## Updated Capital Cost Estimates for Electricity Generation Plants

November 2010

U. S. Energy Information Administration Office of Energy Analysis

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the U.S. Energy Information Admi nistration (EIA), the statis tical and analytical agency within the U.S. Department of Energy. By law, EIA’s dat a, 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 Depart ment of Energy or other Federal agencies.2 The current and future projected cost of new electri city generation capacity is a critical input into the development of energy projections and analyses . The cost of new generating plants plays an important role in determining the mix of capacity additions that will serve growing loads in the future. New plant costs also help to determ ine how new capacity competes against existing capacity, and the response of the electricity generators to the imposition of environmental controls on conventional pollu tants or any limitations on greenhouse gas emissions.

The current and projected future costs of en ergy-related capital proj ects, including but not limited to new electric generating plants, have be en subject to considerable change in recent years. EIA updates its cost and performance assumptions annually, as part of the development cycle for the Annual Energy Outlook (AEO). For the AEO2011 cycle, EIA commissioned an external consultant to develop current cost es timates for utility-scale electric generating plants. 1 This paper briefly summarizes the design of th e project and provides a summary of its main findings, including a comparison of the new estimates to those used in AEO2010 . The final section discusses how EIA uses information on cost and other factor s in modeling technology choice in the electric power sector.

Developing Updated Estimates: Key Design Considerations

In order to maximize its value to EIA and ex ternal energy analysts, the project focused on gathering current informati on regarding the “overnight” 2 cost for a wide range of generation technologies, while taking care to use a comm on boundary in the costing exercise across those technologies. The cost estimates for each tec hnology were developed for a generic facility of a specific size and configuration, and assumi ng a location without unusual constraints or infrastructure needs.

Current information is particul arly important during a period when actual and estimated costs have been evolving rapidly, since the use of up-to -date cost estimates for some technologies in conjunction with estimates that ar e two, three, or even five year s old for others can significantly skew the results of modeling and analysis. Where possible, costs estimates were based on information regarding actual or planned projec ts available to the consultant. When this information was not available, project costs were estimated by using cost ing models that account for current labor and material rates that would be necessary to complete the construction of a generic facility.

The use of a common boundary for costing is also very important. From experience in reviewing many costing studies for individual technologies, EIA is well aware that differences in practices regarding the inclusion or exclus ion of various components of co sts can have a large impact on overall cost estimates. This includes the categorie s of civil and structural costs (e.g., allowance

1 EIA’s electricity modeling includes bo th combined heat and power (CHP) t echnologies as well as a variety of distributed generation technologies, but those technologies were not addressed in the study, which focused on technologies within th e electric power sector.

2 “Overnight cost” is an estimate of the cost at which a plant could be constructed assuming that the entire process from planning through completion could be accomplished in a single day. This concept is useful to avoid any impact of financing issues and assumptions on estimated costs. Starting from overnight cost estimates, EIA’s electricity modeling explicitly takes account of the time requ ired to bring each generation technology online and the costs of financing construction in the period before a plant becomes operational.3 for site preparation, drainage, unde rground utilities, and buildings), project indirect costs (e.g., a construction contingency), and owners costs (e.g., development costs, preliminary feasibility and engineering studies, environmenta l studies and permitting, legal fees, insurance costs, property taxes during construction, and the electrical inte rconnection costs, including a plant switchyard and tie-in to nearby transmission).

Summary of updated overnight capit al costs estimates and compar ison to information used in AEO2010

Table 1 summarizes the updated cost estimates fo r the generic utility-sca le generation plants represented in EIA’s model, including 7 powered by coal, 6 by natural gas, 3 by solar energy, 2 each by wind, hydro, biomass, and geothermal power, and 1 each by uranium and municipal solid waste. For some plant types there are seve ral options shown to bette r represent the range of plants that might be built and their costs. Fo r example, both single unit and dual unit advanced pulverized coal plants are shown, because many plants include multiple units and the costs associated with the dual unit configuration might better reflect the costs of most plants built. Similarly, solar photovoltaic tec hnologies include a re latively small 7 MW system and a much larger 150 MW system, because there is such va riance in the sizes of the facilities being considered. The nominal capacity of the generi c plants ranges from a 7 megawatt (MW) solar plant to a 2,236 MW advanced dual- unit nuclear plant, reflecting th e significant va riation in the scale of utility applications. Each technology is characterized by its overnight capita l costs, heat rate (where applicable), non-fuel operations and maintenance costs, and, though not shown in Table 1, its environmental characteristics.

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

. To facilitate comparisons, both are shown in r eal year 2010 dollars. No table changes between the updated estimates and the AEO2010 values include:

• Coal & Nuclear: The updated overnight capital cost estimates for coal and nuclear power plants are 25 to 37 percent above those in AEO2010 . The higher cost estimates reflect many factors including the overall tr end of rising costs of capital intensive technology in the power sector, higher global commodity prices, and the fact that there are relatively few construction firms with the ability to complete complex engineering projects such as a new nuclear or advancedcoal power plant. The study assumes costsharing agreements between the project owne r and the project cons truction contractors are reflective of those recently observed in the marketplace. As shown in Table 1, dual unit coal and nuclear plants generally have lo wer overnight costs per kilowatt than singleunit plants, reflecting their ab ility to take advantage of redundancies and scale economies in onsite infrastructure such as wastewater management and environmental controls to reduce the estimated total per-kilowatt cost of the project.

• Natural Gas: The updated cost estimates for natura l gas combined cycle and combustion turbines generally remained similar to those of AEO2010

.

• Solar : The overnight capital cost s for solar thermal and photovoltaic technologies dropped by 25 percent and 10 percent, respec tively. The decrease in the cost of photovoltaics was due to the assumption of larg er plant capacity and falling component costs.4 • Onshore Wind : Overnight costs for onshore wind incr eased by about 21 percent relative to AEO 2010 assumptions. This is based on a sp ecification for a new, stand-alone wind plant including all owners’ costs and may differ from other reported cost s in the literature, which are not fully characterized and may incl ude sites that are bui lt along side existing plants (and are thus able to avoid so me amount of infrastructure costs).

• Offshore Wind : While offshore wind plants have been built in Europe, there have only been proposals in the United States, with fi nal permitting only recently issued on the first of these proposals. The updated co sts, some 50 percent higher than AEO 2010 estimates, are consistent with substantia l first-of-a-kind costs that w ould likely be encountered when building projects in the United States, whic h largely lacks the unique infrastructure, needed to support this type of construction.

• Geothermal : Geothermal costs are highl y site-specific, and are represented as such in the AEO estimates. The updated cost estimate is over 50 percent higher than the same site in AEO 2010.

• Biomass: Biomass capital costs are largely unchanged from AEO2010 . However, the technology represented by the costs has change d significantly. Prior estimates were for a highly efficient plant employing gasification and a combined cycle generator; the new estimate is for a significantly less efficient direct combustion boiler. The lower operating efficiency (and therefore higher operating cost ) for the biomass plant considered in the updated cost estimate implies a reduced attr activeness of investment in new biomass generation at an overnight cost similar to that for the more efficient biomass plant characterized in AEO2010.

While estimates of the current cost of generic electric generation capacityof various types are one key input to EIA’s analysis of electricity markets, the evoluti on of the electricity mix in each of the 22 regions to be modeled in AEO2011 3 is also sensitive to ma ny other factors, including the projected evolution of capita l costs over the modeli ng horizon, projected fuel costs, whether wholesale power markets are regulated or competitive, the existing generation mix, additional costs associated with environmental control requ irements, load growth, and the load shape. Almost all of these factors can vary by region, as do capacity factors for renewable generation, operations and maintenance costs associated with individual plants, and cost multipliers applied to the generic estimates of overnight capital costs outlined in Tables 1 and 2. The next section provides a brief overview of some of the relevant issues, which are described in more detail in the description of the Electric Market Module included in the 2010 edition of the documentation for EIA’s National Energy Modeling System.

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

Estimates of the overnight capit al cost of generic generating technologies are only the starting point for consideration of the cost of new gene rating capacity in EIA modeling analyses. EIA also considers regional variation in construction costs, the structure of wholesale power markets that affect financing costs, the length of time re quired to bring each type of plant into service, and the capacity availability factors for solar a nd wind generation plants. EIA also accounts for

3 In AEO2010 and prior editions, the continental U.S., excluding Alaska, was divided in 13 regions for purposes of electricity modeling. The 22 region model that will be used starting with AEO2011 will allow for better representation of policy boundaries and mark et structure at the State level.5 three distinct dynamic forces that drive changes in plant cost over time. One is the projected relationship between rate of infl ation for key drivers of plant costs, such as materials and construction costs, and the overa ll economy-wide rate of infla tion. A projected economy–wide inflation rate that exceeds proj ected inflation for key plant cost drivers results in a projected decline in real (inflation-adjusted) capital costs. Projected capital cost s also reflect projected technology progress over time. Learning-by-doi ng, which allows for additional reductions in projected capital costs as a f unction of cumulative additions ne w technologies, has a further effect on technology costs. See the AEO2010 assumptions and model documentation for more details. 4

Levelized cost is often cited as a convenient summary measure of the overall competiveness of different generating technologies. Le velized cost represents the pres ent value of the total cost of building and operating a generating plant over an assumed economic life, converted to equal annual payments and expressed in terms of real dollars to remove the impact of inflation. Levelized costs, which reflect ove rnight capital cost, fuel cost, fixed and variable O&M cost, are a useful indicator of the competitiveness of diffe rent generation technologies. For technologies such as solar and wind generation that have no fuel costs and relatively small O&M costs, levelized cost changes in rough pr oportion to the estimated overnig ht capital cost of generation capacity. For technologies with significant fuel cost, both fuel cost and overnight cost estimates significantly affect levelized cost. Thus, wh ile Table 2 shows little change between the updated capital cost estimates for natural gas co mbined cycle plants and those used in AEO2010

, improved supply prospects for natural gas that will be incorporated in AEO2011 result in lower projected prices that in turn lower the leveli zed cost of gas-fired generation and improve the attractiveness of operating and adding gas-fired generati on technologies.

It is important to note, however, that actua l investment decisions are affected by numerous factors other than levelized costs. The projected utilization rate , which depends on the load shape and the existing resource mix in an area where additional capacity is needed, is one such factor. The existing resource mix in a region can directly affect the economic viability of a new investment through its effect on the econom ics surrounding the displacement of existing resources. For example, a wind resource that would primarily back out existing natural gas generation will generally have a higher value than one that would back out existing coal generation under fuel price conditions where the variable cost of operating existing gas-fired plants exceeds that of operati ng existing coal-fired plants.

A related factor is the capacity value

, which depends on both the existing capacity mix and load characteristics in a region

. Since load must be balanced on a continuous basis, units whose output can be varied to follow demand generally ha ve more value to a system than less flexible units or those whose operation is tied to the avai lability of an intermittent resource. Policyrelated factors, such as investme nt or production tax credits for specified generation sources, can also impact investment decisions. Finally, alt hough levelized cost calc ulations are generally made using an assumed set of capital and operati ng costs, the inherent un certainty about future fuel prices and future policies, may cause plant ow ners or investors who finance plants to place a

4 Assumptions and model documentation for the 2010 Annual Energy Outlook are available at http://www.eia.doe.gov/oiaf/aeo/index.html

.6 value on portfolio diversification

. EIA considers all of these factors in its analyses of technology choice in the electricity sector.

In sum, while overnight cost estimates are impor tant inputs for EIA modele rs and other analysts, they are not the sole driver of the choice among electric generation t echnologies. Users interested in additional details regarding thes e updated cost estimates should review the consultant study prepared by R.W. Beck for EIA in Appendix A.7 Table 1. Updated Estimates of Powe r Plant Capital and Operating Costs

Plant Characteristics Plant Costs

Nominal Capacity (kilowatts) Heat Rate (Btu/kWh) Overnight Capital Cost (2010 $/kW) Fixed O&M Cost (2010$/kW) Variable O&M Cost (2010 $/MWh) Coal Single Unit Advanced PC 650,000 8,800 $3,167 $35.97 $4.25

Dual Unit Advanced PC 1,300,000 8,800 $2,844 $29.67 $4.25 Single Unit Advanced PC with CCS 650,000 12,000 $5,099 $76.62 $9.05 Dual Unit Advanced PC with CCS 1,300,000 12,000 $4,579 $63.21 $9.05 Single Unit IGCC 600,000 8,700 $3,565 $59.23 $6.87 Dual Unit IGCC 1,200, 000 8,700 $3,221 $48.90 $6.87 Single Unit IGCC with CCS 520,000 10,700 $5,348 $69.30 $8.04 Natural Gas Conventional NGCC 540,000 7,050 $978 $14.39 $3.43 Advanced NGCC 400,000 6,430 $1,003 $14.62 $3.11 Advanced NGCC with CCS 340,000 7,525 $2,060 $30.25 $6.45 Conventional CT 85,000 10,850 $974 $6.98 $14.70 Advanced CT 210,000 9,750 $665 $6.70 $9.87 Fuel Cells 10,000 9,500 $6,835 $350 $0.00 Uranium Dual Unit Nuclear 2,236,000 N/A $5,335 $88.75 $2.04 Biomass Biomass CC 20,000 12,350 $7,894 $338.79 $16.64 Biomass BFB 50,000 13,500 $3,860 $100.50 $5.00 Wind Onshore Wind 100,000 N/A $2,438 $28.07 $0.00 Offshore Wind 400,000 N/A $5,975 $53.33 $0.00 Solar Solar Thermal 100,000 N/A $4,692 $64.00 $0.00 Small Photovoltaic 7, 000 N/A $6,050 $26.04 $0.00 Large Photovoltaic 150,000 N/A $4,755 $16.7 $0.00 Geothermal Geothermal – Dual Flash 50,000 N/A $5,578 $84.27 $9.64 Geothermal – Binary 50,000 NA $4,141 $84.27 $9.64 MSW MSW 50,000 18,000 $8,232 $373.76 $8.33 Hydro Hydro-electric 500,000 N/A $3,076 $13.44 $0.00 Pumped Storage 250,000 N/A $5,595 $13.03 $0.008 Table 2. Comparison of Updated Plant Costs to AEO2010 Plant Costs

Table II Overnight Capital Cost ($/k W) Nominal Capacity KWs 1

AEO 2011 AEO 2010 % Change AEO 2011 AEO 2010

Coal Advanced PC w/o CCS $2,844 $2,271 25% 1,300,000 600,000 IGCC w/o CCS $3,221 $2,624 23% 1,200,000 550,000

IGCC CCS $5,348 $3,857 39% 600,000 380,000 Natural Gas Conventional NGCC $978 $1,005 -3% 540,000 250,000

Advanced NGCC $1,003 $989 1% 400,000 400,000 Advanced NGCC with CCS $2,060 $1,973 4% 340,000 400,000

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

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

Fuel Cells $6,835 $5,595 22% 10,000 10,000 Nuclear Nuclear $5,339 $3,902 37% 2,236,000 1,350,000 Renewables

Biomass $3,860 $3,931 -2% 50,000 80,000 Geothermal $4,141 $1,786 132% 50,000 50,000 MSW - Landfill Gas $8,232 $2,655 210% 50,000 30,000 Conventional Hydropower $3,078 $2,340 32% 500,000 500,000

Wind $2,438 $2,007 21% 100,000 50,000 Wind Offshore $5,975 $4,021 49% 400,000 100,000 Solar Thermal $4,692 $5,242 -10% 100,000 100,000

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

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

site and that savings could be gained by eliminating redundancies and combining services.9 

# Appendix A

## R. W. Beck, Inc. Science Applications International Corporation (SAIC)

Prepared by: 

## Vincent Hahn, R. W. Beck John Fix, R. W. Beck John Schmalz, R. W. Beck Michael Wennen, R. W. Beck Evis Couppis, Ph.D., R. W. Beck

Prepared in Coordination with:



## Jay Ratafia-Brown, SAIC

Prepared For: 

## Energy Information Administration Office of Integrated Analysis and Forecasting

Alan Beamon Michael Leff



# October 2010 EOP III TASK 1606, SUBTASK 3 – REVIEW OF

POWER PLANT COST AND PERFORMANCE ASSUMPTIONS FOR NEMS Technology Documentation Report

## Disclaimer

Certain statements included in this report constitute forward-looking statements. The achievement of certain results or other expectations contained in such forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause actual results, performance or achievements described in the report to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. We do not plan to issue any 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 R. W. Beck Background ........................................................................................ 2-1

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

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

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

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

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

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

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

2.6.2 Operation and 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 .......................................................................................... 2-8

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

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

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

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

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

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

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

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

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

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

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

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

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

4.6 Environmental Compliance Information ............................................................... 4-8ii 5. Conventional Natural Gas Combined Cycle (NGCC) ............................................. 5-1

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

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

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

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

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

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

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

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

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

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

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

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

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

7. Advanced Generation Natural 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 ...................................................................................................... 7-4

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

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

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

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

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

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

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

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

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

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

9.2 Electrical and Control Systems ............................................................................. 9-1iii 9.3 Off-Site Requirements ........................................................................................... 9-1

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

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

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

10. Integrated Gasification 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 .................................................................................................. 10-10

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

13.3 Off-Site Requirements ......................................................................................... 13-3iv 13.4 Capital Cost Estimate .......................................................................................... 13-3

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

17.6 Environmental Compliance Information ............................................................. 17-6v 18. Municipal Solid Waste (MSW) ................................................................................ 18-1

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

22.2 Electrical and Control Systems ........................................................................... 22-2vi 22.3 Off-Site Requirements ......................................................................................... 22-2

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

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

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

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

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

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

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

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

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

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

24. Photovoltaic (Central Stat ion) Facility (PV) .......................................................... 24-1

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

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

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

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

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

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

## 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 ................................................................................... 12-2 Figure 13-1 – BCC Design Configuration ................................................................................. 13-2 Figure 14-1 – BCC Design Configuration ................................................................................. 14-1 Figure 15-1 – FC Design Configuration .................................................................................... 15-1 Figure 16-1 – GT Design Configuration .................................................................................... 16-2 Figure 17-1 – GT Design Configuration .................................................................................... 17-1 Figure 19-1 – Hy Design Configuration .................................................................................... 19-1 Figure 20-1 – PS Design Configuration..................................................................................... 20-1 Figure 21-1 – WN Design Configuration .................................................................................. 21-1 Figure 22-1 – WF Design Configuration ................................................................................... 22-2 Figure 23-1 – So Design Configuration ..................................................................................... 23- 2 Figure 24-1 – PV Design Configuration .................................................................................... 24-1viii 

## 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) ......................................................... 3-5 Table 3-4 – Location-Based Costs for APC (1,300,000 kW) ...................................................... 3-7 Table 3-5 – O&M Expenses for APC (650,000 kW) ................................................................... 3-8 Table 3-6 – O&M Expenses for APC (1,300,000 kW) ................................................................ 3-8

Table 3-7 – Environmental Emissions for APC .......................................................................... 3-9 Table 4-1 – Base Plant Site 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) .................................... 4-4

Table 4-4 – Location-Based Costs for APC/CCS Facility (1,300,000 kW) ................................ 4-6 Table 4-5 – O&M Expenses fo r APC/CCS (650,000 kW) .......................................................... 4-7 Table 4-6 – O&M Expenses fo r APC/CCS (1,300,000 kW) ....................................................... 4-8

Table 4-7 – Environmental Em issions for APC/CCS .................................................................. 4-8 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....................................................... 5-5 Table 5-3 – O&M Expenses for Conventional NGCC ................................................................ 5-7

Table 5-4 – Environmental Emissi ons for Conventional NGCC ................................................. 5-7 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 ...................................................................... 6-3 Table 6-3 – O&M Expenses for AG-NGCC ................................................................................ 6-4

Table 6-4 – Environmental Em issions for AG-NGCC ................................................................ 6-5 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 ............................................................. 7-3ix Table 7-3 – O&M Expenses for AG-NGCC With CCS .............................................................. 7-4

Table 7-4 – Environmental Em issions for AG-NGCC/CCS ....................................................... 7-5 Table 8-1 – Base Plant Site Capital Co st Estimate for Conventional CT .................................... 8-2

Table 8-2 – Location-Based Costs for Conventional CT............................................................. 8-4 Table 8-3 – O&M Expenses for Conventional CT ...................................................................... 8-6

Table 8-4 – Environmental Emissi ons for Conventional CT ....................................................... 8-6 Table 9-1 – Base Plant Site Capital Cost Estimate for Advanced CT ......................................... 9-2

Table 9-2 – Location-Based Co sts for Advanced CT .................................................................. 9-3 Table 9-3 – O&M Expenses for Advanced CT ........................................................................... 9-4

Table 9-4 – Environmental Emi ssions for Advanced CT ............................................................ 9-5 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) ................................................... 10-7 Table 10-4 – Location-Based Costs for IGCC (1,200,000 kW) ................................................ 10-9 Table 10-5 – O&M Expenses for IGCC (600,000 kW) ........................................................... 10-10 Table 10-6 – O&M Expenses for IGCC (1,200,000 kW) ........................................................ 10-11

Table 10-7 – Environmental Emissions for IGCC ................................................................... 10-11 Table 11-1 – Base Plant Site Capita l Cost Estimate for IGCC/CCS ......................................... 11-2

Table 11-2 – Location-Based Costs for IGCC/CCS .................................................................. 11-3 Table 11-3 – O&M Expenses for IGCC/CCS............................................................................ 11-4

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

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

Table 12-2 – Location-Based Costs for AN .............................................................................. 12-5 Table 12-3 – O&M Expenses for AN ........................................................................................ 12-7

Table 12-4 – Environmental Emissions for AN ........................................................................ 12-7 Table 13-1 – Base Plant Site Capi tal Cost Estimate for BCC ................................................... 13-4

Table 13-2 – Location-Based Costs for BCC ............................................................................ 13-6 Table 13-3 – O&M Expenses for BCC ...................................................................................... 13-7

Table 13-4 – Environmental Emissions for BCC ...................................................................... 13-8 Table 14-1 – Base Plant Site Capi tal Cost Estimate for BBFB ................................................. 14-3

Table 14-2– Location-Based Costs for BBFB ........................................................................... 14-5 Table 14-3 – O&M Expenses for BCC ...................................................................................... 14-6

Table 14-4 – Environmental Emissions for BBFB .................................................................... 14-7x Table 15-1 – Base Plant Site Capi tal Cost Estimate for FC ...................................................... 15-2

Table 15-2 – Location-Based Costs for FC ............................................................................... 15-4 Table 15-3 – O&M Expenses for FC ......................................................................................... 15-5

Table 15-4 – Environmental Emissions for FC ......................................................................... 15-6 Table 16-1 – Base Plant Site Capi tal Cost Estimate for GT ...................................................... 16-3

Table 16-2 – Location-Based Costs for GT ............................................................................... 16-5 Table 16-3 – O&M Expenses for GT ........................................................................................ 16-6

Table 16-4 – Environmental Emissions for GT ......................................................................... 16-7 Table 17-1 – Base Plant Site Capi tal Cost Estimate for GT ...................................................... 17-2

Table 17-2 – Location-Based Costs for GT ............................................................................... 17-4 Table 17-3 – O&M Expenses for Binary ................................................................................... 17-5 Table 17-4 – Environmental Emissions for Binary ................................................................... 17-6 Table 18-1 – Base Plant Site Capi tal Cost Estimate for MSW .................................................. 18-3

Table 18-2 – Location-Based Costs for MSW ........................................................................... 18-4 Table 18-3 – O&M Expenses for MSW .................................................................................... 18-6

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

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

Table 19-2 – Location-Based Costs for HY .............................................................................. 19-4 Table 19-3 – O&M Expenses for HY ........................................................................................ 19-5

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

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

Table 20-2 – Location-Based Costs for PS ................................................................................ 20-4 Table 20-3 – O&M Expenses for PS ......................................................................................... 20-5

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

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

Table 21-2 – Location-Based Costs for WN.............................................................................. 21-4 Table 21-3 – O&M Expenses for WN ....................................................................................... 21-6

Table 21-4 – Environmental Emissions for WN ........................................................................ 21-6 Table 22-1 – Base Plant Site Capi tal Cost Estimate for WF ..................................................... 22-3

Table 22-2 – Location-Based Costs for WF .............................................................................. 22-5 Table 23-1 – Base Plant Site Capi tal Cost Estimate for SO ...................................................... 23-4

Table 23-2 – Location-Based Costs for SO ............................................................................... 23-6 Table 23-3 – O&M Expenses for SO ......................................................................................... 23-7xi Table 23-4 – Environmental Emissions for SO ......................................................................... 23-8 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) ................................................................. 24-6 Table 24-4 – Location-Based Costs for PV (150 MW) ............................................................. 24-8 Table 24-5 – O&M Expenses for PV Facility (7 MW) ............................................................. 24-9 Table 24-6 – O&M Expenses for PV Facility (150 MW) ......................................................... 24-9

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

## 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 Sulfidexiii HHV High(er) Heating Value HP High Pressure HRSG Heat Recovery Steam Generator HY Hydroelectric Hz Hertz I&C Instrumentation and Controls IGCC Integrated Gasification Combined Cycle IGCC/CCS Integrated Gasification Combined Cycle Carbon Capture and Sequestration IP Intermediate Pressure kg Kilograms KJ Kilojoules kW Kilowatt kWh Kilowatt-hour kV Kilovolt kVA kilovolt-amperes lb Pound LHV Low(er) Heating Value CLP Low Pressure MEA Monoethanolamine MJ Mega joules MMBtu Million Btu MSW Municipal Solid Waste MW Megawatt MWe Megawatts Electric MWh Megawatt-hour MVA Mega-volt-amperes 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 SNCR Selective Non-catalytic Reductionxiv 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 Discharge1-1 1. INTRODUCTION This report presents R. W. Beck, Inc.’s (“R. W. Beck”) performance and cost assessment of power generation technologies ut ilized by the Energy Information Administration (“EIA”) in the Electricity Market Module (“EMM”) of the Na tional 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 generating 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 assumptions regarding how cons truction costs decline over time due to technological advancement and “learning by doing.”

