Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

fax 703-385-6007

TO: Paul Shriner and Jan Matuszko, EPA

FROM: John Sunda (SAIC) and 

DATE: September 9, 2009

SUBJECT: Cooling Tower 

EPA requested that Tetra Tech 

developing the 316(b) cooling tower compliance

penalty of retrofit cooling towers.

Task: Clarify certain energy penalty 

facilities would be higher than 

condenser replacement, where

California once-through cooling p

Background

The term “energy penalty” can be used in various contexts.

the loss in energy production

facilities. Sometimes energy penalty also includes 

and pumping. For the purposes of estimating compliance costs, both interpretations are 

included.

Energy penalty may also be expressed

average energy penalty data is useful in determining overall annual costs

maximum energy penalty is use

of peak demand during the warmer mon

estimate annual cost would significantly overestimate the costs and using the average 

energy penalty to estimate the impacts on regional capacity w

impact. 

MEMORANDUM

10306 Eaton Place, Suite 340

Paul Shriner and Jan Matuszko, EPA

John Sunda (SAIC) and Kelly Meadows

September 9, 2009

Cooling Tower Energy Penalties

Tetra Tech and SAIC document design assumptions used in 

cooling tower compliance costs. This memo clarifies

penalty of retrofit cooling towers.

energy penalty assumptions, such as whether penalties at 

higher than at coal facilities and whether EPA’s costs include 

, where necessary. Review the assumptions used in the 

through cooling policy and compare them to EPA’s assumptions

can be used in various contexts. Sometimes it refers 

e loss in energy production associated with lower turbine efficiency for retrofit 

facilities. Sometimes energy penalty also includes parasitic power consumption for fans 

For the purposes of estimating compliance costs, both interpretations are 

Energy penalty may also be expressed as the annual average or a maximum. T

average energy penalty data is useful in determining overall annual costs, while

maximum energy penalty is used to estimate impacts on generating capacity 

of peak demand during the warmer months. Using the maximum energy penalty to 

significantly overestimate the costs and using the average 

energy penalty to estimate the impacts on regional capacity would underestimate the 

1

and SAIC document design assumptions used in 

the energy

penalties at nuclear 

facilities and whether EPA’s costs include 

Review the assumptions used in the DOE and 

assumptions.

refers only to 

turbine efficiency for retrofit 

parasitic power consumption for fans 

For the purposes of estimating compliance costs, both interpretations are 

maximum. The annual 

, while the 

on generating capacity for periods 

ths. Using the maximum energy penalty to 

significantly overestimate the costs and using the average 

underestimate the 
2

Estimates of the energy penalty are generally based on the methodology used in the EPRI

cooling tower worksheet. This involves estimating the energy penalty as two separate 

components: one for parasitic power consumption for fans and pumping expressed in 

MW; and one for turbine efficiency loss. A site-specific parasitic loss is calculated for 

each facility based on its flow; the national average is approximately 1.7 percent. 

Turbine efficiency varies by fuel type; nuclear plants operate at a higher pressure and 

would experience a higher loss of efficiency. The overall balance between fossil and 

nuclear (2.0) is consistent with the value used in EPRI’s cooling tower cost estimation 

tool.

Table 1 presents a comparison of the EPA’s estimated energy penalty for replacing oncethrough cooling with closed-cycle recirculating wet cooling towers along with values 

reported in other sources.

Table 1. Summary of Energy Penalty Data

Source Maximum 

Total 

Energy

Penalty

(%)

Annual Average Penalty

Net Pump 

and Fan 

(%)

Turbine 

Efficiency

(%)

Total 

(%)

EPA/EPRI –

Fossil

NA 1.711.5 3.2

EPA/EPRI –

Nuclear

NA 1.712.5 4.2

2002 Phase II 

proposed rule

1.4– 2.0 NA NA 1.5 – 1.8

DOE Phase II22.4 – 4.0 NA NA 0.8 – 1.5

DOE Nuclear3 Up to 5.8 NA NA 2-3

California –

Gas4

NA 1.0 – 2.0 0.8 – 1.3 2.0 – 3.2

California –

Nuclear4

NA 1.4 – 2.6 2.9 – 3.6 5.0 - 5.5

1

Fan and pumping energy is based on cooling water flow. The value of 1.7% shown in Table 1 for net fan 

and pump energy is a calculated average based on the average of the reported DIF flow divided by the 

steam capacity (707 gpm/MW). Estimated individual model facility-specific percent values will vary

above and below this value.

2

Source (DOE 2002). Adopted by EPA in Final Phase II Rule. Developed for coal-fired plants. Data is for 

condenser temperature range of 15oF. 

3DOE Study did not estimate nuclear penalty but cited a previous study of reported values (Veil 1992) with 

a range of 1% to 5.8% and estimated the annual average values would be in the 2% to 3% range. A 

subsequent DOE Study (DOE 2006) estimated nuclear penalty by increasing the coal-fired penalty by 25%.

4

From California cooling water policy. Penalty was calculated for each facility using facility-supplied data. 

