Capital Cost and Performance 

Characteristics for Utility-Scale 

Electric Power Generating 

Technologies

January 2024 

www.eia.gov 

U.S. Department of Energy 

Washington, DC 20585 
U.S. Energy Information Administration   |   Capital Cost and Performance Characteristics for Utility‐Scale Power Generating Technologies i

The U.S. Energy Information Administration (EIA), the statistical and analytical agency within the  

U.S. Department of Energy (DOE), prepared this report. By law, our data, analyses, and forecasts are

independent of approval by any other officer or employee of the U.S. Government. The views in this

report do not represent those of DOE or any other federal agencies.
January 2024

U.S. Energy Information Administration   |   Capital Cost and Performance Characteristics for Utility‐Scale Power Generating Technologies 1

Capital Cost and Performance Characteristics for Utility-Scale 

Electric Power Generating Technologies 

To accurately reflect the changing cost of new electric power generators in the Annual Energy

Outlook 2025 (AEO2025), EIA commissioned Sargent & Lundy (S&L) to evaluate the overnight

capital cost and performance characteristics for 19 electric generator types. The following report

represents S&L’s findings.  

EIA accepted the following report in fulfillment of contract number 89303023‐REI000091. All

views expressed in this report are solely those of the contractor and acceptance of the report in

fulfillment of contractual obligations does not imply agreement with nor endorsement of its

findings. Responsibility for accuracy of the information contained in this report lies with the

contractor. Although EIA intends to use this report to inform the updating of EIA’s Electricity

Market Module in the National Energy Model System (NEMS), EIA is not obligated to modify any

of its models or data in accordance with the findings of this report.

Contacts 

This report, Capital Cost and Performance Characteristics for Utility‐Scale Electric Power

Generating Technologies, was prepared under the general guidance of Angelina LaRose,

Assistant Administrator for Energy Analysis; Jim Diefenderfer, Director of the Office of Long‐

Term Energy Modeling; and Chris Namovicz (202‐586‐7120), Team Lead of the Electricity, Coal,

and Renewables Modeling Team. Technical information concerning the content of the report

also may be obtained from Richard Bowers at 202‐586‐8586 or Nina Vincent at 202‐586‐8501.  
January 2024

U.S. Energy Information Administration   |   Capital Cost and Performance Characteristics for Utility‐Scale Power Generating Technologies 2

Introduction 

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

are critical inputs into the development of energy projections and analyses. The construction

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

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

electricity. These parameters also help to determine how new capacity competes against

existing capacity and how electric generators will respond to imposed environmental controls

on conventional pollutants or any limitations on greenhouse gas emissions.

Consistent with EIA’s practice of developing periodic assessments, EIA commissioned an

external consultant to develop up‐to‐date cost and performance estimates for utility‐scale

electric generating plants for AEO2025. This report is the fifth such report EIA has commissioned

since 2010. As with the prior studies, this information allows EIA to compare the costs of

different electric generating technologies on a standardized basis and is a key input

enhancement to the NEMS.

This report contains cost and performance estimates developed by Sargent & Lundy for 19

reference technology cases for different types of electric generators. To develop the

characteristics of each reference technology case, Sargent and Lundy considered the

specification of representative plant sizes and configurations and major equipment components,

including emission controls, based on current information from similar facilities recently

constructed, under development, or proposed for commercial development in the United States

and abroad. In each successive study that EIA contracted, the evolution of technology,

environmental requirements, and generator preferences influenced the attributes associated

with the reference generating technology. Where these characteristics remain substantially

similar between the study conducted for AEO2020 and the study conducted for AEO2025,

reference technology case costs are comparable and are labeled “updated”; where these

characteristics differ significantly between the two studies, the reference technology costs are

reported as “new” (Findings).

To produce its overnight capital cost estimates, Sargent & Lundy assumed that the power plant

developer or owner will hire an engineering, procurement, and construction (EPC) contractor for

turnkey construction of the project. These costs represent the total cost a developer would

expect to incur during the construction of a project, excluding financing costs. The specific

overnight costs for each type of facility are divided into:  

 Civil and structural material and installation cost covering all material and associated

labor for civil and structural tasks  

 Mechanical equipment supply and installation cost including all mechanical equipment

and associated labor for mechanical tasks  

 Electrical, instrumentation, controls supply, and installation cost including all costs for

transformers, switchgear, control systems, wiring, instrumentation, and raceways.  
January 2024

U.S. Energy Information Administration   |   Capital Cost and Performance Characteristics for Utility‐Scale Power Generating Technologies 3

 Project indirect costs including engineering, construction management, as well as start‐

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

Sargent & Lundy estimated labor, maintenance, minor repairs, and general and administrative

(G&A) costs based on multiple sources including actual projects, vendor publications, and

internal resources. Variable operations and maintenance costs, such as ammonia, water, and

miscellaneous chemicals and consumables, are directly proportional to the electricity generated.

Fuel costs were estimated for reference unit types using representative fuel specifications for

coal, natural gas, and biomass.

Findings

Table 1 summarizes updated cost estimates for reference case utility–scale generating

technologies specifically two powered by coal, five by natural gas, three by solar energy and by

wind, two by uranium, and one each by hydroelectric, biomass, geothermal, and battery

storage. EIA does not model all these generating plant types but included them in the study to

present consistent cost and performance information for a broad range of generating

technologies and to aid in the evaluation for potential inclusion of new or different technologies

or technology configurations in future analyses. The specific technologies represented in the

NEMS model for AEO2025 that use the cost data from this report are identified in the last

column of Table 1.  

Table 2 provides a comparison of updated overnight cost estimates for technologies

substantially similar to those developed for the 2019 report. To facilitate comparisons, the costs

are expressed in 2023 dollars.

Impact of location on power plant capital costs 

The estimates provided in this report are representative of a generic facility located in a

region without any special issues that would alter its cost. However, the cost of building

power plants in different regions of the United States can vary significantly. Sargent & Lundy

estimated capital cost adjustment factors to account for technology deployment at various

U.S. locations using published labor rates for each location to create a wage rate factor for

each location against the base rate (the 30 City Average). The location factors were then

improved by adding a regional labor productivity factor. To reflect these costs in EIA's

modeling, these adjustments were aggregated to represent the 25 Electricity Market

Module regions. EIA also assumes that the development of certain technologies is not

feasible in given regions for geographic, logistical, or regulatory reasons. The regional cost

adjustments for the reference technologies are summarized in Table 3.

Summary 

Although the estimates provided by Sargent & Lundy for this report are key inputs for EIA

electric market projections, they are not the sole driver of electric generation capacity

expansion decisions. The evolution of the electricity mix in each of the 25 regions modeled
January 2024

U.S. Energy Information Administration   |   Capital Cost and Performance Characteristics for Utility‐Scale Power Generating Technologies 4

in AEO2025 is sensitive to many factors, including the projected evolution of capital costs

over the modeling horizon, projected fuel costs, the characteristic of wholesale power

markets (regulated or competitive), the existing generation mix, additional costs associated

with environmental controls, and future electricity demand.
Capital Cost and Performance 

Characteristic Estimates for Utility 

Scale Electric Power Generating

Technologies

Prepared for

U.S. Energy Information Administration and Z Federal

Prepared by Sargent & Lundy

55 East Monroe Street 

Chicago, IL 60603-5780 USA 

312-269-2000

www.sargentlundy.com

Report SL-018001 

Final – Rev A 

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Project 14987.001
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U.S. Energy Information Administration and Z Federal

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Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

i 

L E G A L N O T I C E

This deliverable was prepared by Sargent & Lundy, L.L.C. (S&L) under contract with Z Federal (Client) 

expressly for the sole use of the U.S. Energy Information Administration in accordance with the contract 

agreement between S&L and Client. This deliverable was prepared using the degree of skill and care 

ordinarily exercised by engineers practicing under similar circumstances. Client acknowledges: (1) S&L 

prepared this deliverable subject to the particular scope limitations, budgetary and time constraints, and 

business objectives of Client; (2) information and data provided by others, including Client, may not have 

been independently verified by S&L; and (3) the information and data contained in this deliverable are timesensitive and changes in the data, applicable codes, standards, and acceptable engineering practices may 

invalidate the findings of this deliverable. Any use or reliance upon this deliverable by third parties shall be 

at their sole risk. 
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Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

ii 

Sargent & Lundy is one of the longest-standing full-service architect engineering firms in 

the world. Founded in 1891, the firm is a global leader in power and energy with expertise 

in grid modernization, renewable energy, energy storage, nuclear power, fossil fuels, 

carbon capture, and hydrogen. Sargent & Lundy delivers comprehensive project services

– from consulting, design, and implementation to construction management, 

commissioning, and operations/maintenance – with an emphasis on quality and safety. 

The firm serves public and private sector clients in the power and energy, gas distribution, 

industrial, and government sectors.

55 East Monroe Street • Chicago, IL 60603-5780 USA • 312-269-2000
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Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

iii 

V E R S I O N L O G

Version Issue Date Sections Modified 

Draft A August 11, 2023 Initial Issue 

Interim Final October 2, 2023 All 

Final November 6, 2023 Issued for Final 

Final - Rev A December 6, 2023 Sections 17.1.1, 17.3, 18.1.1, 18.3 
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Power Generating Technologies 

iv 

T A B L E O F C O N T E N T S

INTRODUCTION ............................................................................................................................................ I

INTRODUCTION ............................................................................................................................................ I

COST AND PERFORMANCE OF TECHNOLOGIES .................................................................................... I

COST AND PERFORMANCE ESTIMATES SUMMARY .............................................................................. II

BASIS OF ESTIMATES ................................................................................................................................ V

BASE FUEL SELECTION ............................................................................................................................. V

ENVIRONMENTAL COMPLIANCE BASIS .................................................................................................. VI

COMBUSTION TURBINE CAPACITY ADJUSTMENTS ............................................................................. VII

CAPITAL COST ESTIMATING.................................................................................................................... VII

LOCATIONAL ADJUSTMENTS ................................................................................................................... IX

ENVIRONMENTAL LOCATION FACTORS .................................................................................................. X

ADDITIONAL LOCATION FACTOR CONSIDERATIONS ........................................................................... XI

OPERATING AND MAINTENANCE COST ESTIMATING ......................................................................... XII

FIXED OPERATIONS AND MAINTENANCE ............................................................................................. XII

VARIABLE OPERATIONS AND MAINTENANCE ..................................................................................... XIII

INFLATION REDUCTION ACT CONSIDERATIONS ................................................................................ XIV

CARBON CAPTURE TECHNOLOGIES ................................................................................................... XIV

NUCLEAR TECHNOLOGIES ..................................................................................................................... XV

CLEAN ENERGY PRODUCTION AND INVESTMENT TAX CREDITS .................................................... XV

LABOR REQUIREMENTS ........................................................................................................................ XVI

DOMESTIC CONTENT REQUIREMENTS .............................................................................................. XVII

SOLAR PHOTOVOLTAIC SUPPLY CHAINS ......................................................................................... XVIII

WIND ENERGY SUPPLY CHAINS ........................................................................................................... XIX

ENERGY STORAGE SUPPLY CHAINS ................................................................................................... XIX

ENERGY COMMUNITY REQUIREMENTS ............................................................................................... XX

CASE 1. ULTRA-SUPERCRITICAL COAL PLANT WITHOUT CARBON CAPTURE, 650 MW NET ........ 1

1.1. CASE DESCRIPTION ............................................................................................................................ 1

1.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................... 2

1.1.2. ELECTRICAL AND CONTROL SYSTEMS ......................................................................................... 4

1.1.3. OFFSITE REQUIREMENTS ............................................................................................................... 4

1.2. CAPITAL COST ESTIMATE .................................................................................................................. 4

1.3. OPERATIONS AND MAINTENANCE COST ESTIMATE ...................................................................... 7

1.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ......................................................................... 8
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CASE 2. ULTRA-SUPERCRITICAL COAL PLANT WITH 95% CARBON CAPTURE, 650 MW NET ..... 10

2.1. CASE DESCRIPTION .......................................................................................................................... 10

2.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................. 10

2.1.2. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 13

2.1.3. OFFSITE REQUIREMENTS ............................................................................................................. 13

2.2. CAPITAL COST ESTIMATE ................................................................................................................ 14

2.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 16

2.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 17

CASE 3. COMBUSTION TURBINE - SIMPLE CYCLE PLANT, 4 X AERODERIVATIVE, 211 MW NET 19

3.1. CASE DESCRIPTION .......................................................................................................................... 19

3.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................. 19

3.1.2. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 20

3.1.3. OFFSITE REQUIREMENTS ............................................................................................................. 20

3.2. CAPITAL COST ESTIMATE ................................................................................................................ 20

3.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 22

3.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 23

CASE 4. COMBUSTION TURBINE - SIMPLE CYCLE PLANT, H CLASS, 419 MW NET ....................... 25

4.1. CASE DESCRIPTION .......................................................................................................................... 25

4.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................. 25

4.1.2. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 26

4.1.3. OFFSITE REQUIREMENTS ............................................................................................................. 26

4.2. CAPITAL COST ESTIMATE ................................................................................................................ 26

4.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 28

4.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 29

CASE 5. COMBINED-CYCLE PLANT, H CLASS, 1227 MW NET ............................................................ 31

5.1. CASE DESCRIPTION .......................................................................................................................... 31

5.1.1. MECHANICAL EQUIPMENT AND SYSTEM .................................................................................... 31

5.1.2. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 33

5.1.3. OFFSITE REQUIREMENTS ............................................................................................................. 33

5.2. CAPITAL COST ESTIMATE ................................................................................................................ 33

5.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 35

5.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 36

CASE 6. COMBINED-CYCLE PLANT, H CLASS, SINGLE SHAFT, 627 MW NET ................................. 38

6.1. CASE DESCRIPTION .......................................................................................................................... 38

6.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................. 38

6.1.2. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 40
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Power Generating Technologies 

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6.1.3. OFFSITE REQUIREMENTS ............................................................................................................. 40

6.2. CAPITAL COST ESTIMATE ................................................................................................................ 41

6.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 43

6.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 44

CASE 7. COMBINED-CYCLE PLANT, H CLASS, SINGLE SHAFT, WITH 95% CARBON CAPTURE, 543 

MW NET ...................................................................................................................................................... 45

7.1. CASE DESCRIPTION .......................................................................................................................... 45

7.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................. 45 

7.1.2. 95% CO2 CAPTURE ......................................................................................................................... 46 

7.1.3. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 46 

7.1.4. OFFSITE REQUIREMENTS ............................................................................................................. 47 

7.2. CAPITAL COST ESTIMATES .............................................................................................................. 47

7.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 50

7.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 51

CASE 8. WOODY BIOMASS PLANT, WITH 95% CARBON CAPTURE, 50 MW NET ............................ 52

8.1. CASE DESCRIPTION .......................................................................................................................... 52

8.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................. 52 

8.1.2. 95% CO2 CAPTURE ......................................................................................................................... 55 

8.1.3. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 55 

8.1.4. OFFSITE REQUIREMENTS ............................................................................................................. 55 

8.2. CAPITAL COST ESTIMATE ................................................................................................................ 56

8.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 58

8.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 59

CASE 9. ADVANCED NUCLEAR PLANT (BROWNFIELD), 2 X AP1000 UNITS, 2156 MW NET ........... 61

9.1. CASE DESCRIPTION .......................................................................................................................... 61

9.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .................................................................................. 61

9.1.2. ELECTRICAL AND CONTROL SYSTEMS ....................................................................................... 62

9.1.3. OFFSITE REQUIREMENTS ............................................................................................................. 62

9.2. CAPITAL COST ESTIMATE ................................................................................................................ 62

9.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................... 64

9.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ....................................................................... 65

CASE 10. SMALL MODULAR REACTOR NUCLEAR POWER PLANT, 6 X 80 MW UNITS, 480 MW NET 

66

10.1. CASE DESCRIPTION ........................................................................................................................ 66

10.1.1. MECHANICAL EQUIPMENT AND SYSTEMS ................................................................................ 66

10.1.2. ELECTRICAL AND CONTROL SYSTEMS ..................................................................................... 67
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Power Generating Technologies 

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10.1.3. OFFSITE REQUIREMENTS ........................................................................................................... 67

10.2. CAPITAL COST ESTIMATE .............................................................................................................. 67

10.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................. 69

10.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ..................................................................... 70

CASE 11. GEOTHERMAL PLANT, 50 MW NET ....................................................................................... 71

11.1. CASE DESCRIPTION ........................................................................................................................ 71

11.1.1. MECHANICAL EQUIPMENT AND SYSTEMS ................................................................................ 72

11.1.2. ELECTRICAL AND CONTROL SYSTEMS ..................................................................................... 72

11.1.3. OFFSITE REQUIREMENTS ........................................................................................................... 73

11.2. CAPITAL COST ESTIMATE .............................................................................................................. 73

11.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................. 75

11.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ..................................................................... 75

CASE 12. HYDROELECTRIC PLANT, 100 MW NET ................................................................................ 76

12.1. CASE DESCRIPTION ........................................................................................................................ 76

12.2. CAPITAL COST ESTIMATE .............................................................................................................. 78

12.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................. 80

12.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ..................................................................... 80

CASE 13. ONSHORE WIND, LARGE PLANT FOOTPRINT, 200 MW NET ............................................. 81

13.1. CASE DESCRIPTION ........................................................................................................................ 81

13.1.1. MECHANICAL EQUIPMENT AND SYSTEMS ................................................................................ 81

13.1.2 ELECTRICAL AND CONTROL SYSTEMS ...................................................................................... 81

13.1.3 OFFSITE REQUIREMENTS ............................................................................................................ 81

13.2. CAPITAL COST ESTIMATE .............................................................................................................. 82

13.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................. 83

13.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ..................................................................... 84

CASE 14. ONSHORE WIND, REPOWERING/RETROFIT, 150 MW NET ................................................. 85

14.1. CASE DESCRIPTION ........................................................................................................................ 85

14.1.1. MECHANICAL EQUIPMENT AND SYSTEMS ................................................................................ 86

14.1.2. ELECTRICAL AND CONTROL SYSTEMS ..................................................................................... 86

14.1.3. OFFSITE REQUIREMENTS ........................................................................................................... 86

14.2. CAPITAL COST ESTIMATE .............................................................................................................. 86

14.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................. 88

14.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ..................................................................... 89

CASE 15. OFFSHORE WIND: FIXED-BOTTOM MONOPILE FOUNDATIONS, 900 MW NET ................ 90

15.1. CASE DESCRIPTION ........................................................................................................................ 90

15.1.1. MECHANICAL EQUIPMENT AND SYSTEMS ................................................................................ 90
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15.1.2 ELECTRICAL AND CONTROL SYSTEMS ...................................................................................... 90

15.1.3 OFFSITE REQUIREMENTS ............................................................................................................ 91

15.2. CAPITAL COST ESTIMATE .............................................................................................................. 91

15.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................. 92

15.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ..................................................................... 93

CASE 16. SOLAR PHOTOVOLTAIC WITH SINGLE AXIS TRACKING, 150 MWAC ............................... 94

16.1. CASE DESCRIPTION ........................................................................................................................ 94

16.1.1. MECHANICAL EQUIPMENT AND SYSTEMS ................................................................................ 95

16.1.2. ELECTRICAL AND CONTROL SYSTEMS ..................................................................................... 96

16.1.3. OFFSITE REQUIREMENTS ........................................................................................................... 97

16.2. CAPITAL COST ESTIMATE .............................................................................................................. 97

16.3. OPERATIONS AND MAINTENANCE COST ESTIMATE .................................................................. 99

16.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ................................................................... 100

CASE 17. SOLAR PHOTOVOLTAIC WITH SINGLE AXIS TRACKING, AC-COUPLED BATTERY 

ENERGY STORAGE, 150 MWAC | 200 MWH ......................................................................................... 101

17.1. CASE DESCRIPTION ...................................................................................................................... 101

17.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .............................................................................. 101

17.1.2. ELECTRICAL AND CONTROL SYSTEMS ................................................................................... 102

17.1.3. OFFSITE REQUIREMENTS ......................................................................................................... 103

17.2. CAPITAL COST ESTIMATE ............................................................................................................ 103

17.3. OPERATIONS AND MAINTENANCE COST ESTIMATE ................................................................ 105

17.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ................................................................... 106

CASE 18. SOLAR PHOTOVOLTAIC WITH SINGLE AXIS TRACKING, DC-COUPLED BATTERY 

ENERGY STORAGE, 150 MWAC | 200 MWH ......................................................................................... 107

18.1. CASE DESCRIPTION ...................................................................................................................... 107

18.1.1. MECHANICAL EQUIPMENT AND SYSTEMS .............................................................................. 107

18.1.2. ELECTRICAL AND CONTROL SYSTEMS ................................................................................... 108

18.1.3. OFFSITE REQUIREMENTS ......................................................................................................... 108

18.2. CAPITAL COST ESTIMATE ............................................................................................................ 109

18.3. OPERATIONS AND MAINTENANCE COST ESTIMATE ................................................................ 111

18.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ................................................................... 112

CASE 19. BATTERY ENERGY STORAGE SYSTEM, 150 MW | 600 MWH ........................................... 113

19.1. CASE DESCRIPTION ...................................................................................................................... 113

19.2. CAPITAL COST ESTIMATE ............................................................................................................ 115

19.3. OPERATIONS AND MAINTENANCE COST ESTIMATE ................................................................ 117

19.4. ENVIRONMENTAL AND EMISSIONS INFORMATION ................................................................... 118
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F I G U R E S A N D T A B L E S

FIGURE 1 — SUMMARY OF INVESTMENT TAX CREDITS AND PRODUCTION TAX CREDITS OVER 

TIME .......................................................................................................................................................... XVI

FIGURE 2 — THE SOLAR PHOTOVOLTAICS SUPPLY CHAIN ........................................................... XVIII

FIGURE 3 — DOMESTIC MANUFACTURING CONTENT FOR ONSHORE WIND POWER IN 2020 ... XIX

FIGURE 4 — MAP OF CENSUS TRACTS ELIGIBLE FOR ENERGY COMMUNITY BONUS ................ XXI

FIGURE 1-1 — USC COAL BOILER – FLOW DIAGRAM ............................................................................ 2

FIGURE 2-1 — CARBON CAPTURE FLOW DIAGRAM ............................................................................ 12

FIGURE 3-1 — CASE 3 CONFIGURATION ............................................................................................... 19

FIGURE 4-1 — CASE 4 CONFIGURATION ............................................................................................... 25

FIGURE 5-1 — CASE 5 CONFIGURATION ............................................................................................... 32

FIGURE 6-1 — CASE 6 CONFIGURATION – SIMPLIFIED SKETCH ....................................................... 40

FIGURE 8-1 — TYPICAL BFB BIOMASS BOILER ARRANGEMENT ....................................................... 54

FIGURE 11-1 — GEOTHERMAL PLANT CONFIGURATIONS FOR HYDROTHERMAL RESERVOIRS 71 

FIGURE 12-1 — DAM OF A HYDROELECTRIC POWER PLANT ............................................................ 76

FIGURE 12-2 — STORAGE-TYPE HYDROELECTRIC POWER PLANT .................................................. 77

FIGURE 12-3 — TYPICAL HYDROELECTRIC POWER TURBINE HALL ................................................. 78

FIGURE 14-1 — WIND REPOWER COMPONENT LAYOUT .................................................................... 85

FIGURE 16-1 — SOLAR PV PROJECT ..................................................................................................... 94

FIGURE 16-2 — SINGLE-AXIS TRACKING ............................................................................................... 96

FIGURE 17-1 — AC-COUPLED SOLAR PV AND BATTERY STORAGE ............................................... 102

FIGURE 18-1 — DC-COUPLED SOLAR PV AND BATTERY STORAGE ............................................... 108

FIGURE 19-1 — UTILITY-SCALE LITHIUM-ION BATTERIES ................................................................. 114

FIGURE 19-2 — STANDALONE BESS FLOW DIAGRAM ....................................................................... 114

TABLE 1-1 — LIST OF REFERENCE TECHNOLOGIES .............................................................................. I

TABLE 1-2 — COST & PERFORMANCE SUMMARY TABLE .................................................................... III

TABLE 1-3 — REFERENCE COAL SPECIFICATION .................................................................................. V

TABLE 1-4 — REFERENCE NATURAL GAS SPECIFICATION .................................................................. V

TABLE 1-5 — REFERENCE WOOD BIOMASS SPECIFICATION ............................................................. VI

TABLE 1-6 — UNITED STATES’ AND CHINA’S EXISTING AND UNDER DEVELOPMENT SHARES OF 

GLOBAL LITHIUM-ION BATTERY SUBCOMPONENT CAPACITY ......................................................... XX

TABLE 1-1 — CASE 1 CAPITAL COST ESTIMATE .................................................................................... 5

TABLE 1-2 — CASE 1 OPERATIONAL COST ESTIMATE .......................................................................... 8
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TABLE 1-3 — CASE 1 EMISSION RATES ................................................................................................... 9

TABLE 2-1 — CASE 2 CAPITAL COST ESTIMATE .................................................................................. 15

TABLE 2-2 — CASE 2 OPERATIONAL COST ESTIMATE ........................................................................ 17

TABLE 2-3 — CASE 2 EMISSION RATES ................................................................................................. 18

TABLE 3-1 — CASE 3 CAPITAL COST ESTIMATE .................................................................................. 21

TABLE 3-2 — CASE 3 O&M COST ESTIMATE ......................................................................................... 23

TABLE 3-3 — CASE 3 EMISSIONS ........................................................................................................... 24

TABLE 4-1 — CASE 4 CAPITAL COST ESTIMATE .................................................................................. 27

TABLE 4-2 — CASE 4 O&M COST ESTIMATE ......................................................................................... 29

TABLE 4-3 — CASE 4 EMISSIONS ........................................................................................................... 30

TABLE 5-1 — CASE 5 CAPITAL COST ESTIMATE .................................................................................. 34

TABLE 5-2 — CASE 5 O&M COSTS .......................................................................................................... 36

TABLE 5-3 — CASE 5 EMISSIONS ........................................................................................................... 37

TABLE 6-1 — CASE 6 CAPITAL COST ESTIMATE .................................................................................. 41

TABLE 6-2 — CASE 6 O&M COST ............................................................................................................ 44

TABLE 6-3 — CASE 6 EMISSIONS ........................................................................................................... 44

TABLE 7-1 — CASE 7 CAPITAL COST ESTIMATE .................................................................................. 48

TABLE 7-2 — CASE 7 O&M COST ESTIMATES ....................................................................................... 51

TABLE 7-3 — CASE 7 EMISSIONS ........................................................................................................... 51

TABLE 8-1 — CASE 8 CAPITAL COST ESTIMATE .................................................................................. 56

TABLE 8-2 — CASE 8 OPERATIONAL COST ESTIMATE ........................................................................ 59

TABLE 8-3 — CASE 8 EMISSION RATES ................................................................................................. 60

TABLE 9-1 — CASE 9 CAPITAL COST ESTIMATE .................................................................................. 63

TABLE 9-2 -— CASE 9 OPERATIONAL COST ESTIMATE ...................................................................... 65

TABLE 10-1 — CASE 10 CAPITAL COST ESTIMATE .............................................................................. 67

TABLE 10-2 — CASE 10 OPERATIONAL COST ESTIMATE .................................................................... 70

TABLE 11-1 — CASE 11 CAPITAL COST ESTIMATE .............................................................................. 73

TABLE 11-2 — CASE 11 OPERATING AND MAINTENANCE (O&M) COST ESTIMATES ...................... 75

TABLE 12-1 — CASE 12 CAPITAL COST ESTIMATES ............................................................................ 78

TABLE 12-2 — CASE 12 OPERATING AND MAINTENANCE (O&M) COST ESTIMATES ...................... 80

TABLE 13-1 — CASE 13 CAPITAL COST ESTIMATE .............................................................................. 82

TABLE 13-2 — CASE 13 O&M COST ESTIMATE ..................................................................................... 84

TABLE 14-1 — CASE 14 CAPITAL COST ESTIMATE .............................................................................. 87

TABLE 14-2 — CASE 14 O&M COST ESTIMATE ..................................................................................... 88

TABLE 15-1 — CASE 15 CAPITAL COST ESTIMATE .............................................................................. 91

TABLE 15-2 — CASE 15 O&M COST ESTIMATE ..................................................................................... 93
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TABLE 16-1 — CASE 16 CAPITAL COST ESTIMATE .............................................................................. 98

TABLE 16-2 — CASE 16 O&M COST ESTIMATE ................................................................................... 100

TABLE 17-1 — CASE 17 CAPITAL COST ESTIMATE ............................................................................ 103

TABLE 17-2 — CASE 17 O&M COST ESTIMATE ................................................................................... 106

TABLE 18-1 — CASE 18 CAPITAL COST ESTIMATE ............................................................................ 109

TABLE 18-2 — CASE 18 O&M COST ESTIMATE ................................................................................... 111

TABLE 19-1 — CASE 19 CAPITAL COST ESTIMATE ............................................................................ 115

TABLE 19-2 — CASE 19 O&M COST ESTIMATE ................................................................................... 118

A P P E N D I C E S

APPENDIX A. LABOR LOCATION-BASED COST ADJUSTMENTS 

APPENDIX B. COMBUSTION TURBINE CAPACITY ADJUSTMENTS
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xii 

A C R O N Y M S A N D A B B R E V I A T I O N S

Acronym/Abbreviation Definition/Clarification 

AC Alternating Current 

ACC Air-Cooled Condenser 

ASCE American Society of Civil Engineers 

BESS Battery Energy Storage System 

BFB Bubbling Fluidized Bed 

BOP Balance-of-Plant 

Btu/kWh British Thermal Units Per Kilowatthour 

Btu/lb British Thermal Unit Per Pound 

Btu/scf British Thermal Unit Per Standard Cubic Foot 

CC Combined-Cycle 

CCS Carbon Capture and Sequestration 

CFR Code of Federal Regulations 

CO2 Carbon Dioxide 

COD Commercial Operation Date 

CT Combustion Turbine 

DAC Direct Air Capture 

DC Direct Current 

DCS Distributed Control System 

EGS Enhanced Geothermal System 

EIA Energy Information Administration 

EOH Equivalent Operating Hours 

EPC Engineering, Procurement, and Construction 

FGD Flue Gas Desulfurization 

G&A General and Administrative 

GSU Generator Step-Up Transformer 

HHV Higher Heating Value 

HRSG Heat Recovery Steam Generator 

Hz Hertz 
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Acronym/Abbreviation Definition/Clarification 

I&C Instrumentation and Controls 

IBC International Building Code 

IRA Inflation Reduction Act 

ITC Investment Tax Credit 

kV Kilovolts 

kW Kilowatt 

kWh Kilowatt-hour 

lb/MMBtu Pounds Per One Million British Thermal Units 

LNB Low Nitrogen Oxide Burner 

MCC Motor Control Center 

MVA Megavolt-Ampere 

MW Megawatt 

MWAC Megawatt Alternating Current 

MWh Megawatt-hour 

NOX Nitrogen Oxide 

O&M Operating and Maintenance 

OFA Overfire Air 

PCS Power Conditioning System 

PTC Production Tax Credit 

psia Pounds Per Square Inch Absolute 

PV Photovoltaic 

RH Relative Humidity 

SCADA Supervisory Control and Data Acquisition 

SCR Selective Catalytic Reduction 

SO2 Sulfur Dioxide 

STG Steam Turbine Generator 

USC Ultra-Supercritical 

USD United States Dollar 

USDA U.S. Department of Agriculture 
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Acronym/Abbreviation Definition/Clarification 

WESP Wet Electrostatic Precipitator 

WFGD Wet Flue Gas Desulfurization 

WTG Wind Turbine Generator 

ZLD Zero Liquid Discharge 
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I 

I N T R O D U C T I O N

INTRODUCTION

The U.S. Energy Information Administration (EIA) retained Z Federal and Sargent & Lundy to conduct a 

study of the cost and performance of new utility-scale electric power generating technologies. This report 

contains Sargent & Lundy’s cost and performance estimates for 19 different reference technology cases. 

The EIA will use these estimates to improve the EIA’s Electricity Market Module’s ability to represent the 

changing landscape of electricity generation. With this update, the EIA’s improved Electricity Market Module 

will better represent capital and non-fuel operating costs of generating technologies being installed or under 

consideration for capacity expansion. The Electricity Market Module is a submodule within the EIA’s 

National Energy Modeling System, a computer-based energy supply modeling system used for the EIA’s 

Annual Energy Outlook and other analyses. 

Sargent & Lundy developed the characteristics of the power generating technologies in this study based 

on information about similar facilities recently built or under development in the United States and abroad. 

Developing the characteristics of each generating technology included the specification of representative 

plant sizes, configurations, major equipment, and emission controls. Sargent & Lundy’s cost assessment 

included the estimation of overnight capital costs, construction lead times, contingencies, and fixed and 

variable operating costs. We also estimated the net plant capacity, net plant heat rates, and controlled 

emission rates, as applicable for each technology studied. We performed our assessments with consistent 

estimating methodologies across all generating technologies. 

COST AND PERFORMANCE OF TECHNOLOGIES

Table 1-1 lists all the power generating technologies that we assessed in this study. 

Table 1-1 — List of Reference Technologies 

Case 

No. Technology Description 

1 Ultra-Supercritical (USC) Coal without Carbon Capture – 

Greenfield 1 x 735 MW Gross, 650 MW Net 

2 USC Coal 95% Carbon Capture 1 x 819 MW Gross, 650 MW Net 

3 Aeroderivative Combustion Turbines (CTs) – Simple 

Cycle 4 x 54 MW Gross Aeroderivative, 211 MW Net 

4 CTs – Simple Cycle 1 x H-Class Simple Cycle, 419 MW Net 

5 Combined-Cycle (CC) 2x2x1 2 x 1 H Class CC, 1227 MW Net 

6 CC 1x1x1, Single Shaft 1 x 1 H Class CC, 627 MW Net 

7 CC 1x1x1, Single Shaft, with 95% Carbon Capture 1 x 1 H Class CC, 543 MW Net 
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Case 

No. Technology Description 

8 Biomass Plant with 95% Carbon Capture 1 x Bubbling Fluidized Bed (BFB), 50 MW Net 

9 Advanced Nuclear (Brownfield) 2 x AP1000, 2156 MW Net 

10 Small Modular Reactor Nuclear Power Plant 6 x 80-MW Small Modular Reactor, 480 MW 

Net 

11 Geothermal Binary Cycle, 50 MW Net 

12 Hydroelectric Power Plant New Stream Reach Development, 100 MW Net 

13 Onshore Wind – Large Plant Footprint: Great Plains 

Region 

200 MW | 2.8-MW Wind Turbine Generator 

(WTG) 

14 Onshore Wind – Repowering/Retrofit 150 MW | 1.5-1.62 MW WTG 

15 Fixed-bottom Offshore Wind: Monopile Foundations 900 MW | 15 MW WTG 

16 Solar Photovoltaic (PV) with Single-Axis Tracking 150 MWAC 

17 Solar PV with Single-Axis Tracking and AC-Coupled 

Battery Storage 

150 MWAC Solar

50 MW | 200 MWh Storage 

18 Solar PV with Single-Axis Tracking and DC-Coupled 

Battery Storage 

150 MWAC Solar

50 MW | 200 MWh Storage 

19 Battery Energy Storage System (BESS) Lithium Ion, 150 MW | 600 MWh 

As part of the technology assessment, we reviewed recent market trends for the reference technologies 

using publicly available sources and in-house data. We also used our extensive background in power plant 

design and experience in performing similar cost and performance assessments. Using a combination of 

public and internal information sources, we identified the representative costs and performance for the 

reference technologies. 

COST AND PERFORMANCE ESTIMATES SUMMARY

Table 1-2 summarizes all technologies examined, including overnight capital cost information, fixed 

operating and maintenance (O&M) costs, and variable non-fuel O&M costs as well as emissions estimates 

for new installations (in pounds per one million British thermal units [lb/MMBtu]). 
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Table 1-2 — Cost & Performance Summary Table 

Case 

No. Technology Description 

Net 

Nominal 

Capacity 

(kW) 

Net 

Nominal 

Heat Rate 

(Btu/kWh) 

Capital Cost 

($/kW) 

Fixed O&M 

Cost 

($/kW-year) 

Variable 

O&M Cost 

($/MWh) 

Nitrog

Oxid

(NO

(lb/MM

1 USC Coal without Carbon Capture – Greenfield 1 x 735 MW Gross 650 8,638 $4,103 $61.60 $6.40 0.02 USC Coal 95% Carbon Capture 1 x 819 MW Gross 650 12,293 $7,346 $86.70 $13.73 0.03 Aeroderivative CTs – Simple Cycle 4 x 54 MW Gross 211 9,447 $1,606 $9.56 $5.70 0.00

4 CTs – Simple Cycle 1 x H-Class 419 9,142 $836 $6.87 

$1.24/ 

MWh, 

$23,100/ 

Start 

0.00

5 CC 2x2x1 2 x 1 H Class 1,227 6,266 $868 $12.12 $3.41 0.006 CC 1x1x1, Single Shaft 1 x 1 H Class SS 627 6,226 $921 $15.51 $3.33 0.007 CC 1x1x1, Single Shaft, with 95% Carbon Capture 1 x 1 H Class SS 543 7,239 $2,365 $24.78 $5.05 0.008 Biomass Plant with 95% Carbon Capture 1 x BFB 50 19,965 $12,631 $261.18 $9.65 0.09 Advanced Nuclear (Brownfield) 2 x AP1000 2,156 10,608 $7,861 $156.20 $2.52 0 

10 Small Modular Reactor Nuclear Power Plant 6 x 80 MW Small Modular Reactor 480 10,046 $8,936 $121.99 $3.19 0 11 Geothermal Binary Cycle 50 N/A $3,963 $150.60 $0.00 0 

12 Hydroelectric Power Plant 

New Stream 

Reach 

Development 

100 N/A $7,073 $33.54 $0.00 0 

13 

Onshore Wind – Large Plant Footprint: Great Plains Region 

200 MW | 2.8 MW 

WTG 200 N/A $1,489 $33.06 $0.00 0 

14 Onshore Wind – Repowering/Retrofit 150 MW | 1.5 - 1.62 MW WTG 150 N/A $1,386 $38.55 $0.00 0 
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Capital Cost and Performance Characteristic Estimates for Utility Scale Electric Power Generating Technologies 

Case 

No. Technology Description 

Net 

Nominal 

Capacity 

(kW) 

Net 

Nominal 

Heat Rate 

(Btu/kWh) 

Capital Cost 

($/kW) 

Fixed O&M 

Cost 

($/kW-year) 

Variable 

O&M Cost 

($/MWh) 

Nitrog

Oxid

(NO

(lb/MM

15 

Fixed-bottom Offshore Wind: Monopile Foundations 

900 MW | 15 MW 

WTG 900 N/A $3,689 $154.00 $0.00 0 

16 Solar PV with Single-Axis Tracking 150 MWAC 150 N/A $1,502 $20.23 $0.00 0 17 

Solar PV with Single-Axis Tracking and AC-Coupled Battery Storage 

150 MWAC Solar

50 MW | 200 

MWh Storage 

150 N/A $2,175 $38.39 $0.00 0 

18 

Solar PV with Single-Axis Tracking and DC-Coupled Battery Storage 

150 MWAC Solar

50 MW | 200 

MWh Storage 

150 N/A $2,561 $39.24 $0.00 0 

19 BESS Lithium Ion, 150 MW | 600 MWh 150 N/A $1,744, ($436/kWh) $40.00 $0.00 0 
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B A S I S O F E S T I M A T E S

BASE FUEL SELECTION

We used the following fuel specifications as a basis for the cost estimates. Table 1-3, Table 1-4, and Table 

1-5 represent typical fuel specifications for coal, natural gas, and wood biomass, respectively. 

Table 1-3 — Reference Coal Specification 

Rank Bituminous 

Proximate Analysis (weight %) 

Fuel Parameter As Received 

Moisture 11.2 

Ash 9.7 

Carbon 63.75 

Oxygen 6.88 

Hydrogen 4.5 

Sulfur 2.51 

Nitrogen 1.25 

Chlorine 0.29 

HHV, Btu/lb 11,631 

Fixed Carbon/Volatile Matter 1.2 

HHV = Higher heating value; Btu/lb = British thermal unit per pound 

Table 1-4 — Reference Natural Gas Specification 

Component Volume Percentage 

Methane CH4 93.9 

Ethane C2H6 3.2 

Propane C3H8 0.7 

n-Butane C4H10 0.4 

Carbon Dioxide CO2 1 

Nitrogen N2 0.8 

Total 100 

LHV HHV 

Btu/lb 20,552 22,793 

Btu/scf 939 1,040 

LHV = Lower heating value; Btu/scf = British thermal unit per standard cubic foot 
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Table 1-5 — Reference Wood Biomass Specification 

Type Woodchips 

Component Weight % 

Moisture 20–50 

Ash 0.1–0.7 

Carbon 32 

Sulfur 0.01 

Oxygen 28 

Hydrogen 3.8 

Nitrogen 0.1–0.3 

HHV, Btu/lb 5400–6200 

ENVIRONMENTAL COMPLIANCE BASIS

Our technology assessments selected include the best available (emissions) control technology for sulfur 

dioxide (SO2), nitrogen oxide (NOX), particulate matter, mercury, and carbon dioxide (CO2), where 

applicable. Best available control technology guidelines are covered by the United States’ Clean Air Act 

Title I, which promotes air quality, ozone protection, and emission limitations. The level of emission controls 

is based on the following best available control technology guidelines: 

 Total source emissions 

 Regional environmental impact 

 Energy consumption 

 Economic costs 

Best available control technology is not the most restrictive pollution control standard since it still includes 

a cost-benefit analysis for technology use. Specific technologies chosen for estimation are further described 

in their respective cases. 