• Review of the appropriateness of technology- specific project and process contingency assumptions (capturing differences between 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”) 540 MWe; F-Class system

Advanced NGCC 400 MWe; H-Class system Advanced NGCC with CCS 340 MWe; H-Class system

Conventional Combustion Turbine (“CT”) 85 MWe; E-Class turbine

Advanced CT 210 MWe; F-Class turbine Integrated Gasification Combined Cycle (“IGCC”) 600 MWe and 1,200 MWe; FClass-syngas system

IGCC with CCS 520 MWe; F-Class-syngas system Advanced Nuclear 2,236 megawatt (“MW”); AP1000 PWR Basis Brownfield Installation

Biomass Combined Cycle 20 MWe Wood Fuel Biomass Bubbling Fluidized Bed (“BFB”) 50 MWe Wood Fuel

Fuel Cells 10 MWe Geothermal 50 MWe Dual Flash and Binary Municipal Solid Waste (“MSW”) 50 MWe

Hydroelectric 500 MWe Pumped Storage 250 MWe

Wind Farm – Onshore 100 MWe

Wind Farm – Offshore 400 MWe

Solar Thermal – Central Station 100 MWe

Photovoltaic – Central Station 7 MWe –AC and 150 MWe - AC2-1 2. GENERAL BASIS FOR TECHNOLOGY EVALUATION BASIS This section specifies the general evaluation ba sis used for all technol ogies reviewed herein.

2.1 R. W. BECK BACKGROUND R. W. Beck is an infrastructure consulting firm that has been providing technical and business consulting in the energy industry since 1942. Particularly, R. W. Beck has supported the purchase, sale, financing and Owner’s advisory consulting for tens-of-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 suppor ted R. W. Beck’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 and listed in Table 1-1. Each of the technologies that combust a fuel has the ability to operate over a range of fuels; thus Table 2-1, Table 2- 2 and Table 2-3 show a typical fuel specification for coal , natural gas, and wood-biomass, respectively. MSW has such a wide range of constituents; a typical analysis is not included here.2-2 TABLE 2-1 – REFERENCE COAL SPECIFICATION

Rank Bituminous Seam Illinois No. 6 (Herrin)

Source Old Ben Mine Proximate Analysis (weight %) (Note A) As Received Dry Moisture 11.12 0.00 Ash 9.70 10.91 Volatile Matter 34.99 39.37 Fixed Carbon 44.19 49.72 Total 100.00 100.00 Sulfur 2.51 2.82

HHV (1) , KJ/kg (2) 27,113 30,506 HHV, Btu/lb (3) 11,666 13,126

LHV (4) , KJ/kg 26,151 29,544 LHV, Btu/lb 11,252 12,712 Ultimate Analysis (weight %) As Received Dry Moisture 11.12 0.00 Carbon 63.75 71.72 Hydrogen 4.50 5.06 Nitrogen 1.25 1.41 Chlorine 0.29 0.33 Sulfur 2.51 2.82 Ash 9.70 10.91 Oxygen 6.88 7.75 Total 100.00 100.00

(1) High(er) heating value (“HHV”). (2) Kilojoules per kilogram (“KJ/kg”). (3) British thermal units per pound (“Btu/lb”). (4) Low(er) heating value (“LHV”).2-3 TABLE 2-2 – NATURAL GAS SPECIFICATION

Component Volume Percentage

Methane 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 currently consid ered “proven” or BACT by regulating bodies, R. W. Beck assumed capture and sequestration t echnologies that are currently in development for large-scale deployment, as discussed he rein, and 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 th e ISO net capacity for the CT-based power plant technologies.2-5TABLE 2-4 – CT CAPACITY ADJUSTMENTSISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity Adjusted ISO Capacity AdjustedCapacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment Capacity Capacity Adjustment CapacityState City (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)Alaska Anchorage 85 7.58 92.58 210 18.73 229 540 32.27 572 400 35.67 436 340 30.32 370 600 35.85 636 520 46.38 566Alaska Fairbanks 85 9.97 94.97 210 24.63 235 540 42.43 582 400 46.91 447 340 39.87 380 600 47.14 647 520 60.98 581Alabama Huntsville 85 -2.12 82.88 210 -5.23 205 540 -9.01 531 400 -9.96 390 340 -8.46 332 600 -10.01 590 520 -12.94 507Arizona Phoenix 85 -8.33 76.67 210 -20.59 189 540 -35.47 505 400 -39.22 361 340 -33.34 307 600 -39.41 561 520 -50.98 469Arkansas Little Rock 85 -1.77 83.23 210 -4.37 206 540 -7.53 532 400 -8.32 392 340 -7.07 333 600 -8.36 592 520 -10.82 509California Los Angeles 85 -1.77 83.23 210 -4.37 206 540 -7.52 532 400 -8.32 392 340 -7.07 333 600 -8.36 592 520 -10.81 509California Redding 85 -2.52 82.48 210 -6.21 204 540 -10.71 529 400 -11.84 388 340 -10.06 330 600 -11.90 588 520 -15.39 505California Bakersfield 85 -3.77 81.23 210 -9.30 201 540 -16.03 524 400 -17.72 382 340 -15.06 325 600 -17.81 582 520 -23.03 497California Sacramento 85 -0.69 84.31 210 -1.71 208 540 -2.95 537 400 -3.26 397 340 -2.78 337 600 -3.28 597 520 -4.24 516California San Francisco 85 0.83 85.83 210 2.06 212 540 3.54 544 400 3.92 404 340 3.33 343 600 3.94 604 520 5.09 525Colorado Denver 85 -12.30 72.70 210 -30.40 180 540 -52.37 488 400 -57.90 342 340 -49.22 291 600 -58.19 542 520 -75.27 445Connecticut Hartford 85 2.97 87.97 210 7.33 217 540 12.63 553 400 13.96 414 340 11.87 352 600 14.03 614 520 18.15 538Delaware Dover 85 1.22 86.22 210 3.00 213 540 5.17 545 400 5.72 406 340 4.86 345 600 5.75 606 520 7.43 527District of Columbia Washington 85 2.01 87.01 210 4.96 215 540 8.55 549 400 9.46 409 340 8.04 348 600 9.50 610 520 12.29 532Florida Tallahassee 85 -3.00 82.00 210 -7.42 203 540 -12.79 527 400 -14.14 386 340 -12.01 328 600 -14.21 586 520 -18.38 502Florida Tampa 85 -4.78 80.22 210 -11.80 198 540 -20.34 520 400 -22.49 378 340 -19.11 321 600 -22.60 577 520 -29.23 491Georgia Atlanta 85 -3.66 81.34 210 -9.05 201 540 -15.59 524 400 -17.24 383 340 -14.65 325 600 -17.32 583 520 -22.41 498Hawaii Honolulu 85 -6.75 78.25 210 -16.66 193 540 -28.71 511 400 -31.74 368 340 -26.98 313 600 -31.90 568 520 -41.26 479Idaho Boise 85 -5.52 79.48 210 -13.64 196 540 -23.50 517 400 -25.98 374 340 -22.08 318 600 -26.11 574 520 -33.77 486Illinois Chicago 85 1.76 86.76 210 4.35 214 540 7.49 547 400 8.28 408 340 7.04 347 600 8.33 608 520 10.77 531Indiana Indianapolis 85 0.20 85.20 210 0.50 211 540 0.87 541 400 0.96 401 340 0.81 341 600 0.96 601 520 1.24 521Iowa Davenport 85 1.81 86.81 210 4.47 214 540 7.70 548 400 8.51 409 340 7.23 347 600 8.55 609 520 11.06 531Iowa Waterloo 85 2.02 87.02 210 4.98 215 540 8.58 549 400 9.48 409 340 8.06 348 600 9.53 610 520 12.33 532Kansas Wichita 85 -2.91 82.09 210 -7.19 203 540 -12.39 528 400 -13.70 386 340 -11.65 328 600 -13.77 586 520 -17.81 502Kentucky Louisville 85 -0.20 84.80 210 -0.50 210 540 -0.86 539 400 -0.95 399 340 -0.81 339 600 -0.96 599 520 -1.24 519Louisiana New Orleans 85 -3.26 81.74 210 -8.05 202 540 -13.87 526 400 -15.34 385 340 -13.03 327 600 -15.41 585 520 -19.94 500Maine Portland 85 4.72 89.72 210 11.66 222 540 20.08 560 400 22.20 422 340 18.87 359 600 22.31 622 520 28.86 549Maryland Baltimore 85 1.21 86.21 210 2.98 213 540 5.13 545 400 5.67 406 340 4.82 345 600 5.70 606 520 7.38 527Massachusetts Boston 85 2.92 87.92 210 7.20 217 540 12.41 552 400 13.72 414 340 11.66 352 600 13.79 614 520 17.84 538Michigan Detroit 85 2.03 87.03 210 5.00 215 540 8.62 549 400 9.53 410 340 8.10 348 600 9.58 610 520 12.39 532Michigan Grand Rapids 85 1.97 86.97 210 4.87 215 540 8.39 548 400 9.27 409 340 7.88 348 600 9.32 609 520 12.05 532Minnesota Saint Paul 85 2.00 87.00 210 4.95 215 540 8.52 549 400 9.42 409 340 8.01 348 600 9.47 609 520 12.25 532Mississippi Jackson 85 -2.95 82.05 210 -7.30 203 540 -12.58 527 400 -13.90 386 340 -11.82 328 600 -13.97 586 520 -18.08 502Missouri St. Louis 85 -0.40 84.60 210 -0.98 209 540 -1.68 538 400 -1.86 398 340 -1.58 338 600 -1.87 598 520 -2.42 518Missouri Kansas City 85 -1.23 83.77 210 -3.04 207 540 -5.23 535 400 -5.78 394 340 -4.92 335 600 -5.81 594 520 -7.52 512Montana Great Falls 85 -6.00 79.00 210 -14.81 195 540 -25.52 514 400 -28.21 372 340 -23.98 316 600 -28.35 572 520 -36.68 483Nebraska Omaha 85 0.15 85.15 210 0.36 210 540 0.62 541 400 0.68 401 340 0.58 341 600 0.69 601 520 0.89 521New Hampshire Concord 85 4.18 89.18 210 10.33 220 540 17.79 558 400 19.67 420 340 16.72 357 600 19.77 620 520 25.57 546New Jersey Newark 85 1.69 86.69 210 4.18 214 540 7.21 547 400 7.97 408 340 6.77 347 600 8.01 608 520 10.36 530New Mexico Albuquerque 85 -13.95 71.05 210 -34.46 176 540 -59.37 481 400 -65.64 334 340 -55.79 284 600 -65.97 534 520 -85.33 435New York New York 85 1.69 86.69 210 4.18 214 540 7.21 547 400 7.97 408 340 6.77 347 600 8.01 608 520 10.36 530New York Syracuse 85 3.06 88.06 210 7.56 218 540 13.03 553 400 14.41 414 340 12.25 352 600 14.48 614 520 18.73 539Nevada Las Vegas 85 -9.24 75.76 210 -22.82 187 540 -39.31 501 400 -43.46 357 340 -36.95 303 600 -43.68 556 520 -56.50 463North Carolina Charlotte 85 -2.41 82.59 210 -5.95 204 540 -10.26 530 400 -11.34 389 340 -9.64 330 600 -11.40 589 520 -14.74 505North Dakota Bismarck 85 1.02 86.02 210 2.53 213 540 4.36 544 400 4.82 405 340 4.09 344 600 4.84 605 520 6.26 526Ohio Cincinnati 85 1.45 86.45 210 3.58 214 540 6.16 546 400 6.81 407 340 5.79 346 600 6.85 607 520 8.85 529Oregon Portland 85 2.02 87.02 210 5.00 215 540 8.61 549 400 9.51 410 340 8.09 348 600 9.56 610 520 12.37 532Pennsylvania Philadelphia 85 1.88 86.88 210 4.65 215 540 8.00 548 400 8.85 409 340 7.52 348 600 8.89 609 520 11.50 532Pennsylvania Wilkes-Barre 85 1.07 86.07 210 2.64 213 540 4.55 545 400 5.03 405 340 4.27 344 600 5.05 605 520 6.54 527Rhode Island Providence 85 3.16 88.16 210 7.82 218 540 13.47 553 400 14.89 415 340 12.66 353 600 14.96 615 520 19.36 539South Carolina Spartanburg 85 -2.32 82.68 210 -5.73 204 540 -9.88 530 400 -10.92 389 340 -9.28 331 600 -10.98 589 520 -14.20 506South Dakota Rapid City 85 -5.15 79.85 210 -12.72 197 540 -21.91 518 400 -24.22 376 340 -20.59 319 600 -24.34 576 520 -31.49 489Tennessee Knoxville 85 -2.15 82.85 210 -5.32 205 540 -9.17 531 400 -10.14 390 340 -8.62 331 600 -10.19 590 520 -13.18 507Texas Houston 85 -3.46 81.54 210 -8.54 201 540 -14.71 525 400 -16.27 384 340 -13.83 326 600 -16.35 584 520 -21.15 499Utah Salt Lake City 85 -9.73 75.27 210 -24.03 186 540 -41.40 499 400 -45.77 354 340 -38.90 301 600 -46.00 554 520 -59.50 461Vermont Burlington 85 4.40 89.40 210 10.86 221 540 18.71 559 400 20.68 421 340 17.58 358 600 20.79 621 520 26.89 547Virginia Alexandria 85 0.27 85.27 210 0.66 211 540 1.14 541 400 1.26 401 340 1.07 341 600 1.26 601 520 1.63 522Virginia Lynchburg 85 -1.05 83.95 210 -2.59 207 540 -4.47 536 400 -4.94 395 340 -4.20 336 600 -4.96 595 520 -6.42 514Washington Seattle 85 1.10 86.10 210 2.72 213 540 4.68 545 400 5.18 405 340 4.40 344 600 5.20 605 520 6.73 527Washington Spokane 85 -2.90 82.10 210 -7.17 203 540 -12.35 528 400 -13.66 386 340 -11.61 328 600 -13.73 586 520 -17.75 502West Virginia Charleston 85 -1.21 83.79 210 -3.00 207 540 -5.16 535 400 -5.71 394 340 -4.85 335 600 -5.74 594 520 -7.42 513Wisconsin Green Bay 85 3.51 88.51 210 8.67 219 540 14.94 555 400 16.52 417 340 14.04 354 600 16.60 617 520 21.47 541Wyoming Cheyenne 85 -13.05 71.95 210 -32.24 178 540 -55.55 484 400 -61.42 339 340 -52.21 288 600 -61.7 538 520 -79.84 440Puerto Rico Cayey 85 -6.00 79.00 210 -14.83 195 540 -25.56 514 400 -28.25 372 340 -24.02 316 600 -28.40 572 520 -36.73 483Advanced - NGCC With CCS IGCC IGCC With CCSConventional CT Advanced CT Conventional NGCC Advanced - NGCC2-6 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

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 2010 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 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,2-7 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 22 provide more specific information related to Production-Related Non-Fuel O&M Expenses for each technology. Owner’s expenses, which are not addressed in this report, include expenses paid by plant owners that are plant specific and can vary significantly between two 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.2-8 2.6.2.1 Fixed O&M (FOM) FOM expenses are those expenses incurred at a power plant that do not vary significantly with generation and include the following categories:

• Staffing and monthly fees under pertinent operating agreements

• Typical bonuses paid to the given plant operator

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

• Plant-related general and 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

• 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 of2-9 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.2-10TABLE 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 3,167 35.97 4.250.1(6)0.06 206(7)Advanced Pulverized Coal Coal 1,300,000 8,800 2,844 29.67 4.250.1(6)0.06 206(7)Advanced Pulverized Coal withCCS Coal 650,000 12,000 5,099 76.62 9.050.02(8)0.06 20.6(9)Advanced Pulverized Coal withCCS Coal 1,300,000 12,000 4,579 63.21 9.050.02(8)0.06 20.6(9)NGCC Gas 540,000 7,050 978 14.39 3.430.001 0.0075(13)117(14)AG-NGCCGas 400,000 6,430 1,00314.62 3.11 0.001 0.0075(13)117(14)Advanced NGCC with CCSGas 340,000 7,525 2,06030.25 6.45 0.001 0.0075(13)12(15)Conventional CT Gas 85,000 10,850 974 6.98 14.700.001 0.03(12)117(14)Advanced CT Gas 210,000 9,750 665 6.70 9.870.001 0.03(13)117(14)IGCC Coal 600,000 8,700 3,565 59.23 6.870.025(10)0.0075(12)206(14)IGCC Coal 1,200,000 8,700 3,221 48.90 6.870.025(10)0.0075(12)206(14)IGCC with CCS Coal 520,000 10,700 5,348 69.30 8.040.015(11)0.0075(12)20.6(14)Advanced Nuclear Uranium 2,236,000 N/A 5,339 88.75 2.040 0 0Biomass Combined Cycle Biomass20,000 12,350 7,894 338.79 16.640 0.054 195(14)Biomass BFB Biomass 50,00013,500 3,860 100.50 5.000 0.08 195(14)Fuel Cells Gas 10,000 9,500 6,835 350 00.00013 0.013 130Geothermal – Dual Flash Geothermal 50,000 N/A 5,578 84.27 9.640.2(16)0 120(17)Geothermal – Binary Geothermal50,000 N/A 4,141 84.27 9.640.2(16)0 120(17)MSW MSW 50,000 18,000 8,232 373.76 8.330.07(18)0.27(19)200Hydroelectric Hydro 500,000 N/A 3,076 13.44 00 0 0Pumped Storage Hydro 250,000 N/A 5,595 13.03 00 0 0Onshore Wind Wind 100,000 N/A 2,438 28.07 00 0 0Offshore Wind Wind 400,000 N/A 5,975 53.33 00 0 0Solar Thermal Solar 100,000 N/A 4,692 64.00 00 0 0Photovoltaic Solar 7,000 N/A 6,050 26.04 00 0 0Photovoltaic Solar 150,000 N/A 4,755 16.70 00 0 0Footnotes 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. Emissi on rate could be lower for sub-bituminous fuel. (8) From greenhouse gas (“GHG”) Reporting Rule for Bituminous Coal. (9) SO 2 emission rates are lower than in the non-capt ure case to avoid reagent contamination. (10) Assuming 90 percent capture. (11) Assuming 3 percent sulfur coal at 12, 000 British thermal units pe r pound (“Btu/lb”) and a 99.5 percent sulfur removal rate

. (12) Assuming 3 percent sulfur coal at 12,000 Bt u/lb and a 99.7 percen t sulfur removal rate. (13) Assuming 9 parts per million volume dry (“ppmvd”) corrected to 15 percent O 2 ; simple-cycle E-Class or F-Class engine. (14) Assuming 2 ppmvd corrected to 15 percent O 2 for F-Class engine. Assumes deve lopment of SCR for IGCC with CCS. (15) From GHG Reporting Rule for Pipeline Natural Gas. (16) Assuming 90 percent capture. (17) Reported as pounds per MWh and as H 2 S – actual will vary with resource. (18) Reported as pounds per MWh – actual will vary with resource. (19) Based on 30 ppmvd at 7 percent O 2 – 5,000 Btu/lb HHV of MSW. (20) Based on 150 ppmvd at 7 percent O 2 - 5,000 Btu/lb HHV of MSW.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 connection to an adjacent utility substation, a ssumed to be no more than 1 mile from the Advanced Pulverized Coal Facility.3-3 3.4 CAPITAL COST ESTIMATE

The base Cost Estimate for the Advanced Pulver ized Coal Facility (“APC”) with a nominal capacity of 650 MW is $3,167/kilowatt (“kW”) a nd with a nominal capacity of 1,300 MW is $2,844/kW. Table 3-1 and Table 3-2 summarize the Cost Estimate categories for the APC Facility.

TABLE 3-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR APC Technology: APC Nominal Capacity (ISO): 650,000 kW Nominal Heat Rate (ISO): 8,800 Btu/kWh-HHV

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

Civil Structural Material and Installation 224,000

Mechanical Equipment Supply and Installation 838,500

Electrical / I&C Supply and Installation 123,000

Project Indirects (1) 350,000

EPC Cost before Contingency and Fee 1,535,500

Fee and Contingency 180,000

Total Project EPC 1,715,500

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

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

Total Project EPC $ / kW 2,639

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

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

(1) Includes engineering, distributable costs, 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, 2010$)

Civil Structural Material and Installation 397,250

Mechanical Equipment Supply and Installation 1,596,100

Electrical / I&C Supply and Installation 235,000

Project Indirects (1) 584,750

EPC Cost before Contingency and Fee 2,813,100

Fee and Contingency 320,000

Total Project EPC 3,133,100

Owner Costs (excluding project finance) 563,958

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

Total Project EPC $ / kW 2,410

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

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

(1) Includes engineering, distributable costs, 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, Arizona, Arkansas , Florida, Georgia, Hawaii, Louisiana, Mississippi, New Mexico, S outh 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 4.3-5 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; 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 show the APC capital cost variations for a lternative U.S. plant locations, including the difference between the given loca tion and the average location specified for the Cost Estimate.