Data shown is for several selected examples.

The most recent estimates in Table 1 are from the technical and economic analysis 

supporting the proposed California Power Plant Once-Through Cooling Regulation.1 

 

1

California's Coastal Power Plants: Alternative Cooling System Analysis. February 2008.
3

This study includes a detailed estimation of the energy penalty associated with cooling 

tower retrofit for each electric generating facility in California. These analyses provide 

estimates for each facility and generating unit for the fan energy requirements, the net 

pumping energy requirements, and turbine efficiency reductions; all are expressed as a 

percent of power generation. Fan and pump energy values are conservative as they

assume that fans and pumps will operate at full capacity year round. The turbine 

efficiency loss was calculated on a monthly basis using reported and estimated changes in 

generating unit heat rates. 

Discussion:

Pump and Fan Energy

The California Report estimates for the pump and fan energy penalty component appear 

to be similar in magnitude to EPA’s estimates and are based on basic engineering design 

principles. The DOE analysis includes pump and fan energy requirements as well, and 

examination of several examples shows that the fan and pump energy penalty component 

was around 0.8% at a condenser temperature range of 15oF. One important variable 

throughout these analyses is the condenser temperature rise (or range) which, for any

given plant generating output, will affect the fan and pumping energy in relation to the 

generating capacity. This will affect the values shown in Table 1 which may not 

necessarily be based on the same design conditions. A lower condenser rise will result in 

higher recirculating flows and correspondingly higher energy requirements for fan and 

pumping requirements. The EPA method is not affected by this because it uses actual 

design intake flow values. The temperature ranges used in the California analysis were 

around 18 to 20oF.

Turbine Efficiency

As noted above, a different turbine efficiency penalty is used for fossil and nuclear 

facilities, reflecting the differences in operating pressures in the generating turbines. 

EPRI’s methodology uses a 2% turbine efficiency loss for all facilities and is consistent 

with EPA’s approach; the basis for EPRI’s assumption is not stated in the documentation, 

but (based on our BPJ) is likely to be representative of the maximum value. 

In California’s analysis, average energy penalty estimates are also lower for the gas-fired 

plants and higher for the nuclear plants. A review of the methodology shows that the 

California estimates are based on several conservative assumptions and data selections. 

The approach values selected ranged from 12oF to 16oF, with the 16oF being for the 

nuclear plant with the highest turbine efficiency loss of 3.6%. These values are higher 

than the 10oF value used by and EPRI. The DOE report stated that “the typical 

commercial design is based on an approach....of 8 degrees plus 1-3 degrees to account

for any plume recirculation.”

All of the energy penalty methodologies presented in Table 1 calculated the annual 

average turbine penalty by averaging calculated monthly values. In the California 
4

analyses, each monthly value is based on the maximum wet bulb temperature for the 

month. The DOE analysis used the monthly average wet bulb temperature. The 

difference between the monthly maximum and average wet bulb temperature can be 

significant, and the use of monthly maximum values will skew the California numbers 

higher. Thus, it appears that the annual average turbine efficiency penalty values from 

the California analyses are somewhat overestimated. 

Nuclear Facilities

In a 2008 report,2 DOE estimated nuclear penalty values by assuming that nuclear 

penalties were 25% greater than those for fossil fuel plants. Similarly, a previous DOE 

study (DOE 2006) based fossil-fuel energy penalty estimates on the values reported in the 

2002 DOE study and calculated the nuclear penalty by multiplying the coal-fired penalty

by 25%. 

The total average nuclear energy penalty of 4.2% used In EPA’s cost analysis is 

approximately 30% higher than the non-nuclear penalty of 3.2% and thus is consistent 

with DOE estimates. EPA’s nuclear penalty would still be lower than the California 

study estimates, but as noted above the California study estimates appear to be 

conservatively overestimated with respect to the annual average penalty.

Condenser Modifications

The California analysis assumed that condensers would require modification in the form 

of waterbox reinforcement and tube sheet bracing. This modification was included to 

account for the increase in water pressure associated with the need to pump water through 

the condenser to the top of the cooling towers. A conservative estimate of 5% of all 

direct costs was added to account for condenser modifications. 

The EPRI worksheet instructions state: “The approach to a closed-cycle retrofit used in 

this analysis is the following: The existing once-through cooling system equipment is left 

intact to the extent possible; that is, the condenser, the circulating water pumps and the 

piping connections to the condenser inlet and exit waterboxes are kept the same.” The 

EPRI methodology assumes that the retrofit configuration would be for the cooling tower 

water to be pumped from the condenser effluent channel through the towers to the intake 

pumps inlet using an additional set of pumps. In this configuration, there is no change to 

the condenser hydraulic conditions and thus no need to modify the condenser. 

 

2

DOE. Electricity Reliability Impacts of a Mandatory Cooling Tower Rule for Existing Steam Generation 

Units. October 2008. Accessed at website:

http://www.oe.energy.gov/DocumentsandMedia/Cooling_Tower_Report.pdf