.30
29J77
29.77
30.52
31.3?
31.37
32.20
33.08
33.11
30. oe
30.36
30.92
3*!ob
59.OP
00.10
AMN'JAL
7.03
0.80
0.80
0.80
0.80
1.60
1.60
1.60
0.80
2.00
2.00
2.00
l!bO
1 .60
2.00
l.frO
1.60
2.00
1.60
1 .60
2.00
1 .60
1 .60
1 .20
1.60
1 .20
1.20
1.20
1.20
2.08
1.20
1.00
1.3*
2.0.1
0.8A
CUMI
7.0
ft. a
9.0
9.8
10.6
12.2
13.8
15.0
lfe.2
IB. 6
?1 .0
23.0
25J8
27.4
?9,8
31.4
33.0
35.4
37.0
38.6
01.0
02 §6
04.2
05.4
07.0
08.2
-------
G-98
*INF. TYPE
MH-.S1030
NFiN.S0510
Nt>'.51020
Mhk.. ,S1^3.)
Nt. -.81010
Nfc^. 81520
M. 32520
M. 0720720
MFW.P600720
Mf.w.S303o
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K-KW.S2510
new. 0720410
Nfc'".P720710
. 0721010
NFw. 06004)0
'•Ew. 96007 10
'JE-. 0720405
HE-. 0480710
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9.66
10.47
12.03
12.05
14.M
14.73
15.63
17.01
17. 64
18,34
19.60
20,62
20.89
21.14
21.17
21^86
22.14
22J43
23.79
24.06
26.03
26.45
26.46
27.12
27.40
27.84
28.10
28.28
28.81
291 30
29.66
TYPE *0
*>On»JTT*L PRODUCTION
CUM85
2.6
5.0
6.6
9|8
11. «
13.8
JT!O
21.0
22.6
2.64
2.40
1.60
?.40
0.80
1.60
2.40
1.60
2)40
1.60
2.40
1.60
1.60
3,20
3.80
1.60
1,60
2.40
1.60
U60
4.00
4.00
4.00
1.60
1,60
1.60
3.20
1.60
2.40
3.20
2!oO
31.4
34.6
37.8
39,4
41.U
4]S.4
45.0
46.6
48.2
52.2
56.2
60.2
61.S
63.4
65.0
68.2
69.8
72.2
75.4
77.8
79,8
2.6
5.0
6.6
9^8
11.«
13.»
15.4
17,0
19.4
21.0
?2.6
25,0
26.6
31J4
34.h
37.6
39.4
41.0
43.4
45.0
46.6
48.2
52.2
56.2
60,2
61.8
63.4
68^2
72!2
75.4
77.6
79.8
(HHT/Y8O
CUM95
0.
6.4
7.?
111?
IP.8
14.4
If.4
24.0
?7.2
2H.8
32,0
35.2
36.8
38.4
40.8
42.4
44,0
45,6
49,6
53,6
57,6
59,2
60,8
62,4
65.6
67.2
69.6
75J2
77.2
-------
G-99
COAL TYPE
TYP?
ME-'. P7
J8.9
J9.0
(MMT/YR)
CUM9P
0.8
1.6
2.4
3,b
4.8
5.6
6.6
7.6
8.4
9,2
1^.0
10.6
1 J .?
11.6
12. «
12. ft
13. «
13.9
1«5.0
15.6
15.7
17|o
17.4
17.9
18.0
18.6
18.9
19.0
CiJM<
*.8
1.6
2.«
3.6
0.6
5,6
6.8
7.6
P. 4
9.2
1P.O
10. A
11.8
M. 6
12.4
12,8
15.4
13,9
15.0
15.6
15.7
17.0
17, 'I
17,9
18.0
18,6
18.9
19,0
39.08
uO.Hb
4 3 i 91
44.91
TYPf MH
POTENTIAL
0P J
nt K.(Viol 001
0.16
O.OP
O.lh
0.08
0.08
0.08
0.16
0.08
0.08
0.08
0.08
0.2
0.2
0.6
o'.7
0.9
1.3
1.0
1.1
1.2
ICTIPM (*"T/Y»)
0,2
0.2
0.3
0.5
0.6
0.6
0.7
0.9
l.P
1 .0
\.\
0,2
0.3
o,5
< .6
0.6
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1.0
1.0
1.1
1.2
-------
G-100
.•I YD". INC.;
COAL
-J JF TVPt
PXTSTlNtt
MF.U.S05<*0
'if. w.. SOS 10
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M* 4. SI (
ME*. 5} 010
NF.I.D7204 JO
N£ -.07 20 7 30
NFw. 0600730
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. 06007 20
i.n60io2o
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•Jfcw. 07407 \n
F.Ai. 06007 10
P»ICt
6.55
f. •'.. 14^0710
A.32
10.bo
11.26
I?.87
13.46
13,63
13.61
14.10
• • w • —
15.J9
15,60
15. B2
16.17
16.39
16.62
16,97
17.21
19)55
19.A6
20.20
?0.63
21.37
21,79
21 ,86
22.16
0.05
16,00
19.00
10.00
5.00
6.00
2.0"
1.00
2.00
1.00
6.00
6.00
6.00
3.00
3,00
3.00
10,00
10,00
10,00
4,00
4.00
4.00
4.00
4.00
4.00
10.00
10.00
10.00
6.00
6.00
9.00
6.00
7,00
9,00
7.00
4.50
COM8S
0.0
4*4.0
55.0
57.0
5A.O
6l!o
67.0
73.0
79.0
"2.0
(HMT/VH)
0.0
16.('
34.0
4U.O
55'.0
57.0
5*.0
60.0
61.0
67.0
73.0
79.0
flrf.O
85.0
0.
