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OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

323) IV-B-27 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:59 AM Sheet 323 of 325 
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A-83-27 , CORPORATIO N 

^ IV-B-27 

MEMORANDUM 

DATE: July 20, 1987 

TO: Walt Stevenson, EPA/SDB 

FROM: J. Thomas Waddell, Radian Corporation 

SUBJECT: Profitability Analysis on Third-Party Cogeneration Projects 

This memorandum presents "the results of a profitability analysis 

conducted to examine the impact of a percent SO- reduction requirement on 

third-party, coal-fired cogeneration projects. The project chosen for 

analysis is a 55 MW cogeneration facility in Michigan. Design and operating 

parameters were supplied by a third-party cogeneration specialist submitting 

comments on the proposed new source performance standards (NSPS) which limit 

SO- from industrial steam generating units. A return-on-investment (ROI) 

analysis was selected to examine profitability. Two cases, described in 

Table 1, were considered: 1) firing low-sulfur coal to meet State 

requirements, and 2) burning medium-sulfur coal while meeting a 90 percent 

SO- reduction requirement. 

The methodology used in calculating costs for the steam generating 

units, fabric filters, and FGD systems is presented in the SO- Cost Report. 

Costs for the steam generator/turbine set were scaled for correct size from 

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costs provided by Power Systems Engineering. Fuel prices used in this 

analysis reflect the revised energy scenarios. Costs for FGD systems 

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represent "generic" FGD costs. Capital and operating-and-maintenance (O&M) 

costs were updated to 1985 dollars using Chemical Engineering (CE) and BLS 

producer price indices, respectively. 

Revenues for the cogeneration plant come from selling steam to 

industrial users and electricity to an electric utility. The selling price 

for steam was estimated by calculating the cost incurred by an industrial 

user to generate an equivalent amount of process steam itself. The total 

annualized costs, including capital and O&M charges, were calculated using 

Progress Center/3200 E. Chapel Hill Rd./Nelson Hwy./P.O. Box 13000/Research Triangle Park. N.C. 27709/(919)541-9100 
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Case 2: 

TABLE 1. COGENERATION SYSTEM DESIGN AND OPERATING PARAMETERS 

Case 1: 

o Three 200 million Btu/hr, spreader stoker boilers. 

o Each boiler equipped with a fabric filter controlling particulate 

emissions to 0.05 lb/million Btu. 

o Low excess air used for NO control. 

o One 55 MW steam turbine/generator (STG) set. 

o System operates at a capacity factor of 0.85. 

o Burns 0.75 percent sulfur coal. 

Everything in Case 1 included, except system burns 1.88 percent 

sulfur coal. 

Each boiler equipped with a flue gas desulfurization (FGD) system 

operating at 92 percent SO- removal (to account for system 

variability in meeting continuous 90 percent removal requirement). 
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U. S. EPA cost algorithms (IBCOST). These costs were then used to 

determine steam production costs on a dollars per million Btu ($/MMBtu) 

basis. The selling price was assumed to be 5 percent less than this 

production cost, resulting in a steam price of roughly $6.20/MMBtu. 

Electricity was priced at 2.5 cent/kWh. This is based on avoided cost 

energy credits offered by electric utilities in Michigan. 

Results of the analysis are presented in Table 2. The cost of adding 

FGD systems increases capital and O&M costs by 7.5 and 12.7 percent, 

respectively. The ROI when burning low-sulfur coal is 14.9 percent; adding 

FGD systems and burning medium-sulfur coal reduces the ROI by 1.3 percent. 

It should be noted that a capacity credit was not considered in calculating 

revenues. While receiving funds for installed capacity would increase the 

ROI values for both Case 1 and Case 2, the relative impact of 90 percent S0-

reduction would be the same, or about 1.3 percent difference in ROI. 
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TABLE 2. RESULTS OF COGENERATION COST ANALYSIS3 

Case 1 Case 2 

Total Capital Costs ($1,000) 78,936 84,886 

Total O&M Costs ($l,000/yr) 21,210 23,907 

Revenues ($l,000/yr) 32,860 32,860 

Return on Investment (percent) 14.9 13.6 

aAll costs in 1985 dollars. 

Based on present value discounted cash flow and accelerated (ACRS) 

depreciation. 
REFERENCES 

1. Comments of Cogentrix, Inc., to U. S. Environmental Protection Agency. 

Docket No. A-83-27, NSPS for Industrial-Commercial-Institutional Steam 

Generating Units. 

2. Laughlin, J. H., et al. (Radian Corporation). Industrial Boiler S0-

Cost Report. Prepared for U. S. Environmental Protection Agency, 

EPA-450/3-85-011, November 1984. 

3. Memorandum from Shumaker, J. and T. Waddell (Radian Corporation), to 

Porter, F. (EPA/SDB), April 29, 1987. Use of a Generic Cost Algorithm 

to Represent the Costs of Industrial FGD Systems. 

4. Memorandum from Aul, E., and B. Stackhouse (Radian Corporation), to 

Byrne, D. (EPA/SDB), April 15, 1987. Impacts of New Fuel Prices on 

Costs and Cost Effectiveness Values for Industrial Coal- and Oil-Fired 

Model Steam Generating Units. 

5. Energv User News, October 7, 1985. States' Cogeneration Rate - Setting 

Under PURPA, Part 5. 

6. Emission Standards and Engineering Division. Survey of New Industrial 

Boiler Projects--1981-1984. U.S. Environmental Protection Agency, 

EPA-450/3-87-006, April 1987.