MEMORANDUM

Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

fax 703-385-6007

TO: Paul Shriner and Lisa Biddle, EPA

FROM: John Sunda, Tetra Tech

DATE: June 24, 2013

SUBJECT: Evaluation of EPRI and Riverkeeper Closed-Cycle Cost Estimates

Comparison of EPA to EPRI Costs

In 2007 EPRI provided to EPA a cost worksheet for estimating closed-cycle cooling system 

retrofit costs at power plants. This worksheet included capital cost factors for retrofits of varying 

difficulties. These costs factors were developed based on actual and estimated costs for closedcycle retrofit projects at approximately 50 different power plants. EPA adopted and incorporated 

the cost approach and costs factors in the 2007 EPRI worksheet in the cost methodology used to 

estimated closed-cycle recirculating system (CCRS) retrofits for cost options involving the 

performance requirements based on CCRS technology or its equivalent. Subsequent EPRI

worksheet submissions contained no revisions to the methodology. However, EPRI did conduct

further research and apparently made some changes to their cost estimation approach, the results 

of which was presented in the Closed-Cycle Cooling System Retrofit Study (Technical Report # 

1022491) in 2011 which was included as an attachment to their Proposal public comment. This 

more recent study includes additional cost data from a total of over 80 different power plants and 

appears to be the culmination of EPRI’s effort to derived costs for closed-cycle retrofits at power 

plants. EPRI was able to incorporate into their methodology site-specific facility data obtained 

through a survey they conducted that was not made available to EPA. While the EPA cost 

estimates included consideration of all plants with a DIF >2 MGD, this study focuses on 

compliance costs for requiring closed-cycle cooling for power plants with a design flow >50

MGD that fell within the scope of the 316(b) Phase II Rule. This memo identifies the changes 

EPRI made in the methodology since 2007 and an analysis of differences in the cost 

methodology approach and resulting cost estimates between EPA and EPRI for CCRS 

technology retrofits at generating facilities. The discussion below is divided into major cost 

components.
Capital Costs

EPA based the Proposed Rule cost estimates for closed-cycle cooling systems on EPRI cost 

factors and calculations from their draft Tower Calculation Worksheet provided to EPA by EPRI 

in September 2007. These data are assumed to reflect 2007 dollars. The 2007 EPRI worksheet 

developed capital costs for three scenarios; easy, average, and difficult. For the capital cost 

component for power plants EPA made a reasonable assumption that the average difficulty cost 

would be borne by the typical plant. Using the EPRI Cost Worksheet plus regional cost factors 

EPA derived a national cost for an average difficulty retrofit of $249/gpm (in 2007 dollars) 

which becomes $263/gpm when adjusted to 2009 dollars. However, EPA realized that a 

requirement to install cooling towers at all power plants may include a larger portion of those 

with more difficult and costly retrofit design components, such as plume and/or noise abatement,

than was included in the facilities considered by EPRI in the development of the average 

difficulty cost factor. To account for this EPA adjusted the costs upward by approximately 11% 

from $263/gpm to $293/gpm (both costs are adjusted to 2009 dollars) to account for the need for 

plume/noise abatement at an estimated 25% of the facilities. EPA did not apply a different 

capital cost factor for nuclear plants since EPRI did not make such a distinction in the 2007 

spreadsheet and the EPRI supporting data was inconclusive in this respect, indicating a cost 

difference of no greater than 10%.

The 2011 EPRI Study (EPRI Report # 1022491) used a slightly more complex approach than 

presented in their 2007 Cost Worksheet which included the same three retrofit difficulty

categories (Easy, Average, Difficult) plus 3 more categories: an additional “More Difficult” 

category for fossil-fuel plants and two for nuclear plants (Less Difficult Nuclear, More Difficult 

Nuclear). The EPRI cost estimates used survey data obtained independently by EPRI that was 

not available to EPA to assign different factors for different subsets of facilities. This allowed

EPRI to conduct a more complex cost analysis utilizing site-specific data. No details are 

provided concerning the assignment of retrofit level of difficulty to different facilities. An overall 

EPRI $/gpm value can be derived by dividing the EPRI estimated total capital cost for all Phase 

II Facilities of $62,060 Million by the total EPRI cooling flow of 182,296,000 gpm (EPRI 

102491 Table 8-18). The resulting EPRI 2010 overall capital cost factor is $340/gpm. The EPA 

equivalent value of $302/gpm ($293 adjusted for inflation from 2009 to 2010) used in the EPA 

cost estimates for all generating plants is only 11% lower the EPRI average. This difference is 

well within the expected range of accuracy of preliminary estimates of this type.

