Capital Cost and Performance 

Characteristic Estimates for 

Utility Scale Electric Power 

Generating Technologies

February 2020

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

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

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

analytical agency within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are 

independent of approval by any other officer or employee of the United States Government. The views 

in this report therefore should not be construed as representing those of the U.S. Department of Energy 

or other federal agencies.
February 2020

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

Capital Cost and Performance Characteristic Estimates for Utility 

Scale Electric Power Generating Technologies

To accurately reflect the changing cost of new electric power generators for AEO2020, EIA 

commissioned Sargent & Lundy (S&L) to evaluate the overnight capital cost and performance 

characteristics for 25 electric generator types. The following report represents S&L’s findings. A 

separate EIA report, “Addendum: Updated Capital Cost and Performance Characteristic Estimates for 

Utility Scale Electricity Generating Plants in the Electricity Market Module (EMM) of the National Energy 

Modeling System (NEMS),” details subsequent updates to the EMM module.

The following report was accepted by EIA in fulfillment of contract number 89303019-CEI00022. 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 the findings 

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

contractor. Although intended to be used to inform the updating of EIA’s EMM module of NEMS, EIA is 

not obligated to modify any of its models or data in accordance with the findings of this report.
Capital Cost Study

Cost and Performance Estimates 

for New Utility-Scale Electric Power 

Generating Technologies

Prepared for

U.S. Energy Information Administration,

an agency of the U.S. Department of Energy

FINAL REPORT | DECEMBER 2019

Contract No. 89303019CEI00022

SL-014940 | Project No. 13651.005
Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

LEGAL NOTICE

This report (“Deliverable”) was prepared by Sargent & Lundy, L.L.C. (“Sargent & Lundy”), 

expressly for the sole use of the U.S. Department of Energy – Energy Information 

Administration (“Client”) in accordance with the agreement between Sargent & Lundy and 

the Client. This Deliverable was prepared using the degree of skill and care ordinarily 

exercised by engineers practicing under similar circumstances. Client acknowledges: (1) 

Sargent & Lundy prepared this Deliverable subject to the particular scope limitations, 

budgetary and time constraints, and business objectives of the Client; (2) information and 

data provided by others may not have been independently verified by Sargent & Lundy; 

and (3) the information and data contained in this Deliverable are time sensitive 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. 
Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Sargent & Lundy is one of the oldest and most experienced 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, and fossil fuels. 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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Version Log

Final - Rev. 1

VERSION LOG

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Version Issue Date

Draft June 14, 2019

Interim Final Report August 6, 2019

Final August 30, 2019

Final – Rev 1. December 9, 2019
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Content

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CONTENT

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

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

Cost & Performance of Technologies .......................................................................................................... I

Cost & Performance Estimates Summary..................................................................................................II

BASIS OF ESTIMATES ..................................................................................................VI

Base Fuel Selection....................................................................................................................................VI

Environmental Compliance Basis ............................................................................................................VII

Combustion Turbine Capacity Adjustments............................................................................................VII

Capital Cost Estimating..........................................................................................................................VIII

Locational Adjustments ....................................................................................................................... X

Environmental Location Factors ......................................................................................................... X

Additional Location Factor Considerations...................................................................................... XII

Operating & Maintenance Cost Estimating ............................................................................................ XII

Fixed O&M........................................................................................................................................XIII

Variable O&M ...................................................................................................................................XIII

CASE 1. ULTRA-SUPERCRITICAL COAL WITHOUT CO2 CAPTURE, 650 MW ........... 1-1

1.1 Case Description............................................................................................................................ 1-1

Mechanical Equipment & Systems .........................................................................................1-3

Electrical & Control Systems...................................................................................................1-4

Offsite Requirements...............................................................................................................1-4

1.2 Capital Cost Estimate ....................................................................................................................1-5

1.3 O&M Cost Estimate....................................................................................................................... 1-7

1.4 Environmental & Emissions Information ....................................................................................1-8

CASE 2. ULTRA-SUPERCRITICAL COAL WITH 30% CO2 CAPTURE, 650 MW...........2-1

2.1 Case Description............................................................................................................................2-1

Mechanical Equipment & Systems .........................................................................................2-1
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Electrical & Control Systems.................................................................................................. 2-4

Offsite Requirements.............................................................................................................. 2-4

2.2 Capital Cost Estimate ................................................................................................................... 2-5

2.3 O&M Cost Estimate.......................................................................................................................2-7

2.4 Environmental & Emissions Information ................................................................................... 2-8

CASE 3. ULTRA-SUPERCRITICAL COAL WITH 90% CO2 CAPTURE, 650 MW...........3-1

3.1 Case Description............................................................................................................................3-1

Mechanical Equipment & Systems .........................................................................................3-1

Electrical & Control Systems.................................................................................................. 3-4

Offsite Requirements.............................................................................................................. 3-4

3.2 Capital Cost Estimate ................................................................................................................... 3-5

3.3 O&M Cost Estimate.......................................................................................................................3-7

3.4 Environmental & Emissions Information ................................................................................... 3-8

CASE 4. INTERNAL COMBUSTION ENGINES, 20 MW ..............................................4-1

4.1 Case Description............................................................................................................................4-1

Mechanical Equipment & Systems .........................................................................................4-1

Electrical & Control Systems...................................................................................................4-1

Offsite Requirements.............................................................................................................. 4-2

4.2 Capital Cost Estimate ................................................................................................................... 4-2

4.3 O&M Cost Estimate...................................................................................................................... 4-4

4.4 Environmental & Emissions Information ................................................................................... 4-4

CASE 5. COMBUSTION TURBINES AERODERIVATIVE, 100-MW SIMPLE CYCLE....5-1

5.1 Case Description............................................................................................................................5-1

Mechanical Equipment & Systems .........................................................................................5-1

Electrical & Control Systems.................................................................................................. 5-2

Offsite Requirements.............................................................................................................. 5-2
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5.2 Capital Cost Estimate ................................................................................................................... 5-2

5.3 O&M Cost Estimate...................................................................................................................... 5-4

5.4 Environmental & Emissions Information ....................................................................................5-5

CASE 6. COMBUSTION TURBINE F CLASS, 240-MW SIMPLE CYCLE.......................6-1

6.1 Case Description............................................................................................................................6-1

Mechanical Equipment & Systems .........................................................................................6-1

Electrical & Control Systems.................................................................................................. 6-2

Offsite Requirements.............................................................................................................. 6-2

6.2 Capital Cost Estimate ................................................................................................................... 6-2

6.3 O&M Cost Estimate...................................................................................................................... 6-4

6.4 Environmental & Emissions Information ................................................................................... 6-5

CASE 7. COMBUSTION TURBINE H CLASS, 1100-MW COMBINED CYCLE............... 7-1

7.1 Case Description............................................................................................................................7-1

Mechanical Equipment & Systems .........................................................................................7-1

Electrical & Control Systems.................................................................................................. 7-3

Offsite Requirements.............................................................................................................. 7-3

7.2 Capital Cost Estimate ....................................................................................................................7-3

7.3 O&M Cost Estimate.......................................................................................................................7-5

7.4 Environmental & Emissions Information ....................................................................................7-6

CASE 8. COMBUSTION TURBINE H CLASS, COMBINED-CYCLE SINGLE SHAFT, 430

MW 8-1

8.1 Case Description............................................................................................................................8-1

Mechanical Equipment & Systems .........................................................................................8-1

Electrical & Control Systems..................................................................................................8-4

Offsite Requirements..............................................................................................................8-4

8.2 Capital Cost Estimate ................................................................................................................... 8-5
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8.3 O&M Cost Estimate......................................................................................................................8-6

8.4 Environmental & Emissions Information ................................................................................... 8-7

CASE 9. COMBUSTION TURBINE H CLASS, COMBINED-CYCLE SINGLE SHAFT WITH

90% CO2 CAPTURE, 430 MW .................................................................................9-1

9.1 Case Description............................................................................................................................9-1

Mechanical Equipment & Systems .........................................................................................9-1

Electrical & Control Systems.................................................................................................. 9-2

Offsite Requirements.............................................................................................................. 9-3

9.2 Capital Cost Estimate ................................................................................................................... 9-3

9.3 O&M Cost Estimate...................................................................................................................... 9-5

9.4 Environmental & Emissions Information ................................................................................... 9-6

CASE 10. FUEL CELL, 10 MW .................................................................................... 10-1

10.1 Case Description..........................................................................................................................10-1

Chemical Operation...............................................................................................................10-1

Mechanical Equipment & Systems ...................................................................................... 10-2

Offsite Requirements............................................................................................................ 10-3

10.2 Capital Cost Estimate ..................................................................................................................10-3

10.3 O&M Cost Estimate.....................................................................................................................10-5

10.4 Environmental & Emissions Information ..................................................................................10-5

CASE 11. ADVANCED NUCLEAR, 2156 MW................................................................11-1

11.1 Case Description...........................................................................................................................11-1

Mechanical Equipment & Systems ........................................................................................11-1

Electrical & Control Systems..................................................................................................11-1

Offsite Requirements............................................................................................................. 11-2

11.2 Capital Cost Estimate .................................................................................................................. 11-2

11.3 O&M Cost Estimate..................................................................................................................... 11-3
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11.4 Environmental & Emissions Information .................................................................................. 11-4

CASE 12. SMALL MODULAR REACTOR NUCLEAR POWER PLANT, 600 MW .......... 12-1

12.1 Case Description.......................................................................................................................... 12-1

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

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

Offsite Requirements.............................................................................................................12-2

12.2 Capital Cost Estimate ..................................................................................................................12-2

12.3 O&M Cost Estimate.....................................................................................................................12-4

12.4 Environmental & Emissions Information ..................................................................................12-4

CASE 13. BIOMASS PLANT, 50 MW........................................................................... 13-1

13.1 Case Description.......................................................................................................................... 13-1

Mechanical Equipment & Systems ....................................................................................... 13-1

Electrical & Control Systems.................................................................................................13-4

Offsite Requirements.............................................................................................................13-4

13.2 Capital Cost Estimate ..................................................................................................................13-4

13.3 O&M Cost Estimate.....................................................................................................................13-6

13.4 Environmental & Emissions Information ..................................................................................13-7

CASE 14. 10% BIOMASS CO-FIRE RETROFIT............................................................ 14-1

14.1 Case Description.......................................................................................................................... 14-1

Mechanical Equipment & Systems ....................................................................................... 14-1

Electrical & Control Systems.................................................................................................14-2

Offsite Requirements.............................................................................................................14-2

14.2 Capital Cost Estimate ..................................................................................................................14-3

14.3 O&M Cost Estimate.....................................................................................................................14-4

14.4 Environmental & Emissions Information ..................................................................................14-5
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 15. GEOTHERMAL PLANT, 50 MW.................................................................. 15-1

15.1 Case Description.......................................................................................................................... 15-1

Mechanical Equipment & Systems .......................................................................................15-2

Electrical & Control Systems.................................................................................................15-4

Offsite Requirements.............................................................................................................15-4

15.2 Capital Cost Estimate ..................................................................................................................15-4

15.3 O&M Cost Estimate.....................................................................................................................15-6

15.4 Environmental & Emissions Information ..................................................................................15-6

CASE 16. INTERNAL COMBUSTION ENGINES, LANDFILL GAS, 30 MW.................. 16-1

16.1 Case Description.......................................................................................................................... 16-1

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

Electrical and Control Systems ............................................................................................. 16-1

Offsite Requirements.............................................................................................................16-2

16.2 Capital Cost Estimate ..................................................................................................................16-2

16.3 O&M Cost Estimate.....................................................................................................................16-3

16.4 Environmental & Emissions Information ..................................................................................16-4

CASE 17. HYDROELECTRIC PLANT, 100 MW............................................................17-1

17.1 Case Description.......................................................................................................................... 17-1

Offsite Requirements.............................................................................................................17-3

17.2 Capital Cost Estimate ..................................................................................................................17-3

17.3 O&M Cost Estimate.....................................................................................................................17-4

17.4 Environmental & Emissions Information ..................................................................................17-4

CASE 18. BATTERY ENERGY STORAGE SYSTEM, 50 MW / 200 MWH ..................... 18-1

18.1 Case Description.......................................................................................................................... 18-1

Offsite Requirements............................................................................................................ 18-4
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

18.2 Capital Cost Estimate ..................................................................................................................18-4

18.3 O&M Cost Estimate.....................................................................................................................18-6

18.4 Environmental & Emissions Information ..................................................................................18-7

CASE 19. BATTERY ENERGY STORAGE SYSTEM, 50 MW / 100 MWH ..................... 19-1

19.1 Case Description.......................................................................................................................... 19-1

Offsite Requirements............................................................................................................. 19-1

19.2 Capital Cost Estimate .................................................................................................................. 19-1

19.3 O&M Cost Estimate.....................................................................................................................19-3

19.4 Environmental & Emissions Information ..................................................................................19-4

CASE 20. ONSHORE WIND, LARGE PLANT FOOTPRINT, 200 MW ..........................20-1

20.1 Case Description..........................................................................................................................20-1

20.2 Mechanical Equipment & Systems .............................................................................................20-1

Electrical & Control Systems................................................................................................20-2

Offsite Requirements............................................................................................................20-2

20.3 Capital Cost Estimate .................................................................................................................20-3

20.4 O&M Cost Estimate....................................................................................................................20-4

20.5 Environmental & Emissions Information ................................................................................. 20-5

CASE 21. ONSHORE WIND, SMALL PLANT FOOTPRINT, 50 MW............................. 21-1

21.1 Case Description.......................................................................................................................... 21-1

Mechanical Equipment & Systems ....................................................................................... 21-1

Electrical & Control Systems.................................................................................................21-2

Offsite Requirements.............................................................................................................21-2

21.2 Capital Cost Estimate ..................................................................................................................21-3

21.3 O&M Cost Estimate.....................................................................................................................21-4

21.4 Environmental & Emissions Information ..................................................................................21-5
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 22. OFFSHORE WIND, 400 MW.......................................................................22-1

22.1 Case Description..........................................................................................................................22-1

Mechanical Equipment & Systems .......................................................................................22-1

Electrical & Control Systems.................................................................................................22-1

Offsite Requirements............................................................................................................ 22-2

22.2 Capital Cost Estimate ................................................................................................................. 22-2

22.3 O&M Cost Estimate.................................................................................................................... 22-3

22.4 Environmental & Emissions Information ................................................................................. 22-4

CASE 23. CONCENTRATING SOLAR PLANT, 100 MW, 8-HR STORAGE....................23-1

23.1 Case Description..........................................................................................................................23-1

Offsite Requirements............................................................................................................ 23-4

23.2 Capital Cost Estimate ................................................................................................................. 23-4

23.3 O&M Cost Estimate.................................................................................................................... 23-6

23.4 Environmental & Emissions Information ................................................................................. 23-7

CASE 24. SOLAR PHOTOVOLTAIC, 150 MWAC...........................................................24-1

24.1 Case Description..........................................................................................................................24-1

Mechanical Equipment & Systems .......................................................................................24-1

Electrical & Control Systems................................................................................................ 24-3

Offsite Requirements............................................................................................................ 24-3

24.2 Capital Cost Estimate ................................................................................................................. 24-4

24.3 O&M Cost Estimate.................................................................................................................... 24-5

24.4 Environmental & Emissions Information ................................................................................. 24-6

CASE 25. SOLAR PHOTOVOLTAIC WITH BATTERY ENERGY STORAGE SYSTEM, 150 

MWAC ...................................................................................................................25-1

25.1 Case Description..........................................................................................................................25-1

Mechanical Equipment & Systems .......................................................................................25-1
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Electrical & Control Systems................................................................................................ 25-2

Offsite Requirements............................................................................................................ 25-2

25.2 Capital Cost Estimate ................................................................................................................. 25-3

25.3 O&M Cost Estimate.................................................................................................................... 25-4

25.4 Environmental & Emissions Information ................................................................................. 25-5
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Appendixes

