Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

TO: Paul Shriner and Jan Matuszko, USEPA

FROM: John Sunda (SAIC) and Kelly Meadows

DATE: March 8, 2010

SUBJECT: Estimation of Net Difference in 

Versus Closed

Plants and for Repowering of Existing Generating Units

EPA requested that Tetra Tech and SAIC 

construction of cooling water systems for 

generating units as a way to compar

technologies or flow reduction requirements at existing generating units.

The following cost analysis provides an estimate of the net difference in capital and 

operations and maintenance (

reduction using closed-cycle cooling with mechanical draft cooling towers versus once

through cooling.1 Separate cost estimates are provided for new and repowered generating 

units as well as generating with different thermal efficiencies.

Introduction

The construction of new generating units and repowering of existing units at existing 

power plants is a common practice employed by electric generators to meet one or more 

of the following goals: to increase plant capacity; to increase plant efficiency; to reduce 

operating costs, to extend plant life, to improve plant reliability; and to reduce emission 

of pollutants. There are numerous financial, engineering, and regulatory benefits to 

adding to or rehabilitating generating capacity at existing sites compared to building new 

units at a new site. For example, a new or repowered unit may increase the total capacit

allowing the plant to better meet the demand for power; alternatively, a new or repowered 

unit may replace (or make obsolete) an older generating unit that was no longer cost

effective to operate, creating a more competitive portfolio for the utility.

 

1

For consistency between scenarios (and with potential requirements for impingement controls), the 

costing assumed facilities would install a shoreline intake with modified Ristroph traveling screens with a 

through-screen velocity of 0.5 fps to meet coolin

MEMORANDUM

10306 Eaton Place, Suite 340

Paul Shriner and Jan Matuszko, USEPA

John Sunda (SAIC) and Kelly Meadows

March 8, 2010

Estimation of Net Difference in Capital and O&M Costs for Once

Versus Closed-Cycle Cooling for New Generating Units at Existing Power 

Plants and for Repowering of Existing Generating Units

EPA requested that Tetra Tech and SAIC estimate engineering costs associated with 

cooling water systems for new generating units and for repowered 

generating units as a way to compare these costs against those for retrofitting intake 

technologies or flow reduction requirements at existing generating units.

alysis provides an estimate of the net difference in capital and 

operations and maintenance (O&M) costs between the cooling system options of flow 

cycle cooling with mechanical draft cooling towers versus once

rate cost estimates are provided for new and repowered generating 

units as well as generating with different thermal efficiencies.

The construction of new generating units and repowering of existing units at existing 

practice employed by electric generators to meet one or more 

of the following goals: to increase plant capacity; to increase plant efficiency; to reduce 

operating costs, to extend plant life, to improve plant reliability; and to reduce emission 

nts. There are numerous financial, engineering, and regulatory benefits to 

adding to or rehabilitating generating capacity at existing sites compared to building new 

units at a new site. For example, a new or repowered unit may increase the total capacit

allowing the plant to better meet the demand for power; alternatively, a new or repowered 

unit may replace (or make obsolete) an older generating unit that was no longer cost

effective to operate, creating a more competitive portfolio for the utility. Additionally, 

 

For consistency between scenarios (and with potential requirements for impingement controls), the 

costing assumed facilities would install a shoreline intake with modified Ristroph traveling screens with a 

screen velocity of 0.5 fps to meet cooling water needs.

Capital and O&M Costs for Once-through 

Cycle Cooling for New Generating Units at Existing Power 

engineering costs associated with 

repowered 

retrofitting intake 

alysis provides an estimate of the net difference in capital and 

costs between the cooling system options of flow 

cycle cooling with mechanical draft cooling towers versus oncerate cost estimates are provided for new and repowered generating 

