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OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

311) IV-B-15 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:59 AM Sheet 311 of 325 
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:« 7. A-83-27 

CORPORATION IV-B-15 

MEMORANDUM 

DATE: April 15, 1987 

TO: Fred Porter and Walt Stevenson, EPA/SDB 

FROM: Edward Aul, Radian Corporation 

SUBJECT: Impacts of New Fuel Prices on S02 Emission Credits for Cogeneration 

Systems and Mixed Fuel-Fired Steam Generating Units 

1.0 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 emission 

credits for cogeneration and mixed fuel-fired steam generating units (i.e., 

boilers). The previous analyses were presented in the reports An Analysis 

of the Costs and Cost Effectiveness of Allowing SO,. Emission Credits for 

Cogeneration Svstems (March 1985) and An Analvsis of the Costs and Cost 

Effectiveness of S02 Control for Mixed Fuel-Fired Steam Generating Units 

(January 1986).4 '

5 

The previous analyses were based on fuel prices projected in 1984 (as 

discussed in References 4 and 5). The revised projections (see References 

1, 2, and 3) contain two price scenarios: a high oil price scenario and a 

low oil price scenario. The low oil price scenario was utilized to assess 

the impacts of new fuel prices. 

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

to the methodology for calculating capital and non-fuel operating and 

maintenance costs for the subject units. These modifications are discussed 

in full in References 6 and 7. These modifications have had a negligible 

effect, however, on this assessment of new fuel price impacts. 

2.0 RESULTS OF ANALYSES 

The results of the analyses of new fuel price impacts (as discussed in 

detail in References 6 and 7) are summarized in Tables 1 through 6. These 

Progress Center/3200 E. Chapel Hill Rd./Nelson Hwy./P.O. Box 13000/Research Triangle Park. N.C. 27709/(919)541-9100 
TABLE 1. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION CREDITS FOR COAL-FIRED COGENERATION UNITS 

(August 1986 Price Projections; June 1985 $) 

Regulatory Alternative 

Fuel 

ng 

Type 

50,/J 

(lb S02/a1111on Btu) 

624 

409 

2,384 

2,384 

(1.45) 

(0.95) 

(5.54) 

(5.54) 

REGION 

Annualized 

Cost 

(Sl.OOO/yr) 

9,650 

9.810 

10,410 

10,440 

V 

Annual 

Emi! ssions 

Mg/yr 

(tons/yr) 

934 

608 

372 

272 

(1,030) 

(670) 

(410) 

(300) 

Incremental 

Cost 

Effectiveness 

S/Mg ($/ton) 

490 (445) 

305 (277 

Fuel Type 

ng S0_/J 

(lb S02/m1l1lon Btu) 

624 

409 

409 

409 

(1.45) 

(0.95) 

(0.95) 

(0.95) 

REGION 

Annualized 

Cost 

(Sl,000/yr) 

7,930 

8.010 

8,600 

8,610 

VII I 

Annual 

Em1 ssions 

Mg/yr 

(tons/yr) 

934 

608 

63 

45 

(1,030) 

(670) 

(70) 

(50) 

Increnental 

Cost 

Effectiveness 

$/Mg 

227 

638 

(S/ton) 

(206) 

(579) 

Low Sulfur Coal 

With Emission Credit* . 

Without Emission Credit 

Percent Reduction 

With EmlsslonCredlt0 

Without Emission Credit" 

^ *731 ng/J (1.7 lb/million Btu) S02 emission limit. 

b516 ng/J (1.2 lb/million Btu) S02 emission limit. 

c87 percent SO- reduction. 

90 percent SO. reduction, 

incremental cost effectiveness values were calculated before rounding annualized costs. 

