p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

313) IV-B-17 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:59 AM Sheet 313 of 325 
P.2 

.. ^ A-83-27 

IV-B-17 

MEMORANDUM 

DATE: April 15, 1987 

TO: Fred Porter and Walt Stevenson, EPA/SDB 

FROM: Edward Aul and Sterling Gray, Radian Corporation 

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

of SO- Emission Control of Cogeneration Systems 

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 the cost and 

cost effectiveness of reducing S0~ emissions from cogeneration steam 

generating units (I.e., boilers). The previous analyses were presented in 

the report An Analysis of the Costs and Cost Effectiveness of Allowing S0? 

Emission Credits for Cogeneration Systems (March 1985). 

The previous analysis was based on fuel prices projected in 1984 (as 

discussed in Reference 4) . The revised fuel price 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 low oil prices, the new analysis 1s also based on 

non-carriage, rigid natural gas prices, as described in Reference 3. 

Non-carriage prices were selected since natural gas was utilized 1n the 

model boiler analysis as the backup fuel 1n the event of flue gas 

desulfurization (FGD) system malfunction. Non-carriage prices are 

representative of natural gas delivered on a "non-1nterrupt1le" contract 

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

Progress Center/3200 E. Chapel Hill Rd./Nelson Hwy./P.O. Box 13000/Research Triangle Park. N.C. 27709/(919)541-9100 
P.3 

maintenance costs for cogeneration systems. These modifications are 

discussed in full in Appendix A. These modifications have 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 are summarized in 

Tables 1 through 6. These results can be compared directly with the 

corresponding tables in the previous analysis. 

An overall comparison of the annualized cost results from the previous 

and revised analyses shows that all costs have decreased somewhat, even 

those associated with standards requiring a percent reduction. The reason 

for this decrease 1s that almost all levelized fuel prices have declined 

significantly between the 1984 and 1986 projections. The effect of this 

decrease has been sufficient to overcome the otherwise slight Increase 1n 

costs due to updating the time basis of the cost estimates. 

2.1 LOW SULFUR FUEL STANDARDS 

The Incremental costs of standards based on low sulfur fuels relative 

to the regulatory baseline have declined slightly. The reason for this 

change is that the sulfur premiums for low sulfur fuels have declined 

between the 1984 and 1986 projections. The difference 1n annualized costs 

between the baseline and a low sulfur fuel standard 1s merely the sulfur 

premium (I.e., the difference in price between low sulfur and high sulfur 

fuels). Since fuel sulfur premiums have declined, the Incremental costs of 

low sulfur fuel standards have also declined. 

As a result of this decline in Incremental costs, the cost 

effectiveness of emission control for standards based on low sulfur fuels 

has also declined slightly. Depending on the specific cases examined, the 

cost effectiveness of standards based on firing low sulfur fuels for 

cogeneration units relative to the baseline 1s generally 1n the range of 

$100 to 500/Mg ($100 to 400/ton) using the new fuel price projections; in 
TABLE 1 . COST AMD COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL 

AND COGENERATION COAL-FIRED STEAM GEICRATING UNITS IN REGION V* 

(August 1986 Price Projections; June 1985 f) 

Fuel Type. 

Average 

Cost 

Steaa Generating Unit/Regulatory Alternative 

Annualized Annual 

ng SO./J Costs. Eaissions. Effectiveness/ 

(lb S02/e1l1lon Btu) (tl.OOO/yr) Mg/yr (tons/yr) S/Mg (S/ton) 

Increaental 

Cost 

Effectiveness,' 

S/Mg (S/ton) 

Conventional Unit. 44 MM (150 alllion Btu/hr) 

Regulatory Baseline, 1.076 ng/J (2.5 lb/alllion Btu) 

Low Sulfur Coal. 516 ng/J (1.2 lb/all Hon Btu) 

Percent Reduction (90 Percent) 

904 (2.10) 

409 (0.95) 

2.384 (5.54) 

8.270 

8,480 

9,040 

1.125 (1.240) 

508 (560) 

227 (250) 

-

338 (307) 

853 (774) 

-

-

1,972 (1,789) 

Cogeneration Unit, 53 MH (180 aillion Btu/hr) 

Regulatory Baseline, 1,076 ng/J (2.5 lb/alllion Btu) 

