p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

310) IV-B-14 

Docket Number: 

A-83-27 

Printed 11/12/200811:12:59 AM Sheet 310 of 325 
P.2 

f RADIAN A-83-27 

CORPORATIO N IV-B-14 

MEMORANDUM 

DATE: April 15, 1987 

TO: Fred Porter and Walt Stevenson, EPA/SDB 

FROM: Edward Aul and Butch Stackhouse, Radian Corporation 

SUBJECT: Impact of New Fuel Prices on the Costs and Cost Effectiveness 

of SOp Emission Control of Industrial Coal- and Oil-Fired 

Model Steam Generating Units 

1.0 SUMMARY 

In August 1986, fuel price projections for coal, oil, and natural gas 

supplied to industrial markets were revised. This memo examines the impacts 

of the revised price projections on the incremental cost effectiveness (CE) 

of S02 control for typical model steam generating units (i.e., boilers). 

With regard to coal-fired boilers, the revised price projections have 

little impact. Table 1 shows that the CE of S02 control under the new fuel 

price projections is similar in magnitude to the CE of S02 control under the 

previous projections. The incremental CE of S02 control associated with a 

standard based on using low sulfur coal over the regulatory baseline is 

$350/Mg ($320/ton) or less under 1986 price projections; in the prior 

analysis this value was near $460/Mg ($420/ton) or below. The incremental 

CE of SO- control associated with a standard requiring a percent reduction 

in S02 emissions over a standard based on using low sulfur coal ranges from 

$890 to $1,720/Mg ($810 to $l,560/ton) under new price projections; in the 

prior analyses this range was $770 to $2,050/Mg ($700 to $l,860/ton). In 

addition, the cost effectiveness of S02 control associated with these 

regulatory alternatives for coal-fired boilers operating at lower capacity 

utilization factors are also of the same order of magnitude under both the 

new and the previous price projections. 

The impacts of the revised fuel price projections on the incremental CE 

of S02 control for typical oil-fired boilers are summarized in Table 2. In 

contrast to coal-fired boilers, the revised projections have a significant 

Progress Center/3200 E. Chapel Hill Rd./Nelson Hwy./P.O. Box 13000/Research Triangle Park. N.C. 27709/(919)541-9100 
^ 

ro 

TABLE 1. IMPACT OF REVISED COAL PRICE PROJECTIONS ON THE INCREMENTAL COST EFFECTIVENESS 

OF REGULATORY ALTERNATIVES3 

Incremental Cost Effectiveness, $/ton 

1984 Coal 1986 Coal 

Price Projections Price Projections 

Alternatives Compared Region V Region VIII Region V Region VIII 

29 and 44 MW (100 and 150 million Btu/hr) Steam Generating Units 

Low sulfur coal over baseline 410 210-220 310 40 

Percent reduction over low sulfur coal 1,320-1,730 1,620-1,860 1,280-1,560 1,150-1,360 

73 and 17 MW (250 and 400 million Btu/hr) Steam Generating Units 

Low sulfur coal over baseline 420 230 320 50-60 

Percent reduction over low sulfur coal 700-940 1,230-1,370 880-1,040 810-930 

aCapac1ty utilization factor = 0.60. 

bTo convert from $/ton to $/Mg, multiply by 1.102. 
TABLE 2. IMPACT OF REVISED OIL PRICE PROJECTIONS ON THE INCREMENTAL COST EFFECTIVENESS 

OF REGULATORY ALTERNATIVES3 

480 

640 

3,380-6,630 

400 

550-570 

6,420-9,690 

Incremental Cost Effectiveness, $/ton 

1986 011 Price Projections 

1984 011 Price High 011 Price Low 011 Price 

Alternatives Compared Projections Scenario Scenario 

29 and 44 MW (100 and 150 minion Btu/hr) Steam Generating Units 

Low sulfur oil over baseline 620 

Very low sulfur oil over low sulfur oil 310-680 

Percent reduction over very low sulfur oil 0C 

73 and 17 MW (250 and 400 million Btu/hr) Steam Generating Units 

Low sulfur oil over baseline 450-490 

Very low sulfur oil over low sulfur oil 0 

Percent reduction over very low sulfur oil 0 

3Capac1ty utilization factor = 0.55. 

To convert from $/ton to $/Mg, multiply by 1.102. 

incremental cost effectiveness 1s $0/ton since, for these cases, the least-cost option to meet 

both a very low sulfur oil standard and a percent reduction standard 1s to use an FGD system 

and fire high sulfur oil. 

480 

340-560 

0

C 

410 

550-560 

1,340-3,040 
P.5 

impact on the costs and CE of a percent reduction standard for oil-fired 

boilers relative to a very low sulfur oil standard. Under the previous 

price projections, the least-cost option to meet a very low sulfur oil 

emission limit of 129 ng S02/J (0.3 lb S02/million Btu) was to use an FGD 

system and fire high sulfur oil. With revised price projections, however, 

the least-cost option to meet this same limit is to fire a very low sulfur 

oil in all cases except for boilers at or above 73 MW (250 million Btu/hr) 

under the high oil price scenario. This change has a significant impact on 

the incremental CE of a percent reduction standard over a very low sulfur 

oil standard. Since FGD was used to meet the very low sulfur oil standard 

in the previous analysis, the incremental CE of any additional emission 

reduction associated with a standard requiring a percent reduction in 

emissions was essentially $0/Mg or ton. 

This situation is very different under the new fuel price projections. 

Now a standard requiring a percent reduction in emissions imposes additional 

costs over those for a very low sulfur oil standard. Since the decrease in 

emissions associated with the percent reduction standard is very small, the 

incremental CE of this standard over a very low sulfur oil standard is much 

higher and ranges from $1,480 to $10,680/Mg ($1,340 to $9,690/ton) under low 

oil prices. Under high oil prices, the incremental CE is in this same range 

for boilers below 73 MW (250 million Btu/hr) but is $0/Mg or ton for larger 

boilers since, as with previous price projections, boiler owners choose to 

use an FGD system and fire high sulfur oil in response to both a percent 

reduction standard and a very low sulfur oil standard. 

For other regulatory alternatives, the incremental CE of S02 control 

from oil-fired boilers under the new fuel price projections is similar in 

magnitude to the CE of S02 control under the previous projections. The 

incremental CE of a standard based on using low sulfur oil over the 

regulatory baseline ranges from $ 440 to $530/Mg ($400 to $480/ton) under 

new price projections; in the prior analysis the CE ranged from $500 to 

$680/Mg ($450 to $620/ton). The incremental CE of a very low sulfur oil 

standard over a low sulfur oil standard now ranges from $380 to $710/Mg 
P.6 

($340 to $640/ton); in the previous analysis this value ranged from $0 to 

$680/Mg ($0 to $620/ton). 

For oil-fired boilers operating at lower capacity utilization factors, 

the CE of S02 control associated with standards based on using low sulfur 

oil and very low sulfur oil are of the same order of magnitude under both 

the new and revised fuel price projections. The incremental CE of a percent 

reduction standard over a very low sulfur fuel standard is, however, 

significantly higher under the new fuel price projections. This is due both 

to the effect of capacity utilization factor on FGD system economics and the 

lower fuel sulfur premiums which characterize the new projections. 

