p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

312) IV-B-16 

Docket Number: 

A-83-27 

Printed 11/12/200811:12:59 AM Sheet 312 of 325 
P.2 

' % f 

* RADIAN 

CORPORATIO N 

A-83-27 

IV-B-16 

MEMORANDUM 

DATE: April 15, 1987 

TO: Fred Porter and Walt Stevenson, EPA/SDB 

FROM: Edward Aul and John Martinez, Radian Corporation 

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

S 02 Emission Control of 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 the cost and 

cost effectiveness of reducing S02 emissions from mixed fuel-fired steam 

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

the report An Analvsis of the Costs and Cost Effectiveness of SO,. Control 

4

 c 

for Mixed Fuel-Fired Steam Generating Units (June 1986). 

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 oil price scenarios: a high oil price 

scenario and a low oil price scenario. To maintain consistency with the 

cost analysis described in Reference 8, the high oil price scenario was 

utilized in this assessment of new fuel price impacts together with 

non-carriage natural gas prices and a zero cost for nonfossil fuel. 

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 mixed fuel-fired systems. These modifications are 

discussed in full in Appendix A. These modifications have a negligible 

effect, however, on the assessment of cost effectiveness changes caused by 

the new fuel prices. The modifications have been incorporated into the 

revised cost algorithms used for this analysis and presented in Appendix B. 

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

j f 

2.0 RESULTS OF ANALYSES 

The results of the analyses of new fuel price impacts are summarized in 

Table 1 thru 4. 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 almost all costs have increased somewhat. 

The reasons for this increase are the changes made to the capital and 

non-fuel operating and maintenance costs discussed in Appendix A and the 

updating of the time basis of the cost estimates. The effect of these 

factors has been sufficient to overcome the decrease in levelized fuel 

prices (for the fuel types specified) between the 1984 and 1986 projections. 

The exception to this rule occurs with the boilers in Region I which fire 

80 percent oil/20 percent nonfossil fuel. Because of the high fraction of 

fossil fuel combusted in these boilers and the sizeable decrease in oil 

prices between the two projection sets, the total annualized costs for these 

boilers are slightly lower in the revised analysis than in the previous 

analysis. 

Two model boilers have been selected as examples to illustrate the 

impacts of new fuel prices on the cost and cost effectiveness of S02 

emission control for mixed fuel-fired boilers. The first is a nonfossil/ 

coal-fired unit operating in Region X; the second is a nonfossil/oil-fired 

unit operating in Region I. Both model boilers are 44 MW (150 million 

Btu/hr) units and fire an 80 percent nonfossil/20 percent fossil fuel 

mixture. The costs, emissions, and cost effectiveness of a low sulfur fuel 

standard and a percent reduction standard are discussed below for each of 

these units. The impacts of revised fuel price projections on these values 

are highlighted. 

2.1 LOW SULFUR FUEL STANDARDS 

The incremental costs of standards based on low sulfur fuels relative 

to the regulatory baseline have declined slightly for nonfossil/oil-fired 

boilers but remained nearly constant for nonfossil/coal-fired units. The 
TABLE 1. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR COAL/NONFOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS IN REGION I a , b 

Fossil/Nonfossil 

Fuel Mixture 20X COAL/BOX NONFOSSIL 50* COAL/SOS NONFOSSIL SOX COAL/20X NONFOSSIL 

Cost 

Effectiveness 

($/ton) 

Cost 

Effectiveness 

(S/ton) 

Coal 

Annual 

Costs 

Annual 

Eaissions . Incre- Coal 

Annual 

Costs 

Annual 

Emissions Incre- Coal 

Annual 

Costs 

Annual 

Emissions 

Cost 

Effectiveness 

(J/ton) 

IncreType (Sl,000/yr) (tons/yr) Average0

 mental6 Type (Jl,000/yr) (tons/yr) Average0 mental6 Type ($1.000/yr> (tons/yr) Average0 mental6 

Q . ISO Million Btu/hr 

Regulatory Basel 1nec'°- F-BIt 

(2.S lb/mill Ion Btu) 

Low Sulfur Coal B-BIt 

(1.2 lb/all 1-ton Btu) 

Percent Reduction F-BIt 

(FGD-90S Reduction)1 

tt' 4QQ Mil Han Btu/hr 

Regulatory Basel1nec*- F-BIt 

(1.2 lb/mil lion Btu) 

4,060 

4.130 

4.400 

225 

75 

18 

-

467 

1,643 

Low Sulfur Coal 

(1.2 lb/al l lion Btu) 

Percent Reduction 

(FGD-90S Reduction)' 

Q - 800 Million Btu/hr 

(1.2 lb/mil Hon Btu) 

Loa Sulfur Coal 

(1.2 lb/till lion Btu) 

Percent Reduction 

(FGD-9M Reduction)' 

