# Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants

April 2013

Independent Statistics & Analysis
www.eia.gov U.S. Department of Energy

Washi ngton, DC 20585U.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

.

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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

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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 e stimates

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

................................ ............................... 8 Table 4. Regional cost adjustments for technologies m odeled by NEMS by Electric Market Module (EMM) region ,



### ................................ ................................ ................................ ................................ ............ 10

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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 character istics of new generating plants, play an important role in determining the mix of capacity additions that will serve future demand for electricity.
T hese 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.

I n 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 st andardized 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 th e 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

Th e focus of the 2013 update was to gather current information on the "overnight" construction cost s , 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 cu rrent 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, structu ral steel supply, and constr uction 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, pho tovoltaic modules, combustion turbines , and other auxiliary equipment

• Electrical and instrumentation and control: electrical transformers, switchgear, motor control centers, switchyards, distributed control systems, a nd 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.

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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 commissi oning, and fees for contingency 3



### • 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 electricit y are classified
as variable. The heat rates 4 

### 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 en gineering 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, hydro elec tric , 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 rang e of generating technologies. Additionally, while EIA does model new geothermal and hydro electric capacity, site specific cost estimates from alternate sources
are used in the NEMS model

. The specific technologies represented in the NEMS model for AEO201 3 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 

### Nota ble 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 pe rcent. 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 pri ce 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

assume d 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

.

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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 pl ants 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
relativ e to the 2010 s tudy, primarily d ue 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 s tudy. The size of the smaller photovoltaic units evaluated was increased from 7 MW in the 2010 s tudy 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 s ystem 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 hydroele ctric 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 pl ant 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 a re 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 w eighted 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.

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

### • Inflation of material and constructio n 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

s uitable 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 curve s for each of these technologies . T hese curves assume that the lowest

- co st, 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 s erve 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 co nstruction 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 ga s 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 c omponents are represented in the NEMS model at various stages of maturity.
EIA classifies tech nologies 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 an d 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 learnin g 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, Tabl e 8.4.

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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

- of

a

- 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 le arning

- 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 p ower 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 region s. EIA also assumes that the development of certain technologies is not feasible in given regions for geographic, logistical, or regulatory reasons. Th e 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 model ed in AEO201 3 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 ass ociated 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 Appe ndix B.

9 U.S. Energy Information Administration, AEO 2013 Cost and Performance Characteristics of New Central Station Electricity Generating Technologies, , Table 8.2.

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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

D ual 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

Natura l 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

Onsho re 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 Hydroele ctric 500 N/A $2,936 $14.13 $0.00 N Pumped Storage 250 N/A $5,288 $18.00 $0.00 N

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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%

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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

Re volutionary 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 Nat ural 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

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

### Table 3. Status of technologies and co mponents 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

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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 M odule (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 On

shore

Wind Off

shore

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 1.2 6 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 0.9 1 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 the se technologies which include region al 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 Mo dule region in order to represent regional cost factors in NEMS.

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# 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

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# Appendix B

– Ful l 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 up dates or revisions to the forward-looking statements if or when our expectations or events, conditions, or circ umstances 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 Maintenan ce (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 Ga s 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 Co mbined 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 F acility Diagram .................................................................................... 4-2 Figure 5-1 – Conventional NGCC Design Configuration ........................................................... 5-2 Figure 6-1 – AG-NGCC Desi gn 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 Desi gn 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 Tech nologies For Review ............................................................................. 1-2 Table 2-1 – Reference Coal Specification ................................................................................... 2- 2 Table 2-2 – Natural Gas Specification ......................................................................................... 2-3

Table 2-3 – Wood-Bioma ss Specification ................................................................................... 2-3 Table 2-4 – CT Capacity Adjustments ......................................................................................... 2 -5 Table 2-5 – Technology Perfor mance Specifications ................................................................ 2-10 Table 3-1 – Base Plant Site Capi tal Cost Estimate for APC ........................................................ 3-3 Table 3-2 – Base Plant Site Capi tal 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 Capita l Cost Estimate for APC/CCS ............................................... 4-3 Table 4-2 – Base Plant Site Capita l 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 fo r APC/CCS (650,000 kW) .......................................................... 4-4 Table 4-6 – O&M Expenses fo r APC/CCS (1,300,000 kW) ....................................................... 4-4

Table 4-7 – Environmental Em issions for APC/CCS .................................................................. 4-4 Table 5-1 – Base Plant Site Capital Co st Estimate for Conventional NGCC .............................. 5-3

Table 5-2 – Location-Based Cost s for Conventional NGCC....................................................... 5-9 Table 5-3 – O&M Expenses for Conventional NGCC ................................................................ 5-6

Table 5-4 – Environmental Emissi ons for Conventional NGCC ................................................. 5-6 Table 6-1 – Base Plant Site Capi tal Cost Estimate for AG-NGCC ............................................. 6-2

Table 6-2 – Location-Base d Costs for AG-NGCC .................................................................... 6-11 Table 6-3 – O&M Expenses for AG-NGCC ................................................................................ 6-3

Table 6-4 – Environmental Em issions for AG-NGCC ................................................................ 6-3 Table 7-1 – Base Plant Site Capital Co st Estimate for AG-NG CC/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 Em issions for AG-NGCC/CCS ....................................................... 7-3 Table 8-1 – Base Plant Site Capital Co st 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 Emissi ons for Conventional CT ....................................................... 8-4 Table 9-1 – Base Plant Site Capital Cost Estimate for Advanced CT ......................................... 9-2

Table 9-2 – Location-Based Co sts for Advanced CT ................................................................ 9-17 Table 9-3 – O&M Expenses for Advanced CT ........................................................................... 9-3

Table 9-4 – Environmental Emi ssions for Advanced CT ............................................................ 9-3 Table 10-1 – Base Plant Site Capi tal Cost Estimate for IGCC .................................................. 10-4 Table 10-2 – Base Plant Site Capi tal 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 Capita l 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 Em issions for IGCC/CCS ............................................................ 11-3

Table 12-1 – Base Plant Site Ca pital 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 Capi tal 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 Capi tal 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 Capi tal 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 Capi tal 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 Capi tal 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 Capi tal 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 Ca pital 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 Ca pital 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 Capi tal Cost Estimate for WF ..................................................... 22-3

Table 22-2 – Location-Based Costs for WF ............................................................................ 22-45 Table 23-1 – Base Plant Site Capi tal 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 Capi tal Cost Estimate for PV ...................................................... 24-3 Table 24-2 – Base Plant Site Capi tal 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 Natu ral 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 Availabl e 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 C 2 

### H 6 

### Ethane C 3 

### H 8 

### Propane C 4 

### H 10 

### n- Butane CH 4 

### Methane CO Carbon Monoxide CO 2 

### Carbon Dioxide COS Carbonyl Sulfide CT Combustion Turbine DC Direct Current DCS Distributed Control System DLN Dry Low-NO X 

### 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 H 2 

### S 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 N 2 

### Nitrogen NEMS National Energy Modeling System NGCC Natural Gas Combined Cycle NH 3 

### Ammonia NO X 

### Oxides of Nitrogen O 2 

### 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 SO 2 

### 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 pe rformance and cost assessment of power generation technologies utilized by the Energy Information Administrati on (“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, contingencie s, 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 genera ting technologies are consistent in scope, accounti ng for all costs in the planni ng 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 en gineering 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 dr ive each technolog y’s costs.

• Document the source and basis for final r ecommendations for altering or retaining the various assumptions.

1.1 TECHNOLOGIES ASSESSED The following table lists all technologie s 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 ba sis used for all technol ogies reviewed herein.

2.1 SAIC BACKGROUND

SAIC is a technical solutions and infrastructure c onsulting 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-b illions of dollars of power plants across the world in all commercial power generating technol ogies as well as many emerging technologies. This background has s upported SAIC’s acumen with respect to construction costs, operating cost s, technology development and evol ution, as well as trends in environmental regulation and compliance.

2.2 BASE FUEL CHARACTERISTICS This section provides a general fu el basis for each of the fuel types utilized by the technologies considered in this report which was listed in Tabl e 1-1. Each of the t echnologies that combust a fuel has the ability to operate ove r 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-bioma ss, 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 CH 4 93.9
Ethane C 2 H 6 3.2 Propane C 3 H 8 0.7

n -Butane C 4 H 10 0.4
Carbon Dioxide CO 2 1.0 Nitrogen N 2 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 standa rd 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 H 2 4.77 Nitrogen N 2 0.37
Sulfur S <0.01
Ash 2.35 Oxygen (2) O 2 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 em issions rates after implementation of best available control technology (“BACT ”), including sulfur dioxide (“SO 2 

### ”), oxides of nitrogen (“NO X 

### ”), particulate matter, mercury, and carbon dioxide (“CO 2 

### ”). With respect to CCS technologies, which are not curre ntly considered “proven” or BACT by regulating bodies, SAIC assumed capture and sequestration technologies that are currently in deve lopment for large-scale deployment, as discussed herein, an d at industry expected rates of CO 2 

### 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 ar e machines that produce power proportional to mass flow. Since air density is inversely proportional to temperature, ambient temperature has a strong influence on the cap acity of a given technology utilizing a CT (e.g., peaking power plant, combined-cycle power plant, and some gasifi cation power plants). Additionally, relative humidity impacts the av ailable capacity of a CT and consequently a CT-based power plant, primarily driven by the base assumption that th e CT-based technologies incorporate inlet evaporative cooling. By circul ating 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 temp erature (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 ar eas of high dry-bulb temp erature and low relative humidity. The final adjustment for ambient cond itions made for the CT-based plants is ambient pressure, which on average (not withstanding high or low pre ssure weather fronts that pass through a region) takes into consid eration 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.2-5TABLE 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 te chnology specifications.

