P.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

116) ll-K- (B) -105 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:52 AM Sheet 116 of 325 
P.2 

^ 

*A ENERGY AND ENVIRONMENTAL ANALYSIS, INC. i 

April 19, 1983 

Mr. Robert Short 

Economic Analysis Branch 

U.S. Environmental Protection Agency 

Mail Drop-12 

Research Triangle Park, NC 27711 

Subject: EPA Contract No. 68-02-3564, Work Assignment #9 

Dear Robert: 

Attached is a summary of 

tions for the industrial 

the attached information 

possible. 

TH:mk 

Attachment 

cc: Al Wehe (EPA) 

\-83-27 

II-K-(B)-105 1 

! 

my current understanding of the major assumpboiler S0_ NSPS impact analysis. Please review 

and confirm or correct its accuracy as soon as 

Sincerely, 

Tim Hogan (/ 

Economic s / Engineering 
P.3 

MAJOR ASSUMPTIONS FOR THE INDUSTRIAL BOILER SO? 

NSPS IMPACT ANALYSIS

 C 

1. Revised industrial fuel price projections (Tables 1-5).* 

2. Revised NO monitoring costs (Table 6) . 

A 

3. Revised NO emissions rates (Table 7). 

A 

4. Low excess air is assumed to be standard operating procedure even if 

an uncontrolled boiler can comply with the applicable NO NSPS. No 

boilers are assumed to operate without a NO control technology 

(either low excess air or staged combustion air). 

5. Lime spray drying FGD system is included.** FBC is excluded. 

6. Time horizon has shifted from the 1984-1988 5-year period to the 

1986-1990 5-year period and the 1986-1995 10-year period. 

7. Revised industrial fossil fuel demand projections (Table 8) . 

8. Alternative industrial boiler NSPS air emissions regulations (Tables 

9-12). 

* Table 5, projected delivered industrial coal prices, is not yet available. 

**0nly if sulfur content is less than 3.5 percent sulfur. Upper limit on 

sulfur removal is 90 percent. 
P.4 

TABLE 1. WORLD OIL PRICE FORECAST9 

(1982 $/bbl) 

Average Refiner's 

Acquisition Cost of 

Year Imported Crude Oil 

1985 31.48 

1990 32.75 

increases at 1.0 percent annually in real terms. U.S. Department of 

Energy. Analysis of Natural Gas Consumer Regulatory Reform Legislation. 

February 28, 1983. p. 14. Derived from the fiscal year 1984 budget. 
P.5 

TABLE 2. DISTILLATE FUEL OIL PRICE FORECAST 

(1982 $/MMBtu) 

Demand 

Region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

1985 

6.94 

6.93 

6.93 

6.90 

6.79 

6.69 

6.70 

6.63 

6.69 

6.69 

1990 

7.25 

7.24 

7.24 

7.21 

7.10 

6.99 

7.01 

6.94 

6.99 

6.99 

1995 

7.57 

7.57 

7.57 

7.53 

7.42 

7.31 

7.33 

7.26 

7.31 

7.31 

iggga 

7.85 

7.84 

7.84 

7.80 

7.69 

7.58 

7.60 

7.53 

7.58 

7.58 

aRemains constant in real terms after 1999. 
P.6 

TABLE 3. RESIDUAL FUEL OIL PRICE FORECAST3 

(1982 $/MMBtu) 

Demand 

Region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

1985 

5.37 

5.37 

5.37 

5.37 

5.46 

5.07 

5.39 

5.32 

5.37 

5.37 

1990 

6.21 

6.21 

6.21 

6.29 

6.21 

6.22 

6.24 

6.16 

6.21 

6.21 

1995 

7.19 

7.19 

7.19 

7.19 

7.28 

7.19 

7.21 

7.14 

7.19 

7.19 

1999b 

7.61 

7.61 

7.61 

7.61 

7.69 

7.61 

7.62 

7.55 

7.61 

7.61 

Low sulfur, 0.3 percent sulfur. 

0.8 percent sulfur = 0.3 percent sulfur - $0.33/MMBtu. 

1.6 percent sulfur = 0.3 percent sulfur - $0.68/MMBtu. 

3.0 percent sulfur = 0.3 percent sulfur - $1.13/MMBtu. 

Remains constant in real terms after 1999. 
P.7 

TABLE 4. NATURAL GAS PRICE FORECAST 

(1982 $/MMBtu) 

Demand 

Region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

1985 

5.11 

5.11 

5.11 

5.11 

5.20 

4.82 

5.13 

5.06 

5.11 

5.11 

1990 

5.94 . 

5.94 

5.94 

5.94 

6.03 

5.94 

5.96 

5.89 

5.94 

5.94 

1995a 

6.59 

6.59 

6.59 

6.59 

6.67 

6.59 

6.60 

6.54 

6.59 

6.59 

increases after 1995 at 1.0 percent annually. 
Federal Regions of the United States 

o 

if 

New York City 

Philadelphia 

Washington D.C. 
P.9 

Function 

°2 

N0„ 

/ 

monitoring 

monitoring 

TABLE 6. REVISED NO MONITORING COSTS 

($1982) 

Fuel type 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Coal 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Size class 

(MMBtu/hr) 

50-250 

50-250 

50-250 

>50 

' >250 

>250 

>250 

Capital 

25 

25 

25 

48 

48 

48 

48 

,000 

,000 

,000 

,400 

,400 

,400 

,400 

Annual 

O&M 

__ 

--

--

30,935 

30,935 

30,935 

30,935 

a0nly if nitrogen content is less than or equal to 0.35 percent 
P.10 

TABLE 7. REVISED NO EMISSIONS RATES , 

(lb/MMB^u) 