The CO2 capture systems are commonly referred to as carbon capture and sequestration (CCS) systems; 

however, for the cost estimates provided in this report, no sequestration costs (CO2 transportation or 

storage) have been included. The CO2 captured is assumed compressed to supercritical conditions and 

injected into a pipeline terminated at the fence line of the facility. For this report, the terms “CO2 capture” 

and “carbon capture” are used interchangeably. 
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COMBUSTION TURBINE CAPACITY ADJUSTMENTS

Appendix B includes CT capacity adjustments. 

Adjustments for local ambient conditions were made for power plants using CTs. Since CTs produce power 

proportional to mass flow and ambient air temperature, relative humidity, and elevation affect air density, 

these conditions also affect CT performance. These conditions affect CT performance in the following ways: 

 Temperature affects air density in an inversely proportional relationship. Higher ambient 

temperature lowers the density of the inlet air which reduces the mass flow through the CT and the 

consequent power output. Inlet cooling technology on a CT can increase the air density and recover 

lost performance. 

 Relative humidity affects air density in an inversely proportional relationship as components of water 

vapor are less dense than air. Higher relative humidity lowers density and mass flow through the 

CT which reduces the power output. For plants with wet cooling (evaporative coolers, wet cooling 

towers, etc.), relative humidity and temperature determine the effectiveness of that equipment as 

well. Cooling technologies that depend on evaporation are most effective when the temperature is 

high and the relative humidity low. 

 Elevation affects air pressure and density in an inversely proportional relationship. Ambient air 

density was calculated in this study by using the air pressure related to site elevation above sea 

level. This gives the average impact of air pressure on performance, ignoring the short-term effects 

of weather. 

Temperatures and relative humidity used in the Appendix B adjustment table are based on annual averages 

for the locations specified. An adjustment factor for the various technologies were compared across 

locations on a consistent basis. 

CAPITAL COST ESTIMATING

Sargent & Lundy used a top-down capital cost estimating methodology derived from parametric evaluations 

of costs from actual or planned projects with similar scope and configurations to the generating technology 

considered. We have used both publicly available information and internal sources to establish the 

representative costs and appropriate scaling parameters. In some cases, we have use used portions of 

more detailed cost estimates to adjust the parametric factors. 

The capital cost estimates represent a complete power plant facility on a generic site at a non-specific 

location in the United States. The basis of the capital costs is defined as all costs to engineer, procure, 

construct, and commission all equipment within the plant facility fence line, as well as interconnections to 

electrical transmission and fuel distribution networks, as applicable. As described in the following section, 

we have also estimated location adjustments to help establish the cost impacts to project implementation 
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in more specific areas or regions within the United States. Capital costs account for all costs incurred during 

construction of the power plant before the commercial operation date (COD). The capital costs are divided 

between the engineering, procurement, and construction (EPC) contractor and owner’s costs. Sargent & 

Lundy assumes that the power plant developer or owner will hire an EPC contractor for turnkey construction 

of the project. Unless noted otherwise, the estimates assume that the EPC contractor cost will include 

procurement of equipment, materials, and all construction labor associated with the project. The capital 

costs provided are overnight capital costs in 2023 price levels. Overnight capital costs represent the total 

cost a developer would expect to incur during the construction of a project, excluding financing costs. The 

capital cost breakdowns for the EPC contractor are as follows: 

 Direct Costs: EPC direct costs are broken down in formats applicable to the reference technology. 

In some cases, the cost breakdown includes major scope work packages that are inclusive of 

equipment, materials, and direct labor costs. Other cases have equipment and material procurement 

costs separated from the construction labor. 

 Major Work Scope Costs: Costs for major project scopes of work such as 

“Civil/Structural/Architectural” or “Nuclear Island” include the equipment, materials, and 

construction labor associated with scope described. 

 Equipment and Material Costs: For some cases, the costs for the primary generation 

technologies are listed explicitly (for example, solar PV “Module Supply,” “WTG Procurement 

and Supply,” etc.), or grouped into balance-of-plant (BOP) equipment line items such as 

“Racking, Tracker and BOP Equipment Supply.” Where no other descriptors are present, 

“Other Equipment” generally refers to ancillary equipment, such as pumps, tanks, motor 

control centers, condensers, cooling towers, switchgear, transformers, and any other major 

inside-the-fence process equipment required for the complete facility. “Materials” include all 

construction materials associated with the EPC scope of work and consumables during 

construction. Equipment and material costs are intended to be the delivered costs inclusive 

of purchase price, duties, and freight, (but excluding any sales tax) and are clarified with 

additional descriptors and notes, as needed. 

 Construction Labor Costs: Construction labor costs are intended to represent the fully 

burdened cost of labor to the EPC contractor for the project construction activities. 

Construction labor costs may be listed for individual activities as “installation” costs, included 

with the equipment/material costs where the description includes “supply and installation,” 

or aggregated as “construction labor” for all labor directly attributed to onsite civil/structural 

work and erection/installation of the equipment included in the EPC contractor’s scope. 

 Indirect Costs: Indirect costs include engineering, procurement, project services, construction 

management, field engineering, start-up, and commissioning services provided by the EPC 

contractor. 

 EPC Fee and Contingency: The EPC fee is included to represent the premium applied by the EPC 

contractor for profit and management of subcontracts within their scope. EPC contingency includes 

costs for the “known unknowns” that are not defined explicitly but would be expected to be managed 
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by the EPC contractor while delivering a fully functional generation facility. Contingencies are added 

because experience has shown that such costs are likely, and expected, to be incurred even though 

they cannot be explicitly determined at the time the estimate is prepared. The percentages used to 

calculate these values are generally representative of the degrees of uncertainty, risk, and 

complexity of the generation and any environmental control technologies. These percentages are 

listed in the cost tables and represent values generally accepted within their respective markets. 

Owner’s costs represent costs to the owner that would typically be incurred outside the scope of the EPC 

contract. These primarily consist of costs incurred to develop and manage the project as well as land and 

utility interconnection costs. 

 Owner’s Services: The owner’s services include project development, studies, permitting, legal, 

owner's project management, owner's engineering, and owner's participation in start-up and 

commissioning. 

 Land: project land requirements are based on typical land requirements for each technology with 

per-acreage costs based on a survey of vacant land listings zoned for industrial use within the United 

States. For certain technologies, land is assumed to be leased and those costs are included in the 

operations and maintenance costs instead. 

 Electrical Interconnection: Transmission costs are based on a one-mile transmission line (unless 

otherwise stated) with voltage ranging from 115 kilovolts (kV) to 500 kV depending on the unit 

capacity. We have also assumed that no substation upgrades would be required for the electrical 

interconnections. 

 Gas Interconnection: Natural gas interconnection and metering costs are generic and based on 

nominal one-mile gas pipeline laterals. Per-mile costs are assumed based on historical costs for 

pipeline laterals serving similar generation facilities. Owner’s Contingency: An owner’s contingency 

is also included to account for undefined project scope and pricing uncertainty within owner’s cost 

components. Like the EPC contingency, the levels of owner’s contingencies differ from case to case, 

and do so for many of the same reasons, including project uncertainty, risk, and complexity. 

Locational Adjustments

We estimated the capital costs adjustment factors account for technology implementation at various 

locations in the United States. Appendix A provides locational adjustment factors. 

Craft labor rates for each location were developed from the publication RS Means Labor Rates for the 

Construction Industry, 2023 edition. Costs were added to cover social security, workmen’s compensation, 

and federal and state unemployment insurance. The resulting burdened craft rates were used to develop 

typical crew rates applicable to the task performed. For each technology, up to 26 different crews were 

used to determine the average wage rate for each location. For several technologies, relevant internal 

Sargent & Lundy estimates were used to further refine the average wage rate by using the weighted 

average based on the crew composition for the specific technology. 
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Sargent & Lundy used a “30 City Average” based on RS Means Labor Rates for the Construction Industry 

to establish the base location for all the technologies. We measured the wage rate factor for each location 

against the base rate (the “30 City Average”). The location factors were then improved by adding the 

regional labor productivity factor; these factors are based on the publication Compass International Global 

Construction Costs Yearbook, 2022 edition. Even though Compass International Global Construction Costs 

Yearbook provides productivity factors for some of the major metro areas in the United States, the 

productivity factors on the state level were mostly used to represent the typical construction locations of 

plants for each of the technologies. The final location factor was measured against average productivity 

factor, which is based on the same 30 cities that are included in the “30 City Average” wage rate. 

Environmental Location Factors

Capital cost adjustment factors have also been estimated to account for environmental conditions at various 

locations in the United States. These environmental location factors, however, do not account for any state 

or local jurisdictional amendments or requirements that modify the national design codes and standards 

(for example: American Society of Civil Engineers [ASCE], International Building Code, etc.). Soil Site Class 

D for stiff soils was assumed; geotechnical investigation is required to account for site-specific soil 

conditions that will need to be considered during detailed design. Risk Category II was assumed for all 

power generating technologies. Each environmental factor was baselined, and the geometric mean was 

used to determine the combined environmental location factor that accounts for the wind, seismic, snow, 

and tsunami effects, as applicable. To distribute the environmental location factor to the material costs for 

the civil, mechanical, electrical, carbon capture, and other works for each of the 19 cases, the factor was 

proportioned based on the assumed effect environmental loading would have on the works. In other words, 

the concrete foundations support most of the design loading; therefore, the percentage of the environmental 

loading factor that was distributed to the civil works was typically the highest. The distribution of the 

environmental loading factor was based on typical general arrangements of major equipment, buildings, 

and balance of plant for each of the 19 cases. 

The environmental location factor for wind is based on ASCE 7-16, and it is based on velocity pressure for 

enclosed, rigid buildings with flat roofs, which is the most widely used building configuration at power 

generating stations. The baseline was the approximate average velocity pressure for the location data set; 

therefore, the factor was reduced for locations lower than the average and increased for locations above 

the average. 
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The environmental location factor for seismic is based on the “Seismic Design” category, which is 

determined based on site-specific coefficients1 and the calculated mapped spectral response or design 

spectral acceleration. The baseline was Seismic Design Category B; therefore, the factor was reduced for 

Seismic Design Category A and increased for Seismic Design Category C and D. None of the locations 

selected were Seismic Design Category E or F due in part to the assumed soil Site Class D. 

The environmental location factor for snow loading is based on an importance factor of 1.00. The ground 

snow load was determined using the ASCE 7-16 Hazard Tool; however, the value for Boise, Idaho, was 

based on data from ASCE 7-10 because data from ASCE 7-16 was unavailable. The ground snow load for 

case study areas assumed 50 pounds per square foot. The baseline was the approximate average ground 

snow load for the location data set; therefore, the factor was reduced for locations lower than the average 

and increased for locations above the average. 

The environmental location factor for tsunami loading is based on ASCE 7-16 methodology and an article 

published by The Seattle Times regarding the cost implications of incorporating tsunami-resistant features 

into the first building designed using the methodology. The environmental location factor included tsunami 

effects for one location: Seattle, Washington. 

Additional Location Factor Considerations

Base costs for the thermal power cases were determined assuming no significant constraints with respect 

to available water resources, wastewater discharge requirements, and ambient temperature extremes. In 

areas where these constraints are expected to add significantly to the installed equipment, we applied 

location adjustments to the capital costs. To account for locations with limited water resources, such as 

California, the southwest, and the mountain west regions, air-cooled condensers (ACCs) are used in lieu 

of mechanical draft cooling towers. In regions where wastewater loads to rivers and reservoirs are becoming 

increasingly restricted, zero liquid discharge (ZLD) equipment is added. ZLD wastewater treatment 

equipment is assumed to include reverse osmosis, evaporation/crystallization, and fractional electrode 

ionization. To reduce the loading for the ZLD systems, it is assumed that cases where ZLD is applied will 

also have equipment in place to reduce wastewater such as ACCs or cooling tower blowdown treatment 

systems. 

To account for ambient temperature extremes, costs for boiler enclosures have been included as part of 

the location factors in areas where ambient temperatures will be below freezing for significant periods of 

1 Determined using the web interface on https://seismicmaps.org/. The Structural Engineers Association of California 

and California’s Office of Statewide Health Planning and Development developed this web interface that uses the opensource code provided by the United States Geological Survey to retrieve the seismic design data. This website does 

not perform any calculations to the table values. 
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time. Costs for boiler enclosures are applied to the coal-fired cases and the biomass cases, but not to the 

CC heat recovery steam generators (HRSGs), which are assumed to open in all regions. It is assumed that 

the steam turbine generator (STG) equipment will be enclosed for all cases in all locations. 

OPERATING AND MAINTENANCE COST ESTIMATING

Once a plant enters commercial operation, the plant owners incur ongoing costs for the operation and 

maintenance (O&M) of the facility. These costs are categorized into fixed O&M costs which are incurred 

each year independent of the facility dispatch, and variable O&M costs which vary with the hours of 

operation. Operations and maintenance costs presented in this report do not include the costs for fuel or 

fuel procurement activities. 

Fixed Operations and Maintenance

Fixed O&M costs include costs directly related to the generation technology and facility design which do 

not vary with dispatch. These typically include labor, materials, contract services for routine O&M, general 

and administrative (G&A) costs. Costs were estimated based on a variety of sources including actual 

projects, vendor publications, and Sargent & Lundy’s internal resources. Property taxes and insurance 

would also typically be considered fixed O&M but are excluded from our estimates. 

Where sufficient data was available, fixed O&M cost breakouts are provided in $/year annual costs with 

brief descriptors of the cost components. Typical fixed O&M costs include: 

 Routine Labor

 Materials and Contract Services

 Administrative and General Expenses

Routine labor includes the regular maintenance of the equipment as recommended by the equipment 

manufacturers. This includes maintenance of pumps, compressors, transformers, instruments, controls, 

and valves. The power plant’s typical design is such that routine labor activities do not require a plant 

outage. 

Materials and contract services include the materials associated with the routine labor as well as contracted 

services such as those covered under a long-term service agreement, which has recurring monthly 

payments. 
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General and administrative expenses are operation expenses, which include leases, management salaries, 

and office utilities. 

These annual costs are combined in the fixed O&M subtotal and levelized by dividing by the net kW capacity 

of the facility to deliver values in $/kW-year. For the geothermal, hydro, wind, solar, and battery energy 

storage cases, all O&M costs are treated as fixed costs. 

Variable Operations and Maintenance

Variable O&M costs are costs that vary based on the amount of electrical generation at the power plant. 

These expenses may include water consumption, waste and wastewater discharge, chemicals such as 

selective catalytic reduction ammonia, and consumables including lubricants and calibration gas. Because 

these costs are generation dependent, the values are levelized by the cost per unit of energy generation 

and presented in $/MWh. 
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I N F L A T I O N R E D U C T I O N A C T C O N S I D E R A T I O N S

The Inflation Reduction Act (IRA), signed into law in August of 2022, introduced a comprehensive set of tax 

credits, grants, and loan programs aimed at financing and expediting the deployment of clean energy 

technologies. The capital and operating cost estimates included in this report do not account for investment 

tax credits, production tax credits, or any other tax credit incentives that may be applicable to the reference 

technology. These credits would, however, represent critical components of the financial considerations for 

several of the cases presented herein. For this reason, a brief discussion of some of the available credits 

and their qualification requirements is included below. 

CARBON CAPTURE TECHNOLOGIES

Carbon capture technologies may be eligible for several incentives under the IRA, including the Energy 

Infrastructure Reinvestment Financing, and USDA Assistance for Rural Electric Cooperatives; but the most 

impactful feature pertaining to carbon capture is the extension and expansion of the Internal Revenue 

Code’s (IRC) 45Q tax credit for Credit for Carbon Oxide Sequestration. The IRA extends the preexisting 

45Q tax credit availability timeline, adds an enhanced credit for direct air capture (DAC), and lowers the 

carbon capture threshold requirements for certain facilities to benefit from the credit. Facilities meeting 

prevailing wage and registered apprenticeship requirements can qualify for bonus credits as well. 

The base credit amount is $17 per metric ton of carbon dioxide captured and sequestered or $12 per metric 

ton for carbon dioxide that is injected for enhanced oil recovery or utilized. Those amounts are $36 and 

$26, respectively, for direct air capture facilities. Recipients may qualify for bonus credits worth 5 times 

these amounts if the facilities meet the IRA’s prevailing wage and registered apprenticeship requirements. 

Facilities claiming the 45Q credit must be constructed in the U.S. before January 1, 2023, and must capture 

the necessary minimum annual volumes of CO2 as determined by the type of facility:

 1,000 metric tons of CO2 per year for DAC facilities

 18,750 metric tons for electricity generating facilities (with carbon capture capacity of 75% of 

baseline CO2 production)

 12,500 metric tons for other facilities

The 45Q credits may be claimed for 12 years after an eligible facility is placed in service. 
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NUCLEAR TECHNOLOGIES

Nuclear power generators are also eligible for several credits, most notably, the IRC section 45J credit for 

the production of electricity from advanced nuclear power facilities. This credit was originally enacted by 

section 1306 of the Energy Policy Act of 2005, offering 1.8 cents per kWh of energy produced and sold by 

qualifying advanced nuclear facilities – with certain caps and limitations – which were placed in service 

before January 1, 2021. The IRA does not modify the 45J credit but adds an alternative Zero-Emission 

Nuclear Power Production Credit in the IRC section 45U. This credit applies to existing nuclear power plants 

which at time of enactment, are not eligible for the 45J credit. The base credit amount is 0.3 cents per kWh 

and will be inflation adjusted after 2024. The credit amount phases down depending on the amount of 

energy produced and the gross receipts of the nuclear power facility. 

The 45U credit will be made available for electricity produced at qualifying facilities and sold after December 

31, 2023, and in tax years beginning after that date, expiring in 2032. 45U recipients may qualify for bonus 

credits worth five times the base credit amount if the facility meets the IRA’s prevailing wage requirements. 

CLEAN ENERGY PRODUCTION AND INVESTMENT TAX CREDITS

The Clean Energy Production and Investment Tax Credits (“PTC” and “ITC”) extended in the IRA offer 

financial relief to qualifying entities by offsetting a portion of the costs associated with implementing or 

operating renewable energy technologies. These two credit structures, more commonly known by their 

Internal Revenue Code sections 45Y (PTC) and 48E (ITC) reduce a renewable energy developer’s federal 

tax liability in the following ways: 

 The investment tax credit is a tax credit that reduces the federal income tax liability for a percentage 

of the cost of a qualifying renewable energy system that is installed during the tax year.

 The production tax credit is a per kilowatt-hour (kWh) tax credit for electricity generated by qualifying 

technologies for the first 10 years of a system’s operation. It reduces the federal income tax liability 

and is adjusted annually for inflation.

These IRA tax credits may be applied to a diverse range of renewable energy technologies including wind, 

solar, bioenergy, geothermal, small irrigation, landfill and trash, hydropower, fuel cells, and several more. 

Under the IRA, eligible renewable energy projects may qualify for various bonus credits that further increase 

the tax incentives. Criteria for these bonus credits include labor requirements, energy community 

requirements, and domestic content requirements. These additional qualifications aim to promote fair 

wages, support impacted communities, and foster domestic energy independence. A summary of these 

credits, their values, and their phase-out schedules is presented in Figure 1. 
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Figure 1 — Summary of Investment Tax Credits and Production Tax Credits Over Time 

Source: https://www.energy.gov/eere/solar/federal-solar-tax-credits-businesses 

Additional discussion of the qualification requirements for prevailing wage labor, domestic content, and 

energy community bonus credits is included in the subsections below. 

LABOR REQUIREMENTS

To meet the labor requirements under the IRA, all wages for construction, alteration, and repair—for the 

first 5 years of the project for the investment tax credit and the first 10 years of the project for the production 

tax credit—must be paid at the prevailing rates of that location. Additionally, a certain percentage of the 
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total construction labor hours for a project must be performed by an apprentice. Qualifying projects must 

meet the following minimum percentages of apprentice labor: 

 0% for projects beginning construction in 2022

 12.5% for projects beginning construction in 2023

 15% for projects beginning construction after 2023

If the prevailing wage or apprenticeship requirements were not originally satisfied, a project may still obtain 

the bonus credit by paying the affected employees the difference in wages plus interest and paying a $5000 

fee to the United States Department of Labor for each impacted individual. The apprenticeship requirements 

also can be satisfied if a good faith effort was made to comply or if a penalty is paid to the United States 

Department of the Treasury in the amount of $50/hour of noncompliance. 

DOMESTIC CONTENT REQUIREMENTS

The domestic content requirements under the IRA aim to support and strengthen United States based 

production industries by incentivizing the use of domestically sourced materials and components in 

renewable energy products. To qualify for the domestic content bonus, all structural steel or iron products 

used in the project must be produced in the United States and a “required percentage” of the total costs of 

manufactured products (including components) of the facility need to be mined, produced, or manufactured 

in the United States. The minimum required percentage of manufactured products for bonus qualification 

is as follows: 

 40% for all projects beginning construction before 2025

 45% for projects beginning construction in 2025

 50% for projects beginning construction in 2026

 55% for projects beginning construction after 2026

The percentage is calculated by dividing the cost of all domestically manufactured products and 

components by the total cost of all manufactured products. 

Executive Order 14017 “America’s Supply Chains,” directed the Secretary of Energy to submit a report on 

supply chains for the energy sector industrial base. In response, the U.S. Department of Energy (DOE) 

prepared and issued a series of deep dive assessments of supply chains for eleven different technology 

sectors. These assessments illustrate the limited domestic production capacity available for many 

renewable technologies from raw material and feedstock processing to finished product manufacturing and 

assembly. A brief summary of their findings for solar photovoltaics, wind, and energy storage technologies 

is included in the subsections below. 
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Solar Photovoltaic Supply Chains

In the United States, two primary types of solar PV modules dominate the market: crystalline silicon (c-Si) 

modules, constituting approximately 84%, and cadmium telluride (CdTe) modules, making up the remaining 

16%. Both these module types require mounting structures, commonly referred to as racking, for 

mechanical support, which can either track the sun's movement (tracking) or remain fixed at a specific angle 

(fixed tilt). PV modules produce direct current (DC) output, typically converted into alternating current (AC) 

through an inverter. However, they can also be used directly to charge nearby battery energy storage in 

"DC-coupled" configurations. A breakdown of key components within the solar PV supply chain is illustrated 

in Figure 2. 

Figure 2 — The Solar Photovoltaics Supply Chain 

Source: US Department of Energy. “Solar Photovoltaics Supply Chain." Image. Energy.Gov. February 24, 2022. 

https://www.energy.gov/sites/default/files/2022-02/Solar%20Energy%20Supply%20Chain%20Report%20- 

%20Final.pdf 

The supply chain for crystalline silicon (c-Si) modules begins with the refinement of high-purity 

polycrystalline silicon, commonly referred to as polysilicon. This essential component's raw material is 

metallurgical-grade silicon (MGS), also known as silicon metal, which is derived from high-grade quartz. 

Approximately 12% of the global MGS production is dedicated to the production of high-purity polysilicon 

for the solar industry. Polysilicon undergoes a melting process to cultivate monocrystalline silicon ingots 

which are subsequently sliced into thin silicon wafers. These wafers are then processed to create the solar 

cells that are interconnected and enclosed between layers of glass and plastic, forming the c-Si modules. 

A significant proportion of silicon wafer production, approximately 97%, is concentrated in China, with these 

wafers being exported to manufacturing facilities worldwide, including the United States. Nearly threequarters of the silicon solar cells integrated into modules installed in the United States are manufactured 

by Chinese subsidiaries located in just three Southeast Asian countries: Vietnam, Malaysia, and Thailand. 

Despite announced plans for domestic manufacturing facilities, the United States presently lacks active 

production capacity for c-Si ingots, wafers, or cells. 

The United States does possess domestic production capacity for thin-film Cadmium Telluride (CdTe) 

modules, a technology that does not rely on materials sourced from Chinese companies. The 16% of PV 

installations in the United States utilizing CdTe modules were exclusively supplied by a single American 
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company. This U.S.-based company is responsible for producing roughly one-third of these CdTe modules 

within the United States, contributing to the diversification of the country's solar module manufacturing 

supply chain. 

Wind Energy Supply Chains

Wind power plants are composed of five primary components: towers, rotors/blades, nacelle/drivetrain, 

foundations, and grid interconnection equipment. Domestic content is readily available for larger 

components of land-based wind plants, such as towers, nacelles, and blades (Figure 3), though domestic 

content in blades has declined in recent years. For offshore wind technologies there was no domestic supply 

chain capacity in 2021, apart from some manufacturing of applicable electrical equipment and cabling. 

However, several manufacturers have announced their intent to begin production at U.S. facilities in the 

coming years. The domestic supply chain in 2020 was capable of producing10-15 GW/year for each primary 

land-based turbine component (towers, blades, and nacelles) (Wiser et al. 2021). BloombergNEF estimated 

that a typical onshore wind project in the U.S. sources 57% of its components (by dollar value) domestically 

(Goldie-Scot, Zindler, and Wang 2021). 

Figure 3 — Domestic Manufacturing Content for Onshore Wind Power in 2020 

Source: Lawrence Berkeley National Laboratory Analysis 

Energy Storage Supply Chains

There are five major components of a lithium-ion battery: anode, cathode, electrolyte salts, electrolyte 

solutions, and separators. China has a dominant market presence in terms of both current and planned 

capacity for all subcomponents. The United States has less than 10% of global capacity for any 
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subcomponent and has very little, if any, capacity planned or under construction. The markets for lithiumion batteries, are evolving quickly, primarily in the transportation sector. New facilities are announced almost 

weekly, and data from government sources such as those in China, often lag announcements from industry 

by several months. Table 3 summarizes the subcomponent market positions of the U.S. and China as of 

2021. 

Table 1-6 — United States’ and China’s Existing and Under Development Shares of 

Global Lithium-Ion Battery Subcomponent Capacity 

2021 Under Development 

Battery Component U.S. China U.S. China 

Cathode 0.70% 63% 0% 84% 

Anode Materials 0.60% 84% 0% 91% 

Separator 3% 66% 0% 76% 

Electrolyte 7% 69% 2% 75% 

Source: BloombergNEF (2021) 

Future estimates change often due to new policies related to decarbonization and country-level 

competitiveness. These figures thus indicate overall industry dominance of China over the United States 

across the battery component supply chain rather than absolute market size. 

ENERGY COMMUNITY REQUIREMENTS

The energy community requirements set forth by the IRA encourage the development of new energy 

projects in economically distressed or traditional energy communities. Energy communities include areas 

that (i) a coal mine or coal-fired power plant has closed or (ii) have been economically reliant on the 

extraction, processing, transport, or storage of coal, oil, or natural gas but now face higher-than-average 

unemployment. The DOE maintains an interactive map of metropolitan statistical areas and nonmetropolitan statistical areas that qualify for the energy community bonus under the present definition. 
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Figure 4 — Map of Census Tracts Eligible for Energy Community Bonus 

Source: https://energycommunities.gov/energy-community-tax-credit-bonus/ 
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C A S E 1 . U L T R A - S U P E R C R I T I C A L C O A L P L A N T 

W I T H O U T C A R B O N C A P T U R E , 6 5 0 M W N E T

1.1. CASE DESCRIPTION

This case comprises a greenfield coal-fired power plant with a nominal net capacity of 650 megawatts (MW) 

with a single steam generator and steam turbine with coal storage and handling systems, balance-of-plant 

(BOP) systems, and emissions control systems; there are no carbon dioxide (CO2) capture systems in this 

case. 

This case employs a modified Rankine cycle, referred to as an ultra-supercritical (USC) thermal cycle, which 

is characterized by the operation at supercritical pressures; approximately 3750 psia (pounds per square 

inch absolute) and at steam temperatures above 1100°F (degrees Fahrenheit). This increase in steam 

pressure and temperature provides more energy per pound of fuel able to be converted to shaft power in 

the steam turbine. 

The USC steam cycles are a significant improvement from the more common subcritical cycles. Therefore, 

USC technology represents the most efficient steam cycle configuration currently available. These higher 

efficiency boilers and turbines require less coal and subsequently produce less greenhouse gases and 

lower emissions. Throughout the past two decades, many USC coal power plants have been placed in 

operation, although most of these facilities have been constructed in outside of the United States. The AEP 

John Turk Plant, commissioned in 2012, is the only USC power facility constructed in the United States. 

Figure 1-1 represents a flow diagram of a generic USC coal facility. 
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Figure 1-1 — USC Coal Boiler – Flow Diagram 

Source: U.S. Environmental Protection Agency, 

Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired Electric Generating Units PDF 

Accessed from EPA.gov, https://www.epa.gov/sites/production/files/2015-12/documents/electricgeneration.pdf

The base configuration used for the cost estimate is a single unit station constructed on a greenfield site of 

approximately 400 acres with rail access for coal deliveries. The facility has a nominal net generating 

capacity of 650 MW and is assumed to fire a high sulfur bituminous coal (approximately 4 MMBtu/hour SO2) 

with fuel moisture at 11% to 13% by weight and ash at 9% to 10%. Mechanical draft cooling towers are 

used for cycle cooling, and the water utilized for cycle cooling and steam cycle makeup is provided by an 

assumed adjacent freshwater reservoir or river. 

1.1.1. Mechanical Equipment and Systems

1.1.1.1. USC Steam Cycle

The steam turbine is a tandem compound reheat machine consisting of a high-pressure turbine, an 

intermediate-pressure turbine, and two double-flow low-pressure turbines with horizontal casing splits. The 

USC thermal cycle comprises eight feedwater heaters. The eighth heater is supplied with extraction steam 

from the high-pressure turbine. This heater configuration is commonly referred to as a “HARP” system, 

which is “Heater Above Reheat Point” of the turbine steam flow path. Boiler feedwater is supplied to the 
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cycle with a single steam driven boiler feedwater pump. with the turbine exhaust directed to the lowpressure condenser. Steam leaves the boiler to a high-pressure steam turbine designed for the USC 

pressures and temperatures. Steam leaving the high-pressure turbine is reheated in the boiler and directed 

to the intermediate-pressure turbine. The low-pressure turbine sections are twin dual flow turbines. The 

condensers are multi-flow units, one per each dual flow low-pressure turbine, operated at 2.0 inches of 

mercury absolute. The plant cooling system uses mechanical draft cooling towers with a circulated water 

temperature rise of 20°F. 

The plant performance estimate is based on ambient conditions of 59°F, 60% relative humidity, and sea 

level elevation. The boiler efficiency is assumed to be 87.5%. The gross plant output is estimated to be 735 

MW with a net output of 650 MW. The net heat rate is estimated to be 8638 Btu/kWh (British thermal unit 

per kilowatt-hour) based on the higher heating value (HHV) of the fuel and the net electrical output. 

1.1.1.2. Steam Generator

For the base case design, the single steam generator is designed for an outdoor location. The steam 

generator is a USC, pulverized-coal-fired type, balanced draft, once-through unit equipped with 

superheater, reheater, economizer, and regenerative air heaters. All materials of construction are selected 

to withstand the pressures and temperatures associated with the USC conditions and are in accordance 

with Section 1 of the ASME Boiler Pressure Vessel Code. The boiler is fired with pulverized bituminous coal 

through six pulverizers. The boiler-firing system consists of low-nitrogen oxide (NOX) burners (LNBs) and 

overfire air (OFA). A submerged flight conveyor system is used for bottom ash removal. An economizer 

preheats the feedwater prior to entering the boiler water walls. Combustion air is preheated with two parallel 

trisector air preheaters. Combustion air is delivered to the boiler by two forced draft fans and two primary 

air fans. Two axial induced draft fans are used to transfer combustion gases through a baghouse, wet flue 

gas desulfurization (WFGD) system, wet electrostatic precipitator (WESP), and wet chimney. 

1.1.1.3. Water Treatment

The facility’s water treatment plant consists of pretreatment and demineralization. All raw water entering 

the facility is first sent to the pretreatment system, which mainly consists of two redundant clarifiers where 

chemicals are added for disinfection and suspended solids removal. The pretreatment system includes lime 

addition. The lime addition allows for the partial removal of hardness and alkalinity from the raw water, if 

required. After pretreatment, the water is sent to a storage tank and then directed to the service and 

firewater users. A demineralizer system is used to provide steam cycle makeup water of sufficient quality 

for the once-through system. All wastewater from the demineralizer system is either recycled to the WFGD 

system or sent to the wastewater neutralization and discharge system. 
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1.1.1.4. Material Handling

The coal handling system includes rail car unloading, reclaim systems, a dual coal conveyor system, 

transfer towers, and coal crushers. The fly ash handling system includes equipment to remove ash from 

the boiler, economizer, air heater, and baghouse. Fly ash is collected dry and conveyed to a storage silo. 

Fly ash is collected from the storage by truck for offsite disposal. 

1.1.2. Electrical and Control Systems

The USC facility generator is rated at approximately 780 megavolt-ampere (MVA) with an output of 24 

kilovolts (kV) and is connected via generator circuit breakers to a generator step-up transformer (GSU). 

The GSU increases the voltage from the generator voltage level to the transmission system high-voltage 

level. The electrical system includes auxiliary transformers and reserve auxiliary transformers. The facility 

and most of the subsystems are controlled using a central distributed control system (DCS). 

1.1.3. Offsite Requirements

Coal is delivered to the facility by rail. The maximum daily coal rate for the facility is approximately 4600 

tons per day. The number of rail cars to support this facility is estimated at approximately 330 rail cars per 

week. 

The site is assumed to be located adjacent to a river or reservoir that can be permitted to supply a sufficient 

quantity of cooling water. The total volume of water consumption for cooling tower makeup, cycle makeup, 

and other demands is estimated to be approximately 7000 gallons per minute. Wastewater is sent to the 

adjacent waterway from one or more outfalls from a water treatment pond or wastewater treatment system. 

The facility is assumed to start up on natural gas; therefore, the site is connected to a gas distribution 

system. Natural gas interconnection costs are based on a new lateral connected to existing gas pipeline. 

The electrical interconnection costs are based on a one-mile distance from the facility switchyard to the 

terminal point on an existing utility substation. For the purposes of this estimate, any costs associated with 

expansion of the substation is excluded. 

1.2. CAPITAL COST ESTIMATE

Table 1-1 summarizes the cost components for this case. The basis of the estimate assumes that the site 

is constructed in a United States region that has good access to lower-cost construction labor and has 

reasonable access to water resources, coal, natural gas, and existing utility transmission substations or 

existing transmission lines. The geographic location is assumed to be characterized by seismic, wind, and 
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other loading criteria that do not add significantly to the capital costs. An outdoor installation is assumed— 

meaning that the boiler building is not enclosed—and no special systems are required to prevent freezing 

or to account for structural snow loading. 

To determine the capital costs adjustments in other United States regions where the assumptions listed 

above are not applicable, location factors have been calculated to account for variations in labor wage rates 

and access to construction labor, labor productivity, water and wastewater resource constraints, wind and 

seismic criteria, and other environmental criteria. 

To account for locations where water resources are limited, such as California, the southwest and the 

mountain west regions, ACCs are used in lieu of mechanical draft cooling towers. In regions where 

wastewater loads to rivers and reservoirs are becoming increasingly restricted, zero liquid discharge (ZLD) 

equipment is added. ZLD wastewater treatment equipment is assumed to include reverse osmosis, 

evaporation/crystallization, and fractional electrode ionization. To reduce the loading for the ZLD systems, 

it is assumed that cases where ZLD is applied will also have equipment in place, such as ACCs or cooling 

tower blowdown treatment systems, to reduce wastewater. 

To account for ambient temperature extremes, costs for boiler enclosures have been included as part of 

the location factors in areas where ambient temperatures will be below freezing for significant periods of 

time. It is assumed that the steam turbine generator (STG) equipment will be enclosed in all locations. 

Table 1-1 — Case 1 Capital Cost Estimate 

Case 1 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

650 MW Net 

USC Coal without Carbon Capture 

1 x 735 MW Gross 

Combustion Emissions Controls Low NOx Burners / OFA 

Post-Combustion Emissions Controls Selective Catalytic Reduction (SCR) / Baghouse / WFGD / 

WESP 

Fuel Type High Sulfur Bituminous 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 650 

Heat Rate, HHV Basis Btu/kWh 8638 

Capital Cost Assumptions 

Engineering, Procurement, and Construction (EPC) 

Contracting Fee 

% of Direct and Indirect 

Costs 10% 

EPC Contingency % of EPC Costs 10% 

Owner's Services % of EPC Costs 7% 

Owner's Contingency % of Owner's Costs 12% 
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Case 1 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

650 MW Net 

USC Coal without Carbon Capture 

1 x 735 MW Gross 

Combustion Emissions Controls Low NOx Burners / OFA 

Post-Combustion Emissions Controls Selective Catalytic Reduction (SCR) / Baghouse / WFGD / 

WESP 

Fuel Type High Sulfur Bituminous 

Units 

Estimated Land Requirement acres 400 

Estimated Land Cost $/acre 24,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion Cost $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 2,900,000 

Miles miles 0.50 

Metering Station $ 1,900,000 

Typical Project Timelines 

Development, Permitting, Engineering months 24 

Plant Construction Time months 36 

Total Lead Time Before Commercial Operation Date 

(COD) months 60 

Operating Life years 40 

EPC Cost Components (Note 1) 

Civil/Structural/Architectural - Equipment and 

Materials $ 139,293,000 

Boiler Plant - Equipment and Materials $ 395,674,000 

Turbine Plant - Equipment and Materials $ 124,949,000 

Main and Auxiliary Power System - Equipment and 

Materials $ 41,759,000 

Balance of Plant and I&C - Equipment and Materials $ 272,534,000 

Substation and Switchyard Costs $ 23,254,000 

Construction Labor Costs $ 783,122,000 

Indirect Costs $ 249,366,000 

EPC Fee $ 202,995,000 

EPC Contingency $ 223,295,000 

EPC Subtotal $ 2,456,241,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 171,937,000 

Land $ 9,600,000 
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Case 1 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

650 MW Net 

USC Coal without Carbon Capture 

1 x 735 MW Gross 

Combustion Emissions Controls Low NOx Burners / OFA 

Post-Combustion Emissions Controls Selective Catalytic Reduction (SCR) / Baghouse / WFGD / 

WESP 

Fuel Type High Sulfur Bituminous 

Units 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 3,350,000 

Owner's Contingency $ 22,551,000 

Owner's Cost Subtotal $ 210,478,000 

Total Capital Cost $ 2,666,719,000 

$/kW net 4,103 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include construction 

equipment, cranes and vehicles, project management, engineering, construction management, start-up, and 

commissioning. EPC fees are applied to the sum of direct and indirect costs. 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs, and land acquisition costs. 

1.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

The operating and maintenance (O&M) costs for the USC coal-fired power generation facility are 

summarized in Table 1-2. The fixed costs cover the O&M labor, materials, and contracted maintenance 

services, and general and administrative (G&A). Major overhauls for the facility are generally based on a 

three-year/six-year basis, depending on the equipment. Major steam turbine maintenance work is generally 

performed on a five to six-year cycle. Shorter outages—such as changing out SCR catalyst—are generally 

performed on a three-year cycle. 

Non-fuel variable costs for this technology case include flue gas desulfurization (FGD) reagent costs, SCR 

catalyst replacement costs, ammonia costs, SCR reagent costs, water treatment costs, wastewater 

treatment costs, fly ash and bottom ash disposal costs, bag replacement for the fabric filters, and FGD 

waste disposal costs. 
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Table 1-2 — Case 1 Operational Cost Estimate 

Case 1 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

650 MW Net, USC Coal without Carbon Capture 

Fixed O&M – Plant (Note 1) Units Value 

Labor $/year 19,403,000 

Materials and Contract Services $/year 15,788,000 

Administrative and General $/year 4,851,000 

Subtotal Fixed O&M $/year 40,042,000 

$/kW-year 61.60 

Variable O&M (Note 2) $/MWh 6.40 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and G&A costs. O&M costs exclude property 

taxes and insurance. 

2. Variable O&M costs include catalyst replacement, ammonia, activated carbon, limestone, water, ash disposal, 

FGD waste disposal, and water discharge treatment cost. 

The post-combustion environmental controls for this technology case include an SCR NOX system with 

aqueous ammonia as the reagent, a fabric-filter baghouse ash collection system with pulse jet cleaning, 

and a limestone-based forced-oxidation WFGD for the removal of SO2 and sulfur trioxide. A WESP is 

included to mitigate sulfuric acid emissions. The flue gas pressure drops incurred from these backend 

controls have been accounted for in the induced draft fan sizing and the resultant auxiliary power demands 

in addition to the auxiliary power demands for the emissions control systems themselves. 

