p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

4) ll-K- (A)-17 

Docket Number: 

A-83-27 

Printed 11/12/200811:12:48 AM Sheet 4 of 325 
r » ,» A-83-27 

II-K-CA)-17 

PROJECTED ENVIRONMENTAL, COST AND ENERGY 

IMPACTS OF ALTERNATIVE S02 NSPS FOR 

INDUSTRIAL FOSSIL FUEL-FIRED BOILERS 

Prepared for: 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

Prepared by: 

ENERGY AND ENVIRONMENTAL ANALYSIS, INC. 

1655 North Fort Myer Drive 

Arlington, Virginia 22209 

July 27, 1984 
P.3 

This report was prepared for the U.S. Environmental Protection Agency by 

Energy and Environmental Analysis, Inc., Arlington, Virginia, under 

Contract Number 68-02-3564. The opinions and conclusions presented in 

this report are those of the author and not necessarily those of the 

U.S. Environmental Protection Agency or the Federal Government. 

J 
P.4 

s J 

TABLE OF CONTENTS 

Page 

1. INTRODUCTION 1 

1.1 Scope 1 

1.2 Current and Alternative S02 NSPS 1 

1.3 Fuel Price Projections 3 

1.4 IFCAM Modifications: May/June 1984 7 

2. NATIONAL AND REGIONAL IMPACTS 7 

2.1 Environmental Impacts 14 

2.2 Cost Impacts 19 

2.3 Energy Impacts 21 

3. BOILER COST COMPARISONS 23 

Appendix A: Projections of Regional Coal Demand 26 

Appendix B: Projections of Regional Residual Fuel Oil Demand . . 35 
P.5 

LIST OF TABLES 

Pao_: 

1. Proposed PM NSPS for Industrial Fossil Fuel-Fired Boilers. . . 2 

2. Control of NO Emissions in New Industrial Fossil 

Fuel-Fired BoTlers 4 

3. Alternative S02 NSPS Air Emissions Regulations for 

Industrial Residual Fuel Oil-Fired Boilers 5 

4. Alternative S02 NSPS Air Emission Regulations for 

Industrial Coaf-Fired Boilers 6 

5. World Oil Price Forecasts 8 

6. Annualized Industrial Fuel Prices: Reference Case 9 

7. Annualized Industrial Fuel Prices: Higher Oil and Gas Prices. 12 

8. Projected S02 Emissions in 1990 from New Industrial 

Fossil Fuel-Fired Boilers by Size Category 15 

9. Projected S02 Emissions in 1990 From New Industrial 

Fossil Fuel-Fired Boilers by Region 16 

10. Projected Annualized Cost Increases by Size Category 20 

11. Projected Fuel Mix in 1990 in New Industrial Fossil 

Fuel-Fired Boilers 22 

12. Comparison of Industrial Boiler Costs 25 
P.6 

1. INTRODUCTION 

1.1 Scope 

This report presents the projected environmental, cost and energy 

impacts of alternative Federal sulfur dioxide (S02) emission standards 

(New Source Performance Standards {NSPS}) for new industrial fossil 

fuel-fired boilers. Projected national and regional effects are summarized. 

Current Federal and local S02 emission regulations are used as a 

regulatory baseline. Several alternative Federal S02 standards are 

analyzed and projected values of environmental, cost and energy parameters are compared with the projected parameter values for the regulatory baseline. 

This report is based upon results projected by the Industrial Fuel 

Choice Analysis Model (IFCAM), an energy demand model developed by 

Energy and Environmental Analysis, Inc. IFCAM has been used in this 

analysis to project five-year impacts of alternative S02 NSPS for new 

industrial fossil fuel-fired (coal, distillate and residual fuel oil and 

natural gas) boilers installed between 1985 and 1990. 

1.2 Current and Alternative SO,, NSPS 

Results are compared in this report for seven scenarios: a regulatory baseline and seven alternative national S02 emission standards. 

Federal and local particulate matter (PM) and nitrogen oxide (NO ) air 

A 

emission standards are held constant for all seven scenarios. 

Table 1 summarizes the Federal NSPS PM emission regulations assumptions. Local State Implementation Plan (SIP) PM emission regulations 

are applicable if they are lower than the values presented in Table 1. 

Although a separate regulation is presented in Table 1 for low capacity 

utilization rate coal-fired boilers, IFCAM does not project demand for 

coal in new low capacity utilization rate boilers. 

-1-
TABLE 1. PM NSPS ASSUMPTIONS FOR INDUSTRIAL 

FOSSIL FUEL-FIRED BOILERS 

Boiler PM emissions ceilings 

size class (lb/MMBtu) 

Fuel type (MMBtu/hr) <30% C.U.a >30% C.U.a 

Natural gas 

Distillate fuel oil >250 0.10b 0.10b 

Residual fuel oil >250 0.10b 0.10b 

Coal 100-250 0.20J; 0.05^ 

>250 0.05c 0.05c 

aC.U. -- capacity utilization rate. 

bCurrent NSPS, 40 CFR Part 60, Subpart D. 

Proposed NSPS, 49 FR 25103. 

-2-
P.8 

All new industrial fossil fuel-fired boilers are assumed in this 

analysis to employ one of two NO combustion modification techniques, 

A 

low excess air or staged combustion air (see Table 2). Low NO burners 

A 

were not simulated in this analysis. 

The regulatory baseline for S02 emissions from residual fuel oil 

combustion is 0.8 lb/MMBtu if the boiler size is greater than 250 

MMBtu/hr. This is the current S02 NSPS. For all seven alternative S02 

NSPS scenarios (Option Cases 1-7) "compliance" (unscrubbed) residual 

fuel oil types are available (see Table 3). Local S0? emission standards are applicable if they are lower than the "compliance fuels" 

values in Table 3. 

The regulatory baseline and alternative S02 NSPS for industrial 

coal-fired boilers are compared in Table 4. The Base Case S02 emission 

standard is the current NSPS. Scrubbing is required for all coal types 

on all new industrial coal-fired boilers in Option Cases 2, 3, 6 and 7. 

There are compliance coal types in IFCAM in all 10 Federal regions 

with respect to the Base Case and Option Cases 1, 4 and 5 S02 emission 

standards. Local SIP S0? emissions standards are applicable if they are 

lower than the "compliance fuels" values in Table 4. However, IFCAM may 

choose to scrub a non-compliance coal type in these scenarios because 

the total cost of burning the compliance coal type is not necessarily 

the least cost alternative on an after-tax net present value basis. 

Therefore, in some cases, IFCAM may choose scrubbers in the Base Case 

and Option Cases 1, 4 and 5. 

1.3 Fuel Price Projections 

The regional industrial oil, gas and coal price forecasts have been 

revised recently. There are two new forecasts of oil and gas prices 

and one new forecast of coal prices. The new coal price forecast was 

used with both of the new oil/gas price projections. 

-3-
TABLE 2. CONTROL OF NOx EMISSIONS IN NEW INDUSTRIAL 

FOSSIL FUEL-FIRED BOILERS 

P.9 

Fuel type 

Boiler 

size class 

(MMBtu/hr) 

NO emissions 

control technique 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Coal 

>100 

>100 

>100 

100-250 

>100 

Low excess air 

Low excess air 

Low excess aira 

Low excess air 

(spreader stokers) 

Staged combustion air 

(pulverized coal) 

Staged combustion air if the nitrogen content is greater than 0.35 

percent or if additional control is required by a SIP. 