34.0
44.0
55JO
57.0
5B.O
60,0
61.0
67,0
73.0
79.0
42.0
A6.0
96.0
106.0
114.0
1?2.0
126.0
130.0
1 34.0
136.0
142.0
152.0
\62.0
172.0
17«.0
1 A4.0
193.0
199. P
206.0
215.0
222.^
226.5
9rt .0
10*. 0
ll&.O
1 ?2.0
126.0
1JO.O
134.0
13*. 0
1 4 ? , 0
152.0
162.0
172. ii
178.0
1HU.O
193.0
19«».0
20f>.0
215.0
222.0
226.5
9 If ,0
10ft. 0
11*. 0
1??.0
l?6.0
130.0
134.0
13A.O
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152.0
1^2.0
172.0
178.0
1M4.0
\93.0
J«'9.n
206. n
215.0
P22.0
226.5
-------
G-101
CHAl. TVPE -1H
ANNUAL COMA'S
*' « I 8 T I
CUH90
. sos 10
. 30520
>'£!«..•> 7 20 7 JO
«<, 0601020
\F-i.n7204lo
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. 0^007 10
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6.99
6.23
10,SO
13.61
17.21
17.46
19!«6
20.63
20.99
21 .21
21.37
21.79
21.BA
22.16
?2|S7
22.bl
23,01
23.15
23,40
23.81
23.82
4.00
3.00
2.00
2,00
?.00
3.00
3.00
3.00
4.00
4.00
4.00
2.00
?,0ft
2,00
2.00
2.00
2.00
4.00
4.00
4.00
3.00
3.00
4.00
3.00
2.00
4.00
2.00
2.50
2.00
4.00
1 .00
2,^0
1.00
3.00
1.00
12.2
15.2
17.2
1 9.2
21.2
24.2
27.2
30.2
34.?
38.2
42.2
44.2
46.2
4A.2
50,2
52.2
54.?
58,2
62.2
66,2
69.2
72.2
76.2
79,2
81.2
85.2
*7 ,2
«9.7
91,7
95.7
96.7
99,2
100.2
103.2
104.2
12.2
15,2
17.2
19.2
21.2
24.2
27.2
30.2
34. 2
38.2
42.2
44.2
46.2
48.2
50.2
52.2
54,2
58.2
6?. 2
66.2
69.2
72.2
76.2
79,2
81.2
85,2
87.2
89.7
91,7
95.7
96.7
99.?
100.2
103.2
104.2
0.
'l.O
7.0
1 1.0
13.0
16.0
19.0
22.0
26,0
30.0
34,0
36.0
38.0
40.0
42.0
46,0
50.0
54.0
Sft.O
61.0
64.0
68,0
71.0
73.0
77.0
79.0
81.5
A3,5
H7.5
HA.5
92.0
95.0
96.0
-------
G-102
COAL
PBICE POTENTIAL PRODUCTION (MMT/YR)
M
E«I
NiF.W
Nf. W
ME-
N£W
ME Ui
*JE»
MEw
NEw
NEW
Nf W
siEw
MEW
NEW
NEW
MEW
NEW
MtW
N£W
NE*
Mf.;w
Mf> W
Mfc'W
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M£W
NEW
ME hi
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NEW
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NEW
MEN
Nt <*
JVE TXPE
STlMG
.80540
.30530
.50520
.S1040
31030
*S1020
" S1540
!si530
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.31520
.31510
.0720420
.0720720
.0721020
.0720410
.0720710
.0721010
.0600410
.0600710
.0720405
.0601010
. p4^0 (1 10
,07 ?07 05
.04807 1 0
.D600405
D4A101 0
0721005
|0600705
.04AQU05
.0601005
,04807 05
.0360405
,041) 1 005
,0360705
(S/TON)
a, 14
5,90
6.35
6.99
7.78
». 21
fl.32
9,10
9.68
10. J4
10.50
11.26
12.87
15. J9
15.60
IS. 82
19.53
19.86
20.20
20.63
20,99
21.21
21.37
21.79
21. »8
22.16
22.47
2?. 57
22.61
23.15
23.81
23.91
24.52
2 b, fife
25.30
25.99
ANNUAL
4.32
196.00
147,00
100,00
36,00
50,00
27.00
20.00
12.00
9.00
9.00
6,00
3.00
2.00
2.00
2,00
3,00
3.00
3.00
2.00
2.00
2.50
2.00
2.00
2.50
2.00
1.50
2.00
2.50
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.50
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.50
.50
.50
.50
CUM 8 5
4.3
200.3
347.3
447.3
483.3
533.3
560.3
580.3
592.3
601.3
610.3
616.3
619.3
621.3
623.3
685,3
628.3
631.
