Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

fax 703-385-6007

TO: Paul Shriner, EPA

FROM: John Sunda (SAIC) and Kelly Meadows

DATE: September 30, 2010

SUBJECT: Costs of Traveling Screen Versus

Rivers in the Midwest

During visits to power plants located on the Missouri and Mississippi rivers, EPA observed that 

number of facilities were experiencing substantial equipment and operating problems due to hig

quantities of debris, silt, sand and other river conditions. All of the plants utilized once

cooling with traveling screens.1 

costs that would continue to occur 

the cooling system remained once

provided for comparison to see if the 

system approach those of a closed

high debris loads or other issues, the additional costs of upgrading to closed

unlikely to be offset unless the facility suffers from unscheduled outages or is forced to 

an extended period. However, a facility that does encounter such problems may quickly realize 

the benefits of converting to closed

specifically cited, the plant data provided here are tak

reference section.

EPA Estimated Costs

When only the capital cost, equipment O&M costs, and energy penalty are considered, the 

difference in costs between a traveling screen upgrade and a retrofit with a close

system can be quite substantial. Table 1 presents the estimated costs of replacing existing 

traveling screens with modified Ristroph Screens and a fish return, and the estimated costs of a 

closed-cycle cooling system retrofit for a typical 

screens. These cost estimates are based on the EPA estimates for compliance costs for Module 1 

 

1 One used dual-flow screens and the rest used conventional flow

MEMORANDUM

Paul Shriner, EPA

John Sunda (SAIC) and Kelly Meadows

September 30, 2010

Costs of Traveling Screen Versus Closed-Cycle Cooling at Power Plants on 

Rivers in the Midwest

During visits to power plants located on the Missouri and Mississippi rivers, EPA observed that 

facilities were experiencing substantial equipment and operating problems due to hig

quantities of debris, silt, sand and other river conditions. All of the plants utilized once

 This analysis examines some of the problems and associated 

costs that would continue to occur at these facilities if the traveling screens were upgraded and 

the cooling system remained once-through. Estimated costs for a closed-cycle retrofit are 

provided for comparison to see if the increased maintenance costs for the existing 

sed-cycle retrofit. The analysis suggests that for facilities with 

high debris loads or other issues, the additional costs of upgrading to closed-cycle cooling are 

unlikely to be offset unless the facility suffers from unscheduled outages or is forced to 

an extended period. However, a facility that does encounter such problems may quickly realize 

the benefits of converting to closed-cycle, as lost generation costs are substantial. U

specifically cited, the plant data provided here are taken from the Site Visit Reports listed in the 

When only the capital cost, equipment O&M costs, and energy penalty are considered, the 

difference in costs between a traveling screen upgrade and a retrofit with a close

system can be quite substantial. Table 1 presents the estimated costs of replacing existing 

traveling screens with modified Ristroph Screens and a fish return, and the estimated costs of a 

cycle cooling system retrofit for a typical 500 MW coal-fired power plant with traveling 

screens. These cost estimates are based on the EPA estimates for compliance costs for Module 1 

flow screens and the rest used conventional flow-through screens. 

Cycle Cooling at Power Plants on 

During visits to power plants located on the Missouri and Mississippi rivers, EPA observed that a 

facilities were experiencing substantial equipment and operating problems due to high 

quantities of debris, silt, sand and other river conditions. All of the plants utilized once-through 

This analysis examines some of the problems and associated 

he traveling screens were upgraded and 

cycle retrofit are 

increased maintenance costs for the existing once-through 

The analysis suggests that for facilities with 

cycle cooling are 

unlikely to be offset unless the facility suffers from unscheduled outages or is forced to derate for 

an extended period. However, a facility that does encounter such problems may quickly realize 

cycle, as lost generation costs are substantial. Unless 

en from the Site Visit Reports listed in the 

When only the capital cost, equipment O&M costs, and energy penalty are considered, the 

difference in costs between a traveling screen upgrade and a retrofit with a closed-cycle cooling 

system can be quite substantial. Table 1 presents the estimated costs of replacing existing 

traveling screens with modified Ristroph Screens and a fish return, and the estimated costs of a 

fired power plant with traveling 

screens. These cost estimates are based on the EPA estimates for compliance costs for Module 1 
- 2 -

(coarse-mesh Ristroph screens with fish return) and closed-cycle cooling. Baseline O&M costs 

are not deducted from the values shown. 

