OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

324) IV-B-28 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:13:00 AM Sheet 324 of 325 
P.2 

' K RADIAN A - A 3 - 9 7 

CORPORATION J^**» ^ i '»• f I 

IV-B-28-

MEMORANDUM 

DATE: August 15, 1987 

TO: Walter H. Stevenson and Fred L. Porter, EPA/OAQPS/SDB 

FROM: David M. White, Radian Corporation 

SUBJ: Alternative Estimates of National Impacts Based on Steam Generating 

Unit Sales Data 

1.0 INTRODUCTION 

1.1 IFCAM 

At both proposal and promulgation, estimates of national economic and 

emission impacts associated with the sulfur dioxide (S02) NSPS for 

industrial-commercial-institutional steam generating units were based on 

1 2 projections made by the Industrial Fuel Choice Analysis Model (IFCAM). ' 

IFCAM is an energy demand model developed to evaluate industrial steam 

generating unit fuel choice decisions among coal, oil, and natural gas. The 

population of new industrial steam generating units is projected in IFCAM 

and then for each new steam generating unit the total cost of firing 

alternative fossil fuels, including the costs imposed by environmental 

regulations, is compared on an after-tax discounted cash flow basis over a 

15-year investment period. This allows IFCAM to select the lowest cost 

combination of fossil fuel and emission control system for each new steam 

generating unit. These results are then aggregated to yield five-year 

national projections of fossil fuel consumption, capital and annualized 

costs, sulfur dioxide emissions, and solid and liquid wastes generated in 

response to environmental regulations imposed on new steam generating units. 

The magnitude of the economic, environmental, and energy impacts 

projected by IFCAM in response to alternative regulations is a function of 

two major variables. These are the number of new fossil fuel-fired steam 

generating units and the type of fuel selected for each of these steam 

generating units. 
P.3 

The projected number of new industrial steam generating units is a 

function of the projected growth in industrial fossil fuel energy demand 

between 1985 and 1990 presented in "Annual Energy Outlook 1983," issued by 

the Department of Energy. Based on this total industrial energy demand, 

IFCAM projects fossil fuel use by new industrial steam generating units with 

a heat input capacity of more than 100 million Btu/hour over a five-year 

period to be about 498 trillion Btu/year. This compares to total industrial 

fossil fuel energy consumption in 1982 of about 17.3 quadrillion Btu, of 

which about 7.0 quadrillion Btu were consumed by existing industrial steam 

* 

generating units. Based on this projected fossil fuel energy demand, IFCAM 

projects construction of about 600 new coal-, oil- and gas-fired industrial 

steam generating units with a heat input capacity greater than 100 million 

Btu/hour. 

The type of fossil fuel selected (i.e., coal, oil, or gas) for each new 

steam generating unit in IFCAM is a function of fuel costs (i.e., projected 

prices for coal, oil, and natural gas), capital and non-fuel steam 

generating unit costs, and the costs imposed by regulations limiting S02 

emissions from combustion of coal or oil. Total annualized costs are 

calculated by IFCAM using (1) algorithms to estimate capital and operating 

costs for steam generating units of different sizes, fuel types, and 

capacity factors, and (2) recent fuel price forecasts for coal, oil, and 

natural gas in each of the ten Federal regions. Since IFCAM selects the 

lowest cost combination of fossil fuel and emissions control system for each 

new steam generating unit, a key feature of IFCAM is that it allows explicit 

evaluation of "fuel switching" from coal or oil to natural gas for 

compliance with alternative S02 emission standards. 