B-BIt 

8.840 

9.010 

F-BIt 9,440 

599 

200 

48 

444 

1,088 

F-BIt 4.910 

B-BIt 5.080 

4,737 F-BIt 5,360 

E-BIt 11.190 

B-BIt 11.460 

2.803 F-BIt 11,880 

562 

187 

45 

-

454 

871 

F-BIt 

B-BIt 

2,741 F-BIt 

5,750 

6.010 

6.270 

899 

300 

72 

-

434 

629 1.889 

1.104 

499 

120 

-

480 

701 

B-BIt 

B-BIt 

1,054 F-BIt 

13.910 

13,910 

14.250 

799 

799 

192 

-

0 

560 560 

F-BIt 

B-BIt 

F-BIt 

14,960 

15.310 

16.120 

1.198 

399 

96 

-

443 

1.053 

E-BIt 

B-BIt 

2.673 F-BIt 

19,540 

20.120 

20,930 

2.208 

999 

240 

-

480 

706 

B-BIt 

B-BIt 

1,067 F-BIt 

24.880 

24,880 

25.590 

1.598 

1.598 

383 

-

0 

584 584 

•Metric units can be attained by the following converslonsx $/Mg - $/ton • 1.1023; Mg/yr » tons/yr • 0.9075; MW - million Btu/hr - 0.293; 

ng/J • lb/million Btu • 430.278. 

bBased on a capacity utilization factor of 0.6. 

cAt the regulatory baseline, eeission credits are provided for the heat input of the nonfossil fuel. No emission credits are provided for nonfossil 

heat Input for other regulatory alternatives. 

°Coapared to regulatory baseline. 

6Coopared to next less stringent alternative. 

f

The annual missions are based on a 92 percent removal efficiency; the additional 2 percent accounts for fuel and FGO variability. 

SLoaest-cost coal available which satisfies the baseline emission requirement. 
TABLE 2. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR COAL/NONFOSSIL MIXED FUEL-FIREO STEAM GENERATING UNITS IN REGION IVa

'

b 

Fossil/Nonfossil 

Fuel Mixture 20* COAL/80X NONFOSSIL 50X COAL/5OS NONFOSSIL SOX C0AL/20X NONFOSSIL 

Cost 

Effectiveness 

(S/ton) 

Cost 

Effectiveness 

(S/ton) 

Annual Annual 

Coal Costs Emissions0 

Annual Annual 

Incre- Coal Costs Eaissions0 

Annual 

Costs 

Cost 

Effectiveness 

(S/ton) 

Annual 

Emissions0 

.- . Incre- Coal Costs Emissions'" IncreType (Sl.OOO/yr) (tons/yr) Average0

 mental* Type (Sl.OOO/yr) (tons/yr) Average0 mental6 Type (Sl.OOO/yr) (tons/yr) Average0 mental6 

fl • ISO Million Btu/hr 

Regulatory Baseline H-BIt 3.990 

(2.5 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/mil lion Btu) 

Percent Reduction . 

(FGD-90X Reduction)' 

n • aon Million Btu/hr 

(1.2 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction . 

(FGO-90X Reduction)' 

n • BOO Million Btu/hr 

(1.2 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/mil Hon Btu) 

Percent Reduction 

(FGD-90X Reduction)' 

B-BIt 4.040 

H-BIt 4,440 

H-BIt 

B-BIt 

H-BIt 

8,630 

8.760 

9.300 

1,165 

200 

93 

-

135 

625 

437 - - G-BIt 4,750 

75 138 - B-BIt 4.840 

35 1.119 10,000 H-BIt 5.310 

D-BIt 10.750 

B-BIt 10,840 

5,047 H-BIt 11,640 

818 

187 

87 

-

143 

766 

F-Bit 

B-BIt 

4,705 H-BIt 

5.570 

5.630 

6.170 

899 

300 

140 

-

ICO 

791 

762 

499 

233 

-

342 

1.682 

B-BIt 

B-BIt 

3.003 H-BIt 

12,860 

12,860 

13,960 

799 

799 

373 

-

0 

2.582 

H-BIt 

B-BIt 

H-BIt 

14.530 

14.810 

15.830 

2.329 

399 

186 

-

145 

607 

D-Bit 

B-BIt 

4.769 H-BIt 

18.660 

18,850 

20,400 

1,524 

999 

466 

-

361 

1.644 

B-BIt 

B-BIt 

2,909 H-BIt 

22,840 

22.840 

24.950 

1.596 

1.598 

1*-

-

0 

2.475 

•Metric units can be attained by the following converslonsi S/Mg - S/ton • 1.1023; Mg/yr - tons/yr • 0.9075; MX - million Btu/hr • 0.293; 

ng/J - lb/million Btu • 430.278. 

bBased on a capacity utilization factor of 0.6. 

°At the regulatory baseline, emission credits are provided for the heat Input of the nonfossil fuel. No emission credits are provided for nonfossil 

heat input for other regulatory alternatives. 

•^Compared to regulatory baseline. 

"Compared to next less stringent alternative. 

f

The annual emissions are based on a 92 percent removal efficiency; the additional 2 percent accounts for fuel and FGD variability. 