634.
636.
638.
640.
648.8
644.8
647.3
649.3
650.8
652.8
655.3
656.8
658.3
659.8
661,3
662.8
664,3
665.8
CUH90
tt«5
200.3
347,3
447,3
483.3
533,
560.
540.
592.
601.
610.
616.
619,
621.3
623,3
625,3
628,3
631.3
634.3
636.3
638.3
640.8
642.8
644,8
647.3
649.3
650.8
652.8
655.3
656.8
658.5
659.8
661.3
662.8
664,3
665.8
CUM.15
o.
l9fc.O
343.0
443.0
479.0
529.0
556,0
576.0
588.0
597.0
606.0
612.0
615.0
617.0
619.0
621.0
624.0
627.0
630.0
632.0
A34.0
636,5
634.5
640.5
643.0
645.0
646,5
648,5
651,0
652.5
654.0
655.5
657.0
*>58.5
660.0
*61 .5
-------
G-103
COAL. TVPf SF
TYPF
Nitw. 0720410
Mf>. 07(?07 10
Me w. 07? 1ft ift
MEw.0721003
*Fw. 0600705
MKW.04B1005
n. 07?07ftt
ppjCE
F (S/TONl
4.14
S.90
6.3S
6,99
8,23
10.50
0 1 9.53
o 19 ,86
ft 20.20
5 21,21
5 21 .8*
5 22.47
5 22.61
5 23.15
5 23. »1
5 23.91
5 c*4.b2
5 25. $0
1 26.31
1 27.75
1 2q.30
1 50, 12
1 30.99
1 31.57
1 33.13
1 34.00
1 34.83
1 35.44
1 37. oa
1 58.7-3
POTRNT
ANNUAL
0.64
4,00
3.00
2,00
1 .00
1.00
1,00
1.0ft
1 ,00
0,50
o.Sft
0.50
0.50
0.50
0.50
0.50
ft. 50
0.50
0.90
0.70
0.70
0.90
0.60
0.70
0,70
0.90
0,60
0.70
ft. 70
0.60
m KM
CUH85
0.6
4.6
7.6
9.h
10.6
1 1 .6
12.6
13.6
14.6
15.1
15.6
16.1
16.6
17.1
17,6
14.1
16.6
\9. 1
20.0
20.7
21.4
?2.3
22.9
23.6
24.3
25.2
25. fl
26.5
27,2
27. «
CTTHN
CLIM90
0,6
4.6
7 ,b
9,6
10.6
11.6
12.6
13.6
)4.6
15.1
15. h
16,1
16.6
17.1
17.6
• 11 •
4 w • £
J •» • O
20.0
20.7
21.4
22.3
P2.3
25.6
24.3
25.2
P5.8
26.5
27.2
27.8
(MMT/VR)
CUM95
°.
4.0
7,0
9.0
10.0
tl.O
13.0
13.0
14. 0
11.5
15. ft
15.5
16.0
lb.*5
17.0
17.5
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19)4
20.1
20.8
2U7
22.3
23.0
23.7
24.6
25.2
25.9
26.6
27.2
-------
G-104
fr. TVPF.
F* i JIT i
, 07*0701
.D^fcOaOi
. 0600701
Nt-i.p721001
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Mf ^.Jfc
PMTCK .
