Updated Capital Cost Estimates for Electricity 

Generation Plants 

November 2010

U. S. Energy Information Administration 

 Office of Energy Analysis 

 U.S. Department of Energy 

Washington, DC 20585

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and analytical agency 

within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are independent of approval by 

any other officer or employee of the United States Government. The views in this report therefore should not be 

construed as representing those of the Department of Energy or other Federal agencies. 
2 

The current and future projected cost of new electricity generation capacity is a critical input into 

the development of energy projections and analyses. The cost of new generating plants plays an 

important role in determining the mix of capacity additions that will serve growing loads in the 

future. New plant costs also help to determine how new capacity competes against existing 

capacity, and the response of the electricity generators to the imposition of environmental 

controls on conventional pollutants or any limitations on greenhouse gas emissions. 

The current and projected future costs of energy-related capital projects, including but not 

limited to new electric generating plants, have been subject to considerable change in recent 

years. EIA updates its cost and performance assumptions annually, as part of the development 

cycle for the Annual Energy Outlook (AEO). For the AEO2011 cycle, EIA commissioned an 

external consultant to develop current cost estimates for utility-scale electric generating plants.1

 

This paper briefly summarizes the design of the project and provides a summary of its main 

findings, including a comparison of the new estimates to those used in AEO2010. The final 

section discusses how EIA uses information on cost and other factors in modeling technology 

choice in the electric power sector. 

Developing Updated Estimates: Key Design Considerations

In order to maximize its value to EIA and external energy analysts, the project focused on 

gathering current information regarding the “overnight”2 cost for a wide range of generation 

technologies, while taking care to use a common boundary in the costing exercise across those 

technologies. The cost estimates for each technology were developed for a generic facility of a 

specific size and configuration, and assuming a location without unusual constraints or 

infrastructure needs. 

Current information is particularly important during a period when actual and estimated costs 

have been evolving rapidly, since the use of up-to-date cost estimates for some technologies in 

conjunction with estimates that are two, three, or even five years old for others can significantly 

skew the results of modeling and analysis. Where possible, costs estimates were based on 

information regarding actual or planned projects available to the consultant. When this 

information was not available, project costs were estimated by using costing models that account 

for current labor and material rates that would be necessary to complete the construction of a 

generic facility. 

The use of a common boundary for costing is also very important. From experience in reviewing 

many costing studies for individual technologies, EIA is well aware that differences in practices 

regarding the inclusion or exclusion of various components of costs can have a large impact on 

overall cost estimates. This includes the categories of civil and structural costs (e.g., allowance 

 

1

 EIA’s electricity modeling includes both combined heat and power (CHP) technologies as well as a variety of 

distributed generation technologies, but those technologies were not addressed in the study, which focused on 

technologies within the electric power sector. 2

 “Overnight cost” is an estimate of the cost at which a plant could be constructed assuming that the entire process 

from planning through completion could be accomplished in a single day. This concept is useful to avoid any 

impact of financing issues and assumptions on estimated costs. Starting from overnight cost estimates, EIA’s 

electricity modeling explicitly takes account of the time required to bring each generation technology online and the 

costs of financing construction in the period before a plant becomes operational. 
3 

for site preparation, drainage, underground utilities, and buildings), project indirect costs (e.g., a 

construction contingency), and owners costs (e.g., development costs, preliminary feasibility and 

engineering studies, environmental studies and permitting, legal fees, insurance costs, property 

taxes during construction, and the electrical interconnection costs, including a plant switchyard 

and tie-in to nearby transmission). 

Summary of updated overnight capital costs estimates and comparison to information used in 

AEO2010

Table 1 summarizes the updated cost estimates for the generic utility-scale generation plants 

represented in EIA’s model, including 7 powered by coal, 6 by natural gas, 3 by solar energy, 2 

each by wind, hydro, biomass, and geothermal power, and 1 each by uranium and municipal 

solid waste. For some plant types there are several options shown to better represent the range of 

plants that might be built and their costs. For example, both single unit and dual unit advanced 

pulverized coal plants are shown, because many plants include multiple units and the costs 

associated with the dual unit configuration might better reflect the costs of most plants built. 

Similarly, solar photovoltaic technologies include a relatively small 7 MW system and a much 

larger 150 MW system, because there is such variance in the sizes of the facilities being 

considered. The nominal capacity of the generic plants ranges from a 7 megawatt (MW) solar 

plant to a 2,236 MW advanced dual-unit nuclear plant, reflecting the significant variation in the 

scale of utility applications. Each technology is characterized by its overnight capital costs, heat 

rate (where applicable), non-fuel operations and maintenance costs, and, though not shown in 

Table 1, its environmental characteristics. 

Table 2 compares the updated overnight cost estimates to those used as inputs to the AEO2010. 

To facilitate comparisons, both are shown in real year 2010 dollars. Notable changes between 

the updated estimates and the AEO2010 values include: 

• Coal & Nuclear: The updated overnight capital cost estimates for coal and nuclear 

power plants are 25 to 37 percent above those in AEO2010. The higher cost estimates 

reflect many factors including the overall trend of rising costs of capital intensive 

technology in the power sector, higher global commodity prices, and the fact that there 

are relatively few construction firms with the ability to complete complex engineering 

projects such as a new nuclear or advanced coal power plant. The study assumes costsharing agreements between the project owner and the project construction contractors 

are reflective of those recently observed in the marketplace. As shown in Table 1, dual 

unit coal and nuclear plants generally have lower overnight costs per kilowatt than singleunit plants, reflecting their ability to take advantage of redundancies and scale economies 

in onsite infrastructure such as wastewater management and environmental controls to 

reduce the estimated total per-kilowatt cost of the project. 

• Natural Gas: The updated cost estimates for natural gas combined cycle and combustion 

turbines generally remained similar to those of AEO2010. 

• Solar: The overnight capital costs for solar thermal and photovoltaic technologies 

dropped by 25 percent and 10 percent, respectively. The decrease in the cost of 

photovoltaics was due to the assumption of larger plant capacity and falling component 

costs. 
4 

• Onshore Wind: Overnight costs for onshore wind increased by about 21 percent relative 

to AEO 2010 assumptions. This is based on a specification for a new, stand-alone wind 

plant including all owners’ costs and may differ from other reported costs in the literature, 

which are not fully characterized and may include sites that are built along side existing 

plants (and are thus able to avoid some amount of infrastructure costs). 

• Offshore Wind: While offshore wind plants have been built in Europe, there have only 

been proposals in the United States, with final permitting only recently issued on the first 

of these proposals. The updated costs, some 50 percent higher than AEO 2010 estimates, 

are consistent with substantial first-of-a-kind costs that would likely be encountered when 

building projects in the United States, which largely lacks the unique infrastructure, 

needed to support this type of construction. 

• Geothermal: Geothermal costs are highly site-specific, and are represented as such in the 

AEO estimates. The updated cost estimate is over 50 percent higher than the same site in 

AEO 2010. 

• Biomass: Biomass capital costs are largely unchanged from AEO2010. However, the 

technology represented by the costs has changed significantly. Prior estimates were for a 

highly efficient plant employing gasification and a combined cycle generator; the new 

estimate is for a significantly less efficient direct combustion boiler. The lower operating 

efficiency (and therefore higher operating cost) for the biomass plant considered in the 

updated cost estimate implies a reduced attractiveness of investment in new biomass 

generation at an overnight cost similar to that for the more efficient biomass plant 

characterized in AEO2010.

While estimates of the current cost of generic electric generation capacity of various types are 

one key input to EIA’s analysis of electricity markets, the evolution of the electricity mix in each 

of the 22 regions to be modeled in AEO20113

 is also sensitive to many other factors, including 

the projected evolution of capital costs over the modeling horizon, projected fuel costs, whether 

wholesale power markets are regulated or competitive, the existing generation mix, additional 

costs associated with environmental control requirements, load growth, and the load shape. 

Almost all of these factors can vary by region, as do capacity factors for renewable generation, 

operations and maintenance costs associated with individual plants, and cost multipliers applied 

to the generic estimates of overnight capital costs outlined in Tables 1 and 2. The next section 

provides a brief overview of some of the relevant issues, which are described in more detail in 

the description of the Electric Market Module included in the 2010 edition of the documentation 

for EIA’s National Energy Modeling System. 

 

EIA’s Analysis of Technology Choice in the Electric Power Sector

Estimates of the overnight capital cost of generic generating technologies are only the starting 

point for consideration of the cost of new generating capacity in EIA modeling analyses. EIA 

also considers regional variation in construction costs, the structure of wholesale power markets 

that affect financing costs, the length of time required to bring each type of plant into service, 

and the capacity availability factors for solar and wind generation plants. EIA also accounts for 

 

3

 In AEO2010 and prior editions, the continental U.S., excluding Alaska, was divided in 13 regions for purposes of 

electricity modeling. The 22 region model that will be used starting with AEO2011 will allow for better 

representation of policy boundaries and market structure at the State level. 
5 

three distinct dynamic forces that drive changes in plant cost over time. One is the projected 

relationship between rate of inflation for key drivers of plant costs, such as materials and 

construction costs, and the overall economy-wide rate of inflation. A projected economy–wide 

inflation rate that exceeds projected inflation for key plant cost drivers results in a projected 

decline in real (inflation-adjusted) capital costs. Projected capital costs also reflect projected 

technology progress over time. Learning-by-doing, which allows for additional reductions in 

projected capital costs as a function of cumulative additions new technologies, has a further 

effect on technology costs. See the AEO2010 assumptions and model documentation for more 

details.4

 

Levelized cost is often cited as a convenient summary measure of the overall competiveness of 

different generating technologies. Levelized cost represents the present value of the total cost of 

building and operating a generating plant over an assumed economic life, converted to equal 

annual payments and expressed in terms of real dollars to remove the impact of inflation. 

Levelized costs, which reflect overnight capital cost, fuel cost, fixed and variable O&M cost, are 

a useful indicator of the competitiveness of different generation technologies. For technologies 

such as solar and wind generation that have no fuel costs and relatively small O&M costs, 

levelized cost changes in rough proportion to the estimated overnight capital cost of generation 

capacity. For technologies with significant fuel cost, both fuel cost and overnight cost estimates 

significantly affect levelized cost. Thus, while Table 2 shows little change between the updated 

capital cost estimates for natural gas combined cycle plants and those used in AEO2010, 

improved supply prospects for natural gas that will be incorporated in AEO2011 result in lower 

projected prices that in turn lower the levelized cost of gas-fired generation and improve the 

attractiveness of operating and adding gas-fired generation technologies. 

It is important to note, however, that actual investment decisions are affected by numerous 

factors other than levelized costs. The projected utilization rate, which depends on the load 

shape and the existing resource mix in an area where additional capacity is needed, is one such 

factor. The existing resource mix in a region can directly affect the economic viability of a new 

investment through its effect on the economics surrounding the displacement of existing 

resources. For example, a wind resource that would primarily back out existing natural gas 

generation will generally have a higher value than one that would back out existing coal 

generation under fuel price conditions where the variable cost of operating existing gas-fired 

plants exceeds that of operating existing coal-fired plants. 

A related factor is the capacity value, which depends on both the existing capacity mix and load 

characteristics in a region. Since load must be balanced on a continuous basis, units whose 

output can be varied to follow demand generally have more value to a system than less flexible 

units or those whose operation is tied to the availability of an intermittent resource. Policyrelated factors, such as investment or production tax credits for specified generation sources, can 

also impact investment decisions. Finally, although levelized cost calculations are generally 

made using an assumed set of capital and operating costs, the inherent uncertainty about future 

fuel prices and future policies, may cause plant owners or investors who finance plants to place a 

 

4

 Assumptions and model documentation for the 2010 Annual Energy Outlook are available at 

http://www.eia.doe.gov/oiaf/aeo/index.html. 
6 

value on portfolio diversification. EIA considers all of these factors in its analyses of 

technology choice in the electricity sector. 

In sum, while overnight cost estimates are important inputs for EIA modelers and other analysts, 

they are not the sole driver of the choice among electric generation technologies. Users 

interested in additional details regarding these updated cost estimates should review the 

consultant study prepared by R.W. Beck for EIA in Appendix A. 
7 

 Table 1. Updated Estimates of Power Plant Capital and Operating Costs 

 

Plant Characteristics Plant Costs 

Nominal 

Capacity 

(kilowatts) 

Heat Rate 

(Btu/kWh) 

Overnight 

Capital 

Cost (2010 

$/kW) 

Fixed O&M 

Cost 

(2010$/kW) 

Variable 

O&M 

Cost 

(2010 

$/MWh) 

 Coal 

Single Unit 

Advanced PC 650,000 8,800 $3,167 $35.97 $4.25

Dual Unit 

Advanced PC 1,300,000 8,800 $2,844 $29.67 $4.25

Single Unit Advanced PC with CCS 650,000 12,000 $5,099 $76.62 $9.05

Dual Unit Advanced PC with CCS 1,300,000 12,000 $4,579 $63.21 $9.05

Single Unit IGCC 600,000 8,700 $3,565 $59.23 $6.87

Dual Unit IGCC 1,200,000 8,700 $3,221 $48.90 $6.87

Single Unit IGCC with CCS 520,000 10,700 $5,348 $69.30 $8.04

 Natural Gas 

Conventional NGCC 540,000 7,050 $978 $14.39 $3.43

Advanced NGCC 400,000 6,430 $1,003 $14.62 $3.11

Advanced NGCC with CCS 340,000 7,525 $2,060 $30.25 $6.45

Conventional CT 85,000 10,850 $974 $6.98 $14.70

Advanced CT 210,000 9,750 $665 $6.70 $9.87

Fuel Cells 10,000 9,500 $6,835 $350 $0.00

 Uranium 

Dual Unit Nuclear 2,236,000 N/A $5,335 $88.75 $2.04

 Biomass 

Biomass CC 20,000 12,350 $7,894 $338.79 $16.64

Biomass BFB 50,000 13,500 $3,860 $100.50 $5.00

 Wind 

Onshore Wind 100,000 N/A $2,438 $28.07 $0.00

Offshore Wind 400,000 N/A $5,975 $53.33 $0.00

 Solar 

Solar Thermal 100,000 N/A $4,692 $64.00 $0.00

Small Photovoltaic 7,000 N/A $6,050 $26.04 $0.00

Large Photovoltaic 150,000 N/A $4,755 $16.7 $0.00

 Geothermal 

Geothermal – Dual Flash 50,000 N/A $5,578 $84.27 $9.64

Geothermal – Binary 50,000 NA $4,141 $84.27 $9.64

 MSW 

MSW 50,000 18,000 $8,232 $373.76 $8.33

 Hydro 

Hydro-electric 500,000 N/A $3,076 $13.44 $0.00

Pumped Storage 250,000 N/A $5,595 $13.03 $0.00
8 

Table 2. Comparison of Updated Plant Costs to AEO2010 Plant Costs 

Table II 

 Overnight Capital Cost ($/kW) Nominal Capacity KWs1

 

AEO 

2011 

AEO 

2010 

% 

Change 

AEO 

2011 AEO 2010 

Coal 

Advanced PC w/o CCS $2,844 $2,271 25% 1,300,000 600,000 

IGCC w/o CCS $3,221 $2,624 23% 1,200,000 550,000 

IGCC CCS $5,348 $3,857 39% 600,000 380,000 

Natural Gas 

Conventional NGCC $978 $1,005 -3% 540,000 250,000 

Advanced NGCC $1,003 $989 1% 400,000 400,000 

Advanced NGCC with 

CCS $2,060 $1,973 4% 340,000 400,000 

Conventional CT $974 $700 39% 85,000 160,000 

Advanced CT $665 $662 0% 210,000 230,000 

Fuel Cells $6,835 $5,595 22% 10,000 10,000 

Nuclear 

Nuclear $5,339 $3,902 37% 2,236,000 1,350,000 

Renewables 

Biomass $3,860 $3,931 -2% 50,000 80,000 

Geothermal $4,141 $1,786 132% 50,000 50,000 

MSW - Landfill Gas $8,232 $2,655 210% 50,000 30,000 

Conventional 

Hydropower $3,078 $2,340 32% 500,000 500,000 

Wind $2,438 $2,007 21% 100,000 50,000 

Wind Offshore $5,975 $4,021 49% 400,000 100,000 

Solar Thermal $4,692 $5,242 -10% 100,000 100,000 

Photovoltaic $4,755 $6,303 -25% 150,000 5,000 

1 Higher plant capacity reflects the assumption that plants would install multiple units per 

site and that savings could be gained by eliminating redundancies and combining 

services. 
9 

Appendix A 
R. W. Beck, Inc. 

Science Applications International Corporation (SAIC) 

Prepared by: 

Vincent Hahn, R. W. Beck 

John Fix, R. W. Beck 

John Schmalz, R. W. Beck 

Michael Wennen, R. W. Beck 

Evis Couppis, Ph.D., R. W. Beck 

Prepared in Coordination with: 

Jay Ratafia-Brown, SAIC 

Prepared For: 

Energy Information Administration 

Office of Integrated Analysis and Forecasting 

Alan Beamon 

Michael Leff 

October 2010 

EOP III TASK 1606, SUBTASK 3 – REVIEW OF 

POWER PLANT COST AND PERFORMANCE 

ASSUMPTIONS FOR NEMS 

Technology Documentation Report 
Disclaimer

Certain statements included in this report constitute forward-looking statements. The achievement of certain results 

or other expectations contained in such forward-looking statements involve known and unknown risks, uncertainties 

and other factors which may cause actual results, performance or achievements described in the report to be 

materially different from any future results, performance or achievements expressed or implied by such 

forward-looking statements. We do not plan to issue any updates or revisions to the forward-looking statements if 

or when our expectations or events, conditions, or circumstances on which such statements are based occur. 
i 

TABLE OF CONTENTS 

1. Introduction ................................................................................................................. 1-1

1.1 Technologies Assessed .......................................................................................... 1-1

2. General Basis for Technology Evaluation Basis ...................................................... 2-1

2.1 R. W. Beck Background ........................................................................................ 2-1

2.2 Base Fuel Characteristics ...................................................................................... 2-1

2.3 Environmental Compliance Basis ......................................................................... 2-4

2.4 Local Capacity Adjustments ................................................................................. 2-4

2.5 Technology Specifications .................................................................................... 2-6

2.6 Cost Estimation Methodology ............................................................................... 2-6

2.6.1 Capital Cost ............................................................................................................ 2-6

2.6.1.1 Costing Scope .................................................................................................. 2-6

2.6.2 Operation and Maintenance (O&M) Expenses ...................................................... 2-7

2.6.2.1 Fixed O&M (FOM).......................................................................................... 2-8

2.6.2.2 Variable O&M (VOM) .................................................................................... 2-8

2.6.2.3 Major Maintenance .......................................................................................... 2-8

3. Advanced Pulverized Coal (APC) ............................................................................. 3-1

3.1 Mechanical Equipment and Systems ..................................................................... 3-1

3.2 Electrical and Control Systems ............................................................................. 3-2

3.3 Off-Site Requirements ........................................................................................... 3-2

3.4 Capital Cost Estimate ............................................................................................ 3-3

3.5 O&M Estimate ...................................................................................................... 3-8

3.6 Environmental Compliance Information ............................................................... 3-8

4. Advanced Pulverized Coal With CCS (APC/CCS).................................................. 4-1

4.1 Mechanical Equipment and Systems ..................................................................... 4-1

4.2 Electrical and Control Systems ............................................................................. 4-2

4.3 Off-Site Requirements ........................................................................................... 4-2

4.4 Capital Cost Estimate ............................................................................................ 4-2

4.5 O&M Estimate ...................................................................................................... 4-7

4.6 Environmental Compliance Information ............................................................... 4-8
ii 

5. Conventional Natural Gas Combined Cycle (NGCC) ............................................. 5-1

5.1 Mechanical Equipment and Systems ..................................................................... 5-1

5.2 Electrical and Control Systems ............................................................................. 5-2

5.3 Off-Site Requirements ........................................................................................... 5-2

5.4 Capital Cost Estimate ............................................................................................ 5-3

5.5 O&M Estimate ...................................................................................................... 5-6

5.6 Environmental Compliance Information ............................................................... 5-7

6. Advanced Generation Natural Gas Combined Cycle (AG-NGCC) ....................... 6-1

6.1 Mechanical Equipment and Systems ..................................................................... 6-1

6.2 Electrical and Control Systems ............................................................................. 6-1

6.3 Off-Site Requirements ........................................................................................... 6-1

6.4 Capital Cost Estimate ............................................................................................ 6-1

6.5 O&M Estimate ...................................................................................................... 6-4

6.6 Environmental Compliance Information ............................................................... 6-4

7. Advanced Generation Natural Gas Combined Cycle With CCS 

(AG-NGCC/CCS)........................................................................................................ 7-1

7.1 Mechanical Equipment and Systems ..................................................................... 7-1

7.2 Electrical and Control Systems ............................................................................. 7-1

7.3 Off-Site Requirements ........................................................................................... 7-1

7.4 Capital Cost Estimate ............................................................................................ 7-1

7.5 O&M Estimate ...................................................................................................... 7-4

7.6 Environmental Compliance Information ............................................................... 7-4

8. Conventional Combustion Turbine (CT).................................................................. 8-1

8.1 Mechanical Equipment and Systems ..................................................................... 8-1

8.2 Electrical and Control Systems ............................................................................. 8-1

8.3 Off-Site Requirements ........................................................................................... 8-1

8.4 Capital Cost Estimate ............................................................................................ 8-2

8.5 O&M Estimate ...................................................................................................... 8-5

8.6 Environmental Compliance Information ............................................................... 8-6

9. Advanced Combustion Turbine (ACT) .................................................................... 9-1

9.1 Mechanical Equipment and Systems ..................................................................... 9-1

9.2 Electrical and Control Systems ............................................................................. 9-1
iii 

9.3 Off-Site Requirements ........................................................................................... 9-1

9.4 Capital Cost Estimate ............................................................................................ 9-1

9.5 O&M Estimate ...................................................................................................... 9-4

9.6 Environmental Compliance Information ............................................................... 9-4

10. Integrated Gasification Combined Cycle (IGCC) ................................................. 10-1

10.1 Mechanical Equipment and Systems ................................................................... 10-1

10.2 Electrical and Control Systems ........................................................................... 10-3

10.3 Off-Site Requirements ......................................................................................... 10-3

10.4 Capital Cost Estimate .......................................................................................... 10-4

10.5 O&M Estimate .................................................................................................. 10-10

10.6 Environmental Compliance Information ........................................................... 10-11

11. Integrated Gasification Combined Cycle With CCS (IGCC/CCS) ...................... 11-1

11.1 Mechanical Equipment and Systems ................................................................... 11-1

11.2 Electrical and Control Systems ........................................................................... 11-1

11.3 Off-Site Requirements ......................................................................................... 11-1

11.4 Capital Cost Estimate .......................................................................................... 11-1

11.5 O&M Estimate .................................................................................................... 11-4

11.6 Environmental Compliance Information ............................................................. 11-4

12. Advanced Nuclear (AN) ........................................................................................... 12-1

12.1 Mechanical Equipment and Systems ................................................................... 12-1

12.2 Electrical and Control Systems ........................................................................... 12-2

12.3 Off-Site Requirements ......................................................................................... 12-3

12.4 Capital Cost Estimate .......................................................................................... 12-3

12.5 O&M Estimate .................................................................................................... 12-7

12.6 Environmental Compliance Information ............................................................. 12-7

13. Biomass Combined Cycle (BCC) ............................................................................. 13-1

13.1 Mechanical Equipment and Systems ................................................................... 13-1

13.2 Electrical and Control Systems ........................................................................... 13-2

13.3 Off-Site Requirements ......................................................................................... 13-3

 
iv 

13.4 Capital Cost Estimate .......................................................................................... 13-3

13.5 O&M Estimate .................................................................................................... 13-7

13.6 Environmental Compliance Information ............................................................. 13-8

14. Biomass Bubbling Fluized Bed (BBFB) .................................................................. 14-1

14.1 Mechanical Equipment and Systems ................................................................... 14-1

14.2 Electrical and Control Systems ........................................................................... 14-2

14.3 Off-Site Requirements ......................................................................................... 14-2

14.4 Capital Cost Estimate .......................................................................................... 14-2

14.5 O&M Estimate .................................................................................................... 14-6

14.6 Environmental Compliance Information ............................................................. 14-7

15. Fuel Cell (FC) Mechanical Equipment and Systems ............................................. 15-1

15.1 Electrical and Control Systems ........................................................................... 15-1

15.2 Off-Site Requirements ......................................................................................... 15-1

15.3 Capital Cost Estimate .......................................................................................... 15-2

15.4 O&M Estimate .................................................................................................... 15-5

15.5 Environmental Compliance Information ............................................................. 15-6

16. Geothermal Dual Flash (GT) ................................................................................... 16-1

16.1 Mechanical Equipment and Systems ................................................................... 16-1

16.2 Electrical and Control Systems ........................................................................... 16-2

16.3 Off-Site Requirements ......................................................................................... 16-2

16.4 Capital Cost Estimate .......................................................................................... 16-3

16.5 O&M Estimate .................................................................................................... 16-6

16.6 Environmental Compliance Information ............................................................. 16-6

17. Geothermal Binary (Binary) .................................................................................... 17-1

17.1 Mechanical Equipment and Systems ................................................................... 17-1

17.2 Electrical and Control Systems ........................................................................... 17-1

17.3 Off-Site Requirements ......................................................................................... 17-2

17.4 Capital Cost Estimate .......................................................................................... 17-2

17.5 O&M Estimate .................................................................................................... 17-5

17.6 Environmental Compliance Information ............................................................. 17-6
v 

18. Municipal Solid Waste (MSW) ................................................................................ 18-1

18.1 Mechanical Equipment and Systems ................................................................... 18-1

18.2 Electrical and Control Systems ........................................................................... 18-2

18.3 Off-Site Requirements ......................................................................................... 18-2

18.4 Capital Cost Estimate .......................................................................................... 18-2

18.5 O&M Estimate .................................................................................................... 18-5

18.6 Environmental Compliance Information ............................................................. 18-6

19. Hydroelectric (HY) ................................................................................................... 19-1

19.1 Mechanical Equipment and Systems ................................................................... 19-1

19.2 Electrical and Control Systems ........................................................................... 19-1

19.3 Off-Site Requirements ......................................................................................... 19-1

19.4 Capital Cost Estimate .......................................................................................... 19-2

19.5 O&M Estimate .................................................................................................... 19-5

19.6 Environmental Compliance Information ............................................................. 19-5

20. Pumped Storage (PS) ................................................................................................ 20-1

20.1 Mechanical Equipment and Systems ................................................................... 20-1

20.2 Electrical and Control Systems ........................................................................... 20-1

20.3 Off-Site Requirements ......................................................................................... 20-1

20.4 Capital Cost Estimate .......................................................................................... 20-2

20.5 O&M Estimate .................................................................................................... 20-5

20.6 Environmental Compliance Information ............................................................. 20-5

21. Onshore Wind (WN) ................................................................................................. 21-1

21.1 Mechanical Equipment and Systems ................................................................... 21-1

21.2 Electrical and Control Systems ........................................................................... 21-2

21.3 Off-Site Requirements ......................................................................................... 21-2

21.4 Capital Cost Estimate .......................................................................................... 21-2

21.5 O&M Estimate .................................................................................................... 21-5

21.6 Environmental Compliance Information ............................................................. 21-6

22. Offshore Wind (WF) ................................................................................................. 22-1

22.1 Mechanical Equipment and Systems ................................................................... 22-1

22.2 Electrical and Control Systems ........................................................................... 22-2
vi 

22.3 Off-Site Requirements ......................................................................................... 22-2

22.4 Capital Cost Estimate .......................................................................................... 22-3

22.5 O&M Estimate .................................................................................................... 22-6

22.6 Environmental Compliance Information ............................................................. 22-6

23. Solar Thermal - Central Station (SO) ..................................................................... 23-1

23.1 Mechanical Equipment and Systems ................................................................... 23-1

23.2 Electrical and Control Systems ........................................................................... 23-2

23.3 Off-Site Requirements ......................................................................................... 23-3

23.4 Capital Cost Estimate .......................................................................................... 23-3

23.5 O&M Estimate .................................................................................................... 23-7

23.6 Environmental Compliance Information ............................................................. 23-7

24. Photovoltaic (Central Station) Facility (PV) .......................................................... 24-1

24.1 Mechanical Equipment and Systems ................................................................... 24-1

24.2 Electrical and Control Systems ........................................................................... 24-1

24.3 Off-Site Requirements ......................................................................................... 24-2

24.4 Capital Cost Estimate .......................................................................................... 24-2

24.5 O&M Estimate .................................................................................................... 24-9

24.6 Environmental Compliance Information ........................................................... 24-10
vii 

LIST OF FIGURES 

Figure 3-1 – Advanced Pulverized coal Design Configuration ................................................... 3-2

Figure 4-1 – APC Facility Diagram ............................................................................................. 4-1

Figure 4-2 – APC/CCS Facility Diagram .................................................................................... 4-2

Figure 5-1 – Conventional NGCC Design Configuration ........................................................... 5-2

Figure 6-1 – AG-NGCC Design Configuration ........................................................................... 6-1

Figure 7-1 – AG-NGCC With CCS Design Configuration ......................................................... 7-1

Figure 8-1 – Conventional CT Design Configuration ................................................................. 8-1

Figure 9-1 – Advanced CT Design Configuration ....................................................................... 9-1

Figure 10-1 – IGCC Design Configuration ............................................................................... 10-3

Figure 11-1 – IGCC/CCS Design Configuration ....................................................................... 11-1

Figure 12-1 – AN Design Configuration ................................................................................... 12-2

Figure 13-1 – BCC Design Configuration ................................................................................. 13-2

Figure 14-1 – BCC Design Configuration ................................................................................. 14-1

Figure 15-1 – FC Design Configuration .................................................................................... 15-1

Figure 16-1 – GT Design Configuration .................................................................................... 16-2

Figure 17-1 – GT Design Configuration .................................................................................... 17-1

Figure 19-1 – Hy Design Configuration .................................................................................... 19-1

Figure 20-1 – PS Design Configuration..................................................................................... 20-1

Figure 21-1 – WN Design Configuration .................................................................................. 21-1

Figure 22-1 – WF Design Configuration ................................................................................... 22-2

Figure 23-1 – So Design Configuration ..................................................................................... 23-2

Figure 24-1 – PV Design Configuration .................................................................................... 24-1
viii 

LIST OF TABLES 

Table 1-1 – List of Technologies For Review ............................................................................. 1-2

Table 2-1 – Reference Coal Specification ................................................................................... 2-2

Table 2-2 – Natural Gas Specification ......................................................................................... 2-3

Table 2-3 – Wood-Biomass Specification ................................................................................... 2-3

Table 2-4 – CT Capacity Adjustments ......................................................................................... 2-5

Table 2-5 – Technology Performance Specifications ................................................................ 2-10

Table 3-1 – Base Plant Site Capital Cost Estimate for APC ........................................................ 3-3

Table 3-2 – Base Plant Site Capital Cost Estimate for APC ........................................................ 3-4

Table 3-3 – Location-Based Costs for APC (650,000 kW) ......................................................... 3-5

Table 3-4 – Location-Based Costs for APC (1,300,000 kW) ...................................................... 3-7

Table 3-5 – O&M Expenses for APC (650,000 kW) ................................................................... 3-8

Table 3-6 – O&M Expenses for APC (1,300,000 kW) ................................................................ 3-8

Table 3-7 – Environmental Emissions for APC .......................................................................... 3-9

Table 4-1 – Base Plant Site Capital Cost Estimate for APC/CCS ............................................... 4-3

Table 4-2 – Base Plant Site Capital Cost Estimate for APC/CCS ............................................... 4-3

Table 4-3– Location-Based Costs for APC/CCS Facility (650,000 kW) .................................... 4-4

Table 4-4 – Location-Based Costs for APC/CCS Facility (1,300,000 kW) ................................ 4-6

Table 4-5 – O&M Expenses for APC/CCS (650,000 kW) .......................................................... 4-7

Table 4-6 – O&M Expenses for APC/CCS (1,300,000 kW) ....................................................... 4-8

Table 4-7 – Environmental Emissions for APC/CCS .................................................................. 4-8

Table 5-1 – Base Plant Site Capital Cost Estimate for Conventional NGCC .............................. 5-3

Table 5-2 – Location-Based Costs for Conventional NGCC....................................................... 5-5

Table 5-3 – O&M Expenses for Conventional NGCC ................................................................ 5-7

Table 5-4 – Environmental Emissions for Conventional NGCC ................................................. 5-7

Table 6-1 – Base Plant Site Capital Cost Estimate for AG-NGCC ............................................. 6-2

Table 6-2 – Location-Based Costs for AG-NGCC ...................................................................... 6-3

Table 6-3 – O&M Expenses for AG-NGCC ................................................................................ 6-4

Table 6-4 – Environmental Emissions for AG-NGCC ................................................................ 6-5

Table 7-1 – Base Plant Site Capital Cost Estimate for AG-NGCC/CCS Cost ............................ 7-2

Table 7-2 – Location-Based Costs for AG-NGCC/CCS ............................................................. 7-3
ix 

Table 7-3 – O&M Expenses for AG-NGCC With CCS .............................................................. 7-4

Table 7-4 – Environmental Emissions for AG-NGCC/CCS ....................................................... 7-5

Table 8-1 – Base Plant Site Capital Cost Estimate for Conventional CT .................................... 8-2

Table 8-2 – Location-Based Costs for Conventional CT............................................................. 8-4

Table 8-3 – O&M Expenses for Conventional CT ...................................................................... 8-6

Table 8-4 – Environmental Emissions for Conventional CT ....................................................... 8-6

Table 9-1 – Base Plant Site Capital Cost Estimate for Advanced CT ......................................... 9-2

Table 9-2 – Location-Based Costs for Advanced CT .................................................................. 9-3

Table 9-3 – O&M Expenses for Advanced CT ........................................................................... 9-4

Table 9-4 – Environmental Emissions for Advanced CT ............................................................ 9-5

Table 10-1 – Base Plant Site Capital Cost Estimate for IGCC .................................................. 10-4

Table 10-2 – Base Plant Site Capital Cost Estimate for IGCC .................................................. 10-5

Table 10-3 – Location-Based Costs for IGCC (600,000 kW) ................................................... 10-7

Table 10-4 – Location-Based Costs for IGCC (1,200,000 kW) ................................................ 10-9

Table 10-5 – O&M Expenses for IGCC (600,000 kW) ........................................................... 10-10

Table 10-6 – O&M Expenses for IGCC (1,200,000 kW) ........................................................ 10-11

Table 10-7 – Environmental Emissions for IGCC ................................................................... 10-11

Table 11-1 – Base Plant Site Capital Cost Estimate for IGCC/CCS ......................................... 11-2

Table 11-2 – Location-Based Costs for IGCC/CCS .................................................................. 11-3

Table 11-3 – O&M Expenses for IGCC/CCS............................................................................ 11-4

Table 11-4 – Environmental Emissions for IGCC/CCS ............................................................ 11-5

Table 12-1 – Base Plant Site Capital Cost Estimate for AN ...................................................... 12-4

Table 12-2 – Location-Based Costs for AN .............................................................................. 12-5

Table 12-3 – O&M Expenses for AN ........................................................................................ 12-7

Table 12-4 – Environmental Emissions for AN ........................................................................ 12-7

Table 13-1 – Base Plant Site Capital Cost Estimate for BCC ................................................... 13-4

Table 13-2 – Location-Based Costs for BCC ............................................................................ 13-6

Table 13-3 – O&M Expenses for BCC ...................................................................................... 13-7

Table 13-4 – Environmental Emissions for BCC ...................................................................... 13-8

Table 14-1 – Base Plant Site Capital Cost Estimate for BBFB ................................................. 14-3

Table 14-2– Location-Based Costs for BBFB ........................................................................... 14-5

Table 14-3 – O&M Expenses for BCC ...................................................................................... 14-6

Table 14-4 – Environmental Emissions for BBFB .................................................................... 14-7
x 

Table 15-1 – Base Plant Site Capital Cost Estimate for FC ...................................................... 15-2

Table 15-2 – Location-Based Costs for FC ............................................................................... 15-4

Table 15-3 – O&M Expenses for FC ......................................................................................... 15-5

Table 15-4 – Environmental Emissions for FC ......................................................................... 15-6

Table 16-1 – Base Plant Site Capital Cost Estimate for GT ...................................................... 16-3

Table 16-2 – Location-Based Costs for GT ............................................................................... 16-5

Table 16-3 – O&M Expenses for GT ........................................................................................ 16-6

Table 16-4 – Environmental Emissions for GT ......................................................................... 16-7

Table 17-1 – Base Plant Site Capital Cost Estimate for GT ...................................................... 17-2

Table 17-2 – Location-Based Costs for GT ............................................................................... 17-4

Table 17-3 – O&M Expenses for Binary ................................................................................... 17-5

Table 17-4 – Environmental Emissions for Binary ................................................................... 17-6

Table 18-1 – Base Plant Site Capital Cost Estimate for MSW .................................................. 18-3

Table 18-2 – Location-Based Costs for MSW ........................................................................... 18-4

Table 18-3 – O&M Expenses for MSW .................................................................................... 18-6

Table 18-4 – Environmental Emissions for MSW ..................................................................... 18-6

Table 19-1 – Base Plant Site Capital Cost Estimate for HY ...................................................... 19-2

Table 19-2 – Location-Based Costs for HY .............................................................................. 19-4

Table 19-3 – O&M Expenses for HY ........................................................................................ 19-5

Table 19-4 – Environmental Emissions for HY ........................................................................ 19-6

Table 20-1 – Base Plant Site Capital Cost Estimate for PS ....................................................... 20-2

Table 20-2 – Location-Based Costs for PS ................................................................................ 20-4

Table 20-3 – O&M Expenses for PS ......................................................................................... 20-5

Table 20-4 – Environmental Emissions for PS .......................................................................... 20-6