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APPENDIXES

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Appendix A. Labor Location-Based Cost Adjustments

Appendix B. Combustion Turbine Capacity Adjustments
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Tables and Figures

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TABLES AND FIGURES

Table or Figure Page

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 1 — List of Reference Technologies................................................................................................... I

Table 2 — Cost & Performance Summary Table.......................................................................................III

Table 3 — Reference Coal Specification....................................................................................................VI

Table 4 — Reference Natural Gas Specification .......................................................................................VI

Table 5 — Reference Wood Biomass Specification .................................................................................VII

Table 1-1 — Case 1 Capital Cost Estimate ................................................................................................1-6

Table 1-2 — Case 1 O&M Cost Estimate...................................................................................................1-8

Table 1-3 — Case 1 Emissions...................................................................................................................1-8

Table 2-1 — Case 2 Capital Cost Estimate .............................................................................................. 2-6

Table 2-2 — Case 2 O&M Cost Estimate................................................................................................. 2-8

Table 2-3 — Case 2 Emissions................................................................................................................. 2-9

Table 3-1 — Case 3 Capital Cost Estimate............................................................................................... 3-6

Table 3-2 — Case 3 O&M Cost Estimate................................................................................................. 3-8

Table 3-3 — Case 3 Emissions................................................................................................................. 3-8

Table 4-1 — Case 4 Capital Cost Estimate .............................................................................................. 4-2

Table 4-2 — Case 4 O&M Cost Estimate................................................................................................. 4-4

Table 4-3 — Case 4 Emissions................................................................................................................. 4-4

Table 5-1 — Case 5 Capital Cost Estimate............................................................................................... 5-3

Table 5-2 — Case 5 O&M Cost Estimate ..................................................................................................5-5

Table 5-3 — Case 5 Emissions..................................................................................................................5-5

Table 6-1 — Case 6 Capital Cost Estimate .............................................................................................. 6-3

Table 6-2 — Case 6 O&M Cost Estimate................................................................................................. 6-5

Table 6-3 — Case 6 Emissions................................................................................................................. 6-5

Table 7-1 — Case 7 Capital Cost Estimate................................................................................................7-4

Table 7-2 — Case 7 O&M Cost Estimate ..................................................................................................7-6

Table 7-3 — Case 7 Emissions ..................................................................................................................7-6

Table 8-1 — Case 8 Capital Cost Estimate .............................................................................................. 8-5

Table 8-2 — Case 8 O&M Cost Estimate................................................................................................. 8-7

Table 8-3 — Case 8 Emissions ................................................................................................................ 8-7

Table 9-1 — Case 9 Capital Cost Estimate .............................................................................................. 9-4

Table 9-2 — Case 9 O&M Cost Estimate................................................................................................. 9-6
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TABLES AND FIGURES

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 9-3 — Case 9 Emissions................................................................................................................. 9-6

Table 10-1 — Fuel Cell Chemical Reactions ...........................................................................................10-2

Table 10-2 — Case 10 Capital Cost Estimate .........................................................................................10-4

Table 10-3 — Case 10 O&M Cost Estimate ............................................................................................10-5

Table 10-4 — Case 10 Emissions ........................................................................................................... 10-6

Table 11-1 — Case 11 Capital Cost Estimate ........................................................................................... 11-2

Table 11-2 — Case 11 O&M Cost Estimate.............................................................................................. 11-4

Table 12-1 — Case 12 Capital Cost Estimate ..........................................................................................12-2

Table 12-2 — Case 12 O&M Cost Estimate.............................................................................................12-4

Table 13-1 — Case 13 Capital Cost Estimate ..........................................................................................13-5

Table 13-2 — Case 13 O&M Cost Estimate.............................................................................................13-7

Table 13-3 — Case 13 Emissions ............................................................................................................13-7

Table 14-1 — Case 14 Capital Cost Estimate ..........................................................................................14-3

Table 14-2 — Case 14 O&M Cost Estimate.............................................................................................14-4

Table 14-3 — Case 14 Emissions ............................................................................................................14-5

Table 15-1 — Case 15 Capital Cost Estimate...........................................................................................15-5

Table 15-2 — Case 15 O&M Cost Estimate.............................................................................................15-6

Table 16-1 — Case 16 Capital Cost Estimate ..........................................................................................16-2

Table 16-2 — Case 16 O&M Cost Estimate.............................................................................................16-4

Table 16-3 — Case 16 Emissions ............................................................................................................16-4

Table 17-1 — Case 17 Capital Cost Estimate...........................................................................................17-3

Table 17-2 — Case 17 O&M Cost Estimate .............................................................................................17-4

Table 18-1 — Case 18 Capital Cost Estimate ..........................................................................................18-4

Table 18-2 — Case 18 O&M Cost Estimate ............................................................................................18-7

Table 19-1 — Case 19 Capital Cost Estimate ..........................................................................................19-2

Table 19-2 — Case 19 O&M Cost Estimate.............................................................................................19-4

Table 20-1 — Case 20 Capital Cost Estimate........................................................................................20-3

Table 20-2 — Case 20 O&M Cost Estimate .......................................................................................... 20-5

Table 21-1 — Case 21 Capital Cost Estimate ..........................................................................................21-3

Table 21-2 — Case 21 O&M Cost Estimate.............................................................................................21-5

Table 22-1 — Case 22 Capital Cost Estimate ........................................................................................ 22-3
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Tables and Figures

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TABLES AND FIGURES

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 22-2 — Case 22 O&M Cost Estimate........................................................................................... 22-4

Table 23-1 — Case 23 Capital Cost Estimate ........................................................................................ 23-5

Table 23-2 — Case 23 O&M Cost Estimate........................................................................................... 23-7

Table 24-1 — Case 24 Capital Cost Estimate ........................................................................................ 24-4

Table 24-2 — Case 24 O&M Cost Estimate........................................................................................... 24-6

Table 25-1 — Case 25 Capital Cost Estimate......................................................................................... 25-3

Table 25-2 — Case 25 O&M Cost Estimate........................................................................................... 25-5

Figure 1-1 — USC Coal Boiler – Flow Diagram........................................................................................1-2

Figure 2-1 — Carbon Capture Flow Diagram.......................................................................................... 2-3

Figure 5-1 — Case 2 Configuration...........................................................................................................5-1

Figure 6-1 — Case 6 Configuration ..........................................................................................................6-1

Figure 7-1 — Case 7 Configuration...........................................................................................................7-2

Figure 8-1 — Case 8 Configuration – Process Diagram ......................................................................... 8-3

Figure 8-2 — Case 8 Configuration – Simplified Sketch........................................................................ 8-4

Figure 10-1 — Simplified Solid Oxide Fuel Cell.....................................................................................10-2

Figure 10-2 — Typical Solid Oxide Fuel Cell Project.............................................................................10-3

Figure 13-1 — Typical BFB Biomass Boiler Arrangement.....................................................................13-3

Figure 14-1 — Biomass Cofiring in Coal-Fired Boilers, Separate Feed Arrangement..........................14-2

Figure 15-1 — Geothermal Binary Cycle Power Plant ...........................................................................15-3

Figure 17-1 — Storage-Type Hydroelectric Power Plant ....................................................................... 17-1

Figure 17-2 — Dam and Spillway of Hydroelectric Power Plant...........................................................17-2

Figure 17-3 — Typical Hydroelectric Power Turbine Hall ....................................................................17-2

Figure 18-1 — Utility-Scale Lithium-Ion Batteries ................................................................................18-2

Figure 18-2 — BESS Flow Diagram........................................................................................................18-2

Figure 18-3 — Typical Battery Storage Container .................................................................................18-3

Figure 20-1 — Wind Turbine Generator Drivetrain.............................................................................20-2

Figure 21-1 — Wind Turbine Generator Drivetrain...............................................................................21-2

Figure 23-1 — Concentrating Solar Power Tower System Diagram .................................................... 23-2

Figure 23-2 — Aerial View of Concentrating Solar Power Tower Project ........................................... 23-3

Figure 23-3 — United States Solar Resource........................................................................................ 23-4
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TABLES AND FIGURES

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 24-1 — Solar Photovoltaic Project ..............................................................................................24-1

Figure 24-2 — Single-Axis Tracking ..................................................................................................... 24-2

Figure 25-1 — AC Coupled Solar PV and Battery Storage.................................................................... 25-2
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Acronyms and Abbreviations

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ACRONYMS AND ABBREVIATIONS

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Term Definition or Clarification

°F degrees Fahrenheit 

AC alternating current

ACC air-cooled condenser

BESS battery energy storage system

BFB bubbling fluidized bed

BOP balance of plant

Btu/kWh British thermal unit(s) per kilowatt hour

CC combined cycle

CCS carbon capture and sequestration

CO carbon monoxide

CO2 carbon dioxide

CSP Concentrating Solar Power

CT combustion turbine

DC direct current

DCS distributed control system

EIA U.S. Energy Information Administration

EOH equivalent operating hours

EPC engineering, procurement, and construction

FGD flue gas desulfurization 

G&A general and administrative costs

GSU generator step-up transformer

HHV higher heating value

HRSG heat recovery steam generator
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Acronyms and Abbreviations

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ACRONYMS AND ABBREVIATIONS

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Term Definition or Clarification

Hz hertz

kV kilovolt(s)

kW kilowatt(s) 

kWh kilowatt hour(s)

lb/MMBtu pound(s) per one million British thermal units

LNB low-NOX burner

MVA megavolt ampere

MW megawatt(s) 

MWh megawatt hour(s)

NOX nitrogen oxide

O&M operations and maintenance

OEM original equipment manufacturer

OFA overfire air

psia pounds per square inch absolute

PV photovoltaic

RICE reciprocating internal combustion engine

SCADA Supervisory Control and Data Acquisition 

SCR selective catalytic reduction

SMR small modular reactor

SO2 sulfur dioxide

STG steam turbine generator

USC ultra-supercritical

V volt
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Acronyms and Abbreviations

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ACRONYMS AND ABBREVIATIONS

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Term Definition or Clarification

WFGD wet flue gas desulfurization

WTG wind turbine generator

ZLD zero liquid discharge
Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Introduction
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

INTRODUCTION

The U.S. Energy Information Administration (EIA) retained Sargent & Lundy to conduct a study of the 

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

our cost and performance estimates for 25 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 and thus 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, and 

contingencies as well as fixed and variable operating costs. We also estimated the net plant capacity, net 

plant heat rates, and controlled emission rates for each technology studied. We performed our 

assessments with consistent estimating methodologies across all generating technologies.

COST & PERFORMANCE OF TECHNOLOGIES 

The following table lists all the power generating technologies we assessed in this study.

Table 1 — List of Reference Technologies

Case 

No. Technology Description

1 650 MW Net, Ultra-Supercritical Coal w/o Carbon Capture – Greenfield 1 x 735 MW Gross

2 650 MW Net, Ultra-Supercritical Coal 30% Carbon Capture 1 x 769 MW Gross

3 650 MW Net, Ultra-Supercritical Coal 90% Carbon Capture 1 x 831 MW Gross

4 Internal Combustion Engines 4 x 5.6 MW

5 Combustion Turbines – Simple Cycle 2 x LM6000 

6 Combustion Turbines – Simple Cycle 1 x GE 7FA

7 Combined-Cycle 2x2x1 GE 7HA.02

8 Combined-Cycle 1x1x1, Single Shaft H Class

9 Combined-Cycle 1x1x1, Single Shaft, w/ 90% Carbon Capture H-Class

10 Fuel Cell 34 x 300 kW Gross
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Case 

No. Technology Description

11 Advanced Nuclear (Brownfield) 2 x AP1000

12 Small Modular Reactor Nuclear Power Plant 12 x 50-MW Small Modular Reactor

13 50-MW Biomass Plant Bubbling Fluidized Bed

14 10% Biomass Co-Fire Retrofit 300-MW PC Boiler

15 Geothermal Binary Cycle

16 Internal Combustion Engines – Landfill Gas 4 x 9.1 MW

17 Hydroelectric Power Plant New Stream Reach Development

18 Battery Energy Storage System 50 MW | 200 MWh

19 Battery Energy Storage System 50 MW | 100 MWh

20 Onshore Wind – Large Plant Footprint: Great Plains Region 200 MW | 2.8 MW WTG

21 Onshore Wind – Small Plant Footprint: Coastal Region 50 MW | 2.8 MW WTG

22 Fixed-bottom Offshore Wind: 

Monopile Foundations 400 MW | 10 MW WTG

23 Concentrating Solar Power Tower with Molten Salt Thermal Storage

24 Solar PV w/ Single Axis Tracking 150 MWAC

25 Solar PV w/ Single Axis Tracking + Battery Storage 150 MWAC Solar

50 MW | 200 MWh Storage

Acronym Definitions:

• BESS = battery energy storage system

• Btu/kWh = British thermal units per kilowatt hour

• CC = combined cycle

• CCS = carbon capture and sequestration 

• CT = combustion turbine

• kW = kilowatt

• MW = megawatt

• MWAC = megawatt alternating current

• MWh = megawatt hour

• PV = photovoltaic

• USC = ultra-supercritical

• WTG = wind turbine generator 

As part of the technology assessment, Sargent & Lundy 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, Sargent & Lundy identified the representative

costs and performance for the reference technologies.

COST & PERFORMANCE ESTIMATES SUMMARY

Table 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 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)

NOx

(lb/MMBtu)

SO2

(lb/MMBtu)

CO2

(lb/MMBtu)

1

650 MW Net, UltraSupercritical Coal w/o 

Carbon Capture – Greenfield

1 x 735 MW Gross 650 8638 3676 40.58 4.50 0.06 0.09 206

2

650 MW Net, UltraSupercritical Coal 30% 

Carbon Capture

1 x 769 MW Gross 650 9751 4558 54.30 7.08 0.06 0.09 144

3

650 MW Net, UltraSupercritical Coal 90% 

Carbon Capture

1 x 831 MW Gross 650 12507 5876 59.54 10.98 0.06 0.09 20.6

4 Internal Combustion Engines 4 x 5.6 MW 21 8295 1810 35.16 5.69 0.02 0 117

5 Combustion Turbines –

Simple Cycle 2 x LM6000 105 9124 1175 16.30 4.7 0.09 0.00 117

6 Combustion Turbines –

Simple Cycle 1 x GE 7FA 237 9905 713 7.00 4.5 0.03 0.00 117

7 Combined-Cycle 2x2x1 GE 7HA.02 1083 6370 958 12.20 1.87 0.0075 0.00 117

8 Combined-Cycle 1x1x1, 

Single Shaft H Class 418 6431 1084 14.1 2.55 0.0075 0.00 117

9

Combined-Cycle 1x1x1, 

Single Shaft,

w/ 90% Carbon Capture

H-Class 377 7124 2481 27.6 5.84 0.0075 0.00 11.7

10 Fuel Cell 34 x 300 kW Gross 10 6469 6700 30.78 0.59 0.0002 0 117

11 Advanced Nuclear 

(Brownfield) 2 x AP1000 2156 10608 6041 121.64 2.37 0 0 0

12 Small Modular Reactor 

Nuclear Power Plant

12 x 50-MW Small 

Modular Reactor 600 10046 6191 95.00 3.00 0 0 0

13 50-MW Biomass Plant Bubbling Fluidized 

Bed 50 13300 4097 125.72 4.83 0.08 <0.03 206

14 10% Biomass Co-Fire

Retrofit 300-MW PC Boiler 30 + 1.5% 705 25.57 1.90 0%–20% -8% -8%

15 Geothermal Binary Cycle 50 N/A 2521 128.544 1.16 0 0 0
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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)

NOx

(lb/MMBtu)

SO2

(lb/MMBtu)

CO2

(lb/MMBtu)

16 Internal Combustion Engines

– Landfill Gas 4 x 9.1 MW 35.6 8513 1563 20.1 6.2 0.02 0 117

17 Hydroelectric Power Plant New Stream Reach 

Development 100 N/A 5316 29.86 0 0 0 0

18 Battery Energy Storage 

System 50 MW | 200 MWh 50 N/A 1389 

(347 $/kWh) 24.8 0 0 0 0

19 Battery Energy Storage

System 50 MW | 100 MWh 50 N/A 845 (423 $/kWh) 12.9 0 0 0 0

20

Onshore Wind – Large Plant 

Footprint: Great Plains 

Region

200 MW | 2.82 MW 

WTG 200 N/A 1265 26.34 0 0 0 0

21 Onshore Wind – Small Plant 

Footprint: Coastal Region

50 MW | 2.78 MW 

WTG 50 N/A 1677 35.14 0 0 0 0

22 Fixed-bottom Offshore Wind: 

Monopile Foundations

400 MW | 10 MW 

WTG 400 N/A 4375 110 0 0 0 0

23 Concentrating Solar Power 

Tower

with Molten Salt 

Thermal Storage 115 N/A 7221 85.4 0 0 0 0

24 Solar PV w/ Single Axis 

Tracking 150 MWAC 150 N/A 1313 15.25 0 0 0 0

25

Solar PV w/ Single Axis 

Tracking + 

Battery Storage

150 MWAC Solar 

50 MW | 200 MWh 

Storage

150 N/A 1755 31.27 0 0 0 0

Acronym Definitions: 

• $/kW = dollar(s) per kilowatt

• $/kW-year = dollar(s) per kilowatt year 

• $/MWh = dollar(s) per megawatt hour

• BESS = battery energy storage system

• Btu/kWh = British thermal units per kilowatt hour

• CC = combined cycle

• CCS = carbon capture and sequestration 

• CO2 = carbon dioxide

• CT = combustion turbine

• kW = kilowatt

• lb/MMBtu = pound(s) per million British thermal units

• MW = megawatt

• MWAC = megawatt alternating current

• MWh = megawatt hour

• PV = photovoltaic

• USC = ultra-supercritical

• WTG = wind turbine generator
Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Basis of Estimates
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BASIS OF ESTIMATES

BASE FUEL SELECTION

We used the following fuel specifications as a basis for the cost estimates. The tables shown below 

represent typical fuel specifications for coal, natural gas, and wood biomass.