2.6 COST ESTIMATION METHODOLOGY The approach taken in this latest cost analys is 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 in stance, overall wind a solar capex pricing lowered due to lower equipment pricing. 3. Updated actual costs being made availa ble 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 f acility of a certain size (cap acity) and configuration, and assuming a non-specific U.S. location with no u nusual location impacts (e.g., urban construction constraints) or infrastructure needs (e.g., a pr oject-dedicated interconn ection 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 tota l project engineering, procurement and construction (“EPC”) cost was organi zed into the following categories:

• Civil/structural materi al and installation,

• Mechanical equipment supply and installation,

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

• Project indirect costs, fe es and contingency, and

• Owner’s costs (excluding proj ect financing costs). It should be noted that an EPC (t urnkey) or equipment supply/balance of plant, as applicable to a given technology, contracting approach was a ssumed 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 requi red in typical financing market s. This approach does not always result in the lowest cost of constructio n; however, on average, we believe this approach to result in an achievable cost of construction, given the other cons iderations discussed herein. In addition to the base Cost Estimate provided for the given technology, specific regional cost differences were determined. Re gional costs for 64 unique locations in the U.S. were analyzed. Eleven subcategories were used (depending on the speci fic technology under re view) 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 assessin g the cost differences for outdoor installation considerations, air-cooled condensers versus co oling tower issues, seismic design differences, zero-water discharge issues, local enhancements , remote location issues, urban high-density population issues, labor wage and productivity di fferences, 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 prep aration, such as clearing, roads, drainage, underground utilities installation, concre te for foundations, piling material, structural steel supply and installa tion, and buildings.

The mechanical equipment supply and installation includes major equipment , including but not limited to, boilers, scrubbers, cooling tower, stea m turbine (“ST”) generators, PV modules, CTs, as well as auxiliary equipment such as mate rial 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 tr ansformers, 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 Estimat es 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 manageme nt, and start-up and commissioning. The fees and contingency include c ontractor 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 mitig ate its risk in the cons truction of a project.

The owner’s costs include development costs, preliminar y 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 switc hyard 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, owne r’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 di rect operation of the given power plant tec hnology, referred to here as the “Production Relate d Non-Fuel O&M Expenses,” to allow for comparison of O&M costs on the same basis. Production Related Non-Fuel O&M Expens es 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 Ma jor 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 vi rtually identical plants in the same geographic region. For example, the owne r’s expenses include, but are not limited to, property taxes, asset management fees, en ergy 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 administrativ e expenses (postage, telephone, etc.)

• Routine preventive and predictive main tenance performed during operations

• Maintenance of structures and grounds

• Other fees required for a project to participat e in the relevant Nati onal Electric Reliability Council region and be in good standing with the regulatory bodies Routine preventive and predictive maintenan ce expenses do not require an extended plant shutdown and include th e following categories:

• Maintenance of equipment such as water circuits, feed pu mps, main steam piping, and demineralizer systems

• Maintenance of electric plant equipment, wh ich includes service water, DCS, condensate system, air filters, and plant electrical

• Maintenance of miscellaneous plant equi pment such as communication equipment, instrument and service air, and water supply system

• Plant support equipment which consists of to ols, 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 in curred inversely to operati ng hours), demand charges and related utilities

• Chemicals, catalysts and gases

• Ammonia (“NH 3 

### ”) for selective catalytic reducti on (“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 genera tion or the number of plant starts based on the given technology and specific original equipment manufacturer recommendations and requirements. These majo r maintenance expenses include the following expense categories:

• Scheduled major overhaul expenses for main taining the prime mover equipment at a power plant

• Major maintenance labor

• Major maintenance spares parts costs

• BOP major maintenance, which is major main tenance 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 th e fixed or variable O&M rate depending on the cost structure of the particular plant considering such thi ngs as capacity factor, hour and start cycling patterns, O&M contract structure (if applicab le), and major maintenance timing triggers2-10TABLE 2-5 – TECHNOLOGY PERFORMANCE SPECIFICATIONSTechnologyFuelNominalCapacity(kW)(1)NominalHeat Rate(Btu/kWh)(2)CapitalCost($/kW)(3)Fixed O&M($/kW-yr)(4)VariableO&M($/MWh)(5)SO2(lb/MMBtu(6)NOX(lb/MMBtu)CO2(lb/MMBtu)Advanced Pulverized Coal Coal 650,000 8,800 3,246 37.80 4.470.1(7)0.06 206(7)Advanced Pulverized Coal Coal 1,300,000 8,800 2,934 31.18 4.470.1(7)0.06 206(7)Advanced Pulverized Coal withCCS Coal 650,000 12,000 5,227 80.53 9.510.02(10)0.06 20.6(9)Advanced Pulverized Coal withCCS Coal 1,300,000 12,000 4,724 66.43 9.510.02(10)0.06 20.6(9)NGCC Gas 620,000 7,050 917 13.17 3.600.001 0.0075(12)117AG-NGCCGas 400,000 6,430 1,02315.37 3.27 0.001 0.0075(12)117Advanced NGCC with CCSGas 340,000 7,525 2,09531.79 6.78 0.001 0.0075(12)12(9)Conventional CT Gas 85,000 10,850 973 7.34 15.450.001 0.03(11)117Advanced CT Gas 210,000 9,750 676 7.04 10.370.001 0.03(11)117IGCC Coal 600,000 8,700 4,400 62.25 7.220.025(10)0.0075(12)206(7)IGCC Coal 1,200,000 8,700 3,784 51.39 7.220.025(10)0.0075(12)206(7)IGCC with CCS Coal 520,000 10,700 6,599 72.83 8.450.015(10)(8)0.0075(12)20.6(9)Advanced Nuclear Uranium 2,234,000 N/A 5,530 93.28 2.140 0 0Biomass Combined Cycle Biomass20,000 12,350 8,180 356.07 17.490 0.0075(12)195Biomass BFB Biomass 50,00013,500 4,114 105.63 5.260 0.08 195Fuel Cells Gas 10,000 9,500 7,108 0 43.000.00013 0.013 130Geothermal – Dual Flash Geothermal 50,000 N/A 6,243 132.00 00.2(13)0 120(13)Geothermal – Binary Geothermal 50,000 N/A 4,362 100.00 00.2(13)0 120(13)MSW MSW 50,000 18,000 8,312 392.82 8.750.07(14)0.27(15)200Hydroelectric Hydro 500,000 N/A 2,936 14.13 00 0 0Pumped Storage Hydro 250,000 N/A 5,288 18.00 00 0 0Onshore Wind Wind 100,000 N/A 2,213 39.55 00 0 0Offshore Wind Wind 400,000 N/A 6,230 74.00 00 0 0Solar Thermal Solar 100,000 N/A 5,067 67.26 00 0 0Photovoltaic Solar 20,000 N/A 4,183 27.75 00 0 0Photovoltaic – Tracking Solar 150,000 N/A 3,873 24.69 00 0 0Photovoltaic – Tracking with10% storage Solar 150,000 N/A 4,054Photovoltaic – Tracking with20% storage Solar 150,000 N/A 4,236Footnotes 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 th ermal 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., insura nce, property taxes, and asset management fees). (5) VOM expenses include major maintenance. (6) Million Btu (“MMBtu”). (7) Based on high sulfur bituminous fuel. (8) SO 2 emission rates are lower than in the non-capt ure case to avoid reagent contamination. (9) Assuming 90 percent capture. (10) Assuming 3 percent sulfur coal at 12, 000 British thermal units pe r pound (“Btu/lb”) and a 99.5 percent sulfur removal rate

. (11) Assuming 9 parts per million volume dry (“ppmvd”) corrected to 15 percent O 2 ; simple-cycle E-Class or F-Class engine. (12) Assuming 2 ppmvd corrected to 15 percent O 2 for F-Class engine. Assumes deve lopment of SCR for IGCC with CCS. (13) Reported as pounds per MWh and as H 2 S – actual will vary with resource. (14) Based on 30 ppmvd at 7 percent O 2 – 5,000 Btu/lb HHV of MSW – Large Municipal Waste Combustor Rules (15) Based on 150 ppmvd at 7 percent O 2 - 5,000 Btu/lb HHV of MSW- Large Municipal Waste Combustor Rules

### 3-1 3. ADVANCED PULVERIZED COAL (APC)

3.1 MECHANICAL EQUIPM ENT AND SYSTEMS The following describes the Advanced Pulverized Coal Facility, which is a nominal 650 MW coal-fired supercritical steam-el ectric generating unit built in a Gr eenfield location. An analysis is also provided for a nominally 1,300 MW coal-fi red supercritical steam- electric generating unit built in a Greenfield location, which is essent ially 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 el ectric 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 inle t. The superheated steam produced in the boiler is supplied to the ST, which drives an elec tric 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 dir ectly 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 st orage tank via the LP feedwater heaters. The feedwater pumps discharge feedwater from the f eedwater storage tank to the boiler via the HP feedwater heaters. In the boiler, the supercriti cal 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 pr imary 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 th e boiler economizer enters the SCR equipment for NO X 

### 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 (b aghouse) for th e 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 ga s discharges into the stack. Figure 3-1 presents the Advanced Pulv erized Coal process flow diagram.