TABLE 3-3 – LOCATION-BASE D COSTS FOR APC (650,000 KW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW)

Alaska Anchorage 3,200 33.1% 1,058 4,258 Alaska Fairbanks 3,200 32.0% 1,026 4,226 Alabama Huntsville 3,200 -7.5% (239) 2,961 Arizona Phoenix 3,200 -5.2% (166) 3,034 Arkansas Little Rock 3,200 -5.4% (174) 3,026 California Los Angeles 3,200 20.3% 649 3,849 California Redding 3,200 9.8% 314 3,514 California Bakersfield 3,200 9.4% 300 3,500 California Sacramento 3,200 14.4% 462 3,662 California San Francisco 3,200 42.4% 1,356 4,556 Colorado Denver 3,200 -6.1% (194) 3,006 Connecticut Hartford 3,200 26.6% 851 4,051 Delaware Dover 3,200 23.0% 736 3,936 District of Columbia Washi ngton 3,200 39.6% 1,267 4,467 Florida Tallahassee 3,200 -10.9% (349) 2,851 Florida Tampa 3,200 -4.9% (156) 3,044 Georgia Atlanta 3,200 -8.1% (260) 2,940 Hawaii Honolulu 0 0 0 0 Idaho Boise 3,200 -3.7% (118) 3,082 Illinois Chicago 3,200 19.8% 635 3,835 Indiana Indianapolis 3,200 3.2% 102 3,3023-6 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Iowa Davenport 3,200 -1.6% (50) 3,150 Iowa Waterloo 3,200 -9.0% (288) 2,912 Kansas Wichita 3,200 -6.7% (215) 2,985 Kentucky Louisville 3,200 -5.6% (178) 3,022 Louisiana New Orleans 3,200 -11.2% (359) 2,841 Maine Portland 3,200 -0.6% (21) 3,179 Maryland Baltimore 3,200 4.6% 148 3,348 Massachusetts Boston 3,200 35.3% 1,128 4,328 Michigan Detroit 3,200 3.8% 123 3,323 Michigan Grand Rapids 3,200 -7.9% (251) 2,949 Minnesota St. Paul 3,200 3.9% 125 3,325 Mississippi Jackson 3,200 -7.4% (238) 2,962 Missouri St. Louis 3,200 7.2% 231 3,431 Missouri Kansas City 3,200 3.4% 109 3,309 Montana Great Falls 3,200 -4.3% (137) 3,063 Nebraska Omaha 3,200 -3.5% (113) 3,087 New Hampshire Concord 3,200 -1.6% (52) 3,148 New Jersey Newark 3,200 15.5% 495 3,695 New Mexico Albuquerque 3,200 -3.9% (125) 3,075 New York New York 3,200 32.6% 1,044 4,244 New York Syracuse 3,200 10.7% 342 3,542 Nevada Las Vegas 3, 200 9.2% 295 3,495 North Carolina Charlotte 3,200 -9.6% (308) 2,892 North Dakota Bismarck 3,200 -8.0% (255) 2,945 Ohio Cincinnati 3,200 0.3% 11 3,211 Oregon Portland 3,200 9.5% 305 3,505 Pennsylvania Philadelphia 3,200 12.1% 387 3,587 Pennsylvania Wilkes-Barre 3,200 -3.5% (112) 3,088 Rhode Island Providenc e 3,200 4.1% 132 3,332 South Carolina Spartanburg 3,200 -11.8% (377) 2,823 South Dakota Rapid City 3, 200 -10.7% (342) 2,858 Tennessee Knoxville 3,200 -8.9% (286) 2,914 Texas Houston 3,200 -9.5% (304) 2,896 Utah Salt Lake City 3,200 -3.1% (98) 3,102 Vermont Burlington 3,200 -5.3% (169) 3,031 Virginia Alexandria 3,200 9.7% 310 3,510 Virginia Lynchburg 3,200 -2.0% (62) 3,138 Washington Seattle 3,200 12.8% 409 3,609 Washington Spokane 3,200 -2.3% (74) 3,126 West Virginia Charleston 3,200 -1.8% (58) 3,142 Wisconsin Green Bay 3,200 0.5% 16 3,216 Wyoming Cheyenne 3,200 3.9% 125 3,325 Puerto Rico Cayey 0 0 0 03-7 TABLE 3-4 – LOCATION-BASE D COSTS FOR APC (1,300,000 KW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW)

Alaska Anchorage 2,850 36.5% 1,040 3,890 Alaska Fairbanks 2,850 35.3% 1,006 3,856 Alabama Huntsville 2,850 -8.2% (233) 2,617 Arizona Phoenix 2,850 -5.7% (161) 2,689 Arkansas Little Rock 2,850 -5.9% (169) 2,681 California Los Angeles 2,850 22.4% 638 3,488 California Redding 2,850 10.7% 306 3,156 California Bakersfield 2,850 10.3% 293 3,143 California Sacramento 2,850 15.7% 447 3,297 California San Francisco 2,850 46.7% 1,330 4,180 Colorado Denver 2,850 -6.6% (188) 2,662 Connecticut Hartford 2,850 29.4% 838 3,688 Delaware Dover 2,850 25.5% 728 3,578 District of Columbia Washi ngton 2,850 44.4% 1,265 4,115 Florida Tallahassee 2,850 -11.9% (339) 2,511 Florida Tampa 2,850 -5.4% (154) 2,696 Georgia Atlanta 2,850 -8.9% (253) 2,597 Hawaii Honolulu 0 0 0 0 Idaho Boise 2,850 -4.0% (115) 2,735 Illinois Chicago 2,850 21.3% 606 3,456 Indiana Indianapolis 2,850 3.5% 99 2,949 Iowa Davenport 2,850 -1.8% (53) 2,797 Iowa Waterloo 2,850 -9.8% (280) 2,570 Kansas Wichita 2,850 -7.3% (209) 2,641 Kentucky Louisville 2,850 -6.1% (173) 2,677 Louisiana New Orleans 2,850 -12.2% (348) 2,502 Maine Portland 2,850 -0.6% (16) 2,834 Maryland Baltimore 2,850 5.3% 150 3,000 Massachusetts Boston 2,850 38.7% 1,103 3,953 Michigan Detroit 2,850 4.0% 114 2,964 Michigan Grand Rapids 2,850 -8.6% (244) 2,606 Minnesota St. Paul 2,850 4.1% 116 2,966 Mississippi Jackson 2,850 -8.1% (231) 2,619 Missouri St. Louis 2,850 7.7% 221 3,071 Missouri Kansas City 2,850 3.5% 101 2,951 Montana Great Falls 2,850 -4.7% (133) 2,717 Nebraska Omaha 2,850 -3.9% (111) 2,739 New Hampshire Concord 2,850 -1.8% (52) 2,798 New Jersey Newark 2,850 16.4% 467 3,317 New Mexico Albuquerque 2,850 -4.3% (122) 2,728 New York New York 2,850 34.8% 992 3,842 New York Syracuse 2,850 12.0% 341 3,191 Nevada Las Vegas 2, 850 9.9% 282 3,132 North Carolina Charlotte 2,850 -10.4% (296) 2,554 North Dakota Bismarck 2,850 -8.7% (248) 2,602 Ohio Cincinnati 2,850 0.5% 13 2,863 Oregon Portland 2,850 10.4% 297 3,147 Pennsylvania Philadelphia 2,850 12.9% 366 3,216 Pennsylvania Wilkes-Barre 2,850 -3.8% (109) 2,7413-8 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Rhode Island Providenc e 2,850 4.3% 123 2,973 South Carolina Spartanburg 2,850 -12.7% (363) 2,487 South Dakota Rapid City 2, 850 -11.6% (331) 2,519 Tennessee Knoxville 2,850 -9.7% (276) 2,574 Texas Houston 2,850 -10.3% (295) 2,555 Utah Salt Lake City 2,850 -3.3% (93) 2,757 Vermont Burlington 2,850 -5.8% (164) 2,686 Virginia Alexandria 2,850 10.9% 310 3,160 Virginia Lynchburg 2,850 -2.0% (57) 2,793 Washington Seattle 2,850 13.9% 397 3,247 Washington Spokane 2,850 -2.6% (73) 2,777 West Virginia Charleston 2,850 -2.1% (59) 2,791 Wisconsin Green Bay 2,850 0.6% 16 2,866 Wyoming Cheyenne 2,850 4.6% 131 2,981 Puerto Rico Cayey 0 0 0 0

3.5 O&M ESTIMATE In addition to the general O&M items discussed in Section 2.5.2., the APC Facility includes the major maintenance for boiler, ST, associated 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 $35.97/kW-year Variable O&M Expense $4.25/MWh TABLE 3-6 – O&M EXPENSES FOR APC (1,300,000 KW) Technology: APC Fixed O&M Expense $29.67/kW-year Variable O&M Expense $4.25/MWh

3.6 ENVIRONMENTAL 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 emissions of NO X and SO 2 , respectively. Table 3-7 presents the environmental emissions for the APC Facility.3-9 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/MMBtu4-1 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 DIAGRAM4-2 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 $5,099/kW and with a nominal capacity of 1,300,000 MW is $4,579/kW. The capital cost estimate was based on the advanced pulverized APC Facility (without CCS) and the base Cost Estimate was increased to include the expected 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, 2010$)

Total Project EPC 2,761,958

Owner Costs (excluding project finance) 552,391

Total Project Cost (excluding finance) 3,314,350

Total Project EPC / kW 4,249

Owner Costs 20% (excluding project finance) / kW 850

Total Project Cost (excluding project finance) / kW 5,099

(1) Includes engineering, distributable costs, 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, 2010$)

Total Project EPC 5,045,763

Owner Costs (excluding project finance) 908,237

Total Project Cost (excluding finance) 5,954,000

Total Project EPC / kW 3,881

Owner Costs 18% (excluding project finance) / kW 699

Total Project Cost (excluding project finance) / kW 4,580

(1) Includes engineering, distributable costs, 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. The4-4 methodology used for the APC/CCS Facility is the same as that discussed in Section 3.4 for the APC Facility (without CCS).

Table 4-3 and Table 4-4 show the APC capital cost variations for a lternative U.S. plant locations, including the difference between the given loca tion and the average location specified for the Cost Estimate.

TABLE 4-3– LOCATION-BASED COSTS FOR APC/CCS FACILITY (650,000 KW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 5,100 32.2% 1,643 6,743 Alaska Fairbanks 5,100 31.4% 1,602 6,702 Alabama Huntsville 5,100 -8.0% (409) 4,691 Arizona Phoenix 5,100 -5.7% (289) 4,811 Arkansas Little Rock 5,100 -5.9% (303) 4,797 California Los Angeles 5,100 19.6% 1,000 6,100 California Redding 5,100 9.4% 481 5,581 California Bakersfield 5,100 9.0% 458 5,558 California Sacramento 5,100 14.4% 734 5,834 California San Francisco 5,100 41.6% 2,124 7,224 Colorado Denver 5,100 -6.6% (335) 4,765 Connecticut Hartford 5,100 25.6% 1,306 6,406 Delaware Dover 5,100 21.9% 1,116 6,216

District of Columbia Washi ngton 5,100 37.0% 1,888 6,988 Florida Tallahassee 5,100 -11.6% (591) 4,509 Florida Tampa 5,100 -5.1% (262) 4,838 Georgia Atlanta 5,100 -8.7% (445) 4,655

Hawaii Honolulu 0 0 0 0 Idaho Boise 5,100 -4.1% (211) 4,889 Illinois Chicago 5,100 20.7% 1,055 6,155 Indiana Indianapolis 5,100 2.8% 141 5,241 Iowa Davenport 5,100 -1.7% (85) 5,015 Iowa Waterloo 5,100 -9.6% (491) 4,609 Kansas Wichita 5,100 -7.3% (372) 4,728 Kentucky Louisville 5,100 -6.1% (309) 4,791 Louisiana New Orleans 5,100 -11.9% (608) 4,492 Maine Portland 5,100 -1.4% (72) 5,028 Maryland Baltimore 5,100 3.8% 195 5,295 Massachusetts Boston 5,100 34.9% 1,779 6,879 Michigan Detroit 5,100 4.0% 204 5,304 Michigan Grand Rapids 5,100 -8.4% (428) 4,672 Minnesota St. Paul 5,100 4.0% 206 5,306 Mississippi Jackson 5,100 -8.0% (406) 4,694 Missouri St. Louis 5,100 7.2% 366 5,4664-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Missouri Kansas City 5,100 3.4% 174 5,274 Montana Great Falls 5,100 -4.8% (244) 4,856 Nebraska Omaha 5,100 -3.9% (197) 4,903 New Hampshire Concord 5,100 -2.0% (100) 5,000 New Jersey Newark 5,100 16.4% 837 5,937 New Mexico Albuquerque 5,100 -4.4% (222) 4,878 New York New York 5,100 34.7% 1,768 6,868 New York Syracuse 5,100 8.5% 433 5,533 Nevada Las Vegas 5, 100 7.5% 382 5,482 North Carolina Charlotte 5,100 -10.5% (534) 4,566 North Dakota Bismarck 5,100 -8.5% (434) 4,666 Ohio Cincinnati 5,100 -0.3% (13) 5,087 Oregon Portland 5,100 9.1% 466 5,566 Pennsylvania Philadelphia 5,100 12.7% 649 5,749 Pennsylvania Wilkes-Barre 5,100 -3.9% (201) 4,899

Rhode Island Providenc e 5,100 4.2% 214 5,314 South Carolina Spartanburg 5,100 -12.7% (649) 4,451 South Dakota Rapid City 5, 100 -11.4% (583) 4,517 Tennessee Knoxville 5,100 -9.6% (492) 4,608 Texas Houston 5,100 -10.2% (518) 4,582 Utah Salt Lake City 5,100 -3.8% (194) 4,906 Vermont Burlington 5,100 -5.9% (299) 4,801 Virginia Alexandria 5,100 8.7% 443 5,543 Virginia Lynchburg 5,100 -2.7% (138) 4,962 Washington Seattle 5,100 12.6% 644 5,744 Washington Spokane 5,100 -2.7% (136) 4,964 West Virginia Charleston 5,100 -2.0% (103) 4,997 Wisconsin Green Bay 5,100 0.0% 0 5,100 Wyoming Cheyenne 5,100 1.4% 74 5,174 Puerto Rico Cayey 0 0 0 04-6 TABLE 4-4 – LOCATION-BASED COSTS FOR APC/CCS FACILITY (1,300,000 KW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 4,580 35.2% 1,610 6,190 Alaska Fairbanks 4,580 34.2% 1,565 6,145 Alabama Huntsville 4,580 -8.3% (380) 4,200 Arizona Phoenix 4,580 -5.8% (266) 4,314 Arkansas Little Rock 4,580 -6.1% (278) 4,302 California Los Angeles 4,580 21.5% 985 5,565 California Redding 4,580 10.4% 475 5,055 California Bakersfield 4,580 9.9% 453 5,033 California Sacramento 4,580 15.5% 710 5,290 California San Francisco 4,580 45.2% 2,071 6,651 Colorado Denver 4,580 -6.7% (309) 4,271 Connecticut Hartford 4,580 28.1% 1,288 5,868 Delaware Dover 4,580 24.2% 1,109 5,689

District of Columbia Washi ngton 4,580 41.4% 1,895 6,475 Florida Tallahassee 4,580 -12.1% (552) 4,028 Florida Tampa 4,580 -5.4% (245) 4,335 Georgia Atlanta 4,580 -9.0% (413) 4,167

Hawaii Honolulu 0 0 0 0 Idaho Boise 4,580 -4.2% (191) 4,389 Illinois Chicago 4,580 21.7% 995 5,575 Indiana Indianapolis 4,580 3.2% 148 4,728 Iowa Davenport 4,580 -1.7% (79) 4,501 Iowa Waterloo 4,580 -10.0% (457) 4,123 Kansas Wichita 4,580 -7.5% (343) 4,237 Kentucky Louisville 4,580 -6.2% (284) 4,296 Louisiana New Orleans 4,580 -12.4% (567) 4,013 Maine Portland 4,580 -1.1% (48) 4,532 Maryland Baltimore 4,580 4.6% 211 4,791 Massachusetts Boston 4,580 37.7% 1,728 6,308 Michigan Detroit 4,580 4.2% 193 4,773 Michigan Grand Rapids 4,580 -8.7% (398) 4,182 Minnesota St. Paul 4,580 4.3% 195 4,775 Mississippi Jackson 4,580 -8.2% (377) 4,203 Missouri St. Louis 4,580 7.7% 354 4,934 Missouri Kansas City 4,580 3.7% 168 4,748 Montana Great Falls 4,580 -4.8% (222) 4,358 Nebraska Omaha 4,580 -3.9% (180) 4,400 New Hampshire Concord 4,580 -1.9% (87) 4,493 New Jersey Newark 4,580 17.1% 781 5,3614-7 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 4,580 -4.4% (202) 4,378 New York New York 4,580 36.0% 1,650 6,230 New York Syracuse 4,580 9.7% 442 5,022 Nevada Las Vegas 4, 580 7.9% 361 4,941 North Carolina Charlotte 4,580 -10.7% (492) 4,088 North Dakota Bismarck 4,580 -8.8% (404) 4,176 Ohio Cincinnati 4,580 0.1% 4 4,584 Oregon Portland 4,580 10.1% 461 5,041 Pennsylvania Philadelphia 4,580 13.3% 609 5,189 Pennsylvania Wilkes-Barre 4,580 -4.0% (182) 4,398

Rhode Island Providenc e 4,580 4.5% 205 4,785 South Carolina Spartanburg 4,580 -13.1% (600) 3,980 South Dakota Rapid City 4, 580 -11.8% (542) 4,038 Tennessee Knoxville 4,580 -9.9% (455) 4,125 Texas Houston 4,580 -10.5% (482) 4,098 Utah Salt Lake City 4,580 -3.6% (167) 4,413 Vermont Burlington 4,580 -6.0% (273) 4,307 Virginia Alexandria 4,580 9.9% 455 5,035 Virginia Lynchburg 4,580 -2.4% (112) 4,468 Washington Seattle 4,580 13.7% 626 5,206 Washington Spokane 4,580 -2.6% (121) 4,459 West Virginia Charleston 4,580 -2.0% (93) 4,487 Wisconsin Green Bay 4,580 0.3% 14 4,594 Wyoming Cheyenne 4,580 2.2% 102 4,682 Puerto Rico Cayey 0 0 0 0

4.5 O&M ESTIMATE The O&M items for the APC/CCS Facility are the same as those discussed in Section 3.5 for the APC Facility (without CCS), except that 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 $76.62/kW-year Variable O&M Expense $9.05/MWh4-8 TABLE 4-6 – O&M EXPENSES FOR APC/CCS (1,300,000 KW) Technology: APC/CCS Fixed O&M Expense $63.21/kW-year Variable O&M Expense $9.05/MWh

4.6 ENVIRONMENTAL 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 – ENVIRONMENTAL EMISSIONS FOR APC/CCS Technology: APC/CCS NO X 0.06 lb/MMBtu SO 2 0.02 lb/MMBtu CO 2 20.6 lb/MMBtu5-1 5. CONVENTIONAL NATURAL GAS COMBINED CYCLE (NGCC)

5.1 MECHANICAL EQUIPM ENT AND SYSTEMS The Conventional NGCC produces 540 MW of net elec tricity. The facility utilizes two natural gas-fueled F-class CTs and associated electric ge nerators, 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 172 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 the5-3 dissolved solids from the cooling water and to provide distilled wate r for HRSG makeup. 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 540 MW is $980/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): 540,000 kW Nominal Heat Rate (ISO): 7,050 Btu/kWh-HHV

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

Civil Structural Material and Installation 40,100

Mechanical Equipment Supply and Installation 221,500

Electrical / I&C Supply and Installation 35,000

Project Indirects (1) 88,400

EPC Cost before Contingency and Fee 385,000

Fee and Contingency 55,000

Total Project EPC 440,000

Owner Costs (excluding project finance) 88,000

Total Project Cost (excluding finance) 528,000

Total Project EPC / kW 815

Owner Costs 20% (excluding project finance) / kW 163

Total Project Cost (excluding project finance) / kW 978

(1) Includes engineering, distributable costs, 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 condensers5-4 compared to cooling towers, seismic design differences, zero-water discharge issues, local 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, Rhode Island, Virginia , and Puerto Rico. Similar to water usage discussed above in this section on Conventional NGCC, wastewater treatment and disposal is considered a critical permitting/siting issue in these areas.

The locations with 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, Minnesota, New York, 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 presents the Conventional NGCC capital cost variations for alternative U.S. plant locations, including the difference between the given location and the average location specified for the Cost Estimate.

TABLE 5-2 – LOCATION-BASED CO STS FOR CONVENTIONAL NGCC (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 980 33.3% 326 1,306 Alaska Fairbanks 980 38.2% 374 1,354 Alabama Huntsville 980 -8.6% (84) 896 Arizona Phoenix 980 2.6% 25 1,005 Arkansas Little Rock 980 -7.5% (73) 912 California Los Angeles 980 29.0% 284 1,264 California Redding 980 13.5% 132 1,112 California Bakersfield 980 15.8% 154 1,134 California Sacramento 980 20.5% 200 1,180 California San Francisco 980 46.1% 452 1,432 Colorado Denver 980 2.1% 21 1,001 Connecticut Hartford 980 27.9% 274 1,254 Delaware Dover 980 26.2% 256 1,236 District of Columbia Washington 980 33.3% 326 1,306 Florida Tallahassee 980 -11.6% (113) 867 Florida Tampa 980 -6.0% (58) 922 Georgia Atlanta 980 -6.6% (64) 916 Hawaii Honolulu 980 50.2% 492 1,472 Idaho Boise 980 -3.9% (38) 942 Illinois Chicago 980 16.7% 163 1,143 Indiana Indianapolis 980 0.9% 9 989 Iowa Davenport 980 0.5% 5 985 Iowa Waterloo 980 -6.4% (63) 917 Kansas Wichita 980 -5.0% (49) 936 Kentucky Louisville 980 -5.4% (53) 927 Louisiana New Orleans 980 -5.2% (51) 929 Maine Portland 980 -3.4% (33) 952 Maryland Baltimore 980 20.4% 200 1,180 Massachusetts Boston 980 40.0% 392 1,372 Michigan Detroit 980 5.3% 52 1,032 Michigan Grand Rapids 980 -5.3% (52) 928 Minnesota St. Paul 980 4.5% 44 1,024 Mississippi Jackson 980 -8.6% (84) 8965-6 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Missouri St. Louis 980 5.6% 55 1,035 Missouri Kansas City 980 2.7% 27 1,007 Montana Great Falls 980 -2.4% (24) 956 Nebraska Omaha 980 -1.5% (15) 965 New Hampshire Concord 980 7.3% 72 1,052 New Jersey Newark 980 22.1% 217 1,197 New Mexico Albuquerque 980 -2.4% (24) 956 New York New York 980 68.4% 670 1,650 New York Syracuse 980 16.3% 160 1,140 Nevada Las Vegas 980 6.2% 61 1,041 North Carolina Charlotte 980 -10.5% (102) 888 North Dakota Bismarck 980 -5.4% (53) 927 Ohio Cincinnati 980 -1.7% (17) 963 Oregon Portland 980 13.2% 130 1,110 Pennsylvania Philadelphia 980 26.1% 255 1,235 Pennsylvania Wilkes-Barre 980 -1.7% (17) 963 Rhode Island Providence 980 22.0% 215 1,195 South Carolina Spartanburg 980 -12.8% (126) 854 South Dakota Rapid City 980 -8.0% (78) 902 Tennessee Knoxville 980 -8.5% (84) 896 Texas Houston 980 -8.8% (87) 893 Utah Salt Lake City 980 -4.0% (39) 941 Vermont Burlington 980 -0.1% (1) 979 Virginia Alexandria 980 16.0% 157 1,137 Virginia Lynchburg 980 -5.8% (57) 923 Washington Seattle 980 7.0% 68 1,048 Washington Spokane 980 -2.6% (25) 955 West Virginia Charleston 980 0.1% 1 981 Wisconsin Green Bay 980 -1.3% (13) 967 Wyoming Cheyenne 980 -0.5% (4) 976 Puerto Rico Cayey 980 10.9% 106 1,086

5.5 O&M ESTIMATE In addition to the general O&M items 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 24,000 operating hour in tervals. Table 5-3 presents the O&M expenses for the Conventional NGCC Facility.5-7 TABLE 5-3 – O&M EXPENSES FOR CONVENTIONAL NGCC Technology: Conventional NGCC Fixed O&M Expense $14.39/kW-year Variable O&M Expense $3.43/MWh

5.6 ENVIRONMENTAL 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/MMBtu6-1 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 employees steam cooling of both stationary and rotational hot parts, the HRSG systems and the ST are both considered “advanced” designs, as compared to the Conventional NGCC. The net output of th e AG-NGCC is 400 MW. Fi gure 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.