2.0 INTRODUCTION 

In August 1986, fuel price projections for coal, oil, and natural gas 

1-3 supplied to industrial markets were revised. This memo assesses the 

impacts of these new fuel prices on the previous analyses of the cost and CE 

of reducing S02 emissions from coal- and oil-fired boilers. The previous 

analyses were pres.ented in the reports Industrial Boiler SO? Cost Report and 

Summary of Regulatory Analvsis. ' 

Comparisons of previous and current fuel price projections for coal, 

oil, and natural gas are presented in Tables 3 and 4. As shown, the general 

trend has been a decline in fuel prices between the 1984 and 1986 

projections and a reduction in the fuel sulfur premium (i.e., the additional 

price of low sulfur fuels relative to high sulfur fuels). In addition, both 

low and high oil price scenarios have been developed for the 1986 price 

projections and are reflected in Table 4. For calculation of flue gas 

desulfurization (FGD) malfunction costs, non-carriage/rigid natural gas 

prices were used, as described in Reference 3. Non-carriage prices are 

representative of natural gas delivered on a "non-interruptible" contract 

basis, as would be required in this situation. A rigid natural gas 

regulatory environment was assumed since this represents the current 

status-quo. 

In addition to these fuel price changes, minor modifications were made 

to the methodology for calculating capital and non-fuel operating and 
TABLE 3. COMPARISON OF 1984 AND 1986 COAL AND NATURAL GAS PRICE PROJECTIONS 

Fuel Type 

Nominal Coal 

Sulfur Content 

( l b S02 /m1ll1on Btu) 

Jul y 1984 

Price Projection3 

(1983 $/m1ll1on Btu) 

August 1986 

Pric e Projection1 5 

(1985 $/m1ll1on Btu) 

Region V 

B-bitum1nous coal 

E-bitum1nous coal 

H-b1tum1nous coal 

Natural gas 

1.2 

2.5 

6.0 

3.32 

3.08 

2.50 

5.88 

2.75 

2.57 

2.24 

3.77c 

Region VIII 

E-subb1tum1nous coal 

B-subb1tum1nous coal 

Natural gas 

2.5 

1.2 

1.28 

1.40 

4.91 

1.35 

1.37 

3.14 c 

Source: Reference 4. 

)Source: References 1-3. 

'Based on a non-carr1age/r1gid natural gas market and low oi l prices , as discussed 1n Reference 3, 
TABLE 4. COMPARISON OF 1984 AND 1986 OIL PRICE PROJECTIONS 

Fuel Type 

August 1986 Price Projection 

July 1984 (1985 $/m1ll1on Btu) b 

Price Projection3 

(1983 $/m1ll1on Btu) High Oil Prices Low Oil Prices 

0.3 lb S02/m1ll1on Btu residual oi l 5.97 4.84 3.49 

0.8 lb S02/m1ll1on Btu residual oil 5.63 4.68 3.35 

3.0 lb S02/mill1on Btu residual oi l 4.81 4.15 2.90 

Natural gas 5.88 4.821 3.77' 

Source: Reference 4 . 

Source: References 1-3. 

'Based on a non-carr1age/rig1d natural gas market, as discussed 1n Reference 3. 

Price projections are for Region V. 
P.9 

maintenance costs for model boilers. These modifications are discussed in 

full in Appendix A. These modifications have had a negligible effect, 

however, on this assessment of new fuel price impacts. 

3.0 IMPACTS FOR COAL-FIRED MODEL STEAM GENERATING UNITS 

3.1 Previous Impacts for Coal-Fired Units 

Cost and CE values for typical coal-fired model boilers operating in 

Regions V and VIII, based on the previous (i.e., July 1984) price 

projections, are presented in Tables 5 and 6. The cost estimates in Table 5 

correspond to four different boiler sizes, all operating at a capacity 

utilization factor of 0.60. Table 6 is based on a 44 MW (150 million 

Btu/hr) boiler operating at capacity utilization factors of 0.15, 0.30, and 

0.60. 

For new coal-fired boilers the cost estimates in Table 5 show that the 

incremental CE of SO- control associated with a standard based on using low 

sulfur coal [i.e., coal with potential average S02 emissions of 413 ng S02/J 

(0.96 lb S02/million Btu)] over the regulatory baseline of medium sulfur 

coal [i.e., 903 ng/J (2.10 lb/million Btu)] ranged from $230 to $460/Mg 

($210 to $420/ton) for Regions V and VIII. In Region V, the least cost 

option for meeting a percent reduction requirement was to use a high sulfur 

coal [i.e., 2,382 ng/J (5.54 lb/million Btu)]. The incremental CE of S02 

control associated with a standard requiring a percent reduction in 

emissions over a standard based on low sulfur coal ranged from $770 to 

$1,900/Mg ($700 to $l,730/ton). 

In Region VIII, high sulfur coals are not generally available; the 

highest sulfur coal generally available is a medium sulfur coal. This coal 

was also the least-cost option for meeting a percent reduction requirement. 

The incremental CE of a percent reduction requirement applied to medium 

sulfur coal over the use of low sulfur coal alone ranged from $1,350 to 

$2,050/Mg ($1,230 to $l,860/ton). 
TABLE 5. COST IMPACTS FOR COAL-FIRED STEAM GENERATING UNITS IN REGIONS V AND VII I 

(July 1984 Price Projections; January 1983 $) 

a,b 

REGION V REGION VIII 

Regulatory 

Alternative 

, Incremental 

Coal Type, Annual Annualized Cost 

ng SO./J Emissions, Cost, Effectiveness, 

(lb SO_/minion Btu) Mg/yr (tons/yr) ($1000/yr) J/Mg ($/ton) 

Coal Type. Annual Annualized 

ng S0-/J Emissions, Cost, •.• .cu . .co o 

( lb S02/m1l1lon Btu) Mg/yr (tons/yr) (SlOOO/yr) j/Mg ($/ton) 

Incremental 

Cost 

Effectiveness. 

vo 

29 MW (100 million Btu/hr): 

Baseline . 

Low Sulfur Fuel" 

Percent Reduction6 

903 

413 

2.382 

(2.10) 

(0.96) 

(5.54) 

44 MW (150 million Btu/hr): 

Baseline 903 (2.10) 

Low Sulfur Fuel 413 (0.96) 

Percent Reduction 2,382 (5.54) 

73 MW (250 million Btu/hr): 

Baseline 903 

Low Sulfur Fuel 413 

Percent Reduction 2,382 (5.54) 

(2.10) 

(0.96) 

117 MW (400 million Btu/hr): 

Baseline 

Low Sulfur Fuel 

Percent Reduction 

903 

413 

(2.10) 

(0.96) 

2,382 (5.54) 

500 (550) 

230 (250) 

100 (110) 

750 (830) 

340 (380) 

150 (170) 

1.250 (1.380) 

570 (630) 

250 (280) 

2,010 (2.210) 

920 (1.010) 

400 (440) 

4,430 

4,560 

4.800 

6.160 

6.340 

6.620 

10.430 

10.750 

11,080 

15,200 

15.700 

16,100 

450 

1.900 

450 

1,450 

460 

1,030 

460 

770 

(410) 

(1.730) 

(410) 

(1,320) 

(420) 

(940) 

(420) 

(700) 

903 (2.10) 

413 (0.96) 

903 (2.10) 

903 (2.10) 

413 (0.96) 

903 (2.10) 

903 (2.10) 

413 (0.96) 

903 (2.10) 

903 (2.10) 

413 (0.96) 

903 (2.10) 

500 

230 

40 

750 

340 

50 

1,250 

570 

90 

(550) 

(250) 

(40) 

(830) 

(380) 

(60) 

(1,380) 

(630) 

(100) 

3,640 

3,710 

4,090 

4,950 

5.050 

5.560 

8,200 

8,370 

9,090 

240 

2,050 

230 

1,780 

250 

1.510 

-

(220) 

(1,860) 

(210) 

(1,620) 

(230) 

(1,370) 

2,010 (2,210) 11.560 

920 (1,010) 11,840 

150 (170) 12,860 

250 (230) 

1,350 (1,230) 

Annual emissions, annualized costs, and cost effectiveness values rounded to nearest tenth. 

bCapac1ty utilizatio n factor = 0.60 . 