Table 21-1 – Location-Based Costs for WN.............................................................................. 21-3

Table 21-2 – Location-Based Costs for WN.............................................................................. 21-4

Table 21-3 – O&M Expenses for WN ....................................................................................... 21-6

Table 21-4 – Environmental Emissions for WN ........................................................................ 21-6

Table 22-1 – Base Plant Site Capital Cost Estimate for WF ..................................................... 22-3

Table 22-2 – Location-Based Costs for WF .............................................................................. 22-5

Table 23-1 – Base Plant Site Capital Cost Estimate for SO ...................................................... 23-4

Table 23-2 – Location-Based Costs for SO ............................................................................... 23-6

Table 23-3 – O&M Expenses for SO ......................................................................................... 23-7
xi 

Table 23-4 – Environmental Emissions for SO ......................................................................... 23-8

Table 24-1 – Base Plant Site Capital Cost Estimate for PV ...................................................... 24-3

Table 24-2 – Base Plant Site Capital Cost Estimate for PV ...................................................... 24-4

Table 24-3 – Location-Based Costs for PV (7 MW) ................................................................. 24-6

Table 24-4 – Location-Based Costs for PV (150 MW) ............................................................. 24-8

Table 24-5 – O&M Expenses for PV Facility (7 MW) ............................................................. 24-9

Table 24-6 – O&M Expenses for PV Facility (150 MW) ......................................................... 24-9

Table 24-7 – Environmental Emissions for PV ....................................................................... 24-10
xii 

LIST OF ACRONYMS AND ABBREVIATIONS 

AC Alternating Current 

AG Advanced Generation 

AG Advanced Generation 

AG-NGCC Advanced Generation Natural Gas Combined Cycle 

AG-NGCC/CCS Advanced Generation Natural Gas Combined Cycle with CCS 

AGR Acid Gas Removal 

AN Advanced Nuclear 

APC Advanced Pulverized Coal Facility 

APC/CCS Advanced Pulverized Coal with CCS 

ASU Air Separation Unit 

BACT Best Available Control Technology 

BCC Biomass Combined Cycle 

BBFB Biomass Bubbling Fluidized Bed 

BFB Bubbling Fluidized Bed 

BOP Balance-of-Plant 

BPF Brine Processing Facility 

Btu British Thermal Unit 

C Carbon 

CCS Carbon Capture and Sequestration 

CFB Circulating Fluidized Bed 

C2H6 Ethane 

C3H8 Propane 

C4H10 n-Butane 

CH4 Methane 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

COS Carbonyl Sulfide 

CT Combustion Turbine 

DC Direct Current 

DCS Distributed Control System 

DLN Dry Low-NOX Combustion 

EIA Energy Information Administration 

EMM Electricity Market Module of NEMS 

EPC Engineering, Procurement and Construction 

°F Degrees Fahrenheit 

FC Fuel Cell 

FGD Flue Gas Desulfurization 

FOM Fixed O&M 

Geothermal GT 

GHG Greenhouse Gas 

GSU Generator Step-up Transformer 

GT Geothermal 

H2S Hydrogen Sulfide 
xiii 

HHV High(er) Heating Value 

HP High Pressure 

HRSG Heat Recovery Steam Generator 

HY Hydroelectric 

Hz Hertz 

I&C Instrumentation and Controls 

IGCC Integrated Gasification Combined Cycle 

IGCC/CCS Integrated Gasification Combined Cycle Carbon Capture and Sequestration 

IP Intermediate Pressure 

kg Kilograms 

KJ Kilojoules 

kW Kilowatt 

kWh Kilowatt-hour 

kV Kilovolt 

kVA kilovolt-amperes 

lb Pound 

LHV Low(er) Heating Value 

CLP Low Pressure 

MEA Monoethanolamine 

MJ Mega joules 

MMBtu Million Btu 

MSW Municipal Solid Waste 

MW Megawatt 

MWe Megawatts Electric 

MWh Megawatt-hour 

MVA Mega-volt-amperes 

N2 Nitrogen 

NEMS National Energy Modeling System 

NGCC Natural Gas Combined Cycle 

NH3 Ammonia 

NOX Oxides of Nitrogen 

O2 Oxygen 

O&M Operating and Maintenance 

NOx Nitrogen Oxides 

ppmvd Parts per Million Volume Dry 

PS Pumped Storage 

psia Pounds per Square Inch Absolute 

PV Photovoltaic 

PWR Pressurized Water Reactor 

RCS Reactor Coolant System 

S Sulfur 

SCADA Supervisory Control and Data Acquisition 

scf Standard Cubic Feet 

scm Standard Cubic Meters 

SCR Selective Catalytic Reduction 

SNCR Selective Non-catalytic Reduction 
xiv 

SO Solar Thermal 

SO2 Sulfur Dioxide 

SRU Sulfur Recovery Unit 

ST Steam Turbine 

TGF Turbine Generating Facility 

U.S. United States 

V Volt 

VOM Variable Operating and Maintenance 

WF Offshore Wind 

WFGD Wet Flue Gas Desulfurization 

WN Onshore Wind 

WTG Wind Turbine Generator 

ZLD Zero Liquid Discharge 
1-1 

1. INTRODUCTION 

This report presents R. W. Beck, Inc.’s (“R. W. Beck”) performance and cost assessment of 

power generation technologies utilized by the Energy Information Administration (“EIA”) in the 

Electricity Market Module (“EMM”) of the National Energy Modeling System (“NEMS”). The 

assessment for each of the technologies considered includes the following: 

• Overnight construction costs, construction lead times, first year of commercial 

application, typical unit size, contingencies, fixed and variable operating costs, and 

efficiency (heat rate). The analysis was conducted to ensure that the overnight cost 

estimates developed for use in the EMM for electric generating technologies are 

consistent in scope, accounting for all costs in the planning and development of a power 

plant including the basic interconnection to the grid at the plant site, but excluding 

financing costs. 

• For emission control technologies, the removal rates for pollutants and other assumptions 

were examined. 

• Review of the regional multipliers that are used to represent local conditions, such as 

labor rates that are included in EMM. 

• Review of assumptions regarding how construction costs decline over time due to 

technological advancement and “learning by doing.” 

• Review of the appropriateness of technology-specific project and process contingency 

assumptions (capturing differences between engineering estimates and realized costs for 

new technologies). 

• Where possible, compare the values used by EIA with those for recently built facilities in 

the United States (“U.S.”) or abroad. Where such actual cost estimates do not exist, an 

assessment was made between values used by EIA and other analyst estimates, as well as 

vendor estimates. 

• The key factors expected to drive each technology’s costs. 

• Document the source and basis for final recommendations for altering or retaining the 

various assumptions. 

1.1 TECHNOLOGIES ASSESSED 

The following table lists all technologies to be assessed in this project. 
1-2 

TABLE 1-1 – LIST OF TECHNOLOGIES FOR REVIEW 

TECHNOLOGY DESCRIPTION COMMENTS 

Advanced Pulverized Coal 650 megawatt-electrical (“MWe”) 

and 1,300 MWe; supercritical; all 

advanced pollution control 

technologies 

Greenfield Installation 

Advanced Pulverized Coal with 

Carbon Capture and 

Sequestration (“CCS”) 

650 MWe and 1,300 MWe; 

supercritical; all advanced 

pollution control technologies, 

including CCS technologies 

Greenfield Installation 

Conventional Natural Gas 

Combined Cycle (“NGCC”) 

540 MWe; F-Class system 

Advanced NGCC 400 MWe; H-Class system 

Advanced NGCC with CCS 340 MWe; H-Class system 

Conventional Combustion 

Turbine (“CT”) 

85 MWe; E-Class turbine 

Advanced CT 210 MWe; F-Class turbine 

Integrated Gasification 

Combined Cycle (“IGCC”) 

600 MWe and 1,200 MWe; FClass-syngas system 

IGCC with CCS 520 MWe; F-Class-syngas system 

Advanced Nuclear 2,236 megawatt (“MW”); AP1000 

PWR Basis 

Brownfield Installation 

Biomass Combined Cycle 20 MWe Wood Fuel 

Biomass Bubbling Fluidized 

Bed (“BFB”) 

50 MWe Wood Fuel 

Fuel Cells 10 MWe 

Geothermal 50 MWe Dual Flash and Binary 

Municipal Solid Waste 

(“MSW”) 

50 MWe 

Hydroelectric 500 MWe 

Pumped Storage 250 MWe 

Wind Farm – Onshore 100 MWe 

Wind Farm – Offshore 400 MWe 

Solar Thermal – Central Station 100 MWe 

Photovoltaic – Central Station 7 MWe –AC and 150 MWe - AC 
2-1 

2. GENERAL BASIS FOR TECHNOLOGY EVALUATION BASIS 

This section specifies the general evaluation basis used for all technologies reviewed herein. 

2.1 R. W. BECK BACKGROUND 

R. W. Beck is an infrastructure consulting firm that has been providing technical and business 

consulting in the energy industry since 1942. Particularly, R. W. Beck has supported the 

purchase, sale, financing and Owner’s advisory consulting for tens-of-billions of dollars of 

power plants across the world in all commercial power generating technologies as well as many 

emerging technologies. This background has supported R. W. Beck’s acumen with respect to 

construction costs, operating costs, technology development and evolution, as well as trends in 

environmental regulation and compliance. 

2.2 BASE FUEL CHARACTERISTICS 

This section provides a general fuel basis for each of the fuel types utilized by the technologies 

considered in this report and listed in Table 1-1. Each of the technologies that combust a fuel 

has the ability to operate over a range of fuels; thus Table 2-1, Table 2-2 and Table 2-3 show a 

typical fuel specification for coal, natural gas, and wood-biomass, respectively. MSW has such a 

wide range of constituents; a typical analysis is not included here. 
2-2 

TABLE 2-1 – REFERENCE COAL SPECIFICATION 

Rank Bituminous 

Seam Illinois No. 6 (Herrin) 

Source Old Ben Mine

Proximate Analysis (weight %) (Note A) 

As Received Dry 

Moisture 11.12 0.00 

Ash 9.70 10.91 

Volatile Matter 34.99 39.37 

Fixed Carbon 44.19 49.72 

Total 100.00 100.00 

Sulfur 2.51 2.82 

HHV (1), KJ/kg (2) 27,113 30,506 

HHV, Btu/lb (3) 11,666 13,126 

LHV (4), KJ/kg 26,151 29,544 

LHV, Btu/lb 11,252 12,712 

Ultimate Analysis (weight %) 

As Received Dry 

Moisture 11.12 0.00 

Carbon 63.75 71.72 

Hydrogen 4.50 5.06 

Nitrogen 1.25 1.41 

Chlorine 0.29 0.33 

Sulfur 2.51 2.82 

Ash 9.70 10.91 

Oxygen 6.88 7.75 

Total 100.00 100.00 

(1) High(er) heating value (“HHV”). 

(2) Kilojoules per kilogram (“KJ/kg”). 

(3) British thermal units per pound (“Btu/lb”). 

(4) Low(er) heating value (“LHV”). 
2-3 

TABLE 2-2 – NATURAL GAS SPECIFICATION 

Component Volume Percentage 

Methane CH4 93.9 

Ethane C2H6 3.2 

Propane C3H8 0.7 

n-Butane C4H10 0.4 

Carbon Dioxide CO2 1.0 

Nitrogen N2 0.8 

 Total 100.0 

LHV HHV 

kJ/kg 

MJ/scm (1)

47.764 

35 

52,970 

39 

Btu/lb 

Btu/scf (2)

20,552 

939 

22,792 

1,040 

(1) Mega joules per standard cubic meter (“MJ/scm”). 

(2) Standard cubic feet (“scf”).

TABLE 2-3 – WOOD-BIOMASS SPECIFICATION (1)

Component Volume Percentage 

Moisture 17.27 

Carbon C 41.55 

Hydrogen H2 4.77 

Nitrogen N2 0.37 

Sulfur S <0.01 

Ash 2.35 

Oxygen (2) O2 33.75 

 Total 100.0 

 HHV 

Btu/lb 6,853 

(1) As received. 

(2) Oxygen by Difference.
2-4 

2.3 ENVIRONMENTAL COMPLIANCE BASIS 

The technology assessments considered the emissions rates after implementation of best 

available control technology (“BACT”), including sulfur dioxide (“SO2”), oxides of nitrogen 

(“NOX”), particulate matter, mercury, and carbon dioxide (“CO2”). With respect to CCS 

technologies, which are not currently considered “proven” or BACT by regulating bodies, 

R. W. Beck assumed capture and sequestration technologies that are currently in development 

for large-scale deployment, as discussed herein, and at industry expected rates of CO2 removal 

(i.e., 90 percent). 

2.4 LOCAL CAPACITY ADJUSTMENTS 

For power plants that use CT technologies, adjustments were made for regional ambient 

conditions. The adjustments took into consideration that CTs are machines that produce power 

proportional to mass flow. Since air density is inversely proportional to temperature, ambient 

temperature has a strong influence on the capacity of a given technology utilizing a CT 

(e.g., peaking power plant, combined-cycle power plant, and some gasification power plants). 

Additionally, relative humidity impacts the available capacity of a CT and consequently a 

CT-based power plant, primarily driven by the base assumption that the CT-based technologies 

incorporate inlet evaporative cooling. By circulating water across a porous media in the CT 

compressor inlet (across which the air flows), the inlet evaporative cooling reduces the difference 

between the ambient dry-bulb temperature (the temperature that is typically reported to the 

public as a measure of “local temperature”) and the wet-bulb temperature (a measure of relative 

humidity). Since inlet evaporative cooling is limited by the wet-bulb temperature, the 

effectiveness of these devices increases in areas of high dry-bulb temperature and low relative 

humidity. The final adjustment for ambient conditions made for the CT-based plants is ambient 

pressure, which on average (notwithstanding high or low pressure weather fronts that pass 

through a region) takes into consideration elevation (average number of feet above sea level). 

Air density is proportional to ambient pressure. 

Table 2-4 provides the aggregate capacity adjustment for each location, which provides regional 

differences related to capital costs against the ISO net capacity for the CT-based power plant 

technologies. 
2-5

TABLE 2-4 – CT CAPACITY ADJUSTMENTS 

ISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity Adjusted ISO Cap

Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjus

State City (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MAlaska Anchorage 85 7.58 92.58 210 18.73 229 540 32.27 572 400 35.67 436 340 30.32 370 600 35Alaska Fairbanks 85 9.97 94.97 210 24.63 235 540 42.43 582 400 46.91 447 340 39.87 380 600 47Alabama Huntsville 85 -2.12 82.88 210 -5.23 205 540 -9.01 531 400 -9.96 390 340 -8.46 332 600 -10Arizona Phoenix 85 -8.33 76.67 210 -20.59 189 540 -35.47 505 400 -39.22 361 340 -33.34 307 600 -39Arkansas Little Rock 85 -1.77 83.23 210 -4.37 206 540 -7.53 532 400 -8.32 392 340 -7.07 333 600 -8California Los Angeles 85 -1.77 83.23 210 -4.37 206 540 -7.52 532 400 -8.32 392 340 -7.07 333 600 -8California Redding 85 -2.52 82.48 210 -6.21 204 540 -10.71 529 400 -11.84 388 340 -10.06 330 600 -11California Bakersfield 85 -3.77 81.23 210 -9.30 201 540 -16.03 524 400 -17.72 382 340 -15.06 325 600 -17California Sacramento 85 -0.69 84.31 210 -1.71 208 540 -2.95 537 400 -3.26 397 340 -2.78 337 600 -3California San Francisco 85 0.83 85.83 210 2.06 212 540 3.54 544 400 3.92 404 340 3.33 343 600 3.Colorado Denver 85 -12.30 72.70 210 -30.40 180 540 -52.37 488 400 -57.90 342 340 -49.22 291 600 -58Connecticut Hartford 85 2.97 87.97 210 7.33 217 540 12.63 553 400 13.96 414 340 11.87 352 600 14Delaware Dover 85 1.22 86.22 210 3.00 213 540 5.17 545 400 5.72 406 340 4.86 345 600 5.District of Columbia Washington 85 2.01 87.01 210 4.96 215 540 8.55 549 400 9.46 409 340 8.04 348 600 9.Florida Tallahassee 85 -3.00 82.00 210 -7.42 203 540 -12.79 527 400 -14.14 386 340 -12.01 328 600 -14Florida Tampa 85 -4.78 80.22 210 -11.80 198 540 -20.34 520 400 -22.49 378 340 -19.11 321 600 -22Georgia Atlanta 85 -3.66 81.34 210 -9.05 201 540 -15.59 524 400 -17.24 383 340 -14.65 325 600 -17Hawaii Honolulu 85 -6.75 78.25 210 -16.66 193 540 -28.71 511 400 -31.74 368 340 -26.98 313 600 -31Idaho Boise 85 -5.52 79.48 210 -13.64 196 540 -23.50 517 400 -25.98 374 340 -22.08 318 600 -26Illinois Chicago 85 1.76 86.76 210 4.35 214 540 7.49 547 400 8.28 408 340 7.04 347 600 8.Indiana Indianapolis 85 0.20 85.20 210 0.50 211 540 0.87 541 400 0.96 401 340 0.81 341 600 0.Iowa Davenport 85 1.81 86.81 210 4.47 214 540 7.70 548 400 8.51 409 340 7.23 347 600 8.Iowa Waterloo 85 2.02 87.02 210 4.98 215 540 8.58 549 400 9.48 409 340 8.06 348 600 9.Kansas Wichita 85 -2.91 82.09 210 -7.19 203 540 -12.39 528 400 -13.70 386 340 -11.65 328 600 -13Kentucky Louisville 85 -0.20 84.80 210 -0.50 210 540 -0.86 539 400 -0.95 399 340 -0.81 339 600 -0Louisiana New Orleans 85 -3.26 81.74 210 -8.05 202 540 -13.87 526 400 -15.34 385 340 -13.03 327 600 -15Maine Portland 85 4.72 89.72 210 11.66 222 540 20.08 560 400 22.20 422 340 18.87 359 600 22Maryland Baltimore 85 1.21 86.21 210 2.98 213 540 5.13 545 400 5.67 406 340 4.82 345 600 5.Massachusetts Boston 85 2.92 87.92 210 7.20 217 540 12.41 552 400 13.72 414 340 11.66 352 600 13Michigan Detroit 85 2.03 87.03 210 5.00 215 540 8.62 549 400 9.53 410 340 8.10 348 600 9.Michigan Grand Rapids 85 1.97 86.97 210 4.87 215 540 8.39 548 400 9.27 409 340 7.88 348 600 9.Minnesota Saint Paul 85 2.00 87.00 210 4.95 215 540 8.52 549 400 9.42 409 340 8.01 348 600 9.Mississippi Jackson 85 -2.95 82.05 210 -7.30 203 540 -12.58 527 400 -13.90 386 340 -11.82 328 600 -13Missouri St. Louis 85 -0.40 84.60 210 -0.98 209 540 -1.68 538 400 -1.86 398 340 -1.58 338 600 -1Missouri Kansas City 85 -1.23 83.77 210 -3.04 207 540 -5.23 535 400 -5.78 394 340 -4.92 335 600 -5Montana Great Falls 85 -6.00 79.00 210 -14.81 195 540 -25.52 514 400 -28.21 372 340 -23.98 316 600 -28Nebraska Omaha 85 0.15 85.15 210 0.36 210 540 0.62 541 400 0.68 401 340 0.58 341 600 0.New Hampshire Concord 85 4.18 89.18 210 10.33 220 540 17.79 558 400 19.67 420 340 16.72 357 600 19New Jersey Newark 85 1.69 86.69 210 4.18 214 540 7.21 547 400 7.97 408 340 6.77 347 600 8.New Mexico Albuquerque 85 -13.95 71.05 210 -34.46 176 540 -59.37 481 400 -65.64 334 340 -55.79 284 600 -65New York New York 85 1.69 86.69 210 4.18 214 540 7.21 547 400 7.97 408 340 6.77 347 600 8.New York Syracuse 85 3.06 88.06 210 7.56 218 540 13.03 553 400 14.41 414 340 12.25 352 600 14Nevada Las Vegas 85 -9.24 75.76 210 -22.82 187 540 -39.31 501 400 -43.46 357 340 -36.95 303 600 -43North Carolina Charlotte 85 -2.41 82.59 210 -5.95 204 540 -10.26 530 400 -11.34 389 340 -9.64 330 600 -11North Dakota Bismarck 85 1.02 86.02 210 2.53 213 540 4.36 544 400 4.82 405 340 4.09 344 600 4.Ohio Cincinnati 85 1.45 86.45 210 3.58 214 540 6.16 546 400 6.81 407 340 5.79 346 600 6.Oregon Portland 85 2.02 87.02 210 5.00 215 540 8.61 549 400 9.51 410 340 8.09 348 600 9.Pennsylvania Philadelphia 85 1.88 86.88 210 4.65 215 540 8.00 548 400 8.85 409 340 7.52 348 600 8.Pennsylvania Wilkes-Barre 85 1.07 86.07 210 2.64 213 540 4.55 545 400 5.03 405 340 4.27 344 600 5.Rhode Island Providence 85 3.16 88.16 210 7.82 218 540 13.47 553 400 14.89 415 340 12.66 353 600 14South Carolina Spartanburg 85 -2.32 82.68 210 -5.73 204 540 -9.88 530 400 -10.92 389 340 -9.28 331 600 -10South Dakota Rapid City 85 -5.15 79.85 210 -12.72 197 540 -21.91 518 400 -24.22 376 340 -20.59 319 600 -24Tennessee Knoxville 85 -2.15 82.85 210 -5.32 205 540 -9.17 531 400 -10.14 390 340 -8.62 331 600 -10Texas Houston 85 -3.46 81.54 210 -8.54 201 540 -14.71 525 400 -16.27 384 340 -13.83 326 600 -16Utah Salt Lake City 85 -9.73 75.27 210 -24.03 186 540 -41.40 499 400 -45.77 354 340 -38.90 301 600 -46Vermont Burlington 85 4.40 89.40 210 10.86 221 540 18.71 559 400 20.68 421 340 17.58 358 600 20Virginia Alexandria 85 0.27 85.27 210 0.66 211 540 1.14 541 400 1.26 401 340 1.07 341 600 1.Virginia Lynchburg 85 -1.05 83.95 210 -2.59 207 540 -4.47 536 400 -4.94 395 340 -4.20 336 600 -4Washington Seattle 85 1.10 86.10 210 2.72 213 540 4.68 545 400 5.18 405 340 4.40 344 600 5.Washington Spokane 85 -2.90 82.10 210 -7.17 203 540 -12.35 528 400 -13.66 386 340 -11.61 328 600 -13West Virginia Charleston 85 -1.21 83.79 210 -3.00 207 540 -5.16 535 400 -5.71 394 340 -4.85 335 600 -5Wisconsin Green Bay 85 3.51 88.51 210 8.67 219 540 14.94 555 400 16.52 417 340 14.04 354 600 16Wyoming Cheyenne 85 -13.05 71.95 210 -32.24 178 540 -55.55 484 400 -61.42 339 340 -52.21 288 600 -6Puerto Rico Cayey 85 -6.00 79.00 210 -14.83 195 540 -25.56 514 400 -28.25 372 340 -24.02 316 600 -28

Conventional CT Advanced CT Conventional NGCC Advanced - NGCC Advanced - NGCC With CCS IGC
2-6

2.5 TECHNOLOGY SPECIFICATIONS 

This section provides the base performance specifications for each technology. Table 2-5 

provides the current technology specifications. 

2.6 COST ESTIMATION METHODOLOGY 

2.6.1 Capital Cost 

A summary base capital cost estimate (“Cost Estimate”) was developed for each power plant 

technology, based on a generic facility of a certain size (capacity) and configuration, and 

assuming a non-specific U.S. location with no unusual location impacts (e.g., urban construction 

constraints) or infrastructure needs (e.g., a project-dedicated interconnection upgrade cost). 

Each Cost Estimate was developed assuming costs in fourth quarter 2010 dollars on an 

“overnight” capital cost basis. In each Cost Estimate, the total project engineering, procurement 

and construction (“EPC”) cost was organized into the following categories: 

• Civil/structural material and installation, 

• Mechanical equipment supply and installation, 

• Electrical instrumentation and controls (“I&C”) supply and installation, 

• Project indirect costs, fees and contingency, and 

• Owner’s costs (excluding project financing costs). 

It should be noted that an EPC (turnkey) or equipment supply/balance of plant, as applicable to a 

given technology, contracting approach was assumed for each of the technologies, which 

included a risk sharing between the project owner and project construction contractor that, based 

on our experience, would be required in typical financing markets. This approach does not 

always result in the lowest cost of construction; however, on average, we believe this approach 

to result in an achievable cost of construction, given the other considerations discussed herein. 

In addition to the base Cost Estimate provided for the given technology, specific regional cost 

differences were determined. Regional costs for 64 unique locations in the U.S. were analyzed. 

Eleven subcategories were used (depending on the specific technology under review) to estimate 

the differences in various regions of the U.S. for the each power plant technology. The regional 

analyses include but are not limited to assessing the cost differences for outdoor installation 

considerations, air-cooled condensers versus cooling tower issues, seismic design differences, 

zero-water discharge issues, local enhancements, remote location issues, urban high-density 

population issues, labor wage and productivity differences, location adjustments, owner cost 

differences, and the increase in overheads associated with these 10 locations. More detail with 

respect to regional differences for each given technology is provided in the following sections. 

2.6.1.1 Costing Scope 

The civil and structural costs include allowance for site preparation, such as clearing, roads, 

drainage, underground utilities installation, concrete for foundations, piling material, structural 

steel supply and installation, and buildings. 

The mechanical equipment supply and installation includes major equipment , including but not 

limited to, boilers, scrubbers, cooling tower, steam turbine (“ST”) generators, PV modules, CTs, 
2-7

as well as auxiliary equipment such as material handling, fly and bottom ash handling, pumps, 

condensers, and balance of plant (“BOP”) equipment such as fire protection, as applicable to a 

given technology. 

The electrical and I&C supply and installation includes electrical transformers, switchgear, 

motor control centers, switchyards, distributed control systems (“DCS”) and instrumentation, 

and electrical commodities, such as wire, cable tray, and lighting. 

While commodities, project equipment, and site assumptions can vary widely from project-toproject for a given technology, the Cost Estimates are based upon a cross section of projects. 

The project indirect costs include engineering, distributable labor and materials, craft labor 

overtime and incentives, scaffolding costs, construction management, and start-up and 

commissioning. The fees and contingency include contractor overhead costs, fees and profit, and 

construction contingency. Contingency in this category is considered “contractor” contingency, 

which would be held by a given contractor to mitigate its risk in the construction of a project. 

The owner’s costs include development costs, preliminary feasibility and engineering studies, 

environmental studies and permitting, legal fees, project management (including third-party 

management), insurance costs, infrastructure interconnection costs (e.g., gas, electricity), 

Owner’s Contingency, and property taxes during construction. The electrical interconnection 

cost includes an allowance for the plant switchyard and a subsequent interconnection to an 

“adjacent” (e.g. within a mile) of the plant, but does not include significant transmission system 

upgrades. 

2.6.2 Operation and Maintenance (O&M) Expenses 

O&M expenses consist of non-fuel O&M costs, owner’s expenses, and fuel-related expenses. In 

evaluating the non-fuel O&M expenses for use in the EMM of NEMS, we focused on non-fuel 

O&M costs associated with the direct operation of the given power plant technology, referred to 

here as the “Production Related Non-Fuel O&M Expenses,” to allow for comparison of O&M 

costs on the same basis. 

Production Related Non-Fuel O&M Expenses include the following categories: 

• Fixed O&M (“FOM”) 

• Variable O&M (“VOM”) 

• Major Maintenance 

Presented below is a brief summary below of the expense categories included within the 

categories of Fixed O&M, Variable O&M, and Major Maintenance. Further, Sections 3 through 

22 provide more specific information related to Production-Related Non-Fuel O&M Expenses 

for each technology. 

Owner’s expenses, which are not addressed in this report, include expenses paid by plant owners 

that are plant specific and can vary significantly between two virtually identical plants in the 

same geographic region. For example, the owner’s expenses include, but are not limited to, 

property taxes, asset management fees, energy marketing fees, and insurance. 
2-8

2.6.2.1 Fixed O&M (FOM) 

FOM expenses are those expenses incurred at a power plant that do not vary significantly with 

generation and include the following categories: 

• Staffing and monthly fees under pertinent operating agreements 

• Typical bonuses paid to the given plant operator 

• Plant support equipment which consists of equipment rentals and temporary labor 

• Plant-related general and administrative expenses (postage, telephone, etc.) 

• Routine preventive and predictive maintenance performed during operations 

• Maintenance of structures and grounds 

• Other fees required for a project to participate in the relevant National Electric Reliability 

Council region and be in good standing with the regulatory bodies. 

Routine preventive and predictive maintenance expenses do not require an extended plant 

shutdown and include the following categories: 

• Maintenance of equipment such as water circuits, feed pumps, main steam piping, and 

demineralizer systems 

• Maintenance of electric plant equipment, which includes service water, DCS, condensate 

system, air filters, and plant electrical 

• Maintenance of miscellaneous plant equipment such as communication equipment, 

instrument and service air, and water supply system 

• Plant support equipment which consists of tools, shop supplies and equipment rental, and 

safety supplies. 

2.6.2.2 Variable O&M (VOM) 

VOM expenses are production-related costs which vary with electrical generation and include 

the following categories, as applicable to the given power plant technology: 

• Raw water 

• Waste and wastewater disposal expenses 

• Purchase power (which is incurred inversely to operating hours), demand charges and 

related utilities 

• Chemicals, catalysts and gases 

• Ammonia (“NH3”) for selective catalytic reduction (“SCR”), as applicable 

• Lubricants 

• Consumable materials and supplies. 

2.6.2.3 Major Maintenance 

Major maintenance expenses generally require an extended outage, are typically undertaken no 

more than once per year; and are assumed to vary with electrical generation or the number of 
2-9

plant starts based on the given technology and specific original equipment manufacturer 

recommendations and requirements. These major maintenance expenses include the following 

expense categories: 

• Scheduled major overhaul expenses for maintaining the prime mover equipment at a 

power plant 

• Major maintenance labor 

• Major maintenance spares parts costs 

• BOP major maintenance, which is major maintenance on the equipment at the given plant 

that cannot be accomplished as part of routine maintenance or while the unit is in 

commercial operation. 
2-10

TABLE 2-5 – TECHNOLOGY PERFORMANCE SPECIFICATIONS 

Technology Fuel 

Nominal 

Capacity 

(kW) (1)

Nominal 

Heat Rate 

(Btu/kWh) (2)

Capital 

Cost 

($/kW) (3)

Fixed O&M 

($/kW-yr) (4)

Variable 

O&M 

($/MWh) (5)

SO2 (lb/ 

MMBtu (

Advanced Pulverized Coal Coal 650,000 8,800 3,167 35.97 4.25 0.1 (6) Advanced Pulverized Coal Coal 1,300,000 8,800 2,844 29.67 4.25 0.1 (6) Advanced Pulverized Coal with CCS Coal 650,000 12,000 5,099 76.62 9.05 0.02 (8) Advanced Pulverized Coal with CCS Coal 1,300,000 12,000 4,579 63.21 9.05 0.02 (8) NGCC Gas 540,000 7,050 978 14.39 3.43 0.001 AG-NGCC Gas 400,000 6,430 1,003 14.62 3.11 0.001 Advanced NGCC with CCS Gas 340,000 7,525 2,060 30.25 6.45 0.001 Conventional CT Gas 85,000 10,850 974 6.98 14.70 0.001 Advanced CT Gas 210,000 9,750 665 6.70 9.87 0.001 IGCC Coal 600,000 8,700 3,565 59.23 6.87 0.025 (10) IGCC Coal 1,200,000 8,700 3,221 48.90 6.87 0.025 (10) IGCC with CCS Coal 520,000 10,700 5,348 69.30 8.04 0.015 (11) Advanced Nuclear Uranium 2,236,000 N/A 5,339 88.75 2.04 0 Biomass Combined Cycle Biomass 20,000 12,350 7,894 338.79 16.64 0 Biomass BFB Biomass 50,000 13,500 3,860 100.50 5.00 0 Fuel Cells Gas 10,000 9,500 6,835 350 0 0.00013 Geothermal – Dual Flash Geothermal 50,000 N/A 5,578 84.27 9.64 0.2 (16) Geothermal – Binary Geothermal 50,000 N/A 4,141 84.27 9.64 0.2 (16) MSW MSW 50,000 18,000 8,232 373.76 8.33 0.07 (18) Hydroelectric Hydro 500,000 N/A 3,076 13.44 0 0 Pumped Storage Hydro 250,000 N/A 5,595 13.03 0 0 Onshore Wind Wind 100,000 N/A 2,438 28.07 0 0 Offshore Wind Wind 400,000 N/A 5,975 53.33 0 0 Solar Thermal Solar 100,000 N/A 4,692 64.00 0 0 Photovoltaic Solar 7,000 N/A 6,050 26.04 0 0 Photovoltaic Solar 150,000 N/A 4,755 16.70 0 0 Footnotes are listed on the next page. 
2-11

(1) Capacity is net of auxiliary loads. 

(2) Heat Rate is on a HHV basis for British thermal units per kilowatt-hour (“Btu/kWh”). 

(3) Capital Cost excludes financing-related costs (e.g., fees, interest during construction). 

(4) FOM expenses exclude owner's costs (e.g., insurance, property taxes, and asset management fees). 

(5) VOM expenses include major maintenance. 

(6) Million Btu (“MMBtu”). 

(7) Based on high sulfur bituminous fuel. Emission rate could be lower for sub-bituminous fuel. 

(8) From greenhouse gas (“GHG”) Reporting Rule for Bituminous Coal. 

(9) SO2 emission rates are lower than in the non-capture case to avoid reagent contamination. 

(10) Assuming 90 percent capture. 

(11) Assuming 3 percent sulfur coal at 12,000 British thermal units per pound (“Btu/lb”) and a 99.5 percent sulfur removal rate. 

(12) Assuming 3 percent sulfur coal at 12,000 Btu/lb and a 99.7 percent sulfur removal rate. 

(13) Assuming 9 parts per million volume dry (“ppmvd”) corrected to 15 percent O2; simple-cycle E-Class or F-Class engine. 

(14) Assuming 2 ppmvd corrected to 15 percent O2 for F-Class engine. Assumes development of SCR for IGCC with CCS. 

(15) From GHG Reporting Rule for Pipeline Natural Gas. 

(16) Assuming 90 percent capture. 

(17) Reported as pounds per MWh and as H2S – actual will vary with resource. 

(18) Reported as pounds per MWh – actual will vary with resource. 

(19) Based on 30 ppmvd at 7 percent O2 – 5,000 Btu/lb HHV of MSW. 

(20) Based on 150 ppmvd at 7 percent O2 - 5,000 Btu/lb HHV of MSW. 
3-1

3. ADVANCED PULVERIZED COAL (APC) 

3.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The following describes the Advanced Pulverized Coal Facility, which is a nominal 650 MW 

coal-fired supercritical steam-electric generating unit built in a Greenfield location. An analysis 

is also provided for a nominally 1,300 MW coal-fired supercritical steam-electric generating unit 

built in a Greenfield location, which is essentially a dual-unit configuration, based on doubling 

the single-unit description provided below; however, a detailed technical description (due to the 

similarities/duplication with the single unit) is not provided herein. This unit employs a 

supercritical Rankine power cycle in which coal is burned to produce steam in a boiler, which is 

expanded through a ST to produce electric power. The steam is then condensed to water and 

pumped back to the boiler to be converted to steam once again to complete the cycle. 

The unit will operate at steam conditions of up to 3,700 pounds per square inch-absolute (“psia”) 

and 1,050 degrees Fahrenheit (“oF”) at the ST inlet. The superheated steam produced in the 

boiler is supplied to the ST, which drives an electric generator. After leaving the high-pressure 

(“HP”) ST, the steam is reheated and fed to the intermediate-pressure (“IP”) ST. In the 

low-pressure (“LP”) ST, the steam admitted directly from the IP ST expands to condenser 

pressure and is condensed in the condenser. Cooling tower water is used for the condensing 

process. Condensate collected in the condenser hotwell is discharged by the main condensate 

pumps and returned to the deaerator/feedwater storage tank via the LP feedwater heaters. The 

feedwater pumps discharge feedwater from the feedwater storage tank to the boiler via the HP 

feedwater heaters. In the boiler, the supercritical fluid is heated for return to the ST. 

The combustion air and flue gas systems are designed for balanced draft and starts with the 

ambient air drawn in by the forced draft fans. This air is heated by steam preheaters and the 

regenerative air heaters. Some of the air is passed through the primary air fans for use in drying 

and conveying the pulverized coal to the boiler. The air and coal combust in the boiler furnace 

and the flue gas passes through the furnace and back passes of the boiler, giving up heat to the 

supercritical fluid in the boiler tubes. The flue gas exiting the boiler economizer enters the SCR 

equipment for NOX reduction and into the regenerative air heaters where it transfers heat to the 

incoming air. From the regenerative air heaters, the flue gas is treated with an injection of 

hydrated lime, enters a pulse-jet fabric filter (baghouse) for the collection of particulate material, 

and then flows to the induced draft fans. From the fans, gas enters the Wet Flue Gas 

Desulfurization (“WFGD”) absorber. From the absorber, the flue gas discharges into the stack. 

Figure 3-1 presents the Advanced Pulverized Coal process flow diagram. 
3-2

FIGURE 3-1 – ADVANCED PULVERIZED COAL DESIGN CONFIGURATION 

3.2 ELECTRICAL AND CONTROL SYSTEMS 

The Advanced Pulverized Coal Facility has one ST electric generator. The generator is a 

60 Hertz (“Hz”) machine rated at approximately 800 mega-volt-amperes (“MVA”) with an 

output voltage of 24 kilovolts (“kV”). The ST electric generator is directly connected to 

generator step-up transformer (“GSU”), which in turn is connected between two circuit breakers 

in the high-voltage bus in the Advanced Pulverized Coal Facility switchyard through a 

disconnect switch. The GSU increases the voltage from the electric generator from 24 kV to 

interconnected transmission system high voltage. 