CO 
TABLE 2. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION CREDITS 

FOR OIL-FIRED COGENERATION UNITS 

(August 1986 Price Projections; June 1985 $) 

Regulatory Alternative 

Fuel Type ng SO-/J 

(lb S02/mmion Btu) 

Annualized 

Cost1" 

($l,000/yr) 

Annual 

Emissions 

Mg/yr (tons/yr) 

Incremental Cost 

Effectiveness 

$/Mg ($/ton) 

Low Sulfur Oil 

With Emission Credit* . 

Without Emission Credit 

688 (1.6) 

344 (0.8) 

5,940 

6,310 

1,030 (1,135) 

515 (570) 720 (653) 

co Percent Reduction 

With Emission Cred1tc 

Without Emission Cred1t£ 

1,291 (3.0) 

1,291 (3.0) 

6,550 

6,560 

200 (220) 

145 (160) 182 (167) 

*688 ng/J (1.6 lb/mill 1on Btu) S02 emission Umit. 

*344 ng/J (0.8 lb/m1ll1on Btu) S02 emission Umit. 

c87 percent S02 reduction. 

90 percent SO_ reduction, 

incremental cost effectiveness values were calculated before rounding annualized costs. 

Based on Region V fuel prices. 

Tl 
TABLE 3. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION CREDITS FOR COMBINED CYCLE UNITS 

Fully-Fired Coalf 

(August 1986 Price Projections; June 1985 S) 

Regulatory Alternative 

Low Sulfur Coal 

With Emission Credit8 

Without Emission Credit0 

Percent Reduction 

With EmlsslonCredlt0 . 

Without Emission Credit 

Fuel Type 

ng SO-/J 

(lb S02/m1lT1on Btu) 

624 (1.45) 

409 (0.95) 

2,384 (5.54) 

2,384 (5.54) 

REGION 

AnnualIzed 

Cost 

(Sl.OOO/yr) 

2.080 

2,170 

2,600 

2,630 

V 

Annual 

Emissions 

Mg/yr 

(tons/yr) 

517 (570) 

336 (370) 

227 (250) 

154 (170) 

Incremental 

Cost 

Effectiveness 

S/Mg (S/ton) 

478 (430) 

274 (250) 

Fuel Type 

ng SO./J 

(lb S02/m1l1lon Btu) 

624 (1.45) 

409 (0.95) 

409 (0.95) 

409 (0.95) 

REGION 

AnnualIzed 

Cost 

(Sl.OOO/yr) 

1,050 

1,080 

1.510 

1,520 

VIII 

Annual 

Emissions 

Mg/yr 

(tons/yr) 

517 (570) 

336 (370) 

36 (40) 

27 (30) 

Incremental 

Cost 

Effectiveness 

S/Mg (S/ton) 

133 (120) 

838 (760) 

a731 ng/J (1.7 lb/million Btu) S02 emission limit. 

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

c 87 percent S02 reduction. 

90 percent SO_ reduction, 

incremental cost effectiveness values were calculated before rounding annualized costs. 

fIn this model system the gas turbine was assumed to fire natural gas and the steam generating unit was assumed to fire the listed coal. 

Tl 

C*l 
TABLE 4. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION CREDITS 

FOR OIL-FIRED COMBINED CYCLE STEAM GENERATING UNITS1 

(August 1986 Price Projections; June 1985 $) 

Regulatory Alternative 

Fuel Type ng SO./J 

(lb S02/mmion Btu) 

Annualized 

Cost* 

($l,000/yr) 

Annual 

Emissions 

Mg/yr (tons/yr) 

Incremental Cost 

Effectiveness*^ 

S/Mg ($/ton) 

FullY-F1red 

Low Sulfur Oil 

With Emission Credit8 

Without Emission Credit11 

688 (1.6) 

344 (0.8) 

2,420 

2,630 

572 (630) 

290 (320) 714 (648) 

Percent Reduction 

With Emission Credit0 

Without Emission Credit0 

Supplementary-Fired 

Low Sulfur 011 

With Emission Credit6 . 

Without Emission Credit" 

Percent Reduction . 