### 3-2 FIGURE 3-1 – ADVANCED PULVERIZ ED 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 Pu lverized Coal Facility switchyard through a disconnect switch. The GSU increases the voltag e from the electric generator from 24 kV to interconnected transmission system high voltage. The Advanced Pulverized Coal Facility is controlled using a DC S. The DCS provides centralized control of the plant by integrating the control system s provided with the boiler, ST and associated electric ge nerator 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 Adva nced 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 othe r 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, a ssumed 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 Pulver ized Coal Facility (“ APC”) with a nominal capacity of 650 MW is $3,246/kilowatt (“kW”) a nd 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, sca ffolding, 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: outdoor installation considerati ons, seismic design differences, remote location issues, labor wage and productivity differences, location ad justments, owner cost differences, and the increase in overheads asso ciated 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 pr obability of freezing. The locations that were included in outdoor installation are Alabama, Ariz ona, 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote locations related to the APC Facility include Fairbanks, Alaska; Albuquerque, Ne w Mexico; and Cheyenne, Wyoming. Labor wage and productivity diffe rences were handled as discu ssed in Section 1.5.1, taking into consideration the amount of labor we estimated for the APC Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ma ine, Maryland, Massachusetts, Minnesota, New York, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 th e APC capital cost vari ations for alternative U.S. plant locations, including the difference betw een 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 gene rator, 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 me gawatt-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 COMPLI ANCE INFORMATION As mentioned in Section 3.1, the APC Facility is assumed to include low NO X 

### combustion burners in the boiler, SCR, a nd a flue gas desulfurization (“ FGD”) to further control the

### 3-6 emissions of NO X 

### and SO 2 

### , respectively. Table 3-7 presents the environmental emissions for the APC Facility.

TABLE 3-7 – ENVIRONMENTAL EMISSIONS FOR APC
Technology: APC NO X 

### 0.06 lb/MMBtu SO 2 

### 0.1 lb/MMBtu CO 2 

### 206 lb/MMBtu

### 4-1 4. ADVANCED PULVERIZED COAL WITH CCS (APC/CCS)

4.1 MECHANICAL EQUIPM ENT AND SYSTEMS The plant configuration for the APC with CCS F acility (“APC/CCS”) is the same as the APC case with two exceptions: (1) an amine scrubbi ng system, utilizing monoethanolamine (“MEA”) as a solvent, to capture CO 2 

### from the flue gas, and (2) the scali ng of the boiler to a larger size, as described below. The captured CO 2 

### is compressed to approximately 2,000 psia for injection into a pipeline at the plant fence line as a supercritical flui d. 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 a pproximately one-third (i.e., it is approximately 133 percent the size of the boiler in the APC Facility), which pr ovides the necessary steam to facilitate the capture process and to run a steam-driven compressor for compressing the CO 2 

### for sequestration. Figure 4-1 presen ts a diagram of the APC and Fi gure 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 Facil ity are materially similar to the APC Facility, except that the CO 2 

### needs sequestering in one of th e following geologic formations: (1) exhausted gas storage locati on, (2) unminable coal seam, (3) enhanced oil recovery, or (4) saline aquifer. To the extent that a sequest ration site is not near the given facility being analyzed, transportation for a viab le sequestration site has the poten tial to materially affect the capital cost estimates discussed below.

4.4 CAPITAL COST ESTIMATE

The base Cost Estimate for the APC/CCS Faci lity 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 co sts of CCS. Since there are currently no fullscale pulverized coal f acilities operating with CCS in the worl d, 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 CAP ITAL 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, sca ffolding, construction management, and start-up.



### TABLE 4-2 – BASE PLANT SITE CAP ITAL 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: outdoor installation considerati ons, seismic design differences, remote location issues, labor wage and productivity differences, location ad justments, owner cost differences, and the increase in overheads associat ed 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 th e APC capital cost vari ations for alternative U.S. plant locations, including the difference betw een 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 adde rs 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 presen t 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 COMPLI ANCE INFORMATION In addition to the equipment utilized for envi ronmental compliance in the APC Facility, the APC/CCS Facility includes an amine scrubber th at is intended to remove 90 percent of the CO 2 

### produced in the combustion process, wherein the captured CO 2 

### is later compressed to HP and sequestered, as discussed above . Table 4-7 presents the e nvironmental emissions for the APC/CCS Facility.

TABLE 4- 7 – ENVIRONMENTA L EMISSIONS FOR APC/CCS Technology: APC/CCS NO X 

### 0.06 lb/MMBtu SO 2 

### 0.02 lb/MMBtu CO 2 

### 20.6 lb/MMBtu

### 5-1 5. CONVENTIONAL NATURAL GAS COMBINED CYCLE (NGCC)

5.1 MECHANICAL EQUIPM ENT AND SYSTEMS The Conventional NGCC produces 620 MW of net elec tricity. 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 desi gned to produce nominally 205 MW and includes a dry-low NO X 

### (“DLN”) combustion system and a hydrogen- cooled electric generator. The two triple-pressure HRSGs include integrated deaerato rs, SCRs, oxidation catalyst for the control of carbon monoxide (“CO”), and supplemental duc t firing with associated combustion management. The ST is a single -reheat condensing ST designed for variable pressure operation, designed to produce an additiona l 210 MW. The ST exhaust is cooled in a closed-loop condenser system with a mechanical draft coo ling 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 whic h the CTs, ST, and HRSGs are enclosed to avoid freezing during periods of cold ambient temperat ures. Figure 5-1 pres ents 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 genera tors 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 gene rator is connected to a high-voltage bus in the Conventional NGCC via a dedicated generator circ uit 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 controll ed using a DCS. The DCS pr ovides centralized control of the facility by integrating the co ntrol systems provided with each individual CT and associated electric generator, ST and associated electric generator, and the cont rol 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 NG CC 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 wate r for HRSG makeup.

### 5-3 Wastewater is sent to a munici pal 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 Conventiona l NGCC Facility with a nominal capacity of 620 MW is $917/kW. Table 5-1 summarizes the Co st 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: outdoor insta llation considerations, air-cooled condensers compared to cooling towers, seismic design differences, zero-water discharge issues, local

### 5-4 technical enhancements (e.g., additional noise reme diation that is genera lly 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 pr obability of freezing. The locations that were included in outdoor installation are Alabama, Arizona, Arkansas , Florida, Georgia, Hawaii, Louisiana, Mississippi, New Mexico, S outh 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 Hampsh ire, 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 zone s 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, Di strict of Columbia, Maryland, Massachusetts, New Hampshire, New York, Ore gon, Pennsylvania, Rhode Island, Virginia, and Puerto Rico. Similar to water usage discussed above in th is section on Conventional NGCC, wastewater treatment and disposal is considered a cr itical permitting/siting issue in these areas.

The locations with loca l 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 de veloper or utility to comply with the applicable permitting/siting requirements. Remote location issues are related to geographic ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote loca tions related to the Conventional NGCC include Fairbanks, Alaska; Honolulu, Ha waii; Albuquerque, New Mexico ; Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity differences were ha ndled 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 wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Yo rk, Ohio, and Wisconsin.

### 5-5 Owner costs were reviewed based on the need fo r 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 C onventional 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 disc ussed in Section 2.5.2., the Conventional NGCC Facility includes the major maintenance for th e 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, signifi cant overhauls on a Conventional NGCC Facility occur no less fre quently than 16,000 operating hour in tervals. 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 COMPLI ANCE 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 burn ers in the HRSGs to manage the production of NO X 

### and CO. Additional control of NO X 

### and CO is accomplished through an SCR and an oxidization catalyst, respec tively. Oxides of sulf ur in the Conventional NGCC are managed through the natural gas fuel quali ty, which is generally very low in sulfur U.S. domestic pipeline quality natural gas, and consequently the low sulfur content translates into SO 2 

### after combustion. The Conve ntional NGCC does not includ e any control devices for CO 2 

### , which is proportional the heat rate (inversely proportiona l to the efficiency) of the technology. Water, wastewater, and solid wast e 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 EMI SSIONS FOR CONVENTIONAL NGCC
Technology: Conventional NGCC NO X 

### 0.0075 lb/MMBtu SO 2 

### 0.001 lb/MMBtu CO 2 

### 117 lb/MMBtu

### 6-1 6. ADVANCED GENERATION NATURAL GAS COMBINED CYCLE (AG-NGCC)

6.1 MECHANICAL EQUIPM ENT 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 st eam 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 advant ages compared to th e Conventional NGCC. The advantages of the AG-NGCC are for the sa me size of equipment – more megawatt output due to higher firing temperature. The higher fi ring 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 ramp ing 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 ar e similar to the Conventional NGCC Facility, except that the sizing of the generators and transf ormers 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 Facil ity are the same as the Conventional NGCC. Refer to Section 5.3 for the description of the Conventional NGCC of f-site requirements.

### 6-2 6.4 CAPITAL COST ESTIMATE

The base Cost Estimate for the AG-NGCC Faci lity 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 CAPIT AL 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, sca ffolding, 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 F acility capital cost variations for alternative U.S. plant locations, including the difference betw een 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 th e 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 EXPENS ES FOR AG-NGCC
Technology: AG-NGCC Fixed O&M Expense $15.37/kW-year Variable O&M Expense $3.27/MWh

6.6 ENVIRONMENTAL COMPLI ANCE INFORMATION The environmental compliance strategy and equipment for the AG-NGCC Facility is the same as those described in Section 5.6 for the Conve ntional NGCC Facility. Table 6-4 presents environmental emissions for the AG-NGCC Facility.

