p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

309) IV-B-13 

Docket Number: 

A-83-27 

Printed 11/12/200811:12:59 AM Sheet 309 of 325 
P.2 

' <T v A-83-27 

CORPORATIO N IV-D-I O 

MEMORANDUM 

DATE: April. 15, 1987 

TO: Walt Stevenson and Fred Porter, EPA/SDB 

FROM: Cecil Stackhouse and Edward Aul, Radian Corporation 

SUBJECT: Impacts of New Fuel Prices on the National Impacts Analysis 

for 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 national 

impacts associated with alternative new source performance standards (NSPS) 

limiting sulfur dioxide (SO-) 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 

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

Mixed fuel-fired units generally fire a mixture of fossil and nonfossil 

fuels. As in the previous analysis, however, "nonfossil fuels" is used in 

a very general sense to represent non-sulfur bearing fuels (i.e., fuels 

other than coal or oil). Non-sulfur bearing fuels are generally nonfossil 

fuels, such as wood and municipal solid waste, but may also include natural 

gas. Thus, the terms "nonfossil" and "non-sulfur bearing" are used 

interchangeably to mean fuels which typically have negligible sulfur 

contents. 

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

assumptions used in the prior analysis (i.e., Reference 4) for estimating 

capital and non-fuel operating and maintenance costs for model mixed 

fuel-fired boilers were reviewed and, where appropriate, modified to make 

them consistent with those used in other industrial model boiler cost 

studies. These modifications are discussed in full in Appendix A. These 

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

* * 

modifications have a negligible effect on the assessment of national impact 

changes caused by the new fuel prices. The revised cost algorithms used to 

estimate costs for mixed fuel-fired boilers and associated emission control 

equipment are provided in Appendix B. 

Sections 1.1 and 1.2 of this memorandum address the methodology used to 

update the time basis of the model boiler cost estimates and the revised 

fuel price projections utilized in this analysis, respectively. Section 2 

presents the fuel choice decisions on a model boiler basis using the revised 

fuel prices. Section 3 presents the results of the revised national impacts 

analyses. 

In writing this memorandum, it was assumed that the reader is familiar 

with the costing methodology and decision analysis techniques discussed in 

References 4 and 5, respectively. 

1.1 Time Basis of Cost Estimates 

Revised costs for mixed fuel-fired boilers and associated emission 

control equipment have been estimated using algorithms presented in Appendix 

B to this memorandum. These algorithms incorporate the changes discussed in 

Appendix A as well as update the time basis of the costs from January 1983 

dollars to June 1985 dollars. The updating was accomplished using an 

escalation factor of 1.0295 for capital costs, based on the Chemical 

Engineering Plant Cost Index, and a factor of 1.0347 for non-fuel O&M costs, 

based on the Producer Price Index for All Industrial Commodities compiled 

8 9 by the U.S. Bureau of Labor Statistics. 

1.2 New Fuel Price Projections 

Fuel price projections for the period 1987 to 2002 were revised in 

August 1986 to reflect current and anticipated conditions in world energy 

markets. Table 1 compares the 1984 and 1986 levelized price projections for 

coal, oil, and natural gas. As shown, the general trend is a decline in all 

levelized fuel prices between the 1984 and 1986 projections and a reduction 
P.4 

TABLE 1. COMPARISON OF 1984 AND 1986 COAL, OIL, AND NATURAL GAS 

PRICE PROJECTIONS 

< 

Fuel Type 

Region I 

B-b1tum1nous coal 

E-b1tum1nous coal 

F-bitum1nous coal 

3.0% sulfur oU 

0.856 sulfur oi l 

Natural gas 

Region IY 

B-b1tum1nous coal 

D-b1tum1nous coal 

G-b1tum1nous coal 

H-b1tum1nous coal 

3.0% sulfur oi l 

0.8% sulfur oU 

Natural gas 

Region X 

B-subb1tuminous coal 

E-subb1tuminous coal 

3.0% sulfur oi l 

0.8% sulfur oi l 

Natural gas 

Sulfur Content 

(lb S0?/ 

millio n Btu) a 

<1.08 

1.67-2.50 

2.50-3.33 

3.0 

0.8 

0 

<1.08 

1.08-1 

3.33-5 

>5.00 

3.0 

0.8 

0 

<1.08 

1.67-2 

3.0 

0.8 

0 

.67 

.00 

.50 

July 1984 

Price 

Projections 

(1983 $/ . 

millio n Btu) D'

c 

3.76 

3.65 

3.46 

4.80* 

5.501" 

5.83f 

3.19 

2.98 

2.80 

2.62 

4.77* 

5.46T 

6.02f 

2.66 

2.09 

4.34

 f 

5.07T 

5.57f 

August 1986 

Price Projections 

(1985 $/m1ll1on Btu) c'

d 

Low 011 High 011 

Prices Prices 

3.25 

2.97 

2.83 

2.81 

3.27 

3.30/4. 

2.65 

2.56 

2.42 

2.33 

2.73 

3.18 

3.14/3 

2.40 

1.84 

2.65 

3.08 

2.97/3 

17e 

.88e 

.24e 

3.25 

2.97 

2.83 

4.06 

4.59 

4.38/5.39* 

2.65 

2.56 

2.42 

2.33 

3.98 

4.51 

4.08/4.80* 

2.40 

1.84 

3.88 

4.37 

3.76/4.00 

aMult1ply lb S02/106 Btu by 430.278 to obtain ng S02/J. 

Source: Reference 4. 

cMult1ply $/106 Btu by 9.486 x IO"4 to obtain $/MJ. 

Source: References 1 to 3. 

eBased on a carriage/non-carriage natural gas market. Natural gas prices 

under the low oil price scenario are based on a rigid regulatory environment 

as discussed 1n References 3 and 10. 

^Corresponds to 1984 low oil price scenario. 

3 
P.5 

in the sulfur premium (i.e., the additional price of low sulfur fuels 

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

scenarios are reflected in the 1986 projections. Finally, two prices are 

presented for natural gas corresponding to a carriage market (in which users 

are free to purchase low-priced gas directly from the producer and pay the 

pipeline company for "carriage" to the user's facility) and a non-carriage 

market (similar to the existing market in which the pipeline company 

purchases the gas and sells it to the user at "rolled-in" prices). The 

projected markets and regulatory environments for natural gas are further 

explained in Reference 10. 

In addition to these price scenarios for oil and natural gas, two options 

are considered for nonfossil fuel. In the first option, nonfossil fuel is 

considered to be available at zero cost or price. For the second option, 

nonfossil fuel is assigned the same price as the lowest-cost coal available 

in the region examined. 

A total of eight fuel price scenarios have been developed based on the 

possible combinations of these oil, natural gas, and nonfossil fuel prices, 

as shown in Figure 1. These fuel price scenarios are used to bound the 

impacts analysis for mixed fuel-fired boilers operating under selected SO* 

regulatory alternatives. 

2.0 FUEL CHOICE DECISIONS FOR MODEL STEAM GENERATING UNITS 

Model mixed fuel-fired boilers were developed in Reference 4 based on 

information collected in a 1980 survey of boiler operations in the pulp and 

paper and forest products industries. This information was used to estimate 

the distribution of new mixed fuel-fired boilers with respect to size and 

fossil/nonfossil fuel mixture properties. This distribution of model units 

is repeated for reference purposes in Table 2. 

The mix of fuels fired 1n these boilers may change, however, 1n 

response to the new fuel prices. These changes could occur at the baseline 

(i.e., in the absence of an SO* NSPS) as well as in response to various S02 

regulatory alternatives. Consequently, the mix of fuels fired in these 
Oil Price 

Scenario 

Nonfossil 

Fuel Prices 

Natural Gas 

Prices 

Fuel Price 

Scenario 

tji 

Figure 1. An Overview of the Fuel Price Scenarios 
TABLE 2. ASSUMED REGIONAL DISTRIBUTION OF MODEL MIXED FUEL-FIRED STEAM GENERATING UNITS 

(NUMBER OF UNITS) 

CT> 

Model Unit 

(million B1 

150 

400 

800 

Size 

tu/hr) 

20X 

Fossil 

1 

2 

1 

Fuel 

REGION 

5 OX 

Fossil o o o 

I 

Fuel 

BOX 

Fossil 

0 

0 

2 

Fuel 

20X 

Fossil Fuel 

2 

5 

2 

REGION IV 

5 OX 

Fossil Fuel 

0 

1 

1 

80X 

Fossil Fuel 

0 

1 

4 

Fos 

20X 

sll Fuel 

2 

4 

1 

REGION X 

5 OX 

Fossil Fuel 

0 

1 

1 

Fos 

BOX 

sll Fuel 

0 

1 

3 
projected mixed fuel-fired boilers was re-examined. The fuel choice 

decision methodology utilized was based on the minimization of total steam 

generating plant costs over the useful life of the facility. Specifically, 

it was assumed that boiler owner/operators would select the fuel or fuel 

combination with the lowest after-tax net present value (NPV) of projected 

cash flows over the boiler's useful life. The basic assumptions of this 

methodology are consistent with those employed in the Industrial Fuel Choice 

Analysis Model (IFCAM) which is used to examine national impacts associated 

5 

with various NSPS for fossil fuel-fired boilers. 

2.1 Previous Fuel Choice Analvsis 

The prior analysis of fuel choice decisions (using 1984 fuel price 

projections) in Reference 4 considered the after-tax NPVs of a 44 MW (150 

million Btu/hr) boiler firing either 100 percent fossil fuel or a 20 percent 

fossil/80 percent nonfossil fuel mixture. This latter combination of unit 

size and fuel mixture is the most likely condition under which a mixed 

fuel-fired boiler might switch away from coal or oil to natural gas in 

response to S0« control requirements. Thus, it was used as a "surrogate" to 

examine the likelihood of fuel switching in response to various NSPS. 