Corresponds to 1,075 ng/J (2.5 lb/mil lion Btu) S02 emission limit . 

Corresponds to 516 ng/J (1.2 lb/millio n Btu) S02 emission limit . 

Corresponds to 90 percent SO- reduction requirement. 

f

Least-cost option to meet regulatory alternative . 
TABLE 6. COST IMPACTS FOR A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED STEAM GENERATING UNIT IN REGIONS V AND VII I 

AS A FUNCTION OF CAPACITY UTILIZATION FACTORS4 

(July 1984 Price Projections; January 1983 J) 

Coal Type, 8 

Regulatory ng S0-/J 

Alternative (lb S02/m1111on Btu) 

0.6 Capacity Utilizatio n Factor: 

Basel1neb 903 (2.10) 

Low Sulfur Fuel c 413 (0.96) 

Percent Reduction" 2,382 (5.54) 

0.3 Capacity Utilizatio n Factor: 

Baseline 903 (2.10) 

Low Sulfur Fuel 413 (0.96) 

Percent Reduction 2,382 (5.54) 

0.15 Capacity Utilizatio n Factor: 

Baseline 903 (2.10) 

Low Sulfur Fuel 413 (0.96) 

Percent Reduction 2,382 (5.54) 

REGION V 

Anni 

Emlss 

al 

ons, 

Mg/yr (tons/yr) 

750 

340 

150 

380 

170 

70 

190 

80 

40 

(830) 

(380) 

(170) 

(410) 

(190) 

(80) 

(210) 

(90) 

(40) 

Annualized 

Cost, 

($1000/yr) 

6,160 

6.340 

6.620 

4,520 

4.620 

4.900 

3,870 

3,920 

4,200 

Incremental 

Cost 

Effectiveness, 

$/Mg (J/ton) 

-

450 (410) 

1,480 (1.340) 

-

450 (410) 

3.040 (2,760) 

-

450 (410) 

6.140 (5,570) 

Coal Type, 6 

ng S0-/J 

(lb S02/ro1l1lon Btu) 

903 

413 

903 

903 

413 

903 

903 

413 

903 

(2.10) 

(0.96) 

(2.10) 

(2.10) 

(0.96) 

(2.10) 

(2.10) 

(0.96) 

(2.10) 

REGION VII I 

Anni 

Emlssl 

al 

ons. 

Mg/yr (tons/yr) 

750 

340 

50 

380 

170 

30 

190 

80 

20 

(830) 

(380) 

(60) 

(410) 

(190) 

(30) 

(210) 

(90) 

(20) 

AnnualIzed 

Cost, 

(JlOOO/yr) 

4,950 

5.050 

5.560 

4.030 

4.070 

4,450 

3.720 

3,750 

4.060 

Incremental 

Cost 

Effectiveness, 

J/Mg (J/ton) 

_ 

230 (210) 

1,780 (1,620) 

_ 

230 (210) 

2.660 (2.410) 

_ 

230 (210) 

4,450 (4,030) 

aAnnual emissions, annualized costs, and cost effectiveness values rounded to nearest tenth. 

Corresponds to 1,075 ng/J (2.5 lb/m1ll1on Btu) SO emission limit. 

Corresponds to 516 ng/J (1.2 lb/m11l1on Btu) S02 emission limit. 

Corresponds to 90 percent S0_ reduction requirement. 

Ceast-cost option to meet regulatory alternative. 
P.12 

As shown in Table 6 for a new 44 MW (150 million Btu/hr) coal-fired 

boiler, the incremental CE of using low sulfur coal over the regulatory 

baseline was about $450/Mg ($410/ton) in Region V and $230/Mg ($210/ton) in 

Region VIII and is not a function of capacity utilization factor. The 

reason is that fuel costs and S02 emissions change in the same proportion 

that capacity utilization factor changes; therefore no differences in 

incremental CE values result. 

On the other hand, Table 6 shows that the cost impacts associated with 

a percent reduction requirement relative to the use of low sulfur coal 

increase significantly as capacity utilization factor decreases. This is 

because the large capital costs associated with FGD systems installed to 

comply with a percent reduction requirement must be borne by a smaller 

number of operating hours. As shown, the incremental CE of a percent 

reduction requirement applied to high sulfur coal in Region V over the use 

of low sulfur coal was $3,040/Mg ($2,760/ton) at 0.3 capacity factor and 

$6,140/Mg ($5,570/ton) at 0.15 capacity factor. The same requirement 

applied to medium sulfur coal in Region VIII resulted in incremental CE 

values for a percent reduction standard over the use of low sulfur coal of 

$2,660/Mg ($2,410/ton) at 0.3 capacity factor and $4,450/Mg ($4,030/ton) at 

0.15 capacity factor. 

3.2 Revised Impacts for Coal-Fired Units 

The cost and CE values for new coal-fired boilers based on the revised 

(i.e., August 1986) fuel price projections are presented in Tables 7 and 8. 

One important change that results with the use of the new fuel price 

projections is that it is less expensive to apply a percent reduction 

requirement to medium or low sulfur coals than to a high sulfur coal. The 

reason is that the lower sulfur coals require less FGD reagent to achieve 

the same S02 reduction level and hence incur lower costs for reagent, waste 

disposal, and interest on working capital. These lower costs more than 

compensate for the higher fuel prices associated with these coals; the net 

effect is lower annualized costs for scrubbing lower sulfur coals relative 

11 
TABLE 7. COST IMPACTS FOR COAL-FIRED STEAM GENERATING UNITS IN REGIONS V AND VIII a , b 

(August 1986 Price Projections; June 1985 J) 

REGION V REGION VIII 

Regulatory 

Alternative 

Incremental 

Coal Type, Annual Annualized Cost 

ng SO_/J Emissions, Cost, Effectiveness, 

(lb S02/minion Btu) Hg/yr (tons/yr) (JlOOO/yr) J/Hg (J/ton) 

Incremental 

Coal Type, Annual Annualized Cost 

ng SO-/J Emissions, Cost, Effectiveness, 

(lb S02/m11T1on Btu) Mg/yr (tons/yr) (JlOOO/yr) J/Mg (J/ton) 

29 MW (100 million Btu/hr): 

Basel1nec 903 (2.10) 

Low Sulfur Fueld 413 (0.96) 

Percent Reduction6 903 (2.10) 

44 MW (150 million Btu/hr): 

Baseline 903 (2.10) 

Low Sulfur Fuel 413 (0.96) 

Percent Reduction 903 (2.10) 

73 MW (250 million Btu/hr): 

Baseline 

Low Sulfur Fuel 

Percent Reduction 

117 MW (400 million Btu/hr): 

903 (2.10) 

413 (0.96) 

903 (2.10) 

Baseline 903 (2.10) 

Low Sulfur Fuel 413 (0.96) 

Percent Reduction 903 (2.10) 