(J./TUN)
ML" «.-)7 21005 20.10
26.01
26.74
27.50
28.00
3o|l7
30,89
31.44
32.83
34.36
POTENTIAL
ANM'JAL CIH85
l.OJ 1.0
f*. DJ6 1001
0.50
O.SO
0.60
0.50
0.50
0,60
0.20
0.50
0,5*1
0.60
0.20
o.sn
0.50
0.20
3.5
4.0
b!l
6|7
4.0
s!i
5.6
6.1
6.7
6.9
7.4
e',5
(«
CUM9«>
2io
s!o
3.5
-------
G-105
COLORADO,80UTM
COAL TYPF ZA
NTT.AL
KXiSTlMi 10.b7 1,V i.6 t.t "•
<«.*& 0.42 2.0 2.0 O.fl
MA _-,. A ^ 9 ^9 0 « fc
•if.»i 0*00^01 4O,6fe O.al S.« *•<• •
2.4 2,4 0.6
™T_"^>-^>*^*^\^» -T •. w —• - -™--™ - _
Mfc^.07?070\ 4'3,56 0.42 2,8 2.8 )•>
NF.j,0'0701 45.35 0.21 3.1 '«! »»J
47.30 0.21 3.3 3.3 1.7
a«.38 0,48 3.7 3.7 2,2
49,43 0.07 3.« 3.8 2,2
:!o6010oi SO,20 0.21 4,0 «.0 2.4
52.17 0.21 «.* «.* 2.7
54.30 0.07 4,3 tt,1 i?.7
COAL TVPF z»«
POTENTIAL P100UCTIOM (MMT/Yi»)
•.1l^l^ TYPK (WTON) ANNUAL CUH%5 C'lM«0
|f»lSTI«J(i 10.67 0.9fl 1.0 1.0 0,
COAL TVPfc ZO
PWICF POTENTIAL PHODUCTION C"MT/Yli)l
•Tlf. TVPfc (.S/TI1N) ANNUAL CUMM C»"1'0
PXISTINI. 10.67 0.3«» 0.4 O.tt 0,
-------
G-106
Kwjtr f 111 r IY i i • u ^• i'111n, i i!."•' (^WT/YIJJ
(JR/ION) ANM.IAL CIJMB5 CUM^O COM
10.67 0.0ft 0.0 O.f" 0.
25.'8 0,80 0.8 O.fr 0,«
0720705 26.52 0.80 1.6 1.6 1.6
D600405 27,15 0.40 2.0 P.O 2.0
l)7?1005 27.30 0.80 2.8 ?.« 2.«
0600705 4P070S 20.39 0,40 4.4 4.4 4.4
0<«Ain05 30.22 0.40 4.8 *.« 4.A
0720401 31.32 0.48 5.3 5.3 5.3
*.>Q^U -* Q -# •• * W vvfv
,0600401 32.86 0.24 5,5 5.5 5.5
34.58 0.24 5.8 5.8 5,8
35.48 0.4A 6.2 6.2 6.2
36.43 0.32 6.6 6.6 6,6
37,05 0.24 6.8 6.8 6.8
--.,rwi 3ft.77 0.24 7.0 7.0 7."
T21001 39.74 0.4ft 7.5 7.5 7.5
0360701 40.63 0,32 7,8 7.8 7,8
M.5? 0.24 8.1 H.I *,1
• -' 0,24 8,3 8.3 9,3
0,32 8,6 8.6 8.6
-------
G-107
TYPE HA
TWICE
(S/TON) ANMilAt, CNMH5 C"M9fl CUM99
P3.96 1 .60 1.6 1.6 1.6
«?4.S2 1.60 3.2 3.? 3.2
20.70 1.60 4.9 4.A 4.ft
25.17 0,80 5.6 5,b 5.6
?5.55 O.AO 6.4 6.4 6.4
?5.78 O.AO 7.? 7.2 7,?