The construction of new generating units and repowering of existing units at existing 

practice employed by electric generators to meet one or more 

of the following goals: to increase plant capacity; to increase plant efficiency; to reduce 

operating costs, to extend plant life, to improve plant reliability; and to reduce emission 

nts. There are numerous financial, engineering, and regulatory benefits to 

adding to or rehabilitating generating capacity at existing sites compared to building new 

units at a new site. For example, a new or repowered unit may increase the total capacity, 

allowing the plant to better meet the demand for power; alternatively, a new or repowered 

unit may replace (or make obsolete) an older generating unit that was no longer costAdditionally, 

For consistency between scenarios (and with potential requirements for impingement controls), the 

costing assumed facilities would install a shoreline intake with modified Ristroph traveling screens with a 
- 2 -

projects at existing plants (including repowering projects) can take advantage of existing 

infrastructure and support services, while the construction of new generating units offers 

significant flexibility in the unit’s design and location.

As detailed below, the capital costs for either a once-through or a closed-cycle cooling 

system at new generating units are relatively similar: for each type of generating unit, 

once-through systems are approximately 15% more expensive. For repowered units, 

capital costs for closed-cycle systems are nearly twice as high for an “easy” difficulty 

retrofit and approximately three times more costly for an “average” retrofit. For all 

generating units (new or repowered), O&M costs are approximately twice as high for 

closed-cycle systems.

Definitions

For the purposes of this analysis, the term “new units” refers to generating units that do 

not replace the generating capacity of existing generating units and will require their own 

cooling system that is mostly independent of the cooling system and intakes for the 

existing generating units. The once-through cooling option for new units is assumed to 

require a new intake and discharge structure either adjacent to the existing intake or in a 

new location. The closed-cycle cooling option for new units is also assumed to be 

completely independent of the existing plant cooling systems, with the exceptions of 

make-up water which may be withdrawn from the existing cooling system and tower 

blowdown which may be combined with an existing plant discharge.

For the purposes of this analysis, the term “repowered units” refers to full repowering

projects where all (or a large portion) of the major components of an existing generating 

system such as boilers, steam turbines, and condensers are replaced or upgraded. The 

repowered generating system is assumed to be located and sized such that the repowered 

unit(s) will continue to use the existing once-through cooling water intake, intake pumps, 

and discharge system. It is assumed that the water withdrawal flow rate(s) and heat 

discharge rate(s) would not increase.2In fact, since repowered systems are almost always 

more efficient, more power can be generated even though the cooling water capacity has 

not changed. Table 1 below shows the equivalent increase in generating capacity for a 

repowering project if an average existing 500 MW conventional steam cycle plant with 

an efficiency of about 32% (heat rate = 10,800 BTU/Kwh) is replaced with a newer, more 

efficient steam plant that is sized to reject the same amount of waste heat (i.e., no changes 

to cooling water flow rate and condenser temperature rise [range]).

Table 1. Equivalent Generation Capacities for Steam Power Plants with Similar 

Heat Rejection Rates and Equal Cooling Water Flows

Plant Efficiency Equivalent Capacity

(MW)

Increase Factor

Older Existing Coal 32% 500 1.0

 

2 There are several examples of major repowering projects where this has been the case and, since it does 

not require any major modification to the discharge requirements of the existing NPDES permit nor 

increases in surface water impacts, the permit approval process is usually simpler.
- 3 -

Sub-Critical Fossil Fuel 39.2% 653 1.3

Ultra-Critical Fossil Fuel 45.5% 888 1.8

Combined Cycle 56.9% 1451 2.9

General Design and Cost Assumptions

Net O&M and capital costs are estimated on a per MW generating capacity basis so that 

these cost estimates can be applied to generating units of any size. For repowered units,

since the assumptions are that the existing intake will be used for the once-though option, 

the costs apply only to situations where the new condenser flow rate is equal to or less 

than the existing condenser flow rate. Thus, the repowered units will have an increase in 

power generating capacity similar to the ratios shown in Table 1.

Costs are derived using estimated cooling water flow rates and corresponding costs for 

500 MW generating units representing three different available boiler designs. Table 2

presents the generating unit efficiency and design cooling system flow assumptions. The 

heat rate and efficiency values for ultra-critical fossil fuel and combined cycle represent 

estimates of the current state-of-the-art capabilities for these types of generating systems.