6.4 CAPITAL COST ESTIMATE

The base Cost Estimate for the AG-NGCC Faci lity with a nominal capacity of 400 MW is $1,003/kW. Table 6-1 summarizes the Cost Estimate categories for the Conventional NGCC Facility.6-2 TABLE 6-1 – BASE PLANT SITE 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, 2010$)

Civil Structural Material and Installation 20,610

Mechanical Equipment Supply and Installation 178,650

Electrical / I&C Supply and Installation 24,800

Project Indirects (1) 68,300

EPC Cost before Contingency and Fee 292,360

Fee and Contingency 42,000

Total Project EPC 334,360

Owner Costs (excluding project finance) 66,872

Total Project Cost (excluding finance) 401,232

Total Project EPC / kW 836

Owner Costs 20% (excluding project finance) / kW 167

Total Project Cost (excluding project finance) / kW 1,003

(1) Includes engineering, distributable costs, 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 presents the AG-NGCC Facility capital cost variations for alternative U.S. plant locations, including the difference between the given location and the average location specified for the Cost Estimate.6-3 TABLE 6-2 – LOCATION-BASE D COSTS FOR AG-NGCC (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 1,005 32.4% 325 1,330 Alaska Fairbanks 1,005 37.2% 374 1,379 Alabama Huntsville 1,005 -8.3% (84) 921 Arizona Phoenix 1,005 2.6% 26 1,031 Arkansas Little Rock 1,005 -6.7% (67) 938 California Los Angeles 1,005 28.2% 283 1,288 California Redding 1,005 13.1% 132 1,137 California Bakersfield 1,005 15.4% 154 1,159 California Sacramento 1,005 19.9% 200 1,205 California San Francisco 1,005 44.9% 451 1,456 Colorado Denver 1,005 2.1% 21 1,026 Connecticut Hartford 1,005 27.2% 273 1,278 Delaware Dover 1,005 25.5% 256 1,261

District of Columbia Wash ington 1,005 32.5% 326 1,331 Florida Tallahassee 1,005 -11.2% (113) 892 Florida Tampa 1,005 -5.8% (58) 947 Georgia Atlanta 1,005 -6.3% (64) 941 Hawaii Honolulu 1,005 48.9% 492 1,497 Idaho Boise 1,005 -3.7% (38) 967 Illinois Chicago 1,005 16.1% 162 1,167 Indiana Indianapolis 1,005 0.9% 9 1,014 Iowa Davenport 1,005 0.5% 5 1,010 Iowa Waterloo 1,005 -6.2% (62) 943 Kansas Wichita 1,005 -4.3% (43) 962 Kentucky Louisville 1,005 -5.2% (52) 953 Louisiana New Orleans 1,005 -5.0% (50) 955 Maine Portland 1,005 -2.7% (27) 978 Maryland Baltimore 1,005 19.9% 200 1,205 Massachusetts Boston 1,005 38.9% 391 1,396 Michigan Detroit 1,005 5.2% 52 1,057 Michigan Grand Rapids 1,005 -5.1% (51) 954 Minnesota St. Paul 1,005 4.4% 44 1,049 Mississippi Jackson 1,005 -8.3% (83) 922 Missouri St. Louis 1,005 5.4% 54 1,059 Missouri Kansas City 1,005 2.6% 26 1,031 Montana Great Falls 1,005 -2.3% (24) 981 Nebraska Omaha 1,005 -1.4% (14) 991 New Hampshire Concord 1,005 7.2% 72 1,077 New Jersey Newark 1,005 21.4% 215 1,220 New Mexico Albuquerque 1,005 -2.3% (23) 9826-4 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New York New York 1,005 66.4% 667 1,672 New York Syracuse 1,005 15.9% 160 1,165 Nevada Las Vegas 1, 005 6.0% 61 1,066 North Carolina Charlotte 1,005 -9.1% (91) 914 North Dakota Bismarck 1,005 -5.2% (52) 953 Ohio Cincinnati 1,005 -1.6% (16) 989 Oregon Portland 1,005 12.9% 130 1,135 Pennsylvania Philadelphia 1,005 25.3% 254 1,259 Pennsylvania Wilkes-Barre 1,005 -1.6% (16) 989

Rhode Island Providenc e 1,005 21.4% 215 1,220 South Carolina Spartanburg 1,005 -12.4% (125) 880 South Dakota Rapid City 1,005 -7.7% (77) 928 Tennessee Knoxville 1,005 -8.2% (83) 922 Texas Houston 1,005 -8.5% (86) 919 Utah Salt Lake City 1,005 -3.8% (38) 967 Vermont Burlington 1,005 0.0% (0) 1,005 Virginia Alexandria 1,005 15.6% 157 1,162 Virginia Lynchburg 1,005 -5.6% (56) 949 Washington Seattle 1,005 6.8% 68 1,073 Washington Spokane 1,005 -2.5% (25) 980 West Virginia Charleston 1,005 0.1% 1 1,006 Wisconsin Green Bay 1,005 -1.3% (13) 992 Wyoming Cheyenne 1,005 -0.4% (4) 1,001 Puerto Rico Cayey 1,005 10.6% 107 1,112

6.5 O&M ESTIMATE The O&M items for the AG-NGCC Facility are 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 $14.62/kW-year Variable O&M Expense $3.11/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.6-5 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/MMBtu7-1 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 $2,060/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

Total Project EPC 583,667

Owner Costs (excluding project finance) 116,733

Total Project Cost (excluding finance) 700,400

Total Project EPC / kW 1,717

Owner Costs 20% (excluding project finance) / kW 343

Total Project Cost (excluding project finance) / kW 2,060

(1) Includes engineering, distributable costs, 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 presents the AG-NGCC/CCS Facility capital cost variations for alternative U.S. plant locations, including the difference between the given location and the average location specified for the Cost Estimate.7-3 TABLE 7-2 – LOCATION-BASED COSTS FOR AG-NGCC/CCS (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 2,060 20.8% 428 2,488 Alaska Fairbanks 2,060 23.7% 488 2,548 Alabama Huntsville 2,060 -8.5% (174) 1,886 Arizona Phoenix 2,060 -2.3% (47) 2,013 Arkansas Little Rock 2,060 -7.0% (143) 1,917 California Los Angeles 2,060 16.1% 331 2,391 California Redding 2,060 7.4% 152 2,212 California Bakersfield 2,060 8.2% 169 2,229 California Sacramento 2,060 13.3% 274 2,334 California San Francisco 2,060 29.8% 615 2,675 Colorado Denver 2,060 -2.9% (60) 2,000 Connecticut Hartford 2,060 15.9% 328 2,388 Delaware Dover 2,060 13.5% 278 2,338

District of Columbia Wash ington 2,060 14.8% 305 2,365 Florida Tallahassee 2,060 -11.4% (234) 1,826 Florida Tampa 2,060 -5.3% (108) 1,952 Georgia Atlanta 2,060 -7.9% (162) 1,898 Hawaii Honolulu 2,060 26.8% 551 2,611 Idaho Boise 2,060 -4.9% (100) 1,960 Illinois Chicago 2,060 16.9% 348 2,408 Indiana Indianapolis 2,060 -0.5% (11) 2,049 Iowa Davenport 2,060 -0.6% (13) 2,047 Iowa Waterloo 2,060 -8.2% (168) 1,892 Kansas Wichita 2,060 -6.4% (132) 1,928 Kentucky Louisville 2,060 -6.2% (127) 1,933 Louisiana New Orleans 2,060 -8.5% (175) 1,885 Maine Portland 2,060 -4.9% (102) 1,958 Maryland Baltimore 2,060 7.3% 150 2,210 Massachusetts Boston 2,060 26.6% 547 2,607 Michigan Detroit 2,060 4.3% 88 2,148 Michigan Grand Rapids 2,060 -7.0% (144) 1,916 Minnesota St. Paul 2,060 3.7% 76 2,136 Mississippi Jackson 2,060 -8.4% (173) 1,887 Missouri St. Louis 2,060 4.4% 91 2,151 Missouri Kansas City 2,060 2.3% 47 2,107 Montana Great Falls 2,060 -4.5% (93) 1,967 Nebraska Omaha 2,060 -3.2% (65) 1,995 New Hampshire Concord 2,060 1.6% 34 2,094 New Jersey Newark 2,060 18.8% 388 2,448 New Mexico Albuquerque 2,060 -4.2% (86) 1,9747-4 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New York New York 2,060 50.1% 1,032 3,092 New York Syracuse 2,060 6.4% 133 2,193 Nevada Las Vegas 2, 060 6.1% 126 2,186 North Carolina Charlotte 2,060 -10.8% (223) 1,837 North Dakota Bismarck 2,060 -7.1% (146) 1,914 Ohio Cincinnati 2,060 -3.4% (70) 1,990 Oregon Portland 2,060 7.1% 146 2,206 Pennsylvania Philadelphia 2,060 18.3% 378 2,438 Pennsylvania Wilkes-Barre 2,060 -3.7% (77) 1,983

Rhode Island Providenc e 2,060 11.9% 244 2,304 South Carolina Spartanburg 2,060 -13.4% (275) 1,785 South Dakota Rapid City 2,060 -9.8% (203) 1,857 Tennessee Knoxville 2,060 -9.6% (197) 1,863 Texas Houston 2,060 -9.6% (198) 1,862 Utah Salt Lake City 2,060 -5.9% (123) 1,937 Vermont Burlington 2,060 -4.0% (81) 1,979 Virginia Alexandria 2,060 5.7% 118 2,178 Virginia Lynchburg 2,060 -6.6% (137) 1,923 Washington Seattle 2,060 6.0% 123 2,183 Washington Spokane 2,060 -3.5% (71) 1,989 West Virginia Charleston 2,060 -1.4% (30) 2,030 Wisconsin Green Bay 2,060 -2.7% (55) 2,005 Wyoming Cheyenne 2,060 -4.5% (92) 1,968 Puerto Rico Cayey 2,060 1.7% 34 2,094

7.5 O&M ESTIMATE The O&M items for the AG-NGCC/CCS Facility are the same as those set forth in Section 6.5 for the AG-NGCC Facility, 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 $30.25/kW-year Variable O&M Expense $6.45/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.7-5 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/MMBtu8-1 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 Facility with a nominal capacity of 85 MW is $975/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, 2010$)

Civil Structural Material and Installation 5,570

Mechanical Equipment Supply and Installation 34,709

Electrical / I&C Supply and Installation 10,700

Project Indirects (1) 12,248

EPC Cost before Contingency and Fee 63,227

Fee and Contingency 5,757

Total Project EPC 68,994

Owner Costs (excluding project finance) 13,799

Total Project Cost (excluding finance) 82,793

Total Project EPC / kW 812

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

Total Project Cost (excluding project finance) / kW 974

(1) Includes engineering, distributable costs, 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.

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 were8-3 included in outdoor installation are Alabama, Arizona, Arkansas , Florida, Georgia, Hawaii, Louisiana, Mississippi, New Mexico, S outh 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.

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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 8-2 presents the Conventiona l CT Facility capital cost varia tions for alternative U.S. plant locations.8-4 TABLE 8-2 – LOCATION-BASED CO STS FOR CONVENTIONAL CT (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 975 31.7% 309 1,284 Alaska Fairbanks 975 36.5% 355 1,330 Alabama Huntsville 975 -5.1% (50) 925 Arizona Phoenix 975 -3.5% (34) 941 Arkansas Little Rock 975 -3.7% (36) 939 California Los Angeles 975 19.0% 185 1,160 California Redding 975 3.9% 38 1,013 California Bakersfield 975 6.3% 61 1,036 California Sacramento 975 10.0% 97 1,072 California San Francisco 975 34.2% 334 1,309 Colorado Denver 975 -0.5% (5) 970 Connecticut Hartford 975 17.8% 174 1,149 Delaware Dover 975 16.6% 162 1,137 District of Columbia Washington 975 24.5% 239 1,214 Florida Tallahassee 975 -7.6% (74) 901 Florida Tampa 975 -3.1% (31) 944 Georgia Atlanta 975 -2.9% (29) 946 Hawaii Honolulu 975 51.5% 502 1,477 Idaho Boise 975 -2.8% (28) 947 Illinois Chicago 975 13.6% 132 1,107 Indiana Indianapolis 975 1.3% 13 988 Iowa Davenport 975 0.9% 8 983 Iowa Waterloo 975 -4.6% (45) 930 Kansas Wichita 975 -3.0% (29) 946 Kentucky Louisville 975 -4.1% (40) 935 Louisiana New Orleans 975 -1.1% (11) 964 Maine Portland 975 -1.6% (15) 960 Maryland Baltimore 975 12.0% 117 1,092 Massachusetts Boston 975 28.2% 275 1,250 Michigan Detroit 975 4.8% 46 1,021 Michigan Grand Rapids 975 -3.8% (37) 938 Minnesota St. Paul 975 4.0% 39 1,014 Mississippi Jackson 975 -5.1% (49) 926 Missouri St. Louis 975 5.0% 48 1,023 Missouri Kansas City 975 2.4% 23 998 Montana Great Falls 975 -1.3% (12) 963 Nebraska Omaha 975 -0.6% (6) 969 New Hampshire Concord 975 -1.3% (13) 962 New Jersey Newark 975 19.3% 188 1,1638-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 975 0.6% 6 981 New York New York 975 53.2% 518 1,493 New York Syracuse 975 7.5% 73 1,048 Nevada Las Vegas 975 5.2% 50 1,025 North Carolina Charlotte 975 -7.2% (70) 905 North Dakota Bismarck 975 -3.8% (38) 937 Ohio Cincinnati 975 -0.8% (8) 967 Oregon Portland 975 3.7% 36 1,011 Pennsylvania Philadelphia 975 14.8% 144 1,119 Pennsylvania Wilkes-Barre 975 -0.7% (7) 968 Rhode Island Providence 975 12.2% 119 1,094 South Carolina Spartanburg 975 -8.3% (81) 894 South Dakota Rapid City 975 -5.8% (57) 918 Tennessee Knoxville 975 -6.6% (65) 910 Texas Houston 975 -7.0% (68) 907 Utah Salt Lake City 975 -2.6% (25) 950 Vermont Burlington 975 1.3% 13 988 Virginia Alexandria 975 7.4% 72 1,047 Virginia Lynchburg 975 -4.5% (44) 931 Washington Seattle 975 6.1% 59 1,034 Washington Spokane 975 -1.8% (18) 957 West Virginia Charleston 975 0.6% 6 981 Wisconsin Green Bay 975 -0.6% (6) 969 Wyoming Cheyenne 975 1.0% 10 985 Puerto Rico Cayey 975 4.8% 47 1,022

8.5 O&M ESTIMATE In addition to the general O&M items discussed in Section 2.5.2, the Conventional CT Facility includes the major maintenance for the CT and associated electric generator. These major maintenance expenses are included with the VOM expense for this technology, based upon an assumed 10 percent annual capacity factor and an operating profile of approximately 8 hours of operation per CT start. Typical ly, significant overhauls on a Conve ntional CT Facility occur no less frequently than 8,000 operatin g hour intervals; with more significant major maintenance outages occurring at 24,000 operating hour inte rvals; however, often times the major maintenance for a CT at a peaking facility is driven off of CT hours (depending on the equipment manufacturer and the operating hours per start incurre d on the equipment). Table 8-3 presents the O&M expenses for the Conventional CT Facility.8-6 TABLE 8-3 – O&M EXPENSES FOR CONVENTIONAL CT Technology: Conventional CT Fixed O&M Expense $6.98/kW-year Variable O&M Expense $14.70/MWh

8.6 ENVIRONMENTAL 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/MMBtu9-1 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 2010) 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 $665/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, 2010$)

Civil Structural Material and Installation 11,800

Mechanical Equipment Supply and Installation 58,700

Electrical / I&C Supply and Installation 15,300

Project Indirects (1) 16,460

EPC Cost before Contingency and Fee 102,260

Fee and Contingency 14,196

Total Project EPC 116,456

Owner Costs (excluding project finance) 23,291

Total Project Cost (excluding finance) 139,747

Total Project EPC / kW 554

Owner Costs 20% (excluding project finance) / kW 111

Total Project Cost (excluding project finance) / kW 665

(1) Includes engineering, distributable costs, 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 presents the Advanced CT Facility cap ital cost variations for alternative U.S. plant locations.9-3 TABLE 9-2 – LOCATION-BASED COSTS FOR ADVANCED CT (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 665 41.9% 279 944 Alaska Fairbanks 665 48.4% 322 987 Alabama Huntsville 665 -3.5% (23) 642 Arizona Phoenix 665 -1.9% (12) 653 Arkansas Little Rock 665 -2.0% (13) 652 California Los Angeles 665 25.7% 171 836 California Redding 665 4.8% 32 697 California Bakersfield 665 8.5% 57 722 California Sacramento 665 11.3% 75 740 California San Francisco 665 42.9% 285 950

Colorado Denver 665 2.9% 19 684

Connecticut Hartford 665 23.7% 157 822

Delaware Dover 665 23.3% 155 820 District of Columbia Washington 665 36.9% 245 910 Florida Tallahassee 665 -5.7% (38) 627 Florida Tampa 665 -2.4% (16) 649 Georgia Atlanta 665 0.1% 1 666 Hawaii Honolulu 665 72.8% 484 1,149 Idaho Boise 665 -1.4% (9) 656 Illinois Chicago 665 11.6% 77 742 Indiana Indianapolis 665 2.8% 18 683 Iowa Davenport 665 2.1% 14 679 Iowa Waterloo 665 -2.0% (14) 651 Kansas Wichita 665 -0.5% (3) 662 Kentucky Louisville 665 -2.7% (18) 647

Louisiana New Orleans 665 3.9% 26 691

Maine Portland 665 1.0% 7 672 Maryland Baltimore 665 19.9% 132 797

Massachusetts Boston 665 34.3% 228 893 Michigan Detroit 665 5.4% 36 701 Michigan Grand Rapids 665 -1.4% (9) 656

Minnesota St. Paul 665 4.4% 29 694 Mississippi Jackson 665 -3.4% (23) 642

Missouri St. Louis 665 5.6% 38 703 Missouri Kansas City 665 2.5% 17 682

Montana Great Falls 665 1.2% 8 673

Nebraska Omaha 665 1.3% 9 674 New Hampshire Concord 665 -0.2% (2) 663 New Jersey Newark 665 20.6% 137 8029-4 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 665 3.7% 25 690 New York New York 665 61.7% 410 1,075 New York Syracuse 665 12.2% 81 746 Nevada Las Vegas 665 4.6% 31 696 North Carolina Charlotte 665 -4.6% (31) 634 North Dakota Bismarck 665 -1.5% (10) 655

Ohio Cincinnati 665 1.2% 8 673 Oregon Portland 665 4.7% 31 696 Pennsylvania Philadelphia 665 16.1% 107 772 Pennsylvania Wilkes-Barre 665 1.7% 11 676

Rhode Island Providence 665 16.6% 111 776 South Carolina Spartanburg 665 -5.5% (37) 628 South Dakota Rapid City 665 -3.0% (20) 645 Tennessee Knoxville 665 -4.6% (31) 634 Texas Houston 665 -5.2% (35) 630 Utah Salt Lake City 665 0.0% (0) 665 Vermont Burlington 665 5.6% 37 702 Virginia Alexandria 665 12.6% 84 749 Virginia Lynchburg 665 -3.0% (20) 645 Washington Seattle 665 6.5% 43 708 Washington Spokane 665 -0.6% (4) 661 West Virginia Charleston 665 2.3% 15 680 Wisconsin Green Bay 665 1.0% 6 671 Wyoming Cheyenne 665 5.5% 36 701 Puerto Rico Cayey 665 10.3% 68 733

9.5 O&M ESTIMATE

The O&M items for the Advanced CT Facility are the same as those set forth in Section 8.5 for the Conventional CT Facility. Table 9-3 pres ents the O&M expenses for the Advanced CT Facility.

TABLE 9-3 – O&M EXPENS ES FOR ADVANCED CT Technology: Advanced CT Fixed O&M Expense $6.70/kW-year Variable O&M Expense $9.87/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.9-5 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/MMBtu10-1 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

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 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 10.4 CAPITAL COST ESTIMATE The base Cost Estimate for the IGCC Facility with a nominal capacity of 600 MW is $3,565/kW and with a nominal capacity of 1,200 MW is $3,221/kW. Table 10-1 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, 2010$)

Civil Structural Material and Installation 102,121

Mechanical Equipment Supply and Installation 975,212

Electrical / I&C Supply and Installation 200,708

Project Indirects (1) 313,558

EPC Cost before Contingency and Fee 1,591,599

Fee and Contingency 190,992

Total Project EPC 1,782,591

Owner Costs (excluding project finance) 356,518

Total Project Cost (excluding finance) 2,139,109

Total Project EPC / kW 2,971

Owner Costs 20% (excluding project finance) / kW 594

Total Project Cost (excluding project finance) / kW 3,565

(1) Includes engineering, distributable costs, 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, 2010$)

Civil Structural Material and Installation 178,606

Mechanical Equipment Supply and Installation 1,859,974

Electrical / I&C Supply and Installation 364,745

Project Indirects (1) 521,600

EPC Cost before Contingency and Fee 2,924,925

Fee and Contingency 350,991

Total Project EPC 3,275,916

Owner Costs (excluding project finance) 589,665

Total Project Cost (excluding finance) 3,865,581

Total Project EPC / kW 2730

Owner Costs 18% (excluding project finance) / kW 491

Total Project Cost (excluding project finance) / kW 3,221

(1) Includes engineering, distributable costs, 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, Ar izona, Arkansas, Florida, Georgia, Hawaii, Louisiana, Mississippi, New Mexico, S outh 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 4.10-6 Remote locations issues are rela ted to geographic areas that typi cally require installation of man camps, higher craft incentives, and higher per 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 IGCC Facility include Fairbanks, Alaska; Honolulu, Hawaii; Albuquerque, New Mexico; Cheyenne, Wy oming; 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 present the IGCC Facility capital cost variations for alternative U.S. plant locations.10-7 TABLE 10-3 – LOCATION-BASE D COSTS FOR IGCC (600,000 KW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 3,565 29.4% 1,049 4,614 Alaska Fairbanks 3,565 28.5% 1,016 4,581 Alabama Huntsville 3,565 -6.5% (232) 3,333 Arizona Phoenix 3,565 -4.5% (160) 3,405 Arkansas Little Rock 3,565 -4.7% (167) 3,398 California Los Angeles 3,565 18.1% 645 4,210 California Redding 3,565 8.7% 312 3,877 California Bakersfield 3,565 8.4% 299 3,864 California Sacramento 3,565 12.8% 455 4,020 California San Francisco 3,565 37.6% 1,342 4,907 Colorado Denver 3,565 -5.2% (187) 3,378 Connecticut Hartford 3,565 23.7% 846 4,411 Delaware Dover 3,565 20.6% 734 4,299

District of Columbia Washi ngton 3,565 35.6% 1,269 4,834 Florida Tallahassee 3,565 -9.5% (339) 3,226 Florida Tampa 3,565 -4.3% (152) 3,413 Georgia Atlanta 3,565 -7.1% (252) 3,313

Hawaii Honolulu 0 0 Idaho Boise 3,565 -3.2% (113) 3,452 Illinois Chicago 3,565 17.4% 619 4,184 Indiana Indianapolis 3,565 2.9% 103 3,668 Iowa Davenport 3,565 -1.4% (48) 3,517 Iowa Waterloo 3,565 -7.8% (279) 3,286 Kansas Wichita 3,565 -5.8% (208) 3,357 Kentucky Louisville 3,565 -4.8% (172) 3,393 Louisiana New Orleans 3,565 -9.8% (348) 3,217 Maine Portland 3,565 -0.4% (14) 3,551 Maryland Baltimore 3,565 4.3% 153 3,718 Massachusetts Boston 3,565 31.3% 1,115 4,680 Michigan Detroit 3,565 3.4% 120 3,685 Michigan Grand Rapids 3,565 -6.8% (243) 3,322 Minnesota St. Paul 3,565 3.4% 123 3,688 Mississippi Jackson 3,565 -6.5% (230) 3,335 Missouri St. Louis 3,565 6.4% 227 3,792 Missouri Kansas City 3,565 3.0% 107 3,672 Montana Great Falls 3,565 -3.7% (131) 3,434 Nebraska Omaha 3,565 -3.0% (108) 3,457 New Hampshire Concord 3,565 -1.4% (49) 3,516 New Jersey Newark 3,565 13.5% 480 4,04510-8 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 3,565 -3.4% (120) 3,445 New York New York 3,565 28.4% 1,013 4,578 New York Syracuse 3,565 9.7% 345 3,910 Nevada Las Vegas 3, 565 8.1% 290 3,855 North Carolina Charlotte 3,565 -8.3% (296) 3,269 North Dakota Bismarck 3,565 -6.9% (247) 3,318 Ohio Cincinnati 3,565 0.4% 16 3,581 Oregon Portland 3,565 8.5% 303 3,868 Pennsylvania Philadelphia 3,565 10.6% 377 3,942 Pennsylvania Wilkes-Barre 3,565 -3.0% (107) 3,458