Table 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 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

Btu/scf = British thermal unit per standard cubic foot
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Table 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 5,400–6,200

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 CO2, where applicable. 

Best available control technology guidelines are covered by the U.S. Clean Air Act Title 1, 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.

COMBUSTION TURBINE CAPACITY ADJUSTMENTS

Appendix B includes combustion turbine capacity adjustments.
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Adjustments for local ambient conditions were made for power plants using combustion turbines (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:

• Temperature affects air density in an inversely proportional relationship and effects 

combined-cycle (CC) plants’ cooling systems, which impacts overall plant performance.

• Relative humidity affects air density in a proportional relationship. For plants with wet cooling 

(evaporative coolers, wet cooling towers, etc.), relative humidity and temperature determine the 

effectiveness of that equipment, with the highest effectiveness when the temperature is high and 

the relative humidity low.

• Elevation affects air pressure and density in an inversely proportional relationship, and it was 

calculated in this study by using 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 this 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 has 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 from which to establish the cost 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 

U.S. location. As applicable, 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 described in the 

following section, we have also estimated location adjustments to help establish the cost impacts to 

project implementation 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 online date. The 

capital costs are divided between 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 
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associated with the project. The capital costs provided are overnight capital costs in 2019 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:

• The civil and structural material and installation cost includes all material and associated labor 

for civil and structural tasks. This includes both labor and material for site preparation, 

foundation, piling, structural steel, and buildings. 

• The mechanical equipment supply and installation cost includes all mechanical equipment and 

associated labor for mechanical tasks. This includes both labor and material for equipment 

installation such as pumps and tanks, piping, valves, and piping specialties. 

• The electrical and instrumentation and controls supply and installation includes all costs for 

transformers, switchgear, control systems, wiring, instrumentation, and raceway.

• The project indirect costs include engineering, construction management, and start-up and 

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

The owner’s costs primarily consist of costs incurred to develop the project as well as land and utility

interconnection costs. The owner’s development costs include project development, studies, permitting, 

legal, owner's project management, owner's engineering, and owner's participation in startup and 

commissioning. Outside-the-fence-line costs are considered as owner’s costs. These include electrical 

interconnection costs and natural gas interconnection and metering costs; however, these costs too are 

generic and based on nominal distances to substations and gas pipeline laterals. We have also assumed 

that no substation upgrades would be required for the electrical interconnection. Transmission costs 

are based on a one-mile transmission line (unless otherwise stated) with voltage ranging from 230

kilovolts (kV) to 500 kV depending on the unit capacity. Land requirements are based on typical land 

requirements for each technology with per-acreage costs based on a survey of typical site costs across 

the United States.

The overall project contingency is also included to account for undefined project scope and pricing 

uncertainty for both capital cost components and owner’s cost components. The levels of contingency 

differ in some of the estimates based on the nature of the technology and the complexity of the 

technology implementation.
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Locational Adjustments

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

U.S. locations. 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, 2019 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.

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, 2018 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 U.S. locations. 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 

(i.e., American Society of Civil Engineers, International Building Code. 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 25 cases, the factor was 
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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 (i.e., 

equipment, buildings) for each of the 25 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. 

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 tsunamiresistant features into the first building designed using the methodology. The environmental location 

factor included tsunami effects for one location: Seattle, Washington.

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

California’s Office of Statewide Health Planning and Development developed this web interface that uses the open source 

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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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 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. Zero 

liquid discharge 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 air-cooled condensers 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 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, 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 & MAINTENANCE COST ESTIMATING

Once a plant enters commercial operation, the plant owners incur fixed O&M as well as variable O&M 

costs each year. Operations and maintenance costs presented in this report are non-fuel related.

Fixed O&M costs include costs directly related to the equipment design including labor, materials, 

contract services for routine O&M, and administrative and general costs. Not included are other fixed 

operating costs related to the location, notably property taxes and insurance. Labor, maintenance, and 

minor repairs and general and administrative (G&A) costs were estimated based on a variety of sources 

including actual projects, vendor publications, and Sargent & Lundy’s internal resources. Variable O&M 

costs, such as ammonia, water, and miscellaneous chemicals and consumables, are directly proportional

to the plant generating output.
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Fixed O&M 

Fixed O&M costs are those incurred at a power plant which do not vary with generation. Fixed O&M

typically includes the following expenses:

• 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.

General and administrative expenses are operation expenses, which include leases, management 

salaries, and office utilities. 

For the hydro, solar, wind, and battery energy storage cases, all O&M costs are treated as fixed costs.

Variable O&M 

Variable O&M costs are generation-based costs that vary based on the amount of electrical generation 

at the power plant. These expenses include water consumption, waste and wastewater discharge, 

chemicals such as selective catalytic reduction ammonia, and consumables including lubricants and 

calibration gas.
Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Cases
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CASE 1. ULTRA-SUPERCRITICAL COAL WITHOUT 

CO2 CAPTURE, 650 MW

1.1 CASE DESCRIPTION

This case comprises a 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. This 

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

is characterized by operation at supercritical pressures at approximately 3750 psia2 and at steam 

temperatures above 1100°F (degrees Fahrenheit). This increase in steam pressure and steam 

temperature provides more energy per pound of fuel that can be converted to shaft power in the steam 

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

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

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

lower emissions. Throughout the past decade, many USC coal plants have been placed in operation, 

although most of these facilities have been constructed in Europe and Asia. Figure 1-1 is a view of the 

first U.S. USC coal facility, which began operation in 2012.

 2 Pounds per square inch absolute
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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 (accessed on July 8, 2019).

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

of approximately 300 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 used for cycle cooling and steam cycle makeup is provided by 

an adjacent fresh water reservoir or river. 
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Mechanical Equipment & Systems

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, with the eighth heater supplied with 

extraction steam from the high-pressure turbine. This heater configuration is commonly referred to as 

a “HARP” system, which is a Heater Above Reheat Point of the turbine steam flow path. Boiler feedwater 

is pressured with a single high-pressure boiler feedwater pump, which is driven with an electric motor. 

(For the larger boiler size described in the 90% carbon capture case [Case 3], the boiler feedwater pump 

is steam turbine driven, with the turbine exhaust directed to the low-pressure 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. 

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 are in 

accordance with Section 1 of the ASME BPVC. 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 
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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, and wet chimney. 

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, allowing 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. 

Material Handling

The coal handling system includes rail car unloading, reclaim systems, 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. 

Electrical & 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). 

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 approximate 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 required for cooling tower makeup, cycle 

makeup, and other demands is estimated to be approximately 7,000 gallons per minute. Wastewater is 
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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, the cost associated 

with the expansion of the substation is excluded. 

1.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $3676/kilowatt (kW). 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 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 needed to prevent freezing or to account for snow 

loads on structures. 

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, 

zero liquid discharge (ZLD) equipment is added. Zero liquid discharge 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. 
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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 STG equipment will be enclosed in all locations.

Table 1-1 — Case 1 Capital Cost Estimate

Case 1

EIA – Capital Cost Estimates – 2019 $s

Configuration

650 MW Net

Ultra-Supercritical Coal w/o 

Carbon Capture – Greenfield

1 x 735 MW Gross

Combustion Emissions Controls Low NOx Burners / OFA

Post-Combustion Emissions Controls SCR / Baghouse/ WFGD / WESP

Fuel Type High Sulfur Bituminous

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 650

Heat Rate, HHV Basis Btu/kWh 8638

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 12%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 300

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 2,520,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile 2,500,000

Miles miles 0.50

Metering Station $ 3,600,000

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 36

Total Lead Time Before COD months 60

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 235,200,000

Mechanical – Boiler Plant $ 905,100,000

Mechanical – Turbine Plant $ 155,200,000

Mechanical – Balance of Plant $ 19,300,000

Mechanical Subtotal $ 1,079,600,000

Electrical – Main Power System $ 18,100,000

Electrical – Aux Power System $ 22,800,000

Electrical – BOP and I&C $ 104,900,000

Electrical – Substation and Switchyard $ 15,100,000

Electrical Subtotal $ 160,900,000

Project Indirects $ 323,200,000

EPC Total Before Fee $ 1,798,900,000

EPC Fee $ 179,890,000

EPC Subtotal $ 1,978,790,000
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Case 1

EIA – Capital Cost Estimates – 2019 $s

Configuration

650 MW Net

Ultra-Supercritical Coal w/o 

Carbon Capture – Greenfield

1 x 735 MW Gross

Combustion Emissions Controls Low NOx Burners / OFA

Post-Combustion Emissions Controls SCR / Baghouse/ WFGD / WESP

Fuel Type High Sulfur Bituminous

Units

Owner's Cost Components (Note 2)

Owner's Services $ 138,515,000

Land $ 9,000,000

Electrical Interconnection $ 2,520,000

Gas Interconnection $ 4,850,000

Owner's Cost Subtotal $ 154,885,000

Project Contingency $ 256,041,000

Total Capital Cost $ 2,389,716,000

 $/kW net 3,676

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, gas interconnection costs (if 

applicable), and land acquisition costs.

1.3 O&M COST ESTIMATE

The operating and maintenance costs for the USC coal-fired power generation facility are summarized 

in Table 1-2. The fixed costs cover the operations and maintenance (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/six-year basis depending on the equipment. Major steam 

turbine maintenance work is generally performed on a five- to six-year cycle, while shorter outages (e.g., 

change out selective catalytic reduction [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, 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 O&M Cost Estimate

Case 1

EIA – Non-Fuel O&M Costs – 2019 $S

650 MW Net, Ultra-Supercritical Coal w/o Carbon Capture – Greenfield

Fixed O&M – Plant (Note 1)

Labor $/year 15,317,000

Materials and Contract Services $/year 7,830,000

Administrative and General $/year 3,233,000

Subtotal Fixed O&M $/year 26,380,000

$/kW-year $/kW-year 40.58 $/kW-year

Variable O&M (Note 2) $/MWh 4.50 $/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, limestone, water, ash disposal, FGD waste disposal, and water discharge 

treatment cost.

1.4 ENVIRONMENTAL & 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 pounds per one million British thermal units (lb/MMBtu). The WFGD system is assumed to be 

capable of 98% reduction of SO2 from an inlet loading of 4.3 lb/MMBtu. The CO2 emissions estimates 

are based on the default CO2 emissions factors listed in Table C-1 of 40 CFR 98, Subpart C.

Table 1-3 — Case 1 Emissions

Case 1

EIA – Emissions Rates

650 MW Net, Ultra-Supercritical Coal w/o Carbon Capture – Greenfield

Predicted Emissions Rates (Note 1)

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, 4.3 lb/MMBtu SO2 Coal

2. NOx Removal using LNBs with OFA, and SCR

3. SO2 Removal by Forced Oxidation, Limestone Based, Wet FGD, 98% Reduction

4. Per 40 CFR 98, Subpt. 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 wet 

electrostatic precipitator 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. 
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For this case, no CO2 emissions controls are assumed to be applicable. Please refer to Case 2 for 30% 

carbon capture and Case 3 for 90% carbon capture.
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CASE 2. ULTRA-SUPERCRITICAL COAL WITH 30% 

CO2 CAPTURE, 650 MW

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, BOP systems, emissions control 

systems, and a 30% CO2 capture system. This technology case is similar to the plant description 

provided in Case 1; however, this case employs CO2 capture systems that require a larger boiler size and 

higher heat input to account for the low-pressure steam extraction and larger auxiliary loads needed for 

the CO2 capture technology used. The CO2 capture systems are commonly referred to as carbon capture 

and sequestration system (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. 

As with Case 1, the base configuration used for the cost estimate is a single-unit station constructed on 

a greenfield site of approximately 300 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 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 used for cycle cooling and steam cycle makeup is provided by an adjacent 

fresh water reservoir or river.

Mechanical Equipment & 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 CO2 capture systems 

used as the basis for the capital and O&M cost estimates.

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 
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approximately 2215 psia. The amine-based solvent systems are typically designed for 90% CO2 capture 

in the absorption column. 

CO2 Capture Systems 

This case assumes being built with full integration to the CO2 capture facility. 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 a net derate of approximately 30% in 

comparison with the base facility power output. 

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 is used to cool 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 
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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 WFGD

for makeup water. Due to the reuse, it does not require additional O&M costs. 

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

30% CO2 Capture 

For this technology case, the USC coal-fired facility is required to provide 30% CO2 reduction; 

approximately one-third of the total flue gas must be treated. As referenced previously, 90% capture is 

the typical design limit for CO2 reduction in the absorber. Therefore, 33% of the plant’s flue gas would 

need to be treated to provide 90% reduction efficiency. A slipstream of the flue gas downstream of the 
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WFGD system would be extracted and sent to the CO2 capture island. The remaining flue gas would exit 

through a typical free-standing wet chimney. 

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 33% of the 

flue gas from a new USC coal-fired boiler. Ultimately, the boiler would be built with a larger heat input 

than the non-CO2 capture cases; however, the increase in size would be much less than the 90% capture 

case. 

Plant Performance 

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

elevation, and 30% CO2 capture. Approximately 790,000 pound per hour of low-pressure steam is 

required for the CO2 system. While the boiler efficiency is assumed to be 87.5%, the estimated gross size 

of the steam generator is approximately 827 MW, which is approximately 13% larger than the case 

without carbon capture (Case 1). The estimated total auxiliary load for the plant is 119.5 MW with 28 

MW required for the CO2 system. The net heat rate is estimated to be 9751 Btu/kWh based on the HHV

of the fuel and the net electrical output. 

Electrical & Control Systems

The electrical equipment includes the turbine generator, which connects via generator circuit breakers 

to a GSU. The GSU increases the voltage from the generator voltages 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 DCS.