For this case, no CO2 emissions controls are assumed to be applicable. Refer to Case 2 for the 

implementation of a 95% carbon capture system to the USC coal power generation facility. 

1.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

The emissions for the major criteria pollutants are summarized in Table 1-3. The NOX emissions assume 

that the in-furnace controls such as LNB, OFA, and SCR systems are employed to control emissions to 

0.06 lb/MMBtu. The WFGD system is assumed to be capable of 98% reduction of SO2 from an inlet loading 

of 4.3 lb/MMBtu to an emission rate of 0.09 lb/MMBtu. The CO2 emissions estimate is derived from 40 CFR, 

Subpart C, Table C-1, as 206 lb/MMBtu. 
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Table 1-3 — Case 1 Emission Rates 

Case 1 

EIA – Emissions Rates 

650 MW Net, USC Coal without Carbon Capture 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.06 (Note 2) 

SO2 lb/MMBtu 0.09 (Note 3) 

CO2 lb/MMBtu 206 (Note 4) 

Emissions Control Notes 

1. High sulfur bituminous coal, 4 lb/MMBtu SO2 coal

2. NOx removal using LNBs with OFA, and SCR 

3. SO2 removal by forced-oxidation, limestone-based WFGD; 98% reduction

4. Per 40 CFR 98, Subpart C, Table C-1 

The post-combustion environmental controls for this technology case include an SCR NOX system with 

aqueous ammonia as the reagent, a fabric-filter baghouse ash collection system with pulse jet cleaning, 

and a limestone-based forced-oxidation WFGD for the removal of SO2 and sulfur trioxide. A WESP is 

included to mitigate sulfuric acid emissions. The flue gas pressure drops incurred from these backend 

controls have been accounted for in the induced draft fan sizing and the resultant auxiliary power demands 

in addition to the auxiliary power demands for the emissions control systems themselves. 

For this case, no CO2 emissions controls are assumed to be applicable. Refer to Case 2 for the 

implementation of a 95% carbon capture system to the USC coal power generation facility. 
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C A S E 2 . U L T R A - S U P E R C R I T I C A L C O A L P L A N T 

W I T H 9 5 % C A R B O N C A P T U R E , 6 5 0 M W N ET 

2.1. CASE DESCRIPTION

This case comprises a coal-fired power plant with a nominal net capacity of 650 MW with a single steam 

generator and steam turbine with coal storage and handling systems, balance-of-plant (BOP) systems, 

emissions control systems, and a 95% CO2 capture system. This case is similar to the plant description 

provided in Case 1; however, this case employs a 95% CO2 capture system for the entire flue gas stream, 

which requires an increased boiler size and higher heat input to account for the low-pressure steam 

extraction and larger auxiliary loads required for the CO2 capture technology employed.

The steam cycle is generally similar to that of the ultra-supercritical USC case, Case 1. As with Case 1, the 

base configuration utilized for the cost estimate is a single-unit station constructed on a greenfield site with 

rail access for coal deliveries. The estimated land requirement for this facility is of approximately 430 acres 

to account for the carbon capture equipment. 

The facility has a nominal net generating capacity of 650 MW and is assumed to fire a high sulfur bituminous 

coal (approximately 4 MMBtu/hour SO2) with fuel moisture at 11% to 13% by weight and ash at 9% to 10%. 

The gross plant output is estimated to be 819 MW to account for the additional parasitic and auxiliary loads 

due to the implementation of the CO2 capture system. Mechanical draft cooling towers are used for cycle 

cooling, and the water used for cycle cooling and steam cycle makeup is provided by an assumed adjacent 

freshwater reservoir or river. 

2.1.1. Mechanical Equipment And Systems

Refer to Case 1 for a description of the major mechanical equipment and systems associated with the USC 

power generation facility. This section provides a description of the major equipment and systems for the 

CO2 capture plant used as the basis for the capital and operating and maintenance (O&M) cost estimates.

2.1.1.1. General CO2 Capture Description

The most commercially available CO2 capture technology for coal-fired power plants is amine-based 

scrubbing technology. This technology requires an absorption column to absorb the CO2 from the flue gas 

and a stripping column to regenerate the solvent and release the CO2. Amine-based solvents are used in 

the absorption column and require periodic makeup streams and waste solvent reclamation. Steam is used 

to break the bond between the CO2 and solvent. CO2 leaves the stripper with moisture prior to being 

dehydrated and compressed. The product CO2 is pipeline quality at 99.5% purity and approximately 2215
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psia. The amine-based solvent systems are typically designed for 95% CO2 capture in the absorption 

column. 

2.1.1.2. CO2 Capture Systems

This case assumes full integration of the CO2 capture facility with the boiler/turbine system design. The CO2 

capture technology uses various utilities to operate, including low-quality steam and auxiliary power. Steam 

can be extracted between the intermediate pressure and low-pressure turbine sections that will provide the 

least amount of capacity derate while maintaining the necessary energy to drive the CO2 capture system. 

Extracting steam prior to the low-pressure turbine section requires additional fuel to be fired to account for 

the lost generation potential. As such, the boiler, turbine, and associated systems would be required to be 

made larger to maintain the same net power production. Additionally, the CO2 capture facility and BOP 

associated with the CO2 capture system requires a significant amount of auxiliary power to drive the 

mechanical equipment. Most of the power consumption is used to drive the CO2 compressors to produce 

pipeline quality CO2 at approximately 2215 psia. The increase in auxiliary power consumption due to the 

CO2 facility usage will require a larger turbine throughput to produce the added output. Overall, CO2 capture 

system integration can account for approximately 60% of the total full load auxiliary power demand. 

Other utilities that are integrated with the base plant are demineralized water and cooling water. 

Demineralized water is used to maintain a water balance within the amine process or in the solvent 

regeneration stages. The demineralized water consumption rate for the CO2 capture facility is typically 

minor in comparison with base-plant utilization rates. As such, the demineralized water is expected to be 

fed from the base facility. This cost is accounted for in the O&M estimate only. Conversely, cooling water 

demands for the carbon capture process is significant. CO2 capture systems require circulating cooling 

water rates similar to that of the condensers. As such, the cooling system, in this case evaporative cooling 

towers, are required to be expanded to account for the large amount of additional heat rejection. This cost 

is accounted for in the capital and O&M estimates. The increase in cooling tower size also requires a higher 

cooling tower blowdown rate that needs to be treated at the wastewater treatment system. This cost is 

reflected in the capital and O&M estimates. 

Commercial amine-based CO2 capture technology requires a quencher to be located upstream of the CO2 

absorber vessel. The quencher cools the flue gas to optimize the kinetics and efficiency of the CO2 

absorption process via the amine-based solvent. During the quenching process, a significant amount of flue 

gas moisture condenses into the vessel and requires a significant amount of blowdown to maintain the level 

in the vessel. This blowdown quality is not good enough to reuse in the absorber system for water balance, 

but it is an acceptable quality to either reuse in the cooling towers or wet flue gas desulfurization (WFGD) 

for makeup water. Due to the reuse, it does not require additional O&M costs. 
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A generic flow diagram for post-combustion carbon capture system is provided in Figure 2-1. The 

termination of the process of the CO2 capture facility is the new emissions point, which is a small stack at 

the top of the CO2 absorber vessel. For this configuration, a typical free-standing chimney is not required. 

Additionally, the compressed product CO2 is the other boundary limit. This estimate does not include 

pipeline costs to transport the CO2 to a sequestration or utilization site.

Figure 2-1 — Carbon Capture Flow Diagram 

2.1.1.3. 95% CO2 Capture

Source: Author © Sargent & Lundy, L.L.C 

For the case where a new USC coal-fired facility is required to provide 95% CO2 reduction, the full flue gas 

path must be treated. As referenced previously, 95% capture is the typical design limit for CO2 reduction in 

the absorber. Therefore, 100% of the plant’s flue gas would need to be treated to provide 95% reduction 

efficiency. In this scenario, a significant amount of steam and auxiliary power is required to drive the large 

CO2 capture system, ultimately increasing the size of the boiler to generate the additional steam and power 

required to maintain a net power output of 650 MW. As the boiler gets larger, more flue gas must be treated. 

As such, it is an iterative process to determine the new boiler size necessary to treat 100% of the flue gas 

from a new USC coal-fired boiler. 
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2.1.1.4. Plant Performance

For this case, all the flue gas is discharged from the carbon capture system, so no additional wet chimney 

is included in the capital cost estimate. 

The plant performance estimate is based on ambient conditions of 59°F, 60% relative humidity, sea level 

elevation, and 95% CO2 capture. Approximately 2,238,000 lb/hr of low-pressure steam is required for the 

CO2 system. The boiler efficiency is assumed to be 87.5%, and the estimated gross size of the boiler is 

1013 MW, which is approximately 40% larger than the case without carbon capture (Case 1). The generator 

gross output is approximately 819 MW. The estimated total auxiliary load for the plant is 169 MW, with 106 

MW required for the for the CO2 system. The net heat rate is estimated to be 12,293 Btu/kWh based on the 

higher heating value (HHV) of the fuel and the net electrical output. 

2.1.2. Electrical and Control Systems

The electrical equipment includes the turbine generator, which is connected via generator circuit breakers 

to a generator step-up transformer (GSU). The GSU increases the voltage from the generator voltage level 

to the transmission system high-voltage level. The electrical system is essentially similar to the USC case 

without carbon capture (Case 1); however, there are additional electrical transformers and switchgear for 

the CO2 capture systems. The electrical system includes auxiliary transformers and reserve auxiliary 

transformers. The facility and most of the subsystems are controlled using a central distributed control 

system (DCS). 

2.1.3. Offsite Requirements

Coal is delivered to the facility by rail. The maximum daily coal rate for the facility is approximately 6500 

tons per day. The number of rail cars to support this facility is estimated at approximately 460 rail cars per 

week. 

The site is assumed to be located adjacent to a river or reservoir that can be permitted to supply a sufficient 

quantity of cooling water. The total volume of water required for cooling tower makeup, cycle makeup, and 

cooling for the CO2 system is estimated to be approximately 17,500 gallons per minute. Wastewater is sent 

to the adjacent waterway from one or more outfalls from a water treatment pond or wastewater treatment 

system. 

The CO2 captured will need to be sequestered in a geologic formation or used for enhanced oil recovery. 

The viability of this technology case will be driven, to a large extent, by the proximity of the facility to the 

appropriate geologic formations. The costs presented herein do not account for equipment, piping, or 

structures associated with CO2 sequestration.
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The facility is assumed to start up on natural gas. Therefore, the site is connected to a gas distribution 

system. Natural gas interconnection costs are based on a new lateral connected to existing gas pipeline. 

The electrical interconnection costs are based on a one-mile distance from the facility switchyard to the 

terminal point on an existing utility substation. For the purposes of this estimate, the cost associated with 

the expansion of the substation is excluded. 

2.2. CAPITAL COST ESTIMATE

Table 2-1 summarizes the cost components for this case. The basis of the estimate assumes that the site 

is constructed in a United States region that has good access to lower-cost construction labor and has 

reasonable access to water resources, coal, natural gas, and existing utility transmission substations or 

existing transmission lines. The geographic location is assumed to be characterized by seismic, wind, and 

other loading criteria that do not add significantly to the capital costs. An outdoor installation is assumed, 

meaning that the boiler building is not enclosed, and no special systems are required to prevent freezing or 

to account for structural snow loading. 

To determine the capital costs adjustments in other United States regions where the assumptions listed 

above are not applicable, location factors have been calculated to account for variations in labor wage rates 

and access to construction labor, labor productivity, water and wastewater resource constraints, wind and 

seismic criteria, and other environmental criteria. 

To account for locations where water resources are limited, such as California, the southwest and the 

mountain west regions, air-cooled condensers (ACCs) are used in lieu of mechanical draft cooling towers. 

In regions where wastewater loads to rivers and reservoirs are becoming increasingly restricted, ZLD 

equipment is added. ZLD wastewater treatment equipment is assumed to include reverse osmosis, 

evaporation/crystallization, and fractional electrode ionization. To reduce the loading for the ZLD systems, 

it is assumed that cases where ZLD is applied will also have equipment in place, such as ACCs or cooling 

tower blowdown treatment systems, to reduce wastewater. 

To account for ambient temperature extremes, costs for boiler enclosures have been included as part of 

the location factors in areas where ambient temperatures will be below freezing for significant periods of 

time. It is assumed that the steam turbine generator (STG) equipment will be enclosed in all locations. 
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Table 2-1 — Case 2 Capital Cost Estimate 

Case 2 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

650 MW Net 

USC Coal 

95% Carbon Capture System 

1 x 819 MW Gross 

Combustion Emissions Controls Low NOx Burners (LNBs) / Overfire Air (OFA) 

Post-Combustion Emissions Controls 

Selective Catalytic Reduction (SCR) / Baghouse/ 

WFGD / WESP / Amine-Based Carbon Capture and 

Sequestration (CCS) 

Fuel Type High Sulfur Bituminous 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 650 

Heat Rate, HHV Basis Btu/kWh 12,293 

Capital Cost Assumptions 

Engineering, Procurement, and Construction (EPC) 

Contracting Fee 

% of Direct and Indirect 

Costs 10% 

EPC Contingency % of EPC Costs 12% 

Owner's Services % of EPC Costs 7% 

Owner's Contingency % of Owner's Costs 12% 

Estimated Land Requirement acres 430 

Estimated Land Cost $/acre 23,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion Cost $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 2,900,000 

Miles miles 0.50 

Metering Station $ 1,900,000 

Typical Project Timelines 

Development, Permitting, Engineering months 30 

Plant Construction Time months 44 

Total Lead Time Before Commercial Operation Date 

(COD) months 74 

Operating Life years 40 

EPC Cost Components (Note 1) 

Civil/Structural/Architectural - Equipment and Materials $ 174,284,000 

Boiler Plant - Equipment and Materials $ 434,360,000 

Turbine Plant - Equipment and Materials $ 158,270,000 

Main and Auxiliary Power System - Equipment and 

Materials $ 55,194,000 
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Case 2 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

650 MW Net 

USC Coal 

95% Carbon Capture System 

1 x 819 MW Gross 

Combustion Emissions Controls Low NOx Burners (LNBs) / Overfire Air (OFA) 

Post-Combustion Emissions Controls 

Selective Catalytic Reduction (SCR) / Baghouse/ 

WFGD / WESP / Amine-Based Carbon Capture and 

Sequestration (CCS) 

Fuel Type High Sulfur Bituminous 

Units 

Balance of Plant and I&C - Equipment and Materials $ 283,960,000 

Substation and Switchyard Costs $ 23,254,000 

Carbon Capture System Plant – Equipment and 

Materials $ 615,388,000 

Construction Labor Costs $ 1,562,601,000 

Indirect Costs $ 272,942,000 

EPC Fee $ 358,025,000 

EPC Contingency $ 472,593,000 

EPC Subtotal $ 4,410,871,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 308,761,000 

Land $ 9,890,000 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 3,350,000 

Owner's Contingency $ 39,005,000 

Owner's Cost Subtotal $ 364,046,000 

Total Capital Cost $ 4,774,917,000 

$/kW net 7,346 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include engineering, 

construction management, start-up, and commissioning. EPC fees are applied to the sum of direct and indirect 

costs. 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs, and land acquisition costs. 

2.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

The O&M costs for the USC coal-fired power generation facility with 95% carbon capture are summarized 

in Table 2-2. The fixed costs cover the O&M labor, materials and contract services, and general and 

administrative (G&A). Major overhauls for the facility are generally based on a three-year/six-year basis 

depending on the equipment. Major steam turbine maintenance work is generally performed on a five to 
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six-year cycle. Shorter outages, such as changing out the SCR catalyst, are generally performed on a threeyear cycle. It is assumed that the carbon capture equipment would have major overhauls on a three-year 

cycle, but there is not a sufficient operating base to confidently predict the required frequency of major 

maintenance. The carbon capture equipment will require additional O&M labor. It is assumed that some 

form of service agreement would be needed for the compressors, absorbers, strippers, and other 

specialized equipment. 

Non-fuel variable costs for this technology case include glue gas desulfurization (FGD) reagent costs, SCR 

catalyst replacement costs, ammonia, SCR reagent costs, water treatment costs, wastewater treatment 

costs, fly ash and bottom ash disposal costs, bag replacement for the fabric filters, FGD waste disposal 

costs, and solvent makeup. For the CO2 capture system, variable costs include solvent makeup and 

disposal costs—usually offsite disposal—as the spent solvent may be considered hazardous waste; 

additional wastewater treatment costs (predominantly cooling tower blowdown treatment); and additional 

demineralized makeup water costs. 

Table 2-2 — Case 2 Operational Cost Estimate 

Case 2 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

650 MW Net, USC Coal with 95% Carbon Capture 

Fixed O&M – Plant (Note 1) Units Value 

Labor $/year 27,313,000 

Materials and Contract Services $/year 23,173,000 

Administrative and General $/year 5,872,000 

Subtotal Fixed O&M $/year 56,358,000 

$/kW-year 86.70 

Variable O&M (Note 2) $/MWh 13.73 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and G&A costs. O&M costs exclude property 

taxes and insurance. 

2. Variable O&M costs include catalyst replacement, ammonia, limestone, water, ash disposal, FGD waste 

disposal, solvent and water costs for the CCS, and water discharge treatment cost. 

2.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

The emissions for the major criteria pollutants are summarized in Table 2-3. The NOX emissions assume 

that the in-furnace controls, such as LNB, OFA, and SCR systems, are employed to control emissions to 

0.06 lb/MMBtu. The WFGD system is assumed to be capable of 98% reduction of SO2 from an inlet loading 

of 4.3 lb/MMBtu to an emission rate of 0.09 lb/MMBtu. The CO2 emissions estimate is based on a 95%
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reduction in base emissions, which are derived from 40 CFR, Subpart C, Table C-1 as 206 lb/MMBtu, giving 

a CO2 emission rate of 10.3 lb/MMBtu.

Table 2-3 — Case 2 Emission Rates 

Case 2 

EIA – Emissions Rates 

650 MW Net, USC Coal with 95% Carbon Capture 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.06 (Note 2) 

SO2 lb/MMBtu 0.09 (Note 3) 

CO2 lb/MMBtu 10.3 (Note 4) 

Emissions Control Notes 

1. High sulfur bituminous coal, 4 lb/MMBtu SO2 Coal

2. NOx removal using LNBs with OFA, and SCR 

3. SO2 removal by forced-oxidation, limestone-based WFGD; 98% Reduction

4. Per 40 CFR 98, Subpart. C, Table C-1 in conjunction with 95% reduction of emissions through the carbon 

capture system. 
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C A S E 3 . C O M B U S T I O N T U R B I N E - S I M P L E C Y C L E 

P L A N T , 4 X A E R O D E R I V A T I V E , 2 1 1 M W N E T

3.1. CASE DESCRIPTION

This case is comprised of four identical aeroderivative combustion turbines (CTs) in a simple-cycle 

configuration. It is based on the use of natural gas as fuel, although dual-fuel capability is provided. Output 

power voltage is stepped up for transmission to the external grid through an onsite switchyard. 

3.1.1. Mechanical Equipment and Systems

Case 3 is comprised of four of aeroderivative dual-fuel CTs in a simple-cycle configuration, with a nominal 

output of approximately 54 MW gross per turbine. After deducting internal auxiliary power demand, the net 

output of the plant is approximately 211 MW. Each CT’s inlet air duct has an evaporative cooler to reduce 

the inlet air temperature in warmer seasons to increase the CT output. Each CT is also equipped with 

burners designed to reduce the CT’s emission of NOX. Included in Case 3 are selective catalytic reduction 

(SCR) units for further reduction of NOX emissions and CO catalysts for further reduction of CO emissions. 

Refer to Figure 3-1 for a diagram of the CT systems. 

Figure 3-1 — Case 3 Configuration 

Note: Only one CT shown. All CTs has the same configuration. Source: Author © Sargent & Lundy, L.L.C. 

Aeroderivative CTs differ from industrial frame CTs in that aeroderivative CTs have been adapted from an 

existing aircraft engine design for stationary power generation applications. Consequently, compared to 
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industrial frame CTs of the same MW output, aeroderivative CTs are lighter weight, have a smaller size 

footprint, and have more advanced materials of construction. Additionally, aeroderivative CTs generally 

operate at higher pressure ratios, have faster start-up times, faster ramp rates, and higher efficiencies 

compared to industrial frame CTs. 

3.1.2. Electrical and Control Systems

Case 3 includes one 60-hertz (Hz) electric generator per CT with an approximate rating of 54 MVA and 

output voltage of 13.8 kV. The generator output power is converted to a higher voltage by generator stepup transformers (GSUs) for transmission to the external grid transmitted via an onsite switchyard. 

The simple-cycle facility is controlled by a control system provided by the CT manufacturer, supplemented 

by controls for the balance-of-plant (BOP) systems (for example, water supply to evaporative coolers, and 

fuel supply). 

3.1.3. Offsite Requirements

Offsite provisions in Case 3 include the following: 

 Fuel Gas Supply: A half-mile-long pipeline and a dedicated metering station. 

 High-Voltage Transmission Line: A one-mile-long transmission line. 

 Water Supply for Evaporative Cooler and Miscellaneous Uses: It is assumed that the water 

supply source, such as a municipal water system, is near the power plant site and the 

interconnection for water is at the plant’s site boundary. Blowdown waste from the evaporative 

cooler is sent to an approved discharge location after appropriate treatment of the wastewater, and 

the wastewater interconnection’s location is assumed at the power plant’s site boundary. 

3.2. CAPITAL COST ESTIMATE

Table 3-1 summarizes the cost components for this case. This estimate is based on an engineering, 

procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 3-1 covers owner’s costs. Owner’s 

costs include owner’s services, which include project development, studies, permitting, legal, owner’s 

project management, owner’s engineering, and owner’s start-up and commissioning costs. Other owner’s 

costs include electrical interconnection costs, gas interconnection costs, and land acquisition costs. The 

estimate is presented as an overnight cost in 2023 dollars and thus excludes allowance for funds used 

during construction or interest during construction. In addition to the cost of external systems noted above 

(for example, fuel gas supply and transmission line), an estimated amount is included for the cost of land. 
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Table 3-1 — Case 3 Capital Cost Estimate 

Case 3 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CT – Simple Cycle 

4 x Aeroderivative Class 

Combustion Emissions Controls Dry Low Emissions Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural Gas / No. 2 Backup 

4 x 54 MW rating 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 211 

Heat Rate, Higher Heating Value (HHV) Basis Btu/kWh 9447 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & 

Indirect Costs 9% 

EPC Contingency % of EPC Costs 10% 

Owner's Services % of Project 

Costs 12% 

Owner's Contingency % of Owner's 

Costs 8% 

Estimated Land Requirement acres 20 

Estimated Land Cost $/acre 62,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 2,412,000 

Miles miles 1.00 

Substation Expansion $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 3,500,000 

Miles miles 0.50 

Metering Station $ 2,200,000 

Typical Project Timelines 

Development, Permitting, Engineering months 18 

Plant Construction Time months 22 

Total Lead Time Before Commercial Operation Date 

(COD) months 40 

Operating Life years 40 

EPC Cost Components (Note 1) 

Major Owner-Furnished Equipment (Note 2) $ 155,900,000 

Other Equipment (Note 3) $ 22,800,000 

Construction Labor (Note 4) $ 35,500,000 

Indirect Costs (Note 5) $ 19,278,000 
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Case 3 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CT – Simple Cycle 

4 x Aeroderivative Class 

Combustion Emissions Controls Dry Low Emissions Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural Gas / No. 2 Backup 

4 x 54 MW rating 

Units 

Materials (Note 6) $ 10,722,000 

EPC Fee $ 21,978,000 

EPC Contingency $ 26,618,000 

EPC Subtotal $ 292,796,000 

Owner's Cost Components (Note 7) 

Owner's Services $ 35,136,000 

Land $ 1,240,000 

Electrical Interconnection $ 2,412,000 

Gas Interconnection $ 3,950,000 

Owner's Contingency $ 3,419,000 

Owner's Subtotal $ 46,157,000 

Total Capital Cost $ 338,953,000 

$/kW net 1,606 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. EPC fees are applied to the sum of direct 

and indirect costs. 

2. Major owner-furnished equipment includes CTs, SCRs, and CO catalysts. 

3. Other equipment includes pumps, tanks, MCCs, switchgear, transformers, and any other major inside-the-fence 

process equipment required for the complete facility (excluding major owner-furnished equipment). 

4. Construction labor costs are directly attributed to onsite civil/structural work and erection/installation of the 

equipment included in the EPC’s scope. 

5. Indirect costs are attributed to engineering, procurement, project services, construction management, field 

engineering, start-up, and commissioning services. 

6. Materials include all construction materials associated with the EPC scope of work, material freight costs, and 

consumables during construction. 

7. Owner’s services include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs, and land acquisition costs. 

3.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Table 3-2 shows operating and maintenance (O&M) costs. Fixed O&M costs include staff and administrative 

costs, supplies, and minor routine maintenance. (Not included are property taxes and insurance.) Fixed 

costs also include the fixed payment portion of a long-term service agreement for the CTs. 
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Variable O&M costs include consumable commodities, such as water, lubricants, and chemicals. Also 

included is the average annual cost of the planned maintenance events for the CTs over the long-term 

maintenance cycle, based on the number of equivalent operating hours (EOH) the CT has run. A significant 

overhaul is typically performed for this type of CT every 30,000 EOH, and a major overhaul is performed 

every 60,000 EOH. CTs generally have two criteria to schedule overhauls: number of equivalent starts and 

number of EOH. The aeroderivative CTs in Case 3 always use an EOH-driven maintenance overhaul 

schedule regardless of the operating profile. (Refer to Case 4 for a starts-based overhaul schedule.) An 

additional advantage of an aeroderivative CTs is that, depending on the long-term service agreement terms, 

sections of the CT can be changed out with replacement assemblies, reducing the outage time of major 

overhauls to less than one week (compared to more than a two-week outage for industrial frame CTs). 

Table 3-2 — Case 3 O&M Cost Estimate 

Case 3 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

CT – Simple Cycle 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/kW-year 9.56 $/kW-year 

Variable O&M (Note 2) $/MWh 5.70 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Variable O&M costs include water and water discharge treatment cost. These include turbine major 

maintenance activities which are based on an operating hours-dependent maintenance cycle. 

3.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

For the Case 3 simple-cycle configuration, SCR and CO catalysts are included to reduce emissions of NOX 

and CO below the emission levels in the CT exhaust gas. Table 3-3 indicates predicted NOX, SO2, and CO2 

emissions assuming natural gas firing. 
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Table 3-3 — Case 3 Emissions 

Case 3 

EIA – Emissions Rates 

CT – Simple Cycle 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.0075 

SO2 lb/MMBtu 0.00 

CO2 lb/MMBtu 117 

Emissions Control Notes 

1. Natural gas fuel, emissions controlled with SCR, no water injection 
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C A S E 4 . C O M B U S T I O N T U R B I N E - S I M P L E C Y C L E 

P L A N T , H C L A S S , 4 1 9 M W N ET 

4.1. CASE DESCRIPTION

This case is comprised of one industrial frame Model H combustion turbine (CT) in simple-cycle 

configuration. It is based on natural gas firing of the CT, although dual-fuel capability is provided. Output 

power voltage is stepped up for transmission to the external grid through an onsite switchyard. 

4.1.1. Mechanical Equipment and Systems

Case 4 is comprised of one industrial frame Model H dual-fuel CT in simple-cycle configuration with a 

nominal output of approximately 430 MW gross. After deducting internal auxiliary power demand, the net 

output of the plant is approximately 419 MW. The inlet air duct for the CT is equipped with an evaporative 

cooler to reduce the inlet air temperature in warmer seasons to increase the CT output. The CT is also 

equipped with burners designed to reduce the CT’s emission of NOX. Included in the Case 4 configuration 

is a selective catalytic reduction (SCR) unit for further reduction of NOX emissions and a CO catalyst for 

further reduction of CO emissions. Figure 4-1 shows a diagram of the CT systems. 

Figure 4-1 — Case 4 Configuration 

Source: Author © Sargent & Lundy, L.L.C. 

Frame CTs differ from aeroderivative CTs in that the industrial frame CT’s performance characteristics 

generally are more conducive to improved performance in combined-cycle (CC) applications; that is, 

industrial frame CTs have a greater amount of exhaust energy to produce steam for the CC’s steam turbine 
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portion of the plant. Industrial frame CT sizes, over 400 MW in 60-Hz models, far exceed the maximum 

aeroderivative size, and on a $/kW basis, industrial frame turbines are less costly. 

4.1.2. Electrical and Control Systems

Case 4 includes one 60-Hz CT electric generator with an approximate rating of 430 MVA and output voltage 

of 13.8 kV. The generator output power is converted to a higher voltage by generator step-up transformers 

(GSUs) for transmission to the external grid, transmitted through an onsite facility switchyard. 

The simple-cycle facility is controlled by a control system provided by the CT manufacturer, supplemented 

by controls for the balance-of-plant (BOP) systems (for example, water supply to evaporative coolers, and 

fuel supply). 

4.1.3. Offsite Requirements

Offsite provisions in Case 4 include the following: 

 Fuel Gas Supply: A half-mile-long pipeline and a dedicated metering station. 

 High-Voltage Transmission Line: A one-mile-long transmission line. 

 Water Supply for Evaporative Cooler and Miscellaneous Uses: It is assumed that the water 

supply source, such as a municipal water system, is near the power plant site and the 

interconnection for water is at the plant’s site boundary. Blowdown waste from the evaporative 

cooler is sent to an approved discharge location after appropriate treatment of the wastewater, and 

the wastewater interconnection is assumed at the power plant’s site boundary. 

4.2. CAPITAL COST ESTIMATE

Table 4-1 summarizes the cost components for this case. This estimate is based on an engineering, 

procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 4-1 covers owner’s costs. Owner’s 

costs include owner’s services which include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, and owner’s start-up and commissioning costs. Other owner’s costs 

include electrical interconnection costs, gas interconnection costs, and land acquisition costs. The estimate 

is presented as an overnight cost in 2023 dollars and thus excludes allowance for funds used during 

construction or interest during construction. In addition to the cost of external systems noted above (for 

example, fuel gas supply), an estimated amount is included for the cost of land. 
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Table 4-1 — Case 4 Capital Cost Estimate 

Case 4 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CT – Simple Cycle 

H-Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural Gas / No. 2 Backup 

1 x 430 MW rating 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 419 

Heat Rate, Higher Heating Value (HHV) Basis Btu/kWh 9142 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and 

Indirect Costs 9% 

EPC Contingency % of EPC Costs 10% 

Owner's Services % of Project Costs 12% 

Owner's Contingency % of Owner's Costs 8% 

Estimated Land Requirement acres 20 

Estimated Land Cost $/acre 62,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 4,800,000 

Miles miles 0.50 

Metering Station $ 2,800,000 

Typical Project Timelines 

Development, Permitting, Engineering months 18 

Plant Construction Time months 22 

Total Lead Time Before Commercial 

Operation Date (COD) months 40 

Operating Life years 40 

EPC Cost Components (Note 1) 

Major Owner-Furnished Equipment (Note 2) $ 132,800,000 

Other Equipment (Note 3) $ 30,800,000 

Construction Labor (Note 4) $ 57,600,000 

Indirect Costs (Note 5) $ 19,908,000 
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Case 4 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CT – Simple Cycle 

H-Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural Gas / No. 2 Backup 

1 x 430 MW rating 

Units 

Materials (Note 6) $ 9,816,000 

EPC Fee $ 22,583,000 

EPC Contingency $ 27,351,000 

EPC Subtotal $ 300,858,000 

Owner's Cost Components (Note 7) 

Owner's Services $ 36,103,000 

Land $ 1,240,000 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 5,200,000 

Owner's Contingency $ 3,647,000 

Owner's Subtotal $ 49,230,000 

Total Capital Cost $ 350,088,000 

$/kW net 835.5 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. EPC fees are applied to the sum of direct 

and indirect costs. 

2. Major owner-furnished equipment includes CTs, SCRs, and CO catalysts. 

3. Other equipment includes pumps, tanks, MCCs, switchgear, transformers, and any other major inside-the-fence 

process equipment required for the complete facility (excluding major owner-furnished equipment). 

4. Construction labor costs are directly attributed to onsite civil/structural work and erection/installation of the 

equipment included in the EPC’s scope. 

5. Indirect costs are attributed to engineering, procurement, project services, construction management, field 

engineering, start-up, and commissioning services. 

6. Materials include all construction materials associated with the EPC scope of work, material freight costs, and 

consumables during construction. 

7. Owner’s services include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs, and land acquisition costs. 

4.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Operating and maintenance (O&M) costs are indicated in Table 4-2. Fixed O&M costs include staff and 

administrative costs, supplies, and minor routine maintenance. (Not included are property taxes and 

insurance.) Fixed costs also include the fixed payment portion of a long-term service agreement for the CT. 
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Variable O&M costs include consumable commodities, such as water, lubricants, and chemicals. Also 

included is the average annual cost of the planned maintenance events for the CT over the long-term 

maintenance cycle. Planned maintenance costs for the CT in a given year are based on the number of 

equivalent starts the CT has accumulated. A hot path gas inspection is performed for this type of CT every 

900 equivalent starts, and a major inspection is performed every 1800 equivalent starts. CTs generally have 

two criteria to schedule overhauls: number of equivalent starts or number of equivalent operating hours 

[EOH], whichever occurs first. In Case 4, it is assumed the operating profile results in a starts-driven 

maintenance overhaul schedule. (Refer to Case 3 for an EOH-based overhaul schedule.) In Table 4-2, the 

cost per start is broken out from the variable O&M costs that cover the consumables. 

Table 4-2 — Case 4 O&M Cost Estimate 

Case 4 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

CT – Simple Cycle 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/kW-year 6.87 $/kW-year 

Variable O&M 

Consumables (Note 2) $/MWh 1.24 $/MWh 

CT Major Maintenance (Note 2) $/Start 23,100 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Variable O&M consumables costs include water, water discharge treatment cost, etc. based on $/MWh. In 

addition to the consumables costs, add CT major maintenance variable costs, which are based on a startdependent maintenance cycle, with cost per start indicated. 

4.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

For the Case 4 simple-cycle configuration, SCR and CO catalysts are included to reduce emissions of NOX 

and CO below the emission levels in the CT exhaust gas. Table 4-3 indicates predicted NOX, SO2, and CO2 

emissions assuming natural gas firing. 
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Table 4-3 — Case 4 Emissions 

Case 4 

EIA – Emissions Rates 

CT – Simple Cycle 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.0075 

SO2 lb/MMBtu 0.00 

CO2 lb/MMBtu 117 

Emissions Control Notes 

1. Natural gas fuel, emissions controlled with SCR, no water injection 
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C A S E 5 . C O M B I N E D - C Y C L E P L A N T , H C L A S S ,

1227 MW N E T

5.1. CASE DESCRIPTION

This case is comprised of one block of a combined-cycle (CC) power generation unit in a 2x2x1 

configuration. The plant includes two industrial frame Model H “advanced technology” combustion turbines 

(CTs) and one steam turbine generator (STG). Case 5 is based on natural gas firing of the CTs, although 

dual-fuel capability is provided. Main plant cooling is accomplished with a wet cooling tower system. Output 

power voltage is stepped up for transmission to the external grid through an onsite switchyard. 

5.1.1. Mechanical Equipment and System

Case 5 is comprised of a pair of Model H, dual-fuel CTs in a 2x2x1 CC configuration (two CTs, two heat 

recovery steam generators [HRSGs], and one steam turbine). Each CT generates approximately 436 MW 

gross; the STG generates approximately 393 MW gross. After deducting internal auxiliary power demand, 

the net output of the plant is 1227 MW. Refer to Figure 5-1 for a diagram of the Case 5 configuration. 

Each CT’s inlet air duct has an evaporative cooler to reduce the inlet air temperature in warmer seasons to 

increase the CT and plant output. Each CT is also equipped with burners designed to reduce NOX 

emissions. Included in the Case 5 configuration are selective catalytic reduction (SCR) units for further NOX 

emissions reduction and CO catalysts for further CO emissions reduction. 

The CTs are Model H industrial frame-type CTs with an advanced technology design, since they incorporate 

the following features: 

 High firing temperatures (~2900°F) 

 Advanced materials of construction 

 Advanced thermal barrier coatings 

 Additional cooling of CT assemblies (depending on the CT model, additional cooling applies to the 

CT rotor, turbine section vanes, and the combustor). Refer to Figure 5-1, which depicts a dedicated 

additional cooler for the CT assemblies in Case 5. 

The high-firing temperature and additional features listed above result in increased MW output and 

efficiency of the CT as well as in the CC plant. 

Hot exhaust gas from each CT is directed to a HRSG, with one HRSG per CT. Steam generated in the 

HRSGs is directed to the STG. HRSGs may be optionally equipped with additional supplemental firing, 
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however, this feature is not included in Case 5. (Supplemental HRSG firing, while increasing the MW output 

of the STG, reduces plant efficiency.) 

A wet cooling tower system provides plant cooling for Case 5. A wet cooling tower is preferred over the 

alternative air-cooled condensers (ACC) approach since plant performance is better (that is, greater MW 

output and higher efficiency) and capital cost is generally lower. However, ACCs are often selected in areas 

where the supply of makeup water needed for a wet cooling tower is scarce or expensive, such as in desert 

areas in the southwestern United States. 

Figure 5-1 — Case 5 Configuration 

Source: Author © Sargent & Lundy, L.L.C. 

Heat Recovery Steam Generator

HRSG #1

(Three Pressure Levels with Reheat)

Combustion Turbine #1

Heat Exchanger

for CT Cooling

Heat Recovery Steam Generator

HRSG #2

(Three Pressure Levels with Reheat)

Combustion Turbine #2

Steam Turbine

Wet 

Cooling 

Tower 

SCR/CO CATALYST SCR/CO CATALYST
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5.1.2. Electrical and Control Systems

Case 5 includes one 60-Hz electric generator per CT with an approximate rating of 436 MVA and output 

voltage of 13.8 kV. The STG includes one 60-Hz electric generator with an approximate 393 MVA rating. 

The output power from the three generators is converted to a higher voltage by generator step-up 

transformers (GSUs) for transmission to the external grid, transmitted through an onsite facility switchyard. 

The CC facility is controlled by a central distributed control system (DCS), which is linked to a CT control 

system provided by the CT manufacturer. This DCS includes controls for the steam cycle systems and 

equipment as well as balance-of-plant (BOP) systems and equipment (for example, water systems, fuel 

systems, and main cooling systems). 

5.1.3. Offsite Requirements

Offsite provisions Case 5 include the following: 

 Fuel Gas Supply: A half-mile-long pipeline and a dedicated metering station. 

 High-Voltage Transmission Line: A one-mile-long transmission line. 

 Water Supply for Cooling Tower, Evaporative Coolers, Makeup to Steam Cycle, and 

Miscellaneous Uses: It is assumed that the water supply source is near the power plant site and 

the interconnection for water is at the plant’s site boundary. Blowdown waste from the cooling tower 

and other areas of the plant is sent to an approved discharge location after appropriate treatment of 

the wastewater, and the wastewater interconnection is assumed to be located at the power plant’s 

site boundary. 

5.2. CAPITAL COST ESTIMATE

Table 5-1 summarizes the cost components for this case. This estimate is based on an engineering, 

procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 5-1 covers owner’s costs. Owner’s 

costs include owner’s services which include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, and owner’s start-up and commissioning costs. Other owner’s costs 

include electrical interconnection costs, gas interconnection costs, and land acquisition costs. The estimate 

is presented as an overnight cost in 2023 dollars and thus excludes allowance for funds used during 

construction or interest during construction. In addition to the cost of external systems noted above (for 

example, fuel gas supply and transmission line), an estimated amount is included for the cost of land. 
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Table 5-1 — Case 5 Capital Cost Estimate 

Case 5 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CC 2x2x1 

H-Class 

Combustion Emissions Controls Dry Low NOx combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 1227 

Net Plant Heat Rate, Higher Heating Value (HHV) Basis Btu/kWh 6266 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and 

Indirect Costs 10% 

EPC Contingency % of EPC Costs 11% 

Owner’s Services % of Project Costs 9% 

Owner’s Contingency % of Owner’s Costs 7% 

Estimated Land Requirement acres 30 

Estimated Land Cost $/acre 54,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 6,000,000 

Miles miles 0.50 

Metering Station $ 3,400,000 

Typical Project Timelines 

Development, Permitting, Engineering months 18 

Plant Construction Time months 24 

Total Lead Time Before Commercial 

Operation Date (COD) months 42 

Operating Life years 40 

EPC Cost Components (Note 1) 

Major Owner-Furnished Equipment (Note 2) $ 319,400,000 

Other Equipment (Note 3) $ 119,700,000 

Construction Labor (Note 4) $ 200,000,000 

Indirect Costs (Note 5) $ 63,910,000 
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Case 5 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CC 2x2x1 

H-Class 

Combustion Emissions Controls Dry Low NOx combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

Materials (Note 6) $ 83,429,000 

EPC Fee $ 78,644,000 

EPC Contingency $ 95,159,000 

EPC Subtotal $ 960,242,000 

Owner’s Cost Components (Note 7) 

Owner’s Services $ 86,422,000 

Land $ 1,620,000 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 6,400,000 

Owner’s Contingency $ 6,824,000 

Owner’s Subtotal $ 104,306,000 

Total Capital Cost $ 1,064,548,000 

$/kW net 867.6 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. EPC fees are applied to the sum of direct 

and indirect costs. 