Table 2. Generating Unit Design Assumptions

Sub-Critical 

Fossil Fuel

Ultra-Critical 

Fossil Fuel 

Combined Cycle

Capacity (MW) 500 500 500

Heat Rate (BTU/KWh) 8,700 7,500 6,000

Plant Efficiency (%) 39.2 45.5 56.9

Range (oF) 20 15 20 15 20 15

Cooling Water Flow 

(gpm/MW)

440 590 320 430 200 270

Cooling Water Flow 

(gpm)

220,000 295,000 160,000 215,000 100,000 135,000

The design assumptions in Table 2 are used for both the new unit option and the 

repowering option. It is assumed that the cooling (circulating) water flow rate will be the 

same for once-through and closed-cycle cooling options for each generating unit. Costs 

are estimated for two different condenser temperature rise (range) values of 15oF and 

20oF, since cooling water per MW will be different for different range values. These two 

values were selected because they are typical for values used at existing plants.3 The 

ratios between heat rejection and cooling water flow (shown in Table 1), however, do not 

change as long as the range is the same for the new repowered and old generating units.

The flow rate estimates in Table 2 are based on the assumed heat rates and the 

assumption that 90% of the heat not converted to electric power ends up being rejected 

from the system through the cooling water. 

 

3 Whereas a single value for the range would be selected to estimate costs for any given plant. 
- 4 -

Repowering Scenarios

Once-Through Option

The repowering scenarios are assumed to be a full repowering where all of the major 

components of the generating system such as boilers, steam turbines, and condensers are 

replaced or upgraded. For the once-through option, it is assumed that the existing 

shoreline intake pump well and cooling water piping are retained for the new system. 

Cost assumptions for the once-through cooling system include:

 System will use existing intake pumps and piping;

 Pumping head is 35 ft;

 Intake will be upgraded to modified Ristroph screens with a 0.5 fps throughscreen velocity, requiring an expansion of the intake;

 Intake upgrade costs are based on a cost module for a new, larger intake 

structure;4

 O&M costs are based on coarse mesh modified Ristroph screens with the average 

intake flow equal to 75% of design flow;

 Intake water depth is assumed to be 18 ft and well depth used for cost estimates is 

50 ft;

 Existing circulating pumps will be upgraded to variable speed using VFDs, based 

on a unit cost of $15/gpm applied to the cooling water flow.

The major capital cost components for the once-through option are the upgrades of the 

intake needed to meet impingement requirements, which include the intake and screen 

upgrade and the upgrade of pump drives with VFDs. A review of the intake upgrade cost 

estimates for different flows showed that they were not linear, while most other cost 

components in this analysis (including the cooling tower costs) are in fact linear. To 

avoid the skewed results for net costs that would result from mixing linear cooling tower 

costs and non-linear intake modification costs, capital costs were derived for the median 

flow for the ultra-critical fossil fuel plant for Cost Module 3 and then converted to unit 

costs in dollars/gpm. These unit costs were then applied to the flows for all three 

generating unit types.

The major O&M cost components for the once-through option are the intake technology

O&M and the pump energy. The intake technology O&M is based on modified Ristroph 

traveling screens with a through-screen velocity of 0.5 fps. The O&M costs were linear.

Closed-Cycle Option

The required retrofit components for the closed-cycle option are similar to those required 

for cooling tower retrofits at existing generating units that are not modified or repowered. 

 

4

From the costing methodology for the Phase II rule; in cost module 3, a new, larger intake is constructed 

in front of the existing intake.
- 5 -

However, in some respects, demolition and construction activities associated with unit 

repowering should make the retrofit easier and somewhat less costly compared to 

retrofitting an unmodified unit. In addition, there should be no difference between 

cooling system options for the construction downtime associated with the repowering, as 

the construction of either cooling system could easily be completed during the scheduled 

construction downtime.

Recirculating tower option costs were estimated for two retrofit conditions using cost 

estimate factors derived from the EPRI Tower Calculation Worksheet (EPRI 2007a).