3.379 

2.582 

2.475 
TABLE 3. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR COAL/NONFOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS IN REGION Xa , t 

Fossll/Nonfossll 

Fuel Mixture 20X COAL/80X NONFOSSIL SO* COAL/50* NONFOSSIL SOX COAL/20X NONFOSSIL 

Cost 

Effectiveness 

(S/ton) 

Cost 

Effectiveness 

(S/ton) 

Coal 

Annual Annual 

Costs Emissions0 Incre- Coal 

Annual Annual . -

Costs Emissions0 Incre- Coal 

Annual 

Costs 

Cost 

Effectiveness 

(S/ton) 

Annual 

Emissions0 IncreType (Sl.OOO/yr) (tons/yr) Average0 mental6 Type (Sl.OOO/yr) (tons/yr) Average0 mental6 Type (Sl.OOO/yr) (tons/yr) Average0 mental e 

cn 

n . ISO Million Btu/hr 

Regulatory Baseline" E-Sub 4.000 

(2.5 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction 

(FGD-90S Reduction)' 

Q - 400 Million Btu/hr 

Regulatory Baseline" 

(1.2 lb/all lion Btu) 

Low Sulfur Coal 

(1.2 lb/ail Hon Btu) 

Percent Reduction . 

B-Sub 

E-Sub 

E-Sub 

B-Sub 

E-Sub 

4.090 

4.370 

8,560 

8,800 

9.180 

75 

13 

442 

200 

35 

(FGD-90X Reduction)' 

O - 800 Minion Btu/hr 

Regulatory Basel1ne9 E-Sub 14.280 

(1.2 lb/ailllon Btu) 

Low Sulfur Coal B-Sub 14.780 

(1.2 lb/ailllon Btu) 

Percent Reduction 

(FSO-9QX Reduction)1 

E-Sub 15.460 

166 - - E-Sub 4.520 

993 - B-Sub 4,750 

2.429 4.542 E-Sub 4.930 

E-Sub 10.190 

992 - B-Sub 10,780 

1,530 2.303 E-Sub 10,950 

883 - - E-Sub 17,350 

399 1,033 - B-Sub 18,540 

71 1.453 2.073 E-Sub 18.830 

414 

187 

33 

-

1.015 

1.077 

E-Sub 

B-Sub 

1,168 E-Sub 

5.120 

5,480 

5,580 

662 

300 

53 

-

993 

755 

,104 

499 

88 

-

976 

748 

-

-

414 

E-Sub" 

E-Subh 

E-Sub 

12,610 

12.610 

12,610 

141 

141 

141 

-

0 

0 

.208 

999 

177 

-

984 

729 

E-Subn 

E-Subh 

353 E-Sub 

22.030 

22,030 

22,030 

283 

283 

283 

-

0 

0 

•Metric units can be attained by the following conversions* S/Mg - S/ton • 1.1023; Mg/yr - tons/yr * 0.9075; MW - million Btu/hr » 0.293; 

ng/J - lb/ailllon Btu • 430.278. 

bBased on a capacity utilization factor of 0.6. 

°At the regulatory baseline, emission credits are provided for the heat Input of the nonfossil fuel. No emission credits are provided for 

nonfossil heat Input for other regulatory alternatives. 

''Compared to regulatory baseline. 

6Compared to next less stringent alternative. 

f

The annual emissions are based on a 92 percent removal efficienty; the additional 2 percent accounts for fuel and FGO variability. 

•^Lowest-cost coal available which satisfies the baseline emission requirement. 

"The lowest cost control option to achieve this emission limit Is to fir e Type E-Sub coal and Install an FGD system to achieve a percent 

reduction. 

405 
TABLE 4. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR OIL/NONFOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS IN REGION I a.b 

Fuel Mixture 20« OIL/BO* NONFOSSIL 

Ol 

Cost 

Effectiveness 

(S/ton) 

SOX OIL/SOI NONFOSSIL 80* QIL/20X NONFOSSIL 

Cost 

Effectiveness 

(S/ton) 

Annual Annual _ 

Oil Costs Emissions0 

Annual Annual 

Cost 

Effectiveness 

(S/ton) 

Annual Annual 

. Incre- Oil Costs Emissions0 Incre- Oil Costs Emissions1" IncreType9

 (Sl.OOO/yr) (tons/yr) Average" mental6 Type9 (Sl.OOO/yr)(tons/yr) Average" mental6 Type9 (Jl,000/yr) (tons/yr) Average" mental* 

Q - ISO Million Btu/hr 

Regulatory Baseline 

(3.0 lb/million Btu) 

Lew Sulfur Oil 

(0.8 lb/million Btu) 

Percent Reduction . 