500 

230 

40 

750 

340 

50 

1,250 

570 

90 

2,010 

920 

150 

(550) 

(250) 

(40) 

(830) 

(380) 

(60) 

(1,380) 

(630) 

(100) 

(2,210) 

(1,010) 

(160) 

4,260 

4,350 

4.660 

5,870 

6.010 

6.420 

9.960 

10.200 

10,750 

14.390 

14,770 

15,520 

340 (310) 

1.720 (1,560) 

340 (310) 

1.410 (1.280) 

350 (320) 

1,140 (1,040) 

350 (320) 

970 (880) 

903 (2.10) 

413 (0.96) 

413 (0.96) 

903 (2.10) 

413 (0.96) 

413 (0.96) 

903 (2.10) 

413 (0.96) 

413 (0.96) 

903 (2.10) 

413 (0.96) 

413 (0.96) 

500 

230 

20 

750 

340 

20 

1.250 

570 

40 

2,010 

920 

70 

(550) 

(250) 

(20) 

(830) 

(380) 

(30) 

(1,380) 

(630) 

(50) 

(2,210) 

(1.010) 

(70) 

3,770 

3,790 

4,100 

5,140 

5,150 

5,560 

8.500 

8,540 

9,090 

12,000 

12.060 

12,820 

-

40 (40) 

1,500 (1,360) 

50 (40) 

1.260 (1,150) 

60 (60) 

1,030 (930) 

60 (50) 

890 (810) 

aAnnual emissions, annualized costs, and cost effectiveness values rounded to nearest tenth. 

Capacity utilization factor - 0.60. 

Corresponds to 1,075 ng/J (2.5 lb/million Btu) S02 emission limit. 

Corresponds to 516 ng/J (1.2 lb/million Btu) S02 emission limit. 

Corresponds to 90 percent SO- reduction requirement. 

Least-cost option to meet regulatory alternative. 
OO 

TABLE 8. COST IMPACTS FOR A 44 MW (150 MILLION BTU/HOUR) COAL-FIRED STEAM GENERATING UNIT IN REGIONS V AND VII I 

AS A FUNCTION OF CAPACITY UTILIZATION FACTORS8 

(August 1986 Price Projections; June 1985 J) 

Coal Type, 8 

Regulatory ng SO_/J 

Alternative (lb SO^rollTIon Btu) 

0.6 Capacity Utilizatio n Factor: 

Basel1neb 903 

Low Sulfur Fuel c 413 

Percent Reduction 903 

0.3 Capacity Utilizatio n Factor: 

Baseline 903 

Low Sulfur Fuel 413 

Percent Reduction 903 

0.15 Capacity Utilizatio n Factor 

Baseline 903 

Low Sulfur Fuel 413 

Percent Reduction 903 

(2.10) 

(0.96) 

(2.10) 

(2.10) 

(0.96) 

(2.10) 

(2.10) 

(0.96) 

(2.10) 

REGION V 

Annual 

Emissions, 

Mg/yr (tons/yr) 

750 

340 

50 

380 

170 

30 

190 

90 

10 

(830) 

(380) 

(60) 

(410) 

(190) 

(30) 

(210) 

(100) 

(20) 

Annualized 

Cost. 

(JlOOO/yr) 

5,870 

6,010 

6,420 

4,430 

4,500 

4,850 

3.870 

3,910 

4,230 

Incremental 

Cost 

Effectiveness, 

J/Mg (J/ton) 

340 (310) 

1.410 (1,280) 

340 (310) 

2,470 (2,240) 

340 (310) 

4,520 (4,100) 

Coal 

ng 

(lb S02/m 

903 

413 

413 

903 

413 

413 

903 

413 

413 

Type, 

50-/J 

llllo n Btu) 

(2.10) 

(0.96) 

(0.96) 

(2.10) 

(0.96) 

(0.96) 

(2.10) 

(0.96) 

(0.96) 

REGION VII I 

Annual 

Emissions, 

Mg/yr (tons/yr) 

750 

340 

20 

380 

170 

10 

190 

90 

10 

(830) 

(380) 

(30) 

(410) 

(190) 

(10) 

(210) 

(100) 

(10) 

Annualized 

Cost. 

(JlOOO/yr) 

5,140 

5,150 

5,560 

* 4,160 

4,170 

4.530 

3,850 

3,850 

4.160 

Incremental 

Cost 

Effectiveness, 

J/Mg (J/ton) 

50 (40) 

1,260 (1,150) 

40 (40) 

2,210 (2,010) 

40 (40) 

3,860 (3,500) 

aAnnual emissions, annualized costs, and cost effectiveness values rounded to nearest tenth. 

Corresponds to 1,075 ng/J (2.5 lb/millio n Btu) S0_ emission limit . 

Corresponds to 516 ng/J (1.2 lb/millio n Btu) S02 emission limit . 

Corresponds to 90 percent S0_ reduction requirement. 

e

Least-cost option to meet regulatory alternative . 
P.15 

to high sulfur coals. For the previous fuel price projections, the fuel 

price differences between lower sulfur and high sulfur coals outweighed the 

reagent and other cost savings so as to make scrubbing of high sulfur coals 

the least-cost scrubbing alternative. 

The cost estimates in Table 7 show that the incremental CE of using low 

sulfur coal in a new coal-fired boiler operating at a capacity utilization 

factor of 0.60 over the regulatory baseline ranges from about $40 to $350/Mg 

($40 to $320/ton) for Regions V and VIII. In Region V, the incremental CE 

of a percent reduction requirement applied to medium sulfur coal, which is 

the lowest annualized cost option for this alternative, over the use of low 

sulfur coal ranges from about $970 to $1,720/Mg ($880 to $l,560/ton). In 

Region VIII, the annualized costs for percent reduction are lowest when 

applied to low sulfur coal. The incremental CE of this alternative over the 

use of low sulfur coal range from about $890 to $1,500/Mg ($810 to 

$l,360/ton). 

A comparison of costs for coal-fired boilers operating at lower 

capacity utilization factors is presented in Table 8. The table shows that, 

as with the previous fuel price projections, the incremental CE of the use 

of low sulfur coal over the regulatory baseline [at $40 to $340/Mg ($40 to 

$310/ton)] is not a function of capacity utilization factor, for the same 

reasons discussed in Section 3.1. On the other hand, the incremental CE 

values of the least-cost options for percent reduction relative to the use 

of low sulfur coal increase significantly as capacity utilization factor 

decreases, also due to the same factors discussed in Section 3.1. As shown, 

the incremental CE of a percent reduction requirement applied to medium 

sulfur coal in Region V over the use of low sulfur coal is approximately 

$2,470/Mg ($2,240/ton) at 0.3 capacity factor and $4,520/Mg ($4,100/ton) at 

0.15 capacity factor. The same requirement applied to low sulfur coal in 

Region VIII results in incremental CE values over the use of low sulfur coal 

of $2,210/Mg ($2,010/ton) at 0.3 capacity factor and $3,860/Mg ($3,500/ton) 

at 0.15 capacity factor. 

14 
3.3 Comparison of Impacts for Coal-Fired Units 

The incremental CE values associated with the 1986 fuel price 

projections are similar in magnitude to the corresponding values based on 

the 1984 projections, but slightly lower. It should be noted that, even in 

the absence of fuel price changes, updating the time basis of the non-fuel 

costs from January 1983 dollars to June 1985 dollars acts to increase 

incremental costs, and hence CE values, by a factor of 1.03. Thus the fact 

that the analogous incremental CE values have declined slightly between the 

1983 and 1985 basis estimates indicates that the change in fuel price 

projections has had a small but noticeable impact on the CE of compared 

alternatives. In addition, for both sets of fuel price projections the 

incremental CE values are not a strong function of boiler size, although CE 

values for percent reduction options generally decline as boiler size 

increases due to FGD economies of scale. 