25.94 O.AO P.O A.O A.O
ME-.P7P0705 26.'is? 0.80 rt.A A,fc h.A
-IF --.0600405 27.15 0,40 9.2 9,j 9,2
Mt«.0721005 27.30 0,80 10.0 JO.o 10,0
KlF.'.0600705 27.91 0.40 10.4 10.4 10,4
2A.61 0.80 11.2 11.2 11*2
28.71 0.40 11.6 11,6 11.6
Mt«.n4A070S 29.39 0.80 12.4 12.4 12.4
Mtn.0360405 30.19 0.40 12.8 12.B 12.A
ne-j.OaBinob 30.2? O.AO 12.6 13.6 13.6
Mf.w. 03607 05 30.09 0.40 14.0 14.0 14. fl,
ME-i.D720401 31.32 1.04 15.0 15.0 1«».0
31,A3 0.40 15.4 15.4 15.4
3?.86 0.4A 15.9 15.9 15.9
34.5A O.AO 16.7 16.7 16.7
3b.4H 1.04 17.H 17.8 17.8
36.43 0.64 IS.4 1A.4 18.tt
37.05 0.48 18.9 !».«* 1*,9
5».S3 0.32 19.2 19.? J9.2
38.77 0,80 ?0.0 20.0 20.0
39,74 1.12 21.1 21.1 21.1
40.63 0.64 ?>.e 21.A 21.A
41.32 0,56 22.3 22.3 ?2,3
NEW.02A0701 4?.72 0.32 22.6 22.6 22.6
N'E^.OUAlooi 43.06 0.86 23.5 23.5 23.5
fcu.94 0,64 24.2 24.? 34,2
47,0? 0.32 24.5 24.5 24.5
-------
G-108
SOUTH
COAL TVPF HB
PRODUCT
TVPF
w. 0780410
. 07*0710
wf w.D7j?0405
NEU.072070S
Mtu.ObOOuos
"Fw. 0721005
Ngw.n3b040S
Ntw.03b0705
NFw. 0720401
we*. 0361005
. 0480401
Nf -1.036040)
NFw. 0600701
Ntw. 0280401
N£W,04A()701
Nf n.07?1001
•IF *,nbO]OOl
Nf: ^
Mt-<
wE J.0i?8i00l
84.70
30.19
30.22
30.99
3UB3
3?.86
?4.b8
35.4A
36.43
.17. Ob
36.53
3A.77
39.74
40.S3
41.52
48 \ 78
44.06
44.93
47.02
5?.79
0.40
0,80
O.AO
0.40
1.20
0.80
0.80
O.AO
0.60
0.60
0.40
O.AO
0.40
0.64
0.40
O.U8
0.48
0.64
O.AO
0.46
0.72
0.48
0.72
0.80
0.4A
0..32
0.73
0.4A
O.HO
0,78
0.48
0.48
0.4
1.2
2.0
3J2
4.4
5.6
6.4
7,6
10.0
12.0
12.4
13.0
13,4
13,9
14.4
15.0
15.6
16,3
17,0
17,5
18.2
19.0
19.5
19.8
20.6
21.0
21.6
22.6
23.0
23.5
0,4
1.8
*!«
3,2
4.4
5.6
fc.4
7.6
8.4
9.2
10,0
10.6
11.2
12.0
12.4
13.0
13.ft
13.9
14.4
15.0
15.8
16.3
17.0
17.5
16.2
19.n
19. 5
19.6
80.6
21.0
21.8
82.6
23,0
83.5
0.4
1.?
2.B
3.?
4.4
5.6
6.4
7.6
9J2
10.9
10,A
11.2
12.0
12.4
13.0
13.4
13,9
14.4
15.0
15.6
16.3
17,0
17,5
18.2
19.0
19,5
19,A
20.6
ail*
2?.6
83.0
23.5
31 .38
3S.46
36.4*
39.74
40. 65
48,78
44.9!
47.02
COAL TVPE MC
POTENTIAL PHODUCTIHN i
ASNUAI. CUM8S C'lrl90
0,06
O.OA
0.08
0.08
0,06
0,06
0,08
O.OA
0,06
0.1
0.2
0.2
0.3
0.4
0,5
0,6
O.b
0,7
0,1
0.2
0.2
0.3
0.4
0,5
0.6
O.b
0.7
0,1
0.2
0,2
0,4
0.5
0,6
0,6
0,7
-------
G-109
, SOUTH
COAL TVPE HO
. 31 010
wt to. P720710
MH.D781010
MEW.S2005
Nfc-w.
NEw. 0600705
NEW.P48070S
Nfchi. 0560U05
w.o««oaoi
\i t «•: . n $ fc 0 7 G i
M: w. 060 1001
50.19
30.2*
30.99
31.32
32i66
36.43
37.OS
3H.S3
3ft.77
39.74
41 J32
^« 1 «-C
lu 05
14 J84
16.56
17.17
1H.08
10. i«
21 .69
2.X. 96
24.32
24. 70
25.41
25.7S
26.52
27.15
P7.30
27.91
2* .61
2ft. 71
2<>]39
^ V 1 U r-
ANNUAL
0,80
1.60
1.60
1,60
0.80
1.60
1.60
0,^0
0,60
0.60
1 .60
0.60
0.80
0.40
0.80
0.40
0.40
0.40
O.flO
0.40
1 1 ^ 1« r *«-'-.•
CUH85
0.9
2.4
4.0
5,6
6.4
6.0
9.6
10.4
11.8
18.0
13,6
14,4
15.2
15.6
16.4
16.8
17.8
17,6
lft.4
16,8
CUP90
0.8
2.<»
4.0
5.6
6.4
6.0
*.*
10.4
11.8
18.0
13.6
14.4
15.2
15.6
16.4
16.6
17.?