(FGD-90X Reduction)' 

Q = 400 Hill lon Btu/hr 

Regulatory Baseline 

(0.8 lb/million Btu) 

Lew Sulfur Oil 

(0.8 lb/roll Hon Btu) 

Percent Reduction 

(FGD-90X Reduction)' 

Q •* BOO Million Btu/hr 

3.0 

0.8 

3.0 

3.0 

0.8 

3.0 

4,035 

4,120 

4,421 

8.942 

9,167 

9.634 

237 

63 

19 

631 

168 

SO 

3.0 5.176 

490 - 0.8 5,388 

1,774 6,818 3.0 5,647 

1.6 12.109 

486 - 0.8 12,461 

SO 1.193 3.967 3.0 12.810 

591 

1S8 489 

3.0 6,296 

0.8 6,634 

47 866 2,347 3.0 6,848 

841 

420 837 

946 

252 487 

76 634 1.212 

0.8 

0.8 

3.0 

15,707 

15,707 

15.934 

673 

673 

202 

-

0 

482 

Regu1atory Basel 1ne 

(0.8 lb/million Btu) 

Low Sulfur Oil 

(0.8 lb/million Btu) 

Percent Reduction 

(FGD-90S Reduction)' 

3.0 15.370 1.261 

0.8 15,819 336 485 

1.6 21.599 1.682 

O.B 22.280 841 810 

0.8 28.653 1,346 

0.8 28.653 1,346 

3.0 16.712 101 1.156 3.792 3.0 22,937 252 936 1.116 3.0 29.073 404 446 

482 

446 

-'Metric units can ba attained by the following conversions: J/Mg - $/ton * 1.1023; Mg/yr = tons/yr » 0.9075; MW = million Btu/hr * 0.293; 

ng/J =* lb/nllllon Btu » 430.278. 

Based on a capacity utilization factor of 0.6. 

°At the regulatory baseline, emission credits are provided for the heat Input of the nonfossil fuel. No emission credits are provided for 

nonfossil heat input for other regulatory alternatives. 

Compared to regulatory baseline. 

"Compared to next less stringent alternative. 

f

The annual emissions are based on a 92 percent removal efficiency; the additional 2 percent accounts for fuel and FGO variability. 

9

011 sulfur content in lb SO-/m1111on Btu. 
P.8 

reason for this change for nonfossil/oil-fired boilers is that the sulfur 

premiums for low sulfur oils in Region I have declined between the 1984 and 

1986 projections. The difference in annualized costs between the baseline 

and a low sulfur oil standard is merely the sulfur premium (i.e., the 

difference in price between low sulfur and high sulfur oils). Since the oil 

sulfur premiums have declined, the incremental costs of low sulfur oil 

standards have also declined. Conversely, coal sulfur premiums in Region X 

have remained essentially unchanged between the two projections. As a 

result, the incremental costs of low sulfur coal standards have remained 

constant. 

These incremental cost effects directly influence the cost 

effectiveness of emission control for standards based on low sulfur fuels. 

The cost effectiveness of standards based on firing low sulfur oil for mixed 

fuel-fired boilers relative to the baseline is near $600/Mg ($500/ton) using 

the new fuel price projections; in the previous analysis, the cost effectiveness was near $700/Mg ($600/ton). The cost effectiveness of standards based 

on firing low sulfur coal for mixed fuel-fired boilers relative to the 

baseline remained unchanged at near $1,100/Mg ($l,000/ton). 

2.2 PERCENT REDUCTION STANDARDS 

As with low sulfur fuel standards, the incremental costs associated 

with standards requiring a percent reduction have changed in proportion to 

changes in fuel sulfur premiums. As discussed above, oil sulfur premiums 

for low sulfur oils in Region I have declined between the 1984 and 1986 

projections. Thus the fuel cost savings resulting from firing higher sulfur 

oils and scrubbing have decreased. These fuel savings now offset less of 

the costs associated with the scrubber system. In addition the non-fuel 

annualized costs of scrubbing have also increased between the present and 

prior analysis due to the factors discussed in Appendix A. 

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

standards requiring percent reduction for nonfossil/oil-fired boilers has 

increased. Using the new fuel prices, the average cost effectiveness of 

standards requiring a percent reduction in emissions over the baseline for 

nonfossil/oil-fired boilers is near $2,000/Mg ($l,800/ton); the cost 
P.9 

effectiveness was near $1,700 Mg ($l,500/ton) in the previous analysis. The 

incremental cost effectiveness of percent reduction emission control over 

use of low sulfur fuel for nonfossil/oil-fired boilers is near $7,500/Mg 

($6,800/ton) under new fuel prices; in the previous analysis this value was 

near $5,600/Mg ($5,000/ton). 

Since Region X coal sulfur premiums have not changed between the 1984 

and 1986 projections, the cost effectiveness of standards requiring percent 

reduction for nonfossil/coal-fired boilers has increased only slightly due 

to the factors discussed in Appendix A. For these units, the new fuel 

prices increase the average cost effectiveness over the baseline to 

approximately $2,600/Mg ($2,400/ton) compared to a value near $2,600/Mg 

($2,300/ton) in the previous analysis. The incremental cost effectiveness 

of standards requiring a percent reduction in S02 emissions for nonfossil/ 

coal-fired boilers over standards based on low sulfur coal is near $5,000/Mg 

($4,500/ton) with the new fuel prices; it was near $4,700/Mg ($4,300/ton) in 

the previous analysis. 