1

EPRI included re-optimization of the cooling system for all nuclear plants and about half of 

base-load fossil-fuel plants. Re-optimization is the redesign of the cooling system such that the 

cooling flow is reduced and condenser temperature rise (range) is increased allowing for smaller 

towers, smaller pumps and piping and less pumping energy requirements. Re-optimization 

involves modifying the cooling system design to operate efficiently at a lower cooling flow rates 

requiring an additional retrofit cost associated with upgrading the condensers (e.g., from singlepass to double-pass) plus the required additional downtime to modify the condensers. The EPRI

re-optimization scenario assumes the cooling flow would be cut in half but EPRI does not reduce 

the cooling tower retrofit capital costs associated with a smaller tower, pumps, and pipes because 

 

1 Class 4 level (Study or Feasibility) cost estimates generally have an expected range of accuracy of -30% to +50% 

(AACE 2004).
they concluded that the added costs of upgrading the condensers from single-pass to double-pass 

would offset any cost savings of the smaller closed-cycle system. The assumption that these 

costs would offset each other is reasonable. While EPRI’s approach to including re-optimization 

did not affect capital costs, it did include a substantial increase in downtime duration and a 

reduction in operating energy requirements.

Downtime

EPRI stated that their downtime duration estimate for nuclear plants was based on a limited 

number of independent engineering studies and information from a few actual retrofits at fossil 

plants. EPRI states that “there is relatively little information available to support generalized 

estimates of this cost element.” EPRI used their site-specific survey data to assign different 

downtime estimates to individual plants based on assumed downtime estimates for assigned 

categories. Based on available data, EPA used a simpler approach assuming an average net 

downtime of one month for fossil fuel plants and either zero months or six months for nuclear 

plants depending on whether they would have the opportunity to schedule the closed-cycle 

retrofit to coincide with an extended capacity uprating (ECU). See the Economic Analysis for 

Final 316(b) Existing Facilities Rule for more details. Table 1 presents a comparison of the 

downtime duration assumptions used by EPRI and EPA in estimating downtime costs. Table 2

shows the reported distribution of retrofit difficulty by generating capacity and the corresponding 

months of downtime duration.

Table 1

Summary of Assumed Downtime Duration Used by EPRI and EPA 

For Estimating Cooling Tower Retrofit Downtime Costs

Fuel Type Retrofit 

Difficulty

EPRI 

Downtime

EPA

Downtime

Months Months

Fossil-fuel Easy & Average 0 1

Fossil-fuel Difficult 4 1

Fossil-fuel More Difficult 6 1

Fossil-fuel Re-optimized 6 1

Nuclear All 6 0 or 6
Table2

EPRI Distribution of Generating Capacity by Retrofit Difficulty Type

Fuel Type Difficulty

Percent 

of Fuel 

Type

Months*

Fossil-fuel Easy 22% 0

Fossil-fuel Easy to Average 10% 0

Fossil-fuel Average 26% 0

Fossil-fuel

Average to 

Difficult 13% 2

Fossil-fuel Difficult 24% 4

Fossil-fuel More Difficult 5% 6

Fossil-fuel

Weighted 

Average 100% 1.5

Nuclear Less Difficult 30% 6

Nuclear More Difficult 30% 6

Nuclear Intermediate 40% 6

* Assumes average value was applied (e.g., Average to Difficult is assumed 2 - average of 0 and 4)

One major difference in the EPRI approach that affected downtime costs was to assume that 

certain facilities would chose to re-optimize their cooling system. It is reasonable to expect that

the decision to re-optimize would be based on an economic analysis to determine the least cost 

option over the long term. It is expected that a facility would only choose to re-optimize if it 

would result in a reduction in the overall costs over the long term. Such a cost analysis would 

take into consideration, expected plant life, capital costs, downtime costs, operating costs 

(materials, chemical treatment, labor, auxiliary pump and fan energy) , and the effect on heat rate 

penalty. For plants with high capacity factors and substantial remaining plant life, the added 

downtime and condenser costs should be more than offset by the savings in O&M and auxiliary

energy and heat rate penalty costs.

EPRI’s re-optimized system costs only included the increase in downtime duration costs plus a 

reduction in fan and pumping auxiliary energy costs by 50% commensurate with the reduced 

cooling flow. EPRI’s increase in downtime for re-optimization was six months and resulted in an

additional lost generation cost for downtime for roughly 15% of the total fossil-fuel generating 

capacity analyzed by EPRI. None of the other potential savings in operating costs or heat rate 

penalty are included in EPRI’s cost estimates and, as a result, it appears that their application of 

re-optimization resulted in a net increase in overall costs. A properly designed re-optimization 

cost estimate should result in long term cost savings when compared to a system designed for the 

existing condenser flow for units that choose to re-optimize. Recognizing that re-optimization 

should result in lower costs, EPA chose the more conservative approach and did not consider the 

potential cost savings of re-optimization because of the limited data available and complex 

nature of such an analysis. EPA’s selection of relatively high values for the heat rate penalty is

consistent with this approach.