The Advanced Pulverized Coal Facility is controlled using a DCS. The DCS provides 

centralized control of the plant by integrating the control systems provided with the boiler, ST 

and associated electric generator and the control of BOP systems and equipment. 

3.3 OFF-SITE REQUIREMENTS 

Coal is delivered to the facility via rail, truck or barge. Water for all processes at the Advanced 

Pulverized Coal Facility can be obtained from one of a variety of sources; however, water is 

typically sourced from an adjacent river, when possible. The Advanced Pulverized Coal Facility 

uses a water treatment system and a high-efficiency reverse osmosis system to reduce the 

dissolved solids from the cooling water and to provide distilled water for boiler makeup. 

Wastewater is sent to an adjacent river or other approved alternative. Further, the electrical 

interconnection from the Advanced Pulverized Coal on-site switchyard is effectuated by a 

connection to an adjacent utility substation, assumed to be no more than 1 mile from the 

Advanced Pulverized Coal Facility. 
3-3

3.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the Advanced Pulverized Coal Facility (“APC”) with a nominal 

capacity of 650 MW is $3,167/kilowatt (“kW”) and with a nominal capacity of 1,300 MW is 

$2,844/kW. Table 3-1 and Table 3-2 summarize the Cost Estimate categories for the APC 

Facility. 

TABLE 3-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR APC 

Technology: APC 

Nominal Capacity (ISO): 650,000 kW 

Nominal Heat Rate (ISO): 8,800 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 224,000 

Mechanical Equipment Supply and 

Installation 838,500 

Electrical / I&C Supply and Installation 123,000 

Project Indirects (1) 350,000 

EPC Cost before Contingency and Fee 1,535,500 

Fee and Contingency 180,000 

Total Project EPC 1,715,500 

Owner's Costs (excluding project finance) 343,100 

Total Project Cost (excluding finance) 2,058,600 

Total Project EPC $ / kW 2,639 

Owner Costs 20% (excluding project finance) $ / kW 528 

Total Project Cost (excluding project finance) $ / kW 3,167 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 
3-4

TABLE 3-2 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR APC 

Technology: APC 

Nominal Capacity (ISO): 1,300,000 kW 

Nominal Heat Rate (ISO): 8,800 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 397,250 

Mechanical Equipment Supply and 

Installation 1,596,100 

Electrical / I&C Supply and Installation 235,000 

Project Indirects (1) 584,750 

EPC Cost before Contingency and Fee 2,813,100 

Fee and Contingency 320,000 

Total Project EPC 3,133,100 

Owner Costs (excluding project finance) 563,958 

Total Project Cost (excluding finance) 3,697,058 

Total Project EPC $ / kW 2,410 

Owner Costs 18% (excluding project finance) $ / kW 434 

Total Project Cost (excluding project finance) $ / kW 2,844 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: outdoor installation considerations, seismic design differences, 

remote location issues, labor wage and productivity differences, location adjustments, owner cost 

differences, and the increase in overheads associated with these six adjustment criteria. 

Outdoor installation locations are considered in geographic areas where enclosed structures for 

the boilers would not be required due to the low probability of freezing. The locations that were 

included in outdoor installation are Alabama, Arizona, Arkansas, Florida, Georgia, Hawaii, 

Louisiana, Mississippi, New Mexico, South Carolina, and Puerto Rico. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 
3-5

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the APC Facility include 

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and 

Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 1.5.1, taking into 

consideration the amount of labor we estimated for the APC Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio; and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 3-3 and Table 3-4 show the APC capital cost variations for alternative U.S. plant locations, 

including the difference between the given location and the average location specified for the 

Cost Estimate. 

TABLE 3-3 – LOCATION-BASED COSTS FOR APC (650,000 KW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,200 33.1% 1,058 4,258 

Alaska Fairbanks 3,200 32.0% 1,026 4,226 

Alabama Huntsville 3,200 -7.5% (239) 2,961 

Arizona Phoenix 3,200 -5.2% (166) 3,034 

Arkansas Little Rock 3,200 -5.4% (174) 3,026 

California Los Angeles 3,200 20.3% 649 3,849 

California Redding 3,200 9.8% 314 3,514 

California Bakersfield 3,200 9.4% 300 3,500 

California Sacramento 3,200 14.4% 462 3,662 

California San Francisco 3,200 42.4% 1,356 4,556 

Colorado Denver 3,200 -6.1% (194) 3,006 

Connecticut Hartford 3,200 26.6% 851 4,051 

Delaware Dover 3,200 23.0% 736 3,936 

District of Columbia Washington 3,200 39.6% 1,267 4,467 

Florida Tallahassee 3,200 -10.9% (349) 2,851 

Florida Tampa 3,200 -4.9% (156) 3,044 

Georgia Atlanta 3,200 -8.1% (260) 2,940 

Hawaii Honolulu 0 0 0 0 

Idaho Boise 3,200 -3.7% (118) 3,082 

Illinois Chicago 3,200 19.8% 635 3,835 

Indiana Indianapolis 3,200 3.2% 102 3,302 
3-6

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Iowa Davenport 3,200 -1.6% (50) 3,150 

Iowa Waterloo 3,200 -9.0% (288) 2,912 

Kansas Wichita 3,200 -6.7% (215) 2,985 

Kentucky Louisville 3,200 -5.6% (178) 3,022 

Louisiana New Orleans 3,200 -11.2% (359) 2,841 

Maine Portland 3,200 -0.6% (21) 3,179 

Maryland Baltimore 3,200 4.6% 148 3,348 

Massachusetts Boston 3,200 35.3% 1,128 4,328 

Michigan Detroit 3,200 3.8% 123 3,323 

Michigan Grand Rapids 3,200 -7.9% (251) 2,949 

Minnesota St. Paul 3,200 3.9% 125 3,325 

Mississippi Jackson 3,200 -7.4% (238) 2,962 

Missouri St. Louis 3,200 7.2% 231 3,431 

Missouri Kansas City 3,200 3.4% 109 3,309 

Montana Great Falls 3,200 -4.3% (137) 3,063 

Nebraska Omaha 3,200 -3.5% (113) 3,087 

New Hampshire Concord 3,200 -1.6% (52) 3,148 

New Jersey Newark 3,200 15.5% 495 3,695 

New Mexico Albuquerque 3,200 -3.9% (125) 3,075 

New York New York 3,200 32.6% 1,044 4,244 

New York Syracuse 3,200 10.7% 342 3,542 

Nevada Las Vegas 3,200 9.2% 295 3,495 

North Carolina Charlotte 3,200 -9.6% (308) 2,892 

North Dakota Bismarck 3,200 -8.0% (255) 2,945 

Ohio Cincinnati 3,200 0.3% 11 3,211 

Oregon Portland 3,200 9.5% 305 3,505 

Pennsylvania Philadelphia 3,200 12.1% 387 3,587 

Pennsylvania Wilkes-Barre 3,200 -3.5% (112) 3,088 

Rhode Island Providence 3,200 4.1% 132 3,332 

South Carolina Spartanburg 3,200 -11.8% (377) 2,823 

South Dakota Rapid City 3,200 -10.7% (342) 2,858 

Tennessee Knoxville 3,200 -8.9% (286) 2,914 

Texas Houston 3,200 -9.5% (304) 2,896 

Utah Salt Lake City 3,200 -3.1% (98) 3,102 

Vermont Burlington 3,200 -5.3% (169) 3,031 

Virginia Alexandria 3,200 9.7% 310 3,510 

Virginia Lynchburg 3,200 -2.0% (62) 3,138 

Washington Seattle 3,200 12.8% 409 3,609 

Washington Spokane 3,200 -2.3% (74) 3,126 

West Virginia Charleston 3,200 -1.8% (58) 3,142 

Wisconsin Green Bay 3,200 0.5% 16 3,216 

Wyoming Cheyenne 3,200 3.9% 125 3,325 

Puerto Rico Cayey 0 0 0 0 
3-7

TABLE 3-4 – LOCATION-BASED COSTS FOR APC (1,300,000 KW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 2,850 36.5% 1,040 3,890 

Alaska Fairbanks 2,850 35.3% 1,006 3,856 

Alabama Huntsville 2,850 -8.2% (233) 2,617 

Arizona Phoenix 2,850 -5.7% (161) 2,689 

Arkansas Little Rock 2,850 -5.9% (169) 2,681 

California Los Angeles 2,850 22.4% 638 3,488 

California Redding 2,850 10.7% 306 3,156 

California Bakersfield 2,850 10.3% 293 3,143 

California Sacramento 2,850 15.7% 447 3,297 

California San Francisco 2,850 46.7% 1,330 4,180 

Colorado Denver 2,850 -6.6% (188) 2,662 

Connecticut Hartford 2,850 29.4% 838 3,688 

Delaware Dover 2,850 25.5% 728 3,578 

District of Columbia Washington 2,850 44.4% 1,265 4,115 

Florida Tallahassee 2,850 -11.9% (339) 2,511 

Florida Tampa 2,850 -5.4% (154) 2,696 

Georgia Atlanta 2,850 -8.9% (253) 2,597 

Hawaii Honolulu 0 0 0 0 

Idaho Boise 2,850 -4.0% (115) 2,735 

Illinois Chicago 2,850 21.3% 606 3,456 

Indiana Indianapolis 2,850 3.5% 99 2,949 

Iowa Davenport 2,850 -1.8% (53) 2,797 

Iowa Waterloo 2,850 -9.8% (280) 2,570 

Kansas Wichita 2,850 -7.3% (209) 2,641 

Kentucky Louisville 2,850 -6.1% (173) 2,677 

Louisiana New Orleans 2,850 -12.2% (348) 2,502 

Maine Portland 2,850 -0.6% (16) 2,834 

Maryland Baltimore 2,850 5.3% 150 3,000 

Massachusetts Boston 2,850 38.7% 1,103 3,953 

Michigan Detroit 2,850 4.0% 114 2,964 

Michigan Grand Rapids 2,850 -8.6% (244) 2,606 

Minnesota St. Paul 2,850 4.1% 116 2,966 

Mississippi Jackson 2,850 -8.1% (231) 2,619 

Missouri St. Louis 2,850 7.7% 221 3,071 

Missouri Kansas City 2,850 3.5% 101 2,951 

Montana Great Falls 2,850 -4.7% (133) 2,717 

Nebraska Omaha 2,850 -3.9% (111) 2,739 

New Hampshire Concord 2,850 -1.8% (52) 2,798 

New Jersey Newark 2,850 16.4% 467 3,317 

New Mexico Albuquerque 2,850 -4.3% (122) 2,728 

New York New York 2,850 34.8% 992 3,842 

New York Syracuse 2,850 12.0% 341 3,191 

Nevada Las Vegas 2,850 9.9% 282 3,132 

North Carolina Charlotte 2,850 -10.4% (296) 2,554 

North Dakota Bismarck 2,850 -8.7% (248) 2,602 

Ohio Cincinnati 2,850 0.5% 13 2,863 

Oregon Portland 2,850 10.4% 297 3,147 

Pennsylvania Philadelphia 2,850 12.9% 366 3,216 

Pennsylvania Wilkes-Barre 2,850 -3.8% (109) 2,741 
3-8

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Rhode Island Providence 2,850 4.3% 123 2,973 

South Carolina Spartanburg 2,850 -12.7% (363) 2,487 

South Dakota Rapid City 2,850 -11.6% (331) 2,519 

Tennessee Knoxville 2,850 -9.7% (276) 2,574 

Texas Houston 2,850 -10.3% (295) 2,555 

Utah Salt Lake City 2,850 -3.3% (93) 2,757 

Vermont Burlington 2,850 -5.8% (164) 2,686 

Virginia Alexandria 2,850 10.9% 310 3,160 

Virginia Lynchburg 2,850 -2.0% (57) 2,793 

Washington Seattle 2,850 13.9% 397 3,247 

Washington Spokane 2,850 -2.6% (73) 2,777 

West Virginia Charleston 2,850 -2.1% (59) 2,791 

Wisconsin Green Bay 2,850 0.6% 16 2,866 

Wyoming Cheyenne 2,850 4.6% 131 2,981 

Puerto Rico Cayey 0 0 0 0 

3.5 O&M ESTIMATE 

In addition to the general O&M items discussed in Section 2.5.2., the APC Facility includes the 

major maintenance for boiler, ST, associated generator, BOP, and emissions reduction catalysts. 

These major maintenance expenses are included with the VOM expense for this technology and 

are given on an average basis across the megawatt-hours (“MWh”) incurred. Typically, 

significant overhauls on an APC Facility occur no less frequently than six or seven years. 

Table 3-5 presents the FOM and VOM expenses for the APC Facility. Table 3-5 and Table 3-6 

present the O&M expenses for the APC Facility. 

TABLE 3-5 – O&M EXPENSES FOR APC (650,000 KW) 

Technology: APC 

Fixed O&M Expense $35.97/kW-year 

Variable O&M Expense $4.25/MWh 

TABLE 3-6 – O&M EXPENSES FOR APC (1,300,000 KW) 

Technology: APC 

Fixed O&M Expense $29.67/kW-year 

Variable O&M Expense $4.25/MWh 

3.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

As mentioned in Section 3.1, the APC Facility is assumed to include low NOX combustion 

burners in the boiler, SCR, and a flue gas desulfurization (“FGD”) to further control the 

emissions of NOX and SO2, respectively. Table 3-7 presents the environmental emissions for the 

APC Facility. 
3-9

TABLE 3-7 – ENVIRONMENTAL EMISSIONS FOR APC 

Technology: APC 

NOX 0.06 lb/MMBtu 

SO2 0.1 lb/MMBtu 

CO2 206 lb/MMBtu 
4-1

4. ADVANCED PULVERIZED COAL WITH CCS (APC/CCS) 

4.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The plant configuration for the APC with CCS Facility (“APC/CCS”) is the same as the APC 

case with two exceptions: (1) an amine scrubbing system, utilizing monoethanolamine (“MEA”) 

as a solvent, to capture CO2 from the flue gas, and (2) the scaling of the boiler to a larger size, as 

described below. The captured CO2 is compressed to approximately 2,000 psia for injection into 

a pipeline at the plant fence line as a supercritical fluid. The net output of the APC/CCS Facility 

case is 650 MW (and 1,300 MW for the two unit configuration), and since the CCS system 

requires about one-third of the given facility’s gross capacity in auxiliary load, the APC/CCS 

Facility assumes that the boiler is increased by approximately one-third (i.e., it is approximately 

133 percent the size of the boiler in the APC Facility), which provides the necessary steam to 

facilitate the capture process and to run a steam-driven compressor for compressing the CO2 for 

sequestration. Figure 4-1 presents a diagram of the APC and Figure 4-2 presents a diagram of 

the APC/CCS Facility. 

FIGURE 4-1 – APC FACILITY DIAGRAM
4-2

FIGURE 4-2 – APC/CCS FACILITY DIAGRAM

4.2 ELECTRICAL AND CONTROL SYSTEMS 

The electrical and control systems for the APC/CCS Facility are materially similar to the APC 

Facility. 

4.3 OFF-SITE REQUIREMENTS 

The off-site requirements for the APC/CCS Facility are materially similar to the APC Facility, 

except that the CO2 needs sequestering in one of the following geologic formations: 

(1) exhausted gas storage location, (2) unminable coal seam, (3) enhanced oil recovery, or 

(4) saline aquifer. To the extent that a sequestration site is not near the given facility being 

analyzed, transportation for a viable sequestration site has the potential to materially affect the 

capital cost estimates discussed below. 

4.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the APC/CCS Facility with a nominal capacity of 650 MW is 

$5,099/kW and with a nominal capacity of 1,300,000 MW is $4,579/kW. The capital cost 

estimate was based on the advanced pulverized APC Facility (without CCS) and the base Cost 

Estimate was increased to include the expected costs of CCS. Since there are currently no fullscale pulverized coal facilities operating with CCS in the world, our estimate is based on industry 

research. Our team tested the veracity of this research against assumptions for implementing the 

additional equipment necessary to effectuate CCS on an advanced coal facility. Table 4-1 and 

Table 4-2 summarize the Cost Estimate categories for the APC/CCS Facility. 
4-3

TABLE 4-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR APC/CCS 

Technology: APC/CCS 

Nominal Capacity (ISO): 650,000 kW 

Nominal Heat Rate (ISO): 12,000 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Total Project EPC 2,761,958 

Owner Costs (excluding project finance) 552,391 

Total Project Cost (excluding finance) 3,314,350 

Total Project EPC / kW 4,249 

Owner Costs 20% (excluding project finance) / kW 850 

Total Project Cost (excluding project finance) / kW 5,099 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

TABLE 4-2 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR APC/CCS 

Technology: APC/CCS 

Nominal Capacity (ISO): 1,300,000 kW 

Nominal Heat Rate (ISO): 12,000 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Total Project EPC 5,045,763 

Owner Costs (excluding project finance) 908,237 

Total Project Cost (excluding finance) 5,954,000 

Total Project EPC / kW 3,881 

Owner Costs 18% (excluding project finance) / kW 699 

Total Project Cost (excluding project finance) / kW 4,580 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: outdoor installation considerations, seismic design differences, 

remote location issues, labor wage and productivity differences, location adjustments, owner cost 

differences, and the increase in overheads associated with these six adjustment criteria. The 
4-4

methodology used for the APC/CCS Facility is the same as that discussed in Section 3.4 for the 

APC Facility (without CCS). 

Table 4-3 and Table 4-4 show the APC capital cost variations for alternative U.S. plant locations, 

including the difference between the given location and the average location specified for the 

Cost Estimate. 

TABLE 4-3– LOCATION-BASED COSTS FOR APC/CCS FACILITY (650,000 KW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,100 32.2% 1,643 6,743 

Alaska Fairbanks 5,100 31.4% 1,602 6,702 

Alabama Huntsville 5,100 -8.0% (409) 4,691 

Arizona Phoenix 5,100 -5.7% (289) 4,811 

Arkansas Little Rock 5,100 -5.9% (303) 4,797 

California Los Angeles 5,100 19.6% 1,000 6,100 

California Redding 5,100 9.4% 481 5,581 

California Bakersfield 5,100 9.0% 458 5,558 

California Sacramento 5,100 14.4% 734 5,834 

California San Francisco 5,100 41.6% 2,124 7,224 

Colorado Denver 5,100 -6.6% (335) 4,765 

Connecticut Hartford 5,100 25.6% 1,306 6,406 

Delaware Dover 5,100 21.9% 1,116 6,216 

District of Columbia Washington 5,100 37.0% 1,888 6,988 

Florida Tallahassee 5,100 -11.6% (591) 4,509 

Florida Tampa 5,100 -5.1% (262) 4,838 

Georgia Atlanta 5,100 -8.7% (445) 4,655 

Hawaii Honolulu 0 0 0 0 

Idaho Boise 5,100 -4.1% (211) 4,889 

Illinois Chicago 5,100 20.7% 1,055 6,155 

Indiana Indianapolis 5,100 2.8% 141 5,241 

Iowa Davenport 5,100 -1.7% (85) 5,015 

Iowa Waterloo 5,100 -9.6% (491) 4,609 

Kansas Wichita 5,100 -7.3% (372) 4,728 

Kentucky Louisville 5,100 -6.1% (309) 4,791 

Louisiana New Orleans 5,100 -11.9% (608) 4,492 

Maine Portland 5,100 -1.4% (72) 5,028 

Maryland Baltimore 5,100 3.8% 195 5,295 

Massachusetts Boston 5,100 34.9% 1,779 6,879 

Michigan Detroit 5,100 4.0% 204 5,304 

Michigan Grand Rapids 5,100 -8.4% (428) 4,672 

Minnesota St. Paul 5,100 4.0% 206 5,306 

Mississippi Jackson 5,100 -8.0% (406) 4,694 

Missouri St. Louis 5,100 7.2% 366 5,466 
4-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Missouri Kansas City 5,100 3.4% 174 5,274 

Montana Great Falls 5,100 -4.8% (244) 4,856 

Nebraska Omaha 5,100 -3.9% (197) 4,903 

New Hampshire Concord 5,100 -2.0% (100) 5,000 

New Jersey Newark 5,100 16.4% 837 5,937 

New Mexico Albuquerque 5,100 -4.4% (222) 4,878 

New York New York 5,100 34.7% 1,768 6,868 

New York Syracuse 5,100 8.5% 433 5,533 

Nevada Las Vegas 5,100 7.5% 382 5,482 

North Carolina Charlotte 5,100 -10.5% (534) 4,566 

North Dakota Bismarck 5,100 -8.5% (434) 4,666 

Ohio Cincinnati 5,100 -0.3% (13) 5,087 

Oregon Portland 5,100 9.1% 466 5,566 

Pennsylvania Philadelphia 5,100 12.7% 649 5,749 

Pennsylvania Wilkes-Barre 5,100 -3.9% (201) 4,899 

Rhode Island Providence 5,100 4.2% 214 5,314 

South Carolina Spartanburg 5,100 -12.7% (649) 4,451 

South Dakota Rapid City 5,100 -11.4% (583) 4,517 

Tennessee Knoxville 5,100 -9.6% (492) 4,608 

Texas Houston 5,100 -10.2% (518) 4,582 

Utah Salt Lake City 5,100 -3.8% (194) 4,906 

Vermont Burlington 5,100 -5.9% (299) 4,801 

Virginia Alexandria 5,100 8.7% 443 5,543 

Virginia Lynchburg 5,100 -2.7% (138) 4,962 

Washington Seattle 5,100 12.6% 644 5,744 

Washington Spokane 5,100 -2.7% (136) 4,964 

West Virginia Charleston 5,100 -2.0% (103) 4,997 

Wisconsin Green Bay 5,100 0.0% 0 5,100 

Wyoming Cheyenne 5,100 1.4% 74 5,174 

Puerto Rico Cayey 0 0 0 0 
4-6

TABLE 4-4 – LOCATION-BASED COSTS FOR APC/CCS FACILITY (1,300,000 KW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,580 35.2% 1,610 6,190 

Alaska Fairbanks 4,580 34.2% 1,565 6,145 

Alabama Huntsville 4,580 -8.3% (380) 4,200 

Arizona Phoenix 4,580 -5.8% (266) 4,314 

Arkansas Little Rock 4,580 -6.1% (278) 4,302 

California Los Angeles 4,580 21.5% 985 5,565 

California Redding 4,580 10.4% 475 5,055 

California Bakersfield 4,580 9.9% 453 5,033 

California Sacramento 4,580 15.5% 710 5,290 

California San Francisco 4,580 45.2% 2,071 6,651 

Colorado Denver 4,580 -6.7% (309) 4,271 

Connecticut Hartford 4,580 28.1% 1,288 5,868 

Delaware Dover 4,580 24.2% 1,109 5,689 

District of Columbia Washington 4,580 41.4% 1,895 6,475 

Florida Tallahassee 4,580 -12.1% (552) 4,028 

Florida Tampa 4,580 -5.4% (245) 4,335 

Georgia Atlanta 4,580 -9.0% (413) 4,167 

Hawaii Honolulu 0 0 0 0 

Idaho Boise 4,580 -4.2% (191) 4,389 

Illinois Chicago 4,580 21.7% 995 5,575 

Indiana Indianapolis 4,580 3.2% 148 4,728 

Iowa Davenport 4,580 -1.7% (79) 4,501 

Iowa Waterloo 4,580 -10.0% (457) 4,123 

Kansas Wichita 4,580 -7.5% (343) 4,237 

Kentucky Louisville 4,580 -6.2% (284) 4,296 

Louisiana New Orleans 4,580 -12.4% (567) 4,013 

Maine Portland 4,580 -1.1% (48) 4,532 

Maryland Baltimore 4,580 4.6% 211 4,791 

Massachusetts Boston 4,580 37.7% 1,728 6,308 

Michigan Detroit 4,580 4.2% 193 4,773 

Michigan Grand Rapids 4,580 -8.7% (398) 4,182 

Minnesota St. Paul 4,580 4.3% 195 4,775 

Mississippi Jackson 4,580 -8.2% (377) 4,203 

Missouri St. Louis 4,580 7.7% 354 4,934 

Missouri Kansas City 4,580 3.7% 168 4,748 

Montana Great Falls 4,580 -4.8% (222) 4,358 

Nebraska Omaha 4,580 -3.9% (180) 4,400 

New Hampshire Concord 4,580 -1.9% (87) 4,493 

New Jersey Newark 4,580 17.1% 781 5,361 
4-7

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 4,580 -4.4% (202) 4,378 

New York New York 4,580 36.0% 1,650 6,230 

New York Syracuse 4,580 9.7% 442 5,022 

Nevada Las Vegas 4,580 7.9% 361 4,941 

North Carolina Charlotte 4,580 -10.7% (492) 4,088 

North Dakota Bismarck 4,580 -8.8% (404) 4,176 

Ohio Cincinnati 4,580 0.1% 4 4,584 

Oregon Portland 4,580 10.1% 461 5,041 

Pennsylvania Philadelphia 4,580 13.3% 609 5,189 

Pennsylvania Wilkes-Barre 4,580 -4.0% (182) 4,398 

Rhode Island Providence 4,580 4.5% 205 4,785 

South Carolina Spartanburg 4,580 -13.1% (600) 3,980 

South Dakota Rapid City 4,580 -11.8% (542) 4,038 

Tennessee Knoxville 4,580 -9.9% (455) 4,125 

Texas Houston 4,580 -10.5% (482) 4,098 

Utah Salt Lake City 4,580 -3.6% (167) 4,413 

Vermont Burlington 4,580 -6.0% (273) 4,307 

Virginia Alexandria 4,580 9.9% 455 5,035 

Virginia Lynchburg 4,580 -2.4% (112) 4,468 

Washington Seattle 4,580 13.7% 626 5,206 

Washington Spokane 4,580 -2.6% (121) 4,459 

West Virginia Charleston 4,580 -2.0% (93) 4,487 

Wisconsin Green Bay 4,580 0.3% 14 4,594 

Wyoming Cheyenne 4,580 2.2% 102 4,682 

Puerto Rico Cayey 0 0 0 0 

4.5 O&M ESTIMATE 

The O&M items for the APC/CCS Facility are the same as those discussed in Section 3.5 for the 

APC Facility (without CCS), except that adders are included to both FOM and VOM to 

accommodate the expenses associated with compressor maintenance, sequestration maintenance, 

and the associated additional labor required to manage, operate, and maintain the additional 

equipment. Table 4-5 and Table 4-6 present the FOM and VOM expenses for the APC/CCS 

Facility. 

TABLE 4-5 – O&M EXPENSES FOR APC/CCS (650,000 KW) 

Technology: APC/CCS 

Fixed O&M Expense $76.62/kW-year 

Variable O&M Expense $9.05/MWh 
4-8

TABLE 4-6 – O&M EXPENSES FOR APC/CCS (1,300,000 KW) 

Technology: APC/CCS 

Fixed O&M Expense $63.21/kW-year 

Variable O&M Expense $9.05/MWh 

4.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

In addition to the equipment utilized for environmental compliance in the APC Facility, the 

APC/CCS Facility includes an amine scrubber that is intended to remove 90 percent of the CO2

produced in the combustion process, wherein the captured CO2 is later compressed to HP and 

sequestered, as discussed above. Table 4-7 presents the environmental emissions for the 

APC/CCS Facility. 

TABLE 4-7 – ENVIRONMENTAL EMISSIONS FOR APC/CCS 

Technology: APC/CCS 

NOX 0.06 lb/MMBtu 

SO2 0.02 lb/MMBtu 

CO2 20.6 lb/MMBtu 
5-1

5. CONVENTIONAL NATURAL GAS COMBINED CYCLE (NGCC) 

5.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Conventional NGCC produces 540 MW of net electricity. The facility utilizes two natural 

gas-fueled F-class CTs and associated electric generators, two supplemental-fired heat recovery 

steam generators (“HRSG”), and one condensing ST and associated electric generator operating 

in combined-cycle mode. Each CT is designed to produce nominally 172 MW and includes a 

dry-low NOX (“DLN”) combustion system and a hydrogen-cooled electric generator. The two 

triple-pressure HRSGs include integrated deaerators, SCRs, oxidation catalyst for the control of 

carbon monoxide (“CO”), and supplemental duct firing with associated combustion 

management. The ST is a single-reheat condensing ST designed for variable pressure operation, 

designed to produce an additional 210 MW. The ST exhaust is cooled in a closed-loop 

condenser system with a mechanical draft cooling tower. The CTs are equipped with inlet 

evaporative coolers to reduce the temperature of the turbine inlet air to increase summer output. 

The Conventional NGCC plant also includes a raw water treatment system consisting of 

clarifiers and filters and a turbine hall, in which the CTs, ST, and HRSGs are enclosed to avoid 

freezing during periods of cold ambient temperatures. Figure 5-1 presents the Conventional 

NGCC process flow diagram. 
5-2

FIGURE 5-1 – CONVENTIONAL NGCC DESIGN CONFIGURATION

5.2 ELECTRICAL AND CONTROL SYSTEMS 

The Conventional NGCC has two CT electric generators and one ST electric generator. The 

generators for the CTs are 60 Hz and rated at approximately 215 MVA with an output voltage of 

18 kV. The ST electric generator is 60 Hz and rated at approximately 310 MVA with an output 

voltage of 18 kV. Each CT and ST electric generator is connected to a high-voltage bus in the 

Conventional NGCC via a dedicated generator circuit breaker, generator GSU, and a disconnect 

switch. The GSUs increase the voltage from the electric generators from 18 kV to 

interconnected high voltage. 

The Conventional NGCC is controlled using a DCS. The DCS provides centralized control of 

the facility by integrating the control systems provided with each individual CT and associated 

electric generator, ST and associated electric generator, and the control of BOP systems and 

equipment. 

5.3 OFF-SITE REQUIREMENTS 

Natural gas is delivered to the facility through a lateral connected to the local natural gas trunk 

line. Water for all processes at the Conventional NGCC Facility is obtained from a one of 

several available water sources (e.g., municipal water supply). The Conventional NGCC Facility 

uses a water treatment system and a high-efficiency reverse osmosis system to reduce the 
5-3

dissolved solids from the cooling water and to provide distilled water for HRSG makeup. 

Wastewater is sent to a municipal wastewater system. Further, the electrical interconnection 

from the Conventional NGCC on-site switchyard is effectuated by a connection to an adjacent 

utility substation. 

5.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the Conventional NGCC Facility with a nominal capacity of 

540 MW is $980/kW. Table 5-1 summarizes the Cost Estimate categories for the Conventional 

NGCC Facility. 

TABLE 5-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR CONVENTIONAL 

NGCC 

Technology: Conventional NGCC 

Nominal Capacity (ISO): 540,000 kW 

Nominal Heat Rate (ISO): 7,050 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 40,100 

Mechanical Equipment Supply and 

Installation 221,500 

Electrical / I&C Supply and Installation 35,000 

Project Indirects (1) 88,400 

EPC Cost before Contingency and Fee 385,000 

Fee and Contingency 55,000 

Total Project EPC 440,000 

Owner Costs (excluding project finance) 88,000 

Total Project Cost (excluding finance) 528,000 

Total Project EPC / kW 815 

Owner Costs 20% (excluding project finance) / kW 163 

Total Project Cost (excluding project finance) / kW 978 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: outdoor installation considerations, air-cooled condensers 
5-4

compared to cooling towers, seismic design differences, zero-water discharge issues, local 

technical enhancements (e.g., additional noise remediation that is generally required in urban 

siting), remote location issues, urban – high density population issues, labor wage and 

productivity differences, location adjustments, owner cost differences, and the increase in 

overheads associated with these 10 adjustments. 

Outdoor installation locations are considered in geographic areas where enclosed structures for 

the boilers would not be required due to the low probability of freezing. The locations that were 

included in outdoor installation are Alabama, Arizona, Arkansas, Florida, Georgia, Hawaii, 

Louisiana, Mississippi, New Mexico, South Carolina, and Puerto Rico. 

The potential locations relating to the use of air-cooled condensers in place of mechanical draft 

wet cooling towers were identified as Arizona, California, Connecticut, Delaware, District of 

Columbia, Maryland, Massachusetts, New Hampshire, New York, Oregon, Pennsylvania, Rhode 

Island, Virginia, and Puerto Rico. These locations are identified as those where conservation of 

water, notwithstanding supply, has been and/or is becoming a significant issue in plant 

permitting/siting. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

The potential locations relating to the need of zero-water discharge were identified as Arizona, 

California, Colorado, Connecticut, Delaware, District of Columbia, Maryland, Massachusetts, 

New Hampshire, New York, Rhode Island, Virginia, and Puerto Rico. Similar to water usage 

discussed above in this section on Conventional NGCC, wastewater treatment and disposal is 

considered a critical permitting/siting issue in these areas. 

The locations with local technical enhancements include California, Colorado, Connecticut, 

Delaware, District of Columbia, Louisiana, Maryland, Massachusetts, New Jersey, New York, 

Rhode Island, Vermont, and Virginia. These areas are places where noise, visual impacts, and 

other technical enhancements generally need to be made by a project developer or utility to 

comply with the applicable permitting/siting requirements. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the Conventional NGCC include 

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and 

Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1., taking into 

consideration the amount of labor we estimated for the Conventional NGCC Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 
5-5

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 5-2 presents the Conventional NGCC capital cost variations for alternative U.S. plant 

locations, including the difference between the given location and the average location specified 

for the Cost Estimate. 

TABLE 5-2 – LOCATION-BASED COSTS FOR CONVENTIONAL NGCC 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 980 33.3% 326 1,306 

Alaska Fairbanks 980 38.2% 374 1,354 

Alabama Huntsville 980 -8.6% (84) 896 

Arizona Phoenix 980 2.6% 25 1,005 

Arkansas Little Rock 980 -7.5% (73) 912 

California Los Angeles 980 29.0% 284 1,264 

California Redding 980 13.5% 132 1,112 

California Bakersfield 980 15.8% 154 1,134 

California Sacramento 980 20.5% 200 1,180 

California San Francisco 980 46.1% 452 1,432 

Colorado Denver 980 2.1% 21 1,001 

Connecticut Hartford 980 27.9% 274 1,254 

Delaware Dover 980 26.2% 256 1,236 

District of Columbia Washington 980 33.3% 326 1,306 

Florida Tallahassee 980 -11.6% (113) 867 

Florida Tampa 980 -6.0% (58) 922 

Georgia Atlanta 980 -6.6% (64) 916 

Hawaii Honolulu 980 50.2% 492 1,472 

Idaho Boise 980 -3.9% (38) 942 

Illinois Chicago 980 16.7% 163 1,143 

Indiana Indianapolis 980 0.9% 9 989 

Iowa Davenport 980 0.5% 5 985 

Iowa Waterloo 980 -6.4% (63) 917 

Kansas Wichita 980 -5.0% (49) 936 

Kentucky Louisville 980 -5.4% (53) 927 

Louisiana New Orleans 980 -5.2% (51) 929 

Maine Portland 980 -3.4% (33) 952 

Maryland Baltimore 980 20.4% 200 1,180 

Massachusetts Boston 980 40.0% 392 1,372 

Michigan Detroit 980 5.3% 52 1,032 

Michigan Grand Rapids 980 -5.3% (52) 928 

Minnesota St. Paul 980 4.5% 44 1,024 

Mississippi Jackson 980 -8.6% (84) 896 
5-6

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Missouri St. Louis 980 5.6% 55 1,035 

Missouri Kansas City 980 2.7% 27 1,007 

Montana Great Falls 980 -2.4% (24) 956 

Nebraska Omaha 980 -1.5% (15) 965 

New Hampshire Concord 980 7.3% 72 1,052 

New Jersey Newark 980 22.1% 217 1,197 

New Mexico Albuquerque 980 -2.4% (24) 956 

New York New York 980 68.4% 670 1,650 

New York Syracuse 980 16.3% 160 1,140 

Nevada Las Vegas 980 6.2% 61 1,041 

North Carolina Charlotte 980 -10.5% (102) 888 

North Dakota Bismarck 980 -5.4% (53) 927 

Ohio Cincinnati 980 -1.7% (17) 963 

Oregon Portland 980 13.2% 130 1,110 

Pennsylvania Philadelphia 980 26.1% 255 1,235 

Pennsylvania Wilkes-Barre 980 -1.7% (17) 963 

Rhode Island Providence 980 22.0% 215 1,195 

South Carolina Spartanburg 980 -12.8% (126) 854 

South Dakota Rapid City 980 -8.0% (78) 902 

Tennessee Knoxville 980 -8.5% (84) 896 

Texas Houston 980 -8.8% (87) 893 

Utah Salt Lake City 980 -4.0% (39) 941 

Vermont Burlington 980 -0.1% (1) 979 

Virginia Alexandria 980 16.0% 157 1,137 

Virginia Lynchburg 980 -5.8% (57) 923 

Washington Seattle 980 7.0% 68 1,048 

Washington Spokane 980 -2.6% (25) 955 

West Virginia Charleston 980 0.1% 1 981 

Wisconsin Green Bay 980 -1.3% (13) 967 

Wyoming Cheyenne 980 -0.5% (4) 976 

Puerto Rico Cayey 980 10.9% 106 1,086 

5.5 O&M ESTIMATE 

In addition to the general O&M items discussed in Section 2.5.2., the Conventional NGCC 

Facility includes the major maintenance for the CTs, as well as the BOP, including the ST, 

associated electric generators, HRSGs, and emissions reduction catalysts. These major 

maintenance expenses are included with the VOM expense for this technology and are given on 

an average basis across the MWhs incurred. Typically, significant overhauls on a Conventional 

NGCC Facility occur no less frequently than 24,000 operating hour intervals. Table 5-3 presents 

the O&M expenses for the Conventional NGCC Facility. 
5-7

TABLE 5-3 – O&M EXPENSES FOR CONVENTIONAL NGCC 

Technology: Conventional NGCC 

Fixed O&M Expense $14.39/kW-year 

Variable O&M Expense $3.43/MWh 

5.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The Conventional NGCC utilizes DLN combustion systems in the primary combustion zone of 

the CT and best available burner technology with respect to the duct burners in the HRSGs to 

manage the production of NOX and CO. Additional control of NOX and CO is accomplished 

through an SCR and an oxidization catalyst, respectively. Oxides of sulfur in the Conventional 

NGCC are managed through the natural gas fuel quality, which is generally very low in sulfur 

U.S. domestic pipeline quality natural gas, and consequently the low sulfur content translates 

into SO2 after combustion. The Conventional NGCC does not include any control devices for 

CO2, which is proportional the heat rate (inversely proportional to the efficiency) of the 

technology. Water, wastewater, and solid waste compliance are achieved through traditional onsite and off-site methods, and the costs for such compliance are included in the O&M estimate 

for the Conventional NGCC Facility. Table 5-4 presents environmental emissions for the 

Conventional NGCC Facility. 