As shown, the increase in the incremental cost effectiveness of S02 

emission control associated with standards requiring a percent reduction 

over standards based on low sulfur fuels for nonfossil/oil-fired boilers is 

the most significant impact of the new fuel prices. This increase is the 

result of the lower fuel sulfur premiums which characterize the 1986 

projections compared to the 1984 projections. As discussed above, this 

change results in lower fuel savings when firing a high sulfur oil and thus 

offsets less of the costs of scrubbing. 

8 
P.10 

3.0 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 26, 1986. 

4. Radian Corporation. 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. Research Triangle Park, 

North Carolina. Publication No. EPA-450/3-86-001. June 1986. 

p. 1-29. 

5. Radian Corporation. Industrial Boiler S02 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. 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. 

8. Memorandum from Stackhouse, C. and Edward Aul, Radian Corporation, to 

Stevenson, Walt and Fred Porter, EPA/SDB. Impacts of New Fuel Prices 

on the National Impact Analysis for Mixed Fuel-Fired Steam Generating 

Units. April 15, 1987. 
p.11 

APPENDIX A 

METHODOLOGY FOR REVISING MODEL MIXED FUEL-FIRED BOILER 

COST ESTIMATES TO INCORPORATE NEW FUEL PRICES 

1.0 INTRODUCTION 

In addition to examining new fuel price impacts, the approach and 

assumptions used in Reference 4 in calculating costs of mixed fuel-fired 

steam generating units were reviewed and, where appropriate, modified for 

this analysis. These modifications were necessary to ensure that the 

costing methodologies used in this analysis were consistent with the 

methodologies used in other industrial steam generating unit cost studies. 

The following discussion addresses the differences in approach and 

assumptions used in this cost analysis as compared with the previous 

analysis. The revised cost algorithms used to calculate the mixed 

fuel-fired steam generating unit costs are given in Appendix B. 

2.0 STEAM GENERATING UNIT COSTS 

2.1 CAPITAL COSTS 

The approach and assumptions used to calculate the capital costs for 

the steam generating units in Reference 4 were not modified for this cost 

analysis. 

2.2 OPERATING AND MAINTENANCE COSTS 

The cost equation used for estimating solid waste costs in Reference 4 

was changed for consistency purposes. Instead of using the fossil/nonfossil 

mixture properties in the fossil cost algorithm as was done previously, the 

fossil fuel cost algorithm was used only for estimating solid waste disposal 

costs for the fossil fuel being fired. Nonfossil solid waste disposal costs 

A-1 
P.12 

were calculated by multiplying the solid waste generation rate (based on 

model steam generating unit information in Reference 5) by the solid waste 

unit cost rate and the nonfossil fuel fraction of the mixture being fired. 

The fossil and nonfossil waste disposal costs were summed to calculate the 

total solid waste disposal costs. 

Two calculational omissions were discovered in the cost results 

presented in Reference 4 were also corrected. The first omission was that 

the costs for spare parts, electricity, chemicals, and water calculated from 

cost algorithms based on 1978 dollars were not updated to 1983 dollars. The 

second omission was that the costs for monitors (opacity, 02/C02 outlet, and 

S02 outlet monitors) were not included for the baseline and low sulfur fuel 

regulatory alternatives. 

2.3 STEAM GENERATING UNIT COST IMPACTS 

The annualized costs for model steam generating units calculated for 

this analysis, before incorporating the new fuel prices and updating to 1985 

dollars, are higher than those reported in Reference 4 due to the above 

changes. However, these changes will not affect the cost effectiveness of 

S02 control since steam generating unit costs are the same for the baseline 

and two regulatory alternatives. 

3.0 PARTICULATE MATTER CONTROL COSTS 

3.1 CAPITAL COSTS 

The approach used in Reference 4 to calculate the capital costs for 

fabric filters applied to coal/nonfossil-fired steam generating units and 

venturi scrubbers applied to oil/nonfossil-fired steam generating units was 

to base the costs on the flue gas flow rate of the boiler firing a specified 

fossil/nonfossil mixture. This approach is not consistent with the approach 

used in other cost studies in which the particulate matter (PM) 

A-2 
P.13 

control device is costed for worst-case design conditions. The worst-case 

design conditions for a PM control device on a mixed fuel-fired steam 

generating unit correspond to firing 100 percent nonfossil fuel due to its 

higher flue gas flow rate. For this reason, the PM control costs in this 

analysis were calculated based on a steam generating unit firing 100 percent 

nonfossil fuel. Because the capital costs for both fabric filters and 

venturi scrubbers are directly related to flue gas flow rate, the capital 

costs using this approach will be higher than in Reference 4. 

3.2 OPERATING AND MAINTENANCE COSTS 

The approach used in Reference 4 to calculate the operating and 

maintenance (O&M) costs for was not modified for this analysis. The 

controlled PM emission limits for mixed fuel-fired steam generating units 

were modified, however, to reflect current regulations at 40 CFR Part 60, 

Subpart Db. The following controlled PM emission levels were used in this 

analysis: 

t 43 ng/J (0.1 lb/million Btu) limits for mixed fuel- and oil-fired 

boilers; 

• 22 ng/J (0.05 lb/million Btu) limit for coal-fired boilers. 