TABLE 6-4 – ENVIRONMENTAL EMISSIONS FOR AG-NGCC
Technology: AG-NGCC NO X 

### 0.0075 lb/MMBtu SO 2 

### 0.001 lb/MMBtu CO 2 

### 117 lb/MMBtu

### 7-1 7. ADVANCED GENERATION NATURAL GA S COMBINED CYCLE WITH CCS (AG-NGCC/CCS)

7.1 MECHANICAL EQUIPM ENT AND SYSTEMS The plant configuration for the AG-NGCC/CCS F acility is the same as the AG-NGCC Facility with the exception that an amine system based on MEA as the solvent is included for CO 2 

### capture from the flue gas. The captured CO 2 

### is compressed to approximately 2,000 psia for injection into a pipeline at the plant fence lin e. 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 CO 2 

### needs sequestering in one of the following geologic formations: (1) exhausted gas storage locati on, (2) unminable coal seam, (3) enhanced oil recovery, or (4) saline aquifer. To the extent that a sequestration site is not near th e given facility being analyzed, transportation for a viable sequestra tion 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 F acility with a nominal capacity of 340 MW is $2,095/kW. The capital cost estimate was base d on the AG-NGCC (without CCS) and the base cost estimate was increased to include the exp ected 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 CAPIT AL 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, sca ffolding, construction management, and start-up.



### The locational adjustments for the AG-NGCC/CCS F acility are similar to those made for the Conventional NGCC Facility, de scribed 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, exce pt that adders are include d 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 COMPLI ANCE INFORMATION The environmental compliance strategy and equi pment for the AG-NGCC Facility are the same as those described in Section 5.6 for the Conve ntional NGCC Facility, with the exception that the AG-NGCC with CCS Facility includes an amine scrubber control device for CO 2 

### . 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 NO X 

### 0.0075 lb/MMBtu SO 2 

### 0.001 lb/MMBtu CO 2 

### 12 lb/MMBtu

### 8-1 8. CONVENTIONAL COMBUSTION TURBINE (CT)

8.1 MECHANICAL EQUIPM ENT AND SYSTEMS The Conventional CT Facility produces 85 MW of electricity using a si ngle 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 temperatur e of the turbine inlet air to increase summer output. Figure 8-1 presents the Conventi onal 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-v oltage bus in the Conventional CT F acility switchyard via a dedicated generator circuit breaker, GSU, and a disconnec t switch. The GSU incr eases the voltage from the electric generator from 13.8 kV to interconnected transm ission system high voltage. The Conventional CT Facility is controlled using a DCS. The DCS provides centralized control of the facility by integrating the control system s 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 utili ze water at the Conventional CT Facility is obtained from a one of several availa ble water sources (e.g., m unicipal water supply). The Conventional CT Facility uses a water tr eatment system and a high-efficiency reverse osmosis system to reduce the dissolved solids for compressor cleaning. Wast ewater is sent to a municipal wastewater system. Further, the elect rical interconnection from the Conventional CT on-site switchyard is effectuated by a conn ection to an adjacent utility substation.

### 8-2 8.4 CAPITAL COST ESTIMATE

The base Cost Estimate for the Conventional CT F acility with a nominal capacity of 85 MW is $973/kW. Table 8-1 summarizes the Cost Estimate categories for the Conven tional 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: outdoor installation considerati ons, 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 prev ious 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 zone s 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 loca l 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 ma de by a project developer or utility to comply with the applicable permitt ing/siting requirements. Remote location issues are related to geographic ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote loca tions related to the C onventional CT Facility include Fairbanks, Alaska; Honolulu, Hawaii; Al buquerque, New Mexico; Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed 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 wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Yo rk, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 presen ts 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. Typical ly, significant overhauls on a Conve ntional CT Facility occur no less frequently than 16,000 operating hour interval s; with more significant major maintenance outages occurring at 32,000 operating hour inte rvals; however, often times the major maintenance for a CT at a peaking facility is dr iven off of CT starts (depending on the equipment manufacturer and the operating hours per start incurred on the equi pment). 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 COMPLI ANCE INFORMATION Typically, a Conventional CT Facility woul d 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 temper atures of a simple-cycle plant, though that equipment was not contemplated herein.

TABLE 8-4 – ENVIRONMENTAL EMISSIONS FOR CONVENTIONAL CT
Technology: Conventional CT NO X 

### 0.03 lb/MMBtu SO 2 

### 0.001 lb/MMBtu CO 2 

### 117 lb/MMBtu

### 9-1 9. ADVANCED COMBUSTION TURBINE (ACT)

9.1 MECHANICAL EQUIPM ENT AND SYSTEMS The Advanced CT Facility produces 210 MW of el ectricity using a single natural gas-fueled, state of the art (as of 2012) F-cl ass CT and associated electric generator. The CT is equipped with an inlet evaporative cooler to reduce the temperature of th e 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 gene ral electrical and control systems as the Conventional CT Facility, except that the electri c 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 F acility with a nominal capacity of 210 MW is $676/kW. Table 9-1 summarizes the Cost Estimate categories for the Advan ced CT Facility.

### 9-2 TABLE 9-1 – BASE PLANT SITE CAPIT AL 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, sca ffolding, construction management, and start-up.



### The locational considerations for th e Advanced CT Facility are the same as those set forth in the section on the Conventio nal CT Facility. Table 9-2 in the Appendix presents the Advan ced 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 pres ents the O&M expenses for the Advanced CT Facility.

### 9-3 TABLE 9-3 – O&M EXPENS ES FOR ADVANCED CT
Technology: Advanced CT Fixed O&M Expense $7.04/kW-year Variable O&M Expense $10.37/MWh

9.6 ENVIRONMENTAL COMPLI ANCE INFORMATION The environmental compliance strategy and equipm ent for the Advanced CT Facility are the same as those used for the Conventional CT Faci lity (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 NO X 

### 0.03 lb/MMBtu SO 2 

### 0.001 lb/MMBtu CO 2 

### 117 lb/MMBtu

### 10-1 10. INTEGRATED GASIFICATION CO MBINED CYCLE (IGCC)

10.1 MECHANICAL EQUIPM ENT AND SYSTEMS The following describes the IGCC Facility, wh ich 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 fi nes to form the slurry. A fluxing agent is also added, if necessary, depending on the properties of the feedstock, to facilitate slagging at appropriate temperatur es in the gasifier. Air separation units (“ASU”) provi de a 95 percent-pure oxygen (“O 2 

### ”) stream for gasification, and nitrogen for use as a diluent in th e 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 convert s the slurry feed into syngas consisting of hydrogen, CO, CO 2 

### , methane, nitrogen, argon and water along with sulfur compounds in the form of hydrogen sulfide (“H 2 

### S”) and carbonyl sulfide (“COS”) and a small amount of NH 3


### . The first stage is the slagging section in whic h the feedstock is partially combusted with O 2 

### at elevated temperature and pressure (2,500 degrees oF and 540 psia). O 2 

### 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 ad vantage of the sensible heat in the gas. This fuel undergoes devolatization and pyrolysis ge nerating additional syngas. Th e endothermic nature of the reactions and the introd uction of a quench fluid reduce the te mperature of the gas exiting to the gasifier to approximately 1,900o F. 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 ga s shift (steam and CO) to produce hydrogen and CO 2 

### . In addition, the lower reaction temperature in the second stage allows the form ation 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 fluxi ng agent form a molten slag that flows out of the horizontal section into water quench bath. Th e cooled slag exits the bottom of the quench, is crushed and exits the unit through a conti nuous 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 generate s 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 particle s collect on the filter elements producing an essentially particulate matter free synga s 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 hydr olysis units, which convert the COS in the syngas to H 2 

### S. The syngas is then cooled to ap proximately 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 NH 3 

### and a small portion of CO 2 

### and H 2 

### S are absorbed in the water. A portion of th e condensed water is us ed in the chlorine scrubber with the remainder sent to sour water treatment. Th e low temperature heat removed prior to acid gas removal (“AGR”) is used within the process. After low-temperature heat recovery, the H 2 

### S is then removed in the AGR units. The AGR units use the Selexol solvent in a single absorption st age to remove much of the sulfur from the syngas. The syngas passes through a mercury removal system cons isting of sulfated activated carbon beds. Finally, the treated syngas is mo isturized and sent to the power block. The acid gas streams containing H 2 

### S and COS with some CO 2 

### 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 CO 2 

### , nitrogen, and small amounts of sulfur, is catal ytically hydrogenated to convert all of the sulfur to H 2 

### S. This converted tail gas is compre ssed and recycled to the gasifiers.

Process water blowdown and water condensed duri ng cooling of the sour syngas contains small amounts of dissolved gases (H 2 

### S, CO 2 

### and NH 3 

### ). 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 combin ed 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 a nd one ST electric genera tor. The generators for the CTs are 60 Hz machines rated at approximately 255 MVA with an output voltage of 18 kV. The ST electric genera tor 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 gene rator circuit breaker, GSU, and a disconnect switch. The ST electric generato r 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 cent ralized control of the facility by integrating the cont rol systems provided with each individual CT and associated electric generator, ST and associated electric generator, and the cont rol of BOP systems and equipment.

