Updated Capital Cost Estimates 

for Utility Scale Electricity 

Generating Plants

April 2013

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants ii

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.
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants ii

Contents

Introduction.............................................................................................................................................1

Developing updated estimates: key design considerations....................................................................1

Findings....................................................................................................................................................2

EIA's analysis of technology choice in the electric power sector............................................................3

Impact of location on power plant capital costs .....................................................................................5

Summary..................................................................................................................................................5

Appendix A - Acronym List..........................................................................................................................11

Appendix B – Full Report.............................................................................................................................12
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants iii

Tables

Table 1. Updated estimates of power plant capital and operating costs.....................................................6

Table 2. Overnight cost comparison with 2010 estimates ...........................................................................7

Table 3. Status of technologies and components modeled by EIA...............................................................8

Table 4. Regional cost adjustments for technologies modeled by NEMS by Electric Market Module 

(EMM) region ,

............................................................................................................................................10
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 1

Introduction

The current and future projected cost and performance characteristics of new electric generating 

capacity are a critical input into the development of energy projections and analyses. The construction 

and operating costs, along with the performance characteristics of new generating plants, play an 

important role in determining the mix of capacity additions that will serve future demand for electricity. 

These parameters also help to determine how new capacity competes against existing capacity, and the 

response of the electric generators to the imposition of environmental controls on conventional 

pollutants or any limitations on greenhouse gas emissions.

In 2010, EIA commissioned an external consultant to develop up-to-date cost and performance 

estimates for utility-scale electric generating plants for AEO 2011.

1 This information allowed EIA to 

compare the costs of different power plant technologies on a standardized basis and was a key input 

enhancement to the National Energy Model System (NEMS). For the AEO 2013 development, EIA 

commissioned the same consultant group to update the cost and performance estimates for each of the 

technologies evaluated in the original 2010 study. This paper summarizes the results of the findings and 

discusses how EIA uses the updated information to analyze the development of new capacity in the 

electric power sector. 

Developing updated estimates: key design considerations

The focus of the 2013 update was to gather current information on the "overnight" construction costs, 

operating costs, and performance characteristics for a wide range of generating technologies.2 The 

estimates were developed through costing exercises, using a common methodology across technologies. 

Comparing cost estimates developed on a similar basis using the same methodology is of particular 

importance to ensure modeling consistency.

Each technology is represented by a generic facility of a specific size and configuration, in a location that 

does not have unusual constraints or infrastructure requirements. Where possible, costs estimates were 

based on information derived from actual or planned projects known to the consultant. When this 

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

the current labor and materials rates necessary to complete the construction of a generic facility as well 

as consistent assumptions for the contractual relationship between the project owner and the 

construction contractor.

The specific overnight costs for each type of facility were broken down to include:

• Civil and structural costs: allowance for site preparation, drainage, the installation of 

underground utilities, structural steel supply, and construction of buildings on the site

• Mechanical equipment supply and installation: major equipment, including but not limited to, 

boilers, flue gas desulfurization scrubbers, cooling towers, steam turbine generators, 

condensers, photovoltaic modules, combustion turbines, and other auxiliary equipment

• Electrical and instrumentation and control: electrical transformers, switchgear, motor control 

centers, switchyards, distributed control systems, and other electrical commodities

 1 U.S. Energy Information Administration, Updated Capital Cost Estimates for Electricity Generation Plants November 2010 2 The term “overnight” refers to the cost of the project as if no interest were incurred during its construction.
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 2

• Project indirect costs: engineering, distributable labor and materials, craft labor overtime and 

incentives, scaffolding costs, construction management start up and commissioning, and fees 

for contingency3

• Owners costs: 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 tie-in to a nearby electrical 

transmission system

Non-fuel operations and maintenance (O&M) costs associated with each of the power plant 

technologies were evaluated as well. The O&M costs that do not vary significantly with a plant’s 

electricity generation are classified as fixed, while the costs incurred to generate electricity are classified 

as variable. The heat rates4 were also evaluated for the appropriate technologies.

It should be noted that all estimates provided in this report are broad in scope. A more in-depth cost 

assessment would require a more detailed level of engineering and design work, tailored to a specific 

site.

Findings

Table 1 summarizes updated cost estimates for generic utility-scale generating plants, including seven 

powered by coal, six by natural gas, three by solar energy, two each by wind, hydroelectric, biomass, 

and geothermal power, and one each by uranium and municipal solid waste. EIA does not model all of 

these generating plant types, but included them in the study in order to present consistent cost and 

performance information for a broad range of generating technologies. Additionally, while EIA does 

model new geothermal and hydroelectric capacity, site specific cost estimates from alternate sources 

are used in the NEMS model. The specific technologies represented in the NEMS model for AEO2013

that use the cost data from this report are identified in the last column of Table 1. 

Table 2 compares the updated overnight cost estimates to those developed for the 2010 report. To 

facilitate comparisons, the costs are expressed in 2012 dollars.5 Notable changes include:

• Integrated Gasification Combined Cycle (IGCC) Coal Plants with and without carbon capture 

and storage (CCS): The updated overnight capital cost estimates for single unit IGCC plants with 

and without CCS both rose by approximately 19 percent. This change can be primarily attributed 

to more recent information from current IGCC projects in various stages of the development 

process.6

 3 Fees for contingency include contractor overhead costs, fees, profit, and construction.

4 Heat Rate is a measure of generating station thermal efficiency commonly stated as Btu per kilowatthour. 5 U.S. Energy Information Administration, Annual Energy Outlook 2013, Table 20, GDP chain-type price index. 6 The increase in cost for IGCC with CCS resulted in EIA revising its technology assumption for new coal plants with CCS in EIA’s 

projections. EIA’s National Energy Modeling System (NEMS) includes one option for coal with CCS, and in AEO2012 new coal 

plants with CCS were assumed to have the characteristics consistent with those of an IGCC unit with CCS. However, due to the 

difference in costs between advanced pulverized coal (PC) with CCS and IGCC with CCS presented in the 2013 update, the 

assumed characteristics of a coal plant with CCS in NEMS were assumed to be consistent with those of an advanced PC plant 

with CCS for the AEO2013. 
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 3

• Conventional Natural Gas Combined Cycle (NGCC): The updated overnight capital cost for 

conventional NGCC plants declined by 10 percent relative to the cost in the 2010 study. In 

addition, the assumed capacity of these units rose from 540 MW in the 2010 study to 620 MW. 

• Onshore Wind: Overnight costs for onshore wind decreased by approximately 13 percent 

relative to the 2010 study, primarily due to lower wind turbine prices.

• Solar Photovoltaic: The overnight capital costs for solar photovoltaic technologies decreased by 

22 percent for 150 MW photovoltaic units from the costs presented in the 2010 study. The size

of the smaller photovoltaic units evaluated was increased from 7 MW in the 2010 study to 20 

MW in the 2013 study. Although it is not entirely consistent to compare these two systems, 

there was a significant decline in costs on a $/kW basis from the 7 MW system to the 20 MW 

system. The overall decreases in costs can be attributed to a decline in the component costs and 

construction cost savings for the balance of plant. 

As previously noted, costs are developed using a consistent methodology that includes a broad project 

scope and includes indirect and owners costs. The cost figures will not necessarily match those derived 

in other studies that employ different approaches to cost estimation. 

It should also be noted that when modeling geothermal and hydroelectric power resources, EIA uses 

site-specific sources for the technology cost estimates, and not the estimates provided by the 

consultant, due to the site specific nature of those resource supply models.

EIA's analysis of technology choice in the electric power sector

EIA’s modeling employs a net present value (NPV) capital budgeting methodology to evaluate different 

investment options for new power plants. Estimates of the overnight capital cost, fixed and variable 

operations and maintenance costs, and plant heat rates for generic generating technologies serve as a 

starting point for developing the total cost of new generating capacity. However, other parameters also 

play a key role in determining the total capital costs. Because several of these factors are dynamic, the 

realized overall capital cost for given technologies can vary based on a variety of circumstances. Five of 

the most notable parameters are:

• Financing: EIA determines the cost of capital required to build new power plants by calculating 

a weighted average cost of capital using a mix of macro-economic parameters determined 

through EIA’s modeling and an assumed capital structure for the electric power industry. 

• Lead Time: The amount of time needed to build a given type of power plant varies by 

technology. Projects with longer lead times increase financing costs. Each year of construction 

represents a year of additional interest charges before the plant is placed in service and starts 

generating revenue. 
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 4

• Inflation of material and construction costs: The projected relationship between the rate of 

inflation for the overall economy and key drivers of plant costs, such as materials and 

construction, are important elements impacting overall plant costs. A projected economy-wide

inflation rate that exceeds the projected inflation rate for materials and construction costs 

results in a projected decline in real (inflation-adjusted) capital costs and vice versa.

• Resource Supply: Technologies such as wind, geothermal, or hydroelectric must be sited in 

suitable locations to take advantage of the particular resource. In order to capture the site 

specific costs associated with these technologies, EIA develops upward sloping supply curves for

each of these technologies. These curves assume that the lowest-cost, most-favorable resources 

will be developed first, and that costs associated with the technology will increase as only 

higher-cost, less-favorable sites are left to be developed. 

• Learning by doing: The overnight capital costs developed for the report serve as an input to 

EIA’s long term modeling and represent the cost of construction for a project that could begin as 

early as 2013. However, these costs are assumed to decrease over time in real terms as 

equipment manufacturers, power plant owners, and construction firms gain more experience 

with certain technologies. The rate at which these costs decline is often referred to as the 

learning rate. 

EIA determines learning rates at the power plant component level, not for the power plant technology 

itself because some technologies share the same component types. It is assumed that the knowledge 

and experienced gained through the manufacture and installation of a given component in one type of 

power plant can be carried over to the same component in another type of plant. As an example, the 

experience gained through the construction of combined cycle natural gas plants can be leveraged to 

influence the overall cost of building an IGCC unit, which in part, includes the components of a 

combined cycle natural gas plant. Other technologies, such as nuclear power and pulverized coal (PC) 

plants without CCS, do not share component systems, and their learning rates are determined solely as 

a function of the amount of capacity built over time.

Technologies and their components are represented in the NEMS model at various stages of maturity. 

EIA classifies technologies into three such stages: mature, evolutionary, and revolutionary. The 

technology classification determines the rate of cost reduction that can be achieved through the 

learning function. Generally, overnight costs for technologies and associated components decline at a 

specified rate based on a doubling of new capacity. The cost decline is fastest for revolutionary 

technologies and slower for evolutionary and mature technologies.7

The capacity additions used to influence learning are primarily developed from NEMS results. However, 

external capacity additions from international projects are also included for some technologies, to 

account for additional learning from such projects. For power plant technologies with multiple 

components, the capacity additions are weighted by the contribution of each component to the overall 

plant construction cost.8

 7 U.S. Energy Information Administration, AEO 2012 Electricity Market Module Assumptions Document, Table 8.3. 8 U.S. Energy Information Administration, AEO 2012 Electricity Market Assumptions Document, Table 8.4.
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 5

Table 3 classifies the status of each technology and component as modeled in AEO2013. 

The NEMS model also assumes that efficiency for all fossil-fueled plants improves as a result of learning 

by doing. The power plant heat rates provided by the consultant are intended to represent the 

characteristics of a plant that starts construction in 2013, referred to as “first-of-a-kind.” NEMS assumes 

that the heat rate for all fossil fueled technologies declines over time to a level referred to as an “nth-ofa-kind” heat rate.9 The magnitude of heat rate improvement depends on the current state of the 

technology, with revolutionary technologies seeing a more significant decline in heat rate than mature 

technologies. Heat rate improvements are independent to capacity expansion. Fixed and variable O&M 

are not assumed to achieve learning-related savings.

Impact of location on power plant capital costs

The estimates provided in this report are representative of a generic facility located in a region without 

any special issues that would alter its cost. However, the cost of building power plants in different 

regions of the United States can vary significantly. The report includes location-based cost adjustment 

tables for each technology in 64 metropolitan areas. These adjustments were made to reflect the impact 

of remote location costs, costs associated with seismic design that may vary by region, and labor wage 

and productivity differences by region. In order to reflect these costs in EIA’s modeling, these 

adjustments were aggregated to represent the 22 Electricity Market Module regions. EIA also assumes 

that the development of certain technologies is not feasible in given regions for geographic, logistical, or 

regulatory reasons. The regional cost adjustments and development restrictions are summarized in 

Table 4.

Summary

The estimates provided by the consultant for this report are key inputs for EIA electric market 

projections, but they are not the sole driver of electric generation capacity expansion decisions. The 

evolution of the electricity mix in each of the 22 regions to be modeled in AEO2013 is sensitive to many 

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, and future electricity demand. 

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

consultant study prepared by SAIC Energy Environment and Infrastructure in Appendix B.

 9 U.S. Energy Information Administration, AEO 2013 Cost and Performance Characteristics of New Central Station Electricity 

Generating Technologies,, Table 8.2.
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 6

Table 1. Updated estimates of power plant capital and operating costs

Plant Characteristics Plant Costs (2012$)

Nominal 

Capacity 

(MW)

Heat Rate 

(Btu/kWh)

Overnight 

Capital Cost 

($/kW)

Fixed O&M 

Cost ($/kW-yr)

Variable 

O&M Cost 

($/MWh)

NEMS 

Input

 Coal

Single Unit Advanced PC 650 8,800 $3,246 $37.80 $4.47 N

Dual Unit Advanced PC 1,300 8,800 $2,934 $31.18 $4.47 Y

Single Unit Advanced PC with CCS 650 12,000 $5,227 $80.53 $9.51 Y

Dual Unit Advanced PC with CCS 1,300 12,000 $4,724 $66.43 $9.51 N

Single Unit IGCC 600 8,700 $4,400 $62.25 $7.22 N

Dual Unit IGCC 1,200 8,700 $3,784 $51.39 $7.22 Y

Single Unit IGCC with CCS 520 10,700 $6,599 $72.83 $8.45 N

 Natural Gas

Conventional CC 620 7,050 $917 $13.17 $3.60 Y

Advanced CC 400 6,430 $1,023 $15.37 $3.27 Y

Advanced CC with CCS 340 7,525 $2,095 $31.79 $6.78 Y

Conventional CT 85 10,850 $973 $7.34 $15.45 Y

Advanced CT 210 9,750 $676 $7.04 $10.37 Y

Fuel Cells 10 9,500 $7,108 $0.00 $43.00 Y

 Uranium

Dual Unit Nuclear 2,234 N/A $5,530 $93.28 $2.14 Y

 Biomass

Biomass CC 20 12,350 $8,180 $356.07 $17.49 N

Biomass BFB 50 13,500 $4,114 $105.63 $5.26 Y

 Wind

Onshore Wind 100 N/A $2,213 $39.55 $0.00 Y

Offshore Wind 400 N/A $6,230 $74.00 $0.00 Y

 Solar

Solar Thermal 100 N/A $5,067 $67.26 $0.00 Y

Photovoltaic 20 N/A $4,183 $27.75 $0.00 N

Photovoltaic 150 N/A $3,873 $24.69 $0.00 Y

 Geothermal 

Geothermal – Dual Flash 50 N/A $6,243 $132.00 $0.00 N

Geothermal – Binary 50 N/A $4,362 $100.00 $0.00 N

 Municipal Solid Waste

Municipal Solid Waste 50 18,000 $8,312 $392.82 $8.75 N

 Hydroelectric

Conventional Hydroelectric 500 N/A $2,936 $14.13 $0.00 N

Pumped Storage 250 N/A $5,288 $18.00 $0.00 N
April 2013

U.S. Energy Information Administration   |   Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 7

Table 2. Overnight cost comparison with 2010 estimates

  

Overnight Capital Costs     (2012

$/kW)

2013

Report

2010

Report

%

Difference

   Coal

Single Unit Advanced PC   $3,246 $3,292  ‐1%

Dual Unit Advanced PC   $2,934 $2,956  ‐1%

Single Unit Advanced PC with CCS $5,227 $5,300  ‐1%

Dual Unit Advanced PC with CCS $4,724 $4,760  ‐1%

Single Unit IGCC   $4,400 $3,706 19%

Dual Unit IGCC $3,784 $3,348 13%

Single Unit IGCC with CCS $6,599 $5,559 19%

   Natural Gas

Conventional CC $917 $1,017  ‐10%

Advanced CC $1,023 $1,043  ‐2%

Advanced CC with CCS $2,095 $2,141  ‐2%

Conventional CT $973 $1,012  ‐4%

Advanced CT $676 $691  ‐2%

Fuel Cells $7,108 $7,105 0%

   Uranium

Dual Unit Nuclear $5,530 $5,546 0%

   Biomass

Biomass CC $8,180 $8,205 0%

Biomass BFB $4,114 $4,012 3%

   Wind

Onshore Wind $2,213 $2,534  ‐13%

Offshore Wind $6,230 $6,211 0%

   Solar

Solar Thermal   $5,067 $4,877 4%

Solar Photovoltaic (7 MW) N/A $6,289 N/A

Solar Photovoltaic (20 MW) $4,183 N/A N/A

Solar Photovoltaic (150 MW) $3,873 $4,943  ‐22%

   Geothermal

Geothermal – Dual Flash $6,243 $5,798 8%

Geothermal – Binary $4,362 $4,304 1%

   Municipal Solid Waste

Municipal SolidWaste $8,312 $8,557  ‐3%

   Hydroelectric

Conventional Hydroelectric $2,936 $3,197  ‐8%

Pumped Storage $5,288 $5,816  ‐9%
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 8

Table 3. Status of technologies and components modeled by EIA

Revolutionary Evolutionary Mature

Pulverized Coal X

Pulverized Coal with CCS

 - Non-CCS portion of Pulverized Coal Plant X

 - CCS X

Integrated Gasification Combined Cycle

 - Advanced Combustion Turbine X

 - Heat Recovery Steam Generator X

 - Gasifier X

 - Balance of Plant X

Conventional Natural Gas Combined Cycle

- Conventional Combustion Turbine X

- Heat Recovery Steam Generator X

- Balance of Plant X

Advanced Natural Gas Combined Cycle

- Advanced Combustion Turbine X

- Heat Recovery Steam Generator X

- Balance of Plant X

Advanced Natural Gas Combined Cycle with CCS

- Advanced Combustion Turbine X

- Heat Recovery Steam Generator X

- Balance of Plant X

- CCS X

Conventional Natural Gas Combustion Turbine

- Conventional Combustion Turbine X

- Balance of Plant X

Advanced Natural Gas Combustion Turbine

- Advanced Combustion Turbine X

- Balance of Plant X

Advanced Nuclear X

Biomass

- Pulverized Coal X

- Fuel Preparation X

Geothermal X

Municipal Solid Waste/Landfill Gas X

Conventional Hydroelectric X
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 9

Table 3. Status of technologies and components modeled by EIA (cont.)

Revolutionary Evolutionary Mature

Wind

- Onshore/Common Components X

- Offshore Components X

Solar Thermal X

Solar PV

- Modules (Utility and End Use) X

- Utility Balance of Plant X
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 10

Table 4. Regional cost adjustments for technologies modeled by NEMS by Electric Market Module (EMM) region 10,11

EMM 

Region PC IGCC

PC

w/CCS

Conv. 

CT

Adv. 

CT

Conv. 

CC

Adv. 

CC

Adv. CC 

w/CCS

Fuel 

Cell Nuclear Biomass MSW

Onshore 

Wind

Offshore 

Wind

Solar 

Thermal

Solar 

PV

1 (ERCT) 0.91 0.92 0.92 0.93 0.95 0.91 0.92 0.90 0.96 0.96 0.93 0.93 0.95 0.92 0.86 0.87

2 (FRCC) 0.92 0.93 0.94 0.93 0.93 0.91 0.92 0.92 0.97 0.97 0.94 0.94 N/A N/A 0.89 0.90

3 (MROE) 1.01 1.01 0.99 0.99 1.01 0.99 0.99 0.97 0.99 1.01 0.99 0.98 0.99 0.97 N/A 0.96

4 (MROW) 0.95 0.96 0.96 0.98 1.00 0.97 0.97 0.96 0.98 0.98 0.96 0.96 1.03 1.01 N/A 0.95

5 (NEWE) 1.10 1.09 1.05 1.16 1.20 1.16 1.15 1.08 1.01 1.05 1.04 1.02 1.06 1.03 N/A 1.03

6 (NYCW) N/A N/A N/A 1.63 1.68 1.68 1.66 1.50 1.14 N/A 1.26 1.26 N/A 1.29 N/A N/A

7 (NYLI) N/A N/A N/A 1.63 1.68 1.68 1.66 1.50 1.14 N/A 1.26 1.26 1.25 1.29 N/A 1.45

8 (NYUP) 1.11 1.10 1.05 1.17 1.22 1.16 1.16 1.06 1.00 1.07 1.03 1.00 1.01 0.99 N/A 0.98

9 (RFCE) 1.15 1.14 1.09 1.21 1.25 1.21 1.21 1.12 1.02 1.08 1.07 1.03 1.05 1.03 N/A 1.05

10 (RFCM) 0.98 0.98 0.98 1.01 1.02 1.00 1.00 0.99 0.99 0.99 0.98 0.98 1.00 0.98 N/A 0.97

11 (RFCW) 1.05 1.04 1.02 1.05 1.06 1.04 1.04 1.02 1.00 1.03 1.02 1.00 1.02 1.01 N/A 1.00

12 (SRDA) 0.92 0.93 0.93 0.95 0.96 0.93 0.93 0.92 0.97 0.96 0.93 0.94 0.96 1.00 N/A 0.89

13 (SRGW) 1.07 1.06 1.05 1.05 1.05 1.06 1.05 1.04 1.02 1.03 1.03 1.03 1.04 1.00 N/A 1.05

14 (SRSE) 0.92 0.93 0.93 0.95 0.97 0.93 0.94 0.92 0.97 0.96 0.93 0.94 0.96 0.93 N/A 0.89

15 (SRCE) 0.93 0.94 0.94 0.94 0.95 0.93 0.93 0.92 0.97 0.97 0.94 0.94 0.96 1.00 N/A 0.89

16 (SRVC) 0.89 0.91 0.91 0.91 0.93 0.88 0.89 0.88 0.96 0.95 0.91 0.91 0.95 0.92 N/A 0.84

17 (SPNO) 0.98 0.99 0.98 1.00 1.01 0.99 0.99 0.98 0.99 0.99 0.98 0.98 1.02 N/A 0.97 0.97

18 (SPSO) 0.98 0.99 0.98 1.00 1.01 0.99 0.99 0.98 0.99 0.99 0.98 0.98 1.02 N/A 0.97 0.97

19 (AZNM) 1.00 1.00 0.99 1.03 1.04 1.02 1.02 1.00 0.99 1.00 1.00 0.99 1.03 1.00 0.99 0.99

20 (CAMX) N/A N/A 1.12 1.24 1.29 1.25 1.24 1.15 1.03 N/A 1.08 1.06 1.12 1.05 1.13 1.11

21 (NWPP) 1.01 1.01 1.00 1.02 1.03 1.01 1.01 0.99 0.99 1.01 1.00 0.98 1.05 1.02 0.99 0.99

22 (RMPA) 0.99 0.99 0.97 1.02 1.05 1.01 1.01 0.96 0.98 1.01 0.97 0.95 1.03 N/A 0.93 0.93

Note: Geothermal and Hydroelectric plants are not included in the table because EIA uses site specific cost estimates for these technologies which include regional factors. 

 10 U.S. Energy Information Administration, AEO 2012 EMM Assumptions document, Figure 6. 11 The regional tables in the report were aggregated to the appropriate Electricity Market Module region in order to represent regional cost factors in NEMS.
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 11

Appendix A - Acronym List

BFB - Bubbling Fluidized Bed

CC - Combined Cycle

CCS - Carbon Capture and Sequestration

CT - Combustion Turbine

IGCC - Integrated Gasification Combined Cycle

PC - Pulverized Coal 

PV – Photovoltaic
April 2013

U.S. Energy Information Administration | Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants 12

Appendix B – Full Report
Science Applications International Corporation (SAIC) 

Formerly R. W. Beck 

Prepared by: 

SAIC Energy, Environment & Infrastructure, LLC 

Prepared For: 

Energy Information Administration 

Office of Energy Analysis 

Alan Beamon 

Michael Leff 

February 2013 

 

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 SAIC 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 .................................................................................................. 2-7

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 .......................................................................................... 2-9

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 ...................................................................................................... 3-5

3.6 Environmental Compliance Information ............................................................... 3-5

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 ...................................................................................................... 4-4

4.6 Environmental Compliance Information ............................................................... 4-4
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 ...................................................................................................... 5-5

5.6 Environmental Compliance Information ............................................................... 5-6

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 ............................................................................................ 6-2

6.5 O&M Estimate ...................................................................................................... 6-3

6.6 Environmental Compliance Information ............................................................... 6-3

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 ...................................................................................................... 7-2

7.6 Environmental Compliance Information ............................................................... 7-2

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 ...................................................................................................... 8-3

8.6 Environmental Compliance Information ............................................................... 8-4

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 ...................................................................................................... 9-2

9.6 Environmental Compliance Information ............................................................... 9-3

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 .................................................................................................... 10-7

10.6 Environmental Compliance Information ............................................................. 10-7

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 .................................................................................................... 11-2

11.6 Environmental Compliance Information ............................................................. 11-2

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

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

12.2 Electrical and Control Systems ........................................................................... 12-3

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

12.4 Capital Cost Estimate .......................................................................................... 12-4

12.5 O&M Estimate .................................................................................................... 12-5

12.6 Environmental Compliance Information ............................................................. 12-5

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 .................................................................................................... 13-6

13.6 Environmental Compliance Information ............................................................. 13-6

14. Biomass Bubbling Fluidized 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 .................................................................................................... 14-5

14.6 Environmental Compliance Information ............................................................. 14-5

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 .................................................................................................... 15-3

15.5 Environmental Compliance Information ............................................................. 15-3

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 .................................................................................................... 16-5

16.6 Environmental Compliance Information ............................................................. 16-5

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 .................................................................................................... 17-3

17.6 Environmental Compliance Information ............................................................. 17-4
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 .................................................................................................... 18-4

18.6 Environmental Compliance Information ............................................................. 18-4

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 .................................................................................................... 19-4

19.6 Environmental Compliance Information ............................................................. 19-4

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 .................................................................................................... 20-3

20.6 Environmental Compliance Information ............................................................. 20-3

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

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

21.2 Electrical and Control Systems ........................................................................... 21-1

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

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

21.5 O&M Estimate .................................................................................................... 21-3

21.6 Environmental Compliance Information ............................................................. 21-4

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 ......................................................................................... 22-3

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

22.5 O&M Estimate .................................................................................................... 22-4

22.6 Environmental Compliance Information ............................................................. 22-4

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

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

23.2 Electrical and Control Systems ........................................................................... 23-1

23.3 Off-Site Requirements ......................................................................................... 23-1

23.4 Capital Cost Estimate .......................................................................................... 23-2

23.5 O&M Estimate .................................................................................................... 23-3

23.6 Environmental Compliance Information ............................................................. 23-3

24. Utility-Scale Photovoltaic (PV) Facility .................................................................. 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 .................................................................................................... 24-5

24.6 Environmental Compliance Information ............................................................. 24-5
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 ................................................................................... 12-3

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

Figure 14-1 – BBFB 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 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) ......................................................... 3-1

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

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

Table 3-6 – O&M Expenses for APC (1,300,000 kW) ................................................................ 3-5

Table 3-7 – Environmental Emissions for APC .......................................................................... 3-6

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) .................................... 4-5

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

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

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

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

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

Table 5-2 – Location-Based Costs for Conventional NGCC....................................................... 5-9

Table 5-3 – O&M Expenses for Conventional NGCC ................................................................ 5-6

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

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

Table 6-2 – Location-Based Costs for AG-NGCC .................................................................... 6-11

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

Table 6-4 – Environmental Emissions for AG-NGCC ................................................................ 6-3

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 ........................................................... 7-13
ix 

Table 7-3 – O&M Expenses for AG-NGCC With CCS .............................................................. 7-2

Table 7-4 – Environmental Emissions for AG-NGCC/CCS ....................................................... 7-3

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

Table 8-2 – Location-Based Costs for Conventional CT........................................................... 8-15

Table 8-3 – O&M Expenses for Conventional CT ...................................................................... 8-4

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

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

Table 9-2 – Location-Based Costs for Advanced CT ................................................................ 9-17

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

Table 9-4 – Environmental Emissions for Advanced CT ............................................................ 9-3

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) ................................................... 10-6

Table 10-4 – Location-Based Costs for IGCC (1,200,000 kW) .............................................. 10-21

Table 10-5 – O&M Expenses for IGCC (600,000 kW) ............................................................. 10-7

Table 10-6 – O&M Expenses for IGCC (1,200,000 kW) .......................................................... 10-7

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

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

Table 11-2 – Location-Based Costs for IGCC/CCS ................................................................ 11-23

Table 11-3 – O&M Expenses for IGCC/CCS............................................................................ 11-2

Table 11-4 – Environmental Emissions for IGCC/CCS ............................................................ 11-3

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

Table 12-2 – Location-Based Costs for AN ............................................................................ 12-25

Table 12-3 – O&M Expenses for AN ........................................................................................ 12-5

Table 12-4 – Environmental Emissions for AN ........................................................................ 12-5

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

Table 13-2 – Location-Based Costs for BCC ............................................................................ 13-5

Table 13-3 – O&M Expenses for BCC ...................................................................................... 13-6

Table 13-4 – Environmental Emissions for BCC ...................................................................... 13-6

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

Table 14-2 – Location-Based Costs for BBFB .......................................................................... 14-4

Table 14-3 – O&M Expenses for BCC ...................................................................................... 14-5

Table 14-4 – Environmental Emissions for BBFB .................................................................... 14-5
x 

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

Table 15-2 – Location-Based Costs for FC ............................................................................. 15-31

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

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

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

Table 16-2 – Location-Based Costs for GT ............................................................................... 16-4

Table 16-3 – O&M Expenses for GT ........................................................................................ 16-5

Table 16-4 – Environmental Emissions for GT ......................................................................... 16-5

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

Table 17-2 – Location-Based Costs for GT ............................................................................. 17-35

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

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

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

Table 18-2 – Location-Based Costs for MSW ......................................................................... 18-37

Table 18-3 – O&M Expenses for MSW .................................................................................... 18-4

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

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

Table 19-2 – Location-Based Costs for HY ............................................................................ 19-39

Table 19-3 – O&M Expenses for HY ........................................................................................ 19-4

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

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

Table 20-2 – Location-Based Costs for PS .............................................................................. 20-41

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

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

Table 21-1 – Location-Based Costs for WN.............................................................................. 21-2

Table 21-2 – Location-Based Costs for WN............................................................................ 21-43

Table 21-3 – O&M Expenses for WN ....................................................................................... 21-4

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

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

Table 22-2 – Location-Based Costs for WF ............................................................................ 22-45

Table 23-1 – Base Plant Site Capital Cost Estimate for SO ...................................................... 23-2

Table 23-2 – Location-Based Costs for SO ............................................................................. 23-47

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

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

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) ............................................................... 24-49

Table 24-4 – Location-Based Costs for PV (150 MW) ........................................................... 24-51

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

Table 24-6 – O&M Expenses for PV Facility (150 MW) ......................................................... 24-5

Table 24-7 – Environmental Emissions for PV ......................................................................... 24-6
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 

ISO International Standard Organization 

kg Kilograms 

KJ Kilojoules 

kW Kilowatt 

kWh Kilowatt-hour 

kV Kilovolt 

kVA kilovolt-amperes 

lb Pound 

LHV Low(er) Heating Value 

LP 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 
xiv 

SNCR Selective Non-catalytic Reduction 

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 SAIC’s 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 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”) 

620 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 2,234 megawatt (“MW”); AP1000 

PWR Basis 

Brownfield Installation 

Biomass Combined Cycle 20 MWe Wood Fuel 

Biomass Bubbling Fluidized 

Bed (“BBFB”) 

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 20 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 SAIC BACKGROUND 

SAIC is a technical solutions and infrastructure consulting firm that has been providing technical 

and business consulting in the energy industry since 1942. Particularly, SAIC 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 SAIC’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 which was 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, SAIC 

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 International Standard Organization (“ISO”) net 

capacity for the CT-based power plant technologies. 
2-5

TABLE 2-4 – CT CAPACITY ADJUSTMENTS 
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 

The approach taken in this latest cost analysis of capital and operating estimates concentrated 

primarily in these three areas: 

1. Escalation over the past two years. 

2. Technology Specific changes in pricing, for instance, overall wind a solar capex pricing 

lowered due to lower equipment pricing. 

3. Updated actual costs being made available to Projects we are familiar with. 

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 2012 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 
2-7

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, 

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 
2-8

24 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. 

2.6.2.1 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 
2-9

• 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 

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. 

• Major maintenance expenses are included in the O&M Expenses for each plant. These 

expenses may be in either the fixed or variable O&M rate depending on the cost structure 

of the particular plant considering such things as capacity factor, hour and start cycling 

patterns, O&M contract structure (if applicable), and major maintenance timing triggers 
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 3,246 37.80 4.47 0.1 (7) Advanced Pulverized Coal Coal 1,300,000 8,800 2,934 31.18 4.47 0.1 (7) Advanced Pulverized Coal with CCS Coal 650,000 12,000 5,227 80.53 9.51 0.02 (10) Advanced Pulverized Coal with CCS Coal 1,300,000 12,000 4,724 66.43 9.51 0.02 (10) NGCC Gas 620,000 7,050 917 13.17 3.60 0.001 AG-NGCC Gas 400,000 6,430 1,023 15.37 3.27 0.001 Advanced NGCC with CCS Gas 340,000 7,525 2,095 31.79 6.78 0.001 Conventional CT Gas 85,000 10,850 973 7.34 15.45 0.001 Advanced CT Gas 210,000 9,750 676 7.04 10.37 0.001 IGCC Coal 600,000 8,700 4,400 62.25 7.22 0.025 (10) IGCC Coal 1,200,000 8,700 3,784 51.39 7.22 0.025 (10) IGCC with CCS Coal 520,000 10,700 6,599 72.83 8.45 0.015 (10)(Advanced Nuclear Uranium 2,234,000 N/A 5,530 93.28 2.14 0 Biomass Combined Cycle Biomass 20,000 12,350 8,180 356.07 17.49 0 Biomass BFB Biomass 50,000 13,500 4,114 105.63 5.26 0 Fuel Cells Gas 10,000 9,500 7,108 0 43.00 0.00013 Geothermal – Dual Flash Geothermal 50,000 N/A 6,243 132.00 0 0.2 (13) Geothermal – Binary Geothermal 50,000 N/A 4,362 100.00 0 0.2 (13) MSW MSW 50,000 18,000 8,312 392.82 8.75 0.07 (14) Hydroelectric Hydro 500,000 N/A 2,936 14.13 0 0 Pumped Storage Hydro 250,000 N/A 5,288 18.00 0 0 Onshore Wind Wind 100,000 N/A 2,213 39.55 0 0 Offshore Wind Wind 400,000 N/A 6,230 74.00 0 0 Solar Thermal Solar 100,000 N/A 5,067 67.26 0 0 Photovoltaic Solar 20,000 N/A 4,183 27.75 0 0 Photovoltaic – Tracking Solar 150,000 N/A 3,873 24.69 0 0 Photovoltaic – Tracking with 10% storage Solar 150,000 N/A 4,054 Photovoltaic – Tracking with 20% storage Solar 150,000 N/A 4,236 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. 

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

(9) Assuming 90 percent capture. 

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

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

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

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

(14) Based on 30 ppmvd at 7 percent O2 – 5,000 Btu/lb HHV of MSW – Large Municipal Waste Combustor Rules 

(15) Based on 150 ppmvd at 7 percent O2 - 5,000 Btu/lb HHV of MSW- Large Municipal Waste Combustor Rules 
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 
3-3

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

Advanced Pulverized Coal Facility. 

3.4 CAPITAL COST ESTIMATE 

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

capacity of 650 MW is $3,246/kilowatt (“kW”) and with a nominal capacity of 1,300 MW is 

$2,934/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, 2012$)

 

Civil Structural Material and Installation 230,000 

Mechanical Equipment Supply and 

Installation 863,500 

Electrical / I&C Supply and Installation 132,000 

Project Indirects (1) 350,000 

EPC Cost before Contingency and Fee 1,575,500 

Fee and Contingency 183,000 

Total Project EPC 1,758,500 

Owner's Costs (excluding project finance) 351,700 

Total Project Cost (excluding finance) 2,110,200 

Total Project EPC $ / kW 2,705 

Owner Costs 20% (excluding project finance) $ / kW 541 

Total Project Cost (excluding project finance) $ / kW 3,246 

(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, 2012$)

 

Civil Structural Material and Installation 413,140 

Mechanical Equipment Supply and 

Installation 1,659,944 

Electrical / I&C Supply and Installation 244,400 

Project Indirects (1) 608,140 

EPC Cost before Contingency and Fee 2,925,624 

Fee and Contingency 307,191 

Total Project EPC 3,232,815 

Owner Costs (excluding project finance) 581,907 

Total Project Cost (excluding finance) 3,814,722 

Total Project EPC $ / kW 2,486 

Owner Costs 18% (excluding project finance) $ / kW 448 

Total Project Cost (excluding project finance) $ / kW 2,934 

(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, Louisiana, 

Mississippi, New Mexico, and South Carolina. 

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; Albuquerque, New Mexico; and Cheyenne, Wyoming. 

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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts, 

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 in the Appendix 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. 

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 $37.80/kW-year 

Variable O&M Expense $4.47/MWh 

TABLE 3-6 – O&M EXPENSES FOR APC (1,300,000 KW) 

Technology: APC 

Fixed O&M Expense $31.18/kW-year 

Variable O&M Expense $4.47/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 
3-6

emissions of NOX and SO2, respectively. Table 3-7 presents the environmental emissions for the 

APC Facility. 

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 

$5,227/kW and with a nominal capacity of 1,300,000 MW is $4,724/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, 2012$)

 

Total Project EPC 2,831,694 

Owner Costs (excluding project finance) 566,339 

Total Project Cost (excluding finance) 3,398,033 

Total Project EPC / kW 4,356 

Owner Costs 20% (excluding project finance) / kW 871 

Total Project Cost (excluding project finance) / kW 5,227 

(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, 2012$)

 

Total Project EPC 5,205,119 

Owner Costs (excluding project finance) 936,921 

Total Project Cost (excluding finance) 6,142,040 

Total Project EPC / kW 4,004 

Owner Costs 18% (excluding project finance) / kW 720 

Total Project Cost (excluding project finance) / kW 4,724 

(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 in the Appendix 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. 

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 $80.53/kW-year 

Variable O&M Expense $9.51/MWh 

TABLE 4-6 – O&M EXPENSES FOR APC/CCS (1,300,000 KW) 

Technology: APC/CCS 

Fixed O&M Expense $66.43/kW-year 

Variable O&M Expense $9.51/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 620 MW of net electricity. The facility utilizes two natural 

gas-fueled F5-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 205 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 

dissolved solids from the cooling water and to provide distilled water for HRSG makeup. 
5-3

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 

620 MW is $917/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): 620,000 kW 

Nominal Heat Rate (ISO): 7,050 Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2012$)

 

Civil Structural Material and Installation 41,740 

Mechanical Equipment Supply and 

Installation 256,480 

Electrical / I&C Supply and Installation 37,340 

Project Indirects (1) 92,196 

EPC Cost before Contingency and Fee 427,756 

Fee and Contingency 46,198 

Total Project EPC 473,954 

Owner Costs (excluding project finance) 94,791 

Total Project Cost (excluding finance) 568,745 

Total Project EPC / kW 764 

Owner Costs 20% (excluding project finance) / kW 153 

Total Project Cost (excluding project finance) / kW 917 

(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 

compared to cooling towers, seismic design differences, zero-water discharge issues, local 
5-4

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, Oregon, Pennsylvania, 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, but are not limited to, 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 in the Appendix 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. 

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 16,000 operating hour intervals. Table 5-3 presents 

the O&M expenses for the Conventional NGCC Facility. 
5-6

TABLE 5-3 – O&M EXPENSES FOR CONVENTIONAL NGCC 

Technology: Conventional NGCC 

Fixed O&M Expense $13.17/kW-year 

Variable O&M Expense $3.60/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 employs 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 AG-NGCC has advantages compared to the Conventional NGCC. 

The advantages of the AG-NGCC are for the same size of equipment – more megawatt output 

due to higher firing temperature. The higher firing temperature is due to more technically 

advanced metallurgical metals used, coatings used, and blade cooling systems that are 

technically advanced. The AG-NGCC may or may not have a better ramping rate depending on 

the geographical location of the facility. 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. 
6-2

6.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the AG-NGCC Facility with a nominal capacity of 400 MW is 

$1,023/kW. Table 6-1 summarizes the Cost Estimate categories for the Conventional NGCC 

Facility. 

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, 2012$)

 

Civil Structural Material and Installation 21,434 

Mechanical Equipment Supply and 

Installation 190,396 

Electrical / I&C Supply and Installation 25,792 

Project Indirects (1) 71,032 

EPC Cost before Contingency and Fee 308,654 

Fee and Contingency 32,409 

Total Project EPC 341,063 

Owner Costs (excluding project finance) 68,213 

Total Project Cost (excluding finance) 409,276 

Total Project EPC / kW 853 

Owner Costs 20% (excluding project finance) / kW 170 

Total Project Cost (excluding project finance) / kW 1,023 

(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 in the Appendix 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

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 $15.37/kW-year 

Variable O&M Expense $3.27/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. 

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 

$2,095/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 

 

Capital Cost Category (000s) (October 1, 2012$)

 

Total Project EPC 593,950 

Owner Costs (excluding project finance) 118,690 

Total Project Cost (excluding finance) 712,140 

Total Project EPC / kW 1,746 

Owner Costs 20% (excluding project finance) / kW 349 

Total Project Cost (excluding project finance) / kW 2,095 

(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 in the Appendix 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. 

7.5 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 $31.79/kW-year 

Variable O&M Expense $6.78/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. 
7-3

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 

$973/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, 2012$)

 

Civil Structural Material and Installation 5,793 

Mechanical Equipment Supply and 

Installation 33,520 

Electrical / I&C Supply and Installation 10,608 

Project Indirects (1) 12,738 

EPC Cost before Contingency and Fee 62,659 

Fee and Contingency 6,266 

Total Project EPC 68,925 

Owner Costs (excluding project finance) 13,785 

Total Project Cost (excluding finance) 82,710 

Total Project EPC / kW 811 

Owner Costs 20% (excluding project finance) / kW 162 

Total Project Cost (excluding project finance) / kW 973 

(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. 
8-3

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, 

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, but are not limited to, 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 in the Appendix presents the Conventional CT Facility capital cost variations for 

alternative U.S. plant locations. 

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 16,000 operating hour intervals; with more significant major maintenance 

outages occurring at 32,000 operating hour intervals; however, often times the major 

maintenance for a CT at a peaking facility is driven off of CT starts (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. 
8-4

TABLE 8-3 – O&M EXPENSES FOR CONVENTIONAL CT 

Technology: Conventional CT 

Fixed O&M Expense $7.34/kW-year 

Variable O&M Expense $15.45/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 2012) 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 

$676/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, 2012$)

 

Civil Structural Material and Installation 12,272 

Mechanical Equipment Supply and 

Installation 62,168 

Electrical / I&C Supply and Installation 15,912 

Project Indirects (1) 17,118 

EPC Cost before Contingency and Fee 107,470 

Fee and Contingency 10,747 

Total Project EPC 118,217 

Owner Costs (excluding project finance) 23,643 

Total Project Cost (excluding finance) 141,860 

Total Project EPC / kW 563 

Owner Costs 20% (excluding project finance) / kW 113 

Total Project Cost (excluding project finance) / kW 676 

(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 in the Appendix presents the Advanced CT Facility capital cost variations for 

alternative U.S. plant locations. 

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. 

 
9-3

TABLE 9-3 – O&M EXPENSES FOR ADVANCED CT 

Technology: Advanced CT 

Fixed O&M Expense $7.04/kW-year 

Variable O&M Expense $10.37/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. 

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

Source: Duke Energy 

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 
10-4

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 CAPITAL COST ESTIMATE 

The base Cost Estimate for the IGCC Facility with a nominal capacity of 600 MW is $4,400/kW 

and with a nominal capacity of 1,200 MW is $3,784/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, 2012$)

 

Civil Structural Material and Installation 114,650 

Mechanical Equipment Supply and 

Installation 1,210,600 

Electrical / I&C Supply and Installation 247,500 

Project Indirects (1) 392,000 

EPC Cost before Contingency and Fee 1,964,750 

Fee and Contingency 235,000 

Total Project EPC 2,199,750 

Owner Costs (excluding project finance) 439,950 

Total Project Cost (excluding finance) 2,639,700 

Total Project EPC / kW 3,666 

Owner Costs 20% (excluding project finance) / kW 734 

Total Project Cost (excluding project finance) / kW 4,400 

(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, 2012$)

 

Civil Structural Material and Installation 209,142 

Mechanical Equipment Supply and 

Installation 2,238,000 

Electrical / I&C Supply and Installation 426,000 

Project Indirects (1) 609,000 

EPC Cost before Contingency and Fee 3,482,142 

Fee and Contingency 365,625 

Total Project EPC 3,847,767 

Owner Costs (excluding project finance) 692,598 

Total Project Cost (excluding finance) 4,540,365 

Total Project EPC / kW 3206 

Owner Costs 18% (excluding project finance) / kW 578 

Total Project Cost (excluding project finance) / kW 3,784 

(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, Louisiana, 

Mississippi, New Mexico, and South Carolina. 

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; 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 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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts, 

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 in the Appendix present the IGCC Facility capital cost variations for 

alternative U.S. plant locations. 
10-7

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 Conventional 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 $62.25/kW-year 

Variable O&M Expense $7.22/MWh 

TABLE 10-6 – O&M EXPENSES FOR IGCC (1,200,000 KW) 

Technology: IGCC 

Fixed O&M Expense $51.39/kW-year 

Variable O&M Expense $7.22/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 

$6,599/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, 2012$)

 

Total Project EPC 3,299,125 

Owner Costs (excluding project finance) 659,825 

Total Project Cost (excluding finance) 3,958,950 

Total Project EPC / kW 5,499 

Owner Costs 20% (excluding project finance) / kW 1,100 

Total Project Cost (excluding project finance) / kW 6,599 

(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 in the Appendix presents the IGCC/CCS Facility capital cost variations for 

alternative U.S. plant locations. 

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 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 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 $72.83/kW-year 

Variable O&M Expense $8.45/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. 
11-3

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 at 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 typically encased in a zircalloy tube. The 

uranium atoms in the pellet absorb neutrons causing the nucleus of the uranium atoms to split, or 

fission. When the uranium atom splits, a large amount of energy, as well as additional neutrons 

and fission fragments are released. The resulting nuclei contain a great deal of kinetic energy 

which ultimately adds heat to the primary coolant. The neutrons can be absorbed by other 

uranium atoms which then fission, producing more neutrons available for further fissions. The 

chain reaction is maintained at criticality (eg. “self sustaining”: neither sub critical nor super 

critical) by controlling the number of thermal neutrons available for fission such that, on average, 

each fission results in exactly one thermal neutron being used in a subsequent thermal fission. 

The number of neutrons available is controlled by the temperature (and hence the density) of 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). This concept is commonly referred to as “moderation”. Moderation is the 

slowing down or lowering the energy of a fast neutron to a thermal neutron state such that the 

neutron has a higher probability of resulting in a thermal fission. 

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. The pressurized water from the reactor (the 

primary side) enters a heat exchanger (typically referred to as a steam generator) which converts 

lower pressure water into steam in the power loop side (the secondary side). 

In the primary loop, the cooling water inside the PWR is circulated through the nuclear core by 

reactor coolant 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 Delta125 U-tube type 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. 

In the secondary loop, the 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 
12-2

erosion of the LP ST blades. A portion of the steam is extracted from the HP and LP sections of 

the ST and with 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. 

The passive core cooling system provides protection for the facility against RCS leaks and 

ruptures. The passive containment cooling system provides for an inherently safe heat sink for 

the facility. The passive containment cooling system cools the containment following a loss of 

coolant casualty by rapidly reducing the reactor coolant system pressure by promoting the 

natural circulation of air supplemented by water evaporation to transfer heat through the steel 

containment vessel and away from critical core components that .may be subject to decay heat. 

The advantage of a passive core system is that less safety related equipment (e.g. pumping 

systems) are required to remove the decay heat. 

 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. 
12-3

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. 

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 a nearby water source (eg river, lake, or 

ocean), 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

12.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the AN Facility with a nominal capacity of 2,234 MW is $5,530/kW. 

Table 12-1 summarizes the Cost Estimate categories for the AN Facility. 

TABLE 12-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR AN 

Technology: AN 

Nominal Capacity (ISO): 2,234,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2012$)

 

Civil Structural Material and Installation 1,792,260 

Mechanical Equipment Supply and 

Installation 3,519,000 

Electrical / I&C Supply and Installation 652,050 

Project Indirects (1) 2,817,788 

EPC Cost before Contingency and Fee 8,781,458 

Fee and Contingency 1,345,500 

Total Project EPC 10,126,958 

Owner Costs (excluding project finance) 2,227,931 

Total Project Cost (excluding finance) 12,354,889 

Total Project EPC / kW 4,533 

Owner Costs 22% (excluding project finance) / kW 997 

Total Project Cost (excluding project finance) / kW 5,530 

(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. 
12-5

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 Advanced Nuclear Facility 

include Fairbanks, Alaska; 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 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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts, 

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 in the Appendix presents the AN Facility capital cost variations for alternative U.S. 

plant locations. 

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 $93.28/kW-year 

Variable O&M Expense $2.14/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 $8,180/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, 2012$)

 

Civil Structural Material and Installation 17,117 

Mechanical Equipment Supply and 

Installation 72,942 

Electrical / I&C Supply and Installation 11,718 

Project Indirects (1) 22,055 

EPC Cost before Contingency and Fee 123,832 

Fee and Contingency 12,500 

Total Project EPC 136,332 

Owner Costs (excluding project finance) 27,266 

Total Project Cost (excluding finance) 163,598 

Total Project EPC / kW 6,817 

Owner Costs 20% (excluding project finance) / kW 1,363 

Total Project Cost (excluding project finance) / kW 8,180 

(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, Arkansas, Florida, Georgia, Hawaii, Louisiana, 

Mississippi, 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; 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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, 

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 in the Appendix presents the BCC Facility capital cost variations for alternative U.S. 

plant locations. 
13-6

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 $356.07/kW-year 

Variable O&M Expense $17.49/MWh 

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 0.0075 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 – BBFD 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 $4,114/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, 2012$)

 

Civil Structural Material and Installation 14,500 

Mechanical Equipment Supply and 

Installation 79,600 

Electrical / I&C Supply and Installation 18,000 

Project Indirects (1) 38,250 

EPC Cost before Contingency and Fee 150,350 

Fee and Contingency 21,049 

Total Project EPC 171,399 

Owner Costs (excluding project finance) 34,280 

Total Project Cost (excluding finance) 205,679 

Total Project EPC / kW 3,428 

Owner Costs 20% (excluding project finance) / kW 686 

Total Project Cost (excluding project finance) / kW 4,114 

(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, Arkansas, Florida, Georgia, Hawaii, Louisiana, 

Mississippi, 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; 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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, 

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 in the Appendix presents the BBFB Facility capital cost variations for alternative 

U.S. plant locations. 
14-5

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: BBFB 

Fixed O&M Expense $105.63/kW-year 

Variable O&M Expense $5.26/MWh 

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 $7,108/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, 2012$)

 

Civil Structural Material and Installation 3,274 

Mechanical Equipment Supply and 

Installation 51,922 

Electrical / I&C Supply and Installation 2,132 

Project Indirects (1) 3,612 

EPC Cost before Contingency and Fee 60,940 

Fee and Contingency 4,875 

Total Project EPC 65,815 

Owner Costs (excluding project finance) 5,265 

Total Project Cost (excluding finance) 71,080 

Total Project EPC / kW 6,582 

Owner Costs 8% (excluding project finance) / kW 526 

Total Project Cost (excluding project finance) / kW 7,108 

(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, but are not limited to, 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 in the Appendix presents the FC Facility capital cost variations for alternative U.S. 

plant locations. 

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. 

Based on recent experience, most FC operators do not treat O&M on a fixed basis, and 

consequently, all O&M expenses are shown below on a variable basis. 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 $0/kW-year 

Variable O&M Expense $43.00/MWh 

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. 
15-4

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 two 

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 prior to being re-injected into the 

reservoir. 

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 an additional pressure 

reduction stage, 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 low-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 crystallizer 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 two 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 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 noncondensable 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 

electrical interconnection from the GT Facility is accomplished by interconnecting via the plant 

switchyard into the utility high-voltage transmission system. 
16-3

16.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the GT Facility with a nominal capacity of 50 MW is $6,243/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, 2012$)

 

Civil Structural Material and Installation 11,600 

Mechanical Equipment Supply and 

Installation (and well costs) 167,250 

Electrical / I&C Supply and Installation 17,962 

Project Indirects (1) 33,200 

EPC Cost before Contingency and Fee 230,012 

Fee and Contingency 34,502 

Total Project EPC 264,514 

Owner Costs (excluding project finance) 47,613 

Total Project Cost (excluding finance) 312,127 

Total Project EPC / kW 5,290 

Owner Costs 18% (excluding project finance) / kW 953 

Total Project Cost (excluding project finance) / kW 6,243 

(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 12 states: Alaska, Arizona, California, Colorado, 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, and Hawaii. 

Table 16-2 in the Appendix presents the GT Facility capital cost variations for alternative U.S. 

plant locations. 
16-5

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. In general, most GT facility operators

do not treat O&M on a variable basis, and consequently, all O&M expenses are shown below on 

a fixed basis. 

TABLE 16-3 – O&M EXPENSES FOR GT 

Technology: GT 

Fixed O&M Expense $132.00/kW-year 

Variable O&M Expense $0/MWh 

16.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 16-4 presents environmental emissions for the GT Facility. 

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 power generation systems. These heat recovery 

power generation systems operate on a closed looped organic supercritical Rankine cycle using 

geothermal brine as a heat source, with a brine temperature of approximately 275°F. The 

geothermal brine heats the superheated organic working fluid within an evaporator. The cooled 

brine is then reinjected into the resource at approximately 140°F through injection wells. The 

heated supercritical working fluid is expanded through a multistage, radial inflow turbo-expander 

generator unit. The organic working fluid is cooled within a condenser before being pumped 

back to the supercritical pressure by a single pressure vertical turbine pump. Cycle heat rejection 

will be provided through three cooling towers. The design output (gross) of each turbo-expander 

is approximately 10,000 kW. 

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 $4,362/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, 2012$)

 

Civil Structural Material and Installation 8,351 

Mechanical Equipment Supply and 

Installation (and well costs) 109,730 

Electrical / I&C Supply and Installation 18,335 

Project Indirects (1) 28,600 

EPC Cost before Contingency and Fee 165,016 

Fee and Contingency 19,802 

Total Project EPC 184,818 

Owner Costs (excluding project finance) 33,286 

Total Project Cost (excluding finance) 218,104 

Total Project EPC / kW 3,696 

Owner Costs 18% (excluding project finance) / kW 666 

Total Project Cost (excluding project finance) / kW 4,362 

(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 12 states: Alaska, Arizona, California, Colorado, 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, and Hawaii. 

Table 17-2 in the Appendix presents the GT Facility capital cost variations for alternative U.S. 

plant locations. 

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. In general, most GT facility operators do not treat O&M on a variable basis, and 

consequently, all O&M expenses are shown below on a fixed basis. 

TABLE 17-3 – O&M EXPENSES FOR BINARY 

Technology: GT 

Fixed O&M Expense $100.00/kW-year 

Variable O&M Expense $0/MWh 
17-4

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 Martin 

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 
18-2

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 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. The facility is typically paid a “tip fee” 

for the MSW delivered. 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 $8,312/kW. 

Energy from Waste facilities have a relatively high capital cost on a per installed kW basis; 

however, they are installed primarily as waste management facilities and have several revenue 

streams, most notably waste management tip fees. The final cost of energy from these facilities 

may not include the entire capital cost. Table 18-1 summarizes the Cost Estimate categories for 

the MSW 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, 2012$)

 

Civil Structural Material and Installation 35,230 

Mechanical Equipment Supply and 

Installation 190,320 

Electrical / I&C Supply and Installation 26,312 

Project Indirects (1) 58,323 

EPC Cost before Contingency and Fee 310,185 

Fee and Contingency 36,137 

Total Project EPC 346,322 

Owner Costs (excluding project finance) 69,264 

Total Project Cost (excluding finance) 415,586 

Total Project EPC / kW 6,926 

Owner Costs 20% (excluding project finance) / kW 1,386 

Total Project Cost (excluding project finance) / kW 8,312 

(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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, 

Michigan, Minnesota, New York, Ohio, and Wisconsin. 

Table 18-2 in the Appendix presents the MSW Facility capital cost variations for alternative U.S. 

plant locations. 

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. 

TABLE 18-3 – O&M EXPENSES FOR MSW 

Technology: MSW 

Fixed O&M Expense $392.82/kW-year 

Variable O&M Expense $8.75/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 $2,936/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, 2012$)

 

Civil Structural Material and Installation 634,250 

Mechanical Equipment Supply and 

Installation 208,000 

Electrical / I&C Supply and Installation 70,500 

Project Indirects (1) 174,500 

EPC Cost before Contingency and Fee 1,087,250 

Fee and Contingency 135,906 

Total Project EPC 1,223,156 

Owner Costs (excluding project finance) 244,631 

Total Project Cost (excluding finance) 1,467,787 

Total Project EPC / kW 2,446 

Owner Costs 20% (excluding project finance) / kW 490 

Total Project Cost (excluding project finance) / kW 2,936 

(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 

Oregon. 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, but are not limited to, Alaska, California, 

Connecticut, Maine, Ohio, and South Dakota. 

Table 19-2 in the Appendix presents the HY Facility capital cost variations for alternative U.S. 

plant locations. 
19-4

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 $14.13/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. 

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 

loads when the hydro-turbines are not operating, significant volumes of electricity are consumed 

in off-peak hours at the PS Facility. 
20-2

20.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the PS Facility with a nominal capacity of 250 MW is $5,288/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, 2012$)

 

Civil Structural Material and Installation 660,000 

Mechanical Equipment Supply and 

Installation 94,200 

Electrical / I&C Supply and Installation 63,900 

Project Indirects (1) 165,500 

EPC Cost before Contingency and Fee 983,600 

Fee and Contingency 118,032 

Total Project EPC 1,101,632 

Owner Costs (excluding project finance) 220,326 

Total Project Cost (excluding finance) 1,321,958 

Total Project EPC / kW 4,407 

Owner Costs 20% (excluding project finance) / kW 881 

Total Project Cost (excluding project finance) / kW 5,288 

(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 

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. 
20-3

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, 

Delaware, District of Columbia, Louisiana, Maryland, Massachusetts, New Jersey, New York, 

Oregon, 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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, 

Michigan, Minnesota, New York, Ohio; and Wisconsin. 

Table 20-2 in the Appendix presents the PS Facility capital cost variations for alternative U.S. 

plant locations. 

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. Based on recent 

experience, most PS operators do not treat O&M on a variable basis, and consequently, all O&M 

expenses are shown below on a fixed basis. 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 $18.00/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 
20-4

off-peak pumping to the reservoir, is not considered in this report. Table 20-4 presents 

environmental emissions for the PS Facility. 

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 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 
21-2

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 $2,213/kW. 

Table 21-1 summarizes the Cost Estimate categories for the WN Facility. 

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, 2012$)

 

Civil Structural Material and Installation 26,640 

Mechanical Equipment Supply and 

Installation 132,946 

Electrical / I&C Supply and Installation 28,863 

Project Indirects (1) 8,393 

EPC Cost before Contingency and Fee 196,842 

Fee and Contingency 12,007 

Total Project EPC 208,849 

Owner Costs (excluding project finance) 12,434 

Total Project Cost (excluding finance) 221,283 

Total Project EPC / kW 2,088 

Owner Costs 6% (excluding project finance) / kW 125 
21-3

Technology: WN 

Nominal Capacity (ISO): 100,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

Total Project Cost (excluding project finance) / kW 2,213 

 

(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 

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, but are not limited to, 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 in the Appendix presents the WN Facility capital cost variations for alternative U.S. 

plant locations. 

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 

generator, and associated electric conversion (e.g., GSU) technology repairs and replacement. 

These devices typically undergo major maintenance every five to seven years. Based on recent 

experience, most WN operators do not treat O&M on a variable basis, and consequently, all 

O&M expenses are shown below on a fixed basis. Table 21-3 presents the O&M expenses for 

the WN Facility. 
21-4

TABLE 21-3 – O&M EXPENSES FOR WN 

Technology: WN 

Fixed O&M Expense $39.55/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 

seabed, moored or ballasted. The common foundations typically used for offshore wind projects 

are mono pile, gravity foundations, and tripod foundations. The most common foundation 

currently used on most offshore wind projects is the gravity foundation which utilizes a large 

base of either concrete or steel that rests on the seabed. 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 underwater collection circuit typically buried 1 to 3 meters below 

the sea floor for protection. 

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

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. 

22.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the WF Facility with a nominal capacity of 400 MW is $6,230/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, 2012$)

 

Civil Structural Material and Installation 262,000 

Mechanical Equipment Supply and 

Installation 868,741 

Electrical / I&C Supply and Installation 154,234 

Project Indirects (1) 482,410 

EPC Cost before Contingency and Fee 1,767,385 

Fee and Contingency 210,319 

Total Project EPC 1,977,704 

Owner Costs (excluding project finance) 514,203 

Total Project Cost (excluding finance) 2,491,907 

Total Project EPC / kW 4,944 

Owner Costs 25% (excluding project finance) / kW 1,286 

Total Project Cost (excluding project finance) / kW 6,230 

(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 
22-4

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. 

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 Anchorage, 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, but are not limited to, 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 in the Appendix presents the WF Facility capital cost variations for alternative U.S. 

plant locations. 

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. 

Based on recent experience, most WF operators do not treat O&M on a variable basis, and 

consequently, all O&M expenses are shown below on a fixed basis. 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 $74.00/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. 
22-5

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 - CONCENTRATED SOLAR POWER (CSP) 

23.1 MECHANICAL EQUIPMENT AND SYSTEMS 

Solar thermal electric technology, also known as concentrated solar power (“CSP”) with thermal 

energy storage (“TES”), may be able to solve the problem of storage. Concentrated solar power 

systems use mirrors to concentrate sunlight to heat a working gas or a fluid to generate 

electricity. The inherent advantage of using a molten salt solution as the basis for generating 

steam is that the heat in the fluid can be stored for a period of time and used later to generate 

electricity, like a battery. 

Various CSP technologies are available which use different methods to collect the heat and 

create electricity. Dish/Stirling engines are a type of solar thermal electric technology which 

generates power by using a dish shaped parabolic mirror to reflect sunlight onto a chamber filled 

with gas. In this case, the sunlight is used to heat the gas, which drives a piston to power a 

generator to produce electricity. Dish/Stirling engines are usually mounted on a dual axistracking device to keep the dish pointed directly at the sun during the day for maximum 

performance. 

Another CSP technology is the parabolic trough method. Parabolic trough designs use long 

curved mirrors in a trough shape to concentrate sunlight onto a liquid-filled tube at the focal 

point to collect heat. The hot oil is then routed through a series of heat exchangers and then to a 

steam boiler to create steam which drives a generator, producing electricity. 

A third type of CSP involves the use of tracking mirrors with a tower focal point. This 

concentrated solar design uses a large field of flat, computer-controlled mirrors or heliostats that 

tilt and adjust continuously during the day to reflect sunlight onto a tank sitting on top of a tall 

tower. Liquid molten salts pass through the tank and are heated to temperatures reaching 

1,000 degrees Fahrenheit (“oF”). The heated fluid then passes through a steam boiler, which is 

subsequently used in a steam turbine to generate electricity. 

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. 

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 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 
23-2

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 $5,067/kW. 

Table 23-1 summarizes the Cost Estimate categories for the SO Facility. 

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, 2012$)

 

Civil Structural Material and Installation 50,414 

Mechanical Equipment Supply and 

Installation 270,340 

Electrical / I&C Supply and Installation 42,380 

Project Indirects (1) 41,080 

EPC Cost before Contingency and Fee 404,214 

Fee and Contingency 36,400 

Total Project EPC 440,614 

Owner Costs (excluding project finance) 66,092 

Total Project Cost (excluding finance) 506,706 

Total Project EPC / kW 4,406 

Owner Costs 15% (excluding project finance) / kW 661 

Total Project Cost (excluding project finance) / kW 5,067 

(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 
23-3

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 

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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, 

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 in the Appendix presents the SO Facility capital cost variations for alternative U.S. 

plant locations. 

23.5 O&M ESTIMATE 

The typical O&M expenses for the SO Facility include mirror cleaning, repair, and replacement 

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. Based on recent experience, 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 $67.26/kW-year 

Variable O&M Expense $0/MWh 

23.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 23-4 presents environmental emissions for the SO Facility. 
23-4

TABLE 23-4 – ENVIRONMENTAL EMISSIONS FOR SO 

Technology: SO 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 
24-1

24. UTILITY-SCALE PHOTOVOLTAIC (PV) FACILITY 

24.1 MECHANICAL EQUIPMENT AND SYSTEMS 

The following describes a nominally 20 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 20 MW Facility; however, a detailed technical description (due to the 

similarities with the 20 MW Facility and the technology associated therewith) is not provided 

herein. The PV Facility uses numerous arrays of ground-mounted, single-axis tracking PV 

modules which directly convert incident solar radiation into DC electricity, which can then be 

inverted to AC. Additional BOP components include metal racks mounted to tracker 

components (drive motors, gearboxes, linkages, etc.) supported by foundations, DC wiring, 

combiner boxes where individual series circuits (“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 24-1 presents a picture of a typical PV Facility. 

FIGURE 24-1 

24.2 ELECTRICAL AND CONTROL SYSTEMS 

The 20 MW-AC PV Facility is comprised of 40 half-megawatt building blocks, each block 

consisting of groups of PV modules connected to a 500 kW-AC inverter. While the ratio of DC 
24-2

module capacity to AC inverter capacity varies, for this analysis we have assumed a ratio of 

1.3:1, or 650 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 series “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-AC to 420 V-AC. 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. The output of two or more inverters is frequently combined into a shared 

transformer, each of which is rated 1 MVA (or higher for larger groups of inverters). 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 

for purposes of module washing once or twice annually) and an electrical interconnection 

between the PV Facility switchyard and the local utility distribution system. With regard to 

water supply, we note that some PV facilities purchase water off-site for purposes of module 

washing. 

24.4 CAPITAL COST ESTIMATE 

The base Cost Estimate for the PV Facility with a nominal capacity of 20 MW-AC is 4,183/kWAC and with a nominal capacity of 150 MW is $3,873/kW-AC. 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): 20,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2012$)

 

Civil Structural Material and Installation 14,200 

Mechanical Equipment Supply and 

Installation 36,500 

Electrical / I&C Supply and Installation 10,900 

Project Indirects (1) 5,100 

EPC Cost before Contingency and Fee 66,700 

Fee and Contingency 8,004 

Total Project EPC 74,704 

Owner Costs (excluding project finance) 8,964 

Total Project Cost (excluding finance) 83,668 

Total Project EPC / kW 3,735 

Owner Costs 12% (excluding project finance) / kW 448 

Total Project Cost (excluding project finance) / kW 4,183 

(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, 2012$)

 

Civil Structural Material and Installation 99,030 

Mechanical Equipment Supply and 

Installation 270,800 

Electrical / I&C Supply and Installation 77,000 

Project Indirects (1) 33,300 

EPC Cost before Contingency and Fee 480,130 

Fee and Contingency 43,212 

Total Project EPC 523,342 

Owner Costs (excluding project finance) 57,568 

Total Project Cost (excluding finance) 580,910 

Total Project EPC / kW 3,489 

Owner Costs 12% (excluding project finance) / kW 384 

Total Project Cost (excluding project finance) / kW 3,873 

(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, but are not limited to, Alaska, California, 

Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Maryland, Massachusetts, 

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 in the Appendix present the PV Facility capital cost variations for 

alternative U.S. plant locations. 

24.5 O&M ESTIMATE 

The significant O&M items for a PV Facility include periodic inverter maintenance and periodic 

panel water washing. In general, most PV facility 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, 

Table 24-6, and Table 24-7 present the O&M expenses for the PV Facility. The O&M cost 

variance listed in the below tables are primarily due to economies of scale and the higher O&M 

costs associated with the tracking facility. 

TABLE 24-5 – O&M EXPENSES FOR PV FACILITY (20 MW) 

Technology: PV 

Fixed O&M Expense $27.75/kW-AC-year 

Variable O&M Expense $0/MWh 

TABLE 24-6 – O&M EXPENSES FOR PV-FIXED FACILITY (150 MW) 

Technology: PV - Fixed 

Fixed O&M Expense $21.75/kW-AC-year 

Variable O&M Expense $0/MWh 

TABLE 24-7 – O&M EXPENSES FOR PV-TRACKING FACILITY (150 MW) 

Technology: PV – Tracking 

Fixed O&M Expense $24.69/kW-AC-year 

Variable O&M Expense $0/MWh 

24.6 ENVIRONMENTAL COMPLIANCE INFORMATION 

Table 24-8 presents environmental emissions for the PV Facility. 
24-6

TABLE 24-8 – ENVIRONMENTAL EMISSIONS FOR PV 

Technology: Photovoltaic 

NOX 0 lb/MMBtu 

SO2 0 lb/MMBtu 

CO2 0 lb/MMBtu 

Technology: PV and 10% Storage 

Nominal Capacity (ISO): 150,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2012$)

 

Civil Structural Material and Installation 99,030 

Mechanical Equipment Supply and 

Installation 293,300 

Electrical / I&C Supply and Installation 77,000 

Project Indirects (1) 33,300 

EPC Cost before Contingency and Fee 502,630 

Fee and Contingency 45,237 

Total Project EPC 547,867 

Owner Costs (excluding project finance) 60,265 

Total Project Cost (excluding finance) 608,132 

Total Project EPC / kW 3,652 

Owner Costs 12% (excluding project finance) / kW 402 

Total Project Cost (excluding project finance) / kW 4,054 

(1) Includes engineering, distributable costs, scaffolding, construction management, and start-up. 
24-7

Technology: PV and 20% Storage 

Nominal Capacity (ISO): 150,000 kW 

Nominal Heat Rate (ISO): N/A Btu/kWh-HHV 

 

Capital Cost Category (000s) (October 1, 2012$)

 

Civil Structural Material and Installation 99,030 

Mechanical Equipment Supply and 

Installation 315,800 

Electrical / I&C Supply and Installation 77,000 

Project Indirects (1) 33,300 

EPC Cost before Contingency and Fee 525,130 

Fee and Contingency 47,262 

Total Project EPC 572,392 

Owner Costs (excluding project finance) 62,963 

Total Project Cost (excluding finance) 635,355 

Total Project EPC / kW 3,816 

Owner Costs 12% (excluding project finance) / kW 420 

Total Project Cost (excluding project finance) / kW 4,236 

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

1. APPENDIX 1 – STATE INFORMATION 

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

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,246 32.8% 1,065 4,311 

Alaska Fairbanks 3,246 31.8% 1,033 4,279 

Alabama Huntsville 3,246 -8.5% (276) 2,970 

Arizona Phoenix 3,246 -6.0% (193) 3,053 

Arkansas Little Rock 3,246 -6.9% (225) 3,021 

California Los Angeles 3,246 19.1% 621 3,867 

California Redding 3,246 11.3% 366 3,612 

California Bakersfield 3,246 10.2% 330 3,576 

California Sacramento 3,246 13.1% 427 3,673 

California San Francisco 3,246 40.5% 1,314 4,560 

Colorado Denver 3,246 -6.8% (220) 3,026 

Connecticut Hartford 3,246 25.9% 840 4,086 

Delaware Dover 3,246 22.6% 734 3,980 

District of Columbia Washington 3,246 39.2% 1,273 4,519 

Florida Tallahassee 3,246 -9.8% (319) 2,927 

Florida Tampa 3,246 -4.7% (151) 3,095 

Georgia Atlanta 3,246 -9.6% (312) 2,934 

Hawaii Honolulu - - 

Idaho Boise 3,246 -4.7% (151) 3,095 

Illinois Chicago 3,246 18.6% 603 3,849 

Indiana Indianapolis 3,246 2.1% 68 3,314 

Iowa Davenport 3,246 -2.2% (71) 3,175 

Iowa Waterloo 3,246 -6.3% (205) 3,041 

Kansas Wichita 3,246 -7.3% (238) 3,008 

Kentucky Louisville 3,246 -6.3% (204) 3,042 

Louisiana New Orleans 3,246 -12.0% (390) 2,856 

Maine Portland 3,246 -2.1% (68) 3,178 

Maryland Baltimore 3,246 3.7% 120 3,366 

Massachusetts Boston 3,246 33.5% 1,086 4,332 

Michigan Detroit 3,246 3.1% 100 3,346 

Michigan Grand Rapids 3,246 -3.9% (125) 3,121 

Minnesota St. Paul 3,246 6.1% 197 3,443 

Mississippi Jackson 3,246 -7.9% (256) 2,990 

Missouri St. Louis 3,246 5.7% 186 3,432 

Missouri Kansas City 3,246 2.2% 72 3,318 

Montana Great Falls 3,246 -4.0% (130) 3,116 

Nebraska Omaha 3,246 -3.9% (127) 3,119 

New Hampshire Concord 3,246 -2.4% (78) 3,168 

New Jersey Newark 3,246 16.4% 532 3,778 

New Mexico Albuquerque 3,246 -4.6% (149) 3,097 

New York New York 3,246 31.8% 1,032 4,278 

New York Syracuse 3,246 10.9% 353 3,599 

Nevada Las Vegas 3,246 8.1% 264 3,510 

North Carolina Charlotte 3,246 -8.6% (278) 2,968 

North Dakota Bismarck 3,246 -8.1% (262) 2,984 

Ohio Cincinnati 3,246 -0.8% (27) 3,219 
A-2

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Oregon Portland 3,246 9.4% 305 3,551 

Pennsylvania Philadelphia 3,246 10.7% 347 3,593 

Pennsylvania Wilkes-Barre 3,246 -3.0% (97) 3,149 

Rhode Island Providence 3,246 4.1% 134 3,380 

South Carolina Spartanburg 3,246 -12.3% (401) 2,845 

South Dakota Rapid City 3,246 -10.3% (334) 2,912 

Tennessee Knoxville 3,246 -9.8% (319) 2,927 

Texas Houston 3,246 -10.4% (337) 2,909 

Utah Salt Lake City 3,246 -3.2% (103) 3,143 

Vermont Burlington 3,246 -6.2% (203) 3,043 

Virginia Alexandria 3,246 9.6% 313 3,559 

Virginia Lynchburg 3,246 -3.4% (112) 3,134 

Washington Seattle 3,246 12.4% 401 3,647 

Washington Spokane 3,246 -2.3% (75) 3,171 

West Virginia Charleston 3,246 -1.6% (51) 3,195 

Wisconsin Green Bay 3,246 4.4% 143 3,389 

Wyoming Cheyenne 3,246 3.0% 98 3,344 

Puerto Rico Cayey - - 
A-3

TABLE 3-4 – LOCATION-BASED COSTS FOR APC (1,300,000 KW) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 2,934 35.9% 1,054 3,988 

Alaska Fairbanks 2,934 34.8% 1,021 3,955 

Alabama Huntsville 2,934 -9.0% (265) 2,669 

Arizona Phoenix 2,934 -6.3% (185) 2,749 

Arkansas Little Rock 2,934 -7.3% (215) 2,719 

California Los Angeles 2,934 21.0% 617 3,551 

California Redding 2,934 12.3% 362 3,296 

California Bakersfield 2,934 11.2% 327 3,261 

California Sacramento 2,934 14.3% 420 3,354 

California San Francisco 2,934 44.2% 1,298 4,232 

Colorado Denver 2,934 -7.2% (211) 2,723 

Connecticut Hartford 2,934 28.4% 834 3,768 

Delaware Dover 2,934 24.9% 732 3,666 

District of Columbia Washington 2,934 43.5% 1,275 4,209 

Florida Tallahassee 2,934 -10.5% (307) 2,627 

Florida Tampa 2,934 -5.0% (146) 2,788 

Georgia Atlanta 2,934 -10.2% (299) 2,635 

Hawaii Honolulu - - 

Idaho Boise 2,934 -4.9% (143) 2,791 

Illinois Chicago 2,934 19.9% 585 3,519 

Indiana Indianapolis 2,934 2.4% 71 3,005 

Iowa Davenport 2,934 -2.3% (68) 2,866 

Iowa Waterloo 2,934 -6.7% (197) 2,737 

Kansas Wichita 2,934 -7.8% (228) 2,706 

Kentucky Louisville 2,934 -6.7% (195) 2,739 

Louisiana New Orleans 2,934 -12.8% (376) 2,558 

Maine Portland 2,934 -2.0% (58) 2,876 

Maryland Baltimore 2,934 4.3% 126 3,060 

Massachusetts Boston 2,934 36.5% 1,072 4,006 

Michigan Detroit 2,934 3.3% 97 3,031 

Michigan Grand Rapids 2,934 -4.1% (120) 2,814 

Minnesota St. Paul 2,934 6.5% 191 3,125 

Mississippi Jackson 2,934 -8.4% (245) 2,689 

Missouri St. Louis 2,934 6.3% 184 3,118 

Missouri Kansas City 2,934 2.4% 71 3,005 

Montana Great Falls 2,934 -4.2% (123) 2,811 

Nebraska Omaha 2,934 -4.1% (121) 2,813 

New Hampshire Concord 2,934 -2.5% (73) 2,861 

New Jersey Newark 2,934 17.4% 512 3,446 

New Mexico Albuquerque 2,934 -4.8% (141) 2,793 

New York New York 2,934 33.9% 994 3,928 

New York Syracuse 2,934 12.1% 355 3,289 

Nevada Las Vegas 2,934 8.8% 259 3,193 

North Carolina Charlotte 2,934 -9.0% (265) 2,669 

North Dakota Bismarck 2,934 -8.6% (252) 2,682 

Ohio Cincinnati 2,934 -0.7% (20) 2,914 

Oregon Portland 2,934 10.3% 304 3,238 

Pennsylvania Philadelphia 2,934 11.4% 336 3,270 

Pennsylvania Wilkes-Barre 2,934 -3.1% (91) 2,843 

Rhode Island Providence 2,934 4.4% 131 3,065 

South Carolina Spartanburg 2,934 -13.1% (384) 2,550 
A-4

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

South Dakota Rapid City 2,934 -10.9% (321) 2,613 

Tennessee Knoxville 2,934 -10.4% (305) 2,629 

Texas Houston 2,934 -11.0% (324) 2,610 

Utah Salt Lake City 2,934 -3.2% (94) 2,840 

Vermont Burlington 2,934 -6.6% (193) 2,741 

Virginia Alexandria 2,934 10.8% 317 3,251 

Virginia Lynchburg 2,934 -3.5% (102) 2,832 

Washington Seattle 2,934 13.5% 396 3,330 

Washington Spokane 2,934 -2.4% (70) 2,864 

West Virginia Charleston 2,934 -1.6% (48) 2,886 

Wisconsin Green Bay 2,934 4.9% 142 3,076 

Wyoming Cheyenne 2,934 3.7% 108 3,042 

Puerto Rico Cayey - - 
A-5

TABLE 4-3– LOCATION-BASED COSTS FOR APC/CCS FACILITY (650,000 KW) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,227 31.6% 1,654 6,881 

Alaska Fairbanks 5,227 30.9% 1,613 6,840 

Alabama Huntsville 5,227 -9.0% (471) 4,756 

Arizona Phoenix 5,227 -6.4% (335) 4,892 

Arkansas Little Rock 5,227 -7.4% (389) 4,838 

California Los Angeles 5,227 18.2% 951 6,178 

California Redding 5,227 10.9% 570 5,797 

California Bakersfield 5,227 9.7% 509 5,736 

California Sacramento 5,227 12.9% 673 5,900 

California San Francisco 5,227 39.2% 2,051 7,278 

Colorado Denver 5,227 -7.3% (379) 4,848 

Connecticut Hartford 5,227 24.6% 1,287 6,514 

Delaware Dover 5,227 21.3% 1,113 6,340 

District of Columbia Washington 5,227 36.3% 1,899 7,126 

Florida Tallahassee 5,227 -10.3% (538) 4,689 

Florida Tampa 5,227 -4.8% (253) 4,974 

Georgia Atlanta 5,227 -10.2% (531) 4,696 

Hawaii Honolulu 

Idaho Boise 5,227 -5.1% (267) 4,960 

Illinois Chicago 5,227 19.1% 999 6,226 

Indiana Indianapolis 5,227 1.6% 85 5,312 

Iowa Davenport 5,227 -2.3% (120) 5,107 

Iowa Waterloo 5,227 -6.7% (348) 4,879 

Kansas Wichita 5,227 -7.8% (410) 4,817 

Kentucky Louisville 5,227 -6.7% (352) 4,875 

Louisiana New Orleans 5,227 -12.6% (660) 4,567 

Maine Portland 5,227 -2.9% (152) 5,075 

Maryland Baltimore 5,227 2.8% 147 5,374 

Massachusetts Boston 5,227 32.6% 1,706 6,933 

Michigan Detroit 5,227 3.2% 165 5,392 

Michigan Grand Rapids 5,227 -4.1% (213) 5,014 

Minnesota St. Paul 5,227 6.3% 327 5,554 

Mississippi Jackson 5,227 -8.3% (436) 4,791 

Missouri St. Louis 5,227 5.6% 291 5,518 

Missouri Kansas City 5,227 2.1% 112 5,339 

Montana Great Falls 5,227 -4.4% (231) 4,996 

Nebraska Omaha 5,227 -4.2% (221) 5,006 

New Hampshire Concord 5,227 -2.7% (142) 5,085 

New Jersey Newark 5,227 17.2% 898 6,125 

New Mexico Albuquerque 5,227 -5.0% (262) 4,965 
A-6

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 5,227 33.4% 1,744 6,971 

New York Syracuse 5,227 8.6% 451 5,678 

Nevada Las Vegas 5,227 6.3% 328 5,555 

North Carolina Charlotte 5,227 -9.2% (483) 4,744 

North Dakota Bismarck 5,227 -8.5% (445) 4,782 

Ohio Cincinnati 5,227 -1.5% (77) 5,150 

Oregon Portland 5,227 8.9% 467 5,694 

Pennsylvania Philadelphia 5,227 11.1% 580 5,807 

Pennsylvania Wilkes-Barre 5,227 -3.4% (175) 5,052 

Rhode Island Providence 5,227 4.1% 217 5,444 

South Carolina Spartanburg 5,227 -13.2% (688) 4,539 

South Dakota Rapid City 5,227 -10.9% (568) 4,659 

Tennessee Knoxville 5,227 -10.5% (547) 4,680 

Texas Houston 5,227 -10.9% (572) 4,655 

Utah Salt Lake City 5,227 -3.8% (200) 5,027 

Vermont Burlington 5,227 -6.8% (355) 4,872 

Virginia Alexandria 5,227 8.6% 449 5,676 

Virginia Lynchburg 5,227 -4.2% (221) 5,006 

Washington Seattle 5,227 12.1% 630 5,857 

Washington Spokane 5,227 -2.6% (138) 5,089 

West Virginia Charleston 5,227 -1.8% (92) 5,135 

Wisconsin Green Bay 5,227 4.1% 217 5,444 

Wyoming Cheyenne 5,227 0.5% 28 5,255 

Puerto Rico Cayey $ - 
A-7

TABLE 4-4 – LOCATION-BASED COSTS FOR APC/CCS FACILITY (1,300,000 KW) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,724 34.4% 1,623 6,347 

Alaska Fairbanks 4,724 33.4% 1,580 6,304 

Alabama Huntsville 4,724 -9.3% (441) 4,283 

Arizona Phoenix 4,724 -6.6% (311) 4,413 

Arkansas Little Rock 4,724 -7.7% (362) 4,362 

California Los Angeles 4,724 19.9% 941 5,665 

California Redding 4,724 11.8% 559 5,283 

California Bakersfield 4,724 10.6% 501 5,225 

California Sacramento 4,724 13.9% 656 5,380 

California San Francisco 4,724 42.5% 2,008 6,732 

Colorado Denver 4,724 -7.5% (353) 4,371 

Connecticut Hartford 4,724 26.9% 1,272 5,996 

Delaware Dover 4,724 23.4% 1,107 5,831 

District of Columbia Washington 4,724 40.3% 1,905 6,629 

Florida Tallahassee 4,724 -10.7% (507) 4,217 

Florida Tampa 4,724 -5.1% (239) 4,485 

Georgia Atlanta 4,724 -10.5% (497) 4,227 

Hawaii Honolulu - - 

Idaho Boise 4,724 -5.2% (246) 4,478 

Illinois Chicago 4,724 20.1% 949 5,673 

Indiana Indianapolis 4,724 2.0% 94 4,818 

Iowa Davenport 4,724 -2.4% (113) 4,611 

Iowa Waterloo 4,724 -6.9% (326) 4,398 

Kansas Wichita 4,724 -8.1% (382) 4,342 

Kentucky Louisville 4,724 -6.9% (328) 4,396 

Louisiana New Orleans 4,724 -13.1% (620) 4,104 

Maine Portland 4,724 -2.7% (125) 4,599 

Maryland Baltimore 4,724 3.5% 164 4,888 

Massachusetts Boston 4,724 35.3% 1,666 6,390 

Michigan Detroit 4,724 3.3% 157 4,881 

Michigan Grand Rapids 4,724 -4.2% (199) 4,525 

Minnesota St. Paul 4,724 6.6% 311 5,035 

Mississippi Jackson 4,724 -8.6% (408) 4,316 

Missouri St. Louis 4,724 6.0% 285 5,009 

Missouri Kansas City 4,724 2.3% 110 4,834 

Montana Great Falls 4,724 -4.5% (212) 4,512 

Nebraska Omaha 4,724 -4.3% (205) 4,519 

New Hampshire Concord 4,724 -2.7% (128) 4,596 

New Jersey Newark 4,724 17.9% 845 5,569 

New Mexico Albuquerque 4,724 -5.1% (241) 4,483 
A-8

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4,724 34.7% 1,640 6,364 

New York Syracuse 4,724 9.7% 458 5,182 

Nevada Las Vegas 4,724 6.6% 313 5,037 

North Carolina Charlotte 4,724 -9.5% (448) 4,276 

North Dakota Bismarck 4,724 -8.8% (418) 4,306 

Ohio Cincinnati 4,724 -1.2% (58) 4,666 

Oregon Portland 4,724 9.8% 462 5,186 

Pennsylvania Philadelphia 4,724 11.6% 549 5,273 

Pennsylvania Wilkes-Barre 4,724 -3.4% (160) 4,564 

Rhode Island Providence 4,724 4.4% 208 4,932 

South Carolina Spartanburg 4,724 -13.6% (642) 4,082 

South Dakota Rapid City 4,724 -11.3% (532) 4,192 

Tennessee Knoxville 4,724 -10.8% (510) 4,214 

Texas Houston 4,724 -11.4% (537) 4,187 

Utah Salt Lake City 4,724 -3.7% (176) 4,548 

Vermont Burlington 4,724 -6.9% (328) 4,396 

Virginia Alexandria 4,724 9.7% 460 5,184 

Virginia Lynchburg 4,724 -4.1% (193) 4,531 

Washington Seattle 4,724 13.0% 615 5,339 

Washington Spokane 4,724 -2.6% (125) 4,599 

West Virginia Charleston 4,724 -1.8% (84) 4,640 

Wisconsin Green Bay 4,724 4.6% 216 4,940 

Wyoming Cheyenne 4,724 1.2% 56 4,780 

Puerto Rico Cayey - - 
A-9

TABLE 5-2 – LOCATION-BASED COSTS FOR CONVENTIONAL NGCC 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 917 35.0% 321 1,238 

Alaska Fairbanks 917 40.2% 369 1,286 

Alabama Huntsville 917 -9.6% (88) 829 

Arizona Phoenix 917 2.5% 23 940 

Arkansas Little Rock 917 -8.3% (76) 841 

California Los Angeles 917 29.8% 273 1,190 

California Redding 917 15.8% 145 1,062 

California Bakersfield 917 17.6% 161 1,078 

California Sacramento 917 20.3% 186 1,103 

California San Francisco 917 46.9% 430 1,347 

Colorado Denver 917 2.1% 19 936 

Connecticut Hartford 917 29.1% 267 1,184 

Delaware Dover 917 27.7% 254 1,171 

District of Columbia Washington 917 35.9% 329 1,246 

Florida Tallahassee 917 -10.6% (97) 820 

Florida Tampa 917 -5.9% (54) 863 

Georgia Atlanta 917 -7.7% (71) 846 

Hawaii Honolulu 917 53.1% 486 1,403 

Idaho Boise 917 -4.6% (42) 875 

Illinois Chicago 917 15.5% 143 1,060 

Indiana Indianapolis 917 0.2% 2 919 

Iowa Davenport 917 0.1% 1 918 

Iowa Waterloo 917 -3.7% (34) 883 

Kansas Wichita 917 -4.8% (44) 873 

Kentucky Louisville 917 -6.0% (55) 862 

Louisiana New Orleans 917 -5.6% (51) 866 

Maine Portland 917 -3.8% (35) 882 

Maryland Baltimore 917 21.4% 196 1,113 

Massachusetts Boston 917 40.4% 370 1,287 

Michigan Detroit 917 4.8% 44 961 

Michigan Grand Rapids 917 -1.4% (13) 904 

Minnesota St. Paul 917 6.6% 61 978 

Mississippi Jackson 917 -9.0% (82) 835 

Missouri St. Louis 917 4.4% 41 958 

Missouri Kansas City 917 1.7% 16 933 

Montana Great Falls 917 -1.9% (17) 900 

Nebraska Omaha 917 -1.6% (15) 902 

New Hampshire Concord 917 7.4% 68 985 

New Jersey Newark 917 23.4% 215 1,132 

New Mexico Albuquerque 917 -2.8% (26) 891 
A-10

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 917 70.1% 642 1,559 

New York Syracuse 917 17.9% 164 1,081 

Nevada Las Vegas 917 5.3% 49 966 

North Carolina Charlotte 917 -8.2% (75) 842 

North Dakota Bismarck 917 -5.3% (49) 868 

Ohio Cincinnati 917 -2.5% (23) 894 

Oregon Portland 917 14.0% 129 1,046 

Pennsylvania Philadelphia 917 25.8% 237 1,154 

Pennsylvania Wilkes-Barre 917 -1.0% (9) 908 

Rhode Island Providence 917 23.3% 214 1,131 

South Carolina Spartanburg 917 -13.3% (122) 795 

South Dakota Rapid City 917 -7.4% (67) 850 

Tennessee Knoxville 917 -9.2% (84) 833 

Texas Houston 917 -9.6% (88) 829 

Utah Salt Lake City 917 -3.8% (34) 883 

Vermont Burlington 917 -0.4% (4) 913 

Virginia Alexandria 917 17.5% 160 1,077 

Virginia Lynchburg 917 -7.0% (64) 853 

Washington Seattle 917 6.8% 63 980 

Washington Spokane 917 -2.5% (23) 894 

West Virginia Charleston 917 0.5% 5 922 

Wisconsin Green Bay 917 2.5% 23 940 

Wyoming Cheyenne 917 -0.6% (6) 911 

Puerto Rico Cayey 917 12.3% 113 1,030 
A-11

TABLE 6-2 – LOCATION-BASED COSTS FOR AG-NGCC 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 1,023 32.1% 328 1,351 

Alaska Fairbanks 1,023 36.8% 377 1,400 

Alabama Huntsville 1,023 -9.3% (95) 928 

Arizona Phoenix 1,023 1.7% 18 1,041 

Arkansas Little Rock 1,023 -8.1% (82) 941 

California Los Angeles 1,023 27.0% 276 1,299 

California Redding 1,023 14.4% 147 1,170 

California Bakersfield 1,023 15.9% 163 1,186 

California Sacramento 1,023 18.6% 190 1,213 

California San Francisco 1,023 43.0% 440 1,463 

Colorado Denver 1,023 1.3% 13 1,036 

Connecticut Hartford 1,023 26.5% 271 1,294 

Delaware Dover 1,023 25.0% 256 1,279 

District of Columbia Washington 1,023 32.1% 328 1,351 

Florida Tallahassee 1,023 -10.2% (105) 918 

Florida Tampa 1,023 -5.6% (57) 966 

Georgia Atlanta 1,023 -7.7% (79) 944 

Hawaii Honolulu 1,023 47.9% 490 1,513 

Idaho Boise 1,023 -4.6% (47) 976 

Illinois Chicago 1,023 15.1% 154 1,177 

Indiana Indianapolis 1,023 0.0% (0) 1,023 

Iowa Davenport 1,023 -0.1% (1) 1,022 

Iowa Waterloo 1,023 -3.8% (39) 984 

Kansas Wichita 1,023 -4.9% (51) 972 

Kentucky Louisville 1,023 -5.9% (60) 963 

Louisiana New Orleans 1,023 -5.9% (60) 963 

Maine Portland 1,023 -4.0% (41) 982 

Maryland Baltimore 1,023 18.8% 192 1,215 

Massachusetts Boston 1,023 37.1% 380 1,403 

Michigan Detroit 1,023 4.5% 46 1,069 

Michigan Grand Rapids 1,023 -1.6% (16) 1,007 

Minnesota St. Paul 1,023 6.3% 65 1,088 

Mississippi Jackson 1,023 -8.7% (89) 934 

Missouri St. Louis 1,023 4.1% 42 1,065 

Missouri Kansas City 1,023 1.6% 16 1,039 

Montana Great Falls 1,023 -2.1% (22) 1,001 

Nebraska Omaha 1,023 -1.8% (19) 1,004 

New Hampshire Concord 1,023 6.3% 65 1,088 

New Jersey Newark 1,023 22.2% 227 1,250 

New Mexico Albuquerque 1,023 -3.0% (31) 992 
A-12

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 1,023 65.2% 667 1,690 

New York Syracuse 1,023 15.9% 163 1,186 

Nevada Las Vegas 1,023 5.1% 52 1,075 

North Carolina Charlotte 1,023 -8.2% (84) 939 

North Dakota Bismarck 1,023 -5.4% (55) 968 

Ohio Cincinnati 1,023 -2.7% (27) 996 

Oregon Portland 1,023 12.7% 130 1,153 

Pennsylvania Philadelphia 1,023 23.8% 244 1,267 

Pennsylvania Wilkes-Barre 1,023 -1.2% (13) 1,010 

Rhode Island Providence 1,023 21.1% 216 1,239 

South Carolina Spartanburg 1,023 -12.9% (132) 891 

South Dakota Rapid City 1,023 -7.4% (76) 947 

Tennessee Knoxville 1,023 -9.1% (93) 930 

Texas Houston 1,023 -9.4% (96) 927 

Utah Salt Lake City 1,023 -3.9% (40) 983 

Vermont Burlington 1,023 -1.0% (10) 1,013 

Virginia Alexandria 1,023 15.4% 158 1,181 

Virginia Lynchburg 1,023 -6.9% (71) 952 

Washington Seattle 1,023 6.5% 66 1,089 

Washington Spokane 1,023 -2.5% (26) 997 

West Virginia Charleston 1,023 0.3% 3 1,026 

Wisconsin Green Bay 1,023 2.3% 23 1,046 

Wyoming Cheyenne 1,023 -1.2% (12) 1,011 

Puerto Rico Cayey 1,023 10.6% 108 1,131 
A-13

TABLE 7-2 – LOCATION-BASED COSTS FOR AG-NGCC/CCS 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 2,095 20.6% 432 2,527 

Alaska Fairbanks 2,095 23.5% 493 2,588 

Alabama Huntsville 2,095 -9.5% (198) 1,897 

Arizona Phoenix 2,095 -3.1% (65) 2,030 

Arkansas Little Rock 2,095 -8.4% (176) 1,919 

California Los Angeles 2,095 14.9% 312 2,407 

California Redding 2,095 8.9% 186 2,281 

California Bakersfield 2,095 9.0% 188 2,283 

California Sacramento 2,095 12.0% 251 2,346 

California San Francisco 2,095 28.0% 587 2,682 

Colorado Denver 2,095 -3.7% (77) 2,018 

Connecticut Hartford 2,095 15.3% 321 2,416 

Delaware Dover 2,095 13.2% 277 2,372 

District of Columbia Washington 2,095 14.7% 309 2,404 

Florida Tallahassee 2,095 -10.2% (214) 1,881 

Florida Tampa 2,095 -5.0% (105) 1,990 

Georgia Atlanta 2,095 -9.3% (195) 1,900 

Hawaii Honolulu 2,095 26.1% 547 2,642 

Idaho Boise 2,095 -5.8% (122) 1,973 

Illinois Chicago 2,095 15.6% 327 2,422 

Indiana Indianapolis 2,095 -1.5% (32) 2,063 

Iowa Davenport 2,095 -1.3% (26) 2,069 

Iowa Waterloo 2,095 -5.4% (113) 1,982 

Kansas Wichita 2,095 -7.0% (147) 1,948 

Kentucky Louisville 2,095 -6.9% (144) 1,951 

Louisiana New Orleans 2,095 -9.3% (196) 1,899 

Maine Portland 2,095 -6.3% (132) 1,963 

Maryland Baltimore 2,095 6.3% 131 2,226 

Massachusetts Boston 2,095 24.8% 520 2,615 

Michigan Detroit 2,095 3.5% 73 2,168 

Michigan Grand Rapids 2,095 -2.9% (62) 2,033 

Minnesota St. Paul 2,095 5.8% 122 2,217 

Mississippi Jackson 2,095 -8.8% (185) 1,910 

Missouri St. Louis 2,095 3.0% 63 2,158 

Missouri Kansas City 2,095 1.1% 23 2,118 

Montana Great Falls 2,095 -4.2% (88) 2,007 

Nebraska Omaha 2,095 -3.6% (75) 2,020 

New Hampshire Concord 2,095 0.8% 17 2,112 

New Jersey Newark 2,095 19.7% 412 2,507 

New Mexico Albuquerque 2,095 -4.8% (102) 1,993 
A-14

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 2,095 48.9% 1,024 3,119 

New York Syracuse 2,095 6.7% 139 2,234 

Nevada Las Vegas 2,095 5.1% 106 2,201 

North Carolina Charlotte 2,095 -9.7% (204) 1,891 

North Dakota Bismarck 2,095 -7.2% (151) 1,944 

Ohio Cincinnati 2,095 -4.5% (94) 2,001 

Oregon Portland 2,095 7.0% 146 2,241 

Pennsylvania Philadelphia 2,095 16.8% 352 2,447 

Pennsylvania Wilkes-Barre 2,095 -3.2% (67) 2,028 

Rhode Island Providence 2,095 11.7% 245 2,340 

South Carolina Spartanburg 2,095 -13.9% (291) 1,804 

South Dakota Rapid City 2,095 -9.4% (198) 1,897 

Tennessee Knoxville 2,095 -10.4% (219) 1,876 

Texas Houston 2,095 -10.4% (219) 1,876 

Utah Salt Lake City 2,095 -6.0% (125) 1,970 

Vermont Burlington 2,095 -4.9% (103) 1,992 

Virginia Alexandria 2,095 5.7% 120 2,215 

Virginia Lynchburg 2,095 -8.1% (169) 1,926 

Washington Seattle 2,095 5.6% 118 2,213 

Washington Spokane 2,095 -3.5% (72) 2,023 

West Virginia Charleston 2,095 -1.2% (26) 2,069 

Wisconsin Green Bay 2,095 1.3% 28 2,123 

Wyoming Cheyenne 2,095 -5.2% (109) 1,986 

Puerto Rico Cayey 2,095 1.8% 38 2,133 
A-15

TABLE 8-2 – LOCATION-BASED COSTS FOR CONVENTIONAL CT 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 973 32.0% 311 1,284 

Alaska Fairbanks 973 36.8% 358 1,331 

Alabama Huntsville 973 -6.0% (59) 914 

Arizona Phoenix 973 -4.2% (41) 932 

Arkansas Little Rock 973 -4.9% (48) 925 

California Los Angeles 973 18.4% 179 1,152 

California Redding 973 5.1% 50 1,023 

California Bakersfield 973 7.0% 68 1,041 

California Sacramento 973 9.2% 90 1,063 

California San Francisco 973 33.4% 325 1,298 

Colorado Denver 973 -1.2% (11) 962 

Connecticut Hartford 973 17.6% 171 1,144 

Delaware Dover 973 16.6% 161 1,134 

District of Columbia Washington 973 24.7% 240 1,213 

Florida Tallahassee 973 -6.9% (68) 905 

Florida Tampa 973 -3.1% (30) 943 

Georgia Atlanta 973 -4.2% (41) 932 

Hawaii Honolulu 973 51.5% 501 1,474 

Idaho Boise 973 -3.6% (35) 938 

Illinois Chicago 973 13.0% 126 1,099 

Indiana Indianapolis 973 0.5% 5 978 

Iowa Davenport 973 0.4% 4 977 

Iowa Waterloo 973 -2.7% (27) 946 

Kansas Wichita 973 -3.6% (35) 938 

Kentucky Louisville 973 -4.8% (47) 926 

Louisiana New Orleans 973 -1.9% (19) 954 

Maine Portland 973 -2.7% (27) 946 

Maryland Baltimore 973 11.4% 111 1,084 

Massachusetts Boston 973 27.4% 266 1,239 

Michigan Detroit 973 4.3% 41 1,014 

Michigan Grand Rapids 973 -0.9% (9) 964 

Minnesota St. Paul 973 5.7% 55 1,028 

Mississippi Jackson 973 -5.5% (54) 919 

Missouri St. Louis 973 4.0% 39 1,012 

Missouri Kansas City 973 1.5% 15 988 

Montana Great Falls 973 -1.1% (11) 962 

Nebraska Omaha 973 -1.0% (10) 963 

New Hampshire Concord 973 -1.9% (19) 954 

New Jersey Newark 973 20.3% 197 1,170 

New Mexico Albuquerque 973 0.0% 0 973 
A-16

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 973 53.2% 518 1,491 

New York Syracuse 973 7.7% 75 1,048 

Nevada Las Vegas 973 4.5% 44 1,017 

North Carolina Charlotte 973 -6.6% (64) 909 

North Dakota Bismarck 973 -4.1% (40) 933 

Ohio Cincinnati 973 -1.7% (17) 956 

Oregon Portland 973 3.7% 36 1,009 

Pennsylvania Philadelphia 973 13.9% 136 1,109 

Pennsylvania Wilkes-Barre 973 -0.4% (4) 969 

Rhode Island Providence 973 12.3% 120 1,093 

South Carolina Spartanburg 973 -9.0% (87) 886 

South Dakota Rapid City 973 -5.7% (56) 917 

Tennessee Knoxville 973 -7.5% (73) 900 

Texas Houston 973 -7.8% (76) 897 

Utah Salt Lake City 973 -2.7% (26) 947 

Vermont Burlington 973 0.5% 5 978 

Virginia Alexandria 973 7.5% 73 1,046 

Virginia Lynchburg 973 -5.7% (55) 918 

Washington Seattle 973 5.9% 58 1,031 

Washington Spokane 973 -1.9% (18) 955 

West Virginia Charleston 973 0.7% 7 980 

Wisconsin Green Bay 973 2.3% 22 995 

Wyoming Cheyenne 973 0.4% 4 977 

Puerto Rico Cayey 973 6.4% 48 1,021 
A-17

TABLE 9-2 – LOCATION-BASED COSTS FOR ADVANCED CT 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 676 41.4% 280 956 

Alaska Fairbanks 676 47.8% 323 999 

Alabama Huntsville 676 -4.1% (28) 648 

Arizona Phoenix 676 -2.3% (16) 660 

Arkansas Little Rock 676 -2.9% (19) 657 

California Los Angeles 676 24.8% 168 844 

California Redding 676 5.7% 38 714 

California Bakersfield 676 8.9% 60 736 

California Sacramento 676 10.5% 71 747 

California San Francisco 676 41.5% 281 957 

Colorado Denver 676 2.3% 16 692 

Connecticut Hartford 676 23.1% 156 832 

Delaware Dover 676 22.9% 155 831 

District of Columbia Washington 676 36.4% 246 922 

Florida Tallahassee 676 -5.1% (35) 641 

Florida Tampa 676 -2.3% (15) 661 

Georgia Atlanta 676 -0.8% (6) 670 

Hawaii Honolulu 676 71.5% 483 1,159 

Idaho Boise 676 -1.9% (13) 663 

Illinois Chicago 676 11.0% 74 750 

Indiana Indianapolis 676 2.1% 15 691 

Iowa Davenport 676 1.7% 11 687 

Iowa Waterloo 676 -0.6% (4) 672 

Kansas Wichita 676 -0.9% (6) 670 

Kentucky Louisville 676 -3.2% (21) 655 

Louisiana New Orleans 676 3.3% 22 698 

Maine Portland 676 0.1% 1 677 

Maryland Baltimore 676 19.1% 129 805 

Massachusetts Boston 676 33.1% 224 900 

Michigan Detroit 676 4.9% 33 709 

Michigan Grand Rapids 676 0.7% 5 681 

Minnesota St. Paul 676 5.6% 38 714 

Mississippi Jackson 676 -3.7% (25) 651 

Missouri St. Louis 676 4.8% 33 709 

Missouri Kansas City 676 1.9% 13 689 

Montana Great Falls 676 1.3% 9 685 

Nebraska Omaha 676 1.0% 7 683 

New Hampshire Concord 676 -0.7% (5) 671 

New Jersey Newark 676 21.0% 142 818 

New Mexico Albuquerque 676 3.2% 22 698 
A-18

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 676 60.6% 410 1,086 

New York Syracuse 676 12.2% 82 758 

Nevada Las Vegas 676 4.1% 27 703 

North Carolina Charlotte 676 -4.1% (28) 648 

North Dakota Bismarck 676 -1.6% (11) 665 

Ohio Cincinnati 676 0.5% 4 680 

Oregon Portland 676 4.6% 31 707 

Pennsylvania Philadelphia 676 15.3% 103 779 

Pennsylvania Wilkes-Barre 676 1.9% 13 689 

Rhode Island Providence 676 16.4% 111 787 

South Carolina Spartanburg 676 -5.9% (40) 636 

South Dakota Rapid City 676 -2.8% (19) 657 

Tennessee Knoxville 676 -5.1% (35) 641 

Texas Houston 676 -5.8% (39) 637 

Utah Salt Lake City 676 -0.1% (1) 675 

Vermont Burlington 676 4.9% 33 709 

Virginia Alexandria 676 12.5% 84 760 

Virginia Lynchburg 676 -3.8% (26) 650 

Washington Seattle 676 6.3% 42 718 

Washington Spokane 676 -0.6% (4) 672 

West Virginia Charleston 676 2.3% 16 692 

Wisconsin Green Bay 676 3.1% 21 697 

Wyoming Cheyenne 676 4.9% 33 709 

Puerto Rico Cayey 676 10.2% 69 745 
A-19

TABLE 10-3 – LOCATION-BASED COSTS FOR IGCC (600,000 KW) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,400 24.8% 1,091 5,491 

Alaska Fairbanks 4,400 24.1% 1,063 5,463 

Alabama Huntsville 4,400 -6.9% (302) 4,098 

Arizona Phoenix 4,400 -4.9% (214) 4,186 

Arkansas Little Rock 4,400 -5.7% (249) 4,151 

California Los Angeles 4,400 14.3% 630 5,030 

California Redding 4,400 8.5% 376 4,776 

California Bakersfield 4,400 7.6% 336 4,736 

California Sacramento 4,400 10.0% 442 4,842 

California San Francisco 4,400 30.7% 1,351 5,751 

Colorado Denver 4,400 -5.5% (243) 4,157 

Connecticut Hartford 4,400 19.4% 852 5,252 

Delaware Dover 4,400 16.8% 740 5,140 

District of Columbia Washington 4,400 28.8% 1,268 5,668 

Florida Tallahassee 4,400 -7.9% (347) 4,053 

Florida Tampa 4,400 -3.7% (163) 4,237 

Georgia Atlanta 4,400 -7.7% (341) 4,059 

Hawaii Honolulu - - 

Idaho Boise 4,400 -3.9% (170) 4,230 

Illinois Chicago 4,400 14.7% 647 5,047 

Indiana Indianapolis 4,400 1.4% 60 4,460 

Iowa Davenport 4,400 -1.8% (77) 4,323 

Iowa Waterloo 4,400 -5.1% (223) 4,177 

Kansas Wichita 4,400 -6.0% (263) 4,137 

Kentucky Louisville 4,400 -5.1% (226) 4,174 

Louisiana New Orleans 4,400 -9.7% (425) 3,975 

Maine Portland 4,400 -2.1% (91) 4,309 

Maryland Baltimore 4,400 2.4% 105 4,505 

Massachusetts Boston 4,400 25.5% 1,122 5,522 

Michigan Detroit 4,400 2.4% 107 4,507 

Michigan Grand Rapids 4,400 -3.1% (137) 4,263 

Minnesota St. Paul 4,400 4.8% 212 4,612 

Mississippi Jackson 4,400 -6.4% (280) 4,120 

Missouri St. Louis 4,400 4.4% 192 4,592 

Missouri Kansas City 4,400 1.7% 74 4,474 

Montana Great Falls 4,400 -3.3% (147) 4,253 

Nebraska Omaha 4,400 -3.2% (141) 4,259 

New Hampshire Concord 4,400 -2.0% (89) 4,311 

New Jersey Newark 4,400 13.1% 578 4,978 

New Mexico Albuquerque 4,400 -3.8% (167) 4,233 
A-20

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4,400 25.5% 1,123 5,523 

New York Syracuse 4,400 7.9% 347 4,747 

Nevada Las Vegas 4,400 6.3% 278 4,678 

North Carolina Charlotte 4,400 -7.0% (309) 4,091 

North Dakota Bismarck 4,400 -6.5% (286) 4,114 

Ohio Cincinnati 4,400 -1.0% (44) 4,356 

Oregon Portland 4,400 7.0% 309 4,709 

Pennsylvania Philadelphia 4,400 8.5% 374 4,774 

Pennsylvania Wilkes-Barre 4,400 -2.5% (111) 4,289 

Rhode Island Providence 4,400 3.2% 141 4,541 

South Carolina Spartanburg 4,400 -10.0% (441) 3,959 

South Dakota Rapid City 4,400 -8.3% (365) 4,035 

Tennessee Knoxville 4,400 -8.0% (351) 4,049 

Texas Houston 4,400 -8.4% (368) 4,032 

Utah Salt Lake City 4,400 -2.8% (124) 4,276 

Vermont Burlington 4,400 -5.1% (226) 4,174 

Virginia Alexandria 4,400 6.9% 303 4,703 

Virginia Lynchburg 4,400 -3.1% (137) 4,263 

Washington Seattle 4,400 9.4% 414 4,814 

Washington Spokane 4,400 -2.0% (87) 4,313 

West Virginia Charleston 4,400 -1.3% (58) 4,342 

Wisconsin Green Bay 4,400 3.3% 144 4,544 

Wyoming Cheyenne 4,400 1.7% 73 4,473 

Puerto Rico Cayey - - - 
A-21

TABLE 10-4 – LOCATION-BASED COSTS FOR IGCC (1,200,000 KW) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,784 28.4% 1,073 4,857 

Alaska Fairbanks 3,784 27.6% 1,043 4,827 

Alabama Huntsville 3,784 -7.5% (285) 3,499 

Arizona Phoenix 3,784 -5.3% (200) 3,584 

Arkansas Little Rock 3,784 -6.2% (233) 3,551 

California Los Angeles 3,784 16.5% 624 4,408 

California Redding 3,784 9.8% 369 4,153 

California Bakersfield 3,784 8.8% 332 4,116 

California Sacramento 3,784 11.4% 432 4,216 

California San Francisco 3,784 35.0% 1,326 5,110 

Colorado Denver 3,784 -6.0% (228) 3,556 

Connecticut Hartford 3,784 22.3% 844 4,628 

Delaware Dover 3,784 19.4% 736 4,520 

District of Columbia Washington 3,784 33.6% 1,271 5,055 

Florida Tallahassee 3,784 -8.7% (328) 3,456 

Florida Tampa 3,784 -4.1% (155) 3,629 

Georgia Atlanta 3,784 -8.5% (321) 3,463 

Hawaii Honolulu - - 

Idaho Boise 3,784 -4.2% (157) 3,627 

Illinois Chicago 3,784 16.3% 617 4,401 

Indiana Indianapolis 3,784 1.7% 65 3,849 

Iowa Davenport 3,784 -1.9% (73) 3,711 

Iowa Waterloo 3,784 -5.6% (211) 3,573 

Kansas Wichita 3,784 -6.5% (246) 3,538 

Kentucky Louisville 3,784 -5.6% (211) 3,573 

Louisiana New Orleans 3,784 -10.6% (402) 3,382 

Maine Portland 3,784 -2.0% (76) 3,708 

Maryland Baltimore 3,784 3.0% 115 3,899 

Massachusetts Boston 3,784 29.0% 1,098 4,882 

Michigan Detroit 3,784 2.7% 103 3,887 

Michigan Grand Rapids 3,784 -3.4% (129) 3,655 

Minnesota St. Paul 3,784 5.3% 202 3,986 

Mississippi Jackson 3,784 -7.0% (264) 3,520 

Missouri St. Louis 3,784 5.0% 188 3,972 

Missouri Kansas City 3,784 1.9% 73 3,857 

Montana Great Falls 3,784 -3.6% (135) 3,649 

Nebraska Omaha 3,784 -3.5% (132) 3,652 

New Hampshire Concord 3,784 -2.2% (81) 3,703 

New Jersey Newark 3,784 14.5% 547 4,331 

New Mexico Albuquerque 3,784 -4.1% (155) 3,629 
A-22

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 3,784 28.1% 1,062 4,846 

New York Syracuse 3,784 9.3% 351 4,135 

Nevada Las Vegas 3,784 7.1% 269 4,053 

North Carolina Charlotte 3,784 -7.6% (288) 3,496 

North Dakota Bismarck 3,784 -7.1% (270) 3,514 

Ohio Cincinnati 3,784 -0.9% (33) 3,751 

Oregon Portland 3,784 8.1% 307 4,091 

Pennsylvania Philadelphia 3,784 9.4% 356 4,140 

Pennsylvania Wilkes-Barre 3,784 -2.7% (102) 3,682 

Rhode Island Providence 3,784 3.6% 136 3,920 

South Carolina Spartanburg 3,784 -10.9% (414) 3,370 

South Dakota Rapid City 3,784 -9.1% (344) 3,440 

Tennessee Knoxville 3,784 -8.7% (329) 3,455 

Texas Houston 3,784 -9.2% (347) 3,437 

Utah Salt Lake City 3,784 -2.9% (110) 3,674 

Vermont Burlington 3,784 -5.6% (210) 3,574 

Virginia Alexandria 3,784 8.2% 310 4,094 

Virginia Lynchburg 3,784 -3.2% (120) 3,664 

Washington Seattle 3,784 10.7% 405 4,189 

Washington Spokane 3,784 -2.1% (79) 3,705 

West Virginia Charleston 3,784 -1.4% (54) 3,730 

Wisconsin Green Bay 3,784 3.8% 143 3,927 

Wyoming Cheyenne 3,784 2.4% 89 3,873 

Puerto Rico Cayey - - - 
A-23

TABLE 11-2 – LOCATION-BASED COSTS FOR IGCC/CCS 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 6,599 20.0% 1,317 7,916 

Alaska Fairbanks 6,599 19.9% 1,316 7,915 

Alabama Huntsville 6,599 -8.0% (528) 6,071 

Arizona Phoenix 6,599 -6.0% (394) 6,205 

Arkansas Little Rock 6,599 -6.9% (454) 6,145 

California Los Angeles 6,599 10.8% 710 7,309 

California Redding 6,599 7.0% 460 7,059 

California Bakersfield 6,599 5.9% 392 6,991 

California Sacramento 6,599 8.7% 575 7,174 

California San Francisco 6,599 25.3% 1,672 8,271 

Colorado Denver 6,599 -6.7% (439) 6,160 

Connecticut Hartford 6,599 14.6% 962 7,561 

Delaware Dover 6,599 11.9% 786 7,385 

District of Columbia Washington 6,599 18.6% 1,226 7,825 

Florida Tallahassee 6,599 -8.9% (585) 6,014 

Florida Tampa 6,599 -4.1% (268) 6,331 

Georgia Atlanta 6,599 -9.0% (594) 6,005 

Hawaii Honolulu - - 

Idaho Boise 6,599 -5.0% (331) 6,268 

Illinois Chicago 6,599 15.5% 1,023 7,622 

Indiana Indianapolis 6,599 -0.2% (10) 6,589 

Iowa Davenport 6,599 -2.0% (133) 6,466 

Iowa Waterloo 6,599 -5.9% (386) 6,213 

Kansas Wichita 6,599 -7.2% (473) 6,126 

Kentucky Louisville 6,599 -6.2% (409) 6,190 

Louisiana New Orleans 6,599 -10.9% (720) 5,879 

Maine Portland 6,599 -4.4% (290) 6,309 

Maryland Baltimore 6,599 -0.4% (28) 6,571 

Massachusetts Boston 6,599 21.6% 1,428 8,027 

Michigan Detroit 6,599 2.5% 166 6,765 

Michigan Grand Rapids 6,599 -3.6% (236) 6,363 

Minnesota St. Paul 6,599 5.1% 338 6,937 

Mississippi Jackson 6,599 -7.4% (488) 6,111 

Missouri St. Louis 6,599 3.6% 236 6,835 

Missouri Kansas City 6,599 1.4% 90 6,689 

Montana Great Falls 6,599 -4.4% (291) 6,308 

Nebraska Omaha 6,599 -4.0% (263) 6,336 

New Hampshire Concord 6,599 -2.9% (193) 6,406 

New Jersey Newark 6,599 14.9% 980 7,579 
A-24

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New Mexico Albuquerque 6,599 -4.9% (321) 6,278 

New York New York 6,599 28.8% 1,903 8,502 

New York Syracuse 6,599 4.5% 296 6,895 

Nevada Las Vegas 6,599 6.0% 395 6,994 

North Carolina Charlotte 6,599 -8.7% (571) 6,028 

North Dakota Bismarck 6,599 -7.5% (495) 6,104 

Ohio Cincinnati 6,599 -2.9% (189) 6,410 

Oregon Portland 6,599 5.2% 346 6,945 

Pennsylvania Philadelphia 6,599 9.2% 609 7,208 

Pennsylvania Wilkes-Barre 6,599 -3.5% (229) 6,370 

Rhode Island Providence 6,599 3.1% 206 6,805 

South Carolina Spartanburg 6,599 -11.9% (785) 5,814 

South Dakota Rapid City 6,599 -9.6% (631) 5,968 

Tennessee Knoxville 6,599 -9.5% (625) 5,974 

Texas Houston 6,599 -9.6% (636) 5,963 

Utah Salt Lake City 6,599 -4.7% (309) 6,290 

Vermont Burlington 6,599 -6.5% (429) 6,170 

Virginia Alexandria 6,599 3.4% 221 6,820 

Virginia Lynchburg 6,599 -5.3% (350) 6,249 

Washington Seattle 6,599 8.0% 527 7,126 

Washington Spokane 6,599 -2.9% (188) 6,411 

West Virginia Charleston 6,599 -1.8% (120) 6,479 

Wisconsin Green Bay 6,599 2.3% 154 6,753 

Wyoming Cheyenne 6,599 -2.1% (139) 6,460 

Puerto Rico Cayey - - 
A-25

TABLE 12-2 – LOCATION-BASED COSTS FOR AN 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,530 15.8% 874 6,404 

Alaska Fairbanks 5,530 16.0% 884 6,414 

Alabama Huntsville 5,530 -3.6% (200) 5,330 

Arizona Phoenix 5,530 -2.6% (145) 5,385 

Arkansas Little Rock 5,530 -3.0% (167) 5,363 

California Los Angeles 5,530 8.8% 486 6,016 

California Redding 5,530 5.1% 282 5,812 

California Bakersfield 5,530 4.6% 257 5,787 

California Sacramento 5,530 5.9% 324 5,854 

California San Francisco 5,530 19.6% 1,087 6,617 

Colorado Denver 5,530 -2.8% (156) 5,374 

Connecticut Hartford 5,530 14.0% 777 6,307 

Delaware Dover 5,530 12.8% 706 6,236 

District of Columbia Washington 5,530 23.1% 1,279 6,809 

Florida Tallahassee 5,530 -4.1% (228) 5,302 

Florida Tampa 5,530 -2.0% (111) 5,419 

Georgia Atlanta 5,530 -4.1% (225) 5,305 

Hawaii Honolulu - - - 

Idaho Boise 5,530 -2.0% (110) 5,420 

Illinois Chicago 5,530 8.3% 459 5,989 

Indiana Indianapolis 5,530 1.5% 84 5,614 

Iowa Davenport 5,530 -0.9% (49) 5,481 

Iowa Waterloo 5,530 -2.6% (142) 5,388 

Kansas Wichita 5,530 -3.0% (168) 5,362 

Kentucky Louisville 5,530 -2.6% (144) 5,386 

Louisiana New Orleans 5,530 -5.0% (277) 5,253 

Maine Portland 5,530 -0.2% (12) 5,518 

Maryland Baltimore 5,530 2.9% 160 5,690 

Massachusetts Boston 5,530 17.1% 948 6,478 

Michigan Detroit 5,530 1.2% 67 5,597 

Michigan Grand Rapids 5,530 -1.6% (87) 5,443 

Minnesota St. Paul 5,530 2.7% 149 5,679 

Mississippi Jackson 5,530 -3.4% (186) 5,344 

Missouri St. Louis 5,530 2.1% 117 5,647 

Missouri Kansas City 5,530 0.8% 45 5,575 

Montana Great Falls 5,530 -1.7% (95) 5,435 

Nebraska Omaha 5,530 -1.6% (91) 5,439 

New Hampshire Concord 5,530 -1.1% (59) 5,471 

New Jersey Newark 5,530 6.6% 367 5,897 

New Mexico Albuquerque 5,530 -1.8% (100) 5,430 
A-26

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 5,530 12.9% 712 6,242 

New York Syracuse 5,530 6.5% 361 5,891 

Nevada Las Vegas 5,530 3.6% 199 5,729 

North Carolina Charlotte 5,530 -3.6% (198) 5,332 

North Dakota Bismarck 5,530 -3.3% (182) 5,348 

Ohio Cincinnati 5,530 0.3% 18 5,548 

Oregon Portland 5,530 4.3% 239 5,769 

Pennsylvania Philadelphia 5,530 4.3% 236 5,766 

Pennsylvania Wilkes-Barre 5,530 -1.3% (72) 5,458 

Rhode Island Providence 5,530 1.6% 88 5,618 

South Carolina Spartanburg 5,530 -5.2% (289) 5,241 

South Dakota Rapid City 5,530 -4.2% (232) 5,298 

Tennessee Knoxville 5,530 -4.1% (224) 5,306 

Texas Houston 5,530 -4.2% (234) 5,296 

Utah Salt Lake City 5,530 -1.5% (84) 5,446 

Vermont Burlington 5,530 -2.6% (146) 5,384 

Virginia Alexandria 5,530 6.0% 334 5,864 

Virginia Lynchburg 5,530 -0.7% (41) 5,489 

Washington Seattle 5,530 5.5% 306 5,836 

Washington Spokane 5,530 -1.0% (57) 5,473 

West Virginia Charleston 5,530 -0.7% (38) 5,492 

Wisconsin Green Bay 5,530 2.5% 139 5,669 

Wyoming Cheyenne 5,530 3.0% 168 5,698 

Puerto Rico Cayey - - - 
A-27

TABLE 13-2 – LOCATION-BASED COSTS FOR BCC 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 8,180 13.7% 1,121 9,301 

Alaska Fairbanks 8,180 14.9% 1,217 9,397 

Alabama Huntsville 8,180 -6.7% (546) 7,634 

Arizona Phoenix 0.0% - - 

Arkansas Little Rock 8,180 -6.0% (492) 7,688 

California Los Angeles 8,180 6.3% 515 8,695 

California Redding 8,180 4.4% 362 8,542 

California Bakersfield 8,180 3.6% 294 8,474 

California Sacramento 8,180 5.8% 477 8,657 

California San Francisco 8,180 18.0% 1,476 9,656 

Colorado Denver 8,180 -12.9% (1,057) 7,123 

Connecticut Hartford 8,180 11.3% 922 9,102 

Delaware Dover 8,180 9.4% 766 8,946 

District of Columbia Washington 8,180 14.8% 1,207 9,387 

Florida Tallahassee 8,180 -7.1% (584) 7,596 

Florida Tampa 8,180 -3.3% (268) 7,912 

Georgia Atlanta 8,180 -7.5% (612) 7,568 

Hawaii Honolulu 8,180 28.1% 2,302 10,482 

Idaho Boise 8,180 -4.5% (370) 7,810 

Illinois Chicago 8,180 12.5% 1,021 9,201 

Indiana Indianapolis 8,180 -0.4% (29) 8,151 

Iowa Davenport 8,180 -1.6% (133) 8,047 

Iowa Waterloo 8,180 -4.7% (385) 7,795 

Kansas Wichita 8,180 -6.0% (491) 7,689 

Kentucky Louisville 8,180 -5.2% (427) 7,753 

Louisiana New Orleans 8,180 -8.8% (718) 7,462 

Maine Portland 8,180 -4.0% (328) 7,852 

Maryland Baltimore 8,180 -0.6% (46) 8,134 

Massachusetts Boston 8,180 17.0% 1,387 9,567 

Michigan Detroit 8,180 1.8% 147 8,327 

Michigan Grand Rapids 8,180 -2.9% (236) 7,944 

Minnesota St. Paul 8,180 4.1% 337 8,517 

Mississippi Jackson 8,180 -6.2% (507) 7,673 

Missouri St. Louis 8,180 1.7% 139 8,319 

Missouri Kansas City 8,180 0.6% 51 8,231 

Montana Great Falls 0.0% - - 

Nebraska Omaha 8,180 -3.4% (282) 7,898 

New Hampshire Concord 8,180 -2.8% (231) 7,949 

New Jersey Newark 8,180 11.7% 959 9,139 

New Mexico Albuquerque 0.0% - - 
A-28

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 8,180 22.7% 1,860 10,040 

New York Syracuse 8,180 3.4% 277 8,457 

Nevada Las Vegas 0.0% - - 

North Carolina Charlotte 8,180 -7.4% (609) 7,571 

North Dakota Bismarck 8,180 -6.0% (494) 7,686 

Ohio Cincinnati 8,180 -2.5% (208) 7,972 

Oregon Portland 8,180 3.0% 248 8,428 

Pennsylvania Philadelphia 8,180 7.0% 569 8,749 

Pennsylvania Wilkes-Barre 8,180 -3.3% (268) 7,912 

Rhode Island Providence 8,180 2.0% 167 8,347 

South Carolina Spartanburg 8,180 -10.1% (823) 7,357 

South Dakota Rapid City 8,180 -7.7% (630) 7,550 

Tennessee Knoxville 8,180 -7.9% (643) 7,537 

Texas Houston 8,180 -7.8% (634) 7,546 

Utah Salt Lake City 0.0% - - 

Vermont Burlington 8,180 -5.7% (467) 7,713 

Virginia Alexandria 8,180 2.5% 202 8,382 

Virginia Lynchburg 8,180 -4.5% (368) 7,812 

Washington Seattle 8,180 5.2% 428 8,608 

Washington Spokane 8,180 -2.8% (227) 7,953 

West Virginia Charleston 8,180 -1.7% (139) 8,041 

Wisconsin Green Bay 8,180 1.9% 154 8,334 

Wyoming Cheyenne 0.0% - - 

Puerto Rico Cayey 8,180 -3.5% (282) 7,898 
A-29

TABLE 14-2– LOCATION-BASED COSTS FOR BBFB 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,114 22.9% 944 5,058 

Alaska Fairbanks 4,114 24.8% 1,019 5,133 

Alabama Huntsville 4,114 -9.0% (370) 3,744 

Arizona Phoenix 0.0% - - 

Arkansas Little Rock 4,114 -8.1% (332) 3,782 

California Los Angeles 4,114 11.0% 452 4,566 

California Redding 4,114 7.2% 296 4,410 

California Bakersfield 4,114 6.1% 251 4,365 

California Sacramento 4,114 9.1% 373 4,487 

California San Francisco 4,114 29.8% 1,224 5,338 

Colorado Denver 4,114 -7.4% (304) 3,810 

Connecticut Hartford 4,114 20.3% 837 4,951 

Delaware Dover 4,114 17.7% 730 4,844 

District of Columbia Washington 4,114 30.1% 1,240 5,354 

Florida Tallahassee 4,114 -9.7% (397) 3,717 

Florida Tampa 4,114 -4.5% (186) 3,928 

Georgia Atlanta 4,114 -10.1% (414) 3,700 

Hawaii Honolulu 4,114 53.6% 2,205 6,319 

Idaho Boise 4,114 -5.9% (243) 3,871 

Illinois Chicago 4,114 17.7% 727 4,841 

Indiana Indianapolis 4,114 0.6% 26 4,140 

Iowa Davenport 4,114 -2.2% (89) 4,025 

Iowa Waterloo 4,114 -6.3% (258) 3,856 

Kansas Wichita 4,114 -7.9% (327) 3,787 

Kentucky Louisville 4,114 -6.9% (284) 3,830 

Louisiana New Orleans 4,114 -11.9% (488) 3,626 

Maine Portland 4,114 -4.2% (172) 3,942 

Maryland Baltimore 4,114 1.4% 57 4,171 

Massachusetts Boston 4,114 27.9% 1,148 5,262 

Michigan Detroit 4,114 2.4% 100 4,214 

Michigan Grand Rapids 4,114 -3.8% (158) 3,956 

Minnesota St. Paul 4,114 5.8% 239 4,353 

Mississippi Jackson 4,114 -8.4% (344) 3,770 

Missouri St. Louis 4,114 2.5% 104 4,218 

Missouri Kansas City 4,114 0.9% 38 4,152 

Montana Great Falls 0.0% - - 

Nebraska Omaha 4,114 -4.5% (187) 3,927 

New Hampshire Concord 4,114 -3.7% (150) 3,964 

New Jersey Newark 4,114 15.7% 644 4,758 

New Mexico Albuquerque 0.0% - - 
A-30

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4,114 30.4% 1,250 5,364 

New York Syracuse 4,114 7.7% 316 4,430 

Nevada Las Vegas 0.0% - - 

North Carolina Charlotte 4,114 -9.8% (404) 3,710 

North Dakota Bismarck 4,114 -8.0% (331) 3,783 

Ohio Cincinnati 4,114 -2.3% (94) 4,020 

Oregon Portland 4,114 5.3% 220 4,334 

Pennsylvania Philadelphia 4,114 9.4% 386 4,500 

Pennsylvania Wilkes-Barre 4,114 -4.3% (175) 3,939 

Rhode Island Providence 4,114 2.8% 116 4,230 

South Carolina Spartanburg 4,114 -13.4% (553) 3,561 

South Dakota Rapid City 4,114 -10.2% (422) 3,692 

Tennessee Knoxville 4,114 -10.4% (429) 3,685 

Texas Houston 4,114 -10.3% (425) 3,689 

Utah Salt Lake City 0.0% - - 

Vermont Burlington 4,114 -7.5% (308) 3,806 

Virginia Alexandria 4,114 6.5% 266 4,380 

Virginia Lynchburg 4,114 -4.9% (202) 3,912 

Washington Seattle 4,114 8.3% 341 4,455 

Washington Spokane 4,114 -3.6% (148) 3,966 

West Virginia Charleston 4,114 -2.2% (91) 4,023 

Wisconsin Green Bay 4,114 3.6% 146 4,260 

Wyoming Cheyenne 0.0% - - 

Puerto Rico Cayey 4,114 -4.0% (163) 3,951 
A-31

TABLE 15-2 – LOCATION-BASED COSTS FOR FC 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 7,108 12.4% 883 7,991 

Alaska Fairbanks 7,108 17.8% 1,269 8,377 

Alabama Huntsville 7,108 -5.1% (364) 6,744 

Arizona Phoenix 7,108 -3.9% (279) 6,829 

Arkansas Little Rock 7,108 -4.5% (321) 6,787 

California Los Angeles 7,108 3.6% 257 7,365 

California Redding 7,108 2.7% 189 7,297 

California Bakersfield 7,108 2.7% 190 7,298 

California Sacramento 7,108 3.8% 269 7,377 

California San Francisco 7,108 9.6% 683 7,791 

Colorado Denver 7,108 -4.4% (316) 6,792 

Connecticut Hartford 7,108 4.0% 286 7,394 

Delaware Dover 7,108 2.3% 165 7,273 

District of Columbia Washington 7,108 1.9% 135 7,243 

Florida Tallahassee 7,108 -5.6% (396) 6,712 

Florida Tampa 7,108 -2.4% (174) 6,934 

Georgia Atlanta 7,108 -5.8% (411) 6,697 

Hawaii Honolulu 7,108 11.4% 811 7,919 

Idaho Boise 7,108 -3.5% (249) 6,859 

Illinois Chicago 7,108 9.1% 645 7,753 

Indiana Indianapolis 7,108 -1.2% (87) 7,021 

Iowa Davenport 7,108 -1.3% (93) 7,015 

Iowa Waterloo 7,108 -3.8% (270) 6,838 

Kansas Wichita 7,108 -4.8% (339) 6,769 

Kentucky Louisville 7,108 -4.1% (295) 6,813 

Louisiana New Orleans 7,108 -6.9% (490) 6,618 

Maine Portland 7,108 -3.2% (226) 6,882 

Maryland Baltimore 7,108 -1.8% (125) 6,983 

Massachusetts Boston 7,108 8.6% 612 7,720 

Michigan Detroit 7,108 1.8% 127 7,235 

Michigan Grand Rapids 7,108 -2.1% (146) 6,962 

Minnesota St. Paul 7,108 3.2% 229 7,337 

Mississippi Jackson 7,108 -4.7% (337) 6,771 

Missouri St. Louis 7,108 1.7% 123 7,231 

Missouri Kansas City 7,108 0.6% 46 7,154 

Montana Great Falls 7,108 -2.8% (201) 6,907 

Nebraska Omaha 7,108 -2.7% (193) 6,915 

New Hampshire Concord 7,108 -1.9% (132) 6,976 

New Jersey Newark 7,108 10.5% 743 7,851 

New Mexico Albuquerque 7,108 -3.2% (228) 6,880 
A-32

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 7,108 21.2% 1,510 8,618 

New York Syracuse 7,108 -0.5% (35) 7,073 

Nevada Las Vegas 7,108 3.0% 214 7,322 

North Carolina Charlotte 7,108 -5.9% (417) 6,691 

North Dakota Bismarck 7,108 -4.6% (327) 6,781 

Ohio Cincinnati 7,108 -3.3% (232) 6,876 

Oregon Portland 7,108 1.5% 109 7,217 

Pennsylvania Philadelphia 7,108 5.8% 410 7,518 

Pennsylvania Wilkes-Barre 7,108 -2.5% (177) 6,931 

Rhode Island Providence 7,108 1.8% 127 7,235 

South Carolina Spartanburg 7,108 -7.8% (553) 6,555 

South Dakota Rapid City 7,108 -5.9% (422) 6,686 

Tennessee Knoxville 7,108 -6.3% (446) 6,662 

Texas Houston 7,108 -6.3% (445) 6,663 

Utah Salt Lake City 7,108 -3.6% (259) 6,849 

Vermont Burlington 7,108 -4.2% (298) 6,810 

Virginia Alexandria 7,108 -0.7% (48) 7,060 

Virginia Lynchburg 7,108 -4.8% (344) 6,764 

Washington Seattle 7,108 3.3% 235 7,343 

Washington Spokane 7,108 -1.8% (129) 6,979 

West Virginia Charleston 7,108 -1.0% (73) 7,035 

Wisconsin Green Bay 7,108 0.5% 37 7,145 

Wyoming Cheyenne 7,108 -4.0% (284) 6,824 

Puerto Rico Cayey 7,108 -0.1% (9) 7,099 
A-33

TABLE 16-2 – LOCATION-BASED COSTS FOR GT 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 6,243 13.2% 825 7,068 

Alaska Fairbanks 6,243 19.3% 1,204 7,447 

Alabama Huntsville 0.0% - - 

Arizona Phoenix 6,243 -3.7% (233) 6,010 

Arkansas Little Rock - 0.0% - - 

California Los Angeles 6,243 4.6% 288 6,531 

California Redding 6,243 2.7% 167 6,410 

California Bakersfield 6,243 2.8% 176 6,419 

California Sacramento 6,243 4.2% 261 6,504 

California San Francisco 6,243 10.9% 679 6,922 

Colorado Denver 6,243 -3.6% (227) 6,016 

Connecticut Hartford - 0.0% - - 

Delaware Dover - 0.0% - - 

District of Columbia Washington - 0.0% - - 

Florida Tallahassee - 0.0% - - 

Florida Tampa - 0.0% - - 

Georgia Atlanta - 0.0% - - 

Hawaii Honolulu 6,243 19.8% 1,234 7,477 

Idaho Boise 6,243 -3.3% (208) 6,035 

Illinois Chicago - 0.0% - - 

Indiana Indianapolis - 0.0% - - 

Iowa Davenport - 0.0% - - 

Iowa Waterloo - 0.0% - - 

Kansas Wichita - 0.0% - - 

Kentucky Louisville - 0.0% - - 

Louisiana New Orleans - 0.0% - - 

Maine Portland - 0.0% - - 

Maryland Baltimore - 0.0% - - 

Massachusetts Boston - 0.0% - - 

Michigan Detroit - 0.0% - - 

Michigan Grand Rapids - 0.0% - - 

Minnesota St. Paul - 0.0% - - 

Mississippi Jackson - 0.0% - - 

Missouri St. Louis - 0.0% - - 

Missouri Kansas City - 0.0% - - 

Montana Great Falls - 0.0% - - 

Nebraska Omaha - 0.0% - - 

New Hampshire Concord - 0.0% - - 

New Jersey Newark - 0.0% - - 

New Mexico Albuquerque 6,243 -2.7% (168) 6,075 
A-34

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York - 0.0% - - 

New York Syracuse - 0.0% - - 

Nevada Las Vegas 6,243 2.9% 184 6,427 

North Carolina Charlotte - 0.0% - - 

North Dakota Bismarck - 0.0% - - 

Ohio Cincinnati - 0.0% - - 

Oregon Portland 6,243 1.6% 99 6,342 

Pennsylvania Philadelphia - 0.0% - - 

Pennsylvania Wilkes-Barre - 0.0% - - 

Rhode Island Providence - 0.0% - - 

South Carolina Spartanburg - 0.0% - - 

South Dakota Rapid City - 0.0% - - 

Tennessee Knoxville - 0.0% - - 

Texas Houston - 0.0% - - 

Utah Salt Lake City 6,243 -3.4% (211) 6,032 

Vermont Burlington - 0.0% - - 

Virginia Alexandria - 0.0% - - 

Virginia Lynchburg - 0.0% - - 

Washington Seattle 6,243 3.3% 207 6,450 

Washington Spokane 6,243 -2.0% (123) 6,120 

West Virginia Charleston - 0.0% - - 

Wisconsin Green Bay - 0.0% - - 

Wyoming Cheyenne 6,243 -3.7% (230) 6,013 

Puerto Rico Cayey - 0.0% - - 
A-35

TABLE 17-2 – LOCATION-BASED COSTS FOR GT 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,362 16.8% 735 5,097 

Alaska Fairbanks 4,362 25.3% 1,103 5,465 

Alabama Huntsville - 0.0% - - 

Arizona Phoenix 4,362 -3.7% (161) 4,201 

Arkansas Little Rock - 0.0% - - 

California Los Angeles 4,362 5.9% 256 4,618 

California Redding 4,362 3.1% 134 4,496 

California Bakersfield 4,362 3.5% 153 4,515 

California Sacramento 4,362 4.8% 208 4,570 

California San Francisco 4,362 12.6% 551 4,913 

Colorado Denver 4,362 -3.4% (148) 4,214 

Connecticut Hartford - 0.0% - - 

Delaware Dover - 0.0% - - 

District of Columbia Washington - 0.0% - - 

Florida Tallahassee - 0.0% - - 

Florida Tampa - 0.0% - - 

Georgia Atlanta - 0.0% - - 

Hawaii Honolulu 4,362 27.2% 1,184 5,546 

Idaho Boise 4,362 -3.3% (143) 4,219 

Illinois Chicago - 0.0% - - 

Indiana Indianapolis - 0.0% - - 

Iowa Davenport - 0.0% - - 

Iowa Waterloo - 0.0% - - 

Kansas Wichita - 0.0% - - 

Kentucky Louisville - 0.0% - - 

Louisiana New Orleans - 0.0% - - 

Maine Portland - 0.0% - - 

Maryland Baltimore - 0.0% - - 

Massachusetts Boston - 0.0% - - 

Michigan Detroit - 0.0% - - 

Michigan Grand Rapids - 0.0% - - 

Minnesota St. Paul - 0.0% - - 

Mississippi Jackson - 0.0% - - 

Missouri St. Louis - 0.0% - - 

Missouri Kansas City - 0.0% - - 

Montana Great Falls - 0.0% - - 

Nebraska Omaha - 0.0% - - 

New Hampshire Concord - 0.0% - - 

New Jersey Newark - 0.0% - - 

New Mexico Albuquerque 4,362 -2.4% (107) 4,255 
A-36

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York - 0.0% - - 

New York Syracuse - 0.0% - - 

Nevada Las Vegas 4,362 3.1% 137 4,499 

North Carolina Charlotte - 0.0% - - 

North Dakota Bismarck - 0.0% - - 

Ohio Cincinnati - 0.0% - - 

Oregon Portland 4,362 1.9% 85 4,447 

Pennsylvania Philadelphia - 0.0% - - 

Pennsylvania Wilkes-Barre - 0.0% - - 

Rhode Island Providence - 0.0% - - 

South Carolina Spartanburg - 0.0% - - 

South Dakota Rapid City - 0.0% - - 

Tennessee Knoxville - 0.0% - - 

Texas Houston - 0.0% - - 

Utah Salt Lake City 4,362 -3.1% (137) 4,225 

Vermont Burlington - 0.0% - - 

Virginia Alexandria - 0.0% - - 

Virginia Lynchburg - 0.0% - - 

Washington Seattle 4,362 3.7% 162 4,524 

Washington Spokane 4,362 -1.9% (82) 4,280 

West Virginia Charleston - 0.0% - - 

Wisconsin Green Bay - 0.0% - - 

Wyoming Cheyenne 4,362 -3.3% (145) 4,217 

Puerto Rico Cayey - 0.0% - - 
A-37

TABLE 18-2 – LOCATION-BASED COSTS FOR MSW 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 8,312 12.9% 1,072 9,384 

Alaska Fairbanks 8,312 17.8% 1,480 9,792 

Alabama Huntsville 8,312 -6.6% (552) 7,760 

Arizona Phoenix 8,312 -5.2% (429) 7,883 

Arkansas Little Rock 8,312 -5.9% (492) 7,820 

California Los Angeles 8,312 4.5% 376 8,688 

California Redding 8,312 3.1% 259 8,571 

California Bakersfield 8,312 2.8% 236 8,548 

California Sacramento 8,312 4.9% 406 8,718 

California San Francisco 8,312 12.4% 1,029 9,341 

Colorado Denver 8,312 -5.3% (440) 7,872 

Connecticut Hartford 8,312 4.9% 410 8,722 

Delaware Dover 8,312 3.1% 255 8,567 

District of Columbia Washington 8,312 1.8% 152 8,464 

Florida Tallahassee 8,312 -7.2% (595) 7,717 

Florida Tampa 8,312 -3.1% (262) 8,050 

Georgia Atlanta 8,312 -7.5% (622) 7,690 

Hawaii Honolulu 8,312 19.6% 1,629 9,941 

Idaho Boise 8,312 -4.6% (384) 7,928 

Illinois Chicago 8,312 11.8% 978 9,290 

Indiana Indianapolis 8,312 -1.7% (145) 8,167 

Iowa Davenport 8,312 -1.5% (121) 8,191 

Iowa Waterloo 8,312 -4.7% (387) 7,925 

Kansas Wichita 8,312 -6.0% (495) 7,817 

Kentucky Louisville 8,312 -5.4% (448) 7,864 

Louisiana New Orleans 8,312 -8.1% (672) 7,640 

Maine Portland 8,312 -5.3% (438) 7,874 

Maryland Baltimore 8,312 -2.4% (203) 8,109 

Massachusetts Boston 8,312 10.8% 900 9,212 

Michigan Detroit 8,312 2.1% 177 8,489 

Michigan Grand Rapids 8,312 -2.8% (229) 8,083 

Minnesota St. Paul 8,312 4.0% 334 8,646 

Mississippi Jackson 8,312 -6.1% (510) 7,802 

Missouri St. Louis 8,312 1.9% 161 8,473 

Missouri Kansas City 8,312 0.9% 79 8,391 

Montana Great Falls 8,312 -3.9% (322) 7,990 

Nebraska Omaha 8,312 -3.3% (275) 8,037 

New Hampshire Concord 8,312 -2.6% (218) 8,094 

New Jersey Newark 8,312 12.8% 1,066 9,378 

New Mexico Albuquerque 8,312 -4.1% (337) 7,975 
A-38

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 8,312 26.0% 2,161 10,473 

New York Syracuse 8,312 -0.1% (12) 8,300 

Nevada Las Vegas 8,312 3.8% 312 8,624 

North Carolina Charlotte 8,312 -7.7% (636) 7,676 

North Dakota Bismarck 8,312 -5.8% (481) 7,831 

Ohio Cincinnati 8,312 -4.0% (334) 7,978 

Oregon Portland 8,312 1.7% 139 8,451 

Pennsylvania Philadelphia 8,312 7.5% 625 8,937 

Pennsylvania Wilkes-Barre 8,312 -3.1% (257) 8,055 

Rhode Island Providence 8,312 2.8% 234 8,546 

South Carolina Spartanburg 8,312 -10.1% (841) 7,471 

South Dakota Rapid City 8,312 -7.7% (644) 7,668 

Tennessee Knoxville 8,312 -8.1% (675) 7,637 

Texas Houston 8,312 -8.0% (669) 7,643 

Utah Salt Lake City 8,312 -5.0% (413) 7,899 

Vermont Burlington 8,312 -5.2% (434) 7,878 

Virginia Alexandria 8,312 -1.7% (143) 8,169 

Virginia Lynchburg 8,312 -6.3% (522) 7,790 

Washington Seattle 8,312 4.0% 329 8,641 

Washington Spokane 8,312 -2.8% (233) 8,079 

West Virginia Charleston 8,312 -1.5% (124) 8,188 

Wisconsin Green Bay 8,312 0.8% 65 8,377 

Wyoming Cheyenne 8,312 -5.3% (441) 7,871 

Puerto Rico Cayey 8,312 -1.6% (136) 8,176 
A-39

TABLE 19-2 – LOCATION-BASED COSTS FOR HY 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 2,936 21.1% 619 3,555 

Alaska Fairbanks 2,936 33.1% 973 3,909 

Alabama Huntsville - 0.0% - - 

Arizona Phoenix - 0.0% - - 

Arkansas Little Rock - 0.0% - - 

California Los Angeles 2,936 7.3% 215 3,151 

California Redding 2,936 3.0% 88 3,024 

California Bakersfield 2,936 2.6% 75 3,011 

California Sacramento 2,936 3.8% 113 3,049 

California San Francisco 2,936 13.1% 386 3,322 

Colorado Denver 2,936 -1.6% (48) 2,888 

Connecticut Hartford 2,936 6.5% 190 3,126 

Delaware Dover - 0.0% - - 

District of Columbia Washington - 0.0% - - 

Florida Tallahassee - 0.0% - - 

Florida Tampa - 0.0% - - 

Georgia Atlanta - 0.0% - - 

Hawaii Honolulu - 0.0% - - 

Idaho Boise 2,936 -2.0% (60) 2,876 

Illinois Chicago - 0.0% - - 

Indiana Indianapolis - 0.0% - - 

Iowa Davenport - 0.0% - - 

Iowa Waterloo - 0.0% - - 

Kansas Wichita - 0.0% - - 

Kentucky Louisville - 0.0% - - 

Louisiana New Orleans - 0.0% - - 

Maine Portland 2,936 -1.3% (39) 2,897 

Maryland Baltimore - 0.0% - - 

Massachusetts Boston - 0.0% - - 

Michigan Detroit - 0.0% - - 

Michigan Grand Rapids - 0.0% - - 

Minnesota St. Paul - 0.0% - - 

Mississippi Jackson - 0.0% - - 

Missouri St. Louis 2,936 0.8% 22 2,958 

Missouri Kansas City 2,936 0.9% 27 2,963 

Montana Great Falls 2,936 -1.1% (32) 2,904 

Nebraska Omaha - 0.0% - - 

New Hampshire Concord - 0.0% - - 

New Jersey Newark - 0.0% - - 

New Mexico Albuquerque - 0.0% - - 
A-40

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York - 0.0% - - 

New York Syracuse - 0.0% - - 

Nevada Las Vegas - 0.0% - - 

North Carolina Charlotte 2,936 0.0% 20 32,956 

North Dakota Bismarck - 0.0% - - 

Ohio Cincinnati 2,936 2.8% (62) 2,874 

Oregon Portland 2,936 4.9% 145 3,081 

Pennsylvania Philadelphia - 0.0% - - 

Pennsylvania Wilkes-Barre - 0.0% - - 

Rhode Island Providence - 0.0% - - 

South Carolina Spartanburg - 0.0% - - 

South Dakota Rapid City 2,936 -3.8% (112) 2,824 

Tennessee Knoxville - 0.0% - - 

Texas Houston - 0.0% - - 

Utah Salt Lake City - 0.0% - - 

Vermont Burlington - 0.0% - - 

Virginia Alexandria - 0.0% - - 

Virginia Lynchburg - 0.0% - - 

Washington Seattle 2,936 3.5% 104 3,040 

Washington Spokane 2,936 -1.0% (30) 2,906 

West Virginia Charleston - 0.0% - - 

Wisconsin Green Bay - 0.0% - - 

Wyoming Cheyenne - 0.0% - - 

Puerto Rico Cayey - 0.0% - - 
A-41

TABLE 20-2 – LOCATION-BASED COSTS FOR PS 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,288 23.7% 1,251 6,539 

Alaska Fairbanks 5,288 31.8% 1,680 6,968 

Alabama Huntsville 5,288 -13.8% (730) 4,558 

Arizona Phoenix 5,288 -10.8% (571) 4,717 

Arkansas Little Rock 5,288 -12.4% (654) 4,634 

California Los Angeles 5,288 8.3% 439 5,727 

California Redding 5,288 6.2% 326 5,614 

California Bakersfield 5,288 5.3% 280 5,568 

California Sacramento 5,288 9.7% 510 5,798 

California San Francisco 5,288 24.3% 1,283 6,571 

Colorado Denver 5,288 -11.2% (595) 4,693 

Connecticut Hartford 5,288 9.4% 496 5,784 

Delaware Dover 5,288 5.5% 292 5,580 

District of Columbia Washington 5,288 2.2% 118 5,406 

Florida Tallahassee - - - 

Florida Tampa - - - 

Georgia Atlanta 5,288 -15.5% (822) 4,466 

Hawaii Honolulu 5,288 19.1% 1,012 6,300 

Idaho Boise 5,288 -9.7% (511) 4,777 

Illinois Chicago 5,288 24.1% 1,275 6,563 

Indiana Indianapolis 5,288 -3.8% (201) 5,087 

Iowa Davenport 5,288 -3.1% (165) 5,123 

Iowa Waterloo 5,288 -9.7% (515) 4,773 

Kansas Wichita - - - 

Kentucky Louisville 5,288 -11.2% (592) 4,696 

Louisiana New Orleans 5,288 -17.1% (905) 4,383 

Maine Portland 5,288 -11.2% (595) 4,693 

Maryland Baltimore 5,288 -5.8% (307) 4,981 

Massachusetts Boston 5,288 21.6% 1,141 6,429 

Michigan Detroit 5,288 4.2% 224 5,512 

Michigan Grand Rapids 5,288 -5.8% (307) 4,981 

Minnesota St. Paul 5,288 8.2% 433 5,721 

Mississippi Jackson 5,288 -12.8% (675) 4,613 

Missouri St. Louis 5,288 3.7% 196 5,484 

Missouri Kansas City 5,288 1.7% 92 5,380 

Montana Great Falls 5,288 -8.2% (436) 4,852 

Nebraska Omaha 5,288 -7.0% (371) 4,917 

New Hampshire Concord 5,288 -5.7% (300) 4,988 

New Jersey Newark 5,288 26.2% 1,383 6,671 

New Mexico Albuquerque 5,288 -8.7% (459) 4,829 
A-42

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 5,288 52.5% 2,776 8,064 

New York Syracuse 5,288 -1.0% (52) 5,236 

Nevada Las Vegas 5,288 7.6% 404 5,692 

North Carolina Charlotte 5,288 -16.0% (844) 4,444 

North Dakota Bismarck 5,288 -12.2% (646) 4,642 

Ohio Cincinnati 5,288 -8.5% (449) 4,839 

Oregon Portland 5,288 4.0% 213 5,501 

Pennsylvania Philadelphia 5,288 15.3% 811 6,099 

Pennsylvania Wilkes-Barre 5,288 -6.6% (351) 4,937 

Rhode Island Providence 5,288 5.4% 285 5,573 

South Carolina Spartanburg 5,288 -21.0% (1,113) 4,175 

South Dakota Rapid City 5,288 -16.1% (854) 4,434 

Tennessee Knoxville 5,288 -16.9% (891) 4,397 

Texas Houston 5,288 -16.6% (880) 4,408 

Utah Salt Lake City 5,288 -10.6% (559) 4,729 

Vermont Burlington 5,288 -11.2% (594) 4,694 

Virginia Alexandria 5,288 -3.9% (208) 5,080 

Virginia Lynchburg 5,288 -13.1% (690) 4,598 

Washington Seattle 5,288 7.9% 418 5,706 

Washington Spokane 5,288 -5.9% (313) 4,975 

West Virginia Charleston 5,288 -3.3% (173) 5,115 

Wisconsin Green Bay 5,288 1.4% 73 5,361 

Wyoming Cheyenne 5,288 -11.5% (609) 4,679 

Puerto Rico Cayey 5,288 -4.8% (256) 5,032 
A-43

TABLE 21-2 – LOCATION-BASED COSTS FOR WN 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 2,213 28.0% 620 2,833 

Alaska Fairbanks 2,213 49.9% 1,104 3,317 

Alabama Huntsville 2,213 -4.5% (100) 2,113 

Arizona Phoenix 2,213 -3.1% (68) 2,145 

Arkansas Little Rock 2,213 -3.6% (81) 2,132 

California Los Angeles 2,213 13.3% 294 2,507 

California Redding 2,213 10.0% 221 2,434 

California Bakersfield 2,213 11.6% 256 2,469 

California Sacramento 2,213 11.1% 245 2,458 

California San Francisco 2,213 19.8% 439 2,652 

Colorado Denver 2,213 2.0% 44 2,257 

Connecticut Hartford 2,213 7.2% 159 2,372 

Delaware Dover 2,213 5.0% 112 2,325 

District of Columbia Washington 2,213 8.4% 185 2,398 

Florida Tallahassee 2,213 -5.3% (116) 2,097 

Florida Tampa 2,213 -2.3% (51) 2,162 

Georgia Atlanta 2,213 -5.2% (114) 2,099 

Hawaii Honolulu 2,213 30.1% 667 2,880 

Idaho Boise 2,213 3.2% 71 2,284 

Illinois Chicago 2,213 15.2% 336 2,549 

Indiana Indianapolis 2,213 -0.2% (4) 2,209 

Iowa Davenport 2,213 4.7% 103 2,316 

Iowa Waterloo 2,213 2.3% 51 2,264 

Kansas Wichita 2,213 1.7% 37 2,250 

Kentucky Louisville 2,213 -3.6% (80) 2,133 

Louisiana New Orleans 2,213 -6.5% (144) 2,069 

Maine Portland 2,213 6.2% 137 2,350 

Maryland Baltimore 2,213 1.4% 30 2,243 

Massachusetts Boston 2,213 11.6% 256 2,469 

Michigan Detroit 2,213 2.7% 59 2,272 

Michigan Grand Rapids 2,213 -1.3% (29) 2,184 

Minnesota St. Paul 2,213 9.6% 213 2,426 

Mississippi Jackson 2,213 -4.2% (92) 2,121 

Missouri St. Louis 2,213 3.2% 72 2,285 

Missouri Kansas City 2,213 1.3% 28 2,241 

Montana Great Falls 2,213 4.5% 99 2,312 

Nebraska Omaha 2,213 3.6% 81 2,294 

New Hampshire Concord 2,213 5.4% 119 2,332 

New Jersey Newark 2,213 12.4% 274 2,487 

New Mexico Albuquerque 2,213 3.8% 84 2,297 
A-44

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 2,213 27.1% 600 2,813 

New York Syracuse 2,213 1.1% 25 2,238 

Nevada Las Vegas 2,213 9.4% 208 2,421 

North Carolina Charlotte 2,213 -4.9% (109) 2,104 

North Dakota Bismarck 2,213 2.2% 48 2,261 

Ohio Cincinnati 2,213 -2.8% (61) 2,152 

Oregon Portland 2,213 8.9% 198 2,411 

Pennsylvania Philadelphia 2,213 6.2% 136 2,349 

Pennsylvania Wilkes-Barre 2,213 -1.7% (38) 2,175 

Rhode Island Providence 2,213 2.4% 53 2,266 

South Carolina Spartanburg 2,213 -6.8% (149) 2,064 

South Dakota Rapid City 2,213 0.9% 19 2,232 

Tennessee Knoxville 2,213 -5.6% (124) 2,089 

Texas Houston 2,213 -5.9% (131) 2,082 

Utah Salt Lake City 2,213 4.0% 89 2,302 

Vermont Burlington 2,213 3.2% 70 2,283 

Virginia Alexandria 2,213 2.2% 48 2,261 

Virginia Lynchburg 2,213 -4.3% (94) 2,119 

Washington Seattle 2,213 4.8% 105 2,318 

Washington Spokane 2,213 5.4% 120 2,333 

West Virginia Charleston 2,213 0.0% (0) 2,213 

Wisconsin Green Bay 2,213 1.2% 26 2,239 

Wyoming Cheyenne 2,213 4.3% 95 2,308 

Puerto Rico Cayey 2,213 7.7% 170 2,383 
A-45

TABLE 22-2 – LOCATION-BASED COSTS FOR WF 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 6,230 15.5% 967 7,197 

Alaska Fairbanks - 0.0% - - 

Alabama Huntsville - 0.0% - - 

Arizona Phoenix - 0.0% - - 

Arkansas Little Rock - 0.0% - - 

California Los Angeles 6,230 6.7% 416 6,646 

California Redding - 0.0% - - 

California Bakersfield - 0.0% - - 

California Sacramento - 0.0% - - 

California San Francisco 6,230 15.0% 932 7,162 

Colorado Denver - 0.0% - - 

Connecticut Hartford 6,230 5.2% 326 6,556 

Delaware Dover 6,230 2.9% 182 6,412 

District of Columbia Washington 6,230 1.9% 119 6,349 

Florida Tallahassee - 0.0% - - 

Florida Tampa - 0.0% - - 

Georgia Atlanta 6,230 -8.1% (505) 5,725 

Hawaii Honolulu 6,230 13.8% 857 7,087 

Idaho Boise - 0.0% - - 

Illinois Chicago 6,230 14.7% 914 7,144 

Indiana Indianapolis 6,230 -1.8% (113) 6,117 

Iowa Davenport - 0.0% - - 

Iowa Waterloo - 0.0% - - 

Kansas Wichita - 0.0% - - 

Kentucky Louisville - 0.0% - - 

Louisiana New Orleans - 0.0% - - 

Maine Portland 6,230 -3.8% (235) 5,995 

Maryland Baltimore 6,230 -2.8% (174) 6,056 

Massachusetts Boston 6,230 11.6% 725 6,955 

Michigan Detroit 6,230 2.1% 130 6,360 

Michigan Grand Rapids 6,230 -3.2% (202) 6,028 

Minnesota St. Paul 6,230 6.5% 405 6,635 

Mississippi Jackson - 0.0% - - 

Missouri St. Louis - 0.0% - - 

Missouri Kansas City - 0.0% - - 

Montana Great Falls - 0.0% - - 

Nebraska Omaha - 0.0% - - 

New Hampshire Concord - 0.0% - - 

New Jersey Newark 6,230 13.3% 827 7,057 

New Mexico Albuquerque - 0.0% - - 
A-46

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 6,230 28.1% 1,754 7,984 

New York Syracuse 6,230 -0.9% (54) 6,176 

Nevada Las Vegas - 0.0% - - 

North Carolina Charlotte 6,230 -8.3% (514) 5,716 

North Dakota Bismarck - 0.0% - - 

Ohio Cincinnati - 0.0% - - 

Oregon Portland 6,230 4.9% 304 6,534 

Pennsylvania Philadelphia - 0.0% - - 

Pennsylvania Wilkes-Barre - 0.0% - - 

Rhode Island Providence 6,230 2.4% 152 6,382 

South Carolina Spartanburg 6,230 -11.1% (691) 5,539 

South Dakota Rapid City - 0.0% - - 

Tennessee Knoxville - 0.0% - - 

Texas Houston 6,230 -8.7% (544) 5,686 

Utah Salt Lake City - 0.0% - - 

Vermont Burlington - 0.0% - - 

Virginia Alexandria 6,230 -2.5% (157) 6,073 

Virginia Lynchburg 6,230 -6.8% (423) 5,807 

Washington Seattle 6,230 4.4% 277 6,507 

Washington Spokane - 0.0% - - 

West Virginia Charleston - 0.0% - - 

Wisconsin Green Bay 6,230 0.6% 40 6,270 

Wyoming Cheyenne - 0.0% - - 

Puerto Rico Cayey 6,230 -1.0% (65) 6,165 
A-47

TABLE 23-2 – LOCATION-BASED COSTS FOR SO 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 5,067 22.5% 1,139 6,206 

Alaska Fairbanks 5,067 33.3% 1,685 6,752 

Alabama Huntsville 5,067 -12.2% (619) 4,448 

Arizona Phoenix 5,067 -9.5% (483) 4,584 

Arkansas Little Rock 5,067 -10.9% (553) 4,514 

California Los Angeles 5,067 9.4% 477 5,544 

California Redding 5,067 8.2% 414 5,481 

California Bakersfield 5,067 7.6% 383 5,450 

California Sacramento 5,067 10.8% 549 5,616 

California San Francisco 5,067 23.2% 1,177 6,244 

Colorado Denver 5,067 -8.0% (407) 4,660 

Connecticut Hartford 5,067 8.1% 410 5,477 

Delaware Dover 5,067 4.3% 217 5,284 

District of Columbia Washington 5,067 1.7% 87 5,154 

Florida Tallahassee 5,067 -13.1% (666) 4,401 

Florida Tampa 5,067 -5.8% (293) 4,774 

Georgia Atlanta 5,067 -13.8% (697) 4,370 

Hawaii Honolulu 5,067 36.7% 1,861 6,928 

Idaho Boise 5,067 -6.0% (302) 4,765 

Illinois Chicago 5,067 23.7% 1,201 6,268 

Indiana Indianapolis 5,067 -3.3% (166) 4,901 

Iowa Davenport 5,067 -0.5% (27) 5,040 

Iowa Waterloo 5,067 -6.4% (325) 4,742 

Kansas Wichita 5,067 -8.8% (447) 4,620 

Kentucky Louisville 5,067 -9.9% (502) 4,565 

Louisiana New Orleans 5,067 -16.3% (824) 4,243 

Maine Portland 5,067 -7.6% (386) 4,681 

Maryland Baltimore 5,067 -5.4% (275) 4,792 

Massachusetts Boston 5,067 18.9% 958 6,025 

Michigan Detroit 5,067 3.5% 175 5,242 

Michigan Grand Rapids 5,067 -5.5% (278) 4,789 

Minnesota St. Paul 5,067 9.9% 501 5,568 

Mississippi Jackson 5,067 -11.3% (573) 4,494 

Missouri St. Louis 5,067 3.4% 174 5,241 

Missouri Kansas City 5,067 1.3% 64 5,131 

Montana Great Falls 5,067 -4.6% (235) 4,832 

Nebraska Omaha 5,067 -4.0% (200) 4,867 

New Hampshire Concord 5,067 -2.7% (138) 4,929 

New Jersey Newark 5,067 22.4% 1,133 6,200 

New Mexico Albuquerque 5,067 -5.4% (273) 4,794 
A-48

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 5,067 46.3% 2,347 7,414 

New York Syracuse 5,067 -1.8% (92) 4,975 

Nevada Las Vegas 5,067 9.4% 477 5,544 

North Carolina Charlotte 5,067 -14.1% (714) 4,353 

North Dakota Bismarck 5,067 -8.5% (433) 4,634 

Ohio Cincinnati 5,067 -7.8% (397) 4,670 

Oregon Portland 5,067 5.5% 279 5,346 

Pennsylvania Philadelphia 5,067 13.3% 676 5,743 

Pennsylvania Wilkes-Barre 5,067 -6.2% (312) 4,755 

Rhode Island Providence 5,067 4.0% 201 5,268 

South Carolina Spartanburg 5,067 -18.6% (943) 4,124 

South Dakota Rapid City 5,067 -11.7% (593) 4,474 

Tennessee Knoxville 5,067 -14.9% (756) 4,311 

Texas Houston 5,067 -14.8% (748) 4,319 

Utah Salt Lake City 5,067 -6.7% (338) 4,729 

Vermont Burlington 5,067 -8.2% (416) 4,651 

Virginia Alexandria 5,067 -4.3% (219) 4,848 

Virginia Lynchburg 5,067 -11.6% (586) 4,481 

Washington Seattle 5,067 7.2% 362 5,429 

Washington Spokane 5,067 -2.6% (133) 4,934 

West Virginia Charleston 5,067 -2.8% (142) 4,925 

Wisconsin Green Bay 5,067 1.0% 48 5,115 

Wyoming Cheyenne 5,067 -7.8% (394) 4,673 

Puerto Rico Cayey 5,067 -3.6% (181) 4,886 
A-49

TABLE 24-3 – LOCATION-BASED COSTS FOR PV 20 MW 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4183 19.9% 831 5014 

Alaska Fairbanks 4183 32.1% 1,341 5524 

Alabama Huntsville 4183 -7.5% (313) 3870 

Arizona Phoenix 4183 -5.7% (238) 3945 

Arkansas Little Rock 4183 -6.5% (274) 3909 

California Los Angeles 4183 8.8% 368 4551 

California Redding 4183 7.2% 299 4482 

California Bakersfield 4183 7.3% 307 4490 

California Sacramento 4183 8.8% 369 4552 

California San Francisco 4183 17.7% 739 4922 

Colorado Denver 4183 -3.4% (141) 4042 

Connecticut Hartford 4183 6.2% 261 4444 

Delaware Dover 4183 3.7% 154 4337 

District of Columbia Washington 4183 3.5% 144 4327 

Florida Tallahassee 4183 -8.2% (341) 3842 

Florida Tampa 4183 -3.6% (150) 4033 

Georgia Atlanta 4183 -8.4% (353) 3830 

Hawaii Honolulu 4183 40.5% 1,692 5875 

Idaho Boise 4183 -2.0% (82) 4101 

Illinois Chicago 4183 16.5% 688 4871 

Indiana Indianapolis 4183 -1.7% (71) 4112 

Iowa Davenport 4183 1.2% 50 4233 

Iowa Waterloo 4183 -2.5% (103) 4080 

Kansas Wichita 4183 -3.9% (161) 4022 

Kentucky Louisville 4183 -6.0% (253) 3930 

Louisiana New Orleans 4183 -10.1% (423) 3760 

Maine Portland 4183 -2.8% (116) 4067 

Maryland Baltimore 4183 -2.3% (95) 4088 

Massachusetts Boston 4183 13.0% 542 4725 

Michigan Detroit 4183 2.3% 94 4277 

Michigan Grand Rapids 4183 -3.4% (143) 4040 

Minnesota St. Paul 4183 7.9% 330 4513 

Mississippi Jackson 4183 -6.9% (289) 3894 

Missouri St. Louis 4183 2.7% 113 4296 

Missouri Kansas City 4183 1.0% 42 4225 

Montana Great Falls 4183 -0.9% (38) 4145 

Nebraska Omaha 4183 -0.8% (35) 4148 

New Hampshire Concord 4183 0.0% 2 4185 

New Jersey Newark 4183 14.0% 586 4769 

New Mexico Albuquerque 4183 -1.5% (62) 4121 
A-50

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4183 30.7% 1,286 5469 

New York Syracuse 4183 -0.6% (24) 4159 

Nevada Las Vegas 4183 7.6% 317 4500 

North Carolina Charlotte 4183 -8.5% (357) 3826 

North Dakota Bismarck 4183 -3.6% (149) 4034 

Ohio Cincinnati 4183 -4.8% (199) 3984 

Oregon Portland 4183 5.5% 230 4413 

Pennsylvania Philadelphia 4183 8.5% 356 4539 

Pennsylvania Wilkes-Barre 4183 -3.6% (150) 4033 

Rhode Island Providence 4183 2.7% 113 4296 

South Carolina Spartanburg 4183 -11.3% (474) 3709 

South Dakota Rapid City 4183 -5.5% (231) 3952 

Tennessee Knoxville 4183 -9.2% (383) 3800 

Texas Houston 4183 -9.2% (384) 3799 

Utah Salt Lake City 4183 -2.1% (86) 4097 

Vermont Burlington 4183 -3.4% (141) 4042 

Virginia Alexandria 4183 -2.6% (108) 4075 

Virginia Lynchburg 4183 -7.1% (295) 3888 

Washington Seattle 4183 5.0% 210 4393 

Washington Spokane 4183 0.1% 4 4187 

West Virginia Charleston 4183 -1.4% (59) 4124 

Wisconsin Green Bay 4183 0.8% 34 4217 

Wyoming Cheyenne 4183 -2.5% (105) 4078 

Puerto Rico Cayey 4183 0.6% 26 4209 
A-51

TABLE 24-4 – LOCATION-BASED COSTS FOR PV (150 MW) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 3,873 20.9% 811 4,684 

Alaska Fairbanks 3,873 34.0% 1,318 5,191 

Alabama Huntsville 3,873 -7.5% (292) 3,581 

Arizona Phoenix 3,873 -5.7% (222) 3,651 

Arkansas Little Rock 3,873 -6.6% (256) 3,617 

California Los Angeles 3,873 9.3% 361 4,234 

California Redding 3,873 7.5% 292 4,165 

California Bakersfield 3,873 7.8% 302 4,175 

California Sacramento 3,873 9.2% 357 4,230 

California San Francisco 3,873 18.3% 711 4,584 

Colorado Denver 3,873 -3.2% (123) 3,750 

Connecticut Hartford 3,873 6.5% 251 4,124 

Delaware Dover 3,873 3.9% 150 4,023 

District of Columbia Washington 3,873 3.8% 148 4,021 

Florida Tallahassee 3,873 -8.3% (320) 3,553 

Florida Tampa 3,873 -3.6% (141) 3,732 

Georgia Atlanta 3,873 -8.5% (330) 3,543 

Hawaii Honolulu 3,873 43.4% 1,681 5,554 

Idaho Boise 3,873 -1.7% (67) 3,806 

Illinois Chicago 3,873 16.9% 655 4,528 

Indiana Indianapolis 3,873 -1.7% (65) 3,808 

Iowa Davenport 3,873 1.4% 55 3,928 

Iowa Waterloo 3,873 -2.3% (89) 3,784 

Kansas Wichita 3,873 -3.7% (142) 3,731 

Kentucky Louisville 3,873 -6.1% (236) 3,637 

Louisiana New Orleans 3,873 -10.2% (396) 3,477 

Maine Portland 3,873 -2.5% (98) 3,775 

Maryland Baltimore 3,873 -2.1% (83) 3,790 

Massachusetts Boston 3,873 13.3% 515 4,388 

Michigan Detroit 3,873 2.3% 89 3,962 

Michigan Grand Rapids 3,873 -3.5% (134) 3,739 

Minnesota St. Paul 3,873 8.2% 319 4,192 

Mississippi Jackson 3,873 -7.0% (270) 3,603 

Missouri St. Louis 3,873 2.8% 109 3,982 

Missouri Kansas City 3,873 1.1% 41 3,914 

Montana Great Falls 3,873 -0.6% (25) 3,848 

Nebraska Omaha 3,873 -0.6% (24) 3,849 

New Hampshire Concord 3,873 0.3% 11 3,884 

New Jersey Newark 3,873 14.2% 550 4,423 

New Mexico Albuquerque 3,873 -1.2% (48) 3,825 
A-52

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 3,873 31.4% 1,216 5,089 

New York Syracuse 3,873 -0.5% (19) 3,854 

Nevada Las Vegas 3,873 7.9% 307 4,180 

North Carolina Charlotte 3,873 -8.6% (333) 3,540 

North Dakota Bismarck 3,873 -3.4% (130) 3,743 

Ohio Cincinnati 3,873 -4.8% (186) 3,687 

Oregon Portland 3,873 5.9% 227 4,100 

Pennsylvania Philadelphia 3,873 8.6% 335 4,208 

Pennsylvania Wilkes-Barre 3,873 -3.6% (140) 3,733 

Rhode Island Providence 3,873 2.8% 107 3,980 

South Carolina Spartanburg 3,873 -11.4% (443) 3,430 

South Dakota Rapid City 3,873 -5.4% (207) 3,666 

Tennessee Knoxville 3,873 -9.3% (358) 3,515 

Texas Houston 3,873 -9.3% (360) 3,513 

Utah Salt Lake City 3,873 -1.8% (70) 3,803 

Vermont Burlington 3,873 -3.2% (122) 3,751 

Virginia Alexandria 3,873 -2.6% (100) 3,773 

Virginia Lynchburg 3,873 -7.1% (276) 3,597 

Washington Seattle 3,873 5.2% 200 4,073 

Washington Spokane 3,873 0.3% 14 3,887 

West Virginia Charleston 3,873 -1.4% (53) 3,820 

Wisconsin Green Bay 3,873 0.9% 33 3,906 

Wyoming Cheyenne 3,873 -2.2% (86) 3,787 

Puerto Rico Cayey 3,873 1.0% 40 3,913 
A-53

TABLE 25-1 – LOCATION-BASED COSTS FOR PV (150 MW + 10% STORAGE) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,054 20.0% 811 4,865 

Alaska Fairbanks 4,054 32.5% 1,318 5,372 

Alabama Huntsville 4,054 -7.2% (292) 3,762 

Arizona Phoenix 4,054 -5.5% (222) 3,832 

Arkansas Little Rock 4,054 -6.3% (256) 3,798 

California Los Angeles 4,054 8.9% 361 4,415 

California Redding 4,054 7.2% 292 4,346 

California Bakersfield 4,054 7.5% 302 4,356 

California Sacramento 4,054 8.8% 357 4,411 

California San Francisco 4,054 17.5% 711 4,765 

Colorado Denver 4,054 -3.0% (123) 3,931 

Connecticut Hartford 4,054 6.2% 251 4,305 

Delaware Dover 4,054 3.7% 150 4,204 

District of Columbia Washington 4,054 3.7% 148 4,202 

Florida Tallahassee 4,054 -7.9% (320) 3,734 

Florida Tampa 4,054 -3.5% (141) 3,913 

Georgia Atlanta 4,054 -8.1% (330) 3,724 

Hawaii Honolulu 4,054 41.5% 1,681 5,735 

Idaho Boise 4,054 -1.7% (67) 3,987 

Illinois Chicago 4,054 16.1% 655 4,709 

Indiana Indianapolis 4,054 -1.6% (65) 3,989 

Iowa Davenport 4,054 1.3% 55 4,109 

Iowa Waterloo 4,054 -2.2% (89) 3,965 

Kansas Wichita 4,054 -3.5% (142) 3,912 

Kentucky Louisville 4,054 -5.8% (236) 3,818 

Louisiana New Orleans 4,054 -9.8% (396) 3,658 

Maine Portland 4,054 -2.4% (98) 3,956 

Maryland Baltimore 4,054 -2.1% (83) 3,971 

Massachusetts Boston 4,054 12.7% 515 4,569 

Michigan Detroit 4,054 2.2% 89 4,143 

Michigan Grand Rapids 4,054 -3.3% (134) 3,920 

Minnesota St. Paul 4,054 7.9% 319 4,373 

Mississippi Jackson 4,054 -6.7% (270) 3,784 

Missouri St. Louis 4,054 2.7% 109 4,163 

Missouri Kansas City 4,054 1.0% 41 4,095 

Montana Great Falls 4,054 -0.6% (25) 4,029 

Nebraska Omaha 4,054 -0.6% (24) 4,030 

New Hampshire Concord 4,054 0.3% 11 4,065 

New Jersey Newark 4,054 13.6% 550 4,604 

New Mexico Albuquerque 4,054 -1.2% (48) 4,006 
A-54

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4,054 30.0% 1,216 5,270 

New York Syracuse 4,054 -0.5% (19) 4,035 

Nevada Las Vegas 4,054 7.6% 307 4,361 

North Carolina Charlotte 4,054 -8.2% (333) 3,721 

North Dakota Bismarck 4,054 -3.2% (130) 3,924 

Ohio Cincinnati 4,054 -4.6% (186) 3,868 

Oregon Portland 4,054 5.6% 227 4,281 

Pennsylvania Philadelphia 4,054 8.3% 335 4,389 

Pennsylvania Wilkes-Barre 4,054 -3.4% (140) 3,914 

Rhode Island Providence 4,054 2.6% 107 4,161 

South Carolina Spartanburg 4,054 -10.9% (443) 3,611 

South Dakota Rapid City 4,054 -5.1% (207) 3,847 

Tennessee Knoxville 4,054 -8.8% (358) 3,696 

Texas Houston 4,054 -8.9% (360) 3,694 

Utah Salt Lake City 4,054 -1.7% (70) 3,984 

Vermont Burlington 4,054 -3.0% (122) 3,932 

Virginia Alexandria 4,054 -2.5% (100) 3,954 

Virginia Lynchburg 4,054 -6.8% (276) 3,778 

Washington Seattle 4,054 4.9% 200 4,254 

Washington Spokane 4,054 0.3% 14 4,068 

West Virginia Charleston 4,054 -1.3% (53) 4,001 

Wisconsin Green Bay 4,054 0.8% 33 4,087 

Wyoming Cheyenne 4,054 -2.1% (86) 3,968 

Puerto Rico Cayey 4,054 1.0% 40 4,094 

 
A-55

TABLE 25-2 – LOCATION-BASED COSTS FOR PV (150 MW + 20% STORAGE) 

(OCTOBER 1, 2012 DOLLARS) 

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

Alaska Anchorage 4,236 19.1% 811 5,047 

Alaska Fairbanks 4,236 31.1% 1,318 5,554 

Alabama Huntsville 4,236 -6.9% (292) 3,944 

Arizona Phoenix 4,236 -5.2% (222) 4,014 

Arkansas Little Rock 4,236 -6.0% (256) 3,980 

California Los Angeles 4,236 8.5% 361 4,597 

California Redding 4,236 6.9% 292 4,528 

California Bakersfield 4,236 7.1% 302 4,538 

California Sacramento 4,236 8.4% 357 4,593 

California San Francisco 4,236 16.8% 711 4,947 

Colorado Denver 4,236 -2.9% (123) 4,113 

Connecticut Hartford 4,236 5.9% 251 4,487 

Delaware Dover 4,236 3.5% 150 4,386 

District of Columbia Washington 4,236 3.5% 148 4,384 

Florida Tallahassee 4,236 -7.6% (320) 3,916 

Florida Tampa 4,236 -3.3% (141) 4,095 

Georgia Atlanta 4,236 -7.8% (330) 3,906 

Hawaii Honolulu 4,236 39.7% 1,681 5,917 

Idaho Boise 4,236 -1.6% (67) 4,169 

Illinois Chicago 4,236 15.5% 655 4,891 

Indiana Indianapolis 4,236 -1.5% (65) 4,171 

Iowa Davenport 4,236 1.3% 55 4,291 

Iowa Waterloo 4,236 -2.1% (89) 4,147 

Kansas Wichita 4,236 -3.4% (142) 4,094 

Kentucky Louisville 4,236 -5.6% (236) 4,000 

Louisiana New Orleans 4,236 -9.4% (396) 3,840 

Maine Portland 4,236 -2.3% (98) 4,138 

Maryland Baltimore 4,236 -2.0% (83) 4,153 

Massachusetts Boston 4,236 12.1% 515 4,751 

Michigan Detroit 4,236 2.1% 89 4,325 

Michigan Grand Rapids 4,236 -3.2% (134) 4,102 

Minnesota St. Paul 4,236 7.5% 319 4,555 

Mississippi Jackson 4,236 -6.4% (270) 3,966 

Missouri St. Louis 4,236 2.6% 109 4,345 

Missouri Kansas City 4,236 1.0% 41 4,277 

Montana Great Falls 4,236 -0.6% (25) 4,211 

Nebraska Omaha 4,236 -0.6% (24) 4,212 

New Hampshire Concord 4,236 0.3% 11 4,247 

New Jersey Newark 4,236 13.0% 550 4,786 

New Mexico Albuquerque 4,236 -1.1% (48) 4,188 
A-56

State City

Base 

Project 

Cost 

($/kW) 

Location 

Percent 

Variation

Delta Cost 

Difference 

($/kW) 

Total Location 

Project Cost 

($/kW) 

New York New York 4,236 28.7% 1,216 5,452 

New York Syracuse 4,236 -0.5% (19) 4,217 

Nevada Las Vegas 4,236 7.2% 307 4,543 

North Carolina Charlotte 4,236 -7.9% (333) 3,903 

North Dakota Bismarck 4,236 -3.1% (130) 4,106 

Ohio Cincinnati 4,236 -4.4% (186) 4,050 

Oregon Portland 4,236 5.4% 227 4,463 

Pennsylvania Philadelphia 4,236 7.9% 335 4,571 

Pennsylvania Wilkes-Barre 4,236 -3.3% (140) 4,096 

Rhode Island Providence 4,236 2.5% 107 4,343 

South Carolina Spartanburg 4,236 -10.5% (443) 3,793 

South Dakota Rapid City 4,236 -4.9% (207) 4,029 

Tennessee Knoxville 4,236 -8.5% (358) 3,878 

Texas Houston 4,236 -8.5% (360) 3,876 

Utah Salt Lake City 4,236 -1.6% (70) 4,166 

Vermont Burlington 4,236 -2.9% (122) 4,114 

Virginia Alexandria 4,236 -2.4% (100) 4,136 

Virginia Lynchburg 4,236 -6.5% (276) 3,960 

Washington Seattle 4,236 4.7% 200 4,436 

Washington Spokane 4,236 0.3% 14 4,250 

West Virginia Charleston 4,236 -1.3% (53) 4,183 

Wisconsin Green Bay 4,236 0.8% 33 4,269 

Wyoming Cheyenne 4,236 -2.0% (86) 4,150 

Puerto Rico Cayey 4,236 0.9% 40 4,276