Lo« Sulfur Coal, 516 ng/J (1.2 lb/all lion Btu) 

Percent Reduction (90 Percent) 

904 (2.10) 

409 (0.95) 

2,384 (5.54) 

9,550 

9.810 

10.440 

1.352 (1.490) 

608 (670) 

272 (300) 

347 (315) 

828 (751) 1.873 (1.699) 

'Based on a capacity factor of 0.9. 

bAverage uncontrolled SO. eaissions. 

cCoapared to regulatory baseline. 

dCoapared to low sulfur fuel alternative. 
TABLE 2 . COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL 

AND COGENERATION COAL-FIRED STEAM GENERATING UNITS IN REGION VIII * 

(August 1986 Price Project Ions | June 1985 S) 

Fuel Type, 

Average 

Cost 

Steaa Generating Unit/Regulatory Alternative 

Annualized Annual 

ng SO./J Costs, Eaissions, Effectiveness,1 

(lb S02/a1l1lon Btu) (Sl.OOO/yr) Mg/yr (tons/yr) S/Mg (S/ton) 

Increaental 

Cost 

Effectiveness, 

S/Mg (S/ton) 

Conventional Unit, 44 MN (150 all Hon Btu/hr) 

Regulatory Baseline, 1,076 ng/J (2.5 lb/all lion Btu) 

Low Sulfur Coal, 516 ng/J (1.2 lb/alllion Btu) 

Percent Reduction (90 Percent) 

Cogeneration Unit, 53 Mt (180 aillion Btu/hr) 

Regulatory Baseline, 1,076 ng/J (2.5 lb/allllon Btu) 

Low Sulfur Coal, 516 ng/J (1.2 lb/allllon Btu) 

Percent Reduction (90 Percent) 

624 (1.45) e 

409 (0.95) 

409 (0.95) 

624 (1.45)* 

409 (0.95) 

409 (0.95) 

6,940 

6,990 

7,520 

7,930 

8.010 

8.610 

777 (860) 

508 (560) 

36 (40) 

934 (1,030) 

608 (670) 

45 (50) 

-

202 (183) 

790 (717) 

— 

227 (206) 

760 (690) 

-

-

1,125 (1,021) 

— 

-

1.065 (966) 

*Based on a capacity factor of 0.9. 

Average uncontrolled SO. eaissions. 

cCoapared to regulatory baseline. 

dCoapared to low sulfur fuel alternative. 

^ased on firing D-subb1tua1nous coal C624 ng SO./J (1.45 lb S0./a1111on Btu)] rather than E-subbltualnous coal [904 ng SO./J 

(2.10 lb S02/a1111on Btu)]. 

XI 

(Jx 
TABLE 3. COST ANO COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL 

AND COGENERATION OIL-FIRED STEAM GENERATING UNITS* 

(August 1986 Price Projections; June 1985 S) 

'".IllJ)'.!,1. 

M,.'iH»' 

Steaa Generating Unit/Regulatory Altentative 

. Average Increaental 

Fuel Type, Annualized Annual Cost Cost 

ng SO./J Costs, Eaissions, Effectiveness,0 Effectiveness,' 

(lb S02/a1l1lon Btu) (Sl.OOO/yr) Mg/yr (tons/yr) S/Mg (S/ton) S/Mg (S/ton) 

Conventional Unit. 44 NH (150 aillion ftta/hr) 

Regulatory Baseline. 1.291 ng/J (3.0 lb/allllon Btu) 

Low Sulfur Oil. 344 ng/J (0.8 lb/allllon Btu)* 

Percent Reduction (90 Percent) 

1.291 (3.0) 

344 (0.8) 

1.291 (3.0) 

4.840 

5,370 

5.610 

1,606 (1.770) 

429 (475) 

122 (135) 

-

448 (406) 

517 (469) 

-

-

783 (710) 

Cogeneration Unit. 53 MH (180 aillion Btu/hr) 

Regulatory Baseline. 1.291 ng/J (3.0 lb/allllon Btu) 

Low Sulfur Oil, 344 ng/J (0.8 lb/allllon Btu)* 

Percent Reduction (90 Percent) 

1.291 (3.0) 

344 (0.8) 

1.291 (3.0) 

5,670 

6.310 

6.560 

1.932 (2.130) 

515 (570) 

145 (160) 

-

453 (411) 

498 (452) 676 (613) 

"Based on a capacity factor of 0.9. 