TABLE 5-4 – ENVIRONMENTAL EMISSIONS FOR CONVENTIONAL NGCC 

 Technology: Conventional NGCC 

NOX 0.0075 lb/MMBtu 

SO2 0.001 lb/MMBtu 

CO2 117 lb/MMBtu 
6-1

6. ADVANCED GENERATION NATURAL GAS COMBINED CYCLE (AG-NGCC) 

6.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Advanced Generation (“AG”)-NGCC design is the same as the Conventional NGCC, except 

an H-class CT is utilized in lieu of F-class, and there is only one CT/HRSG supporting the ST 

included. Since the H-class CT design employees steam cooling of both stationary and rotational 

hot parts, the HRSG systems and the ST are both considered “advanced” designs, as compared to 

the Conventional NGCC. The net output of the AG-NGCC is 400 MW. Figure 6-1 presents the 

AG-NGCC process flow diagram. 

FIGURE 6-1 – AG-NGCC DESIGN CONFIGURATION

6.2 ELECTRICAL AND CONTROL SYSTEMS 

The AG-NGCC electrical and control systems are similar to the Conventional NGCC Facility, 

except that the sizing of the generators and transformers are larger to support the larger CT and 

ST equipment utilized in the AG-NGCC. 

6.3 OFF-SITE REQUIREMENTS 

The off-site requirements for the AG-NGCC Facility are the same as the Conventional NGCC. 

Refer to Section 5.3 for the description of the Conventional NGCC off-site requirements. 

6.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the AG-NGCC Facility with a nominal capacity of 400 MW is 

$1,003/kW. Table 6-1 summarizes the Cost Estimate categories for the Conventional NGCC 

Facility. 
6-2

TABLE 6-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR AG-NGCC 

Technology: AG-NGCC 

Nominal Capacity (ISO): 400,000 kW 

Nominal Heat Rate (ISO): 6,430 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 20,610 

Mechanical Equipment Supply and 

Installation 178,650 

Electrical / I&C Supply and Installation 24,800 

Project Indirects (1) 68,300 

EPC Cost before Contingency and Fee 292,360 

Fee and Contingency 42,000 

Total Project EPC 334,360 

Owner Costs (excluding project finance) 66,872 

Total Project Cost (excluding finance) 401,232 

Total Project EPC / kW 836 

Owner Costs 20% (excluding project finance) / kW 167 

Total Project Cost (excluding project finance) / kW 1,003 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

The locational adjustments for the AG-NGCC Facility similar to those made for the 

Conventional NGCC Facility. 

Table 6-2 presents the AG-NGCC Facility capital cost variations for alternative U.S. plant 

locations, including the difference between the given location and the average location specified 

for the Cost Estimate. 
6-3

TABLE 6-2 – LOCATION-BASED COSTS FOR AG-NGCC 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 1,005 32.4% 325 1,330 

Alaska Fairbanks 1,005 37.2% 374 1,379 

Alabama Huntsville 1,005 -8.3% (84) 921 

Arizona Phoenix 1,005 2.6% 26 1,031 

Arkansas Little Rock 1,005 -6.7% (67) 938 

California Los Angeles 1,005 28.2% 283 1,288 

California Redding 1,005 13.1% 132 1,137 

California Bakersfield 1,005 15.4% 154 1,159 

California Sacramento 1,005 19.9% 200 1,205 

California San Francisco 1,005 44.9% 451 1,456 

Colorado Denver 1,005 2.1% 21 1,026 

Connecticut Hartford 1,005 27.2% 273 1,278 

Delaware Dover 1,005 25.5% 256 1,261 

District of Columbia Washington 1,005 32.5% 326 1,331 

Florida Tallahassee 1,005 -11.2% (113) 892 

Florida Tampa 1,005 -5.8% (58) 947 

Georgia Atlanta 1,005 -6.3% (64) 941 

Hawaii Honolulu 1,005 48.9% 492 1,497 

Idaho Boise 1,005 -3.7% (38) 967 

Illinois Chicago 1,005 16.1% 162 1,167 

Indiana Indianapolis 1,005 0.9% 9 1,014 

Iowa Davenport 1,005 0.5% 5 1,010 

Iowa Waterloo 1,005 -6.2% (62) 943 

Kansas Wichita 1,005 -4.3% (43) 962 

Kentucky Louisville 1,005 -5.2% (52) 953 

Louisiana New Orleans 1,005 -5.0% (50) 955 

Maine Portland 1,005 -2.7% (27) 978 

Maryland Baltimore 1,005 19.9% 200 1,205 

Massachusetts Boston 1,005 38.9% 391 1,396 

Michigan Detroit 1,005 5.2% 52 1,057 

Michigan Grand Rapids 1,005 -5.1% (51) 954 

Minnesota St. Paul 1,005 4.4% 44 1,049 

Mississippi Jackson 1,005 -8.3% (83) 922 

Missouri St. Louis 1,005 5.4% 54 1,059 

Missouri Kansas City 1,005 2.6% 26 1,031 

Montana Great Falls 1,005 -2.3% (24) 981 

Nebraska Omaha 1,005 -1.4% (14) 991 

New Hampshire Concord 1,005 7.2% 72 1,077 

New Jersey Newark 1,005 21.4% 215 1,220 

New Mexico Albuquerque 1,005 -2.3% (23) 982 
6-4

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 1,005 66.4% 667 1,672 

New York Syracuse 1,005 15.9% 160 1,165 

Nevada Las Vegas 1,005 6.0% 61 1,066 

North Carolina Charlotte 1,005 -9.1% (91) 914 

North Dakota Bismarck 1,005 -5.2% (52) 953 

Ohio Cincinnati 1,005 -1.6% (16) 989 

Oregon Portland 1,005 12.9% 130 1,135 

Pennsylvania Philadelphia 1,005 25.3% 254 1,259 

Pennsylvania Wilkes-Barre 1,005 -1.6% (16) 989 

Rhode Island Providence 1,005 21.4% 215 1,220 

South Carolina Spartanburg 1,005 -12.4% (125) 880 

South Dakota Rapid City 1,005 -7.7% (77) 928 

Tennessee Knoxville 1,005 -8.2% (83) 922 

Texas Houston 1,005 -8.5% (86) 919 

Utah Salt Lake City 1,005 -3.8% (38) 967 

Vermont Burlington 1,005 0.0% (0) 1,005 

Virginia Alexandria 1,005 15.6% 157 1,162 

Virginia Lynchburg 1,005 -5.6% (56) 949 

Washington Seattle 1,005 6.8% 68 1,073 

Washington Spokane 1,005 -2.5% (25) 980 

West Virginia Charleston 1,005 0.1% 1 1,006 

Wisconsin Green Bay 1,005 -1.3% (13) 992 

Wyoming Cheyenne 1,005 -0.4% (4) 1,001 

Puerto Rico Cayey 1,005 10.6% 107 1,112 

6.5 O&M ESTIMATE 

The O&M items for the AG-NGCC Facility are the same as those described in Section 5.5 for 

the Conventional NGCC Facility. Table 6-3 presents the O&M expenses for the AG-NGCC 

Facility. 

TABLE 6-3 – O&M EXPENSES FOR AG-NGCC 

Technology: AG-NGCC 

Fixed O&M Expense $14.62/kW-year 

Variable O&M Expense $3.11/MWh 

6.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The environmental compliance strategy and equipment for the AG-NGCC Facility is the same as 

those described in Section 5.6 for the Conventional NGCC Facility. Table 6-4 presents 

environmental emissions for the AG-NGCC Facility. 
6-5

TABLE 6-4 – ENVIRONMENTAL EMISSIONS FOR AG-NGCC 

Technology: AG-NGCC 

NOX 0.0075 lb/MMBtu 

SO2 0.001 lb/MMBtu 

CO2 117 lb/MMBtu 
7-1

7. ADVANCED GENERATION NATURAL GAS COMBINED CYCLE WITH CCS 

(AG-NGCC/CCS) 

7.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The plant configuration for the AG-NGCC/CCS Facility is the same as the AG-NGCC Facility 

with the exception that an amine system based on MEA as the solvent is included for CO2

capture from the flue gas. The captured CO2 is compressed to approximately 2,000 psia for 

injection into a pipeline at the plant fence line. Figure 7-1 presents the AG-NGCC with CCS 

process flow diagram. 

FIGURE 7-1 – AG-NGCC WITH CCS DESIGN CONFIGURATION

7.2 ELECTRICAL AND CONTROL SYSTEMS 

The electrical and control systems for the AG-NGCC/CCS Facility are materially similar to the 

AG-NGCC Facility described in Section 6.2. 

7.3 OFF-SITE REQUIREMENTS 

The off-site requirements for the AG-NGCC/CCS Facility are materially similar to the 

AG-NGCC Facility, except that the CO2 needs sequestering in one of the following geologic 

formations: (1) exhausted gas storage location, (2) unminable coal seam, (3) enhanced oil 

recovery, or (4) saline aquifer. To the extent that a sequestration site is not near the given facility 

being analyzed, transportation for a viable sequestration site has the potential to materially affect 

the capital cost estimates discussed below. 

7.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the AG-NGCC/CCS Facility with a nominal capacity of 340 MW is 

$2,060/kW. The capital cost estimate was based on the AG-NGCC (without CCS) and the base 

cost estimate was increased to include the expected costs of CCS. Table 7-1 summarizes the 

Cost Estimate categories for the AG-NGCC/CCS Facility. 
7-2

TABLE 7-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR AG-NGCC/CCS 

COST 

Technology: AG-NGCC/CCS 

Nominal Capacity (ISO): 340,000 kW 

Nominal Heat Rate (ISO): 7,525 Btu/kWh-HHV 

 

Total Project EPC 583,667 

 

Owner Costs (excluding project finance) 116,733 

Total Project Cost (excluding finance) 700,400 

Total Project EPC / kW 1,717 

Owner Costs 20% (excluding project finance) / kW 343 

Total Project Cost (excluding project finance) / kW 2,060 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

The locational adjustments for the AG-NGCC/CCS Facility are similar to those made for the 

Conventional NGCC Facility, described in Section 5.4. 

Table 7-2 presents the AG-NGCC/CCS Facility capital cost variations for alternative U.S. plant 

locations, including the difference between the given location and the average location specified 

for the Cost Estimate. 
7-3

TABLE 7-2 – LOCATION-BASED COSTS FOR AG-NGCC/CCS 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 2,060 20.8% 428 2,488 

Alaska Fairbanks 2,060 23.7% 488 2,548 

Alabama Huntsville 2,060 -8.5% (174) 1,886 

Arizona Phoenix 2,060 -2.3% (47) 2,013 

Arkansas Little Rock 2,060 -7.0% (143) 1,917 

California Los Angeles 2,060 16.1% 331 2,391 

California Redding 2,060 7.4% 152 2,212 

California Bakersfield 2,060 8.2% 169 2,229 

California Sacramento 2,060 13.3% 274 2,334 

California San Francisco 2,060 29.8% 615 2,675 

Colorado Denver 2,060 -2.9% (60) 2,000 

Connecticut Hartford 2,060 15.9% 328 2,388 

Delaware Dover 2,060 13.5% 278 2,338 

District of Columbia Washington 2,060 14.8% 305 2,365 

Florida Tallahassee 2,060 -11.4% (234) 1,826 

Florida Tampa 2,060 -5.3% (108) 1,952 

Georgia Atlanta 2,060 -7.9% (162) 1,898 

Hawaii Honolulu 2,060 26.8% 551 2,611 

Idaho Boise 2,060 -4.9% (100) 1,960 

Illinois Chicago 2,060 16.9% 348 2,408 

Indiana Indianapolis 2,060 -0.5% (11) 2,049 

Iowa Davenport 2,060 -0.6% (13) 2,047 

Iowa Waterloo 2,060 -8.2% (168) 1,892 

Kansas Wichita 2,060 -6.4% (132) 1,928 

Kentucky Louisville 2,060 -6.2% (127) 1,933 

Louisiana New Orleans 2,060 -8.5% (175) 1,885 

Maine Portland 2,060 -4.9% (102) 1,958 

Maryland Baltimore 2,060 7.3% 150 2,210 

Massachusetts Boston 2,060 26.6% 547 2,607 

Michigan Detroit 2,060 4.3% 88 2,148 

Michigan Grand Rapids 2,060 -7.0% (144) 1,916 

Minnesota St. Paul 2,060 3.7% 76 2,136 

Mississippi Jackson 2,060 -8.4% (173) 1,887 

Missouri St. Louis 2,060 4.4% 91 2,151 

Missouri Kansas City 2,060 2.3% 47 2,107 

Montana Great Falls 2,060 -4.5% (93) 1,967 

Nebraska Omaha 2,060 -3.2% (65) 1,995 

New Hampshire Concord 2,060 1.6% 34 2,094 

New Jersey Newark 2,060 18.8% 388 2,448 

New Mexico Albuquerque 2,060 -4.2% (86) 1,974 
7-4

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 2,060 50.1% 1,032 3,092 

New York Syracuse 2,060 6.4% 133 2,193 

Nevada Las Vegas 2,060 6.1% 126 2,186 

North Carolina Charlotte 2,060 -10.8% (223) 1,837 

North Dakota Bismarck 2,060 -7.1% (146) 1,914 

Ohio Cincinnati 2,060 -3.4% (70) 1,990 

Oregon Portland 2,060 7.1% 146 2,206 

Pennsylvania Philadelphia 2,060 18.3% 378 2,438 

Pennsylvania Wilkes-Barre 2,060 -3.7% (77) 1,983 

Rhode Island Providence 2,060 11.9% 244 2,304 

South Carolina Spartanburg 2,060 -13.4% (275) 1,785 

South Dakota Rapid City 2,060 -9.8% (203) 1,857 

Tennessee Knoxville 2,060 -9.6% (197) 1,863 

Texas Houston 2,060 -9.6% (198) 1,862 

Utah Salt Lake City 2,060 -5.9% (123) 1,937 

Vermont Burlington 2,060 -4.0% (81) 1,979 

Virginia Alexandria 2,060 5.7% 118 2,178 

Virginia Lynchburg 2,060 -6.6% (137) 1,923 

Washington Seattle 2,060 6.0% 123 2,183 

Washington Spokane 2,060 -3.5% (71) 1,989 

West Virginia Charleston 2,060 -1.4% (30) 2,030 

Wisconsin Green Bay 2,060 -2.7% (55) 2,005 

Wyoming Cheyenne 2,060 -4.5% (92) 1,968 

Puerto Rico Cayey 2,060 1.7% 34 2,094 

7.5 O&M ESTIMATE 

The O&M items for the AG-NGCC/CCS Facility are the same as those set forth in Section 6.5 

for the AG-NGCC Facility, except that adders are included to both FOM and VOM to 

accommodate the expenses associated with compressor maintenance, sequestration maintenance, 

and the associated additional labor required to manage, operate, and maintain the additional 

equipment. Table 7-3 presents the O&M expenses for the AG-NGCC/CCS Facility. 

TABLE 7-3 – O&M EXPENSES FOR AG-NGCC WITH CCS 

Technology: AG-NGCC/CCS 

Fixed O&M Expense $30.25/kW-year 

Variable O&M Expense $6.45/MWh 

7.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The environmental compliance strategy and equipment for the AG-NGCC Facility are the same 

as those described in Section 5.6 for the Conventional NGCC Facility, with the exception that 

the AG-NGCC with CCS Facility includes an amine scrubber control device for CO2. Table 7-4 

presents environmental emissions for the AG-NGCC/CCS Facility. 
7-5

TABLE 7-4 – ENVIRONMENTAL EMISSIONS FOR AG-NGCC/CCS 

 Technology: AG-NGCC/CCS 

NOX 0.0075 lb/MMBtu 

SO2 0.001 lb/MMBtu 

CO2 12 lb/MMBtu 
8-1

8. CONVENTIONAL COMBUSTION TURBINE (CT) 

8.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Conventional CT Facility produces 85 MW of electricity using a single natural gas-fueled 

E-class CT and associated electric generator in simple-cycle mode. The CT is equipped with an 

inlet evaporative cooler to reduce the temperature of the turbine inlet air to increase summer 

output. Figure 8-1 presents the Conventional CT Facility process flow diagram. 

FIGURE 8-1 – CONVENTIONAL CT DESIGN CONFIGURATION

8.2 ELECTRICAL AND CONTROL SYSTEMS 

The Conventional CT Facility has one CT electric generator. The generator is a 60 Hz machine 

rated at approximately 101 MVA with an output voltage of 13.8 kV. The CT electric generator 

is connected to a high-voltage bus in the Conventional CT Facility switchyard via a dedicated 

generator circuit breaker, GSU, and a disconnect switch. The GSU increases the voltage from 

the electric generator from 13.8 kV to interconnected transmission system high voltage. 

The Conventional CT Facility is controlled using a DCS. The DCS provides centralized control 

of the facility by integrating the control systems provided with the individual CT and associated 

electric generator and the control of BOP systems and equipment. 

8.3 OFF-SITE REQUIREMENTS 

Natural gas is delivered to the facility through an approximately lateral connected to the local 

natural gas trunk line. Water for the limited processes that utilize water at the Conventional CT 

Facility is obtained from a one of several available water sources (e.g., municipal water supply). 

The Conventional CT Facility uses a water treatment system and a high-efficiency reverse 

osmosis system to reduce the dissolved solids for compressor cleaning. Wastewater is sent to a 

municipal wastewater system. Further, the electrical interconnection from the Conventional CT 

on-site switchyard is effectuated by a connection to an adjacent utility substation. 
8-2

8.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the Conventional CT Facility with a nominal capacity of 85 MW is 

$975/kW. Table 8-1 summarizes the Cost Estimate categories for the Conventional CT Facility. 

TABLE 8-1 – BASE PLANT SITE 

CAPITAL COST ESTIMATE FOR CONVENTIONAL CT 

Technology: Conventional CT 

Nominal Capacity (ISO): 85,000 kW 

Nominal Heat Rate (ISO): 10,850 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 5,570 

Mechanical Equipment Supply and 

Installation 34,709 

Electrical / I&C Supply and Installation 10,700 

Project Indirects (1) 12,248 

EPC Cost before Contingency and Fee 63,227 

Fee and Contingency 5,757 

Total Project EPC 68,994 

Owner Costs (excluding project finance) 13,799 

Total Project Cost (excluding finance) 82,793 

Total Project EPC / kW 812 

Owner Costs 20% (excluding project finance) / kW 162 

Total Project Cost (excluding project finance) / kW 974 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: outdoor installation considerations, seismic design differences, 

local technical enhancements (e.g., additional noise remediation that is generally required in 

urban siting), remote location issues, urban – high density population issues, labor wage and 

productivity differences, location adjustments, owner cost differences, and the increase in 

overheads associated with these previous eight location adjustments. 

Outdoor installation locations are considered in geographic areas where enclosed structures for 

the boilers would not be required due to the low probability of freezing. The locations that were 
8-3

included in outdoor installation are Alabama, Arizona, Arkansas, Florida, Georgia, Hawaii, 

Louisiana, Mississippi, New Mexico, South Carolina, and Puerto Rico. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

The locations with local technical enhancements include California, Colorado, Connecticut, 

Delaware, District of Columbia, Louisiana, Maryland, Massachusetts, New Jersey, New York, 

Rhode Island, Vermont, and Virginia. These are areas where noise, visual impacts, and other 

technical enhancements generally need to be made by a project developer or utility to comply 

with the applicable permitting/siting requirements. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the Conventional CT Facility 

include Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; 

and Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the Conventional CT Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 8-2 presents the Conventional CT Facility capital cost variations for alternative U.S. plant 

locations. 
8-4

TABLE 8-2 – LOCATION-BASED COSTS FOR CONVENTIONAL CT 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 975 31.7% 309 1,284 

Alaska Fairbanks 975 36.5% 355 1,330 

Alabama Huntsville 975 -5.1% (50) 925 

Arizona Phoenix 975 -3.5% (34) 941 

Arkansas Little Rock 975 -3.7% (36) 939 

California Los Angeles 975 19.0% 185 1,160 

California Redding 975 3.9% 38 1,013 

California Bakersfield 975 6.3% 61 1,036 

California Sacramento 975 10.0% 97 1,072 

California San Francisco 975 34.2% 334 1,309 

Colorado Denver 975 -0.5% (5) 970 

Connecticut Hartford 975 17.8% 174 1,149 

Delaware Dover 975 16.6% 162 1,137 

District of Columbia Washington 975 24.5% 239 1,214 

Florida Tallahassee 975 -7.6% (74) 901 

Florida Tampa 975 -3.1% (31) 944 

Georgia Atlanta 975 -2.9% (29) 946 

Hawaii Honolulu 975 51.5% 502 1,477 

Idaho Boise 975 -2.8% (28) 947 

Illinois Chicago 975 13.6% 132 1,107 

Indiana Indianapolis 975 1.3% 13 988 

Iowa Davenport 975 0.9% 8 983 

Iowa Waterloo 975 -4.6% (45) 930 

Kansas Wichita 975 -3.0% (29) 946 

Kentucky Louisville 975 -4.1% (40) 935 

Louisiana New Orleans 975 -1.1% (11) 964 

Maine Portland 975 -1.6% (15) 960 

Maryland Baltimore 975 12.0% 117 1,092 

Massachusetts Boston 975 28.2% 275 1,250 

Michigan Detroit 975 4.8% 46 1,021 

Michigan Grand Rapids 975 -3.8% (37) 938 

Minnesota St. Paul 975 4.0% 39 1,014 

Mississippi Jackson 975 -5.1% (49) 926 

Missouri St. Louis 975 5.0% 48 1,023 

Missouri Kansas City 975 2.4% 23 998 

Montana Great Falls 975 -1.3% (12) 963 

Nebraska Omaha 975 -0.6% (6) 969 

New Hampshire Concord 975 -1.3% (13) 962 

New Jersey Newark 975 19.3% 188 1,163 
8-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 975 0.6% 6 981 

New York New York 975 53.2% 518 1,493 

New York Syracuse 975 7.5% 73 1,048 

Nevada Las Vegas 975 5.2% 50 1,025 

North Carolina Charlotte 975 -7.2% (70) 905 

North Dakota Bismarck 975 -3.8% (38) 937 

Ohio Cincinnati 975 -0.8% (8) 967 

Oregon Portland 975 3.7% 36 1,011 

Pennsylvania Philadelphia 975 14.8% 144 1,119 

Pennsylvania Wilkes-Barre 975 -0.7% (7) 968 

Rhode Island Providence 975 12.2% 119 1,094 

South Carolina Spartanburg 975 -8.3% (81) 894 

South Dakota Rapid City 975 -5.8% (57) 918 

Tennessee Knoxville 975 -6.6% (65) 910 

Texas Houston 975 -7.0% (68) 907 

Utah Salt Lake City 975 -2.6% (25) 950 

Vermont Burlington 975 1.3% 13 988 

Virginia Alexandria 975 7.4% 72 1,047 

Virginia Lynchburg 975 -4.5% (44) 931 

Washington Seattle 975 6.1% 59 1,034 

Washington Spokane 975 -1.8% (18) 957 

West Virginia Charleston 975 0.6% 6 981 

Wisconsin Green Bay 975 -0.6% (6) 969 

Wyoming Cheyenne 975 1.0% 10 985 

Puerto Rico Cayey 975 4.8% 47 1,022 

8.5 O&M ESTIMATE 

In addition to the general O&M items discussed in Section 2.5.2, the Conventional CT Facility 

includes the major maintenance for the CT and associated electric generator. These major 

maintenance expenses are included with the VOM expense for this technology, based upon an 

assumed 10 percent annual capacity factor and an operating profile of approximately 8 hours of 

operation per CT start. Typically, significant overhauls on a Conventional CT Facility occur no 

less frequently than 8,000 operating hour intervals; with more significant major maintenance 

outages occurring at 24,000 operating hour intervals; however, often times the major 

maintenance for a CT at a peaking facility is driven off of CT hours (depending on the 

equipment manufacturer and the operating hours per start incurred on the equipment). Table 8-3 

presents the O&M expenses for the Conventional CT Facility. 
8-6

TABLE 8-3 – O&M EXPENSES FOR CONVENTIONAL CT 

Technology: Conventional CT 

Fixed O&M Expense $6.98/kW-year 

Variable O&M Expense $14.70/MWh 

8.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Typically, a Conventional CT Facility would be equipped with only the DLN combustion 

hardware to mitigate emissions. There are some states in the U.S. that do require a “hot” SCR 

that can operate at the higher exhaust temperatures of a simple-cycle plant, though that 

equipment was not contemplated herein. 

TABLE 8-4 – ENVIRONMENTAL EMISSIONS FOR CONVENTIONAL CT 

Technology: Conventional CT 

NOX 0.03 lb/MMBtu 

SO2 0.001 lb/MMBtu 

CO2 117 lb/MMBtu 
9-1

9. ADVANCED COMBUSTION TURBINE (ACT) 

9.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Advanced CT Facility produces 210 MW of electricity using a single natural gas-fueled, 

state of the art (as of 2010) F-class CT and associated electric generator. The CT is equipped 

with an inlet evaporative cooler to reduce the temperature of the turbine inlet air to increase 

summer output. Figure 9-1 presents the Advanced CT process flow diagram. 

FIGURE 9-1 – ADVANCED CT DESIGN CONFIGURATION

9.2 ELECTRICAL AND CONTROL SYSTEMS 

The Advanced CT Facility has the same general electrical and control systems as the 

Conventional CT Facility, except that the electric generator is rated at approximately 234 MVA 

and the corresponding GSU is larger in the Advanced CT Facility. 

9.3 OFF-SITE REQUIREMENTS 

The off-site requirements for the Advanced CT Facility are materially similar to the 

Conventional CT Facility. 

9.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the Advanced CT Facility with a nominal capacity of 210 MW is 

$665/kW. Table 9-1 summarizes the Cost Estimate categories for the Advanced CT Facility. 
9-2

TABLE 9-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR ADVANCED CT 

Technology: Advanced CT 

Nominal Capacity (ISO): 210,000 kW 

Nominal Heat Rate (ISO): 9,750 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 11,800 

Mechanical Equipment Supply and 

Installation 58,700 

Electrical / I&C Supply and Installation 15,300 

Project Indirects (1) 16,460 

EPC Cost before Contingency and Fee 102,260 

Fee and Contingency 14,196 

Total Project EPC 116,456 

Owner Costs (excluding project finance) 23,291 

Total Project Cost (excluding finance) 139,747 

Total Project EPC / kW 554 

Owner Costs 20% (excluding project finance) / kW 111 

Total Project Cost (excluding project finance) / kW 665 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

The locational considerations for the Advanced CT Facility are the same as those set forth in the 

section on the Conventional CT Facility. 

Table 9-2 presents the Advanced CT Facility capital cost variations for alternative U.S. plant 

locations. 
9-3

TABLE 9-2 – LOCATION-BASED COSTS FOR ADVANCED CT 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 665 41.9% 279 944 

Alaska Fairbanks 665 48.4% 322 987 

Alabama Huntsville 665 -3.5% (23) 642 

Arizona Phoenix 665 -1.9% (12) 653 

Arkansas Little Rock 665 -2.0% (13) 652 

California Los Angeles 665 25.7% 171 836 

California Redding 665 4.8% 32 697 

California Bakersfield 665 8.5% 57 722 

California Sacramento 665 11.3% 75 740 

California San Francisco 665 42.9% 285 950 

Colorado Denver 665 2.9% 19 684 

Connecticut Hartford 665 23.7% 157 822 

Delaware Dover 665 23.3% 155 820 

District of Columbia Washington 665 36.9% 245 910 

Florida Tallahassee 665 -5.7% (38) 627 

Florida Tampa 665 -2.4% (16) 649 

Georgia Atlanta 665 0.1% 1 666 

Hawaii Honolulu 665 72.8% 484 1,149 

Idaho Boise 665 -1.4% (9) 656 

Illinois Chicago 665 11.6% 77 742 

Indiana Indianapolis 665 2.8% 18 683 

Iowa Davenport 665 2.1% 14 679 

Iowa Waterloo 665 -2.0% (14) 651 

Kansas Wichita 665 -0.5% (3) 662 

Kentucky Louisville 665 -2.7% (18) 647 

Louisiana New Orleans 665 3.9% 26 691 

Maine Portland 665 1.0% 7 672 

Maryland Baltimore 665 19.9% 132 797 

Massachusetts Boston 665 34.3% 228 893 

Michigan Detroit 665 5.4% 36 701 

Michigan Grand Rapids 665 -1.4% (9) 656 

Minnesota St. Paul 665 4.4% 29 694 

Mississippi Jackson 665 -3.4% (23) 642 

Missouri St. Louis 665 5.6% 38 703 

Missouri Kansas City 665 2.5% 17 682 

Montana Great Falls 665 1.2% 8 673 

Nebraska Omaha 665 1.3% 9 674 

New Hampshire Concord 665 -0.2% (2) 663 

New Jersey Newark 665 20.6% 137 802 
9-4

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 665 3.7% 25 690 

New York New York 665 61.7% 410 1,075 

New York Syracuse 665 12.2% 81 746 

Nevada Las Vegas 665 4.6% 31 696 

North Carolina Charlotte 665 -4.6% (31) 634 

North Dakota Bismarck 665 -1.5% (10) 655 

Ohio Cincinnati 665 1.2% 8 673 

Oregon Portland 665 4.7% 31 696 

Pennsylvania Philadelphia 665 16.1% 107 772 

Pennsylvania Wilkes-Barre 665 1.7% 11 676 

Rhode Island Providence 665 16.6% 111 776 

South Carolina Spartanburg 665 -5.5% (37) 628 

South Dakota Rapid City 665 -3.0% (20) 645 

Tennessee Knoxville 665 -4.6% (31) 634 

Texas Houston 665 -5.2% (35) 630 

Utah Salt Lake City 665 0.0% (0) 665 

Vermont Burlington 665 5.6% 37 702 

Virginia Alexandria 665 12.6% 84 749 

Virginia Lynchburg 665 -3.0% (20) 645 

Washington Seattle 665 6.5% 43 708 

Washington Spokane 665 -0.6% (4) 661 

West Virginia Charleston 665 2.3% 15 680 

Wisconsin Green Bay 665 1.0% 6 671 

Wyoming Cheyenne 665 5.5% 36 701 

Puerto Rico Cayey 665 10.3% 68 733 

9.5 O&M ESTIMATE 

The O&M items for the Advanced CT Facility are the same as those set forth in Section 8.5 for 

the Conventional CT Facility. Table 9-3 presents the O&M expenses for the Advanced CT 

Facility. 

TABLE 9-3 – O&M EXPENSES FOR ADVANCED CT 

Technology: Advanced CT 

Fixed O&M Expense $6.70/kW-year 

Variable O&M Expense $9.87/MWh 

9.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The environmental compliance strategy and equipment for the Advanced CT Facility are the 

same as those used for the Conventional CT Facility (see Section 8.6). Table 9-4 presents 

environmental emissions for the Advanced CT Facility. 
9-5

TABLE 9-4 – ENVIRONMENTAL EMISSIONS FOR ADVANCED CT 

Technology: Advanced CT 

NOX 0.03 lb/MMBtu 

SO2 0.001 lb/MMBtu 

CO2 117 lb/MMBtu 
10-1

10. INTEGRATED GASIFICATION COMBINED CYCLE (IGCC) 

10.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The following describes the IGCC Facility, which is a nominal 600 MW net coal-fired 

gasification-to-power facility. An analysis is also provided for a nominally 1,200 MW coal-fired 

gasification-to-power facility, which is essentially a dual-unit configuration, based on doubling 

the single-unit description provided below; however, a detailed technical description (due to the 

similarities/duplication with the single unit) is not provided herein. The feed for the gasification 

system is a slurry of water and ground coal and/or petroleum coke. The raw feedstock is ground 

in rod mills along with recycled water and slag fines to form the slurry. A fluxing agent is also 

added, if necessary, depending on the properties of the feedstock, to facilitate slagging at 

appropriate temperatures in the gasifier. 

Air separation units (“ASU”) provide a 95 percent-pure oxygen (“O2”) stream for gasification, 

and nitrogen for use as a diluent in the CTs, and for purging the gasifiers. 

The IGCC Facility is based on two trains of ConocoPhillips (E-Gas®) gasifier, which is a 

two-stage, refractory lined vessel that converts the slurry feed into syngas consisting of 

hydrogen, CO, CO2, methane, nitrogen, argon and water along with sulfur compounds in the 

form of hydrogen sulfide (“H2S”) and carbonyl sulfide (“COS”) and a small amount of NH3. 

The first stage is the slagging section in which the feedstock is partially combusted with O2 at 

elevated temperature and pressure (2,500 degrees oF and 540 psia). O2 and preheated slurry are 

fed to each of two opposing mixing nozzles at opposite ends of the horizontal section. The 

gasification temperature is maintained above the ash fusion point to allow for slag formation and 

carbon conversion. 

The raw syngas from the first stage flows into the vertical second stage where additional feed 

slurry is introduced to take advantage of the sensible heat in the gas. This fuel undergoes 

devolatization and pyrolysis generating additional syngas. The endothermic nature of the 

reactions and the introduction of a quench fluid reduce the temperature of the gas exiting to the 

gasifier to approximately 1,900oF. At these temperatures (2,500oF to 1,900oF), two additional 

reactions occur, which change the character of the syngas as follows: (1) carbon-steam to 

produce CO; and (2) water gas shift (steam and CO) to produce hydrogen and CO2. In addition, 

the lower reaction temperature in the second stage allows the formation of methane. Unreacted 

char is carried overhead and exits the reactor with the syngas. This char is recycled to the first 

stage of gasification. 

The mineral matter in the feedstock and any fluxing agent form a molten slag that flows out of 

the horizontal section into water quench bath. The cooled slag exits the bottom of the quench, is 

crushed and exits the unit through a continuous slag removal system as a slurry. 

The hot raw syngas is cooled in a vertical fire tube boiler from 1,900oF to 700oF. The hot gas is 

on the tube side with pressurized water on the shell side. This unit generates HP saturated steam. 

The saturated steam is sent to the HRSGs in the power block. 

After cooling, the syngas is cleaned of entrained particles in a filter vessel containing numerous 

candlestick-type filter elements. The particles collect on the filter elements producing an 

essentially particulate matter free syngas that proceeds through the system. 
10-2

Captured particulate matter is cleaned from the filter elements using cleaned syngas (in a 

back-pulse mode) and the carbon-rich material is pneumatically conveyed back to the first stage 

of the gasifier for conversion. 

Following particulate matter removal, the syngas is scrubbed with water to remove chlorine and 

trace metals. The scrubbing medium is condensed sour water from the low-temperature heat 

recovery system. 

After the chlorine scrubber, the raw syngas is treated in COS hydrolysis units, which convert the 

COS in the syngas to H2S. The syngas is then cooled to approximately 100°F in a series of shell 

and tube heat exchangers in a step known as low-temperature heat recovery. This cooling 

removes most of the water in the syngas. In addition, most of the NH3 and a small portion of 

CO2 and H2S are absorbed in the water. A portion of the condensed water is used in the chlorine 

scrubber with the remainder sent to sour water treatment. The low temperature heat removed 

prior to acid gas removal (“AGR”) is used within the process. 

After low-temperature heat recovery, the H2S is then removed in the AGR units. The AGR units 

use the Selexol solvent in a single absorption stage to remove much of the sulfur from the 

syngas. The syngas passes through a mercury removal system consisting of sulfated activated 

carbon beds. Finally, the treated syngas is moisturized and sent to the power block. 

The acid gas streams containing H2S and COS with some CO2 from AGR and sour water 

treatment are fed to the sulfur recovery units (“SRUs”). The SRUs are based on a standard Claus 

process to convert the acid gas to pure molten sulfur. The tail gas from the SRUs, composed of 

CO2, nitrogen, and small amounts of sulfur, is catalytically hydrogenated to convert all of the 

sulfur to H2S. This converted tail gas is compressed and recycled to the gasifiers. 

Process water blowdown and water condensed during cooling of the sour syngas contains small 

amounts of dissolved gases (H2S, CO2 and NH3). This water is treated in sour water stripping 

units and either recycled to slurry preparation or further treated in a zero-liquid discharge 

(“ZLD”) system to recover and reuse water. Solid waste from the ZLD is landfilled. 

The power block for the IGCC Facility case is based on a two-on-one combined-cycle 

configuration using F-class CTs. The combined cycle is similar to the Conventional NGCC 

Facility except the CTs are designed to combust natural gas and/or syngas, and the combustors 

are not DLN. Figure 10-1 presents the IGCC process flow diagram. 
10-3

FIGURE 10-1 – IGCC DESIGN CONFIGURATION

10.2 ELECTRICAL AND CONTROL SYSTEMS 

The IGCC Facility has two CT electric generators and one ST electric generator. The generators 

for the CTs are 60 Hz machines rated at approximately 255 MVA with an output voltage of 

18 kV. The ST electric generator is a 60 Hz machine rated at approximately 333 MVA with an 

output voltage of 18 kV. Each CT electric generator is connected to a high-voltage bus in the 

IGCC Facility switchyard via a dedicated generator circuit breaker, GSU, and a disconnect 

switch. The ST electric generator is connected directly to its GSU and connected through a 

disconnect switch between two breakers on the high-voltage bus. The GSUs increase the 

voltage from the electric generators from 18 kV to interconnected transmission system high 

voltage. 