Using the 1984 fuel price projections, the prior analysis showed that 

new mixed fuel-fired boilers would, in almost all cases, fire a mixture of 

coal and nonfossil fuels at the regulatory baseline as well as under both 

an NSPS based on using low sulfur fuel and an NSPS requiring a percent 

reduction in emissions. One exception was noted in Region I at the 

regulatory baseline when the price of the nonfossil fuel was equal to that 

of the lowest-priced coal. In this case, firing 100 percent oil had the 

lowest NPV. It was generally expected, however, that the price of nonfossil 

fuel would not be as high as the price of low-cost coal. In light of these 

results, "fuel switching" by new boilers away from coal/nonfossil mixtures 

in response to SO- control alternatives was "ruled out" as economically 

unfavorable for both this boiler size and fuel mixture as well as other 

projected sizes and mixtures. Thus the prior analysis concluded that fuel 
P.9 

switching would not occur among mixed fuel-fired boilers in response to 

various NSPS. 

2.2 Revised Fuel Choice Analvsis 

The analysis discussed above [for a 44 MW (150 million Btu/hr) boiler 

firing a 20% fossil/80% nonfossil fuel mixture] was repeated using the 1986 

fuel price projections. However, whereas the prior analysis was conducted 

with only one oil price and one natural gas price, the revised analysis 

considered two oil prices (i.e., high and low) and two natural gas prices 

(i.e., carriage and non-carriage) as discussed in Section 1.2. The 

nonfossil fuel price options remained the same as before. Tables 3 thru 6 

present the revised NPV analysis for the various combinations of oil, 

natural gas, and nonfossil fuel prices. 

Examination of these tables shows that the lowest NPV option varies as 

a function of oil price, natural gas price, and nonfossil fuel price. The 

most economically attractive fuel options correspond to those with the 

lowest NPVs; these options are identified in the tables. These tables 

indicate that fossil fuel firing (I.e., 100 percent oil or natural gas) is 

more attractive than mixed fuel firing for the 44 MW (150 million Btu/hr) 

model boiler if the price of the nonfossil fuel 1s assumed to equal that of 

the least expensive coal in the region. This is true under all combinations 

of oil and gas prices. Fossil fuel firing 1s also more attractive than 

mixed fuel firing if the price of the nonfossil fuel is assumed to be 

negligible (i.e., zero) under the assumption of low oil prices. 

Only under the combined assumptions of negligible nonfossil fuel prices 

and high oil prices are mixed fuel-fired boilers more attractive than fossil 

fuel-fired units for the 44 MW (150 million Btu/hr) model boiler at the 

regulatory baseline. Even under these assumptions, however, fuel switching 

from coal to natural gas occurs among mixed fuel-fired boilers 1n response 

to standards requiring a percent reduction in emissions. 

The absence of mixed fuel-fired boilers at the regulatory baseline 

under the assumption of low oil prices (as well as under the assumptions of 
TABLE 3 . NET PRESENT VALUE FOR 44 MW (150 MILLION BTU/HOUR) NONFOSSIL/FOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS 

HIGH OIL PRICES (1985 $) 

(NON-CARRIAGE NATURAL GAS PRICE) 

Fossil/Nonfossil 

Fuel Mixture 

Control Alternatives 

20X Coal/BOX 

Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

20X 011/BOX 

Nonfossil Fuel 

Nonfossil 

= Coal8 

Nonfossil 

= 0 

20X Natural Gas/ 

80X Nonfossil Fuel 

Nonfossil 

Coal a 

Nonfossil 

= 0 

IOOX Fossil Fuel 

Coal 011 

Natural 

Gas 

Region I 

Regulatory Baseline 

Low Sul fur Fuel 

Percent Reduction 

22,590 

22,950 

24,280 

16,070° 

16,360° 

17,760 

23,440 

23,770 

25,040 

16,840 

17,170 

18,440 

24,330 

24,330 

24,330 

17,730 

17,730 

17,730° 

24,240 

25,100 

26,710 

18.7101-

19,360c 

19,720c 

21,970 

21,970 

21,970 

<o 

Region IV 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

21,340 

21.540 

23,160 

15,810° 

16,010° 

17,630 

22,340 

22,660 

23,910 

16,800 

17,120 

18,370 

22,940 

22,940 

22,940 

17,400 

17,400 

17,400° 

23,100 

23,330 

25,620 

18,470'' 

19,110c 

19,460c 

20.250 

20,250 

20,250 

Region X 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

20,330 

20,650 

21,760 

15,920° 

16,240° 

17,340 

21,490 

21,780 

23,050 

17,070 

17,360 

18,630 

21,710 

21,710 

21,710 

17,290 

17,290 

17,290° 

21,860 

23,460 

24.000 

18,150 

18,670 

19,120 

17,610*-

17,610c 

17,610c 

Nonfossll fuel cost equals that of the lowest price coal In the region. 

Lowest NPV alternative under the assumption that the price of nonfossil fuel Is negligible. 

:Lowest NPV alternative under the assumption that the price of nonfossil fuel Is equal to the lowest price coal available In the region. 

o 
TABLE 4. NET PRESENT VALUE FOR 44 MW (150 MILLION BTU/HOUR) NONFOSSIL/FOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS 

HIGH OIL PRICES (1985 $) 

(CARRIAGE NATURAL GAS PRICE) 

Foss11/Nonfossil 

Fuel Mixture 

Control Alternatives 

20X Coal/80X 

Nonfossil Fuel 

Nonfossil 

= Coal8 

Nonfossil 

= 0 

20X 011/80X 

Nonfossil' Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

20X Natural Gas/ 

BOX Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

IOOX Fossil Fuel 

Coal 011 

Natural 

Gas 

Region I 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

22,590 

22,950 

24,255 

16,070" 

16,360° 

17,735 

23.440 

23,770 

25,007 

16,840" 

17,170° 

18,407 

23,626 

23,626 

23,626 

17,027 

17,027 

17,027° 

24,240 

25,100 

25,520 

18,710 

19.360 

19,680 

18,390L 

18.390c 

18,390c 

Region IV 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

21,340 

21,540 

23.139 

15,810" 

16.010° 

17,608 

22,340 

22,660 

23,894 

16,800" 

17,120° 

18,353 

22,455 

22,455 

22,455 

16,914 

16,914 

16,914° 

23,100 

23,330 

25,590 

18,470 

19,110 

19,430 

17.7701-

17,770° 

17,770c 

Region X 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

20,330 

20,650 

21,749 

15,920° 

16,240° 

17,337 

21,490 

21,780 

23,045 

17,070° 

17,360° 

18,625 

21,610 

21,610 

21,610 

17,190 

17,190 

17,190 

21,860 

23,460 

23,990 

18,150 

18,670 

19,110 

17,080c 

17.080*; 

17,080° 

Nonfossil fuel cost equals that of the lowest price coal in the region. 

Lowest NPV alternative under the assumption that the price of nonfossil fuel 1s negligible. 

cLowest NPV alternative under the assumption that the price of nonfossil fuel is equal to the lowest price coal available In the region. 
TABLE 5 . NET PRESENT VALUE FOR 44 MW (150 MILLION BTU/HOUR) NONFOSSIL/FOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS 

LOW OIL PRICES (1985 $) 

(NON-CARRIAGE NATURAL GAS PRICE) 

Foss11/Nonfossil 

Fuel Mixture 

Control Alternatives 

20X Coal/BOX 

Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

20X 011/BOX 

Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

20X Natural Gas/ 

SOX Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

IOOX Fossil Fuel 

Coal 011 

Natural 

Gas 

Region I 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

22,590 

22,950 

24,250 

16,070 

16,360 

17,730 

22,660 

22,940 

24,260 

16,060 

16,340 

17,660 

23,500 

23,500 

23,500 

16,900 

16,900 

16,900 

24,240 

25,100 

26,530 

14,810"'c 17,740 

15,610"' c 17,740 

15,820°' c 17,740 

Region IV 

Regulatory Baseline 

Low Sul fur Fuel 

Percent Reduction 

21,340 

21,540 

23,130 

15,810 

16,010 

17,600 

21,560 

21,830 

23,150 

16,020 

16,290 

17,600 

22,280 

22,280 

22,280 

16,740 

16,740 

16,740 

23,100 

23,330 

25,480 

14,570 

15,360 

15,580' 

b.c 

b.c 

b.c 

16,900 

16,900 

16,900 

Region X 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

20,330 

20,650 

21,730 

15,920 

16,240 

17,320 

20,800 

21,060 

22,370 

16,380 

16,670 

17,960 

21,200 

21,200 

21,200 

17,290 

17,290 

17,290 

21,860 

23,460 

23,890 

14.330! 

15,000 

15,310 

b.c 

b.c 

15,040 

15,040 

15,040 b.c 

Nonfossil fuel cost equals that of the lowest price coal in the region. 

Lowest NPV alternative under the assumption that the price of nonfossil fuel Is negligible. 

"Lowest NPV alternative under the assumption that the price of nonfossil fuel 1s equal to the lowest price coal available in the region. 
TABLE 6. NET PRESENT VALUE FOR 44 MW (150 MILLION BTU/HOUR) NONFOSSIL/FOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS 

LOW OIL PRICES (1985 $) 

(CARRIAGE NATURAL GAS PRICES - FLEXIBLE) 

Fossil/Nonfossil 

Fuel Mixture 

Control Alternatives 

20X Coal/80X 

Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

20X Oil/BOX 

Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

20X Natural Gas/ 

BOX Nonfossil Fuel 

Nonfossil 

= Coal a 

Nonfossil 

= 0 

IOOX Fossil Fuel 

Coal Oil 

Natural 

Gas 

Region I 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

22,590 

22,950 

24,219 

16,070 

16,360 

17,699 

22,660 

22,940 

24,227 

16,840 

17,170 

18,440 

22,845 

22,845 

22,845 

16,246 

16,246 

16,246 

24,240 

25,100 

25.360 

14,810 

15,610 

15,780 

14,410 

14,410 

14,410 

b.c 

b.c 

b,c 

Region IV 

J^ Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

21,340 

21,540 

23,108 

15.810 

16,010 

17,577 

21,560 

21,830 

23,120 

16,800 

17,120 

18,370 

21,759 

21,759 

21,759 

16,219 

16,219 

16,219 

23.100 

23.330 

25,450 

14,570 

15,360 

15,540 

14,260', 

14,260 

14,260' 

b.c 

b.c 

b.c 

Region X 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

20,330 

20,650 

21,727 

15,920 

16.240 

17,315 

20,800 

21,060 

22,368 

16,380 

16,670 

17,948 

21,053 

21,053 

21,053 

16,634 

16,634 

16,634 

21,860 

23,460 

23,880 

14,330 

15,000 

15,300 

14,270 

14,270 

14,270 

b.c 

b.c 

b.c 

Nonfossil fuel cost equals that of the lowest price coal in the region. 

Lowest NPV alternative under the assumption that the price of nonfossil fuel 1s negligible. 

Lowest NPV alternative under the assumption that the price of nonfossil fuel Is equal to the lowest price coal available In the region. 
high oil prices and nonfossil fuel prices equal to those of the least 

expensive regional coals) raised questions as to whether any mixed 

fuel-fired boilers would be expected at other sizes or mixtures. To answer 

these questions, NPVs were calculated for a 234 MW (800 million Btu/hr) 

boiler in Region IV firing an 80% fossil/20% nonfossil fuel mixture. This 

unit was selected because it is the largest, highest fossil fuel ratio model 

boiler projected and would be the unit most likely to show low NPVs for 

mixed fuel firing relative to other options. Region IV was chosen for 

examination because the levelized price difference between high sulfur coal 

and natural gas (under non-carriage prices) is greatest in this region. 

Thus, large mixed fuel-fired boilers in this region firing a high percentage 

of fossil fuel would be the most likely to fire mixed fuels at the 

regulatory baseline as well as under more stringent regulatory alternatives. 

If no mixed fuel-fired boilers were projected for this case, none would be 

expected for other model boiler sizes, fuel mixtures, or regions. 

The NPV results for this unit are summarized in Tables 7 and 8 for high 

and low oil prices, respectively. The NPVs in these tables indicate that 

100 percent fossil fuel firing (either oil or natural gas) is more 

attractive than mixed fuel firing for the 234 MW (800 million Btu/hr) model 

boiler considered only under the combined assumptions of low oil prices and 

nonfossil fuel prices equal to the least expensive coal in the region. For 

all other scenarios, mixed fuel firing (with coal as the fossil fuel) is the 

most economically attractive option at the regulatory baseline as well as 

under standards based on using low sulfur fuel. Under the assumptions of a 

percent reduction standard and negligible prices for nonfossil fuels, mixed 

fuel firing remains the lowest cost option in all scenarios except for low 

oil prices and carriage natural gas prices. Under these conditions, use of 

100 percent natural gas has the lowest cost. 

As a result of these analyses, it 1s apparent that both the number of 

projected mixed fuel-fired boilers operating at the regulatory baseline and 

the extent of fuel stitching occurring 1n response to S02 control 

alternatives depend directly on the assumptions made concerning oil, natural 

gas, and nonfossil fuel prices. This is a far different result than that 

13 
TABLE 7. NET PRESENT VALUE FOR 234 MW (800 MILLION BTU/HOUR) NONFOSSIL/FOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS 

(HIGH OIL PRICES (1985 $) 

Fossil/Nonfossil 

Fuel Mixture 

Control Alternatives 

BOX Coal/20X 

Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

80X 011/20X 

Nonfossil Fuel 

Nonfossil 

= Coala 

Nonfossil 

= 0 

SOX Natural Gas/ 

20X Nonfossil Fuel 

Nonfossil 

= Coal8 

Nonfossil 

= 0 

IOOX Fossil Fuel 

Coal Oil 

Natural 

Gas 

Region IV (Carriage Natural Gas Price) 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

98.120*-

99,110c 

108,850c 

88,240" 

89,220° 

98,160° 

121,380" 

128,300 

130,050 

114,030 

120,920 

122,700 

121.640 

121,640 

121.640 

114,250 

114,250 

114.250 

100,820 

100,820 

110,980 

rfi 115,410" 109,370 

115,410° 109,370 

123,930 109,370 

Region IV (Non-Carriage Natural Gas Price) 

Regulatory Baseline 

Low Sulfur Fuel 

Percent Reduction 

98,120*-

99,110c 

108,490c 

88,240" 

89,220° 

98,610° 

121,380" 

128,300 

130.500 

114,030 

120.920 

123,140 

132,030 

132,030 

132,030 

124,640 

124,640 

124.640 

100,820" 

100,820e 

111,530 

115,410° 

115,410e 

137,480 

122,300 

122,300 

122,300 

Nonfossil fuel cost equals that of the lowest price coal In the region. 

Lowest NPV alternative under the assumption that the price of nonfossil fuel Is negligible. 

c

Lowest NPV alternative under the assumption that the price of nonfossil fuel is equal to the lowest price coal available In the region. 

"Dilution" credit for nonfossil heat Input allowed at regulatory baseline. 

eS1nce Subpart D NSPS applies to boilers above 73 MW (250 million Btu/hr) heat Input, the regulatory baseline and low sulfur fuel standard 

are equivalent. 
TABLE 8 . NET PRESENT VALUE FOR 234 MW (800 MILLION BTU/HOUR) NONFOSSIL/FOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS 

(LOW OIL PRICES (1985 $) 

Foss1l/Nonfoss1l BOX Coal/20% 

Fuel Mixture Nonfossil Fuel 

Nonfossil 

Control Alternatives = Coala 

Region IV (Carriage Natural Gas Price) 

Regulatory Baseline 98,120 

Low Sulfur Fuel 99,110 

Percent Reduction 107,390 

Region IY (Non-Carriaqe Natural Gas Price) 

Nonfossil 

= 0 

88,240^ 

89.2306 

97,510 

80X 011/20X 

Nonfossil Fuel 

Nonfossil Nonfossil 

= Coal8 = 0 

104,760 97,400 

110,600 103,230 

113.680 106,190 

80X Natural Gas/ 

20X Nonfossil Fuel 

Nonfossil Nonfossil 

= Coal8 = 0 

106,790 99,410 

106,790 99,410 

106,790 99,410 

100X 

Coal 

100,820° 

100,820° 

110,150 

Fossil Fuel 

Natural 

011 Gas 

93,340° 91,240' 

93,340° 91,240' 

105,260 91,240 b.c 

Regu1atory Basel 1ne 

Low Sulfur Fuel 

Percent Reduction 

98,120 

99.110 

107,390 

88,240" 

89,230? 

98,040° 

104,760 

110,600 

114,210 

97,400 

103,230 

106,720 

117,830 

117,830 

117,830 

110,440 

110,440 

110,440 

100,820 

100,820 

110.820 

93,340c' ° 104,420 

93,340c' ° 104,420 

119,730 104,4201-

Nonfossll fuel cost equals that of the lowest price coal In the region. 

Lowest NPV alternative under the assumption that the price of nonfossil fuel 1s negligible. 

^Lowest NPV alternative under the assumption that the price of nonfossil fuel Is equal to the lowest price coal available In the region. 

"Dilution*1 credit for nonfossil heat Input allowed at regulatory baseline. 

BS1nce Subpart D NSPS applies to boilers above 73 MW (250 million Btu/hr) heat Input, the regulatory baseline and low sulfur fuel standard 

are equivalent. 
P.17 

obtained with the 1984 fuel prices in which all projected units were mixed 

fuel-fired units and almost all of these units selected coal/nonfossil 

mixtures as the lowest NPV option both at the baseline and under SO- control 

alternatives. 

2.3 Selection of Bounding Fuel Price Scenarios 

Rather than projecting the national impacts of SO- control for all 

eight combinations of fuel prices illustrated in Figure 1, the decision was 

made to select two fuel price scenarios that would bound the range of 

potential national impacts. Table 9 summarizes the fuel choice decisions 

under the eight fuel price scenarios for the regulatory baseline, low sulfur 

fuel alternative and percent reduction alternative. As shown, no mixed 

fuel-fired boilers are projected under Scenario 7 (i.e., low oil prices, 

carriage natural gas prices, and nonfossil fuel prices equal to coal prices) 

either at the regulatory baseline or for the two SO- control alternatives. 

Hence, the national impacts of both SO- control alternatives for mixed 

fuel-fired boilers would be zero under this fuel price scenario. 

Conversely, mixed fuel-fired boilers are the lowest NPV option for the 

regulatory baseline and both SO- control alternatives under Scenario 2 

(i.e., high oil prices, non-carriage natural gas prices, and a nonfossil 

fuel price of zero). Thus, the national impacts of SO- control alternatives 

on mixed fuel-fired boilers would be at their highest level for this fuel 

price scenario. National impacts for the other six fuel price scenarios 

fall somewhere between the impacts for Scenarios 2 and 7. 

On the basis of this analysis, the bounding fuel price scenarios with 

respect to national impacts of SO- control alternatives have been identified 

as Scenarios 2 and 7. Since Scenario 7 1s essentially the "null set", no 

further analysis is required and national impacts are zero. The remainder of 

the analysis deals with the national impacts of SO- control alternatives 

under 1986 fuel price projections and Fuel Price Scenario 2. 

16 
TABLE 9. IMPACTS OF FUEL PRICE SCENARIOS ON PROJECTIONS FOR NEW MIXED FUEL-FIRED STEAM GENERATING UNITS 

Fuel Price 

Fuel Price Scenarios 

S02 Control 

Alternatives 

Fuel Choice Decisions . 

For Each Control Alternative 'D'

c 

Impact on New Mixed Fuel 

Boiler Population Projections 

1 . High Oil Price , 

Nonfossil Pr1ce=0 

Carriage N. Gas Price 

2. High Oil Price, 

Nonfossil Pr1ce=0 

Nonearriage N. Gas Price 

3 . High Oil Price , 

Nonfossil Price=Coal 

Carriage N. Gas Price 

4 . High Oil Price , 

Nonfossil Pr1ce=Coal 

Noncarrlage N. Gas Price 

5. Low Oil Price, 

Nonfossil Pr1ce=0 

Carriage N. Gas price 

6. Low Oil Price, 

Nonfossil Pr1ce=0 

Noncarrlage N. Gas Price 

7. Low Oil Price, 

Nonfossil Pr1ce=Coal 

Carriage N. Gas Price 

8. Low Oil Price, 

Nonfossil Pr1ce=Coal 

Noncarrlage N. Gas Price 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

-Reg. Baseline 

-Low S Fuel 

-X Reduction 

All Cntrl. Alts. Have Mixed Fuel Boilers 

at 150 and 800 MMBTU/HR, except Region X/ 

150/90X reduction. 

All Cntrl. Alts. Have Mixed Fuel Boilers 

at 150 and 800 MMBTU/HR 

All Cntrl. Alts. Have 100X Fossil (N. Gas) 

Fuel Boilers at 150 MMBTU/HR 

All Cntrl. Alts. Have Mixed Fuel Boilers 

at 800 MMBTU/HR 

All Cntrl. Alts. Have 100X Fossil 

Fuel Boilers at 150 MMBTU/HR 

All Cntrl. Alts. Have Mixed Fuel Boilers 

at 800 MMBTU/HR 

100X Fossil (N. Gas) Fuel Boilers at 

150 MMBTU/HR and Mixed Fuel Boilers at 

800 MMBTU/HR 

100X Fossil (N. Gas) Fuel Boilers at 

150 MMBTU/HR and Mixed Fuel Boilers at 

800 MMBTU/HR 

100X Fossil (N. Gas) Fuel Boilers at 

150 and 800 MMBTU/HR 

100X Fossil (Oil) Fuel Boilers at 

150 MMBTU/HR and Mixed Fuel Boilers at 

800 MMBTU/HR 

100X Fossil Fuel Boilers at 

150 MMBTU/HR and 

800 MMBTU/HR 

100X Fossil Fuel Boilers at 

at 150 and 800 MMBTU/HR 

All Cntrl. Alts. Have 100X Fossil (N. 

Fuel Boilers at 150 & 800 MMBTU/HR 

Gas) 

100X Fossil (Oil) Fuel Boilers at 

150 MMBTU/HR and Mixed Fuel Boilers at 

800 MMBTU/HR 

100X Fossil (Oil) Fuel Boilers at 

150 and 800 MMBTU/HR 

100X Fossil Fuel Boilers at 

150 and 800 MMBTU/HR 

Near Maximum Number of Mixed Fuel 

Boilers 

Maximum Number of Mixed Fuel 

Boilers 

Some Mixed Fuel Boilers at 

All Cntrl. Alts. 

Some Mixed Fuel Boilers at 

All Cntrl. Alts. 

Some Mixed Fuel Boilers at 

the Reg. Baseline and 

Low S. Fuel Alternative. 

No Mixed Fuel Boilers at the X 

Reduction Alternatives. 

Portion of Projected Mixed Fuel 

Boilers at the Reg. Baseline. 

No Mixed Fuel Boilers at the Low 

S. Fuel or the X Reduction 

Alternatives. 

No Mixed Fuel Boilers 

Some Mixed Fuel Boilers at 

the Reg. Baseline. 

No Mixed Boilers at the 

low S. Fuel or the X 

reduction alternatives. 

"Mixed fuel boiler = mixed fuel-fired steam generating unit. 

bMM Btu/hr = million Btu/hr. 

c150 million Btu/hr = 44 MW; 800 million Btu/hr = 234 MW. 
P.19 

3.0 NATIONAL IMPACTS 

While fuel choice decisions are modeled on an after-tax NPV basis, 

national costs for SO- control alternatives are estimated on a before-tax 

annualized cost basis. Total annualized costs based on Scenario 2 were 

calculated for each combination of boiler size, fuel mixture, regional fuel 

price, and regulatory option. These costs and associated annual emissions 

for Region I, IV, and X are summarized in Tables 10, 11, and 12, 

respectively. 

It should be noted that with one exception, all of the model boilers in 

Tables 10, 11, and 12 select a coal/nonfossil mixture as the lowest-NPV fuel 

option under the baseline and two SO- control alternatives considered. The 

exception occurs for the 44 MW (150 million Btu/hr) mixed fuel-fired boiler 

firing a 20 percent fossil/80 percent nonfossil fuel mixture and subject to 

a percent reduction requirement. In this case a natural gas/nonfossil fuel 

mixture is selected, as discussed in Section 2.3. 

3.1 Analysis of National Impacts 

National impacts have been calculated for each of the regulatory 

alternatives shown in Table 13 using the costs and emission values in Tables 

10 thru 12 and the mixed fuel-fired boiler population projected in Table 2. 

The resulting national impacts, consistent with Scenario 2, are summarized 

in Table 14. 

Table 14 shows that, at the regulatory baseline, the annualized costs 

for the projected national 5-year population of new mixed fuel-fired steam 

generating units are $463.1 million per year and the annual SO- emissions 

are about 30,800 Mg/yr (33,900 tons per year). Under Regulatory 

Alternative 1, annualized costs would be $468.5 million per year with annual 

SO- emissions of 17,800 Mg/yr (19,600 tons per year); this corresponds to an 

average cost effectiveness of $417/Mg ($378/ton). For Regulatory 

Alternative 2, annualized costs would be $468.8 million per year and annual 

SO- emissions would be reduced to 16,800 Mg/yr (18,500 tons per year), for 

18 
TABLE 10. COST AND COST EFFECTIVENESS OF S02 CONTROL FOR COAL/NONFOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS IN REGION I a , b 

to 

Fossil/Nonfossll 

Fuel Mixture 20X COAL/80X NONFOSSIL 

Annual Annual 

Costs Emissions 

Coal Type ($l,000/yr) (tons/yr) 

50X COAL/SOX NONFOSSIL 

Annual Annual 

Costs Emissions 

Coal Type ($l,000/yr) (tons/yr) 

80X COAL/20X NONFOSSIL 

Annual Annual 

Costs Emissions 

Coal Type ($l,000/yr) (tons/yr) 

0 = 150 Million Btu/hr 

Regulatory Basel1nec'° 

(2.5 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction . 

(FGD-90X Reduction)0 

u = 400 Million Btu/hr 

Regulatory Basel1nec,e 

(1.2 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction rf 

(FGD-90X Reduction)0 

0 = BOO Million Btu/hr 

Regulatory Basel1nec'° 

(1.2 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction . 

(FGD-90X Reduction)0 

F-Blt 

B-Blt 

NGf 

F-Blt 

B-Bit 

F-Blt 

F-B1t 

B-Bit 

F-Blt 

4,060 

4,130 

4,240 

8,840 

9,010 

9.440 

14,960 

15,310 

16,120 

225 

75 

0 

599 

200 

48 

1,198 

399 

96 

F-B1t 

B-Bit 

F-Blt 

B-Bit 

B-Bit 

F-Blt 

E-Bit 

B-Bit 

F-Blt 

4,910 

5,080 

5,360 

11.190 

11,480 

11,880 

19,540 

20,120 

20,930 

562 

187 

45 

1,104 

499 

120 

-

2,208 

999 

240 

F-B1t 

B-B1t 

F-Blt 

B-B1t 

B-B1t 

F-Blt 

B-Bit 

B-Bit 

F-Blt 

5,750 

6,010 

6.270 

13,910 

13.910 

14.250 

24,880 

24,880 

25,590 

899 

300 

72 

799 

799 

192 

1.598 

1,598 

383 

"Metric units can be attained by the following conversions: $/Mg = $/ton « 1.1023; Mg/yr » tons/yr « 0.9075; MW = million Btu/hr » 0.293; 

ng/J = lb/million Btu « 430.278. 

Based on a capacity utilization factor of 0.6 and Fuel Price Scenario 2. 

cAt 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. 

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

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

Natural gas/nonfossil fuel mixture is the losest-NPV fuel option for this ccdsl belIsr. 
ro 

o 

TABLE 11. COST AND 

Fossil/Nonfossll 

Fuel Mixture 

Q = 150 Million Btu/hr 

Regulatory Baseline 

(2.5 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction 

(FGD-90X Reduction)0 

0 = 400 Million Btu/hr 

Regulatory Baseline 

(1.2 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction 

(FGD-90X Reduction)0 

Q = 800 Million Btu/hr 

Regu1ato ry Basel 1ne 

(1.2 lb/mill Ion Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction 

(FGD-90X Reduction)0 

COST EFFECTIVENESS OF SC 2 CONTROL FOR COAL/NONFOSSIL MIXED FUEL20X COAL/80X NONFOSSIL 

Coal Type 

H-BIt 

B-Bit 

NG® 

H-BIt 

B-Bit 

H-B1t 

H-BIt 

B-Bit 

H-B1t 

aMetr1c units can be attained by the 

ng/J = lb/million Btu « 430.278. 

Annual 

Costs 

(Jl.OOO/yr) 

3,990 

4,040 

4.150 

8,630 

8,760 

9,300 

14,530 

14,810 

15,830 

FIRED STEAM 

50X C0AL/50X NONFOSSIL 

Annual 

Emissions 

(tons/yr) Coal Type 

437 

75 

0 

1.165 

200 

93 

2,329 

399 

186 

following conversions: $/Mg 

Based on a capacity utilization factor of 0.6 and 

cAt the regulatory basel1 

nonfossil heat Input for 

°The annual emissions are 

G-BIt 

B-B1t 

H-B1t 

D-B1t 

B-Bit 

H-B1t 

D-B1t 

B-Bit 

H-BIt 

= $/ton * 

Fuel Price Scenario 2. 

ne. emission credits are provided for the 

other regulatory alternatives. 

based on a 

"Natural gas/nonfossil fuel mixture 1 

92 percent removal efficiency 

s the lowest-NPV fuel option 

Annual 

Costs 

($1.000/yr) 

4,750 

4,840 

5,310 

10,750 

10,840 

11,640 

18,660 

18,850 

20,400 

1.1023; Mg/yr 

Annual ' 

Emissions 

(tons/yr) 

818 

187 

87 

762 

499 

233 

1,524 

999 

466 

= tons/yr 

heat Input of the nonfossil fuel. 

; the additional 2 percent accounts 

for this model boiler. 

GENERATING UNITS IN REGION 

SOX 

Coal Type 

F-Blt 

B-B1t 

H-BIt 

B-B1t 

B-Bit 

H-BIt 

B-Bit 

B-Bit 

H-BIt 

» 0.9075; MW 

Iva,b 

C0AL/20X NONFOSSIL 

Annual 

Costs 

($l,000/yr) 

5,570 

5,630 

6,170 

12,860 

12,860 

13,960 

22,840 

22.840 

24,950 

Annual 

Emissions 

(tons/yr) 

899 

300 

140 

799 

799 

373 

1.598 

1,598 

745 

= million Btu/hr • 0.293; 

No emission credits are provided for 

for fuel and FGD variability. 
TABLE 12. COST AND COST EFFECTIVENESS OF Sa2 CONTROL FOR COAL/NONFOSSIL MIXED FUEL-FIRED STEAM GENERATING UNITS IN REGION Xa'

b 

Foss11/Nonfossil 

Fuel Mixture 20X COAL/BOX NONFOSSIL 

Coal Type 

Annual 

Costs 

($l,000/yr) 

Annual 

Emissions 

(tons/yr) 

50X C0AL/50X NONFOSSIL 

Coal Type 

Annual 

Costs 

($l,000/yr) 

Annual 

Emissions 

(tons/yr) 

80X C0AL/20X NONFOSSIL 

Coal Type 

Annual 

Costs 

($1.000/yr) 

Annual 

Emissions 

(tons/yr) 

ro 

Q = ISO Million Btu/hr 

Regulatory Baseline6 

(2.5 lb/mill1on Btu) 

Low Sulfur Coal 

(1.2 lb/mil Hon Btu) 

Percent Reduction 

(FGD-90X Reduction)0 

0 = 400 Million Btu/hr 

Regulatory Baseline® 

(1.2 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

J_i Percent Reduction 

(FGD-90X Reduction)0 

0 = 800 Million Btu/hr 

Regulatory Baseline® 

(1.2 lb/million Btu) 

Low Sulfur Coal 

(1.2 lb/million Btu) 

Percent Reduction 

(FGD-90X Reduction)0 

E-Sub 

B-Sub 

NGf 

4,010 

4.090 

4,120 

166 

75 

0 

E-Sub 

B-Sub 

E-Sub , 

4,520 

4.750 

4,930 

414 

187 

33 

E-Sub 

B-Sub 

E-Sub 

5,120 

5,460 

5,580 

E-Sub 

B-Sub 

E-Sub 

8.560 

8,800 

9,180 

442 

200 

35 

E-Sub 

B-Sub 

E-Sub 

10,190 

10,780 

10.950 

1,104 

499 

88 

E-Sub 

B-Sub 

E-Sub 

14,280 

14,780 

15.460 

883 

399 

71 

E-Sub 

B-Sub 

E-Sub 

17,350 

18.540 

18.830 

2,208 

999 

177 

E-Sub9 12,610 

E-Sub9 12.610 

E-Sub 12.610 

E-Sub9 22,030 

E-Sub9 22,030 

E-Sub 22.030 

662 

300 

53 

141 

141 

141 

283 

283 

283 

"Metric units can be attained by the following conversions: $/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 and Fuel Price Scenario 2. 

cAt 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. 

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

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

Natural gas/nonfossil fuel mixture is the lowest-NPV fuel option for this model boiler. 

9Lowest-cost control option to achieve this emission limit Is to fire Type E-Sub coal and install an FGD system to achieve 90 percent 

reduction. 
P.23 

Regulatory 

Alternative 

Alternative 

Alternative 

Alternative 

aBasel1ne = 

Baseline = 

CLSF = Low 

0.8 

dPer Red = 

^ 0 convert 

TABLE 13. 

Mixed FuelBaseUne 

1 

2 

3 

4 

2. 

1. 

sul 

lb 

90 

fi 

5 lb S02/mni1on 

2 lb S02/m1ll1on 

REGULATORY ALTERNATIVES 

Fired 

Btu 

Btu 

fur fuel standard (1. 

S02/m1ll1on Btu for c 

percent S02 reductlor 

-om million Btu/h r to 

Steam Generating Units 

Steam Generatl 

(million 

100 - 250 

BaseUne3 

BaseUne 

LSF 

LSF 

Per Red. 

(SIP level). 

(Subpart D level). 

2 lb S07/m1ll1on Btu 

)11). 

i required. 

MW, multiply by 0.293 

rig Unit ! 

Btu/hr) 

fo 

• 

r coal 

31zee 

•» >250 

BaseUne 

Pe 

Pe 

and 

To convert 

LSFC 

LSF 

r Red.d 

r Red. 

from i u tuiive i L i rum IIIIIIIU M DLU/II I U U mn , IIIU i 1.1 y i y u, 

lb S02/m1Uion Btu to ng S02/J, multiply by 430. 

22 
TABLE 14. NATIONAL IMPACTS OF REGULATORY ALTERNATIVES BASED ON THE 1986 PRICE PROJECTIONS 

FOR MIXED FUEL-FIRED STEAM GENERATING UNITS9'

b 

Annual Annualized 

Regulatory SO- Emissions Costs 

Alternative (1,000 tons/yr) ($ million/yr) 

Cost Effectiveness 

($/ton) 

Average0 Incremental' 

Quantity of 

Fuel Scrubbed 

(Trillion Btu/yr) Liquid Waste 

Generation 

t31 

Solid Waste 

Generation 

Fossil Nonfossil (Million ft-Vyr) (1,000 tons/yr) 

Baseline 

Alternative 1 

Alternative 2 

Alternative 3 

Alternative 4 

33.9 

19.6 

18.5 

7.7 

7.3 

463.1 

468.5 

468.8 

491.2 

491.6 

378 

370 

1,073 

1,071 

273 

2,074 

1,000 

5 

5 

5 

48 

48e 

5 

5 

5 

47 

47 

51 

51 

51 

129 

130 

325 

324 

324 

330 

326 

ro 

LO Based on Fuel Price Scenario 2 (see Table 9) . 

Metric units can be attained by the following conversions: 

1,000 Mg/yr = 1,000 tons/yr « 0.9075 

$/Mg = $/ton « 1.1023 

Trillion J/yr = trillio n B±u/yr * 1054.185 

Million fT/yr = million ftr/y r • 0.02832 

cCompared to Regulatory Baseline. 

Compared to less stringent alternative. 

®The amount of natural gas fired under this alternative is estimated at 765 million ft /yr or 0.8 trillio n Btu/yr. 

£ 
P.25 

an average cost effectiveness of $408/Mg ($370/ton). The incremental cost 

effectiveness of Regulatory Alternative 2 over Regulatory Alternative 1 is 

$301/Mg ($273/ton). 

Under Regulatory Alternative 3, annualized costs would be $491.2 

million per year and annual emissions would be reduced to 7,000 Mg/yr (7,700 

tons per year). Under Regulatory Alternative 4, annualized costs would be 

$491.6 million per year with annual S02 emissions of only 6,600 Mg/yr (7,300 

tons per year). 

The average cost effectiveness of Regulatory Alternatives 3 and 4 are 

$1,183/Mg and $1,181/Mg ($l,073/ton and $l,071/ton), respectively. The 

incremental cost effectiveness of Regulatory Alternative 3 over ReguTatory 

Alternative 2 is $2,286/Mg ($l,074/ton). The incremental cost effectiveness 

of Regulatory Alternative 4 over Regulatory Alternative 3 is $1,102/Mg 

($l,000/ton). The difference between Regulatory Alternatives 3 and 4 1s 

that a percent reduction requirement applies to model boilers below 73 MW 

(250 million Btu/hr) 1n the latter, but not 1n the former alternative. As 

shown in Tables 10, 11, and 12, the model boilers in this size range [I.e., 

44 MW (150 million Btu/hr)] will fire a natural gas/nonfossil fuel mixture 

in response to a percent reduction requirement. Although annualized costs 

increase slightly between Regulatory Alternatives 3 and 4, the emission 

reductions which accompany fuel switching to natural gas results in a lower 

incremental cost effectiveness for Alternative 4 over Alternative 3 compared 

to the cost effectiveness of Alternative 3 over Alternative 2 (where no fuel 

switching to natural gas firing occurs). 

The amount of fossil fuel fired on an annual basis compared to the 

rated annual heat Input capacity for a particular boiler 1s referred to as 

the fossil fuel utilization factor. Table 15 summarizes national impacts as 

a function of fossil fuel utilization factor, consistent with the 

Reference 4 analysis. 

The impacts associated with the regulatory baseline in Table 15 are the 

same as those in Table 14 -- the annualized costs for the projected national 

5-year population of new mixed fuel-fired boilers are $463.1 million per 

year and the annual SO- emissions are about 30,800 Mg/yr (33,900 tons per 

24 
TABLE 15. MIXED FUEL-FIRED STEAM GENERATING UNIT NATIONAL IMPACTS AS A FUNCTION OF 

FOSSIL FUEL UTILIZATION FACTOR BASED ON 1986 PRICE PROJECTIONS9 

Alternative 

Annual Emissions 

(1,000 tons/yr)c 

Annualized 

Costs 

($ million) 

463.1 

468.8 

Average Cost 

Effectiveness 

($/ton)3'

e 

370 

Incremental Cost 

Effectiveness 

($/ton)d'

f 

429 

ro 

(ji 

Basellne 

(2.5/1.2 lb S02/m1ll1on Btu) 

Low Sulfur Fuel 

(1.2 lb S02/m1ll1on Btu) 

Percent Reduction for 

Fossil Fuel Utilization 

Factors >0.30D 

Percent Reduction for 

Fossil Fuel Utilization 

Factors >0.12b 

Percent Reduction 

33.9 

18.5 

12.3 

10.2 

7.3 

479.8 

482.6 

491.6 

773 

823 

1,071 

1,774 

1,333 

3,103 

aBasel1ne requires 2.5 lb S02/m1ll1on Btu emission Um1t for model boilers less than or equal to 250 

million Btu/hr heat Input and a 1.2 lb S02/m1ll1on Btu limit for model boilers greater than 

250 million Btu/hr heat Input. 

bSteam generating units with fossil fuel utilization factors at or below the specified cutoff are 

not required to achieve a percent reduction 1n S02 emissions but must meet an emission limit of 

1.2 lb S02/m1ll1on Btu. 

cMult1ply 1,000 tons/year by 0.9075 to convert to 1,000 Mg/yr. 

dMult1ply $/ton by 1.1023 to convert to $/Mg. 

'Compared to regulatory baseUne. 

^Over next less stringent alternative. 

9Based on Fuel Price Scenario 2. (See Table 9) 
P.27 

year). For a low sulfur fuel standard applied to all mixed fuel-fired 

units, annualized costs would be $468.8 million per year and annual SOemissions would be reduced to 16,800 Mg/yr (18,500 tons per year). The 

average cost effectiveness of the low sulfur fuel standard over the 

regulatory baseline is $408/Mg ($370/ton), which is the same as the 

incremental cost effectiveness for this standard. 

The next alternative considered in Table 15 applies the percent 

reduction requirement to units with fossil fuel utilization factors greater 

than 0.30; this effectively means the units firing an 80 percent coal/20 

percent nonfossil fuel mixture since the overall capacity utilization factor 

for these model boilers is 0.60. All of these units will use an FGD system 

and fire high sulfur coal in response to a percent reduction requirement. 

The national annualized costs for this alternative would increase to $479.8 

million per year and annual emissions would be reduced to 11,200 Mg/yr 

(12,300 tons per year). The average cost effectiveness of this alternative 

is $852/Mg ($773/ton) while the incremental cost effectiveness of this 

alternative over the low sulfur fuel alternative is $1,955/Mg ($l,774/ton). 

The third alternative Usted in Table 15 applies percent reduction to 

units with fossil fuel utilization factors above 0.12 (I.e., model boilers 

firing either a 50/50 or 80/20 coal/nonfossil fuel mixture). Tables 10 to 

12 show that all of these model units will use an FGD system and fire high 

sulfur coal in response to a percent reduction requirement. The annualized 

costs for this alternative would increase to $482.6 million per year and the 

annual emissions would be reduced to 9,300 Mg/yr (10,200 tons per year). 

This corresponds to an average cost effectiveness for this standard of 

$907/Mg ($823/ton) and an incremental cost effectiveness of $1,469/Mg 

($l,333/ton) for this alternative over the alternative requiring percent 

reduction for units with fossil fuel utilization factors above 0.30. 

The final alternative listed in Table 15 requires a percent reduction 

in emissions for all mixed fuel-fired boilers irrespective of their fossil 

fuel utilization factor. Tables 10 to 12 show that all model boilers 

evaluated will use an FGD system with high sulfur coal 1n response to this 

requirement except small (i.e., 44 MW) units with low (I.e., 20/80) 

26 
coal to nonfossil fuel ratio; for these units natural gas/nonfossil fuel 

firing is more economically attractive. The annualized costs under this 

last alternative would increase to $491.6 million per year and annual 

emissions would be reduced to 6,600 Mg/yr (7,300 tons per year), for an 

average cost effectiveness of $1,181/Mg ($l,071/ton). The incremental cost 

effectiveness of this last alternative over the alternative requiring 

percent reduction for units with fossil fuel utilization factors above 0.12 

is $3,420/Mg ($3,103/ton). 

In considering the national impacts of regulatory alternatives under 

1986 fuel price projections, it is important to remember that the impacts 

discussed above are for Scenario 2. The national impacts of these same 

regulatory alternatives under Scenario 7 are estimated at zero since no 

mixed fuel-fired boilers are projected under this scenario. The national 

impacts of the other fuel price scenarios listed in Table 9 will fall 

between zero and the impacts projected for Scenario 2. 

3.2 Sensitivity of National Impacts to Fuel Price Projections 

Table 16 compares the/national cost and emission impacts of the Table 4 

regulatory alternatives under the 1984 and 1986 fuel price projections. The 

table shows a significant decrease in SO- emission levels at the regulatory 

baseline under the revised analysis due to the change from a 1076 ng S0-/J 

(2.5 lb S02/million Btu) limit to a 516 ng S02/J (1.2 lb S02/m1llion Btu) 

limit for boilers with heat input capacities greater than 73 MW (250 million 

Btu/hr). The SO- emission levels under 1986 prices are slightly lower for 

Alternatives 1 and 2 than under 1984 prices due to the use of an FGD system 

with Type E-sub coal in Region X for both the 117 and 234 MW (400 and 800 

million Btu/hr) model boilers which fire an 80 percent coal/20 percent 

nonfossil fuel mixture. Annual emissions for Alternative 3 decline under 

1986 prices compared to 1984 prices due to the use of a lower sulfur content 

coal, Type F, for the percent reduction requirement in Region I as compared 

to Type G coal. For the 1986 price projections, Type F coal is available at 

a lower cost than Type G coal in this region even though its sulfur content 

27 
TABLE 16. COMPARISON OF NATIONAL IMPACTS AS ESTIMATED WITH 1984 AND 1986 FUEL PRICE PROJECTIONS 

ro 

oo 

Regulatory 

Alternative 

Baseline 

Alternative 1 

Alternative 2 

Alternative 3 

Alternative 4 

1986 Fuel Price Projectl 

Annual 

SO- Emissions 

(1,000 tons/yr) 

0 - 33.9 

0 - 19.6 ' 

0 - 18.5 

0 - 7.7 

0 - 7.3 

Annualized 

Costs 

($ million/yr) 

0 - 463.1 

0 - 468.5 

0 - 468.8 

0 - 491.2 

0 - 491.6 

ons 

Cost 

Incremental 

Effectiveness 

(S/tons) 

— 

0 - 378 

0 - 273 

0 - 2,074 

0 - 1,000 

Annual 

S0_ Emiss 

(1,000 ton 

69.1 

24.3 

23.2 

8.2 

7.9 

ions 

s/yr) 

1984 Fuel Price Projections0 

Annualized 

Costs 

($ million/yr) 

424.8 

445.9 

446.3 

470.0 

471.6 

Incremental . 

Cost Effectiveness 

($/ton) 

~ 

471 

364 

1,580 

5,333 

**Metr1c units can be attained by the following conversions: 

1,000 Mg/yr = 1.000 tons/yr • 0.9075 

$/Mg = $/ton * 1.1023 

Trillion 1/yr = trillion Btu/yr *> 1054.185 

Million MVy r = million ftVyr * 0.02832 

Based on Fuel Price Scenario 7 (minimum Impact) and Scenario 2 (maximum impact) (see Table 9). 

""Reference 4 national impacts. 

Compared to next less stringent alternative. 
P.30 

is also lower. In addition to this effect, the fuel switching from 

coal/nonfossil fuel to natural gas/nonfossil fuel that occurs under 

Alternative 4 with the 1986 fuel prices acts to reduce emissions below the 

levels estimated with 1984 prices. 

Table 16 also shows that the incremental CE values associated with the 

1986 fuel price projections and Alternatives 1, 2, and 3 are similar in 

magnitude to those based on previous projections. The only incremental CE 

value to change significantly as a result of revisions to fuel price 

projections is that for Alternative 4. Under 1984 fuel price projections, 

the incremental CE of Alternative 4 relative to Alternative 3 was $5,879/Mg 

($5,333/ton); this same value 1s $1,102/Mg ($l,000/ton) under 1986 prices. 

This change is due primarily to the fuel switching that occurs among the 

44 MW (150 million Btu/hr) model boilers in response to the percent 

reduction requirement. The result of the fuel switch from the 

coal/nonfossil mixture to the natural gas/nonfossil mixture is to increase 

costs slightly while reducing SO- emissions for these units to zero. As a 

result, the national incremental CE value declines. However, it is 

important to recognize that the incremental CE value for Alternative 4 

represents the ratio of small differences among large numbers for both costs 

and emissions; minor changes can have a large impact on the calculated 

value. 

Finally, Table 17 compares the national impacts as a function of fossil 

fuel utilization factor under the 1984 and 1986 fuel price projections. The 

same trends are evident in this table as discussed above for Table 16. The 

national impacts for all alternatives except the last one in the table are 

similar in magnitude. For the last alternative, which requires a percent 

reduction for all mixed fuel-fired boilers and 1s equivalent to 

Alternative 4 in Table 16, the incremental CE under 1986 fuel price 

projections is significantly lower than under 1984 projections. The reason 

for this change, as discussed above, is the fuel switching that occurs among 

boilers firing 20 percent fossil/80 percent nonfossil fuel mixtures in 

response to the percent reduction requirement. 

29 
TABLE 17. COMPARISON OF NATIONAL IMPACTS AS A FUNCTION OF FOSSIL FUEL UTILIZATION FACTOR FOR 1984 AND 1986 PRICE PROJECTIONS 

Alternative 

1986 Fuel Price Projections f 

Annual Emissions 

(1.000 tons/year)c 

Annualized Costs 

(S million) 

Incremental Cost 

Effectiveness 

(J ton)* .e 

1984 Fuel Price Projections 

Annual Emissions 

(1,000 tons/year)c 

AnnualIzed Costs 

(S million) 

Incremental Cost 

Effectiveness 

($ ton)f ,e 

BaselIne 

(2.5/1.2 lb S02/m1111on Btu) 

Low Sulfur Fuel 

(1.2 lb S02/mill1on Btu) 

Percent Reduction for 

Fossil Fuel Utilization 

Factors >0.30b 

0 - 33.9° 

0 - 18.5 

0 - 12.3 

0 - 463.1 

0 - 468.8 

0 - 479.8 

0 - 429 

0 - 1.774 

69.1 

23.2 

12.7 

424.8 

446.3 

457.2 

470 

1,040 

O 

Percent Reduction for 

Fossil Fuel Utilization 

Factors >0.12D 

Percent Reduction 

0 - 10.2 

0 - 7.3 

0 - 482.6 

0 - 491.6 

0 - 1,333 

0 - 3,103 

10.7 

7.9 

460.2 

471.6 

1,460 

4,150 

Baseline requires 2.5 lb S0_/m1ll1on Btu emission limit for model SGUs less than or equal to 250 million Btu/hr heat Input and 1.2 lb 

SO /million Btu limit for model SGUs greater than 250 million Btu/hr heat Input. 

Steam generating units with fossil fuel utilization factors at or below the specified cutoff are not required to achieve a percent 

reduction in S0_ emissions but must meet an emission limit of 1.2 lb SO^/mllllon Btu. 

cMult1ply 1,000 tons/year by 0.9075 to convert to 1,000 Mg/Yr. 

dMult1ply $/ton by 1.1023 to convert to $/Mg. 

e0ver next less stringent alternative. 

Based on Fuel Price Scenario 7 (minimum impact) and Scenario 2 (maximum Impact) (see Table 9). 

-D 
P.32 

^ 

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 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. Analysis of Costs and Cost Effectiveness of S0« 

Control for Mixed Fuel-Fired Steam Generating Units. Prepared for The 

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

North Carolina. Publication No. EPA-450/8-86-001. June 1986. 64 p. 

5. Energy and Environmental Analysis, Inc. Description of the Industrial 

Fuel Choice Analysis Model. Prepared for the U. S. Environmental 

Protection Agency. Research Triangle Park, North Carolina. Contract 

Number 68-02-4202. May 1985. 79 p. 

6. Radian Corporation. Background Information Document for Nonfossil Fuel 

Fired Boilers. Prepared for the U. S. Environmental Protection Agency. 

Research Triangle Park, North Carolina. Publication No. EPA-450/3-82-007. 

March 1982. p. 6-12. 

7. Code of Federal Regulations (July 1, 1986 Edition). Title 40, Part 60. 

Washington, D.C. July 1986. pp. 226 to 246. 

8. Economic Indicators. Chemical Engineering. 9_3_ (16): August 18, 1986, 

p. 7. 

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

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

1985 update. 

10. Energy and Environmental Analysis, Inc. Development of Revised 

Industrial 011 and Gas Price Forecasts for the Industrial Boiler S02 

NSPS Analysis. Prepared for the U. S. Environmental Protection Agency. 

Research Triangle Park, North Carolina. August 1986. 31 p. 

11. Energy and Environmental Analysis, Inc. Regional Projections of 

Industrial Fuel Prices. Prepared for the U. S. Environmental 

Protection Agency. Research Triangle Park, North Carolina. 

August 14, 1986. 

31 
P.33 

APPENDIX A 

METHODOLOGY FOR REVISING THE MIXED FUEL-FIRED BOILER 

NATIONAL IMPACTS ANALYSIS TO INCORPORATE NEW FUEL PRICES 
P.34 

1.0 INTRODUCTION 

This Appendix discusses the differences in the approach and assumptions 

used in this analysis to estimate capital and non-fuel operating and 

maintenance costs for mixed fuel-fired boilers as compared with the 

Reference 4 analysis. These modifications were necessary to ensure that the 

costing methodologies used in this analysis were consistent with the 

methodologies used in other industrial boiler cost studies. Changes in fuel 

price projections are discussed in Section 1.2 of the memo. 

2.0 STEAM GENERATING UNIT COSTS 

2.1 Capital Costs 

The only change made in the methodology for estimating capital costs 

for boilers was to add costs for emission monitors (i.e., opacity, 02/C02, 

and SO, monitors) to the regulatory baseline and the low sulfur fuel c

 i 

alternative. As an oversight, these monitoring costs were not included in 

the Reference 4 analysis. 

2.2 Non-Fuel Operating and Maintenance Costs 

The equation used for estimating bottom ash disposal costs in Reference 

4 was changed to a small extent. Previously, the fossil/nonfossil fuel 

mixture properties were used in the fossil fuel cost algorithm to estimate 

waste disposal costs. This procedure underestimated the bottom ash 

generation rate for the mixture because of the non-linear nature of the 

equation. In the present analysis, the fossil fuel algorithm was used only 

for estimating bottom ash disposal costs for the fossil fuel component 

being fired. Nonfossil fuel bottom ash disposal costs were calculated by 

multiplying the nonfossil fuel bottom ash generation rate (based on model 

boiler information in Reference 6) by the ash disposal unit cost rate. The 

A-l 
P.35 

fossil and nonfossil fuel ash disposal costs were then summed to estimate 

the total bottom ash disposal costs. 

In addition to this change, two calculational omissions in Reference 4 

were noted during review. The first omission was that the costs for spare 

parts, electricity, chemicals, and water, which had been calculated from 

cost algorithms based on 1978 dollars, had not been updated to 1983 dollars. 

The second omission, as discussed above, was that costs for monitors had not 

been included in the baseline and low sulfur fuel alternative, although they 

were included in the percent reduction alternative. In this analysis, all 

costs were updated to June 1985 and costs for the monitors Usted above were 

included for all regulatory alternatives as appropriate. 

Finally, the model boiler regulatory baseline was modified from the 

baseline presented in Reference 4. The regulatory baseUne 1n the prior 

analysis was an emission limit of 1076 ng/J (2.5 lb/million Btu) for all 

model boilers. The regulatory baseline in this analysis has been revised to 

a 516 ng/J (1.2 lb/million Btu) emission limit for model boilers with heat 

input capacities above 73 MW (250 million Btu/hr); for units below this 

size, the higher emission limit still applies. 

2.3 Steam Generating Unit'Cost Impacts 

As a result of these changes, annualized costs for model boilers 

presented in this memorandum, are higher than those reported in Reference 4. 

In particular, the costs for boiler sizes greater than 73 MW (250 million 

Btu/hr) heat input at the regulatory baseline are higher since lower sulfur 

content, higher-priced coals are required to meet the 516 ng/J (1.2 

lb/million Btu) emission limit. As a result, the average cost effectiveness 

values for S0« regulatory alternatives relative to the baseline decline in 

this analysis relative to the Reference 4 analysis. On the other hand, the 

incremental cost effectiveness of S02 regulatory alternatives relative to 

each other are not affected since the changes apply equally to boiler costs 

for each alternative. 

Pt-2 
P.36 

3.0 PARTICULATE MATTER CONTROL COSTS 

3.1 Capital Costs 

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

fabric filters (applied to coal/nonfossil fuel-fired boilers) and venturi 

scrubbers (applied to oil/nonfossil fuel-fired boilers) was to base the 

costs on the flue gas flow rate of the fossil/nonfossil fuel mixture. This 

approach is not consistent with the approach used in other model boiler cost 

studies in which the control device is sized for worst-case (i.e., maximum 

fuel flexibility) design conditions. The maximum fuel-flexibility design 

conditions for a PM control device applied to a mixed fuel-fired boiler 

correspond to firing 100 percent nonfossil fuel since the flue gas flowrate 

for nonfossil fuels is higher than for fossil fuels. For this reason, the 

PM control costs in the present analysis are based on the combustion of 100 

percent nonfossil fuel. Capital costs for both fabric filters and venturi 

scrubbers increase as flue gas flow rate increases. 

3.2 Non-Fuel Operating and Maintenance Costs 

The methodology used in Reference 4 to calculate the non-fuel operating 

and maintenance (0&M) costs for PM control devices was not modified for this 

analysis. The controlled PM emission limits for mixed fuel-fired boilers 

were modified, however, to reflect recently promulgated regulations at 40 

CFR Part 60, Subpart Db. The following controlled PM emission limits were 

used in this analysis: 

o 43 ng/J (0.1 lb/million Btu) for mixed fuel- and oilfired boilers; 

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

A-3 
P.37 

3.3 PM Control Cost Impacts 

As a result of the capital cost changes discussed above, the annualized 

costs for PM control are higher 1n this analysis those reported in 

Reference 4. However, the prior analysis assumed controlled PM emission 

limits of 22 ng/J (0.05 lb/million Btu) for boilers firing all fuel types. 

By raising the PM emission limit to reflect the new Subpart Db regulations 

for mixed fuel-fired boilers, the annualized costs for fly ash disposal have 

decreased slightly from those reported in Reference 4. However, the cost 

effectiveness values for S02 regulatory alternatives do not change since PM 

control requirements are the same for both the SO- regulatory baseline and 

regulatory alternatives. 

4.0 S02 CONTROL COSTS 

4.1 Capital Costs 

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

gas desulfurization (FGD) systems applied to mixed fuel-fired boilers was 

modified to reflect worst-case, or maximum fuel flexiliblty, design 

conditions. As in the prior analysis, sodium scrubbing system costs are 

used to represent FGD costs. The prior analysis estimated the costs of the 

FGD system based on the flue gas flow rate and SO- loading generated by 

firing 100 percent fossil fuel. However, this does not reflect maximum fuel 

flexibility design conditions with respect to flue gas flow rate, as 

discussed above. The highest flue gas flow rate in a mixed fuel-fired 

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

loading occurs when 100 percent fossil fuel is fired. In the present 

analysis, the flue gas flow rate is specified based on 100 percent nonfossil 

fuel while the SO- processing rate is based on 100 percent fossil fuel. 

A-4 
4.2 Non-Fuel Operating and Maintenance Costs 

The methodology and assumptions used in calculating non-fuel O&M costs 

for FGD systems were not altered. However, upon review of the calculations 

used to generate the costs in Reference 4, it was noted that the costs of 

spare parts and S02 monitors had not been updated to January 1983 dollars 

from July 1978 dollars. Therefore, the S02 costs presented 1n Reference 4 

were slightly underestimated. These costs were update to June 1985 dollars 

in the present analysis. 

4.3 SO- Control Cost Impacts 

As a result of these changes, the annualized costs for FGD systems are 

higher than those estimated in Reference 4. Therefore, excluding other 

factors, the average and incremental cost effectiveness values for percent 

reduction alternatives relative to low sulfur fuel alternatives are also 

higher than those presented in Reference 4. 

A-5 
P.39 

APPENDIX B 

REVISED COST ALGORITHMS FOR MIXED FUEL-FIRED BOILERS 

AND ASSOCIATED EMISSION CONTROL EQUIPMENT 
TABLE B-l. NONMENCLATURE USED IN COST ALGORITHMS 

1. 

2. 

3. 

Caoital 

EQUP 

INST 

IND 

TK 

Costs 

= ' 

s 

= 

= 

Operation and 

DL 

SPRV 

MANT 

SP 

ELEC 

UC 

WTR 

SW 

LW 

SC 

Boiler 

= 

= 

= 

= 

= 

= 

= 

= 

O 

= 

Specif 

(1985 dollars) 

Equipment 

Installation 

Indirect (engineering, Field, Construction, Start-up, 

and other miscellaneous costs) 

Turnkey 

Maintenance Costs3 (1985 dollars/vear) 

Direct Labor 

Supervision Labor 

Maintenance Labor 

Spare Parts 

Electricity 

Utilities and Chemicals 

Water 

Solid Waste Disposal 

Liquid Waste Disposal 

Sodium Carbonate 

ications 

Q = Thermal Input (IO6 Btu/hr) {MW)b 

FLW = Flue Gas Flowrate (acfm) (nr/s) 

CF = Capacity Factor (-) 

4. Fuel Specifications 

FC = Fuel Cost ($/106 Btu) ($MJ)b 

H = Heating Value of Fossil/Non-Fossil mixture (Btu/lb) 

(KJ/kg)D 

S = Sulfur Content of Fossil/Non-Fossil mixture (percent by 

weight) 

A = Ash Content of Fossil/Non-Fossil mixture (percent by 

weight) 

N = Fuel Nitrogen Content (percent by weight) 

FF = Fossil Fuel Fraction 

AF = Ash Content of Fossil Fuel (percent by weighty 

HF = Heating Value of Fossil Fuel (Btu/lb) (KJ/kg)D 

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-l 
P.41 

TABLE B-l. NOMENCLATURE USED IN COST ALGORITHMS (CONTINUED) 

PM Control Specifications 

UNCPM 

CTRPM 

EFFPM 

Uncontrolled PM Emissions (lb/10° Btu) (ng/J)1 

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

PM Removal Efficiency (percent) 

7. Cost Rates (in January 1983 dollars) 

ELECR 

WTRR 

ALIME 

ALS 

SASH 

SLDG 

SWR 

LWD 

DLR 

SLR 

AMLR 

Electricity Rate-($/kw-hr) , . 

Water Rate ($/10J gal) ($/nT)D 

Lime Rate ($/ton) ($/kgr h 

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

 b 

Sodium Carbonate Rate ($/ton) ($/kgJr 

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

SoUd Waste Disposal Rate (S/tonl ($/kg)D - h 

Liquid Waste Disposal Rate ($/103 gal) ($/nr)D 

Direct Labor Rate ($/man-hr) 

Supervision Labor Rate ($/man-hr) 

Maintenance Labor Rate ($/man-hr) 

8. Miscellaneous 

DLM 

SLM 

MLM 

Sl 

S2 

LF 

Direct Labor Man-Hours (man-hours/sh1ft) 

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 (-) 

aCost 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.42 

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

FIRING FOSSIL/NONFOSSIL MIXTURES (IN JUNE 1985 DOLLARS)* 

Capital Costs 

TKb •» [11,785 (Q/358)0'

77 + 154.47*(1 -2*FF*Q)°*78 - 11,785* 

(1.2*FF*Q/358)°'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.43 

TABLE B-2. C0ST EQUATIONS FOR FIELD-ERECTED, WATERTUBE SPREADER-STOKER BOILER 

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

SP - ((50,000 + 1,000 Q)*(0.767)*[TK/(ll,785*(Q/358)°-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. 

bApplies 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. 

eApplies only to o1l/wood-f1red boilers. 

B-4 
P.44 

TABLE B-3. C0ST EQUATIONS FOR FABRIC FILTERS APPLIED TO MIXED FUEL-FIRED 

BOILERS 

(IN JUNE 1985 DOLLARS)* 

Routine Code: 

Caoital Costs:3 

EQUP 

INST 

IND 

Annual Costs: 

DL 

a 

SPRV 

* 

FF 

,b 

[8.340(FLW)0,966]*(1.44)(1.0295) 

[-1,405,523 + 168,531 ln (FLW)]*(1.44)*(1.0295) 

[24.990(FLW)°*821] (1.44)*(1.0295) 

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 

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)°'997](1.0347)(1.51) 

ELEC - [(CF/O.6)0.740(FLW)°-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) in capital cost equations is based on boiler firing 100 

percent nonfossil fuel. Flow rate (FLW) in annual cost equations is based on 

boiler firing the specific fossil/non-fossil mixture. 

B-5 
P.45 

,.» 

» 

» 

TABLE B-4. COST EQUATIONS FOR VENTURI SCRUBBERS APPLIED TO MIXED FUEL-FIRED 

BOILERS 

(IN JUNE 1985 DOLLARS) a 

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 -i- 1.285(FLW)](1.44)(1.0295) 

Annual Costs: 

DL - LF (10,150 + 106 Q) (OLR/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/0.6)(0.95*304.3*Q°'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) 

aCost equations are in English units. 

bFlow rate (FLW) 1s based on boiler firing 100 percent nonfossil fuel. 

B-6 
____m 

5 O „> 

TABLE B-5. COST EQUATIONS FOR SODIUM SCRUBBING FGD SYSTEMS (IN JUNE 1985 

DOLLARS)3 

Routine Code: SOD 

Capital Costs:b ,c 

TKS - [39,900(FLW)0'

585 + 1,370 (S2)0,727](1.0295) 

TKW - 26,500 S2°'39](1.0295) 

TK - TKS + TK^ 

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) 

ELECW - 8760*CF*ELECR[0.23(S2) + 1.32](1.0347) 

ELEC - ELECS + ELEC^ 

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) 

aCost equations are 1n metric units. 

bFlow rate (FLW) in Capital Cost equations is based on a boiler firing 100 

percent nonfossil fuel. Flow rate (FLW) in annual cost equations is based on 

a boiler firing the specified fossil/non-fossil mixture. 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. 

dThis 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