1.2 Alternative Methodology 

During the public comment period on the proposed regulation, several 

commenters stated that IFCAM overestimates both the number of new fossil 

fuel-fired steam generating units to be built and the number of these units 

that would fuel switch in response to an NSPS for S02 . Commenters suggested 

498 trillion Btu = 0.000498 quadrillion Btu. 
P.4 

fuel switching, as allowed by IFCAM, masks the true cost and costeffectiveness of the NSPS by selecting a less expensive control option (fuel 

switching) that shows more S02 emissions reduction than if post-combustion 

flue gas desulfurization (FGD) technology was applied. This memo addresses 

these comments by presenting results of an alternate analytical methodology 

for projecting the emissions reductions, costs, and cost-effectiveness of 

S 02 standards. 

The alternative methodology is less refined than IFCAM and is based on 

two key simplifying assumptions: (1) the same number and type of steam 

generating units built over the past five years will be built in the next 

five years; and (2) the same amount of coal, oil, and natural gas fired in 

new steam generating units built over the past five years will be fired in 

new steam generating units built in the next five years. Because of these 

assumptions, fuel switching from coal or oil to natural gas in response to 

S02 standards is not allowed to occur. Thus, a new steam generating unit 

projected to fire coal or oil in the absence of S02 standards, is projected 

to continue firing coal or oil following adoption of S02 standards, even if 

firing natural gas would have been less expensive. Finally, this 

alternative methodology does not consider region-specific cost data as is 

done in IFCAM. 

Alternative S02 standards addressed in this paper include: 

o Alternative A--no standard (emission limits of 2.5 lbs S02/million 

Btu for coal-fired units of less than 250 million Btu/hour heat input 

capacity, 1.2 lbs/million Btu for coal-fired units larger than 250 

million Btu/hour heat input capacity, and 3.0 lbs/million Btu for all 

oil-fired units are assumed), 

o Alternative B--establish an emission limit based on use of low sulfur 

fuels (equal to 1.2 lbs S02/million Btu for coal and 0.8 lbs/million 

Btu for oil), 

o Alternative C--establish an emission limit based on use of lower 

sulfur fuels (equal to 1.2 lbs S02/million Btu for coal and 0.3 

lbs/million Btu for oil), 
P.5 

o Alternative D--require use of 90 percent S02 removal technology for 

coal- and oil-fired units, but exempt from percent reduction units 

with an annual capacity factor of 30 percent or less (these units 

would be required to meet the emission limits in Alternative C), and 

o Alternative E--require use of 90 percent S02 removal technology for 

coal- and oil-fired units without any exemptions. 

2.0 FOSSIL FUEL-FIRED UNIT DATA SOURCES 

2.1 Steam Generating Unit Sales 

The alternate methodology assumes installations of fossil fuel-fired 

steam generating units during the next five years will be at the same rate 

as the past five years (i.e., 1982-1986). Historical data covering sales of 

industrial steam generating units firing coal, oil, and natural gas as their 

primary fuel during this period were provided by the American Boiler 

Manufacturers Association (ABMA). Summary statistics for these fuels by 

number of units and capacity are shown in Table 1. The sales data shows 

coal-fired units predominant with 44 percent of steam generating unit sales 

by number and 57 percent of steam generating unit capacity. Coal is 

followed by natural gas which represents 29 percent of the steam generating 

units by number and 21 percent of steam generating unit capacity. 

2.2 Unit Capacity Factors 

The ABMA sales data in Section 2.1 provides information on the number, 

size, and fuels fired in new steam generating units sold in the past five 

years. This data was supplemented with operating information from a recent 

3 * 

EPA survey to determine typical unit annual capacity factors. Because of 

the large range in coal-fired steam generating unit sizes covered by the 

survey (100-1,000 million Btu/hour heat input capacity), coal-fired units 

* Annual capacity factor - (Btu/yr of fossil fuel fired) 

(Btu/hr nameplate capacity) x (8760 hrs/year) 
P.6 

TABLE 1. STEAM GENERATING UNIT SALES STATISTICS FOR 1982-1986* 

No. of Units 

Total Capacity 

(billion Btu/hr) 

Average Unit Size 

(million Btu/hr) 

Percent of Units 

Percent of Capacity 

Coal 

98 

26.4 

270 

44.1 

57.1 

Oil 

60 

10.2 

171 

27.0 

22.1 

Gas 

64 

9.6 

149 

28.8 

20.8 

Total 

Fossil Fuel 

222 

46.2 

208 

100 

100 

* 

Based on ABMA sales data 

were divided into two subsets: small units (100-250 million Btu/hour heat 

input capacity) and large units (larger than 250 million Btu/hour). 

