Technical Support Document 

for the Final 

Clean Air Interstate Rule 

Cogeneration Unit Efficiency Calculations 

EPA Docket Number: OAR-2003-0053 

March 2005 

U.S. Environmental Protection Agency

Office of Air and Radiation 

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In the CAIR rule, certain cogeneration units may qualify for an exemption from the 

CAIR. A cogeneration unit can qualify for the exemption if it meets EPA’s definition of a 

cogeneration unit and sells 1/3 or less of its potential electric output capacity. For further 

discussion, see section VIII of the CAIR. To meet EPA’s definition of cogeneration unit, a 

cogeneration unit must meet a minimum efficiency standard. EPA proposed and is finalizing a 

minimum efficiency standard of 42.5% as calculated by using the efficiency formula used under 

the Public Utilities Regulatory Policy Act (“PURPA”). As discussed in the proposal and this 

final rule, a cogeneration unit must meet this minimum efficiency standard regardless of the fuel 

it utilizes. The purpose of an efficiency standard in this rule is to prevent units with very low 

efficiencies from claiming the cogeneration exemption. Without a minimum efficiency standard, 

a potential loop hole would exist for units to claim the exemption by sending a nominal or 

insignificant amount of thermal energy to a process. For further discussion, see section VIII of 

the CAIR. 

The minimum efficiency standard EPA proposed and is finalizing (42.5% using the 

PURPA efficiency formula applied to any fuel) is intended to be a standard that most 

cogeneration units can meet. To demonstrate this, EPA has calculated efficiencies of a range of 

cogeneration units. Some commenters expressed concern that applying an efficiency standard to 

coal-fired cogenerators may adversely impact coal-fired cogenerators because some may not 

meet the efficiency standard and therefore become affected units under the CAIR. This 

document shows that the efficiency standard chosen by EPA is one that most coal-fired 

cogenerators should be able to meet and therefore the standard should not have a significant 

adverse impact on coal-fired cogenerators. 

EPA selected a range of coal-fired cogeneration units from 25 to 250 MWe output and 

calculated the efficiency of each system to determine whether they would meet the minimum 

efficiency required to qualify as a cogeneration unit. This range includes three different 

cogeneration units, two utilizing back pressure turbines and one utilizing an extraction 

/condensing turbine. Back pressure units larger than 100 MWe were not selected because 

generally the larger the back pressure unit the higher the efficiency. Therefore, if a 100 MWe 

unit meets the efficiency standard then EPA feels it is reasonable to assume that larger back 

pressure units would also meet the efficiency standard. A 250 MWe condensing extraction unit 

was chosen because condensing extraction units smaller than 250 MWe are not expected to be 

common due to the higher capital cost of these units compared to back pressure units. Similar to 

back pressure units, generally speaking, efficiency increases as the MW capacity increases and 

thus EPA believes it is reasonable to assume that most condensing extraction units larger than 

250 MWe would also meet the efficiency standard if a 250 MWe condensing extraction unit 

meets the efficiency standard. Coal-fired units were selected, because EPA received no adverse 

comments regarding applying the proposed efficiency standard to oil or gas-fired cogeneration 

units. 

Table 1 below describes each coal-fired cogeneration system selected as well as the 

assumptions used in the calculations. EPA considers these assumptions to be reasonable for the 

units described. In the condensing/extraction case, the greater the process steam flow the higher 

the PURPA thermal efficiency will be. To be conservative, EPA assumed approximately 30% of 

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the turbine throttle steam flow is sent to process. Some condensing/extraction units such as 

those burning low-rank coal or biomass may need to send more than 30% of turbine throttle 

steam flow to process to meet the 42.5% PURPA thermal efficiency standard. EPA expects most 

back pressure units burning low-rank coal or biomass to meet the efficiency standard because 

100% of the throttle steam is sent to process, which has the effect of increasing the unit’s 

efficiency. See Table 2 which shows the higher efficiencies associated with back pressure units 

as compared to condensing/extraction. 

The calculations and results for each representative cogeneration unit are shown in Table 

2 below. The results show that in all cases, the efficiency of the coal-fired cogeneration unit 

meets the minimum efficiency standard for qualifying as a cogeneration unit. Based on this 

analysis, EPA expects most coal-fired cogeneration units will meet this minimum PURPA 

thermal efficiency standard. 