With Emission Cred1tT 

Without Emission Credit" 

1,291 (3.0) 

1,291 (3.0) 

2,850 

2,860 

109 (120) 

82 (90) 357 (324) 

1,291 (3.0) 

344 (0.8) 

1,291 (3.0) 

1,291 (3.0) 

2,270 

2,630 

3,140 

3,210 

1,070 (1,180) 

290 (320) 

299 (330) 

82 (90) 

456 (414) 

340 (309) 

a688 ng/J (1.6 lb/million Btu) S02 emission limit. 

b344 ng/J (0.8 lb/mil Hon Btu) S02 emission limit. 

c87 percent S02 reduction. 

d90 percent S02 reduction. 

el,291 ng/J (3.0 lb/million Btu) emission limit. 

69 percent S02 reduction, 

incremental cost effectiveness values were calculated before rounding annualized costs. 

Based on Region V fuel prices. 

1In this model system the gas turbine was assumed to fire natural gas and the steam generating 

unit was assumed to fire the listed oil. 
TABLE 5. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION CREDITS 

FOR MIXED FUEL-FIRED STEAM GENERATING UNITS FIRING COAL WITH NONFOSSIL FUEL 

(August 1986 Price Projections; June 1985 $)f 

Regulatory Alternative 

Fuel Type ng SO?/J 

(lb S02/m1ll1on Btu)9 

Annualized 

Cost 

($l,000/yr) 

Annual 

Emissions 

Mg/yr (tons/yr) 

Incremental Cost 

Effectiveness 

$/Mg ($/ton) 

Low Sulfur Coal 

With Emission Credit3 

Without Emission Credit 

904 

409 

(2.1) 

(0.95) 

4,005 

4,094 

151 (166) 

68 (75) 1,082 (982) 

o**> Percent Reduction 

With Emission Credit0 

Without Emission Cred1t( 

904 (2.1) 

904 (2.1) 

4,349 

4,367 

72 (80) 

12 (13) 300 (272) 

a

l,075 ng/J (2.5 lb/m1ll1on Btu) S02 emission Umit. 

3

516 ng/J (1.2 lb/m1ll1on Btu) S02 emission Hm1t. 

c

50 percent SO- reduction. 

90 percent S02 reduction, 

incremental cost effectiveness values were calculated before rounding annualized costs. 

Based on Region X fuel prices. 

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The fuel mixture was assumed to be 80 percent nonfossil fuel and 20 percent coal; the coal fired 

1s listed under fuel type. 

Tl 
TABLE 6. INCREMENTAL COST EFFECTIVENESS OF NOT PROVIDING EMISSION CREDITS 

FOR MIXED FUEL-FIRED STEAM GENERATING UNITS FIRING OIL WITH NONFOSSIL FUEL 

(August 1986 Price Projections; June 1985 $)f 

Regulatory Alternative 

Fuel Type ng SO_/J 

(lb S02/m11l1on Btu)9 

Annualized 

Cost 

($l,000/yr) 

Annual 

Emissions 

Mg/yr (tons/yr) 

Incremental Cost 

Effectiveness 

$/Mg ($/ton) 

Low Sulfur 011 

With Emission Credit* 

Without Emission Credit 

1,291 (3.0) 

344 (0.8) 

3,837 

3,911 

215 (237) 

57 (63) 471 (427) 

Percent Reduction 

With Emission Credit0 

Without Emission Cred1tc 

1,291 (3.0) 

1,291 (3.0) 

4,207 

4,234 

103 (114) 

17 (19) 314 (285) 

a

l,291 ng/J (3.0 lb/million Btu) S02 emission limit. 

b

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

c

50 percent S02 reduction. 

90 percent S02 reduction, 

incremental cost effectiveness values were calculated before rounding annualized costs. 

Based on Region I fuel prices. 

^ h e fuel mixture was assumed to be 80 percent nonfossil fuel and 20 percent oil ; the oil fired 

1s listed under fuel type. 