Rhode Island Providenc e 3,565 3.6% 129 3,694 South Carolina Spartanburg 3,565 -10.2% (364) 3,201 South Dakota Rapid City 3,565 -9.3% (331) 3,234 Tennessee Knoxville 3,565 -7.7% (276) 3,289 Texas Houston 3,565 -8.3% (294) 3,271 Utah Salt Lake City 3,565 -2.6% (91) 3,474 Vermont Burlington 3,565 -4.6% (162) 3,403 Virginia Alexandria 3,565 8.8% 313 3,878 Virginia Lynchburg 3,565 -1.6% (56) 3,509 Washington Seattle 3,565 11.3% 404 3,969 Washington Spokane 3,565 -2.0% (70) 3,495 West Virginia Charleston 3,565 -1.5% (55) 3,510 Wisconsin Green Bay 3,565 0.5% 19 3,584 Wyoming Cheyenne 3,565 3.7% 132 3,697 Puerto Rico Cayey 0 0 010-9 TABLE 10-4 – LOCATION-BASE D COSTS FOR IGCC (1,200,000 KW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 3,221 32.0% 1,031 4,252 Alaska Fairbanks 3,221 30.9% 996 4,217 Alabama Huntsville 3,221 -6.7% (216) 3,005 Arizona Phoenix 3,221 -4.6% (147) 3,074 Arkansas Little Rock 3,221 -4.8% (154) 3,067 California Los Angeles 3,221 19.8% 637 3,858 California Redding 3,221 9.6% 308 3,529 California Bakersfield 3,221 9.2% 296 3,517 California Sacramento 3,221 13.7% 442 3,663 California San Francisco 3,221 40.8% 1,313 4,534 Colorado Denver 3,221 -5.4% (173) 3,048 Connecticut Hartford 3,221 26.0% 836 4,057 Delaware Dover 3,221 22.7% 730 3,951

District of Columbia Washi ngton 3,221 39.5% 1,272 4,493 Florida Tallahassee 3,221 -9.9% (318) 2,903 Florida Tampa 3,221 -4.4% (143) 3,078 Georgia Atlanta 3,221 -7.3% (235) 2,986

Hawaii Honolulu - - Idaho Boise 3,221 -3.2% (102) 3,119 Illinois Chicago 3,221 18.2% 586 3,807 Indiana Indianapolis 3,221 3.3% 107 3,328 Iowa Davenport 3,221 -1.4% (45) 3,176 Iowa Waterloo 3,221 -8.1% (261) 2,960 Kansas Wichita 3,221 -6.0% (192) 3,029 Kentucky Louisville 3,221 -4.9% (158) 3,063 Louisiana New Orleans 3,221 -10.1% (326) 2,895 Maine Portland 3,221 0.0% (1) 3,220 Maryland Baltimore 3,221 5.0% 162 3,383 Massachusetts Boston 3,221 33.8% 1,087 4,308 Michigan Detroit 3,221 3.5% 114 3,335 Michigan Grand Rapids 3,221 -7.1% (227) 2,994 Minnesota St. Paul 3,221 3.6% 117 3,338 Mississippi Jackson 3,221 -6.6% (214) 3,007 Missouri St. Louis 3,221 6.9% 221 3,442 Missouri Kansas City 3,221 3.2% 103 3,324 Montana Great Falls 3,221 -3.7% (119) 3,102 Nebraska Omaha 3,221 -3.1% (99) 3,122 New Hampshire Concord 3,221 -1.3% (42) 3,179 New Jersey Newark 3,221 14.0% 449 3,67010-10 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 3,221 -3.4% (109) 3,112 New York New York 3,221 29.5% 949 4,170 New York Syracuse 3,221 10.8% 349 3,570 Nevada Las Vegas 3, 221 8.6% 278 3,499 North Carolina Charlotte 3,221 -8.5% (273) 2,948 North Dakota Bismarck 3,221 -7.2% (230) 2,991 Ohio Cincinnati 3,221 0.8% 25 3,246 Oregon Portland 3,221 9.3% 300 3,521 Pennsylvania Philadelphia 3,221 11.0% 355 3,576 Pennsylvania Wilkes-Barre 3,221 -3.0% (96) 3,125

Rhode Island Providenc e 3,221 3.9% 124 3,345 South Carolina Spartanburg 3,221 -10.5% (337) 2,884 South Dakota Rapid City 3,221 -9.6% (309) 2,912 Tennessee Knoxville 3,221 -7.9% (256) 2,965 Texas Houston 3,221 -8.5% (275) 2,946 Utah Salt Lake City 3,221 -2.4% (76) 3,145 Vermont Burlington 3,221 -4.6% (148) 3,073 Virginia Alexandria 3,221 9.9% 320 3,541 Virginia Lynchburg 3,221 -1.3% (41) 3,180 Washington Seattle 3,221 12.3% 395 3,616 Washington Spokane 3,221 -1.9% (62) 3,159 West Virginia Charleston 3,221 -1.5% (49) 3,172 Wisconsin Green Bay 3,221 0.8% 27 3,248 Wyoming Cheyenne 3,221 4.6% 148 3,369 Puerto Rico Cayey 0 0 0 0

10.5 O&M ESTIMATE In addition to the general O&M items 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 Advanced NGCC discussed above. Table 10-5 and Table 10-6 present the O&M expenses for the IGCC Facility. TABLE 10-5 – O&M EXPENSES FOR IGCC (600,000 KW) Technology: IGCC Fixed O&M Expense $59.23/kW-year Variable O&M Expense $6.87/MWh10-11 TABLE 10-6 – O&M EXPENSES FOR IGCC (1,200,000 KW) Technology: IGCC Fixed O&M Expense $48.90/kW-year Variable O&M Expense $6.87/MWh

10.6 ENVIRONMENTAL 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/MMBtu11-1 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 $5,348/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, 2010$)

Total Project EPC 2,317,500

Owner Costs (excluding project finance) 463,500

Total Project Cost (excluding finance) 2,781,000

Total Project EPC / kW 4,458

Owner Costs 20% (excluding project finance) / kW 892

Total Project Cost (excluding project finance) / kW 5,350

(1) Includes engineering, distributable costs, 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 presents the IGCC/CCS Facility capital cost variations for alternative U.S. plant locations.11-3 TABLE 11-2 – LOCATION-BASE D COSTS FOR IGCC/CCS (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 5,350 23.1% 1,236 6,586 Alaska Fairbanks 5,350 22.9% 1,225 6,575 Alabama Huntsville 5,350 -7.4% (397) 4,953 Arizona Phoenix 5,350 -5.5% (293) 5,057 Arkansas Little Rock 5,350 -5.7% (306) 5,044 California Los Angeles 5,350 13.7% 732 6,082 California Redding 5,350 6.5% 348 5,698 California Bakersfield 5,350 6.1% 326 5,676 California Sacramento 5,350 11.1% 591 5,941 California San Francisco 5,350 30.7% 1,642 6,992 Colorado Denver 5,350 -6.3% (335) 5,015 Connecticut Hartford 5,350 17.7% 946 6,296 Delaware Dover 5,350 14.5% 774 6,124

District of Columbia Washi ngton 5,350 23.0% 1,229 6,579 Florida Tallahassee 5,350 -10.5% (561) 4,789 Florida Tampa 5,350 -4.5% (243) 5,107 Georgia Atlanta 5,350 -8.1% (432) 4,918

Hawaii Honolulu 0 0 0 0 Idaho Boise 5,350 -4.2% (227) 5,123 Illinois Chicago 5,350 17.9% 959 6,309 Indiana Indianapolis 5,350 1.2% 67 5,417 Iowa Davenport 5,350 -1.5% (82) 5,268 Iowa Waterloo 5,350 -8.9% (474) 4,876 Kansas Wichita 5,350 -6.9% (370) 4,980 Kentucky Louisville 5,350 -5.8% (309) 5,041 Louisiana New Orleans 5,350 -10.8% (577) 4,773 Maine Portland 5,350 -2.8% (151) 5,199 Maryland Baltimore 5,350 1.1% 60 5,410 Massachusetts Boston 5,350 26.2% 1,402 6,752 Michigan Detroit 5,350 3.5% 185 5,535 Michigan Grand Rapids 5,350 -7.7% (413) 4,937 Minnesota St. Paul 5,350 3.4% 181 5,531 Mississippi Jackson 5,350 -7.4% (394) 4,956 Missouri St. Louis 5,350 5.5% 295 5,645 Missouri Kansas City 5,350 2.7% 145 5,495 Montana Great Falls 5,350 -4.8% (259) 5,091 Nebraska Omaha 5,350 -3.8% (201) 5,149 New Hampshire Concord 5,350 -2.2% (119) 5,231 New Jersey Newark 5,350 14.9% 795 6,14511-4 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 5,350 -4.4% (235) 5,115 New York New York 5,350 31.4% 1,681 7,031 New York Syracuse 5,350 5.5% 295 5,645 Nevada Las Vegas 5, 350 7.7% 410 5,760 North Carolina Charlotte 5,350 -10.1% (538) 4,812 North Dakota Bismarck 5,350 -7.8% (419) 4,931 Ohio Cincinnati 5,350 -1.5% (82) 5,268 Oregon Portland 5,350 6.2% 333 5,683 Pennsylvania Philadelphia 5,350 11.3% 602 5,952 Pennsylvania Wilkes-Barre 5,350 -4.1% (217) 5,133

Rhode Island Providenc e 5,350 3.4% 183 5,533 South Carolina Spartanburg 5,350 -12.0% (640) 4,710 South Dakota Rapid City 5, 350 -10.5% (562) 4,788 Tennessee Knoxville 5,350 -9.1% (486) 4,864 Texas Houston 5,350 -9.3% (499) 4,851 Utah Salt Lake City 5,350 -4.6% (245) 5,105 Vermont Burlington 5,350 -5.8% (311) 5,039 Virginia Alexandria 5,350 4.5% 241 5,591 Virginia Lynchburg 5,350 -3.8% (203) 5,147 Washington Seattle 5,350 9.4% 505 5,855 Washington Spokane 5,350 -2.9% (154) 5,196 West Virginia Charleston 5,350 -2.1% (111) 5,239 Wisconsin Green Bay 5,350 -1.1% (58) 5,292 Wyoming Cheyenne 5,350 -0.5% (29) 5,321 Puerto Rico Cayey 0 0 0 0

11.5 O&M ESTIMATE The O&M methodology for the IGCC/CCS Facility is th e same as that set forth in the section on the IGCC Facility, except that consideration ne eds to be made for the additional maintenance resulting from the CCS 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 $69.30/kW-year Variable O&M Expense $8.04/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.11-5 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/MMBtu12-1 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 in a brownfield (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 pellet encased in a zirconium alloy tube. The uranium atoms in the pellet absorb neutrons and split, or fission. When the uranium atom splits, a large amount of energy, as well as additional neutr ons and fission fragments are released. The neutrons can be absorbed by ot her uranium atoms which fission, producing more neutrons. The chain reaction is controlled by controlling the nu mber of neutrons available for fission. The number of neutrons available is controlled by the water in the nuclear reactor core, the arrangement of neutron absorbing control rods inse rted into the core, the design of the core, and by controlling the void fraction an d temperature of the coolant water (which both affect the density of water which affects the neut rons available for the fission process). 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 bo il, but through a heat exchanger (typically referred to as a steam generator) results in a lowe r pressure water (that in the “secondary loop”) to boil. The cooling water inside the PWR is circulated th rough the nuclear core by internal pumps. This cooling water system is termed the Reactor Cool ant System (“RCS”). The RCS consists of two heat transfer circuits, with each circuit cont aining one Delta-125 steam generator, two reactor coolant pumps, and a single hot leg and two cold legs for circulating cool ant between the reactor and the steam generators. The system also includ es a pressurizer, interc onnecting piping, and the valves and instrumentation necessary for operati onal control and the actuation of safeguards. Each AP1000 unit has a 130-foot diameter frees tanding containment vessel with four ring sections and an upper and lower head. The passive core cooling system provides prot ection for the facility against RCS leaks and ruptures. The passive containment cooling system is the ultimate safety-related ultimate heat sink for the facility. The passiv e containment cooling system c ools the containment following an accident to rapidly reduce the pressure via the natural circulation of air supplemented by water evaporation to transfer heat through the stee l containment vessel. Main steam from the steam generator is routed to the HP section of the ST. The ST consists of a double-flow HP ST section and three double-f low LP ST sections in a tandem-compound configuration. As the steam exits the HP section it passes th rough a moisture separator and reheater. The moisture separator and reheater dr ies and reheats the steam before it enters the LP ST section, which improves the cycle efficiency a nd reduces moisture related erosion of the LP ST blades. A portion of the steam is extracted fr om the HP and LP sections of the ST and with12-2 ST exhaust heats the condensate and feedwater before it is sent back to the reactor. The HP and LP STs are connected via a common shaft that drives the genera tor which produces the electrical power output of approximately 1,100 MW per unit. The steam that exits the LP section of the ST, as well as the drains from the feedwater heaters, are directed to the condenser. The condenser is a surface condensing (tube type) heat exchanger that is maintained under vacuum to increase the turbine efficiency. The steam condenses on the outside of the tubes and condenser cooling water is circulated thr ough the inside of the tubes. Numerous other systems are needed to suppor t 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.

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.12-3 The AN Facility is controlled using a DCS. The DCS provides centralized control of the facility by integrating the control systems provided with the reactor, ST and associated electric generator and the control of BOP systems and equipment.

12.3 OFF-SITE REQUIREMENTS Water for all processes at the AN Facility is obta ined from one of severa l available water supply options; however, water is typically sourced fr om an adjacent river, when possible. The AN Facility uses a water treatment system and a high-efficiency reverse osmosis system to reduce the dissolved solids from the cooling water a nd to provide distilled wa ter. Wastewater is sent to an adjacent river or other approved wastew ater delivery point. Further, the electrical interconnection from the AN on-site switchyard is effectuated by a connection to an adjacent utility substation.

12.4 CAPITAL COST ESTIMATE The base Cost Estimate for the AN Facility w ith a nominal capacity of 2,236 MW is $5,339/kW. Table 12-1 summarizes the Cost Estimate categories for the AN Facility.12-4 TABLE 12-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR AN Technology: AN Nominal Capacity (ISO): 2,236,000 kW Nominal Heat Rate (ISO): N/A Btu/kWh-HHV

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

Civil Structural Material and Installation 1,732,000

Mechanical Equipment Supply and Installation 3,400,000

Electrical / I&C Supply and Installation 630,000

Project Indirects (1) 2,722,500

EPC Cost before Contingency and Fee 8,484,500

Fee and Contingency 1,300,000

Total Project EPC 9,784,500

Owner Costs (excluding project finance) 2,152,590

Total Project Cost (excluding finance) 11,937,090

Total Project EPC / kW 4,376

Owner Costs 22% (excluding project finance) / kW 963

Total Project Cost (excluding project finance) / kW 5,339

(1) Includes engineering, distributable costs, 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. 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 Facility12-5 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 presents the AN Facility capital cost va riations for alternative U.S. plant locations.

TABLE 12-2 – LOCATION-BASED COSTS FOR AN (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 5,340 16.3% 868 6,208 Alaska Fairbanks 5,340 16.4% 878 6,218 Alabama Huntsville 5,340 -3.3% (174) 5,166 Arizona Phoenix 5,340 -2.4% (126) 5,214 Arkansas Little Rock 5,340 -2.5% (131) 5,209 California Los Angeles 5,340 9.5% 505 5,845 California Redding 5,340 4.6% 245 5,585 California Bakersfield 5,340 4.4% 236 5,576 California Sacramento 5,340 6.5% 348 5,688 California San Francisco 5,340 20.9% 1,114 6,454 Colorado Denver 5,340 -2.6% (136) 5,204 Connecticut Hartford 5,340 14.7% 784 6,124 Delaware Dover 5,340 13.2% 707 6,047

District of Columbia Washi ngton 5,340 23.9% 1,275 6,615 Florida Tallahassee 5,340 -4.6% (248) 5,092 Florida Tampa 5,340 -2.1% (114) 5,226 Georgia Atlanta 5,340 -3.5% (189) 5,151

Hawaii Honolulu 0 0 0 0 Idaho Boise 5,340 -1.6% (86) 5,254 Illinois Chicago 5,340 9.0% 479 5,819 Indiana Indianapolis 5,340 2.0% 108 5,448 Iowa Davenport 5,340 -0.6% (35) 5,305 Iowa Waterloo 5,340 -3.7% (200) 5,140 Kansas Wichita 5,340 -2.8% (151) 5,189 Kentucky Louisville 5,340 -2.4% (126) 5,21412-6 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Louisiana New Orleans 5,340 -4.8% (254) 5,086 Maine Portland 5,340 0.4% 21 5,361 Maryland Baltimore 5,340 3.4% 180 5,520 Massachusetts Boston 5,340 18.3% 976 6,316 Michigan Detroit 5,340 1.6% 83 5,423 Michigan Grand Rapids 5,340 -3.3% (174) 5,166 Minnesota St. Paul 5,340 1.9% 99 5,439 Mississippi Jackson 5,340 -3.2% (173) 5,167 Missouri St. Louis 5,340 2.8% 148 5,488 Missouri Kansas City 5,340 1.3% 70 5,410 Montana Great Falls 5,340 -1.9% (100) 5,240 Nebraska Omaha 5,340 -1.5% (80) 5,260 New Hampshire Concord 5,340 -0.8% (41) 5,299 New Jersey Newark 5,340 6.4% 340 5,680 New Mexico Albuquerque 5,340 -1.6% (83) 5,257 New York New York 5,340 13.4% 718 6,058 New York Syracuse 5,340 6.6% 355 5,695 Nevada Las Vegas 5, 340 4.1% 220 5,560 North Carolina Charlotte 5,340 -4.1% (218) 5,122 North Dakota Bismarck 5,340 -3.3% (176) 5,164 Ohio Cincinnati 5,340 0.8% 45 5,385 Oregon Portland 5,340 4.5% 239 5,579 Pennsylvania Philadelphia 5,340 4.9% 263 5,603 Pennsylvania Wilkes-Barre 5,340 -1.5% (82) 5,258

Rhode Island Providenc e 5,340 1.6% 87 5,427 South Carolina Spartanburg 5,340 -5.1% (272) 5,068 South Dakota Rapid City 5,340 -4.4% (237) 5,103 Tennessee Knoxville 5,340 -3.7% (200) 5,140 Texas Houston 5,340 -3.9% (210) 5,130 Utah Salt Lake City 5,340 -1.5% (80) 5,260 Vermont Burlington 5,340 -2.3% (122) 5,218 Virginia Alexandria 5,340 6.2% 332 5,672 Virginia Lynchburg 5,340 -0.1% (6) 5,334 Washington Seattle 5,340 5.8% 311 5,651 Washington Spokane 5,340 -1.0% (56) 5,284 West Virginia Charleston 5,340 -0.8% (42) 5,298 Wisconsin Green Bay 5,340 1.0% 51 5,391 Wyoming Cheyenne 5,340 3.5% 188 5,528 Puerto Rico Cayey 0 0 0 012-7 12.5 O&M ESTIMATE In addition to the general items discussed in the section of this report entitled O&M Estimate, the AN Facility includes provisions for major maintenance on the steam generators, STs, electric generators, BOP systems, and the reactor (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 $88.75/kW-year Variable O&M Expense $2.04/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/MMBtu13-1 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 associated13-3 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 $7,573/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, 2010$)

Civil Structural Material and Installation 16,459

Mechanical Equipment Supply and Installation 70,137

Electrical / I&C Supply and Installation 11,267

Project Indirects (1) 21,207

EPC Cost before Contingency and Fee 119,070

Fee and Contingency 12,500

Total Project EPC 131,570

Owner Costs (excluding project finance) 26,314

Total Project Cost (excluding finance) 157,884

Total Project EPC / kW 6,578

Owner Costs 20% (excluding project finance) / kW 1,316

Total Project Cost (excluding project finance) / kW 7,894

(1) Includes engineering, distributable costs, 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, Ar izona, Arkansas, Florida, Georgia, Hawaii, Louisiana, Mississippi, New Mexico, S outh 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; Albuque rque, 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 presents the BCC Facility capital cost va riations for alternativ e U.S. plant locations.13-6 TABLE 13-2 – LOCATION-BASED COSTS FOR BCC (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 7,900 14.0% 1,104 9,004 Alaska Fairbanks 7,900 15.2% 1,197 9,097 Alabama Huntsville 7,900 -6.0% (472) 7,428

Arizona Phoenix 0 0.0% 0 0 Arkansas Little Rock 7,900 -5.0% (392) 7,508 California Los Angeles 7,900 7.2% 566 8,466 California Redding 7,900 3.3% 262 8,162 California Bakersfield 7,900 3.0% 237 8,137 California Sacramento 7,900 6.8% 539 8,439 California San Francisco 7,900 19.6% 1,547 9,447 Colorado Denver 7,900 -9.2% (724) 7,176 Connecticut Hartford 7,900 11.9% 940 8,840 Delaware Dover 7,900 9.7% 768 8,668

District of Columbia Washi ngton 7,900 15.1% 1,196 9,096 Florida Tallahassee 7,900 -8.0% (635) 7,265 Florida Tampa 7,900 -3.5% (274) 7,626 Georgia Atlanta 7,900 -6.5% (511) 7,389 Hawaii Honolulu 7,900 29.3% 2,311 10,211 Idaho Boise 7,900 -3.9% (304) 7,596 Illinois Chicago 7,900 13.6% 1,073 8,973 Indiana Indianapolis 7,900 0.4% 35 7,935 Iowa Davenport 7,900 -1.2% (93) 7,807 Iowa Waterloo 7,900 -6.8% (539) 7,361 Kansas Wichita 7,900 -5.6% (444) 7,456 Kentucky Louisville 7,900 -4.7% (375) 7,525 Louisiana New Orleans 7,900 -8.3% (653) 7,247 Maine Portland 7,900 -3.0% (236) 7,664 Maryland Baltimore 7,900 0.1% 10 7,910 Massachusetts Boston 7,900 18.5% 1,459 9,359 Michigan Detroit 7,900 2.4% 188 8,088 Michigan Grand Rapids 7,900 -5.9% (469) 7,431 Minnesota St. Paul 7,900 2.5% 200 8,100 Mississippi Jackson 7,900 -5.9% (469) 7,431 Missouri St. Louis 7,900 2.8% 220 8,120 Missouri Kansas City 7,900 1.5% 119 8,019 Montana Great Falls 7,900 -4.8% (379) 7,521 Nebraska Omaha 7,900 -3.2% (252) 7,648 New Hampshire Concord 7,900 -2.3% (182) 7,718 New Jersey Newark 7,900 11.2% 882 8,78213-7 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 0 0.0% 0 0 New York New York 7,900 23.6% 1,866 9,766 New York Syracuse 7,900 3.3% 259 8,159 Nevada Las Vegas 0 0.0% 0 0 North Carolina Charlotte 7,900 -8.3% (658) 7,242 North Dakota Bismarck 7,900 -6.0% (476) 7,424 Ohio Cincinnati 7,900 -1.7% (134) 7,766 Oregon Portland 7,900 3.1% 246 8,146 Pennsylvania Philadelphia 7,900 8.1% 639 8,539 Pennsylvania Wilkes-Barre 7,900 -3.7% (293) 7,607

Rhode Island Providenc e 7,900 2.1% 162 8,062 South Carolina Spartanburg 7,900 -9.8% (771) 7,129 South Dakota Rapid City 7,900 -8.1% (639) 7,261 Tennessee Knoxville 7,900 -7.3% (575) 7,325 Texas Houston 7,900 -7.2% (568) 7,332 Utah Salt Lake City 0 0.0% 0 0 Vermont Burlington 7,900 -5.1% (400) 7,500 Virginia Alexandria 7,900 2.5% 198 8,098 Virginia Lynchburg 7,900 -3.4% (271) 7,629 Washington Seattle 7,900 5.6% 441 8,341 Washington Spokane 7,900 -2.8% (222) 7,678 West Virginia Charleston 7,900 -1.9% (149) 7,751 Wisconsin Green Bay 7,900 -1.1% (83) 7,817 Wyoming Cheyenne 0 0.0% 0 0 Puerto Rico Cayey 7,900 -3.7% (290) 7,610

13.5 O&M ESTIMATE In addition to the general items discussed in the section of this report entitled O&M Estimate, the BCC Facility include the major maintenance for 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 $338.79/kW-year Variable O&M Expense $16.64/MWh13-8 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 0.054 lb/MMBtu SO 2 0 lb/MMBtu CO 2 195 lb/MMBtu14-1 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 – BCC DESIGN CONFIGURATION14-2 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 $3,860/kW. Table 14-1 summarizes the Cost Estimate categories for the BBFB Facility.14-3 TABLE 14-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR BBFB Technology: BBFB Nominal Capacity (ISO): 50,000 kW Nominal Heat Rate (ISO): 13,500 Btu/kWh-HHV