If re-optimization is not included in the EPRI analysis, based on the distribution in Table 2, the 

aggregated average EPRI downtime duration for fossil-fuel plants would be around 1.5 months. 

This is roughly comparable to the EPA estimate of 1.0 month for all fossil-fuel retrofits given the 

uncertainty of the true value of the estimated downtime duration assigned. Factoring in the 6 
months extra downtime for re-optimized plants, the average downtime assigned to fossil-fuel 

plants is 2.4 months. EPA’s revised net nuclear downtime is the same as that used by EPRI.

However, for many nuclear facilities that have not yet conducted an ECU, EPA has assumed the 

net downtime value will be zero.

The decision to include re-optimization I the analysis increased the average downtime duration 

by nearly one month for fossil-fuel plants. One inconsistency in EPRI’s downtime analysis is 

that the extra costs of downtime for the re-optimized units are much greater than the projected 

savings in energy costs over a 30 yr. timeframe. Since facilities would choose re-optimization 

only if it would reduce long term costs, then it is likely the EPRI assumptions regarding reoptimizations are either incorrect or incomplete in that there are likely to be additional cost 

savings that are not accounted for. One of these savings is that re-optimization may result in a 

smaller heat rate penalty. Thus a portion of the EPRI downtime costs should be offset by savings 

in long term operating costs that are not included in the EPRI analysis.

In support of 6 month longer downtimes for complex retrofits, EPRI cited engineering estimates 

for four large nuclear plants. The estimated total downtime ranged from 5 months for Oyster 

Creek, 10 months for Indian Point Units 2 and 3, 17 months for Diablo Canyon, and just under 

22 months for San Onofre (ENERCON 2010, URS 2006). EPRI assumed that since nuclear 

plants operate as base-load and would have relatively long remaining service life (NRC license 

renewals are typically 20 years), re-optimization would be included in the retrofit design. EPA 

arrived at the same 6 month net downtime estimate using a different approach based on a gross 

downtime derived under Phase III minus the expected 8 week minimum duration of in-service 

inspection conducted every 5 years.

Heat Rate Energy Penalty

The heat rate penalty associated with conversion from once-through to closed-cycle cooling is 

the direct result of the difference in turbine backpressure2that result from changes in the cooling 

water temperature that is associated with the change in cooling water source. These changes vary

considerably for different locations, time of year, meteorological conditions, source water 

conditions, tower design and operation, and turbine design. As such, the lack of site-specific 

conditions and system design data for the model facilities make it very difficult to estimate 

“typical” or “annual average” heat rate penalties. In the EPA cost analysis heat rate penalties are 

expressed as a percent of steam generation. Estimates of heat rate penalties from different source 

have varied considerably. For the cost estimation for estimating heat rate penalty costs EPA 

selected a value of 1.5% for fossil steam generating units and 2.5% for nuclear steam generating 

units. EPA selected these relatively conservative (on the high side) values based on the range of 

1.5-2.0% provided by EPRI previously. A larger value was selected for nuclear because penalties 

tend to be greater for steam units that operate at lower throttle pressures.

The analysis included a detailed evaluation of heat rate penalties at several example facilities in 

seven different waterbodies/regions of the US. Since the slope of turbine performance curves 

varies with temperature, EPRI estimated heat rates for different conditions. They estimated that 

for higher temperatures on hot days the average heat rate will change by 2.0% for each 1.0 inch 

 

2 Turbine backpressure is typically less than atmospheric pressure and is expressed in inches of Mercury (in. Hg).
of Hg difference in backpressure. And that for the general range of temperatures over the entire 

year the average heat rate will change by 1.0% for each 1.0 inch of Hg difference in 

backpressure. Thus, for the annual average, a difference in backpressure of 0.5 in Hg will result 

in a heat rate penalty of 0.5%. For the cost estimates, EPRI assumes that the hot day period lasts 

for 10% of the year and that the equivalent cost is $35/Mwh. Table 3 presents the calculated hot 

day and annual average differences in turbine backpressure for the seven different waterbody

/region example facilities along with the calculated heat rate penalty based on assumptions which 

are not shown in the EPRI Report. This data shows that the average heat rate penalty for the 

seven facilities evaluated by EPRI can vary from <0% to 2.3%, depending on the time of the 

year and location. EPRI’s description of their heat rate penalty cost calculations indicates that 

they used the average hot day and annual average values of the seven case studies. EPRI’s only 

distinction between nuclear and fossil-fuel units was in the assumed capacity utilization rates. 