2. Major owner-furnished equipment includes CTs, HRSG, SCRs, CO catalysts, and steam turbines. 

3. Other equipment includes pumps, tanks, MCCs, condensers, cooling towers, switchgear, transformers, and any 

other major inside-the-fence process equipment required for the complete facility (excluding major owner-furnished 

equipment). 

4. Construction labor costs are directly attributed to onsite civil/structural work and erection/installation of the 

equipment included in the EPC’s scope. 

5. Indirect costs are attributed to engineering, procurement, project services, construction management, field 

engineering, start-up, and commissioning services. 

6. Materials include all construction materials associated with the EPC scope of work, material freight costs, and 

consumables during construction. 

7. Owner’s services include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs, and land acquisition costs. 

5.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Table 5-2 indicates operating and maintenance (O&M) costs. Fixed O&M costs include staff and 

administrative costs, supplies, and minor routine maintenance. (Not included are property taxes and 

insurance.) Fixed costs also include the fixed payment portion of a long-term service agreement for the 
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CTs. Additional O&M costs for firm gas transportation service are not included as the facility has dual-fuel 

capability. 

Variable O&M costs include consumable commodities, such as water, lubricants, and chemicals. It also 

includes the periodic costs to change out the SCR and CO catalysts. The variable O&M costs also include 

the average annual cost of the planned maintenance events for the CTs and the STG over the long-term 

maintenance cycle. Planned maintenance costs for the CTs in a given year are based on the number of 

equivalent operating hours (EOH) the CT has run. A hot path gas inspection is performed for this type of 

CT every 900 equivalent starts, and a major inspection is performed every 1800 equivalent starts. (CTs 

generally have two criteria to schedule overhauls: number of equivalent starts and number of EOH. Case 

5 assumes the operating profile results in an EOH-driven maintenance overhaul schedule. Refer to Case 4 

for a starts-based overhaul schedule.) 

Table 5-2 — Case 5 O&M Costs 

Case 5 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

CC 2x2x1 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/kW-year 12.12 $/kW-year 

Variable O&M (Note 2) $/MWh 3.41 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Variable O&M costs include water and water discharge treatment cost. These include turbine major 

maintenance activities which are based on an operating hours-dependent maintenance cycle. 

5.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

For the Case 5 CC configuration, NOX emissions from the HRSG stacks when firing gas are indicated in 

Table 5-3. SCRs and CO catalysts are included in the HRSGs to reduce HRSG stack emissions of NOX 

and CO below the emission levels in the CT exhaust gas. 
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Table 5-3 — Case 5 Emissions 

Case 5 

EIA – Emissions Rates 

CC 2x2x1 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.0075 (Note 1) 

SO2 lb/MMBtu 0.00 

CO2 lb/MMBtu 117 

Emissions Control Notes 

1. Natural gas, SCR, no water injection 
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C A S E 6 . C O M B I N E D - C Y C L E P L A N T , H C L A S S , 

S I N G L E S H A F T , 6 2 7 M W N E T

6.1. CASE DESCRIPTION

This case is comprised of one block of a combined-cycle (CC) power generation unit. The plant includes 

one industrial frame Model HL derived from an H-Class technology combustion turbine (CT), one steam 

turbine generator (STG), and one electric generator that is common to the CT and the STG. Case 6 is 

based on natural gas firing of the CT, although dual-fuel capability is provided. Main plant cooling is 

accomplished with a wet cooling tower system. Output power voltage is stepped up for transmission to the 

external grid through an onsite switchyard. 

6.1.1. Mechanical Equipment and Systems

Case 6 is comprised of one Model HL dual-fuel CT in a 1x1x1 single-shaft CC configuration. The CT 

generates approximately 453 MW gross and the STG generates 192 MW gross. After deducting internal 

auxiliary power demand, the net output of the plant is approximately 627 MW. 

Case 6 layout differs from Case 5 in that Case 6 is a single-shaft CC plant. That is, the Case 5 CT, STG, 

and electric generator all share one horizontal shaft. Therefore, it has a more compact footprint than a plant 

like Case 5, where the CTs and STG have separate shafts and generators. Refer to Figure 6-1 for a 

simplified sketch of a single-shaft CT/steam turbine/generator unit. Generally, there are no major 

performance advantages of a single-shaft CC unit. Instead, the advantages are in costs; that is, in the case 

of a 1x1x1 CC configuration, the single-shaft unit will have only one electric generator whereas a multiple 

shaft 1x1x1 CC configuration will have two generators. Also, the smaller footprint of the single-shaft unit 

will lessen balance-of-plant (BOP) costs, such as foundations, piping, and cabling costs. 

The inlet air duct for the CT is equipped with an evaporative cooler to reduce the inlet air temperature in 

warmer seasons to increase the CT and plant output. The CT is also equipped with burners designed to 

reduce the CT’s emission of NOX. Included in the Case 6 configuration is a selective catalytic reduction 

(SCR) unit for further reduction of NOX emissions and a CO catalyst for further reduction of CO emissions.

The CT is categorized as derived from H Class industrial frame-type CT with an advanced technology 

design since it incorporates in the design the following features: 

 High-firing temperatures (~2900°F) 

 Advanced materials of construction 
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 Advanced thermal barrier coatings 

 Additional cooling of CT assemblies (depending on the CT model, additional cooling applies to the 

CT rotor, turbine section vanes, and the combustor). The high-firing temperature and additional 

features listed above result in an increase in MW output and efficiency of the CT as well as in the 

CC plant. 

In addition, the HL class industrial frame-type CT utilizes a modular design approach and is designed for 

operational flexibility. 

Hot exhaust gas from the CT is directed to a heat recovery steam generator (HRSG). Steam generated in 

the HRSG is directed to the STG. An HRSG may be optionally equipped with additional supplemental firing 

to boost steam turbine output, but this feature is not included in Case 6. (Supplemental HRSG firing, while 

increasing the MW output of the STG, reduces plant efficiency.) 

Plant cooling for Case 6 is provided by a wet cooling tower system. Generally, a wet cooling tower is 

preferred over the alternative air-cooled condensers (ACC) approach since plant performance is better (that 

is, greater MW output and higher efficiency) with a wet tower and capital cost is generally lower. However, 

ACCs are often selected in areas where the supply of makeup water needed for a wet cooling tower is 

scarce, expensive, or difficult to permit such as in desert areas in the southwestern United States. 

. 
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Figure 6-1 — Case 6 Configuration – Simplified Sketch 

Conceptual sketch of a 1x1x1 single-shaft CT/steam turbine/generator plant 

Source: Author © Sargent & Lundy, L.L.C 

6.1.2. Electrical and Control Systems

Case 6 includes one 60-Hz electric generator for both the CT and steam turbine, with an approximate rating 

of 453 MVA and output voltage of 13.8 kV. The output power from the generator is converted to a higher 

voltage by a generator step-up transformer (GSU) for transmission to the external grid, transmitted through 

an onsite facility switchyard. 

The CC facility is controlled by a central distributed control system (DCS), which is linked to a CT control 

system provided by the CT manufacturer. The DCS system includes controls for the steam cycle systems 

and equipment as well as the BOP systems and equipment (for example, water systems, fuel systems, and 

main cooling systems). 

6.1.3. Offsite Requirements

Offsite provisions in Case 6 include the following: 

 Fuel Gas Supply: A half-mile-long pipeline and a dedicated metering station. 
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 High-Voltage Transmission Line: A one-mile-long transmission line. 

 Water Supply for Cooling Tower, Evaporative Coolers, Makeup to Steam Cycle, and 

Miscellaneous Uses: It is assumed that the water supply source is near the power plant site and 

the interconnection for water is at the plant’s site boundary. Blowdown waste from the cooling tower 

and other areas of the plant is sent to an approved discharge location after appropriate treatment of 

the wastewater, and the wastewater interconnection is assumed to be located at the power plant’s 

site boundary. 

6.2. CAPITAL COST ESTIMATE

Table 6-1 summarizes the cost components for this case. The capital cost estimate is based on an 

engineering, procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 6-1 covers owner’s costs. Owner’s 

costs include owner’s services which include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, and owner’s start-up and commissioning costs. Other owner’s costs 

include electrical interconnection costs, gas interconnection costs, and land acquisition costs. The estimate 

is presented as an overnight cost in 2023 dollars and thus excludes allowance for funds used during 

construction or interest during construction. In addition to the cost of external systems noted above (for 

example, fuel gas supply and transmission line), an estimated amount is included for the cost of land. 

Table 6-1 — Case 6 Capital Cost Estimate 

Case 6 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CC 1x1x1, Single Shaft 

H Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural Gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 627 

Heat Rate, Higher Heating Value (HHV) Basis Btu/kWh 6226 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and 

Indirect Costs 10% 

EPC Contingency % of EPC Costs 11% 

Owner’s Services % of Project Costs 9% 

Owner’s Contingency % of Owner’s Costs 7% 
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Case 6 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CC 1x1x1, Single Shaft 

H Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural Gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

Estimated Land Requirement acres 30 

Estimated Land Cost $/acre 54,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 4,800,000 

Miles miles 0.50 

Metering Station $ 2,800,000 

Typical Project Timelines 

Development, Permitting, Engineering months 18 

Plant Construction Time months 22 

Total Lead Time Before Commercial Operation 

Date (COD) months 40 

Operating Life years 40 

EPC Cost Components (Note 1) 

Major Owner-Furnished Equipment (Note 2) $ 158,000,000 

Other Equipment (Note 3) $ 80,400,000 

Construction Labor (Note 4) $ 105,400,000 

Indirect Costs (Note 5) $ 34,380,000 

Materials (Note 6) $ 45,296,000 

EPC Fee $ 42,348,000 

EPC Contingency $ 51,241,000 

EPC Subtotal $ 517,065,000 

Owner’s Cost Components (Note 7) 

Owner’s Services $ 46,536,000 

Land $ 1,620,000 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 5,200,000 
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Case 6 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration CC 1x1x1, Single Shaft 

H Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural Gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

Owner’s Contingency $ 3,948,000 

Owner’s Subtotal $ 60,344,000 

Total Capital Cost $ 577,409,000 

$/kW net 920.9 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. EPC fees are applied to the sum of direct 

and indirect costs. 

2. Major owner-furnished equipment includes CTs, HRSG, SCRs, CO catalysts, and steam turbines. 

3. Other equipment includes pumps, tanks, MCCs, condensers, cooling towers, switchgear, transformers, and any 

other major inside-the-fence process equipment required for the complete facility (excluding the major ownerfurnished equipment). 

4. Construction labor costs are directly attributed to onsite civil/structural work and erection/installation of the 

equipment included in the EPC’s scope. 

5. Indirect costs are attributed to engineering, procurement, project services, construction management, field 

engineering, start-up, and commissioning services. 

6. Materials include all construction materials associated with the EPC scope of work, material freight costs, and 

consumables during construction. 

7. Owner’s services include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs, and land acquisition costs. 

6.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Operating and maintenance (O&M) costs are indicated in Table 6-2. Fixed O&M costs include staff and 

administrative costs, supplies, and minor routine maintenance. (Not included are property taxes and 

insurance.) Fixed costs also include the fixed payment portion of a long-term service agreement for the CT. 

Variable O&M costs include consumable commodities, such as water, lubricants, and chemicals and 

periodic costs to change out the SCR and CO catalysts. The variable O&M costs also include the average 

annual cost of the planned maintenance events for the CT and the STG over the long-term maintenance 

cycle. Planned maintenance costs for the CT in a given year are based on the number of equivalent 

operating hours (EOH) the CT has run. A hot gas path inspection is typically performed for this type of CT 

every 25,000 EOH, and a major inspection is performed every 66,400 EOH. (CTs generally have two criteria 

to schedule overhauls: number of equivalent starts and number of EOH. In Case 6, it is assumed the 
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operating profile results in an EOH-driven maintenance overhaul schedule. Refer to Case 4 for a startsbased overhaul schedule.) 

Table 6-2 — Case 6 O&M Cost 

Case 6 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Combined-Cycle 1x1x1, Single Shaft 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/kW-year 15.51 $/kW-year 

Variable O&M (Note 2) $/MWh 3.33 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Variable O&M costs include water and water discharge treatment cost. These include turbine major 

maintenance activities which are based on an operating hours-dependent maintenance cycle. 

6.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

For the Case 6 CC configuration, NOX emissions from the HRSG stack when firing gas are indicated in 

Table 6-3. An SCR and a CO catalyst are included in the HRSG to reduce HRSG stack emissions of NOX 

and CO below the emission levels in the CT exhaust gas. 

Table 6-3 — Case 6 Emissions 

Case 6 

EIA – Emissions Rates 

Combined-Cycle 1x1x1, Single Shaft 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.0075 (Note 1) 

SO2 lb/MMBtu 0.00 

CO2 lb/MMBtu 117 

Emissions Control Notes 

1. Natural gas, SCR, no water injection 
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C A S E 7 . C O M B I N E D - C Y C L E P L A N T , H C L A S S ,

S I N G L E S H A F T , W I T H 9 5 % C A R B O N C A P T U R E , 

5 4 3 M W N E T

7.1. CASE DESCRIPTION

This case includes one block of a combined-cycle (CC) power generation unit in a 1x1x1 single-shaft 

configuration. The plant includes one industrial frame Model HL derived from H-Class combustion-turbine 

(CT) technology, one steam turbine generator (STG), and one electric generator that is common to the CT 

and the STG. Case 7 is based on natural gas firing of the CT, although dual-fuel capability is provided. Main 

plant cooling is accomplished with a wet cooling tower system. Output power voltage is stepped up for 

transmission to the external grid through an onsite switchyard. 

In addition, a system is included to remove and capture 95% of the CO2 in the CT exhaust gas.

Refer to Case 6 for a description the power generation systems since Case 7 is the same in this regard. 

7.1.1. Mechanical Equipment and Systems

This technology case adds a 95% CO2 capture system to an industrial frame Siemens Energy Model SGT6- 

9000HL dual-fuel CTs in a 1x1x1 single-shaft CC configuration. The nominal output of the CC plant unit 

without carbon capture is 627 MW gross. The major power cycle equipment and configurations are 

described in Case 6. The CO2 capture systems are commonly referred to as carbon capture and 

sequestration (CCS) systems; however, for cost estimates provided in this report, no sequestration costs 

have been included. For this case, the CO2 captured is assumed to be compressed to supercritical 

conditions and injected into a pipeline that terminates at the facility’s fence line. For this report, the terms 

“CO2 capture” and “carbon capture” are used interchangeably.

As with the technology of Case 6, the base configuration used for the cost estimate is a single CC unit 

power generation plant station constructed on a greenfield site of approximately 30 acres. Case 7 CC unit 

power generation plant station constructed with a 95% CC system on a greenfield site increase to 

approximately 60 acres or required land. A wet mechanical draft cooling tower is used for plant cycle cooling 

and the makeup water used for cycle cooling and steam cycle makeup is provided by an adjacent fresh 

water source, reservoir, or river. 
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7.1.2. 95% CO2 Capture

For Case 7, to obtain 95% CO2 removal from the flue gas generated from the CT, the full flue gas path must 

be treated. The flue gas generated from natural gas-fired CT combustion results in a much lower CO2 

concentration in the flue gas than flue gas from a coal-fired facility. As such, the flue gas absorber and 

quencher would be much larger in scale on a per ton of CO2 treated basis than with a coal facility. The 

stripper and compression system, however, would scale directly with the mass rate of CO2 captured.

In this scenario, it is not practical to increase the CT size or STG size to account for the steam extraction 

and added auxiliary power required by the CO2 capture system. The net power output in the CO2 capture 

case is significantly less than Case 6. 

The flue gas path differs from the base case (Case 6) in that 100% of the gas is directed to the carbon 

capture system located downstream of the preheater section of the heat recovery steam generator (HRSG). 

The selective catalytic reduction (SCR) and CO catalysts would operate the same and the flue gas mass 

flows would be the same. Rather than exiting a stack, the flue gases would be ducted to a set of booster 

fans that would feed the CO2 absorber column. The total gross power generated from the CT is 

approximately the same as Case 6 with no carbon capture. 

Steam for the CO2 stripper is to be extracted from the intermediate-pressure turbine to low-pressure turbine 

crossover line; however, the steam must be attemporated to meet the requirements of the carbon capture 

system. The total process steam flow required for the carbon capture system is approximately 571,514 

pounds per hour. As a result of the steam extraction, the gross STG generation outlet decreases from 

approximately 192 MW to 151 MW. 

The total auxiliary power required by the plant is approximately 61 MW, of which approximately 44 MW is 

used by the carbon capture system. The net output decreases from the base case (Case 6) from 627 MW 

to 543 MW. The net plant heat rate for the 95% carbon capture case is 7,239 Btu/kWh, higher heating value 

(HHV) basis (compared to 6,226 Btu/kWh, HHV basis, for Case 6). 

7.1.3. Electrical and Control Systems

The electrical and controls systems for this case are similar in scope to Case 6’s electrical system; however, 

the auxiliary power system supplies a much larger amount of medium voltage load for the 95% carbon 

capture case. 

The CC facility and the CO2 capture plant are controlled by a central distributed control system (DCS), 

which is linked to a CT control system provided by the CT manufacturer. It includes controls for the steam 
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cycle systems and equipment as well as the balance-of-plant (BOP) systems and equipment (for example, 

water systems, fuel systems, main cooling systems). 

7.1.4. Offsite Requirements

Offsite provisions in Case 7 include the following: 

 Fuel Gas Supply: A half-mile-long pipeline and a dedicated metering station. 

 High-Voltage Transmission Line: A is a one-mile-long transmission line. 

 Water Supply for Cooling Tower, Evaporative Coolers, Makeup to Steam Cycle, and 

Miscellaneous Uses: It is assumed that the water supply source is near the power plant site and 

the interconnection for water is at the plant’s site boundary. The volume of water needed for this 

95% carbon capture case is significantly higher than for the base CC case (Case 6). Blowdown 

waste from the cooling tower and other areas of the plant is sent to an approved discharge location 

after appropriate treatment of the wastewater, and the wastewater interconnection is assumed to 

be located at the power plant’s site boundary. 

7.2. CAPITAL COST ESTIMATES

Table 7-1 summarizes the cost components for this case. The capital cost estimate is based on an 

engineering, procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 7-1 covers owner’s costs. Owner’s 

costs include owner’s services which include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, and owner’s start-up and commissioning costs. Other owner’s costs 

include electrical interconnection costs, gas interconnection costs, and land acquisition costs. The estimate 

is presented as an overnight cost in 2023 dollars and thus excludes allowance for funds used during 

construction or interest during construction. In addition to the cost of external systems noted above (for 

example, fuel gas supply and transmission line), an estimated amount is included for the cost of land. 
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Table 7-1 — Case 7 Capital Cost Estimate 

Case 7 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

CC 1x1x1, Single Shaft, 

with 95% Carbon Capture 

H-Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 543 

Heat Rate, HHV Basis Btu/kWh 7239 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and 

Indirect Costs 10% 

EPC Contingency % of EPC Costs 12% 

Owner's Services % of Project Costs 9% 

Owner's Contingency % of Owner's 

Costs 7% 

Estimated Land Requirement acres 60 

Estimated Land Cost $/acre 44,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 4,800,000 

Miles miles 0.50 

Metering Station $ 2,800,000 

Typical Project Timelines 

Development, Permitting, Engineering months 24 

Plant Construction Time months 30 

Total Lead Time Before Commercial Operation 

Date (COD) months 54 

Operating Life years 40 

EPC Cost Components (Note 1) 

CC: Major Owner-Furnished Equipment (Note 2) $ 158,000,000 

CC: Other Equipment (Note 3) $ 80,400,000 
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Case 7 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

CC 1x1x1, Single Shaft, 

with 95% Carbon Capture 

H-Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

CC: Construction Labor (Note 4) $ 105,400,000 

CC: Indirect Costs (Note 5) $ 34,380,000 

CC: Materials (Note 6) $ 45,296,000 

Carbon Capture: Equipment and Materials $ 251,424,000 

Carbon Capture: System Labor $ 267,469,000 

EPC Fee $ 94,237,000 

EPC Contingency $ 124,393,000 

EPC Subtotal $ 1,160,999,000 

Owner's Cost Components (Note 7) 

Owner's Services $ 104,490,000 

Land $ 2,640,000 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 5,200,000 

Owner's Contingency $ 8,076,000 

Owner's Subtotal $ 123,446,000 

Total Capital Cost $ 1,284,445,000 

$/kW net 2,365 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. EPC fees are applied to the sum of direct 

and indirect costs. 

2. CC: major owner-furnished equipment for the CC Unit includes CT, HRSG, SCRs, CO catalyst, and steam 

turbine. 

3. CC: other equipment includes pumps, tanks, MCCs, condensers, cooling towers, switchgear, transformers, and 

any other major inside-the-fence process equipment required for the complete facility (excluding the major owner 

furnished equipment). 

4. CC: construction labor costs are directly attributed to onsite civil/structural work and erection/installation of the 

equipment included in the EPC’s scope. 

5. CC: indirect costs are attributed to engineering, procurement, project services, construction management, field 

engineering, start-up, and commissioning services. 

6. CC: materials include all construction materials associated with the EPC scope of work, material freight costs, 

and consumables during construction. 
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Case 7 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

CC 1x1x1, Single Shaft, 

with 95% Carbon Capture 

H-Class 

Combustion Emissions Controls Dry Low Emissions 

Combustor 

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst 

Fuel Type Natural gas / No. 2 Backup 

Post Firing No Post Firing 

Units 

7. Owner’s services include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs (if applicable), and land acquisition costs. 

7.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Operation and maintenance costs are indicated in Table 7-2. Fixed operating and maintenance (O&M) 

costs include staff and administrative costs, supplies, and minor routine maintenance. (Not included are 

property taxes and insurance.) Fixed costs also include the fixed payment portion of a long-term service 

agreement for the CT and carbon capture system equipment. 

Variable O&M costs include consumable commodities such as water, lubricants, chemicals, solvent 

makeup, and periodic costs to change out the SCR and CO catalysts. The variable O&M costs also include 

the average annual cost of the planned maintenance events for the CT and the STG over the long-term 

maintenance cycle. Planned maintenance costs for the CT in a given year are based on the number of 

equivalent operating hours (EOH) the CT has run. A hot gas path inspection is typically performed for this 

type of CT every 25,000 EOH, and a major inspection is performed every 66,400 EOH. (CTs generally have 

two criteria to schedule overhauls: number of equivalent starts and number of EOH. In Case 7, it is assumed 

the operating profile results in an EOH-driven maintenance overhaul schedule. Refer to Case 4 for a startbased overhaul schedule.) Planned major outage work on the STG is scheduled less frequently than the 

CT; it is typically planned for every six to eight years. 

For the CO2 capture system, variable costs include solvent makeup and disposal costs (usually offsite 

disposal; the spent solvent may be considered hazardous waste), additional wastewater treatment costs 

(predominantly CT blowdown treatment), and additional demineralized makeup water costs. 
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Table 7-2 — Case 7 O&M Cost Estimates 

Case 7 

EIA – O&M Costs – 2023 $ USD 

CC 1x1x1, Single Shaft, with 95% Carbon Capture 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/kW-year 24.78 $/kW-year 

Variable O&M (Note 2) $/MWh 5.05 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials, and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Variable O&M costs include water and water discharge treatment cost. These include turbine major 

maintenance activities which are based on an operating hours-dependent maintenance cycle. 

7.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

For the Case 7 CC configuration with 95% carbon capture, NOX emissions from the plant when firing gas 

are indicated in Table 7-3. An SCR and a CO catalyst are included in the HRSG to further reduce plant 

emissions of NOX and CO below the emissions levels in the CT exhaust gas. The CO2 in the CT exhaust 

gas is reduced by 95% for Case 7. 

Table 7-3 — Case 7 Emissions 

Case 7 

EIA – Emissions Rates 

CC 1x1x1, Single Shaft, with 95% Carbon Capture 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.0075 (Note 1) 

SO2 lb/MMBtu 0.00 

CO2 lb/MMBtu 6 

Emissions Control Notes 

1. Natural gas, SCR, CCS, no water injection 
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C A S E 8 . W O O D Y B I O M A S S P L A N T , W I T H 9 5 % 

C A R B O N C A P T U R E , 5 0 M W N E T

8.1. CASE DESCRIPTION

This case comprises a greenfield biomass-fired power generation facility with a net capacity of 50 MW with 

a single steam generator and condensing steam turbine with biomass storage and handling systems, 

balance-of-plant (BOP) systems, in-furnace and post-combustion emissions control systems, and a 95% 

CO2 capture system. The CO2 capture systems are commonly referred to as carbon capture and 

sequestration (CCS) systems; however, for the cost estimates provided in this report, no sequestration 

costs have been included. For this case, the CO2 captured is assumed to be compressed to supercritical 

conditions and injected into a pipeline terminated at the fence line of the facility. For this report, the terms 

“CO2 capture” and “carbon capture” are used interchangeably.

The facility is designed to receive, store, and burn wood chips with moisture content between 20% and 

50%. The technology used is a bubbling fluidized bed (BFB) boiler with bed material consisting of sand, 

crushed limestone, or ash. The facility does not include equipment to further process or dry the fuel prior to 

combustion. The fuel storage area is assumed to be uncovered. The facility does not have a connection to 

a natural gas supply and is designed to start up on diesel fuel only. The emission controls are used to limit 

NOX and particulate matter, while SO2 emissions are not controlled.

8.1.1. Mechanical Equipment and Systems

The core technology for this case is a BFB boiler designed to combust wood chips. The boiler is a natural 

circulation balanced-draft, non-reheat cycle. For this size range, the boiler is assumed to be a top-supported 

design arranged in a similar manner as shown in Figure 8-1. The BFB furnace consists of horizontally 

arranged air distribution nozzles in the lower portion of the furnace that introduces air or recirculated flue 

gas to a bed of sand, ash, or other non-combustible material such as crushed limestone. The balanceddraft boiler consists of water-wall tubes that are refractory lined in the bed area. Air flow is forced upward 

through the bed material at velocities just beyond the point of fluidization where voids or bubbles start to 

form within the bed. The bed material is maintained typically at a range of temperatures between 1400°F 

to 1600°F, depending on the moisture content of the fuel. Diesel oil-fired start-up burners are used to heat 

the bed material prior to the introduction of fuel. The biomass fuel is fed through chutes located in the lower 

furnace. Depending on the moisture content of the fuel, flue gases can be mixed with the fluidized air to 

control the bed heat release rate to levels that prevent the formation of agglomerated ash. Overfire air 

(OFA) is used to complete combustion of the fuel and to control the emissions of NOX.
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The steam cycle includes a condensing steam turbine and turbine auxiliaries, condensate pumps, lowpressure and high-pressure feedwater heaters, boiler feed pumps, economizers, furnace water walls, steam 

drum, and primary and secondary superheaters. Boiler feed pumps and condensate pumps are provided 

in a 2x100% sizing basis. The steam conditions at the turbine are assumed to be 1500 psig at 950°F. Cycle 

cooling is provided by a mechanical draft cooling tower. 

The air and flue gas systems include primary and secondary air fans, flue gas recirculation fans, a single 

tubular air heater, induced draft fans and the associated duct work, and dampers. The fans are assumed 

to be provided on a 2x50% basis. A material handling is provided to convey the wood chips to the fuel surge 

bins that direct the fuel to multiple feeders. The BOP equipment includes sootblowers, a water treatment 

system and demineralized water storage tanks, a fire protection and detection system, a diesel oil storage 

and transfer system, a compressed air system, an aqueous ammonia storage system and feed pumps, an 

ash handling and storage system, and a continuous emissions monitoring system. 

NOX emissions are controlled in-furnace using OFA and with a high dust selective catalytic reduction (SCR) 

system, SO2 emissions from wood firing are inherently low and therefore are uncontrolled. Particulate 

matter is controlled using a pulse jet fabric filter baghouse. 
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Figure 8-1 — Typical BFB Biomass Boiler Arrangement 

Babcock & Wilcox Top-Supported BFB Boiler 

Source: Babcock & Wilcox, BFB-boiler-top-supported, ND. Digital Image. Reprinted with permission from Babcock & 

Wilcox. 

Retrieved from Babcock.com, https://www.babcock.com/products/bubbling-fluidized-bed-boilers

The plant performance estimates for woodchip fired BFB boilers are highly dependent on fuel moisture. 

Generally, BFB boiler efficiencies range from 75% to 80%. The estimated net heat rate firing wood chips is 

19,965 Btu/kWh for this system based on the higher heating value (HHV) of the fuel. 

Steam 

Drum 

Downcomers 

Upper OFA Supply Duct 

Upper OFA Ports 

Lower OFA Supply Ducts 

Economizers Start-up Burner 

Supply Duct 

Lower OFA Ports 

Start-up Burners 

Bed Material 

Open 

Bottom 

Hoppers 

Bed Material 

Transfer 

Conveyor

Bed Material 

Collection 

Conveyors 

Fluidizing Air 

Supply Duct 

Fuel Chutes 

Furnace 

Superheaters Sootblowers 
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8.1.2. 95% CO2 Capture

For Case 8, to obtain 95% CO2 removal from the flue gas generated from the biomass plant, the full flue 

gas path must be treated. The flue gas generated from biomass combustion results in a similar CO2 

concentration in the flue gas as compared to the flue gas from a coal-fired facility. As such, the CO2 capture 

system would scale directly with the mass rate of CO2 captured.

In this scenario, it is not practical to increase the biomass plant size to account for the steam extraction and 

added auxiliary power required by the CO2 capture system.

100% of the gas is directed to the CO2 capture system located downstream of the pulse jet fabric filter 

baghouse. Rather than exiting a stack, the flue gases would be ducted to a set of booster fans that would 

feed the CO2 absorber column.

Steam for the CO2 stripper is to be extracted from the intermediate-pressure turbine to low-pressure turbine 

crossover line; however, the steam must be attemperated to meet the requirements of the CO2 capture 

system. The total process steam flow required for the carbon capture system is approximately 77 pounds 

per hour. 

The total auxiliary power required by the plant is approximately 15.5 MW, of which 9 MW is used by the 

CO2 capture system. This reduces the plant’s 65.5 MW (gross) steam turbine generator to 50 MW of net 

output. The net plant heat rate for the 95% carbon capture case is 19,965 Btu/kWh, HHV basis. 

8.1.3. Electrical and Control Systems

The electrical system for this case includes the turbine generator which is connected via generator circuit 

breakers to a generator step-up transformer (GSU). The GSU increases the voltage from the generator 

voltages level to the transmission system high-voltage level. The facility and most of the sub-systems are 

controlled using a central distributed control system (DCS). Some systems are controlled using 

programmable logic controllers, and these systems include the sootblower system, the fuel handling 

system, and the ash handling system. 

8.1.4. Offsite Requirements

The facility is constructed on a greenfield site of approximately 100 acres. Wood chips are delivered to the 

facility by truck and rail. The maximum daily rate for wood chips for the facility is approximately 1750 tons 

per day. 
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Water for steam cycle makeup and cooling tower makeup is assumed to be sourced from onsite wells. 

Wastewater generated from the water treatment systems and the cooling tower blow down is sent to the 

adjacent waterway from one or more outfalls from a water treatment pond or wastewater treatment system. 

The electrical interconnection costs are based on a one-mile distance from the facility switchyard to the 

terminal point on an existing utility substation. For the purposes of this estimate, the cost associated with 

the expansion of the substation is excluded. 

8.2. CAPITAL COST ESTIMATE

Table 8-1 below summarizes the cost components for this case. The basis of the estimate assumes that 

the site is constructed in a United States region that has good access to lower cost construction labor and 

has reasonable access to either well water or water resources, locally sourced wood chips, and existing 

utility transmission substations or existing transmission lines. The geographic location is assumed to be 

characterized by seismic, wind, and other loading criteria that do not add significantly to the capital costs. 

An outdoor installation is assumed, meaning that the boiler building is not enclosed. No special systems 

are needed to prevent freezing or to account for snow loads on structures. 

Table 8-1 — Case 8 Capital Cost Estimate 

Case 8 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

50 MW Biomass Plant 

Bubbling Fluidized Bed 

95% Carbon Capture System 

Combustion Emissions Controls OFA 

Post-Combustion Emissions Controls SCR / Baghouse / Amine-Based CCS 

Fuel Type Woodchips 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 50 

Heat Rate, HHV Basis Btu/kWh 19,965 

Capital Cost Assumptions 

Engineering, Procurement, and Construction (EPC) 

Contracting Fee 

% of Direct and Indirect 

Costs 10% 

EPC Contingency % of EPC Costs 12% 

Owner's Services % of EPC Costs 7% 

Owner's Contingency % of Owner's Costs 12% 

Estimated Land Requirement acres 100 

Estimated Land Cost $/acre 37,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 
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Case 8 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

50 MW Biomass Plant 

Bubbling Fluidized Bed 

95% Carbon Capture System 

Combustion Emissions Controls OFA 

Post-Combustion Emissions Controls SCR / Baghouse / Amine-Based CCS 

Fuel Type Woodchips 

Units 

Transmission Line Cost $/mile 2,076,000 

Miles miles 1.00 

Substation Expansion Cost $ 0 

Typical Project Timelines 

Development, Permitting, Engineering months 24 

Plant Construction Time months 40 

Total Lead Time Before Commercial Operation Date 

(COD) months 64 

Operating Life years 40 

EPC Cost Components (Note 1) 

Civil/Structural/Architectural - Equipment and Materials $ 19,621,000 

Boiler Plant - Equipment and Materials $ 44,217,000 

Turbine Plant - Equipment and Materials $ 10,330,000 

Main and Aux Power System - Equipment and 

Materials $ 3,801,000 

Balance of Plant and I&C - Equipment and Materials $ 4,326,000 

Substation and Switchyard Costs $ 29,405,000 

Carbon Capture System Plant – Equipment and 

Materials $ 134,825,000 

Construction Labor Costs $ 181,190,000 

Indirect Costs $ 42,772,000 

EPC Fee $ 47,049,000 

EPC Contingency $ 62,104,000 

EPC Subtotal $ 579,640,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 40,575,000 

Land $ 3,700,000 

Electrical Interconnection $ 2,076,000 

Gas Interconnection $ 0 

Owner's Contingency $ 5,562,000 

Owner's Cost Subtotal $ 51,913,000 

Total Capital Cost $ 631,553,000 

$/kW net 12,631 

Capital Cost Notes 
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Case 8 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

50 MW Biomass Plant 

Bubbling Fluidized Bed 

95% Carbon Capture System 

Combustion Emissions Controls OFA 

Post-Combustion Emissions Controls SCR / Baghouse / Amine-Based CCS 

Fuel Type Woodchips 

Units 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include engineering, 

construction management, start-up, and commissioning. EPC fees are applied to the sum of direct and indirect 

costs. 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, and land acquisition costs. 

8.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

The operating and maintenance (O&M) costs for the 50 MW biomass wood-fired generation facility are 

summarized in Table 8-2. The fixed costs cover the O&M labor, contracted maintenance services and 

materials, and general and administrative (G&A). Major overhauls for the facility are generally based on a 

three-year basis for boiler equipment and firing equipment and a six-year basis for the steam turbine. 

Shorter outages (for example, change out SCR catalyst) are generally performed on a two-year cycle. 

Non-fuel variable costs for this case include SCR catalyst replacement costs, SCR reagent costs, water 

treatment costs, wastewater treatment costs, fly ash and bottom ash disposal costs, bag replacement for 

the fabric filters, bed material makeup, and water and solvent costs for the CO2 capture system.
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Table 8-2 — Case 8 Operational Cost Estimate 

Case 8 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

50 MW BFB Biomass Plant with 95% Carbon Capture 

Fixed O&M – Plant (Note 1) Units Value 

Labor $/year 7,957,000 

Materials and Contract Services $/year 3,266,000 

Administrative and General $/year 1,836,000 

Subtotal Fixed O&M $/year 13,059,000 

$/kW-year 261.18 $/kW-year 

Variable O&M (Note 2) $/MWh 9.65 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and G&A costs. O&M costs exclude property 

taxes and insurance. 

2. Variable O&M costs include catalyst replacement, ammonia, water, ash disposal, solvent and water costs for the 

CCS, and water discharge treatment cost. 

8.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

The emissions for the major criteria pollutants are summarized below in Table 8-3. The NOX emissions 

assume that the in-furnace controls such as low NOx burners (LNBs), OFA, and SCR systems are 

employed to control emissions to 0.08 lb/MMBtu. The SO2 emissions from wood fired combustion are 

assumed to be negligible and are uncontrolled. The CO2 emissions estimate is based on a 95% reduction 

in base emissions, through the implementation of the CO2 capture system. The base CO2 emission rate is 

derived from 40 CFR, Subpart C, Table C-1; as 206 lb/MMBtu; therefore, giving a net CO2 emission rate of

10.3 lb/MMBtu. 
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Table 8-3 — Case 8 Emission Rates 

Case 8 

EIA – Emissions Rates 

50 MW, BFB Biomass Plant with 95% Carbon Capture 

Predicted Emissions Rates (Note 1) Units Value 

NOx lb/MMBtu 0.08 (Note 2) 

SO2 lb/MMBtu <0.03 (Note 3) 

PM lb/MMBtu 0.03 (Note 4) 

CO2 lb/MMBtu 10.3 (Note 5) 

Emissions Control Notes 

1. Wood fuel – 20% to 50% fuel moisture 

2. NOx removal using OFA, and SCR 

3. SO2 is assumed negligible in wood fuel 

4. Controlled using pulse jet fabric filter 

5. Per 40 CFR 98, Subpart. C, Table C-1 
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C A S E 9 . A D V A N C E D N U C L E A R P L A N T

( B R O W N F I E L D ) , 2 X A P 1 0 0 0 U N I T S , 2 1 5 6 M W 

N E T

9.1. CASE DESCRIPTION

The case is based on the AP1000 (“AP” stands for “Advanced Passive”), which is an improvement of 

AP600. The AP1000 is a pressurized water reactor nuclear plant designed by Westinghouse. The first 

AP1000 unit came online in China’s Sanmen Nuclear Power Station in June 2018. Two new AP1000 units 

have been constructed at the Vogtle Electric Generating Station in Burke County Georgia. Vogtle Unit 3 

began commercial operation in July of 2023, and Vogtle Unit 4 began the process to load fuel into the 

reactor core in August of 2023. These represent the only newly constructed nuclear units in the United 

States in more than three decades. We assume the plant for this case is constructed on a brownfield site 

as it is likely for current U.S. operators to take advantage of their existing nuclear plant sites as in the case 

of Vogtle Units 3 and 4. This assumption considers several efficiencies in zoning, permitting, and regulatory 

activities, which would otherwise add to the cost and extend the development schedule if a new greenfield 

nuclear facility were being considered. 

9.1.1. Mechanical Equipment and Systems

The AP1000 improves on previous nuclear designs by simplifying the design to decrease the number of 

components including piping, wiring, and valves. The AP1000 design is also standardized as much as 

possible to reduce engineering and procurement costs. The AP1000 component reductions from previous 

designs are approximately: 

 50% fewer valves 

 35% fewer pumps 

 80% less pipe 

 45% less seismic building volume 

 85% less cable 

The AP1000 design uses an improved passive nuclear safety system that requires no operator intervention 

or external power to remove heat for up to 72 hours. 

The AP1000 uses a traditional steam cycle similar to other generating facilities such as coal or combinedcycle (CC) units. The primary difference is that the AP1000 uses enriched uranium as fuel instead of coal 

or gas as the heat source to generate steam. The fission reaction of enriched uranium releases large 
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amounts of energy in the form of heat and radiation inside the pressurized water reactor. The AP1000 uses 

a two-loop system in which the heat generated by the fuel is released into the surrounding pressurized 

reactor cooling water. The pressurization allows the cooling water to absorb the released heat without 

boiling. The reactor cooling water then flows through a steam generator where it rejects heat into the 

secondary loop, producing steam that turns a steam turbine for electrical generation. 

9.1.2. Electrical and Control Systems

The advanced nuclear facility has one steam turbine 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 steam turbine 

electric generator is connected through a generator circuit breaker to a generator step-up transformer 

(GSU). The GSU is connected between two circuit breakers in the high-voltage bus in the facility switchyard 

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

interconnected transmission system high voltage. 

The advanced nuclear facility is controlled using a distributed control system (DCS). The DCS provides 

centralized control of the facility by integrating the control systems provided with the reactor, steam turbine, 

and associated electric generator and the control of balance-of-plant (BOP) systems and equipment. 