The IGCC Facility is controlled using a DCS. The DCS provides centralized control of the 

facility by integrating the control systems provided with each individual CT and associated 

electric generator, ST and associated electric generator, and the control of BOP systems and 

equipment. 

10.3 OFF-SITE REQUIREMENTS 

Coal is delivered to the IGCC Facility by rail, truck or barge. Water for all processes at the 

IGCC is obtained from one of several available water sources; however, water is typically 

sourced from an adjacent river, when possible. The IGCC uses a water treatment system and a 

high-efficiency reverse osmosis system to reduce the dissolved solids from the cooling water and 

to provide distilled water for HRSG makeup. Wastewater is sent to an adjacent river or other 

approved wastewater delivery point. Further, the electrical interconnection from the IGCC onsite switchyard is effectuated by a connection to an adjacent utility substation. 
10-4

10.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the IGCC Facility with a nominal capacity of 600 MW is $3,565/kW 

and with a nominal capacity of 1,200 MW is $3,221/kW. Table 10-1 and Table 10-2 summarize 

the Cost Estimate categories for the IGCC Facility. 

TABLE 10-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR IGCC 

Technology: IGCC 

Nominal Capacity (ISO): 600,000 kW 

Nominal Heat Rate (ISO): 8,700 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 102,121 

Mechanical Equipment Supply and 

Installation 975,212 

Electrical / I&C Supply and Installation 200,708 

Project Indirects (1) 313,558 

EPC Cost before Contingency and Fee 1,591,599 

Fee and Contingency 190,992 

Total Project EPC 1,782,591 

Owner Costs (excluding project finance) 356,518 

Total Project Cost (excluding finance) 2,139,109 

Total Project EPC / kW 2,971 

Owner Costs 20% (excluding project finance) / kW 594 

Total Project Cost (excluding project finance) / kW 3,565 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 
10-5

TABLE 10-2 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR IGCC 

Technology: IGCC 

Nominal Capacity (ISO): 1,200,000 kW 

Nominal Heat Rate (ISO): 8,700 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 178,606 

Mechanical Equipment Supply and 

Installation 1,859,974 

Electrical / I&C Supply and Installation 364,745 

Project Indirects (1) 521,600 

EPC Cost before Contingency and Fee 2,924,925 

Fee and Contingency 350,991 

Total Project EPC 3,275,916 

Owner Costs (excluding project finance) 589,665 

Total Project Cost (excluding finance) 3,865,581 

Total Project EPC / kW 2730 

Owner Costs 18% (excluding project finance) / kW 491 

Total Project Cost (excluding project finance) / kW 3,221 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: outdoor installation considerations, seismic design differences, 

remote location issues, labor wage and productivity differences, location adjustments, owner cost 

differences, and the increase in overheads associated with these six adjustments. 

Outdoor installation locations are considered in geographic areas where enclosed structures for 

the boilers would not be required due to the low probability of freezing. The locations that 

included outdoor installation are Alabama, Arizona, Arkansas, Florida, Georgia, Hawaii, 

Louisiana, Mississippi, New Mexico, South Carolina, and Puerto Rico. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 
10-6

Remote locations issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems for construction, because such areas are 

long distances from urban areas, where labor is generally abundant. Remote location 

designations were also considered in locations where higher equipment freight costs are typically 

incurred, which for example are regions not near established rail or highway access. Remote 

locations related to the IGCC Facility include Fairbanks, Alaska; Honolulu, Hawaii; 

Albuquerque, New Mexico; Cheyenne, Wyoming; and Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the IGCC Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 10-3 and Table 10-4 present the IGCC Facility capital cost variations for alternative U.S. 

plant locations. 
10-7

TABLE 10-3 – LOCATION-BASED COSTS FOR IGCC (600,000 KW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,565 29.4% 1,049 4,614 

Alaska Fairbanks 3,565 28.5% 1,016 4,581 

Alabama Huntsville 3,565 -6.5% (232) 3,333 

Arizona Phoenix 3,565 -4.5% (160) 3,405 

Arkansas Little Rock 3,565 -4.7% (167) 3,398 

California Los Angeles 3,565 18.1% 645 4,210 

California Redding 3,565 8.7% 312 3,877 

California Bakersfield 3,565 8.4% 299 3,864 

California Sacramento 3,565 12.8% 455 4,020 

California San Francisco 3,565 37.6% 1,342 4,907 

Colorado Denver 3,565 -5.2% (187) 3,378 

Connecticut Hartford 3,565 23.7% 846 4,411 

Delaware Dover 3,565 20.6% 734 4,299 

District of Columbia Washington 3,565 35.6% 1,269 4,834 

Florida Tallahassee 3,565 -9.5% (339) 3,226 

Florida Tampa 3,565 -4.3% (152) 3,413 

Georgia Atlanta 3,565 -7.1% (252) 3,313 

Hawaii Honolulu 0 0 

Idaho Boise 3,565 -3.2% (113) 3,452 

Illinois Chicago 3,565 17.4% 619 4,184 

Indiana Indianapolis 3,565 2.9% 103 3,668 

Iowa Davenport 3,565 -1.4% (48) 3,517 

Iowa Waterloo 3,565 -7.8% (279) 3,286 

Kansas Wichita 3,565 -5.8% (208) 3,357 

Kentucky Louisville 3,565 -4.8% (172) 3,393 

Louisiana New Orleans 3,565 -9.8% (348) 3,217 

Maine Portland 3,565 -0.4% (14) 3,551 

Maryland Baltimore 3,565 4.3% 153 3,718 

Massachusetts Boston 3,565 31.3% 1,115 4,680 

Michigan Detroit 3,565 3.4% 120 3,685 

Michigan Grand Rapids 3,565 -6.8% (243) 3,322 

Minnesota St. Paul 3,565 3.4% 123 3,688 

Mississippi Jackson 3,565 -6.5% (230) 3,335 

Missouri St. Louis 3,565 6.4% 227 3,792 

Missouri Kansas City 3,565 3.0% 107 3,672 

Montana Great Falls 3,565 -3.7% (131) 3,434 

Nebraska Omaha 3,565 -3.0% (108) 3,457 

New Hampshire Concord 3,565 -1.4% (49) 3,516 

New Jersey Newark 3,565 13.5% 480 4,045 
10-8

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 3,565 -3.4% (120) 3,445 

New York New York 3,565 28.4% 1,013 4,578 

New York Syracuse 3,565 9.7% 345 3,910 

Nevada Las Vegas 3,565 8.1% 290 3,855 

North Carolina Charlotte 3,565 -8.3% (296) 3,269 

North Dakota Bismarck 3,565 -6.9% (247) 3,318 

Ohio Cincinnati 3,565 0.4% 16 3,581 

Oregon Portland 3,565 8.5% 303 3,868 

Pennsylvania Philadelphia 3,565 10.6% 377 3,942 

Pennsylvania Wilkes-Barre 3,565 -3.0% (107) 3,458 

Rhode Island Providence 3,565 3.6% 129 3,694 

South Carolina Spartanburg 3,565 -10.2% (364) 3,201 

South Dakota Rapid City 3,565 -9.3% (331) 3,234 

Tennessee Knoxville 3,565 -7.7% (276) 3,289 

Texas Houston 3,565 -8.3% (294) 3,271 

Utah Salt Lake City 3,565 -2.6% (91) 3,474 

Vermont Burlington 3,565 -4.6% (162) 3,403 

Virginia Alexandria 3,565 8.8% 313 3,878 

Virginia Lynchburg 3,565 -1.6% (56) 3,509 

Washington Seattle 3,565 11.3% 404 3,969 

Washington Spokane 3,565 -2.0% (70) 3,495 

West Virginia Charleston 3,565 -1.5% (55) 3,510 

Wisconsin Green Bay 3,565 0.5% 19 3,584 

Wyoming Cheyenne 3,565 3.7% 132 3,697 

Puerto Rico Cayey 0 0 0 
10-9

TABLE 10-4 – LOCATION-BASED COSTS FOR IGCC (1,200,000 KW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,221 32.0% 1,031 4,252 

Alaska Fairbanks 3,221 30.9% 996 4,217 

Alabama Huntsville 3,221 -6.7% (216) 3,005 

Arizona Phoenix 3,221 -4.6% (147) 3,074 

Arkansas Little Rock 3,221 -4.8% (154) 3,067 

California Los Angeles 3,221 19.8% 637 3,858 

California Redding 3,221 9.6% 308 3,529 

California Bakersfield 3,221 9.2% 296 3,517 

California Sacramento 3,221 13.7% 442 3,663 

California San Francisco 3,221 40.8% 1,313 4,534 

Colorado Denver 3,221 -5.4% (173) 3,048 

Connecticut Hartford 3,221 26.0% 836 4,057 

Delaware Dover 3,221 22.7% 730 3,951 

District of Columbia Washington 3,221 39.5% 1,272 4,493 

Florida Tallahassee 3,221 -9.9% (318) 2,903 

Florida Tampa 3,221 -4.4% (143) 3,078 

Georgia Atlanta 3,221 -7.3% (235) 2,986 

Hawaii Honolulu - - 

Idaho Boise 3,221 -3.2% (102) 3,119 

Illinois Chicago 3,221 18.2% 586 3,807 

Indiana Indianapolis 3,221 3.3% 107 3,328 

Iowa Davenport 3,221 -1.4% (45) 3,176 

Iowa Waterloo 3,221 -8.1% (261) 2,960 

Kansas Wichita 3,221 -6.0% (192) 3,029 

Kentucky Louisville 3,221 -4.9% (158) 3,063 

Louisiana New Orleans 3,221 -10.1% (326) 2,895 

Maine Portland 3,221 0.0% (1) 3,220 

Maryland Baltimore 3,221 5.0% 162 3,383 

Massachusetts Boston 3,221 33.8% 1,087 4,308 

Michigan Detroit 3,221 3.5% 114 3,335 

Michigan Grand Rapids 3,221 -7.1% (227) 2,994 

Minnesota St. Paul 3,221 3.6% 117 3,338 

Mississippi Jackson 3,221 -6.6% (214) 3,007 

Missouri St. Louis 3,221 6.9% 221 3,442 

Missouri Kansas City 3,221 3.2% 103 3,324 

Montana Great Falls 3,221 -3.7% (119) 3,102 

Nebraska Omaha 3,221 -3.1% (99) 3,122 

New Hampshire Concord 3,221 -1.3% (42) 3,179 

New Jersey Newark 3,221 14.0% 449 3,670 
10-10

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 3,221 -3.4% (109) 3,112 

New York New York 3,221 29.5% 949 4,170 

New York Syracuse 3,221 10.8% 349 3,570 

Nevada Las Vegas 3,221 8.6% 278 3,499 

North Carolina Charlotte 3,221 -8.5% (273) 2,948 

North Dakota Bismarck 3,221 -7.2% (230) 2,991 

Ohio Cincinnati 3,221 0.8% 25 3,246 

Oregon Portland 3,221 9.3% 300 3,521 

Pennsylvania Philadelphia 3,221 11.0% 355 3,576 

Pennsylvania Wilkes-Barre 3,221 -3.0% (96) 3,125 

Rhode Island Providence 3,221 3.9% 124 3,345 

South Carolina Spartanburg 3,221 -10.5% (337) 2,884 

South Dakota Rapid City 3,221 -9.6% (309) 2,912 

Tennessee Knoxville 3,221 -7.9% (256) 2,965 

Texas Houston 3,221 -8.5% (275) 2,946 

Utah Salt Lake City 3,221 -2.4% (76) 3,145 

Vermont Burlington 3,221 -4.6% (148) 3,073 

Virginia Alexandria 3,221 9.9% 320 3,541 

Virginia Lynchburg 3,221 -1.3% (41) 3,180 

Washington Seattle 3,221 12.3% 395 3,616 

Washington Spokane 3,221 -1.9% (62) 3,159 

West Virginia Charleston 3,221 -1.5% (49) 3,172 

Wisconsin Green Bay 3,221 0.8% 27 3,248 

Wyoming Cheyenne 3,221 4.6% 148 3,369 

Puerto Rico Cayey 0 0 0 0 

10.5 O&M ESTIMATE 

In addition to the general O&M items discussed in Section 2.5.2, IGCC Facility includes the 

major maintenance for the CTs, as well as the BOP, including the ST, associated electric 

generators, HRSGs, and emissions reduction catalysts. Additionally, provisions need to be made 

for routine and major maintenance for the gasification systems, the ASU, and associated 

gasification auxiliary equipment needs to be made. For example, major maintenance for the 

gasifier includes repair and replacement of the refractory. Typically, significant overhauls on an 

IGCC Facility occur no less frequently than 18 months and the cycle for the power generation 

equipment is similar to the to the Advanced NGCC discussed above. Table 10-5 and Table 10-6 

present the O&M expenses for the IGCC Facility. 

TABLE 10-5 – O&M EXPENSES FOR IGCC (600,000 KW) 

Technology: IGCC 

Fixed O&M Expense $59.23/kW-year 

Variable O&M Expense $6.87/MWh 
10-11

TABLE 10-6 – O&M EXPENSES FOR IGCC (1,200,000 KW) 

Technology: IGCC 

Fixed O&M Expense $48.90/kW-year 

Variable O&M Expense $6.87/MWh 

10.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The IGCC uses syngas combustors (which do not have DLN) in the CT and best available burner 

technology with respect to the duct burners in the HRSGs to manage the production of NOX and 

CO. Additional control of NOX and CO is accomplished through an SCR and an oxidization 

catalyst, respectively. SO2 in the IGCC is managed through the removal of sulfur in the syngas 

via the AGR system prior to combustion. The IGCC does not include any control devices for 

CO2, which is proportional to the heat rate (inversely proportional to the efficiency) of the 

technology. Water, wastewater, and solid waste compliance are achieved through traditional 

on-site and off-site methods, and the costs for such compliance are included in the O&M 

Estimate for the IGCC. Table 10-7 presents environmental emissions for the IGCC Facility. 

TABLE 10-7 – ENVIRONMENTAL EMISSIONS FOR IGCC 

Technology: IGCC 

NOX 0.0075 lb/MMBtu 

SO2 0.025 lb/MMBtu 

CO2 206 lb/MMBtu 
11-1

11. INTEGRATED GASIFICATION COMBINED CYCLE WITH CCS (IGCC/CCS) 

11.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The plant configuration for the IGCC/CCS Facility case is the same as the IGCC Facility case 

with the exceptions that: (1) a water gas shift reactor system is substituted instead of the COS 

hydrolysis system upstream of the AGR; and (2) a two-stage Selexol AGR system is utilized 

instead of a single stage to allow the capture of CO2 from the syngas prior to combustion. The 

captured CO2 is compressed to approximately 2,000 psia for injection into a pipeline at the plant 

fence line. The IGCC/CCS Facility produces 690 MW of gross power and 520 MW of net 

power. Figure 11-1 presents the IGCC/CCS process flow diagram. 

FIGURE 11-1 – IGCC/CCS DESIGN CONFIGURATION

11.2 ELECTRICAL AND CONTROL SYSTEMS 

The electrical and control systems for the IGCC/CCS Facility are materially similar to the IGCC 

Facility (without CCS) discussed in Section 10.2. 

11.3 OFF-SITE REQUIREMENTS 

The off-site requirements for the IGCC/CCS Facility are materially similar to the IGCC Facility 

(without CCS) discussed in Section 10.3, except that an interconnection needs to be made with 

respect to the sequestration of CO2. 

11.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the IGCC/CCS Facility with a nominal capacity of 520 MW is 

$5,348/kW. Table 11-1 summarizes the Cost Estimate categories for the IGCC/CCS Facility. 
11-2

TABLE 11-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR IGCC/CCS 

Technology: IGCC/CCS 

Nominal Capacity (ISO): 520,000 kW 

Nominal Heat Rate (ISO): 10,700 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Total Project EPC 2,317,500 

Owner Costs (excluding project finance) 463,500 

Total Project Cost (excluding finance) 2,781,000 

Total Project EPC / kW 4,458 

Owner Costs 20% (excluding project finance) / kW 892 

Total Project Cost (excluding project finance) / kW 5,350 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

The locational considerations for the IGCC/CCS Facility are the same as those set forth in 

Section 10.4 for the IGCC Facility. 

Table 11-2 presents the IGCC/CCS Facility capital cost variations for alternative U.S. plant 

locations. 
11-3

TABLE 11-2 – LOCATION-BASED COSTS FOR IGCC/CCS 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,350 23.1% 1,236 6,586 

Alaska Fairbanks 5,350 22.9% 1,225 6,575 

Alabama Huntsville 5,350 -7.4% (397) 4,953 

Arizona Phoenix 5,350 -5.5% (293) 5,057 

Arkansas Little Rock 5,350 -5.7% (306) 5,044 

California Los Angeles 5,350 13.7% 732 6,082 

California Redding 5,350 6.5% 348 5,698 

California Bakersfield 5,350 6.1% 326 5,676 

California Sacramento 5,350 11.1% 591 5,941 

California San Francisco 5,350 30.7% 1,642 6,992 

Colorado Denver 5,350 -6.3% (335) 5,015 

Connecticut Hartford 5,350 17.7% 946 6,296 

Delaware Dover 5,350 14.5% 774 6,124 

District of Columbia Washington 5,350 23.0% 1,229 6,579 

Florida Tallahassee 5,350 -10.5% (561) 4,789 

Florida Tampa 5,350 -4.5% (243) 5,107 

Georgia Atlanta 5,350 -8.1% (432) 4,918 

Hawaii Honolulu 0 0 0 0 

Idaho Boise 5,350 -4.2% (227) 5,123 

Illinois Chicago 5,350 17.9% 959 6,309 

Indiana Indianapolis 5,350 1.2% 67 5,417 

Iowa Davenport 5,350 -1.5% (82) 5,268 

Iowa Waterloo 5,350 -8.9% (474) 4,876 

Kansas Wichita 5,350 -6.9% (370) 4,980 

Kentucky Louisville 5,350 -5.8% (309) 5,041 

Louisiana New Orleans 5,350 -10.8% (577) 4,773 

Maine Portland 5,350 -2.8% (151) 5,199 

Maryland Baltimore 5,350 1.1% 60 5,410 

Massachusetts Boston 5,350 26.2% 1,402 6,752 

Michigan Detroit 5,350 3.5% 185 5,535 

Michigan Grand Rapids 5,350 -7.7% (413) 4,937 

Minnesota St. Paul 5,350 3.4% 181 5,531 

Mississippi Jackson 5,350 -7.4% (394) 4,956 

Missouri St. Louis 5,350 5.5% 295 5,645 

Missouri Kansas City 5,350 2.7% 145 5,495 

Montana Great Falls 5,350 -4.8% (259) 5,091 

Nebraska Omaha 5,350 -3.8% (201) 5,149 

New Hampshire Concord 5,350 -2.2% (119) 5,231 

New Jersey Newark 5,350 14.9% 795 6,145 
11-4

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 5,350 -4.4% (235) 5,115 

New York New York 5,350 31.4% 1,681 7,031 

New York Syracuse 5,350 5.5% 295 5,645 

Nevada Las Vegas 5,350 7.7% 410 5,760 

North Carolina Charlotte 5,350 -10.1% (538) 4,812 

North Dakota Bismarck 5,350 -7.8% (419) 4,931 

Ohio Cincinnati 5,350 -1.5% (82) 5,268 

Oregon Portland 5,350 6.2% 333 5,683 

Pennsylvania Philadelphia 5,350 11.3% 602 5,952 

Pennsylvania Wilkes-Barre 5,350 -4.1% (217) 5,133 

Rhode Island Providence 5,350 3.4% 183 5,533 

South Carolina Spartanburg 5,350 -12.0% (640) 4,710 

South Dakota Rapid City 5,350 -10.5% (562) 4,788 

Tennessee Knoxville 5,350 -9.1% (486) 4,864 

Texas Houston 5,350 -9.3% (499) 4,851 

Utah Salt Lake City 5,350 -4.6% (245) 5,105 

Vermont Burlington 5,350 -5.8% (311) 5,039 

Virginia Alexandria 5,350 4.5% 241 5,591 

Virginia Lynchburg 5,350 -3.8% (203) 5,147 

Washington Seattle 5,350 9.4% 505 5,855 

Washington Spokane 5,350 -2.9% (154) 5,196 

West Virginia Charleston 5,350 -2.1% (111) 5,239 

Wisconsin Green Bay 5,350 -1.1% (58) 5,292 

Wyoming Cheyenne 5,350 -0.5% (29) 5,321 

Puerto Rico Cayey 0 0 0 0 

11.5 O&M ESTIMATE 

The O&M methodology for the IGCC/CCS Facility is the same as that set forth in the section on 

the IGCC Facility, except that consideration needs to be made for the additional maintenance 

resulting from the CCS equipment. 

Table 11-3 presents the O&M expenses for the IGCC/CCS Facility. 

TABLE 11-3 – O&M EXPENSES FOR IGCC/CCS 

Technology: IGCC/CCS 

Fixed O&M Expense $69.30/kW-year 

Variable O&M Expense $8.04/MWh 

11.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The environmental compliance strategy for the IGCC/CCS Facility is the same as that set forth in 

the section on the IGCC Facility, except for CCS including a two-stage Selexol AGR for capture 

of CO2. Table 11-4 presents environmental emissions for the IGCC/CCS Facility. 
11-5

TABLE 11-4 – ENVIRONMENTAL EMISSIONS FOR IGCC/CCS 

Technology: IGCC/CCS 

NOX 0.0075 lb/MMBtu 

SO2 0.015 lb/MMBtu 

CO2 20.6 lb/MMBtu 
12-1

12. ADVANCED NUCLEAR (AN) 

12.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Advanced Nuclear (“AN”) Facility consists of two 1,117 MW Westinghouse AP1000 

nuclear power units built in a brownfield (existing nuclear facility site). 

The steam cycle of a nuclear powered electric generation facility is similar to other 

steam-powered generating facilities. The difference is with the source of heat used to generate 

steam. In units that use fossil fuels, hydrocarbons are burned to heat water, producing steam. In 

the AP1000, splitting the nucleus (fission) of uranium atoms provides the energy to heat the 

water. 

Nuclear fuel is a uranium dioxide ceramic pellet encased in a zirconium alloy tube. The uranium 

atoms in the pellet absorb neutrons and split, or fission. When the uranium atom splits, a large 

amount of energy, as well as additional neutrons and fission fragments are released. The 

neutrons can be absorbed by other uranium atoms which fission, producing more neutrons. The 

chain reaction is controlled by controlling the number of neutrons available for fission. The 

number of neutrons available is controlled by the water in the nuclear reactor core, the 

arrangement of neutron absorbing control rods inserted into the core, the design of the core, and 

by controlling the void fraction and temperature of the coolant water (which both affect the 

density of water which affects the neutrons available for the fission process). 

The uranium fuel is contained inside a pressurized water reactor (“PWR”). The AP1000 is a 

two-loop PWR. The fission of the uranium fuel releases heat to the surrounding water (reactor 

cooling water), which under pressure does not boil, but through a heat exchanger (typically 

referred to as a steam generator) results in a lower pressure water (that in the “secondary loop”) 

to boil. 

The cooling water inside the PWR is circulated through the nuclear core by internal pumps. This 

cooling water system is termed the Reactor Coolant System (“RCS”). The RCS consists of two 

heat transfer circuits, with each circuit containing one Delta-125 steam generator, two reactor 

coolant pumps, and a single hot leg and two cold legs for circulating coolant between the reactor 

and the steam generators. The system also includes a pressurizer, interconnecting piping, and the 

valves and instrumentation necessary for operational control and the actuation of safeguards. 

Each AP1000 unit has a 130-foot diameter freestanding containment vessel with four ring 

sections and an upper and lower head. 

The passive core cooling system provides protection for the facility against RCS leaks and 

ruptures. The passive containment cooling system is the ultimate safety-related ultimate heat 

sink for the facility. The passive containment cooling system cools the containment following an 

accident to rapidly reduce the pressure via the natural circulation of air supplemented by water 

evaporation to transfer heat through the steel containment vessel. 

Main steam from the steam generator is routed to the HP section of the ST. The ST consists of a 

double-flow HP ST section and three double-flow LP ST sections in a tandem-compound 

configuration. As the steam exits the HP section it passes through a moisture separator and 

reheater. The moisture separator and reheater dries and reheats the steam before it enters the LP 

ST section, which improves the cycle efficiency and reduces moisture related erosion of the LP 

ST blades. A portion of the steam is extracted from the HP and LP sections of the ST and with 
12-2

ST exhaust heats the condensate and feedwater before it is sent back to the reactor. The HP and 

LP STs are connected via a common shaft that drives the generator which produces the electrical 

power output of approximately 1,100 MW per unit. 

The steam that exits the LP section of the ST, as well as the drains from the feedwater heaters, 

are directed to the condenser. The condenser is a surface condensing (tube type) heat exchanger 

that is maintained under vacuum to increase the turbine efficiency. The steam condenses on the 

outside of the tubes and condenser cooling water is circulated through the inside of the tubes. 

Numerous other systems are needed to support and provide redundancy for the cycle process 

described herein. These include the residual heat removal system, the HP core flooder system, 

and the LP core flooder system which are redundant systems and are designed to remove heat 

from the reactor core in the event the normal core cooling system fails. Other support systems 

include the liquid and solid radioactive waste systems which handle, control, and process 

radioactive waste from the plant. The reactor containment ventilation system controls and filters 

airborne radiation. Figure 12-1 presents a simplified process flow diagram for a PWR AN plant. 

FIGURE 12-1 – AN DESIGN CONFIGURATION

12.2 ELECTRICAL AND CONTROL SYSTEMS 

The AN Facility has one ST electric generator for each reactor. Each generator is a 60 Hz 

machine rated at approximately 1,250 MVA with an output voltage of 24 kV. The ST electric 

generator is connected through a generator circuit breaker to a GSU that is in turn connected 

between two circuit breakers in the high-voltage bus in the facility switchyard through a 

disconnect switch. The GSU increases the voltage from the electric generator from 24 kV to 

interconnected transmission system high voltage. 
12-3

The AN Facility is controlled using a DCS. The DCS provides centralized control of the facility 

by integrating the control systems provided with the reactor, ST and associated electric generator 

and the control of BOP systems and equipment. 

12.3 OFF-SITE REQUIREMENTS 

Water for all processes at the AN Facility is obtained from one of several available water supply 

options; however, water is typically sourced from an adjacent river, when possible. The 

AN Facility uses a water treatment system and a high-efficiency reverse osmosis system to 

reduce the dissolved solids from the cooling water and to provide distilled water. Wastewater is 

sent to an adjacent river or other approved wastewater delivery point. Further, the electrical 

interconnection from the AN on-site switchyard is effectuated by a connection to an adjacent 

utility substation. 

12.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the AN Facility with a nominal capacity of 2,236 MW is $5,339/kW. 

Table 12-1 summarizes the Cost Estimate categories for the AN Facility. 
12-4

TABLE 12-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR AN 

Technology: AN 

Nominal Capacity (ISO): 2,236,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 1,732,000 

Mechanical Equipment Supply and 

Installation 3,400,000 

Electrical / I&C Supply and Installation 630,000 

Project Indirects (1) 2,722,500 

EPC Cost before Contingency and Fee 8,484,500 

Fee and Contingency 1,300,000 

Total Project EPC 9,784,500 

Owner Costs (excluding project finance) 2,152,590 

Total Project Cost (excluding finance) 11,937,090 

Total Project EPC / kW 4,376 

Owner Costs 22% (excluding project finance) / kW 963 

Total Project Cost (excluding project finance) / kW 5,339 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, remote location issues, labor wage and 

productivity differences, location adjustments, owner cost differences, and the increase in 

overheads associated with these five adjustments. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the Advanced Nuclear Facility 
12-5

include Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; 

and Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the AN Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 12-2 presents the AN Facility capital cost variations for alternative U.S. plant locations. 

TABLE 12-2 – LOCATION-BASED COSTS FOR AN 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,340 16.3% 868 6,208 

Alaska Fairbanks 5,340 16.4% 878 6,218 

Alabama Huntsville 5,340 -3.3% (174) 5,166 

Arizona Phoenix 5,340 -2.4% (126) 5,214 

Arkansas Little Rock 5,340 -2.5% (131) 5,209 

California Los Angeles 5,340 9.5% 505 5,845 

California Redding 5,340 4.6% 245 5,585 

California Bakersfield 5,340 4.4% 236 5,576 

California Sacramento 5,340 6.5% 348 5,688 

California San Francisco 5,340 20.9% 1,114 6,454 

Colorado Denver 5,340 -2.6% (136) 5,204 

Connecticut Hartford 5,340 14.7% 784 6,124 

Delaware Dover 5,340 13.2% 707 6,047 

District of Columbia Washington 5,340 23.9% 1,275 6,615 

Florida Tallahassee 5,340 -4.6% (248) 5,092 

Florida Tampa 5,340 -2.1% (114) 5,226 

Georgia Atlanta 5,340 -3.5% (189) 5,151 

Hawaii Honolulu 0 0 0 0 

Idaho Boise 5,340 -1.6% (86) 5,254 

Illinois Chicago 5,340 9.0% 479 5,819 

Indiana Indianapolis 5,340 2.0% 108 5,448 

Iowa Davenport 5,340 -0.6% (35) 5,305 

Iowa Waterloo 5,340 -3.7% (200) 5,140 

Kansas Wichita 5,340 -2.8% (151) 5,189 

Kentucky Louisville 5,340 -2.4% (126) 5,214 
12-6

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Louisiana New Orleans 5,340 -4.8% (254) 5,086 

Maine Portland 5,340 0.4% 21 5,361 

Maryland Baltimore 5,340 3.4% 180 5,520 

Massachusetts Boston 5,340 18.3% 976 6,316 

Michigan Detroit 5,340 1.6% 83 5,423 

Michigan Grand Rapids 5,340 -3.3% (174) 5,166 

Minnesota St. Paul 5,340 1.9% 99 5,439 

Mississippi Jackson 5,340 -3.2% (173) 5,167 

Missouri St. Louis 5,340 2.8% 148 5,488 

Missouri Kansas City 5,340 1.3% 70 5,410 

Montana Great Falls 5,340 -1.9% (100) 5,240 

Nebraska Omaha 5,340 -1.5% (80) 5,260 

New Hampshire Concord 5,340 -0.8% (41) 5,299 

New Jersey Newark 5,340 6.4% 340 5,680 

New Mexico Albuquerque 5,340 -1.6% (83) 5,257 

New York New York 5,340 13.4% 718 6,058 

New York Syracuse 5,340 6.6% 355 5,695 

Nevada Las Vegas 5,340 4.1% 220 5,560 

North Carolina Charlotte 5,340 -4.1% (218) 5,122 

North Dakota Bismarck 5,340 -3.3% (176) 5,164 

Ohio Cincinnati 5,340 0.8% 45 5,385 

Oregon Portland 5,340 4.5% 239 5,579 

Pennsylvania Philadelphia 5,340 4.9% 263 5,603 

Pennsylvania Wilkes-Barre 5,340 -1.5% (82) 5,258 

Rhode Island Providence 5,340 1.6% 87 5,427 

South Carolina Spartanburg 5,340 -5.1% (272) 5,068 

South Dakota Rapid City 5,340 -4.4% (237) 5,103 

Tennessee Knoxville 5,340 -3.7% (200) 5,140 

Texas Houston 5,340 -3.9% (210) 5,130 

Utah Salt Lake City 5,340 -1.5% (80) 5,260 

Vermont Burlington 5,340 -2.3% (122) 5,218 

Virginia Alexandria 5,340 6.2% 332 5,672 

Virginia Lynchburg 5,340 -0.1% (6) 5,334 

Washington Seattle 5,340 5.8% 311 5,651 

Washington Spokane 5,340 -1.0% (56) 5,284 

West Virginia Charleston 5,340 -0.8% (42) 5,298 

Wisconsin Green Bay 5,340 1.0% 51 5,391 

Wyoming Cheyenne 5,340 3.5% 188 5,528 

Puerto Rico Cayey 0 0 0 0 
12-7

12.5 O&M ESTIMATE 

In addition to the general items discussed in the section of this report entitled O&M Estimate, the 

AN Facility includes provisions for major maintenance on the steam generators, STs, electric 

generators, BOP systems, and the reactor (beyond refueling). Table 12-3 presents the O&M 

expenses for the AN Facility. 

TABLE 12-3 – O&M EXPENSES FOR AN 

Technology: AN 

Fixed O&M Expense $88.75/kW-year 

Variable O&M Expense $2.04/MWh 

12.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Environmental compliance with respect to air emissions is effectively not necessary for the AN 

Facility, as this technology does not combust a fuel as is the case for other non-renewable power 

technologies. While there are environmental compliance considerations for a given nuclear 

facility (e.g., spent nuclear fuel), only air emissions were considered in this report. Table 12-4 

presents environmental emissions for the AN Facility. 

TABLE 12-4 – ENVIRONMENTAL EMISSIONS FOR AN 

Technology: AN 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 
13-1

13. BIOMASS COMBINED CYCLE (BCC) 

13.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Biomass Combined-Cycle (“BCC”) Facility utilizes approximately 500 tons per day of 

wood (at 25 percent moisture), or 370 dry tons per day for the production of 20 MW net of 

electricity. The facility consists of a biomass gasification system for the conversion of the wood 

to syngas, a clean-up system for the syngas, and a combined-cycle plant using the syngas as fuel. 

The gasification system consists of dual circulating fluid bed (“CFB”) units (one gasifier and one 

combustor) connected by a sand circulation system. Related equipment includes the wood feed 

system, the product gas quench, ash handling, steam supply and typical BOP equipment. 

The wood is fed to the circulating fluid bed gasifier through a standard system of lock hoppers, 

live bottom bins and feed screws. The lock hoppers are purged with nitrogen to keep the 

produced fuel gas from escaping.

The gasifier is a refractory-lined vessel with a sand-type carrier and requires a LP steam source. 

The primary purpose of the steam is to maintain a reducing environment in the gasifier to enable 

pure gasification and not partial oxidation conditions. The gasification CFB is essentially an 

entrained flow reactor, which operates between 1,400°F and 1,500°F. The two products of the 

gasifier are a medium-heating value gas (approximately 450 Btu/scf dry) and non-converted 

char. A small amount of condensable “tars” are also produced. The gases are directed to a 

clean-up system to remove the entrained tars. 

The CFB combustor unit burns the char produced in the gasifier. The char combustor operates at 

approximately 1,800°F. The flue gas from the char combustor goes to a boiler to recover the 

excess sensible energy. 

The two CFBs are connected by the sand circulation system. The purpose of this system is to 

transfer the char and circulating sand from the gasifier to the combustor, where the char is 

burned to reheat the sand. This hotter sand is then returned to the gasifier to provide the energy 

to convert the solid wood to a gas. The sand transfer system consists of mechanical cyclones 

(two in series for each CFB) and a sand inventory pot for each leg of the configuration. An 

overflow system, with some fluidizing steam in the pot, is used to regulate the flow from the 

gasifier to the combustor. 

The syngas clean-up system consists of a reformer to convert the tars and other hydrocarbons to 

CO and hydrogen in an isothermal fluidized bed reactor. The hot syngas is cooled by producing 

steam to be used in the combined cycle. A wet scrubber removes particulates, NH3 and residual 

tars. The excess scrubber water is sent off-site to a wastewater treatment facility. 

The syngas is then compressed to the required pressure for use in the CT. The BCC Facility is 

based on a single CT, which produces approximately 15 MW of electricity. The CT exhaust is 

sent to an HRSG. The HRSG is equipped with an SCR to reduce NOX emissions. Both the 

steam generated in the HRSG and the steam generated the cooling of the combustion flue gas 

and the syngas are superheated and sent to the ST. The ST output is approximately 9 MW. The 

total gross output is approximately 24 MW. The internal power load is approximately 4 MW for 

a net power output of about 20 MW. 
13-2

Nitrogen is required for start-up and shutdown. A separate steam system is required for start-up. 

NH3 is required for operation of the two SCRs for reducing NOX emissions. A flare system is 

required for normal operation to eliminate volatile organics from the scrubbing system, and for 

start-up and shutdown of the process. Figure 13-1 presents the BCC process flow diagram, 

where the “Power Block” is based on a traditional combined-cycle configuration, as is often the 

case for gasification derivative plants. 

FIGURE 13-1 – BCC DESIGN CONFIGURATION

13.2 ELECTRICAL AND CONTROL SYSTEMS 

The BCC Facility has one CT electric generator and one ST electric generator. The generator for 

the CT is a 60 Hz machine rated at approximately 17 MVA with an output voltage of 13.8 kV. 

The ST electric generator is a 60 Hz machine rated at approximately 10 MVA with an output 

voltage of 13.8 kV. The generator breakers for the CT and ST electric generators are bussed 

together in 15 kV class switchgear that is connected to a high-voltage transmission system at the 

facility switchyard via a circuit breaker, GSU, and a disconnect switch. The GSU increases the 

voltage from the electric generators from 13.8 kV to interconnected transmission system high 

voltage. 

The BCC Facility is controlled using a DCS. The DCS provides centralized control of the 

facility by integrating the control systems provided with each individual CT and associated 
13-3

electric generator, ST and associated electric generator, and the control of BOP systems and 

equipment. 

13.3 OFF-SITE REQUIREMENTS 

Biomass is delivered to the BCC Facility by rail, truck or barge. Water for all processes at the 

BCC Facility is obtained from one of several available water sources. The BCC Facility uses a 

water treatment system and a high-efficiency reverse osmosis system to reduce the dissolved 

solids from the cooling water and to provide distilled water for HRSG makeup. Wastewater is 

sent to a municipal wastewater system or other available wastewater delivery point. Further, the 

electrical interconnection from the BCC Facility on-site switchyard is effectuated by a 

connection to an adjacent utility substation. 