For boilers with lower capacity utilization factors, the same trends 

apply for both sets of fuel price projections. Again, the incremental CE 

values are of the same order of magnitude but slightly lower for the 1986 

fuel price projections. It is important to note, however, that the previous 

national impacts analysis showed that little, if any, coal would be fired in 

new fossil fuel-fired boilers operating at low capacity utilization factors 

even assuming a high coal penetration. At capacity factors of 0.30 and 

below, oil or natural gas were the fuels of choice even in the absence of a 

standard. Since natural gas prices have declined to a greater extent 

between the 1984 and 1986 projections than have coal prices, natural gas 

combustion will be even more attractive on an after-tax net present value 

basis than was the case for the 1984 projections. Thus at capacity 

utilization factors of 0.3 or less, oil and natural gas will continue to 

represent the "economic fuels of choice" even in the absence of a standard. 

15 
4.0 IMPACTS FOR OIL-FIRED MODEL STEAM GENERATING UNITS 

4.1 Previous Impacts for Oil-Fired Units 

Cost and cost effectiveness values for oil-fired model boilers 

operating in Region V, based on the previous fuel price projections, are 

presented in Tables 9 and 10. Only one set of oil price values were used 

for these tables, corresponding to the low oil price scenario. The results 

of the prior cost analysis showed that for all boiler sizes operating at a 

typical capacity utilization factor of 0.55, it was less costly to fire a 

high sulfur oil and install an FGD system to meet an emissions limit of 129 

ng S02/J (0.3 lb S02/million Btu) heat input than to fire a very low sulfur 

oil. Also, for boilers at or above 73 MW (250 million Btu/hr) heat input 

capacity, it was less costly to fire a high sulfur oil and install an FGD 

system to meet an emission limit of 344 ng S02/J (0.8 lb S02/million Btu) 

heat input than to fire a low sulfur oil. At lower capacity utilization 

factors, however, it was less costly to fire very low sulfur oil or low 

sulfur oil to meet these respective S02 emission limits. 

For new oil-fired boilers, the cost estimates in Table 9 show that the 

incremental CE of S02 control associated with a standard based on using low 

sulfur oil over the regulatory baseline of medium sulfur oil ranged from 

$490 to $680/Mg ($450 to $620/ton). Because boilers of 73 MW (250 million 

Btu/hr) and above choose to use an FGD system and fire high sulfur oil to 

comply with a standard based on low sulfur oil, the incremental CE of S02 

control associated with a standard based on very low sulfur oil over a 

standard based on low sulfur oil ranged from $0 to $750/Mg ($0 to $680/ton). 

Moreover, the incremental CE of S02 control associated with a standard 

requiring a percent reduction in emissions over a standard based on very low 

sulfur oil was effectively $0/Mg or ton. 

Table 10 shows that, for a new 44 MW (150 million Btu/hr) oil-fired 

boiler, the incremental CE of using low sulfur oil over the regulatory 

baseline was $680/Mg ($620/ton) and is not a function of capacity 

utilization factor. For a very low sulfur oil standard, the least-cost 

option changed from using an FGD system and firing high sulfur oil at 0.55 

16 
TABLE 9. COST IMPACTS FOR OIL-FIRED STEAM GENERATING UNITS IN REGION V a , b 

(July 1984 Price Projections; January 1983 J) 

Regulatory Alternative 

Oil Type, 9 

ng SO_/J 

(lb SO_/mTil1on Btu) 

Annual Emissions 

Mg/yr (tons/yr) 

Annualized Cost, 

(JlOOO/yr) 

Incremental 

Cost Effectiveness, 

J/Mg (J/ton) 

29 MW (100 million Btu/hr) 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel£ 

Percent Reduction 

44 MW (150 million Btu/hr) 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

73 MW (250 million Btu/hr) 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

117 MW (400 million Btu/hr) 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

3.0 

0.8. 

3.0 h 

3.0 

3.0 

0.8. 

3.0 h 

3.0 

3.0 

3

-°h 

3.0 h 

3.0 

3.0 

3.0 h 

3.0 

660 

180 

50 

50 

980 

260 

80 

80 

1.640 

130 

130 

130 

2.620 

200 

200 

200 

(720) 

(190) 

(60) 

(60) 

(1,080) 

(290) 

(80) 

(80) 

(1,810) 

(140) 

(140) 

(140) 

(2.890) 

(220) 

(220) 

(220) 

3,270 

3,600 

3.710 

3,710 

4,660 

5,150 

5,220 

5.220 

7.410 

8.230 

8.230 

8,230 

11,970 

13.160 

13.160 

13.160 

680 (620) 

750 (680) 

0 (0) J 

680 (620) 

340 (310) 

0 (0>J ti 

540 (490) 

0 (or 

0 (0) J 

490 (450) 

0 (0)* 

0 (0)*5 

aAnnual emissions, annualized costs, and cost effectiveness values rounded to the nearest tenth. 

Capacity utilizatio n factor «• 0.55. 

Corresponds to 1,290 ng/J (3.0 lb/m1ll1on Btu) S02 emission limi t 

d Corresponds to 344 ng/J (0.8 lb/m1ll1on Btu) S02 emission limit . 

Corresponds to 129 ng/J (0.3 lb/m1ll1on Btu) SO_ emission Umit . 

Corresponds to 90 percent SO_ reduction requirement. 

9

Least-cost option to meet regulatory alternative . 

Ces s expensive to fir e 3.0 lb SO /millio n Btu oi l and Instal l an FGD system than to fir e 0.3 lb S02/m1111on Btu oil . 

1

Less expensive to fir e 3.0 lb SO /millio n Btu oi l and Instal l an FGD system than to fir e 0.8 lb S02/m1111on Btu oil . 

-'Incremental cost effectiveness Is JO/Mg or ton since, for these cases, the least-cost option t o meet both a very 

low sulfur oi l standard and a percent reduction standard Is to use an FGD system and fir e high sulfur oil . 

k

Incremental cost effectiveness Is JO/Mg or ton since, for these cases, the least-cost option to meet a low sulfur 

o i l standard and a very low sulfur oi l standard Is to use an FGD system and fir e high sulfur oil . 
TABLE 10. COST IMPACTS FOR A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED STEAM GENERATING UNIT IN REGION V 

AS A FUNCTION OF CAPACITY UTILIZATION FACTORS3 

(July 1984 Price Projections; January 1983 J) 

CO 

Regulatory Alternative 

011 Type.' 

ng SO./J 

(IbSGymllllon Btu) 

Annual Emissions 

Mg/yr (tons/yr) 

Annualized Cost, 

($1000/yr) 

0.55 Capacity Utilization Factor: 

Baseline 

Low Sulfur Fuelc 

Very Low Sulfur Fuel 

Percent Reduction8 

0.30 Capacity Utilization Factor: 

BaselIne 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

0.15 Capacity Utilization Factor: 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

3.0 

0.8 

3.09 

3.0 

3.0 

0.8 

0.3 

3.0 

3.0 

0.8 

0.3 

3.0 

980 (1,080) 

260 (290) 

80 (80) 

60 (80) 

540 (590) 

140 (160) 

50 (60) 

40 (50) 

270 (300) 

70 (80) 

30 (30) 

20 (20) 

4,660 

5.150 

5,220 

5,220 

2,900 

3,170 

3,320 

3,320 

1,910 

2,050 

2,120 

2,250 

Incremental 

Cost Effectiveness, 

J/Mg (J/ton) 

680 (620) 

340 (310) 

0 <or 

680 (620) 

1,650 (1,500) 

150 (140) 

680 (620) 

1,650 (1,500) 

18,800 (17,070) 

aAnnual emissions, annualized costs, and cost effectiveness values rounded to the nearest tenth. 

