p.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

138) VI-B-3 

Docket Number: 

A-83-27 

Printed 12/3/2008 3:22:20 PM Sheet 138 of 198 
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4 

MMHMI A-83-27 

VI-B-3 

MEMORANDU M 

TO: Fred Porter, EPA/SDB 

FROM: David White, Butch Stackhouse, and Irene Kuo, Radian 

DATE: October 14, 1988 

SUBJECT: Response to API/NFPA Petition Regarding Flue Gas 

Desulfurization System Malfunction Costs 

BACKGROUND 

The American Paper Institute and the National Forest Products 

Association (API/NFPA) petitioned EPA to modify its final regulations on <• 

sulfur dioxide (S02) emissions from industrial boilers (52 Federal Register 

47,826) to allow variances from S02 control requirements during startup, 

shutdown, and malfunction periods. The API/NFPA petition states that EPA 

did not include all the costs associated with maintaining backup fuel 

supplies during periods of flue gas desulfurization (FGD) system 

malfunction. This memorandum examines the issues raised by API/NFPA 

regarding the cost of regulatory compliance during periods of FGD system 

malfunction. 

PREVIOUS ANALYSIS 

The costs for installing and operating backup FGD equipment or 

switching to low sulfur fuels during FGD malfunction periods was examined by 

2 3 EPA in two separate analyses conducted prior to proposal of regulations. ' 

These analyses considered the emissions and costs (in January 1983 dollars) 

associated with controlling S02 emissions from model coal-fired boilers with 

heat input capacities of 100, 150, 250, and 400 million Btu/hour. Fuel 

prices were based on high sulfur coal (5.5 lbs S02/million Btu) in EPA 
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Region V. Several FGD malfunction alternatives were considered: 

o Total flue gas bypass during malfunction periods; 

o Installation of backup scrubbing equipment (i.e., absorber plus 

associated pumps and tanks, but not spare feed preparation or 

solids separation equipment); and 

o Installation of fuel storage and handling equipment to allow use 

of low sulfur fuels such as natural gas and low sulfur fuel oils. 

2 

The first of these two analyses assumed that dual alkali scrubbing was used 

3 

for FGD, while the second analysis was based on sodium scrubbing. 

The annualized costs of the backup FGD and low sulfur fuel options were 

compared to the total bypass option. For all the cases examined, the total 

annualized cost of the boiler and FGD system was 1 to 4 percent higher when 

using the backup FGD or low sulfur fuel options than when allowing total 

bypass. The cost effectiveness values ranged from $326/ton SO- removed when 

a spare FGD system was used to $2,029/ton S02 removed when using 0.3 lb 

S02/million Btu fuel oil. 

CURRENT ANALYSIS 

The analysis presented in this memorandum reexamines the cost of 

controlling S02 emissions during FGD malfunctions based on (1) the issues 

raised by API/NFPA regarding the cost of maintaining backup fuel supplies 

and (2) changes in fuel prices and FGD equipment assumptions made since the 

4 

time of the previous analyses. This analysis also considers liquefied 

petroleum gas (LPG) as an alternative backup fuel. To better examine the 

cost and emission impacts specific to the pulp, paper, paperboard, and wood 

products industries, this analysis focuses on a 400 million Btu/hour model 

boiler located in EPA Region IV. Use of two different coals were included 

in the analysis: a high sulfur bituminous coal (H-bituminous, 5.5 lbs 

S02/million Btu) as was used in the previous analyses and a medium sulfur 

coal (F-bituminous, 2.8 lbs S02/million Btu) as was used by API/NFPA 1n 

their petition. The new analysis also includes annual fuel demand charges 
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and storage costs for backup fuels (such as natural gas, LPG, and low sulfur 

oil) which API/NFPA stated were necessary to assure fuel availability during 

periods of FGD malfunction. 