13.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the BCC Facility with a nominal capacity of 20 MW is $7,573/kW. 

Table 13-1 summarizes the Cost Estimate categories for the BCC Facility. 
13-4

TABLE 13-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR BCC 

Technology: BCC 

Nominal Capacity (ISO): 20,000 kW 

Nominal Heat Rate (ISO): 12,350 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 16,459 

Mechanical Equipment Supply and 

Installation 70,137 

Electrical / I&C Supply and Installation 11,267 

Project Indirects (1) 21,207 

EPC Cost before Contingency and Fee 119,070 

Fee and Contingency 12,500 

Total Project EPC 131,570 

Owner Costs (excluding project finance) 26,314 

Total Project Cost (excluding finance) 157,884 

Total Project EPC / kW 6,578 

Owner Costs 20% (excluding project finance) / kW 1,316 

Total Project Cost (excluding project finance) / kW 7,894 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: outdoor installation considerations, seismic design differences, 

remote location issues, labor wage and productivity differences, location adjustments, owner cost 

differences, and the increase in overheads associated with these six adjustments. 

Outdoor installation locations are considered in geographic areas where enclosed structures for 

the boilers would not be required due to the low probability of freezing. The locations that 

included outdoor installation are Alabama, Arizona, Arkansas, Florida, Georgia, Hawaii, 

Louisiana, Mississippi, New Mexico, South Carolina, and Puerto Rico. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 
13-5

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the BCC include Fairbanks, 

Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and Cayey, Puerto 

Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the BCC Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 13-2 presents the BCC Facility capital cost variations for alternative U.S. plant locations. 
13-6

TABLE 13-2 – LOCATION-BASED COSTS FOR BCC 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 7,900 14.0% 1,104 9,004 

Alaska Fairbanks 7,900 15.2% 1,197 9,097 

Alabama Huntsville 7,900 -6.0% (472) 7,428 

Arizona Phoenix 0 0.0% 0 0 

Arkansas Little Rock 7,900 -5.0% (392) 7,508 

California Los Angeles 7,900 7.2% 566 8,466 

California Redding 7,900 3.3% 262 8,162 

California Bakersfield 7,900 3.0% 237 8,137 

California Sacramento 7,900 6.8% 539 8,439 

California San Francisco 7,900 19.6% 1,547 9,447 

Colorado Denver 7,900 -9.2% (724) 7,176 

Connecticut Hartford 7,900 11.9% 940 8,840 

Delaware Dover 7,900 9.7% 768 8,668 

District of Columbia Washington 7,900 15.1% 1,196 9,096 

Florida Tallahassee 7,900 -8.0% (635) 7,265 

Florida Tampa 7,900 -3.5% (274) 7,626 

Georgia Atlanta 7,900 -6.5% (511) 7,389 

Hawaii Honolulu 7,900 29.3% 2,311 10,211 

Idaho Boise 7,900 -3.9% (304) 7,596 

Illinois Chicago 7,900 13.6% 1,073 8,973 

Indiana Indianapolis 7,900 0.4% 35 7,935 

Iowa Davenport 7,900 -1.2% (93) 7,807 

Iowa Waterloo 7,900 -6.8% (539) 7,361 

Kansas Wichita 7,900 -5.6% (444) 7,456 

Kentucky Louisville 7,900 -4.7% (375) 7,525 

Louisiana New Orleans 7,900 -8.3% (653) 7,247 

Maine Portland 7,900 -3.0% (236) 7,664 

Maryland Baltimore 7,900 0.1% 10 7,910 

Massachusetts Boston 7,900 18.5% 1,459 9,359 

Michigan Detroit 7,900 2.4% 188 8,088 

Michigan Grand Rapids 7,900 -5.9% (469) 7,431 

Minnesota St. Paul 7,900 2.5% 200 8,100 

Mississippi Jackson 7,900 -5.9% (469) 7,431 

Missouri St. Louis 7,900 2.8% 220 8,120 

Missouri Kansas City 7,900 1.5% 119 8,019 

Montana Great Falls 7,900 -4.8% (379) 7,521 

Nebraska Omaha 7,900 -3.2% (252) 7,648 

New Hampshire Concord 7,900 -2.3% (182) 7,718 

New Jersey Newark 7,900 11.2% 882 8,782 
13-7

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 0 0.0% 0 0 

New York New York 7,900 23.6% 1,866 9,766 

New York Syracuse 7,900 3.3% 259 8,159 

Nevada Las Vegas 0 0.0% 0 0 

North Carolina Charlotte 7,900 -8.3% (658) 7,242 

North Dakota Bismarck 7,900 -6.0% (476) 7,424 

Ohio Cincinnati 7,900 -1.7% (134) 7,766 

Oregon Portland 7,900 3.1% 246 8,146 

Pennsylvania Philadelphia 7,900 8.1% 639 8,539 

Pennsylvania Wilkes-Barre 7,900 -3.7% (293) 7,607 

Rhode Island Providence 7,900 2.1% 162 8,062 

South Carolina Spartanburg 7,900 -9.8% (771) 7,129 

South Dakota Rapid City 7,900 -8.1% (639) 7,261 

Tennessee Knoxville 7,900 -7.3% (575) 7,325 

Texas Houston 7,900 -7.2% (568) 7,332 

Utah Salt Lake City 0 0.0% 0 0 

Vermont Burlington 7,900 -5.1% (400) 7,500 

Virginia Alexandria 7,900 2.5% 198 8,098 

Virginia Lynchburg 7,900 -3.4% (271) 7,629 

Washington Seattle 7,900 5.6% 441 8,341 

Washington Spokane 7,900 -2.8% (222) 7,678 

West Virginia Charleston 7,900 -1.9% (149) 7,751 

Wisconsin Green Bay 7,900 -1.1% (83) 7,817 

Wyoming Cheyenne 0 0.0% 0 0 

Puerto Rico Cayey 7,900 -3.7% (290) 7,610 

13.5 O&M ESTIMATE 

In addition to the general items discussed in the section of this report entitled O&M Estimate, the 

BCC Facility include the major maintenance for the CT, as well as the BOP, including the ST, 

associated electric generator, HRSG, and emissions reduction catalysts. These major 

maintenance expenses are included with the VOM expense for this technology and are given on 

an average basis across the MWhs incurred. Typically, significant overhauls on a BCC Facility 

occur no less frequently than 8,000 operating hour intervals, with more significant major outages 

occurring on 24,000 hour intervals. Additionally, major maintenance needs to be completed on 

the gasifier, including the refractory, which due to the lower operating temperature (as compared 

to the IGCC Facility discussed above) only needs replacing approximately every 10 years. 

Table 13-3 presents the O&M expenses for the BCC Facility. 

TABLE 13-3 – O&M EXPENSES FOR BCC 

Technology: BCC 

Fixed O&M Expense $338.79/kW-year 

Variable O&M Expense $16.64/MWh 
13-8

13.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The BCC Facility utilizes syngas combustors (which do not have DLN) in the CT and best 

available burner technology with respect to the duct burners in the HRSGs to manage the 

production of NOX and CO. Additional control of NOX and CO is accomplished through an SCR 

and an oxidization catalyst, respectively. SO2 in the IGCC is managed through the use of lowsulfur biomass feedstocks. The BCC does not include any control devices for CO2, which is 

proportional to the heat rate (inversely proportional to the efficiency) of the technology. Water, 

wastewater, and solid waste compliance are achieved through traditional on-site and off-site 

methods, and the costs for such compliance are included in the O&M Estimate for the BCC 

Facility. Table 13-4 presents environmental emissions for the BCC Facility. 

TABLE 13-4 – ENVIRONMENTAL EMISSIONS FOR BCC 

Technology: BCC 

NOX 0.054 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 195 lb/MMBtu 
14-1

14. BIOMASS BUBBLING FLUIDIZED BED (BBFB) 

14.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Biomass BFB (“BBFB”) Facility utilizes approximately 2,000 tons per day of wood (at 

50 percent maximum moisture) for the production of 50 MW net of electricity. The BBFB 

Facility consists of a BFB boiler, which will flow to the ST. Steam leaving the ST will be 

condensed to water in a shell and tube surface condenser. The water will be pumped from the 

“hotwell” of the condenser through a series of feedwater heaters for purposes of pre-heating the 

water with ST extraction steam. The combination of feedwater heating and waste heat flowing 

through the economizer is included to improve cycle efficiency. The water will enter the first 

feedwater heater where it will be heated using extraction steam from the ST. The water will then 

flow to the deaerating feedwater heater and into an electric-driven boiler feed pump where the 

pressure of the water will be increased to approximately 1,800 psia. After leaving the boiler feed 

pump, the water will flow through two more feedwater heaters. After exiting the last feedwater 

heater, the water will flow to the economizer section of the BFB boiler for delivery to the 

combustion section where it will be converted back to steam and the cycle will be repeated. The 

cooling tower is to be used to cool the circulating water that is used to condense the steam inside 

the condenser. 

In a BFB boiler, a portion of air is introduced through the bottom of the combustor. The bottom 

of the bed is supported by refractory walls or water-cooled membrane with specially designed air 

nozzles which distribute the air uniformly. The fuel and limestone are fed into the lower bed. In 

the presence of fluidizing air, the fuel and limestone quickly and uniformly mix under the 

turbulent environment and behave like a fluid. Carbon particles in the fuel are exposed to the 

combustion air. The balance of combustion air is introduced at the top of the lower, dense bed. 

This staged combustion limits the formation of NOX. The advantages of BFB boiler technology 

include fuel flexibility, low SO2 emissions, low NOX emissions, and high combustion efficiency. 

FIGURE 14-1 – BCC DESIGN CONFIGURATION
14-2

14.2 ELECTRICAL AND CONTROL SYSTEMS 

The BBFB Facility has one ST electric generator. The generator for the ST is a 60 Hz machine 

rated at approximately 65 MVA with an output voltage of 13.8 kV. The generator breakers for 

the ST electric generator are bussed together in 15 kV class switchgear that is connected to a 

high-voltage transmission system at the facility switchyard via a circuit breaker, GSU, and a 

disconnect switch. The GSU increases the voltage from the electric generators from 13.8 kV to 

interconnected transmission system high voltage. 

The BBFB Facility is controlled using a DCS. The DCS provides centralized control of the 

facility by integrating the control systems provided with the ST and associated electric generator 

and the control of BOP systems and equipment. 

14.3 OFF-SITE REQUIREMENTS 

Biomass is delivered to the BBFB Facility by rail, truck or barge. Water for all processes at the 

BBFB Facility is obtained from one of several available water sources. The BBFB Facility uses 

a water treatment system and a high-efficiency reverse osmosis system to reduce the dissolved 

solids from the cooling water and to provide distilled water for HRSG makeup. Wastewater is 

sent to a municipal wastewater system or other available wastewater delivery point. Further, the 

electrical interconnection from the BBFB Facility on-site switchyard is effectuated by a 

connection to an adjacent utility substation. 

14.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the BBFB Facility with a nominal capacity of 50 MW is $3,860/kW. 

Table 14-1 summarizes the Cost Estimate categories for the BBFB Facility. 
14-3

TABLE 14-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR BBFB 

Technology: BBFB 

Nominal Capacity (ISO): 50,000 kW 

Nominal Heat Rate (ISO): 13,500 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 13,650 

Mechanical Equipment Supply and 

Installation 67,200 

Electrical / I&C Supply and Installation 20,000 

Project Indirects (1) 40,250 

EPC Cost before Contingency and Fee 141,100 

Fee and Contingency 19,754 

Total Project EPC 160,854 

Owner Costs (excluding project finance) 32,171 

Total Project Cost (excluding finance) 193,025 

Total Project EPC / kW 3,217 

Owner Costs 20% (excluding project finance) / kW 643 

Total Project Cost (excluding project finance) / kW 3,860 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: outdoor installation considerations, seismic design differences, 

remote location issues, labor wage and productivity differences, location adjustments, owner cost 

differences, and the increase in overheads associated with these six adjustments. 

Outdoor installation locations are considered in geographic areas where enclosed structures for 

the boilers would not be required due to the low probability of freezing. The locations that 

included outdoor installation are Alabama, Arizona, Arkansas, Florida, Georgia, Hawaii, 

Louisiana, Mississippi, New Mexico, South Carolina, and Puerto Rico. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 
14-4

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the BCC include Fairbanks, 

Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and Cayey, Puerto 

Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the BCC Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 14-2 presents the BBFB Facility capital cost variations for alternative U.S. plant locations. 
14-5

TABLE 14-2– LOCATION-BASED COSTS FOR BBFB 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,860 25.8% 995 4,855 

Alaska Fairbanks 3,860 27.9% 1,076 4,936 

Alabama Huntsville 3,860 -9.7% (376) 3,484 

Arizona Phoenix 0 0.0% 0 0 

Arkansas Little Rock 3,860 -8.1% (311) 3,549 

California Los Angeles 3,860 13.4% 516 4,376 

California Redding 3,860 6.3% 242 4,102 

California Bakersfield 3,860 5.7% 221 4,081 

California Sacramento 3,860 11.9% 460 4,320 

California San Francisco 3,860 35.6% 1,373 5,233 

Colorado Denver 3,860 -8.2% (318) 3,542 

Connecticut Hartford 3,860 22.9% 882 4,742 

Delaware Dover 3,860 19.3% 745 4,605 

District of Columbia Washington 3,860 31.6% 1,219 5,079 

Florida Tallahassee 3,860 -13.1% (506) 3,354 

Florida Tampa 3,860 -5.7% (221) 3,639 

Georgia Atlanta 3,860 -10.5% (407) 3,453 

Hawaii Honolulu 3,860 58.2% 2,248 6,108 

Idaho Boise 3,860 -6.2% (238) 3,622 

Illinois Chicago 3,860 22.7% 875 4,735 

Indiana Indianapolis 3,860 1.5% 56 3,916 

Iowa Davenport 3,860 -1.9% (74) 3,786 

Iowa Waterloo 3,860 -11.0% (426) 3,434 

Kansas Wichita 3,860 -9.1% (350) 3,510 

Kentucky Louisville 3,860 -7.6% (295) 3,565 

Louisiana New Orleans 3,860 -13.5% (520) 3,340 

Maine Portland 3,860 -4.0% (156) 3,704 

Maryland Baltimore 3,860 1.6% 63 3,923 

Massachusetts Boston 3,860 33.5% 1,292 5,152 

Michigan Detroit 3,860 3.9% 150 4,010 

Michigan Grand Rapids 3,860 -9.6% (371) 3,489 

Minnesota St. Paul 3,860 4.3% 166 4,026 

Mississippi Jackson 3,860 -9.7% (373) 3,487 

Missouri St. Louis 3,860 4.7% 181 4,041 

Missouri Kansas City 3,860 2.5% 96 3,956 

Montana Great Falls 3,860 -4.8% (185) 3,675 

Nebraska Omaha 3,860 -5.1% (198) 3,662 

New Hampshire Concord 3,860 -3.6% (141) 3,719 

New Jersey Newark 3,860 18.1% 698 4,558 
14-6

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 0 0.0% 0 0 

New York New York 3,860 38.3% 1,477 5,337 

New York Syracuse 3,860 7.5% 288 4,148 

Nevada Las Vegas 0 0.0% 0 0 

North Carolina Charlotte 3,860 -13.4% (517) 3,343 

North Dakota Bismarck 3,860 -9.7% (376) 3,484 

Ohio Cincinnati 3,860 -2.0% (77) 3,783 

Oregon Portland 3,860 5.9% 228 4,088 

Pennsylvania Philadelphia 3,860 13.1% 507 4,367 

Pennsylvania Wilkes-Barre 3,860 -5.9% (229) 3,631 

Rhode Island Providence 3,860 3.4% 131 3,991 

South Carolina Spartanburg 3,860 -15.8% (611) 3,249 

South Dakota Rapid City 3,860 -13.1% (505) 3,355 

Tennessee Knoxville 3,860 -11.7% (453) 3,407 

Texas Houston 3,860 -11.6% (449) 3,411 

Utah Salt Lake City 0 0.0% 0 0 

Vermont Burlington 3,860 -8.1% (314) 3,546 

Virginia Alexandria 3,860 6.2% 240 4,100 

Virginia Lynchburg 3,860 -4.8% (186) 3,674 

Washington Seattle 3,860 9.9% 382 4,242 

Washington Spokane 3,860 -4.5% (172) 3,688 

West Virginia Charleston 3,860 -3.0% (117) 3,743 

Wisconsin Green Bay 3,860 -1.0% (39) 3,821 

Wyoming Cheyenne 0 0.0% 0 0 

Puerto Rico Cayey 3,860 -5.5% (213) 3,647 

14.5 O&M ESTIMATE 

In addition to the general items discussed in the section of this report entitled O&M Estimate, the 

BBFB Facility includes the major maintenance for the ST and associated electric generator, as 

well as the BOP. These major maintenance expenses are included with the VOM expense for 

this technology and are given on an average basis across the MWhs incurred. Typically, 

significant overhauls on a BBFB Facility occur no less frequently than 6 to 8 years. Table 14-3 

presents the O&M expenses for the BBFB Facility. 

TABLE 14-3 – O&M EXPENSES FOR BCC 

Technology: BCC 

Fixed O&M Expense $100.50/kW-year 

Variable O&M Expense $5.0/MWh 
14-7

14.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The BBFB Facility utilizes BFB combustion to control NOX and CO. SO2 in the BFB is 

managed through the use of low-sulfur biomass feedstocks. The BBFB Facility does not include 

any control devices for CO2, which is proportional to the heat rate (inversely proportional to the 

efficiency) of the technology. Water, wastewater, and solid waste compliance are achieved 

through traditional on-site and off-site methods, and the costs for such compliance are included 

in the O&M Estimate for the BBFB Facility. Table 14-4 presents environmental emissions for 

the BBFB Facility. 

TABLE 14-4 – ENVIRONMENTAL EMISSIONS FOR BBFB 

Technology: BBFB 

NOX 0.08 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 195 lb/MMBtu 
15-1

15. FUEL CELL (FC) MECHANICAL EQUIPMENT AND SYSTEMS 

The Fuel Cell (“FC”) Facility utilizes multiple phosphoric acid fuel cell units, each with a power 

output of 400 kW, for a total output of 10 MW. The fuel cells convert chemical energy directly 

into electricity from natural gas and air vapor and produce heat and water vapor as byproducts. 

The fuel (the reactant) is introduced continuously to the anode side of the unit cell while air (the 

oxidant) is introduced continuously into the cathode side via a blower. In a fuel cell, electricity 

is produced by ionic transfer across an electrolyte that separates the fuel from the air. A high 

temperature fuel cell produces electricity by splitting a molecule of the oxidant into its ionic 

components at the cathode, passing ions through the electrolyte (e.g. in the case of the 

FC Facility, a phosphoric acid ion) and then reacting the ions with the fuel at the anode to 

produce heat to allow the reaction to occur. During this ionic transfer process, two electrons are 

stripped from each ion to which develops a voltage and current. Since each fuel cell develops a 

relatively low voltage, the cells are stacked to produce a higher, more useful voltage. Depending 

on the type of fuel cell, high temperature waste heat from the process may be available for 

cogeneration applications. Figure 15-1 presents the fuel cell process flow diagram. 

FIGURE 15-1 – FC DESIGN CONFIGURATION 

15.1 ELECTRICAL AND CONTROL SYSTEMS 

Each fuel cell stack generates DC electric power. These stacks are connected to DC-to-AC 

inverters that produce an output of 60 Hz, three-phase 480 volt (“V”) AC electric power voltage. 

The inverters also provide power quality control and protection when designed to IEEE 

Standards. The fuel cell units are connected through circuit breakers to a switchgear bus that 

combines the output of the fuel cell units for a total output of 10 MW. The switchgear is 

connected through a circuit breaker to the local utility distribution system. 

Each individual fuel cell module has its own autonomous control system with an overall data 

acquisition system for the combined FC Facility. 

15.2 OFF-SITE REQUIREMENTS 

Natural gas is delivered to the FC Facility through a lateral or in an urban environment, 

potentially through the local distribution company infrastructure. Water for all processes at the 

FC Facility is obtained from one of several available water sources, but given that the water 
15-2

needs are low, a municipal (potable) water source would be preferable. Wastewater is sent to a 

municipal wastewater system. Further, the electrical interconnection from the FC Facility is into 

the local grid distribution infrastructure. 

15.3 CAPITAL COST ESTIMATE 

The base Cost Estimate for the FC Facility with a nominal capacity of 10 MW is $9,960/kW. 

Table 15-1 summarizes the Cost Estimate categories for the FC Facility. 

TABLE 15-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR FC 

Technology: FC 

Nominal Capacity (ISO): 10,000 kW 

Nominal Heat Rate (ISO): 9,500 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 3,148 

Mechanical Equipment Supply and 

Installation 49,925 

Electrical / I&C Supply and Installation 2,050 

Project Indirects (1) 3,473 

EPC Cost before Contingency and Fee 58,596 

Fee and Contingency 4,688 

Total Project EPC 63,284 

Owner Costs (excluding project finance) 5,063 

Total Project Cost (excluding finance) 68,347 

Total Project EPC / kW 6,328 

Owner Costs 8% (excluding project finance) / kW 500 

Total Project Cost (excluding project finance) / kW 6,835 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, remote location issues, labor wage and 

productivity differences, location adjustments, owner cost differences, and the increase in 

overheads associated with these five adjustments. 
15-3

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the FC Facility include 

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and 

Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the FC Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 15-2 presents the FC Facility capital cost variations for alternative U.S. plant locations. 
15-4

TABLE 15-2 – LOCATION-BASED COSTS FOR FC 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 6,835 12.7% 871 7,706 

Alaska Fairbanks 6,835 18.4% 1,255 8,090 

Alabama Huntsville 6,835 -4.6% (312) 6,523 

Arizona Phoenix 6,835 -3.5% (240) 6,595 

Arkansas Little Rock 6,835 -3.7% (251) 6,584 

California Los Angeles 6,835 4.3% 293 7,128 

California Redding 6,835 1.7% 119 6,954 

California Bakersfield 6,835 2.2% 150 6,985 

California Sacramento 6,835 4.6% 313 7,148 

California San Francisco 6,835 10.7% 733 7,568 

Colorado Denver 6,835 -4.1% (278) 6,557 

Connecticut Hartford 6,835 4.4% 299 7,134 

Delaware Dover 6,835 2.4% 166 7,001 

District of Columbia Washington 6,835 1.9% 127 6,962 

Florida Tallahassee 6,835 -6.3% (432) 6,403 

Florida Tampa 6,835 -2.6% (179) 6,656 

Georgia Atlanta 6,835 -5.0% (340) 6,495 

Hawaii Honolulu 6,835 12.0% 817 7,652 

Idaho Boise 6,835 -3.0% (203) 6,632 

Illinois Chicago 6,835 10.0% 681 7,516 

Indiana Indianapolis 6,835 -0.6% (42) 6,793 

Iowa Davenport 6,835 -1.0% (65) 6,770 

Iowa Waterloo 6,835 -5.5% (378) 6,457 

Kansas Wichita 6,835 -4.5% (306) 6,529 

Kentucky Louisville 6,835 -3.8% (258) 6,577 

Louisiana New Orleans 6,835 -6.5% (445) 6,390 

Maine Portland 6,835 -2.4% (162) 6,673 

Maryland Baltimore 6,835 -1.3% (86) 6,749 

Massachusetts Boston 6,835 9.7% 662 7,497 

Michigan Detroit 6,835 2.3% 156 6,991 

Michigan Grand Rapids 6,835 -4.5% (310) 6,525 

Minnesota St. Paul 6,835 1.9% 133 6,968 

Mississippi Jackson 6,835 -4.5% (310) 6,525 

Missouri St. Louis 6,835 2.6% 180 7,015 

Missouri Kansas City 6,835 1.4% 94 6,929 

Montana Great Falls 6,835 -3.1% (209) 6,626 

Nebraska Omaha 6,835 -2.5% (172) 6,663 

New Hampshire Concord 6,835 -1.4% (98) 6,737 

New Jersey Newark 6,835 10.1% 689 7,524 
15-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 6,835 -2.8% (194) 6,641 

New York New York 6,835 22.2% 1,514 8,349 

New York Syracuse 6,835 -0.7% (48) 6,787 

Nevada Las Vegas 6,835 3.7% 253 7,088 

North Carolina Charlotte 6,835 -6.6% (451) 6,384 

North Dakota Bismarck 6,835 -4.6% (314) 6,521 

Ohio Cincinnati 6,835 -2.6% (180) 6,655 

Oregon Portland 6,835 1.6% 107 6,942 

Pennsylvania Philadelphia 6,835 6.7% 459 7,294 

Pennsylvania Wilkes-Barre 6,835 -2.9% (195) 6,640 

Rhode Island Providence 6,835 1.8% 124 6,959 

South Carolina Spartanburg 6,835 -7.6% (517) 6,318 

South Dakota Rapid City 6,835 -6.3% (429) 6,406 

Tennessee Knoxville 6,835 -5.8% (398) 6,437 

Texas Houston 6,835 -5.8% (398) 6,437 

Utah Salt Lake City 6,835 -3.7% (251) 6,584 

Vermont Burlington 6,835 -3.7% (251) 6,584 

Virginia Alexandria 6,835 -0.8% (52) 6,783 

Virginia Lynchburg 6,835 -4.0% (276) 6,559 

Washington Seattle 6,835 3.6% 244 7,079 

Washington Spokane 6,835 -1.8% (126) 6,709 

West Virginia Charleston 6,835 -1.2% (80) 6,755 

Wisconsin Green Bay 6,835 -1.9% (130) 6,705 

Wyoming Cheyenne 6,835 -3.6% (245) 6,590 

Puerto Rico Cayey 6,835 -0.2% (14) 6,821 

15.4 O&M ESTIMATE 

In addition to the general items discussed in the section of this report entitled O&M Estimate, 

since a FC is a direct energy conversion device, the specific O&M related to the FC Facility that 

differs from other facilities discussed in this report is the stack replacement, currently anticipated 

to be every five years by the various vendors and developers. Table 15-3 presents the O&M 

expenses for the FC Facility. 

TABLE 15-3 – O&M EXPENSES FOR FC 

Technology: FC 

Fixed O&M Expense $350/kW-year 

Variable O&M Expense $0/MWh 
15-6

15.5 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 15-4 presents environmental emissions for the FC Facility. It should be noted that the CO2

production from the FC Facility occurs as a result of reforming natural gas to the feedstock for 

the fuel cell module. 

TABLE 15-4 – ENVIRONMENTAL EMISSIONS FOR FC 

Technology: FC 

NOX <0.013 lb/MMBtu 

SO2 <0.00013 lb/MMBtu 

CO2 <130 lb/MMBtu 
16-1

16. GEOTHERMAL DUAL FLASH (GT) 

16.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Geothermal (“GT”) Facility produces 50 MW net of electricity. The facility uses a 

dual-flash GT cycle, which includes one ST with the capability to generate 55 gross MW based 

on a high-temperature, high-salinity brine. The GT Facility consists of production wells, a 

Turbine Generating Facility (“TGF”), a Brine Processing Facility (“BPF”), injection wells, and a 

plant injection well. GT fluid in mixed phase (steam and brine) from the production wells is 

piped to the BPF where the fluid is flashed at successively lower pressures to produce three 

separate pressure levels of steam to be delivered to the TGF. Additionally, the BPF will produce 

a concentrated brine to be further processed to remove solids. 

The GT production wells deliver the GT brine to the BPF where it is initially flashed in a 

separator drum to produce HP steam. The remaining brine is subject to two additional pressure 

reduction stages, in closed pressure vessels called crystallizers, which are operated in a manner 

to prevent the rapid scaling of the vessel walls and internal parts by the precipitation of solids 

from the brine. The medium-pressure crystallizer is supplied with a small quantity of seed flow, 

concentrated brine from the primary clarifier, to provide a nucleus to which the solids in the 

crystallizer brine can attach themselves and be carried out with the brine leaving the crystallizer. 

The separated brine from the crystallizers is sent through an atmospheric flash tank to reduce 

pressure, and then further processed via a primary and secondary clarifier system where the 

solids produced are formed into a solid cake after being passed through a filter press, treated with 

acid and neutralizing washes, and steam and hot-air dried to produce a silica rich filter cake 

Steam at the three pressure levels from the BPF is delivered to the TGF and directed through 

steam scrubbers (one for each pressure level), which are designed to produce 99.95 percent 

quality steam, by removing free liquids and a proportion of the entrained liquids within the 

steam. The scrubbed steam is delivered to the ST. The ST is a condensing ST equipped with 

dual HP, IP, and LP inlets. Steam from the ST is condensed in a two-pass shell and tube 

condenser constructed of stainless steel, with part of the condensate used for cooling tower 

make-up, and the remainder pumped to the re-injection wells. Condensate pumps direct 

condensate to the circulating water system, the purge system, or the condensate injection system. 

The non-condensable gases are evacuated by a non-condensable gas removal system and vent 

products delivered to an H2S abatement system. Cooling water for the ST condenser is supplied 

by an induced-draft cooling tower. Circulating water pumps direct water from the cooling tower 

to the ST condenser. Make-up water for the cycle is supplied from the condensate from the ST 

condenser. Additional make-up water may be needed during the summer months. Figure 16-1 

presents a simplified process flow diagram for a GT power plant configuration. 
16-2

FIGURE 16-1 – GT DESIGN CONFIGURATION

16.2 ELECTRICAL AND CONTROL SYSTEMS 

The GT Facility has one ST electric generator. The generator is a 60 Hz machine rated at 

approximately 70 MVA with an output voltage of 13.8 kV. The ST electric generator is 

connected to a high-voltage bus in the facility switchyard via a dedicated generator circuit 

breaker, GSU, high-voltage circuit breaker and a disconnect switch. The GSU increases the 

voltage from the electric generator from 13.8 kV to interconnected transmission system high 

voltage. 

The GT Facility is controlled using a DCS. The DCS provides centralized control of the facility 

by integrating the control systems provided with the BPF, ST and associated electric generator, 

and the control of BOP systems and equipment. 

16.3 OFF-SITE REQUIREMENTS 

Since the GT Facility is fueled by a renewable, underground fuel source, an off-site fuel source, 

other than incidental plant heating, is not required. Water for all processes at the GT Facility is 

obtained from one of several available water sources; however, due to the geography of most 

geothermal power plants, water is sourced from on-site wells. Processed wastewater is generally 

re-injected, if wells are the source of water, though many GT facilities utilize ZLD. Further, the 
16-3

electrical interconnection from the GT Facility is accomplished by interconnecting via the plant 

switchyard into the utility high-voltage transmission system. 

16.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the GT Facility with a nominal capacity of 50 MW is $6,163/kW. 

Table 16-1 summarizes the Cost Estimate categories for the GT Facility. 

TABLE 16-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR GT 

Technology: GT 

Nominal Capacity (ISO): 50,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 9,450 

Mechanical Equipment Supply and 

Installation (and well costs) 152,000 

Electrical / I&C Supply and Installation 12,062 

Project Indirects (1) 32,000 

EPC Cost before Contingency and Fee 205,512 

Fee and Contingency 30,827 

Total Project EPC 236,339 

Owner Costs (excluding project finance) 42,541 

Total Project Cost (excluding finance) 278,880 

Total Project EPC / kW 4,726 

Owner Costs 18% (excluding project finance) / kW 852 

Total Project Cost (excluding project finance) / kW 5,578 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, local technical enhancements 

(e.g., additional noise remediation that is generally required in urban siting), remote location 

issues, labor wage and productivity differences, location adjustments, and the increase in 

overheads associated with these five adjustments. It was assumed that geothermal facilities 

would only be considered in 13 states: Alaska, Arizona, California, Colorado, Florida, Hawaii, 

Idaho, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming. 
16-4

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the Geothermal Facility include 

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; and Cheyenne, Wyoming. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the GT Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Hawaii, and Wyoming. 

Table 16-2 presents the GT Facility capital cost variations for alternative U.S. plant locations. 
16-5

TABLE 16-2 – LOCATION-BASED COSTS FOR GT 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,580 13.9% 777 6,357 

Alaska Fairbanks 5,580 20.6% 1,150 6,730 

Alabama Huntsville 0 0.0% 0 0 

Arizona Phoenix 5,580 -3.1% (173) 5,407 

Arkansas Little Rock 0 0.0% 0 0 

California Los Angeles 5,580 5.4% 301 5,881 

California Redding 5,580 1.8% 101 5,681 

California Bakersfield 5,580 2.4% 136 5,716 

California Sacramento 5,580 4.9% 271 5,851 

California San Francisco 5,580 11.8% 661 6,241 

Colorado Denver 5,580 -3.0% (165) 5,415 

Connecticut Hartford 0 0.0% 0 0 

Delaware Dover 0 0.0% 0 0 

District of Columbia Washington 0 0.0% 0 0 

Florida Tallahassee 0 0.0% 0 0 

Florida Tampa 0 0.0% 0 0 

Georgia Atlanta 0 0.0% 0 0 

Hawaii Honolulu 5,580 21.8% 1,217 6,797 

Idaho Boise 5,580 -2.6% (146) 5,434 

Illinois Chicago 0 0.0% 0 0 

Indiana Indianapolis 0 0.0% 0 0 

Iowa Davenport 0 0.0% 0 0 

Iowa Waterloo 0 0.0% 0 0 

Kansas Wichita 0 0.0% 0 0 

Kentucky Louisville 0 0.0% 0 0 

Louisiana New Orleans 0 0.0% 0 0 

Maine Portland 0 0.0% 0 0 

Maryland Baltimore 0 0.0% 0 0 

Massachusetts Boston 0 0.0% 0 0 

Michigan Detroit 0 0.0% 0 0 

Michigan Grand Rapids 0 0.0% 0 0 

Minnesota St. Paul 0 0.0% 0 0 

Mississippi Jackson 0 0.0% 0 0 

Missouri St. Louis 0 0.0% 0 0 

Missouri Kansas City 0 0.0% 0 0 

Montana Great Falls 0 0.0% 0 0 

Nebraska Omaha 0 0.0% 0 0 

New Hampshire Concord 0 0.0% 0 0 

New Jersey Newark 0 0.0% 0 0 
16-6

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 5,580 -2.1% (117) 5,463 

New York New York 0 0.0% 0 0 

New York Syracuse 0 0.0% 0 0 

Nevada Las Vegas 5,580 3.5% 193 5,773 

North Carolina Charlotte 0 0.0% 0 0 

North Dakota Bismarck 0 0.0% 0 0 

Ohio Cincinnati 0 0.0% 0 0 

Oregon Portland 5,580 1.7% 92 5,672 

Pennsylvania Philadelphia 0 0.0% 0 0 

Pennsylvania Wilkes-Barre 0 0.0% 0 0 

Rhode Island Providence 0 0.0% 0 0 

South Carolina Spartanburg 0 0.0% 0 0 

South Dakota Rapid City 0 0.0% 0 0 

Tennessee Knoxville 0 0.0% 0 0 

Texas Houston 0 0.0% 0 0 

Utah Salt Lake City 5,580 -3.1% (173) 5,407 

Vermont Burlington 0 0.0% 0 0 

Virginia Alexandria 0 0.0% 0 0 

Virginia Lynchburg 0 0.0% 0 0 

Washington Seattle 5,580 3.5% 194 5,774 

Washington Spokane 5,580 -1.8% (103) 5,477 

West Virginia Charleston 0 0.0% 0 0 

Wisconsin Green Bay 0 0.0% 0 0 

Wyoming Cheyenne 5,580 -2.9% (164) 5,416 

Puerto Rico Cayey 0 0.0% 0 0 

16.5 O&M ESTIMATE 

In addition to the general items discussed in the section of this report entitled O&M Estimate, the 

GT Facility includes major maintenance on the ST, electric generator (each approximately every 

six years) and well field maintenance, which can vary depending on the GT resource. Table 16-3 

presents the FOM and VOM expenses for the GT Facility. 

TABLE 16-3 – O&M EXPENSES FOR GT 

Technology: GT 

Fixed O&M Expense $84.27/kW-year 

Variable O&M Expense $9.46/MWh 

16.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 16-4 presents environmental emissions for the GT Facility. 
16-7

TABLE 16-4 – ENVIRONMENTAL EMISSIONS FOR GT 

Technology: GT 

NOX 0 per MWh 

SO2 0.2 per MWh 

CO2 120 per MWh 
17-1

17. GEOTHERMAL BINARY (BINARY) 

17.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Geothermal Binary (“Binary”) Facility produces 50 MW net of electricity. The Binary 

Facility consists primarily of three heat recovery systems. These heat recovery systems operate 

on a closed looped organic supercritical Rankine cycle using geothermal brine as a heat source, 

with a brine temperature approximately 275°F. Cycle heat rejection will be provided through 

three cooling towers. After supplying the three heat recovery systems with hot water, the 

geothermal brine will be re-injected into the resource at approximately 140°F through injection 

wells. 

The heat recovery systems are equipped with a multistage, radial inflow turbo-expander 

generator unit. The turbo-expander is designed for a supercritical refrigerant inlet pressure and 

temperature. Each turbo-expander unit has a design output (gross) of approximately 10,000 kW. 

Refrigerant is pumped from the condenser to the evaporators in each heat recovery system by 

means of a single high pressure vertical turbine pump. 

FIGURE 17-1 – GT DESIGN CONFIGURATION

17.2 ELECTRICAL AND CONTROL SYSTEMS 

There are to be three turbine generators at the Binary Facility. Each turbine generator is to be an 

air cooled unit with static excitation designed for operation at 60 Hz, three-phase and 12.5 kV. 

Each turbine generator is to be rated for 18 MW with a power factor range of 0.85 lagging. 

The three turbine generators are to be connected to a single GSU connected through a generator 

circuit breaker and a switchgear main circuit breaker and underground cable to a switch on a 

common open air bus in the Binary Facility substation. 
17-2

17.3 OFF-SITE REQUIREMENTS 

Since the Binary Facility is fueled by a renewable, underground fuel source, an off-site fuel 

source, other than incidental plant heating is not required. Water for all processes at the Binary 

Facility is obtained from one of several available water sources; however, due to the geography 

of most geothermal power plants, water is sourced from on-site wells. Processed wastewater is 

generally re-injected, if wells are the source of water, though many Binary facilities utilize ZLD. 