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

Civil Structural Material and Installation 13,650

Mechanical Equipment Supply and Installation 67,200

Electrical / I&C Supply and Installation 20,000

Project Indirects (1) 40,250

EPC Cost before Contingency and Fee 141,100

Fee and Contingency 19,754

Total Project EPC 160,854

Owner Costs (excluding project finance) 32,171

Total Project Cost (excluding finance) 193,025

Total Project EPC / kW 3,217

Owner Costs 20% (excluding project finance) / kW 643

Total Project Cost (excluding project finance) / kW 3,860

(1) Includes engineering, distributable costs, 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, Ar izona, Arkansas, Florida, Georgia, Hawaii, Louisiana, Mississippi, New Mexico, S outh 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; Albuque rque, 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 presents the BBFB Facility capital cost variations for alternative U.S. plant locations.14-5 TABLE 14-2– LOCATION-BA SED COSTS FOR BBFB (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 3,860 25.8% 995 4,855 Alaska Fairbanks 3,860 27.9% 1,076 4,936 Alabama Huntsville 3,860 -9.7% (376) 3,484

Arizona Phoenix 0 0.0% 0 0 Arkansas Little Rock 3,860 -8.1% (311) 3,549 California Los Angeles 3,860 13.4% 516 4,376 California Redding 3,860 6.3% 242 4,102 California Bakersfield 3,860 5.7% 221 4,081 California Sacramento 3,860 11.9% 460 4,320 California San Francisco 3,860 35.6% 1,373 5,233 Colorado Denver 3,860 -8.2% (318) 3,542 Connecticut Hartford 3,860 22.9% 882 4,742 Delaware Dover 3,860 19.3% 745 4,605

District of Columbia Washi ngton 3,860 31.6% 1,219 5,079 Florida Tallahassee 3,860 -13.1% (506) 3,354 Florida Tampa 3,860 -5.7% (221) 3,639 Georgia Atlanta 3,860 -10.5% (407) 3,453 Hawaii Honolulu 3,860 58.2% 2,248 6,108 Idaho Boise 3,860 -6.2% (238) 3,622 Illinois Chicago 3,860 22.7% 875 4,735 Indiana Indianapolis 3,860 1.5% 56 3,916 Iowa Davenport 3,860 -1.9% (74) 3,786 Iowa Waterloo 3,860 -11.0% (426) 3,434 Kansas Wichita 3,860 -9.1% (350) 3,510 Kentucky Louisville 3,860 -7.6% (295) 3,565 Louisiana New Orleans 3,860 -13.5% (520) 3,340 Maine Portland 3,860 -4.0% (156) 3,704 Maryland Baltimore 3,860 1.6% 63 3,923 Massachusetts Boston 3,860 33.5% 1,292 5,152 Michigan Detroit 3,860 3.9% 150 4,010 Michigan Grand Rapids 3,860 -9.6% (371) 3,489 Minnesota St. Paul 3,860 4.3% 166 4,026 Mississippi Jackson 3,860 -9.7% (373) 3,487 Missouri St. Louis 3,860 4.7% 181 4,041 Missouri Kansas City 3,860 2.5% 96 3,956 Montana Great Falls 3,860 -4.8% (185) 3,675 Nebraska Omaha 3,860 -5.1% (198) 3,662 New Hampshire Concord 3,860 -3.6% (141) 3,719 New Jersey Newark 3,860 18.1% 698 4,55814-6 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 0 0.0% 0 0 New York New York 3,860 38.3% 1,477 5,337 New York Syracuse 3,860 7.5% 288 4,148 Nevada Las Vegas 0 0.0% 0 0 North Carolina Charlotte 3,860 -13.4% (517) 3,343 North Dakota Bismarck 3,860 -9.7% (376) 3,484 Ohio Cincinnati 3,860 -2.0% (77) 3,783 Oregon Portland 3,860 5.9% 228 4,088 Pennsylvania Philadelphia 3,860 13.1% 507 4,367 Pennsylvania Wilkes-Barre 3,860 -5.9% (229) 3,631

Rhode Island Providenc e 3,860 3.4% 131 3,991 South Carolina Spartanburg 3,860 -15.8% (611) 3,249 South Dakota Rapid City 3, 860 -13.1% (505) 3,355 Tennessee Knoxville 3,860 -11.7% (453) 3,407 Texas Houston 3,860 -11.6% (449) 3,411 Utah Salt Lake City 0 0.0% 0 0 Vermont Burlington 3,860 -8.1% (314) 3,546 Virginia Alexandria 3,860 6.2% 240 4,100 Virginia Lynchburg 3,860 -4.8% (186) 3,674 Washington Seattle 3,860 9.9% 382 4,242 Washington Spokane 3,860 -4.5% (172) 3,688 West Virginia Charleston 3,860 -3.0% (117) 3,743 Wisconsin Green Bay 3,860 -1.0% (39) 3,821 Wyoming Cheyenne 0 0.0% 0 0 Puerto Rico Cayey 3,860 -5.5% (213) 3,647

14.5 O&M ESTIMATE In addition to the general items discussed in the section of this report entitled O&M Estimate, the BBFB Facility includes the major maintenance for 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: BCC Fixed O&M Expense $100.50/kW-year Variable O&M Expense $5.0/MWh14-7 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/MMBtu15-1 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 water15-2 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 $9,960/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, 2010$)

Civil Structural Material and Installation 3,148

Mechanical Equipment Supply and Installation 49,925

Electrical / I&C Supply and Installation 2,050

Project Indirects (1) 3,473

EPC Cost before Contingency and Fee 58,596

Fee and Contingency 4,688

Total Project EPC 63,284

Owner Costs (excluding project finance) 5,063

Total Project Cost (excluding finance) 68,347

Total Project EPC / kW 6,328

Owner Costs 8% (excluding project finance) / kW 500

Total Project Cost (excluding project finance) / kW 6,835

(1) Includes engineering, distributable costs, 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 15-2 presents the FC Facility capital cost variations for alternative U.S. plant locations.15-4 TABLE 15-2 – LOCATION-BASED COSTS FOR FC (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 6,835 12.7% 871 7,706 Alaska Fairbanks 6,835 18.4% 1,255 8,090 Alabama Huntsville 6,835 -4.6% (312) 6,523 Arizona Phoenix 6,835 -3.5% (240) 6,595 Arkansas Little Rock 6,835 -3.7% (251) 6,584 California Los Angeles 6,835 4.3% 293 7,128 California Redding 6,835 1.7% 119 6,954 California Bakersfield 6,835 2.2% 150 6,985 California Sacramento 6,835 4.6% 313 7,148 California San Francisco 6,835 10.7% 733 7,568 Colorado Denver 6,835 -4.1% (278) 6,557 Connecticut Hartford 6,835 4.4% 299 7,134 Delaware Dover 6,835 2.4% 166 7,001

District of Columbia Wash ington 6,835 1.9% 127 6,962 Florida Tallahassee 6,835 -6.3% (432) 6,403 Florida Tampa 6,835 -2.6% (179) 6,656 Georgia Atlanta 6,835 -5.0% (340) 6,495 Hawaii Honolulu 6,835 12.0% 817 7,652 Idaho Boise 6,835 -3.0% (203) 6,632 Illinois Chicago 6,835 10.0% 681 7,516 Indiana Indianapolis 6,835 -0.6% (42) 6,793 Iowa Davenport 6,835 -1.0% (65) 6,770 Iowa Waterloo 6,835 -5.5% (378) 6,457 Kansas Wichita 6,835 -4.5% (306) 6,529 Kentucky Louisville 6,835 -3.8% (258) 6,577 Louisiana New Orleans 6,835 -6.5% (445) 6,390 Maine Portland 6,835 -2.4% (162) 6,673 Maryland Baltimore 6,835 -1.3% (86) 6,749 Massachusetts Boston 6,835 9.7% 662 7,497 Michigan Detroit 6,835 2.3% 156 6,991 Michigan Grand Rapids 6,835 -4.5% (310) 6,525 Minnesota St. Paul 6,835 1.9% 133 6,968 Mississippi Jackson 6,835 -4.5% (310) 6,525 Missouri St. Louis 6,835 2.6% 180 7,015 Missouri Kansas City 6,835 1.4% 94 6,929 Montana Great Falls 6,835 -3.1% (209) 6,626 Nebraska Omaha 6,835 -2.5% (172) 6,663 New Hampshire Concord 6,835 -1.4% (98) 6,737 New Jersey Newark 6,835 10.1% 689 7,52415-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 6,835 -2.8% (194) 6,641 New York New York 6,835 22.2% 1,514 8,349 New York Syracuse 6,835 -0.7% (48) 6,787 Nevada Las Vegas 6, 835 3.7% 253 7,088 North Carolina Charlotte 6,835 -6.6% (451) 6,384 North Dakota Bismarck 6,835 -4.6% (314) 6,521 Ohio Cincinnati 6,835 -2.6% (180) 6,655 Oregon Portland 6,835 1.6% 107 6,942 Pennsylvania Philadelphia 6,835 6.7% 459 7,294 Pennsylvania Wilkes-Barre 6,835 -2.9% (195) 6,640

Rhode Island Providenc e 6,835 1.8% 124 6,959 South Carolina Spartanburg 6,835 -7.6% (517) 6,318 South Dakota Rapid City 6,835 -6.3% (429) 6,406 Tennessee Knoxville 6,835 -5.8% (398) 6,437 Texas Houston 6,835 -5.8% (398) 6,437 Utah Salt Lake City 6,835 -3.7% (251) 6,584 Vermont Burlington 6,835 -3.7% (251) 6,584 Virginia Alexandria 6,835 -0.8% (52) 6,783 Virginia Lynchburg 6,835 -4.0% (276) 6,559 Washington Seattle 6,835 3.6% 244 7,079 Washington Spokane 6,835 -1.8% (126) 6,709 West Virginia Charleston 6,835 -1.2% (80) 6,755 Wisconsin Green Bay 6,835 -1.9% (130) 6,705 Wyoming Cheyenne 6,835 -3.6% (245) 6,590 Puerto Rico Cayey 6,835 -0.2% (14) 6,821

15.4 O&M ESTIMATE In addition to the general items discussed in the section of this report entitled O&M Estimate, since a FC is a direct energy conversion device, 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 various vendors and developers. Table 15-3 presents the O&M expenses for the FC Facility.

TABLE 15-3 – O&M EXPENSES FOR FC Technology: FC Fixed O&M Expense $350/kW-year Variable O&M Expense $0/MWh15-6 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.

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/MMBtu16-1 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 three separate pressure levels of steam to be deliver ed to the TGF. Additionally, the BPF will produce a concentrated brine to be furt her processed to remove solids. The GT production wells deliver the GT brine to the BPF where it is initially flashed in a separator drum to produce HP steam. The remaini ng brine is subject to two additional pressure reduction stages, in closed pressure vessels call ed crystallizers, which are operated in a manner to prevent the rapid scaling of the vessel walls and internal parts by th e precipitation of solids from the brine. The medium-pressure crystallizer is supplied with a small quantity of seed flow, concentrated brine from the primary clarifier, to provide a nucleus to which the solids in the crystallizer brine can attach themselves and be ca rried out with the brine leaving the crystallizer. The separated brine from the crystallizers 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 three pressure levels from the BP F is delivered to the TG F 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, IP, and LP inlets. Steam from the ST is condensed in a two-pass shell and tube condenser constructed of stainl ess steel, with part of the c ondensate 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 purg e system, or the condensa te injection system. The non-condensable gases are evacuated by a non- condensable 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. Circulating water pumps direct water from the cooling tower to the ST condenser. Make-up water for the cycle is supplied from the condensate from the ST condenser. Additional make-up water may be 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, the16-3 electrical interconnection from the GT Facility is accomplished by interconnecting via the plant switchyard into the utility hi gh-voltage transmission system.

16.4 CAPITAL COST ESTIMATE The base Cost Estimate for the GT Facility with a nominal capacity of 50 MW is $6,163/kW. Table 16-1 summarizes the Cost Estimate categories for the GT Facility.

TABLE 16-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR GT Technology: GT Nominal Capacity (ISO): 50,000 kW Nominal Heat Rate (ISO): N/A Btu/kWh-HHV

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

Civil Structural Material and Installation 9,450

Mechanical Equipment Supply and Installation (and well costs) 152,000

Electrical / I&C Supply and Installation 12,062

Project Indirects (1) 32,000

EPC Cost before Contingency and Fee 205,512

Fee and Contingency 30,827

Total Project EPC 236,339

Owner Costs (excluding project finance) 42,541

Total Project Cost (excluding finance) 278,880

Total Project EPC / kW 4,726

Owner Costs 18% (excluding project finance) / kW 852

Total Project Cost (excluding project finance) / kW 5,578

(1) Includes engineering, distributable costs, 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 13 states: Alaska , Arizona, California, Colorado, Florida, Hawaii, Idaho, Nevada, New Mexico, Orego n, Utah, Washington, and Wyoming.16-4 Seismic design differences among the various locations were based on U.S. seismic map information that detailed the various seismic 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 locations include Alaska, Ca lifornia, Hawaii, and Wyoming. Table 16-2 presents the GT Facility capital cost variations for alternative U.S. plant locations.16-5 TABLE 16-2 – LOCATION-BASED COSTS FOR GT (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 5,580 13.9% 777 6,357 Alaska Fairbanks 5,580 20.6% 1,150 6,730

Alabama Huntsville 0 0.0% 0 0 Arizona Phoenix 5,580 -3.1% (173) 5,407

Arkansas Little Rock 0 0.0% 0 0 California Los Angeles 5,580 5.4% 301 5,881 California Redding 5,580 1.8% 101 5,681 California Bakersfield 5,580 2.4% 136 5,716 California Sacramento 5,580 4.9% 271 5,851 California San Francisco 5,580 11.8% 661 6,241 Colorado Denver 5,580 -3.0% (165) 5,415

Connecticut Hartford 0 0.0% 0 0

Delaware Dover 0 0.0% 0 0 District of Columbia Washington 0 0.0% 0 0

Florida Tallahassee 0 0.0% 0 0 Florida Tampa 0 0.0% 0 0 Georgia Atlanta 0 0.0% 0 0 Hawaii Honolulu 5,580 21.8% 1,217 6,797 Idaho Boise 5,580 -2.6% (146) 5,434 Illinois Chicago 0 0.0% 0 0 Indiana Indianapolis 0 0.0% 0 0 Iowa Davenport 0 0.0% 0 0 Iowa Waterloo 0 0.0% 0 0

Kansas Wichita 0 0.0% 0 0 Kentucky Louisville 0 0.0% 0 0

Louisiana New Orleans 0 0.0% 0 0

Maine Portland 0 0.0% 0 0 Maryland Baltimore 0 0.0% 0 0

Massachusetts Boston 0 0.0% 0 0 Michigan Detroit 0 0.0% 0 0 Michigan Grand Rapids 0 0.0% 0 0

Minnesota St. Paul 0 0.0% 0 0 Mississippi Jackson 0 0.0% 0 0

Missouri St. Louis 0 0.0% 0 0 Missouri Kansas City 0 0.0% 0 0

Montana Great Falls 0 0.0% 0 0

Nebraska Omaha 0 0.0% 0 0 New Hampshire Concord 0 0.0% 0 0 New Jersey Newark 0 0.0% 0 016-6 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 5,580 -2.1% (117) 5,463

New York New York 0 0.0% 0 0 New York Syracuse 0 0.0% 0 0 Nevada Las Vegas 5, 580 3.5% 193 5,773

North Carolina Charlotte 0 0.0% 0 0

North Dakota Bismarck 0 0.0% 0 0

Ohio Cincinnati 0 0.0% 0 0 Oregon Portland 5,580 1.7% 92 5,672 Pennsylvania Philadelphia 0 0.0% 0 0 Pennsylvania Wilkes-Barre 0 0.0% 0 0

Rhode Island Providence 0 0.0% 0 0 South Carolina Spartanburg 0 0.0% 0 0 South Dakota Rapid City 0 0.0% 0 0

Tennessee Knoxville 0 0.0% 0 0

Texas Houston 0 0.0% 0 0 Utah Salt Lake City 5,580 -3.1% (173) 5,407 Vermont Burlington 0 0.0% 0 0 Virginia Alexandria 0 0.0% 0 0 Virginia Lynchburg 0 0.0% 0 0 Washington Seattle 5,580 3.5% 194 5,774 Washington Spokane 5,580 -1.8% (103) 5,477 West Virginia Charleston 0 0.0% 0 0 Wisconsin Green Bay 0 0.0% 0 0 Wyoming Cheyenne 5,580 -2.9% (164) 5,416 Puerto Rico Cayey 0 0.0% 0 0

16.5 O&M ESTIMATE In addition to the general items discussed in the section of this report entitled O&M Estimate, the GT Facility includes major maintenance on the ST , electric generator (each approximately every six years) and well field maintenance, which can vary depending on the GT resource. Table 16-3 presents the FOM and VOM expenses for the GT Facility.

TABLE 16-3 – O&M EXPENSES FOR GT Technology: GT Fixed O&M Expense $84.27/kW-year Variable O&M Expense $9.46/MWh

16.6 ENVIRONMENTAL COMPLI ANCE INFORMATION Table 16-4 presents environmental emissions for the GT Facility.16-7 TABLE 16-4 – ENVIRONMENTAL EMISSIONS FOR GT Technology: GT NO X 0 per MWh SO 2 0.2 per MWh CO 2 120 per MWh17-1 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 th ree heat recovery systems. These heat recovery systems operate on a closed looped organic supercri tical Rankine cycle using geothe rmal brine as a heat source, with a brine temperature approximately 275°F. Cycle heat rejection wi ll be provided through three cooling towers. After s upplying the three heat recovery systems with hot water, the geothermal brine will be re-inj ected into the resource at appr oximately 140°F through injection wells. The heat recovery systems are equipped with a multistage, radial inflow turbo-expander generator unit. The turbo-expander is designed fo r a supercritical refrigerant inlet pressure and temperature. Each turbo-expander unit has a design output (gross) of approximately 10,000 kW. Refrigerant is pumped from the condenser to the ev aporators in each heat recovery system by means of a single high pressure vertical turb ine pump.

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 $4,141/kW. Table 17-1 summarizes the Cost Estimate categories for the Binary Facility.

TABLE 17-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR GT Technology: GT Nominal Capacity (ISO): 50,000 kW Nominal Heat Rate (ISO): N/A Btu/kWh-HHV

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

Civil Structural Material and Installation 6,760

Mechanical Equipment Supply and Installation (and well costs) 107,545

Electrical / I&C Supply and Installation 13,345

Project Indirects (1) 29,000

EPC Cost before Contingency and Fee 156,650

Fee and Contingency 18,798

Total Project EPC 175,448

Owner Costs (excluding project finance) 31,598

Total Project Cost (excluding finance) 207,046

Total Project EPC / kW 3,509

Owner Costs 18% (excluding project finance) / kW 632

Total Project Cost (excluding project finance) / kW 4,141

(1) Includes engineering, distributable costs, 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 13 states: Alaska , Arizona, California, Colorado, Florida, Hawaii, Idaho, Nevada, New Mexico, Orego n, Utah, 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 locations include Alaska, Ca lifornia, Hawaii, and Wyoming. Table 17-2 presents the GT Facility capital cost variations for alternative U.S. plant locations.17-4 TABLE 17-2 – LOCATION-BASED COSTS FOR GT (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 4,140 17.1% 710 4,850 Alaska Fairbanks 4,140 26.0% 1,075 5,215

Alabama Huntsville 0 0.0% 0 0 Arizona Phoenix 4,140 -3.0% (125) 4,015

Arkansas Little Rock 0 0.0% 0 0 California Los Angeles 4,140 6.5% 270 4,410 California Redding 4,140 2.1% 88 4,228 California Bakersfield 4,140 3.1% 127 4,267 California Sacramento 4,140 5.4% 222 4,362 California San Francisco 4,140 13.4% 553 4,693 Colorado Denver 4,140 -2.7% (112) 4,028

Connecticut Hartford 0 0.0% 0 0

Delaware Dover 0 0.0% 0 0 District of Columbia Washington 0 0.0% 0 0

Florida Tallahassee 0 0.0% 0 0 Florida Tampa 0 0.0% 0 0 Georgia Atlanta 0 0.0% 0 0 Hawaii Honolulu 4,140 28.5% 1,178 5,318 Idaho Boise 4,140 -2.5% (105) 4,035 Illinois Chicago 0 0.0% 0 0 Indiana Indianapolis 0 0.0% 0 0 Iowa Davenport 0 0.0% 0 0 Iowa Waterloo 0 0.0% 0 0

Kansas Wichita 0 0.0% 0 0 Kentucky Louisville 0 0.0% 0 0

Louisiana New Orleans 0 0.0% 0 0

Maine Portland 0 0.0% 0 0 Maryland Baltimore 0 0.0% 0 0

Massachusetts Boston 0 0.0% 0 0 Michigan Detroit 0 0.0% 0 0 Michigan Grand Rapids 0 0.0% 0 0

Minnesota St. Paul 0 0.0% 0 0 Mississippi Jackson 0 0.0% 0 0

Missouri St. Louis 0 0.0% 0 0 Missouri Kansas City 0 0.0% 0 0

Montana Great Falls 0 0.0% 0 0

Nebraska Omaha 0 0.0% 0 0 New Hampshire Concord 0 0.0% 0 0 New Jersey Newark 0 0.0% 0 017-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New Mexico Albuquerque 4,140 -1.8% (76) 4,064

New York New York 0 0.0% 0 0 New York Syracuse 0 0.0% 0 0 Nevada Las Vegas 4, 140 3.6% 150 4,290

North Carolina Charlotte 0 0.0% 0 0

North Dakota Bismarck 0 0.0% 0 0

Ohio Cincinnati 0 0.0% 0 0 Oregon Portland 4,140 2.0% 81 4,221 Pennsylvania Philadelphia 0 0.0% 0 0 Pennsylvania Wilkes-Barre 0 0.0% 0 0

Rhode Island Providence 0 0.0% 0 0 South Carolina Spartanburg 0 0.0% 0 0 South Dakota Rapid City 0 0.0% 0 0

Tennessee Knoxville 0 0.0% 0 0

Texas Houston 0 0.0% 0 0 Utah Salt Lake City 4,140 -2.9% (118) 4,022 Vermont Burlington 0 0.0% 0 0 Virginia Alexandria 0 0.0% 0 0 Virginia Lynchburg 0 0.0% 0 0 Washington Seattle 4,140 3.8% 158 4,298 Washington Spokane 4,140 -1.7% (72) 4,068 West Virginia Charleston 0 0.0% 0 0 Wisconsin Green Bay 0 0.0% 0 0 Wyoming Cheyenne 4,140 -2.6% (106) 4,034 Puerto Rico Cayey 0 0.0% 0 0

17.5 O&M ESTIMATE In addition to the general items discussed in the section of this report entitled O&M Estimate, the Binary Facility includes major 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.

TABLE 17-3 – O&M EXPE NSES FOR BINARY Technology: GT Fixed O&M Expense $43.82/kW-year Variable O&M Expense $5.15/MWh17-6 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 MWh18-1 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 Marin 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 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 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, truc k or barge. Water for all processes at the MSW Facility can be obtained from one of a vari ety of sources. The MSW Facility uses a water treatment system and a high-efficiency reverse osmosis system to reduce the dissolved solids from the cooling water and to provi de distilled water for boiler make -up. Wastewater is sent to a municipal wastewater system or other appr oved alternative. Further, the electrical interconnection from the MSW Fac ility on-site switchyard is eff ectuated by a connection to an adjacent utility substation.

18.4 CAPITAL COST ESTIMATE The base Cost Estimate for the MSW Facility with a nominal capacity of 50 MW is $8,232/kW. Table 18-1 summarizes the Cost Estimate categories for the GT Facility.18-3 TABLE 18-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR MSW Technology: MSW Nominal Capacity (ISO): 50,000 kW Nominal Heat Rate (ISO): 18,000 Btu/kWh-HHV

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

Civil Structural Material and Installation 33,875

Mechanical Equipment Supply and Installation 183,000

Electrical / I&C Supply and Installation 25,300

Project Indirects (1) 56,080

EPC Cost before Contingency and Fee 298,255

Fee and Contingency 44,738

Total Project EPC 342,993

Owner Costs (excluding project finance) 68,599

Total Project Cost (excluding finance) 411,592

Total Project EPC / kW 6,860

Owner Costs 20% (excluding project finance) / kW 1,372

Total Project Cost (excluding project finance) / kW 8,232

(1) Includes engineering, distributable costs, 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 include18-4 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, Minnesota, New York, Ohio, and Wisconsin. Table 18-2 presents the MSW Facility capital cost variations for alternative U.S. plant locations.