Most of the costs used in this new analysis were taken directly from 

Reference 4 which was prepared in early 1987 and assumed that natural gas 

would be used during periods of FGD malfunction. These costs differ from 

those presented in References 2 and 3 in three areas: 

o Use of revised fuel prices reflecting lower projected fuel oil and 

natural gas prices, 

o Use of a "generic" algorithm for estimating FGD costs, and 

o Updating of all costs from January 1983 dollars to June 1985 

dollars. 

To update the cost of backup FGD systems in References 2 and 3 from 

January 1983 to June 1985, capital costs were multiplied by 1.03 based on 

the Chemical Engineering Plant Index and non-fuel operating and maintenance 

(O&M) costs were multiplied by 1.035 based on the Bureau of Labor 

Statistics' Index of All Industrial Commodities. 

The options examined in the current analysis for compliance during FGD 

malfunction include installation of backup FGD equipment, use of natural 

gas, use of low sulfur oil (0.3 lb S02/mill1on Btu), and use of LPG. The 

annualized cost of backup FGD equipment was based on the average of dual 

alkali scrubbing costs from Reference 2 and sodium scrubbing costs from 

Reference 3; these costs were escalated from January 1983 to June 1985 

dollars as discussed in the preceding paragraph. The natural gas 

alternatives are based on non-carriage, rigid natural gas prices. Analysis 

of low sulfur oil include the use of 0.3 lb S02/million Btu distillate oil 

and 0.3 lbs S0,/million Btu residual oil. The LPG alternative assumes the 

6 price for LPG is equivalent on a Btu basis to that of the distillate oil. 

Capital costs associated with firing natural gas, LPG, distillate oil, 

and residual oil during FGD malfunctions are $148,000, $2,557,000, $692,000, 

and $1,029,000, respectively. These estimates reflect the cost of LPG, 

distillate oil, and residual oil storage and handling facilities (sufficient 
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to operate the boiler for seven days at full load), boiler modifications, 

fuel gun Installations, special oil heating and pumping equipment to handle 

the residual oil, and a vaporizer and mixer for the LPG. These costs were 

derived from References 7 and 8. The estimated costs of residual oil 

facilities are similar to those provided 1n the API/NFPA petition. 

The capital cost for the LPG fuel storage and handling equipment 1s 

relatively expensive due to the large number of tanks needed for a seven day 

supply. The cost of the tanks alone make up for almost 87 percent of the 

8 total direct cost. The large number of tanks 1s due to size limits on 

individual storage tanks used for storing pressurized LPG 

(60,000 gallons/tank). As a result, the number of tanks needed (and the 

associated capital cost) varies linearly with the amount of backup fuel 

required. On a site-specific basis, underground storage of LPG may be less 

expensive than in above ground pressurized tanks. Indirect costs for 

engineering, construction fees, start-up, and contingencies were added 

4 

based on previously used percentages of direct costs. 

Tables 1 and 2 present costs and cost-effectiveness values for each of 

these compliance options for a model 400 million Btu/hour boiler firing a 

medium sulfur coal (F-bituminous) and a high sulfur coal (H-b1tuminous), 

respectively. The natural gas options include (1) a baseline case that 

assumes no additional charges are imposed by the natural gas supply company 

to assure delivery of natural gas on a short-term non-interruptlble basis 

during FGD malfunction, and (2) two alternative cases based on a demand 

charge by the natural gas supplier of $7/million Btu/day/month and 

$12/million Btu/day/month to assure gas delivery on a short-term 

non-interruptible basis. The additional charges were identified by 

API/NFPA as costs that EPA had overlooked in prior analyses. This range of 

demand charges was based on jnformtion provided to EPA by API/NFPA 1n a 

g 

meeting to discuss their petition. 