Further, the electrical interconnection from the Binary Facility is accomplished by 

interconnecting via the plant switchyard into the utility high-voltage transmission system. 

17.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the Binary Facility with a nominal capacity of 50 MW is $4,141/kW. 

Table 17-1 summarizes the Cost Estimate categories for the Binary Facility. 

TABLE 17-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR GT 

Technology: GT 

Nominal Capacity (ISO): 50,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 6,760 

Mechanical Equipment Supply and 

Installation (and well costs) 107,545 

Electrical / I&C Supply and Installation 13,345 

Project Indirects (1) 29,000 

EPC Cost before Contingency and Fee 156,650 

Fee and Contingency 18,798 

Total Project EPC 175,448 

Owner Costs (excluding project finance) 31,598 

Total Project Cost (excluding finance) 207,046 

Total Project EPC / kW 3,509 

Owner Costs 18% (excluding project finance) / kW 632 

Total Project Cost (excluding project finance) / kW 4,141 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 
17-3

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, local technical enhancements 

(e.g., additional noise remediation that is generally required in urban siting), remote location 

issues, labor wage and productivity differences, location adjustments, and the increase in 

overheads associated with these five adjustments. It was assumed that geothermal facilities 

would only be considered in 13 states: Alaska, Arizona, California, Colorado, Florida, Hawaii, 

Idaho, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the Geothermal Facility include 

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; and Cheyenne, Wyoming. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the GT Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Hawaii, and Wyoming. 

Table 17-2 presents the GT Facility capital cost variations for alternative U.S. plant locations. 
17-4

TABLE 17-2 – LOCATION-BASED COSTS FOR GT 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,140 17.1% 710 4,850 

Alaska Fairbanks 4,140 26.0% 1,075 5,215 

Alabama Huntsville 0 0.0% 0 0 

Arizona Phoenix 4,140 -3.0% (125) 4,015 

Arkansas Little Rock 0 0.0% 0 0 

California Los Angeles 4,140 6.5% 270 4,410 

California Redding 4,140 2.1% 88 4,228 

California Bakersfield 4,140 3.1% 127 4,267 

California Sacramento 4,140 5.4% 222 4,362 

California San Francisco 4,140 13.4% 553 4,693 

Colorado Denver 4,140 -2.7% (112) 4,028 

Connecticut Hartford 0 0.0% 0 0 

Delaware Dover 0 0.0% 0 0 

District of Columbia Washington 0 0.0% 0 0 

Florida Tallahassee 0 0.0% 0 0 

Florida Tampa 0 0.0% 0 0 

Georgia Atlanta 0 0.0% 0 0 

Hawaii Honolulu 4,140 28.5% 1,178 5,318 

Idaho Boise 4,140 -2.5% (105) 4,035 

Illinois Chicago 0 0.0% 0 0 

Indiana Indianapolis 0 0.0% 0 0 

Iowa Davenport 0 0.0% 0 0 

Iowa Waterloo 0 0.0% 0 0 

Kansas Wichita 0 0.0% 0 0 

Kentucky Louisville 0 0.0% 0 0 

Louisiana New Orleans 0 0.0% 0 0 

Maine Portland 0 0.0% 0 0 

Maryland Baltimore 0 0.0% 0 0 

Massachusetts Boston 0 0.0% 0 0 

Michigan Detroit 0 0.0% 0 0 

Michigan Grand Rapids 0 0.0% 0 0 

Minnesota St. Paul 0 0.0% 0 0 

Mississippi Jackson 0 0.0% 0 0 

Missouri St. Louis 0 0.0% 0 0 

Missouri Kansas City 0 0.0% 0 0 

Montana Great Falls 0 0.0% 0 0 

Nebraska Omaha 0 0.0% 0 0 

New Hampshire Concord 0 0.0% 0 0 

New Jersey Newark 0 0.0% 0 0 
17-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 4,140 -1.8% (76) 4,064 

New York New York 0 0.0% 0 0 

New York Syracuse 0 0.0% 0 0 

Nevada Las Vegas 4,140 3.6% 150 4,290 

North Carolina Charlotte 0 0.0% 0 0 

North Dakota Bismarck 0 0.0% 0 0 

Ohio Cincinnati 0 0.0% 0 0 

Oregon Portland 4,140 2.0% 81 4,221 

Pennsylvania Philadelphia 0 0.0% 0 0 

Pennsylvania Wilkes-Barre 0 0.0% 0 0 

Rhode Island Providence 0 0.0% 0 0 

South Carolina Spartanburg 0 0.0% 0 0 

South Dakota Rapid City 0 0.0% 0 0 

Tennessee Knoxville 0 0.0% 0 0 

Texas Houston 0 0.0% 0 0 

Utah Salt Lake City 4,140 -2.9% (118) 4,022 

Vermont Burlington 0 0.0% 0 0 

Virginia Alexandria 0 0.0% 0 0 

Virginia Lynchburg 0 0.0% 0 0 

Washington Seattle 4,140 3.8% 158 4,298 

Washington Spokane 4,140 -1.7% (72) 4,068 

West Virginia Charleston 0 0.0% 0 0 

Wisconsin Green Bay 0 0.0% 0 0 

Wyoming Cheyenne 4,140 -2.6% (106) 4,034 

Puerto Rico Cayey 0 0.0% 0 0 

17.5 O&M ESTIMATE 

In addition to the general items discussed in the section of this report entitled O&M Estimate, the 

Binary Facility includes major maintenance on the turbines, electric generator (each 

approximately every six years) and well field maintenance, which can vary depending on the 

Binary Facility resource. Table 17-3 presents the FOM and VOM expenses for the Binary 

Facility. 

TABLE 17-3 – O&M EXPENSES FOR BINARY 

Technology: GT 

Fixed O&M Expense $43.82/kW-year 

Variable O&M Expense $5.15/MWh 
17-6

17.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 17-4 presents environmental emissions for the Binary Facility. 

TABLE 17-4 – ENVIRONMENTAL EMISSIONS FOR BINARY 

Technology: Binary 

NOX 0 per MWh 

SO2 0.2 per MWh 

CO2 120 per MWh 
18-1

18. MUNICIPAL SOLID WASTE (MSW) 

18.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The MSW Facility processes approximately 2,000 tons per day of MSW and produces 

approximately 50 MW. Three refuse-fired boilers are installed, which incorporate the Marin 

mass-burning technology and grates specifically designed for combusting waste having an HHV 

between 4,000 and 6,500 Btu/lb. The three boilers together produce approximately 450,000 lb/hr 

of 900 psia steam. 

Grapple cranes are used to transfer solid waste from a storage pit to loading chutes, where 

hydraulically operated feeds push the MSW onto the grates at a rate determined by the 

combustion control system. The Martin grates are constructed as assemblies of modular grate 

units. The units are driven by hydraulic systems to provide a reverse reciprocating motion of the 

grates, which move the burning refuse along the length of the downward sloped grate. At the 

end of its travel along the grate, the MSW is completely combusted, and the remaining ash 

residue falls into a proprietary Martin ash residue discharger, which receives the combustion 

residue and cools it in a quench chamber. The fly ash from the dry flue gas scrubber and fabric 

filter baghouse is conveyed to the ash discharger where it is combined with the bottom ash and 

quenched. After being quenched, the combined ash residue is pushed up an inclined 

draining/drying chute. Excess water from the residue drains back into the quench bath. The 

residue, containing sufficient moisture to prevent dusting, is transferred by a conveyor to a 

residue storage pit. Clamshell grapple cranes transport the residue to a scalper screen. The 

scalper screen extracts pieces of the residue larger than a certain size in order to protect the 

downstream equipment. The smaller material which passes through the scalper screen is fed 

onto a conveyer belt which discharges onto a vibrating feeder. The vibrating feeder passes the 

residue beneath a magnetic drum to separate ferrous material from the ash. Non-magnetic 

residue falls onto a distribution conveyor for distribution to a transport vehicle. Ferrous material 

is conveyed to a rotating trommel screen for cleaning, after which it is conveyed to a roll-off 

container. 

Each boiler is equipped with a dry flue gas scrubber in combination with a reverse air fabric 

filter baghouse. The dry scrubbers remove the acid gases (mainly SO2, hydrochloric acid and 

hydrofluoric acid) from the flue gas. A hydrated lime injection system prior to the dry scrubber 

augments the AGR capability of the system. The reverse air baghouse reduces dioxin/furan and 

particulate emissions. The facility also uses selective non-catalytic reduction (“SNCR”) for NOX

control, and activated carbon injection for mercury control. 

Steam from the boilers is used to drive a single condensing ST for the production of 

approximately 50 MW of net electricity. The ST exhausts to a water-cooled condenser which 

receives circulating cooling water from an evaporative-type cooling tower. The ST includes 

extraction taps to provide steam for feedwater heating, air preheating and other miscellaneous 

steam requirements. The MSW process flow diagram at a high level is similar to the pulverized 

coal flow diagram, except that the fuel source is MSW, rather than coal (see Figure 3-1). 

The MSW process flow diagram at a high level is similar to the pulverized coal flow diagram, 

except that the fuel source is MSW, rather than coal. 
18-2

18.2 ELECTRICAL AND CONTROL SYSTEMS 

The MSW Facility has one ST electric generator. The generator is a 60 Hz machine rated at 

approximately 70 MVA with an output voltage of 13.8 kV. The ST electric generator is 

connected to a high-voltage bus in the facility switchyard via a dedicated generator circuit 

breaker, GSU, high-voltage circuit breaker and a disconnect switch. The GSU increases the 

voltage from the electric generator from 13.8 kV to interconnected transmission system high 

voltage. 

The MSW Facility is controlled using a DCS. The DCS provides centralized control of the 

facility by integrating the control systems provided with the boiler, ST and associated electric 

generator, and the control of BOP systems and equipment. 

18.3 OFF-SITE REQUIREMENTS 

MSW is delivered to the facility via rail, truck or barge. Water for all processes at the 

MSW Facility can be obtained from one of a variety of sources. The MSW Facility uses a water 

treatment system and a high-efficiency reverse osmosis system to reduce the dissolved solids 

from the cooling water and to provide distilled water for boiler make-up. Wastewater is sent to a 

municipal wastewater system or other approved alternative. Further, the electrical 

interconnection from the MSW Facility on-site switchyard is effectuated by a connection to an 

adjacent utility substation. 

18.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the MSW Facility with a nominal capacity of 50 MW is $8,232/kW. 

Table 18-1 summarizes the Cost Estimate categories for the GT Facility. 
18-3

TABLE 18-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR MSW 

Technology: MSW 

Nominal Capacity (ISO): 50,000 kW 

Nominal Heat Rate (ISO): 18,000 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 33,875 

Mechanical Equipment Supply and 

Installation 183,000 

Electrical / I&C Supply and Installation 25,300 

Project Indirects (1) 56,080 

EPC Cost before Contingency and Fee 298,255 

Fee and Contingency 44,738 

Total Project EPC 342,993 

Owner Costs (excluding project finance) 68,599 

Total Project Cost (excluding finance) 411,592 

Total Project EPC / kW 6,860 

Owner Costs 20% (excluding project finance) / kW 1,372 

Total Project Cost (excluding project finance) / kW 8,232 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, local enhancements, remote location 

issues, labor wage and productivity differences, location adjustments, and the increase in 

overheads associated with these five adjustments. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the MSW Facility include 
18-4

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and 

Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the MSW Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Table 18-2 presents the MSW Facility capital cost variations for alternative U.S. plant locations. 

TABLE 18-2 – LOCATION-BASED COSTS FOR MSW 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 8,240 12.8% 1,054 9,294 

Alaska Fairbanks 8,240 17.7% 1,459 9,699 

Alabama Huntsville 8,240 -5.8% (474) 7,766 

Arizona Phoenix 8,240 -4.5% (371) 7,869 

Arkansas Little Rock 8,240 -4.7% (387) 7,853 

California Los Angeles 8,240 5.2% 430 8,670 

California Redding 8,240 1.9% 154 8,394 

California Bakersfield 8,240 2.1% 176 8,416 

California Sacramento 8,240 5.7% 472 8,712 

California San Francisco 8,240 13.4% 1,104 9,344 

Colorado Denver 8,240 -4.7% (384) 7,856 

Connecticut Hartford 8,240 5.2% 429 8,669 

Delaware Dover 8,240 3.1% 258 8,498 

District of Columbia Washington 8,240 1.7% 140 8,380 

Florida Tallahassee 8,240 -7.9% (649) 7,591 

Florida Tampa 8,240 -3.3% (268) 7,972 

Georgia Atlanta 8,240 -6.3% (515) 7,725 

Hawaii Honolulu 8,240 19.9% 1,638 9,878 

Idaho Boise 8,240 -3.8% (315) 7,925 

Illinois Chicago 8,240 12.5% 1,033 9,273 

Indiana Indianapolis 8,240 -0.9% (78) 8,162 

Iowa Davenport 8,240 -1.0% (79) 8,161 

Iowa Waterloo 8,240 -6.7% (548) 7,692 

Kansas Wichita 8,240 -5.4% (446) 7,794 

Kentucky Louisville 8,240 -4.8% (392) 7,848 

Louisiana New Orleans 8,240 -7.3% (603) 7,637 

Maine Portland 8,240 -4.1% (341) 7,899 

Maryland Baltimore 8,240 -1.7% (144) 8,096 
18-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Massachusetts Boston 8,240 11.8% 975 9,215 

Michigan Detroit 8,240 2.7% 220 8,460 

Michigan Grand Rapids 8,240 -5.8% (475) 7,765 

Minnesota St. Paul 8,240 2.3% 190 8,430 

Mississippi Jackson 8,240 -5.7% (471) 7,769 

Missouri St. Louis 8,240 3.0% 247 8,487 

Missouri Kansas City 8,240 1.8% 150 8,390 

Montana Great Falls 8,240 -4.0% (333) 7,907 

Nebraska Omaha 8,240 -3.0% (243) 7,997 

New Hampshire Concord 8,240 -2.0% (166) 8,074 

New Jersey Newark 8,240 11.9% 984 9,224 

New Mexico Albuquerque 8,240 -3.5% (287) 7,953 

New York New York 8,240 26.3% 2,167 10,407 

New York Syracuse 8,240 -0.4% (31) 8,209 

Nevada Las Vegas 8,240 4.5% 370 8,610 

North Carolina Charlotte 8,240 -8.3% (688) 7,552 

North Dakota Bismarck 8,240 -5.6% (463) 7,777 

Ohio Cincinnati 8,240 -3.1% (256) 7,984 

Oregon Portland 8,240 1.7% 136 8,376 

Pennsylvania Philadelphia 8,240 8.5% 698 8,938 

Pennsylvania Wilkes-Barre 8,240 -3.4% (283) 7,957 

Rhode Island Providence 8,240 2.8% 229 8,469 

South Carolina Spartanburg 8,240 -9.5% (786) 7,454 

South Dakota Rapid City 8,240 -7.9% (654) 7,586 

Tennessee Knoxville 8,240 -7.3% (603) 7,637 

Texas Houston 8,240 -7.3% (598) 7,642 

Utah Salt Lake City 8,240 -4.9% (401) 7,839 

Vermont Burlington 8,240 -4.4% (364) 7,876 

Virginia Alexandria 8,240 -1.8% (148) 8,092 

Virginia Lynchburg 8,240 -5.1% (420) 7,820 

Washington Seattle 8,240 4.1% 342 8,582 

Washington Spokane 8,240 -2.8% (228) 8,012 

West Virginia Charleston 8,240 -1.6% (135) 8,105 

Wisconsin Green Bay 8,240 -2.3% (186) 8,054 

Wyoming Cheyenne 8,240 -4.6% (383) 7,857 

Puerto Rico Cayey 8,240 -1.7% (144) 8,096 

18.5 O&M ESTIMATE 

In addition to the general items discussed in the section of this report entitled O&M Estimate, the 

MSW Facility includes major maintenance for the feedstock handling, ST, electric generator, 

boiler, and BOP systems. Table 18-3 presents the O&M expenses for the MSW Facility. 
18-6

TABLE 18-3 – O&M EXPENSES FOR MSW 

Technology: MSW 

Fixed O&M Expense $373.76/kW-year 

Variable O&M Expense $8.33/MWh 

18.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

As mentioned above in the section on mechanical systems, each boiler is equipped with a dry 

flue gas scrubber in combination with a reverse air fabric filter baghouse. A hydrated lime 

injection system prior to the dry scrubber augments the AGR capability of the system. The 

reverse air baghouse reduces dioxin/furan and particulate emissions, an SNCR is used for NOX

control, and activated carbon injection is used for mercury control. Table 18-4 presents 

environmental emissions for the MSW Facility. 

TABLE 18-4 – ENVIRONMENTAL EMISSIONS FOR MSW 

Technology: MSW 

NOX 0.27 lb/MMBtu 

SO2 0.07 lb/MMBtu 

CO2 200 lb/MMBtu 
19-1

19. HYDROELECTRIC (HY) 

19.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The 500 MW Hydroelectric (“HY”) Facility is composed of two 250 MW vertical shaft Francis 

turbine generator units with a minimum of 650 feet (200 meters) of head. Figure 19-1 presents 

the HY process flow diagram. 

FIGURE 19-1 – HY DESIGN CONFIGURATION

19.2 ELECTRICAL AND CONTROL SYSTEMS 

The HY Facility has two synchronous electric generators. Each generator is a 60 Hz machine 

rated at approximately 300 MVA with an output voltage of approximately 23 kV. Each electric 

generator is connected to a high-voltage bus in the facility switchyard via a dedicated generator 

circuit breaker, GSU, high-voltage circuit breaker and a disconnect switch. In some instances, 

the generator is connected directly to its GSU and connected through a disconnect switch 

between two breakers on the high-voltage bus. The GSU increases the voltage from the electric 

generator from 23 kV to interconnected transmission system high voltage. 

The HY Facility is controlled using a DCS. The DCS provides centralized control of the facility 

by integrating the control systems provided hydro-turbine and associated electric generator and 

the control of BOP systems and equipment. 

19.3 OFF-SITE REQUIREMENTS 

Since the fuel source for the HY Facility is renewable, the most important off-site requirement is 

the electrical interconnection to the high-voltage transmission system of the utility, which can be 

effectuated through the HY Facility switchyard. 
19-2

19.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the HY Facility with a nominal capacity of 500 MW is $3,076/kW. 

Table 19-1 summarizes the Cost Estimate categories for the HY Facility. 

TABLE 19-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR HY 

Technology: HY 

Nominal Capacity (ISO): 500,000 kW 

Nominal Heat Rate (ISO): Not Applicable 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 634,250 

Mechanical Equipment Supply and 

Installation 253,000 

Electrical / I&C Supply and Installation 77,600 

Project Indirects (1) 174,500 

EPC Cost before Contingency and Fee 1,139,350 

Fee and Contingency 142,419 

Total Project EPC 1,281,769 

Owner Costs (excluding project finance) 256,354 

Total Project Cost (excluding finance) 1,538,123 

Total Project EPC / kW 2,564 

Owner Costs 20% (excluding project finance) / kW 513 

Total Project Cost (excluding project finance) / kW 3,076 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, local technical enhancements 

(e.g., additional noise remediation that is generally required in urban siting), remote location 

issues, labor wage and productivity differences, location adjustments, and the increase in 

overheads associated with these five adjustments. The assumption was made that hydroelectric 

facilities would only be considered for construction in the states of Alaska, California, Colorado, 

Connecticut, Idaho, Maine, Missouri, Montana, North Carolina, Ohio, Oregon, South Dakota, 

and Washington. 
19-3

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

The locations with local technical enhancements include California, Colorado, Connecticut, and 

Delaware. These are areas where technical enhancements generally need to be made by a project 

developer or utility to comply with the applicable permitting/siting requirements. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. The remote location related to the Hydroelectric Facility is 

Fairbanks, Alaska. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the HY Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Maine, 

Ohio, and South Dakota. 

Table 19-2 presents the HY Facility capital cost variations for alternative U.S. plant locations. 
19-4

TABLE 19-2 – LOCATION-BASED COSTS FOR HY 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,080 20.1% 619 3,699 

Alaska Fairbanks 3,080 31.6% 974 4,054 

Alabama Huntsville 0 0.0% 0 0 

Arizona Phoenix 0 0.0% 0 0 

Arkansas Little Rock 0 0.0% 0 0 

California Los Angeles 3,080 7.4% 228 3,308 

California Redding 3,080 2.8% 88 3,168 

California Bakersfield 3,080 2.4% 75 3,155 

California Sacramento 3,080 3.7% 113 3,193 

California San Francisco 3,080 13.2% 408 3,488 

Colorado Denver 3,080 -1.3% (40) 3,040 

Connecticut Hartford 3,080 6.4% 197 3,277 

Delaware Dover 0 0.0% 0 0 

District of Columbia Washington 0 0.0% 0 0 

Florida Tallahassee 0 0.0% 0 0 

Florida Tampa 0 0.0% 0 0 

Georgia Atlanta 0 0.0% 0 0 

Hawaii Honolulu 0 0.0% 0 0 

Idaho Boise 3,080 -1.6% (49) 3,031 

Illinois Chicago 0 0.0% 0 0 

Indiana Indianapolis 0 0.0% 0 0 

Iowa Davenport 0 0.0% 0 0 

Iowa Waterloo 0 0.0% 0 0 

Kansas Wichita 0 0.0% 0 0 

Kentucky Louisville 0 0.0% 0 0 

Louisiana New Orleans 0 0.0% 0 0 

Maine Portland 3,080 -0.8% (23) 3,057 

Maryland Baltimore 0 0.0% 0 0 

Massachusetts Boston 0 0.0% 0 0 

Michigan Detroit 0 0.0% 0 0 

Michigan Grand Rapids 0 0.0% 0 0 

Minnesota St. Paul 0 0.0% 0 0 

Mississippi Jackson 0 0.0% 0 0 

Missouri St. Louis 3,080 1.3% 41 3,121 

Missouri Kansas City 3,080 1.4% 42 3,122 

Montana Great Falls 3,080 -1.2% (37) 3,043 

Nebraska Omaha 0 0.0% 0 0 

New Hampshire Concord 0 0.0% 0 0 

New Jersey Newark 0 0.0% 0 0 

New Mexico Albuquerque 0 0.0% 0 0 
19-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 0 0.0% 0 0 

New York Syracuse 0 0.0% 0 0 

Nevada Las Vegas 0 0.0% 0 0 

North Carolina Charlotte 3,080 0.0% 20 3,100 

North Dakota Bismarck 0 0.0% 0 0 

Ohio Cincinnati 3,080 -1.6% (49) 3,031 

Oregon Portland 3,080 4.7% 145 3,225 

Pennsylvania Philadelphia 0 0.0% 0 0 

Pennsylvania Wilkes-Barre 0 0.0% 0 0 

Rhode Island Providence 0 0.0% 0 0 

South Carolina Spartanburg 0 0.0% 0 0 

South Dakota Rapid City 3,080 -3.9% (119) 2,961 

Tennessee Knoxville 0 0.0% 0 0 

Texas Houston 0 0.0% 0 0 

Utah Salt Lake City 0 0.0% 0 0 

Vermont Burlington 0 0.0% 0 0 

Virginia Alexandria 0 0.0% 0 0 

Virginia Lynchburg 0 0.0% 0 0 

Washington Seattle 3,080 3.5% 109 3,189 

Washington Spokane 3,080 -1.0% (31) 3,049 

West Virginia Charleston 0 0.0% 0 0 

Wisconsin Green Bay 0 0.0% 0 0 

Wyoming Cheyenne 0 0.0% 0 0 

Puerto Rico Cayey 0 0.0% 0 0 

19.5 O&M ESTIMATE 

In addition to the general items discussed in the section of the report entitled O&M Estimate, the 

most significant differentiating O&M expenses for the HY Facility include dam and associated 

civil major maintenance and hydro-turbine major maintenance, which are generally conducted 

approximately every ten years. Because HY power plants are typically operated when available, 

most operators consider a majority of O&M expenses for this technology to be fixed. Table 19-3 

presents the O&M expenses for the HY Facility. 

TABLE 19-3 – O&M EXPENSES FOR HY 

Technology: HY 

Fixed O&M Expense $13.44/kW-year 

Variable O&M Expense $0/MWh 

19.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The HY Facility does not burn a fuel and consequently there are no air emissions from this type 

of plant. Table 19-4 presents environmental emissions for the HY Facility. 
19-6

TABLE 19-4 – ENVIRONMENTAL EMISSIONS FOR HY 

Technology: HY 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 
20-1

20. PUMPED STORAGE (PS) 

20.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The 250 MW Pumped Storage (“PS”) Facility is composed of two 125 MW Francis turbine 

generator units. During off-peak hours, water is pumped from a lower reservoir to an upper 

reservoir using electricity from the grid. During the generating cycle, water is discharged 

through the reversible turbine generators to produce power. Figure 20-1 presents the PS process 

flow diagram. 

FIGURE 20-1 – PS DESIGN CONFIGURATION

20.2 ELECTRICAL AND CONTROL SYSTEMS 

The PS Facility has two synchronous electric generators that are also capable of being operated 

as motors powered from the grid to provide the pumping function by driving the Francis 

hydro-turbines in reverse. The generators are 60 Hz machines rated at approximately 150 MVA 

with an output voltage of 13.8 kV to 24 kV. Each electric generator is connected to a highvoltage bus in the facility switchyard via a dedicated generator circuit breaker, GSU, 

high-voltage circuit breaker and a disconnect switch. The GSU increases the voltage from the 

electric generator voltage to the interconnected transmission system high voltage. 

The PS Facility is controlled using a DCS. The DCS provides centralized control of the facility 

by integrating the control systems provided with the hydro-turbine and associated electric 

generator and the control of BOP systems and equipment. 

20.3 OFF-SITE REQUIREMENTS 

Similar to the HY Facility, since the fuel source for the PS Facility is renewable, the most 

important off-site requirement is the electrical interconnection to the high-voltage transmission 

system of the utility, which can be effectuated through the PS switchyard. Unlike the HY 

Facility, which uses the backfeed from the utility transmission system only to run required plant 
20-2

loads when the hydro-turbines are not operating, significant volumes of electricity are consumed 

in off-peak hours at the PS Facility. 

20.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the PS Facility with a nominal capacity of 250 MW is $5,595/kW. 

Table 20-1 summarizes the Cost Estimate categories for the PS Facility. However, it should be 

noted that the construction costs for future pumped storage power plants are strongly impacted 

by the size (e.g., larger plants are most generally lower cost on a $/kW basis) and by the existing 

infrastructure that may be leveraged in the development, design, and construction. 

TABLE 20-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR PS 

Technology: PS 

Nominal Capacity (ISO): 250,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 653,000 

Mechanical Equipment Supply and 

Installation 152,400 

Electrical / I&C Supply and Installation 73,700 

Project Indirects (1) 171,100 

EPC Cost before Contingency and Fee 1,050,200 

Fee and Contingency 115,522 

Total Project EPC 1,165,722 

Owner Costs (excluding project finance) 233,144 

Total Project Cost (excluding finance) 1,398,866 

Total Project EPC / kW 4,663 

Owner Costs 20% (excluding project finance) / kW 933 

Total Project Cost (excluding project finance) / kW 5,595 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, local technical enhancements, remote 

location issues, labor wage and productivity differences, location adjustments, and the increase 

in overheads associated with these five adjustments listed. While the analysis shown below 
20-3

contemplates cost adjustment factors for each area considered, realistically, there are certain 

areas that do not have enough elevation difference to cost effectively produce a pumped storage 

plant. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

The locations with local technical enhancements include California, Colorado, Connecticut, 

Delaware, District of Columbia, Louisiana, Maryland, Massachusetts, New Jersey, New York, 

Rhode Island, Vermont, and Virginia. These are areas where noise, visual impacts, and other 

technical enhancements generally need to be made by a project developer or utility to comply 

with the applicable permitting/siting requirements. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the Pumped Storage Facility 

include Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; 

and Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1., taking into 

consideration the amount of labor we estimated for the PS Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio; and Wisconsin. 

Table 20-2 presents the PS Facility capital cost variations for alternative U.S. plant locations. 
20-4

TABLE 20-2 – LOCATION-BASED COSTS FOR PS 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,595 17.6% 985 6,580 

Alaska Fairbanks 5,595 24.7% 1,382 6,977 

Alabama Huntsville 5,595 -7.4% (413) 5,182 

Arizona Phoenix 5,595 -5.7% (322) 5,273 

Arkansas Little Rock 5,595 -6.0% (335) 5,260 

California Los Angeles 5,595 7.1% 398 5,993 

California Redding 5,595 2.5% 141 5,736 

California Bakersfield 5,595 3.0% 166 5,761 

California Sacramento 5,595 7.5% 422 6,017 

California San Francisco 5,595 17.8% 994 6,589 

Colorado Denver 5,595 -5.9% (329) 5,266 

Connecticut Hartford 5,595 7.0% 392 5,987 

Delaware Dover 5,595 4.3% 243 5,838 

District of Columbia Washington 5,595 2.8% 155 5,750 

Florida Tallahassee 0 0 0 0 

Florida Tampa 0 0 0 0 

Georgia Atlanta 5,595 -8.0% (449) 5,146 

Hawaii Honolulu 5,595 15.8% 883 6,478 

Idaho Boise 5,595 -4.9% (273) 5,322 

Illinois Chicago 5,595 16.2% 907 6,502 

Indiana Indianapolis 5,595 -1.1% (64) 5,531 

Iowa Davenport 5,595 -1.2% (66) 5,529 

Iowa Waterloo 5,595 -8.5% (476) 5,119 

Kansas Wichita 0 0 0 0 

Kentucky Louisville 5,595 -6.1% (341) 5,254 

Louisiana New Orleans 5,595 -9.3% (519) 5,076 

Maine Portland 5,595 -5.2% (290) 5,305 

Maryland Baltimore 5,595 -2.0% (110) 5,485 

Massachusetts Boston 5,595 15.5% 869 6,464 

Michigan Detroit 5,595 3.5% 196 5,791 

Michigan Grand Rapids 5,595 -7.4% (413) 5,182 

Minnesota St. Paul 5,595 3.0% 168 5,763 

Mississippi Jackson 5,595 -7.3% (410) 5,185 

Missouri St. Louis 5,595 4.0% 222 5,817 

Missouri Kansas City 5,595 2.4% 136 5,731 

Montana Great Falls 5,595 -5.1% (286) 5,309 

Nebraska Omaha 5,595 -3.7% (209) 5,386 

New Hampshire Concord 5,595 -2.5% (140) 5,455 

New Jersey Newark 5,595 15.5% 867 6,462 

New Mexico Albuquerque 5,595 -4.4% (245) 5,350 
20-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 5,595 34.3% 1,921 7,516 

New York Syracuse 5,595 -0.2% (13) 5,582 

Nevada Las Vegas 5,595 5.8% 326 5,921 

North Carolina Charlotte 5,595 -10.7% (599) 4,996 

North Dakota Bismarck 5,595 -7.1% (399) 5,196 

Ohio Cincinnati 5,595 -3.9% (220) 5,375 

Oregon Portland 5,595 3.1% 171 5,766 

Pennsylvania Philadelphia 5,595 11.0% 615 6,210 

Pennsylvania Wilkes-Barre 5,595 -4.3% (243) 5,352 

Rhode Island Providence 5,595 3.7% 209 5,804 

South Carolina Spartanburg 5,595 -12.2% (684) 4,911 

South Dakota Rapid City 5,595 -10.2% (569) 5,026 

Tennessee Knoxville 5,595 -9.4% (526) 5,069 

Texas Houston 5,595 -9.3% (523) 5,072 

Utah Salt Lake City 5,595 -6.2% (344) 5,251 

Vermont Burlington 5,595 -5.5% (309) 5,286 

Virginia Alexandria 5,595 -2.2% (121) 5,474 

Virginia Lynchburg 5,595 -6.5% (366) 5,229 

Washington Seattle 5,595 5.4% 305 5,900 

Washington Spokane 5,595 -3.5% (197) 5,398 

West Virginia Charleston 5,595 -2.0% (114) 5,481 

Wisconsin Green Bay 5,595 -2.8% (157) 5,438 

Wyoming Cheyenne 5,595 -5.8% (324) 5,271 

Puerto Rico Cayey 5,595 -1.7% (95) 5,500 

20.5 O&M ESTIMATE 

The O&M discussion in Section 17.5, related to the HY Facility at a high-level is applicable to 

the PS Facility, including the fact that most operators budget for a given PS facility on a FOM 

expense basis only. The additional areas of O&M that are applicable to the PS Facility that are 

not applicable to the HY Facility are pump and associated motor maintenance. Table 20-3 

presents the O&M expenses for the PS Facility. 

TABLE 20-3 – O&M EXPENSES FOR PS 

Technology: PS 

Fixed O&M Expense $13.03/kW-year 

Variable O&M Expense $0/MWh 

20.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

The PS Facility does not directly burn a fuel and consequently there are no air emissions from 

this type of plant. Note that the fuel used to power the off-peak energy market, allowing 

off-peak pumping to the reservoir, is not considered in this report. Table 20-4 presents 

environmental emissions for the PS Facility. 
20-6

TABLE 20-4 – ENVIRONMENTAL EMISSIONS FOR PS 

Technology: PS 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 
21-1

21. ONSHORE WIND (WN) 

21.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Onshore Wind (“WN”) Facility is based on 67 wind turbine generators (“WTGs”), each with 

a rated capacity of 1.5 MW. The total design capacity is 100 MW. 

The turbines are each supported by a conical steel tower, which is widest at the base and tapers 

in diameter just below the nacelle. A foundation provides the tower with a firm anchor to the 

ground. The nacelle is attached to the top of the tower and contains the main mechanical 

components of the wind turbine, which include a variable-speed generator, transmission, and 

yaw drive. The rotor hub connects to the transmission through one end of the nacelle, and the 

rotor is then connected to the hub. The WTG has a three-bladed rotor with a diameter of 

77 meters. The WTG has an active yaw system in the nacelle to keep the rotor facing into the 

wind. 

Power is generated by the wind turbines, then converted using an onboard transformer to 

34.5 kV AC. It is then delivered to a collection system at the base of each turbine. Power from 

all turbines will be collected by the underground collection circuit. 

The collection system supplies power to a new substation designed to step up the voltage to 

115 kV for interconnection with the transmission system. Other facility components include 

access roads, an O&M building and electrical interconnection facilities. Figure 21-1 presents a 

picture of a typical WN Facility. 

FIGURE 21-1 – WN DESIGN CONFIGURATION
21-2

21.2 ELECTRICAL AND CONTROL SYSTEMS 

The WN Facility has 67 wind turbine-driven electric generators. Each generator is a doubly-fed 

induction generator that feeds an AC/DC/AC power converter that provides an output of 

three-phase, 60 Hz electrical power. The power output available is approximately 1.75 MVA 

with an output voltage of 575 V stepped up to 34.5 kV using a pad-mounted transformer at the 

base of the wind turbine. The wind turbine transformers are interconnected on one or more 

underground collector circuits that are connected to a collector bus through a circuit breaker for 

each circuit. The collector bus is connected to a high-voltage transmission system through the 

facility substation, which includes a 34.5 kV switch or circuit breaker, GSU, high-voltage circuit 

breaker, and a disconnect switch. The GSU increases the voltage from the electric generator 

from 34.5 kV to interconnected transmission system high voltage. 

The WN Facility is controlled using a control system generally referred to as the wind farm 

supervisory control and data acquisition (“SCADA”) system. The SCADA system provides 

centralized control of the facility by integrating the control systems provided with each of the 

wind turbines and the control of BOP systems and equipment. 

21.3 OFF-SITE REQUIREMENTS 

Since wind uses a renewable fuel, the most significant off-site requirements are the construction 

of and interconnection to roads and the electrical interconnection to the utility high-voltage 

transmission system, as discussed in Section 19.2. 

21.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the WN Facility with a nominal capacity of 100 MW is $2,400/kW. 

Table 21-1 summarizes the Cost Estimate categories for the WN Facility. 
21-3

TABLE 21-1 – LOCATION-BASED COSTS FOR WN 

Technology: WN 

Nominal Capacity (ISO): 100,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 25,625 

Mechanical Equipment Supply and 

Installation 158,585 

Electrical / I&C Supply and Installation 27,753 

Project Indirects (1) 8,070 

EPC Cost before Contingency and Fee 220,033 

Fee and Contingency 10,000 

Total Project EPC 230,033 

Owner Costs (excluding project finance) 13,802 

Total Project Cost (excluding finance) 243,835 

Total Project EPC / kW 2,300 

Owner Costs 6% (excluding project finance) / kW 138 

Total Project Cost (excluding project finance) / kW 2,438 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, remote location issues, labor wage and 

productivity differences, location adjustments, and owner cost differences and the increase in 

overheads associated with these five adjustments. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the WN Facility include 
21-4

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and 

Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the WN Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 21-2 presents the WN Facility capital cost variations for alternative U.S. plant locations. 