EPA used a similar approach of applying average heat rate penalty values for the entire nation.

The EPRI estimation methodology described should produce an equivalent annual average heat 

rate penalty of 0.9%. However, in reviewing heat rate penalty costs reported in Table 8-17 of the 

EPRI Technical Report #1022491, it is apparent that the EPRI estimated heat rate penalty costs 

are not calculated as described in the text. The EPRI calculations use the “%/in Hg” heat rate 

penalties of 2.0% and 1.0%, for hot day and annual average periods, respectively, instead of the 

1.2% and 0.9% values that are derived by multiplying the backpressure increase with the “%/in 

Hg” shown in Table 3. As a result, the EPRI costs are based on an estimated average value of 

1.1% which is approximately 20% higher than it should be if the described method were 

followed. Regardless, with respect to heat rate penalty, the EPA estimated annual average heat 

rate penalty of 1.5% for fossil-fuel and 2.5% for nuclear facilities is greater than those used by

EPRIs by factors of 1.4 to 2.3, respectively.

Table 3

Results of EPRI Case Study Heat Rate Penalties

Region/

Waterbody

Hot Day Annual Average Heat 

Rate 

Penalty -

Time 

Weighted 

Average2

Backpressure 

Increase 

(inch Hg) 1

Assumed 

Penalty 

per Inch 

Hg

Heat 

Rate 

Penalty

Backpressure 

Increase (in. 

Hg) 1

Assumed 

Penalty 

per Inch 

Hg

Heat 

Rate 

Penalty

1 North Atlantic--

Off-shore 1.15 2% 2.3% 1.13 1% 1.1% 1.2%

2 South Pacific—

Offshore 0.74 2% 1.5% 0.95 1% 1.0% 1.0%

3 South Atlantic--

Shoreline intake 0.46 2% 0.9% 0.61 1% 0.6% 0.6%

4 Great Lakes 0.34 2% 0.7% 1.41 1% 1.4% 1.3%

5 Large River--

North Central 1.12 2% 2.2% 0.79 1% 0.8% 0.9%

6 Small River--Mid 

Atlantic 0.57 2% 1.1% 0.72 1% 0.7% 0.8%
7 Small lake—

South Central -0.09 2% -0.2% 0.55 1% 0.6% 0.5%

Average30.6 2% 1.2% 0.9 1% 0.9% 0.9%

Values Used by 

EPRI4 2.0% 1.0% 1.1%

1 Source: Tables 7-3 and 7-4 of EPRI Technical Report #1022491 

2 Equivalent EPRI overall annual rate based on assumption that hot day penalty applies to 10% of hours in the year

3 Average of values reported in Tables 7-3 and 7-4

4 Values based on costs provided in Table 8-17 of EPRI Technical Report #1022491 

Auxiliary Pump and Fan Energy Requirements

EPA used a factor of 0.0000245 MW/gpm as the basis for estimating the auxiliary (pump and 

fan) energy requirement. This factor was derived from aggregated model facility data and the 

draft EPRI cooling tower cost worksheet and certain assumptions plus modifications to account 

for partial use of plume abatement. The EPRI Technical Report #1022491 estimates that the 

auxiliary energy requirement will range from 0.85% to 1.5% of plant output. Using the EPA 

factor this is equivalent to cooling flow values of 350 to 700 gpm/MW of generation. EPRI 

reports in Table 7-1 that the expected range of cooling water flow, expressed in gpm/MW, is a 

low of 400 and a high of 800. The general agreement of these ranges confirms that the EPA 

estimates are similar in magnitude to those of EPRI.

Comparison of EPA to Powers Engineering (Riverkeeper) Costs

Appendix D to Riverkeeper’s public comment to the Proposed Rule contains “Powers 

Engineering comments on EPA 316(b) March 28, 2011 TDD”. Powers Engineering is hereafter 

referred to as PE. The PE comment document includes among other things an analysis of the 

reasonableness of cooling tower retrofit capital costs identified by EPA, the turbine efficiency

penalties, cooling tower auxiliary fan and pump loads, and retrofit downtime.