3.3 PM CONTROL COST IMPACTS 

As a result of the capital cost changes discussed in Section 3.1, the 

PM control annualized costs will be higher for all units compared to those 

reported in Reference 4. The prior analysis assumed controlled PM emission 

limits of 22 ng/J (0.05 lb/million Btu) for steam generating units 

firing all fuel types. By increasing the PM emission limit from 22 ng/J 

(0.05 lb/million Btu) to 43 ng/J (0.10 lb/million Btu) for mixed fuel-fired 

steam generating units, the annualized costs for solid waste disposal will 

decrease slightly from those reported in Reference 4. However, cost 

effectiveness values for S02 control associated with the regulatory 

alternatives examined will not change as a result of these modifications 

A-3 
P.14 

since PM control costs are the same for the baseline and two regulatory 

alternatives. 

4.0 S02 CONTROL COSTS 

4.1 CAPITAL COSTS 

The approach used in Reference 4 to calculate capital costs for sodium 

scrubbing systems applied to mixed fuel-fired boilers was modified to 

reflect worst-case design conditions. The prior approach based the costs of 

the sodium scrubbing system on the flue gas flow rate and S02 loading 

generated by firing 100 percent fossil fuel. However, this does not 

represent worst-case design conditions with respect to flue gas flow rate. 

The highest flow rate in mixed fuel-fired steam generating unit occurs when 

100 percent nonfossil fuel is fired; the highest S02 loading occurs when 100 

percent fossil fuel is fired. This revision will result in higher capital 

costs than the approach discussed in Reference 4. 

4.2 OPERATING AND MAINTENANCE COSTS 

The same approach and assumptions were used in calculating operating 

and maintenance costs for sodium scrubbing systems. However, upon review of 

the calculations used for generating the costs presented in Reference 4, it 

was noted that both the maintenance and S02 monitor costs were not updated 

to January 1983 dollars from July 1978 dollars. Therefore, the S02 costs 

presented in 1983 dollars in Reference 4 were underestimated. 

In addition, the maintenance costs for the sodium scrubbing system were 

underestimated in Reference 4. The costs for maintenance were calculated as 

8 percent of the turnkey costs of a sodium scrubbing system designed for a 

flue gas flow rate and S02 loading based on a specific fossil/nonfossil fuel 

mixture instead of the actual fuel characteristics. In this analysis, the 

maintenance costs are based on 8 percent of the turnkey costs of a scrubber 

system using the modified approach discussed in Section 4.1. 

A-4 
P.15 

4.3 S02 CONTROL COST IMPACTS 

As a result of these changes, the annualized costs for percent 

reduction of S02 in this analysis are higher than those presented in 

Reference 4. Therefore, the average and incremental cost effectiveness 

values for a percent reduction regulatory alternative are also higher than 

those presented in Reference 4. 

5.0 UPDATED ANNUALIZED COST ESTIMATES 

Fuel price projections over the fifteen-year period beginning in 1987 

were revised in August 1986 to reflect current and anticipated conditions in 

world fuel markets. Comparisons of previous and revised fossil fuel price 

projections for coal, oil, and natural gas are presented in Table A-1. The 

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

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

cost and cost effectiveness estimates are 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. 

Revised costs for mixed fuel-fired steam generating units and 

associated emission control equipment were calculated using the algorithms 

presented in Appendix B to this memorandum. These algorithms update the 

costs from January 1983 dollars to June 1985 dollars using an escalation 

factor of 1.0295 for capital costs based on the Chemical Engineering Plant 

Index and an escalation factor of 1.0347 for non-fuel O&M costs based on the 

Producer Price Index for all industrial commodities. ' ' 

A-5 
P.16 

APPENDIX B 

REVISED COST ALGORITHMS FOR MIXED FUEL-FIRED STEAM GENERATING 

UNITS AND ASSOCIATED EMISSION CONTROL EQUIPMENT 
P.17 

TABLE 1. NOMENCLATURE USED IN COST ALGORITHMS 

1. Capital Costs (1985 dollars) 

EQUP = Equipment 

INST = Installation 

IND = Indirect (Engineering, Field, Construction, Start-up, 

and other miscellaneous costs) 

TK = Turnkey 

2. Operation and Maintenance Costs3 (1985 dollars/year) 

DL = Direct Labor 

SPRV = Supervision Labor 

MANT = Maintenance Labor 

SP = Spare Parts 

ELEC = Electricity 

UC = Utilities and Chemicals 

WTR = Water 

SW = Solid Waste Disposal 

LW = Liquid Waste Disposal 

SC = Sodium Carbonate 

Boiler Specifications 

Q 

FLW 

CF 

FC 

H 

S 

A 

N 

FF 

Thermal Input (IO6 Btu/hr) {MW)£ 

Flue Gas Flowrate (acfm) (m/s) 

Capacity Factor (-) 

Fuel Specifications 

Fuel Cost ($/106 Btu) ($MJ)b . 