One cost estimate uses the EPRI cooling tower retrofit costs for the “easy” difficulty

cooling tower installation option, which represents situations where there is suitable 

space nearby for the cooling tower and that the repower project construction is extensive 

enough such that many of the difficulties encountered in retrofitting cooling towers to a 

mostly unaltered existing generating unit can readily be addressed through design 

modifications of the repowered units. This would be more applicable to major 

repowering projects where a substantial portion of the existing generating unit is 

demolished and replaced with an entirely new system. The other cost estimate uses the 

EPRI cooling tower retrofit costs for the “average” difficulty cooling tower installation, 

which represents more difficult circumstances, such as limited space onsite or the 

proximity of residential areas. Both of these cost items include all of the typical capital 

cost components of a cooling tower retrofit, including cooling towers, pumps, piping, 

make-up water and blowdown systems. 

The factors cited by EPRI (EPRI 2007b) that affect the selection of cooling tower retrofit 

difficulty include:

 The need to make modifications to the condensers;

 The distance between the tower and generating unit;

 Steps necessary to prepare the site such as demolishing buildings or structures;

 Elevation of tower site, e.g., too low site elevation may require grading to raise 

elevation or extra pumps for return flow;

 Presence of underground, surface and overhead interferences such as utilities, 

roadways, and overhead transmission lines that may conflict with the placement 

of the towers, water pipes, and pump wells;

 Difficulty related to tie-in and ability to use existing intake and discharge 

structures for make-up and blowdown;

 Proximity of the location selected for circulating pumps and the availability of 

power;

 Presence of unfavorable soil conditions or contamination.

Since this option assumes that major modifications, if not a complete rebuild, will be 

performed on the generating unit as well as portions of the cooling system, it is 

reasonable to assume that some of these difficulties will be dealt with regardless of the 

cooling option selected and that many may be at least partially mitigated in the repowered 

system design. For this reason, only the “easy” and “average” difficulty cost options are 

included in these repower cooling tower options.
- 6 -

The following assumptions were used for the closed-cycle option:

 Retrofit capital costs are based on EPRI capital cost factor of $160/gpm for an 

“easy” retrofit and $249/gpm for an “average” retrofit;

 Cooling tower pump energy requirements are based on a total pumping head of 38 

to 40 ft;

 Cooling tower fan energy requirements are based on tower cells sized to handle

12,000 gpm per cell with 200 Hp fans in each cell;

 Cooling tower O&M is based on the EPRI cost estimate plus added costs for 

optimized operation at a higher cycle of concentration (COC) than is typical for 

existing power plants with cooling towers. The cost factor used was $2.01/gpm 

of recirculating flow.

New Generating Unit Scenarios

New generating units are assumed to require their own cooling water system that is 

mostly independent of the existing cooling water system. While the site layout may

impose certain restrictions, the flexibility inherent in new construction should allow for 

more optimal placement of generating units, cooling towers, piping, and intakes, at least 

between the cooling system options, than would be available for repowering of existing 

units. It is assumed that cooling water piping costs will be the same for each cooling 

option, since the cooling flow will be the same and similar sized pipes would be used, 

and thus the cost differences will be dependent mostly on the required distances for each 

option. Without knowledge of site-specific conditions, it is not possible to determine 

which option would require greater lengths of piping. 

Once-Through Option

For the once-through option, a new intake structure and traveling screens must be 

constructed along with the pump wells. These costs are based on Cost Module 3. While 

this module is intended to estimate the cost for adding a new larger intake in front of an 

existing intake, is assumed to be reasonably similar to the cost for construction a portion 

of a new intake. An additional cost is added to account for the deeper pump wells needed 

for the once-through option (as opposed to a closed-cycle pump well, which can be 

shallower). Since both pump well and intake screen structures should be similar in 

relative size and cost with respect to concrete requirements and equipment requirements 

(pump shafts versus added screen height), the added pump well depth cost is assumed to 

be similar in magnitude to the difference in cost between the cost for Module 3 with a 50 

ft screen well versus Module 3 with a 25 ft screen well. This is based on the assumption 

that the concrete and equipment costs for the added depth are comparable for the screen 

channel walls and added screening equipment versus the pump well walls and pump 

shaft.