Annual average 

Fuel type NO control technology NO emission rate 

A A 

Natural gas Low excess air 0.19 

Distillate fuel oil Low excess air 0.16 

Residual fuel oil 

- 3% S (0.44% N) Low excess air 0.42 

Staged combustion air 0.23 

- 1.6% S (0.23% N) Low excess air 0.27 

Staged combustion air 0.21 

- 0.8% S (0.12% N) Low excess air 0.20 

- 0.3% S (0.04% N) Low excess air 0.18 

Coal 

- pulverized Staged combustion air 0.58 

- stoker Low excess air 0.50 
p.11 

TABLE 8. PROJECTIONS OF INDUSTRIAL FOSSIL FUEL DEMAND0 

(IO12 Btu) 

Demand Region 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 

U.S. TOTAL 

1985 

206.2 

528.6 

1,021.3 

1,450.1 

2,194.8 

3,284.8 

496.4 

371.8 

697.5 

350.1 

10,601.5 

1990 

227.0 

582.2 

1,127.6 

1,604.9 

2,312.5 

3,602.8 

530.4 

405.3 

794.7 

389.5 

11,576.9 

1995 

247.5 

637.8 

1,224.9 

1,754.0 

2,506.7 

3,948.8 

581.8 

438.1 

858.4 

421.5 

12,619.4 

Includes coal, residual and distillate fuel oil and natural gas consumption in boilers and process heat equipment. Excludes fuel demand 

for feedstocks or raw materials. 
TABLE 9. BASE CASE NSPS AIR EMISSIONS REGULATIONS 

(lb/MMBtu) 

P.12 

Fuel type 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Coal 

Size class 

(MMBtu/hr) 

>50 

>50 

50-250 

>250 

50-100 

100-250 

>250 

SO '.2 PM NO 

0.80 

1.20 

0.10 

0.20, 

0.05( 

0.05 

0.20 

0.20 

0.30. 

0.25b 

0.60 , 

0.60/0.70( 

0.70 

Low excess air required for natural gas, distillate fuel oil, low sulfur 

residual fuel oil and coal burned on stokers. Staged combustion air 

required for pulverized coal boilers and high sulfur residual fuel oil. 

Requires staged combustion air when nitrogen content is greater than 0.2 

percent. 

'0.20 if capacity utilization is less than 30 percent. 

0.70 for pulverized coal boilers; 0.60 for stoker coal boilers. 
TABLE 10. OPTION CASE 1 NSPS AIR EMISSIONS REGULATIONS 

(lb/MMBtu) 

P.13 

Fuel type 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Coal 

Size class 

(MMBtu/hr) 

>50 

>50 

50-250 

>250 

50-100 

100-250 

>250 

so2 

— 

— 

0.80 

0.80 

2.00 

2.00 

1.20 

PM 

— 

— 

0.10 

CD CD O 

• • • 

o o ro 

tn tn o 

N O/ 

0.20 

0.20 

0.30. 

0.25° 

0.60 A 

0.60/0.70° 

0.70 

Low excess air required for natural gas, distillate fuel oil, low sulfur 

residual fuel oil and coal burned on stokers. Staged combustion air 

required for pulverized coal boilers and high sulfur residual fuel oil. 

'Requires staged combustion air when nitrogen content is greater than 0.2 

percent. 

'0.20 if capacity utilization is less than 30 percent. 

0.70 for pulverized coal boilers; 0.60 for stoker coal boilers. 
TABLE 11. OPTION CASE 2 NSPS AIR EMISSIONS REGULATIONS 

(lb/MMBtu) 

P.14 

Fuel type 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Coal 

Size class 

(MMBtu/hr) 

>50 

>50 

50-250 

>250 

50-100 

100-250 

>250 

so2 

— 

— 

0.80 

0.80 

1.00 

1.00 

1.00 

PM 

— 

— 

0.10 

(J 

CD t

n in 

CM CD o 

• • • 

ooo 

NO/ 

0.20 

0.20 

0.30. 

0.25° 

0.60 . 

0.60/0.70° 

0.70 

Low excess air required for natural gas, distillate fuel oil, low sulfur 

residual fuel oil and coal burned on stokers. Staged combustion air 

required for pulverized coal boilers and high sulfur residual fuel oil. 

Requires staged combustion air when nitrogen content is greater than 0.2 

percent. 

c0.20 if capacity utilization is less than 30 percent. 

0.70 for pulverized coal boilers; 0.60 for stoker coal boilers. 
TABLE 12. OPTION CASE 3 NSPS AIR EMISSIONS REGULATIONS 

(lb/MMBtu) 

P.15 

Fuel type 

Natural gas 

Distillat e fuel oi l 

Residual fuel oi l 

Coal 

Size class 

(MMBtu/hr) 

>50 

>50 

50-250 

>250 

50-100 

100-250 

>250 

so2 

— 

— 

0.80 

0.80 

1.00 J 

1.00^ 

1.00c 

PM 

— 

— 

0.10 

0.20. 

0.05° 

0.05 

NO/ 

0.20 

0.20 

0.30. 

0.25° 

0.60 a 

0.60/0.70e 

0.70 

Low excess air required for natural gas, distillate fuel oil, low sulfur 

residual fuel oil and coal burned on stokers. Staged combustion air 

required for pulverized coal boilers and high sulfur residual fuel oil. 

'Requires staged combustion air when nitrogen content is greater than 0.2 

percent. 

'90 percent removal required. 

0.20 if capacity utilization is less than 30 percent. 

J0.70 for pulverized coal boilers; 0.60 for stoker coal boilers.