Assumed design parameters include:

 Coal-fired plant with capacity of 500 MW

 Design intake flow is 600 gpm/MW or 300,000 gpm

 Capacity Utilization is 75%

 Shoreline intake is 12 ft deep, with 50 ft screen wells with 1.4 fps screen velocity

 Screen values were selected to produce a cost design equivalent to six 10-ft wide screens

 Surface shoreline intake is on freshwater river

 Discount Rate is 5% and service life of traveling screens and cooling towers are 20 and 

30 years, respectively

 Cost of lost power sales is $50/MWh

 Cost of excess fuel use is $11/MWh

 Energy and turbine penalty costs are assumed to be incurred as lost power 24% of the 

time and as excess fuel use 76% of the time

 Turbine efficiency energy penalty is 1.5%

 Downtime for Closed Cycle is a net of 4 weeks and is assessed as lost power at 80% of 

capacity, based on assumption that downtime will be scheduled during period of lower 

demand

 Costs use a regional adjustment factor of 1.0 (national average) 

Table 1. EPA Estimated Costs of Upgraded Traveling Screens and Closed-Cycle Retrofit

at a Typical 500 MW Coal-fired Power Plant

Capital 

Costs Downtime

Fixed 

O&M

Variable 

O&M1

Energy

Penalty -

Pump & Fan1

Turbine 

Penalty1

Amortized

Capital and 

Downtime 

Costs

Total 

Annualized 

Costs

Modified 

Ristroph TS $2,272,000 $0 $147,000 $166,000 See Var. O&M $0 $182,000 $495,000

Closed Cycle 

(easy) $50,700,000 $13,440,000 $380,000 $281,000 $951,000 $1,003,000 $4,172,000 $6,787,000

Closed Cycle 

(average) $78,900,000 $13,440,000 $380,000 $281,000 $951,000 $1,003,000 $6,007,000 $8,622,000

Closed Cycle 

(difficult) $123,300,000 $13,440,000 $380,000 $281,000 $951,000 $1,003,000 $8,895,000 $11,510,000

1 These costs are adjusted using the capacity utilization rate.

In order to allow comparison of long-term costs, capital and downtime costs are amortized over 

the estimated service life of the technology. As can be seen, EPA’s estimated total annualized 

compliance costs for closed-cycle cooling are more than an order of magnitude higher than the 

costs of upgraded traveling screens when only the direct technology costs are considered. 

It is important to note that the closed-cycle costs represent a somewhat conservative (high-end) 

cost estimate. The closed-cycle costs for pump/fan energy penalty assume the fans will operate 

year-round, even though they are often turned off during winter operation. The closed-cycle 
- 3 -

variable O&M costs assume treatment chemicals will be needed for optimized operation. Thus, 

the closed-cycle costs are representative of a well-operated system where operational problems 

that could result in equipment failure and poor tower or condenser performance will be 

minimized. It is also assumed that the cost estimates include costs for towers that are designed 

and operated in a manner to prevent damage such as may occur due to ice formation in the winter 

or fouling due to solids and microbial growth build-up on the media.

The closed-cycle costs include the annual average turbine efficiency loss, which takes into 

consideration losses during periods when high wet bulb temperatures may reduce the turbine 

efficiency due to higher cold water temperatures compared to what would be available in a oncethrough system as well as any de-rate that may occur due to periods when the turbine backpressure exceeds the maximum pressure allowed to prevent damage to the turbines.

The different capital costs are related to degree of difficulty encountered in retrofitting the 

technology. As described later in this analysis, the closed-cycle cooling system capital costs 

reported by two facilities visited by EPA in the region appear to fall close to the “easy” end of 

the range of estimated costs.