Oil-fired units are generally smaller than 250 million Btu/hour and were 

handled as a single size category. 

The capacity factor data for coal- and oil-fired units in each size 

category were aggregated into three capacity factor groupings: units with 

capacity factors of less than 30 percent, 30 to 45 percent, and greater than 

45 percent. The steam generating units exhibiting the highest capacity 

factor were large coal-fired units (>250 million Btu/hr) with an average 

capacity factor of 69 percent, followed by small coal-fired units (100-250 

million Btu/hr) with an average capacity factor of 64 percent, and oil-fired 

units with an average capacity factor of 38 percent. Average capacity 

factors within each of these fuel, size, and capacity factor categories are 

shown in Table 2. Because natural gas-fired units are not covered by the 

S 02 standard, capacity factor data for these units were not compiled. 
P.7 

TABLE 2. AVERAGE ANNUAL UNIT CAPACITY FACTOR (%) BY FUEL AND UNIT SIZE 

Fuel-Fired (Unit Size) 

Annual Capacity Factor Range (%) 

0-30 30-45 45-100 Overall 

Coal (100-250 million Btu/hr) 

Coal (>250 million Btu/hr) 

Oil (all sizes) 

9 37 74 

19 38 84 

12 33 62 

64 

69 

38 

* 3 

Based on Survey of New Industrial Boiler Projects. 

2.3 Annualized Costs and Emissions for Typical Units 

Estimates of annualized costs and emissions for individual units were 

taken from analyses of coal- and oil-fired steam generating units using 

4 

recent fuel price forecasts. Typical unit sizes used in the analysis were 

150 and 400 million Btu/hour heat input for coal-fired units and 150 million 

Btu/hour for oil-fired units. Region V was assumed to be representative of 

all ten EPA regions; therefore, cost and emission estimates were based on 

fuel quality and costs in Region V. 

3.0 METHODOLOGY FOR FOSSIL FUEL-FIRED UNITS 

3.1 Estimation of Steam Generating Unit Population 

The fossil fuel-fired steam generating unit population used by the 

alternative model was derived from the above data based on the total steam 

generating capacity in each of the subcategories defined by: 

o 

o 

steam generating unit size (100-250 and >250 million Btu/hour for 

coal, >100 million Btu/hour for oil), 

fuel type (coal and oil), and 

capacity factor (<30, 30-45, and >45 percent). 
P.8 

The projected coal-fired steam generating unit population was divided 

between small units (150 million Btu/hour) and large units (400 million 

Btu/hour) so as to have the average size of all coal-fired units equal the 

ABMA sales average of 270 million Btu/hour. The number of steam generating 

units in each category is based on the total generating capacity divided by 

typical unit size of the category. Table 3 shows the number of units and 

total steam generating capacity in each fuel, size, and capacity factor 

category used for the analysis. The total of 229 fossil fuel-fired units 

(97 coal, 68 oil, and 64 gas) used in the alternative analysis is less than 

half of the 604 new units projected by IFCAM. 