10.3 OFF-SITE REQUIREMENTS Coal is delivered to the IGCC Facility by rail, tr uck or barge. Water for all processes at the IGCC is obtained from one of several availa ble 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. Wastew ater is sent to an ad jacent river or other

### 10-4 approved wastewater delivery point. Further, the electrical interconnection from the IGCC onsite switchyard is effectuated by a connec tion 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 an d 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, sca ffolding, 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: outdoor installation considerati ons, seismic design differences, remote location issues, labor wage and productivity differences, location ad justments, 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 lo w probability of freezing. The locations that included outdoor installation are Alabama, Ariz ona, 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 zone s 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 rela ted to geographic areas that typi cally require installation of man camps, higher craft incentives, and higher per diems for construc tion, because such areas are long distances from urban ar eas, where labor is generally abundant. Remote location designations were also considered in locations where higher equi pment 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 diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the IGCC Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ma ine, Maryland, Massachusetts, Minnesota, New York, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 presen t 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 discu ssed 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 gasi fication systems, the ASU, and associated gasification auxiliary equipment needs to be ma de. For example, major maintenance for the gasifier includes repair and repl acement of the refractory. Typi cally, 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 Conven tional NGCC discussed a bove. 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 COMPLI ANCE INFORMATION The IGCC uses syngas combustors (which do not ha ve DLN) in the CT and best available burner technology with respect to the duct burners in the HRSG s to manage the production of NO X 

### and CO. Additional control of NO X 

### and CO is accomplished thr ough an SCR and an oxidization catalyst, respectively. SO 2 

### in the IGCC is manage d through the removal of sulfur in the syngas via the AGR system prior to combustion. The IGCC does not include any control devices for CO 2 

### , which is proportional to the heat rate (inversely proportiona l 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 ar e 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 NO X 

### 0.0075 lb/MMBtu SO 2 

### 0.025 lb/MMBtu CO 2 

### 206 lb/MMBtu

### 11-1 11. INTEGRATED GASIFICATION COMBINED CYCLE WITH CCS (IGCC/CCS)

11.1 MECHANICAL EQUIPM ENT 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 CO 2 

### from the syngas prior to combustion. The captured CO 2 

### 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 materia lly similar to the IGCC Facility (without CCS) discu ssed in Section 10.2.

11.3 OFF-SITE REQUIREMENTS The off-site requirements for the IGCC/CCS Facil ity are materially similar to the IGCC Facility (without CCS) discussed in Section 10.3, except that an interconnection need s to be made with respect to the se questration of CO 2


### .

11.4 CAPITAL COST ESTIMATE

The base Cost Estimate for the IGCC/CCS Faci lity with a nominal capacity of 520 MW is $6,599/kW. Table 11-1 summarizes th e Cost Estimate categories fo r the IGCC/CCS Facility.

### 11-2 TABLE 11-1 – BASE PLANT SITE CAP ITAL 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, sca ffolding, 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 th e 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 mainte nance, sequestration maintenance, and the associated additional labor required to manage, operate, and maintain the additional equipment Table 11-3 presents the O&M expens es 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 COMPLI ANCE INFORMATION The environmental compliance strategy for the IGCC/CC S 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 CO 2 

### . Table 11-4 presents environmental emissions for the IGCC/CCS Facility.

### 11-3 TABLE 11-4 – ENVIRONMENTAL EMISSIONS FOR IGCC/CCS
Technology: IGCC/CCS NO X 

### 0.0075 lb/MMBtu SO 2 

### 0.015 lb/MMBtu CO 2 

### 20.6 lb/MMBtu

### 12-1 12. ADVANCED NUCLEAR (AN)

12.1 MECHANICAL EQUIPM ENT AND SYSTEMS The Advanced Nuclear (“AN”) Facility c onsists of two 1,117 MW Westinghouse AP1000 nuclear power units built at a brownfie ld (existing nuclear facility) site. The steam cycle of a nuclear powered electric generation faci lity 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, hydrocarbon s are burned to heat water, producing steam. In the AP1000, splitting the nucleus (fission) of uran ium atoms provides the energy to heat the
water. Nuclear fuel is a uranium dioxide ceramic pelle t typically encased in a zircalloy tube. The uranium atoms in the pellet absorb neutrons causi ng 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 re leased. The resulting nuclei contai n a great deal of kinetic energy which ultimately adds heat to the primary cool ant. The neutrons ca n 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 neutr on being used in a subsequent thermal fission. The number of neutrons available is controlled by the temperatur e (and hence the density) of the water in the nuclear reactor core, the arrangement of neutron absorbing cont rol rods inserted into the core, the design of the core, and by contro lling the void fraction and temperature of the coolant water (which both affect the density of wa ter which affects the neutrons available for the fission process). This concept is commonly re ferred to as “moderation”. Moderation is the slowing down or lowering the energy of a fast ne utron 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 pressu rized 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 exch anger (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 th e PWR is circulated th rough the nuclear core by reactor coolant pumps. This cooling water sy stem 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 c oolant pumps, and a single hot leg and two cold legs for circulating coolant between the reacto r 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 safeguard s. 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 st eam from the steam generator is r outed to the HP section of the ST. The ST consists of a double-flow HP ST se ction 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 a nd reheater dries and reheats the steam before it enters the LP ST section, which improves the cy cle 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 heat s the condensate and feedwater befo re 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 circ ulated through the insi de of the tubes. The passive core cooling system provides prot ection 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 reacto r coolant system pressure by promoting the natural circulation of air supplemented by water ev aporation to transfer heat through the steel containment vessel and away from critical core components that .m ay be subject to decay heat. The advantage of a passive core system is th at less safety related equipment (e.g. pumping systems) are required to remove the decay heat. Numerous other systems are needed to suppo rt 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 redunda nt systems and are desi gned to remove heat from the reactor core in the event the normal co re 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 simplif ied 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 ge nerator circuit breaker to a GS U 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 voltag e 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 obta ined from one of severa l available water supply options; however, water is typically sourced fr om 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 adja cent river or other approved wastewater delivery point. Further, the electrical in terconnection from the AN on-site switchyard is effectuated by a connection to an adjace nt utility substation.

### 12-4 12.4 CAPITAL COST ESTIMATE The base Cost Estimate for the AN Facility w ith 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design diffe rences, 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote loca tions related to the Advanced Nuclear Facility include Fairbanks, Alaska; Albuquerque, New Mexico; and Cheyenne, Wyoming. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the AN Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ma ine, Maryland, Massachusetts, Minnesota, New York, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 (be yond 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 COMPLI ANCE INFORMATION Environmental compliance with respect to air em issions 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 consider ed in this report. Table 12-4 presents environmental emissions for the AN Facility.

TABLE 12-4 – ENVIRONMENTAL EMISSIONS FOR AN
Technology: AN NO X 

### 0 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 0 lb/MMBtu

### 13-1 13. BIOMASS COMBINED CYCLE (BCC)

13.1 MECHANICAL EQUIPM ENT 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 flui d bed (“CFB”) units (one gasifier and one combustor) connected by a sand circulation syst em. Related equipment includes the wood feed system, the product gas quench, ash handling, st eam supply and typical BOP equipment. The wood is fed to the circulating fluid bed gasi fier through a standard system of lock hoppers, live bottom bins and feed screws. The lock hoppers are purged with ni trogen to keep the produced fuel gas from escaping. The gasifier is a refractory-lined vessel with a sand-type carrier and requir es 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 conditi ons. 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 (appr oximately 450 Btu/scf dry) and non-converted char. A small amount of condensab le “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 com bustor goes to a boile r to recover the excess sensible energy. The two CFBs are connected by the sand circulati on 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 tr ansfer system consists of mechanical cyclones (two in series for each CFB) and a sand invent ory pot for each leg of the configuration. An overflow system, with some fluidizing steam in th e 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, NH 3 

### and residual tars. The excess scrubber water is sent off-site to a wast ewater treatment facility. The syngas is then compressed to the required pr essure 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 NO X 

### emissions. Both the steam generated in the HRSG and the steam gene rated 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 se parate steam system is required for start-up. NH 3 

### is required for operation of the two SCRs for reducing NO X 

### 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 pr ocess. 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 elect ric generator and one ST electric generator. The generator for the CT is a 60 Hz machine rated at approximate ly 17 MVA with an output voltage of 13.8 kV. The ST electric generator is a 60 Hz machine ra ted at approximately 10 MVA with an output voltage of 13.8 kV. The genera tor breakers for the CT and ST electric generators are bussed together in 15 kV class switchgear that is connect ed to a high-voltage tr ansmission system at the facility switchyard via a circui t breaker, GSU, and a disconnect switch. The GSU increases the voltage from the electric gene rators from 13.8 kV to interc onnected transmission system high voltage. The BCC Facility is controlled using a DCS. The DCS provides centra lized control of the facility by integrating the cont rol systems provided with each individual CT and associated

### 13-3 electric generator, ST and associated electric generator, and the cont rol of BOP systems and equipment.

13.3 OFF-SITE REQUIREMENTS Biomass is delivered to the BCC Facility by rail, tr uck or barge. Water for all processes at the BCC Facility is obtained from one of several av ailable water sources. The BCC Facility uses a water treatment system and a high-efficiency re verse osmosis system to reduce the dissolved solids from the cooling water and to provide di stilled water for HRSG makeup. Wastewater is sent to a municipal wastewater sy stem or other available wastewat er delivery point. Further, the electrical interconnection from the BCC Facility on-site switchyard is effectuated by a connection to an adjace nt utility substation.