The traveling screen upgrade costs in Table 1 are based on a typical system that is not 

experiencing any substantial problems such as episodes of high quantities of debris, silt, and sand 

in the source water, low source water levels, low source water flow, or high source water 

temperatures. Such problems can result in higher maintenance costs for the screens and other 

equipment, greater system downtime (lost generation costs), and reduced capacity during peak 

demand. The costs in Table 1 do not include consideration of site-specific costs that may be 

encountered at facilities where the characteristics of the source water and intake location may

present additional operational difficulties that have economic consequences.

The following sections provide an examination of some of the problems associated with 

traveling screen operation in certain environments. Some examples from visited facilities are 

presented, along with estimates of the economic impact when compared to an alternative closedcycle cooling system. While closed-cycle cooling will still require the use of intake technologies 

such as traveling screens for makeup water, the substantial reduction in intake flow volume 

should minimize or eliminate the problems described and the associated economic impact.

 

Debris, Silt, and Sand

Rivers with high levels of debris, silt, or sand can cause recurring problems for once-through 

systems that utilize traveling screens. Episodes of high concentrations of debris such as leaves 

and aquatic vegetation can rapidly blind traveling screens, resulting in an emergency shutdown 

of generating units or, under the worst-case situation, the collapse of the screen. Silt and sand 

can also be abrasive on moving parts such as traveling screens and pump impellers, requiring 

more frequent rebuild and replacement. Debris and silt can also coat and clog condenser tubing, 

resulting in reduced condenser performance and reduced generator output.
- 4 -

Meramec Power Station

The Meramec Power Station is a four-unit coal-fired power plant with a combined capacity of 

835 MW and an average capacity utilization of 76%. The intake consists of eight dual-flow 

traveling screens with a single pump behind each screen (two for each generating unit). The 

intake is located on the Mississippi River 20 miles south of St Louis, Missouri. Meramec has 

had significant problems with debris in the past (especially with spring and fall leaf loads), 

including five unit shutdowns from 2000 to 2009. Facility representatives noted that a major 

debris event typically leads to 4-5 screen panels being damaged. 

Nebraska City

Nebraska City is a single-unit 650-MW coal-fired power plant located on the Missouri River

about 8 miles southeast of Nebraska City, Nebraska. The intake consists of six conventional 3/8-

in mesh traveling screens and three pumps with a capacity of 223 MGD each. Two pumps are 

normally operated and, due to sedimentation problems in the intake bays, the screens are rotated 

continuously. Wear on the traveling screens due to silt and sand has resulted in repeated screen 

rebuild and maintenance that totaled $2,481,282 over a 10-year period. Every six months, the 

traveling screens become silted in and sediment must be pumped out. The costs of the screen 

rebuilds alone equal about $250,000 per year, or roughly 80% of the total EPA O&M cost for a 

similar number of screens as shown in Table 1. 

Fort Calhoun

Fort Calhoun is a single-unit 492-MW nuclear power plant about 5 miles northwest of the town 

of Fort Calhoun in eastern Nebraska on the Missouri River. The intake consists of six 

conventional 3/8-in mesh traveling screens and three pumps with a capacity of 173 MGD each. 

The facility has had problems with gravel in the intake and as a result, during each refueling 

shutdown (occurring every 18 months), they have rebuilt each screen at a cost of $80,000 per 

screen and cleaned the condenser at a cost of $250,000. This is equivalent to an annual screen 

overhaul costs of $320,000 per year for six screens, which is 102% of the total EPA O&M cost 

for a similar number of screens as shown in Table 1.

Cooper Nuclear

The 836-MW Cooper Nuclear facility reported that in 2002 debris plugging problems in the 

condensers resulted in the need to perform 45 backwash cycles (nearly one per week) with a 

brief shutdown each time, resulting in an annual loss of 3,220 MWhs. This is roughly equivalent 

to about 0.2 days of lost generation per year. Even with the backwashes, some of the debris 

remains until removed during the next scheduled maintenance shutdown. 

Increased Screen Maintenance Summary

The screen rebuild frequency for Nebraska City is about once every two years. Three other 

plants located on the Missouri River—the Hawthorne, Iatan, and Lake Road power plants—also 

reported that traveling screens were rebuilt once every two years during scheduled maintenance 
- 5 -

downtime. The EPA O&M cost estimates for the proposed rule include routine operator labor, 

maintenance, and power requirements, in addition to screen rebuild costs. By comparison, for 

the two plants that reported cost data, the screen rebuild costs alone were equivalent to 80% to 

100% of the total EPA-estimated costs shown in Table 1. This indicates that, for plants located 

on water bodies with high levels of debris, silt, and sand like the Missouri River, the actual O&M 

costs will likely be higher those estimated by EPA. 

A review of the EPA cost module component O&M costs for a 10-ft wide and 50-ft deep 

traveling screen shows that the split is roughly one-third each for labor, power, and materials. It 

is reasonable to assume that a portion of the labor and materials costs in the EPA estimate 

includes the replacement of traveling screen parts, such as occurs in the Nebraska City and Fort 

Calhoun screen rebuilds. If one assumes that roughly half of both of these costs are routine and 

the other half are rebuild-related, then the facility rebuild-related costs exceed the EPA-estimated 

rebuild component by 69% for Fort Calhoun and 49% for Nebraska City. Thus, a reasonable 

estimate is to assume an increase of approximately 50% in total O&M for traveling screens at 

facilities with water body characteristics that result in excessive wear and tear on the screens.

Pumps

While no specific pump maintenance cost data were cited, the presence of sand in an intake can 

result in increased wear on pump impellers, resulting in reduced service life. Cavitation and air 

entrainment that result from operation at low water levels can also damage pump bearings and 

impellers. However, such conditions are typically avoided by reducing the pump flow rate. To 

examine the magnitude of the cost implications of such wear and tear on the pumps, it is 

assumed that the service life of the pump impeller is cut in half from 15 years to 7.5 years. A 

project that involves upgrading a power plant’s circulating water pumps with new impellers, 

diffusers, shrouds, and shafts results in a cost of $1,100,000 for a combined pump flow of 

236,000 gpm (Flory 2005). Using this data, the inflation-adjusted unit cost would be $5.6/gpm. 

The equivalent $1,680,000 pump upgrade cost for a 300,000-gpm system amortized over 15 

years and 7.5 years at 5% is $162,000 and $274,000, respectively. The difference of $112,000 

represents the estimated increase in pump maintenance cost that results from reducing a pump 

impeller service life by half.

Condenser Performance

Condenser performance can suffer as the result of several problems. The water side of tube walls 

can become coated with sediment, scale or biological growth, reducing the heat transfer rate. 

Individual tubes can develop leaks due to corrosion or erosion, requiring them to be plugged as 

an interim measure prior to tube replacement. Debris too large to pass through the typical 7/8-in 

diameter can plug condenser tubes, reducing or eliminating flow through individual tubes. 

Traveling screens can contribute to this latter problem by allowing carryover of large debris to 

the back side, where the reverse-direction flow dislodges the debris which then plugs condenser 

tubes, resulting in reduced condenser performance and reduced turbine efficiency. Since the 

screen wash water is often withdrawn from the clean side, this debris may also plug screen wash 

water nozzles, increasing the potential for debris carryover in a spiraling cycle. The plugging of 
- 6 -

condenser tubes may require more frequent unit shutdowns to clean the condenser. Downtime 

for cleaning may take from 3 to 5 days, depending on the amount of tube cleaning required and 

the amount of scale present (Spielmann 2002). 

While retrofit of the traveling screens with dual-flow or multi-disc screens may resolve this 

problem, there are often other problems associated with the existing intake design, such as 

concerns about changes in the distribution, direction and velocity of inlet and outlet flows that 

may make such retrofits difficult or require costly structural modifications. Use of closed-cycle 

cooling would greatly reduce or eliminate the possibility of debris carryover because of the 

greatly reduced intake flow and the fact that the reduced flow volume may increase the 

opportunity to replace the existing traveling screens with screen designs that minimize carryover.

Condenser Ball Cleaning System

A condenser ball cleaning system is a technology where small foam balls that are slightly larger 

in diameter than the condenser tubes are continuously introduced upstream of the steam 

condenser tubes and then randomly pass through the tubes, scrubbing out any sediment/solid 

deposits and biological growth. The balls are then collected on a screen downstream and 

recirculated back through the system. These systems can maintain the condenser heat transfer 

efficiency close to the design clean levels. Such systems can increase generator output by 1% to 

2% compared to uncleaned systems, and will often pay for themselves in a short period of time. 

Additional benefits include reduced condenser cleaning costs and increased service life of 

condenser tubes through reduction of microbe-induced corrosion. 

The initial capital costs and downtimes associated with installation of such systems often serves 

as an impediment to their installation, since installation requires replacing a portion of the 

condenser inlet and outlet piping with the ball release and collection equipment. The retrofit of 

an existing once-through cooling system with a closed-cycle system presents an opportunity to 

save on installation and downtime costs, since piping is being replaced or modified already and 

the ball cleaning system can be installed during the retrofit downtime. As shown in Table 1, 

retrofit downtime costs can be substantial. For the purpose of estimating savings associated with 

this technology, the value of the annual increase in power production is assumed to be equivalent 

to an average turbine efficiency increase of 1%. The actual increase is expected to be somewhat 

higher in most instances, and the difference is assumed to cover the cost of system O&M and the 

amortized capital costs.

Lost Generation Due to Inadequate River Flow or Lower River Levels

Seasonal variations, drought conditions, and/or changes to the water body can result in 

conditions where facilities may be forced to reduce power generation rates below full capacity

(aka derate). This can require the utility to purchase power from another source at a cost that is 

much higher than the cost to generate power at the plant. Closed-cycle cooling, which requires a 

much smaller intake volume, is an available alternative that can allow a facility to operate at full 

capacity regardless of river flow conditions. While there may be an energy penalty of up to 

several percent in output when compared to once-through operation under favorable river 
- 7 -

conditions, this reduction may be much smaller in magnitude compared to the size of the derate 

necessary to meet the restrictive conditions.

The inability of the cooling system to operate at full capacity generally results from situations 

where water body conditions limit pump operation or limit the ability of the water body to 

accommodate the full generating capacity or process cooling heat load. In some cases, this is the 

result of the river surface elevation dropping below the level necessary to maintain the 

submergence depth required to prevent severe pump damage from cavitation and air entrainment. 

When this happens, the only immediate solution available is to reduce the circulating pump 

flow.2The result is a reduction in the required pump submergence depth if the pump speed is 

reduced and/or an increase in water depth due to a reduction in the head loss across the screens. 

Low water conditions are often the result of drought and seasonal variations, but can also be 

exacerbated by changes in the normal surface level of the water body. For example, the surface 

level of the lower Missouri River is dropping in several locations due to erosion of the river bed.

 

In many cases, physical characteristics of the water body (e.g., high temperatures and/or low 

flow) create conditions where 316(a) NPDES limitations for heat load and temperature increase 

would be exceeded unless the generating rate is reduced. One common solution employed in the 

past involves constructing cooling towers that operate in a helper mode. 

This lost generation due to limitations in the availability of cooling or the water body’s ability to 

assimilate heat can result in substantial costs to the utility. Such costs include purchasing or 

generating replacement power at a much higher cost. Also, since these problems often coincide 

with periods of peak power demand, replacement power costs will tend to be high and the 

unreliability will lead to the need for construction of additional generating units to increase 

peaking power capacity.

Nearman Creek

The Nearman Creek Power Station is a 235-MW single-unit coal-fired power plant in Wyandotte 

County in Kansas City, Kansas along the Missouri River. The plant’s average capacity utilization 

rate is about 50%. The intake consists of four standard 3/8-in traveling screens serving two 

pumps with a total design intake flow of 230 MGD. A minimum of one pump (108 MGD) is 

required to operate at full capacity during the winter (Domkowski and Arbesman, 2001). 

The plant has been experiencing problems associated with the reduction in river surface 

elevation due to the progressive degradation of the river bed. River flows tend to be lowest 

during the winter months and drought conditions during the summer of 2000 caused the river 

level to drop so low in December that the plant had to completely shut down. The situation was 

created as a result of an ice dam upstream and the clogging of the intake with ice. The problem 

was temporarily solved by fixing barges just upstream to divert ice, which allowed for 25% 

capacity operation. But the river level was still 3 ft below the level needed to prevent cavitation 

of the pumps at full flow. Next, the intake entrance was temporarily blocked by welding steel 

plates onto the bar racks such that the top was 3 ft above the required depth. Low head pumps 

 

2 This can be done by shutting off pumps, throttling pump output, or reducing pump speed if pumps are equipped for 

multiple or variable speed operation.
- 8 -

capable of pumping the minimum flow needed for full capacity operation were rented and 

installed in front of the intake so that the discharge flowed directly onto the top of the water in 

the screen wells. The pumps were subsequently purchased and, more recently, upgraded pump 

designs with additional capacity (144 MGD) were installed. 

To help resolve this problem, Nearman Creek installed a closed-cycle cooling system in 2006 

that uses city water as a source of makeup water. The closed-cycle cooling tower capital cost 

was $22,000,000 and included reinforcement of the existing condenser to support the higher 

pressure associated with CCRS operation. 

The normal production costs at Nearman Creek were about $11/MWh, but in December 2000 the 

utility was forced to purchase replacement power at rates of $50 to $130/MWh (Domkowski and 

Arbesman, 2001). During the emergency shutdown in December 2000, the average cost of 

purchased power was over $250,000 per day and the total cost of purchased power for the 

duration of the emergency was $2,500,000. Dividing this per-day cost by the plant capacity

results in an equivalent cost of $1,064/MW/day. Attachment A presents river bottom and water 

elevation data, as well as photos and cost data for the emergency pumps used at Nearman Creek 

and at the nearby Quindaro Plant which experienced similar problems. The Quindaro plant has 

installed emergency pumps as well, but has no current plans to install closed-cycle cooling. 

Nearman operates the CCRS for only part of the year (from the spring to the fall), when cooling 

water requirements and river temperatures are the highest. The plant still operates in a oncethrough mode during the winter months and has purchased an emergency pump system at a cost 

of $1,200,000 to allow continued operation at full capacity when needed during low water-level 

conditions.3

Lost Generation 

While various problems associated with the use of traveling screens can result in substantial 

increases in equipment maintenance or purchase costs, the greatest costs tend to be the result of 

lost generation. Lost generation can result from:

 Reduction in turbine efficiency due to increase in steam condensing temperature as a 

result of reduced cooling water flow or condenser performance

 Forced derate (reduction in power output) due to 316(a) limitations in receiving water

 Generating unit shutdown due to limitations or failure of cooling water supply or 

equipment

 Generating unit shutdown due to need to perform maintenance.

 

3 Note that even if the existing traveling screens are upgraded, operation of the emergency pumps will likely not be 

compliant with the IM reduction requirements based on modified Ristroph screens in the proposed rule, since fish 

must first pass through the emergency pumps before encountering the traveling screens. The emergency pump 

inlets, which appear to include bar screens only, would be difficult to retrofit with a compliant screening system. 

The best option to resolve this problem would be year-round operation of the cooling tower. If that option were not 

available, such as is the current situation at the Quindaro Plant, then the intake would need to be rebuilt with deeper 

pump wells and modified Ristroph screens or equivalent. Each of these alternatives would involve considerably 

more cost than a simple replacement and upgrade of the existing traveling screens.
- 9 -

A maintenance shutdown is often performed in order to improve system performance; the 

decision to shut down will often involve weighing the tradeoff of short-term lost generation due 

to the shutdown versus long-term lost generation due to decreased system performance. Costs 

are minimized if maintenance can be deferred until the next scheduled shutdown for routine 

maintenance. However, if performance is reduced significantly, then a shutdown for 

maintenance may be the most economical solution. If a plant’s output is reduced by an average 

of 10% for two months, this is equivalent to losing 100% capacity for 6 days. 

The simplest way to express lost generation is in MWh per year or equivalent days of generation 

(at full capacity) per year. Reduction in turbine efficiency is often expressed in percent reduction 

in generator output. For a base-load plant, a 1% reduction in turbine efficiency is roughly 

equivalent to about 3 days of lost generation per year.

The Sioux City Power Plant reported in 2009 that, over the last 5 years, the facility had lost an 

average of one generating day per year to debris or icing.

Traveling Screen Replacement Capital Costs

Two plants reported that they recently replaced their traveling screens. The Labadie Power Plant 

replaced 8 screens at a cost of $2,800,000. The equivalent cost for 6 screens, which should be 

similar in size and scope to the example in Table 1, is $2,100,000. The new screens at Labadie 

do not include fish buckets or a separate fish return trough, but are amenable to the addition of 

these features in the future. The higher cost in Table 1 may reflect such differences. These data 

indicate that the EPA cost estimates for Module 1 (upgrade to Ristroph traveling screens with 

fish return) are accurate for this facility.

Closed-Cycle Cooling Retrofit Capital Costs

Nearman Creek installed a closed-cycle cooling system in 2006 that allowed the cooling system 

to operate in both once-through and closed-cycle mode. The cost cited was $22,000,000. This is 

comparable to the EPA estimate for an “easy” closed-cycle retrofit, which is $24,000,000 in 

2006 dollars. 

Nebraska City is in the process of constructing a second new 650-MW coal-fired generating unit 

that will use an 18-cell back-to-back closed-cycle mechanical-draft cooling system. The capital 

costs are estimated to be $40,000,000 to $60,000,000 for the cooling system. The equivalent 

scaled-down costs for a 500-MW generation unit would be $31,000,000 to $46,000,000. If 

additional costs associated with retrofitting an existing generating unit are factored in as well, 

these costs appear to fall closer to the “easy” retrofit range of the EPA capital cost estimates for a 

500-MW plant shown in Table 1.

Summary of Costs

Using the example 500-MW facility as the basis for comparison, Table 2 presents the estimated 

annualized technology costs from Table 1 and estimates of potential annual costs of some of the 

problems described above. As can be seen, just one day of lost generation is equivalent to the 
- 10 -

estimated increase in costs associated with all of the traveling screen-related problems described 

here. Thus, only in situations where the use of once-through cooling results in multiple days of 

lost generation does the difference in costs between closed-cycle and once-through cooling begin 

to converge. The break-even point is when the total once-through lost generation approaches 8 or 

9 days when compared to the “easy” closed-cycle retrofit. If the cooling towers are operated for 

only half of the year (as at Nearman Creek), then the reduction in tower variable O&M, pump 

and fan energy, and turbine penalty may reduce this time threshold by about 2 days (to 6 or 7 

days). The cost of generating equipment to replace lost power-generating capacity during peak 

demand periods is not included in this analysis, and may result in an even lower threshold. 

Table 2

Summary of Estimated Annualized Costs Associated with Once-through Cooling

Total 

Annualized 

Costs From 

Table 1

Frequent

Traveling 

Screen 

Rebuilds

Condenser 

Cleaning

Reduced 

Pump 

Impeller 

Life

One Day

Lost 

Generation 

Condenser 

Ball 

Cleaning

Total with 

One Day

Lost 

Generation

Modified 

Ristroph TS $495,000 $156,500 $250,000 $112,000 $532,000 N/A $1,545,500

Closed Cycle 

(easy) $6,787,000 N/A N/A N/A N/A -$1,643,000 $5,144,000

Closed Cycle 

(average) $8,622,000 N/A N/A N/A N/A -$1,643,000 $6,979,000

Closed Cycle 

(difficult) $11,510,000 N/A N/A N/A N/A -$1,643,000 $9,867,000

Cost for Selected Scenarios

As can be seen in Table 2, a cost comparison for even a theoretical plant will vary depending on 

the mix and degree of the associated problems. The total values shown in the far-right-hand 

column present a sum of all values shown, but do not represent a specific scenario. Table 3 

presents the annualized estimated totals for the easy closed-cycle cooling and once-through 

conditions for the following scenarios:

1. Water quality is poor with high sand and silt resulting in more frequent screen and pump 

maintenance, but little to no lost generation as a result (i.e., maintenance can be 

scheduled to minimize downtime)

2. High sand, silt, and debris result in more frequent screen and pump maintenance, and an 

unscheduled 3-day condenser cleaning

3. Water quality does not present a problem but low water levels and/or high temperatures 

result in an average derate of 10% for two months, resulting in an equivalent of six days 

lost generation

4. Water quality does not present a problem but low water levels and/or high temperatures 

result in an average derate of 15% for two months, resulting in an equivalent of nine days 

lost generation. 
- 11 -

Table 3

Estimated Annualized Costs for Selected Scenarios

Baseline Scenario 1 Scenario 2 Scenario 3 Scenario 4

Typical 

Intake with 

no added 

costs

Frequent 

screen/pump 

maintenance 

due to high 

sand and silt 

Frequent 

screen/pump 

maintenance & 

unscheduled 3-

day condenser 

cleaning due to 

high sand, silt, 

and debris 

6 days/yr lost 

generation 

from average 

derate of 10% 

for 2 months 

due to low 

water/high 

temperature

9 days/yr lost 

generation 

from average 

derate of 15% 

for 2 months 

due to low 

water/high 

temperature

Once- through with 

Modified Ristroph TS $495,000 $763,500 $2,609,500 $3,687,000 $5,283,000

Easy Closed Cycle 

with Ball Cleaning $5,144,000 $5,144,000 $5,144,000 $5,144,000 $5,144,000

Easy Closed Cycle 

without Ball Cleaning $6,787,000 $6,787,000 $6,787,000 $6,787,000 $6,787,000

The comparable closed-cycle costs are shown with and without condenser ball cleaning savings, 

since this option may not be available or necessary in some instances. 

These estimates suggest that facilities with once-through cooling systems that encounter chronic 

problems involving a significant derate over a period of time or frequent and/or extended 

downtimes (especially during periods of peak power demand) may consider cooling towers as an 

economically viable solution.

References

Cassidy, Patrick J. Kansas City Board of Public Utilities. Missouri River Degradation At 

KCBPU. Presentation to MARC River Degradation Meeting North Kansas City, Missouri March 

14, 2007.

Domkowski, Bob and Arbesman, Gary – Flygt US. Winter Power Plant Outage Ended Thanks 

to Innovative Engineering Solution with Large Flygt Pumps. 2001.

EPA. Site Visit Report. Fort Calhoun Station. 2009a.

EPA. Site Visit Report. Nebraska City Power Plant. 2009b.

EPA. Site Visit Report. Sioux City Power Plant. 2009d.

EPA. Site Visit Report. Cooper Nuclear Power Plant. 2009e.

EPA. Site Visit Report. Nearman Creek Power Plant. 2009f.

EPA. Site Visit Report. Iatan Power Plant. 2009g.
- 12 -

EPA. Site Visit Report. Meramec Power Plant. 2009h.

EPA. Site Visit Report. Power Plant. 2009i.

EPA. Site Visit Report. Quindaro Power Plant. 2009j.

EPA. Site Visit Report. Hawthorne Power Plant. 2009k.

EPA. Site Visit Report. Lake Road Power Plant. 2009l.

EPA. Site Visit Report. Labadie Power Plant. 2009m.

EPA. Site Visit Report. Sioux Power Plant. 2009n.

Flory, Alan. Austin Energy: Pumping System Improvement Project Saves Energy and Improves 

Performance at a Power Plant. June 2005. 

http://www1.eere.energy.gov/industry/bestpractices/pdfs/austinenergy.pdf

Shipilev, S.G. and Kataev, M.P. Improvement of Equipment for the Ball Cleaning of Steam 

Turbine Condensers. Thermal Engineering. Vol. 54 No 4. 2007.

Spielmann, Steve. Big Shot System Speeds Tube Cleaning. Power Engineering Magazine. 2002.

http://www.goodway.com/power_generation/bigshot_system_speeds.aspx

http://www.tubetech.com/case-studies/power-case-studies/dartt-removes-tenacious-musselsfrom-condenser