Average uncontrolled SO. eaissions. 

cCoapared to regulatory baseline. 

dCcapared to low sulfur fuel alternative. 

*L Less expensive to fire a low sulfur oil [344 ng SO./J (0.8 lb SO./allllon Btu)] than to purchase a high sulfur oil [1,291 ng SO./J 

(3 lb S02/a1111on Btu)] and Install an F60 systea fo achieve 73 percent reduction. 

Tl 
TABLE 4 . COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL 

AND COMBINED CYCLE STEAM GENERATING UNITS IN REGION V* 

Fully-Fired Coal 

(August 1986 Price Projections; June 1985 S) 

Annual 

Average 

Cost 

IncTenanta1 

Cost 

Steaa Generating Unit/Regulatory Alternative 

Fuel Type, Annualized TMmu«i KIB V . u U >i 

ng SO./J Costs, Eaissions, Effectiveness, 0 Effectiveness. 6 

(lb S02 /an1lon Btu) (Sl.OOO/yr) Mg/yr (tons/yr) S/Mg (S/ton) S/Mg (S/ton) 

<r> 

Conventional Unit. 29 MM (100 aillion Btu/hr) 

Regulatory Baseline. 1.076 ng/J (2.5 lb/allllon Btu) 

Low Sulfur Coal. 516 ng/J (1.2 lb/allllon Btu) 

Percent Reduction (90 Percent) 

Cogeneration Unit. 40 MM (137 aillion Btu/hr) 

Regulatory Baseline, 1,076 ng/J (2.5 lb/allllon Btu) 

Low Sulfur Coal, 516 ng/J (1.2 lb/allllon Btu) 

Percent Reduction (90 Percent) 

904 (2.10) 

409 (0.95) 

2,384 (5.54) 

904 (2.10) 

409 (0.95) 

2,384 (5.54) 

2.020 

2.170 

2.590 

2,020 

2.170 

2.630 

753 (830) 

336 (370) 

154 (170) 

753 (830) 

336 (370) 

154 (170) 

-

345 (313) 

949 (861) 

— 

345 (313) 

1.000 (908) 

-

-

2.269 (2,058) 

_ 

-

2.433 (2.207) 

"Based on a capacity factor of 0.9; gas turbine Is assuaed to fire natural gas and steaa generating unit Is assuaed to fire listed coal. 

bAverage uncontrolled S02 eaissions. 

cAnnual cost only Includes cost of fuel fired plus annualized cost of S02 control device and does not Include other steaa generating unit 

operating and aaintenance costs or annualized cost of the steaa generating unit. 

dCoapared to regulatory baseline. 

*Coapared to low sulfur fuel alternative. 

Tl 
TABLE 5. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL 

AND COMBINED CYCLE STEAM GENERATING UNITS IN REGION VIII s 

Fully-Fired Coal 

(August 1986 Price Projections; June 1985 S) 

Steaa Generating Unit/Regulatory Alternative 

Increaental 

Cost 

Average 

Fuel Type, Annualized Annual Cost 

ng SO./J Costs, Eaissions, Effectiveness, Effectiveness, 6 

(lb SO./allllon Btu) (Sl,0O0/yr) Mg/yr (tons/yr) S/Mg (S/ton) S/Mg (S/ton) 

Conventional Unit. 29 MM (100 aillio n Btu/hr) 

Regulatory Baseline, 1,076 ng/J (2.5 lb/allllo n Btu) 

Low Sulfur Coal, 516 ng/J (1.2 lb/allllo n Btu) 

Percent Reduction (90 Percent) 

Cogeneration Unit. 40 MH (137 aillio n Btu/hr) 

Regulatory Baseline, 1,076 ng/J (2.5 lb/allllo n Btu) 

Low Sulfur Coal. 516 ng/J (1.2 lb/allllo n Btu) 

Percent Reduction (90 Percent) 

624 (1.45)* 

409 (0.95) 

409 (0.95) 

624 (1.45)f 

409 (0.95) 

409 (0.95) 

1.050 

1.080 

1.490 

1.050 

1.080 

1.520 

519 (570) 

336 (370) 

27 (30) 

519 (570) 

336 (370) 

27 (30) 

-

155 (141) 

893 (810) 

— 

133 (121) 

947 (859) 

-

-

1,314 (1,192) 

— 

-

1,413 (1.282) 

"Based on a capacity factor of 0.9 ; gas turbine Is assuaed to fir e natural gas and steaa generating unit 1s assuaed to fir e listed coal. 

bAverage uncontrolled S02 eaissions. 

cAnnual cost only Includes cost of fuel fired plus annualized cost of S02 contro) device and does not Include other steaa generating unit 

operating and aaintenance costs or annualized cost of the steaa generating unit. 

dCoapared to regulatory baseline. 