TABLE 18-2 – LOCATION-BASED COSTS FOR MSW (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 8,240 12.8% 1,054 9,294 Alaska Fairbanks 8,240 17.7% 1,459 9,699 Alabama Huntsville 8,240 -5.8% (474) 7,766 Arizona Phoenix 8,240 -4.5% (371) 7,869 Arkansas Little Rock 8,240 -4.7% (387) 7,853 California Los Angeles 8,240 5.2% 430 8,670 California Redding 8,240 1.9% 154 8,394 California Bakersfield 8,240 2.1% 176 8,416 California Sacramento 8,240 5.7% 472 8,712 California San Francisco 8,240 13.4% 1,104 9,344 Colorado Denver 8,240 -4.7% (384) 7,856 Connecticut Hartford 8,240 5.2% 429 8,669 Delaware Dover 8,240 3.1% 258 8,498

District of Columbia Wash ington 8,240 1.7% 140 8,380 Florida Tallahassee 8,240 -7.9% (649) 7,591 Florida Tampa 8,240 -3.3% (268) 7,972 Georgia Atlanta 8,240 -6.3% (515) 7,725 Hawaii Honolulu 8,240 19.9% 1,638 9,878 Idaho Boise 8,240 -3.8% (315) 7,925 Illinois Chicago 8,240 12.5% 1,033 9,273 Indiana Indianapolis 8,240 -0.9% (78) 8,162 Iowa Davenport 8,240 -1.0% (79) 8,161 Iowa Waterloo 8,240 -6.7% (548) 7,692 Kansas Wichita 8,240 -5.4% (446) 7,794 Kentucky Louisville 8,240 -4.8% (392) 7,848 Louisiana New Orleans 8,240 -7.3% (603) 7,637 Maine Portland 8,240 -4.1% (341) 7,899 Maryland Baltimore 8,240 -1.7% (144) 8,09618-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Massachusetts Boston 8,240 11.8% 975 9,215 Michigan Detroit 8,240 2.7% 220 8,460 Michigan Grand Rapids 8,240 -5.8% (475) 7,765 Minnesota St. Paul 8,240 2.3% 190 8,430 Mississippi Jackson 8,240 -5.7% (471) 7,769 Missouri St. Louis 8,240 3.0% 247 8,487 Missouri Kansas City 8,240 1.8% 150 8,390 Montana Great Falls 8,240 -4.0% (333) 7,907 Nebraska Omaha 8,240 -3.0% (243) 7,997 New Hampshire Concord 8,240 -2.0% (166) 8,074 New Jersey Newark 8,240 11.9% 984 9,224 New Mexico Albuquerque 8,240 -3.5% (287) 7,953 New York New York 8,240 26.3% 2,167 10,407 New York Syracuse 8,240 -0.4% (31) 8,209 Nevada Las Vegas 8, 240 4.5% 370 8,610 North Carolina Charlotte 8,240 -8.3% (688) 7,552 North Dakota Bismarck 8,240 -5.6% (463) 7,777 Ohio Cincinnati 8,240 -3.1% (256) 7,984 Oregon Portland 8,240 1.7% 136 8,376 Pennsylvania Philadelphia 8,240 8.5% 698 8,938 Pennsylvania Wilkes-Barre 8,240 -3.4% (283) 7,957

Rhode Island Providenc e 8,240 2.8% 229 8,469 South Carolina Spartanburg 8,240 -9.5% (786) 7,454 South Dakota Rapid City 8,240 -7.9% (654) 7,586 Tennessee Knoxville 8,240 -7.3% (603) 7,637 Texas Houston 8,240 -7.3% (598) 7,642 Utah Salt Lake City 8,240 -4.9% (401) 7,839 Vermont Burlington 8,240 -4.4% (364) 7,876 Virginia Alexandria 8,240 -1.8% (148) 8,092 Virginia Lynchburg 8,240 -5.1% (420) 7,820 Washington Seattle 8,240 4.1% 342 8,582 Washington Spokane 8,240 -2.8% (228) 8,012 West Virginia Charleston 8,240 -1.6% (135) 8,105 Wisconsin Green Bay 8,240 -2.3% (186) 8,054 Wyoming Cheyenne 8,240 -4.6% (383) 7,857 Puerto Rico Cayey 8,240 -1.7% (144) 8,096

18.5 O&M ESTIMATE In addition to the general items discussed in the section of this report entitled O&M Estimate, the MSW Facility includes major maintenance for th e feedstock handling, ST, electric generator, boiler, and BOP systems. Table 18-3 presents the O&M expenses for the MSW Facility.18-6 TABLE 18-3 – O&M EXPENSES FOR MSW Technology: MSW Fixed O&M Expense $373.76/kW-year Variable O&M Expense $8.33/MWh

18.6 ENVIRONMENTAL 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/MMBtu19-1 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 $3,076/kW. Table 19-1 summarizes the Cost Estimate categories for the HY Facility.

TABLE 19-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR HY Technology: HY Nominal Capacity (ISO): 500,000 kW Nominal Heat Rate (ISO): Not Applicable

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

Civil Structural Material and Installation 634,250

Mechanical Equipment Supply and Installation 253,000

Electrical / I&C Supply and Installation 77,600

Project Indirects (1) 174,500

EPC Cost before Contingency and Fee 1,139,350

Fee and Contingency 142,419

Total Project EPC 1,281,769

Owner Costs (excluding project finance) 256,354

Total Project Cost (excluding finance) 1,538,123

Total Project EPC / kW 2,564

Owner Costs 20% (excluding project finance) / kW 513

Total Project Cost (excluding project finance) / kW 3,076

(1) Includes engineering, distributable costs, 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 Delaware. These are areas where technical enhancements generally need to be made by a project developer or utility to comply with the applicable permitting/siting requirements. Remote location issues are related to geographic 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 Alaska, California, Connecticut, Maine, Ohio, and South Dakota. Table 19-2 presents the HY Facility capital cost va riations for alternative U.S. plant locations.19-4 TABLE 19-2 – LOCATION-BASED COSTS FOR HY (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 3,080 20.1% 619 3,699 Alaska Fairbanks 3,080 31.6% 974 4,054

Alabama Huntsville 0 0.0% 0 0

Arizona Phoenix 0 0.0% 0 0

Arkansas Little Rock 0 0.0% 0 0 California Los Angeles 3,080 7.4% 228 3,308 California Redding 3,080 2.8% 88 3,168 California Bakersfield 3,080 2.4% 75 3,155 California Sacramento 3,080 3.7% 113 3,193 California San Francisco 3,080 13.2% 408 3,488 Colorado Denver 3,080 -1.3% (40) 3,040 Connecticut Hartford 3,080 6.4% 197 3,277

Delaware Dover 0 0.0% 0 0 District of Columbia Washington 0 0.0% 0 0

Florida Tallahassee 0 0.0% 0 0 Florida Tampa 0 0.0% 0 0 Georgia Atlanta 0 0.0% 0 0

Hawaii Honolulu 0 0.0% 0 0 Idaho Boise 3,080 -1.6% (49) 3,031 Illinois Chicago 0 0.0% 0 0 Indiana Indianapolis 0 0.0% 0 0 Iowa Davenport 0 0.0% 0 0 Iowa Waterloo 0 0.0% 0 0

Kansas Wichita 0 0.0% 0 0 Kentucky Louisville 0 0.0% 0 0

Louisiana New Orleans 0 0.0% 0 0 Maine Portland 3,080 -0.8% (23) 3,057 Maryland Baltimore 0 0.0% 0 0

Massachusetts Boston 0 0.0% 0 0 Michigan Detroit 0 0.0% 0 0 Michigan Grand Rapids 0 0.0% 0 0

Minnesota St. Paul 0 0.0% 0 0 Mississippi Jackson 0 0.0% 0 0 Missouri St. Louis 3,080 1.3% 41 3,121 Missouri Kansas City 3,080 1.4% 42 3,122 Montana Great Falls 3,080 -1.2% (37) 3,043

Nebraska Omaha 0 0.0% 0 0 New Hampshire Concord 0 0.0% 0 0 New Jersey Newark 0 0.0% 0 0 New Mexico Albuquerque 0 0.0% 0 019-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW)

New York New York 0 0.0% 0 0 New York Syracuse 0 0.0% 0 0 Nevada Las Vegas 0 0.0% 0 0 North Carolina Charlotte 3,080 0.0% 20 3,100

North Dakota Bismarck 0 0.0% 0 0 Ohio Cincinnati 3,080 -1.6% (49) 3,031 Oregon Portland 3,080 4.7% 145 3,225 Pennsylvania Philadelphia 0 0.0% 0 0 Pennsylvania Wilkes-Barre 0 0.0% 0 0

Rhode Island Providence 0 0.0% 0 0 South Carolina Spartanburg 0 0.0% 0 0 South Dakota Rapid City 3,080 -3.9% (119) 2,961

Tennessee Knoxville 0 0.0% 0 0

Texas Houston 0 0.0% 0 0 Utah Salt Lake City 0 0.0% 0 0 Vermont Burlington 0 0.0% 0 0 Virginia Alexandria 0 0.0% 0 0 Virginia Lynchburg 0 0.0% 0 0 Washington Seattle 3,080 3.5% 109 3,189 Washington Spokane 3,080 -1.0% (31) 3,049 West Virginia Charleston 0 0.0% 0 0 Wisconsin Green Bay 0 0.0% 0 0 Wyoming Cheyenne 0 0.0% 0 0 Puerto Rico Cayey 0 0.0% 0 0

19.5 O&M ESTIMATE In addition to the general items discussed in the section of the report entitled O&M Estimate, the most significant differentiating O&M expenses 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 $13.44/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.19-6 TABLE 19-4 – ENVIRONMENTAL EMISSIONS FOR HY Technology: HY NO X 0 lb/MMBtu SO 2 0 lb/MMBtu CO 2 0 lb/MMBtu20-1 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 plant20-2 loads when the hydro-turbines are not operating, si gnificant volumes of electricity are consumed in off-peak hours at the PS Facility.

20.4 CAPITAL COST ESTIMATE The base Cost Estimate for the PS Facility with a nominal capacity of 250 MW is $5,595/kW. Table 20-1 summarizes the Cost Estimate 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, 2010$)

Civil Structural Material and Installation 653,000

Mechanical Equipment Supply and Installation 152,400

Electrical / I&C Supply and Installation 73,700

Project Indirects (1) 171,100

EPC Cost before Contingency and Fee 1,050,200

Fee and Contingency 115,522

Total Project EPC 1,165,722

Owner Costs (excluding project finance) 233,144

Total Project Cost (excluding finance) 1,398,866

Total Project EPC / kW 4,663

Owner Costs 20% (excluding project finance) / kW 933

Total Project Cost (excluding project finance) / kW 5,595

(1) Includes engineering, distributable costs, 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 below20-3 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. 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, Minnesota, New York, Ohio; and Wisconsin. Table 20-2 presents the PS Facility capital cost variations for alternative U.S. plant locations.20-4 TABLE 20-2 – LOCATION-BASED COSTS FOR PS (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 5,595 17.6% 985 6,580 Alaska Fairbanks 5,595 24.7% 1,382 6,977 Alabama Huntsville 5,595 -7.4% (413) 5,182 Arizona Phoenix 5,595 -5.7% (322) 5,273 Arkansas Little Rock 5,595 -6.0% (335) 5,260 California Los Angeles 5,595 7.1% 398 5,993 California Redding 5,595 2.5% 141 5,736 California Bakersfield 5,595 3.0% 166 5,761 California Sacramento 5,595 7.5% 422 6,017 California San Francisco 5,595 17.8% 994 6,589 Colorado Denver 5,595 -5.9% (329) 5,266 Connecticut Hartford 5,595 7.0% 392 5,987 Delaware Dover 5,595 4.3% 243 5,838

District of Columbia Wash ington 5,595 2.8% 155 5,750

Florida Tallahassee 0 0 0 0 Florida Tampa 0 0 0 0 Georgia Atlanta 5,595 -8.0% (449) 5,146 Hawaii Honolulu 5,595 15.8% 883 6,478 Idaho Boise 5,595 -4.9% (273) 5,322 Illinois Chicago 5,595 16.2% 907 6,502 Indiana Indianapolis 5,595 -1.1% (64) 5,531 Iowa Davenport 5,595 -1.2% (66) 5,529 Iowa Waterloo 5,595 -8.5% (476) 5,119

Kansas Wichita 0 0 0 0 Kentucky Louisville 5,595 -6.1% (341) 5,254 Louisiana New Orleans 5,595 -9.3% (519) 5,076 Maine Portland 5,595 -5.2% (290) 5,305 Maryland Baltimore 5,595 -2.0% (110) 5,485 Massachusetts Boston 5,595 15.5% 869 6,464 Michigan Detroit 5,595 3.5% 196 5,791 Michigan Grand Rapids 5,595 -7.4% (413) 5,182 Minnesota St. Paul 5,595 3.0% 168 5,763 Mississippi Jackson 5,595 -7.3% (410) 5,185 Missouri St. Louis 5,595 4.0% 222 5,817 Missouri Kansas City 5,595 2.4% 136 5,731 Montana Great Falls 5,595 -5.1% (286) 5,309 Nebraska Omaha 5,595 -3.7% (209) 5,386 New Hampshire Concord 5,595 -2.5% (140) 5,455 New Jersey Newark 5,595 15.5% 867 6,462 New Mexico Albuquerque 5,595 -4.4% (245) 5,35020-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New York New York 5,595 34.3% 1,921 7,516 New York Syracuse 5,595 -0.2% (13) 5,582 Nevada Las Vegas 5, 595 5.8% 326 5,921 North Carolina Charlotte 5,595 -10.7% (599) 4,996 North Dakota Bismarck 5,595 -7.1% (399) 5,196 Ohio Cincinnati 5,595 -3.9% (220) 5,375 Oregon Portland 5,595 3.1% 171 5,766 Pennsylvania Philadelphia 5,595 11.0% 615 6,210 Pennsylvania Wilkes-Barre 5,595 -4.3% (243) 5,352

Rhode Island Providenc e 5,595 3.7% 209 5,804 South Carolina Spartanburg 5,595 -12.2% (684) 4,911 South Dakota Rapid City 5, 595 -10.2% (569) 5,026 Tennessee Knoxville 5,595 -9.4% (526) 5,069 Texas Houston 5,595 -9.3% (523) 5,072 Utah Salt Lake City 5,595 -6.2% (344) 5,251 Vermont Burlington 5,595 -5.5% (309) 5,286 Virginia Alexandria 5,595 -2.2% (121) 5,474 Virginia Lynchburg 5,595 -6.5% (366) 5,229 Washington Seattle 5,595 5.4% 305 5,900 Washington Spokane 5,595 -3.5% (197) 5,398 West Virginia Charleston 5,595 -2.0% (114) 5,481 Wisconsin Green Bay 5,595 -2.8% (157) 5,438 Wyoming Cheyenne 5,595 -5.8% (324) 5,271 Puerto Rico Cayey 5,595 -1.7% (95) 5,500

20.5 O&M ESTIMATE The O&M discussion in Section 17.5, related to the HY Facility at a high-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 Facility are pump and associated motor maintenance. Table 20-3 presents the O&M expenses for the PS Facility.

TABLE 20-3 – O&M EXPENSES FOR PS Technology: PS Fixed O&M Expense $13.03/kW-year Variable O&M Expense $0/MWh

20.6 ENVIRONMENTAL 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 off-peak pumping to the reservoir, is not cons idered in this report. Table 20-4 presents environmental emissions for the PS Facility.20-6 TABLE 20-4 – ENVIRONMENTAL EMISSIONS FOR PS Technology: PS NO X 0 lb/MMBtu SO 2 0 lb/MMBtu CO 2 0 lb/MMBtu21-1 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 CONFIGURATION21-2 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 interconn ected on one or more underground collector circuits that are connected to a collector bus through a circuit breaker for each circuit. The collector bus is connected to a high-voltage transmission system through the facility substation, which 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 $2,400/kW. Table 21-1 summarizes the Cost Estimate categories for the WN Facility.21-3 TABLE 21-1 – LOCATION-BASED COSTS FOR WN Technology: WN Nominal Capacity (ISO): 100,000 kW Nominal Heat Rate (ISO): N/A Btu/kWh-HHV

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

Civil Structural Material and Installation 25,625

Mechanical Equipment Supply and Installation 158,585

Electrical / I&C Supply and Installation 27,753

Project Indirects (1) 8,070

EPC Cost before Contingency and Fee 220,033

Fee and Contingency 10,000

Total Project EPC 230,033

Owner Costs (excluding project finance) 13,802

Total Project Cost (excluding finance) 243,835

Total Project EPC / kW 2,300

Owner Costs 6% (excluding project finance) / kW 138

Total Project Cost (excluding project finance) / kW 2,438

(1) Includes engineering, distributable costs, 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 include21-4 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 21-2 presents the WN Facility capital cost variations for alternative U.S. plant locations.

TABLE 21-2 – LOCATION-BASED COSTS FOR WN (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 2,440 25.2% 615 3,055 Alaska Fairbanks 2,440 45.0% 1,099 3,539 Alabama Huntsville 2,440 -3.5% (86) 2,354 Arizona Phoenix 2,440 -2.4% (58) 2,382 Arkansas Little Rock 2,440 -2.5% (61) 2,379 California Los Angeles 2,440 12.4% 304 2,744 California Redding 2,440 8.2% 200 2,640 California Bakersfield 2,440 10.0% 243 2,683 California Sacramento 2,440 10.5% 257 2,697 California San Francisco 2,440 18.6% 453 2,893 Colorado Denver 2,440 2.2% 54 2,494 Connecticut Hartford 2,440 6.6% 162 2,602 Delaware Dover 2,440 4.6% 111 2,551

District of Columbia Wash ington 2,440 7.4% 182 2,622 Florida Tallahassee 2,440 -5.3% (128) 2,312 Florida Tampa 2,440 -2.2% (53) 2,387 Georgia Atlanta 2,440 -3.9% (94) 2,346 Hawaii Honolulu 2,440 27.4% 668 3,108 Idaho Boise 2,440 3.4% 83 2,523 Illinois Chicago 2,440 14.2% 346 2,786 Indiana Indianapolis 2,440 0.3% 8 2,448 Iowa Davenport 2,440 4.5% 111 2,551 Iowa Waterloo 2,440 0.7% 18 2,458 Kansas Wichita 2,440 1.9% 46 2,486 Kentucky Louisville 2,440 -2.9% (70) 2,37021-5 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Louisiana New Orleans 2,440 -5.4% (132) 2,308 Maine Portland 2,440 6.4% 155 2,595 Maryland Baltimore 2,440 1.7% 41 2,481 Massachusetts Boston 2,440 11.1% 270 2,710 Michigan Detroit 2,440 2.7% 67 2,507 Michigan Grand Rapids 2,440 -3.2% (78) 2,362 Minnesota St. Paul 2,440 7.5% 183 2,623 Mississippi Jackson 2,440 -3.5% (85) 2,355 Missouri St. Louis 2,440 3.6% 88 2,528 Missouri Kansas City 2,440 1.7% 41 2,481 Montana Great Falls 2,440 3.9% 95 2,535 Nebraska Omaha 2,440 3.5% 86 2,526 New Hampshire Concord 2,440 5.3% 128 2,568 New Jersey Newark 2,440 10.5% 257 2,697 New Mexico Albuquerque 2,440 3.8% 93 2,533 New York New York 2,440 24.6% 600 3,040 New York Syracuse 2,440 0.8% 20 2,460 Nevada Las Vegas 2, 440 9.0% 219 2,659 North Carolina Charlotte 2,440 -4.9% (120) 2,320 North Dakota Bismarck 2,440 2.1% 50 2,490 Ohio Cincinnati 2,440 -1.9% (47) 2,393 Oregon Portland 2,440 8.0% 196 2,636 Pennsylvania Philadelphia 2,440 6.1% 150 2,590 Pennsylvania Wilkes-Barre 2,440 -1.8% (44) 2,396

Rhode Island Providenc e 2,440 2.1% 51 2,491 South Carolina Spartanburg 2,440 -5.7% (140) 2,300 South Dakota Rapid City 2,440 0.7% 17 2,457 Tennessee Knoxville 2,440 -4.6% (111) 2,329 Texas Houston 2,440 -4.8% (118) 2,322 Utah Salt Lake City 2,440 3.7% 90 2,530 Vermont Burlington 2,440 3.4% 83 2,523 Virginia Alexandria 2,440 1.9% 46 2,486 Virginia Lynchburg 2,440 -3.1% (75) 2,365 Washington Seattle 2,440 4.4% 107 2,547 Washington Spokane 2,440 4.9% 120 2,560 West Virginia Charleston 2,440 -0.1% (3) 2,437 Wisconsin Green Bay 2,440 -1.0% (25) 2,415 Wyoming Cheyenne 2,440 4.3% 105 2,545 Puerto Rico Cayey 2,440 6.9% 167 2,607

21.5 O&M ESTIMATE In addition to the general items discussed in the section of the report entitled O&M Estimate, the major areas for O&M for an Onshore Wind Facil ity include periodic gearbox, WTG, electric21-6 generator, and associated electric conversi on (e.g., GSU) technology repa irs and replacement. These devices typically undergo major maintenan ce every five to seve n years. Table 21-3 presents the O&M expenses for the WN Facility.

TABLE 21-3 – O&M EXPENSES FOR WN Technology: WN Fixed O&M Expense $28.07/kW-year Variable O&M Expense $0/MWh

21.6 ENVIRONMENTAL 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/MMBtu22-1 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 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 approximately 125 meters. The WTG has an active yaw system in the nacelle to keep the rotor facing into the wind. The WF WTG is designed to withstand the conditions of the high seas, including additional redundancy of key components to enhance availability, corrosion protection and permanent monitoring. Power is generated by the wind turbines, then converted using an onboard transformer to 34.5 kV AC. It is then delivered to a collection system at the base of each turbine. Power from all turbines is collected by the underground collection circuit. The collection system supplies power to a new substation designed to 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 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.22-3 22.4 CAPITAL COST ESTIMATE The base Cost Estimate for the WF Facility with a nominal capacity of 400 MW is $5,975/kW. Table 22-1 summarizes the Cost Estimate categories for the WF Facility.

TABLE 22-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR WF Technology: WF Nominal Capacity (ISO): 400,000 kW Nominal Heat Rate (ISO): N/A Btu/kWh-HHV

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

Civil Structural Material and Installation 252,000

Mechanical Equipment Supply and Installation 835,328

Electrical / I&C Supply and Installation 148,302

Project Indirects (1) 463,856

EPC Cost before Contingency and Fee 1,699,486

Fee and Contingency 212,436

Total Project EPC 1,911,922

Owner Costs (excluding project finance) 477,981

Total Project Cost (excluding finance) 2,389,903

Total Project EPC / kW 4,780

Owner Costs 25% (excluding project finance) / kW 1,195

Total Project Cost (excluding project finance) / kW 5,975

(1) Includes engineering, distributable costs, 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 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.22-4 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 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 Offshore Wind Facility 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 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Maine, Mary land, 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 presents the WF Facility capital cost variations for alternative U.S. plant locations.22-5 TABLE 22-2 – LOCATION-BASED COSTS FOR WF (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 5,975 15.9% 952 6,927 Alaska Fairbanks 0 0.0%

Alabama Huntsville 0 0.0%

Arizona Phoenix 0 0.0%

Arkansas Little Rock 0 0.0% California Los Angeles 5,975 7.7% 460 6,435 California Redding 0 0.0% California Bakersfield 0 0.0% California Sacramento 0 0.0% California San Francisco 5,975 16.6% 993 6,968

Colorado Denver 0 0.0% Connecticut Hartford 5,975 5.7% 342 6,317 Delaware Dover 5,975 3.1% 184 6,159

District of Columbia Wash ington 5,975 1.8% 110 6,085

Florida Tallahassee 0 0.0% Florida Tampa 0 0.0% Georgia Atlanta 5,975 -7.0% (418) 5,557 Hawaii Honolulu 5,975 14.5% 864 6,839

Idaho Boise 0 0.0% Illinois Chicago 5,975 16.0% 958 6,933 Indiana Indianapolis 5,975 -1.0% (58) 5,917 Iowa Davenport 0 0.0% Iowa Waterloo 0 0.0%

Kansas Wichita 0 0.0% Kentucky Louisville 0 0.0%

Louisiana New Orleans 0 0.0% Maine Portland 5,975 -2.6% (156) 5,819 Maryland Baltimore 5,975 -2.1% (126) 5,849 Massachusetts Boston 5,975 13.2% 787 6,762 Michigan Detroit 5,975 2.8% 165 6,140 Michigan Grand Rapids 5,975 -6.7% (403) 5,572 Minnesota St. Paul 5,975 4.8% 288 6,263 Mississippi Jackson 0 0.0%

Missouri St. Louis 0 0.0% Missouri Kansas City 0 0.0%

Montana Great Falls 0 0.0%

Nebraska Omaha 0 0.0% New Hampshire Concord 0 0.0% New Jersey Newark 5,975 12.7% 761 6,736 New Mexico Albuquerque 0 0.0%22-6 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New York New York 5,975 29.4% 1,759 7,734 New York Syracuse 5,975 -1.2% (69) 5,906 Nevada Las Vegas 0 0.0% North Carolina Charlotte 5,975 -9.3% (557) 5,418

North Dakota Bismarck 0 0.0%

Ohio Cincinnati 0 0.0% Oregon Portland 5,975 5.1% 302 6,277 Pennsylvania Philadelphia 0 0.0% Pennsylvania Wilkes-Barre 0 0.0%

Rhode Island Providenc e 5,975 2.5% 148 6,123 South Carolina Spartanburg 5,975 -6.6% (391) 5,584 South Dakota Rapid City 0 0.0%

Tennessee Knoxville 0 0.0% Texas Houston 5,975 -8.2% (487) 5,488 Utah Salt Lake City 0 0.0% Vermont Burlington 0 0.0% Virginia Alexandria 5,975 -2.7% (161) 5,814 Virginia Lynchburg 5,975 -5.7% (340) 5,635 Washington Seattle 5,975 4.8% 287 6,262 Washington Spokane 0 0.0% West Virginia Charleston 0 0.0% Wisconsin Green Bay 5,975 -2.7% (164) 5,811 Wyoming Cheyenne 0 0.0% Puerto Rico Cayey 5,975 -1.2% (72) 5,903

22.5 O&M ESTIMATE The types of maintenance performed on the WF Facility are materially similar to the WN Facility, discussed in Section 19.5; however, the expenses are higher because maintaining offshore parts is considerably more complicated, due to staging on ships and with helicopters. Table 22-3 presents the FOM and VOM expenses for the WF Facility.