The LPG and the low sulfur oil options include the cost of maintaining 

a fuel inventory for use during FGD malfunction. This cost 1s handled as an 

amortized capital charge to recover the cost of the initial fuel supply used 

to fill the fuel storage tank(s). Fuel used to refill the tank after an FGD 

malfunction is an annual 0&M expense. The fuel inventory expense was 

identified by API/NFPA as a cost that had been overlooked 1n prior analyses. 
usssaxaxs 

U l 

TABLE I . COST ANALYSIS OF ALIERHAIIVE HAIFUHCIION PROVISIONS FIRINE FRI T COAl IH REGION IV (i l 

CAPITAL COST ANNOAIIIED COST 

" " " INCREASED TOTAL ANNUAL AVERAGE COST 

HALFUNCIION MILER I FUEL FUEL TOTAL UILER I FUEL FUEL FUEL TOTAL ANNUAL!m> PERCENT 502 EFFECTIVENESS 

ONIONS S02 COMROl BURNING INVEN- BOILER S02 CONTROL MIMING INVEN- SWITCH HILER COSIS, I d INCREASE, EHISSIONS, l/TOM SOI ' 

EOUIPHENI EBUIPHENI TORT lb) EOUIPHENI EOUIPHENI TORT IIOOO/YR I TONS/YR It)) REHOVU I d 

••sssajsaKsnaaKsssscssBssisasjExs s**xxx*4*4tm***m**mxvu%***a\mmmwmn**KBaa**xamKmK%ttZMnx*,n*mmm»UBKBWB*K»*uum*m* •tisannuuciiiiMBaiHiiiNtEAtitBiiifxiszKiBisuiiuituuuitiBHtiuitajiaana ^ 

TOTAL BYPASS 16,744 

STARE FGD EOUIPHENI I O 37,509 

NATURAL GAS 34,744 

NAIURAL GAS 36,744 

(HUH A 47/MMIH KHAND CHARGE) <«) 

NATURAL GAS 36,744 

(HUH A II2/H0NTH BEMNt CHARGE) l|) 

LIOUEFIED PETROLEUM GAS 36,744 

IISIIUAIE OIL 16,744 

IO.I Ik S02/ •illi m »tu) 

0 

0 

148 

141 

141 

2,557 

692 

H/A It) 36,744 

N/A 17,501 

N/A 34,892 

N/A 34,892 

N/A 34,892 

261 19,362 

261 37,697 

11,705 

15,(36 

15,705 

15,705 

RESIDUAL OIL 16,744 1,029 221 37,996 

10.1 Ik S02/ •illioo IU ) 

R»iMii£taEtxtNiuiii>Biiis:A3»33i;::tEi3sis:3i33iiictiE3axtseittt::saai3Xiuti>tiU3Gtus i 

0 N/A 

0 N/A 

25 N/A 

25 N/A 

0 15,705 

0 15,836 

140 15,870 

946 16,477 

15,705 23 N/A 1,522 17,253 

15,705 439 45 141 14,310 

15,705 119 45 141 14,009 

15,703 174 38 81 16,001 

131 

145 

972 

I,SAB 

425 

304 

294 

I 

I 

6 

10 

4 

2 

177 

240 

228 

228 

228 

228 

243 

243 

954 

1,110 

4,522 

10,388 

4,193 

2,272 

2,207 

!B«nallllBttBI«l«inMH*lttCBI3X3tataiI(IC333ia3aS31XE£CS(*tai*CCiaS33333MUXS131UaiNUUaaB*2tB t 

U ) All COSTS IN 1000 1985 DOLLARS FOR A 400 BILLION ITU/HR MODEL I0ILER. 

lb) INI HAL COSI OF FUEL INVENTORY ASSUMING A 7 DAT SUPPLY 

Id IHE INCREHENTAL ANALYSIS IS OVER THE TOTAL BYPASS OPTION. 

It)) OASED ON 921 S02 CONIROL EFFICIENCY AHD 951 SCRUBBER RELIABILITY. 

It) N/A = NOI APPLICABLE 

I O GENERIC FLUE GAS DESULFURI/AIION IS BASED ON THE COSIS OF DUAL AltALI AND SOOIUH SCRUBBER SISTERS. 