Capital Costs

The PE analysis compares the more recent EPA closed-cycle cooling system capital costs 

estimates to the previous estimates generated by EPA under Phase II and concludes that the new 

EPA capital costs based on the EPRI model is 45% higher than those estimated using EPA’s 

previous model for in-line wet cooling towers. A more detailed analysis that compares EPA’s 

composite (25% plume abatement) cost estimate used in the national cost estimate to an 

equivalent cost based on the previous EPA model and vendor quotes for plume abatement towers

concludes that the revised EPA estimate is 30% greater. PE notes that the previous EPA closedcycle model that EPA abandoned was well documented. This is true for the cooling tower 

component which was based on Phase I Rule estimates. However, the Phase I costs were for new 

construction and one important component added for the Phase II estimates was a retrofit factor 

which EPA assumed to be 20% of installed cooling tower capital costs. This factor was intended 
to cover the added costs for demolition, reconstruction, and other items not included in estimates 

for a greenfield installation since retrofits do not include some offsetting costs associated with 

the once-through alternative that must otherwise be built in a greenfield project. While the Phase 

II EPA model did include a nominal cost component for intake and blowdown piping and for 

condenser upgrades at some systems, it did not include costs for the recirculating water piping 

since it was assumed to be included in the 80% factor added to tower equipment costs to cover 

installation and associated equipment. While this may be valid for greenfield applications where 

the costs for the baseline alternative once-through piping would provide some offset, the costs of 

rerouting and installing new and often longer circulating water piping while working around 

many existing structural interferences can add significantly to the costs. In fact, the differences 

associated with the relative difficulty encountered when installing recirculating piping is a major 

driver of the differences between the EPRI easy and difficult retrofit costs. This 20% retrofit 

factor was a BPJ estimate that was not based on any supporting analysis or documentation. This 

20% factor likely represents an easy retrofit scenario. And in fact, Exhibit 12-2 of the TDD 

presents a comparison of closed-cycle retrofit costs using EPAs Phase II model and the EPRI

model and found that the Phase II model costs are comparable to the EPRI “easy” difficulty 

costs. EPA presented this table to demonstrate that the costs of new cost model based on EPRI 

data were comparable to the EPA Phase II model. PE takes the position that they aren’t 

comparable since EPA selected the “average” difficulty cost factor. While PE presents additional 

arguments suggesting the Phase II model costs are conservative because EPA used an assumed 

range of 10 oF instead of 12 oF and potentially inflated condenser upgrade costs, the resulting 

total capital costs all rely upon the same potentially unrepresentative methodology. The decision 

to revise the closed-cycle cost model was based in part on the fact that the retrofit costs are very

site specific and EPA chose to use the EPRI methodology which was based on detailed project 

estimates and actual costs at a wide range of different facilities. PE noted that the actual costs for 

retrofits at the Palisades, Pittsburg, and Yates facilities presented in Phase II Proposal TDD (to 

support the Phase II model) supports their argument. As can be seen, when adjusted for inflation, 

the capital costs of the Palisades and Pittsburg plants are comparable to the EPRI “easy” costs. 

The Yates project which was described as requiring additional sitework to prepare the tower 

location and reinforcement of the cooling water piping, is closer to the EPRI average costs. 

Additional cost estimates at two more recent retrofit projects at the McDonough and Brayton 

Point plants suggest that the EPA estimate is more representative of the full range of costs than 

the three cited in the Phase II Proposal TDD. Table 4 presents the calculated unit capital costs 

adjusted for inflation to 2009 Dollars.

Table 4

Costs for Actual Closed-Cycle Retrofits

Year

Flow

(gpm)

Capital 

Cost 

(Million 

Dollars)

Unit Capital Costs

$/gpm 

$/gpm in 

2009 Dollars1

Palisades21998 410,000 55.9 136 197

Pittsburg21998 352,000 34.4 98 142

Yates22002 460,000 87 189 248

McDonough 2008 272,900 96 352 363

Brayton Point 2011 720,000 570 792 748

2007 EPRI "Easy" 2007 - - 160 172
EPA/EPRI “Average” 

w/o Plume Abatement 2009 - - 263 263

2007 EPRI “Difficult” - - 415 446

EPRI Recent Average 2010 - - 340 330

EPA/EPRI Cost Model 2009 - - 293 293

1 Adjusted for inflation using ENR CCI

2

Source: PE analysis

3

Source: McDonough EPA Site Visit Report

The inflation adjusted 2009 unit cost for the Yates project is within 6% of the EPA average 

retrofit estimate of $263/gpm for non-plume abated systems. The McDonough retrofit which 

would be considered as a somewhat difficult retrofit shows a unit cost that is consistent with 

EPAs cost estimates.

3

Items that added to the difficulty of this retrofit included: need for plume 

abatement, space constraints, need to replace pumps and piping, lack of plans/blueprints for 

existing underground piping. The Brayton Point unit cost is much higher because the project 

involved natural draft towers which were chosen to avoid a potentially serious plume related 

fogging/icing problem for a nearby highway. Natural draft towers costs more in up-front capital 

costs but have lower operating costs. Rough calculations suggest the Brayton Point power 

savings could have a net present value as high as $125/gpm.