Offsite Requirements

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

5200 tons per day. The approximate number of rail cars to support this facility is estimated at 

approximately 360 rail cars per week. 
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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 estimated total volume of water required for cooling tower 

makeup, cycle makeup, and cooling for the CO2 system is approximately 10,000 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 

appropriate geologic formations. The costs presented herein do not account for equipment, piping, or 

structures associated with CO2 sequestration.

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

The base cost estimate for this technology case totals $4558/kW. Table 2-1 summarizes the cost 

components for this case. Cost associated with CO2 sequestration have been excluded. The basis of the 

estimate assumes that the site is constructed in a United States region that has good access to lowercost 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. No special 

systems are needed to prevent freezing or to account for snow loads on structures. 

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 and the southwest and 

the mountain west regions, ACCs are used in lieu of mechanical draft cooling towers. In regions where 
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wastewater loads to rivers and reservoirs are becoming increasingly restricted, ZLD equipment is added. 

Zero liquid discharge 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 STG equipment will be enclosed in all locations.

Table 2-1 — Case 2 Capital Cost Estimate

Case 2

EIA – Capital Cost Estimates – 2019 $s

Configuration

650 MW Net, Ultra-Supercritical Coal w/ 

30% Carbon Capture

1 x 769 MW Gross

Combustion Emissions Controls Low NOx Burners / OFA

Post-Combustion Emissions Controls SCR / Baghouse/ WFGD / WESP - AMINE 

Based CCS

Fuel Type High Sulfur Bituminous

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 650

Heat Rate, HHV Basis Btu/kWh 9751

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 12%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 300

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 2,520,000

 Miles miles 1.00

 Substation Expansion $ 0

Gas Interconnection Costs

 Pipeline Cost $/mile 2,500,000

 Miles miles 0.50

 Metering Station $ 3,600,000

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 36

Total Lead Time Before COD months 60

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 263,200,000

Mechanical – Boiler Plant $ 935,766,667

Mechanical – Turbine Plant $ 185,866,667

Mechanical – Balance of Plant $ 49,966,667

Mechanical Subtotal $ 1,171,600,000
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Case 2

EIA – Capital Cost Estimates – 2019 $s

Configuration

650 MW Net, Ultra-Supercritical Coal w/ 

30% Carbon Capture

1 x 769 MW Gross

Combustion Emissions Controls Low NOx Burners / OFA

Post-Combustion Emissions Controls SCR / Baghouse/ WFGD / WESP - AMINE 

Based CCS

Fuel Type High Sulfur Bituminous

Units

Electrical – Main Power System $ 21,100,000

Electrical – Aux Power System $ 25,800,000

Electrical – BOP and I&C $ 107,900,000

Electrical – Substation and Switchyard $ 18,100,000

Electrical Subtotal $ 172,900,000

CCS Plant Subtotal $ 278,752,000

Project Indirects $ 347,200,000

EPC Total Before Fee $ 2,233,652,000

EPC Fee $ 223,365,200

EPC Subtotal $ 2,457,017,200

Owner's Cost Components (Note 2)

Owner's Services $ 171,991,000

Land $ 9,000,000

Electrical Interconnection $ 2,520,000

Gas Interconnection $ 4,850,000

Owner's Cost Subtotal $ 188,361,000

Project Contingency $ 317,445,000

Total Capital Cost $ 2,962,823,200

 $/kW net 4,558

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, gas interconnection costs (if applicable), and 

land acquisition costs.

2.3 O&M COST ESTIMATE

The O&M costs for the USC coal-fired power generation facility with 30% carbon capture are 

summarized in Table 2-2. The fixed costs cover the O&M labor, contracted maintenance services and 

materials, and 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 fiveto six-year cycle, while shorter outages (e.g., change out SCR catalyst) are generally performed on a 

three-year 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 
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that some type of service agreement would be needed for the compressors, absorbers, strippers, and 

other specialized equipment.

Non-fuel variable costs for this technology case include FGD reagent costs, 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, FGD waste disposal costs, and solvent makeup. 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 combustion turbine [CT] blowdown treatment), and additional demineralized makeup 

water costs.

Table 2-2 — Case 2 O&M Cost Estimate

Case 2

EIA – Non-Fuel O&M Costs – 2019 $s

650 MW Net, Ultra-Supercritical Coal w/ 30% Carbon Capture

Fixed O&M – Plant (Note 1)

Labor $/year 18,177,000

Materials and Contract Services $/year 10,959,000

Administrative and General $/year 6,156,000

Subtotal Fixed O&M $/year 35,292,000

$/kW-year $/kW-year 54.30 $/kW-year

Variable O&M (Note 2) $/MWh 7.08 $/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, limestone, water, ash disposal, FGD waste disposal, and water discharge 

treatment cost.

2.4 ENVIRONMENTAL & 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. The CO2 emissions estimates are based on a 30% removal from the default 

CO2 emissions factors listed in Table C-1 of 40 CFR 98, Subpart C.
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Table 2-3 — Case 2 Emissions

Case 2

EIA – Emissions Rates

650 MW Net, Ultra-Supercritical Coal w/ 30% Carbon Capture

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.06 (Note 2)

SO2 lb/MMBtu 0.09 (Note 3)

CO2 lb/MMBtu 144 (Note 4)

Emissions Control Notes 

1. High sulfur Bituminous Coal, 4.3 lb/MMBtu SO2 Coal

2. NOx Removal using LNBs with OFA, and SCR

3. SO2 Removal by Forced Oxidation, Limestone Based, Wet FGD, 98% Reduction

4. 30% reduction from baseline Per 40 CFR 98, Subpt. C, Table C-1
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CASE 3. ULTRA-SUPERCRITICAL COAL WITH 90% 

CO2 CAPTURE, 650 MW

3.1 CASE DESCRIPTION

This case comprises a coal-fired power plant with a nominal net capacity of 650 MW with a single steam 

generator and ST with coal storage and handling systems, BOP systems, emissions control systems, and 

a 90% CO2 capture system. This case is similar to the plant description provided in (Case 1) and (Case 

2); however, this case employs 90% CO2 capture system for the entire flue gas stream, which requires a 

larger boiler size and higher heat input to account for the low-pressure steam extraction and larger 

auxiliary loads needed for the CO2 capture technology used. The steam cycle is generally similar to the 

UCS cases with carbon capture; however, the boiler feedwater pumps are steam driven as opposed to 

motor driven. 

The CO2 capture systems are commonly referred to as 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 compressed to supercritical conditions and injected into a pipeline at terminated at the fence 

line of the facility. For this report, the terms “CO2 capture” and “carbon capture” are used 

interchangeably. 

As with Case 1 and Case 2, the base configuration used for the cost estimate is a single-unit station 

constructed on a greenfield site of approximately 300 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 used for cycle cooling 

and steam cycle makeup is provided by an adjacent fresh water reservoir or river.

Mechanical Equipment & 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 CO2 capture systems 

used as the basis for the capital and O&M cost estimates.

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 
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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 psia. The amine based solvent systems are typically designed for 90% CO2 capture 

in the absorption column. Please refer to Figure 2-1 for simplified process flow diagram of the CO2

capture system.

CO2 Capture Systems

It is assumed that this case will be built with full integration to the CO2 capture facility. 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, which 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 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 compressor 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. Doing so 

requires a larger boiler or turbine to maintain the same net power output of the facility. Overall, CO2

capture system integration can account for a net derate of approximately 30% in comparison with the 

base facility power output. 

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 is not a minor flow rate. CO2 capture systems can require similar circulating cooling water rates 

as condensers themselves. 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 
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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 is used to cool 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. This 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 WFGD 

for makeup water. Due to the reuse, it does not require additional O&M costs. 

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. 

90% CO2 Capture

For the case where a new USC coal-fired facility is required to provide 90% CO2 reduction, the full flue 

gas path must be treated. As referenced previously, 90% 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 

90% 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. 

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 90% CO2 capture. Approximately 2,370,000 lb/hr of low-pressure steam is required for 

the CO2 system. While the boiler efficiency is assumed to be 87.5%, the estimated gross size of the steam 
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generator is approximately 1,054 MW, which is approximately 40% larger than the case without carbon 

capture (Case 1). The estimated total auxiliary load for the plant is 181 MW, with 118 MW required for 

the for the CO2 system. The net heat rate is estimated to be 12507 Btu/kWh based on the HHV of the 

fuel and the net electrical output.

Electrical & Control Systems

The electrical equipment includes the turbine generator, which is connected via generator circuit 

breakers to a 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 DCS.

Offsite Requirements

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

6700 tons per day. The number of rail cars to support this facility is estimated at approximately 470 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 17,000 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.

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. 
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3.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $5876/kW. Table 3-1 summarizes the cost 

components for this case. Cost associated with CO2 sequestration have been excluded. The basis of the 

estimate assumes that the site is constructed in a United States region that has good access to lowercost 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. No special 

systems are needed to prevent freezing or to account for snow loads on structures. 

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 and 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, ZLD equipment is added. 

Zero liquid discharge 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 STG equipment will be enclosed in all locations.
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 3-1 — Case 3 Capital Cost Estimate

Case 3

EIA – Capital Cost Estimates – 2019 $s

Configuration

650 MW Net, Ultra-Supercritical Coal 

w/ 90% Carbon Capture

1 x 831 MW Gross

Combustion Emissions Controls Low NOx Burners / OFA

Post-Combustion Emissions Controls SCR / Baghouse/ WFGD / WESP / AMINE 

Based CCS 90%

Fuel Type High Sulfur Bituminous

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 650

Heat Rate, HHV Basis Btu/kWh 12507

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect 

Costs 10%

Project Contingency % of Project Costs 15%

Owner's Services % of Project Costs 5%

Estimated Land Requirement (acres) $ 300

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 2,520,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile 2,500,000

Miles miles 0.50

Metering Station $ 3,600,000

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 36

Total Lead Time Before COD months 60

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 311,200,000

Mechanical – Boiler Plant $ 967,433,333

Mechanical – Turbine Plant $ 242,533,333

Mechanical – Balance of Plant $ 92,077,778

Mechanical Subtotal $ 1,302,044,444

Electrical – Main Power System $ 26,350,000

Electrical – Aux Power System $ 31,050,000

Electrical – BOP and I&C $ 113,150,000

Electrical – Substation and Switchyard $ 23,350,000

Electrical Subtotal $ 193,900,000

CCS Plant Subtotal $ 663,846,000

Project Indirects $ 390,200,000

EPC Total Before Fee $ 2,861,190,000

EPC Fee $ 286,119,000

EPC Subtotal $ 3,147,309,000

Owner's Cost Components (Note 2)

Owner's Services $ 157,365,000

Land $ 9,000,000

Electrical Interconnection $ 2,520,000

Gas Interconnection $ 4,850,000
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 3

EIA – Capital Cost Estimates – 2019 $s

Configuration

650 MW Net, Ultra-Supercritical Coal 

w/ 90% Carbon Capture

1 x 831 MW Gross

Combustion Emissions Controls Low NOx Burners / OFA

Post-Combustion Emissions Controls SCR / Baghouse/ WFGD / WESP / AMINE 

Based CCS 90%

Fuel Type High Sulfur Bituminous

Units

Owner's Cost Subtotal $ 173,735,000

Project Contingency $ 498,157,000

Total Capital Cost $ 3,819,201,000

 $/kW net 5,876

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, gas interconnection costs (if applicable), and 

land acquisition costs.

3.3 O&M COST ESTIMATE

The O&M costs for the USC coal-fired power generation facility with 90% carbon capture are 

summarized in Table 3-2. The fixed costs cover the O&M labor, contracted maintenance services and 

materials, and 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 fiveto six-year cycle, while shorter outages (e.g., change out SCR catalyst) are generally performed on a 

three-year 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 type of service agreement would be needed for the compressors, absorbers, strippers, and 

other specialized equipment.

Non-fuel Variable costs for this technology case include FGD reagent costs, 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, FGD waste disposal costs, and solvent makeup. 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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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 3-2 — Case 3 O&M Cost Estimate

Case 3

EIA – Non-Fuel O&M Costs – 2019 $s

650 MW Net, Ultra-Supercritical Coal w/ 90% Carbon Capture

Fixed O&M – Plant (Note 1)

Labor $/year 18,817,000

Materials and Contract Services $/year 12,051,000

Administrative and General $/year 7,836,000

Subtotal Fixed O&M $/year 38,704,000

$/kW-year $/kW-year 59.54 $/kW-year

Variable O&M (Note 2) $/MWh 10.98 $/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, limestone, water, ash disposal, FGD waste disposal, and water discharge 

treatment cost.

3.4 ENVIRONMENTAL & EMISSIONS INFORMATION

The emissions for the major criteria pollutants are summarized in Table 3-3. 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. The CO2 emissions estimates are based on a 90% removal from the default 

CO2 emissions factors listed in Table C-1 of 40 CFR 98, Subpart C.

Table 3-3 — Case 3 Emissions

Case 3

EIA – Emissions Rates

650 MW Net, Ultra-Supercritical Coal w/ 90% Carbon Capture

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.06 (Note 2)

SO2 lb/MMBtu 0.09 (Note 3)

CO2 lb/MMBtu 20.6 (Note 4)

Emissions Control Notes 

1. High sulfur Bituminous Coal, 4.3 lb/MMBtu SO2 Coal

2. NOx Removal using LNBs with OFA, and SCR

3. SO2 Removal by Forced Oxidation, Limestone Based, Wet FGD, 98% Reduction

4. 90% reduction from baseline Per 40 CFR 98, Subpt. C, Table C-1
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 4. INTERNAL COMBUSTION ENGINES, 20 MW

4.1 CASE DESCRIPTION

This case is a reciprocating internal combustion engine (RICE) power plant based on four large-scale 

natural-gas-fired engines. Each engine is rated nominally at 5.6 MW with a net capacity of 21.4 MW. 

The configuration is selected to represent the installation of peaking or supplemental capacity for a 

municipality or small utility.

Mechanical Equipment & Systems

The RICE power plant comprises four gas-fired engines that are coupled to a generator. The power plant 

also includes the necessary engine auxiliary systems, which are fuel gas, lubricated oil, compressed air, 

cooling water, air intake, and exhaust gas.

Each engine is comprised of 10 cylinders in a V configuration. The engines are a four-stroke, sparkignited, single fuel engine that operates on the Otto cycle. Each engine includes a turbocharger with an 

intercooler that uses the expansion of hot exhaust gases to drive a compressor that raises the pressure 

and density of the inlet air to each cylinder, leading to increased power output of the engine. Each engine 

is equipped with an SCR and carbon monoxide (CO) catalyst for emissions control.

The engines are cooled using a closed-loop cooling water system that circulates a water/glycol mixture 

through the engine block. Heat is rejected from the cooling water system by air-cooled radiators. A 

starting air system provides the high-pressure compressed air required to start the engine. An 

instrument air system is provided for standard instrumentation and plant air use. 

Electrical & Control Systems

The electrical generator is coupled to the engine. The generator is a medium voltage, air-cooled, 

synchronous alternating current (AC) generator. 

The engine original equipment manufacturer (OEM) provides a DCS that allows for a control interface, 

plant operating data, and historian functionality. The control system is in an onsite building. 

Programmable logic controllers are also provided throughout the plant for local operation.
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Offsite Requirements

Natural gas is delivered to the facility through a gas connection at the site boundary. A natural gas line 

is routed from the nearest gas lateral to a gas metering station at the site boundary. The gas pressure is 

reduced as necessary to meet the requirements of the facility downstream of the metering station. 

Since water consumption is minimal at the power plant, water is obtained from the municipal water 

supply. The power plant also includes minimal water treatment for onsite water usage. Wastewater is 

treated using an oil-water separator and then is directed to a municipal wastewater system. Used oil 

that is no longer filterable is stored in a waste oil tank and removed offsite with a vacuum truck. 

The power plant’s onsite switchyard is connected to the transmission system through a nearby 

substation.

4.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1810/kW. Table 4-1 summarizes the cost 

components for this case. 