(gl OEHAND CHARGES RANGE FROH I7-M2/HILL10H BIU/DAV/nOHIH 
o» 

TABLE 2. COST ANALYSIS OF AITERHAIIVE HALFUNCIION PROVISIONS FIRING H-BII COAL IH RE6I0N IV U l 

CAPITAL COSI ANNUALWED COST 

-

 :

 - INCREASED TOTAL ANNUAL AVERAGE COST 

HALFUNCIION BOILER I FUEL FUEL IOIAL BOILER t FUEL FUEL FUEL TOTAL ANNUALUEO PERCENT S02 EFFECTIVENESS, 

OPTIONS S02 CONTROL BURNING INVEN- BOILER S02 CONTROL BURNING INVEN- SNITCH BOILER COSIS, I d INCREASE, EHISSIONS, l/ION S02 

EOUIPHEHT EOUIPHENI TORY (bl EOUIPHENI EOUIPHENI TORY IIOOO/VR I TONS/YR (Al RENSVEB (c ) 

IOIAL BYPASS 

SPARE ABSORBER I O 

NATURAL GAS 

17,148 

18,114 

17,368 

NATURAL GAS 17,348 

(NITH A 17/NONIH OEHAND CHARGE) l|) 

NAIUtAL GAS 16,744 

(NITH A M2/HONIH OEHAND CHARGE) (| l 

II0UEF1EI PEIROLEUH GAS 

DISTILLATE OIL 

(0.3 Ik SOJI •illioo Btu) 

KSlkUAL OIL 

17,368 

37,168 

17,168 

0 

0 

148 

148 

I4B 

2,557 

692 

1,029 

N/A lit 

N/A 

N/A 

N/t 

N/A 

261 

261 

221 

17,168 

18,114 

37,516 

37,514 

34.B92 

40,186 

38,321 

18,620 

15,650 

15,781 

15,650 

15,650 

15,650 

15,650 

15,650 

15,630 

0 

0 

25 

25 

23 

439 

119 

174 

N/A 

N/A 

l/A 

N/A 

N/A 

45 

45 

38 

0 

0 

163 

949 

1,545 

164 

144 

104 

15,450 

15,781 

15,838 

14,445 

17,221 

14,297 

15,977 

15,949 

-

I l l 

IBB 

995 

1,571 

447 

127 

119 

-

1 

1 

4 

10 

4 

2 

2 

714 

464 

441 

443 

441 

443 

438 

458 

-

489 

447 

3,418 

5,198 

2,224 

1,184 

1,155 

(0.1 Ik S02/ •illiM IU) 

as sa aass *s BS ;s3»ES3»a8a«cazax3* s » s ss^ 

U> A U COSTS IN 1000 1985 DOLLARS FOR A 400 HILLION BTU/HR ROOEL BOILER. 

lb) INITIAL COST OF FUEL INVENTORY ASSURING A 7 DAY SUPPLY 

Id THE INCREMENTAL ANALYSIS IS OVER IHE TOTAL BYPASS OPTION. 

I l l BASEI ON 921 S02 CONTROL EFFICIENCY ANO 951 SCRUBBER RELIABILITY. 

I l l N/A • NOI APPLICABLE 

IO GENERIC FLUE GAS BESULFURUATIDN IS BASED ON IHE COSTS OF SPRAY DRYING AND SOO I LB SCRUBBER SYSTEHS. 

(9) RERAN) CHARGES RANGE FROH I7-JI2/HUUO M BIU/DAY/M1NIH 
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The cost increases associated with providing backup FGD equipment or 

low sulfur fuel capability relative to flue gas bypass range from 1 to 6 

percent in all cases except when a $12/million Btu/day/month demand charge 

for natural gas is assumed. In this case, the Increase in annualized costs 

are 10 percent higher than if flue gas bypass is allowed. Note that these 

percentages and the incremental dollar costs are roughly equal for both 

medium sulfur coal and high sulfur coal analyses. Note also that the total 

annualized cost of operating the boiler and FGD system (including spare FGD 

equipment or fuel switching during malfunction) with high sulfur coal is 

generally $30,000 to $50,000 less than with medium sulfur coal. 