T l 

CO 
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results can be compared directly with the corresponding tables in the 

previous analyses. 

An overall comparison of the incremental cost effectiveness results 

from the current and prior analyses shows that the new fuel prices have 

little impact on the cost effectiveness of emission credits for cogeneration 

and mixed fuel-fired boilers. Using the new fuel prices, the cost 

effectiveness of the additional emission reductions achieved by not 

providing emission credits under standards based on firing low sulfur fuels 

for cogeneration systems has decreased slightly. It is now in the range of 

$100 to 700/Mg ($100 to 700/ton); in the previous analysis it was in the 

range of $0 to 1,100/Mg ($0 to 1,000/ton). Similarly, for mixed fuel-fired 

boilers, the cost effectiveness of the additional emission reductions 

achieved under standards based on firing low sulfur fuels has also decreased 

slightly. It is now in the range of $500 to 1,100/Mg ($400 to 1,000/ton) 

using the new fuel prices; in the previous analysis it was in the range of 

$700 to 1,100/Mg ($600 to 1,000/ton). 

For standards requiring a percent reduction in S02 emissions, the cost 

effectiveness of the additional emission reductions achieved by not 

providing emission credits for cogeneration systems has not changed. It 

remains in the range of $200 to 1,100/Mg ($200 to 1,000/ton). Similarly, 

for mixed fuel-fired boilers, the cost effectiveness of the additional 

emission reductions achieved by not providing emission credits also remains 

the same -- in the range of $300 to 500/Mg ($300 to 400/ton). 

These results are consistent with what one would expect. Under 

standards based on the use of low sulfur fuels, an emission credit permits 

the firing of a higher sulfur fuel. Thus the cost effectiveness of the 

additional emission reduction achieved by not providing an emission credit 

(i.e., requiring the firing of a lower sulfur fuel) is merely the sulfur 

premium or difference 1n price between the low sulfur and higher sulfur 

fuel. Since the sulfur premiums in the new fuel prices have decreased, one 

would expect to see a slight decrease in the cost effectiveness of the 

additional emission reduction achieved by not providing an emission credit 

under standards based on firing low sulfur fuels. 
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Under standards requiring a percent reduction in emissions, an emission 

credit permits the installed scrubber to operate at a lower percent 

reduction than would otherwise be required. Thus, the difference in 

annualized costs with and without an emission credit is equal to the 

operating and maintenance cost differences (i.e., primarily reagent usage) 

associated with the two levels of percent reduction. It is not influenced 

by the price of fuel; as a result, one would not expect changes in fuel 

prices to influence the cost effectiveness of the additional emission 

reductions achieved by not providing an emission credit. 
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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 26, 1986. 

4. An Analysis of the Costs and Cost Effectiveness of Allowing S02 

Emission Credits for Cogeneration Systems. (Prepared for U. S. 

Environmental Protection Agency). Radian Corporation, Research 

Triangle Park, North Carolina. March 1985. pp. 3-37. 

5. An Analysis of the Costs and Cost Effectiveness of S02 Control for 

Mixed Fuel-Fired Steam Generating Units. (Prepared for U. S. 

Environmental Protection Agency). Radian Corporation, Research 

Triangle Park, North Carolina. January 1986. pp. 1-56 

6. Impact of New Fuel Prices on the Costs and Cost Effectiveness of S02 

Emission Control of Cogeneration Systems. (Prepared for U. S. 

Environmental Protection Agency). Radian Corporation, Research 

Triangle Park, North Carolina. April 15, 1987. pp. 1-11. 

7. Impact of New Fuel Prices on the Costs and Cost Effectiveness of S02 

Emission Control of Mixed Fuel-Fired Steam Generating Units. (Prepared 

for U. S. Environmental Protection Agency). Radian Corporation, 

Research Triangle Park, North Carolina. April 15, 1987. pp. 1-10. 

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