3.2 Estimation of Annualized Costs and Emissions for Individual Units 

The cost and emission data referenced in Section 2.3 were calculated 

using the Industrial Boiler Cost (IBCOST) algorithms for "typical" steam 

generating units operating at selected capacity factors. To simplify the 

calculation of costs and emissions at other capacity factors, the cost and 

emissions estimates obtained from IBCOST for typical coal- and oil-fired 

units were converted into linear equations of the form y=mx+b. The 

resulting equations were then used to calculate a unit's total annual cost 

(y*) based on its capacity factor (x), variable cost (m*), and fixed cost 

(b*). Similarly, the unit's annual emissions (y ) were estimated based on 

its capacity factor (x) and emission rate (m ) ; because a unit has zero 

emissions when it is not operating (i.e., x=0 percent), the value of b is 

zero. The calculated value of b*, ITU, and m for each steam generating unit 

size and fuel and regulatory alternative are shown in Table 4. The 

resulting values of y* and y are in million dollars and tons of S02 per 

year. 

3.3 Estimation of National Annualized Costs and Emissions 

National annualized costs and emissions for a given regulatory 

alternative were calculated by combining the projected national steam 

generating unit population (Table 3), capacity factors (Table 2), and annual 
P.9 

TABLE 3. MODELED STEAM GENERATING UNIT STATISTICS 

No. of Units 

Total Capacity 

(million Btu/hr) 

Annual 

Capacity 

Factor(%) 

<30 

30-45 

>45 

All 

<30 

30-45 

>45 

All 

Small 

Coal 

Units 

5 

5 

43 

53 

750 

750 

6,450 

7,950 

Large 

Coal 

Units . 

4 

9 

31 

44 

1,600 

3,600 

12,400 

17,600 

All 

Coal 

Units 

9 

14 

74 

97 

2,350 

4,350 

18,850 

25,550 

All 

Oil 

Units 

24 

14 

30 

68 

3,600 

2,100 

4,500 

10,200 

TABLE 4. PARAMETER VALUES USED TO CALCULATE COST AND EMISSIONS 

Unit Size and Fuel 

150 MMBtu/hr Coal 

400 MMBtu/hr Coal 

150 MMBtu/hr Oil 

Regulatory 

Alternative 

2.5 

1.2 

FGD 

1.2 

FGD 

3.0 

0.8 

0.3 

FGD 

Cost 

b

$ 

3.205 

3.205 

3.717 

7.290 

8.007 

0.920 

0.920 

0.920 

1.380 

Parameters 

m $ 

0.04444 

0.04667 

0.04922 

0.12445 

0.12771 

0.04182 

0.04764 

0.05415 

0.04935 

Emissions 

me 

13.80 

7.10 

1.43 

16.82 

3.80 

21.31 

5.69 

2.13 

0.44 
P.10 

costs and emissions from individual steam generating units (Table 4). The 

formula for calculating cost for a single steam generating unit category is: 

Y* = n(m*x + b$) 

where: Y* = total annualized cost for all units in a category (million 

dollars per year), 

n = number of units in a category (from Table 3), 

nu = variable cost per unit (from Table 4) (million dollars/year - % 

capacity factor), 

x = capacity factor in percent (from Table 2), and 

b* = fixed cost per unit (from Table 4) (million dollars/year). 

The formula for calculating emissions for a single steam generating unit 

category is: 

Ye = n(mex) 

where: Y = total annualized emissions for all units in a category, and 

m = emission rate per unit (from Table 4) (ton S02/year - % capacity 

factor). 

The total national cost and emissions for all units are obtained by summing 

the totals for each category as follows. 

n n 

Cost = £ Yt. Emissions = £ Y . 

1=1

 $1 i= l ei 

4.0 ANALYSIS OF MIXED FUEL-FIRED UNITS 

IFCAM projects cost and emission impacts for only fossil fuel-fired 

steam generating units. To estimate the national impact of alternate NSPS 

on all steam generating units covered by the NSPS, a separate analysis of 
P.11 

fuel-fired unit analysis were then added to the IFCAM results to estimate 

total national impacts. 

The mixed fuel-fired unit impacts that were added to IFCAM results were 

based on estimates provided by the wood industry for units firing mixtures 

of wood and fossil fuels. Based on these data, it was estimated that 35 

mixed fuel-fired units would be built. The fuel mixtures in these units 

range from 20 percent nonfossil fuel/80 percent fossil fuel to 80 percent 

nonfossil fuel/20 percent fossil fuel. 