9.1.3. Offsite Requirements

Water for the power plant is obtained from a nearby river or lake. The facility uses a water treatment system 

to produce the high-quality process water required as well as service water and potable water. The electrical 

interconnection from the power plant onsite switchyard is connected to the transmission line through a 

nearby substation. 

9.2. CAPITAL COST ESTIMATE

Table 9-1 summarizes the cost components for this case. The overnight capital cost estimate was compared 

to actual construction costs documented for various reactor types in multiple countries found in Table 8.2 

of the IEA 2020 Projected Costs of Generating Electricity Report. The capital cost breakdown for the various 

reactor types was not provided in the report, nor were the construction completion dates, but construction 

of all reference projects commenced ten or more years ago. Therefore, these values (escalated to 2023 $ 

USD), their mean and collective standard deviation were used as benchmarks to validate the capital cost 

estimate we determined. 
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Table 9-1 — Case 9 Capital Cost Estimate 

Case 9 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Advanced Nuclear 

(Brownfield) 

2 x AP1000 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 2156 

Net Plant Heat Rate Btu/kWh 10608 

Capital Cost Assumptions 

Engineering, Procurement, and Construction (EPC) 

Contracting Fee 

% of Direct and Indirect 

Costs 10% 

EPC Contingency % of EPC Costs 12% 

Owner’s Services % of EPC Costs 20% 

Owner’s Contingency % of Owner's Costs 12% 

Estimated Land Requirement acres 60 

Estimated Land Cost $/acre 44,000 

Interconnection Costs 

Electrical Transmission Line Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 0 

Miles miles 0.00 

Metering Station $ 0 

Typical Project Timelines 

Development, Permitting, Engineering months 32 

Plant Construction Time months 52 

Total Lead Time Before Commercial Operation Date 

(COD) months 84 

Operating Life years 40 

EPC Cost Components (Note 1) 

Civil/Structural/Architectural $ 2,098,819,000 

Nuclear Island $ 3,086,499,000 

Conventional Island $ 1,728,440,000 

Balance of Plant $ 1,975,360,000 

Indirect Costs $ 2,345,739,000 

EPC Fee $ 1,123,486,000 

EPC Contingency $ 1,483,001,000 

EPC Subtotal $ 13,841,344,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 2,768,269,000 

Land $ 2,640,000 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 0 

Owner’s Contingency $ 332,874,000 

Owner's Cost Subtotal $ 3,106,823,000 
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Case 9 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Advanced Nuclear 

(Brownfield) 

2 x AP1000 

Units 

Total Capital Cost $ 16,948,167,000 

$/kW net 7,861 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, start-up and commissioning, 

and contractor overhead. EPC fees are applied to the sum of direct and indirect costs. 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs (if applicable), and land acquisition costs. 

As a consideration for the interconnection costs, the transmission line for the nuclear facility is expected to 

operate at a high voltage to be capable of exporting the large capacity of baseload power. 

9.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

The operating and maintenance (O&M) cost estimates for nuclear power were informed by the Nuclear 

Energy Institute’s (NEI) Nuclear Costs in Context (NEI 2022) which summarizes operating and maintenance 

data collected by the EUCG from operating nuclear power generation facilities. The NEI report is the most 

comprehensive source of cost data that is publicly available for both merchant and regulated nuclear power 

plants in the United States. Non-fuel reported costs were separated between fixed and variable components 

and escalated to 2023 dollars using Handy Whitman’s Total Nuclear Production Plant index. 
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Table 9-2 -— Case 9 Operational Cost Estimate 

Case 9 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Advanced Nuclear (Brownfield) 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/kW-year 156.20 $/kW-year 

Variable O&M (Note 2) $/MWh 2.52 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and G&A costs. O&M costs exclude property taxes and 

insurance. 

2. Variable O&M costs include water, water discharge treatment cost, chemicals, and consumables. Fuel is not included. 

9.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Nuclear power plants do not produce regulated environmental air emissions. While other environmental 

compliance requirements may apply, only air emissions were considered for this report. Therefore, the 

emissions of NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 0 . S M A L L M O D U L A R R E A C T O R N U C L E A R 

P O W E R P L A N T , 6 X 8 0 MW U N I T S , 4 8 0 M W N E T

10.1. CASE DESCRIPTION

Small modular reactors (SMRs) are a class of advanced nuclear reactors that are typically sized to deliver 

300 MW(e) or less per unit. Besides this distinction in size which is about one third the capacity of traditional 

nuclear power stations, SMRs are designed with modular building blocks which allow key systems and 

components to be factory-assembled and shipped to site for improved quality control and a more 

streamlined installation. 

This case is based on 6 small reactor modules. Each module has a net capacity of 80 MW for a net plant 

capacity of 480 MW. The SMR case is not based on a particular OEM but rather is a representative SMR 

plant. 

10.1.1. Mechanical Equipment and Systems

The mechanical systems are similar to those of an advanced nuclear power plant. Each reactor module is 

comprised of a nuclear core and steam generator within a reactor vessel, which is enclosed within a 

containment vessel in a vertical orientation. The nuclear core is located at the base of the module with the 

steam generator located in the upper half of the module. Feedwater enters and steam exits through the top 

of the vessel towards the steam turbine. The entire containment vessel sits within a water-filled pool that 

provides cooling and passive protection in a loss of power event. All 6 reactor modules sit within the same 

water-filled pool housed within a common reactor building. 

Each SMR module uses a pressurized water reactor design to achieve a high level of safety and reduce 

the number of components required. To improve on licensing and construction times, each reactor is 

prefabricated at the OEM’s facility and shipped to site for assembly. The compact integral design allows 

each reactor to be shipped by rail, truck, or barge. 

Each module has a dedicated balance-of-plant (BOP) system for power generation. Steam from the reactor 

module is pumped through a steam turbine connected to a generator for electrical generation. Each BOP 

system is fully independent, containing a steam turbine and all necessary pumps, tanks, heat exchangers, 

electrical equipment, and controls for operation. This allows for independent operation of each reactor 

module. The independent operation of each reactor module allows for greater efficiencies at lower operating 

loads when dispatched capacity is reduced. 
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Additionally, the modular design of the reactors allows for refueling and maintenance of the individual 

reactors without requiring an outage of the entire facility. An extra reactor bay is included in the pool housed 

within the reactor building. This extra bay allows for removal of individual reactors for maintenance without 

impacting the remaining reactors. 

10.1.2. Electrical and Control Systems

Each SMR has its own generator, which is a 60-Hz machine rated at approximately 80 MVA with an output 

voltage of 13.8 kV. The steam turbine electric generator is connected through a generator circuit breaker 

to a generator step-up transformer (GSU) that is in turn connected between two circuit breakers in the highvoltage bus in the facility switchyard through a disconnect switch. The GSU increases the voltage from the 

electric generator from 13.8 kV to interconnected transmission system high voltage. 

The SMR facility is controlled using a distributed control system (DCS). The DCS provides centralized 

control of the facility by integrating the control systems provided with the reactor, steam turbine, and 

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

10.1.3. Offsite Requirements

Water for all processes at the SMR nuclear power plant is obtained from a nearby river or lake. The SMR 

power plant uses a water treatment system to produce the high-quality process water required as well as 

service and potable water. The electrical interconnection from the SMR nuclear power plant onsite 

switchyard is connected to the transmission line through a nearby substation. 

10.2. CAPITAL COST ESTIMATE

Table 10-1 summarizes the cost components for this case. 

Table 10-1 — Case 10 Capital Cost Estimate 

Case 10 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Small Modular Reactor Nuclear 

Power Plant 

6 x 80 MW Small Modular Reactor 

Units 

Plant Characteristics 

Net Plant Capacity (60°F, 60% RH) MW 480 

Net Plant Heat Rate Btu/kWh 10046 

Capital Cost Assumptions 

Engineering, Procurement, and 

Construction (EPC) Contracting 

Fee 

% of Direct and Indirect 

Costs 10% 
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Case 10 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Small Modular Reactor Nuclear 

Power Plant 

6 x 80 MW Small Modular Reactor 

Units 

EPC Contingency % of EPC Costs 12% 

Owner's Services % of EPC Costs 7.5% 

Owner’s Contingency % of Owner’s Costs 12% 

Estimated Land Requirement acres 35 

Estimated Land Cost $/acre 52,000 

Interconnection Costs 

Electrical Transmission Line Costs 

Transmission Line Cost $/mile 3,040,000 

Miles miles 1.00 

Substation Expansion $ 0 

Gas Interconnection Costs 

Pipeline Cost $/mile 0 

Miles miles 0.00 

Metering Station $ 0 

Typical Project Timelines 

Development, Permitting, 

Engineering months 24 

Plant Construction Time months 42 

Total Lead Time Before 

Commercial Operation Date (COD) months 66 

Operating Life years 40 

EPC Cost Components (Note 1) 

Civil/Structural/Architectural $ 656,126,000 

Nuclear Island $ 729,029,000 

Conventional Island $ 473,869,000 

Balance of Plant $ 729,029,000 

Indirect Costs $ 619,555,000 

EPC Fee $ 320,761,000 

EPC Contingency $ 423,404,000 

EPC Subtotal $ 3,951,773,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 296,383,000 

Land $ 1,820,000 

Electrical Interconnection $ 3,040,000 

Gas Interconnection $ 0 

Owner’s Contingency $ 36,149,000 

Owner's Cost Subtotal $ 337,392,000 

Total Capital Cost $ 4,289,165,000 

$/kW net 8,936 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, start-up and commissioning, 

and contractor overhead. EPC fees are applied to the sum of direct and indirect costs. 
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Case 10 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Small Modular Reactor Nuclear 

Power Plant 

6 x 80 MW Small Modular Reactor 

Units 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs, gas interconnection costs (if applicable), and land acquisition costs. 

Owner’s costs include owner’s services, land, and utility interconnection costs. Specifically, the 

transmission line for the SMR nuclear power plant is expected to operate at a high voltage to be capable of 

exporting the full plant output. The SMR costs also take into account cost efficiencies including industry 

learning that would be expected to be realized by a nth-of-a-kind facility. The indicated costs do not include 

the full burden of design, licensing, and manufacturing facility development required to bring a new SMR 

design to market. These costs are expected to make first-of-a-kind capital expenses greater than nth-of-akind capital expenses but may be somewhat offset by financial incentives such as tax credits or cost sharing 

arrangements through public-private partnerships. 

10.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

The operating and maintenance (O&M) cost estimates for SMR nuclear power were informed by the Nuclear 

Energy Institute’s (NEI) Nuclear Costs in Context (NEI 2022) which summarizes operating and maintenance 

data collected by the EUCG from operating nuclear power generation facilities. Adjustments were made to 

reflect assumed differentials in fixed and variable O&M attributable to the nuances of SMR plant design and 

operation. Cost basis values were escalated to 2023 dollars using Handy Whitman’s Total Nuclear 

Production Plant index. 
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Table 10-2 — Case 10 Operational Cost Estimate 

Case 10 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Small Modular Reactor Nuclear Power Plant 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/kW-year 121.99 $/kW-year 

Variable O&M (Note 2) $/MWh 3.19 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and G&A costs. O&M costs exclude property taxes and 

insurance. 

2. Variable O&M costs include water, water discharge treatment cost, chemicals, and consumables. Fuel is not included. 

10.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Small modular reactor nuclear power plants do not produce regulated environmental air emissions. While 

other environmental compliance requirements may apply, only air emissions were considered for this report. 

Therefore, the emissions of NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 1 . G E O T H E R M A L P L A N T , 5 0 M W N E T

11.1. CASE DESCRIPTION

This case is a 50 MW (net) geothermal power plant accessing a hydrothermal reservoir to generate power 

via a binary cycle. Geothermal power can be generated either from hydrothermal reservoirs or an enhanced 

geothermal system (EGS). Hydrothermal reservoirs are underground reservoirs of high temperature, 

pressurized water. The hot water can be used to generate power through dry steam generators, flash steam 

generators, or binary cycles, as used in this case. Dry and flash steam generators convert the pumped 

water into steam to directly turn steam turbines. While these plants have lower capital costs per kW of 

capacity, they are restricted to very hot (>390°F) aquifers and the dissolved minerals and gases in the water 

lead to greater wear on the turbines and therefore higher maintenance costs. 

Figure 11-1 — Geothermal Plant Configurations for Hydrothermal Reservoirs 

Source: DOE, “GeoVision: Harnessing the Heat Beneath Our Feet”, 2019 

Binary cycle geothermal power plants use the hydrothermal reservoir to power an Organic Rankine Cycle 

(ORC) generator. ORC power generation uses an organic working fluid that is vaporized in a heat 

exchanger to power a conventional steam turbine. The low boiling-point of the working fluid allows power 

generation from lower temperature hydrothermal resources, typically 300–375°F. Binary cycle plants 

comprise the majority of new geothermal power plants built in the United States in the last five years. They 

are typically located near existing geothermal resources to utilize the aquifer’s generation potential more 

fully. Additionally, binary cycle plants are often built to repower older power plants whose hydrothermal 

reservoirs have cooled down too much to be effective for steam power generation. Both of these scenarios 

significantly reduce the costs associated with resource exploration and well drilling, which can account for 
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over 50% of the cost of a new geothermal plant. Likewise, this case presents a brownfield site, in which a 

hot aquifer (350°F) has been identified with production and injection wells already drilled. This analysis 

isolates the costs of building and maintaining the geothermal plant itself and is a realistic starting point for 

a new geothermal plant built in the United States today. 

While hydrothermal reservoirs are naturally occurring geologic features, EGS reservoirs are human-made 

reservoirs where additional fluid has been injected into underground rock to increase permeability and fluid 

flow. They are less geographically restricted than conventional hydrothermal plants. EGS power plants are 

the subject of active research and development, but at this time there are no commercial examples in the 

United States on which to base a cost estimate. 

11.1.1. Mechanical Equipment and Systems

A binary cycle geothermal power plant requires power generation equipment and a gathering system to 

convey geothermal fluid between the power plant and the reservoir wells. 

The ORC power generation equipment for this case includes two 30 MW turbine generators, heat 

exchangers, and the associated fluid pumps. Each turbine generator requires three heat exchangers. Two 

of the heat exchangers are used to preheat and vaporize the organic working fluid by contacting it with the 

hot geothermal fluid, and the remaining heat exchanger uses an air blower to cool and condense the organic 

working fluid after expansion in the turbine. Unlike steam geothermal plants, the geothermal fluid never 

contacts air, as it cycles from the production wells through the heat exchangers and back into the reservoirs 

at injection wells. 

The field gathering equipment includes pumps associated with production and injection wells, which are 

assumed to be already drilled to the depth of the hydrothermal reservoir. The number of wells required 

depends strongly on the characteristics of the hydrothermal reservoir, and this modeled case assumes 8 

production and 8 injection wells. Pipes to transfer the fluid from the wells to the power plant equipment are 

also include in the field gathering system. 

Operating the pumps and cooling equipment requires electricity that reduces the net output of the power 

plant. To obtain 50 MW of net output, the turbine generators require a gross output of about 58 MW. 

11.1.2. Electrical and Control Systems

Each generator has its own step-up transformer and circuit breaker. After the circuit breaker, each electrical 

connection is combined via a high-voltage bus into a high-voltage circuit breaker before being fed into the 

grid. 
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11.1.3. Offsite Requirements

Geothermal plants must be located near drilled wells that tap into reservoirs of hot geothermal fluid. This 

case also assumes a one-mile transmission line. 

11.2. CAPITAL COST ESTIMATE

Table 11-1 summarizes the cost components for this case. 

Table 11-1 — Case 11 Capital Cost Estimate 

Case 11 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Geothermal 

50 MW 

Binary Cycle 

Units 

Plant Characteristics 

Net Plant Capacity MW 50 

Capital Cost Assumptions (Note 1) 

Engineering, Procurement, and 

Construction (EPC) Contracting Fee 

% of Direct and 

Indirect Costs 10% 

EPC Contingency % of EPC Costs 4% 

Owner's Services % of EPC Costs 12% 

Owner's Contingency % of Owner’s 

Costs 4% 

Estimated Land Requirements (Support 

buildings only) acres 200 

Estimated Land Cost $/acre 30,000 

Electric Interconnection Costs 

Transmission Line Cost $/mile 2,076,000 

Miles miles 1.00 

Typical Project Timelines 

Development, Permitting, Engineering months 18 

Plant Construction Time months 18 

Total Lead Time Before Commercial 

Operation Date (COD) months 36 

Operating Life years 40 

EPC Cost Components 

Civil Structural Material and Installation $ 39,670,000 

Mechanical – Power generating 

Equipment $ 56,672,000 

Mechanical – Field Gathering, 

Production / Injection Pumps 20,654,000 

Electrical – Balance of Plant (BOP) and 

I&C $ 8,213,000 
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Case 11 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Geothermal 

50 MW 

Binary Cycle 

Units 

Electrical – Substation and Switchyard 6,453,000 

Indirect Costs $ 15,799,000 

EPC Fee $ 14,746,000 

EPC Contingency $ 6,488,000 

EPC Subtotal $ 168,695,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 20,243,000 

Land $ 6,000,000 

Electrical Interconnection $ 2,076,000 

Owner's Contingency $ 1,133,000 

Owner's Cost Subtotal $ 29,452,000 

Total Capital Cost $ 198,147,000 

$/kW net 3,963 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, start-up and commissioning, 

and contractor overhead. EPC fees are applied to the sum of direct and indirect costs. 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs and land acquisition costs. 
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11.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Table 11-2 — Case 11 Operating and Maintenance (O&M) Cost Estimates 

Case 11 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Geothermal 

Fixed O&M – Plant (Note 1) Units Value 

Labor $/year 2,019,000 

Plant Maintenance $/year 2,994,000 

Field Maintenance $/year 1,258,000 

Geothermal Pump Maintenance $/year 1,259,000 

Subtotal Fixed O&M $/year 7,530,000 

$/kW-year $/kW-year 150.60 $/kW-year 

Variable O&M $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

11.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Binary geothermal power plants do not burn fuel, and the geothermal fluid extracted from the ground does 

not contact the air, so there is no release of dissolved gases from the hydrothermal reservoir. However, a 

small amount of the organic working fluid used in the ORC generator, typically isobutane or n-pentane, 

leaks through valves and seals during normal operation. For a 50 MW plant, this is expected to be limited 

to 125 tons of isobutane or n-pentane per year (0.167 lbs / MMBtu). 
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C A S E 1 2 . H Y D R O E L E C T R I C P L A N T , 1 0 0 M W N E T

12.1. CASE DESCRIPTION

This case is based on a “New Stream Reach Development” 100 MW hydroelectric power plant with 30 feet 

of available head. There are several types of hydroelectric power plants including run-of-river, storage, and 

pumped storage. This case is based on a storage type hydropower plant that includes a dam to store water 

in a reservoir where water is released through tunnels to a powerhouse to spin a turbine. 

Figure 12-1 — Dam of a Hydroelectric Power Plant 

Source: Alan Cressler, Marshall County, AL. Digital Image. 

Retrieved from Guntersville Dam - Encyclopedia of Alabama (accessed Aug 1, 2023) 

Figure 12-2 show a diagram of the major components of a storage-type hydroelectric power plant. The dam 

structure holds water in a reservoir. Water passes through an intake in the reservoir through the penstock. 

The penstock consists of concrete ‘power tunnels’ that direct water to a turbine that spins a generator that 

distributes electric power to the grid. 
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Figure 12-2 — Storage-Type Hydroelectric Power Plant 

Source: Tennessee Valley Authority, Licensed by GFDL and CC-BY-2.6, Wikimedia Commons (Accessed Aug 2 

2023) 

The costs for this case include a concrete dam with a spillway and diversion tunnel to control the water 

level in the reservoir. There are four identical penstocks, approximately 4.5 meters in diameter. Each 

penstock leads to a Kaplan-type hydro-turbine, which is suitable for modeled stream head. Each of the four 

turbine-generators is rated for 25 MW. Power is stepped up from 13.8 kV to 154 kV for distribution. 
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Figure 12-3 — Typical Hydroelectric Power Turbine Hall 

Source: Sargent & Lundy project site photo archive. 

12.2. CAPITAL COST ESTIMATE

Table 12-1 summarizes the cost components for this case. 

Table 12-1 — Case 12 Capital Cost Estimates 

Case 12 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Hydroelectric Power Plant 

New Stream Reach 

Development 

Units 

Plant Characteristics 

Net Plant Capacity MW 100 
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Case 12 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Hydroelectric Power Plant 

New Stream Reach 

Development 

Units 

Head ft 30 

Capital Cost Assumptions (Note 1) 

Engineering, Procurement, and 

Construction (EPC) Contracting Fee 

% of Direct and 

Indirect Costs 10% 

EPC Contingency % of EPC Costs 5% 

Owner’s Services % of EPC Costs 7% 

Owner’s Contingency % of Owner’s 

Costs 5% 

Estimated Land Requirements (Support 

buildings only) acres 2 

Estimated Land Cost $/acre 128,000 

Electric Interconnection Costs 

Transmission Line Cost $/mile 2,412,000 

Miles miles 1.00 

Substation Expansion $ 0 

Typical Project Timelines 

Development, Permitting, Engineering months 36 

Plant Construction Time months 36 

Total Lead Time Before COD months 72 

Operating Life years 50 

EPC Cost Components 

Civil Structural Material and Installation $ 371,101,000 

Mechanical Equipment Supply and 

Installation $ 93,933,000 

Electrical / I&C Supply and Installation $ 42,248,000 

Indirect Costs $ 60,874,000 

EPC Fee $ 56,816,000 

EPC Contingency $ 31,249,000 

EPC Subtotal $ 656,221,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 45,935,000 

Land $ 256,000 

Electrical Interconnection $ 2,412,000 

Owner's Contingency $ 2,430,000 

Owner's Cost Subtotal $ 51,033,000 

Total Capital Cost $ 707,254,000 
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Case 12 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Hydroelectric Power Plant 

New Stream Reach 

Development 

Units 

$/kW net 7,073 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, startup and commissioning, 

and contractor overhead. EPC fees are applied to the sum of direct and indirect costs. 

2. Owner’s costs include project development, studies, permitting, legal, owner's project management, owner's 

engineering, and owner's start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs and land acquisition costs. 

12.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Table 12-2 summarizes the operating and maintenance cost components for this case. 

Table 12-2 — Case 12 Operating and Maintenance (O&M) Cost Estimates 

Case 12 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Hydroelectric Power Plant 

Fixed O&M – Plant (Note 1) Units Value 

Subtotal Fixed O&M $/year 3,354,000 

$/kW-year $/kW-year 33.54 $/kW-year 

Variable O&M $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials, and contracted services, and general and administrative (G&A) costs. 

 O&M costs exclude property taxes and insurance. 

12.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Hydroelectric power does not produce regulated environmental air emissions. While other environmental 

compliance requirements apply, only air emissions were considered for this report. Therefore, the emissions 

of NOX, SO2, and CO2 are 0.00 lb/MMBtu. Academic research on the impact of dams on the carbon cycle 

of their local waterways is ongoing. 
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C A S E 1 3 . O N S H O R E W I N D , L A R G E P L A N T 

F O O T P R I N T , 2 0 0 M W N E T

13.1. CASE DESCRIPTION

This case is an onshore wind project in the Great Plains region that is based on a total project capacity of 

200 MW. The region has an abundance of land that is suitable for onshore wind turbine siting and is not 

subject to land constraints that would constraint project size. Parameters that affect project costs and 

performance include turbine nameplate capacity, rotor diameter, and hub height. The case configuration 

assumes wind turbines rated at 2.8 MW and 125-meter rotor diameters and 90-meter hub height. These 

features reflect modern wind turbines which employ larger rotor diameter and greater hub heights. The 

main advantage to taller hub heights and increased rotor diameters include access to better wind profiles 

at higher altitudes and increased turbine swept area, allowing the turbine unit to capture more energy. 

13.1.1. Mechanical Equipment and Systems

Wind turbine generators (WTGs) convert kinetic wind energy into electrical power. The most ubiquitous 

type of wind turbine utilized for electric power generation are those of the horizontal-axis three-bladed 

design. Lift is generated when wind flows around the turbine blades, resulting in rotation. The blades are 

connected to a central hub and drivetrain which turns a generator located inside of the nacelle, the housing 

positioned atop the wind turbine tower. 

13.1.2 Electrical and Control Systems

Each WTG consists of a doubly fed induction generator. The low-voltage output from the generator is 

stepped up to medium voltage through a transformer located either in the nacelle or at the tower base. A 

medium-voltage collection system conveys the generated energy to an onsite substation, which further 

steps up the voltage for interconnection with the transmission system with a voltage of 230 kV. 

A supervisory control and data acquisition (SCADA) system is provided for communications and control of 

the wind turbines and substation. The SCADA system allows the operations staff to remotely control and 

monitor each wind turbine and the wind farm as a whole. 

13.1.3 Offsite Requirements

Wind farms harness power from wind and thus, require no fuel or fuel infrastructure. The offsite 

requirements are limited to construction of site and access roads to each wind turbine, operating and 

maintenance (O&M) building and electrical interconnection to the transmission system. 
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13.2. CAPITAL COST ESTIMATE

Table 13-1 summarizes the cost components for this case. The capital cost estimate is based on an 

engineering, procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 13-1 covers owner’s costs. Owner’s 

costs include owner’s services which include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, owner’s start-up and commissioning costs, project feasibility analyses, 

wind resource assessments, geotechnical studies, contracting for land access, transmission access, 

permitting, and electrical interconnection costs. The estimate is presented as an overnight cost in 2023 

dollars and thus excludes allowance for funds used during construction or interest during construction. 

Leasing costs are provided in the O&M. 

Table 13-1 — Case 13 Capital Cost Estimate 

Case 13 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Onshore Wind – Large Plant 

Footprint: Great Plains Region 

200 MW | 2.8 MW WTG 

Hub Height (m) 90 

Rotor Diameter (m) 125 

Units 

Plant Characteristics 

Net Plant Capacity MW 200 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and 

Indirect Costs 8% 

EPC Contingency % of EPC Costs 5% 

Owner's Services % of EPC 7% 

Owner's Contingency % of Owners Costs 5% 

Electric Interconnection Costs 

Transmission Line Cost $/mile 2,412,000 

Miles miles 1.00 

Typical Project Timelines 

Development, Permitting, Engineering months 12 

Plant Construction Time months 9 

Total Lead Time Before Commercial 

Operation Date (COD) months 21 

Operating Life years 25 

EPC Cost Components (Note 1) 

WTG Procurement and Supply $ 160,168,000 
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Case 13 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Onshore Wind – Large Plant 

Footprint: Great Plains Region 

200 MW | 2.8 MW WTG 

Hub Height (m) 90 

Rotor Diameter (m) 125 

Units 

WTG Civil Work $ 62,130,000 

Electrical - Collection System $ 12,100,000 

Indirect Costs $ 8,112,000 

EPC Fee $ 19,401,000 

EPC Contingency $ 13,096,000 

EPC Subtotal $ 275,007,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 19,250,000 

Electrical Interconnection $ 2,412,000 

Owner's Contingency $ 1,083,000 

Owner's Cost Subtotal $ 22,745,000 

Total Capital Cost $ 297,752,000 

$/kW net 1,489 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor 

to construct the civil/structural, mechanical, and electrical/I&C components of the facility. 

Indirect costs include distributable material and labor costs, cranes, scaffolding, engineering, 

construction management, startup and commissioning, and contractor overhead. EPC fees are 

applied to the sum of direct and indirect costs. 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, and owner’s startup and commissioning costs. Other 

owner’s costs include electrical interconnection costs. 

13.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

O&M cost estimates reflect a full-service agreement arrangement, under which an O&M contractor provides 

labor, management, and parts replacement (including unscheduled parts replacement) for the WTGs, 

collection system, and substation. Our cost estimates exclude site specific owner's costs such royalties, 

property taxes and insurance. Table 13-2 summarizes the average annual O&M expenses projected for an 

assumed 25-year project life. 
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Table 13-2 — Case 13 O&M Cost Estimate 

Case 13 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Onshore Wind – Large Plant Footprint: Great Plains Region 

Fixed O&M – Plant (Note 1) Units Value 

WTG Scheduled Maintenance $/year 2,240,000 

WTG Unscheduled Maintenance $/year 2,800,000 

Leasing Costs $/year 996,000 

Balance of Plant Maintenance $/year 575,200 

Subtotal Fixed O&M $/year 6,611,200 

$/kW-year $/kW-year 33.06 $/kW-year 

Variable O&M (Note 2) $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

2. O&M costs estimates reflect the Full Service Agreement, unscheduled maintenance, land lease, and BOP 

maintenance, and exclude certain site-specific owner's costs such as royalties, property taxes, and insurance. 

3. Average Full Service Agreement term considered: 25 years 

13.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Wind power projects do not produce regulated environmental air emissions. While other environmental 

compliance requirements may apply, only air emissions were considered for this report. Therefore, the 

emissions of NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 4 . O N S H O R E W I N D ,

R E P O W E R I N G / R E T R O F I T , 1 5 0 M W N E T

14.1. CASE DESCRIPTION

The onshore wind repower case is based on a total project capacity of 150 MW. The region is reflective of 

the Midwest/Great Plains area in the center of the United States, which has an abundance of wind turbines 

suitable for potential repower scenarios. Parameters that affect project cost and performance include 

turbine nameplate capacity, rotor diameter and hub height. The case configuration assumes a partial 

repower of wind turbines rated at 1.5 MW to wind turbines rated at 1.6 MW with 125-m rotor diameter and 

90-m hub height. This will consist of the repowering of 94 wind turbine generators (WTGs) for a 150 MW 

capacity. These features reflect modern wind turbine repowers which employ larger rotor diameter. The 

primary advantage of larger rotor diameters is the increased turbine swept area, enabling the unit to capture 

more energy. Wind project repowering can be categorized as either a partial repowering or a full repowering. 

This case is assumed to be a partial repowering, which entails the replacement of certain high use WTG 

components with upgraded equipment while other components of the initial WTG are reused. The partial 

repower includes the replacement of blades, hub, nacelle components, main shaft, main bearing assembly, 

gearbox, and flex coupling. 

Figure 14-1 — Wind Repower Component Layout 

Source: Office of Energy Efficiency & Renewable Energy, Wind Energy Technologies Office – U.S. Department of 

Retrieved from Energy.gov, https://www.energy.gov/eere/wind/inside-wind-turbine (accessed May 31, 2019). 
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14.1.1. Mechanical Equipment and Systems

WTGs convert kinetic wind energy into electrical power. The most ubiquitous type of wind turbine utilized 

for electric power generation are those of the horizontal-axis three-bladed design. Lift is generated when 

wind flows around the turbine blades, resulting in rotation. The blades are connected to a central hub and 

drivetrain which turns a generator located inside of the nacelle, the housing positioned atop the wind turbine 

tower. 

14.1.2. Electrical and Control Systems

Each WTG consists of a doubly fed induction generator. The low-voltage output from the generator is 

stepped up to medium voltage through a transformer located either in the nacelle or at the tower base. A 

medium-voltage collection system conveys the generated energy to an onsite substation, which further 

steps up the voltage for interconnection with the transmission system with a voltage of 230 kV. 

A supervisory control and data acquisition (SCADA) system is provided for communications and control of 

the wind turbines and substation. The SCADA system allows the operations staff to remotely control and 

monitor each wind turbine and the wind farm as a whole. 

14.1.3. Offsite Requirements

Wind farms harness power from wind and thus, require no fuel or fuel infrastructure. The offsite 

requirements are limited to construction of site and access roads to each wind turbine, operating and 

maintenance (O&M) building and electrical interconnection to the transmission system. 

14.2. CAPITAL COST ESTIMATE

Table 14-1 summarizes the cost components for this case. The capital cost estimate is based on an 

engineering, procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 14-1 covers owner’s costs. Owner’s 

costs include owner’s services which include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, owner’s start-up and commissioning costs, project feasibility analyses, 

wind resource assessments, geotechnical studies, contracting for land access, transmission access, 

permitting, and electrical interconnection costs. The estimate is presented as an overnight cost in 2023 

dollars and thus excludes allowance for funds used during construction or interest during construction. 

Leasing Costs are provided in the O&M. 
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Table 14-1 — Case 14 Capital Cost Estimate 

Case 14 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Onshore Wind – Repower 

150 MW | 1.5-1.62 MW WTG 

Hub Height (m) 90 

Rotor Diameter (m) 125 

Units 

Plant Characteristics 

Net Plant Capacity MW 150 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and 

Indirect Costs 8% 

EPC Contingency % of EPC Costs 5% 

Owner's Services % of EPC Costs 10% 

Owner's Contingency % of Owner's Costs 5% 

Electric Interconnection Costs 

Transmission Line Cost $/mile 0 

Miles miles 0 

Typical Project Timelines 

Development, Permitting, Engineering months 12 

Plant Construction Time months 6 

Total Lead Time Before Commercial 

Operation Date (COD) months 18 

Operating Life years 20 

EPC Cost Components (Notes 1) 

WTG Components -Turbine Kit and Blade 

Kit $ 136,323,000 

Component Removal $ 4,928,000 

Installation/Repowering $ 12,017,000 

Mobilization/Demobilization $ 4,739,000 

Indirect Costs $ 7,900,000 

EPC Fee $ 13,273,000 

EPC Contingency $ 8,959,000 

EPC Subtotal $ 188,139,000 

Owner's Cost Components (Notes 2) 

Owner's Services $ 18,814,000 

Owner's Contingency $ 941,000 

Owner's Costs Subtotal $ 19,755,000 

Total Capital Cost $ 207,894,000 

$/kW net 1,386 

Capital Cost Notes 

1. Costs based on EPC contracting approach. This is an estimate of a repower replacing the blades, hub, 

nacelle, main shaft, main bearing assembly, gearbox, and flex coupling. WTG component costs consist of 

1.62 MW components to replace 1.5 MW WTGs. Indirect costs include distributable material and labor 
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Case 14 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration Onshore Wind – Repower 

150 MW | 1.5-1.62 MW WTG 

Hub Height (m) 90 

Rotor Diameter (m) 125 

Units 

costs, cranes, scaffolding, engineering, construction management, startup and commissioning, and 

contractor overhead. Component removal costs include dismantling of WTG, loading to vehicles, 

grounding checks, and (gearbox) oil disposal. Installation/Repowering costs include road work, civil work, 

and WTG installation. 

2. Owner’s costs include project development, studies, permitting, legal, owner’s project management, 

owner’s engineering, and owner’s startup and commissioning costs. Owner's contingency is applied to 

owner's services costs only. Interconnection costs are not included as existing interconnection equipment 

is assumed to be reused for the repowered facility. 

14.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

O&M cost estimates reflect a full-service agreement arrangement, under which an O&M contractor provides 

labor, management, and parts replacement (including unscheduled parts replacement) for the WTGs, 

collection system, and substation. Our cost estimates exclude site specific owner's costs such as property 

taxes and insurance. Table 14-2 summarizes the average annual O&M expenses projected for an assumed 

additional 20-year project life. 

Table 14-2 — Case 14 O&M Cost Estimate 

Case 14 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Onshore Wind – Large Plant Footprint: Great Plains Region 

Fixed O&M – Plant (Note 1) Units Value 

WTG Scheduled Maintenance $/year 1,808,000 

WTG Unscheduled Maintenance $/year 2,260,000 

Balance of Plant Maintenance $/year 452,000 

Leasing Costs $/year 1,262,000 

Subtotal Fixed O&M $/year 5,782,000 

$/kW-year $/kW-year 38.55 $/kW-year 

Variable O&M (Note 2) $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

2. O&M costs estimates reflect the Full Service Agreement and exclude site-specific owner's costs, such as 

royalties, property taxes, and insurance. 

3. Average FSA term considered: 20 years 
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14.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Wind power projects do not produce regulated environmental air emissions. While other environmental 

compliance requirements may apply, only air emissions were considered for this report. Therefore, the 

emissions of NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 5 . O F F S H O R E W I N D : F I X E D - B O T T O M 

M O N O P I L E F O U N D A T I O N S , 9 0 0 M W N E T

15.1. CASE DESCRIPTION

The offshore wind project is based on a total project capacity of 900 MW. Parameters that affect project 

cost and performance include project size, turbine nameplate capacity, water depth and distance to shore. 

The case configuration assumes wind turbines rated at 15 MW each, located 30 miles offshore in waters 

with a depth of 100 feet. An onshore cable run of 5 miles is also assumed. 

For the purposes of this study, it has been assumed that wind turbines installed employ fixed-type 

foundation structures. Generally, these are installed in relatively shallow waters, not exceeding 150 feet, 

consistent with our assumption. Water depth and distance to shore has a significant impact on the cost of 

fixed foundation structure due to the expenses being related to cable lengths and installation costs. 

15.1.1. Mechanical Equipment and Systems

Wind turbine generators (WTGs) convert kinetic wind energy into electrical power. The most ubiquitous 

type of wind turbine utilized for electric power generation are those of the horizontal-axis three-bladed 

design. Lift is generated when wind flows around the turbine blades, resulting in rotation. The blades are 

connected to a central hub and drivetrain which turns a generator located inside of the nacelle, the housing 

positioned atop the wind turbine tower. 

15.1.2 Electrical and Control Systems

Each wind turbine consists of a doubly fed induction generator with high-speed electrical slip rings, which 

produces electricity from the rotational energy of wind. The converter converts DC to AC. The power 

collection system collects energy from all the wind turbines and increases the voltage to 66 kV through a 

dedicated transformer at the WTG. The electricity is transmitted via array cables, buried in the sea floor to 

the offshore substation, where the voltage is increased to 138kV. It is then transmitted to an onshore 

substation via export cables. The power from this substation is supplied for interconnection with the 

transmission system. 

A supervisory control and data acquisition (SCADA) system is provided for communications and control of 

the wind turbines and substation. The SCADA system allows the operations staff to remotely control and 

monitor each wind turbine and the wind farm as a whole. 
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15.1.3 Offsite Requirements

Since wind is a clean source of energy, the offsite requirements are very limited. These include construction 

of offshore-to-shore submarine cables, port infrastructures, installation vessels (construction and cable 

laying) and electrical interconnection to the transmission system. 

15.2. CAPITAL COST ESTIMATE

Table 15-1 summarizes the cost components for this case. The capital cost estimate is based on an 

engineering, procurement, and construction (EPC) contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 15-1 covers owner’s costs. Owner’s 

costs include owner’s services which include project development, studies, permitting, legal, owner’s project 

management, owner’s engineering, owner’s start-up and commissioning costs, project feasibility analyses, 

wind resource assessments, geotechnical studies, contracting for land access, transmission access, 

permitting, and electrical interconnection costs. The estimate is presented as an overnight cost in 2023 

dollars and thus excludes allowance for funds used during construction or interest during construction. 

Leasing Costs are provided in the operating and maintenance (O&M). 

Table 15-1 — Case 15 Capital Cost Estimate 

Case 15 

EIA – Capital Cost Estimates – 2023 $ USD 

Offshore Wind: Fixed-Bottom 

Configuration Monopile Foundations 

900 MW | 15 MW WTG 

Offshore Cable Length (mi) 30 

Onshore Cable Length (mi) 5 

Water Depth (ft) 100 

Plant Characteristics 

Net Plant Capacity MW 900 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and Indirect 

Costs 10% 

EPC Contingency % of EPC Costs 6% 

Owner's Services % of EPC Costs 10% 

Owner's Contingency % of Owner's Costs 7% 

Typical Project Timelines 

Development, Permitting, Engineering months 24 

Plant Construction Time months 12 

Total Lead Time Before Commercial 

Operation Date (COD) months 36 

Operating Life years 25 

EPC Cost Components (Note 1-2) 
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Case 15 

EIA – Capital Cost Estimates – 2023 $ USD 

Offshore Wind: Fixed-Bottom 

Configuration Monopile Foundations 

900 MW | 15 MW WTG 

Offshore Cable Length (mi) 30 

Onshore Cable Length (mi) 5 

Water Depth (ft) 100 

WTG Procurement and Supply $ 1,172,322,000 

WTG Fabrication/Assembly/Installation $ 688,635,000 

Electrical Interconnection $ 385,623,000 

Onshore Transmission $ 49,832,000 

Offshore Transmission and Electrical 

Balance of Plant (BOP) $ 152,010,000 

Indirect Costs $ 123,678,000 

EPC Fee $ 257,210,000 

EPC Contingency $ 169,759,000 

EPC Subtotal $ 2,999,069,000 

Owner's Cost Components (Note 3) $ 

Owner's Services $ 299,907,000 

Owner's Contingency $ 20,993,000 

Owner's Costs Subtotal $ 320,900,000 

Total Capital Cost $ 3,319,969,000 

$/kW net 3,689 

Capital Cost Notes 

1. Costs based on EPC contracting approach. WTG assembly and installation costs include port staging, WTG and 

offshore substation foundations, and installation costs of WTGs. Indirect costs include distributable material and 

labor costs, cranes, scaffolding, engineering, construction management, startup and commissioning, and contractor 

overhead. EPC fees are applied to the sum of direct and indirect costs. 

