p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

317) IV-B-21 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:59 AM Sheet 317 of 325 
P.2 

A v * RADIA N A-83-27 

CORPORATIO N ^ ^ 

MEMORANDUM 

DATE: May 15, 1987 

TO: Fred Porter and Walt Stevenson, EPA/SDB 

FROM: John Martinez and Ed Aul, Radian Corporation 

SUBJECT: Assumptions and Procedures Used to Generate Model Boiler Impacts 

1.0 INTRODUCTION 

This memorandum documents the assumptions and procedures used to 

examine the cost and emission impacts associated with several sulfur dioxide 

(SO-) regulatory alternatives on various model boilers. The primary purpose 

of this analysis was to update the cost and cost effectiveness estimates for 

SO- reductions resulting from (1) inclusion of additional coals, (2) changes 

in fuel prices, and (3) use of "generic" costs for flue gas desulfurization 

(FGD). Except for the changes noted above and those in Appendix F, all 

other assumptions and procedures used to calculate the costs of the 

1 2 regulatory alternatives are consistent with those in prior analyses. ' 

Regulatory alternatives in this analysis include the use of low sulfur 

fuels (i.e., 1.2 lb S02/106 Btu for coal and 0.8 lb S02/106 Btu for oil) and 

very low sulfur fuels (i.e., 0.7 and 0.9 lb S0-/10 Btu for coal and 0.3 lb 

S0-/10 Btu for oil) as well as 90 percent SO- reduction based on FGD. 

Model boiler costs were calculated in June 1985 dollars using the 

industrial boiler cost program (IBCOST). Capital costs were updated from 

January 1983 to June 1985 dollars using an escalation factor of 1.03, based 

on the Chemical Engineering Plant Cost Index. For updating non-fuel 

operating and maintenance (0&M) costs, an escalation factor of 1.035 was 

used, based on Bureau of Labor Statistics' Index of All Industrial 

Commodities. No escalation factor was used for updating the fuel costs 

because these costs were already in June 1985 dollars. 

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

Section 2.0 presents the assumptions used to generate coal-fired model 

boiler costs. Sections 3.0 and 4.0 present the same for the oil- and 

natural gas-fired model boilers, respectively. Results of the analysis for 

each fuel type are presented in Appendices A through C. Data used for 

developing generic FGD costs are presented in Appendix D. Appendix D also 

presents costs for boilers firing the very low sulfur coals. Appendix E 

discusses assumptions made concerning the sulfur variability of low and very 

low sulfur coals. Appendix F discusses adjustments made to IBCOST inputs to 

assure consistency with boiler cost analyses conducted since publication of 

Reference 2. 

2.0 COAL-FIRED MODEL BOILER COSTS 

Costs were estimated for model coal-fired boilers of 150 and 400 

million Btu/hour heat inputs located in EPA Regions III, IV, V and VIII. 

The 150 million Btu/hour model boiler was represented by a coal-fired 

spreader stoker, and the 400 million Btu/hour model boiler was represented 

by a pulverized coal-fired boiler. The boilers operated at a 0.6 capacity 

factor. Coal types and prices used in this analysis are presented in 

Table 2-1 for each region. 

For estimating capital and annualized costs of model boilers firing 

very low sulfur bituminous coals (A-Bit and AA-Bit), the heating values and 

ash contents of B-Bit coal were assumed. Similarly, the heating values and 

ash contents of the A-Sub and AA-Sub coals were assumed equal to those of 

B-Sub coal. For model boilers firing very high sulfur bituminous coal 

(J-Bit), the heating values and ash contents of H-Bit coal were used. Fuel 

prices for J-Bit coal were estimated by linearly extrapolating the price 

versus sulfur content relationship for the other coal types to the sulfur 

content of J-Bit coal (i.e., 8.0 lb S0-/10 Btu). 

6 FGD control costs were based on a "generic" FGD system cost. To 

estimate the generic costs of FGD system, the existing algorithms in IBCOST 

for sodium scrubbing, dual alkali, and lime spray drying were executed for 

each boiler size, fuel type, and region. The lowest and highest costs among 

these three types of FGD systems were then averaged to obtain the generic 

costs for a FGD system. 
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Costs for FGD malfunction were also included in the generic costs of an 

FGD system and were based on the boiler firing natural gas during FGD 

malfunction. Included in the costs were the capital costs of natural gas 

burning equipment designed to fire at 100 percent load and the fuel cost of 

burning natural gas (based on the gas prices corresponding to the low oil 

scenario and non-carriage/rigid market) during period of FGD malfunction. 

Appendix F discusses the procedures and assumptions used to calculate boiler 

and FGD system costs. 

3.0 OIL-FIRED MODEL BOILER COSTS 

Costs were estimated for an oiT-fired model boiler rated at 150 million 

Btu/hour heat input located in EPA Region V. The boiler operated at a 0.55 

capacity factor. Oil prices used in this analysis are presented in 

Table 3-1 for Region V. 

The 150 million Btu/hour model boiler was represented by a package 

boiler. Generic FGD costs are based on the average costs of dual alkali and 

sodium scrubbing. Spray drying FGD was not evaluated due to its limited 

applications on oil-fired boilers. Appendix F discusses the assumptions and 

methodology changes for FGD controls on oil-fired boilers. 

4.0 NATURAL GAS-FIRED MODEL BOILER COSTS 

Costs were estimated for natural gas-fired model boilers rated at 150 

and 400 million Btu/hour heat inputs and located in EPA Regions III, IV, V 

and VIII. The natural gas-fired boilers operated at the same capacity 

factor as the oil-fired model boiler (0.55). Table 4-1 presents the natural 

gas prices for the flexible carriage market under the low oil price 

scenario. 

The 150 million Btu/hour natural gas-fired model boiler was represented 

by a package boiler. The 400 million Btu/hour natural gas-fired model 

boiler was represented by two package boilers each rated at 200 million 

2 

Btu/hour heat input, as was done in the previous boiler cost analysis. 
P.6 

TABLE 3-1. OIL PRICES USED IN ESTIMATING THE OIL-FIRED 

MODEL BOILER COSTS IN EPA REGION Va 

Percent Sulfur Oil Prices, g 

Fuel Type by Weight June 1985 Dollars/10 Btu 

Residual Oil 3.0 2.90 

1.6 3.09 

0.8 3.35 

0.3 3.49 

Distillate Oil 0.3 3.86 

a0il prices were based on the low oil price scenario as cited in 

Reference 9. 
P.7 

TABLE 4-1. NATURAL GAS PRICES USED IN ESTIMATING THE 

NATURAL GAS-FIRED MODEL BOILER COSTS3 

Carriage, Flexible Market Prices, 

EPA Region June 1985 Dollars/10 Btu 

III 3.06 

IV 3.01 

3.17 

VIII 3.06 

a Reference 5. 
P.8 

5.0 REFERENCES 

1. Radian Corporation. Costs of Sulfur Dioxide, Particulate Matter, and 

Nitrogen Oxide Controls on Fossil Fuel-Fired Industrial Boilers. 