13.4 CAPITAL COST ESTIMATE The base Cost Estimate for the BCC Facility w ith a nominal capacity of 20 MW is $8,180/kW. Table 13-1 summarizes the Cost Estima te 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: outdoor installation considerati ons, seismic design differences, remote location issues, labor wage and productivity differences, location ad justments, 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 lo w probability of freezing. The locations that included outdoor installation are Alabama, Arka nsas, 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway acce ss. Remote locations relate d to the BCC include Fairbanks, Alaska; Honolulu, Hawaii; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the BCC Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Minnesota, New York, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 va riations 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 th e 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. T ypically, significant overhauls on a BCC Facility occur no less frequently than 8,000 operating hour in tervals, with more si gnificant major outages occurring on 24,000 hour intervals. Additionally, major maintenance needs to be completed on the gasifier, including the refract ory, which due to the lower ope rating temperature (as compared to the IGCC Facility discusse d above) only needs replacing a pproximately 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 COMPLI ANCE INFORMATION The BCC Facility utilizes syngas combustors (w hich 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 NO X 

### and CO. Additi onal control of NO X 

### and CO is accomplished through an SCR and an oxidization catalyst, respectively. SO 2 

### in the IGCC is managed through the use of lowsulfur biomass feedstocks. The BCC doe s not include any control devices for CO 2 

### , which is proportional to the heat rate (inv ersely proportional to the effici ency) of the technology. Water, wastewater, and solid waste comp liance are achieved through trad itional on-site and off-site methods, and the costs for such compliance ar e 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 NO X 

### 0.0075 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 195 lb/MMBtu

### 14-1 14. BIOMASS BUBBLING FL UIDIZED BED (BBFB)

14.1 MECHANICAL EQUIPM ENT AND SYSTEMS The Biomass BFB (“BBFB”) Facility utilizes approximately 2,000 tons per day of wood (at 50 percent maximum moisture) for the producti on 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 cycl e efficiency. The water will enter the first feedwater heater where it will be heated using extr action 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 appr oximately 1,800 psia. After leaving the boiler feed pump, the water will flow through two more feedwa ter heaters. After exiting the last feedwater heater, the water will flow to the economizer section of the BFB boile r 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 circulatin g water that is used to condense the steam inside the condenser. In a BFB boiler, a portio n of air is introduced th rough 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 uni formly. The fuel and limestone are fed into the lower bed. In the presence of fluidizing air, the fuel a nd limestone quickly and uniformly mix under the turbulent environment and behave like a fluid. Ca rbon 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 NO X 

### . The advantages of BFB boiler technology include fuel flexibility, low SO 2 

### emissions, low NO X 

### 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 elect ric 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 provide s centralized control of the facility by integrating the contro l systems provided with the ST a nd 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 av ailable 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 di stilled water for HRSG makeup. Wastewater is sent to a municipal wastewater sy stem or other available wastewat er delivery point. Further, the electrical interconnection from the BBFB Facility on-site switchyard is effectuated by a connection to an adjace nt 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: outdoor installation considerati ons, seismic design differences, remote location issues, labor wage and productivity differences, location ad justments, 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 lo w probability of freezing. The locations that included outdoor installation are Alabama, Arka nsas, 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway acce ss. Remote locations relate d to the BCC include Fairbanks, Alaska; Honolulu, Hawaii; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the BCC Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Minnesota, New York, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 Fac ility 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 th e ST and associated electric generator, as well as the BOP. These major maintenance ex penses 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 le ss 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 COMPLI ANCE INFORMATION The BBFB Facility utilizes BFB combustion to control NO X 

### and CO. SO 2 

### in the BFB is managed through the use of low-sulfur biomass f eedstocks. The BBFB Faci lity does not include any control devices for CO 2 

### , 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. Tabl e 14-4 presents enviro nmental emissions for the BBFB Facility.

TABLE 14-4 – ENVIRONMENTAL EMISSIONS FOR BBFB
Technology: BBFB NO X 

### 0.08 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 195 lb/MMBtu

### 15-1 15. FUEL CELL (FC) MECHANICA L EQUIPMENT AND SYSTEMS The Fuel Cell (“FC”) Facility uti lizes multiple phosphoric acid fuel cell units, each with a power output of 400 kW, for a total output of 10 MW. The fuel cells c onvert chemical energy directly into electricity from natural gas and air vapor and produce heat and water vapor as byproducts. The fuel (the reactant) is introdu ced continuously to the anode side of the unit cell while air (the oxidant) is introduced con tinuously into the cathode side via a bl ower. 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, passi ng ions through the el ectrolyte (e.g. in the case of the FC Facility, a phosphoric acid ion) and then react ing the ions with the fuel at the anode to produce heat to allow the reaction to occur. Duri ng 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 pr oduce a higher, more useful voltage. Depending on the type of fuel cell, high temperature wast e heat from the process may be available for cogeneration applications. Figure 15-1 pres ents the fuel cell process flow diagram.

FIGURE 15-1 – FC DESIGN CONFIGURATION

15.1 ELECTRICAL AND CONTROL SYSTEMS Each fuel cell stack generate s DC electric power. These st acks 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 co ntrol and protection when designed to IEEE Standards. The fuel cell units are connected through circuit br eakers to a switchgear bus that combines the output of the fuel cell units fo r a total output of 10 MW . The switchgear is connected through a circuit breaker to the local util ity distribution system.

Each individual fuel cell module has its own aut onomous 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 th rough a lateral or in an urban environment, potentially through the local distribution company in frastructure. Water for all processes at the FC Facility is obtained from one of several av ailable water sources, but given that the water

### 15-2 needs are low, a municipal (potable) water source w ould be preferable. Wastewater is sent to a municipal wastewater system. Furt her, the electrical interconnecti on 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 Estima te 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design diffe rences, 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote locations related to the FC Facility include Fairbanks, Alaska; Honolulu, Ha waii; Albuquerque, New Mexico ; Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the FC Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Yo rk, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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, th e specific O&M related to the FC Facility that differs from other facilities discu ssed in this report is the stack replacement, currently anticipated to be every five years by the va rious 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 COMPLI ANCE INFORMATION Table 15-4 presents environmental emissions for the FC Facility. It should be noted that the CO 2 

### production from the FC Facility occurs as a resu lt of reforming natural gas to the feedstock for the fuel cell module.

### 15-4 TABLE 15-4 – ENVIRONMENTAL EMISSIONS FOR FC
Technology: FC NO X 

### <0.013 lb/MMBtu SO 2 

### <0.00013 lb/MMBtu CO 2 

### <130 lb/MMBtu

### 16-1 16. GEOTHERMAL DUAL FLASH (GT)

16.1 MECHANICAL EQUIPM ENT 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 gene rate 55 gross MW based on a high-temperature, high-salinity brine. Th e 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 deliver ed 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 pressu re 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 ca rried out with the brine leaving the crystallizer. The separated brine from the crystallizer is sent through an atmosphe ric flash tank to reduce pressure, and then further processed via a prim ary and secondary clarifier system where the solids produced are formed into a solid cake after being passed through a filte r press, treated with acid and neutralizing washes, and steam and hot-a ir dried to produce a si lica 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 pr oportion of the entraine d 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 co ndensed in a two-pass sh ell 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-condens able gas removal system and vent products delivered to an H 2 

### S abatement system. Cooling water for the ST condenser is supplied by an induced-draft cooling tower. Ci rculating 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 n eeded during the summer months. Figure 16-1 presents a simplified process flow diagra m 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 el ectric generator is connected to a high-voltage bus in the facility switchyard via a dedicated generator circuit breaker, GSU, high-voltage circ uit breaker and a disconnect sw itch. 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 c ontrol of the facility by integrating the control systems provided with th e 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 heati ng, 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, t hough many GT facilities util ize ZLD. Further, the electrical interconnection from the GT Facility is accomplished by interconnecting via the plant switchyard into the utility hi gh-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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design differences, local tec hnical enhancements (e.g., additional noise remediation that is genera lly required in urban siting), remote location issues, labor wage and producti vity differences, location adju stments, 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, Califor nia, Colorado, Hawaii, Idaho, Nevada, New Mexico, Oregon, Ut ah, 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote locati ons related to the Geothermal Facility include Fairbanks, Alaska; Honolulu, Hawaii; Albuquer que, New Mexico; and Cheyenne, Wyoming. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the GT Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es to higher construction costs for power and other infrastructure projects. These locati ons include Alaska, Ca lifornia, and Hawaii. Table 16-2 in the Appendix presents the GT Facili ty 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 F acility. In general, most GT facility operators do not treat O&M on a variable ba sis, 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 COMPLI ANCE INFORMATION Table 16-4 presents environmental emissions for the GT Facility.

TABLE 16-4 – ENVIRONMENTAL EMISSIONS FOR GT
Technology: GT NO X 

### 0 per MWh SO 2 

### 0.2 per MWh CO 2 

### 120 per MWh

### 17-1 17. GEOTHERMAL BINARY (BINARY)

17.1 MECHANICAL EQUIPM ENT AND SYSTEMS The Geothermal Binary (“Binary”) Facility pr oduces 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 lo oped organic supercritical Rankine cycle using geothermal brine as a heat s ource, with a brine temperature of approximately 275°F. The geothermal brine heats the superheated organic wo rking 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 th rough 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 ve rtical 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 Bina ry Facility. Each turbine generator is to be an air cooled unit with static excitation designed for operation at 60 Hz, th ree-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 sw itchgear main circuit breaker and underground cable to a switch on a common open air bus in the Bi nary Facility substation.