Corresponds to 1,290 ng/J (3.0 lb/m11Hon Btu) S02 emission limit. 

Corresponds to 344 ng/J (0.8 lb/m1ll1on Btu) S02 emission limit. 

Corresponds to 129 ng/J (0.3 lb/m1ll1on Btu) S02 emission limit. 

Corresponds to 90 percent SO- reduction requirement. 

Least-cost option to meet regulatory alternative. 

9

Less expensive to fir e 3.0 lb S02/m1111on Btu oil and Install an FGD system than to fir e 0.3 lb S02/m1ll1on Btu oil . 

Incremental cost effectiveness is JO/Mg or ton since, for this case, the least-cost option to meet both a very low 

sufur oil standard and a percent reduction standard Is to use an FGD system and fir e high sulfur oil . 
P.20 

capacity factor to firing very low sulfur oil for lower capacity factors. 

The incremental CE of S02 control associated with a standard based on very 

low sulfur oil over a standard based on low sulfur oil ranged from $340 to 

$1,650/Mg ($310 to $l,500/ton); the higher values correspond to the lower 

capacity factors. 

As a result of the impact of capacity factor on FGD economics, the cost 

impacts associated with a percent reduction requirement relative to a very 

low sulfur oil standard increase significantly as capacity utilization 

factor decreases. The incremental CE of a percent reduction requirement 

over a standard based on using very low sulfur oil was $150/Mg ($140/ton) at 

0.3 capacity factor and $18,800/Mg ($17,070/ton) at 0.15 capacity factor. 

4.2 Revised Impacts for Oil-Fired Units 

The cost and cost effectiveness values for new oil-fired boilers based 

on revised fuel price projections are presented in Tables 11 and 12. The 

annualized cost results of Table 11 indicate that, for the low oil price 

scenario, it is less expensive to fire a very low sulfur oil to reduce S02 

emissions to 129 ng S02/J (0.3 lb S02/million Btu) heat input than to fire a 

high sulfur oil with an FGD system for all sizes of boilers examined at a 

0.55 annual capacity utilization factor. For the high oil price scenario, 

this same situation is true for boiler sizes of 29 and 44 MW (100 and 150 

million Btu/hour), but is reversed for larger boiler sizes of 73 and 117 MW 

(250 and 400 million Btu/hour). The reason for this trend is that the fuel 

sulfur premium is larger under high oil prices than under low oil prices. 

Thus the fuel cost savings associated with FGD use are higher under high oil 

prices and offset more of the annualized costs of the FGD system than is the 

case for low oil prices. 

The cost estimates in Table 11 show that the incremental CE of S02 

control associated with the use of low sulfur oil over the regulatory 

baseline ranges from about $440 to $530/Mg ($400 to $480/ton) under both oil 

price scenarios. The incremental CE of S02 control associated with a very 

low sulfur oil standard over a low sulfur oil standard ranges from $380 to 

$710/Mg ($340 to $640/ton). The incremental CE of a percent reduction 

19 
TABLE 11 . COST IMPACTS FOR OIL-FIRED STEAM GENERATING UNITS IN REGION V a , b 

(August 1986 Price Projections; June 1985 J) 

ro 

O 

Regulatory 

Alternative (lb 

29 MW (100 Millio n Btu/hr): 

Baseline0 

Low Sulfur Fuel 

Very Low Sulfur Fuel 6 

Percent Reduction 

44 MW (150 Millio n Btu/hr): 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

73 MW (250 Millio n Btu/hr): 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

117 MW (400 million Btu/hr) 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

011 Type, 9 

ng SO./J 

S02 /m1lilon Btu) 

3.0 

0.8 

0.3 

3.0 

3.0 

0.8 

0.3 

3.0 

3.0 

0.8. 

3.0 h 

3.0 

. 

3.0 

0.8,. 

3.0 " 

3.0 

HIGH OIL PRICE SCENARIO 

Annual 

Emissions, 

Mg/yr (tons/yr) 

660 (720) 

180 (190) 

70 (70) 

50 (60) 

980 (1,080) 

260 (290) 

100 (110) 

80 (80) 

1,640 (1,810) 

440 (490) 

130 (140) 

130 (140) 

2,620 (2,890) 

700 (770) 

200 (220) 

200 (220) 

Annualized 

Cost, 

(JlOOO/yr) 

2,910 

3,160 

3.240 

3.350 

4.110 

4,490 

4.610 

4,690 

6,500 

7,130 

7,320 

7,320 

10,520 

10,530 

11,720 

11,720 

Incremental 

Cost 

Effectiveness, 

J/Mg (J/ton) 

-

530 (480) 

710 (640) 

7,310 (6,630) 

-

530 (480) 

710 (640) 

3,730 (3,380) 

-

530 (480) 

610 (560) 

0 (0) 1 

-

530 (480) 

380 (340) 

0 (0)' 

011 

"9 

Type, 9 

S0,/J 

(lb S02/m1l1lon Btu) 

3.0 

0.8 

0.3 

3.0 

3.0 

0.8 

0.3 

3.0 

3.0 

0.8 

0.3 

3.0 

3.0 

0.8 

0.3 

3.0 

LOW OIL PRICE SCENARIO 

Annual 

Emlss ons. 

Mg/yr (tons/yr) 

660 

180 

70 

50 

980 

260 

100 

80 

1,640 

440 

160 

130 

2,620 

700 

260 

200 

(720) 

(190) 

(70) 

(60) 

(1.080) 

(290) 

(110) 

(80) 

(1,810) 

(490) 

(180) 

(140) 

(2,890) 

(770) 

(290) 

(220) 

Annualized 

Cost, 

(JlOOO/yr) 

2.310 

2.520 

2.590 

2,760 

3,220 

3,540 

3,640 

3.800 

5,000 

5.540 

5,710 

5.840 

8,130 

8,990 

9,260 

9,350 

Incremental 

Cost 

Effectiveness, 

J/Mg (J/ton) 

-

450 (400) 

620 (570) 

10,680 (9,690) 

-

440 (400) 

610 (550) 

7,080 (6.420) 

-

450 (410) 

620 (560) 

3,360 (3.040) 

-

450 (410) 

610 (550) 

1,480 (1.340) 

Annual emissions, annualized costs, and cost effectiveness values rounded to nearest tenth. 

Capacit y utilizatio n factor = 0.55. 

Corresponds to 1,290 ng/J (3.0 lb/millio n Btu) S02 emission limit . 

Corresponds t o 344 ng/J (0. 8 lb/millio n Btu) SO emission limit . 

Corresponds to 129 ng/J (0.3 lb/millio n Btu) SO. emission limit . 

Corresponds t o 90 percent S0_ reduction requirement. 

9

Least-cost option to meet regulatory alternative . 