Prepared for the U.S. Environmental Protection Agency. Research 

Triangle Park, NC. Publication No. EPA-450/3-82-021. August 1982. 

p. A-l to A-34. 

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

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

Publication No. EPA-450/3-85-011. November 1984. p. 2-1 to 2-27. 

3. ICF, Incorporated. Availability and Cost of Very Low Sulfur Coals for 

the Industrial Market. Prepared for the U.S. Environmental Protection 

Agency. Research Triangle Park, NC. March 6, 1987. p. 4-33. 

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

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

August 29, 1986. 

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

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

August 27, 1986. 

6. Memorandum from Shumaker, J. L. and J. T. Waddell, Radian Corporation, 

to Porter, F. L., EPA/SDB. April 29, 1987. 10 p. Use of a Generic 

Cost Algorithm to Represent the Costs of Industrial Flue Gas 

Desulfurization (FGD) Systems. 

7. Memorandum from Martinez, J., Radian Corporation, to SO- Docket Files. 

January 8, 1986. 11 p. Update on Flue Gas Desulfurization System 

Malfunction Costs. 

8. 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, NC. Publication No. EPA-450/3-86-005. 

June 1986. p. 6-1. 

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

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

August 26, 1986. 

10. Margerum, S., and G. Giguere (Radian Corporation). Variability of S0-

Emissions from Low Sulfur Coal-Fired Industrial Boilers. Prepared for 

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

July 1985. 

11. Reference 8. p. 5-55 to 5-56. 
P.9 

12. Giguere, G., and S. Margerum (Radian Corporation). Determination of 

Mean SO- Emission Levels Required to Meet a 1.2 lb S0-/Milli'on Btu 

Emission Standard for Various Averaging Times and Compliance Policies. 

Prepared for the U.S. Environmental Protection Agency. Research 

Triangle Park, N. C. March 1985. pp. A-8 to B-4. 

J 
P.10 

APPENDIX A 

COST AND COST EFFECTIVENESS RESULTS FOR 

COAL-FIRED MODEL BOILERS IN REGIONS 3, 4, 5 AND 8 
TABLE A-l. COST RESULTS FOR 

STANDARD ANALYZED 

Million BTU/HR 

Percent 

1 NOMINAL SO 

2 

\ NOMINAL EMISSION 

| PERCENT 

| REDUCTION 

| COMMENT REQUIRED 

3> i 

Tt ' ' b 

| BASELINE - least cost option NA 

| COMPLIANCE COAL - least cost option NA 

| VERY LOU SULFUR COAL 

| *0.9 Std - least cost option NA 

| *0.7 Std - least cost option NA 

| PERCENT REDUCTION 

| *90X on least cost option 90 

| *90I on high sulfur coal 90 

| *90X on medium sulfur coal 90 

LIMIT 

(LBS PER 

10 BTU) 

2.5 

1.2 

0.9 

0.7 

NA 

NA 

NA 

a 

Total annualized costs for boiler and all applicable emiss lc 

NA = not applicable 

Less expensive than the 0.7 standard option 

COAL 

TYPE 

E-Blt 

B-Bit 

A-Bit 

AA-Bit 

F-Bit 

J-Bit 

G-Bit 

A 150 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION III 

COAL SELEC 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

2.1 

1.08 

0.82 

0.62 

0.217 

0.608 

0.316 

n control systems 

rED 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

828 

426 

323 

244 

86 

240 

125 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

5,731 

5,926 

6,068 

6,714 

6,473 

6,634 

6,530 

INCREMENTAL COST EFFECTIVENESS 

($ PER TON OF SO REMOVED) 

2 

BASELINE 

— 1.2 COAL — 

0.9 COAL 

NA 

485 

1,385 

4,346 

1,608 1,704 

3,805 6,773 

2,006 2,325 

-

0.7 COAL 

-1,517 

-16,912 

c 

-1,535 

04/15/87 

# 

1 
TABLE A-2. COST RESULTS FOR A 400 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION III 

FUEL TYPE3> 

ro 

FOR REGIONBOILER SIZECOAL 

400 Million BTU/HR 

CAPACITY FACTOR- 60 Percent 

STANDARD ANALYZED 

COMMENT 

NOMINAL SO 

2 

NOMINAL EMISSION 

PERCENT LIMIT 

REDUCTION (LBS PER 

REQUIRED 10 BTU) 

BASELINE - least cost option 

COMPLIANCE COAL - least cost option 

VERY LOU SULFUR COAL 

*0.9 Std - least cost option 

*0.7 Std - least cost option 

PERCENT REDUCTION 

*90Z on least cost option 

*90Z on high sulfur coal 

*90X on medium sulfur coal 

NA 

NA 

NA 

NA 

90 

90 

90 

2.5 

1.2 

0.9 

0.7 

NA 

HA 

NA 

COAL SELECTED 

| COAL 

| TYPE 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

E-Blt 

B-Bit 

A-Blt 

AA-Blt 

F-Blt 

J-Blt 

G-Bit 

2.1 2,208 

1.08 1,135 

0.82 

0.62 

862 

652 

14,027 

14,550 

14,932 

16,675 

0.217 

0.608 

0.316 

228 

639 

332 

15,318 

15,704 

15,477 

INCREMENTAL COST EFFECTIVENESS 

| BASELINE 

NA 

488 

($ PER TON OF SO REMOVED) 

2 

— 1.2 COAL — 

0.9 COAL 

1,398 

4,395 

847 609 

2,326 3,464 

1,154 1,029 

0.7 COAL | 

-3,203 | 

-.76,976 | 

-3,749 | 

Total annualized costs for boiler and all applicable emission control-systems 

b 

NA = not applicable 

c 

Less expensive than the 0.7 standard option 

04/15/87 
TABLE A-3. COST RESULTS FOR A 150 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION IV 