TABLE 21-2 – LOCATION-BASED COSTS FOR WN 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 2,440 25.2% 615 3,055 

Alaska Fairbanks 2,440 45.0% 1,099 3,539 

Alabama Huntsville 2,440 -3.5% (86) 2,354 

Arizona Phoenix 2,440 -2.4% (58) 2,382 

Arkansas Little Rock 2,440 -2.5% (61) 2,379 

California Los Angeles 2,440 12.4% 304 2,744 

California Redding 2,440 8.2% 200 2,640 

California Bakersfield 2,440 10.0% 243 2,683 

California Sacramento 2,440 10.5% 257 2,697 

California San Francisco 2,440 18.6% 453 2,893 

Colorado Denver 2,440 2.2% 54 2,494 

Connecticut Hartford 2,440 6.6% 162 2,602 

Delaware Dover 2,440 4.6% 111 2,551 

District of Columbia Washington 2,440 7.4% 182 2,622 

Florida Tallahassee 2,440 -5.3% (128) 2,312 

Florida Tampa 2,440 -2.2% (53) 2,387 

Georgia Atlanta 2,440 -3.9% (94) 2,346 

Hawaii Honolulu 2,440 27.4% 668 3,108 

Idaho Boise 2,440 3.4% 83 2,523 

Illinois Chicago 2,440 14.2% 346 2,786 

Indiana Indianapolis 2,440 0.3% 8 2,448 

Iowa Davenport 2,440 4.5% 111 2,551 

Iowa Waterloo 2,440 0.7% 18 2,458 

Kansas Wichita 2,440 1.9% 46 2,486 

Kentucky Louisville 2,440 -2.9% (70) 2,370 
21-5

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Louisiana New Orleans 2,440 -5.4% (132) 2,308 

Maine Portland 2,440 6.4% 155 2,595 

Maryland Baltimore 2,440 1.7% 41 2,481 

Massachusetts Boston 2,440 11.1% 270 2,710 

Michigan Detroit 2,440 2.7% 67 2,507 

Michigan Grand Rapids 2,440 -3.2% (78) 2,362 

Minnesota St. Paul 2,440 7.5% 183 2,623 

Mississippi Jackson 2,440 -3.5% (85) 2,355 

Missouri St. Louis 2,440 3.6% 88 2,528 

Missouri Kansas City 2,440 1.7% 41 2,481 

Montana Great Falls 2,440 3.9% 95 2,535 

Nebraska Omaha 2,440 3.5% 86 2,526 

New Hampshire Concord 2,440 5.3% 128 2,568 

New Jersey Newark 2,440 10.5% 257 2,697 

New Mexico Albuquerque 2,440 3.8% 93 2,533 

New York New York 2,440 24.6% 600 3,040 

New York Syracuse 2,440 0.8% 20 2,460 

Nevada Las Vegas 2,440 9.0% 219 2,659 

North Carolina Charlotte 2,440 -4.9% (120) 2,320 

North Dakota Bismarck 2,440 2.1% 50 2,490 

Ohio Cincinnati 2,440 -1.9% (47) 2,393 

Oregon Portland 2,440 8.0% 196 2,636 

Pennsylvania Philadelphia 2,440 6.1% 150 2,590 

Pennsylvania Wilkes-Barre 2,440 -1.8% (44) 2,396 

Rhode Island Providence 2,440 2.1% 51 2,491 

South Carolina Spartanburg 2,440 -5.7% (140) 2,300 

South Dakota Rapid City 2,440 0.7% 17 2,457 

Tennessee Knoxville 2,440 -4.6% (111) 2,329 

Texas Houston 2,440 -4.8% (118) 2,322 

Utah Salt Lake City 2,440 3.7% 90 2,530 

Vermont Burlington 2,440 3.4% 83 2,523 

Virginia Alexandria 2,440 1.9% 46 2,486 

Virginia Lynchburg 2,440 -3.1% (75) 2,365 

Washington Seattle 2,440 4.4% 107 2,547 

Washington Spokane 2,440 4.9% 120 2,560 

West Virginia Charleston 2,440 -0.1% (3) 2,437 

Wisconsin Green Bay 2,440 -1.0% (25) 2,415 

Wyoming Cheyenne 2,440 4.3% 105 2,545 

Puerto Rico Cayey 2,440 6.9% 167 2,607 

21.5 O&M ESTIMATE 

In addition to the general items discussed in the section of the report entitled O&M Estimate, the 

major areas for O&M for an Onshore Wind Facility include periodic gearbox, WTG, electric 
21-6

generator, and associated electric conversion (e.g., GSU) technology repairs and replacement. 

These devices typically undergo major maintenance every five to seven years. Table 21-3 

presents the O&M expenses for the WN Facility. 

TABLE 21-3 – O&M EXPENSES FOR WN 

Technology: WN 

Fixed O&M Expense $28.07/kW-year 

Variable O&M Expense $0/MWh 

21.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Since wind utilizes a renewable fuel and no additional fuel is combusted to make power from an 

Onshore Wind Facility, air emissions are not created. Table 21-4 presents environmental 

emissions for the WN Facility. 

TABLE 21-4 – ENVIRONMENTAL EMISSIONS FOR WN 

Technology: WN 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 
22-1

22. OFFSHORE WIND (WF) 

22.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The Offshore Wind (“WF”) Facility is based on 80 offshore WTGs, each with a rated capacity of 

5.0 MW. The total design capacity is 400 MW. 

The turbines are each supported by a conical steel tower, which is widest at the base and tapers 

in diameter just below the nacelle. A foundation provides the tower with a firm anchor to the 

ground. The nacelle is attached to the top of the tower and contains the main mechanical 

components of the wind turbine, which include a variable-speed generator, transmission, and 

yaw drive. The rotor hub connects to the transmission through one end of the nacelle, and the 

rotor is then connected to the hub. The WTG has a three-bladed rotor with a diameter of 

approximately 125 meters. The WTG has an active yaw system in the nacelle to keep the rotor 

facing into the wind. The WF WTG is designed to withstand the conditions of the high seas, 

including additional redundancy of key components to enhance availability, corrosion protection 

and permanent monitoring. 

Power is generated by the wind turbines, then converted using an onboard transformer to 

34.5 kV AC. It is then delivered to a collection system at the base of each turbine. Power from 

all turbines is collected by the underground collection circuit. 

The collection system supplies power to a new substation designed to step up the voltage to 

115 kV for interconnection with the transmission system. Figure 22-1 presents a picture of a 

currently operating WF Facility. 
22-2

FIGURE 22-1 – WF DESIGN CONFIGURATION

22.2 ELECTRICAL AND CONTROL SYSTEMS 

The WF Facility has 80 wind turbine-driven electric generators. Each generator is a doubly-fed 

induction generator that feeds an AC/DC/AC power converter that provides an output of threephase, 60 Hz electrical power. The power output available is approximately 5.5 MVA with an 

output voltage of 690 V stepped up to 34.5 kV using a transformer installed in the wind turbine 

pylon. The wind turbine transformers are interconnected on one or more underwater collector 

circuits trenched into the seabed that are connected to a collector bus (or several collector busses) 

through a circuit breaker for each circuit. The collector bus is connected to a high-voltage 

transmission system through the facility substation that includes a 34.5 kV switch or circuit 

breaker, GSU, high-voltage circuit breaker and a disconnect switch. If there are multiple 

collector busses this arrangement may be replicated for each bus. The GSU increases the voltage 

from the electric generator from 34.5 kV to interconnected transmission system high voltage. 

The WF Facility is controlled using a SCADA system. The SCADA system provides centralized 

control of the facility by integrating the control systems provided with each of the wind turbines 

and the control of BOP systems and equipment. 

22.3 OFF-SITE REQUIREMENTS 

Similar to the WF Facility, the most significant off-site requirement for the WF Facility is the 

electrical interconnection to the utility transmission system, as discussed directly above. 
22-3

22.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the WF Facility with a nominal capacity of 400 MW is $5,975/kW. 

Table 22-1 summarizes the Cost Estimate categories for the WF Facility. 

TABLE 22-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR WF 

Technology: WF 

Nominal Capacity (ISO): 400,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 252,000 

Mechanical Equipment Supply and 

Installation 835,328 

Electrical / I&C Supply and Installation 148,302 

Project Indirects (1) 463,856 

EPC Cost before Contingency and Fee 1,699,486 

Fee and Contingency 212,436 

Total Project EPC 1,911,922 

Owner Costs (excluding project finance) 477,981 

Total Project Cost (excluding finance) 2,389,903 

Total Project EPC / kW 4,780 

Owner Costs 25% (excluding project finance) / kW 1,195 

Total Project Cost (excluding project finance) / kW 5,975 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, remote location issues, labor wage and 

productivity differences, location adjustments, owner cost differences, and the increase in 

overheads associated with these five location adjustments. The assumption was made that 

offshore wind projects would only be constructed offshore of the following states (where 

significant offshore wind resource is available): Alaska, California, Connecticut, Delaware, 

District of Columbia, Georgia, Hawaii, Illinois, Indiana, Maine, Maryland, Massachusetts, 

Michigan, Minnesota, New Jersey, New York, North Carolina, Oregon, Rhode Island, South 

Carolina, Texas, Virginia, Washington, Wisconsin and Puerto Rico. 
22-4

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote locations issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems for construction, because such areas are 

long distances from urban areas, where labor is generally abundant. Remote location 

designations were also considered in locations where higher equipment freight costs are typically 

incurred, which for example are regions not near established rail or highway access. Remote 

locations related to the Offshore Wind Facility include Fairbanks, Alaska; Honolulu, Hawaii; and 

Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the WF Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Maine, Maryland, Massachusetts, New York, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 22-2 presents the WF Facility capital cost variations for alternative U.S. plant locations. 
22-5

TABLE 22-2 – LOCATION-BASED COSTS FOR WF 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,975 15.9% 952 6,927 

Alaska Fairbanks 0 0.0% 

Alabama Huntsville 0 0.0% 

Arizona Phoenix 0 0.0% 

Arkansas Little Rock 0 0.0% 

California Los Angeles 5,975 7.7% 460 6,435 

California Redding 0 0.0% 

California Bakersfield 0 0.0% 

California Sacramento 0 0.0% 

California San Francisco 5,975 16.6% 993 6,968 

Colorado Denver 0 0.0% 

Connecticut Hartford 5,975 5.7% 342 6,317 

Delaware Dover 5,975 3.1% 184 6,159 

District of Columbia Washington 5,975 1.8% 110 6,085 

Florida Tallahassee 0 0.0% 

Florida Tampa 0 0.0% 

Georgia Atlanta 5,975 -7.0% (418) 5,557 

Hawaii Honolulu 5,975 14.5% 864 6,839 

Idaho Boise 0 0.0% 

Illinois Chicago 5,975 16.0% 958 6,933 

Indiana Indianapolis 5,975 -1.0% (58) 5,917 

Iowa Davenport 0 0.0% 

Iowa Waterloo 0 0.0% 

Kansas Wichita 0 0.0% 

Kentucky Louisville 0 0.0% 

Louisiana New Orleans 0 0.0% 

Maine Portland 5,975 -2.6% (156) 5,819 

Maryland Baltimore 5,975 -2.1% (126) 5,849 

Massachusetts Boston 5,975 13.2% 787 6,762 

Michigan Detroit 5,975 2.8% 165 6,140 

Michigan Grand Rapids 5,975 -6.7% (403) 5,572 

Minnesota St. Paul 5,975 4.8% 288 6,263 

Mississippi Jackson 0 0.0% 

Missouri St. Louis 0 0.0% 

Missouri Kansas City 0 0.0% 

Montana Great Falls 0 0.0% 

Nebraska Omaha 0 0.0% 

New Hampshire Concord 0 0.0% 

New Jersey Newark 5,975 12.7% 761 6,736 

New Mexico Albuquerque 0 0.0% 
22-6

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 5,975 29.4% 1,759 7,734 

New York Syracuse 5,975 -1.2% (69) 5,906 

Nevada Las Vegas 0 0.0% 

North Carolina Charlotte 5,975 -9.3% (557) 5,418 

North Dakota Bismarck 0 0.0% 

Ohio Cincinnati 0 0.0% 

Oregon Portland 5,975 5.1% 302 6,277 

Pennsylvania Philadelphia 0 0.0% 

Pennsylvania Wilkes-Barre 0 0.0% 

Rhode Island Providence 5,975 2.5% 148 6,123 

South Carolina Spartanburg 5,975 -6.6% (391) 5,584 

South Dakota Rapid City 0 0.0% 

Tennessee Knoxville 0 0.0% 

Texas Houston 5,975 -8.2% (487) 5,488 

Utah Salt Lake City 0 0.0% 

Vermont Burlington 0 0.0% 

Virginia Alexandria 5,975 -2.7% (161) 5,814 

Virginia Lynchburg 5,975 -5.7% (340) 5,635 

Washington Seattle 5,975 4.8% 287 6,262 

Washington Spokane 0 0.0% 

West Virginia Charleston 0 0.0% 

Wisconsin Green Bay 5,975 -2.7% (164) 5,811 

Wyoming Cheyenne 0 0.0% 

Puerto Rico Cayey 5,975 -1.2% (72) 5,903 

22.5 O&M ESTIMATE 

The types of maintenance performed on the WF Facility are materially similar to the WN 

Facility, discussed in Section 19.5; however, the expenses are higher because maintaining 

offshore parts is considerably more complicated, due to staging on ships and with helicopters. 

Table 22-3 presents the FOM and VOM expenses for the WF Facility. 

TABLE 22-3 – O&M EXPENSES FOR WF 

Technology: WF 

Fixed O&M Expense $53.33/kW-year 

Variable O&M Expense $0/MWh 

22.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Since the WF Facility uses a renewable fuel and no additional fuel is combusted, there are no air 

emissions. Table 22-4 presents environmental emissions for the WF Facility. 
22-7

TABLE 22-4 – ENVIRONMENTAL EMISSIONS FOR WF 

Technology: WF 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 
23-1

23. SOLAR THERMAL - CENTRAL STATION (SO) 

23.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The 100 MW Solar Thermal (“SO”) Facility uses a solar concentrating thermal process based on 

direct steam, power towers, and heliostat mirror technology. The SO Facility incorporates a 

Rankine-cycle reheat ST which receives steam from a solar steam generator and a solar 

superheater and reheated steam from a solar reheater. The solar steam generator, solar 

superheater, and solar reheater are all installed at the top of a tower adjacent to a power block 

located at grade. The tower and power block are generally in the center of a heliostat solar field. 

The solar energy heats water in the steam generator, superheater and reheat boiler to make steam 

that runs the ST. The solar field and power generation equipment are started up each morning 

after sunrise and insolation (or light intensity) build-up, and are shut down in the evening when 

insolation drops below the level required for keeping the ST online. 

A partial load natural gas-fired boiler is used for thermal input to the ST during the morning 

start-up cycle. The boiler is also generally operated during transient cloudy conditions, in order 

to keep the ST online and ready to resume production from solar thermal input, after the clouds 

clear. After the cloud passes and solar-to-thermal input resumes, the ST will be returned to full 

solar production and the gas-fired boiler is shut down. While permitting SO facilities with 

respect to water usage continues to be a challenge, our base assumption is that the SO Facility 

uses wet cooling technology. 

The power block consists of one solar power tower and an ST with a reheat cycle, and it uses 

typical auxiliary components for heat rejection, water treatment, water disposal, and 

interconnection to the grid. Figure 23-1 presents a picture of a typical SO Facility. 
23-2

FIGURE 23-1 – SO DESIGN CONFIGURATION

23.2 ELECTRICAL AND CONTROL SYSTEMS 

The SO Facility has one ST electric generator. The generator is a 60 Hz machine rated at 

approximately 120 MVA with an output voltage of 13.8 kV. The ST electric generator is 

connected to a high-voltage bus in the facility switchyard via a dedicated generator circuit 

breaker, GSU, high-voltage circuit breaker and a disconnect switch. The GSU increases the 

voltage from the electric generator from 13.8 kV to interconnected transmission system high 

voltage. 
23-3

The SO Facility is controlled using a DCS. The DCS provides centralized control of the facility 

by integrating the control systems provided with the solar steam generator/superheater/reheater 

system, ST and associated electric generator, and the control of BOP systems and equipment. 

23.3 OFF-SITE REQUIREMENTS 

Natural gas is delivered to the facility through a lateral connected to the local natural gas trunk 

line. Water for all processes at the SO Facility is obtained from a one of several available water 

sources (e.g., municipal water supply); however, due to the remote location of most solar thermal 

power plants, water is often sourced through on-site wells. The SO Facility uses a water 

treatment system and a high-efficiency reverse osmosis system to reduce the dissolved solids 

from the cooling water and to provide distilled water for HRSG make-up. Processed wastewater 

is sent to a municipal wastewater system, re-injected on-site, or an on-site ZLD system. Further, 

the electrical interconnection from the SO Facility on-site switchyard is effectuated by a 

connection to an adjacent utility substation. 

23.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the SO Facility with a nominal capacity of 100 MW is $4,692/kW. 

Table 23-1 summarizes the Cost Estimate categories for the SO Facility. 
23-4

TABLE 23-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR SO 

Technology: SO 

Nominal Capacity (ISO): 100,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV (2)

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 48,475 

Mechanical Equipment Supply and 

Installation 254,250 

Electrical / I&C Supply and Installation 40,750 

Project Indirects (1) 39,500 

EPC Cost before Contingency and Fee 382,975 

Fee and Contingency 25,000 

Total Project EPC 407,975 

Owner Costs (excluding project finance) 61,196 

Total Project Cost (excluding finance) 469,171 

Total Project EPC / kW 4,080 

Owner Costs 15% (excluding project finance) / kW 612 

Total Project Cost (excluding project finance) / kW 4,692 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

(2) Does not include natural gas firing, as such usage is sporadic and highly dependent on time of year and 

method of operation. 

 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, remote location issues, labor wage and 

productivity differences, location adjustments, owner cost differences, and the increase in 

overheads associated with the previous five location adjustments. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 
23-5

established rail or highway access. Remote locations related to the Solar Thermal Facility 

include Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wyoming; and Cayey, Puerto 

Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the SO Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 23-2 presents the SO Facility capital cost variations for alternative U.S. plant locations. 
23-6

TABLE 23-2 – LOCATION-BASED COSTS FOR SO 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,700 23.8% 1,119 5,819 

Alaska Fairbanks 4,700 35.4% 1,662 6,362 

Alabama Huntsville 4,700 -11.3% (532) 4,168 

Arizona Phoenix 4,700 -8.9% (417) 4,283 

Arkansas Little Rock 4,700 -9.3% (435) 4,265 

California Los Angeles 4,700 11.4% 538 5,238 

California Redding 4,700 6.3% 297 4,997 

California Bakersfield 4,700 6.7% 316 5,016 

California Sacramento 4,700 13.3% 623 5,323 

California San Francisco 4,700 26.8% 1,261 5,961 

Colorado Denver 4,700 -7.3% (344) 4,356 

Connecticut Hartford 4,700 9.2% 431 5,131 

Delaware Dover 4,700 4.7% 220 4,920 

District of Columbia Washington 4,700 1.6% 74 4,774 

Florida Tallahassee 4,700 -15.5% (727) 3,973 

Florida Tampa 4,700 -6.4% (300) 4,400 

Georgia Atlanta 4,700 -12.3% (578) 4,122 

Hawaii Honolulu 4,700 39.8% 1,871 6,571 

Idaho Boise 4,700 -4.8% (225) 4,475 

Illinois Chicago 4,700 26.8% 1,262 5,962 

Indiana Indianapolis 4,700 -1.9% (90) 4,610 

Iowa Davenport 4,700 0.4% 20 4,720 

Iowa Waterloo 4,700 -10.8% (505) 4,195 

Kansas Wichita 4,700 -8.3% (392) 4,308 

Kentucky Louisville 4,700 -9.4% (440) 4,260 

Louisiana New Orleans 4,700 -15.9% (748) 3,952 

Maine Portland 4,700 -5.9% (278) 4,422 

Maryland Baltimore 4,700 -4.4% (209) 4,491 

Massachusetts Boston 4,700 22.2% 1,043 5,743 

Michigan Detroit 4,700 4.8% 224 4,924 

Michigan Grand Rapids 4,700 -11.8% (554) 4,146 

Minnesota St. Paul 4,700 7.2% 340 5,040 

Mississippi Jackson 4,700 -11.2% (528) 4,172 

Missouri St. Louis 4,700 5.7% 270 4,970 

Missouri Kansas City 4,700 3.1% 144 4,844 

Montana Great Falls 4,700 -5.3% (248) 4,452 

Nebraska Omaha 4,700 -3.5% (165) 4,535 

New Hampshire Concord 4,700 -1.7% (80) 4,620 

New Jersey Newark 4,700 22.2% 1,042 5,742 

New Mexico Albuquerque 4,700 -4.6% (217) 4,483 
23-7

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4,700 50.1% 2,355 7,055 

New York Syracuse 4,700 -2.4% (114) 4,586 

Nevada Las Vegas 4,700 11.5% 542 5,242 

North Carolina Charlotte 4,700 -16.4% (772) 3,928 

North Dakota Bismarck 4,700 -8.8% (412) 4,288 

Ohio Cincinnati 4,700 -6.6% (310) 4,390 

Oregon Portland 4,700 5.9% 277 4,977 

Pennsylvania Philadelphia 4,700 16.1% 758 5,458 

Pennsylvania Wilkes-Barre 4,700 -7.3% (341) 4,359 

Rhode Island Providence 4,700 4.2% 196 4,896 

South Carolina Spartanburg 4,700 -18.8% (882) 3,818 

South Dakota Rapid City 4,700 -12.8% (604) 4,096 

Tennessee Knoxville 4,700 -14.4% (677) 4,023 

Texas Houston 4,700 -14.2% (670) 4,030 

Utah Salt Lake City 4,700 -6.9% (325) 4,375 

Vermont Burlington 4,700 -7.2% (338) 4,362 

Virginia Alexandria 4,700 -4.8% (225) 4,475 

Virginia Lynchburg 4,700 -10.0% (471) 4,229 

Washington Seattle 4,700 8.0% 377 5,077 

Washington Spokane 4,700 -2.7% (127) 4,573 

West Virginia Charleston 4,700 -3.3% (155) 4,545 

Wisconsin Green Bay 4,700 -4.9% (232) 4,468 

Wyoming Cheyenne 4,700 -7.0% (329) 4,371 

Puerto Rico Cayey 4,700 -4.0% (190) 4,510 

23.5 O&M ESTIMATE 

The typical O&M expenses for the SO Facility include mirror cleaning, repair, and replacement; 

thermal tube replacements; and BOP major maintenance. The BOP major maintenance is similar 

to that which is performed on a combined-cycle plant: HRSG, ST, and electric generator major 

maintenance, typically performed approximately every seven years. Additionally, most thermal 

solar operators do not treat O&M on a variable basis, and consequently, all O&M expenses are 

shown below on a fixed basis. Table 23-3 presents the O&M expenses for the SO Facility. 

TABLE 23-3 – O&M EXPENSES FOR SO 

Technology: SO 

Fixed O&M Expense $64.00/kW-year 

Variable O&M Expense $0/MWh 

23.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 23-4 presents environmental emissions for the SO Facility. 
23-8

TABLE 23-4 – ENVIRONMENTAL EMISSIONS FOR SO 

Technology: SO 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 
24-1

24. PHOTOVOLTAIC (CENTRAL STATION) FACILITY (PV) 

24.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The following describes a nominally 7 MW-AC Photovoltaic (“PV”) Facility. An analysis is 

also provided for a nominally 150 MW-AC PV Facility, which is essentially a significant 

expansion of the 7 MW Facility; however, a detailed technical description (due to the similarities 

with the 7 MW Facility and the technology associated therewith) is not provided herein. The PV 

Facility uses numerous arrays of ground-mounted, fixed-tilt PV modules which directly convert 

incident solar radiation into DC electricity, which can then be inverted to AC. Additional BOP 

components include metal racks and foundations to support fixed panels and keep them aligned 

at the correct angle, DC wiring, combiner boxes where individual strings of panels are connected 

prior to being fed into the inverters, DC-to-AC inverters, AC wiring, various switchgear and 

step-up transformers, and a control system (partly incorporated into the inverter control 

electronics) to monitor plant output and adjust the balance of voltage and current to yield 

maximum power. Figure 22-1 presents a picture of a typical PV Facility. 

FIGURE 24-1 – PV DESIGN CONFIGURATION

24.2 ELECTRICAL AND CONTROL SYSTEMS 

The 7 MW-AC PV Facility is comprised of 14 half-megawatt building blocks, each block 

consisting of groups of PV modules connected to a 500 kW-AC inverter. While the ratio of DC 

module capacity to AC inverter capacity varies, for this analysis we have assumed a ratio of 
24-2

1.2:1, or 600 kW-DC of modules per 500 kW-AC inverter. Such a ratio is typical of current 

systems, though higher ratios are becoming more common. Groups of PV modules produce DC 

electricity and are connected in series to form “strings” which are then connected in parallel in a 

combiner box which contains a fuse for each string. The cables are routed from the modules to 

combiner boxes and a number of combiner boxes are connected to the input of a 500 kW-AC 

inverter, which converts the aggregate power from DC to three-phase AC electricity at an output 

voltage of typically 265 V. The output voltage of an inverter (or sometimes several inverters 

connected together) is stepped up to a higher voltage level, typically in the range of 13.8 kV (or 

34.5 kV for larger systems) through a GSU connected to the inverter output terminals. Two 

inverters are often combined on each of transformer, each of which is rated 1 MVA. The 

transformers are connected in groups to form circuits on an underground collection system. The 

circuits are connected to a 13.8 kV circuit breaker and then to the local utility distribution grid. 

Each inverter has its own integral control system. The aggregate of all the inverters and 

associated DC arrays are monitored through a SCADA system, sometimes provided by the 

inverter manufacturer. 

24.3 OFF-SITE REQUIREMENTS 

Unlike other power technologies discussed in this report, the essential off-site requirements for 

which provisions must be made on a PV Facility are water supply (generally in limited 

quantities) and an electrical interconnection between the PV Facility switchyard and the local 

utility distribution system. 

24.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the PV Facility with a nominal capacity of 7 MW-AC is 6,050/kW 

and with a nominal capacity of 150 MW is $4,755/kW. Table 24-1 and Table 24-2 summarize 

the Cost Estimate categories for the PV Facility. 
24-3

TABLE 24-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR PV 

Technology: PV 

Nominal Capacity (ISO): 7,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 6,100 

Mechanical Equipment Supply and 

Installation 20,500 

Electrical / I&C Supply and Installation 3,550 

Project Indirects (1) 3,665 

EPC Cost before Contingency and Fee 33,815 

Fee and Contingency 4,000 

Total Project EPC 37,815 

Owner Costs (excluding project finance) 4,538 

Total Project Cost (excluding finance) 42,353 

Total Project EPC / kW 5,402 

Owner Costs 12% (excluding project finance) / kW 648 

Total Project Cost (excluding project finance) / kW 6,050 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 
24-4

TABLE 24-2 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR PV 

Technology: PV 

Nominal Capacity (ISO): 150,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2010$)

 

Civil Structural Material and Installation 65,000 

Mechanical Equipment Supply and 

Installation 391,583 

Electrical / I&C Supply and Installation 64,350 

Project Indirects (1) 52,762 

EPC Cost before Contingency and Fee 573,695 

Fee and Contingency 68,843 

Total Project EPC 642,538 

Owner Costs (excluding project finance) 70,679 

Total Project Cost (excluding finance) 713,217 

Total Project EPC / kW 4,283 

Owner Costs 12% (excluding project finance) / kW 471 

Total Project Cost (excluding project finance) / kW 4,755 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 

For this type of technology and power plant configuration, our regional adjustments took into 

consideration the following: seismic design differences, remote location issues, labor wage and 

productivity differences, location adjustments, owner cost differences, and the increase in 

overheads associated with these five location adjustments. 

Seismic design differences among the various locations were based on U.S. seismic map 

information that detailed the various seismic zones throughout the U.S. No cost increases were 

associated with seismic Zone 0 and cost step increases were considered for Zones 1, 2, 3 and 4. 

Remote location issues are related to geographic areas that typically require installation of man 

camps, higher craft incentives, and higher per diems are generally required with respect to 

construction, due to the fact that such areas are long distances from urban areas, where labor is 

generally abundant. Remote location designations were also considered in locations where 

higher equipment freight costs are typically incurred, which for example are regions not near 

established rail or highway access. Remote locations related to the Photovoltaic Facility include 
24-5

Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico Cheyenne, Wyoming; and 

Cayey, Puerto Rico. 

Labor wage and productivity differences were handled as discussed in Section 2.5.1, taking into 

consideration the amount of labor we estimated for the PV Facility. 

Location adjustments were made to locations where higher cost of living levels are incurred 

and/or where population density generally correlates to higher construction costs for power and 

other infrastructure projects. These locations include Alaska, California, Connecticut, Delaware, 

District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, 

New York, Ohio, and Wisconsin. 

Owner costs were reviewed based on the need for utility upgrades and/or infrastructure costs 

such as new facility transmission lines to tie to existing utility transmission substations or 

existing transmission lines. 

Table 24-3 and Table 24-4 present the PV Facility capital cost variations for alternative U.S. 

plant locations. 
24-6

TABLE 24-3 – LOCATION-BASED COSTS FOR PV (7 MW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 6,050 16.8% 1,016 7,066 

Alaska Fairbanks 6,050 25.6% 1,548 7,598 

Alabama Huntsville 6,050 -7.3% (441) 5,609 

Arizona Phoenix 6,050 -5.7% (344) 5,706 

Arkansas Little Rock 6,050 -5.9% (359) 5,691 

California Los Angeles 6,050 8.1% 490 6,540 

California Redding 6,050 4.6% 277 6,327 

California Bakersfield 6,050 5.0% 301 6,351 

California Sacramento 6,050 9.1% 549 6,599 

California San Francisco 6,050 18.1% 1,096 7,146 

Colorado Denver 6,050 -4.3% (263) 5,787 

Connecticut Hartford 6,050 6.2% 376 6,426 

Delaware Dover 6,050 3.3% 198 6,248 

District of Columbia Washington 6,050 1.6% 96 6,146 

Florida Tallahassee 6,050 -10.0% (605) 5,445 

Florida Tampa 6,050 -4.1% (250) 5,800 

Georgia Atlanta 6,050 -7.9% (480) 5,570 

Hawaii Honolulu 6,050 29.9% 1,812 7,862 

Idaho Boise 6,050 -2.7% (162) 5,888 

Illinois Chicago 6,050 17.8% 1,075 7,125 

Indiana Indianapolis 6,050 -1.2% (70) 5,980 

Iowa Davenport 6,050 0.6% 38 6,088 

Iowa Waterloo 6,050 -6.6% (399) 5,651 

Kansas Wichita 6,050 -5.0% (303) 5,747 

Kentucky Louisville 6,050 -6.0% (364) 5,686 

Louisiana New Orleans 6,050 -10.3% (622) 5,428 

Maine Portland 6,050 -3.4% (203) 5,847 

Maryland Baltimore 6,050 -2.6% (158) 5,892 

Massachusetts Boston 6,050 14.6% 885 6,935 

Michigan Detroit 6,050 3.1% 188 6,238 

Michigan Grand Rapids 6,050 -7.6% (461) 5,589 

Minnesota St. Paul 6,050 5.1% 308 6,358 

Mississippi Jackson 6,050 -7.2% (438) 5,612 

Missouri St. Louis 6,050 3.9% 233 6,283 

Missouri Kansas City 6,050 2.0% 123 6,173 

Montana Great Falls 6,050 -2.9% (178) 5,872 

Nebraska Omaha 6,050 -1.9% (114) 5,936 

New Hampshire Concord 6,050 -0.7% (42) 6,008 

New Jersey Newark 6,050 14.4% 869 6,919 

New Mexico Albuquerque 6,050 -2.5% (154) 5,896 
24-7

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 6,050 32.9% 1,988 8,038 

New York Syracuse 6,050 -1.4% (86) 5,964 

Nevada Las Vegas 6,050 7.9% 476 6,526 

North Carolina Charlotte 6,050 -10.6% (640) 5,410 

North Dakota Bismarck 6,050 -5.3% (318) 5,732 

Ohio Cincinnati 6,050 -4.2% (256) 5,794 

Oregon Portland 6,050 4.3% 260 6,310 

Pennsylvania Philadelphia 6,050 10.5% 634 6,684 

Pennsylvania Wilkes-Barre 6,050 -4.6% (281) 5,769 

Rhode Island Providence 6,050 2.7% 166 6,216 

South Carolina Spartanburg 6,050 -12.1% (731) 5,319 

South Dakota Rapid City 6,050 -7.9% (477) 5,573 

Tennessee Knoxville 6,050 -9.3% (562) 5,488 

Texas Houston 6,050 -9.2% (557) 5,493 

Utah Salt Lake City 6,050 -4.0% (240) 5,810 

Vermont Burlington 6,050 -4.2% (256) 5,794 

Virginia Alexandria 6,050 -3.1% (185) 5,865 

Virginia Lynchburg 6,050 -6.5% (391) 5,659 

Washington Seattle 6,050 5.3% 322 6,372 

Washington Spokane 6,050 -1.3% (81) 5,969 

West Virginia Charleston 6,050 -2.0% (124) 5,926 

Wisconsin Green Bay 6,050 -3.1% (190) 5,860 

Wyoming Cheyenne 6,050 -4.0% (240) 5,810 

Puerto Rico Cayey 6,050 -1.9% (117) 5,933 
24-8

TABLE 24-4 – LOCATION-BASED COSTS FOR PV (150 MW) 

(OCTOBER 1, 2010 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,755 19.9% 947 5,702 

Alaska Fairbanks 4,755 30.9% 1,470 6,225 

Alabama Huntsville 4,755 -8.0% (379) 4,376 

Arizona Phoenix 4,755 -6.2% (294) 4,461 

Arkansas Little Rock 4,755 -6.5% (307) 4,448 

California Los Angeles 4,755 9.6% 458 5,213 

California Redding 4,755 5.5% 263 5,018 

California Bakersfield 4,755 6.1% 291 5,046 

California Sacramento 4,755 10.5% 498 5,253 

California San Francisco 4,755 20.7% 985 5,740 

Colorado Denver 4,755 -4.4% (208) 4,547 

Connecticut Hartford 4,755 7.1% 339 5,094 

Delaware Dover 4,755 3.8% 183 4,938 

District of Columbia Washington 4,755 2.3% 111 4,866 

Florida Tallahassee 4,755 -11.0% (522) 4,233 

Florida Tampa 4,755 -4.5% (216) 4,539 

Georgia Atlanta 4,755 -8.7% (413) 4,342 

Hawaii Honolulu 4,755 37.2% 1,771 6,526 

Idaho Boise 4,755 -2.5% (119) 4,636 

Illinois Chicago 4,755 19.9% 949 5,704 

Indiana Indianapolis 4,755 -1.2% (57) 4,698 

Iowa Davenport 4,755 1.1% 51 4,806 

Iowa Waterloo 4,755 -6.9% (327) 4,428 

Kansas Wichita 4,755 -5.1% (242) 4,513 

Kentucky Louisville 4,755 -6.6% (313) 4,442 

Louisiana New Orleans 4,755 -11.3% (537) 4,218 

Maine Portland 4,755 -3.2% (152) 4,603 

Maryland Baltimore 4,755 -2.6% (124) 4,631 

Massachusetts Boston 4,755 16.4% 778 5,533 

Michigan Detroit 4,755 3.4% 163 4,918 

Michigan Grand Rapids 4,755 -8.4% (398) 4,357 

Minnesota St. Paul 4,755 6.0% 286 5,041 

Mississippi Jackson 4,755 -7.9% (377) 4,378 

Missouri St. Louis 4,755 4.4% 208 4,963 

Missouri Kansas City 4,755 2.3% 109 4,864 

Montana Great Falls 4,755 -2.7% (130) 4,625 

Nebraska Omaha 4,755 -1.7% (79) 4,676 

New Hampshire Concord 4,755 -0.3% (15) 4,740 

New Jersey Newark 4,755 15.8% 751 5,506 

New Mexico Albuquerque 4,755 -2.3% (111) 4,644 
24-9

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4,755 36.6% 1,739 6,494 

New York Syracuse 4,755 -1.4% (68) 4,687 

Nevada Las Vegas 4,755 9.1% 432 5,187 

North Carolina Charlotte 4,755 -11.6% (549) 4,206 

North Dakota Bismarck 4,755 -5.3% (254) 4,501 

Ohio Cincinnati 4,755 -4.6% (220) 4,535 

Oregon Portland 4,755 5.2% 249 5,004 

Pennsylvania Philadelphia 4,755 11.6% 550 5,305 

Pennsylvania Wilkes-Barre 4,755 -5.0% (240) 4,515 

Rhode Island Providence 4,755 3.1% 146 4,901 

South Carolina Spartanburg 4,755 -13.2% (628) 4,127 

South Dakota Rapid City 4,755 -8.2% (392) 4,363 

Tennessee Knoxville 4,755 -10.2% (483) 4,272 

Texas Houston 4,755 -10.1% (481) 4,274 

Utah Salt Lake City 4,755 -3.8% (183) 4,572 

Vermont Burlington 4,755 -4.2% (201) 4,554 

Virginia Alexandria 4,755 -3.3% (159) 4,596 

Virginia Lynchburg 4,755 -7.1% (336) 4,419 

Washington Seattle 4,755 6.0% 284 5,039 

Washington Spokane 4,755 -1.0% (49) 4,706 

West Virginia Charleston 4,755 -2.2% (103) 4,652 

Wisconsin Green Bay 4,755 -3.4% (161) 4,594 

Wyoming Cheyenne 4,755 -3.8% (180) 4,575 

Puerto Rico Cayey 4,755 -1.4% (68) 4,687 

24.5 O&M ESTIMATE 

The significant O&M items for a PV Facility include periodic inverter maintenance and periodic 

panel water washing. Additionally, most PV solar operators do not treat O&M on a variable 

basis, and consequently, all O&M expenses are shown below on a fixed basis. Table 24-5 and 

Table 24-6 present the O&M expenses for the PV Facility. 

TABLE 24-5 – O&M EXPENSES FOR PV FACILITY (7 MW) 

Technology: PV 

Fixed O&M Expense $26.40/kW-year 

Variable O&M Expense $0/MWh 

TABLE 24-6 – O&M EXPENSES FOR PV FACILITY (150 MW) 

Technology: PV 

Fixed O&M Expense $16.70/kW-year 

Variable O&M Expense $0/MWh 
24-10

24.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 24-7 presents environmental emissions for the PV Facility. 

TABLE 24-7 – ENVIRONMENTAL EMISSIONS FOR PV 

Technology: Photovoltaic 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu