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 construc tion of cooling water s ys tems for generating units as a way to compar technologies or flow reduction requirements at existing generating units. The following cost an al ysis 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 capacit y; 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; alternativel y, 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 w ith 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 s ys tems for new generating units and for repowered generating units as a way to compar e the se costs against those for retrofitting intake technologies or flow reduction requirements at existing generating units.

al ysis provides an estimate of the net difference in capital and operations and maintenance ( O&M ) costs between the cooling s ys tem 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 capacit y; 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; alternativel y, 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 w ith 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
al ysis provides an estimate of the net difference in capital and

costs between the cooling s ys tem options of flow cycle cooling with mechanical draft cooling towers versus once

rate 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 capacit y; 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 y, allowing the plant to better meet the demand for power; alternativel y, a new or repowered unit may replace (or make obsolete) an older generating unit that was no longer cost

Additionally, For consistency between scenarios (and w ith potential requirements for impingement controls), the costing assumed facilities would install a shoreline intake with modified Ristroph traveling screens with a- 2
-

p rojects 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 relativel y similar: for each type of generating unit, once - through s ys tems are approximately 15% more expensive. For repowered unit s, capital costs for closed

- cycle systems are nearl y twice as high for an “eas y” difficulty retrofit and approximately three times more costl y 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 purpose s 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 s ys tem that is mostly independent of the cooling s ys tem 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 c los ed

- cycle cooling option for new units is also assumed to be completely

independent of the existing plant cooling s ys tems , with the exception s of make

- up water which may be withdrawn from the exi s ting cooling s ys tem and tower blowdown which may

be combined with an existing plant discharge. For the purposes of this analysis , the term “repowered unit s ” refers to full repowering project s 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 s ys tem 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 s ys tem
. Itis assumed that the water withdrawal flow rate ( s ) and heat discharge rate (s) would not increase. 2 In fact, since repowered s ys tems 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 repow ering project if an average existing 500 MW conventional steam cycle plant with an efficiency

of a bout 32 % (h eat rate = 10, 8 00 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 H eat Rejection Rates and Equal Cooling Water Flows Plant Efficiency Equivalent Capacity (MW) In crease 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 im pacts, the permit approval process is usually simpler.- 3
-

Sub

- Critical Fossil F uel 39.2% 653 1.3 Ultra

- Critical Fossil F uel 45.5% 888 1.8 Combined Cycle 56.9% 1451 2.9 General Design and Cost Assumptions Net O&M and ca

pital costs are estimated on a per MW generating capacity basis so that these cost estimate s can be applied to generating units of any size

. F or repowered units , since the assumptions are that the existing intake will be used for the once

- though option, the costs apply onl y 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. Cost s 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 g enerating unit efficiency and design cooling s ys tem flow assumptions. The heat rate and efficiency

v alues for ultra

- critical fossil fuel and combined cycle represent estimates of the current state

- of

- the

- art capabilities for these types of generating s ys tems. Table 2 . Generating Unit Design Assumptions Sub

- C ritical Fossil F uel Ultra

- Critical

Fossil F ue l 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 ( o F) 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 15 oF and 20 oF , since cooling water per MW will be different for different range value s . 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. Th e flow rate estimates in Table 2 are based on the assumed heat rate s and the assumption that 90% of the heat not converted to electric power ends up being rejected from the s ys tem 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

- T hrough Option The repowering scenarios are assumed to be a full repowering where all of the major components of the generating s ys tem such as boilers, steam turbines, and condensers are replaced or upgraded. For the once

- through option , i t is assumed that the existing shoreline intake pump well and cooling water piping are retained for the new system. Cost assumptions f

or the o nce - through cooling s ys tem 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 through

screen 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 7 5% 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 upgrade s of the intake needed to meet impingement requirements , which include the intake and screen upgrade and the upgrade of pump drives with VFD s . A review of the intake upgrade cost estimates for different flows showed that they were not linear , while most other cost component s 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 M odule 3 and then converted to unit costs in dollars/gpm. These unit costs were then applied to the flows for all three generating unit ty

pes. 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 bas ed 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 retrofit s 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 unmo dified unit

. Inaddition, there should be no difference between cooling s ys tem options for the construction downtime associated with the repowering, as the construction of either cooling s ys tem 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 E PRITower Calculation Worksheet (EPRI 2007a)

. O ne cost estimate uses the EPRI cooling tower retrofit costs for the “eas y” difficulty cooling tower installation option, which represents situations where there is suitable space nearb y for the cooling tower and that the repower project construction is extensive enough such that many of the difficulties encountered in retrofitting cooling tower s 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 entirel y new s ys tem. 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 o nsite or the proximity of residential areas

. Both of these cost items include all of the ty pical capital cost components of a cooling tower retrofit , including cooling towers, pumps, piping, make

- up water and blowdown systems. The factors cited b y EPRI (EPRI2007b) 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 o r 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 well s;  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 modificatio ns, if not a complete rebuild, will be performed on the generating unit as well as portions of the cooling s ys tem, 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 partiall y mitigated in the repowered system design. For this reason , onl y the “eas y” and “average” difficulty cost options are included in these repower cooling tower options.- 6
-

The following a ssumptions were used for the closed

- cycle option :

 Retrofit c apital costs are based on EPRIcapital cost factor of $160/gpm for an “eas y” retrofit and $249/gpm for an “average” retrofit ;  Coo l ing tower pump energy requirements are based on a total pumping head of 38 to 40 ft;  Cooling tower f

an energy requirements are based on tower cells sized to handle 12,00 0 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 ty pical for existing power plants with cooling towers. The cost factor used was $2.01/gpm of recirculating flow. N ew G enerating Unit Scenarios New generating units are assumed to require their own cooling water s ys tem 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 fo r more optimal placement of generating units, cooling towers, piping, and intakes, at least between the cooling s ys tem 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 po ssible to determine which option would require greater lengths of piping. Once

- T hrough 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 c an be shallower). Since both pump well and intake screen structures should be similar in relative size and cost with respect to concrete requirements a nd 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 we ll. 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 optio n 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 s ys tem. As such , the cooling tower c omponent costs will be limited to the cooling towers and basins , with some added costs for make

- up and blowdown pumping and p iping

. S ince the se flows are relativel y low, the make

- up and blowdown pumping and piping costs are a relativel y small component but are included

. The cooling tower capital costs included in this analysis are limited to these components because b oth systems will require similar pump and piping costs. C apital 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 a ssumptions for the closed

- cycle option include:

 Cost of co oling 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 Anal ys is ” ( 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 tow er vendors plus engineering estimates for the concrete basin s;  Capital c ost 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 siz ed 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 pow er 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 back pressure 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 s ys tems. 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 improve d equipment efficiency . This improvement is assumed to result in a 10% reduction in the energy

penalty over equivalent exi sting 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 onl y 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 repowere d 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 Ty pe Assumed Plant

Efficiency Assumed HP

Turbine Inlet Pre ssure (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 Cycle 1 57% 1800 0.67% 1 Assumes HSRG produces 33% of power. Table 4 . Estimate New and Repowered Unit Turbine Efficiency Energy Penalty Plant Ty pe Assumed Plant

Thermal Efficiency Turbine

Efficiency Penalty

– Repower Turbine

Efficiency Penalty

– Repower Optimized 1 Turbine

Efficiency Penalty

– New 1
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 Cycle 2 57% 0.67% 0.60% 0.60% 1 Assume turbine and condenser optimization 2 Assumes HSRG produces 33% of power Estimated Costs Table s 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 s ys tem options for the three dif ferent fuel

- ty

pe 500 MW plant s 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 “eas y”and “average” difficulty cooling tower retrofits , respectively

. The table s show the total costs and differences in costs for the components included in this analysis , but do not necessaril y 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 20 oF. To obtain the unit cost estimates for a range of 15 oF shown in the last column , the 20 oF ran ge costs were adjusted based on the differences in the estimated condenser flow rates. Costs are in 2009 dollars, with intake module cost s adjusted for inflation using the February 2009 ENR CCI index o f 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 anal ys es 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 S ys tem Analysis

. February 2008
. EPRI . Tower Calculation W orksheet. 2007. EPRI
. Instructions for Retrofit Cost Analy ses . 2007- 11
- Cost Component Units Once-Through (OT) CCRS Change OT to CCRS Unit Cost per

MW at 20 o F Range Unit Cost per

MW at 15 o F Range 3 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/MWh 1 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 o F Range Unit Cost per

MW at 15 o F Range 3 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/MWh 1 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 o F Range Unit Cost per

MW at 15 o F Range 3 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 2.46 1.60 0.0032 0.0043 Energy Dollars at $50/MWh 1 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 o F 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 Cy cle for New Generating Unit at Existing Plant

Table 5- 12
- Units OnceThrough (OT) CCRS Increase OT to CCRS Unit Cost per

MW at 20 o F Range Unit Cost per

MW at 15 o F Range 3 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/MWh 1 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) CCRS Increase OT to CCRS Unit Cost per

MW Unit Cost per

MW at 15 o F Range 3 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 1 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) CCRS Increase OT to CCRS Unit Cost per

MW Unit Cost per

MW at 15 o F Range 3 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/MWh 1 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 o F 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 o F Range Unit Cost per

MW at 15 o F Range 3 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 o F Range Unit Cost per

MW at 15 o F Range 3 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 o F Range Unit Cost per

MW at 15 o F Range 3 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 o F 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 "A verage Difficulty " Closed Cycle for Repower of Existing Generating Unit Table 7