4

Even after adjusting for these 

savings, the nearly $623/gpm equivalent cost for a mechanical draft tower at Brayton Point 

shows just how high “difficult” retrofit costs can be. Also, as discussed below EPA did not 

include any added cost for nuclear facility retrofits which were assumed to be included in the 

aggregated EPRI costs. These data demonstrate that the selection of the “average” rather than 

“easy” EPRI costs factor used in the EPA cost model was a reasonable decision and clearly 

represents a reasonable approximation of the range of costs that may be incurred nationwide.

The PE concerns regarding condenser upgrade costs are irrelevant since the EPA costs are based 

on aggregated total project costs that include condenser upgrades where necessary.

Nuclear Plant Retrofits

PE expressed concern that EPA repeated the previous error regarding the application of a cost 

premium for nuclear facilities. EPA did not include a cost premium for closed-cycle retrofits at 

nuclear facilities. EPA did apply a cost premium for the installation of impingement technologies 

for nuclear facilities in the final rule cost analysis because these costs were built up costs derived 

from vendor and other sources which did not factor in the added costs associated with working at 

nuclear facilities. However, since the EPRI cost estimates were based on aggregated cost data

that included nuclear facilities, EPA assumed that such costs were already factored in to the 

aggregated cost.

Auxiliary Pump & Fan Energy Requirement

 

3 EPA estimated that an average retrofit with plume abatement would cost approximately $383/gpm (DCN 10-6652) 

which is within 5% of the McDonough unit cost.

4 Net present value calculated over 50 years at 3% discount rate assuming an average wholesale power cost of 

$50/MWh using mechanical draft tower cells with 200Hp fans and 12,000 gpm flow/cell operating 75% of time.
PE noted that the EPA auxiliary pump and fan energy requirement was 30% higher than the 

model estimate provided in the 2002 Phase II TDD. EPA agrees that these requirements are 

higher but that was the result of a change in the assumed system design. The primary difference 

is that the 2002 EPA estimate assumed a pumping configuration where a single set of pumps 

would pump water through both the condenser and cooling tower in series. While this 

configuration would be the likely choice for a newly built system, EPA decided that the design 

for retrofits at existing units would in many instances leave the existing circulating pumps inplace and install a second set of pumps that would pump water from the condenser outfall to the 

existing pump inlet. Both the EPA and EPRI estimates are based on this design configuration 

and, as a result, do not deduct the once-though pumping energy component. The auxiliary pump 

and fan energy requirements are based on engineering calculations using typical design 

parameters and should be reasonably representative of actual requirements.

Heat Rate Penalty

PE expressed concern that EPA’s heat rate penalty used in the final rule analysis for fossil-fuel 

plants was 4 times the EPA model estimates in the 2002 Phase II Proposal TDD and nuclear 

estimate was 10 times the penalty measured for the Jeffries Plant as presented in the 2002 TDD. 

PE is also concerned that EPA is using an estimate based on assumed maximum values for 

annual estimates. EPA’s revision of the heat rate penalty from the 2002 Proposal is the result of 

new information. As noted in the analysis of heat rate energy penalty estimates (DCN 10-6670), 

the EPA estimated heat rate energy penalty values are consistent with the upper range of 

estimates provided by DOE and with a nuclear heat rate penalty lower than the somewhat 

conservative estimates for California coastal power plants. Calculation of national average heat 

rate penalty is difficult because the penalty for each plant is highly variable, being subject to sitespecific conditions including equipment design and factors that vary considerably over time,

including operating conditions, meteorological and ambient water conditions. Based on 

comments, the EPA estimates of the heat rate penalty are representative of the upper end of the 

possible range of penalty values. Therefore EPA considers the approach and resulting estimates 

as reasonable.

Downtime

PE states that EPA overestimated downtime duration at fossil-fuel plants by a factor of two and 

states that EPA presented a strong case for one month as a reasonable and conservative outage 

period. PE notes that at the Canadys Station and Jefferies Station sites, the closed-cycle system 

hook-up was completed within the scheduled plant outage period. EPA agrees that in many 

instances, like those cited, the net downtime may be zero which is supported by the EPRI 

estimate of zero net downtime for “easy” to “average” retrofits (see Table 2). However, the 

single value used by EPA represents a national average and should be representative of the full 

range of downtime values that would occur. As noted elsewhere in this analysis, the weighted 

average of the EPRI net downtime estimates which represent the full range of difficulties is 1.5 

months (if much longer estimates for optimization are excluded). Also, EPA has obtained new 

data that supports the 2 month total (one moth net) estimate. During the site visits EPA learned 

that both the McDonough and Yates Plants in GA, experienced a tie-in outage for the cooling 

tower retrofit of 6-8 weeks (see DCN 10-6536 and DCN 10-6537). These projects would be 
classified as average to difficult retrofits. This new information supports EPA’s estimate used in 

the cost analysis of 4 weeks net (8 weeks minus the assumed 4 weeks of scheduled 

maintenance). Since there are a limited number of examples to draw from and EPA’s estimate 

falls between the values suggested by Riverkeeper and EPRI, EPA feels that its estimate is 

reasonable and that the new data supports the assumption.