Consistent with the alternative analysis of fossil fuel-fired units 

discussed above, recent sales data on mixed fuel-fired units were also 

examined. Review of data from ABMA and the EPA Boiler Replacement Survey 

identified ten wood/coal-fired units ordered between 1981 and 1985. The 

percent wood fired in these units ranged from 6 to 80 percent. Review of 

data on wood/oil-fired boilers indicated that these units use very little 

oil; therefore, these units were dropped from further analysis. 

For use in the alternative analysis, the ten wood/coal-fired units were 

subdivided into two size and three capacity factor categories as shown in 

Table 5 based on available data and subjective judgment. Because the 

average capacity factors used in the alternative analysis were the same as 

those used in the recent review of mixed fuel-fired units, costs and 

emissions for each size and capacity factor category were taken directly 

from this recent review of mixed fuel-fired units (i.e., use of linear 

equations was not required). 

TABLE 5. DISTRIBUTION OF MIXED FUEL-FIRED UNITS BY SIZE AND CAPACITY FACTOR 

-

No. of Units 

Annual 

Fossil Fuel 

Capacity 

Factor 

Range (%) 

<30 

30-45 

>45 

Average 

Annual 

Fossil Fuel 

Capacity 

Factor (%) 

12 

30 

48 

Number 

Small Units 

150 MMBtu/hr 

2 

2 

1 

of Units 

Large Units 

400 MMBtu/hr 

1 

2 

2 

10 
P.12 

5.0 CALCULATION OF NATIONAL IMPACTS 

The alternative methodology previously discussed for fossil fuel-fired 

and mixed fuel-fired units were added together and used to estimate national 

impacts associated with alternative regulatory standards. To reduce 

calculating time, the data and equations for both fossil- and mixed 

fuel-fired units were entered into a computerized spreadsheet program. A 

set of decision commands were inserted into the spreadsheet to allow 

automatic recalculation of cost and emission totals under alternate 

regulatory options. The input listing to the spreadsheet for Alternative D 

is shown in Table 6. 

The output from the computerized spreadsheet is a listing of summary 

statistics detailing the total number of units, steam generating capacity, 

Btu fired, average capacity factor, annualized cost, annual emissions, and 

annual waste disposal quantities for each fuel type. The costs and 

emissions for all fuels are then totaled to calculate national impacts. A 

sample output for Alternative D is presented in Table 7. 

The national impacts estimated for each of the five regulatory 

alternatives were then tallied in a separate spreadsheet to calculate 

average and incremental cost effectiveness values for each alternative. The 

resulting estimates of national costs, emission reductions, average CE 

values, and incremental CE values for fossil fuel- and mixed fuel-fired 

steam generating units separately and in combination are presented in 

Table 8. 

11 
TABLE 6. INPUT VALUES USED IN NATIONAL IMPACT ANALYSIS BASED ON BOILER SALES (Alternative D) 

BOILE R DISTRIBUTIO N DAT A 

Type LSO= 0.3 dist CF Cutoff= 30 

Case ID 

C-150CV) 

C-150CV) 

C-150(V) 

C-400CV) 

C-400(V) 

C-400(V) 

0-150(V) 

0-150(V) 

0-150(V) 

G-150(V) 

G-150(V) 

G-150(V) 

M-150(V) 

M-150(V) 

M-150(V) 

M-400(V) 

M-400(V) 

M-400(V) 