*Cotapared to low sulfur fuel alternative. 

fBased on firin g D-subbltualnous coal [624 ng SO./J (1.45 lb SO./allllon Btu)] rather than E-subbltualnous coal [904 ng SO./J 

(2.10 lb S02/a1111on Btu)]. 
TABLE 6. COST ANO COST EFFECTIVENESS OF S02 CONTROL FOR CONVENTIONAL 

AND COMBINED CYCLE OIL-FIRED STEAM GENERATING UNITS* 

(August 1986 Price Projections; June 1985 S) 

Fuel Type, 

Average 

Cost 

Steaa Generating Unit/Regulatory Alternative 

Annualized Annual 

ng SO./J Costs, Eaissions. Effectiveness,' 

(lb S02/a1l1lon Btu) (Sl.OOO/yr) Mg/yr (tons/yr) S/Mg (S/ton) 

Increaental 

Cost 

Effectiveness,' 

S/Mg (S/ton) 

Conventional Unit. 29 MH (100 aillion Btu/hr) 

Regulatory Baseline, 1,291 ng/J (3.0 lb/allllon Btu) 

Low Sulfur 011, 344 ng/J (0.8 lb/allllon Btu) 

Percent Reduction (90 Percent) 

1,291 (3.0) 

344 (0.8) 

1,291 (3.0) 

2.270 

2.630 

2.840 

1.070 (1.180) 

290 (320) 

82 (90) 

-

456 (414) 

579 (525) 

-

-

1,054 (956) 

CD 

Fullv-FIran 

Cogeneration Unit, 38 MH (129 aillion Btu/hr) 

Regulatory Baseline, 1.291 ng/J (3.0 lb/allllon Btu) 

Low Sulfur Oil. 344 ng/J (0.8 lb/allllon Btu) 

Percent Reduction (90 Percent) 

1.291 (3.0) 

344 (0.8) 

1.291 (3.0) 

2.270 

2.630 

2.860 

1,070 (1,180) 

290 (320) 

82 (90) 

-

456 (414) 

600 (544) 

-

-

1,156 (1.049) 

S»ppla—nta rv-Flred 

Cogeneration Unit, 92 MH (313 aillion Btu/hr) 

Regulatory Baseline, 1.291 ng/J (3.0 lb/allllon Btu) 

Low Sulfur Oil. 344 ng/J (0.8 lb/allllon Btu) 

Percent Reduction (90 Percent) 

1,291 (3.0) 

344 (0.8) 

1.291 (3.0) 

2.270 

2.630 

3.210 

1.070 (1,160) 

290 (320) 

82 (90) 

-

456 (414) 

955 (866) 

-

-

2,876 (2,609) 

"Based on a capacity factor of 0.9; gas turbine Is assuaed to fire natural gas and steaa generating unit Is assuaed to fire listed oil. 

bAverage uncontrolled S02 eaissions. 

cAnnual cost only Includes cost of fuel fired plus annualized cost of S0_ control device and does not Include other steaa generating unit 

operating and aaintenance costs or annualized cost of the steaa generating unit. 

^Compared to regulatory baseline. 

6Coapared to low sulfur fuel alternative. 

Tl 

CO 
P.10 

the previous analysis, the cost effectiveness was generally in the range of 

$200 to 700/Mg ($200 to 600/ton). 

2.2 PERCENT REDUCTION STANDARDS 

Although the overall costs associated with standards requiring a 

percent reduction have declined slightly, the incremental costs of these 

standards versus low sulfur fuel standards have Increased. The reason for 

this increase is that the fuel sulfur premium for low sulfur fuels has 

declined between the 1984 and 1986 projections while other costs have 

remained largely unchanged. Thus the fuel cost savings resulting from 

firing higher sulfur fuels and scrubbing have decreased. These fuel savings 

now offset less of the costs associated with the scrubber system. The same 

situation applies to the Incremental costs of firing high sulfur fuels and 

scrubbing versus firing medium sulfur fuels at the regulatory baseline. 