2. Interconnection costs include interconnection surveys, application fees, and construction materials/contracting 

costs with the necessary equipment. Onshore/Offshore transmission costs include onshore/offshore substation 

costs and transmission line costs. 

3. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s startup and commissioning costs. Other owner’s costs include electrical interconnection 

costs. 

15.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Operating expenditures cover all maintenance expenses during operations, including leasing, 

management, labor, equipment and vessel rentals, parts, and consumables for both scheduled and 

unscheduled maintenance of the WTGs and balance of plant systems, as well as operations monitoring. 

Table 15-2 summarizes the average annual O&M expenses projected for an assumed 25-year project life. 
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Table 15-2 — Case 15 O&M Cost Estimate 

Case 15 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Fixed-bottom Offshore Wind: Monopile Foundations 

Fixed O&M – Plant (Notes 1-2) Units Value 

Maintenance Costs $/year 109,800,000 

Leasing Costs $/year 28,800,000 

Subtotal Fixed O&M $/year 138,600,000 

$/kW-year $/kW-year 154.00 $/kW-year 

Variable O&M $/MWh 0.00 $/MWh 

O&M Notes 

1. Leasing numbers are based on projects on the east coast (New York, North Carolina, and South Carolina). 

Leasing will fluctuate based on location. 

2. Fixed O&M costs include labor, materials, and contracted services. 

15.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Wind power projects do not produce regulated environmental air emissions. While other environmental 

compliance requirements may apply, only air emissions were considered for this report. Therefore, the 

emissions of NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 6 . S O L A R P H O T O V O L T A I C W I T H S I N G L E 

A X I S T R A C K I N G , 1 5 0 M W A C

16.1. CASE DESCRIPTION

This case is a nominal 150 MWAC solar photovoltaic (PV) facility with single-axis tracking. While continued 

advances in technical efficiency have resulted in lower module prices over the past decade, solar PV costs 

have increased somewhat relative to 2019 pricing. This case uses 195 MWDC of monocrystalline passive 

emitter and rear contact (PERC) bifacial modules connected in 1500-V strings with independent single-axis 

tracker rows that are placed in a north-south orientation with east-west tracking. The case also uses 150 

MWAC of central power conversion stations (inverters with integrated medium-voltage transformers), 

resulting in a DC/AC ratio of 1.3 at the inverter. Solar PV projects are relatively simple since there is no fuel 

or waste and limited moving parts; however, single-axis tracking systems require considerable land 

commitments due to a low ground coverage ratio intended to limit self-shading as well as create room for 

both tracking rotation and easy access for maintenance purposes. Many tracking companies offer advanced 

backtracking software that help to optimize yield and ground coverage ratio, though this was not considered 

in this estimate. 

Figure 16-1 — Solar PV Project 

Bifacial PV panels (left) and tracking systems (right). 

Source: Sargent & Lundy project site photo archive. 
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16.1.1. Mechanical Equipment and Systems

Solar PV systems convert sunlight into electrical power. Solar PV modules convert incident solar radiation 

into a potential difference within individual solar cells that produces DC electricity. The solar PV facility 

assumed for this study is comprised of 390,000 individual 500-watt, 1500-V monocrystalline solar modules 

with PERC architecture for increased efficiency. These modules are connected in series to each other in 

strings. The exact number of modules in each string varies across the United States depending on site 

specific conditions and module characteristics but typically range from 26 up to 32 modules per string. The 

strings connect to each other in parallel to form large solar arrays, which make up the bulk of the facility. 

Arrays are often grouped together into distinct blocks throughout the plant with each block having a single 

designated inverter pad. Mechanical components of these arrays include the racking and solar tracking 

equipment. This estimate assumes the racking uses a driven pile foundation; however, depending on the 

site’s geotechnical characteristics, ground screws and concrete foundations can also be used. 

The tracking system’s exact mechanics depend on the manufacturer. This system, and nearly all singleaxis tracking systems currently being manufactured, use a north-south oriented tracking axis that is 

horizontally parallel with respect to the ground. This orientation allows the panels to track the sun as it 

crosses the sky from east to west. One variation in tracking mechanics that can impact the overall cost is 

linked versus unlinked row tracking. Linked row tracking connects multiple rows to a single tracker 

mechanism, thereby requiring them all to rotate at the same angle throughout the day but significantly 

reducing the number of tracker motors that need to be procured for the system. Unlinked row tracking allows 

individual rows to track the sun at different angles but require a solar tracker mechanism on each row. This 

case assumes an unlinked single-axis tracker technology. 
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Figure 16-2 — Single-Axis Tracking 

16.1.2. Electrical and Control Systems

Each block within a PV is typically made up of identical components and functionality. Electrical components 

include: 

 DC and AC wiring 

 Combiner boxes 

 Inverters 

 Step-up transformers 

 Control system 

 Switchyard with electrical interconnection to the grid 

As previously explained, modules are combined in series to form series strings. These strings are combined 

in parallel to form solar arrays. Arrays are then connected via combiner boxes to combine the current from 

each string of each array before feeding the DC power into an inverter. The number of arrays combined 

into each combiner box is dependent on the site layout, the current of each string, and the size of the 

combiner box. This estimate assumes one combiner box for every thirty strings. After DC cables from the 

combiner boxes are fed into the inverter, the inverter then converts the DC electricity from the combiner 

boxes into AC electricity. Inverters are generally grouped into two different categories defined by their 

capacity with smaller inverters that are spread around the array being referred to as string inverters and 
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larger inverters skidded at select central locations in the facility are referred to as central inverters. Central 

inverters currently used in new projects are typically rated between 1,500 kW and 4000 kW. This system 

uses one 2500-kW central inverter with one integrated 2.5 MVA medium-voltage transformer within each 

PV block. Inverters that are skidded with a medium-voltage transformer (either via internal or external 

integration) are referred to as power conversion stations and are typically sold as a cohesive unit from the 

inverter manufacturer. 

A solar facility’s nominal capacity is typically defined by either the net AC capacity of the inverters across 

all blocks or the maximum allowable injection capacity into the electric grid as defined by the project’s 

interconnection agreement. In general, there will always be more installed DC capacity from the modules 

than AC capacity from the inverters. The ratio of DC to AC capacity (DC/AC ratio) is typically between 1.2 

and 1.4; however, some projects increase the DC/AC ratio with the intention of harnessing the DC power 

that is clipped by the inverter’s maximum capacity into battery storage energy. On the other side of the 

spectrum, some projects will decrease the DC/AC ratio to allow for additional reactive compensation. This 

estimate assumes a DC/AC ratio of 1.3. 

16.1.3. Offsite Requirements

Solar PV facilities require no fuel and produce no waste. The offsite requirements are limited to an 

interconnection between the PV facility and the transmission system. In the event the facility plans to have 

the modules cleaned, offsite requirements will also include water for the purpose of cleaning the solar 

modules. Water is not always a requirement because the necessity of cleaning is regionally dependent. In 

regions with significant rainfall and limited dust accumulation, cleaning is often unnecessary because it 

occurs naturally. In dust heavy and dry regions (which often have higher solar irradiance), cleaning occurs 

proportionally to the dust accumulation from once or twice a year up to bi-monthly and typically uses offsite 

water that is brought in on trucks. This analysis assumes one cleaning per year. 

16.2. CAPITAL COST ESTIMATE

Table 16-1 summarizes the cost components for this case. Solar prices have been increasing due to rising 

commodity pricing, delivery and manufacturing costs, and labor costs. As the solar PV industry has been 

subject to volatile pricing, labor challenges, and being restricted to difficult land, the engineering, 

procurement, and construction (EPC) contractors and developers have also been bearing more 

contingency and overhead, further increasing a solar project’s overall cost. 

Despite these cost increases, advancements in solar PV technology and construction continue to provide 

downward pressure on the $/kW cost. As solar modeling and engineering software advances, projects are 

able to optimize layouts and ground coverage for the lowest levelized cost of energy; however, in recent 
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years, this only serves to limit the cost increases rather than to cause a material decrease in total project 

costs. Solar modules that are arriving on the market are rated to have a net string potential of 1500 V rather 

than the previous 1000 V string that was common in the early and mid-2010s. This increased net potential 

allows for lower wiring losses, which increases the net energy yield and lowers wiring material costs in the 

electrical balance-of-plant. 

Table 16-1 — Case 16 Capital Cost Estimate 

Case 16 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with Single-Axis 

Tracking 

150 MW AC 

DC / AC Ratio 1.3 

Module Type Bifacial Monocrystalline 

Units 

Plant Characteristics 

Net Plant Capacity MW_AC 150 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and 

Indirect Costs 5% 

EPC Contingency % of EPC Costs 5% 

Owner's Services % of EPC Costs 5% 

Owner's Contingency % of Owner's Costs 10% 

Estimated Land Requirement (Note 1) acres 1000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 2,412,000 

Miles miles 1.00 

Typical Project Timelines 

Development, Permitting, Engineering months 24 

Plant Construction Time months 12 

Total Lead Time Before Commercial 

Operation Date (COD) months 36 

Operating Life years 35 

EPC Cost Components (Note 2) 

Module Supply $ 72,150,000 

Inverter Supply $ 10,395,000 

Racking, Tracker and Balance-of-Plant 

(BOP) Equipment Supply $ 44,850,000 

Main Power Transformer and Substation $ 10,500,000 

Construction / Installation Labor $ 26,325,000 

Supervisory, Control, and Data Acquisition 

Subcontract $ 915,000 

Civil/Structural/Architectural Subcontract $ 13,650,000 

Indirect Costs $ 12,675,000 

EPC Contracting Fee $ 9,573,000 
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Case 16 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with Single-Axis 

Tracking 

150 MW AC 

DC / AC Ratio 1.3 

Module Type Bifacial Monocrystalline 

Units 

EPC Contingency $ 10,052,000 

EPC Subtotal $ 211,085,000 

Owner's Cost Components (Note 3) 

Owner's Services $ 10,554,000 

Electrical Interconnection $ 2,412,000 

Owner's Contingency $ 1,297,000 

Owner's Costs Subtotal $ 14,263,000 

Total Capital Cost $ 225,348,000 

$/kW net 1,502 

Capital Cost Notes 

1. Land for this resource type is typically leased and not purchased. Minor costs for land acquisition and lease 

during development and construction period is included in the owner's services costs. Annual lease costs are also 

accounted for in the fixed operating and maintenance (O&M). 

2. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, start-up and 

commissioning, contractor overhead, freight, and duties/sales taxes. EPC fees are applied to the sum of direct 

and indirect costs. 

3. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical 

interconnection costs. 

16.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

Operations and maintenance costs associated with 150-MWAC, single-axis tracking solar PV project have 

increased slightly overall with a range of specific factors increasing and decreasing individually. There are 

five main factors to solar PV O&M: preventative maintenance, unscheduled maintenance, module cleaning, 

inverter maintenance reserve, and the land lease. As technological reliability increases and designs 

become more focused on decreasing O&M costs, preventative maintenance gets less costly and 

unscheduled maintenance occurs less frequently. Examples of O&M-focused designs are DC harnesses 

for optimal wiring configurations, wireless communication and control systems, and central inverter 

locations for ease of access. These increases in design and reliability savings are more than offset by the 

increases in equipment and maintenance labor costs leading to an overall increase in both preventative 

and unscheduled maintenance. Similarly, the inverter maintenance reserve is another factor that increased 

overall in cost but is subject to competing impacts between higher inverter pricing but increasing inverter 

reliability that drives the reserve down. 
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Module cleaning is the only cost component that decreased overall. Cleaning is typically less expensive for 

PV fields with trackers using independent rows because a single truck can clean two rows at a time instead 

of one. New coatings and design of PV modules have also resulted in slight decreases in the amount of 

“typical” module cleanings in the United States from two on average down to one. The final annual expense 

is the land lease. Solar PV projects typically rent, rather than purchase, the land for the project; therefore, 

it is an operating expense and not a capital cost. As the increased demand for solar PV projects continues 

throughout the country, there has been a material drop in ideal sites that are available and PV developers 

have been forced to locate facilities on more expensive and unideal land. Additionally, landowners have 

become more aware of the economic value of these facilities and have begun to charge more for leasing 

their land. 

Table 16-2 — Case 16 O&M Cost Estimate 

Case 16 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Solar PV with Single-Axis Tracking 

Fixed O&M – Plant (Note 1) Units Value 

Preventative Maintenance $/year 1,500,000 

Module Cleaning (Note 2) $/year 136,000 

Unscheduled Maintenance $/year 225,000 

Inverter Maintenance Reserve $/year 374,000 

Land Lease (Note 3) $/year 800,000 

Subtotal Fixed O&M $/year 3,035,000 

$/kW-year $/kW-year 20.23 $/kW-yr 

Variable O&M $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Assume one module cleaning per year. 

3. Land for solar PV projects is typically leased rather than owned, this is considered to be a representative annual 

expense but varies across projects. 

16.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Solar PV does not produce regulated environmental air emissions. While other environmental compliance 

requirements may apply, only air emissions were considered for this report. Therefore, the emissions of 

NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 7 . S O L A R P H O T O V O L T A I C W I T H S I N G L E 

A X I S T R A C K I N G , AC - C O U P L E D B A T T E R Y

E N E R G Y S T O R A G E , 1 5 0 M W A C | 2 0 0 M W H

17.1. CASE DESCRIPTION

This case is based on a nominal 150 MWAC solar photovoltaic (PV) plant with 200 MWh of lithium-ion battery 

storage that is AC-coupled. Solar PV has increasingly been coupled with battery storage in recent years 

due to price reductions in lithium-ion batteries. The AC-coupling architecture refers to a design in which the 

PV and battery components are coupled on AC side (grid side) of the inverter. The AC-coupled system 

assumes a DC/AC ratio of 1.4, resulting in a DC size of 210 MW. AC-coupled systems are typically built at 

a higher DC/AC ratio than standalone PV to maximize the amount of available energy to charge the battery 

energy storage system (BESS) without sacrificing PV output while the BESS is charging or idle. The factors 

driving cost increases of solar PV projects are shared with systems coupled with battery storage. Cost 

increases are partially offset by modeling technology used to optimize design and reduce civil costs per 

kW, higher power modules, lower priced inverters, and lower risk. Batteries can be either AC- or DC-coupled 

to the solar array. AC-coupled systems have a simpler architecture that is easier to install and can be retrofit 

to an existing solar plant with the batteries interconnected directly at the substation. AC-coupled systems 

offer higher efficiency when used in power AC applications, but they also have slightly lower efficiencies 

when charging the battery. The most common application for AC-coupled systems is peak shaving, or 

energy arbitrage, where there is a limit on the power allowed into the grid and the peak of the solar 

generation is stored in a battery to be sold during the highest demand peaks for optimal profit. 

17.1.1. Mechanical Equipment and Systems

This case assumes a nominal 150 MWAC solar PV plant with 200 MWh of lithium-ion battery storage. 

Batteries are typically sized by their output in kWh and not by their capacity in MW, which is defined by the 

AC capacity of the battery’s inverters. The 200 MWh battery system in this estimate is comprised of four 

hours of 50 MW output. The mechanical equipment for the solar portion is the same as a stand-alone solar 

PV facility: 500-watt 1500-V monocrystalline modules, ground mounted racking with driven pile foundations, 

and independent single-axis tracking equipment. The mechanical equipment associated with the battery 

storage is the batteries themselves, the containers they are placed in, the fire suppression system, and the 

concrete foundations for the battery containers. This estimate assumes the use of 80 containers, each 40 

feet in length and containing 2.5 MWh of battery storage. Smaller 20-foot containers are sometimes used 

depending on constraints with site availability and project size. Containers are often provided with 

unpopulated racks to allow for periodic additions of more batteries (“augmentation”) to compensate for 
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energy capacity lost to battery degradation. Alternatively, battery augmentation may be performed by 

adding entirely new battery containers to vacant footprints on a project site. 

17.1.2. Electrical and Control Systems

When incorporating AC-coupled battery storage into a solar PV site, there is no change in the electrical 

components of the solar array and solar inverters. The solar modules are connected in series with DC wiring 

into solar strings. The solar strings are connected in parallel to combiner boxes that output the current into 

the solar inverters. The output of the solar inverter then enters a switchgear that feeds the AC current into 

either the grid or the battery inverter. It is also important to note that battery storage inverters are different 

from solar inverters in that they are typically bi-directional inverters that can alternate between inverting AC 

to DC and inverting DC to AC. Battery storage inverters also allow the batteries to be charged by either the 

solar array or the grid. This facility uses 150 MW of solar inverters plus 50 MW of battery inverters. Battery 

inverters are typically more expensive than solar inverters. 

Figure 17-1 — AC-Coupled Solar PV and Battery Storage 

Adapted from Clean Energy Reviews, 

https://www.cleanenergyreviews.info/blog/ac-coupling-vs-dc-coupling-solar-battery-storage (accessed June 12, 

2019). 

Whether power is being used from the battery storage or the solar array, it passes through a switchyard 

that contains the circuit breaker, step-up transformer, and electrical interconnection with the grid. A 

supervisory control and data acquisition (SCADA) system is provided for communications and control of 
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the inverters and substation. The SCADA system allows the operations staff to remotely control and monitor 

the solar PV farm as a whole. 

17.1.3. Offsite Requirements

Solar PV and battery storage facilities require no fuel and produce no waste. The offsite requirements are 

limited to an interconnection between the facility and the transmission system as well as water for the 

purpose of cleaning the solar modules—if applicable since cleaning is regionally dependent. In regions with 

significant rainfall and limited dust accumulation, cleaning is often unnecessary and occurs naturally. In 

dust heavy and dry regions, cleaning typically occurs once or twice a year and uses offsite water that is 

brought in on trucks. This analysis assumes two cleanings per year. 

17.2. CAPITAL COST ESTIMATE

Table 17-1 summarizes the cost components for this case. It should be noted that the DC/AC ratio for this 

paired technology is higher than that of a standalone PV system. This requires more panels, racking, etc., 

so the cost for these components will be higher than those of a standalone PV system with the same net 

AC output. Solar prices have been increasing due to rising commodity pricing, delivery and manufacturing 

costs, and labor costs. Facing volatile pricing, labor challenges, and being restricted to difficult land, EPC 

contractors and developers have also been bearing more contingency and overhead, further increasing the 

solar portion of the project’s overall price. The battery cost estimate also increased relative to the 2019 

pricing due to inflation and the inclusion of substation costs. 

Table 17-1 — Case 17 Capital Cost Estimate 

Case 17 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with SingleAxis Tracking and 

Battery Storage 

Battery Configuration AC Coupled 

DC / AC Ratio 1.4 

Module Type Bifacial 

Monocrystalline 

Battery Type Lithium Ion 

Units 

Plant Characteristics 

Net Solar Capacity MW_AC 150 

Net Battery Capacity MW_AC 50 

Battery Duration hour 4 

Capital Cost Assumptions 
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Case 17 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with SingleAxis Tracking and 

Battery Storage 

Battery Configuration AC Coupled 

DC / AC Ratio 1.4 

Module Type Bifacial 

Monocrystalline 

Battery Type Lithium Ion 

Units 

EPC Contracting Fee % of Direct and Indirect Costs 5% 

EPC Contingency % of Project Costs 5% 

Owner's Services % of Project Costs 5% 

Owner's Contingency % of Project Costs 10% 

Estimated Land Requirement (Note 1) acres 1150 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 2,412,000 

Miles miles 1.00 

Typical Project Timelines 

Development, Permitting, Engineering months 24 

Plant Construction Time months 12 

Total Lead Time Before 

Commercial Operation Date (COD) months 36 

Operating Life years 35-Year PV; 20-Year 

BESS 

EPC Cost Components (Note 2) 

PV Module Supply $ 77,700,000 

PV Inverter Supply $ 10,395,000 

PV Racking, Tracker and Balance-of-Plant 

(BOP) Equipment Supply $ 48,300,000 

BESS Container Supply $ 50,560,000 

BESS BOP Equipment Supply (Note 3) $ 12,280,000 

Main Power Transformer and Substation $ 10,500,000 

PV Construction / Installation Labor $ 28,350,000 

BESS Construction / Installation Labor $ 2,900,000 

SCADA Subcontract $ 915,000 

Civil/Structural/Architectural Subcontract $ 14,700,000 

Indirect Costs $ 21,650,000 

EPC Contracting Fee $ 13,913,000 

EPC Contingency $ 14,608,000 

EPC Subtotal $ 306,771,000 
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Case 17 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with SingleAxis Tracking and 

Battery Storage 

Battery Configuration AC Coupled 

DC / AC Ratio 1.4 

Module Type Bifacial 

Monocrystalline 

Battery Type Lithium Ion 

Units 

Owner's Cost Components (Note 4) 

Owner's Services $ 15,339,000 

Electrical Interconnection $ 2,412,000 

Owner's Contingency $ 1,775,000 

Owner's Cost Subtotal $ 19,526,000 

Total Capital Cost $ 326,297,000 

$/kW net 2,175 

Capital Cost Notes 

1. Land for this resource type is typically leased and not purchased. Minor costs for land acquisition and lease 

during development and construction period is included in the owner's services costs. Annual lease costs are also 

accounted for in the fixed operating and maintenance (O&M). 

2. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, start-up and commissioning, 

contractor overhead, freight, and duties/sales taxes. EPC fees are applied to the sum of direct and indirect costs. 

3. BESS BOP equipment supply is inclusive of all equipment and materials except for BESS units to provide 

medium-voltage feeders to the substation. Including but not limited to auxiliary power equipment and transfer 

switches; inverters; medium-voltage transformers; cabling and conduit; equipment foundations; and supervisory 

control and data acquisition (SCADA). 

4. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs. 

17.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

For this case, Sargent & Lundy grouped the O&M costs into the following categories: preventative 

maintenance, unscheduled maintenance, module cleaning, inverter maintenance reserve, battery 

augmentation, and the land lease. Descriptions of all the factors except the battery augmentation can be 

found in Section 16.3. The typical lifetime of a battery is 7300 cycles, which yields a lifetime of roughly 20 

years (based on approximately one cycle per day). Sargent & Lundy assumes periodic augmentation to 

compensate for energy capacity lost to battery degradation for the first 20 years. More extensive 

decommissioning of the original BESS equipment and rebuilding with entirely new batteries, may be 

necessary in order to have storage of PV generation for the 35-year expected life of the PV technology. 
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Sargent & Lundy has modeled only augmentation through year 20, not any decommissioning or extensive 

rebuild afterwards. 

Table 17-2 — Case 17 O&M Cost Estimate 

Case 17 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Solar PV with Single-Axis Tracking and Battery Storage 

Fixed O&M – Plant (Note 1) Units Value 

Preventative Maintenance $/year 2,700,000 

Module Cleaning (Note 2) $/year 146,000 

Unscheduled Maintenance $/year 525,000 

Inverter Maintenance Reserve $/year 374,000 

Battery Augmentation $/year 1,200,000 

Land Lease (Note 3) $/year 814,200 

Subtotal Fixed O&M $/year 5,759,200 

$/kW-year $/kW-year 38.39 $/kW-year 

Variable O&M $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Assume two module cleanings per year. 

3. Solar PV projects typically rent land rather than purchase it, this is considered to be a representative annual 

expense but varies across projects. 

17.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Neither solar PV nor battery storage produce regulated environmental air emissions. While other 

environmental compliance requirements may apply, only air emissions were considered for this report. 

Therefore, the emissions of NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 8 . S O L A R P H O T O V O L T A I C W I T H S I N G L E 

A X I S T R A C K I N G , D C - C O U P L E D B A T T E R Y

E N E R G Y S T O R A G E , 1 5 0 M W A C | 2 0 0 M W H

18.1. CASE DESCRIPTION

This case is based on a nominal 150 MWAC solar photovoltaic (PV) plant with 200 MWh of lithium-ion battery 

storage that is DC-coupled. The DC-coupling architecture refers to a design in which the PV and battery 

components are coupled on DC side (plant side) of the inverter. The DC-coupled system assumes a DC/AC 

ratio of 1.6, resulting in a DC size of 240 MW. DC-coupled systems often have the highest DC/AC ratio 

because unlike most systems that experience increased clipping losses as the DC/AC ratio increases, DCcoupled systems can capture energy that would have otherwise been clipped and use it to charge the 

battery energy storage system (BESS). DC-coupled systems require no inversion of solar electricity from 

DC to AC and back again before the electricity is stored in the battery and can thus achieve higher BESS 

roundtrip efficiency than AC-coupled systems. But DC-coupled systems also have a more complex 

arrangement and control architecture, are more difficult to install and retrofit with an existing solar system, 

and require additional equipment such as DC to DC converters. DC-coupled systems may be used for the 

same applications as AC-coupled systems such as peak shaving, or energy arbitrage, but they tend to be 

more costly to install than AC-coupled designs and are less common in the industry. 

18.1.1. Mechanical Equipment and Systems

This case assumes a nominal 150 MWAC solar PV plant with 200 MWh of lithium-ion battery storage. 

Batteries are typically sized by their output in kWh and not by their capacity in MW, which is defined by the 

AC capacity of the battery’s inverters. The 200 MWh battery system in this estimate is comprised of four 

hours of 50 MW output. The mechanical equipment for the solar portion is the same as a stand-alone solar 

PV facility: 500-watt 1500-V monocrystalline modules, ground mounted racking with driven pile foundations, 

and independent single-axis tracking equipment. The mechanical equipment associated with the battery 

storage is the batteries themselves, the containers they are placed in, the fire suppression system, and the 

concrete foundations for the battery containers. This estimate assumes the use of 80 containers, each 40 

feet in length and containing 2.5 MWh of battery storage. Smaller 20-foot containers are sometimes used 

depending on constraints with site availability and project size. Containers are often provided with 

unpopulated racks to allow for periodic battery augmentations to compensate for energy capacity lost to 

battery degradation. Alternatively, battery augmentation may be performed by adding entirely new battery 

containers to vacant footprints on a project site. For DC-coupled PV and BESS facilities, the former 

augmentation strategy (using spare racks in original containers) has historically been preferred to allow for 
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more gradual augmentations at the distributed BESS locations on the site; but many modern suppliers offer 

stand-alone modular options in smaller kWh increments to serve the same purpose. 

18.1.2. Electrical and Control Systems

In a DC-coupled system, the PV and battery components share the same bidirectional inverters, and energy 

used to charge the battery passes through a DC-to-DC converter. In such an architecture, the hardware 

and controls allow charging the battery from the grid or directly from the PV without conversion to AC. In 

this case, excess PV generation that exceeds the inverter capacity limit and would normally be clipped by 

the inverter is instead used to charge the batteries. Like most PV arrangements, the PV modules are 

connected in series with DC wiring to form strings which are in turn connected in parallel at combiner boxes. 

In the DC-coupled architecture, the DC output from the PV combiner boxes may be sent through the DC/AC 

inverters to the grid or directly to the BESS through the DC-to-DC converters. This facility uses 150 MW of 

bidirectional inverters which covers both the PV and BESS capacities. Bidirectional inverters (sometimes 

referred to as battery inverters) are typically more expensive than solar inverters. 

Figure 18-1 — DC-Coupled Solar PV and Battery Storage 

NREL 

Source: (https://www.nrel.gov/docs/fy21osti/77917.pdf) 

Whether power is being used from the battery storage or the solar array, it passes through a switchyard 

that contains the circuit breaker, step-up transformer, and electrical interconnection with the grid. 

18.1.3. Offsite Requirements

Solar PV and battery storage facilities require no fuel and produce no waste. The offsite requirements are 

limited to an interconnection between the facility and the transmission system as well as water for the 

purpose of cleaning the solar modules. Cleaning is regionally dependent. In regions with significant rainfall 

and limited dust accumulation, cleaning is often unnecessary and occurs naturally. In dust heavy and dry 
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regions, cleaning typically occurs once or twice a year and uses offsite water that is brought in on trucks. 

This analysis assumes two cleanings per year. 

18.2. CAPITAL COST ESTIMATE

Table 18-1 summarizes the cost components for this case. It should be noted that the DC/AC ratio for this 

paired technology is higher than that of the AC-coupled and standalone PV systems. This requires more 

panels, racking, etc., so the cost for these components will be higher than those of the AC-coupled and 

standalone PV cases with the same net AC capacity ratings. Facing volatile pricing, labor challenges, and 

being restricted to difficult land, EPC contractors and developers have also been bearing more contingency 

and overhead, further increasing the solar portion of the project’s overall price. The battery cost estimate 

also increased relative to the 2019 pricing due to inflation and the inclusion of substation costs in this 

iteration of the estimate. 

Table 18-1 — Case 18 Capital Cost Estimate 

Case 18 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with Single-Axis 

Tracking and 

Battery Storage 

Battery Configuration DC Coupled 

DC / AC Ratio 1.6 

Module Type Bifacial Monocrystalline 

Battery Type Lithium Ion 

Units 

Plant Characteristics 

Net Solar Capacity MW_AC 150 

Net Battery Capacity MW_AC 50 

Battery Duration hour 4 

Capital Cost Assumptions 

EPC Contracting Fee % of Direct and Indirect 

Costs 5% 

EPC Contingency % of Project Costs 5% 

Owner's Services % of Project Costs 5% 

Owner's Contingency % of Project Costs 10% 

Estimated Land Requirement (Note 1) acres 1300 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 2,412,000 

Miles miles 1.00 
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Case 18 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with Single-Axis 

Tracking and 

Battery Storage 

Battery Configuration DC Coupled 

DC / AC Ratio 1.6 

Module Type Bifacial Monocrystalline 

Battery Type Lithium Ion 

Units 

Typical Project Timelines 

Development, Permitting, Engineering months 24 

Plant Construction Time months 12 

Total Lead Time Before Commercial 

Operation Date (COD) months 36 

Operating Life years 35-Year PV; 20-Year BESS 

EPC Cost Components (Note 2) 

PV Module Supply $ 88,800,000 

Bidirectional Inverter Supply $ 11,205,000 

PV Racking, Tracker and Balance-ofPlant 

(BOP) Equipment Supply 

$ 55,200,000 

BESS Container Supply $ 50,560,000 

BESS BOP Equipment Supply (Note 3) $ 30,700,000 

Main Power Transformer & Substation $ 10,500,000 

PV Construction / Installation Labor $ 32,400,000 

BESS Construction / Installation Labor $ 7,250,000 

Supervisory, Control, and Data 

Acquisition Subcontract $ 915,000 

Civil/Structural/Architectural 

Subcontractor $ 16,800,000 

Indirect Costs $ 23,600,000 

EPC Contracting Fee $ 16,397,000 

EPC Contingency $ 17,216,000 

EPC Subtotal $ 361,543,000 

Owner's Cost Components (Note 4) 

Owner's Services $ 18,077,000 

Electrical Interconnection 2,412,000 

Owner's Contingency $ 2,049,000 

Owner's Cost Subtotal $ 22,538,000 

Total Capital Cost $ 384,081,000 

$/kW net 2,561 

Capital Cost Notes 
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Case 18 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Solar PV with Single-Axis 

Tracking and 

Battery Storage 

Battery Configuration DC Coupled 

DC / AC Ratio 1.6 

Module Type Bifacial Monocrystalline 

Battery Type Lithium Ion 

Units 

1. Land for this resource type is typically leased and not purchased. Minor costs for land acquisition and lease 

during development and construction period is included in the owner's services costs. Annual lease costs are also 

accounted for in the fixed operating and maintenance (O&M). 

2. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, start-up and commissioning, 

contractor overhead, freight, and duties/sales taxes. EPC fees are applied to the sum of direct and indirect costs. 

3. BESS BOP equipment supply is inclusive of all equipment and materials except for BESS units to provide 

medium-voltage feeders to the substation, including, but not limited to, auxiliary power equipment and transfer 

switches; DC-to-DC converters; medium-voltage transformers; cabling and conduit; equipment foundations; and 

supervisory control and data acquisition (SCADA). 

4. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical interconnection 

costs. 

18.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

For this case, Sargent & Lundy grouped the O&M costs into the following categories: preventative 

maintenance, unscheduled maintenance, module cleaning, inverter maintenance reserve, battery 

augmentation, and the land lease. Descriptions of all the factors except the battery augmentation can be 

found in Section 16.3. The typical lifetime of a battery is 7300 cycles, which yields a lifetime of roughly 20 

years (based on approximately one cycle per day). Sargent & Lundy assumes periodic augmentation to 

compensate for energy capacity lost to battery degradation for the first 20 years. More extensive 

decommissioning of the original BESS equipment and rebuilding with entirely new batteries, may be 

necessary in order to have storage of PV generation for the 35-year expected life of the PV technology. 

Sargent & Lundy has modeled only augmentation through year 20, not any decommissioning or extensive 

rebuild afterwards. 

Table 18-2 — Case 18 O&M Cost Estimate 

Case 18 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

Solar PV with Single-Axis Tracking and Battery Storage 
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Fixed O&M – Plant (Note 1) Units Value 

Preventative Maintenance $/year 2,700,000 

Module Cleaning (Note 2) $/year 167,000 

Unscheduled Maintenance $/year 525,000 

Inverter Maintenance Reserve $/year 374,000 

Battery Augmentation $/year 1,200,000 

Land Lease (Note 3) $/year 920,400 

Subtotal Fixed O&M $/year 5,886,400 

$/kW-year $/kW-year 39.24 $/kW-year 

Variable O&M $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and general and administrative (G&A) costs. 

O&M costs exclude property taxes and insurance. 

2. Assume one module cleaning per year. 

3. Land for solar PV projects is typically leased rather than owned, this is considered to be a representative annual 

expense but varies across projects. 

18.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

Solar PV does not produce regulated environmental air emissions. While other environmental compliance 

requirements may apply, only air emissions were considered for this report. Therefore, the emissions of 

NOX, SO2, and CO2 are 0.00 lb/MMBtu.
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C A S E 1 9 . B A T T E R Y E N E R G Y S T O R A G E S Y S T E M ,

1 5 0 M W | 600 MWH 

19.1. CASE DESCRIPTION

This case consists of a utility-scale, lithium-ion, battery energy storage system (BESS) with a 150 MW 

power rating and 600 MWh energy rating; the system can provide 150 MW of power for a four-hour duration. 

The cost estimate includes a substation consisting of a transformer to increase voltage from the BESS 

system to the interconnection voltage (modeled as 138 kV), as well as associated switchgear. 

The BESS consists of 240 modular, factory-integrated battery storage containers that house the batteries 

and supporting systems (for example, battery management system, electrical protections, thermal 

management system, fire protection, etc.). The battery containers modeled in Case 19 are of representative 

size, 20 feet long x 10 feet wide x 8 feet high, however, industry offerings vary in size and modularity but 

offer roughly the same energy density per acre and total cost. The BESS uses utility-scale lithium-ion 

batteries. Approximately 1.5% of the initial battery capacity is assumed to degrade each year and require 

augmentation by the addition of new batteries. (The augmentation cost is included with the annual O&M, 

as discussed in Section 19.3). Battery containers are grouped together and connected with an associated 

inverter-transformer skid, which is approximately 15 feet long x 10 feet wide x 8 feet high and is commonly 

referred to as a Power Conditioning System (PCS). The PCS houses the inverters, transformer, and 

associated electrical equipment (for example, fuses and breakers). There is one control building with 

approximate dimension of 20 feet long x 10 feet wide x 8 feet high to support O&M activities. Each building 

is set on a concrete slab foundation. 

Figure 19-1 shows a typical utility-scale lithium-ion battery. Several battery cells make up a battery module, 

also commonly referred to as a “battery pack”, which is independently monitored and controlled. Several 

battery modules are contained within a battery rack, and there are several battery racks in a battery 

container. 
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Project 14987.001

Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

114 

Figure 19-1 — Utility-Scale Lithium-Ion Batteries 

Source: National Renewable Energy Laboratory (NREL) “2018 U.S. Utility-Scale Photovoltaics-Plus-Energy Storage 

System Costs Benchmark, Technical Report NREL/TP-6A20-71714, November 2018. 

(https://www.nrel.gov/docs/fy19osti/71714.pdf) (accessed July 23, 2019) 

The BESS is equipped with 600 MWh of lithium-ion batteries connected in strings and one hundred 1.5 MW 

inverters. Batteries operate on DC power; however, most electric power generation on the grid is produced 

and distributed as AC power. Standalone BESS are equipped with inverters to convert between AC power 

from the grid to DC power for storage within the batteries. Sequentially, the grid or substation AC power is 

converted by the main power transformer from high-voltage (138+ kV) to medium-voltage (34.5 kV), 

medium-voltage power is converted to the operational voltage range of the inverters (480–700 VAC, 

depending on design) by medium-voltage transformers, and inverters convert AC power to DC power 

(1000–1500 VDC) for connection with the battery containers. AC-coupled and DC-coupled BESS are 

discussed in Case 17 and Case 18, respectively, however it is noteworthy that the majority of existing and 

near-term planned installations of BESS are either standalone or AC-coupled configurations. 

Figure 19-2 — Standalone BESS Flow Diagram 

Adapted from Clean Energy Reviews, 

https://www.cleanenergyreviews.info/blog/ac-coupling-vs-dc-coupling-solar-battery-storage (accessed June 12, 

2019). 
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Project 14987.001

Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

115 

19.2. CAPITAL COST ESTIMATE

Table 19-1 summarizes the cost components for this case. Both the $/kW and $/kWh are provided to clearly 

describe the system estimate. The capital cost estimate is based on a BESS with a power rating of 150 MW 

and energy rating of 600 MWh (equivalent to a four-hour duration system). The cost estimate includes civil 

works, foundations, buildings, electrical equipment and related equipment, substation, switchyard, 

transformers, transmission lines, cabling, controls, and instrumentation. The cost estimate increased 

relative to the 2019 pricing due to inflation and the inclusion of substation costs in this iteration of the 

estimate. 

Table 19-1 — Case 19 Capital Cost Estimate 

Case 19 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Battery Energy Storage System 

150 MW | 600 MWh 

Greenfield 

Battery Type Lithium-Ion 

Service Life 20 years 

Total Charging Cycles in Service Life 7,300 

Units 

Plant Characteristics 

Power Rating MW 150 

Energy Rating MWh 600 

Duration hour 4 

Capital Cost Assumptions 

Engineering, Procurement, and Construction 

(EPC) Contracting Fee 

% of Direct & Indirect 

Costs 5% 

EPC Contingency % of EPC Costs 5% 

Owner's Services % of EPC Costs 4% 

Owner's Contingency % of Owner's Costs 5% 

Estimated Land Requirement acres 6 

Estimated Land Cost $/acre 90,000 

Interconnection Costs 

Electrical Transmission Interconnection Costs 

Transmission Line Cost $/mile 2,412,000 

Miles miles 1.00 

Typical Project Timelines 

Development, Permitting, Engineering months 

Plant Construction Time months 12 

Total Lead Time Before Commercial 

Operation Date (COD) months 18 

Operating Life years 20 

EPC Cost Components (Note 1) 

BESS Unit Supply $ 151,700,000 
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December 6, 2023

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Project 14987.001

Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

116 

Case 19 

EIA – Capital Cost Estimates – 2023 $ USD 

Configuration 

Battery Energy Storage System 

150 MW | 600 MWh 

Greenfield 

Battery Type Lithium-Ion 

Service Life 20 years 

Total Charging Cycles in Service Life 7,300 

Units 

BESS Balance-of-Plant (BOP) Equipment 

Supply (Note 2) $ 36,857,000 

BESS Installation $ 8,672,000 

Main Power Transformer & Substation $ 10,500,000 

Indirect Costs $ 17,345,000 

EPC Contracting Fee $ 11,254,000 

EPC Contingency $ 11,816,000 

EPC Subtotal $ 248,144,000 

Owner's Cost Components (Note 2) 

Owner's Services $ 9,926,000 

Land $ 540,000 

Electrical Interconnection $ 2,412,000 

Owner's Contingency $ 644,000 

Owner's Cost Subtotal $ 13,522,000 

Total Capital Cost $ 261,666,000 

$/kW net 1,744 

$/kWh 436 

Capital Cost Notes 

1. Costs based on EPC contracting approach. Direct costs include equipment, material, and labor to construct the 

civil/structural, mechanical, and electrical/I&C components of the facility. Indirect costs include distributable 

material and labor costs, cranes, scaffolding, engineering, construction management, start-up and 

commissioning, contractor overhead, freight, and duties/sales taxes. EPC fees are applied to the sum of direct 

and indirect costs. 

2. BESS BOP equipment supply is inclusive of all equipment and materials except for BESS units to provide 

medium-voltage feeders to the substation, including, but not limited to, auxiliary power equipment and transfer 

switches; inverters; medium-voltage transformers; cabling and conduit; equipment foundations; and supervisory 

control and data acquisition (SCADA). 