TOTAL 

Fossil 

MFF 

# Units 

5 

5 

43 

4 

9 

31 

24 

14 

30 

64 

0 

0 

2 

2 

1 

1 

2 

2 

239 

229 

10 

Total 

Capacity 

750 

750 

6450 

1600 

3600 

12400 

3600 

2100 

4500 

9600 

0 

0 

300 

300 

150 

400 

800 

800 

48100 

45350 

2750 

Avg 

CF 

9 

37 

74 

19 

38 

84 

12 

33 

62 

0 

35 

65 

12 

30 

48 

12 

30 

48 

MMMBtu 

Flred/Yr 

591 

2431 

41811 

2663 

11984 

91244 

3784 

6071 

24440 

0 

0 

0 

315 

788 

631 

420 

2102 

3364 

192641 

185020 

7621 

Cost 

Basel1ne 

18 

24 

279 

39 

108 

550 

34 

32 

105 

0 

0 

0 

6 

10 

6 

9 

22 

26 

1269 

1190 

79 

(mil $/yr) 

LSF 

18 

0 

0 

39 

0 

0 

38 

0 

0 

0 

0 

0 

8 

10 

0 

9 

22 

0 

143 

94 

48 

FGD 

0 

28 

316 

0 

116 

581 

0 

42 

133 

0 

0 

0 

0 

0 

6 

0 

0 

28 

1250 

1216 

34 

Emissions 

BaselIne 

621 

2553 

43912 

1278 

5751 

43791 

6137 

9845 

39635 

0 

0 

0 

874 

1636 

899 

1165 

1524 

1598 

161218 

153522 

7696 

(tons S02/y 

LSF 

320 

0 

0 

1278 

0 

0 

613 

0 

0 

0 

0 

0 

150 

374 

0 

200 

998 

0 

3932 

2210 

1722 

r) 

FGD 

0 

265 

4561 

0 

1300 

9895 

0 

202 

812 

0 

0 

0 

0 

0 

140 

0 

0 

746 

17920 

17034 

886 
P.14 

TABLE 7. OUTPUT STATISTICS FROM NATIONAL IMPACT ANALYSIS BASED ON BOILER SALES (Alternative D) 

SUMMAR Y STATISTIC S 

Total Mixed 

ALL UNITS Coal 011 Gas Fossil Fuel Total 

Number of Units 97 68 64 229 10 239 

% of Fossil Units 42.4X 29.7X 27.9X 100.OX 

Total Capacity (MMBtu/hr) 25550 10200 9600 45350 2750 48100 

X of Fossil Capacity 56.3X 22.5X 21.2X 100.OX 

Btu Fired (MMMBtu/yr) 150725 34295 0 185020 7621 192641 

X of Fossil Btu 81.5X 18.5X O.OX 100.OX 

Average Capactly Factor 

UNITS SUBJECT TO PERCENT REDUCTION 

67.3X 38.4% O.OX 46.6X 31.6% 45.7% 

Number of Units 

X of Category 

Total Capacity (MMBtu/hr) 

X of Category 

Btu Fired (MMMBtu/yr) 

X of Category 

88 

90.7X 

23200 

90.8X 

147470 

97.8X 

44 

64.7X 

6600 

64.7X 

30511 

89. OX 

0 

O.OX 

0 

O.OX 

0 

O.OX 

132 

57.6X 

29800 

65.7X 

177981 

96.2% 

3 

30.OX 

950 

34.5X 

3995 

52.4% 

135 

56.5X 

30750 

63.9X 

181976 

94.5% 

Average Capactly Factor 72.6X 52.8X O.OX 68.2% 48.OX 67.6X 

Total Cost (mil $/yr) 

BaselIne 

Controlled 

Total Emissions (tons S02/yr) 

Basel1ne 

Controlled 

Waste Disposal Quantities 

English Units 

Metric Units 

Cost (mil J/yr) 

1018 

1097 

97906 

17618 

tons/Mg K 

661057 

602729 

NATIO N 

Emissions (tons S02/yr) 

Cost Effectiveness (S/ton S02) 

(Average CE versus Baseline) 