PE believes there is no justification for the 7 month downtime for nuclear facilities. Based on 

data regarding recent nuclear generating system upgrades, PE states that the additional outage 

should be no longer than 2 months. In response to comments received since proposal and upon 

evaluation of additional data, EPA has revised the downtime estimates for closed-cycle retrofits 

at nuclear facilities in a way that substantially reduces the overall downtime estimate to an 

aggregate value similar to that suggested by PE. In the revised approach, facilities are divided 

into two groups: those that have conducted or are currently planning to conduct an extended 

capacity uprate (ECU) and those that have not. An important characteristic of an ECU is that it 

involves considerably more construction activities compared to simple refueling outages 

(including replacement of portions of the generating system) and therefore involves outages 

much longer than those for refueling. These projects provide an ideal opportunity to further 

reduce downtime if the closed-cycle retrofit is performed concurrently. Data regarding ECU 

scheduling was readily available and revisions to the final rule have given the Director greater 

flexibility in establishing compliance schedules for entrainment requirements would allow for 

scheduling of the closed-cycle retrofit to occur concurrently with an ECU. For those facilities 

where ECUs are unlikely to occur in the future (i.e., facilities where an ECU has been performed 

or is currently planned), EPA took a more conservative approach similar to the approach used at 

proposal but with the duration adjusted downward to a level consistent with new information. At 

proposal, EPA used the 7 month (28 week) closed-cycle retrofit outage for all nuclear facilities 

on the Phase II NODA estimate which was based on the only nuclear closed-cycle retrofit 

actually performed at an existing nuclear facility (Palisades) in the 1970s. For the revised final 

rule estimate, EPA evaluated the EPRI net downtime estimate of 6 months used in their cost 

estimate (EPRI Report Number 1022491, provided as an attachment to EPRI’s comments on the 

proposed rule; see EPA-HQ-OW-2008-0667-2200). In support of the 6 month estimate, EPRI

cited engineering estimates for four nuclear plants that ranged from 5 to 22 months and noted 

that the expected downtime was difficult to predict since there was a great degree of uncertainty 

given the lack of actual data. A closed-cycle retrofit for these facilities that will not conduct an 

ECU would likely occur concurrently with a refueling outage which now typically takes about 4 

to 6 weeks (See DCN 12-6876). Thus, the EPRI net downtime estimate of 6 months or 24 weeks 

would be consistent with a total retrofit downtime of about 28 weeks. EPA notes that this 28 

week value is consistent with the duration of the first steam generator replacement project for 

SONGs Unit 25and while this outage length is the higher of the two similar projects at SONGS, 

the difference demonstrates that complex projects for which contractors and engineers have little 

previous experience will tend to take longer. The actual duration of the outage required for a 

nuclear closed-cycle retrofit is still unknown and will be influenced by site-specific factors. 

Given this uncertainty, EPA concluded that a 24 week estimate was reasonable and applied this 

value in the economic analysis.

 

5

The first attempt at replacement of the steam generator for SONGS unit 2 took 28 weeks but a similar subsequent 

project for unit 3 was expected to be shorter (see DCN 10-6548)
For the remainder of facilities that are likely to conduct an ECU in the future, EPA estimates that 

under favorable conditions, ECUs typically have a duration of two to four months (see DCN 12-

6875) but can also take much longer.6For this analysis, EPA assumed that facilities performing 

an ECU would be capable of completing the retrofit concurrently with the ECU and that the 

scope of the ECU would be extensive enough to push the duration toward the longer end of the 2 

to 4 month or longer range. For these projects, EPA assumed zero downtime which is actually a 

shorter duration than the 2 months suggested by PE. Based on data from the NRC, EPA 

estimates that roughly one-third of existing nuclear generating units have already performed or 

have applied for an ECU and therefore are assumed the a 24 week downtime. As a result, the 

equivalent average net downtime across all nuclear units should be about 8 weeks (2 months). 

Thus, while the 24 week estimate is still longer than PE’s suggested length, EPA has adjusted the 

overall nuclear closed-cycle retrofit downtime to a value that is consistent with PE’s position.

EPA notes that while the replacement of condenser tubing or steam turbines, including those 

where the containment structure must be opened, are indeed very involved projects, they

generally involve only the replacement of existing equipment and do not involve substantial 

modifications to existing structures (except maybe for access). Whereas, the installation,

construction, and tying-in of the new circulating water system to the existing condenser’s 

intake/discharge piping are more involved.

As noted in the EPRI report analysis above, engineering estimates of outage duration for four 

nuclear plants ranged from 5 to 22 months (about 3.5 to 20.5 months assuming 43 days for 

refueling7). While it is possible that these industry-supplied estimates may be conservative (i.e., 

on the high side), there are no actual examples of retrofits at nuclear plants where shorter 

durations occurred upon which EPA could rely to support a duration shorter than its current net 

of 7 months.

Conclusion

In summary, this analysis supports the following conclusions:

 The EPA capital cost estimate is much higher than the model estimates used in support of 

the Phase II Rule but is lower than the EPRI cost estimate by about 13%. The EPA and 

EPRI estimated capital costs are similar in magnitude. The Phase II Rule model estimates 

were based on the well documented Phase I Rule model for the cooling towers but the 

retrofit component was BPJ and not well documented. The EPA capital costs for the 

existing facility final rule are based on the EPRI model which is based on actual and 

planned system costs.

 The EPRI and EPA cost estimates for the O&M component for auxiliary pumping and 

fan energy appear to be similar in magnitude. Both are based on well documented 

engineering calculations and on a reasonable assumption that separate pumps will supply

water to the condensers and cooling towers. EPRI provided no estimate of non-energy

O&M.

 

6

PE provided examples of ECU-type activities suggesting that a 75 day (10 week) duration which is in agreement 

with a 2 to 4 week duration cited by engineers (see DCN 12-6875) but there are instances where the duration was 

much longer. For example, Turkey Point took 5 months and SONGS unit 2 took 28 weeks.

7

For the past 5 years nuclear refueling outages have averaged 38 to 43 days (NEI 2011).
 The aggregated EPRI estimate for construction downtime is higher than EPAs but much 

of the difference is based on an assumption that many base-load facilities would reoptimize. In practice a re-optimized design should reduce long term costs but such 

savings are only partially accounted for in the EPRI analysis resulting in a higher cost for 

re-optimized systems. The EPA and EPRI downtime estimates are similar when reoptimization is not included.

 The EPA estimate for the heat rate energy penalty is higher than EPRIs and represent a 

conservative overestimate. The higher heat rate penalty assumed by EPA will help 

account somewhat for the less efficient performance of the non-re-optimized system 

design assumed by EPA.

It was not possible to directly compare the aggregated costs of all components for the EPRI and 

EPA models due to the use of a different universe of facilities and different economic 

measurements. However, the two approaches appear to be in agreement regarding the general 

magnitude of the costs. Also, EPRI’s estimation of higher downtime costs resulting from the 

inclusion of re-optimization should be offset by EPA’s use of higher heat rate energy penalty 

costs and inclusion of non-energy O&M costs.

EPRI’s approach including some re-optimization is probably a better model of the real world but 

an approach that includes such a long term costs saving measure should not result in an overall 

increase in costs by including consideration of added downtime and operating energy savings 

only. The EPA heat rate energy penalty estimates were not based on a detailed analysis and 

relatively conservative values were chosen. Given though EPRI’s more rigorous estimates are 

based calculations using several example facilities, their lower estimates are probably more 

accurate. The effect these differences would have on overall long term costs should be offsetting.
References

American Association of Costs Engineers. AACE. Skills and Knowledge of Cost Engineering. 

5th Edition. 2004. Table 9-2

EPRI. Technical Report #1022491. “Closed-Cycle Cooling System Retrofit Study.“ January

2011.

EPRI. Closed Cycle Cooling Cost Worksheet. 2007. (DCN 10-6930A)

Enercon. “Engineering Feasibility and Costs of Conversion Of Indian Point Units 2 and 3 to a 

Closed-loop Condenser Cooling Water Configuration.” February 12, 2010.

Enercon. “Diablo Canyon Power Plant; Cooling Tower Feasibility Study, March, 2009.

Enercon. “Feasibility Study for Installation of Cooling Towers and the San Onofre Nuclear 

Generating Station.” 2009.

Powers Engineering. “Powers Engineering comments on EPA 316(b) March 28, 2011 TDD.” 

August 11, 2011.

URS Corporation, “Determination of Cooling Tower Availability for Oyster Creek Generating 

Station.” March, 2, 2006.

NEI. U.S. Nuclear Refueling Outage Days (Average, 1990-2011).

Accessed at: http://www.nei.org/resourcesandstats/Documentlibrary/Reliable-and-AffordableEnergy/graphicsandcharts/refuelingoutagedays