Ces s expensive to fir e 3.0 lb SO /millio n Btu and Instal l an FGD system than to fir e 0.3 lb S02 /m1ll1on Btu oil . 

'incremental cost effectiveness Is JO/Mg or ton since, for these cases, the least-cost option to meet both a 

very low sulfur oi l standard and a percent reduction standard Is to use an FGD system and fir e high sulfur oil . 
TABLE 12. COST IMPACTS FOR A 44 MW (150 MILLION BTU/HOUR) OIL-FIRED STEAM GENERATING UNIT IN REGON V 

AS A FUNCTION OF CAPACITY UTILIZATION FACTORS8 

(August 1986 Price Projections; June 1985 J) 

Regulatory 

Alternative 

HIGH OIL PRICE SCENARIO LOW OIL PRICE SCENARIO 

Oil Type,' 

ng SO./J 

Annual 

Emissions, 

( l b S02 /m1l1lon Btu) Mg/yr (tons/yr) 

Annualized 

Cost, 

(JlOOO/yr) 

Incremental 

Cost 

Effectiveness, 

J/Mg (J/ton) 

Incremental 

011 Type, Annual Annualized Cost 

ng SO./J Emissions, Cost, Effectiveness, 

(lb SO./mllilon Btu) Mg/yr (tons/yr) (JlOOO/yr) J/Mg (J/ton) 

0.55 Capacity Utilizatio n Factor: 

Baseline 

Low Sulfur Fuel c 

Very Low Sulfur Fuel' 

Percent Reduction6 

3.0 

0.8 

0.3 

3.0 

0.30 Capacity Utilizatio n Factor: 

ro Baseline 

1 - 1

 Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

3.0 

0.8 

0.3 

3.0 

0.15 Capacity Utilization Factor: 

Baseline 

Low Sulfur Fuel 

Very Low Sulfur Fuel 

Percent Reduction 

3.0 

0.8 

0.3 

3.0 

980 (1,080) 

260 (290) 

100 (110) 

80 (60) 

540 (590) 

140 (160) 

50 (60) 

40 (50) 

270 (300) 

70 (80) 

30 (30) 

20 (20) 

4,110 

4,490 

4,610 

4,690 

2,620 

2.830 

2.890 

3,050 

1,790 

1.890 

1,930 

2,140 

-

530 (480) 

710 (640) 

3.730 (3.380) 

530 (480) 

710 (640) 

12.350 (11,200) 

530 (480) 

700 (630) 

32,610 (29,600) 

3.0 

O.B 

0.3 

3.0 

3.0 

0.8 

0.3 

3.0 

3.0 

0.8 

0.3 

3.0 

980 (1,080) 

260 (290) 

100 (110) 

80 (80) 

540 (590) 

140 (160) 

50 (60) 

40 (50) 

270 (300) 

70 (80) 

30 (30) 

20 (20) 

3,220 

3.540 

3,640 

3,800 

,'2,130 

2.310 

2.360 

2,570 

- 1,550 

1.630 

1.660 

1.890 

-

440 (400) 

610 (550) 

7.080 (6.420) 

450 (410) 

610 (560) 

15,910 (14,430) 

430 (390) 

630 (570) 

36.040 (32,700) 

aAnnual emissions, annualized costs, and cost effectiveness values rounded to nearest tenth. 

Corresponds to 1,290 ng/J (3.0 lb/millio n Btu) S02 emission limit . 

Corresponds to 344 ng/J (O.B lb/millio n Btu) S02 emission limit . 

Corresponds to 129 ng/J (0.3 lb/millio n Btu) S02 emission limit . 

Corresponds to 90 percent S02 reduction requirement. 

^Least-cost option to meet regulatory alternative . 
P.23 

. j « 

requirement over a very low sulfur oil standard ranges from $0 to $10,680/Mg 

($0 to $9,690/ton). The lower CE value results from the use of an FGD 

system with high sulfur oil as the least-cost option to meet both of these 

regulatory alternatives for larger boilers under high oil prices. 

A comparison of costs for oil-fired boilers operating at lower capacity 

utilization factors is presented in Table 12. The table shows that the 

incremental CE of the use of low sulfur oil over the regulatory baseline and 

the use of very low sulfur oil over low sulfur oil are not a function of 

capacity utilization factor. The incremental CE of a low sulfur oil 

standard over the baseline ranges from $430 to $530/Mg ($390 to $480/ton). 

The incremental CE of a very low sulfur oil standard over a low sulfur oil 

standard ranges from $610 to $710/Mg ($550 to $640/ton). In contrast, the 

incremental CE value of a percent reduction requirement over the use of very 

low sulfur oil increases significantly as capacity utilization factor 

decreases. Under low oil prices, the incremental CE value increases from 

$7,080/ng ($6,420/ton) at 0.55 capacity factor, to $15,910/Mg ($14,430/ton) 

at 0.3 capacity factor, and $36,040/Mg ($32,700/ton) at 0.15 capacity 

factor. The same trend applies to high oil prices. 

4.3 Comparison of Impacts for Oil-Fired Units 

Comparing the incremental CE results from Sections 4.1 and 4.2 for 

typical oil-fired boilers (i.e., with 0.55 capacity utilization factor), the 

conclusion can be drawn that the incremental CE values associated with the 

revised fuel price projections are similar in magnitude to those associated 

with the previous projections for a low sulfur oil standard and a very low 

sulfur oil standard. The incremental CE of a standard based on using low 

sulfur oil over the regulatory baseline ranges from $440 to $530/Mg ($0 to 

$480/ton) under new price projections; in the prior analysis the CE ranged 

from $500 to $680/Mg ($450 to $620/ton). The incremental CE of a very low 

sulfur oil standard over a low sulfur oil standard now ranges from $380 to 

$710/Mg ($340 to $640/ton); in the previous analysis this value ranged from 

$0 to $680/Mg ($0 to $620/ton). 

22 
P.24 

Revised incremental CE values for a percent reduction standard, 

however, are significantly higher than previous values. A fundamental 

difference is evident between the previous and revised price projections 

regarding the least-cost option to meet a very low sulfur oil standard. In 

the prior analysis, boiler owners chose to use an FGD system and fire high 

sulfur oil to meet the very low sulfur oil emission limit of 129 ng S02/J 

(0.3 lb S02/million Btu). With new fuel prices, boiler owners choose 

instead to fire very low sulfur oil to meet this emission limit in all cases 

except for boilers at or above 73 MW (250 million Btu/hr) under the high oil 

price scenario. Thus, the cost of S02 control associated with a standard 

based on using very low sulfur oil reflects the use of very low sulfur oil, 

except as noted. 

These changes have a significant effect on the incremental CE of a 

percent reduction requirement over a very low sulfur standard. Since boiler 

owners chose to use FGD for the very low sulfur oil standard in the previous 

analysis, the incremental CE of any additional emission reductions 

associated with a standard requiring a percent reduction in emissions was 

essentially $0/Mg a ton. The situation is very different under new fuel 

price projections. Now a standard requiring a percent reduction in 

emissions imposes additional costs over those of a very low sulfur oil 

standard. Since the associated decrease in emissions with the percent 

reduction standard is very small, the incremental CE of this standard over a 

very low sulfur oil standard is much higher and ranges from $1,480 to 

$10,680/Mg ($1,340 to $9,690/ton) under low oil prices. Under high oil 

prices, the incremental CE is in this same range for boilers below 73 MW 

(250 million Btu/hr) but is $0/Mg a ton for larger boilers since, as with 

previous price projections, boiler owners choose to use an FGD system and 

fire high sulfur oil in response to both a percent reduction standard and a 

very low sulfur oil standard. 