3. Owner’s costs include project development, studies, permitting, legal, owner’s project management, owner’s 

engineering, and owner’s start-up and commissioning costs. Other owner’s costs include electrical 

interconnection costs, gas interconnection costs (if applicable), and land acquisition costs. 
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December 6, 2023

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Project 14987.001

Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

117 

19.3. OPERATIONS AND MAINTENANCE COST ESTIMATE

The O&M cost estimate considers the ongoing O&M cost through the life of a BESS project. The service 

life of a BESS depends on how it is used. This case assumes that the BESS will have a service life of 7300 

equivalent cycles, which yields a lifetime of roughly 20 years (based on approximately one cycle per day) 

representing a typical use case basis in the industry. A full charge-discharge cycle occurs when a battery 

is at 0% usable state of charge, is then charged fully to 100% state of charge, and finally is discharged fully 

back to 0% state of charge. An “equivalent cycle” can be understood as the sum of partial charges and 

discharges equating to the same net energy throughput as a full charge-discharge cycle. BESS projects 

that serve ancillary markets may not experience a full charge and discharge cycle every day or may 

experience partial charge cycles, which is why the concept of “equivalent cycles” is useful. The 7300 

equivalent-cycle service life is a typical industry basis to determine the cost and technical specifications for 

an energy storage system. Capacity degradation of lithium-ion batteries is an inherent performance 

characteristic of lithium-ion battery technology, occurring both due to age-alone and proportional to their 

usage. Battery performance guarantees in the industry suggest approximately 1.5% average annual 

capacity degradation associated with a one full-cycle per day use case for a four-hour duration lithium-ion 

BESS. Battery degradation guarantees are tailored to the specific use case expected for the individual 

BESS. 

Many BESS projects engage a third-party contractor to conduct regular O&M activities. This cost estimate 

considers the cost of such contracted services, which include remote monitoring of the system, periodic 

onsite inspection of equipment conditions and cable connections, replacement of regular consumables (air 

filters, coolant, etc.), and grounds maintenance. This O&M cost estimate uses the 1.5% battery degradation 

factor and incorporates the equipment and labor cost of subsequent augmentations in the annual fixed 

O&M cost. The O&M cost include an annual allowance for general and administrative (G&A) costs. The 

fixed O&M costs are $40.00/kW-year or $10.00/kWh-year. Augmentation is included with fixed cost in this 

case since the use case assumes the same number of charging cycles each year during the service life of 

the project. Divergence from the use case could cause greater than expected degradation and voiding of 

battery performance guarantees. The variable costs are $0.00/MWh, since there are no consumables linked 

to energy output within the expected use case. 

The O&M costs do not include the cost of energy to charge the system. No costs are included for 

decommissioning. 
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December 6, 2023

U.S. Energy Information Administration and Z Federal

Project 14987.001

Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 

118 

Table 19-2 — Case 19 O&M Cost Estimate 

Case 19 

EIA – Non-Fuel O&M Costs – 2023 $ USD 

BESS - 150 MW | 600 MWh - Greenfield 

Fixed O&M – Plant (Note 1) Units Value 

Battery Maintenance 

(Preventative & Corrective) $/year 2,400,000 

Battery Augmentation $/year 3,600,000 

Subtotal Fixed O&M $/year 6,000,000 

$/kW-year $/kW-year 40.00 $/kW-year 

Variable O&M (Note 2) $/MWh 0.00 $/MWh 

O&M Cost Notes 

1. Fixed O&M costs include labor, materials and contracted services, and G&A costs. O&M costs exclude 

property taxes and insurance. 

2. All costs tied to energy produced are covered in fixed cost. 

19.4. ENVIRONMENTAL AND EMISSIONS INFORMATION

BESSs do not produce regulated environmental emission. While other environmental compliance 

requirements may apply, only air emissions were considered for this report. Therefore, the emissions of 

NOX, SO2, and CO2 are 0.00 lb/MMBtu.
SL-018001

Final – Rev A 

December 6, 2023

U.S. Energy Information Administration and Z Federal

Project 14987.001

. 

A P P E N D I X A . L A B O R L O C A T I O N - B A S E D C O S T

A D J U S T M E N T S

Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 
Table 1‐1 — Location Adjustment for Ultra-Supercritical Coal w/o Carbon Capture – Greenfield 

(2023 USD)

Case Configuration: 650 MW Net, 1 x 735 MW Gross

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 4,103 0.97 (132) 3971

Arizona Phoenix 4,103 1.09 383 4486

Arkansas Little Rock 4,103 0.97 (137) 3966

California Bakersfield 4,103 1.31 1,262 5365

California Los Angeles 4,103 1.33 1,366 5469

California Modesto 4,103 1.35 1,418 5521

California Sacramento 4,103 1.37 1,501 5604

California San Francisco 4,103 1.48 1,951 6054

Colorado Denver 4,103 1.03 141 4244

Connecticut Hartford 4,103 1.27 1,103 5206

Delaware Dover 4,103 1.24 991 5094

District of Columbia Washington 4,103 1.09 381 4484

Florida Tallahassee 4,103 0.94 (255) 3848

Florida Tampa 4,103 0.96 (184) 3919

Georgia Atlanta 4,103 1.02 84 4187

Idaho Boise 4,103 1.03 114 4217

Illinois Chicago 4,103 1.36 1,466 5569

Indiana Indianapolis 4,103 1.01 25 4128

Iowa Davenport 4,103 1.05 203 4306

Iowa Waterloo 4,103 0.99 (52) 4051

Kansas Wichita 4,103 0.99 (59) 4044

Kentucky Louisville 4,103 1.01 32 4135

Louisiana New Orleans 4,103 1.00 4 4107

Maine Portland 4,103 1.03 137 4240

Maryland Baltimore 4,103 1.03 111 4214

Massachusetts Boston 4,103 1.36 1,489 5592

Michigan Detroit 4,103 1.11 461 4564

Michigan Grand Rapids 4,103 1.02 62 4165

Minnesota Saint Paul 4,103 1.13 531 4634

Mississippi Biloxi 4,103 0.95 (209) 3894

Missouri St. Louis 4,103 1.13 525 4628

Missouri Kansas City 4,103 1.07 306 4409

Montana Great Falls 4,103 0.98 (76) 4027

Nebraska Omaha 4,103 0.99 (56) 4047

New Hampshire Manchester 4,103 1.11 466 4569

New Jersey Newark 4,103 1.30 1,249 5352

New Mexico Albuquerque 4,103 1.03 141 4244

New York New York 4,103 1.70 2,852 6955

New York Syracuse 4,103 1.14 573 4676

Nevada Las Vegas 4,103 1.17 681 4784

North Carolina Charlotte 4,103 0.98 (71) 4032

North Dakota Bismarck 4,103 1.04 183 4286

Ohio Cincinnati 4,103 0.98 (97) 4006

Oklahoma Oklahoma City 4,103 0.95 (217) 3886

Oregon Portland 4,103 1.21 866 4969

Pennsylvania Philadelphia 4,103 1.35 1,422 5525

Pennsylvania Scranton 4,103 1.13 538 4641

Rhode Island Providence 4,103 1.23 927 5030

South Carolina Charleston 4,103 0.95 (207) 3896

South Dakota Rapid City 4,103 1.00 (6) 4097

Tennessee Nashville 4,103 0.99 (54) 4049

Texas Houston 4,103 0.90 (406) 3697

Utah Salt Lake City 4,103 0.99 (30) 4073

Vermont Burlington 4,103 1.08 315 4418

Virginia Alexandria 4,103 1.07 304 4407

Virginia Roanoke 4,103 1.04 161 4264

Washington Seattle 4,103 1.21 843 4946

Washington Spokane 4,103 1.07 284 4387

West Virginia Charleston 4,103 1.02 100 4203

Wisconsin Green Bay 4,103 1.10 408 4511

Wyoming Cheyenne 4,103 1.00 (21) 4082
Table 1‐2 — Location Adjustment for Ultra-Supercritical Coal 95% Carbon Capture 

(2023 USD)

Case Configuration: 650 MW Net, 1 x 819 MW Gross

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 7,346 0.97 (246) 7100

Arizona Phoenix 7,346 1.03 210 7556

Arkansas Little Rock 7,346 0.97 (224) 7122

California Bakersfield 7,346 1.24 1,799 9145

California Los Angeles 7,346 1.27 1,977 9323

California Modesto 7,346 1.28 2,067 9413

California Sacramento 7,346 1.30 2,205 9551

California San Francisco 7,346 1.40 2,962 10308

Colorado Denver 7,346 0.98 (151) 7195

Connecticut Hartford 7,346 1.20 1,492 8838

Delaware Dover 7,346 1.17 1,260 8606

District of Columbia Washington 7,346 1.04 269 7615

Florida Tallahassee 7,346 0.93 (486) 6860

Florida Tampa 7,346 0.95 (354) 6992

Georgia Atlanta 7,346 1.02 136 7482

Idaho Boise 7,346 1.03 221 7567

Illinois Chicago 7,346 1.35 2,600 9946

Indiana Indianapolis 7,346 1.01 73 7419

Iowa Davenport 7,346 1.05 359 7705

Iowa Waterloo 7,346 0.99 (92) 7254

Kansas Wichita 7,346 0.99 (105) 7241

Kentucky Louisville 7,346 1.01 86 7432

Louisiana New Orleans 7,346 1.00 15 7361

Maine Portland 7,346 1.03 253 7599

Maryland Baltimore 7,346 1.03 204 7550

Massachusetts Boston 7,346 1.29 2,149 9495

Michigan Detroit 7,346 1.11 817 8163

Michigan Grand Rapids 7,346 1.01 109 7455

Minnesota Saint Paul 7,346 1.12 911 8257

Mississippi Biloxi 7,346 0.94 (408) 6938

Missouri St. Louis 7,346 1.14 1,002 8348

Missouri Kansas City 7,346 1.07 543 7889

Montana Great Falls 7,346 0.98 (141) 7205

Nebraska Omaha 7,346 0.99 (98) 7248

New Hampshire Manchester 7,346 1.06 451 7797

New Jersey Newark 7,346 1.30 2,228 9574

New Mexico Albuquerque 7,346 1.04 260 7606

New York New York 7,346 1.60 4,431 11777

New York Syracuse 7,346 1.08 584 7930

Nevada Las Vegas 7,346 1.17 1,263 8609

North Carolina Charlotte 7,346 0.98 (125) 7221

North Dakota Bismarck 7,346 1.04 293 7639

Ohio Cincinnati 7,346 0.98 (178) 7168

Oklahoma Oklahoma City 7,346 0.95 (387) 6959

Oregon Portland 7,346 1.15 1,132 8478

Pennsylvania Philadelphia 7,346 1.28 2,023 9369

Pennsylvania Scranton 7,346 1.07 530 7876

Rhode Island Providence 7,346 1.16 1,208 8554

South Carolina Charleston 7,346 0.96 (296) 7050

South Dakota Rapid City 7,346 0.99 (41) 7305

Tennessee Nashville 7,346 0.99 (38) 7308

Texas Houston 7,346 0.90 (715) 6631

Utah Salt Lake City 7,346 1.00 2 7348

Vermont Burlington 7,346 1.09 674 8020

Virginia Alexandria 7,346 1.02 140 7486

Virginia Roanoke 7,346 0.99 (109) 7237

Washington Seattle 7,346 1.21 1,560 8906

Washington Spokane 7,346 1.07 530 7876

West Virginia Charleston 7,346 1.02 174 7520

Wisconsin Green Bay 7,346 1.09 683 8029

Wyoming Cheyenne 7,346 0.99 (49) 7297
Table 1‐3 — Location Adjustment for Combustion Turbine – Simple Cycle (Aeroderivative) 

(2023 USD)

Case Configuration: 211 MW Net, 4 x 54 MW Gross Aeroderivative Simple Cycle

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,606 0.98 (31) 1575

Arizona Phoenix 1,606 1.01 10 1616

Arkansas Little Rock 1,606 0.99 (22) 1584

California Bakersfield 1,606 1.11 179 1785

California Los Angeles 1,606 1.13 208 1814

California Modesto 1,606 1.13 206 1812

California Sacramento 1,606 1.14 223 1829

California San Francisco 1,606 1.22 362 1968

Colorado Denver 1,606 0.98 (26) 1580

Connecticut Hartford 1,606 1.09 147 1753

Delaware Dover 1,606 1.08 136 1742

District of Columbia Washington 1,606 1.02 32 1638

Florida Tallahassee 1,606 0.97 (55) 1551

Florida Tampa 1,606 0.97 (41) 1565

Georgia Atlanta 1,606 1.00 8 1614

Idaho Boise 1,606 1.01 19 1625

Illinois Chicago 1,606 1.16 258 1864

Indiana Indianapolis 1,606 1.00 (1) 1605

Iowa Davenport 1,606 1.01 22 1628

Iowa Waterloo 1,606 0.99 (23) 1583

Kansas Wichita 1,606 0.98 (25) 1581

Kentucky Louisville 1,606 1.00 (0) 1606

Louisiana New Orleans 1,606 1.00 (3) 1603

Maine Portland 1,606 1.01 15 1621

Maryland Baltimore 1,606 1.01 15 1621

Massachusetts Boston 1,606 1.14 232 1838

Michigan Detroit 1,606 1.05 88 1694

Michigan Grand Rapids 1,606 1.00 3 1609

Minnesota Saint Paul 1,606 1.06 98 1704

Mississippi Biloxi 1,606 0.97 (47) 1559

Missouri St. Louis 1,606 1.07 105 1711

Missouri Kansas City 1,606 1.03 54 1660

Montana Great Falls 1,606 0.99 (20) 1586

Nebraska Omaha 1,606 0.99 (23) 1583

New Hampshire Manchester 1,606 1.02 35 1641

New Jersey Newark 1,606 1.15 246 1852

New Mexico Albuquerque 1,606 1.01 19 1625

New York New York 1,606 1.28 454 2060

New York Syracuse 1,606 1.04 57 1663

Nevada Las Vegas 1,606 1.08 135 1741

North Carolina Charlotte 1,606 0.99 (18) 1588

North Dakota Bismarck 1,606 1.01 19 1625

Ohio Cincinnati 1,606 0.98 (26) 1580

Oklahoma Oklahoma City 1,606 0.97 (45) 1561

Oregon Portland 1,606 1.08 126 1732

Pennsylvania Philadelphia 1,606 1.14 233 1839

Pennsylvania Scranton 1,606 1.03 41 1647

Rhode Island Providence 1,606 1.07 117 1723

South Carolina Charleston 1,606 0.98 (29) 1577

South Dakota Rapid City 1,606 0.99 (10) 1596

Tennessee Nashville 1,606 1.00 1 1607

Texas Houston 1,606 0.95 (80) 1526

Utah Salt Lake City 1,606 1.00 (5) 1601

Vermont Burlington 1,606 1.04 62 1668

Virginia Alexandria 1,606 1.01 15 1621

Virginia Roanoke 1,606 0.99 (20) 1586

Washington Seattle 1,606 1.12 189 1795

Washington Spokane 1,606 1.03 44 1650

West Virginia Charleston 1,606 1.01 14 1620

Wisconsin Green Bay 1,606 1.04 71 1677

Wyoming Cheyenne 1,606 0.99 (12) 1594
Table 1‐4 — Location Adjustment for Combustion Turbine – Simple Cycle 

(2023 USD)

Case Configuration: 419 MW Net, 1 x H Class Simple Cycle

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 836 0.97 (22) 814

Arizona Phoenix 836 1.01 6 842

Arkansas Little Rock 836 0.98 (18) 818

California Bakersfield 836 1.14 115 951

California Los Angeles 836 1.16 133 969

California Modesto 836 1.16 132 968

California Sacramento 836 1.17 144 980

California San Francisco 836 1.28 234 1070

Colorado Denver 836 0.98 (17) 819

Connecticut Hartford 836 1.11 95 931

Delaware Dover 836 1.11 90 926

District of Columbia Washington 836 1.02 20 856

Florida Tallahassee 836 0.96 (37) 799

Florida Tampa 836 0.97 (28) 808

Georgia Atlanta 836 1.00 3 839

Idaho Boise 836 1.01 11 847

Illinois Chicago 836 1.20 169 1005

Indiana Indianapolis 836 1.00 (3) 833

Iowa Davenport 836 1.02 14 850

Iowa Waterloo 836 0.98 (16) 820

Kansas Wichita 836 0.98 (17) 819

Kentucky Louisville 836 1.00 (2) 834

Louisiana New Orleans 836 0.99 (5) 831

Maine Portland 836 1.01 9 845

Maryland Baltimore 836 1.01 8 844

Massachusetts Boston 836 1.18 151 987

Michigan Detroit 836 1.07 57 893

Michigan Grand Rapids 836 1.00 1 837

Minnesota Saint Paul 836 1.08 65 901

Mississippi Biloxi 836 0.96 (32) 804

Missouri St. Louis 836 1.08 65 901

Missouri Kansas City 836 1.04 35 871

Montana Great Falls 836 0.98 (13) 823

Nebraska Omaha 836 0.98 (16) 820

New Hampshire Manchester 836 1.02 20 856

New Jersey Newark 836 1.19 160 996

New Mexico Albuquerque 836 1.01 9 845

New York New York 836 1.36 297 1133

New York Syracuse 836 1.04 37 873

Nevada Las Vegas 836 1.10 86 922

North Carolina Charlotte 836 0.99 (12) 824

North Dakota Bismarck 836 1.02 13 849

Ohio Cincinnati 836 0.98 (17) 819

Oklahoma Oklahoma City 836 0.96 (30) 806

Oregon Portland 836 1.10 79 915

Pennsylvania Philadelphia 836 1.18 152 988

Pennsylvania Scranton 836 1.03 26 862

Rhode Island Providence 836 1.09 75 911

South Carolina Charleston 836 0.97 (25) 811

South Dakota Rapid City 836 0.99 (6) 830

Tennessee Nashville 836 1.00 (3) 833

Texas Houston 836 0.94 (53) 783

Utah Salt Lake City 836 0.99 (7) 829

Vermont Burlington 836 1.04 35 871

Virginia Alexandria 836 1.01 9 845

Virginia Roanoke 836 0.98 (14) 822

Washington Seattle 836 1.15 121 957

Washington Spokane 836 1.03 27 863

West Virginia Charleston 836 1.01 9 845

Wisconsin Green Bay 836 1.06 48 884

Wyoming Cheyenne 836 0.99 (8) 828
Table 1‐5 — Location Adjustment for Combined-Cycle 2x2x1 

(2023 USD)

Case Configuration: 1227 MW Net, 2 x 1 H Class Combined Cycle

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 868 0.97 (26) 842

Arizona Phoenix 868 1.01 8 876

Arkansas Little Rock 868 0.97 (22) 846

California Bakersfield 868 1.15 131 999

California Los Angeles 868 1.18 152 1020

California Modesto 868 1.17 151 1019

California Sacramento 868 1.19 164 1032

California San Francisco 868 1.31 268 1136

Colorado Denver 868 0.98 (20) 848

Connecticut Hartford 868 1.13 109 977

Delaware Dover 868 1.12 104 972

District of Columbia Washington 868 1.03 23 891

Florida Tallahassee 868 0.95 (42) 826

Florida Tampa 868 0.96 (32) 836

Georgia Atlanta 868 1.00 3 871

Idaho Boise 868 1.01 12 880

Illinois Chicago 868 1.22 194 1062

Indiana Indianapolis 868 1.00 (4) 864

Iowa Davenport 868 1.02 16 884

Iowa Waterloo 868 0.98 (18) 850

Kansas Wichita 868 0.98 (19) 849

Kentucky Louisville 868 1.00 (3) 865

Louisiana New Orleans 868 0.99 (7) 861

Maine Portland 868 1.01 10 878

Maryland Baltimore 868 1.01 10 878

Massachusetts Boston 868 1.20 173 1041

Michigan Detroit 868 1.08 66 934

Michigan Grand Rapids 868 1.00 2 870

Minnesota Saint Paul 868 1.09 76 944

Mississippi Biloxi 868 0.96 (36) 832

Missouri St. Louis 868 1.08 73 941

Missouri Kansas City 868 1.05 40 908

Montana Great Falls 868 0.98 (15) 853

Nebraska Omaha 868 0.98 (18) 850

New Hampshire Manchester 868 1.03 22 890

New Jersey Newark 868 1.21 184 1052

New Mexico Albuquerque 868 1.01 10 878

New York New York 868 1.39 341 1209

New York Syracuse 868 1.05 42 910

Nevada Las Vegas 868 1.11 97 965

North Carolina Charlotte 868 0.98 (14) 854

North Dakota Bismarck 868 1.02 16 884

Ohio Cincinnati 868 0.98 (20) 848

Oklahoma Oklahoma City 868 0.96 (34) 834

Oregon Portland 868 1.10 90 958

Pennsylvania Philadelphia 868 1.20 174 1042

Pennsylvania Scranton 868 1.04 30 898

Rhode Island Providence 868 1.10 85 953

South Carolina Charleston 868 0.96 (32) 836

South Dakota Rapid City 868 0.99 (6) 862

Tennessee Nashville 868 0.99 (5) 863

Texas Houston 868 0.93 (61) 807

Utah Salt Lake City 868 0.99 (9) 859

Vermont Burlington 868 1.04 37 905

Virginia Alexandria 868 1.01 10 878

Virginia Roanoke 868 0.98 (16) 852

Washington Seattle 868 1.16 138 1006

Washington Spokane 868 1.04 31 899

West Virginia Charleston 868 1.01 10 878

Wisconsin Green Bay 868 1.07 56 924

Wyoming Cheyenne 868 0.99 (9) 859
Table 1‐6 — Location Adjustment for Combined-Cycle 1x1x1, Single Shaft 

(2023 USD)

Case Configuration: 627 MW Net, 1 x 1 H Class Combined Cycle

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 921 0.97 (29) 892

Arizona Phoenix 921 1.01 10 931

Arkansas Little Rock 921 0.97 (27) 894

California Bakersfield 921 1.14 133 1054

California Los Angeles 921 1.17 156 1077

California Modesto 921 1.17 154 1075

California Sacramento 921 1.18 168 1089

California San Francisco 921 1.30 277 1198

Colorado Denver 921 0.98 (20) 901

Connecticut Hartford 921 1.12 113 1034

Delaware Dover 921 1.12 111 1032

District of Columbia Washington 921 1.03 24 945

Florida Tallahassee 921 0.95 (44) 877

Florida Tampa 921 0.96 (34) 887

Georgia Atlanta 921 1.00 1 922

Idaho Boise 921 1.01 12 933

Illinois Chicago 921 1.22 204 1125

Indiana Indianapolis 921 0.99 (6) 915

Iowa Davenport 921 1.02 18 939

Iowa Waterloo 921 0.98 (19) 902

Kansas Wichita 921 0.98 (20) 901

Kentucky Louisville 921 1.00 (5) 916

Louisiana New Orleans 921 0.99 (10) 911

Maine Portland 921 1.01 10 931

Maryland Baltimore 921 1.01 10 931

Massachusetts Boston 921 1.20 180 1101

Michigan Detroit 921 1.08 69 990

Michigan Grand Rapids 921 1.00 2 923

Minnesota Saint Paul 921 1.09 82 1003

Mississippi Biloxi 921 0.96 (37) 884

Missouri St. Louis 921 1.08 72 993

Missouri Kansas City 921 1.05 42 963

Montana Great Falls 921 0.98 (15) 906

Nebraska Omaha 921 0.98 (19) 902

New Hampshire Manchester 921 1.02 20 941

New Jersey Newark 921 1.21 193 1114

New Mexico Albuquerque 921 1.01 7 928

New York New York 921 1.39 356 1277

New York Syracuse 921 1.05 44 965

Nevada Las Vegas 921 1.11 98 1019

North Carolina Charlotte 921 0.98 (14) 907

North Dakota Bismarck 921 1.02 20 941

Ohio Cincinnati 921 0.98 (20) 901

Oklahoma Oklahoma City 921 0.96 (35) 886

Oregon Portland 921 1.10 91 1012

Pennsylvania Philadelphia 921 1.20 182 1103

Pennsylvania Scranton 921 1.03 32 953

Rhode Island Providence 921 1.10 88 1009

South Carolina Charleston 921 0.96 (41) 880

South Dakota Rapid City 921 1.00 (4) 917

Tennessee Nashville 921 0.99 (9) 912

Texas Houston 921 0.93 (64) 857

Utah Salt Lake City 921 0.99 (13) 908

Vermont Burlington 921 1.03 31 952

Virginia Alexandria 921 1.01 10 931

Virginia Roanoke 921 0.98 (16) 905

Washington Seattle 921 1.15 140 1061

Washington Spokane 921 1.03 31 952

West Virginia Charleston 921 1.01 11 932

Wisconsin Green Bay 921 1.07 62 983

Wyoming Cheyenne 921 0.99 (8) 913
Table 1‐7 — Location Adjustment for Combined Cycle 1x1x1, Single Shaft 95% Carbon Capture 

(2023 USD)

Case Configuration: 543 MW Net, 1 x 1 H Class Combined Cycle

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 2,365 0.96 (92) 2273

Arizona Phoenix 2,365 1.01 32 2397

Arkansas Little Rock 2,365 0.96 (90) 2275

California Bakersfield 2,365 1.18 417 2782

California Los Angeles 2,365 1.21 488 2853

California Modesto 2,365 1.20 481 2846

California Sacramento 2,365 1.22 526 2891

California San Francisco 2,365 1.37 870 3235

Colorado Denver 2,365 0.97 (60) 2305

Connecticut Hartford 2,365 1.15 357 2722

Delaware Dover 2,365 1.15 352 2717

District of Columbia Washington 2,365 1.03 75 2440

Florida Tallahassee 2,365 0.94 (138) 2227

Florida Tampa 2,365 0.95 (107) 2258

Georgia Atlanta 2,365 1.00 3 2368

Idaho Boise 2,365 1.02 37 2402

Illinois Chicago 2,365 1.27 643 3008

Indiana Indianapolis 2,365 0.99 (20) 2345

Iowa Davenport 2,365 1.02 56 2421

Iowa Waterloo 2,365 0.98 (58) 2307

Kansas Wichita 2,365 0.97 (61) 2304

Kentucky Louisville 2,365 0.99 (16) 2349

Louisiana New Orleans 2,365 0.99 (35) 2330

Maine Portland 2,365 1.01 32 2397

Maryland Baltimore 2,365 1.01 32 2397

Massachusetts Boston 2,365 1.24 566 2931

Michigan Detroit 2,365 1.09 219 2584

Michigan Grand Rapids 2,365 1.00 8 2373

Minnesota Saint Paul 2,365 1.11 262 2627

Mississippi Biloxi 2,365 0.95 (117) 2248

Missouri St. Louis 2,365 1.09 222 2587

Missouri Kansas City 2,365 1.06 135 2500

Montana Great Falls 2,365 0.98 (46) 2319

Nebraska Omaha 2,365 0.97 (60) 2305

New Hampshire Manchester 2,365 1.03 60 2425

New Jersey Newark 2,365 1.26 607 2972

New Mexico Albuquerque 2,365 1.01 18 2383

New York New York 2,365 1.47 1,123 3488

New York Syracuse 2,365 1.06 141 2506

Nevada Las Vegas 2,365 1.13 307 2672

North Carolina Charlotte 2,365 0.98 (45) 2320

North Dakota Bismarck 2,365 1.03 65 2430

Ohio Cincinnati 2,365 0.97 (61) 2304

Oklahoma Oklahoma City 2,365 0.95 (109) 2256

Oregon Portland 2,365 1.12 283 2648

Pennsylvania Philadelphia 2,365 1.24 573 2938

Pennsylvania Scranton 2,365 1.04 100 2465

Rhode Island Providence 2,365 1.12 275 2640

South Carolina Charleston 2,365 0.94 (140) 2225

South Dakota Rapid City 2,365 1.00 (8) 2357

Tennessee Nashville 2,365 0.99 (34) 2331

Texas Houston 2,365 0.91 (202) 2163

Utah Salt Lake City 2,365 0.98 (45) 2320

Vermont Burlington 2,365 1.04 89 2454

Virginia Alexandria 2,365 1.01 32 2397

Virginia Roanoke 2,365 0.98 (51) 2314

Washington Seattle 2,365 1.18 437 2802

Washington Spokane 2,365 1.04 95 2460

West Virginia Charleston 2,365 1.02 37 2402

Wisconsin Green Bay 2,365 1.08 199 2564

Wyoming Cheyenne 2,365 0.99 (22) 2343
Table 1‐8 — Location Adjustment for Bio Energy 95% Carbon Capture 

(2023 USD)

Case Configuration: 50 MW Net, 1 x 65.5 MW Gross Woody Biomass Bubbling Fluidized Bed

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 12,631 0.96 (527) 12104

Arizona Phoenix 12,631 1.01 161 12792

Arkansas Little Rock 12,631 0.96 (492) 12139

California Bakersfield 12,631 1.19 2,375 15006

California Los Angeles 12,631 1.23 2,903 15534

California Modesto 12,631 1.21 2,639 15270

California Sacramento 12,631 1.24 2,986 15617

California San Francisco 12,631 1.40 5,046 17677

Colorado Denver 12,631 0.98 (294) 12337

Connecticut Hartford 12,631 1.17 2,165 14796

Delaware Dover 12,631 1.16 1,961 14592

District of Columbia Washington 12,631 1.05 588 13219

Florida Tallahassee 12,631 0.94 (814) 11817

Florida Tampa 12,631 0.95 (686) 11945

Georgia Atlanta 12,631 1.00 (32) 12599

Idaho Boise 12,631 1.02 293 12924

Illinois Chicago 12,631 1.29 3,679 16310

Indiana Indianapolis 12,631 1.00 41 12672

Iowa Davenport 12,631 1.03 354 12985

Iowa Waterloo 12,631 0.99 (167) 12464

Kansas Wichita 12,631 0.99 (148) 12483

Kentucky Louisville 12,631 1.00 (50) 12581

Louisiana New Orleans 12,631 0.99 (152) 12479

Maine Portland 12,631 1.01 165 12796

Maryland Baltimore 12,631 1.03 386 13017

Massachusetts Boston 12,631 1.26 3,259 15890

Michigan Detroit 12,631 1.10 1,203 13834

Michigan Grand Rapids 12,631 1.01 93 12724

Minnesota Saint Paul 12,631 1.11 1,433 14064

Mississippi Biloxi 12,631 0.94 (725) 11906

Missouri St. Louis 12,631 1.11 1,450 14081

Missouri Kansas City 12,631 1.06 801 13432

Montana Great Falls 12,631 0.98 (256) 12375

Nebraska Omaha 12,631 0.99 (170) 12461

New Hampshire Manchester 12,631 1.04 471 13102

New Jersey Newark 12,631 1.27 3,456 16087

New Mexico Albuquerque 12,631 1.01 164 12795

New York New York 12,631 1.52 6,576 19207

New York Syracuse 12,631 1.07 858 13489

Nevada Las Vegas 12,631 1.13 1,695 14326

North Carolina Charlotte 12,631 0.98 (306) 12325

North Dakota Bismarck 12,631 1.03 365 12996

Ohio Cincinnati 12,631 0.97 (357) 12274

Oklahoma Oklahoma City 12,631 0.95 (664) 11967

Oregon Portland 12,631 1.13 1,700 14331

Pennsylvania Philadelphia 12,631 1.27 3,356 15987

Pennsylvania Scranton 12,631 1.06 776 13407

Rhode Island Providence 12,631 1.13 1,589 14220

South Carolina Charleston 12,631 0.94 (747) 11884

South Dakota Rapid City 12,631 0.99 (74) 12557

Tennessee Nashville 12,631 0.99 (178) 12453

Texas Houston 12,631 0.90 (1,202) 11429

Utah Salt Lake City 12,631 0.99 (184) 12447

Vermont Burlington 12,631 1.06 757 13388

Virginia Alexandria 12,631 1.02 310 12941

Virginia Roanoke 12,631 0.98 (262) 12369

Washington Seattle 12,631 1.20 2,499 15130

Washington Spokane 12,631 1.05 575 13206

West Virginia Charleston 12,631 1.01 171 12802

Wisconsin Green Bay 12,631 1.09 1,090 13721

Wyoming Cheyenne 12,631 0.99 (153) 12478
Table 1‐9 — Location Adjustment for Advanced Nuclear (Brownfield) 

(2023 USD)

Case Configuration: 2156 MW Net, 2 x AP1000

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 7,861 1.01 68 7929

Arizona Phoenix 7,861 1.00 (18) 7843

Arkansas Little Rock 7,861 1.04 328 8189

California Bakersfield 7,861 1.18 1,384 9245

California Los Angeles 7,861 1.19 1,499 9360

California Modesto 7,861 1.20 1,567 9428

California Sacramento 7,861 1.21 1,628 9489

California San Francisco 7,861 1.26 2,053 9914

Colorado Denver 7,861 0.98 (191) 7670

Connecticut Hartford 7,861 1.12 926 8787

Delaware Dover 7,861 1.06 488 8349

District of Columbia Washington 7,861 1.02 179 8040

Florida Tallahassee 7,861 0.97 (253) 7608

Florida Tampa 7,861 0.98 (129) 7732

Georgia Atlanta 7,861 1.04 287 8148

Idaho Boise 7,861 1.03 272 8133

Illinois Chicago 7,861 1.19 1,464 9325

Indiana Indianapolis 7,861 1.03 265 8126

Iowa Davenport 7,861 1.02 189 8050

Iowa Waterloo 7,861 0.99 (48) 7813

Kansas Wichita 7,861 0.99 (74) 7787

Kentucky Louisville 7,861 1.03 271 8132

Louisiana New Orleans 7,861 1.05 376 8237

Maine Portland 7,861 1.03 219 8080

Maryland Baltimore 7,861 1.02 169 8030

Massachusetts Boston 7,861 1.17 1,352 9213

Michigan Detroit 7,861 1.06 452 8313

Michigan Grand Rapids 7,861 1.01 49 7910

Minnesota Saint Paul 7,861 1.04 279 8140

Mississippi Biloxi 7,861 0.97 (241) 7620

Missouri St. Louis 7,861 1.14 1,099 8960

Missouri Kansas City 7,861 1.04 310 8171

Montana Great Falls 7,861 0.98 (134) 7727

Nebraska Omaha 7,861 0.99 (44) 7817

New Hampshire Manchester 7,861 1.07 581 8442

New Jersey Newark 7,861 1.17 1,344 9205

New Mexico Albuquerque 7,861 1.07 546 8407

New York New York 7,861 1.33 2,567 10428

New York Syracuse 7,861 1.04 304 8165

Nevada Las Vegas 7,861 1.14 1,118 8979

North Carolina Charlotte 7,861 0.99 (72) 7789

North Dakota Bismarck 7,861 0.99 (83) 7778

Ohio Cincinnati 7,861 0.98 (152) 7709

Oklahoma Oklahoma City 7,861 0.97 (248) 7613

Oregon Portland 7,861 1.13 1,013 8874

Pennsylvania Philadelphia 7,861 1.15 1,193 9054

Pennsylvania Scranton 7,861 1.04 300 8161

Rhode Island Providence 7,861 1.11 861 8722

South Carolina Charleston 7,861 1.09 728 8589

South Dakota Rapid City 7,861 0.97 (271) 7590

Tennessee Nashville 7,861 1.06 444 8305

Texas Houston 7,861 0.95 (371) 7490

Utah Salt Lake City 7,861 1.06 435 8296

Vermont Burlington 7,861 1.16 1,262 9123

Virginia Alexandria 7,861 1.01 105 7966

Virginia Roanoke 7,861 0.99 (97) 7764

Washington Seattle 7,861 1.17 1,344 9205

Washington Spokane 7,861 1.06 501 8362

West Virginia Charleston 7,861 1.01 76 7937

Wisconsin Green Bay 7,861 1.01 86 7947

Wyoming Cheyenne 7,861 0.98 (132) 7729
Table 1‐10 — Location Adjustment for Small Modular Reactor Nuclear Power Plant 

(2023 USD)

Case Configuration: 480 MW Net, 6 x 80 MW Small Modular Reactor

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 8,936 0.99 (76) 8860

Arizona Phoenix 8,936 1.01 60 8996

Arkansas Little Rock 8,936 1.00 26 8962

California Bakersfield 8,936 1.13 1,193 10129

California Los Angeles 8,936 1.15 1,305 10241

California Modesto 8,936 1.15 1,364 10300

California Sacramento 8,936 1.16 1,442 10378

California San Francisco 8,936 1.21 1,897 10833

Colorado Denver 8,936 0.98 (148) 8788

Connecticut Hartford 8,936 1.10 912 9848

Delaware Dover 8,936 1.07 668 9604

District of Columbia Washington 8,936 1.02 153 9089

Florida Tallahassee 8,936 0.97 (288) 8648

Florida Tampa 8,936 0.98 (190) 8746

Georgia Atlanta 8,936 1.02 157 9093

Idaho Boise 8,936 1.02 186 9122

Illinois Chicago 8,936 1.18 1,579 10515

Indiana Indianapolis 8,936 1.01 123 9059

Iowa Davenport 8,936 1.02 213 9149

Iowa Waterloo 8,936 0.99 (55) 8881

Kansas Wichita 8,936 0.99 (69) 8867

Kentucky Louisville 8,936 1.01 130 9066

Louisiana New Orleans 8,936 1.02 139 9075

Maine Portland 8,936 1.02 180 9116

Maryland Baltimore 8,936 1.02 143 9079

Massachusetts Boston 8,936 1.15 1,327 10263

Michigan Detroit 8,936 1.06 493 9429

Michigan Grand Rapids 8,936 1.01 62 8998

Minnesota Saint Paul 8,936 1.05 474 9410

Mississippi Biloxi 8,936 0.97 (252) 8684

Missouri St. Louis 8,936 1.09 792 9728

Missouri Kansas City 8,936 1.04 331 9267

Montana Great Falls 8,936 0.99 (105) 8831

Nebraska Omaha 8,936 0.99 (56) 8880

New Hampshire Manchester 8,936 1.04 368 9304

New Jersey Newark 8,936 1.15 1,383 10319

New Mexico Albuquerque 8,936 1.03 298 9234

New York New York 8,936 1.30 2,683 11619

New York Syracuse 8,936 1.04 326 9262

Nevada Las Vegas 8,936 1.10 905 9841

North Carolina Charlotte 8,936 0.99 (76) 8860

North Dakota Bismarck 8,936 1.01 92 9028

Ohio Cincinnati 8,936 0.99 (126) 8810

Oklahoma Oklahoma City 8,936 0.97 (246) 8690

Oregon Portland 8,936 1.09 794 9730

Pennsylvania Philadelphia 8,936 1.14 1,222 10158

Pennsylvania Scranton 8,936 1.03 302 9238

Rhode Island Providence 8,936 1.09 773 9709

South Carolina Charleston 8,936 1.02 143 9079

South Dakota Rapid City 8,936 0.99 (112) 8824

Tennessee Nashville 8,936 1.02 142 9078

Texas Houston 8,936 0.95 (423) 8513

Utah Salt Lake City 8,936 1.02 155 9091

Vermont Burlington 8,936 1.08 717 9653

Virginia Alexandria 8,936 1.01 75 9011

Virginia Roanoke 8,936 0.99 (98) 8838

Washington Seattle 8,936 1.12 1,104 10040

Washington Spokane 8,936 1.04 392 9328

West Virginia Charleston 8,936 1.01 98 9034

Wisconsin Green Bay 8,936 1.03 312 9248

Wyoming Cheyenne 8,936 0.99 (67) 8869
Table 1‐11 — Location Adjustment for Geothermal 

(2023 USD)

Case Configuration: 50 MW Net, Binary Cycle

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville N/A N/A N/A N/A

Arizona Phoenix N/A N/A N/A N/A

Arkansas Little Rock N/A N/A N/A N/A

California Bakersfield 3,963 1.14 535 4,498

California Los Angeles 3,963 1.16 625 4,588

California Modesto 3,963 1.15 606 4,569

California Sacramento 3,963 1.17 656 4,619

California San Francisco 3,963 1.24 934 4,897

Colorado Denver N/A N/A N/A N/A

Connecticut Hartford N/A N/A N/A N/A

Delaware Dover N/A N/A N/A N/A

District of Columbia Washington N/A N/A N/A N/A

Florida Tallahassee N/A N/A N/A N/A

Florida Tampa N/A N/A N/A N/A

Georgia Atlanta N/A N/A N/A N/A

Idaho Boise 3,963 1.02 82 4,045

Illinois Chicago N/A N/A N/A N/A

Indiana Indianapolis N/A N/A N/A N/A

Iowa Davenport N/A N/A N/A N/A

Iowa Waterloo N/A N/A N/A N/A

Kansas Wichita N/A N/A N/A N/A

Kentucky Louisville N/A N/A N/A N/A

Louisiana New Orleans N/A N/A N/A N/A

Maine Portland N/A N/A N/A N/A

Maryland Baltimore N/A N/A N/A N/A

Massachusetts Boston N/A N/A N/A N/A

Michigan Detroit N/A N/A N/A N/A

Michigan Grand Rapids N/A N/A N/A N/A

Minnesota Saint Paul N/A N/A N/A N/A

Mississippi Biloxi N/A N/A N/A N/A

Missouri St. Louis N/A N/A N/A N/A

Missouri Kansas City N/A N/A N/A N/A

Montana Great Falls N/A N/A N/A N/A

Nebraska Omaha N/A N/A N/A N/A

New Hampshire Manchester N/A N/A N/A N/A

New Jersey Newark N/A N/A N/A N/A

New Mexico Albuquerque N/A N/A N/A N/A

New York New York N/A N/A N/A N/A

New York Syracuse N/A N/A N/A N/A

Nevada Las Vegas 3,963 1.10 395 4,358

North Carolina Charlotte N/A N/A N/A N/A

North Dakota Bismarck N/A N/A N/A N/A

Ohio Cincinnati N/A N/A N/A N/A

Oklahoma Oklahoma City N/A N/A N/A N/A

Oregon Portland 3,963 1.09 353 4,316

Pennsylvania Philadelphia N/A N/A N/A N/A

Pennsylvania Scranton N/A N/A N/A N/A

Rhode Island Providence N/A N/A N/A N/A

South Carolina Charleston N/A N/A N/A N/A

South Dakota Rapid City N/A N/A N/A N/A

Tennessee Nashville N/A N/A N/A N/A

Texas Houston N/A N/A N/A N/A

Utah Salt Lake City N/A N/A N/A N/A

Vermont Burlington N/A N/A N/A N/A

Virginia Alexandria N/A N/A N/A N/A

Virginia Roanoke N/A N/A N/A N/A

Washington Seattle 3,963 1.13 512 4,475

Washington Spokane 3,963 1.03 138 4,101

West Virginia Charleston N/A N/A N/A N/A

Wisconsin Green Bay N/A N/A N/A N/A

Wyoming Cheyenne N/A N/A N/A N/A
Table 1‐12 — Location Adjustment for Hydroelectric Power Plant 