-4-
TABLE 3. ALTERNATIVE S02 NSPS AIR EMISSIONS 

REGULATIONS FOR INDUSTRIAL RESIDUAL FUEL OIL-FIRED BOILERS 

Scenario 

Boiler 

size class 

(MMBtu/hr) 

Compliance 

fuels 

(% sulfur) 

Non-compliance 

Non-compliance fuels 

fuels: S02 emissions 

removal required ceiling 

(%) (lb S02/MMBtu) 

i 

tn 

i 

Base Case 

Option Cases 1 and 2 

Option Case 3 

Option Case 4 

Option Case 5 

Option Case 6 

Option Case 7 

>250 

>100 

>100 

100-250 

>250 

>100 

>100 

>100 

<.0.8 

<.0.8 

<.0.3 

£.1.6 

£.0.8 

£0.8 

<.0.3 

<0.3 

Variable 

>50 

70-90 

>50 

>50 

>.70 

>70 

90 

0.8 

0.9 

1.21 

0.9 

0.9 

0.5 

0.5 

0.6 

1.6 and 3.0 percent sulfur residual fuel oil types in IFCAM are scrubbed to comply with the current 

NSPS: 0.8 lb S02/MMBtu. 

30.6 lb S02/MMBtu "floor" or "lower cap." 
TABLE 4. ALTERNATIVE S 02 NSPS AIR EMISSIONS REGULATIONS 

FOR INDUSTRIAL COAL-FIRED BOILERS 

Boiler 

size class 

Scenario (MMBtu/hr) 

Base Cc 

Option 

Option 

• Option 

Option 

Option 

Option 

Option 

ise >250 

Case 1 >100 

Case 2 >100 

Case 3 >100 

Case 4 100-250 

>250 

Case 5 >100 

Case 6 >100 

Case 7 >100 

Thirty-day, rolling average. 

Scrub to comply with the current NSPS: 1.2 1b 

c 0.6 lb S02/MMBtu "floor" or "lower cap." 

i 

Compliance 

fuels 

(lb S02 /MMBtu)a 

<1.2 

<1.2 

— 

— 

<1.7 

<1.2 

<1.2 

— 

— 

S02/MMBtu (30-day, 

Non-compliance 

fuels: S02 

removal required 

.%) 

Variable5 

>_50 

^50 

70-90 

_50 

>_50 

>_70 

>70 

90 

rolling average). 

Non-compliance 

fuels 

emissions 

ceiling 

(lb S02/MMBtu) 

1.2 

0.9 

0.9 

1.2C 

0.9 

0.9 

0.5 

0.5 

0.6 
P.12 

Table 5 summarizes the two world oil price forecasts assumed for 

this analysis. Tables 6 and 7 illustrate the expected regional variability in projected annualized industrial fuel prices. 

1.4 IFCAM Modifications: May/June 1984 

1. Lime spray drying FGD systems availability estimate was revised 

from 95 percent to 90 percent. This raises the annual fuel costs 

and lowers the annual average S02 emission rate estimate because 

it is assumed that natural gas is burned when the scrubber is not 

available. 

2. Lime spray drying FGD systems are restricted only to low sulfur coals 

(ICF coal types B and D, less than 1.67 lb S02/MMBtu). They are not 

a control option for medium and high sulfur coal types regardless of 

the required sulfur removal rate. Previously, this technology was 

applicable to all coal types. 

3. The sodium throwaway (NATH) scrubber capital and annual O&M cost 

algorithms have been revised by Radian Corporation. 

4. "Interest during construction" (IDC) estimates have been added to 

the aggregate annualized cost output tables. Previously, IDC had 

not been estimated. The IDC estimates range from 3.3 to 13.6 percent of total capital costs. 

5. ICF coal type A (<0.8 lb S02/MMBtu) has been deleted in all regions. 

Two new subbituminous coal types were added in Federal regions 5 

(Midwest), 6 (Southwest) and 9 (West). 

2. NATIONAL AND REGIONAL IMPACTS 

This section summarizes the IFCAM projections of the national and 

regional impacts of the alternative S02 emissions control levels described in Section 1.2. The tables in this section present aggregate 

results for all new industrial fossil fuel-fired boilers larger than 100 

MMBtu/hr installed between 1985 and 1990, including natural gas, residual 

fuel oil and coal boilers. The air emissions and fuel demand forecasts 

are for calendar year 1990. 

-7-
P.13 

TABLE 5. WORLD OIL PRICE FORECASTS 

(1982 $/bbl) 

Year 

1985 

1990 

1995 

2000 

Average annual 

refiner acquisition 

of imported crude 

Reference 

case9 

25 

28 

32 

37 

ai 

cost 

oil 

Higher oil 

id gas prices 

25.90 

31.90 

46.50 

57.40 

aEnergy and Environmental Analysis, Inc. 

DOE/OPPA's mid-range projections (Scenario B - Reference Case) from 

NEPP - 1983. Energy Projections to the Year 2010. U.S. Department 

of Energy, Office of Policy, Planning and Analysis. DOE/PE-0029/2. 

October 1983. p. 3-2. 

-8-
P.14 

TABLE 6. ANNUALIZED INDUSTRIAL FUEL PRICES: 

(1982 $/MMBtu) 

REFERENCE CASE0 

Fuel type 

Natural gas 

New 

England 

5.71 

New York/ 

New Jersey 

5.67 

Middle 

Atlantic 

5.62 

South 

Atlantic 

5.90 

Midwest 

5.76 

Residual fuel oil 

3.0% S 

1.6% S 

0.8% S 

0.3% S 

Bituminous coalc 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

2.50-3.33 

3.33-5.00 

>5.00 

Subbituminous coal0 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

4.71 

5.02 

5.39 

5.75 

3.69 

3.64 

3.58 

3.39 

3.10 

3.20 

--

--

—— 

4.70 

5.01 

5.38 

5.74 

3.45 

3.38 

3.23 

3.07 

2.76 

2.79 

— 

— 

—— 

4.70 

5.01 

5.38 

5.74 

3.08 

2.88 

2.79 

2.70 

2.37 

2.34 

--

--

~ — 

4.68 

4.99 

5.35 

5.72 

3.13 

2.92 

2.90 

2.82 

2.74 

2.57 

--

--

"* — 

4.84 

5.15 

5.52 

5.89 

3.25 

3.12 

3.02 

2.87 

2.62 

2.45 

3.31 

3.27 

3.24 

Ten percent discount rate. Fifteen year period beginning in 1987. 

Energy and Environmental Analysis, Inc. 

°Based on an ICF Incorporated forecast of delivered industrial coal prices. 

-9-
P.15 

TABLE 6. ANNUALIZED INDUSTRIAL FUEL PRICES: 

(1982 $/MMBtu) 

(Continuation) 

REFERENCE CASE3 

Fuel type 

Natural gas 

Residual fuel 

3.0% S 

1.6% S 

0.8% S 

0.3% S 

oilb 

r 

Bituminous coal 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

2.50-3.33 

3.33-5.00 

>5.00 

Subbituminous coal0 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

Southwest 

5.30 

4.70 

5.01 

5.38 

5.74 

3.27 

3.15 

3.14 

3.13 

3.03 

2.90 

3.42 

3.32 

3.26 

Central 

5.34 

4.81 

5.12 

5.49 

5.86 

3.08 

3.02 

2.98 

2.86 

2.57 

2.42 

2.69 

2.64 

2.67 

North 

Central 

4.81 

4.51 

4.83 

5.19 

5.56 

1.95 

1.82 

1.83 

1.37 

1.36 

1.26 

West 

5.33 

4.30 

4.62 

5.01 

5.34 

2.74 

2.76 

2.72 

2.78 

2.69 

2.60 

Northwest 

5.46 

4.26 

4.58 

4.97 

5.30 

3.12 

2.91 

2.78 

2.61 

2.55 

2.05 

Ten percent discount rate. Fifteen year period beginning in 1987. 