For boilers with lower capacity utilization factors, the same trends 

generally apply under both the 1984 and 1986 fuel price projections. The 

incremental CE values are of the same order of magnitude for standards based 

on using low sulfur oil and very low sulfur oil. The incremental CE of a 

23 
v 

percent reduction standard over a very low sulfur oil standard is, however, 

significantly higher under new price projections for boilers operating at 

lower capacity utilization factors. The incremental CE of a percent 

reduction requirement over a standard based on very low sulfur oil ranges 

from $12,350 to $15,910/Mg ($11,200 to $14,430/ton) at 0.3 capacity factor 

with the new price projections; with the 1984 projections this value was 

$150/Mg ($140/ton). At 0.15 capacity factor, the incremental CE of a 

percent reduction standard is $18,800/Mg ($17,070/ton) under the 1984 price 

projections, and $32,610 to $36,040/Mg ($29,600 to $32,700/ton) with the new 

projections. Under both sets of fuel price projections, the cost impacts 

associated with a percent reduction requirement relative to the use of very 

low sulfur oil increase significantly as capacity utilization factor 

decreases. Like coal-fired systems, this is because the capital costs 

associated with FGD systems installed to comply with a percent reduction 

requirement must be borne by a smaller number of operating hours. Under the 

1984 projections, this effect is masked somewhat by the use of an FGD system 

with high sulfur oil for both the very low sulfur oil standard and the 

percent reduction standard at 0.55 capacity factor. In addition, at 0.3 

capacity factor, the annualized costs of using very low sulfur oil are just 

below the costs of an FGD/high sulfur oil system; as a result, the 

incremental CE of a percent reduction standard over a very low sulfur fuel 

standard is low. With the lower fuel sulfur premiums which characterize the 

1986 projections, the incremental costs of the use of FGD are significantly 

higher than the use of very low sulfur oil for the full range of capacity 

utilization factors examined. Since the emissions decrease associated with 

a percent reduction standard versus a very low sulfur oil standard is small, 

the incremental CE values are high. 

24 
5.0 REFERENCES 

1. Letter from Hogan, T., Energy and Environmental Analysis, Inc., to 

Pahel-Short, R., EPA/EAB. Annualized Industrial Coal Prices. 

August 29, 1986. 

2. Letter from Hogan, T., Energy and Environmental Analysis, Inc., to 

Pahel-Short, R., EPA/EAB. Annualized Industrial Oil Prices. 

August 26, 1986. 

3. Letter from Hogan, T., Energy and Environmental Analysis, Inc., to 

Pahel-Short, R., EPA/EAB. Annualized Industrial Natural Gas Prices. 

August 27, 1986. 

4. Radian Corporation. Industrial Boiler S02 Cost Report. Prepared for 

the U.S. Environmental Protection Agency. Research Triangle Park, 

North Carolina. Publication No. EPA-450/3-85-011. November 1984. 

p. 3-1 to 4-7. 

5. U.S. Environmental Protection Agency. Summary of Regulatory Analysis, 

New Source Performance Standards: Industrial-Commercial-Institutional 

Steam Generating Units of Greater than 100 Million Btu/hr Heat Input. 

Research Triangle Park, North Carolina, June 1986. p. 6-1 to 6-18. 

6. Economic Indicators. Chemical Enqineerinq. 93 (16): August 18, 1986, 

p. 7. 

7. U.S. Bureau of Labor Statistics Producer Price Index: All Industrial 

Commodities. File 176, Dialog Information Services, Inc. August 17, 

1985 update. 

25 
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* 

APPENDIX A 

METHODOLOGY FOR REVISING MODEL COAL- AND OIL-FIRED 

BOILER COST ESTIMATES TO INCORPORATE NEW FUEL PRICES 

This Appendix presents the methodology used to revise the model coaland oil-fired boiler cost estimates in References 4 and 5 to incorporate new 

levelized fuel price projections. Since the new fuel prices are expressed 

in June 1985 dollars, it was also necessary to update the time basis of 

model boiler cost estimates. To accomplish these tasks, model boiler cost 

estimates were updated using the relationships between annualized costs and 

fuel prices contained in the original estimates of annualized costs (see 

Reference 4). 

Fuel prices influence annualized costs in three areas. The first, and 

most obvious, area involves annual fuel costs. Annual fuel costs are 

estimated as: 

AFC = Q ' CF * 8760 ' FP (1) 

where: 

AFC = Annual fuel costs, $/year, 

Q = Boiler heat input capacity, million Btu/hour, 

CF = Annual capacity utilization factor, and 

FP = Fuel price, $/million Btu. 

Thus the change in AFC as a result of fuel price changes is given by: 

AAF C = Q ' CF * 8760 * AF P (2) 

The second area of fuel price impacts involves interest on working 

capital (IWC) associated with maintaining a one-month inventory of fuel. 

This quantity is related to AFC changes by: 

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P.28 

f 

AlWC = 0.0083 ' AAF C (3) 

The final area of fuel price impacts is malfunction costs, which only 

applies to model steam generating units equipped with flue gas 

desulfurization (FGD) systems. During periods of FGD system malfunction, 

the cost algorithms assume that the SGU operator replaces his normal fuel 

with natural gas. Thus, the cost of malfunction is the fuel price 

difference between natural gas and the normal fuel and is calculated as: 

MC = Q ' CF ' 8760 ' (l-REL/100) (NGP-FP) (4) 

where 

MC = Malfunction costs, $/year, 

REL = FGD system reliability, %, and 

NGP = Natural gas price, $/million Btu. 

Therefore, the change in malfunction costs from the original estimates due 

to changes in natural gas and other fuel prices is given by: 

A M C = Q • CF * 8760 ' (l-REL/100) (ANGP-AFP) (5) 

An operating reliability of 95 percent is assumed for sodium scrubbing 

systems, which are used in this analysis as the basis for FGD system costs. 

The change in total annualized costs (TAC) for a model SGU case 

compared to the original estimate is the sum of the factors discussed above. 

After combination of Equations 2, 3, and 5 and rearrangement, the expression 

developed for changes in total annualized costs is: 

ATAC = Q ' CF ' 8760 [1.0083 AF P + (l-REL/100) (ANGP-AFP)] (6) 

The fuel prices projected in August 1986 are expressed in June 1985 

dollars compared to January 1983 dollars for the July 1984 projections. 

Therefore, in updating the model boiler cost estimates it was also necessary 

A-2 
P.29 

Mr: 

r 

to adjust the time basis from January 1983 to June 1985 for all other 

non-fuel costs. This was accomplished using a factor of 1.030 for capital 

related costs (based on the Chemical Engineering Plant Cost Index) and 1.035 

for non-fuel operating and maintenance (O&M) costs (based on the Producer 

Price Index for All Industrial Commodities). ' In cases where it was not 

appropriate to adjust capital and nonfuel O&M costs separately, an average 

factor of 1.032 was used. 

The methodology described above was used to update the original model 

boiler cost estimates where they were available. This was the case for 

coal-fired boilers at 0.60 capacity factor and oil-fired boilers at 0.55 

capacity factor. However, for both fuel types, annualized costs were not 

readily available for lower capacity factors of 0.30 and 0.15. For these 

cases, therefore, it was necessary to estimate model boiler costs using the 

computerized cost algorithms and the appropriate fuel prices and update 

factors. 

A-3