The overall result of these factors is that the cost effectiveness of 

standards requiring percent reduction has Increased. Using the new fuel 

prices, the average cost effectiveness of standards requiring a percent 

reduction 1n emissions 1s generally 1n the range of $500 to 800/Mg ($500 to 

800/ton) for steam generator-based coal- and oil-fired cogeneration units; 

the cost effectiveness was generally In the range of $500 to 700/Mg ($400 to 

600/ton) 1n the previous analysis. For combined cycle coal- and oil-fired 

cogenerator units, the average cost effectiveness with new fuel prices is in 

the range of $600 to 1000/Ng ($500 to 900/ton); in the previous analysis it 

was in the range of $600 to 900/Mg ($500 to 800/ton). 

The Incremental cost effectiveness of standards requiring a percent 

reduction 1n Sfc emissions have also Increased over standards based on 

firing low spl fur fuels. Based on the new fuel prices, the Incremental cost 

effectiveness? of percent reduction emission control ranges from $1100 to 

1900/Mg ($1000 to 1700/ton) for steam generator-based coal-fired 

cogeneration units; 1n the previous analysis, this value ranged from $900 to 

1300/Mg ($800 to 1100/ton). For steam generator-based oil-fired 

cogeneration units, the new fuel prices Increase the Incremental cost 
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4.0 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 011 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. Radian Corporation. An Analysis of the Costs and Cost Effectiveness of 

Allowing SO- Emission Credits for Cogeneration Systems. Prepared for 

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

Carolina. Publication No. EPA-450/3-85-030. December 1985. 

5. Radian Corporation. Industrial Boiler SO- Cost Report. Prepared for 

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

Carolina. Publication No. EPA-450/3-85-011. November 1984. p. 1-1 to 

4-7. 

6. Economic Indicators. Chemical Engineering. 21 (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. 

11 
APPENDIX A 

METHODOLOGY FOR REVISING MODEL COGENERATION SYSTEM 

COST ESTIMATES TO INCORPORATE NEW FUEL PRICES 

This Appendix presents the methodology used to revise the model 

cogeneration system cost estimates in Reference 4 to Incorporte 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 

other model boiler cost estimates. 

To accomplish these tasks, cogeneration cost estimates were updated 

using the relationships between annualized costs and fuel prices contained 

1n the original estimates of annualized costs. Fuel prices Influence 

annualized costs in four 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, $/uill1on Btu. 

Thus the chajjgerIn AFC as a result of fuel price changes Is given by: 

AAFC - Q ' CF * 8760 * AF P (2) 

A-l 
P.14 

The second area of fuel price impacts involves Interest on working 

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

This quantity 1s related to AFC changes by: 

IWC - 0.0083 AFC (3) 

The third area of fuel price impacts Is malfunction costs, which only 

apply to model steam generating units equipped with flue gas desulfurization 

(FGD) systems. During periods of FGD system malfunction, the cost 

algorithms assume that the steam generating unit 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 ' (1.0-REL/100) (NGP-FP) (4) 

where 

MC - Malfunction costs, $/year, 

REL - FGD system reliability, %, and 

NGP - Natural gas price, $/mill1on Btu. 

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

to changes In natural gas and other fuel prices 1s given by: 

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

For sodium scrubbing FGD systems, an operating reliability of 95 percent Is 

assumed. 

The final area of fuel price Impacts 1s NO control costs, which apply 

to steam generator-based cogeneration systems only. The original cost 

estimates for these systems assumed NO emissions are controlled by low 

excess air (LEA) control technology. Because LEA reduces fuel requirements, 

A-2 
the cost of applying the method 1s actually realized as a fuel savings. The 

N0X control costs attributed to fuel costs are calculated as: 

NCC - Q • CF * (-0.00055) * FP * FFAC * (UNCEA - CTREA) (6) 

where 

NCC = NO control costs, $/year, 

FFAC - F-factor, dscf/million Btu, 

UNCEA - Uncontrolled excess air, %, and 

CTREA - Controlled excess air, %. 