The assumptions for the once-through option include:
- 7 -

 Pumping head is 35 ft;

 Cost for intake screens, screen structure and extra pump well depth are $98/gpm 

flow. This value is based on costs for Module 3 with a 50 ft screen well using a 

flow of 160,000 gpm plus difference between Module 3 costs for 25 ft and 50 ft 

screen wells;

Closed-Cycle Option

It is assumed that the cooling tower option will not require a new intake structure, since 

make-up can often be taken from the existing plant cooling water intake system. As 

such, the cooling tower component costs will be limited to the cooling towers and basins,

with some added costs for make-up and blowdown pumping and piping. Since these 

flows are relatively low, the make-up and blowdown pumping and piping costs are a 

relatively small component but are included. The cooling tower capital costs included in 

this analysis are limited to these components because both systems will require similar 

pump and piping costs.

Capital costs for the pumping equipment are assumed to be the same as those for the 

once-through option. The pump well component costs are also assumed to be equal,

except that the surface water intake pump well structure for the once-through option must 

be deeper to allow for water level fluctuations and prevent equipment damage from flood 

conditions. 

The assumptions for the closed-cycle option include:

 Cost of cooling tower is assumed to be $80/gpm. This cost is derived from the 

estimated median total cost for the towers and basins based on cost estimates 

presented in the report “California's Coastal Power Plants: Alternative Cooling 

System Analysis” (Tetra Tech 2008). These costs include the 25% indirect and 

25% contingency factors used in this report. Report costs are based on design and 

build estimates submitted by cooling tower vendors plus engineering estimates for 

the concrete basins;

 Capital cost of makeup water pumps and piping is assumed to be 5% of cooling 

tower costs;

 Pump energy requirement is based on total pumping head from EPRI worksheet 

(38 to 40 ft);

 Fan energy requirement is based on tower cells sized for 12,000 gpm per cell with 

200 Hp fans;

 Cooling tower O&M is based on the EPRI cost estimate plus added costs for 

optimized operation at a higher COC than is typical for existing power plants with 

cooling towers. The cost factor used was $2.01/gpm of recirculating flow.

Turbine Efficiency Penalty

It is expected that the turbine efficiency penalty as a percent of total power generation 

will be lower for newer, more efficient generating units. The estimates for the turbine 
- 8 -

efficiency penalty presented here use the current EPA estimates for existing plants of 

1.5% for non-nuclear and 2.5% for nuclear plants as the starting point. For newer, more 

efficient generating units, these values are adjusted using assumed high pressure (HP) 

steam turbine inlet pressures. The assumption is that the energy available is a function of 

the difference between the high pressure and low pressure sides of the steam turbine and 

that the energy loss in MW associated with a given increase in the turbine exhaust 

backpressure is somewhat constant, all else being equal. Thus, the percent of energy loss 

due to a given change in turbine backpressure should decrease and be indirectly

proportional to the increase in the HP steam inlet pressure. While the energy available is 

also a function of the inlet steam temperature and steam reheat steps, these values tend to 

be higher as well for the newer generating systems. 

It is also assumed that for new and repowered units, either new or refurbished turbines 

and condensers with improved optimal designs will be utilized and that they will result in 

improved equipment efficiency. This improvement is assumed to result in a 10% 

reduction in the energy penalty over equivalent existing designs. Table 3 shows the 

estimated existing plant energy penalty adjustments based on proportional differences in 

the assumed HP turbine inlet pressures. For combined cycle, the adjustment is based on 

the assumption that the steam component penalty would be similar to that for an existing 

non-nuclear plant but is responsible for only 1/3 of total generation. Table 4 presents the 

estimated energy penalty for repowered and new generating units. While the energy

penalties for non-optimized repowered units are also shown in Table 4, it is reasonable to 

assume that in most cases optimization of condensers and turbines will occur.