17.6
16.4
16.8
r U M '
0,B
2.4
4,0
5.6
6.4
f,0
9.fc
10.4
11.8
18.0
13.6
14.4
1.5.2
15.6
16,4
Ih.M
17,8
17.6
1H.4
1ft. 6
0.40
0.40
0.48
0.40
0.56
0.56
0.48
0.48
0.56
0.56
0,48
0.40
0.56
10.2
aoio
20.5
20,9
21.4
82,0
?2,5
?3.0
23.5
2<».0
24,6
?S.O
25.5
26.1
19.6
20.0
20.5
?0.9
21."
28,0
23!o
23.5
?4.0
2b.l
19,2
19,6
20.0
80.5
20.9
81."
2?.0
82.5
23,0
83.5
24.1
24.6
85,0
85.S
86.1
-------
G-110
SOUTH
? ; F * , o 7 8 r. u r 1
Nfei-'.[i7207ni
Mr ri.O
PPICE
fS/TOM)
:«i .32
37.OS
56.S3
4?.7?
4 ?. (Ib
n.lf.
O.Ofl
0.0ft
O.U
0.16
0.0ft
0.16
0.16
0.08
0.24
0.08
0.16
0.24
0.2
0.2
0.5
0.6
0.7
.0
.0
.2
.4
.4
.7
!o
0.7
1.0
1.0
1.?
.7
.a
2. a
TYPE
POTfMTIAL PSODHCTION («*T/VP)
CllMQO
0.2
0.2
0.3
0.5
0.?
0.2
0.3
0.7
1,0
1.0
1.2
1.4
1.7
i.a
2^2
-------
G-lH
, SOUTH
cn»i.
HJME TYPk
I STING
>'.31010
LI . S 1 5 1 0
MF-.-.S20IO
ME..J.S ISO'S
N^. I? 7 204 13
\f *'. 0730710
Nf w. 0731010
Nf w.i)h00410
N£. w. 94001
*l -4.0600710
\»r w. Oh 00 7 05
Mfc W.
Mf:-'.
se. wi.
P.WTCE
(*/TQiO
I1*.04
^1. 0360701
23.78
35.94
27| 15
27.30
27.91
§0.19
50.22
30.99
31.32
31.M
54^58
37.05
3H.53
.5*.77
40.74
ao.63
AMNIJAL
0.92
0.80
1.60
-0.40
1.60
1.20
1.60
1 .60
0.80
0.80
0.80
0.80
0.80
0.40
0.80
o.ao
0.80
o.ao
o.ao
0.80
o.ao
0.80
o.ao
0.96
n,,4
2.8
a.a
5.6
7.2
4.8
10.a
11.2
1$!?
14.0
14.8
15,6
Ib'.S
17.2
Idla
18.8
19.6
2o!s
21.2
22.2
£2.6
23.0
23.8
2a,8
25,5
26.0
26.4
J>7.?
26.9
-------
G-112
COLORADO,SOUTH
CUAI.. TYPE
EXIST I MS
. 0720710
. 0721010
M. 0600705
.w.naaouos
w. 0601005
t ".04* J005
fc*. 0360705
-i.o '56 1005
KF. a. 1)720701
NEw.n'jJbOaoi
ME -(. 0600701
^. 1)^60701
i*. 1)60100)
J-'-'ICf
P7.91
30.99
31 .52
12.«6
35!«P
an.6)
41 .92
Uu.95
at.Of
AMNUAt
2.93
0,80
0.80
0.80
0.80
O.ftO
0.40
0.80
o.ao
0.40
o.ao
o.ao
0.40
0.40
O.ao
0.64
0.40
0.64
0 ,64
0.64
0,24
0.64
0,16
0.64
0.64
0.24
0.6a
0.16
0 fc {1
O ^ 4i
0.16
COMAS
£,q
3.7
a,b
5.3
6.1
h.9
7.3
4. 1
8.5
8.9
9.3
9.7
10.1
10.5
10.9
11. b
12.0
12.6
13.2
13.9
14,1
14,8
14.9
15.6
16.2
\6.4
17.1
17.2
17.9
18.1
18.3
2.9
3.T
5!3
6.1
7i3
8.1
a!*
9.3
9.7
10.1
10.5
10.9
I 1.6
12.0
12.6
13.2
>3.9
14.1
14,H
14,9
15.6
16.2
16.4
17.1
17.2
17.9
18.1
18,3
0.
0,8
l.t
2.4
3.2
4,0
4,0
5.2
5.6
6.0
6.4
6.8
7.2
7,6
8.6
940
9.7
10.3
11.0
11.2
11.8
18.0
12.6
13.3
13.5
1ft, 2
15.2
15.4
'iVt TVPF
F«ISTI\C
8.91
COAL TYPE MF
POTENTIAL
ANNUAL
0.76 0.9
C"MC'0
O.b
0.
-------
G-113
UTAH
T*. 32501
(S/TflN)
COAL TYPE
0.0*
0.08
0.06
0.2
0.1
0.2
0.2
(MMT/YB)
0.1
0.2
0,2
COAL TYPE HH
MT>if. 1YPF
F X I S T I NG
NKw. 0720*10
MEu. 0720710
. 0600405
. 0721005
. 0600705
*. 0601005
-i. n.48 1005
*. 0720401
Mfc*. 0720701
Hi -.0360401
ME*. 0600701
1001
»0701
ME. vi. 060 1001
Nf»'.P«»lP01
MFw, 0361001
2?.69
23.03
25.38
25.48
26.76
29.23
32! 33
33.06
34.10
3b!l7
36.97
37.94
«1.B9
POTENTIAL PRODUCTION
ANMUAL
6,50
0.60
0,60
0,80
0,00
0,80
0.60
1.20
0,60
0.60
0.60
0,80
0.80
0.96
0.4A
0.4A
0.96
0.56
0.4fl
0 ,4A
0.64
0.56
0.46
0.4A
0.56
CI.IMAS
6.5
7.3
«.l
6,9
9.7
10.5
11.3
12.5
13.3
l«.l
14.9
15.7
U.5
17.5
17.9
18, a
19.4
19.9
?0«4
?0.9
21.5
22.1
22.6
23.1
23,6
CIIH90
6.5
7.3
• *
A U
9*,7
10.8
11.3
12.5
13,3
14.1
14.9
15.7
16.5
17.5
17.9
1 A. 4
19,4
10,9
20,4
20, «*
21,5
22.1
22, b
23.1
23.6
(MHT/VS)
o,
O.A
2.4
3,2
6.0
6.A
7.6
A.fl
9.2
10.0
11.0
11.4
11.9
12.9
13.4
13,9
14.4
15,0
15,6
17.1
-1TNE TYPf
V.S1501
i- .St?noi
PWICfc
(S/TOM
S6]s7
TYPE HP
ANNUAL
D.OA
0.0 A
0.0«
0,1
0,2
0,1
0.?
fMMT/YK')
0,1
0.2
0.?
-------
G-114
UTAH
CD At. TVPF 30
•JAI. BjnmiPTT inJ ('<•
s*
IAL
MlNt TvP^ (S/Ti'iN) ANNIHU t,unf«:i ^,.r--r-. ~-
Mr/.SlOOl ib.SH 0.0* 0.1 0.1 0.1
"H..IISOI o*.£ o.j* j;j J-J ft;fl
bfr]sH o]lb O.b O.fr «>.*,
77.sa o.oft n.h o.h o.fc
MI "If TVPP r*/TPw^ AKlNUAL
NE-'siOOb l-i.38 0.40 0.0 0.4 0.0
-%A DA JA
21.bl l.*0 2-A *•* *•*
25 01 1.20 0.0 ft.O «.0
28.f,? 0.40 4.4 ft.* ••«
56.5ft o.«n "•* a«8 *•?
46.fl« 0.8ft 5.7 5.7 5.7
5 •»•»• **
ix «o rt AA 74 7.4 7.0
on.on u.nn '«w • ••
77.54 0.40 7.ft 7.ft 7.B
-------
G-115 .
M: w , S 1 0 1
*. 51*01
COAI. TVPE HO
PMTCE POTENTIAL PRODUCT 11'.1M (MMT/VW)
A.'JMIJAL CUMrt!» CM190 CiH9S
«.55
12.20
I 4.41
15,78
16.70
18,97
19.1?
22.24
37,09
47,12
57,28
67.69
6.S9
1.60
0.80
0.40
0.80
0.80
0.80
0.80
0.40
0.40
0.40
0.4?
6.6
fl,?
9.0
9.4
10.2
11.0
1 l.A
12.6
13.0
13.4
13.*
M.I
8,6
8.2
9,0
9.4
10.2
11.0
1 1 . ft
12.6
1S.O
13.4
13.8
M.I
0.
1.6
2.4
2.8
1.6
u.u
S.2
6,0
6. a
6.8
7.2
7.5
COAL TYPE 3F
P*m POTENTtAI. PPOOUCTTtl.M
TvPF (S/TDM) AMf'UAL CUM85
001 ?8.9J
0.20
0.10
0.10
o.ir
0.2
0.3
0,4
0.5
0.2
0.5
0,4
o.s
0.2
0.3
O.fl
0.1
-------
G-116
TYPE
: W. 06007 If)
W. 0601010
N£w. 03607 10
Nfrt. 0361010
NEW. 060 1005
Mtw.0560705
. 0720701
PRICE:
(4/MN)
1.79
^S.88
26,03
26.93
27.25
57.34
27.3«»
i?7.8b
28.01
28! 7,?
-»8.74
28.81
29.50
30.30
30. 3P
-M.IO
31.41
32! 01
32.14
32.97
34169
S6!5S
38.66
COAL TYPE HA
PnT£>Tl»L PSTinuCTTON
CHM90
1.6
4|8
9.6
6.4
A.O
4.8
1 .60
0.80
0.80
1.60
0.80
0.80
0.80
0.80
0.40
0.80
0.80
0.40
0.80
0.40
0,80
1.20
0.80
0.80
0.8(J
0,b*
0,80
0.88
1.20
1.28
O.Sfa
1.6
3.2
s!6
6.4
fl,0
4.8
9.6
lala
12.9
13.6
15.2
16.0
16.8
17.6
18.0
20.8
21.2
22.0
23.2
?6.2
27.0
27.8
30.3
3?!?
11.2
12.0
12.*
13.6
1-5.2
lfc.0
16.6
17.6
18.0
18.6
19.6
20.0
20.8
21.<
22.0
23.2
24.0
24.B
95.6
26.2
27.0
30,3
30.9
32,4
33.3
CUM95
1.6
5,2
•5.6
6.4
8,0
8.A
9.6
11.2
12.0
12.8
13,6
15.2
16.0
16.A
17,6
10,0
18.A
19.6
20.0
20.8
21.2
22.0
25.2
24.0
25, 6
26.2
27. 0
27.A
29.0
30.3
30.9
52. 4
S3.3
-------
G-117
COAL TtPE
-sjf TYPE
TIW;
S102P
N£W .SHU 3
Mfcrf.0360401
H. 03*0701
w.RhOlOPl
w. SlOOl
PRICE
a.55
12.47
14^77
16. U9
17.99
21.62
3l|4l
32.97
34.69
35.57
37!l5
3R.87
39.A3
41.42
NFW. 82001
P'lTfc'NTIAL P9UIKICT10N
A^NUAt.
0,5*
1.60
2.40
1.60
1.60
0.80
0.80
0.40
O.Urt
0,16
0.16
O.ttrt
0.0ft
0.16
0.16
0.40
O.Ofl
0.16
0.40
0.16
0,0ft
0.32
0.3P
CUM 8*1
0,3
2.1
u.S
6.1
7.7
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9.3
9,7
10. i
10.3
10.4
10. e
10.9
11.1
11.2
11.6
11. T
11.9
12.3
12.4
12.5
12. ft
13.2
CHM9
0.5
2.1
4.5
6.1
7.7
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9.3
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to.i
10.3
10.4
10. ft
10. <»
11.1
11.2
11.6
11.7
11.9
12.3
12.4
12.5
12. *
13.2
CUM9S
0.
1.6
$!*
7.2
9.0
la
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(9
10.3
10.4
10.7
11.1
11.2
11.4
11.A
11.9
12.0
12.3
12.6
-------
G-118
ME* MEXICO .
l' Ml. SI 430
ew. si 010
Mt ' * . 3 1 '1 1 .1
NEW. 920*0
MFw.S 1005
NEW, 0721010
Nfcw.ObO()«o5
Mt*.r>r21D05
M£' to, 0*007 05
Nf:w.f5bC1005
ME •<. 0480/05
64. D&0070J
f *
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14)77
17J13
19)09
' ..si oo i
27.39
28.01
28J81
29.50
3^.32
51.41
32.97
34.b9
35.57
36.55
37.15
38.66
38.87
<9,8J
40.74
41. '12
42.27
COAL
ANNUAL
9.60
11.20
7.20
12.80
9.60
11.20
4.40
1,60
3.60
0.80
0.80
0.80
1.20
0,80
0.80
0,40
0,40
0,40
0,40
0,40
0,40
0,56
0,56
0,56
0,56
0,56
0,56
0.08
0.56
0.56
0.56
0,56
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78,8
79,6
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21.67
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1.50
1,50
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1.50
1.50
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41.0
42.5
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48.5
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54.6
55.7
56.6
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12.0
15.0
17.0
19.0
21.0
23.0
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27,0
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30.5
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36.5
36.0
39.5
41,0
42.5
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50.4
51.5
53.6
54.6
55,7
56.6
56.7
59.5
60,7
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4,0
6,0
9,0
18.0
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19.0
81.0
23.0
85.0
87.0
89.0
30.9
38.S
35.0
36.5
39.5
41.0
48,5
44,0
45.9
47.6
49.3
50.4
51,5
53,6
54.6
55.7
56.A
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59.5
M.9
------- |