Therefore, the change in N0X control costs due to fuel price changes 1s 

given by: 

ANCC - Q ' CF * (-0.00055) ' AF P * FFAC * (UNCEA-CTREA) (7) 

Because exhaust gas from the gas turbine 1s used as combustion air for 

supplementary-fired and fully-fired combined cycle systems, N0X control by 

LEA 1s not applicable to combined cycle units and 1s not Included In cost 

estimates for those units. Thus, for combined cycle units, there are no NO 

control cost Impacts due to fuel price changes. 

The change in total annualized costs (TAC) resulting from fuel price 

changes for a model cogeneration system 1s the sum the factors discussed 

above. Comparisons of previous and new fuel price projections for coal, 

oil, and natural gas are presented In Table A-l. The fuel prices projected 

in August 1986 are expressed 1n June 1985 dollars compared to January 1983 

dollars for th* July 1984 projections. The new cost and cost effectiveness 

estimates ar« based on low oil prices and low natural gas prices consistent 

with a non-carriage natural gas market and a rigid regulatory environment, 

as discussed in References 2 and 3. 

In updating the model cogeneration system cost estimates 1t was also 

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

other non-fuel costs. This was accomplished using an average factor of 

A-3 
TABLE A-l. COMPARISON OF 1984 AND 1986 COAL, OIL, ANO NATURAL GAS PRICE PROJECTIONS 

Fuel Type 

V'^ysife. 

Sulfur Content 

(lb S(ymillion Btu) 

July 1984 

Price Projection3 

(1983 $/m11Hon Btu) 

August 1986 

Price Projection 

(1985 $/m1111on Btu) 

Region V 

*» 

•0> 

B-blturn1nous coal 

D-b1tum1nous coal '• 

E-b 1 tun 1 nous coal 

H-b1tum1nous coal 

3.Of Sulfur 011d 

1.6% Sulfur 011d 

0.8* Sulfur 01l d 

Natural gas 

Region VII I 

E-subbltunlnous coal 

D-subbituminous coal 

B-subbltunlnous coal 

Natural gas 

<1.08 

1.08-1.67 

1.67-2.50 

>5.00 

3.0 

1.6 

0.8 

0.00 

1.67-2.50 

1.08-1.67 

<1.08 

0.00 

3.32 

3.18 

3.08 

2.50 

4.94 

5.25 

5.63 

5.88 

1.28 

1.39 

1.40 

4.91 

2.75 

2.64 

2.57 

2.24 

2.90 

3.09 

3.35 

3.77c 

1.35 

1.33 

1.37 

3.14c 

'Source: Reference 4. 

Source: References 1-3. 

'Based on a non-carriage natural gas market and rigid regulatory environment, as dl 

References 2 and 3. 

scussed In 

J 

Prices given are for low oil prices. 
> 

1.032 based on the Chemical Engineering Plant Cost Index and the Producer 

Price Index for all Industrial commodities. ' 

The methodology described above was used to update the original model 

cogeneration system cost estimates where appropriate. In two cases, 

however, the fuel selected to meet a regulatory alternative was changed due 

to fuel price changes. In the first case, the fuel selected to meet the low 

sulfur fuel standard for oil-fired cogeneration was changed from a high 

sulfur oil (3.0 lb S02/m1ll1on Btu) with an Installed FGD system operating 

at 73 percent SO- reduction to a low sulfur oil (0.8 lb SO-/m1ll1on Btu). 

This change was made since, for the new fuel prices, the firing of low 

sulfur oil entails lower annual costs than firing high sulfur oil 1n 

combination with an FGD system; for the former fuel prices this was not the 

case. 

In the second case, the coal selected for the regulatory baseline case 

(2.5 lb S02/m1llion Btu) in Region VIII was changed froa Type 

E-subbituminous coal (2.10 lb S02/m1ll1on Btu) to Type D-subbituminous coal 

(1.45 lb S02/mill1on Btu). This change was made because Type 

D-subbituminous coal In Region VIII has a lower price than Type 

E-subb1tum1nous coal, based on 1986 fuel price projections, even though It 

has a lower sulfur content. For these two cases, therefore, 1t was 

necessary to estimate model cogeneration systen costs using the computerized 

cost algorithms and the appropriate fuel prices and update factors. 

A-5