Table 3. Assumed Values and Penalties for Existing Plants

Plant Type Assumed Plant 

Efficiency

Assumed HP 

Turbine Inlet 

Pressure (psi)

Penalty Without Optimizing 

Turbine and Condenser 

Design

Nuclear 33% 800 2.5%

Non-nuclear (Old 

and New)

34% 2400 1.5%

Non-nuclear 39% 39% 3600 1.0%

Non-nuclear 45% 45% 4500 0.80%

Combined Cycle157% 1800 0.67%

1 Assumes HSRG produces 33% of power.

Table 4. Estimate New and Repowered Unit Turbine Efficiency Energy Penalty

Plant Type Assumed Plant 

Thermal 

Efficiency

Turbine 

Efficiency

Penalty –

Repower

Turbine 

Efficiency

Penalty –

Repower 

Optimized1

Turbine 

Efficiency

Penalty – New1

Nuclear 33% 2.5% 2.25% 2.25%

Non-nuclear 

(Old and New)

34% 1.5% 1.35% 1.35%

Non-nuclear 39% 1.0% 0.90% 0.90%
- 9 -

39%

Non-nuclear 

45%

45% 0.80% 0.72% 0.72%

Combined 

Cycle2

57% 0.67% 0.60% 0.60%

1 Assume turbine and condenser optimization

2 Assumes HSRG produces 33% of power

Estimated Costs

Tables 5, 6, and 7 present a summary of the estimated Capital and O&M costs in dollars 

(and MW) per MW generating capacity representing the difference in costs between the 

two cooling system options for the three different fuel-type 500 MW plants shown in 

Table 2. Table 5 presents the estimates for adding a new generating unit to an existing 

power plant and Tables 6 and 7 present the estimates for repowering existing generating 

units for “easy” and “average” difficulty cooling tower retrofits, respectively. The tables

show the total costs and differences in costs for the components included in this analysis, 

but do not necessarily include items that were assumed to be equal in value between the 

cooling options. The unit costs per MW were derived by dividing the cost difference by

the generating capacity. The costs in columns 3 through 6 were derived using estimated 

flow rates for a condenser temperature rise (range) of 20oF. To obtain the unit cost 

estimates for a range of 15oF shown in the last column, the 20oF range costs were 

adjusted based on the differences in the estimated condenser flow rates.

Costs are in 2009 dollars, with intake module costs adjusted for inflation using the 

February 2009 ENR CCI index of 8533. O&M costs for energy in dollars and the 

resulting total were derived using an assumed value of $50/MWh and are presented for 

comparative purposes. Where possible, economic analyses should use the energy values 

shown in MW and apply the predicted energy cost per MW for the specific application.
- 10 -

References

Tetra Tech. California's Coastal Power Plants: Alternative Cooling System Analysis.

February 2008.

EPRI. Tower Calculation Worksheet. 2007.

EPRI. Instructions for Retrofit Cost Analyses. 2007
- 11 -

Cost Component Units

Once-Through 

(OT) CCRS

Change OT 

to CCRS

Unit Cost per 

MW at 20 oF 

Range

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 220,000 220,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $423,000 $442,200 $19,200 $38 $51

Pump & Fan Energy MW 1.9 5.21 3.31 0.0066 0.0088

Energy Dollars at $50/MWh1

2009 Dollars $707,000 $1,939,000 $1,232,000 $2,464 $3,277

Total* 2009 Dollars $1,130,000 $2,381,200 $1,251,200 $2,502 $3,328

Energy Penalty % 0.90% 0.90%

Capital Costs 2

2009 Dollars $21,520,000 $18,480,000 -$3,040,000 -$6,080 -$8,086

Cost Component Units

Once-Through 

(OT) CCRS

Increase OT 

to CCRS

Unit Cost per 

MW at 20 oF 

Range

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 160,000 160,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $311,000 $321,600 $10,600 $21 $28

Pump & Fan Energy MW 1.38 3.84 2.46 0.0049 0.0065

Energy Dollars at $50/MWh1

2009 Dollars $514,000 $1,429,000 $915,000 $1,830 $2,434

Total* 2009 Dollars $825,000 $1,750,600 $925,600 $1,851 $2,462

Energy Penalty % 0.72% 0.72%

Capital Costs 2

2009 Dollars $15,650,000 $13,440,000 -$2,210,000 -$4,420 -$5,879

Cost Component Units

Once-Through 

(OT) CCRS

Increase OT 

to CCRS

Unit Cost per 

MW at 20 oF 

Range

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 100,000 100,000

Range oF 20 20 20 20 15

Non-energy O&M 2009 Dollars $199,000 $201,000 $2,000 $4.0 $5.3

Pump & Fan Energy MW 0.86 2.46 1.60 0.0032 0.0043

Energy Dollars at $50/MWh1

2009 Dollars $320,000 $917,000 $597,000 $1,194 $1,588

Total* 2009 Dollars $519,000 $1,118,000 $599,000 $1,198 $1,593

Energy Penalty % 0.75% 0.75%

Capital Costs 2

2009 Dollars $9,780,000 $8,400,000 -$1,380,000 -$2,760 -$3,671

1

 Includes Energy Cost at $50/MWh for illustrative purposes. Economic analyses Non-Energy O&M Plus Energy in MW.

2 Capital costs for OT and CCRS include only items not shared by both and do not necessarily represent total project costs.

3 Costs are based on costs for range = 20 o

F adjusted to reflect the higher flow rate when range = 15 oF

Values in blue to be used in economic modeling

Capital Costs

O&M Costs

Capital Costs

500 MW Combined Cycle Plant (Eff = 57%)

Capital Costs

O&M Costs

500 MW Fossil-fuel Plant (Eff = 39%)

O&M Costs

500 MW Ultra-Critical Fossil-fuel Plant (Eff = 46%)

Difference in Costs for Changing Cooling System Design from Once-through to Closed Cycle for 

New Generating Unit at Existing Plant

Table 5
- 12 -

Units

OnceThrough (OT) CCRSIncrease OT 

to CCRS

Unit Cost per 

MW at 20 oF 

Range

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 220,000 220,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $423,000 $442,200 $19,200 $38 $51

Pump & Fan Energy MW 1.9 4.67 2.77 0.0055 0.0073

Energy Dollars at $50/MWh1

2009 Dollars $707,000 $1,739,000 $1,032,000 $2,064 $2,745

Total 2009 Dollars $1,130,000 $2,181,200 $1,051,200 $2,102 $2,796

Energy Penalty % 0.90% 0.90%

Capital Costs 2009 Dollars $18,450,000 $35,200,000 $16,750,000 $33,500 $44,555

Units

OnceThrough (OT) CCRSIncrease OT 

to CCRS

Unit Cost per 

MW

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 160,000 160,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $311,000 $321,600 $10,600 $21 $28

Pump & Fan Energy MW 1.38 3.44 2.06 0.0041 0.0055

Energy Dollars at $50/MWh1

2009 Dollars $514,000 $1,281,000 $767,000 $1,534 $2,040

Total 2009 Dollars $825,000 $1,602,600 $777,600 $1,555 $2,068

Energy Penalty % 0.72% 0.72%

Capital Costs 2009 Dollars $13,420,000 $25,600,000 $12,180,000 $24,360 $32,399

Units

OnceThrough (OT) CCRSIncrease OT 

to CCRS

Unit Cost per 

MW

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 100,000 100,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $199,000 $201,000 $2,000 $4.0 $5.3

Pump & Fan Energy MW 0.86 2.22 1.36 0.0027 0.0036

Energy Dollars at $50/MWh1

2009 Dollars $320,000 $827,000 $507,000 $1,014 $1,349

Total 2009 Dollars $519,000 $1,028,000 $509,000 $1,018 $1,354

Energy Penalty % 0.75% 0.75%

Capital Costs 2009 Dollars $8,390,000 $16,000,000 $7,610,000 $15,220 $20,243

1

 Includes Energy Cost at $50/MWh for illustrative purposes. Economic analyses Non-Energy O&M Plus Energy in MW.

2 Capital costs for OT and CCRS include only items not shared by both and do not necessarily represent total project costs.

3 Costs are based on costs for range = 20 o

F adjusted to reflect the higher flow rate when range = 15 oF

Values in blue to be used in economic modeling

Capital Costs

500 MW Combined Cycle Plant (Eff = 57%)

O&M Costs

Capital Costs

500 MW Fossil-fuel Plant (Eff = 39%)

O&M Costs

Capital Costs

500 MW Ultra-Critical Fossil-fuel Plant (Eff = 46%)

O&M Costs

Table 6

Difference in Costs for Changing Cooling System Design from Once-through to 

"Easy Difficulty" Closed Cycle for Repower of Existing Generating Unit 
- 13 -

Units

Once-Through 

(OT) CCRS

Increase OT 

to CCRS

Unit Cost per 

MW at 20 oF 

Range

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 220,000 220,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $423,000 $442,200 $19,200 $38 $51

Pump & Fan Energy MW 1.90 4.67 2.77 0.0055 0.0073

Energy Dollars at $50/MWh* 2009 Dollars $707,000 $1,739,000 $1,032,000 $2,064 $2,745

Total O&M 2009 Dollars $1,130,000 $2,181,200 $1,051,200 $2,102 $2,796

Energy Penalty % 0.90% 0.90%

Capital Costs 2009 Dollars $18,450,000 $54,780,000 $36,330,000 $72,660 $96,638

Units

Once-Through 

(OT) CCRS

Increase OT 

to CCRS

Unit Cost per 

MW at 20 oF 

Range

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 160,000 160,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $311,000 $321,600 $10,600 $21 $28

Pump & Fan Energy MW 1.38 3.44 2.06 0.0041 0.0055

Energy Dollars at $50/MWh* 2009 Dollars $514,000 $1,281,000 $767,000 $1,534 $2,040

Total 2009 Dollars $825,000 $1,602,600 $777,600 $1,555 $2,068

Energy Penalty % 0.72% 0.72%

Capital Costs 2009 Dollars $13,420,000 $39,840,000 $26,420,000 $52,840 $70,277

Units

Once-Through 

(OT) CCRS

Increase OT 

to CCRS

Unit Cost per 

MW at 20 oF 

Range

Unit Cost per 

MW at 15 oF 

Range3 

Flow gpm 100,000 100,000

Range o

F 20 20 20 20 15

Non-energy O&M 2009 Dollars $199,000 $201,000 $2,000 $4 $5

Pump & Fan Energy MW 0.86 2.22 1.36 0.0027 0.0036

Energy Dollars at $50/MWh* 2009 Dollars $320,000 $827,000 $507,000 $1,014 $1,349

Total 2009 Dollars $519,000 $1,028,000 $509,000 $1,018 $1,354

Energy Penalty % 0.75% 0.75%

Capital Costs 2009 Dollars $8,390,000 $24,900,000 $16,510,000 $33,020 $43,917

1

 Includes Energy Cost at $50/MWh for illustrative purposes. Economic analyses Non-Energy O&M Plus Energy in MW.

2 Capital costs for OT and CCRS include only items not shared by both and do not necessarily represent total project costs.

3 Costs are based on costs for range = 20 o

F adjusted to reflect the higher flow rate when range = 15 oF

Values in blue to be used in economic modeling

Capital Costs

O&M Costs

Capital Costs

500 MW Combined Cycle Plant (Eff = 57%)

O&M Costs

500 MW Fossil-fuel Plant (Eff = 39%)

O&M Costs

Capital Costs

500 MW Ultra-Critical Fossil-fuel Plant (Eff = 46%)

Difference in Costs for Changing Cooling System Design from Once-through to 

"Average Difficulty" Closed Cycle for Repower of Existing Generating Unit 

Table 7