Table 1: Representative Cogeneration Units and Assumptions 

Cogeneration units Operating Assumptions 

25 MW capacity back pressure steam turbine. Turbine Isentropic Efficiency - 80%. 

Inlet steam conditions are 1250 psig, 900 deg Turbine Mechanical Efficiency - 97%. 

F. Outlet steam conditions for process are 165 The cycle includes a direct contact 

psia. All outlet steam is used by the process, feedwater heater - there are no closed 

i.e., no steam is condensed for additional feedwater heaters. Lower Heating 

power output. Assume boiler efficiency of Value (“LHV”) is 3% of Higher Heating 

87% burning bituminous coal. No condensate Value (“HHV”) for bituminous coal. 

is returned from the process. 

100 MW capacity back pressure steam Turbine Isentropic Efficiency - 84%. 

turbine. Inlet steam conditions are 1800 psig, Turbine Mechanical Efficiency - 97%. 

900 deg F. Outlet steam conditions for The cycle includes a direct contact 

process are 165 psia. All outlet steam is used feedwater heater - there are no closed 

by the process, i.e., no steam is condensed for feedwater heaters. LHV is 3% of HHV 

additional power output. Assume boiler for bituminous coal. 

efficiency of 87% burning bituminous coal. 

No condensate is returned from the process. 

250 MW capacity condensing extraction The cycle is based on a system 

steam turbine. Inlet steam conditions are consisting of six closed feedwater 

2400 psig, 1000 deg F. Outlet steam heaters and a direct contact feedwater 

conditions for process is 165 psia. Assume heater. An existing heat balance is used, 

boiler efficiency of 87% burning bituminous which is modified by adding an 

coal. No condensate is returned from the automatic extraction point at 165 psia.1 

process. Boiler efficiency is assumed at 87%. 

Condenser cooling is provided via once 

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through cooling. 

1. R.C. Spencer, K.C. Cotton, and C. N. Cannon, “A Method for Predicting the Performance of Steam 

Turbine Generators - 16,500 kW and Larger,” ASME, Winter Annual Meeting, New York, Revised July 

1974 version. Also, “Heat Rate Improvement Guidelines for Existing Fossil Power Plants,” EPRI CS-4554, 

May 1986. 

Table 2: Cogeneration Unit Calculations 

Cogeneration unit type Backpressure Backpressure Condensing 

Extraction 

Turbine Gross Electrical Output (MW) 25 100 250 

Turbine Net Electrical Output (MW) 23 93 225 

Turbine Net Electrical Output (BTU/hr) 79,332,023 317,328,090 767,818,307 

Turbine Throttle Steam Flow, lb/hr 486,384 1,688,520 1,846,913 

Turbine Throttle Steam Pressure (psig) 1,250 1,800 2,400 

Turbine Throttle Steam Temperature (F) 900 900 1,000 

Turbine Throttle Steam Enthalpy, (Btu/lbm 1,438 1,416 1,461 

Reheat Steam Flow, lb/hr NA NA 1,619,929 

Reheat Steam Enthalpy Gain in Boiler, Btu/lbm NA NA 212 

Process Steam Flow (lb/hr) 400,000 1,385,000 539,000 

Process Steam Pressure (psia) 165 165 100 

Process Steam Enthalpy (Btu/lbm) 1,257 1,208 1,389 

Condenser Pressure (in Hg abs) NA NA 1.0 

Make-up Water Enthalpy (BTU/lbm) 58 58 58 

Process Thermal Output (BTU/hr) 479,600,000 1,592,750,000 717,516,800 

Power to Heat Ratio 0.17 0.20 1.07 

Boiler Efficiency 0.87 0.87 0.87 

Boiler Feedwater Temperature 305 300 400 

Boiler Feedwater Enthalpy (BTU/lbm) 277 265 385 

Fuel Heat Input HHV (BTU/hr) 648,847,437 2,234,474,800 2,678,593,275 

Fuel Heat Input LHV BTU/hr 629,382,014 2,167,440,556 2,598,235,477 

Thermal Efficiency (%)\ 86.1% 85.5% 55.5% 

PURPA Thermal Efficiency (%) 50.7% 51.4% 43.4% 

PURPA Thermal Efficiency Standard (%) 42.50% 42.50% 42.50% 

PURPA Thermal Efficiency = (Net Electric Output + Net Thermal Output/2)/Fuel Heat Input (LHV) 

Thermal Efficiency = (Net Electric Output + Net Thermal Output)/Fuel Heat Input (HHV) 

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