FUEL TYPE- COAL 

FOR REGIONBOILER SIZE- 150 Million BTU/HR 

CAPACITY FACTOR- 60 Percent 

STANDARD ANALYZED COAL SELECTED INCREMENTAL COST EFFECTIVENESS 

I 

co 

| COMMENT 

| BASELINE - least cost option 

| COMPLIANCE COAL - least cost option 

| VERY LOU SULFUR COAL 

| *0.9 Std - least cost option 

| "0.7 Std - least cost option 

| PERCENT REDUCTION 

| *90X on least cost option 

| *90X on high sulfur coal 

| *90X on medium sulfur coal 

NOMINAL 

PERCENT 

REDUCTION 

REQUIRED 

b 

NA 

NA 

NA 

NA 

90 

90 

90 

ROMINAL SO 

2 

EMISSION 

LIMIT 

(LBS PER 

6 

10 BTU) 

2.5 

1.2 

0.9 

0.7 

NA 

NA 

NA 

COAL 

TYPE 

E-Blt 

B-Bit 

A-Blt 

AA-Bit 

D-Bit 

J-Blt 

G-Bit 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

2.1 

1.08 

0.82 

0.62 

0.11 

0.608 

0.316 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

828 

426 

323 

244 

43 

240 

125 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

5,873 

5,934 

6,147 

6,698 

6,620 

6,858 

6,713 

($ PER TON OF SO REMOVED) 

2 

BASELINE 

1.2 COAL — 

0.9 COAL 

HA 

152 

2,078 

4,213 

1,794 1,690 

4,966 8,508 

2,587 2,849 

0.7 COAL | 

-388 | 

33,824 | 

125 | 

Total annualized costs for boiler and all applicable emission control systems 

b 

NA = Not applicable 

c 

Less expensive than the 0.7 standard option 

04/15/87 
TABLE A-4. COST RESULTS FOR A 400 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION IV 

3> 

I 

FUEL TYPEFOR REGIONBOILER SIZECAPACITY FACTORCOAL 

400 Million BTU/HR 

60 Percent 

STANDARD ANALYZED 

COMMENT 

NOMINAL SO 

2 

NOMINAL EMISSION 

PERCENT LIMIT 

REDUCTION (LBS PER 

6 

REQUIRED 10 BTU) 

BASELINE - least cost option NA 

COMPLIANCE COAL - least cost option NA 

VERY LOU SULFUR COAL 

*0.9 Std - least cost option 

*0.7 Std - least cost option 

PERCENT REDUCTION 

*90X on least cost option 

*90X on high sulfur coal 

*90X on medium sulfur coal 

NA 

NA 

90 

90 

90 

2.5 

1.2 

0.9 

0.7 

HA 

HA 

HA 

COAL SELECTED 

| COAL 

| TYPE 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

E-Blt 2.1 2,208 14,407 

B-Blt 1.08 1,135 14,569 

A-Bit 0.82 

AA-Blt 0.62 

D-Blt 0.11 

J-Bit 0.608 

G-Bit 0.316 

862 15,143 

652 16,630 

116 15,717 

639 16,276 

332 15,957 

.INCREMENTAL COST EFFECTIVENESS_ 

($ PER TON OF SO REMOVED) 

2 

BASELINE 

— 1.2 COALNA 

151 

2,100 

4,262 

1,126 

3,440 

1,728 

0.9 COAL 

0.7 COAL 

769 -1,703 

5,084 r28,063 

1,536 -2,106 

Total annualized costs for boiler and all applicable emission control systems 

b 

NA = not applicable 

c 

Less expensive than the 0.7 standard option 

04/15/87 
TABLE A-5. COST RESULTS FOR A 150 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION V 

I 

cn 

FUEL TYPEFOR REGIONBOILER SIZECAPACITY FACTORCOAL 

150 Million BTU/HR 

60 Percent 

STANDARD ANALYZED 

COMMENT 

NOMINAL SO 

2 

NOMINAL EMISSION 

PERCENT LIMIT 

REDUCTION (LBS PER 

REQUIRED 10 BTU) 

BASELINE - least cost option NA 

COMPLIANCE COAL - least cost option NA 

VERY LOU SULFUR COAL 

*0.9 Std - least cost option 

*0.7 Std - least cost option 

PERCENT REDUCTION 

*90X on least cost option 

*90X on high sulfur coal 

*90X on medium sulfur coal 

NA 

NA 

90 

90 

90 

2.5 

1.2 

0.9 

0.7 

COAL SELECTED 

| COAL 

| TYPE 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

E-Bit 2.1 

B-Bit 1.08 

828 

426 

A-Sub 0.65 256 

AA-Sub 0.45 177 

NA 

HA 

NA 

F-Blt 

J-Blt 

G-Blt 

0.217 

0.608 

0.316 

86 

240 

125 

5,885 

6,014 

6,157 

6,267 

6,622 

6,656 

6,636 

INCREMENTAL COST EFFECTIVENESS 

1 ($ PER TON OF SO REMOVED) 

2 

| BASELINE 

| —1. 2 COAL — 

| 0.9 COAL 

NA 

321 

844 

1,019 

1,787 2,724 

3,450 30,139 

2,065 3,638 

0.7 COAL | 

3,865 | 

r6,246C | 

6,986 | 

Total annualized costs for boiler and all applicable emission control systems 

b 

NA = not applicable 

c 

Inferior option 

04/15/87 
TABLE A-6. COST RESULTS FOR A 400 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION V 

FUEL TYPEI 

cn 

FOR REGIONBOILER SIZECAPACITY FACTORCOAL 

5 

400 Million BTU/HR 

60 Percent 

STANDARD ANALYZED COAL SELECTED 

COMMENT 

NOMINAL 

PERCENT 

REDUCTION 

REQUIRED 

b 

NOMINAL SO 

2 

EMISSION 

LIMIT 

(LBS PER 

6 

10 BTU) 

COAL 

TYPE 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

BASELINE - least cost coal option NA 

COMPLIANCE COAL - least cost coal NA 

option 

VERY LOU SULFUR COAL 

*0.9 Std - least cost coal option NA 

*0.7 Std - least cost coal option NA 

PERCENT REDUCTION 

.5 

.2 

E-Blt 

B-Sub 

2.1 

0.96 

2,208 

1,009 

14,395 

14,757 

*90X on least cost option 

*90X on high sulfur coal 

*90X on medium sulfur coal 

90 

90 

90 

0.9 A-Sub 0.65 

0.7 AA-Sub 0.45 

NA F-Blt 0.217 

NA J-Bit 0.608 

NA G-Blt 0.316 

683 14,757 

473 15,054 

228 15,670 

639 15,751 

332 15,754 

INCREMENTAL COST EFFECTIVENESS 

1 ($ PER TON OF SO REMOVED) 

2 

| BASELINE 

| —1. 2 COAL — 

| 0.9 COAL 

NA 

302 

0 

554 

1,169 2,006 

2,686 22,514 

1,473 2,840 

0.7 COAL | 

2,515 | 

-4,197 | 

4,969 | 

Total annualized costs for boiler and all applicable emission control systems 

b 

NA = not applicable 

c 

Inferior option 

04/15/87 
TABLE A-7. COST RESULTS FOR A 150 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION VIII 

FUEL TYPEI 

FOR REGIONBOILER SIZECAPACITY FACTORCOAL 

150 Million BTU/HR 

60 Percent 

STANDARD ANALYZED 

COMMENT 

NOMINAL SO 

2 

NOMINAL EMISSION 

PERCENT LIMIT 

REDUCTION (LBS PER 

6 

REQUIRED 10 BTU) 

BASELINE - least cost option NA 2.5 

COMPLIANCE COAL - least cost option NA 1.2 

VERY LOU SULFUR COAL 

*0.9 Std - least cost option NA 0.9 

*0.7 Std - least cost option NA 0.7 

PERCENT REDUCTION 

*90X on least cost option 90 NA 

*90X on high sulfur coal 90 HA 

*90X on medium sulfur coal 90 NA 

COAL SELECTED 

| COAL 

| TYPE 

D-Sub 

B-Sub 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

1.44 

0.96 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

568 

378 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

5,118 

5,153 

A-Sub 0.65 256 

AA-Sub 0.45 177 

B-Sub 0.073 29 

E-Sub 0.161 63 

B-Sub 0.073 29 

5,153 

5,263 

5,824 

5,889 

5,824 

INCREMENTAL COST EFFECTIVENESS 

BASELINE 

NA 

185 

($ PER TON OF SO REMOVED) 

2 

— 1.2 COAL — 

0.9 COAL 

0 

547 

1,919 2,950 

2,337 3,818 

1,919 2,950 

0.7 COAL | 

3,775 | 

• 5,495 | 

3,775 | 

Total annualized costs for boiler and all applicable emission control systems 

b 

NA = not applicable 

04/15/87 
TABLE A-8. COST RESULTS FOR A 400 MILLION BTU/HOUR COAL-FIRED BOILER IN REGION VIII 

FUEL TYPE- COAL 

FOR REGIONBOILER SIZE 400 

STANDARD ANALYZED 

Million BTU 

Percent 

1 NOMINAL SO 

2 

| NOMINAL EMISSION 

| PERCENT 

| REDUCTION 

1 COMMENT REQUIRED 

**• 1 

1 1 

CO t> 

| BASELINE - least cost option NA 

| COMPLIANCE COAL - least cost option NA 

| VERY LOU SULFUR COAL 

| *0.9 Std - least cost option NA 

| *0.7 Std - least cost option NA 

| PERCENT REDUCTIOH 

| *90Z on least cost option 90 

| *90X on high sulfur coal 90 

1 *90Z on medium sulfur coal 90 

LIMIT 

(LBS PER 

10 BTU) 

2.5 

1.2 

0.9 

0.7 

NA 

HA 

HA 

a 

Total annualized costs for boiler and all applicable emisslo 

NA = not applicable 

ran 

COAL 

TYPE 

D-Sub 

B-Sub 

A-Sub 

AA-Sub 

D-Sub 

E-Sub 

B-Sub 

COAL SELEC1 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

1.44 

0.96 

0.65 

0.45 

0.109 

0.161 

0.073 

n control systems 

"ED 

ANNUAL 

EMISSIONS 

(TONS 

PER 

YEAR) 

1,514 

1,009 

683 

473 

115 

169 

77 

ANNUALIZED 

COSTS 

($1000 

PER YEAR) 

11,956 

12,064 

12,064 

12,361 

13,242 

13,410 

13,254 

INCREMENTAL COST EFFECTIVENESS 

($ PER TON OF SO REMOVED) 1 

2 - . 

BASELINE | 

—-1.2 COAL — | 

0.9 COAL | 

0.7 COAL | 

HA | 

214 | 

0 1 

554 | 

1,317 2,071 2,458 | 

1,603 2,618 . 3,453 | 

1,276 1,962 2,253 | 

04/15/87 
P.19 

APPENDIX B 

COST AND COST EFFECTIVENESS RESULTS FOR 

OIL-FIRED MODEL BOILERS IN REGION 5 
TABLE B-l. COST RESULTS FOR A 150 MILLION BTU/HOUR RESIDUAL OIL-FIRED BOILER IN REGION V 

CO 

I 

FUEL TYPEFOR REGIONBOILER SIZECAPACITY FACTOROIL 

150 Milion BTU/HR 

55 Percent 

STANDARD ANALYZED OIL SELECTED 

COMMENT 

NOMINAL SO 

2 

NOMINAL EMISSION 

PERCENT LIMIT 

REDUCTION (LBS PER 

6 

REQUIRED 10 BTU) 

| OIL 

| TYPE 

AVERAGE SO 

2 

EMISSIONS 

(LBS 

PER 

6 

10 BTU) 

ANNUAL 

EMISSIONS 

(TOHS 

PER 

YEAR) 

ANNUALIZED 

b 

COSTS | 

($1000 | 

PER YEAR) | 

BASELINE - least cost option NA 

COMPLIANCE OIL - least cost option NA 

VERY LOH SULFUR OIL 

*0.3 Std - least cost option NA 

PERCENT REDUCTION 

*90X on least cost option 90 

*90X on high sulfur option 90 

*90X on medium sulfur oil 90 

3.0 

0.8 

0.3 

NA 

HA 

HA 

3.0XS 

0.8XS 

3.243 1,172 

0.865 313 

3,236 

3,559 

0.3XS 0.324 117 3,659 

0.8XS 

3.0XS 

1.6XS 

0.066 

0.246 

0.131 

24 

89 

47 

4,094 

4,103 

4,132 

INCREMENTAL COST EFFECTIVENESS 

($ PER 

BASELINE 

NA 

376 

TON OF SO 

2 

- — 0.8 OIL512 

1,853 

2,432 

2,160 

REMOVED) | 

0.3 OIL | 

4,666 | 

15,753 | 

6,782 | 

XS •* percent sulfur 

b 

Totai annualized costs for boiler and all applicable control systems 

c 

NA = not applicable 

04/15/87 
TABLE B-2. COST RESULTS FOR A 150 MILLION BTU/HOUR RESIDUAL AND DISTILLATE OIL-FIRED BOILER IN REGION V 

FUEL TYPE 

FOR REGION 

BOILER SIZE 

CAPACITY FACTOR 

STANDARD ANALYZED 

OIL (Residual/Distillate) 

150 Million BTU/HR 

55 Percent 

OIL SELECTED 

NOMINAL 

PERCENT 

NOMINAL SO 

2 

EMISSION 

LIMIT 

COMMENT 

REDUCTION (LBS PER 

REQUIRED 10 BTU) 

AVERAGE SO ANNUAL 

2 

EMISSIONS EMISSIONS ANNUALIZED 

b 

(LBS (TONS COSTS 

OIL PER 

TYPE 10 BTU) 

PER 

YEAR) 

($1000 

PER YEAR) 

BASELINE - least cost option NA 

COMPLIANCE OIL - least cost option NA 

VERY LOU SULFUR OIL 

c 

*0.3 Std - least cost option HA 

PERCENT REDUCTION 

*90X on least cost option 90 

*90X on high sulfur oil 90 

*90X on medium sulfur oil 90 

3.0 

0.8 

0.3 

NA 

HA 

HA 

3.0XS RO 3.243 

0.8XS RO 0.865 

0.3XS DO 0.324 

0.8XS RO 0.066 

3.0XS RO 0.246 

1.6XS RO 0.131 

1,172 

313 

117 

24 

89 

47 

3,236 

3,559 

3,917 

4,09 4 

4,10 3 

4,13 2 

INCREMENTAL COST EFFECTIVENESS 

($ PER 

BASELINE 

NA 

376 

TON OF SO 

2 

—0. 8 OIL1,831 

1,853 

2,432 

2,160 

REMOVED) | 

— 

0.3 

1 

6 

3 

OIL | 

899 | 

599 | 

083 | 

ZS - percent sulfur; RO = residual oil; and DO - distillate oil 

b 

Total annualized costs for boiler and all applicable control systems 

c 

Least cost option using distillate oil 

d 

NA = not applicable 

04/15/87 
P.22 

APPENDIX C 

COSTS FOR THE NATURAL GAS-FIRED MODEL BOILERS 

IN REGIONS 3, 4, 5, AND 8 
P.23 

TABLE C-1. ANNUALIZED COSTS (IN JUNE 1985 DOLLARS) FOR NATURAL 

GAS-FIRED MODEL BOILERS IN REGIONS III, IV, V, AND VIII 

ModelKBoiler Size, Annualized Cost 

10° Btu/hr EPA Region ($l,000)a 

150 

400 

III 

IV 

V 

VIII 

III 

IV 

V 

VIII 

3,293 

3,250 

3,372 

3,293 

8,394 

8,284 

8,604 

8,394 

aNatural gas fuel prices are based on the low oil price scenario and 

carriage/flexible market as cited in Reference 5. 

C-1 
P.24 

APPENDIX D 

ANNUALIZED COSTS FOR BOILERS USING FGD SYSTEMS 

(GENERIC COSTS) AND VERY LOW SULFUR COAL 
TABLE D-1. ANNUALIZED COSTS FOR COAL-FIRED MODEL BOILERS IN 

REGION III UNDER THE PERCENT S02 REDUCTION ALTERNATIVE3 

Model Boiler 

Size, 

10° Btu/hr 

150 

400 

Coal 

Type 

J-Bit 

H-Bit 

G-Bit 

F-Bit 

E-Bit 

D-Bit 

B-Bit 

J-Bit 

H-Bit 

G-Bit 

F-Bit 

E-Bit 

D-Bit 

B-Bit 

Uncontrolled 

SO, Emissions, 

fb/10e Btu 

8.00 

5.54 

4.15 

2.85 

2.10 

1.45 

1.08 

8.00 

5.54 

4.15 

2.85 

2.10 

1.45 

1.08 

Annuali 

DAb 

6,738 

6,777 

6,684 

6,650 

6,730 

6,741 

6,863 

15,636 

15,811 

15,564 

15,468 

15,688 

15,717 

16,043 

zed Costs, 

DSC 

6,641 

6,639 

6,529 

6,474 

6,534 

6,531 

6,638 

15,645 

15,698 

15,408 

15,257 

15,430 

15,424 

15,711 

($1,000) 

NATHd 

6,530 

6,517 

6,376 

6,295 

6,345 

6,332 

6,439 

15,772 

15,768 

15,390 

15,167 

15,310 

15,273 

15,559 

June 1985 

Generic 

6,634f 

6,647n 

6,530? 

6,473n 

6,538 

6,537 

6,651 

15,704f 

15,755fl 

15,477g 

15,318n 

15,499 

15,495 

15,801 

Boiler and continuous emission monitoring system costs are included. 

DA = Dual Alkali; costs include a fabric filter for PM control. 

CDS = Spray Drying; costs include a fabric filter for PM control 

(integral to the FGD system). 

NATH = Sodium Scrubbing; costs include a fabric filter for PM control. 

eGeneric = Average costs of the lowest and highest of the three FGD/PM 

systems. 

f 

Total system annualized costs for a boiler firing high sulfur coal. 

^Total system annualized costs for a boiler firing medium sulfur coal. 

Total system annualized costs for the lowest cost option. 

D-1 
P.26 

TABLE D-2. ANNUALIZED COSTS FOR COAL-FIRED BOILERS IN 

REGION IV UNDER THE PERCENT S02 REDUCTION ALTERNATIVE3 

Model Boiler 

Size, 

10° Btu/hr 

150 

400 

Coal 

Type 

J-Bit 

H-Bit 

G-Bit 

F-Bit 

E-Bit 

D-Bit 

B-Bit 

J-Bit 

H-Bit 

G-Bit 

F-Bit 

E-Bit 

D-Bit 

B-Bit 

Uncontrolled 

SO, Emissions, 

fb/10° Btu 

8.00 

5.54 

4.15 

2.85 

2.10 

1.45 

1.08 

8.00 

5.54 

4.15 

2.85 

2.10 

1.45 

1.08 

Annuali 

DAb 

6,962 

6,878 

6,867 

6,891 

6,867 

6,825 

6,873 

16,218 

16,076 

16,047 

16,114 

16,052 

15,939 

16,065 

zed Costs, 

DSC 

6,856 

6,737 

6,703 

6,703 

6,665 

6,611 

6,600 

16,198 

15,950 

15,866 

15,871 

15,777 

15,637 

15,605 

($1,000) 

NATHd 

6,754 

6,619 

6,558 

6,535 

6,483 

6,415 

6,449 

16,354 

16,032 

15,872 

15,813 

15,675 

15,494 

15,582 

June 1985 

Generic 

6,858f 

6,749 

6,713g 

6,713 

6,738. 

6,620" 

6,661 

16,276f 

16,013o 

15,957g 

15,964 

15,864. 

15,717" 

15,824 

Boiler and continuous emission monitoring system costs are included. 

DA = Dual Alkali; costs include a fabric filter for PM control. 

CDS = Spray Drying; costs include a fabric filter for PM control 

(integral to the FGD system). 

NATH = Sodium Scrubbing; costs include a fabric filter for PM control. 

eGeneric = Average costs of the lowest and highest of the three FGD/PM 

systems. 

f 

Total system annualized costs for a boiler firing high sulfur coal. 

9Total system annualized costs for a boiler firing medium sulfur coal. 

Total system annualized costs for the lowest cost option. 

D-2 
P.27 

. * 

TABLE D-3. ANNUALIZED COSTS FOR COAL-FIRED BOILERS IN 

REGION V UNDER THE PERCENT S02 REDUCTION ALTERNATIVE3 

Model Boiler 

Size, 

10° Btu/hr 

150 

400 

Coal 

Type 

J-Bit 

H-Bit 

G-Bit 

F-Bit 

E-Bit 

D-Bit 

B-Bit 

E-Sub 

D-Sub 

B-Sub 

J-Bit 

H-Bit 

G-Bit 

F-Bit 

E-Bit 

D-Bit 

B-Bit 

E-Sub 

D-Sub 

B-Sub 

Uncontrolled 

SO, Emissions, 

Tb/105 Btu 

8.00 

5.54 

4.15 

2.85 

2.10 

1.45 

1.08 

2.10 

1.45 

0.96 

8.00 

5.54 

4.15 

2.85 

2.10 

1.45 

1.08 

2.10 

1.45 

0.96 

Annuali 

DAb 

6,760 

6,806 

6,790 

6,800 

6,862 

6,879 

6,942 

6,992 

6,928 

6,985 

15,685 

15,881 

15,843 

15,861 

16,028 

16,076 

16,249 

16,101 

15,928 

16,082 

zed Costs, 

DSC 

6,586 

6,664 

6,627 

6,613 

6,657 

6,658 

6,710 

6,804 

6,729 

6,727 

15,680 

15,753 

15,664 

15,478 

15,739 

15,750 

15,894 

15,791 

15,465 

15,713 

($1,000) 

NATHd 

6,551 

6,547 

6,482 

6,444 

6,478 

6,469 

6,519 

6,673 

6,583 

6,620 

15,821 

15,838 

15,669 

15,560 

15,651 

15,632 

15,766 

15,811 

15,571 

15,672 

June 1985 

Generic 

6,656f 

6,677a 

6,636? 

6,622" 

6,670 

6,674 

6,731 

6,833 

6,746 

6,803 

15,751f 

15,817n 

15,754? 

15,670" 

15,840 

15,854 

16,008 

15,946 

15,697 

15,877 

Boiler and continuous emission monitoring system costs are included. 

DA = Dual Alkali; costs include a fabric filter for PM control. 

CDS = Spray Drying; costs include a fabric filter for PM control 

(integral to the FGD system). 

NATH = Sodium Scrubbing; costs include a fabric filter PM control. 

eGeneric = Average costs of the lowest and highest of the three FGD/PM 

systems. 

f 

Total system annualized costs for a boiler firing high sulfur coal. 

gTotal system annualized costs for a boiler firing medium sulfur coal. 

Total system annualized costs for the lowest cost option. 

D-3 
P.28 

TABLE D-4. ANNUALIZED COSTS FOR COAL-FIRED BOILERS IN 

REGION VIII UNDER THE PERCENT S02 REDUCTION ALTERNATIVE3 

Model Boiler 

Size, 

10° Btu/hr 

150 

400 

Coal 

Type 

E-Bit 

D-Bit 

B-Bit 

E-Sub 

D-Sub 

B-Sub 

E-Bit 

D-Bit 

B-Bit 

E-Sub 

D-Sub 

B-Sub 

Uncontrolled 

SO, Emissions, 

fb/10° Btu 

2.10 

1.45 

1.08 

2.10 

1.45 

0.96 

2.10 

1.45 

1.08 

2.10 

1.45 

0.96 

Annuali 

DAb 

6,342 

6,293 

6,286 

6,049 

5,999 

6,006 

14,624 

14,493 

14,474 

13,555 

13,421 

13,458 

zed Costs, 

DSC 

6,140 

6,079 

6,064 

5,884 

5,822 

5,819 

14,341 

14,183 

14,144 

13,308 

13,147 

13,166 

($1,000) 

NATHd 

6,958 

5,884 

5,862 

5,729 

5,653 

5,642 

14,247 

14,049 

13,992 

13,265 

13,062 

13,049 

June 1985 

Generic 

6,150 

6,089 

6,074f 

5,889T 

5,826fl . 

5,824g'' 

14,436 

14,271 

14,233-

13,410.1 

13,242" 

13,254g 

Boiler and continuous emission monitoring system costs are included. 

DA • Dual Alkali; costs include a fabric filter for PM control. 

CDS = Spray Drying; costs include a fabric filter for PM control 

(integral to the FGD system). 

NATH = Sodium Scrubbing; costs include a fabric filter for PM control. 

eGeneric = Average costs of the lowest and highest of the three FGD/PM 

systems. 

f 

Total system annualized costs for a boiler firing high sulfur coal. 

gTotal system annualized costs for a boiler firing medium sulfur coal. 

Total system annualized costs for the lowest cost option. 

D-4 
P.29 

TABLE D-5. ANNUALIZED COSTS FOR RESIDUAL OIL-FIRED MODEL BOILERS 

RATED AT 150 MILLION BTU/HOUR HEAT INPUT IN REGION V 

UNDER THE PERCENT S02 REDUCTION ALTERNATIVE3 

Oil Type 

Nominal S02 

Emissions, 

lb/10° Btu 

Annualized Costs, ($1,000) 

June 1985 

DAC 

4,167 

4,222 

4,264 

4,333 

NATHd 

4,038 

4,041 

3,924 

3,975 

Generice 

4,103f 

4.1329 

4,094h 

4,154 

3 Percent Sulfur RO 

1.6 Percent Sulfur RO 

0.8 Percent Sulfur RO 

0.3 Percent Sulfur RO 

3.0 

1.6 

0.8 

0.3 

Boiler and continuous emission monitoring system costs are included. 

DA » Dual Alkali; costs include a fabric filter for PM control. 

CDS • Spray Drying; costs include a fabric filter for PM control 

(integral to the FGD system). 

NATH = Sodium Scrubbing; costs include a fabric filter for PM control. 

eGeneric = Average costs of the lowest and highest of the three FGD/PM 

systems. 

f 

Total system annualized costs for a boiler firing high sulfur oil. 

gTotal system annualized costs for a boiler firing medium sulfur oil. 

Total system annualized costs for the lowest cost option. 

D-5 
TABLE D-6. ANNUALIZED COSTS OF THE VERY LOW SULFUR COAL-FIRED MODEL BOILERS 

IN REGIONS III, IV, V AND VIII 

Average Uncontrolled 

Model Boiler Size, SO? Emissions, 

10° Btu/hr Coal Type tb/10 Btu 

Annualized Costs, ($1,000) June 1985 

Region III 

6,068 

6,714 

_a 

-

14,932 

16,675 

-

— 

Region IV 

6,147 

6,698 

-

-

15,143 

16,630 

-

— 

Region V 

6,163 

6,329 

6,157 

6,267 

15,179 

15,625 

14,757 

15,054 

Region VIII 

5,348 

5,451 

5,153 

5,263 

12,977 

13,253 

12,064 

12,361 

o 

I 

Oi 

150 

400 

A-B1t 

AA-B1t 

A-Sub 

AA-Sub 

A-B1t 

AA-B1t 

A-Sub 

AA-Sub 

0.82 

0.62 

0.65 

0.45 

0.82 

0.62 

0.65 

0.45 

"—" denotes coal type not available in this region. 
P.31 

APPENDIX E 

ASSUMPTIONS CONCERNING COAL SULFUR VARIABILITY 
P.32 

Table E-1 summarizes the variability statistics and average S02 

emission levels for the various coals used in this model boiler cost 

analysis to meet selected S02 emission limits. 

The 24-hour standard deviation values in the table for low sulfur 

bituminous (B-Bit) and subbituminous (B-Sub) coals were based on the CEM 

data for low sulfur coal-fired boilers presented in Reference 10. The use 

of 0.10 as the 24-hour standard deviation for B-Bit coal is a deviation from 

previous studies which assumed a value of 0.20 for both bituminous and 

subbituminous coals. The new lower value for bituminous coal is based on 

the S0« emissions variability data in Reference 10. The B-Bit coal 

represents a washed and/or blended coal which the Reference 10 data show 

typically has a lower 24-hour standard deviation of near 0.10. The B-Sub 

coal, on the other hand, represents an unwashed subbituminous coal delivered 

directly from the mine which is characterized by a higher 24-hour standard 

deviation of near 0.20, according to the Reference 10 data. 

The 24-hour standard deviation for very low sulfur bituminous coals 

(A-Bit and AA-Bit) of 0.064 was calculated by dropping the highest 10 

percent of the S02 emission values in the Reference 10 data set for washed 

bituminous coal fired in Boiler I. This procedure mimics the operations 

anticipated at an industrial boiler site where the operator must comply with 

a 0.9 or 0.7 lb S02/million Btu standard. In this case, the operator will 

likely sample the coal upon arrival and reject coal portions with high 

sulfur contents. The sampling and rejection could also be done at the mine 

before shipment. This procedure is consistent with the cost analysis in 

Reference 3 which states that additional sampling and handling will be 

required for these coals. 

Reference 3 indicated that additional sampling and handling would not 

be required for very low sulfur subbituminous coals (A-Sub and AA-Sub) fired 

to meet the 0.9 and 0.7 lb S02 emission limits, respectively. Hence the 

24-hour standard deviation value assumed for these coals was the same as 

that discussed above for the B-Sub coal (i.e., 0.20). 

The 24-hour autocorrelation values shown in Table E-1 were also based 

on the emissions data for low sulfur coals in Reference 10. These data 

E-1 
TABLE E-1. S02 EMISSIONS VARIABILITY AMONG MODEL BOILER COAL TYPES3 

E-2 

SO? Emission 

zL1mit 

(lb/10° Btu) 

2.5 

1.2 

0.9 

0.7 

2.5 

1.2 

0.9 

0.7 

Coal Type 

E-B1tum1nous 

B-B1tum1nous 

A-B11urn1 nous 

AA-B1tuminous 

D-Subb1tum1nous 

B-Subb1tum1nous 

A-Subb1tum1nous 

AA-Subbitum1nous 

S02 Emiss 

24-Hour 

Standard 

Deviation 

NDb 

0.10 

0.064 

0.064 

ND 

0.20 

0.20 

0.20 

Ions Statistics 

24-Hour 

Autocorrelation 

ND 

0.7 

0.7 

0.7 

ND 

0.7 

0.7 

0.7 

Average S0~ 

Emission Level 

(lb/10° Btu) 

2.10 

1.08 

0.82 

0.62 

1.44 

0.96 

0.65 

0.45 

24-Hour 

Relative Standard 

Deviation 

ND 

9.3 

7.8 

10.3 

ND 

20.8 

30.8 

44.4 

See Reference 10 for definition of terms. 

'ND = No data. 
P.34 

indicate that autocorrelation values are not a function of coal type, sulfur 

content, or standard deviation. 

The statistical procedures presented in Reference 12 were used to 

calculate the average S02 emission levels required to comply with the 

selected emission limit, as shown in Table E-1, using the standard deviation 

and autocorrelation values for each coal. The calculations assumed a 

one-in-10 years exceedance frequency, a 30-day rolling average period, and a 

normal distribution of the 30-day rolling averages. 

As an example of the calculational procedures used, consider the case 

of a B-Bit coal (with a 24-hour S02 emission standard deviation of 0.10 and 

24-hour S0? emissions autocorrelation of 0.7) which is fired to meet an 

emission limit of 1.2 lb S02/million Btu subject to the assumptions 

discussed above. Since only the standard deviation and autocorrelation of 

the coal are known, the procedure is an iterative one. An initial estimate 

of the relative standard deviation (RSD) of a coal used to meet this limit 

could be 10 percent. Table A-8 of Reference 12 indicates that a coal with 

an average S02 emission level of 1.07 or less would be required to meet the 

1.2 lb S02/million Btu limit given these variability characteristics. This 

corresponds to a variability allowance, C, of 0.13 lb S02/million Btu (i.e., 

1.20 - 1.07 - 0.13). However, the standard deviation for a coal with an RSD 

of 10 percent and average emission limit of 1.07 lb/million Btu is 0.107 

(i.e., 1.07x0.10 = 0.107). This is greater than the 0.10 standard deviation 

characteristic of the B-Bit coal. While it is possible to iterate on the 

values in Table A-8 alone (this does require interpolation of table values) 

to arrive at the final solution, a useful relationship discussed 1n 

Appendix B to that report provides a deterministic approach. The equations 

in Appendix B show that the allowance for variability, C, is directly 

proportional to the standard deviation, SD, if all other things are equal. 

Thus, 

Cj = C, |^- J (1) 

E-3 
P.35 

t 

Substituting the appropriate values from above yields 

/o.ioo\ 

C

l

 = °' 1 3

 \0A07) " °' 1 2 (2) 

and 

Emissions average = 1.20 - 0.12 = 1.08 (3) 

Therefore, given a 24-hour S02 emissions standard deviation of 0.10 and 

autocorrelation of 0.7, a B-Bit coal with an average S02 emission level of 

1.08 lb/million Btu, or less, could be fired to meet a 1.2 lb S02/mill1on 

Btu emission limit. 

These same relationships were used to calculate the remainder of the 

average S02 emission levels in Table E-1. The final column in this table is 

simply the 24-hour standard deviation divided by the calculated average S02 

emission level. 

E-4 
P.36 

APPENDIX F 

METHODOLOGY AND ASSUMPTIONS USED 

FOR MODEL BOILER COST ANALYSES 
P.37 

The methodology and assumptions used in this analysis to calculate 

costs for model boilers and associated air pollution control equipment are 

the same as those used in prior model boiler cost analyses (as described in 

References 1, 2, 7, and 8) except where noted in this appendix. These 

exceptions were: modifications to the maximum fuel flexibility option of 

IBCOST when firing J-Bit coal; the use of natural gas during FGD 

malfunction; excess air levels for NO control on coal-fired boilers; and 

FGD controls on boilers firing higher sulfur oils. The IBCOST computer 

program used to calculate model boiler costs was modified to reflect these 

changes. 

Maximum Fuel Flexibility When Firing J-Bit Coal 

Capital costs were estimated in this analysis using the maximum fuel 

2 8 flexibility option of IBCOST as was done in previous analyses. ' This 

option, if chosen, designs the boiler and FGD system with the flexibility to 

fire high sulfur fuels. For coal-fired boilers, the capital costs for the 

boiler and FGD system are based on the flow rate and S02 loading of flue gas 

corresponding to the generic high sufur coal. For boilers designed to fire 

bituminous coals, the boiler and FGD system are designed to fire a coal with 

a heating value of 11,500 Btu/lb and a sulfur content of 3.19 weight percent 

(5.54 lb S02/10 Btu). For boilers designed to fire subbituminous coals, 

the boiler and FGD system are designed to fire a coal with a heating value 

of 8,800 Btu/lb and a sulfur content of 0.93 weight percent (2.1 lb S02/106 

Btu). 

For boilers firing J-Bit coal, this option was modified to calculate 

the capital costs of the FGD system based on the sulfur content of J-Bit 

coal (4.67 percent) and the coal heating value of 11,500 Btu/lb. Operating 

and maintenance costs which depend on fuel properties were based on a 

heating value and sulfur content of the actual fuel type chosen. Under the 

percent reduction alternative, the FGD system is designed to achieve 90 

percent S02 removal. 

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P.38 

Natural Gas Use During FGD Malfunction 

FGD control costs included the costs associated with firing natural gas 

during FGD malfunction. The previous analysis for coal-fired boilers 

included the fuel costs associated with firing natural gas but omitted the 

costs for natural gas-burning equipment capable of firing at 100 percent 

e 

7 

2 

load. The cost results presented in this memo include the costs for the 

natural gas burning equipment as part of the total FGD malfunction costs, 

The equipment costs for firing natural gas at 100 percent load were already 

incorporated into the oil-fired boiler costs, since the boiler was designed 

with the capability to fire both fuels. As discussed in Section 2.0, the 

natural gas price used to calculate the fuel costs of firing natural gas 

during periods of FGD malfunction is based on the low oil price scenario and 

the non-carriage/rigid market as cited in Reference 5. 

Excess Air Levels for NO Control with Coal-Fired Boilers 

For coal-fired boilers using low excess air (LEA) to control NO 

emissions, uncontrolled and controlled excess air levels were 48 and 32 

percent, respectively. These levels deviated slightly from those used in 

the 1984 model boiler analysis (50 percent for uncontrolled and 35 percent 

for controlled excess air levels). The cost impacts of these changes are 

minor. 

FGD Control for Boilers Firino Higher Sulfur Oils 

Although an FGD system is capable of reducing PM levels to less than 

0.1 lb/10 Btu from a boiler firing high sulfur oil, the previous analysis 

did not consider the costs required for handling the high levels of 

particulates collected by an FGD system. IBCOST does not currently 

include such an algorithm for sodium scrubbing (but does include one for 

dual alkali). The approach used in this memo to estimate the costs for a 

combined PM/S02 sodium scrubber on a boiler firing medium or high sulfur 

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P.39 

_m_t. ••* ' 

oils (i.e., oils containing 1.6 weight percent sulfur or greater) was to 

include the costs of a separate venturi scrubber with that of a sodium 

scrubber. This approach provided a conservative estimate of the costs of a 

combined PM/S02 sodium scrubber applied to a boiler firing higher sulfur 

oils. The generic costs of an FGD system for a boiler firing a higher 

sulfur oil was based on the average costs of the combined PM/S02 dual alkali 

scrubber and the estimated combined PM/S02 sodium scrubber. 

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