(2023 USD)

Case Configuration: 100 MW Net, New Stream Reach Development

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville N/A N/A N/A N/A

Arizona Phoenix N/A N/A N/A N/A

Arkansas Little Rock N/A N/A N/A N/A

California Bakersfield 7,073 1.18 1,254 8327

California Los Angeles 7,073 1.19 1,366 8439

California Modesto 7,073 1.20 1,428 8501

California Sacramento 7,073 1.21 1,498 8571

California San Francisco 7,073 1.27 1,937 9010

Colorado Denver 7,073 0.98 (162) 6911

Connecticut Hartford 7,073 1.13 904 7977

Delaware Dover N/A N/A N/A N/A

District of Columbia Washington N/A N/A N/A N/A

Florida Tallahassee N/A N/A N/A N/A

Florida Tampa N/A N/A N/A N/A

Georgia Atlanta N/A N/A N/A N/A

Idaho Boise 7,073 1.03 216 7289

Illinois Chicago N/A N/A N/A N/A

Indiana Indianapolis N/A N/A N/A N/A

Iowa Davenport N/A N/A N/A N/A

Iowa Waterloo N/A N/A N/A N/A

Kansas Wichita N/A N/A N/A N/A

Kentucky Louisville N/A N/A N/A N/A

Louisiana New Orleans N/A N/A N/A N/A

Maine Portland 7,073 1.03 192 7265

Maryland Baltimore N/A N/A N/A N/A

Massachusetts Boston N/A N/A N/A N/A

Michigan Detroit N/A N/A N/A N/A

Michigan Grand Rapids N/A N/A N/A N/A

Minnesota Saint Paul N/A N/A N/A N/A

Mississippi Biloxi N/A N/A N/A N/A

Missouri St. Louis 7,073 1.13 903 7976

Missouri Kansas City 7,073 1.04 318 7391

Montana Great Falls 7,073 0.98 (115) 6958

Nebraska Omaha N/A N/A N/A N/A

New Hampshire Manchester N/A N/A N/A N/A

New Jersey Newark N/A N/A N/A N/A

New Mexico Albuquerque N/A N/A N/A N/A

New York New York N/A N/A N/A N/A

New York Syracuse N/A N/A N/A N/A

Nevada Las Vegas 7,073 1.14 978 8051

North Carolina Charlotte N/A N/A N/A N/A

North Dakota Bismarck N/A N/A N/A N/A

Ohio Cincinnati 7,073 0.98 (134) 6939

Oklahoma Oklahoma City N/A N/A N/A N/A

Oregon Portland 7,073 1.12 870 7943

Pennsylvania Philadelphia N/A N/A N/A N/A

Pennsylvania Scranton N/A N/A N/A N/A

Rhode Island Providence N/A N/A N/A N/A

South Carolina Charleston N/A N/A N/A N/A

South Dakota Rapid City 7,073 0.98 (173) 6900

Tennessee Nashville N/A N/A N/A N/A

Texas Houston N/A N/A N/A N/A

Utah Salt Lake City N/A N/A N/A N/A

Vermont Burlington N/A N/A N/A N/A

Virginia Alexandria N/A N/A N/A N/A

Virginia Roanoke N/A N/A N/A N/A

Washington Seattle 7,073 1.17 1,186 8259

Washington Spokane 7,073 1.06 429 7502

West Virginia Charleston N/A N/A N/A N/A

Wisconsin Green Bay N/A N/A N/A N/A

Wyoming Cheyenne N/A N/A N/A N/A
Table 1‐13 — Location Adjustment for Onshore Wind – Large Plant Footprint: Great Plains Region 

(2023 USD)

Case Configuration: 200 MW Net, 200 MW | 2.82 MW WTG

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,489 0.99 (18) 1471

Arizona Phoenix 1,489 1.00 (8) 1481

Arkansas Little Rock 1,489 1.00 5 1494

California Bakersfield 1,489 1.15 218 1707

California Los Angeles 1,489 1.18 274 1763

California Modesto 1,489 1.16 244 1733

California Sacramento 1,489 1.18 268 1757

California San Francisco 1,489 1.28 420 1909

Colorado Denver 1,489 0.98 (31) 1458

Connecticut Hartford 1,489 1.11 167 1656

Delaware Dover 1,489 1.07 102 1591

District of Columbia Washington 1,489 1.03 38 1527

Florida Tallahassee 1,489 0.96 (54) 1435

Florida Tampa 1,489 0.97 (38) 1451

Georgia Atlanta 1,489 1.01 16 1505

Idaho Boise 1,489 1.02 34 1523

Illinois Chicago 1,489 1.20 304 1793

Indiana Indianapolis 1,489 1.02 26 1515

Iowa Davenport 1,489 1.02 24 1513

Iowa Waterloo 1,489 0.98 (24) 1465

Kansas Wichita 1,489 0.98 (27) 1462

Kentucky Louisville 1,489 1.01 12 1501

Louisiana New Orleans 1,489 1.02 23 1512

Maine Portland 1,489 1.01 17 1506

Maryland Baltimore 1,489 1.01 15 1504

Massachusetts Boston 1,489 1.18 273 1762

Michigan Detroit 1,489 1.06 92 1581

Michigan Grand Rapids 1,489 1.00 1 1490

Minnesota Saint Paul 1,489 1.07 104 1593

Mississippi Biloxi 1,489 0.97 (51) 1438

Missouri St. Louis 1,489 1.10 152 1641

Missouri Kansas City 1,489 1.04 60 1549

Montana Great Falls 1,489 0.98 (25) 1464

Nebraska Omaha 1,489 0.98 (26) 1463

New Hampshire Manchester 1,489 1.04 54 1543

New Jersey Newark 1,489 1.19 284 1773

New Mexico Albuquerque 1,489 1.02 33 1522

New York New York 1,489 1.34 501 1990

New York Syracuse 1,489 1.05 78 1567

Nevada Las Vegas 1,489 1.12 181 1670

North Carolina Charlotte 1,489 0.99 (21) 1468

North Dakota Bismarck 1,489 1.00 2 1491

Ohio Cincinnati 1,489 0.98 (34) 1455

Oklahoma Oklahoma City 1,489 0.97 (47) 1442

Oregon Portland 1,489 1.11 161 1650

Pennsylvania Philadelphia 1,489 1.18 265 1754

Pennsylvania Scranton 1,489 1.03 41 1530

Rhode Island Providence 1,489 1.09 140 1629

South Carolina Charleston 1,489 1.01 20 1509

South Dakota Rapid City 1,489 0.99 (21) 1468

Tennessee Nashville 1,489 1.02 23 1512

Texas Houston 1,489 0.95 (81) 1408

Utah Salt Lake City 1,489 1.01 14 1503

Vermont Burlington 1,489 1.07 105 1594

Virginia Alexandria 1,489 1.02 25 1514

Virginia Roanoke 1,489 0.98 (24) 1465

Washington Seattle 1,489 1.16 238 1727

Washington Spokane 1,489 1.04 56 1545

West Virginia Charleston 1,489 1.00 6 1495

Wisconsin Green Bay 1,489 1.05 76 1565

Wyoming Cheyenne 1,489 0.98 (26) 1463
Table 1‐14 — Location Adjustment for Onshore Wind Repowering/Retrofit 

(2023 USD)

Case Configuration: 150 MW Net, 150 MW | 1.5-1.62 MW WTG

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,386 1.00 (3) 1383

Arizona Phoenix 1,386 0.99 (9) 1377

Arkansas Little Rock 1,386 1.01 21 1407

California Bakersfield 1,386 1.11 148 1534

California Los Angeles 1,386 1.13 182 1568

California Modesto 1,386 1.12 165 1551

California Sacramento 1,386 1.13 179 1565

California San Francisco 1,386 1.20 271 1657

Colorado Denver 1,386 0.98 (22) 1364

Connecticut Hartford 1,386 1.08 106 1492

Delaware Dover 1,386 1.04 56 1442

District of Columbia Washington 1,386 1.02 25 1411

Florida Tallahassee 1,386 0.98 (32) 1354

Florida Tampa 1,386 0.99 (20) 1366

Georgia Atlanta 1,386 1.01 18 1404

Idaho Boise 1,386 1.02 27 1413

Illinois Chicago 1,386 1.13 186 1572

Indiana Indianapolis 1,386 1.02 24 1410

Iowa Davenport 1,386 1.01 15 1401

Iowa Waterloo 1,386 0.99 (15) 1371

Kansas Wichita 1,386 0.99 (17) 1369

Kentucky Louisville 1,386 1.01 16 1402

Louisiana New Orleans 1,386 1.02 28 1414

Maine Portland 1,386 1.01 13 1399

Maryland Baltimore 1,386 1.01 11 1397

Massachusetts Boston 1,386 1.12 173 1559

Michigan Detroit 1,386 1.04 56 1442

Michigan Grand Rapids 1,386 1.00 0 1386

Minnesota Saint Paul 1,386 1.04 55 1441

Mississippi Biloxi 1,386 0.98 (32) 1354

Missouri St. Louis 1,386 1.08 113 1499

Missouri Kansas City 1,386 1.03 37 1423

Montana Great Falls 1,386 0.99 (17) 1369

Nebraska Omaha 1,386 0.99 (16) 1370

New Hampshire Manchester 1,386 1.03 46 1432

New Jersey Newark 1,386 1.13 177 1563

New Mexico Albuquerque 1,386 1.03 35 1421

New York New York 1,386 1.22 310 1696

New York Syracuse 1,386 1.03 48 1434

Nevada Las Vegas 1,386 1.09 125 1511

North Carolina Charlotte 1,386 0.99 (13) 1373

North Dakota Bismarck 1,386 0.99 (8) 1378

Ohio Cincinnati 1,386 0.98 (22) 1364

Oklahoma Oklahoma City 1,386 0.98 (30) 1356

Oregon Portland 1,386 1.08 114 1500

Pennsylvania Philadelphia 1,386 1.12 165 1551

Pennsylvania Scranton 1,386 1.02 26 1412

Rhode Island Providence 1,386 1.07 93 1479

South Carolina Charleston 1,386 1.03 48 1434

South Dakota Rapid City 1,386 0.98 (22) 1364

Tennessee Nashville 1,386 1.02 32 1418

Texas Houston 1,386 0.97 (48) 1338

Utah Salt Lake City 1,386 1.02 25 1411

Vermont Burlington 1,386 1.07 97 1483

Virginia Alexandria 1,386 1.01 18 1404

Virginia Roanoke 1,386 0.99 (15) 1371

Washington Seattle 1,386 1.12 162 1548

Washington Spokane 1,386 1.03 42 1428

West Virginia Charleston 1,386 1.00 3 1389

Wisconsin Green Bay 1,386 1.03 36 1422

Wyoming Cheyenne 1,386 0.99 (20) 1366
Table 1‐15 — Location Adjustment for Fixed-bottom Offshore Wind: 

Monopile Foundations

Case Configuration: 900 MW Net, 900 MW | 15 MW WTG

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville N/A N/A N/A N/A

Arizona Phoenix N/A N/A N/A N/A

Arkansas Little Rock N/A N/A N/A N/A

California Bakersfield 3,689 1.15 542 4231

California Los Angeles 3,689 1.18 674 4363

California Modesto 3,689 1.16 606 4295

California Sacramento 3,689 1.18 660 4349

California San Francisco 3,689 1.27 1,012 4701

Colorado Denver N/A N/A N/A N/A

Connecticut Hartford 3,689 1.11 397 4086

Delaware Dover 3,689 1.06 218 3907

District of Columbia Washington N/A N/A N/A N/A

Florida Tallahassee N/A N/A N/A N/A

Florida Tampa N/A N/A N/A N/A

Georgia Atlanta 3,689 1.02 57 3746

Idaho Boise N/A N/A N/A N/A

Illinois Chicago 3,689 1.19 703 4392

Indiana Indianapolis N/A N/A N/A N/A

Iowa Davenport N/A N/A N/A N/A

Iowa Waterloo N/A N/A N/A N/A

Kansas Wichita N/A N/A N/A N/A

Kentucky Louisville N/A N/A N/A N/A

Louisiana New Orleans N/A N/A N/A N/A

Maine Portland 3,689 1.01 47 3736

Maryland Baltimore 3,689 1.01 41 3730

Massachusetts Boston 3,689 1.18 647 4336

Michigan Detroit 3,689 1.06 212 3901

Michigan Grand Rapids 3,689 1.00 1 3690

Minnesota Saint Paul 3,689 1.06 218 3907

Mississippi Biloxi N/A N/A N/A N/A

Missouri St. Louis N/A N/A N/A N/A

Missouri Kansas City N/A N/A N/A N/A

Montana Great Falls N/A N/A N/A N/A

Nebraska Omaha N/A N/A N/A N/A

New Hampshire Manchester N/A N/A N/A N/A

New Jersey Newark 3,689 1.18 664 4353

New Mexico Albuquerque N/A N/A N/A N/A

New York New York 3,689 1.32 1,168 4857

New York Syracuse 3,689 1.05 181 3870

Nevada Las Vegas N/A N/A N/A N/A

North Carolina Charlotte 3,689 0.99 (48) 3641

North Dakota Bismarck N/A N/A N/A N/A

Ohio Cincinnati N/A N/A N/A N/A

Oklahoma Oklahoma City N/A N/A N/A N/A

Oregon Portland 3,689 1.11 412 4101

Pennsylvania Philadelphia N/A N/A N/A N/A

Pennsylvania Scranton N/A N/A N/A N/A

Rhode Island Providence 3,689 1.09 344 4033

South Carolina Charleston 3,689 1.04 134 3823

South Dakota Rapid City N/A N/A N/A N/A

Tennessee Nashville N/A N/A N/A N/A

Texas Houston 3,689 0.95 (185) 3504

Utah Salt Lake City N/A N/A N/A N/A

Vermont Burlington N/A N/A N/A N/A

Virginia Alexandria 3,689 1.02 64 3753

Virginia Roanoke 3,689 0.98 (56) 3633

Washington Seattle 3,689 1.16 595 4284

Washington Spokane 3,689 1.04 150 3839

West Virginia Charleston N/A N/A N/A N/A

Wisconsin Green Bay 3,689 1.04 147 3836

Wyoming Cheyenne N/A N/A N/A N/A
Table 1‐16 — Location Adjustment for Solar PV w/ Single Axis Tracking 

(2023 USD)

Case Configuration: 150 MW Net, 150 MWAC

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,502 0.98 (22) 1480

Arizona Phoenix 1,502 1.01 11 1513

Arkansas Little Rock 1,502 0.99 (20) 1482

California Bakersfield 1,502 1.09 136 1638

California Los Angeles 1,502 1.10 150 1652

California Modesto 1,502 1.10 155 1657

California Sacramento 1,502 1.11 165 1667

California San Francisco 1,502 1.16 247 1749

Colorado Denver 1,502 0.99 (18) 1484

Connecticut Hartford 1,502 1.07 112 1614

Delaware Dover 1,502 1.07 104 1606

District of Columbia Washington 1,502 1.01 19 1521

Florida Tallahassee 1,502 0.97 (40) 1462

Florida Tampa 1,502 0.98 (29) 1473

Georgia Atlanta 1,502 1.00 7 1509

Idaho Boise 1,502 1.01 14 1516

Illinois Chicago 1,502 1.13 201 1703

Indiana Indianapolis 1,502 1.00 (2) 1500

Iowa Davenport 1,502 1.01 23 1525

Iowa Waterloo 1,502 0.99 (15) 1487

Kansas Wichita 1,502 0.99 (15) 1487

Kentucky Louisville 1,502 1.00 2 1504

Louisiana New Orleans 1,502 1.00 (3) 1499

Maine Portland 1,502 1.01 14 1516

Maryland Baltimore 1,502 1.01 11 1513

Massachusetts Boston 1,502 1.11 171 1673

Michigan Detroit 1,502 1.04 65 1567

Michigan Grand Rapids 1,502 1.00 4 1506

Minnesota Saint Paul 1,502 1.05 77 1579

Mississippi Biloxi 1,502 0.98 (33) 1469

Missouri St. Louis 1,502 1.05 74 1576

Missouri Kansas City 1,502 1.03 42 1544

Montana Great Falls 1,502 0.99 (12) 1490

Nebraska Omaha 1,502 0.99 (15) 1487

New Hampshire Manchester 1,502 1.02 24 1526

New Jersey Newark 1,502 1.12 181 1683

New Mexico Albuquerque 1,502 1.01 14 1516

New York New York 1,502 1.23 341 1843

New York Syracuse 1,502 1.03 42 1544

Nevada Las Vegas 1,502 1.07 101 1603

North Carolina Charlotte 1,502 0.99 (12) 1490

North Dakota Bismarck 1,502 1.01 21 1523

Ohio Cincinnati 1,502 0.99 (16) 1486

Oklahoma Oklahoma City 1,502 0.98 (32) 1470

Oregon Portland 1,502 1.06 87 1589

Pennsylvania Philadelphia 1,502 1.11 165 1667

Pennsylvania Scranton 1,502 1.02 32 1534

Rhode Island Providence 1,502 1.06 89 1591

South Carolina Charleston 1,502 0.98 (28) 1474

South Dakota Rapid City 1,502 1.00 (4) 1498

Tennessee Nashville 1,502 1.00 (3) 1499

Texas Houston 1,502 0.96 (58) 1444

Utah Salt Lake City 1,502 1.00 (5) 1497

Vermont Burlington 1,502 1.03 41 1543

Virginia Alexandria 1,502 1.00 7 1509

Virginia Roanoke 1,502 0.99 (14) 1488

Washington Seattle 1,502 1.09 132 1634

Washington Spokane 1,502 1.02 35 1537

West Virginia Charleston 1,502 1.01 13 1515

Wisconsin Green Bay 1,502 1.04 55 1557

Wyoming Cheyenne 1,502 1.00 (6) 1496
Table 1‐17 — Location Adjustment for Solar PV w/ Single Axis Tracking + AC Coupled Battery Storage 

(2023 USD)

Case Configuration: 150 MW Net, 150 MWAC Solar 

50 MW | 200 MWh Storage

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 2,175 0.99 (18) 2157

Arizona Phoenix 2,175 1.00 8 2183

Arkansas Little Rock 2,175 1.00 (2) 2173

California Bakersfield 2,175 1.09 191 2366

California Los Angeles 2,175 1.10 209 2384

California Modesto 2,175 1.10 216 2391

California Sacramento 2,175 1.10 227 2402

California San Francisco 2,175 1.15 331 2506

Colorado Denver 2,175 0.99 (27) 2148

Connecticut Hartford 2,175 1.07 146 2321

Delaware Dover 2,175 1.06 120 2295

District of Columbia Washington 2,175 1.01 27 2202

Florida Tallahassee 2,175 0.98 (49) 2126

Florida Tampa 2,175 0.98 (33) 2142

Georgia Atlanta 2,175 1.01 19 2194

Idaho Boise 2,175 1.01 26 2201

Illinois Chicago 2,175 1.12 251 2426

Indiana Indianapolis 2,175 1.00 9 2184

Iowa Davenport 2,175 1.01 27 2202

Iowa Waterloo 2,175 0.99 (19) 2156

Kansas Wichita 2,175 0.99 (20) 2155

Kentucky Louisville 2,175 1.01 13 2188

Louisiana New Orleans 2,175 1.01 15 2190

Maine Portland 2,175 1.01 21 2196

Maryland Baltimore 2,175 1.01 17 2192

Massachusetts Boston 2,175 1.10 222 2397

Michigan Detroit 2,175 1.04 82 2257

Michigan Grand Rapids 2,175 1.00 4 2179

Minnesota Saint Paul 2,175 1.04 84 2259

Mississippi Biloxi 2,175 0.98 (42) 2133

Missouri St. Louis 2,175 1.06 120 2295

Missouri Kansas City 2,175 1.02 53 2228

Montana Great Falls 2,175 0.99 (19) 2156

Nebraska Omaha 2,175 0.99 (18) 2157

New Hampshire Manchester 2,175 1.02 48 2223

New Jersey Newark 2,175 1.11 231 2406

New Mexico Albuquerque 2,175 1.02 37 2212

New York New York 2,175 1.20 433 2608

New York Syracuse 2,175 1.02 53 2228

Nevada Las Vegas 2,175 1.07 147 2322

North Carolina Charlotte 2,175 0.99 (15) 2160

North Dakota Bismarck 2,175 1.01 13 2188

Ohio Cincinnati 2,175 0.99 (23) 2152

Oklahoma Oklahoma City 2,175 0.98 (41) 2134

Oregon Portland 2,175 1.06 130 2305

Pennsylvania Philadelphia 2,175 1.10 211 2386

Pennsylvania Scranton 2,175 1.02 42 2217

Rhode Island Providence 2,175 1.06 122 2297

South Carolina Charleston 2,175 1.01 11 2186

South Dakota Rapid City 2,175 0.99 (18) 2157

Tennessee Nashville 2,175 1.01 20 2195

Texas Houston 2,175 0.97 (71) 2104

Utah Salt Lake City 2,175 1.01 15 2190

Vermont Burlington 2,175 1.04 97 2272

Virginia Alexandria 2,175 1.01 12 2187

Virginia Roanoke 2,175 0.99 (18) 2157

Washington Seattle 2,175 1.09 188 2363

Washington Spokane 2,175 1.02 54 2229

West Virginia Charleston 2,175 1.01 15 2190

Wisconsin Green Bay 2,175 1.02 54 2229

Wyoming Cheyenne 2,175 0.99 (13) 2162
Table 1‐18 — Location Adjustment for Solar Photovoltaic, Single-Axis Tracking (with 1.6 Inverter Loading Ratio) with Battery Hybrid 

(2023 USD)

Case Configuration: 150 MW PV DC Coupled to 50 MW/200 MWh BESS

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 2,561 0.99 (23) 2538

Arizona Phoenix 2,561 1.00 9 2570

Arkansas Little Rock 2,561 1.00 (4) 2557

California Bakersfield 2,561 1.09 230 2791

California Los Angeles 2,561 1.10 252 2813

California Modesto 2,561 1.10 261 2822

California Sacramento 2,561 1.11 274 2835

California San Francisco 2,561 1.16 400 2961

Colorado Denver 2,561 0.99 (34) 2527

Connecticut Hartford 2,561 1.07 177 2738

Delaware Dover 2,561 1.06 146 2707

District of Columbia Washington 2,561 1.01 31 2592

Florida Tallahassee 2,561 0.98 (60) 2501

Florida Tampa 2,561 0.98 (41) 2520

Georgia Atlanta 2,561 1.01 22 2583

Idaho Boise 2,561 1.01 30 2591

Illinois Chicago 2,561 1.12 305 2866

Indiana Indianapolis 2,561 1.00 9 2570

Iowa Davenport 2,561 1.01 33 2594

Iowa Waterloo 2,561 0.99 (23) 2538

Kansas Wichita 2,561 0.99 (25) 2536

Kentucky Louisville 2,561 1.01 15 2576

Louisiana New Orleans 2,561 1.01 16 2577

Maine Portland 2,561 1.01 25 2586

Maryland Baltimore 2,561 1.01 19 2580

Massachusetts Boston 2,561 1.11 269 2830

Michigan Detroit 2,561 1.04 98 2659

Michigan Grand Rapids 2,561 1.00 4 2565

Minnesota Saint Paul 2,561 1.04 102 2663

Mississippi Biloxi 2,561 0.98 (52) 2509

Missouri St. Louis 2,561 1.06 144 2705

Missouri Kansas City 2,561 1.02 63 2624

Montana Great Falls 2,561 0.99 (23) 2538

Nebraska Omaha 2,561 0.99 (23) 2538

New Hampshire Manchester 2,561 1.02 57 2618

New Jersey Newark 2,561 1.11 280 2841

New Mexico Albuquerque 2,561 1.02 43 2604

New York New York 2,561 1.21 526 3087

New York Syracuse 2,561 1.03 64 2625

Nevada Las Vegas 2,561 1.07 177 2738

North Carolina Charlotte 2,561 0.99 (19) 2542

North Dakota Bismarck 2,561 1.01 16 2577

Ohio Cincinnati 2,561 0.99 (29) 2532

Oklahoma Oklahoma City 2,561 0.98 (51) 2510

Oregon Portland 2,561 1.06 156 2717

Pennsylvania Philadelphia 2,561 1.10 256 2817

Pennsylvania Scranton 2,561 1.02 50 2611

Rhode Island Providence 2,561 1.06 147 2708

South Carolina Charleston 2,561 1.00 10 2571

South Dakota Rapid City 2,561 0.99 (22) 2539

Tennessee Nashville 2,561 1.01 22 2583

Texas Houston 2,561 0.97 (87) 2474

Utah Salt Lake City 2,561 1.01 17 2578

Vermont Burlington 2,561 1.04 114 2675

Virginia Alexandria 2,561 1.01 13 2574

Virginia Roanoke 2,561 0.99 (23) 2538

Washington Seattle 2,561 1.09 227 2788

Washington Spokane 2,561 1.03 65 2626

West Virginia Charleston 2,561 1.01 18 2579

Wisconsin Green Bay 2,561 1.03 65 2626

Wyoming Cheyenne 2,561 0.99 (16) 2545
Table 1‐19 — Location Adjustment for Battery Storage: 4 hours 

(2023 USD)

Case Configuration: 150 MW / 600 MWh

State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,744 1.01 21 1765

Arizona Phoenix 1,744 0.99 (17) 1727

Arkansas Little Rock 1,744 1.03 58 1802

California Bakersfield 1,744 1.07 126 1870

California Los Angeles 1,744 1.09 149 1893

California Modesto 1,744 1.07 130 1874

California Sacramento 1,744 1.08 136 1880

California San Francisco 1,744 1.11 187 1931

Colorado Denver 1,744 0.99 (18) 1726

Connecticut Hartford 1,744 1.05 83 1827

Delaware Dover 1,744 1.01 22 1766

District of Columbia Washington 1,744 1.01 24 1768

Florida Tallahassee 1,744 0.99 (15) 1729

Florida Tampa 1,744 1.00 (4) 1740

Georgia Atlanta 1,744 1.02 34 1778

Idaho Boise 1,744 1.02 31 1775

Illinois Chicago 1,744 1.07 121 1865

Indiana Indianapolis 1,744 1.02 37 1781

Iowa Davenport 1,744 1.01 13 1757

Iowa Waterloo 1,744 1.00 (5) 1739

Kansas Wichita 1,744 1.00 (4) 1740

Kentucky Louisville 1,744 1.02 35 1779

Louisiana New Orleans 1,744 1.03 56 1800

Maine Portland 1,744 1.01 19 1763

Maryland Baltimore 1,744 1.01 19 1763

Massachusetts Boston 1,744 1.07 123 1867

Michigan Detroit 1,744 1.02 32 1776

Michigan Grand Rapids 1,744 1.00 1 1745

Minnesota Saint Paul 1,744 1.01 15 1759

Mississippi Biloxi 1,744 0.99 (17) 1727

Missouri St. Louis 1,744 1.07 121 1865

Missouri Kansas City 1,744 1.01 25 1769

Montana Great Falls 1,744 0.99 (13) 1731

Nebraska Omaha 1,744 1.00 (4) 1740

New Hampshire Manchester 1,744 1.03 60 1804

New Jersey Newark 1,744 1.06 112 1856

New Mexico Albuquerque 1,744 1.03 61 1805

New York New York 1,744 1.12 204 1948

New York Syracuse 1,744 1.02 34 1778

Nevada Las Vegas 1,744 1.07 116 1860

North Carolina Charlotte 1,744 1.00 (5) 1739

North Dakota Bismarck 1,744 0.99 (22) 1722

Ohio Cincinnati 1,744 0.99 (17) 1727

Oklahoma Oklahoma City 1,744 0.99 (19) 1725

Oregon Portland 1,744 1.06 107 1851

Pennsylvania Philadelphia 1,744 1.06 105 1849

Pennsylvania Scranton 1,744 1.01 23 1767

Rhode Island Providence 1,744 1.04 75 1819

South Carolina Charleston 1,744 1.07 119 1863

South Dakota Rapid City 1,744 0.98 (35) 1709

Tennessee Nashville 1,744 1.04 66 1810

Texas Houston 1,744 0.99 (23) 1721

Utah Salt Lake City 1,744 1.03 60 1804

Vermont Burlington 1,744 1.08 143 1887

Virginia Alexandria 1,744 1.01 21 1765

Virginia Roanoke 1,744 1.00 (8) 1736

Washington Seattle 1,744 1.08 138 1882

Washington Spokane 1,744 1.03 44 1788

West Virginia Charleston 1,744 1.00 (1) 1743

Wisconsin Green Bay 1,744 0.99 (8) 1736

Wyoming Cheyenne 1,744 0.99 (22) 1722
U.S. Energy Information Administration and Z Federal 

Project 14987.001

SL-018001

Final – Rev A 

December 6, 2023

A P P E N D I X B . C O M B U S T I O N T U R B I N E C A P A C I T Y

A D J U S T M E N T S

Capital Cost and Performance Characteristic Estimates for Utility Scale Electric 

Power Generating Technologies 
Gas Turbine Base

LOCATION Adjustment Basis Simple Cycle Combined Cyle 4 x LM6000PF+ 1 x 7HA.03 2 x 7HA.03 

State City ASHRAE Station Alt (ft) Ave T (F) MW adj SC HR adj SC MW adj CC HR adj CC MW net HR net MW net HR net MW net ISO ISO ‐ 0 59.0 100.0% 100.0% 100.0% 100.0% 210.7 8,511 419.4 8,236 1,227.3 Alabama Huntsville 723230 624 62.2 96.6% 100.3% 97.0% 100.3% 203.5 8,538 405.0 8,262 1,190.9 Arizona Phoenix 722780 1,107 75.5 89.8% 101.7% 92.2% 101.0% 189.2 8,651 376.6 8,372 1,131.1 Arkansas Little Rock 723400 563 61.7 97.0% 100.3% 97.4% 100.2% 204.3 8,534 406.7 8,258 1,195.0 California Los Angeles 722950 97 63.4 97.9% 100.4% 98.6% 100.2% 206.3 8,548 410.6 8,272 1,209.7 California Bakersfield 723840 489 66.2 95.5% 100.7% 96.5% 100.5% 201.2 8,572 400.4 8,295 1,184.6 California Sacramento 724839 23 61.9 98.8% 100.3% 99.2% 100.1% 208.1 8,536 414.2 8,260 1,217.4 California Modesto 724926 73 63.4 98.0% 100.4% 98.6% 100.2% 206.5 8,548 411.0 8,272 1,210.7 California San Francisco 724940 8 58.3 100.3% 99.9% 100.1% 100.0% 211.3 8,505 420.5 8,230 1,229.1 California Redding 725920 497 63.2 96.6% 100.4% 97.2% 100.3% 203.6 8,547 405.2 8,271 1,193.3 Colorado Denver 725650 5,414 51.2 83.6% 99.2% 82.6% 100.7% 176.1 8,444 350.5 8,172 1,014.1 Connecticut Hartford 725087 19 52.5 102.5% 99.4% 101.6% 99.7% 216.1 8,456 430.0 8,182 1,246.4 DC Washington 745940 282 56.7 99.9% 99.8% 99.6% 99.9% 210.6 8,491 419.1 8,217 1,222.2 Delaware Dover 724088 28 56.3 101.0% 99.7% 100.6% 99.9% 212.8 8,488 423.5 8,214 1,234.4 Florida Tampa 722110 19 73.9 94.0% 101.5% 96.2% 100.7% 198.0 8,638 394.2 8,359 1,180.8 Florida Tallahassee 722140 55 68.6 96.0% 101.0% 97.4% 100.5% 202.2 8,593 402.5 8,315 1,195.5 Georgia Atlanta 722190 1,027 63.3 94.7% 100.4% 95.4% 100.4% 199.7 8,547 397.4 8,271 1,170.5 Idaho Boise 726810 2,814 53.4 92.2% 99.4% 91.4% 100.3% 194.2 8,463 386.6 8,190 1,121.9 Illinois Chicago 997338 663 50.1 101.2% 99.1% 99.9% 99.7% 213.2 8,435 424.3 8,163 1,225.5 Indiana Indianapolis 724380 790 53.9 99.2% 99.5% 98.5% 99.9% 209.1 8,467 416.1 8,194 1,208.6 Iowa Davenport 725349 753 49.7 101.0% 99.1% 99.6% 99.7% 212.8 8,432 423.5 8,159 1,222.7 Iowa Waterloo 725480 686 48.0 101.9% 98.9% 100.3% 99.6% 214.7 8,417 427.4 8,145 1,230.8 Kansas Wichita 724500 1,321 57.9 95.8% 99.9% 95.6% 100.2% 201.9 8,501 401.8 8,227 1,173.8 Kentucky Louisville 724230 488 58.6 98.4% 100.0% 98.4% 100.1% 207.5 8,507 412.9 8,233 1,207.5 Louisiana New Orleans 722316 2 69.1 96.0% 101.0% 97.5% 100.5% 202.2 8,597 402.4 8,319 1,196.2 Maine Portland 726060 45 47.2 104.6% 98.8% 102.8% 99.4% 220.3 8,410 438.5 8,139 1,261.5 Maryland Baltimore 724060 56 56.3 100.9% 99.7% 100.5% 99.9% 212.6 8,488 423.1 8,214 1,233.2 Massachusetts Boston 725090 12 52.2 102.7% 99.3% 101.7% 99.7% 216.4 8,453 430.6 8,180 1,247.6 Michigan Detroit 725375 626 51.1 100.9% 99.2% 99.7% 99.7% 212.6 8,444 423.2 8,171 1,224.1 Michigan Grand Rapids 726350 803 49.1 101.0% 99.0% 99.6% 99.7% 212.9 8,427 423.8 8,154 1,222.3 Minnesota Saint Paul 726584 700 46.9 102.3% 98.8% 100.5% 99.5% 215.5 8,408 428.9 8,136 1,233.4 Mississippi Jackson 722350 330 65.5 96.3% 100.7% 97.2% 100.4% 202.9 8,566 403.8 8,290 1,193.4 Missouri St. Louis 724340 531 57.8 98.6% 99.9% 98.4% 100.0% 207.8 8,501 413.6 8,226 1,208.1 Missouri Kansas City 724463 742 57.4 98.0% 99.8% 97.8% 100.1% 206.6 8,497 411.1 8,223 1,200.2 Montana Great Falls 727750 3,364 45.2 93.1% 98.6% 91.3% 100.0% 196.2 8,393 390.5 8,122 1,120.2 Nebraska Omaha 725530 1,332 51.6 98.2% 99.3% 97.1% 99.9% 206.8 8,448 411.7 8,175 1,191.7 Nevada Las Vegas 724846 2,203 69.4 88.5% 101.0% 89.9% 101.0% 186.4 8,599 371.0 8,322 1,103.2 New Hampshire Concord 726050 346 47.2 103.5% 98.8% 101.7% 99.5% 218.0 8,410 433.9 8,139 1,248.2 New Jersey Newark 725020 7 55.8 101.3% 99.7% 100.8% 99.8% 213.4 8,484 424.7 8,210 1,236.8 New Mexico Albuquerque 723650 5,310 58.5 81.6% 100.0% 81.5% 101.0% 171.9 8,507 342.1 8,232 1,000.5 New York New York 725053 130 55.3 101.0% 99.6% 100.5% 99.8% 212.9 8,479 423.7 8,206 1,233.0 New York Syracuse 725190 413 48.9 102.5% 99.0% 101.0% 99.6% 216.1 8,425 430.0 8,153 1,240.1 North Carolina Charlotte 723140 728 61.5 96.5% 100.3% 96.8% 100.3% 203.3 8,532 404.6 8,257 1,188.6 North Carolina Asheville 723150 2,117 56.5 93.5% 99.8% 93.2% 100.3% 197.1 8,490 392.2 8,215 1,143.5 North Dakota Bismarck 727640 1,651 43.5 100.1% 98.5% 97.9% 99.6% 210.9 8,379 419.7 8,108 1,201.2 Ohio Cincinnati 724297 490 55.0 99.9% 99.6% 99.3% 99.9% 210.4 8,477 418.8 8,203 1,218.3 
Gas Turbine Base

LOCATION Adjustment Basis Simple Cycle Combined Cyle 4 x LM6000PF+ 1 x 7HA.03 2 x 7HA.03 

State City ASHRAE Station Alt (ft) Ave T (F) MW adj SC HR adj SC MW adj CC HR adj CC MW net HR net MW net HR net MW net ISO ISO ‐ 0 59.0 100.0% 100.0% 100.0% 100.0% 210.7 8,511 419.4 8,236 1,227.3 Oklahoma Oklahoma City 723530 1,285 61.3 94.6% 100.2% 95.0% 100.4% 199.4 8,530 396.9 8,255 1,165.4 Oklahoma Tulsa 723560 650 61.6 96.7% 100.3% 97.1% 100.3% 203.8 8,533 405.6 8,257 1,191.6 Oregon Portland 726980 19 54.9 101.6% 99.6% 101.0% 99.8% 214.0 8,476 426.0 8,202 1,239.1 Pennsylvania Philadelphia 724080 10 56.8 100.8% 99.8% 100.5% 99.9% 212.5 8,492 423.0 8,218 1,233.6 Pennsylvania Wilkes‐Barre 725130 930 50.5 100.0% 99.2% 98.8% 99.8% 210.8 8,439 419.6 8,166 1,212.6 Rhode Island Providence 997278 33 53.0 102.3% 99.4% 101.4% 99.7% 215.5 8,460 429.0 8,187 1,244.3 South Carolina Charleston 722080 40 66.7 96.8% 100.8% 97.9% 100.4% 203.9 8,576 405.9 8,299 1,202.0 South Carolina Spartanburg 723120 943 61.6 95.7% 100.3% 96.1% 100.3% 201.6 8,533 401.4 8,257 1,179.1 South Dakota Rapid City 726620 3,160 47.3 93.1% 98.8% 91.5% 100.0% 196.2 8,411 390.5 8,140 1,123.5 Tennessee Knoxville 723260 962 59.8 96.3% 100.1% 96.4% 100.2% 203.0 8,518 404.0 8,243 1,183.6 Tennessee Nashville 723270 600 60.5 97.3% 100.2% 97.5% 100.2% 205.1 8,524 408.1 8,248 1,197.0 Texas Houston 722436 32 70.7 95.2% 101.2% 97.0% 100.6% 200.6 8,610 399.3 8,332 1,190.1 Utah Salt Lake City 725720 4,225 54.1 86.9% 99.5% 86.3% 100.6% 183.1 8,469 364.4 8,196 1,058.6 Vermont Burlington 726170 330 47.0 103.6% 98.8% 101.8% 99.5% 218.3 8,409 434.5 8,137 1,249.5 Virginia Alexandria 724050 10 59.0 100.0% 100.0% 100.0% 100.0% 210.6 8,511 419.3 8,236 1,226.9 Virginia Lynchburg 724100 940 56.5 97.7% 99.8% 97.3% 100.1% 205.8 8,490 409.7 8,215 1,194.3 Washington Spokane 727850 2,353 48.5 95.6% 99.0% 94.2% 99.9% 201.5 8,421 401.0 8,150 1,155.8 Washington Seattle 994014 7 53.5 102.2% 99.5% 101.4% 99.7% 215.3 8,464 428.5 8,191 1,243.9 West Virginia Charleston 724140 910 56.0 98.0% 99.7% 97.5% 100.0% 206.5 8,485 410.9 8,211 1,197.1 Wisconsin Green Bay 726450 687 45.8 102.7% 98.7% 100.8% 99.5% 216.5 8,399 430.9 8,127 1,237.3 Wyoming Cheyenne 725640 6,130 47.0 82.3% 98.8% 80.9% 100.6% 173.5 8,409 345.2 8,137 992.9