TABLE 22-3 – O&M EXPENSES FOR WF Technology: WF Fixed O&M Expense $53.33/kW-year Variable O&M Expense $0/MWh

22.6 ENVIRONMENTAL 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.22-7 TABLE 22-4 – ENVIRONMENTAL EMISSIONS FOR WF Technology: WF NO X 0 lb/MMBtu SO 2 0 lb/MMBtu CO 2 0 lb/MMBtu23-1 23. SOLAR THERMAL - CENTRAL STATION (SO)

23.1 MECHANICAL EQUIPM ENT AND SYSTEMS The 100 MW Solar Thermal (“SO”) Facility uses a solar concentrating thermal process based on direct steam, power towers, and heliostat mirror technology. The SO Facility incorporates a Rankine-cycle reheat ST which receives stea m from a solar steam generator and a solar superheater and reheated steam from a solar reheater. The solar steam generator, solar superheater, and solar reheater are all installed at the top of a tower adjacent to a power block located at grade. The tower and power block are ge nerally in the center of a heliostat solar field. The solar energy heats water in the steam generato r, superheater and reheat boiler to make steam that runs the ST. The solar field and power generation equipment are started up each morning after sunrise and insolation (or li ght intensity) build-up, and are shut down in the evening when insolation drops below the level requir ed for keeping the ST online. A partial load natural gas-fired boiler is used for thermal input to the ST during the morning start-up cycle. The boiler is also generally operated during tran sient cloudy conditions, in order to keep the ST online and rea dy to resume production from sola r thermal input, after the clouds clear. After the cloud passes and solar-to-thermal input resumes, th e ST will be re turned to full solar production and the gas-fire d boiler is shut down. While pe rmitting SO facilities with respect to water usage continues to be a challeng e, our base assumption is that the SO Facility uses wet cooling technology. The power block consists of one solar power tower and an ST with a reheat cycle, and it uses typical auxiliary components fo r heat rejection, water treatment, water disposal, and interconnection to the grid. Figure 23-1 pres ents a picture of a typical SO Facility.23-2 FIGURE 23-1 – SO DESIGN CONFIGURATION

23.2 ELECTRICAL AND CONTROL SYSTEMS The SO Facility has one ST electric generator. The generator is a 60 Hz machine rated at approximately 120 MVA with an output voltage of 13.8 kV. The ST electric generator is connected to a high-voltage bus in the facility switchyard via a dedicated generator circuit breaker, GSU, high-voltage 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.23-3 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 a one of several available water sources (e.g., municipal water supply); however, due to the remote location of most solar thermal power plants, water is often s ourced through on-site wells. Th e SO Facility uses a water treatment system and a high-efficiency reverse osmosis system to reduce the dissolved solids from the cooling water and to 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 $4,692/kW. Table 23-1 summarizes the Cost Estimate categories for the SO Facility.23-4 TABLE 23-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR SO Technology: SO Nominal Capacity (ISO): 100,000 kW Nominal Heat Rate (ISO): N/A Btu/kWh-HHV (2)

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

Civil Structural Material and Installation 48,475

Mechanical Equipment Supply and Installation 254,250

Electrical / I&C Supply and Installation 40,750

Project Indirects (1) 39,500

EPC Cost before Contingency and Fee 382,975

Fee and Contingency 25,000

Total Project EPC 407,975

Owner Costs (excluding project finance) 61,196

Total Project Cost (excluding finance) 469,171

Total Project EPC / kW 4,080

Owner Costs 15% (excluding project finance) / kW 612

Total Project Cost (excluding project finance) / kW 4,692

(1) Includes engineering, distributable costs, 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 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 near23-5 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 presents the SO Facility capital cost variations for alternative U.S. plant locations.23-6 TABLE 23-2 – LOCATION-BASED COSTS FOR SO (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 4,700 23.8% 1,119 5,819 Alaska Fairbanks 4,700 35.4% 1,662 6,362 Alabama Huntsville 4,700 -11.3% (532) 4,168 Arizona Phoenix 4,700 -8.9% (417) 4,283 Arkansas Little Rock 4,700 -9.3% (435) 4,265 California Los Angeles 4,700 11.4% 538 5,238 California Redding 4,700 6.3% 297 4,997 California Bakersfield 4,700 6.7% 316 5,016 California Sacramento 4,700 13.3% 623 5,323 California San Francisco 4,700 26.8% 1,261 5,961 Colorado Denver 4,700 -7.3% (344) 4,356 Connecticut Hartford 4,700 9.2% 431 5,131 Delaware Dover 4,700 4.7% 220 4,920

District of Columbia Wash ington 4,700 1.6% 74 4,774 Florida Tallahassee 4,700 -15.5% (727) 3,973 Florida Tampa 4,700 -6.4% (300) 4,400 Georgia Atlanta 4,700 -12.3% (578) 4,122 Hawaii Honolulu 4,700 39.8% 1,871 6,571 Idaho Boise 4,700 -4.8% (225) 4,475 Illinois Chicago 4,700 26.8% 1,262 5,962 Indiana Indianapolis 4,700 -1.9% (90) 4,610 Iowa Davenport 4,700 0.4% 20 4,720 Iowa Waterloo 4,700 -10.8% (505) 4,195 Kansas Wichita 4,700 -8.3% (392) 4,308 Kentucky Louisville 4,700 -9.4% (440) 4,260 Louisiana New Orleans 4,700 -15.9% (748) 3,952 Maine Portland 4,700 -5.9% (278) 4,422 Maryland Baltimore 4,700 -4.4% (209) 4,491 Massachusetts Boston 4,700 22.2% 1,043 5,743 Michigan Detroit 4,700 4.8% 224 4,924 Michigan Grand Rapids 4,700 -11.8% (554) 4,146 Minnesota St. Paul 4,700 7.2% 340 5,040 Mississippi Jackson 4,700 -11.2% (528) 4,172 Missouri St. Louis 4,700 5.7% 270 4,970 Missouri Kansas City 4,700 3.1% 144 4,844 Montana Great Falls 4,700 -5.3% (248) 4,452 Nebraska Omaha 4,700 -3.5% (165) 4,535 New Hampshire Concord 4,700 -1.7% (80) 4,620 New Jersey Newark 4, 700 22.2% 1,042 5,742 New Mexico Albuquerque 4,700 -4.6% (217) 4,48323-7 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New York New York 4,700 50.1% 2,355 7,055 New York Syracuse 4,700 -2.4% (114) 4,586 Nevada Las Vegas 4, 700 11.5% 542 5,242 North Carolina Charlotte 4,700 -16.4% (772) 3,928 North Dakota Bismarck 4,700 -8.8% (412) 4,288 Ohio Cincinnati 4,700 -6.6% (310) 4,390 Oregon Portland 4,700 5.9% 277 4,977 Pennsylvania Philadelphia 4,700 16.1% 758 5,458 Pennsylvania Wilkes-Barre 4,700 -7.3% (341) 4,359

Rhode Island Providenc e 4,700 4.2% 196 4,896 South Carolina Spartanburg 4,700 -18.8% (882) 3,818 South Dakota Rapid City 4, 700 -12.8% (604) 4,096 Tennessee Knoxville 4,700 -14.4% (677) 4,023 Texas Houston 4,700 -14.2% (670) 4,030 Utah Salt Lake City 4,700 -6.9% (325) 4,375 Vermont Burlington 4,700 -7.2% (338) 4,362 Virginia Alexandria 4,700 -4.8% (225) 4,475 Virginia Lynchburg 4,700 -10.0% (471) 4,229 Washington Seattle 4,700 8.0% 377 5,077 Washington Spokane 4,700 -2.7% (127) 4,573 West Virginia Charleston 4,700 -3.3% (155) 4,545 Wisconsin Green Bay 4,700 -4.9% (232) 4,468 Wyoming Cheyenne 4,700 -7.0% (329) 4,371 Puerto Rico Cayey 4,700 -4.0% (190) 4,510

23.5 O&M ESTIMATE The typical O&M expenses for th e SO Facility include mirror cleaning, repair, and replacement; thermal tube replacements; and BOP major mainte nance. The BOP major maintenance is similar to that which is performed on a combined-cycle plant: HRSG, ST, and el ectric generator major maintenance, typically performed approximately every seven years. Additionally, most thermal solar operators do not treat O&M on a variable basis, and consequently, all O&M expenses are shown below on a fixed basis. Table 23-3 pres ents the O&M expenses for the SO Facility.

TABLE 23-3 – O&M EXPENSES FOR SO Technology: SO Fixed O&M Expense $64.00/kW-year Variable O&M Expense $0/MWh

23.6 ENVIRONMENTAL COMPLI ANCE INFORMATION Table 23-4 presents environmental emissions for the SO Facility.23-8 TABLE 23-4 – ENVIRONMENTAL EMISSIONS FOR SO Technology: SO NO X 0 lb/MMBtu SO 2 0 lb/MMBtu CO 2 0 lb/MMBtu24-1 24. PHOTOVOLTAIC (CENTRAL STATION) FACILITY (PV)

24.1 MECHANICAL EQUIPM ENT AND SYSTEMS The following describes a nominally 7 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 7 MW Facility; however, a detaile d technical description (due to the similarities with the 7 MW Facility and the technology associat ed therewith) is not pr ovided herein. The PV Facility uses numerous arrays of ground-mounte d, fixed-tilt PV modules which directly convert incident solar radiation into DC electricity, whic h can then be inverted to AC. Additional BOP components include metal racks and foundations to support fixed panels a nd keep them aligned at the correct angle, DC wiring, combiner boxes where individual st rings of panels are connected prior to being fed into the inverters, DC-to-AC inverters, AC wiring, various switchgear and step-up transformers, and a control system (par tly incorporated into the inverter control electronics) to monitor plant output and adjust the balance of voltage and current to yield maximum power. Figure 22-1 presents a picture of a typical PV Facility.

FIGURE 24-1 – PV DESIGN CONFIGURATION

24.2 ELECTRICAL AND CONTROL SYSTEMS The 7 MW-AC PV Facility is comprised of 14 half-megawatt building blocks, each block consisting of groups of PV modules connected to a 500 kW-AC inverter. While the ratio of DC module capacity to AC inverter ca pacity varies, for this analysis we have assumed a ratio of24-2 1.2:1, or 600 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 “s trings” which are then connected in parallel in a combiner box which contains a fuse for each stri ng. The cables are routed from the modules to combiner boxes and a number of combiner boxe s are connected to the input of a 500 kW-AC inverter, which converts the aggreg ate power from DC to three-phase AC electricity at an output voltage of typically 265 V. Th e output voltage of an inverter (or sometimes several inverters connected together) is stepped up to a higher voltage level, typi cally in the range of 13.8 kV (or 34.5 kV for larger systems) through a GSU connect ed to the inverter output terminals. Two inverters are often combined on each of transf ormer, each of which is rated 1 MVA. 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 Facil ity are water supply (generally in limited quantities) and an electrical interconnection between the PV Facility switchyard and the local utility distribution system.

24.4 CAPITAL COST ESTIMATE The base Cost Estimate for the PV Facility with a nominal capacity of 7 MW-AC is 6,050/kW and with a nominal capacity of 150 MW is $4,755/kW. Tabl e 24-1 and Table 24-2 summarize the Cost Estimate categories for the PV Facility.24-3 TABLE 24-1 – BASE PLANT SITE CAPITAL COST ESTIMATE FOR PV Technology: PV Nominal Capacity (ISO): 7,000 kW Nominal Heat Rate (ISO): N/A Btu/kWh-HHV

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

Civil Structural Material and Installation 6,100

Mechanical Equipment Supply and Installation 20,500

Electrical / I&C Supply and Installation 3,550

Project Indirects (1) 3,665

EPC Cost before Contingency and Fee 33,815

Fee and Contingency 4,000

Total Project EPC 37,815

Owner Costs (excluding project finance) 4,538

Total Project Cost (excluding finance) 42,353

Total Project EPC / kW 5,402

Owner Costs 12% (excluding project finance) / kW 648

Total Project Cost (excluding project finance) / kW 6,050

(1) Includes engineering, distributable costs, 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, 2010$)

Civil Structural Material and Installation 65,000

Mechanical Equipment Supply and Installation 391,583

Electrical / I&C Supply and Installation 64,350

Project Indirects (1) 52,762

EPC Cost before Contingency and Fee 573,695

Fee and Contingency 68,843

Total Project EPC 642,538

Owner Costs (excluding project finance) 70,679

Total Project Cost (excluding finance) 713,217

Total Project EPC / kW 4,283

Owner Costs 12% (excluding project finance) / kW 471

Total Project Cost (excluding project finance) / kW 4,755

(1) Includes engineering, distributable costs, 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 include24-5 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 Alaska, California, Connecticut, Delaware, District of Columbia, Hawaii, Illinois, Maine, Ma ryland, Massachusetts, Michigan, 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 present the PV Facility capital cost variations for alternative U.S. plant locations.24-6 TABLE 24-3 – LOCATION-BASED COSTS FOR PV (7 MW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 6,050 16.8% 1,016 7,066 Alaska Fairbanks 6,050 25.6% 1,548 7,598 Alabama Huntsville 6,050 -7.3% (441) 5,609 Arizona Phoenix 6,050 -5.7% (344) 5,706 Arkansas Little Rock 6,050 -5.9% (359) 5,691 California Los Angeles 6,050 8.1% 490 6,540 California Redding 6,050 4.6% 277 6,327 California Bakersfield 6,050 5.0% 301 6,351 California Sacramento 6,050 9.1% 549 6,599 California San Francisco 6,050 18.1% 1,096 7,146 Colorado Denver 6,050 -4.3% (263) 5,787 Connecticut Hartford 6,050 6.2% 376 6,426 Delaware Dover 6,050 3.3% 198 6,248

District of Columbia Wash ington 6,050 1.6% 96 6,146 Florida Tallahassee 6,050 -10.0% (605) 5,445 Florida Tampa 6,050 -4.1% (250) 5,800 Georgia Atlanta 6,050 -7.9% (480) 5,570 Hawaii Honolulu 6,050 29.9% 1,812 7,862 Idaho Boise 6,050 -2.7% (162) 5,888 Illinois Chicago 6,050 17.8% 1,075 7,125 Indiana Indianapolis 6,050 -1.2% (70) 5,980 Iowa Davenport 6,050 0.6% 38 6,088 Iowa Waterloo 6,050 -6.6% (399) 5,651 Kansas Wichita 6,050 -5.0% (303) 5,747 Kentucky Louisville 6,050 -6.0% (364) 5,686 Louisiana New Orleans 6,050 -10.3% (622) 5,428 Maine Portland 6,050 -3.4% (203) 5,847 Maryland Baltimore 6,050 -2.6% (158) 5,892 Massachusetts Boston 6,050 14.6% 885 6,935 Michigan Detroit 6,050 3.1% 188 6,238 Michigan Grand Rapids 6,050 -7.6% (461) 5,589 Minnesota St. Paul 6,050 5.1% 308 6,358 Mississippi Jackson 6,050 -7.2% (438) 5,612 Missouri St. Louis 6,050 3.9% 233 6,283 Missouri Kansas City 6,050 2.0% 123 6,173 Montana Great Falls 6,050 -2.9% (178) 5,872 Nebraska Omaha 6,050 -1.9% (114) 5,936 New Hampshire Concord 6,050 -0.7% (42) 6,008 New Jersey Newark 6,050 14.4% 869 6,919 New Mexico Albuquerque 6,050 -2.5% (154) 5,89624-7 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New York New York 6,050 32.9% 1,988 8,038 New York Syracuse 6,050 -1.4% (86) 5,964 Nevada Las Vegas 6, 050 7.9% 476 6,526 North Carolina Charlotte 6,050 -10.6% (640) 5,410 North Dakota Bismarck 6,050 -5.3% (318) 5,732 Ohio Cincinnati 6,050 -4.2% (256) 5,794 Oregon Portland 6,050 4.3% 260 6,310 Pennsylvania Philadelphia 6,050 10.5% 634 6,684 Pennsylvania Wilkes-Barre 6,050 -4.6% (281) 5,769

Rhode Island Providenc e 6,050 2.7% 166 6,216 South Carolina Spartanburg 6,050 -12.1% (731) 5,319 South Dakota Rapid City 6,050 -7.9% (477) 5,573 Tennessee Knoxville 6,050 -9.3% (562) 5,488 Texas Houston 6,050 -9.2% (557) 5,493 Utah Salt Lake City 6,050 -4.0% (240) 5,810 Vermont Burlington 6,050 -4.2% (256) 5,794 Virginia Alexandria 6,050 -3.1% (185) 5,865 Virginia Lynchburg 6,050 -6.5% (391) 5,659 Washington Seattle 6,050 5.3% 322 6,372 Washington Spokane 6,050 -1.3% (81) 5,969 West Virginia Charleston 6,050 -2.0% (124) 5,926 Wisconsin Green Bay 6,050 -3.1% (190) 5,860 Wyoming Cheyenne 6,050 -4.0% (240) 5,810 Puerto Rico Cayey 6,050 -1.9% (117) 5,93324-8 TABLE 24-4 – LOCATION-BASE D COSTS FOR PV (150 MW) (OCTOBER 1, 2010 DOLLARS)

State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) Alaska Anchorage 4,755 19.9% 947 5,702 Alaska Fairbanks 4,755 30.9% 1,470 6,225 Alabama Huntsville 4,755 -8.0% (379) 4,376 Arizona Phoenix 4,755 -6.2% (294) 4,461 Arkansas Little Rock 4,755 -6.5% (307) 4,448 California Los Angeles 4,755 9.6% 458 5,213 California Redding 4,755 5.5% 263 5,018 California Bakersfield 4,755 6.1% 291 5,046 California Sacramento 4,755 10.5% 498 5,253 California San Francisco 4,755 20.7% 985 5,740 Colorado Denver 4,755 -4.4% (208) 4,547 Connecticut Hartford 4,755 7.1% 339 5,094 Delaware Dover 4,755 3.8% 183 4,938

District of Columbia Wash ington 4,755 2.3% 111 4,866 Florida Tallahassee 4,755 -11.0% (522) 4,233 Florida Tampa 4,755 -4.5% (216) 4,539 Georgia Atlanta 4,755 -8.7% (413) 4,342 Hawaii Honolulu 4,755 37.2% 1,771 6,526 Idaho Boise 4,755 -2.5% (119) 4,636 Illinois Chicago 4,755 19.9% 949 5,704 Indiana Indianapolis 4,755 -1.2% (57) 4,698 Iowa Davenport 4,755 1.1% 51 4,806 Iowa Waterloo 4,755 -6.9% (327) 4,428 Kansas Wichita 4,755 -5.1% (242) 4,513 Kentucky Louisville 4,755 -6.6% (313) 4,442 Louisiana New Orleans 4,755 -11.3% (537) 4,218 Maine Portland 4,755 -3.2% (152) 4,603 Maryland Baltimore 4,755 -2.6% (124) 4,631 Massachusetts Boston 4,755 16.4% 778 5,533 Michigan Detroit 4,755 3.4% 163 4,918 Michigan Grand Rapids 4,755 -8.4% (398) 4,357 Minnesota St. Paul 4,755 6.0% 286 5,041 Mississippi Jackson 4,755 -7.9% (377) 4,378 Missouri St. Louis 4,755 4.4% 208 4,963 Missouri Kansas City 4,755 2.3% 109 4,864 Montana Great Falls 4,755 -2.7% (130) 4,625 Nebraska Omaha 4,755 -1.7% (79) 4,676 New Hampshire Concord 4,755 -0.3% (15) 4,740 New Jersey Newark 4,755 15.8% 751 5,506 New Mexico Albuquerque 4,755 -2.3% (111) 4,64424-9 State City Base Project

Cost ($/kW) Location Percent Variation Delta Cost Difference

($/kW) Total Location Project Cost ($/kW) New York New York 4,755 36.6% 1,739 6,494 New York Syracuse 4,755 -1.4% (68) 4,687 Nevada Las Vegas 4, 755 9.1% 432 5,187 North Carolina Charlotte 4,755 -11.6% (549) 4,206 North Dakota Bismarck 4,755 -5.3% (254) 4,501 Ohio Cincinnati 4,755 -4.6% (220) 4,535 Oregon Portland 4,755 5.2% 249 5,004 Pennsylvania Philadelphia 4,755 11.6% 550 5,305 Pennsylvania Wilkes-Barre 4,755 -5.0% (240) 4,515

Rhode Island Providenc e 4,755 3.1% 146 4,901 South Carolina Spartanburg 4,755 -13.2% (628) 4,127 South Dakota Rapid City 4,755 -8.2% (392) 4,363 Tennessee Knoxville 4,755 -10.2% (483) 4,272 Texas Houston 4,755 -10.1% (481) 4,274 Utah Salt Lake City 4,755 -3.8% (183) 4,572 Vermont Burlington 4,755 -4.2% (201) 4,554 Virginia Alexandria 4,755 -3.3% (159) 4,596 Virginia Lynchburg 4,755 -7.1% (336) 4,419 Washington Seattle 4,755 6.0% 284 5,039 Washington Spokane 4,755 -1.0% (49) 4,706 West Virginia Charleston 4,755 -2.2% (103) 4,652 Wisconsin Green Bay 4,755 -3.4% (161) 4,594 Wyoming Cheyenne 4,755 -3.8% (180) 4,575 Puerto Rico Cayey 4,755 -1.4% (68) 4,687

24.5 O&M ESTIMATE The significant O&M items for a PV Facility include periodic inve rter maintenance and periodic panel water washing. Additiona lly, most PV solar operators do not treat O&M on a variable basis, and consequently, all O&M expenses are shown below on a fixed basis. Table 24-5 and Table 24-6 present the O&M expenses for the PV Facility. TABLE 24-5 – O&M EXPENSES FOR PV FACILITY (7 MW) Technology: PV Fixed O&M Expense $26.40/kW-year Variable O&M Expense $0/MWh

TABLE 24-6 – O&M EXPENSES FOR PV FACILITY (150 MW) Technology: PV Fixed O&M Expense $16.70/kW-year Variable O&M Expense $0/MWh24-10 24.6 ENVIRONMENTAL COMPLI ANCE INFORMATION Table 24-7 presents environmental emissions for the PV Facility.

TABLE 24-7 – ENVIRONMENTAL EMISSIONS FOR PV Technology: Photovoltaic NO X 0 lb/MMBtu SO 2 0 lb/MMBtu CO 2 0 lb/MMBtu