While the annualized costs are similar for both coals, the 

cost-effectiveness values for medium sulfur coal are roughly double those 

for the high sulfur coal due to the smaller annual S0« emission reductions. 

For medium sulfur coal, the cost-effectiveness values range from $596/ton 

SO- removed based on use of spare FGD equipment, to $1,110/ton for natural 

gas with no demand charge, to $2,206-2,271/ton for the two low sulfur oil * 

options, to $4,193/ton for LPG, to $6,522-10,388/ton for the two natural gas 

options with a demand charge. For high sulfur coal, the cost-effectiveness 

values range from $489/ton SO* removed based on use of spare FGD equipment, 

to $647/ton for natural gas use without a demand charge, to $1,155-1,186/ton 

with the two low sulfur oil options, to $2,224/ton for LPG, to 

$3,418-$5,398/ton for the two natural gas options with a demand charge. 

COMPARISON OF PREVIOUS AND CURRENT ANALYSES 

For high sulfur coals, the annualized costs in the current analysis for 

each of the examined control options relative to flue gas bypass are less 

2 3 than or roughly equal to those presented in the previous analyses, ' except 

when natural gas demand charges ($7/million Btu/day/month and $l2/m1llion 

Btu/day/month) are included. As a result, cost-effectiveness values for 

high sulfur coal are less than those in the previous analyses except when 

natural gas demand charges are assumed. This decrease in cost-effectiveness 

values is primarily due to the lower fuel price differential between coal 

versus natural gas and low sulfur oils. 
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For the medium sulfur coal (which was not examined in the earlier 

analyses), cost-effectiveness values estimated in the current analysis for 

in the cases of natural gas without a demand charge and low sulfur oil are 

generally similar to those presented in the earlier analyses based on high 

sulfur coal. The current cost-effectiveness values are higher, however, 

when spare FGD equipment or natural gas with a demand charge is assumed. 

The similarity in cost-effectiveness values for natural gas without a demand 

charge and low sulfur oil reflects the trade-off between lower fuel price 

differentials in the current analyses and the lower emission reductions when 

medium sulfur coal is used. The higher cost-effectiveness values for the 

backup FGD equipment option reflects similar costs but lower emission 

reductions with medium sulfur coal, whereas for the natural gas demand 

charge options, the emission reductions are lower and the annualized costs 

are higher. 

8 
P.10 

I' 

REFERENCES 

1. Petition for Reconsideration of the American Paper Institute and the 

National Forest Products Association. Standards of Performance for New 

Stationary Sources; Industrial-Commercial-Institutional Steam 

Generating Units. Docket No. A-83-27. 

2. Memorandum from Margerum, S.C, Radian Corporation, to Sedman, CB . 

April 6, 1984. FGD System Malfunction Costs. 

3. Memorandum from Martinez, J.A., Radian Corporation, to SO- Docket 

Files. January 8, 1986. Update on Flue Gas Desulfurization System 

Malfunction Costs. 

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

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

and Procedures Used to Generate Model Boiler Impacts. 

5. Letter from Hogan, T., Energy and Environmental Analysis, Inc., to 

Pahel-Short, R., EPA/EAB. Annualized Industrial Natural Gas Prices. 

August 27, 1986. 

6. Letter from Hogan, T., Energy and Environmental Analysis, Inc., to 

Pahel-Short, R., EPA/EAB. Industrial Liquefied Petroleum Gas (LPG) 

Prices. September 7, 1988. 

7. PEDCO Environmental, Inc., Capital and Operating Costs for Industrial 

Boilers. Prepared for U.S. Environmental Protection Agency. Research 

Triangle Park, NC. Publication No. EPA 450/5-80-007. June 1979. 

8. Telecon, Kuo, I.R., Radian Corporation with Stocker, J., Thomas 

Associates. September 28, 1988. Discussion of LPG equipment and cost. 

9. Memorandum of Meeting from Porter, F.L., EPA/SDB, to File. 

September 22, 1988. Meeting with American Paper Institute Regarding 

Industrial Boiler NSPS.