Heating Value (Btu/lb) (KJ/kg)D 

Sulfur Content (percent by weight) 

Ash Content (percent by weight) 

Fuel Nitrogen Content (percent by weight) 

Fossil Fuel Fraction 

5. SO^Control Specifications 

UNCS02 = Uncontrolled SO, Emissions (lb/106 Btu) (ng/J)b 

CTRS02 = Controlled SO, Emissions (lb/10° Btu) (ng/J)D 

EFFS02 = SO, Removal Efficiency (percent) 

B-1 
P.18 

TABLE 1. NOMENCLATURE USED IN COST ALGORITHMS (CONTINUED) 

6. PM Control Specifications 

UNCPM = Uncontrolled PM Emissions (lb/106 Btu) (ng/J)b 

CTRPM = Controlled PM Emissions (lb/10° Btu) (ng/J)D 

EFFPM = PM Removal Efficiency (percent) 

7. Cost Rates (in January 1983 dollars) 

ELECR = Electricity Rate-($/kw-hr) - . 

WTRR = Water Rate ($/10J gal) ($/m ) 

ALIME = Lime Rate ($/ton) ($/kg)tr

 h 

ALS = Limestone Rate ($/ton) ($/kg)D

 b 

SASH = Sodium Carbonate Rate ($/ton) ($/kgi 

SLDG = Sludge Disposal Rate ($/ton) ($/kg)D . 

SWR = Solid Waste Disposal Rate ($/tonl ($/kg) ., . 

LWD = Liquid Waste Disposal Rate ($/103 gal) ($/trr)° 

DLR = Direct Labor Rate ($/man-hr) 

SLR = Supervision Labor Rate ($/man-hr) 

AMLR = Maintenance Labor Rate ($/man-hr) 

8. Miscellaneous 

DLM 

SLM 

MLM 

Sl 

S2 

LF 

Direct Labor Man-Hours (man-hours/shift) 

Supervision Man-Hours (man-hours/shift) 

Maintenance Man-Hours (man-hours/shift) 

Heat Specific Sulfur Removal (kg S/1000 MJ) 

Time Specific Sulfur Removal (kg S/hr) 

Labor Factor (-) 

Cost categories are not mutually exclusive. For example, some costing 

routines include electricity and waste cost in the utilities category while 

other calculate these cost separately. 

SOD algorithm uses metric units. 

"(-) factor presented as fraction not as percent. 

B-2 
P.19 

TABLE 2. COST EQUATIONS FOR FIELD-ERECTED, WATERTUBE SPREADER-STOKER 

BOILER FIRING FOSSIL/NONFOSSIL MIXTURES (IN JUNE 1985 DOLLARS)3 

Capital Costs 

TKb = [11,785 (Q/358)0,7 7 + 154.47*(1.2*FF*Q)0,78 - 11,785* 

(1.2*FF*Q/358)0,77]*1.44*1.0295 

TKC = [11,785 (Q/358)0,7 7 + 192.02*(1.2*FF*Q)0,75 - 11,785* 

(1.2*FF*Q/358)0,77]*1.44*1.0295 

Annual Costs 

DL = DLM*(4)*(8)*(52)*(0.767)*(DLR)*(LF)*(1.0347); where 

DLM = 3.25 for Q = 150, 

DLM = 6.75 for Q = 400, 

DLM = 10.00 for Q = 800 

SPRV = SLM*(4)*(8)*(52)*(0.767)*(SLR)*(LF)*(1.0347); where 

SLM =1.00 for Q = 150, 

SLM = 1.50 for Q = 400, 

SLM = 2.00 for Q = 800. 

MANT = (MLM)*(4)*(8)*(52)*(0.767)*(AMLR)*(LF)*(1.0347); where 

MLM - 1.00 for Q - 150, 

MLM = 3.00 for Q = 400, 

MLM = 4.50 for Q = 800. 

B-3 
P.20 

TABLE 2. COST EQUATIONS FOR FIELD-ERECTED, WATERTUBE SPREADER-STOKER 

BOILER FIRING FOSSIL/NONFOSSIL MIXTURES (IN JUNE 1985 DOLLARS)3 (CONTINUED) 

SP = {(50,000 + 1,000 Q)*(0.767)*[TK/(11,785*(Q/358)0,77]}(1.51)(1.0347) 

VC = CF [29,303 + 719.8(Q)](0.848)(1.51)(1.0347) 

SWd = [(0.38)(FF)(CF)(547,320 + 66,038 ln AF/HF)(FF*Q/150)0,9754* 

(0.848)(1.51) + 1.48(Q)(CF)(1-FF)(SWR)8760/2000]*1.0347 

SWe - 1.48(Q)(CF)*(1-FF)(SWR)(8760/2000) 

aCost equations use English units. 