### 17-2 17.3 OFF-SITE REQUIREMENTS Since the Binary Facility is fueled by a renewa ble, underground fuel source, an off-site fuel source, other than incide ntal plant heating is not required. Water for all processes at the Binary Facility is obtained from one of several ava ilable water sources; howev er, due to the geography of most geothermal power plants, water is source d 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 inte rconnection from the Binary F acility 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, sca ffolding, construction management, and start-up.

### 17-3 For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design differences, local tec hnical enhancements (e.g., additional noise remediation that is genera lly required in urban siting), remote location issues, labor wage and producti vity differences, location adju stments, 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, Califor nia, Colorado, Hawaii, Idaho, Nevada, New Mexico, Oregon, Ut ah, Washington, and Wyoming. Seismic design differences among the various locations were based on U.S. seismic map information that detailed the various seismic zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote locati ons related to the Geothermal Facility include Fairbanks, Alaska; Honolulu, Hawaii; Albuquer que, New Mexico; and Cheyenne, Wyoming. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the GT Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es to higher construction costs for power and other infrastructure projects. These locati ons include Alaska, Ca lifornia, and Hawaii. Table 17-2 in the Appendix presents the GT Facili ty 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 maintenan ce 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 ar e shown below on a fixed basis.

TABLE 17-3 – O&M EXPE NSES FOR BINARY
Technology: GT Fixed O&M Expense $100.00/kW-year Variable O&M Expense $0/MWh

### 17-4 17.6 ENVIRONMENTAL COMPLI ANCE INFORMATION Table 17-4 presents environmental em issions for the Binary Facility.

TABLE 17-4 – ENVIRONMENTA L EMISSIONS FOR BINARY
Technology: Binary NO X 

### 0 per MWh SO 2 

### 0.2 per MWh CO 2 

### 120 per MWh

### 18-1 18. MUNICIPAL SOLID WASTE (MSW)

18.1 MECHANICAL EQUIPM ENT 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 grat es specifically designed for co mbusting waste having an HHV between 4,000 and 6,500 Btu/lb. The three boilers together pr oduce 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 asse mblies of modular grate units. The units are driven by hydraulic systems to provide a reverse reci procating 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 re sidue discharger, which receives the combustion residue and cools it in a quench ch amber. The fly ash from the dr y 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 re sidue drains back into the quench bath. The residue, containing sufficient moisture to prev ent dusting, is transferred by a conveyor to a residue storage pit. Clamshell grapple cranes transport the residue to a scalper screen. The scalper screen extr acts pieces of the residue larger than a certain size in or der to protect the downstream equipment. The smaller material which passes through the s calper screen is fed onto a conveyer belt which discha rges 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 distri bution to a transport vehi cle. 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 scru bber in combination with a reverse air fabric filter baghouse. The dry scrubbers remove the acid gases (mainly SO 2 

### , hydrochloric acid and hydrofluoric acid) from the flue gas. A hydrated lime injection sy stem prior to the dry scrubber augments the AGR capability of the system. The reverse air baghouse re duces dioxin/furan and particulate emissions. The facility also uses selective non-catalytic reduction (“SNCR”) for NO X 

### control, and activated carbon in jection for merc ury 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 eva porative-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 diagra m 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 el ectric generator is connected to a high-voltage bus in the facility switchyard via a dedicated generator circuit breaker, GSU, high-voltage circ uit breaker and a disconnect sw itch. 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 provide s centralized control of the facility by integrating the contro l 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 ba rge. 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 MS W Facility uses a water treatmen t 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 munici pal wastewater system or other approved alternative. Further, the electrica l interconnection from the MSW Facility on-site switchyard is effectuated by a connecti on 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 ha ve 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: se ismic design differences, local enhancements, remote location issues, labor wage and producti vity differences, location adju stments, 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, 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, Ha waii; Albuquerque, New Mexico ; Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the MSW Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Yo rk, Ohio, and Wisconsin. Table 18-2 in the Appendix presents the MSW Facil ity 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 th e 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 COMPLI ANCE INFORMATION

As mentioned above in the section on mechanical systems, each boiler is equipped with a dry flue gas scrubber in combinati on with a reverse air fabric f ilter baghouse. A hydrated lime injection system prior to the dry scrubber augm ents the AGR capability of the system. The reverse air baghouse reduces dioxin/furan and pa rticulate emissions, an SNCR is used for NO X 

### 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 NO X 

### 0.27 lb/MMBtu SO 2 

### 0.07 lb/MMBtu CO 2 

### 200 lb/MMBtu

### 19-1 19. HYDROELECTRIC (HY)

19.1 MECHANICAL EQUIPM ENT AND SYSTEMS The 500 MW Hydroelectric (“HY”) Facility is co mposed of two 250 MW vertical shaft Francis turbine generator units w ith a minimum of 650 feet (200 mete rs) 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 synchrono us electric generators. Each generator is a 60 Hz machine rated at approximately 300 MVA with an output vo ltage of approximately 23 kV. Each electric generator is connected to a high-voltage bus in the facility switchyard vi a 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. Th e 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-t urbine 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 renewa ble, 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 wi th 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design differences, local technical enhancements (e.g., additional noise remediation that is genera lly required in urban siting), remote location issues, labor wage and producti vity differences, location adju stments, and the increase in overheads associated with these five adjustments. The assumption was ma de that hydroelectric facilities would only be considered for construction in the states of Alaska, California, Colorado, Connecticut, Idaho, Maine, Missouri, Montana, North Carolina, Ohi o, 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 zone s 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 techni cal enhancements include Califo rnia, Colorado, Connecticut, and Oregon. These are areas where technical enhancem ents 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. The remote lo cation related to the Hydr oelectric Facility is Fairbanks, Alaska. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the HY Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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 fo r the HY Facility include dam and associated civil major maintenance and hydro-turbine majo r 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 expens es 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 COMPLI ANCE INFORMATION The HY Facility does not burn a fuel and consequen tly 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 NO X 

### 0 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 0 lb/MMBtu

### 20-1 20. PUMPED STORAGE (PS)

20.1 MECHANICAL EQUIPM ENT 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. Du ring the generating cycle, water is discharged through the reversible turbine ge nerators to produce power. Fi gure 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 genera tors 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 ar e 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 brea ker and a disconnect switch. The GS U increases the voltage from the electric generator voltage to the interc onnected transmission system high voltage. The PS Facility is controlled using a DCS. The DC S provides centralized control of the facility by integrating the control system s provided with the hydro-turb ine 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 electrica l interconnection to the high-voltage transmission system of the utility, which can be effect uated 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, si gnificant 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 categor ies 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 lo wer cost on a $/kW basis) and by the existing infrastructure that may be leveraged in the development, desi gn, 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seis mic design differences, local t echnical enhancements, remote location issues, labor wage and productivity differe nces, location adjustment s, and the increase in overheads associated with these five adjust ments 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 differen ce 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 zone s 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 loca l technical enhancements include California, Colorado, Connecticut, Delaware, District of Columbia, Louisiana, Maryland, Massachusetts, New Jersey, New York, Oregon, Rhode Island, Vermont, and Vi rginia. These are areas wher e noise, visual impacts, and other technical enhancements generally need to be made by a project de veloper or utility to comply with the applicable permitting/siting requirements. Remote location issues are related to geographic ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote loca tions related to the Pu mped Storage Facility include Fairbanks, Alaska; Honolulu, Hawaii; Al buquerque, New Mexico; Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity differences were ha ndled 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 wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Yo rk, 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-lev el is applicable to the PS Facility, including the f act that most operators budget for a given PS facility on a FOM expense basis only. The additional areas of O&M th at are applicable to the PS Facility that are not applicable to the HY Facil ity 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. Ta ble 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 COMPLI ANCE 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 us ed to power the off-peak energy market, allowing

### 20-4 off-peak pumping to the reservoir, is not cons idered in this report. Table 20-4 presents environmental emissions for the PS Facility.

TABLE 20-4 – ENVIRONMENTAL EMISSIONS FOR PS
Technology: PS NO X 

### 0 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 0 lb/MMBtu

### 21-1 21. ONSHORE WIND (WN)

21.1 MECHANICAL EQUIPM ENT 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 tota l 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 conn ects to the transmission through one end of the nacelle, and the rotor is then connected to the hub. The WTG ha s 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 st ep up the voltage to 115 kV for interconnection with the transmission system. Othe r facility components include access roads, an O&M building and electrical inte rconnection 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 turb ine-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 pa d-mounted transformer at the base of the wind turbine. The wind turbine tr ansformers 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 include s a 34.5 kV switch or circuit brea ker, 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 th e facility by integrating the contro l 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 signi ficant off-site requirements are the construction of and interconnection to roads and the electrical interconnec tion to the utility high-voltage transmission system, as di scussed 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design diffe rences, remote location issues, labor wage and productivity differences, location adjustments, a nd 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 zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote lo cations related to the WN Facility include Fairbanks, Alaska; Honolulu, Ha waii; Albuquerque, New Mexico ; Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the WN Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Yo rk, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 Faci lity include periodic gearbox, WTG, electric generator, and associated electric conversi on (e.g., GSU) technology repa irs and replacement. These devices typically undergo major maintenance every five to seven ye ars. 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 COMPLI ANCE INFORMATION

Since wind utilizes a renewable fuel and no additio nal fuel is combusted to make power from an Onshore Wind Facility, air emissions are not created. Table 21-4 pr esents environmental emissions for the WN Facility.

TABLE 21-4 – ENVIRONMENTAL EMISSIONS FOR WN
Technology: WN NO X 

### 0 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 0 lb/MMBtu

### 22-1 22. OFFSHORE WIND (WF)

22.1 MECHANICAL EQUIPM ENT 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 offshor e wind projects is the gravity foundation which ut ilizes 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 com ponents of the wind turbine, which include a variable-speed generator, tr ansmission, 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 w ith a diameter of approximately 125 meters. The WTG has an active yaw system in the nacelle to keep the rotor facing in to the wind. The WF WTG is designed to withstand the conditi ons of the high seas, includ ing additional redundancy of key components to enhance availability, corro sion 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 typical ly buried 1 to 3 meters below the sea floor for protection. The collection system supplies power to a new substation designed to st ep up the voltage to 115 kV for interconnection with the transmission system. Figure 22-1 pres ents 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 turbin e-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 approxim ately 5.5 MVA with an output voltage of 690 V stepped up to 34.5 kV usi ng a transformer installe d in the wind turbine pylon. The wind turbine transforme rs are interconnected on one or more underwater collector circuits trenched into the seabed that are connect ed to a collector bus (or several collector busses) through a circuit breaker for each circuit. The coll ector bus is connected to a high-voltage transmission system through the facility substation th at includes a 34.5 kV switch or circuit breaker, GSU, high-voltage circuit breaker an d 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 SCAD A system provides centralized control of the facility by integrating the contro l 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 o ff-site requirement for the WF Facility is the electrical interconnectio n 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, 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 construc ted offshore of the following states (where

### 22-4 significant offshore wind resource is available) : Alaska, California, Connecticut, Delaware, District of Columbia, Georgia, Hawaii, Illinoi s, Indiana, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Jersey, New York, North Carolina, Oregon, Rhode Island, South Carolina, Texas, Virginia, Washi ngton, Wisconsin and Puerto Rico. Seismic design differences among the various locations were based on U.S. seismic map information that detailed the various seismic zone s 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 rela ted to geographic areas that typi cally require installation of man camps, higher craft incentives, and higher per di ems for construction, because such areas are long distances from urban ar eas, where labor is generally abundant. Remote location designations were also considered in locations where higher equi pment freight costs are typically incurred, which for example are regions not near established rail or highway access. Remote locations related to the Offshor e Wind Facility include Anchor age, Alaska; Honolulu, Hawaii; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the WF Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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 fo r 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 belo w on a fixed basis. Ta ble 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 COMPLI ANCE INFORMATION Since the WF Facility uses a renewable fuel a nd no additional fuel is co mbusted, there are no air emissions. Table 22-4 presents environm ental emissions for the WF Facility.

### 22-5 TABLE 22-4 – ENVIRONMENTAL EMISSIONS FOR WF
Technology: WF NO X 

### 0 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 0 lb/MMBtu

### 23-1 23. SOLAR THERMAL - CONCENTRATED SOLAR POWER (CSP)

23.1 MECHANICAL EQUIPM ENT AND SYSTEMS Solar thermal electric technology, also known as c oncentrated solar power (“CSP”) with thermal energy storage (“TES”), may be able to solve the problem of storage. Co ncentrated solar power systems use mirrors to concentr ate sunlight to heat a worki ng gas or a flui d 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 us e 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 dr ives a piston to power a generator to produce electricit y. Dish/Stirling engines are usually mounted on a dual axistracking device to keep the dish pointed dire ctly at the sun during the day for maximum performance. Another CSP technology is the parabolic tr ough 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 th e use of tracking mirrors with a tower focal point. This concentrated solar design uses a large field of fl at, computer-controlled mirro rs 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 ta nk and are heated to temperatures reaching 1,000 degrees Fahrenheit (“oF”). The heated fluid then passes through a st eam boiler, which is subsequently used in a steam turb ine 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 circ uit breaker and a disconnect sw itch. 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. Th e DCS provides centralized control of the facility by integrating the control systems provided with the solar steam generator/superheater/reheater system, ST and associated electr ic 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 s ourced through on-site wells. Th e 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 pr ovide distilled water for HRSG make-up. Processed wastewater is sent to a municipal wastewater system, re-injec ted 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 adjace nt 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, sca ffolding, construction management, and start-up. (2) Does not include natural gas firing, as such us age is sporadic and highly dependent on time of year and method of operation.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design diffe rences, remote location issues, labor wage and

### 23-3 productivity differences, location adjustments, owner cost differences, and the increase in overheads associated with the prev ious five location adjustments. Seismic design differences among the various locations were based on U.S. seismic map information that detailed the various seismic zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote lo cations related to the Solar Thermal Facility include Honolulu, Hawaii; Albuquerque, New Mexi co; Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the SO Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Minnesota, New York, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 Facili ty 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 mainte nance is similar to that which is performed on a combined-cycle plant: HRSG, ST, and elect ric 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 consequen tly, all O&M expenses are shown below on a fixed basis. Tabl e 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 COMPLI ANCE INFORMATION Table 23-4 presents environmental emissions for the SO Facility.

### 23-4 TABLE 23-4 – ENVIRONMENTAL EMISSIONS FOR SO
Technology: SO NO X 

### 0 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 0 lb/MMBtu

### 24-1 24. UTILITY-SCALE PHOTOVOLTAIC (PV) FACILITY

24.1 MECHANICAL EQUIPM ENT AND SYSTEMS The following describes a nominally 20 MW-AC Phot ovoltaic (“PV”) Facility. An analysis is also provided for a nominally 150 MW-AC PV F acility, which is essentially a significant expansion of the 20 MW Facility; however, a detailed technical description (due to the similarities with the 20 MW F acility and the technology associat ed therewith) is not provided herein. The PV Facility uses numerous arra ys of ground-mounted, si ngle-axis tracking PV modules which directly convert in cident solar radiation into DC electricity, which can then be inverted to AC. Additional BOP component s include metal racks mounted to tracker components (drive motors, gearboxes, linkage s, 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 inverter s, AC wiring, various switchgear and step-up transformers, and a control system (partly incorpor ated 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 modul es connected to a 500 kW-AC inve rter. While the ratio of DC

### 24-2 module capacity to AC inverter ca pacity varies, for this analysis we have assumed a ratio of 1.3:1, or 650 kW-DC of modules per 500 kW-AC invert er. 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 pow er from DC to three-phase AC electricity at an output voltage of typically 265 V-AC to 420 V-AC. Th e output voltage of an inverter (or sometimes several inverters connected together) is stepped up to a higher vo ltage level, typically in the range of 13.8 kV (or 34.5 kV for larger sy stems) through a GSU connected to the inverter output terminals. The output of two or more i nverters 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 ci rcuits on an underground collection system. The circuits are connected to a 13.8 kV circuit breaker and then to th e local utility distribution grid.

Each inverter has its own inte gral control system. The aggr egate of all the inverters and associated DC arrays are monitored thr ough 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 syst em. 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 w ith 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, sca ffolding, 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, sca ffolding, construction management, and start-up.



### For this type of technology and power plant conf iguration, our regional adjustments took into consideration the following: seismic design diffe rences, remote location issues, labor wage and productivity differences, location adjustments, owner cost differences, and the increase in overheads associated with thes e five location adjustments. Seismic design differences among the various locations were based on U.S. seismic map information that detailed the various seismic zone s 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 ar eas that typically require installation of man camps, higher craft incentives, and higher per diems are genera lly required with respect to construction, due to the fact that such areas ar e 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 in curred, which for example are regions not near established rail or highway access. Remote locati ons related to the Photovo ltaic Facility include

### 24-5 Fairbanks, Alaska; Honolulu, Hawaii; Albuquer que, New Mexico Cheyenne, Wyoming; and Cayey, Puerto Rico. Labor wage and productivity diffe rences were handled as discu ssed in Section 2.5.1, taking into consideration the amount of labor we estimated for the PV Facility. Location adjustments were made to locations wh ere higher cost of livi ng levels are incurred and/or where population density generally correlat es 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, Ha waii, Illinois, Maine, Maryland, Massachusetts, Minnesota, New York, Ohio, and Wisconsin.

Owner costs were reviewed based on the need fo r 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 inve rter 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 pr esent the O&M expenses for th e 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 th e 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 COMPLI ANCE INFORMATION Table 24-8 presents environmental emissions for the PV Facility.

### 24-6 TABLE 24-8 – ENVIRONMENTAL EMISSIONS FOR PV
Technology: Photovoltaic NO X 

### 0 lb/MMBtu SO 2 

### 0 lb/MMBtu CO 2 

### 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, sca ffolding, 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, sca ffolding, construction management, and start-up.

### A-1 1. APPENDIX 1 – STATE INFORMATION

TABLE 3-3 – LOCATION-BASE D 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-BASE D 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 CO STS 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-BASE D 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 CO STS 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-BASE D 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-BASE D 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-BASE D 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-BA SED 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-BASE D 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-BASE D 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-BA SED 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-BA SED 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