Table 4-1 — Case 4 Capital Cost Estimate

Case 4

EIA – Capital Cost Estimates – 2019 $s

Configuration Internal Combustion Engines

4 x 5.6 MW

Combustion Emissions Controls None

Post-Combustion Emissions Controls SCR

Fuel Type Natural Gas

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 21.4

Net Plant Heat Rate, HHV Basis Btu/kWh 8295

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 8%

Owner's Services % of Project Costs 7.5%

Estimated Land Requirement (acres) $ 10

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 720,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile 100,000

Miles miles 0.50

Metering Station $ 75,000
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Case 4

EIA – Capital Cost Estimates – 2019 $s

Configuration Internal Combustion Engines

4 x 5.6 MW

Combustion Emissions Controls None

Post-Combustion Emissions Controls SCR

Fuel Type Natural Gas

Units

Typical Project Timelines

Development, Permitting, Engineering months 12

Plant Construction Time months 18

Total Lead Time Before COD months 30

Operating Life years 30

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 6,861,000

Engines (Note 3) $ 11,974,000

Mechanical BOP $ 5,521,000

Mechanical Subtotal $ 17,495,000

Electrical Subtotal $ 6,668,000

Project Indirects $ 180,000

EPC Total Before Fee $ 19,230,000

EPC Fee $ 1,923,000

EPC Subtotal $ 21,153,000

Owner's Cost Components (Note 2)

Owner's Services $ 1,586,000

Land $ 300,000

Owner Furnished Equipment (Note 3) $ 11,974,000

Electrical Interconnection $ 720,000

Gas Interconnection $ 125,000

Owner's Cost Subtotal $ 14,705,000

Project Contingency $ 2,869,000

Total Capital Cost $ 38,727,000

 $/kW net 1,810

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, gas interconnection costs (if applicable), 

and land acquisition costs.

3. Engines and associated auxiliaries procured by Owner from the engine OEM.
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4.3 O&M COST ESTIMATE

The O&M cost estimate includes all tasks discussed in the O&M estimate description.

Table 4-2 — Case 4 O&M Cost Estimate

Case 4

EIA – Non-Fuel O&M Costs – 2019 $s

Internal Combustion Engines

Fixed O&M – Plant (Note 1)

Subtotal Fixed O&M $/kW-year 35.16 $/kW-year

Variable O&M (Note 2) $/MWh 5.69 $/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.

4.4 ENVIRONMENTAL & EMISSIONS INFORMATION

NOX and CO emissions are maintained through an SCR and CO catalyst installed in the exhaust system 

of each engine. SO2 is uncontrolled but minimal and below emission limits because of the low amounts 

of SO2 in the natural gas fuel. Water, wastewater, solid waste, and spent lubricating oil are disposed of 

through conventional means.

Table 4-3 — Case 4 Emissions

Case 4

EIA – Emissions Rates

Internal Combustion Engines

Predicted Emissions Rates – Natural Gas

NOx lb/MMBtu 0.02 (Note 1)

SO2 lb/MMBtu 0.00

CO lb/MMBtu 0.03

CO2 lb/MMBtu 117 (Note 2)

Emissions Control Notes 

1. With SCR

2. Per 40 CFR98 Sub Part C – Table C1
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 5. COMBUSTION TURBINES AERODERIVATIVE, 

100-MW SIMPLE CYCLE

5.1 CASE DESCRIPTION

This case is comprised of two duplicate aeroderivative CTs in simple-cycle configuration. It is based on 

natural gas firing of the CTs, although dual fuel capability is provided. Output power voltage is stepped 

up for transmission to the external grid through an onsite switchyard.

Mechanical Equipment & Systems

Case 5 is comprised of a pair of aeroderivative dual fuel CTs in simple-cycle configuration, with a 

nominal output of 53.7 MW gross per turbine. After deducting internal auxiliary power demand, the net 

output of the plant is 105.1 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. Not included in the Case 5 configuration are SCR units for 

further reduction of NOX emissions or CO catalysts for further reduction of CO emissions. Refer to 

Figure 5-1 for a diagram of the CT systems.

Figure 5-1 — Case 2 Configuration

Note: Only one CT shown. Second CT has the same configuration.
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Combustion Turbines Aeroderivative, 100-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

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 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 in general operate at higher pressure ratios, have faster start-up times and ramp rates, and higher 

efficiencies compared to industrial frame CTs.

Electrical & Control Systems

Case 5 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 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 BOP systems (e.g., water supply to evaporative coolers, fuel supply). 

Offsite Requirements

Offsite provisions in Case 5 include:

• 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.

5.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1175/kW. 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, which 

include project development, studies, permitting, and legal; owner's project management; owner's 

engineering; and owner's participation in startup and commissioning. The estimate is presented as an 

overnight cost in 2019 dollars and thus excludes Allowance for Funds Used During Construction or 
5-3

SL-014940

Combustion Turbines Aeroderivative, 100-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

interest during construction. In addition to the cost of external systems noted above (e.g., fuel gas supply 

and transmission line), an estimated amount is included for the cost of land.

Table 5-1 — Case 5 Capital Cost Estimate

Case 5

EIA – Capital Cost Estimates – 2019 $s

Configuration Combustion Turbines – Simple Cycle 

2 x Aeroderivative Class 

Combustion Emissions Controls Dry Low Emissions Combustor

Post-Combustion Emissions Controls None

Fuel Type Natural Gas / No. 2 Backup

2 x 54 MW rating

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 105

Heat Rate, HHV Basis Btu/kWh 9124

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 20

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 1,200,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile 2,800,000

Miles miles 0.50

Metering Station $ 3,100,000

Typical Project Timelines

Development, Permitting, Engineering months 18

Plant Construction Time months 22

Total Lead Time Before COD months 40

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 6,300,000

Mechanical – Major Equipment $ 43,400,000

Mechanical – Balance of Plant $ 9,900,000

Mechanical Subtotal $ 53,300,000

Electrical Subtotal $ 15,400,000

Project Indirects $ 15,000,000

EPC Total Before Fee $ 90,000,000

EPC Fee $ 9,000,000

EPC Subtotal $ 99,000,000

Owner's Cost Components (Note 2)

Owner's Services $ 6,930,000

Land $ 600,000

Electrical Interconnection $ 1,200,000

Gas Interconnection $ 4,500,000
5-4

SL-014940

Combustion Turbines Aeroderivative, 100-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 5

EIA – Capital Cost Estimates – 2019 $s

Configuration Combustion Turbines – Simple Cycle 

2 x Aeroderivative Class 

Combustion Emissions Controls Dry Low Emissions Combustor

Post-Combustion Emissions Controls None

Fuel Type Natural Gas / No. 2 Backup

2 x 54 MW rating

Units

Owner's Cost Subtotal $ 13,230,000

Project Contingency $ 11,223,000

Total Capital Cost $ 123,453,000

 $/kW net 1,175

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, gas interconnection costs (if 

applicable), and land acquisition costs.

5.3 O&M COST ESTIMATE

Table 5-2 shows 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. 

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 25,000 EOH, and a major overhaul 

is performed every 50,000 EOH. (CTs generally have two criteria to schedule overhauls: number of 

equivalent starts and number of EOH. The aeroderivative CTs in Case 5 always use an EOH-driven 

maintenance overhaul schedule regardless of the operating profile. Refer to Case 6 for a starts-based 

overhaul schedule.) An additional advantage of an aeroderivative CTs is that, depending on the longterm 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).
5-5

SL-014940

Combustion Turbines Aeroderivative, 100-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 5-2 — Case 5 O&M Cost Estimate

Case 5

EIA – Non-Fuel O&M Costs – 2019 $s

Combustion Turbine – Simple Cycle 

Fixed O&M – Plant (Note 1)

Subtotal Fixed O&M $/kW-year 16.30 $/kW-year

Variable O&M (Note 2) $/MWh 4.70 $/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 and water discharge treatment cost. They are based on a number operating hours-based regimen.

5.4 ENVIRONMENTAL & EMISSIONS INFORMATION

For the Case 5 simple-cycle configuration, NOX emissions from the CT stacks when firing gas are 

indicated in Table 5-3. Although some locations in the United States would require SCRs and CO 

catalysts to further reduce stack emissions, SCRs and CO catalysts have not been included for Case 5. 

Table 5-3 — Case 5 Emissions

Case 5

EIA – Emissions Rates

Combustion Turbine – Simple Cycle 

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.09

SO2 lb/MMBtu 0.00

CO2 lb/MMBtu 117

Emissions Control Notes 

1. Natural Gas, no water injection
6-1

SL-014940

Combustion Turbine F Class, 240-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 6. COMBUSTION TURBINE F CLASS, 240-MW 

SIMPLE CYCLE

6.1 CASE DESCRIPTION

This case is comprised of one industrial frame Model F 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.

Mechanical Equipment & Systems

Case 6 is comprised of one industrial frame Model F dual fuel CT in simple-cycle configuration with a 

nominal output of 237.2 MW gross. After deducting internal auxiliary power demand, the net output of 

the plant is 232.6 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. Not included in the Case 6 configuration is an SCR unit 

for further reduction of NOX emissions or a CO catalyst for further reduction of CO emissions. Figure 

6-1 shows a diagram of the CT systems.

Figure 6-1 — Case 6 Configuration
6-2

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Combustion Turbine F Class, 240-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Frame CTs differ from aeroderivative CTs in that the industrial frame CT’s performance characteristics 

generally are more conducive to improved performance in CC applications; that is, industrial frame CTs 

have a greater amount of exhaust energy to produce steam for the CC’s steam turbine 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.

Electrical & Control Systems

Case 6 includes one 60-Hz CT electric generator with an approximate rating of 240 MVA and output 

voltage of 13.8 kV. The generator output power is converted to a higher voltage by 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 BOP systems (e.g., water supply to evaporative coolers, fuel supply) 

Offsite Requirements

Offsite provisions in Case 6 include:

• 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.

6.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $713/kW. Table 6-1 summarizes the cost 

components for this case. This estimate is based on an EPC contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 6-1 covers owner’s costs, which 

include project development, studies, permitting, and legal; owner's project management; owner's 

engineering; and owner's participation in startup and commissioning. The estimate is presented as an 

overnight cost in 2019 dollars and thus excludes Allowance for Funds Used During Construction or 

interest during construction. In addition to the cost of external systems noted above (e.g., fuel gas 

supply), an estimated amount is included for the cost of land.
6-3

SL-014940

Combustion Turbine F Class, 240-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 6-1 — Case 6 Capital Cost Estimate

Case 6

EIA – Capital Cost Estimates – 2019 $s

Configuration Combustion Turbine – Simple Cycle 

F-Class

Combustion Emissions Controls Dry Low Emissions Combustor

Post-Combustion Emissions Controls None

Fuel Type Natural Gas / No. 2 Backup

1 x 237 MW rating

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 233

Heat Rate, HHV Basis Btu/kWh 9905

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 20

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 1,200,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile 2,800,000

Miles miles 0.50

Metering Station $ 3,100,000

Typical Project Timelines

Development, Permitting, Engineering months 18

Plant Construction Time months 22

Total Lead Time Before COD months 40

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 12,300,000

Mechanical – Major Equipment $ 54,000,000

Mechanical – Balance of Plant $ 17,200,000

Mechanical Subtotal $ 71,200,000

Electrical Subtotal $ 20,200,000

Project Indirects $ 19,000,000

EPC Total Before Fee $ 122,700,000

EPC Fee $ 12,270,000

EPC Subtotal $ 134,970,000

Owner's Cost Components (Note 2)

Owner's Services $ 9,448,000

Land $ 600,000

Electrical Interconnection $ 1,200,000

Gas Interconnection $ 4,500,000

Owner's Cost Subtotal $ 15,748,000

Project Contingency $ 15,072,000

Total Capital Cost $ 165,790,000

 $/kW net 713
6-4

SL-014940

Combustion Turbine F Class, 240-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 6

EIA – Capital Cost Estimates – 2019 $s

Configuration Combustion Turbine – Simple Cycle 

F-Class

Combustion Emissions Controls Dry Low Emissions Combustor

Post-Combustion Emissions Controls None

Fuel Type Natural Gas / No. 2 Backup

1 x 237 MW rating

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, gas interconnection costs (if applicable), 

and land acquisition costs.

6.3 O&M COST ESTIMATE

Operation and maintenance 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. 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 significant overhaul is performed for this type of CT every 

900 equivalent starts, and a major overhaul is performed every 2,400 equivalent starts. (CTs generally 

have two criteria to schedule overhauls: number of equivalent starts and number of EOH. In Case 6, it 

is assumed the operating profile results in a starts-driven maintenance overhaul schedule. Refer to Case 

5 for an EOH-based overhaul schedule.) In Table 6-2, the cost per start is broken out from the variable 

O&M costs that cover the consumables. 
6-5

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Combustion Turbine F Class, 240-MW Simple Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 6-2 — Case 6 O&M Cost Estimate

Case 6

EIA – Non-Fuel O&M Costs – 2019 $s

Combustion Turbine – Simple Cycle

Fixed O&M – Plant (Note 1)

Subtotal Fixed O&M $/kW-year 7.00 $/kW-year

Variable O&M

Consumables, etc. (Note 2) $/MWh 0.60 $/MWh

CT Major Maintenance (Note 2) $/Start $18,500/Start

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 consumables costs include water, water discharge treatment cost, etc. based on $/MWh. In addition to the 

Consumables VOM, add CT Major Maintenance VOM costs, which are based on a starts operating regime, with cost per start indicated.

6.4 ENVIRONMENTAL & EMISSIONS INFORMATION

For the Case 6 simple-cycle configuration, NOX emissions from the CT stack when firing gas are 

indicated in Table 6-3. Although some locations in the United States would require SCRs and CO 

catalysts to further reduce stack emissions, an SCR and a CO catalyst have not been included for Case 

6.

Table 6-3 — Case 6 Emissions

Case 6

EIA – Emissions Rates

Combustion Turbine – Simple Cycle 

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.030

SO2 lb/MMBtu 0.00

CO2 lb/MMBtu 117

Emissions Control Notes 

1. Natural Gas, no water injection
7-1

SL-014940

Combustion Turbine H Class, 1100-MW Combined Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 7. COMBUSTION TURBINE H CLASS, 1100-MW 

COMBINED CYCLE

7.1 CASE DESCRIPTION

This case is comprised of one block of a CC power generation unit in a 2x2x1 configuration. The plant 

includes two industrial frame Model H “advanced technology” CTs and one STG. Case 7 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.

Mechanical Equipment & Systems

Case 7 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) with a nominal output for the CC plant of 

1114.7-MW gross. Each CT generates 385.2 MW gross; the STG generates 344.3 MW gross. After 

deducting internal auxiliary power demand, the net output of the plant is 1083.3 MW. Refer to Figure 

7-1 for a diagram of the Case 7 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 7 configuration are 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 7-1, which depicts a 

dedicated additional cooler for the CT assemblies in Case 7.

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. 
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Combustion Turbine H Class, 1100-MW Combined Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

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, 

however, this feature is not included in Case 7. (Supplemental HRSG firing, while increasing the MW 

output of the STG, reduces plant efficiency.)

A wet cooling tower system provides plant cooling for Case 7. A wet cooling tower is preferred over the 

alternative ACC approach since plant performance is better (i.e., 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 7-1 — Case 7 Configuration

Wet 

Cooling 

Tower

SCR/CO CATALYST SCR/CO CATALYST

Heat Recovery Steam Generator

HRSG #1

(Three Pressure Levels with Reheat)

Heat Recovery Steam Generator

HRSG #2

(Three Pressure Levels with Reheat)

Generator

Generator

Combustion Turbine #1

Combustion Turbine #2

Steam Turbine

HP / IP / LP Generator

Condenser

Fuel

Evap

Cooler Air

Water

Air

Water

Evap

Cooler

Heat Exchanger Feedwater

for CT Cooling

Feedwater Heat Exchanger 

for CT Cooling
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Combustion Turbine H Class, 1100-MW Combined Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Electrical & Control Systems

Case 7 includes one 60-Hz electric generator per CT with an approximate rating of 390 megavolt 

amperes (MVA) and output voltage of 13.8 kV. The STG includes one 60-Hz electric generator with an 

approximate 350-MVA rating. The output power from the three generators is converted to a higher 

voltage by GSUs for transmission to the external grid, transmitted through an onsite facility switchyard. 