Applies only to eastern coals in EPA Regions 1 through 7. Turnkey costs 

for oil/wood-fired boilers are assumed to be the same as coal/wood-fired 

boilers in those EPA regions. 

cApplies only to Western coal in EPA Region 8 through 10. Turnkey costs 

for oil/wood-fired boilers are assumed to be the same as coal/wood-fired 

boilers in those EPA regions. 

Applies only to coal/wood-fired boilers. AF = Ash content of fossil fuel; 

HF = Heating Value of Fossil Fuel. 

eApplies only to oil/wood-fired boilers. 

B-4 
P.21 

TABLE 3. COST EQUATIONS FOR FABRIC FILTERS APPLIED 

TO MIXED FUEL-FIRED BOILERS 

(IN JUNE 1985 DOLLARS)3 

Routine Code: FF 

Capital Costs:a ,b 

EQUP = [8.340(FLW)0,966] (1.44)(1.0295) 

INST = [-1,405,523 + 168,531 In (FLW)] (1.44)(1.0295) 

IND •*-> [24.990(FLW)0,821] (1.44)(1.0295) 

Annual Costs: 

DL = LF (10,150 + 106 Q)(DLR/12.02)(1.0347) if 30 < Q < 400 

= LF (52,600)(DLR/2.02)(1.0347) if 400 < Q < 700 

SPRV = 0 if 30 < Q < 400 

= LF (17,000)(SLR/15.63)(1.0347) if 400 < Q < 700 

MANT = LF (14,840 + 0.106 Q2)(AMLR/14.63)(1.0347) if 30 < Q < 400 

= LF (32,000)(AMLR/14.63)(1.0347) if 400 < Q < 700 

SP = [0.278 (FLW)0,997](1.0347)(1.51) 

ELEC = [(CF/O.6)0.740(FLW)0,953](ELECR/0.0258)(1.0347) 

SW = (CF/0.6)(39.42)(Q)(UNCPM - CTRPM) (SWD/15)(1.0347) 

aCost equations are in English units. 

Flow rate (FLW) is based on boiler firing 100 percent nonfossil fuel. 

B-5 
P.22 

TABLE 4. COST EQUATIONS FOR VENTURI SCRUBBERS APPLIED 

TO MIXED FUEL-FIRED BOILERS 

(IN JUNE 1985 DOLLARS)3 

Routine Code: VS 

Capital Costs: 

EQUP = [26,916 + 2.294(FLW)](1.44)(1.0295) 

INST = [13,904 + 1.653(FLW)](1.44)(1.0295) 

IND = [15,463 + 1.285(FLW)](1.44)(1.0295) 

Annual Costs: 

DL = LF (10,150 + 106 Q) (DLR/12.02)(1.0347) if 30 < Q < 400 

= LF (52,600)(DLR/12.02)(1.0347) if 400 < Q < 700 

SPRV = 0 if 30 < Q < 400 

- LF (17,000)(SLR/15.63)(1.0347) if 400 < Q < 700 

MANT = (4,525 + 104.4 Q)(AMLR/14.63)(1.0347) 

ELEC = (CF/O.6)(0.95*304.3*Q0,938)(ELECR/0.0258)(1.0347) 

WTR = (CF/0.6)(0.05*304.3*Q0,938)(WTR/15)(1.0347) 

SW = (CF/0.6) 39.42 Q (UNCPM - CTRPM)(SWD/15)(1.0347) 

3Cost equations are in English units. ' 

Flow rate (FLW) is based on boiler firing 100 percent nonfossil fuel. 

B-6 
P.23 

TABLE 5. COST EQUATIONS FOR SODIUM SCRUBBING FGD SYSTEMS 

IN JUNE 1985 DOLLARS)3 

Routine Code: SOD 

Capital Costs:b ,c 

TK$ = [39,900(FLW)0,585 + 1,370 (S2)0727](1.0295) 

TK = 26,500 S20,39](1.0295) 

W 

TK = TK + TK 

s w 

Annual Costs: 

DL = 1,100*DLR 

SPRV = 165*SLR 

MANT3 = 0.08*TK 

ELECS = 8,760*CF*ELECR[3.61(FLW) - 2.15](1.0347) 

ELEC = 8760*CF*ELECR[0.23(S2) + 1.32](1.0347) 

ELEC = ELECC + ELEC,, 

s w 

WTR = 8760*CF*WTRR[0.600(FLW) - 2.08][0.527(S1) + 0.364](1.0347) 

SC = 8760*CF*SASH[3.33(S2) + 0.082](1.0347) 

LW = 8760*CF*LWD[0.0616(S2) + 0.298](1.0347) 

3Cost equations are in metric units. 

Flow rate (FLW) is based on a boiler firing 100 percent nonfossil fuel. 

Time specific sulfur removal (S2) is based on a boiler firing 100 percent 

fossil fuel. 

cThe subscript "s" denotes scrubber costs and the subscript "w" denotes 

wastewater costs. 

This equation assumes that the wastewater stream has a total dissolved 

solids concentration (TDS) of 5.7. 

eSl = S*EFFS02*100/H; S2 = S1*Q*3.6. 

B-7