^Energy and Environmental Analysis, Inc. 

"Based on an ICF Incorporated forecast of delivered industrial coal prices. 

-10-
FIGURE 1 

Federal Regions of the United States 

°« 9 

HAiAII " 

REGION NAMES 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. 

7. 

8. 

9. 

10. 

| \ 

*

ttts* N_. 

" * \ 

* 1 ^ 

Southwest 

Central 

North Central 

West 

Northwest 
P.17 

TABLE 7. ANNUALIZED INDUSTRIAL FUEL PRICES: 

(1982 $/MMBtu) 

HIGHER OIL AND GAS PRICES0 

Fuel type 

Natural gas 

New 

England 

6.26 

New York/ 

New Jersey 

6.25 

Middle 

Atlantic 

6.24 

South 

Atlantic 

6.39 

Midwest 

6.35 

Residual fuel oil 

3.0% S 

1.6% S 

0.8% S 

0.3% S 

Bituminous coal 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

2.50-3.33 

3.33-5.00 

>5.00 

Subbituminous coal0 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

5.88 

6.29 

6.76 

7.23 

3.69 

3.64 

3.58 

3.39 

3.10 

3.20 

— 

5.87 

6.28 

6.75 

7.22 

3.45 

3.38 

3.23 

3.07 

2.76 

2.79 

— 

5.87 

6.28 

6.75 

7.22 

3.08 

2.88 

2.79 

2.70 

2.37 

2.34 

--

5.85 

6.26 

6.73 

7.20 

3.13 

2.92 

2.90 

2.82 

2.74 

2.57 

— 

6.00 

6.41 

6.88 

7.35 

3.25 

3.12 

3.02 

2.87 

2.62 

2.45 

3.31 

3.27 

3.24 

aTen percent discount rate. Fifteen year period beginning in 1987. 

Energy and Environmental Analysis, Inc. 

°Based on an ICF Incorporated forecast of delivered industrial coal prices. 

•12-
P.18 

TABLE 7. ANNUALIZED INDUSTRIAL FUEL PRICES: 

(1982 $/MMBtu) 

(Continuation) 

HIGHER OIL AND GAS PRICES3 

Fuel type Southwest Central 

North 

Central West Northwest 

Natural gas 5.89 5.75 5.16 5.70 5.67 

Residual fuel oil 

3.0% S 

1.6% S 

0.8% S 

0.3% S 

Bituminous coal0 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

2.50-3.33 

3.33-5.00 

>5.00 

Subbituminous coal0 

(lb S02/MMBtu) 

<1.08 

1.08-1.67 

1.67-2.50 

5.87 

6.28 

6.75 

7.22 

3.27 

3.15 

3.14 

3.13 

3.03 

2.90 

3.42 

3.32 

3.26 

5.97 

6.38 

6.85 

7.32 

3.08 

3.02 

2.98 

2.86 

2.57 

2.42 

2.69 

2.64 

2.67 

5.70 

6.11 

6.58 

7.05 

1.95 

1.82 

1.83 

--

--

-— 

1.37 

1.36 

1.26 

5.47 

5.88 

6.39 

6.82 

2.74 

2.76 

2.72 

--

— 

--

2.78 

2.69 

2.60 

5.44 

5.84 

6.35 

6.79 

3.12 

2.91 

2.78 

--

— 

--

2.61 

2.55 

2.05 

Ten percent discount rate. Fifteen year period beginning in 1987. 

Energy and Environmental Analysis, Inc. 

°Based on an ICF Incorporated forecast of delivered industrial coal prices. 

-13-
P.19 

All seven alternative S02 NSPS (see Tables 3 and 4) were not run in 

IFCAM with both sets of oil and gas price projections. The Base Case 

and Option Cases 1-3 were run for both sets of oil and gas price projections. Option Cases 4-7 were run only for the "higher oil and gas 

prices" forecast. 

2.1 Environmental Impacts 

Projected aggregate S02 emissions from new industrial fossil fuelfired boilers are summarized in Tables 8 and 9. The aggregate S02 

emission reductions in the Option Cases are achieved by: 

o Burning a lower sulfur fuel in an Option Case than in the 

Base Case, 

o Scrubbing at a higher S02 removal rate in an Option Case 

than in the Base Case, or 

o Scrubbing non-compliance fuels in the Option Cases to a 

level which is lower than the uncontrolled emission rate of 

the compliance fuel type in the Base Case. 

Table 8 shows that aggregate S02 emissions projections in 1990 from 

new industrial fossil fuel-fired boilers are sensitive to the S02 NSPS 

assumptions. Sulfur dioxide emissions reductions are projected to range 

from 55 to 95 percent and from 173,500 to 309,000 short tons. 

The S02 emissions projections in 1990 for the two Base Case scenarios are similar. However, the projected fuel mix is quite different. 

Residual fuel oil is the primary fuel type for the Reference Case fuel 

prices/Base Case S02 NSPS scenario and coal is the primary fuel type for 

the higher oil and gas prices/Base Case S02 NSPS scenario. 

Recognize that Option Cases 1 (50/1.2), 2 (50), 4 (50/1.7), 5 

(70/1.2), and 6 (70) do not require all non-compliance coal types to 

collect a constant percentage of S02 emissions (50 or 70 percent in 

these examples). They are sliding scales similar to Option Case 3 (70-

90). The minimum S02 collection rate is 50 percent in Option Cases 1, 2 

and 4. The minimum S02 collection rate is 70 percent in Option Cases 5 

-14-
P.20 

TABLE 8. 

FROM NEW INDUSTRIAL FOSSIL FUEL-FIRED BOILERS 

PROJECTED S02 EMISSIONS IN 1990 

BY SIZE CATEGORY0 

(IO3 Short tons) 

Scenario 

Reference case fuel prices 

Base Case 

Option Case 1 (50/1.2) 

Option Case 2 (50) 

Option Case 3 (70-90) 

Higher oil and gas prices 

Base Case 

Option Case 1 (50/1.2) 

Option Case 2 (50) 

Option Case 3 (70-90) 

Option Case 4 (50/1.7) 

Option Case 5 (70/1.2) 

Option Case 6 (70) 

Option Case 7 (90) 

100-250 

238.5 

65.5 

63.9 

34.1 

267.3 

56.5 

16.1 

10.6 

89.9 

56.8 

9.2 

6.3 

Size category 

(MMBtu/hr) 

>250 

40.9 

40.4 

37.9 

13.0 

58.6 

57.8 

29.5 

19.1 

57.8 

56.5 

17.0 

9.7 

Total 

279.4 

105.9 

101.8 

47.1 

325.9 

114.3 

45.6 

29.7 

147.7 

113.3 

26.2 

16.0 

Reduction 

from 

Base Case 

(%) 

--

-62.1 

-63.6 

-83.1 

— 

-64.9 

-86.0 

-90.9 

-54.7 

-65.2 

-92.0 

-95.1 

Includes new units installed after 1985. 

-15-
P.21 

TABLE 9. PROJECTED S02 EMISSIONS IN 1990 FROM 

NEW INDUSTRIAL FOSSIL FUEL-FIRED BOILERS BY REGION3 

(IO3 Short tons) 

r-H CVJ 3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. total 

Base 

Case 

3.1 

5.1 

21.0 

53.3 

64.1 

85.0 

18.9 

8.2 

7.3 

13.3 

279.4 

Reference 

Option 

Case 1 

(50/1.2) 

2.7 

4.1 

14.2 

27.4 

32.9 

b 

1.9 

3.9 

6.0 

12.6 

105.9 

case fuel prices 

Option 

Case 2 

(50) 

2.7 

4.1 

14.2 

27.4 

32.9-

b 

b 

1.6 

6.0 

12.6 

101.8 

Option 

Case 3 

(70-90) 

1.0 

1.9 

7.4 

12.0 

13.3 

b 

b 

0.9 

3.8 

6.7 

47.1 

'includes new units larger than 100 MMBtu/hr installed after 1985. 

Less than 50 short tons. 

-16-
P.22 

TABLE 9. PROJECTED S02 EMISSIONS IN 1990 FROM 

NEW INDUSTRIAL FOSSIL FUEL-FIRED BOILERS BY REGION6 

(IO3 Short tons) 

(Continuation) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. total 

Base 

Case 

b 

5.7 

28.0 

81.0 

81.7 

77.9 

25.2 

14.7 

3.1 

8.6 

325.9 

Higher 

Option 

Case 1 

(50/1.2) 

b 

2.0 

12.4 

25.9 

25.1 

28.2 

3.7 

9.6 

3.1 

4.2 

114.3 

oil and 

Option 

Case 2 

(50) 

b 

1.3 

8.1 

7.9 

11.9 

7.6 

1.3 

2.7 

0.7 

4.1 

45.6 

gas prices 

Option 

Case 3 

(70-90) 

b 

0.9 

5.6 

4.8 

8.0 

4.6 

0.9 

1.8 

0.5 

2.7 

29.7 

Option 

Case 4 

(50/1.7) 

b 

2.2 

17.4 

35.7 

35.6 

30.8 

4.5 

11.9 

3.1 

6.4 

147.7 

Includes new units larger than 100 MMBtu/hr installed after 1985. 

Less than 50 short tons, 

-17-
P.23 

TABLE 9. PROJECTED S02 EMISSIONS IN 1990 FROM 

NEW INDUSTRIAL FOSSIL FUEL-FIRED BOILERS BY REGION3 

(IO3 Short tons) 

(Continuation) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. total 

Base 

Case 

b 

5.7 

28.0 

81.0 

81.7 

77.9 

25.2 

14.7 

3.1 

8.6 

325.9 

Higher oil 

Option 

Case 5 

(70/1.2) 

b 

1.7 

11.4 

25.9 

25.1 

28.2 

3.7 

9.6 

3.1 

4.6 

113.3 

and gas prices 

Option 

Case 6 

(70) 

b 

0.7 

4.6 

4.7 

6.6 

4.6 

0.7 

1.5 

0.4 

2.3 

26.2 

Option 

Case 7 

(90) 

b 

0.6 

3.8 

1.6 

7.4 

1.1 

0.1 

0.6 

0.2 

0.5 

16.0 

aIncludes new units larger than 100 MMBtu/hr installed after 1985. 

Less than 50 short tons. 

•18-
P.24 

and 6. The emissions ceilings shown in Table 4 can require higher removal rates. Non-compliance low sulfur coal types are scrubbed at the 

minimum rate. High sulfur coal types are scrubbed at higher rates such 

that the emissions ceilings are not violated. 

In this respect, Option Case 6 (70) is a sliding scale S02 emissions control standard which is similar to Option Case 3 (70-90). Table 

8 shows that the projected S02 emissions in these two cases are similar. 

The S02 emissions regulation for coal boilers larger than 250 

MMBtu/hr is identical for Option Cases 1 (50/1.2) and 4 (50/1.7). Table 

8 shows that the aggregate S02 emission projections are consistent. 

The S02 emission reductions presented in Table 8 are due, to some 

extent, to selecting natural gas in the Option Cases when residual fuel 

oil or coal was chosen in the Base Case. The projected fuel mix is 

variable and is not held constant between IFCAM runs. 

2.2 Cost Impacts 

The cost impacts of the alternative S02 NSPS are expressed on a 

pre-tax annualized basis. The real (not nominal) discount rate is 10 

percent and the investment period is 15 years. The capital recovery 

factor is 0.13147. It is also assumed that the capital and annual nonfuel O&M costs do not increase in real terms over time and do not vary 

by region. The fuel costs do vary by region (see Tables 6 and 7). 

Table 10 compares the projected annualized cost impacts. The 

annualized cost impacts of the alternative S02 emissions standards 

(Option Case costs less Base Case costs) range from $10.3 million for 

Option Case 4 (50/1.7) under higher oil and gas prices to $124.7 million 

for Option Case 3 (70-90) under the Reference Case fuel prices. 

Under higher oil and gas prices, the range of annualized cost 

increases is relatively small: $10.3 million to $18.2 million for 

scenarios which permit low sulfur coal to b(e burned without a scrubber, 

$29.2 million to $34.6 million for cases which require scrubbing on all 

coal types. 

-19-
TABLE 10. PROJECTED ANNUALIZED COST 

INCREASES BY SIZE CATEGORY3 

(Millions of 1982 dollars) 

P.25 

Scenario 

I Reference case fuel prices 

I 

Option Case 1 (50/1.2) 

Option Case 2 (50) 

j Option Case 3 (70-90) 

Higher oil and gas prices 

Option Case 1 (50/1.2) 

Option Case 2 (50) 

Option Case 3 (70-90) 

Option Case 4 (50/1.7) 

Option Case 5 (70/1.2) 

Option Case 6 (70) 

Option Case 7 (90) 

100-250 

56.4 

57.1 

88.3 

18.1 

4.5 

5.8 

10.2 

17.5 

6.4 

3.0 

Size category 

(MMBtu/hr) 

>250 

0.1 

1.3 

36.3 

0.2 

24.8 

27.3 

0.2 

0.4 

28.3 

28.7 

Total 

56.6 

58.5 

124.7 

18.2 

29.2 

33.0 

10.3 

17.8 

34.6 

31.6 

aIncludes new fossil fuel-fired boilers installed between 1985 and 1990. 

Total (capital, O&M and fuel) annualized costs, Option Case less Base Case, 

-20-
The fuel mix is not held constant between IFCAM runs. In each, run, 

IFCAM independently selects the lowest-cost alternative fuel type for 

each new boiler. If the fuel mix was held constant (e.g., all Option 

Cases would have the same fuel mix as the Base Case), the annualized 

cost impacts presented in Table 10 would increase. 

2.3 Energy Impacts 

The aggregate environmental and cost impacts presented in this 

report are a function of the projected number of new industrial boilers 

and the expected fuel mix. Since the expected fuel mix is variable, a 

key impact is the change in the projected fuel mix due to the alternative S02 NSPS. 

For the Base Case S02 NSPS, residual fuel oil is the predominant 

fuel type under the Reference Case fuel prices and coal is the primary 

fuel type under the higher oil and gas prices (see Table 11). Under 

both sets of fuel prices, natural gas consumption generally increases as 

the S02 emission standards become more stringent. Natural gas combustion is sometimes selected in IFCAM as the least-cost compliance option. 

Table 11 shows that, under the Reference Case fuel prices, coal 

combustion is highest under Option Case 3 (70-90), a scenario with 

tighter coal S02 emissions standards than the Base Case, Option Case 1 

(50/1.2) and Option Case 2 (50). A few large boilers with large capacity utilization rates selected 0.8 percent sulfur residual fuel oil in 

the Base Case and Option Cases 1 (50/1.2) and 2 (50); these units 

selected high sulfur coal with a scrubber in Option Case 3 (70-90) 

rather than burn 0.3 percent sulfur residual fuel oil, natural gas or 

scrub other residual fuel oil types. See Section 3 for further details 

on this model result. 

Projections of coal and residual fuel oil demand in 1990 in new 

industrial boilers larger than 100 MMBtu/hr and installed after 1985 are 

presented in Appendices A and B by Federal region and sulfur category. 

-21-
P.27 

Scenario 

Reference 

Base 

IN 

TABLE 11. PR 

NEW INDUSTRIAL 

case fuel prices 

Case 

Option Case 

Option Case 

Option Case 

-

1 (50/1.2) 

2 (50) 

3 (70-90) 

OJECTED FUEL 

FOSSIL FUEL-

(1012 Btu) 

Natural 

gas 

152 

225 

232 

267 

MIX IN 1990 

-FIRED BOILERS3 

Residual 

fuel oil 

323 

257 

257 

206 

Coal 

23 

17 

9 

26 

Total 

498 

498 

498 

498 

Higher oil and gas prices 

Base Case 

Option Case 1 (50/1.2) 

Option Case 2 (50) 

Option Case 3 (70-90) 

Option Case 4 (50/1.7) 

Option Case 5 (70/1.2) 

Option Case 6 (70) 

Option Case 7 (90) 

aIncludes new units larger than 

107 

250 

345 

345 

237 

250 

345 

351 

100 MMBtu/hr 

7 

0 

0 

0 

0 

0 

0 

0 

installed 

284 

248 

153 

153 

261 

248 

153 

147 

after 1985. 

498 

498 

498 

498 

498 

498 

498 

498 

-22-
P.28 

3. BOILER COST COMPARISONS 

The purpose of this section is to present example cost comparisons 

for new industrial boilers in order to highlight and explain the aggregate IFCAM results summarized in Section 2. Fuel choice decisions in 

IFCAM are based on the alternative with the lowest total after-tax net 

present value of capital costs, annual non-fuel O&M costs and annual 

fuel costs. Factors used in IFCAM to derive after-tax net present value 

estimates are summarized in a separate report.* 

Table 11 shows that expected coal demand under the Reference Case 

fuel prices is larger for Option Case 3 (70-90) than for the other 

cases. This occurs in spite of the fact that Option Case 3 (70-90) has 

more stringent coal S02 emission standards than the Base Case, Option 

Case 1 (50/1.2) and Option Case 2 (50). 

The coal demand in Option Case 3 (70-90), Reference Case fuel 

prices, occurs in new 325 MMBtu/hr, 75 percent capacity utilization rate 

boilers** in Federal regions 3 (Middle Atlantic) and 5 (Midwest) that 

selected 0.8 sulfur residual fuel oil in the other cases. In Option 

Case 3 (70-90), 0.3 percent sulfur residual fuel oil is a compliance 

fuel type, but 0.8 percent sulfur residual fuel oil is not. In Option 

Case 3 (70-90), IFCAM chooses to scrub a high sulfur coal rather than 

burn natural gas, 0.3 percent sulfur residual fuel oil, or scrub one of 

the non-compliance residual fuel oil types. 

Table 12 shows that the costs increase more for residual fuel oil 

than for coal between the Base Case and Option Case 3 (70-90). As a 

result, coal is selected in Option Case 3 (70-90) when residual fuel oil 

is selected in the other cases. 

*The Current Basis for Comparing Life Cycle Costs in IFCAM for New 

Industrial Fossil Fuel-Fired Boiler Fuel Choice Decisions. Energy 

and Environmental Analysis, Inc. Arlington, Virginia. Prepared 

for the U.S. Environmental Protection Agency. June 10, 1983. 

**The largest boiler size/capacity utilization rate combination in 

IFCAM. 

-23-
P.29 

In the Base Case, the least-expensive coal option is to burn a 

compliance coal type. The coal cost impact of Option Case 3 (.70-90) is 

$0.6 million ($54.0 million - $53.4 million). However, the cost impact 

of Option Case 3 (70-90) for residual fuel oil is $1.8 million. 

Table 12 also shows that the selection of the lowest-cost compliance option can be a very marginal choice. The difference in cost 

between scrubbing a high sulfur coal and burning a compliance coal type 

in the Base Case in this example is less than 0.5 percent ($53,621 

million versus $53.4 million). 

Table 12 also presents a cost example of scrubbing a non-compliance 

residual fuel oil type in preference to a compliance residual fuel oil 

type. In Option Case 3 (70-90), the most common compliance strategies 

are natural gas or scrubbing non-compliance residual fuel oil types,* 

not selecting a compliance (0.3 percent sulfur) residual fuel oil type. 

Table 12 shows that scrubbing a 1.6 percent sulfur residual fuel oil in 

Option Case 3 (70-90) can be less expensive than burning natural gas or 

0.3 percent sulfur residual fuel oil. 

Each region has a unique new boiler population (distribution of 

sizes, capacity utilization rates and local SIP emission regulations) 

and unique fuel price differences. Therefore, projected coal demand 

observed in regions 3 and 5 in Option Case 3 (70-90) does not also occur 

in other regions. 

*1.6 and 0.8 percent sulfur; 3.0 percent sulfur residual fuel oil requires SCA for NO control and higher scrubber O&M costs; 1.6 percent 

sulfur residual f_el oil requires higher scrubber O&M costs (and sometimes an ESP) than 0.8 percent sulfur residual fuel oil. 

-24-
P.30 

' 

TABLE 12. COMPARISON OF INDUSTRIAL BOILER COSTS3 

(Thousand of 1982 dollars) 

Capital 

' Boiler 

j FGD/PM 

! NOy 

| Total 

Annual non-fuel 

Boiler 

1 FGD/PM 

i N0y 

Total 

After-tax NPV 

! Capital 

Annual non 

Fuel 

Total 

O&M 

-fuel O&M 

, 

Base 

0.8 % S 

Resid 

5,687 

--

137 

5,824 

1,810 

--

-246 

1,564 

3,649 

5,727 

43,695 

53,071 

Case 

High S 

Coal 

22,028. 

4,212° 

148 

26,388 

3,701. 

1,469° 

98 

5,268 

13,883 

19,291 

20,447r 

53,621° 

Option Case 3 

(70-90) 

1.6 % S 

Resid 

5,687. 

3,015° 

137 

8,839 

1,810. 

766° 

-226 

2,350 

5,538 

8,606 

40,715. 

54,859° 

High S 

Coal 

22,028. 

4,238° 

148 

26,414 

3,701. 

1,579° 

98 

5,378 

13,896 

19,694 

20,447 

54,037 

3Size: 325 MMBtu/hr 

Capacity utilization rate: 75 percent 

Region: 3 Middle Atlantic. 

Reference case fuel prices. 

Sodium scrubber and an ESP. 

°The comparable value for compliance coal type B is $53.4 million. 

Lower than the total cost of 0.3 sulfur residual fuel oil without a 

scrubber (.$56.0 million) or of natural gas ($55.4 million). 

-25-
P.31 

APPENDIX A 

PROJECTIONS OF REGIONAL COAL DEMAND 

The tables presented in this appendix summarize the projected 

demand for coal in 1990 in new industrial boilers larger than 100 

MMBtu/hr installed after 1985 by region and coal type. Tables are 

provided for the Base Case and Option Cases 1-7 only for the "higher 

oil and gas prices." Tables are not included for the Reference Case 

fuel price scenarios because the projected coal demand is inconsequential (see Table 11). 

Note that the selection of a specific coal type in IFCAM can be a 

very marginal decision. Table 12 shows that the difference in cost 

between scrubbing a high sulfur coal and burning a compliance coal type 

in the Base Case can be relatively small, less than 0.5 percent. 

Recall that ICF coal type A, <0.8 lb S02/MMBtu, is not permitted 

and that Option Cases 2, 3, 6 and 7 require scrubbing for all coal 

types. 

-26-
P.32 

CO 

"=C 

o 

t / > 

< 

CQ 

CO 

cr 

• e 

e 

— *

— 

a 

V 

- J 

< o 

u 

> X 

_ 

V — 

r— -

I 

2 

1 

o 

3 

-* 

A 

Vt 

_ 

_ 

_ — •o 

X 

VI 

z 

c 

»» ts 

UJ 

a 

- i 

« 

_ — c 

1 _ 

u. 

K 

2 

W 

O • 

z 

_' THA 

z 

U.' 

u 

r1/1 

_ 3 

• c 

l/l 

rl/l 

Ul 

£ 

c 

• — 

_ 

_• l 

»-«x 

-

l/l 

o 

z 

u j 

Z 

Z 

1 

_ 

c 

< 

o 

o 

CB 

tn z 

_ z 

a. v 

*• rst 

»- o 

l/l 

_l 

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O _ l 

t > — 

c c — o o c o 

a o o c> © c c 

o — r- a 

« « o * m _ 

« * • PI 

^ * 

c © o e © c 

© c _ J-. 

rv. 

ooo o 

* c — 

» -c r> 

* IM 0> 

Cf « « 

i * o o 

<z m 

rr -9 

its 

IT 

a 

<M 

rt 

c » e e h n M 

o» i— *• r-

•c m * * 

« r- •» Ifl * — 

O « ifl « 3 1*1 — 

« O n 3 * — 

er x or o 4 

O f f CNC4 9 

-.or- * a — 

cr n m x r- m 

rM ru r- -• m x 

IM - . 

© r- 3 rv « — o 

r> « ifl r- its 

KIODMVi r 

O — « .0 c 

O — O © I*- Ifl © 

in -o ro 

» ru — 

99 r», rM 

coo©©© © 

3 © e © cr 

rn 

IM 

COC O 

© © © o 

a 

er & 

IT 

occ © rIT. 

©OC O 

ooo o 

cw 

Ifl 

IM 

aren a 

041/in o 

</i 

O 

</, --rgo * z 

3 • I I I I O — 

o tc o a) r- o n o z 

z «x o •© m n • 3 

« o • • • • • m rx — O'^rgn A *• 

3 x 

r- _ — _ 

1) I A 

X * • O 

O .0 Ifl • • • 

— — IM 

• I t I arc r-

• X o -o 

o • • • 

V O — - > 

-27-
TABLE A-2. OPTION CASE 1 (50/1.2) 

COAL UtrlANU IN Nt» INOU*TH|AL BOILEHS » 100 MMdlU/MH bY COAL TYt>t I10»«V bTuS) 

COAL TYHES 

(LU S02/NMBTU) 

CEOEMAL «El>iONS 

NEW ENU. a,Y/N.J. M{U «TL. SO, AIL* MIUPEST SO, WEST CfcNTHAL NO. CM ML HEST NO, WtST 

I ro 

oo 

i 

blTUMINOUS 

<0.H 

O.UO-l.OB 

1.OH-1.67 

1.67*2.50 

2.30*3,33 

3.33-S.00 

>S,00 

$Ubttl TUMI NOUS 

<0,B 

u.ao-i.ob 

l,0b-1.6 7 

1.67-2.b0 

TOTAL 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

u. 

0. 

0. 

0. 

u. 

u. 27Jb, 

0. 

0. 

0. 

2135. 

u. 

0. 

0. 

0. 

0. 

4673. 

0. 

20597. 

0. 

0. 

0. 

M/«2. 

0. 

0. 

0. 

0. 

0. 

2*379. 

0. 

5*4 76, 

0. 

0. 

0. 

0. 

0* 

0. 

0* 

0. 

0. 

94476. 

0. 

52«4S* 

0. 

0. 

0. 

0. 

0. 

o. 

0. 

0. 

0. 

52.45. 

u. S)»37l, 

0. 

U. 

0. 

0. 

0. 

U. 

0. 

0. 

0. 

-9371. 

0. 

0* 

0* 

0* 

0. 

0. 

0. 

0. 

7709. 

0. 

0. 

7709. 

0. 

0* 

0. 

0. 

u. 

0. 

u. 

0* 

20192* 

0. 

0. 

20192. 

0. 

6570. 

0. 

0* 

0. 

0* 

0. 

0. 

0. 

0. 

U* 

6570. 

0* 

0. 

0. 

0. 

0* 

0. 

0. 

0* 

712* 

0. 

115B&, 

12297, 
TABLE A-3. OPTION CASE 2 (50) 

COAL DEMAND IN NEW INDUSTRIAL BOILERS > 100 MM8TU/HW BY COAL TYRE (10**9 0TU8J 

1 

ro 

to 

1 

CUAL TYPES 

(LB S02/MHBTU) 

FEOERAL REGIONS 

NEN ENG. N.Y/N.J, MID ATL, SO, ATL. MI0KE3T 80, HEST CENTRAL NU.CNTHL "t»T NU, WfcSl 

BITUMINOUS 

<0.8 

0,80-1.08 

1,08-1,67 

1,67-2.SO 

2.50-3.31 

S.33-5.00 

>S.0O 

SUBBITUMINOUS 

<0.8 

0.00-1.OS 

1,08-1.67 

1.67-2.SO 

TOTAL 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

3986. 

°. 

0. 

0. 

0. 

0. 

3186, 

0. 

0. 

0. 

0. 

0. 

25338, 

0. 

0. 

0. 

0. 

0. 

25338, 

0. 

0. 

29258, 

1566, 

0, 

«. 

0. 

0. 

0. 

0. 

0. 

30624, 

0. 

0. 

0. 

0. 

0. 

0. 

36288. 

0. 

0. 

0. 

0. 

36288, 

0. 

0. 

29694, 

0. 

0. 

0 . 

0. 

0. 

0. 

0. 

0. 

2989a, 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

3986, 

3986, 

0. 

0. 

0. 

0. 

0. 

0. 

0 . 

0. 

0. 

0. 

6267. 

8267. 

0* 

0. 

0. 

0. 

0. 

0* 

0 . 

0. 

0. 

0. 

2135. 

2135. 

0. 

0. 

0. 

0 ; 

0. 

0 . 

°* 

0. 

0. 

0. 

12297. 

12297, 
TABLE A-4. OPTION CASE 3 (70-90) 

COAl OEMANfl IN N£« INDUSTHIAL HOILEHS > luO HMbT'l/Hl, HY COAL TYPE U0«»9 HTUS> 

COAL TYPES 

Cl.H S02/rtHbTU) 

FEOEML HEGIONS 

nt*' F.HG. C-.Y/H.J. r*!D ATL, SO, ATL. >«|r>kEST SO. WfST CFNTMAI NO,CNT»L *EST NO , WEST 

00 

o 

1 

MIIUM^OUS 

<0.8 

O.hO-l ,')8 

I , .»8«1 .67 

1.07-2,S'< 

2.50-3.33 

3.33-5.00 

>S.00 

bUbUlTUMiriCHJS 

<0,8 

O.HO-l,Cd 

l.Ud-1.67 

l.t>T-2.oO 

TOTAL 

0. 

0. 

0. 

0. 

c. 

<>. 

'•» . 

u. 

f. 

0 . 

0. 

o. 

39K6. 

o. 

0. 

0. 

o. 

0. 

n. 

2533H, 

0. 

<> 

li 

2925* 

156h 

li 

0 

0 

0. 

r. 

«. 

0. 

«'. 

*'. 

3626(1. 

". 

0. 

29H94 , 

0. 

0. 

«'. 

0. 

0. 

0. 

o. 

'•. 

o. 

o. 

(>. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

n. 

f. 

0. 

o. 

0. 

n. 

0. 

n. 

o. 

o. 

0. 

0. 

o. 

o. 

o. 

o. 

o. 

o. 

o. 

o. 

o. 

o. 

0. 

o. 

». 

u. 

•'. 

•J. 

•>. 

0. 

o. 

c. 

1). 

••>. 

o. 

0. 

o. 

0. 

o. 

19Pf>. 

0. 

0. 

0. 

B2r.7. 

0. 

0. 

1 . 

2135. 

0. 

0. 

o. 

12297. 

o. 39H6. 2S33H, 3(M2«, ir.?P.e, 29t*9«. 39«f», B267, 2135 , 12297, 
COAL TYPES 

TABLE A-5. OPTION CASE 4 (50/1.7) 

COAL DELANO IN N£w INDUSTRIAL HOILEKS > 100 MUHTU/HK BY COAL TYPE (I0»» 9 BTUS) 

FEOEHAL WfGIONS 

I (LB SU2/"MBTU) 'JEW E*G , N.Y/N.J , MI|) ATL , SO, ATL. *Il>WEST 90 , WEST Cf'THA L NU.CNTHL WEST NO, "EST 

I 

BITUMINOUS 

<0.8 

ft,80-1,08 

1.08-1.67 

1,67-2.50 

2,50-3.33 

3.33-5.00 

>5.00 

, SURBITUMIN0U9 

<0.8 

ft.80-1.08 

1.08-1.67 

1.67-2.50 

TOTAL 0. 1873. 33|57. 5B9H, 57772. 59371, 7709. 20|92, 6570. 12297, 

o. 

•>. 

o. 

o. 

o. 

o. 

o. 

•>. 

o. 

o. 

o. 

o. 

1851. 

A87, 

o. 

o. 

2135. 

o. 

o. 

o. 

o. 

o. 

o. 

9S37, 

14837, 

«. 

0. 

8782. 

o. 

0. 

0. 

o. 

0. 

229 

ft. 

1". 

35993. 

0. 

0. 

n. 

». 

0. 

«. 

0. 

". 

0. 

19644. 

38128. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

47545. 

1182b, 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

». 

0. 

0. 

0. 

0. 

0. 

0. 

3986, 

3723. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

9494, 

10696, 

0. 

0. 

6570, 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

6461. 

5036. 
TABLE A-6. OPTION CASE 5 (70/1.2) 

COAL DEMAND IN NEW INDUSTRIAL BOUE»S > 100 MMHTU/HR HY COAL TYPE <10»«9 RTUS) 

COAL TYPES 

(LB S02/MMBTU) 

FEDERAL REGIONS 

NEW ENG, N.Y/M.J. Mil) ATL. SO, ATL. MIDWEST SO. WEST CENTRAL NO.CNTRL WfST NO. WEST 

I 

Co 

ro 

i 

BITUMINOUS 

<0.B 

O.dO-1,06 

1.08-1.67 

1.67-2.50 

2.50-3.33 

3.33-5.00 

>5.00 

SUBBMUMINOUS 

<0.R 

0.80-1.08 

1.08-1.67 

1.67-2.50 

TOTAL 

0. 

0. 

o. 

0. 

0. 

o. 

o. 

o. 

0. 

o. 

o. 

0. 

2738, 

o. 

9. 

0. 

2135. 

0. 

0. 

0. 

o. 

o. 

0. 

20597. 

0. 

0. 

o. 

R782, 

0. 

0. 

0. 

0. 

0. 

•). 

54476, 

«. 

0. 

0. 

0. 

0. 

0. 

0. 

o. 

0. 

0. 

52845. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

C. 

0, 

59371, 

0. 

0. 

0. 

0. 

0. 

0. 

0.. 

0. 

0. 

0. 

0. 

o. 

0. 

ft. 

o. 

o. 

o. 

7709. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

20192. 

0. 

0. 

0. 

6570. 

0. 

0. 

0. 

0. 

P. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

o. 

0. 

0. 

8026. 

0. 

4271, 

o. 4d73. 29379. 54476. 52B4S. 59371, 7709. 20192. 6570. 12297. 

f
TABLE A-7. OPTION CASE 6 (70) 

COAL DEMAND IN NEW INOUSTRIAL BOILERS > 100 MMBTU/HM BY COAL TYPE (10**9 BTUS) 

i 

co 

co 

i 

COAL TVPCS 

(LB S02/MMBTU) 

FEDERAL REGIONS 

NEM ENG.' N.Y/N.J, MID ATL, SO, ATL, MIDWEST SO, HEST CENTRAL NU.CNTRL WEST NU, WEST 

BITUMINOUS 

<0.6 

0.60-1.06 

1,08-1,67 

1.67-2,50 

2.50-3.33 

3.33-5.00 

>5.00 

SUBBITUMINOUS 

<0.8 

0.00-1.06 

1.08-1,67 

1.67-2*50 

o. 

0. 

o. 

o. 

o. 

o. 

o. 

0. 

o. 

o. 

o. 

0. 

o. 

o. 

0. 

o. 3986, 

o. 

o. 

o. 

o. 

o. 

0. 

o. 

o. 

o. 

o. 25338. 

o. 

o. 

o. 

o. 

o. 

0. 

o. 29256. 

1566, 

0. 

0. 

0. 

0. 

0. 

o. 

0. 

0. 

0. 

0. 

o. 

0. 

36266, 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

29694, 

0. 

0. 

o. 

0. 

0. 

0. 

0, 

0. 

0. 

0. 

0. 

0* 

o. 

o. 

o. 

o. 

o. 0, 

3966, 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

6267. 

0. 

0. 

0. 

o. 

0. 

0. 

0. 

o. 

o. 

o. 2135. 

0. 

o. 

0. 

o. 

o. 

o. 

°. 

o. 

0. 

o. 