172 

213 

55617 

1626 

gal/cu m 

12817 

361219 

A L T 

Fossil 

MFF 

Total 

Fossil 

MFF 

Total 

Fossil 

MFF 

Total 

0 

0 

0 

0 

OTA L 

Baseline 

1190.05 

78.90 

1268.95 

153522 

7696 

161218 

1190 

1310 

153522 

19244 

Control 1ed 

1310.38 

82.29 

1392.67 

19244 

2608 

21852 

79 

82 

7696 

2608 

Delta 

120.33 

3.39 

123.72 

-134278 

-5088 

-139366 

896 

666 

888 

1269 

1393 

161218 

21852 

13 
P.15 

TABLE 8. NATIONAL IMPACTS BASED ON BOILER SALES ANALYSIS 

COAL- AND OILAlternative 

A-No Change 

B-l.2/0.8 

C-1.2/0.3 

D-90% w/ Exc 

E-90% No Exc 

-FIRED BOILERS 

Cost 

(mil $) 

1190.05 

1212.85 

1229.84 

1310.38 

1325.83 

ElT isslons 

.(tons) 

153522 

89898 

80597 

19244 

17513 

Avg CE 

($/ton) 

_-

358 

546 

896 

998 

Inc CE 

($/ton) 

__ 

--

1827 

1313 

8925 

MIXED FUEL-FIRED BOILERS 

Alternative 

A-No Change 

B-l.2/0.8 

C-1.2/0.3 

D-90% w/ Exc 

E-90% No Exc 

ALL BOILERS 

Alternative 

A-No Change 

B-l.2/0.8 

C-1.2/0.3 

D-90% ml Exc 

E-90% No Exc 

Cost 

(mil $) 

78.90 

79.55 

79.55 

82.29 

86.17 

Cost 

(mil $) 

1268.95 

1292.40 

1309.39 

1392.67 

1412.00 

Emissions 

(tons) 

7696 

3620 

3620 

2608 

1689 

Emissions 

(tons) 

161218 

93518 

84217 

21852 

19202 

Avg CE 

($/ton) 

--

159 

159 

666 

1210 

Avg CE 

($/ton) 

— 

346 

525 

888 

1007 

Inc CE 

($/ton) 

—— 

— 

0 

2708 

4222 

Inc CE 

($/ton) 

— 

— 

1827 

1335 

7294 

14 
P.16 

-I 

6.0 REFERENCES 

1. Energy and Environmental Analysis, Inc. Projected Impacts of 

Alternative Sulfur Dioxide New Source Performance Standards for 

Industrial Fossil Fuel-Fird Boilers. Prepared for the U.S. 

Environmental Protection Agency, Office of Air Quality Planning and 

Standards. March 1985. 

2. Energy and Environmental Analysis, Inc. Revised Impacts of Alternative 

Sulfur Dioxide New Source Performance Standards for Industrial Fossil 

Fuel-Fired Boilers. Prepared for the U.S. Environmental Protection 

Agency, Office of Air Quality Planning and Standards. February 1987. 

3. U.S. Environmental Protection Agency. Survey of New Industrial Boiler 

Projects -- 1981-1984. Office of Air Quality Planning and Standards. 

Publication No. EPA-450/3-87-006. April 1987. 

4. Memorandum from Martinez. J. and E. Aul, Radian Corporation, to F. L. 

Porter and W. H. Stevenson, EPA/SDB. May 15, 1987. Assumptions and 

Procedures Used to Generate Model Boiler Impacts. 

5. Radian Corporation. Industrial Boiler S02 Cost Report. Prepared for 

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

Publication No. EPA-450/3-85-011. November 1984. 

6. Memorandum from Stackhouse, C. and E. Aul, Radian Corporation, to W. H. 

Stevenson and F. L. Porter, EPA/SDB. April 15, 1987. Impacts of New 

Fuel Prices on the National Impacts Analysis for Mixed Fuel-Fired Steam 

Generating Units. 

7. Radian Corporation. Analysis of Costs and Cost Effectiveness of S02 

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

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

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

15