12297. 

TOTAL 0. 3986, 25336, 30824, 36266, 29894, 398b, 8267, 2135. 12297, 
TABLE A-8. OPTION CASE 7 (90) 

CUAL UEhANIJ IN NtW JNDUitlHlAL UU1LLHS > 100 MHBTU/HH bV CUAL TYPE (10»*9 bTUS) 

COAL TYPES 

(Lb SO2/MM0TU) 

FtUtHAL KtUlUNS 

NEW ENti. N.Y/N.j, H|U ATL. SO. AIL. MIOWfcSI SO. »t.ST CENThAL NO.CNIHL WfcST NO. WEST 

1 

co 

4-

oITonlNOuS 

<0,b 

O.bO-l.Ob 

l.Ob-1.67 

1.67-2.50 

2.5U-3.33 

3.33-5.OO 

>5.0G 

SUdbllUMlNOUS 

<ft.b 

0.80-1,Ob 

l.Ob-1.67 

1.67-2.5U 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

0. 

u. 

0. 

0. 

u. 

0. 

3966, 

u. 

0. 

0. 

0. 

0. 

0. 

u. 

u. 

0. 

b. 

2533b. 

0. 

u* 

0. 

0. 

u. 

0. 

0. 

292bb, 

1566. 

0. 

0. 

0. 

0. 

0. 

0. 

U. 

fa. 

0. 

u. 

0. 

0. 

0. 

-62-U. 

0. 

0. 

0. 

0. 

u. 

29b9*. 

0. 

0. 

U. 

0. 

fa. 

0. 

U. 

0. 

fa. 

0. 

0. 

0. 

0. 

0. 

0. 

0* 

0* 

3986. 

0. 

0. 

0. 

0. 

fa. 

0. 

0. 

0. 

0. 

0. 

0. 

fa. 

B267. 

0. 

0. 

0. 

u. 

0. 

0. 

0. 

0. 

0. 

0. 

21J5. 

0. 

0* 

0. 

0. 

0. 

fa. 

0. 

0. 

0. 

0. 

6548. 

IOTAL 39b6. 2533b. 30b_4. 3628b. 29B94. 3986. 8267. 2135. 6548. 
APPENDIX B 

PROJECTIONS OF REGIONAL RESIDUAL FUEL OIL DEMAND 

The tables presented in this appendix summarize the projected 

demand for residual fuel oil in 1990 in new industrial boilers larger 

than 100 MMBtu/hr installed after 1985. Tables are provided for the 

Base Case and Option Cases 1-3 only for the Reference Case fuel prices. 

Tables are not included for the higher oil and gas prices scenarios 

because the projected residual fuel oil demand is inconsequential (see 

Table 11). 

Recall that 0.3 and 0.8 percent sulfur residual fuel oil are 

assumed to be compliance fuel types in Option Cases 1 and 2; 0.3 percent 

sulfur residual fuel oil is a compliance fuel type in Option Case 3. 

Natural gas is less expensive than 0.8 percent sulfur residual fuel oil 

(reference Table 6) in regions 6 (Southwest), 7 (Central), and 8 (North 

Central) and, as a result, there is no projected demand for 0.8 percent 

sulfur residual fuel oil in these regions. Similarly, natural gas is 

less expensive than 0.3 percent sulfur residual fuel oil in regions 2 

(New York/New Jersey), 3 (Middle Atlantic), 5 (Midwest), 6 (Southwest), 

7 (Central) and 8 (North Central) and, as a result, there is no expected 

demand for 0.3 percent sulfur residual fuel oil in these regions. In 

regions 1 (New England) and 9 (West), the prices of 0.3 percent sulfur 

residual fuel oil and natural gas are very close. 

In Option Cases 1 (50/1.0) and 2 (50), the preferred compliance 

strategy for residual fuel oil boilers is burning compliance 0.8 percent 

sulfur residual fuel oil. In Option Case 3 (70-90), most of the residual 

fuel oil boilers scrub 0.8 or 1.6 percent sulfur residual fuel oil 

rather than burn 0.3 percent sulfur residual fuel oil. Table 12 presents 

sample boiler costs that illustrate this fuel choice decision. 

-35-
BASE CASE 

RESIDUAL FUEL OIL DEMAND IN NEM INDUSTRIAL BOILERS > 100 MMgTU/HR 

(10**9 BTUS) 

FEDERAL REGIONS 

< 

RESIDUAL 

FUEL OIL TYPES 

3.0X8 

1,6X9 

O.M S 

0.3X9 

NEW (NC. 

0. 

1785, 

5300. 

0. 

N.Y/N.J, 

493. 

1651. 

io*as. 

o. 

MID ATL, 

1314, 

20531. 

17290. 

0. 

SO. ATL. 

12505, 

20192, 

33625. 

0. 

MIDWEST 

10961, 

25408. 

40066. 

0. 

80, WEST 

47709, 

9769, 

o. 

0. 

CENTRAL 

7556, 

5661, 

0. 

0. 

NO.CNTRL 

0. 

1380. 

0. 

0. 

NEST 

3975, 

4314, 

5166, 

6660, 

NO, NEST 

0, 

9395, 

17509, 

1424. 

US TOTAL 

84512, 

100606, 

129703, 

6101. 

I 

co 

(Ti 

I 

RF8IDIIAL 

FUEL OIL TYPES 

s.oxs 

1.6X9 

0.6XS 

O.SXS 

OPTION CASES 1(50/1.0) and 2(50) 

RESIDUAL FUEL OIL DEMANO IN NEM INDUSTRIAL BOILERS > 100 MMBTU/HR 

(10**9 BTUS) 

FEOERAL REGIONS 

NEW ENG. N.Y/N.J, MID ATL, SO. ATL, MIDWEST SO, WEST CENTRAL NO.CNTRL 

n. 

821. 

6263. 

0. 

o. 

887. 

12001. 

0. 

o. 

13«69, 

25667, 

o. 

0. 

10019, 

57926. 

0. 

0. 

23674, 

57696. 

0. 

o. 

o. 

o. 

o. 

o. 

o. 

o. 

o. 

WEST NU. WEST US TOTAL 

o. 

0. 

0. 

0. 

1002. 

5081, 

6975. 

6680. 

0. 

6902, 

18002, 

1424, 

1402, 

62653, 

164529, 

• 103. 

OPTION CASE 3(70-90) 

RESIDUAL FUEL OIL DEMAND IN NEM INDUSTRIAL BOILERS > 100 "MBTU/MR 

(10**9 BTUS) 

FEOERAL REGIONS 

RESIDUAL 

FUEL OIL TYPES 

3.0X9 

1.6X8 

0,8X9 

0,3X9 

NEW ENG. 

0, 

2201, 

2166, 

1183. 

N.Y/N.J, 

0. 

4139. 

6778, 

0. 

MID ATL. 

o. 20093. 

7116, 

6. 

90. ATL. 

0. 

24057. 

30668. 

13020. 

MIOMEST 

0. 

38544. 

8968, 

0. 

SO. WEST 

0. 

o. 

0. 

0. 

CENTRAL 

0. 

0. 

0. 

0. 

NO.CNTRL 

0. 

0. 

0. 

0. 

wE9T 

3176, 

6066, 

2135. 

6680. 

NO, NEST 

o. 15527, 

6SS9, 

6242, 

US TOTAL 

3176. 

110626, 

64594, 

27123, 

^