The CC facility is controlled by a central 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 BOP

systems and equipment (e.g., water systems, fuel systems, main cooling systems). 

Offsite Requirements

Offsite provisions in Case 7 include:

• 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.

7.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $958/kW. Table 7-1 summarizes the cost 

components for this case. This estimate is based on an EPC contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 7-1 covers owner’s costs, which 

include project development, studies, permitting, and legal; owner's project management; owner's 

engineering; and owner's participation in startup and commissioning. The estimate is presented as an 

overnight cost in 2019 dollars and thus excludes Allowance for Funds Used During Construction or 

interest during construction. In addition to the cost of external systems noted above (e.g., fuel gas supply 

and transmission line), an estimated amount is included for the cost of land.
7-4

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Combustion Turbine H Class, 1100-MW Combined Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 7-1 — Case 7 Capital Cost Estimate

Case 7

EIA – Capital Cost Estimates – 2019 $s

Configuration Combined Cycle 2x2x1

H-Class

Combustion Emissions Controls Dry Low NOx combustor with axial fuel 

staging

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 deg F, 60% RH) MW 1083

Net Plant Heat Rate, HHV Basis Btu/kWh 6370

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 60

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 2,520,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile 2,800,000

Miles miles 0.50

Metering Station $ 4,500,000

Typical Project Timelines

Development, Permitting, Engineering months 18

Plant Construction Time months 24

Total Lead Time Before COD months 42

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 60,000,000

Mechanical – Major Equipment $ 294,000,000

Mechanical – Balance of Plant $ 196,000,000

Mechanical Subtotal $ 490,000,000

Electrical Subtotal $ 93,000,000

Project Indirects $ 150,000,000

EPC Total Before Fee $ 793,000,000

EPC Fee $ 79,300,000

EPC Subtotal $ 872,300,000

Owner's Cost Components (Note 2)

Owner's Services $ 61,061,000

Land $ 1,800,000

Electrical Interconnection $ 2,520,000

Gas Interconnection $ 5,900,000

Owner's Cost Subtotal $ 71,281,000

Project Contingency $ 94,358,000

Total Capital Cost $ 1,037,939,000

 $/kW net 958
7-5

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Combustion Turbine H Class, 1100-MW Combined Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 7

EIA – Capital Cost Estimates – 2019 $s

Configuration Combined Cycle 2x2x1

H-Class

Combustion Emissions Controls Dry Low NOx combustor with axial fuel 

staging

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst

Fuel Type Natural gas / No. 2 Backup

Post Firing No Post Firing

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, gas interconnection costs (if applicable), 

and land acquisition costs.

7.3 O&M COST ESTIMATE

Table 7-2 indicates 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. 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 

EOH the CT has run. Typically, a significant overhaul is performed for this type of CT every 25,000 

EOH, and a major overhaul is performed every 50,000 EOH. (CTs generally have two criteria to 

schedule overhauls: number of equivalent starts and number of EOH. Case 7 assumes the operating 

profile results in an EOH-driven maintenance overhaul schedule. Refer to Case 6 for a starts-based 

overhaul schedule.) Planned major outage work on the STG is scheduled less frequently than the CTs, 

typically planned for every six to eight years.
7-6

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Combustion Turbine H Class, 1100-MW Combined Cycle

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 7-2 — Case 7 O&M Cost Estimate

Case 7

EIA – Non-Fuel O&M Costs – 2019 $s

Combined Cycle 2x2x1

Fixed O&M – Plant (Note 1)

Subtotal Fixed O&M $/kW-year 12.20 $/kW-year

Variable O&M (Note 2) $/MWh 1.87 $/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, and water discharge treatment cost.

7.4 ENVIRONMENTAL & EMISSIONS INFORMATION

For the Case 7 CC configuration, NOX emissions from the HRSG stacks when firing gas are indicated in 

Table 7-3. 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.

Table 7-3 — Case 7 Emissions

Case 7

EIA – Emissions Rates

Combined Cycle 2x2x1

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.0075

SO2 lb/MMBtu 0.001

CO2 lb/MMBtu 117

Emissions Control Notes 

1. Natural Gas, no water injection
8-1

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Combustion Turbine H Class, Combined-Cycle Single Shaft, 430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 8. COMBUSTION TURBINE H CLASS, 

COMBINED-CYCLE SINGLE SHAFT, 430 MW

8.1 CASE DESCRIPTION

This case is comprised of one block of a combined-cycle power generation unit. The plant includes one 

industrial frame Model H “advanced technology” CT, one STG, and one electric generator that is 

common to the CT and the STG. Case 8 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.

Mechanical Equipment & Systems

Case 8 is comprised of one Model H dual fuel CT in a 1x1x1 single-shaft CC configuration with a nominal 

output for the CC plant of 430.4 MW gross. The CT generates 297.2 MW gross and the STG generates 

133.2 MW gross. After deducting internal auxiliary power demand, the net output of the plant is 418.3 

MW. Refer to Figure 8-1 for a diagram of the Case 8 process, which is similar to Case 7. 

The Case 8 layout differs from Case 7 in that Case 8 is a single-shaft CC plant. That is, the Case 8 CT, 

STG, and electric generator all share one horizontal shaft. Therefore, it has a more compact footprint 

than a plant like Case 7, where the CTs and STG have separate shafts and generators. Refer to Figure 

8-2 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, the single-shaft unit will have only one electric generator whereas a multiple shaft 

1x1x1 CC will have two generators. Also, the smaller footprint of the single-shaft unit will lessen 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 8 configuration is an SCR unit for further 

reduction of NOX emissions and a CO catalyst for further reduction of CO emissions. 

The CT is categorized as Model H 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
8-2

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Combustion Turbine H Class, Combined-Cycle Single Shaft, 430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

• 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 8-1, which depicts a 

dedicated additional cooler for the CT assemblies in Case 8.

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. 

Hot exhaust gas from the CT is directed to a HRSG. Steam generated in the HRSG is directed to the 

STG. An HRSG may be optionally equipped with additional supplemental firing, but this feature is not 

included in Case 8. (Supplemental HRSG firing, while increasing the MW output of the STG, reduces 

plant efficiency.)

Plant cooling for Case 8 is provided by a wet cooling tower system. Generally, a wet cooling tower is 

preferred over the alternative ACC approach since plant performance is better (i.e., 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 or 

expensive, such as in desert areas in the southwestern United States.
8-3

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Combustion Turbine H Class, Combined-Cycle Single Shaft, 430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 8-1 — Case 8 Configuration – Process Diagram

Note: Only one CT and one HRSG shown. Second CT and HRSG have the same configurations.
8-4

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Combustion Turbine H Class, Combined-Cycle Single Shaft, 430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 8-2 — Case 8 Configuration – Simplified Sketch

Conceptual sketch of a 1x1x1 single-shaft CT/steam turbine/generator plant

Electrical & Control Systems

Case 8 includes one 60-Hz electric generator for both the CT and steam turbine, with an approximate 

rating of 435 MVA and output voltage of 13.8 kV. The output power from the generator is converted to 

a higher voltage by a GSU for transmission to the external grid, transmitted through an onsite facility 

switchyard. 

The CC facility is controlled by a central 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 (e.g., water systems, fuel systems, main cooling systems). 

Offsite Requirements

Offsite provisions in Case 8 include:

• Fuel Gas Supply: A half-mile-long pipeline and a dedicated metering station. 

Wet 

Cooling 

Tower

SCR/CO CATALYST

Heat Recovery Steam Generator

HRSG 

(Three Pressure Levels with Reheat)

Generator

Combustion Turbine 

Steam Turbine

HP / IP / LP

Condenser

Fuel

Air

Water

Evap

Cooler

Feedwater

Heat Exchanger 

for CT Cooling
8-5

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Combustion Turbine H Class, Combined-Cycle Single Shaft, 430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

• 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.

8.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1084/kW. Table 8-1 summarizes the cost 

components for this case. The capital cost estimate is based on an EPC contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 8-1 covers owner’s costs, which 

include project development, studies, permitting, and legal; owner's project management; owner's 

engineering; and owner's participation in startup and commissioning. The estimate is presented as an 

overnight cost in 2019 dollars and thus excludes Allowance for Funds Used During Construction or 

interest during construction. In addition to the cost of external systems noted above (e.g., fuel gas supply 

and transmission line), an estimated amount is included for the cost of land.

Table 8-1 — Case 8 Capital Cost Estimate

Case 8

EIA – Capital Cost Estimates – 2019 $s

Configuration Combined Cycle 1x1x1, Single Shaft

H Class

Combustion Emissions Controls Dry Low NOx combustor with axial fuel 

staging

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 deg F, 60% RH) MW 418

Heat Rate, HHV Basis Btu/kWh 6431

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 60

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 1,800,000

Miles miles 1.00

Substation Expansion $ 0
8-6

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Combustion Turbine H Class, Combined-Cycle Single Shaft, 430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 8

EIA – Capital Cost Estimates – 2019 $s

Configuration Combined Cycle 1x1x1, Single Shaft

H Class

Combustion Emissions Controls Dry Low NOx combustor with axial fuel 

staging

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst

Fuel Type Natural Gas / No. 2 Backup

Post Firing No Post Firing

Units

Gas Interconnection Costs

Pipeline Cost $/mile 2,800,000

Miles miles 0.50

Metering Station $ 4,500,000

Typical Project Timelines

Development, Permitting, Engineering months 18

Plant Construction Time months 22

Total Lead Time Before COD months 40

Operating Life years 25

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 31,000,000

Mechanical – Major Equipment $ 130,000,000

Mechanical – Balance of Plant $ 73,000,000

Mechanical Subtotal $ 203,000,000

Electrical Subtotal $ 28,000,000

Project Indirects $ 80,000,000

EPC Total Before Fee $ 342,000,000

EPC Fee $ 34,200,000

EPC Subtotal $ 376,200,000

Owner's Cost Components (Note 2)

Owner's Services $ 26,334,000

Land $ 1,800,000

Electrical Interconnection $ 1,800,000

Gas Interconnection $ 5,900,000

Owner's Cost Subtotal $ 35,834,000

Project Contingency $ 41,203,000

Total Capital Cost $ 453,237,000

 $/kW net 1,084

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, gas interconnection costs (if applicable), 

and land acquisition costs.

8.3 O&M COST ESTIMATE

Operation and maintenance costs are indicated in Table 8-2. 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. 
8-7

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Combustion Turbine H Class, Combined-Cycle Single Shaft, 430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

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 EOH the CT has 

run. A significant overhaul is typically performed for this type of CT every 25,000 EOH, and a major 

overhaul is performed every 50,000 EOH. (CTs generally have two criteria to schedule overhauls: 

number of equivalent starts and number of EOH. In Case 8, it is assumed the operating profile results 

in an EOH-driven maintenance overhaul schedule. Refer to Case 6 for a starts-based 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.

Table 8-2 — Case 8 O&M Cost Estimate

Case 8

EIA – Non-Fuel O&M Costs – 2019 $s

Combined Cycle 1x1x1, Single Shaft

Fixed O&M – Plant (Note 1)

Subtotal Fixed O&M $kW-/year 14.10 $/kW-year

Variable O&M (Note 2) $/MWh 2.55 $/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, and water discharge treatment cost.

8.4 ENVIRONMENTAL & EMISSIONS INFORMATION

For the Case 8 CC configuration, NOX emissions from the HRSG stack when firing gas are indicated in 

Table 8-3. 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 8-3 — Case 8 Emissions

Case 8

EIA – Emissions Rates

Combined Cycle 1x1x1, Single Shaft

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.0075 (Note 2)

SO2 lb/MMBtu 0.00

CO2 lb/MMBtu 117

Emissions Control Notes 

1. Natural Gas, no water injection
9-1

SL-014940

Combustion Turbine H Class, Combined-Cycle Single Shaft with 90% CO2 Capture, 

430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 9. COMBUSTION TURBINE H CLASS, 

COMBINED-CYCLE SINGLE SHAFT WITH 90% CO2

CAPTURE, 430 MW

9.1 CASE DESCRIPTION

This case includes one block of a combined-cycle power generation unit in a 1x1x1 single-shaft 

configuration. The plant includes one industrial frame Model H “advanced technology” CT, one STG, 

and one electric generator that is common to the CT and the STG. Case 9 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 90% of the CO2 in the CT exhaust gas. 

Refer to Case 8 for a description the power generation systems, since Case 9 is the same in this regard. 

Mechanical Equipment & Systems

This technology case adds a 90% CO2 capture system to an industrial frame GE Model H 7HA.01 dual 

fuel CTs in a 1x1x1 single-shaft CC configuration. The nominal output of the CC plant unit without 

carbon capture is 430.4 MW gross. The major power cycle equipment and configurations are described 

in Case 8. The CO2 capture systems are commonly referred to as 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. For a brief description of the post-combustion, amine-based CO2 capture system, 

please refer to Case 5.

As with the technology of Case 8, the base configuration used for the cost estimate is a single CC unit 

power generation plant station constructed on a greenfield site of approximately 60 acres. 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. 

For Case 9, to obtain 90% CO2 removal from the flue gas generated from the CT, he full flue gas path 

must be treated. The flue gas generated from natural gas-fired CT combustions 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 
9-2

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Combustion Turbine H Class, Combined-Cycle Single Shaft with 90% CO2 Capture, 

430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

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 8.

The flue gas path differs from the base case (Case 8) in that 100% of the gas is directed to the carbon 

capture system located downstream of the preheater section of the HRSG. The 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 8 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 steam required for the carbon capture system is approximately 

306,000 pounds per hour. As a result of the steam extraction, the gross STG generation outlet decreases 

from 133 MW to 112 MW. 

The total auxiliary power required by the plant is 31.7 MW, of which 20 MW is used by the carbon 

capture system. The net output decreases from the base case (Case 8) from 418 MW to 377 MW. The 

net plant heat rate for the 90% carbon capture case is 7124 Btu/kWh, HHV basis (compared to 6431 

Btu/kWh, HHV basis, for Case 8).

Electrical & Control Systems

The electrical and controls systems for this case is essentially similar is scope to Case 8’s electrical 

system; however, the auxiliary power system supplies a much larger amount of medium voltage load for 

the 90% carbon capture case. 

The CC facility and the CO2 capture plant are controlled by a central DCS, which is linked to a CT control 

system provided by the CT manufacturer. It includes controls for the steam cycle systems and 

equipment as well as the BOP systems and equipment (e.g., water systems, fuel systems, main cooling 

systems). 
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Combustion Turbine H Class, Combined-Cycle Single Shaft with 90% CO2 Capture, 

430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Offsite Requirements

Offsite provisions in Case 9 include:

• 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 90% carbon capture case is significantly higher than for the base CC case (Case 8. The 

estimated increase in cooling water makeup is approximately 1,500 gallons per minute. 

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.

9.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $2481/kW. Table 9-1 summarizes the cost 

components for this case. The capital cost estimate is based on an EPC contracting approach. 

In addition to EPC contract costs, the capital cost estimate in Table 9-1 covers owner’s costs, which 

include project development, studies, permitting, and legal; owner's project management; owner's 

engineering; and owner's participation in startup and commissioning. The estimate is presented as an 

overnight cost in 2019 dollars and thus excludes Allowance for Funds Used During Construction or 

interest during construction. In addition to the cost of external systems noted above (e.g., fuel gas supply 

and transmission line), an estimated amount is included for the cost of land.
9-4

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Combustion Turbine H Class, Combined-Cycle Single Shaft with 90% CO2 Capture, 

430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 9-1 — Case 9 Capital Cost Estimate

Case 9

EIA – Capital Cost Estimates – 2019 $s

Configuration

Combined Cycle 1x1x1, Single Shaft, 

w/ 90% Carbon Capture

H-Class

Combustion Emissions Controls Dry Low NOx combustor with axial fuel 

staging

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 deg F, 60% RH) MW 377

Heat Rate, HHV Basis Btu/kWh 7124

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 60

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 1,800,000

 Miles miles 1.00

 Substation Expansion $ 0

Gas Interconnection Costs

 Pipeline Cost $/mile 2,800,000

 Miles miles 0.50

 Metering Station $ 4,500,000

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 30

Total Lead Time Before COD months 54

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 31,000,000

Mechanical – Major Equipment $ 130,000,000

Mechanical – Balance of Plant $ 73,000,000

Mechanical Subtotal $ 203,000,000

Electrical Subtotal $ 28,000,000

CCS Plant Subtotal $ 362,306,000

Project Indirects $ 90,000,000

EPC Total Before Fee $ 714,306,000

EPC Fee $ 71,430,600

EPC Subtotal $ 785,736,600

Owner's Cost Components (Note 2)

Owner's Services $ 55,002,000

Land $ 1,800,000

Electrical Interconnection $ 1,800,000

Gas Interconnection $ 5,900,000

Owner's Cost Subtotal $ 64,502,000

Project Contingency $ 85,024,000

Total Capital Cost $ 935,262,600

 $/kW net 2,481
9-5

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Combustion Turbine H Class, Combined-Cycle Single Shaft with 90% CO2 Capture, 

430 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 9

EIA – Capital Cost Estimates – 2019 $s

Configuration

Combined Cycle 1x1x1, Single Shaft, 

w/ 90% Carbon Capture

H-Class

Combustion Emissions Controls Dry Low NOx combustor with axial fuel 

staging

Post-Combustion Emissions Controls SCR Catalyst, CO Catalyst

Fuel Type Natural gas / No. 2 Backup

Post Firing No Post Firing

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, gas interconnection costs (if applicable), 

and land acquisition costs.

9.3 O&M COST ESTIMATE

Operation and maintenance costs are indicated in Table 9-2. 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 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 

EOH the CT has run. A significant overhaul is typically performed for this type of CT every 25,000 EOH, 

and a major overhaul is performed every 50,000 EOH. (CTs generally have two criteria to schedule 

overhauls: number of equivalent starts and number of EOH. In Case 9, it is assumed the operating 

profile results in an EOH-driven maintenance overhaul schedule. Refer to Case 6 for a start-based 

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.
9-6

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Combustion Turbine H Class, Combined-Cycle Single Shaft with 90% CO2 Capture, 

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Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 9-2 — Case 9 O&M Cost Estimate

Case 9

EIA – O&M Costs – 2019 $s

Combined Cycle 1x1x1, Single Shaft, w/ 90% Carbon Capture

Fixed O&M – Plant (Note 1)

Subtotal Fixed O&M $/kW-year 27.60 $/kW-year

Variable O&M (Note 2) $/MWh 5.84 $/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, and water discharge treatment cost.

9.4 ENVIRONMENTAL & EMISSIONS INFORMATION

For the Case 9 CC configuration with 90% carbon capture, NOX emissions from the plant when firing 

gas are indicated in Table 9-3. 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 90% for Case 9.

Table 9-3 — Case 9 Emissions

Case 9

EIA – Emissions Rates

Combined Cycle 1x1x1, Single Shaft, w/ 90% Carbon Capture

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.0075 (Note 2)

SO2 lb/MMBtu 0.00

CO2 lb/MMBtu 12

Emissions Control Notes 

1. Natural Gas, no water injection
10-1

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Fuel Cell, 10 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 10. FUEL CELL, 10 MW

10.1 CASE DESCRIPTION

This case is based on a 10-MW fuel cell power generation facility using a series of identical modular fuel 

cells. Fuel cells use a potential difference between a cathode and an anode. There is a chemical reaction 

between oxygen from the air and the fuel within the anode that releases an electron to generate a 

current. There are many types of fuel cells, but only two technologies have demonstrated capability for 

utility-sized projects: molten carbonate fuel cell and solid oxide fuel cells. These types of fuel cells 

operate at high temperatures, (greater than 1,000°F) providing the unique ability to use multiple types 

of fuel and allows for more design options such as combined heat and power production. This study is 

based on solid oxide fuel cells oriented in multiple 300-kW stacks. Solid oxide fuel cell stacks are 

intended to act as modular components that can be combined in various geometries to generate 

whatever capacity is required for the project. The 10-MW solid oxide fuel cell plant used in this estimate 

comprises 36 fuel cell stacks operating at 92% capacity. These stacks would be grouped together in 3 

groups of 12 stacks, and each group would have its own inverter.

Chemical Operation

A solid oxide fuel cell stack is comprised of thousands of individual fuel cells made of a ceramic 

electrolyte (typically yttria stabilized zirconia) with a thin anode coating on one side and cathode coating 

on the other. Solid oxide fuel cells operate by generating steam to reform natural gas methane into 

hydrogen and carbon monoxide at the anode. At the same time, hot air passes over the cathode which 

absorbs oxygen molecules. The oxygen molecules react with the electrons in the cathode to form oxygen 

ions that pass through an electrolyte to combine with the hydrogen and carbon monoxide in the anode 

to form carbon dioxide, water, a free electron, and heat. The free electron is harnessed and used to 

generate an electrical current that can be converted into power, the water and heat are recycled to 

continually generate steam to reform the fuel, and the carbon dioxide is a waste byproduct that is 

released outside of the fuel cell.
10-2

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Fuel Cell, 10 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 10-1 — Fuel Cell Chemical Reactions

Reaction Equation

Steam Reforming CCHH4 + HH2OO (gg) yyyyyyyyyyyy

�⎯⎯⎯� 3HH2 + CC

Electrolyte Reaction 3HH2 + CC + 2OO2

yyyyyyyyyyyy

�⎯⎯⎯� CCOO2 + 2HH2OO + ee− + HH HHHH

Net Solid Oxide Fuel Cell CCHH4 + HH2OO (gg) + 2OO2

yyyyyyyyyyyy

�⎯⎯⎯� CCOO2 + HH2OO + ee− + HH HHHH

Figure 10-1 — Simplified Solid Oxide Fuel Cell

Adapted from Battery Japan, 

https://www.batteryjapan.jp/en-gb/visit/feature10-tokyo.html (accessed June 12, 2019)

Mechanical Equipment & Systems

Due to the small physical size and relative simplicity in design of these modular fuel cell stacks, minimal 

additional equipment is required. The heating of air and water, fuel reforming, and current generation 

all occur within the fuel stack itself. Their only external mechanical requirement is a foundation and the 

gas interconnection for the fuel. For this cost breakdown, however, the stack itself will refer only to the 

fuel cells within it. The mechanical BOP includes heat recovery components; the fuel processor 

components; and the supply components for the fuel, water, and air. The electrical equipment includes 

the power electric equipment such as the inverter and step-up transformer as well as the control and 
10-3

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Fuel Cell, 10 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

instrumentation equipment. The most expensive single component of the facility is the electric 

inverters. Fuel cells use a hybrid inverter. Hybrid inverters eliminate the need for a direct current 

(DC)/DC converter to match the battery voltage and are relatively new on the market. The recent 

development of these inverters makes them more expensive than other inverters. 

Figure 10-2 — Typical Solid Oxide Fuel Cell Project

Source: Office of Fossil Energy – U.S. Department of Energy, ND. Digital Image.

Retrieved from Energy.gov, https://www.energy.gov/fe/science-innovation/clean-coal-research/solid-oxide-fuel-cells

(accessed July 8, 2019).

Offsite Requirements

Fuel cells require a water supply and natural fuel supply as well as water discharge. They are typically 

designed near existing transmission lines and typically have minimal offsite electrical interconnection 

and transmission costs.

10.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $6700/kW. Table 10-2 summarizes the cost 

components for this case. Although the costs shown are based on an EPC contracting basis, the utilitysized fuel cell projects have been structured as build, own, operate, and maintain by the fuel cell 

manufacturers with electricity purchase agreements with the client or end user at a set $/kilowatt hour 

(kWh) basis. With that in mind, most of the solid oxide fuel cell applications are for individual entities, 
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not microgrid or utility operations. These individual entities can range from small-scale businesses to 

large data centers that need 10+ MW of constant, uninterruptible power because they are unable to be 

offline for more than a few minutes.

Table 10-2 — Case 10 Capital Cost Estimate

Case 10

EIA – Capital Cost Estimates – 2019 $s

Configuration Fuel Cell

34 x 300 kW Gross

Fuel Cell Type Solid Oxide

Fuel Type Natural Gas

Units

Plant Characteristics

Net Plant Capacity MW 10

Heat Rate Btu/kWh 6469

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 5%

Project Contingency % of Project Costs 4%

Owner's Services % of Project Costs 8%

Estimated Land Requirement (acres) $ 2

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Gas Interconnection Costs

Pipeline Cost $/mile 2,500,000

Miles miles 0.25

Metering Station $ 1,200,000

Typical Project Timelines

Development, Permitting, Engineering months 21

Plant Construction Time months 3

Total Lead Time Before COD months 24

Operating Life years 20

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 3,764,000

Mechanical – Fuel Cell Stacks $ 11,601,000

Mechanical – Balance of Plant $ 16,033,000

Mechanical Subtotal $ 27,634,000

Electrical Subtotal $ 21,809,000

Project Indirects $ 3,075,000

EPC Total Before Fee $ 56,282,000

EPC Fee $ 2,814,000

EPC Subtotal $ 59,096,000

Owner's Cost Components (Note 2)

Owner's Services $ 4,728,000

Land $ 60,000

Gas Interconnection $ 1,825,000

Owner's Cost Subtotal $ 6,613,000

Project Contingency $ 2,628,000

Total Capital Cost $ 68,337,000

 $/kW net 6,700
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Case 10

EIA – Capital Cost Estimates – 2019 $s

Configuration Fuel Cell

34 x 300 kW Gross

Fuel Cell Type Solid Oxide

Fuel Type Natural Gas

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, gas interconnection costs (if applicable),

and land acquisition costs.

10.3 O&M COST ESTIMATE

Common practice for solid oxide fuel cell vendors is to build, operate, and maintain the fuel cell plant 

while charging a fixed monthly O&M to the owner of the project (i.e., the utility or corporation to which

they are selling the energy). This leads to a large amount of fixed O&M costs. The only exception being 

the water supply and discharge, which is left to the owner. These costs are shown as variable O&M 

within this estimate.

Table 10-3 — Case 10 O&M Cost Estimate

Case 10

EIA – Non-Fuel O&M Costs – 2019 $s

Fuel Cell

Fixed O&M – Plant (Note 1)

Routine Maintenance & Management $/year 34,000

Fuel Cell Maintenance Reserve $/year 280,000

Subtotal Fixed O&M $/year 314,000

 $/kW-year $/kW-year 30.78 $/kW-year

Variable O&M (Note 2) $/MWh 0.59 $/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 includes costs of water supply and water discharge.

10.4 ENVIRONMENTAL & EMISSIONS INFORMATION

Solid oxide fuel cell emissions are dependent on the fuel that is used: biofuel or natural gas. Biofuel 

allows for a reduction in emissions but carries a higher associated heat rate and operating cost. 

Therefore, in the interest of being economically competitive, most fuel cells today use natural gas. Even 

when using natural gas as the fuel source, fuel cells are considered a clean energy source. One important 

distinction between a natural gas-powered combustion turbine and a fuel cell that uses natural gas is 
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that the fuel cell does not burn the gas. Within the fuel cell, natural gas is reformed with steam, which 

still releases CO2 but reduces the other emissions, allowing fuel cells to maintain their “green” status.

Table 10-4 — Case 10 Emissions

Case 10

EIA – Emissions Rates

Fuel Cell

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.0002

SO2 lb/MMBtu 0.00

CO lb/MMBtu 0.005

CO2 lb/MMBtu 117

Emissions Control Notes 

1. Natural Gas
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Advanced Nuclear, 2156 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 11. ADVANCED NUCLEAR, 2156 MW

11.1 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 June 2018.

Mechanical Equipment & 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 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 enriched uranium is contained 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 cooling water then flows through a steam generator that provide 

steam to the steam turbine for electrical generation.

Electrical & 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 GSU. The GSI is
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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 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.

Offsite Requirements

Water for all processes at the power plant is obtained from a nearby river or lake. The 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 power plant onsite switchyard is typically

connected to the transmission line through a nearby substation.

11.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $6041/kW. Table 11-1 summarizes the cost 

components for this case.

Table 11-1 — Case 11 Capital Cost Estimate

Case 11

EIA – Capital Cost Estimates – 2019 $s

Configuration Advanced Nuclear (Brownfield)

2 x AP1000

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 2156

Net Plant Heat Rate, HHV Basis Btu/kWh 10608

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 20.0%

Estimated Land Requirement (acres) $ 60

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 2,520,000

 Miles miles 1.00

 Substation Expansion $ 0

Gas Interconnection Costs

 Pipeline Cost $/mile 0

 Miles miles 0.00

 Metering Station $ 0
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Case 11

EIA – Capital Cost Estimates – 2019 $s

Configuration Advanced Nuclear (Brownfield)

2 x AP1000

Units

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 48

Total Lead Time Before COD months 72

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 1,675,180,000

Nuclear Island $ 2,463,500,000

Conventional Island $ 1,379,560,000

Balance of Plant $ 788,320,000

Mechanical Subtotal $ 4,631,380,000

Electrical Subtotal $ 788,320,000

Project Indirects $ 1,872,260,000

EPC Total Before Fee $ 8,967,140,000

EPC Fee $ 896,714,000

EPC Subtotal $ 9,863,854,000

Owner's Cost Components (Note 2)

Owner's Services $ 1,972,771,000

Land $ 1,800,000

Electrical Interconnection $ 2,520,000

Gas Interconnection $ 0

Owner's Cost Subtotal $ 1,977,091,000

Project Contingency $ 1,184,095,000

Total Capital Cost $ 13,025,040,000

 $/kW net 6,041

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, gas interconnection costs (if applicable), 

and land acquisition costs.

Owner’s costs were reviewed to ensure that utility interconnection costs were accounted for 

appropriately. Specifically, 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.

11.3 O&M COST ESTIMATE

The O&M cost estimate includes all tasks discussed in the O&M estimate description.
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 11-2 — Case 11 O&M Cost Estimate

Case 11

EIA – Non-Fuel O&M Costs – 2019 $s

Advanced Nuclear (Brownfield)

Fixed O&M – Plant ($/year) (Note 1)

 Subtotal Fixed O&M $/kW-year 121.64 $/kW-year

Variable O&M ($/MWh) (Note 2) $/MWh 2.37 $/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.

11.4 ENVIRONMENTAL & 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.
12-1

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Small Modular Reactor Nuclear Power Plant, 600 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 12. SMALL MODULAR REACTOR NUCLEAR 

POWER PLANT, 600 MW

12.1 CASE DESCRIPTION

This case is based on 12 small reactor modules. Each module has a net capacity of 50 MW for a net plant 

capacity of 600 MW. The small modular reactor (SMR) case is not based on a particular OEM but rather 

is a representative SMR plant.

Mechanical Equipment and Systems

The mechanical systems of an SMR are much smaller than those of a traditional nuclear plant. The 

mechanical systems are similar to that 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 12 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 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. 

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 including the pool 

housed with the reactor building. This extra bay allows for removal of individual reactors for 

maintenance without impacting the remaining reactors. 
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Electrical and Control Systems

Each SMR has its own generator, which is a 60-Hz machine rated at approximately 45 MVA with an 

output voltage of 13.8 kV. The steam turbine electric generator is connected through a generator circuit 

breaker to a GSU that is in turn connected between two circuit breakers in the high-voltage bus in the 

facility switchyard through a disconnect switch. The GSU increases the voltage from the electric 

generator from 13.8 kV to interconnected transmission system high voltage. 

The SMR facility is controlled using a 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.

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 typically connected to the transmission line through a nearby substation.

12.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $6191/kW. Table 12-1 summarizes the cost 

components for this case.

Table 12-1 — Case 12 Capital Cost Estimate

Case 12 

EIA – Capital Cost Estimates – 2019 $s

Configuration Small Modular Reactor Nuclear Power Plant

12 x 50-MW Small Modular Reactor

Units

Plant Characteristics

Net Plant Capacity MW 600

Net Plant Heat Rate, HHV Basis Btu/kWh 10046

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7.5%

Estimated Land Requirement (acres) acres 35

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 2,520,000

Miles miles 1.00

Substation Expansion $ 0
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 12 

EIA – Capital Cost Estimates – 2019 $s

Configuration Small Modular Reactor Nuclear Power Plant

12 x 50-MW Small Modular Reactor

Units

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 48

Total Lead Time Before COD months 72

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 583,524,000

Nuclear Island $ 648,360,000

Conventional Island $ 421,434,000

Balance of Plant $ 389,016,000

Mechanical Subtotal $ 1,458,810,000

Electrical Subtotal $ 259,344,000

Project Indirects $ 551,000,000

EPC Total Before Fee $ 2,852,678,000

EPC Fee $ 285,267,800

EPC Subtotal $ 3,137,945,800

Owner's Cost Components (Note 2)

Owner's Services $ 235,346,000

Land $ 1,050,000

Electrical Interconnection $ 2,520,000

Gas Interconnection $ 0

Owner's Cost Subtotal $ 238,916,000

Project Contingency $ 337,686,000

Total Capital Cost $ 3,714,547,800

 $/kW net 6,191

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, gas interconnection costs (if applicable), and 

land acquisition costs.

Owner’s costs include 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 that any SMR built at this time would be a first-of-a-kind 

facility. The indicated costs do not include financial incentives such as tax credits or cost sharing 

arrangements through public-private partnerships that may support first-of-a-kind facilities.
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12.3 O&M COST ESTIMATE

The O&M cost estimate includes all tasks discussed in the O&M estimate description.

Table 12-2 — Case 12 O&M Cost Estimate

Case 12

EIA – Non-Fuel O&M Costs – 2019 $s

Small Modular Reactor Nuclear Power Plant

Fixed O&M – Plant (Note 1)

 Subtotal Fixed O&M $/kW-year 95.00 $/kW-year

Variable O&M (Note 2) $/MWh 3.00 $/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. Variable O&M costs include water, water discharge treatment cost, chemicals, and consumables. Fuel is not included.

12.4 ENVIRONMENTAL & 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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Biomass Plant, 50 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 13. BIOMASS PLANT, 50 MW

13.1 CASE DESCRIPTION

This case comprises a greenfield biomass-fired power generation facility with a nominal net capacity of 

50 MW with a single steam generator and condensing steam turbine with biomass storage and handling 

systems, BOP systems, in-furnace, and post-combustion emissions control systems. 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 and CO2 are not controlled.

Mechanical Equipment & Systems

The core technology for this case is a BFB boiler designed to fire wood chips. The boiler is a natural 

circulation balanced-draft, non-reheat cycle. For this size range, the boiler is assumed to be a topsupported design arranged in a similar manner as shown in Figure 13-1. 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 balanced-draft 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 1,400°F to 1,600°F, depending on the moisture content of the fuel. Diesel oil-fired 

startup 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 is used to complete combustion of the fuel and to control 

the emissions of NOX.

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 
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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, water 

treatment system and demineralized water storage tanks, a fire protection and detection system, diesel 

oil storage and transfer system, compressed air system, 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 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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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 13-1 — 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 (accessed June 5, 2019).

The plant performance estimates for BFB boilers firing wood chips is highly dependent on fuel moisture. 

Generally, BFB boiler efficiencies range from 75% to 80%. The estimated net heat rate firing wood chips 

is 13,300 Btu/kWh based on the HHV of the fuel.

Superheaters Sootblowers

Steam 

Drum

Downcomers

Economizers

Upper OFA Supply Duct

Upper OFA Ports

Lower OFA Supply Ducts

Start-up Burner 

Supply Duct

Lower OFA Ports

Start-up Burners

Bed Material

Furnace

Fuel Chutes

Open 

Bottom 

Hoppers

Bed Material 

Transfer

Conveyor

Bed Material 

Collection 

Conveyors

Fluidizing Air 

Supply Duct
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Electrical & Control Systems

The electrical system for this case includes the turbine generator which is connected via generator 

circuit breakers to a GSU. The GSU increases the voltage from the generator voltages level to the 

transmission system high voltage level. The facility and most of the subsystems are controlled using a 

central 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

Offsite Requirements

The facility is constructed on a greenfield site of approximately 50 acres. Wood chips are delivered to 

the facility by truck and rail. The maximum daily rate for wood chips for the facility is approximately 

1500 tons per day. 

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. 

13.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $4097/kW. Table 13-1 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 well 

water and/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. 
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Table 13-1 — Case 13 Capital Cost Estimate

Case 13

EIA – Capital Cost Estimates – 2019 $s

Configuration 50-MW Biomass Plant

Bubbling Fluidized Bed

Combustion Emissions Controls OFA

Post-Combustion Emissions Controls SCR / Baghouse

Fuel Type Woodchips

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 50

Heat Rate, HHV Basis Btu/kWh 13300

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 12%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 50

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 1,200,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile N/A

Miles miles N/A

Metering Station $ N/A

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 36

Total Lead Time Before COD months 60

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 22,266,000

Mechanical – Boiler Plant $ 60,477,000

Mechanical – Turbine Plant $ 8,230,000

Mechanical – Balance of Plant $ 20,111,000

Mechanical Subtotal $ 88,818,000

Electrical – Main and Auxiliary Power Systems $ 3,543,000

Electrical – BOP and I&C $ 17,657,000

Electrical – Substation and Switchyard $ 5,408,000

Electrical Subtotal $ 26,608,000

Project Indirects $ 15,418,000

EPC Total Before Fee $ 153,110,000

EPC Fee $ 15,311,000

EPC Subtotal $ 168,421,000

Owner's Cost Components (Note 2)

Owner's Services $ 11,789,000

Land $ 1,500,000

Electrical Interconnection $ 1,200,000

Gas Interconnection $ 0

Owner's Cost Subtotal $ 14,489,000

Project Contingency $ 21,949,000

Total Capital Cost $ 204,859,000

 $/kW net 4,097
13-6

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Biomass Plant, 50 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 13

EIA – Capital Cost Estimates – 2019 $s

Configuration 50-MW Biomass Plant

Bubbling Fluidized Bed

Combustion Emissions Controls OFA

Post-Combustion Emissions Controls SCR / Baghouse

Fuel Type Woodchips

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, gas interconnection costs (if applicable),

and land acquisition costs.

13.3 O&M COST ESTIMATE 

The O&M costs for 50-MW biomass wood-fired generation facility are summarized in Table 13-2. The 

fixed costs cover the O&M labor, contracted maintenance services and materials, and 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 (e.g., 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, and bed material makeup.
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 13-2 — Case 13 O&M Cost Estimate

Case 13

EIA – Non-Fuel O&M Costs – 2019 $s

50-MW Biomass Plant

Fixed O&M – Plant (Note 1)

Labor $/year 3,510,000

Materials and Contract Services $/year 1,250,000

Administrative and General $/year 1,526,000

Subtotal Fixed O&M $/year 6,286,000

 $/kW-year $/kW-year 125.72 $/kW-year

Variable O&M (Note 2) $/MWh 4.83 $/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, and water discharge treatment cost.

13.4 ENVIRONMENTAL & EMISSIONS INFORMATION

The emissions for the major criteria pollutants are summarized in Table 13-3. The NOX emissions 

assume that the in-furnace controls such as LNB, 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 estimates are based on emissions factors listed in 

Table C-1 of 40 CFR 98, Subpart C.

Table 13-3 — Case 13 Emissions

Case 13

EIA – Emissions Rates

50-MW Biomass Plant

Predicted Emissions Rates (Note 1)

NOx lb/MMBtu 0.08 (Note 2)

SO2 lb/MMBtu <0.03 (Note 3)

PM lb/MMBtu 0.03 (Note 4)

CO2 lb/MMBtu 206 (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 for wood fuel

4. Controlled using pulse jet fabric filter

5. Per 40 CFR 98, Subpt. C, Table C-1
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10% Biomass Co-Fire Retrofit

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 14. 10% BIOMASS CO-FIRE RETROFIT

14.1 CASE DESCRIPTION

This case is a retrofit of an existing 300-MW pulverized coal power facility to cofire wood biomass at a 

rate corresponding to 10% of the equivalent output in MW. In this scenario, the biomass fuel displaces 

coal to generate approximately 30 MW of the net output with the balance from coal. The type of boiler 

assumed for the retrofit is a balanced draft, radiant reheat type boiler that fires a high to medium sulfur 

bituminous coal through pulverizers. The firing system is either tangential or wall-fired and is assumed 

to have low-NOX features such as LNBs and OFA. The biomass is a pelletized wood-based material 

formed from sawdust or paper. The biomass is not mixed with the coal and is not fed through the 

pulverizers but is introduced into the boiler through separate burners in new water-wall openings. The 

heat input from the biomass displaces the equivalent heat input from coal.

Mechanical Equipment & Systems

Figure 14-1 summarizes schematically the equipment required for the retrofit of biomass cofiring 

equipment to an existing 300-MW coal-fired facility. A portion of the facility is modified to receive and 

store the biomass fuel. The biomass fuel storage area is constructed on a concrete pad and a roof to 

minimize exposure to rain and snow. A reclaim system will convey the fuel to a grinder and feeder 

system located near the boiler. The biomass is then fed into surge bins feeding four individual burners. 

The biomass is conveyed to the boiler with heated primary air. The biomass burners have windboxes 

for secondary air distribution. The boiler water walls are modified to account for the new biomass firing 

equipment. 

The BOP equipment modifications include additional fire detection and protection equipment. 

Additional duct control equipment is provided to minimize dangerous accumulation of fines. Additional 

automated and manual wash water systems are provided to remove any dust accumulation along the 

material handling path. Additional sootblowers are included in areas of the upper furnace and 

convective passes to address increases in fouling and slagging by the cofiring of the wood biomass. No 

modifications to the boiler post-combustion emissions controls are necessary; however, the boiler 

controls are modified to account for the redistribution of combustion air.

The introduction of biomass into the boiler will decrease the boiler efficacy. The estimated increase in 

heat rate for the 100% coal-fired base case is approximately 1.5%. 
14-2

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 14-1 — Biomass Cofiring in Coal-Fired Boilers, Separate Feed Arrangement

Source: NREL, DOE/EE-0288 Biomass Cofiring in Coal-Fired Boilers, 2004. PDF. 

Retrieved from NREL.gov, https://www.nrel.gov/docs/fy04osti/33811.pdf (accessed June 13, 2019).

Electrical & Control Systems

No major modifications to the electrical system are needed for this retrofit; however, new power feeds 

to the biomass fuel handling equipment and biomass conveying fans will be required. The plant DCS 

system will be upgraded to accommodate the additional input/output and control systems for the 

biomass handling and combustions systems. 

Offsite Requirements

The pelletized wood biomass is delivered to the facility by truck. The maximum daily biomass fuel rate 

for the facility is approximately 500 tons per day, which corresponds to 20 to 24 trucks per day. New 

roads and additional site access are provided to accommodate the increase in daily truck traffic. 

There are no substantial increases in the demands of cycle makeup water or cooling tower makeup. The 

service water demands increase due to the additional washdown systems needed for dust control, but 

the current water resources are sufficient to meet these demands. 
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Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

14.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $705/kW based on the net output from the 

biomass; in this case, it is 30 MW. Table 14-1 summarizes the cost components for this case. The basis 

of the estimate assumes that the site has sufficient space for the biomass fuel storage and sufficient 

auxiliary power capacity for the new electrical loads. 

Table 14-1 — Case 14 Capital Cost Estimate

Case 14

EIA – Capital Cost Estimates – 2019 $s

Configuration 10% Biomass Co-Fire Retrofit

300-MW PC Boiler

Combustion Emissions Controls LNB / OFA / SCR

Post-Combustion Emissions Controls ESP

Fuel Type Wood Pellets, up to 10%

Units

Plant Characteristics

Equivalent Biomass Plant Capacity MW 30

Heat Rate, HHV Basis % Change from Baseline + 1.5%

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 20%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (acres) $ 0

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 1,200,000

Miles miles 1.00

Substation Expansion $ N/A

Gas Interconnection Costs

Pipeline Cost $/mile N/A

Miles miles N/A

Metering Station $ N/A

Typical Project Timelines

Development, Permitting, Engineering months 18

Plant Construction Time months 8

Total Lead Time Before COD months 26

Operating Life years 20

Cost Components (Note 1) Total

Civil/Structural/Architectural Subtotal $ 1,572,000

Mechanical Subtotal $ 9,880,000

Electrical Subtotal $ 2,769,000

Project Indirects $ 749,000

EPC Total Before Fee $ 14,970,000

EPC Fee $ 1,497,000

EPC Subtotal $ 16,467,000
14-4

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10% Biomass Co-Fire Retrofit

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 14

EIA – Capital Cost Estimates – 2019 $s

Configuration 10% Biomass Co-Fire Retrofit

300-MW PC Boiler

Combustion Emissions Controls LNB / OFA / SCR

Post-Combustion Emissions Controls ESP

Fuel Type Wood Pellets, up to 10%

Units

Owner's Cost Components (Note 2)

Owner's Services $ 1,153,000

Land $ 0

Electrical Interconnection $ 0

Gas Interconnection $ 0

Owner's Cost Subtotal $ 1,153,000

Project Contingency $ 3,524,000

Total Capital Cost $ 21,144,000

 $/kW net 705

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, gas interconnection costs (if applicable), and 

land acquisition costs.

14.3 O&M COST ESTIMATE

The O&M costs for biomass cofiring are summarized in Table 14-2. Costs are normalized by the 

equivalent electrical output from biomass. The fixed costs cover the O&M labor, contracted 

maintenance services and materials, and G&A for the cofiring systems only. 

Non-fuel variable costs for this technology case include increased water treatment costs and increased 

fly ash and bottom ash disposal costs. 

Table 14-2 — Case 14 O&M Cost Estimate

Case 14

EIA – Non-Fuel O&M Costs – 2019 $s

10% Biomass Co-Fire Retrofit

Fixed O&M – Plant (Note 1)

Labor $/year 267,000

Materials and Contract Services $/year 350,000

Administrative and General $/year 150,000

Subtotal Fixed O&M $/year 767,000

 $/kW-year $/kW-year 25.57 $/kW-year

Variable O&M (Note 2) $/MWh 1.90 $/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, ash disposal, and water discharge treatment cost.
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

14.4 ENVIRONMENTAL & EMISSIONS INFORMATION

The emissions for the major criteria pollutants are summarized in Table 14-3. No major modifications 

to the emissions controls system are required; however, the combustion air and OFA distribution within 

the furnace need to be tuned and adjusted to optimize the performance on the biomass fuel. The NOX

emissions as measured at the outlet of the economizer are expected to decrease by up to 20% from 

baseline levels depending on the type of boiler and the coal fired. The SO2 emissions are expected to 

decrease by approximately 8%. and the CO2 emissions derived from coal reduce by approximately 8% 

from baseline levels. 

Table 14-3 — Case 14 Emissions

Case 14

EIA – Emissions Offsets

10% Biomass Co-Fire Retrofit

Predicted Emissions Rates (Note 1)

NOx % change at Economizer Outlet - 0 to -20% (Note 2)

SO2 % change at Economizer Outlet -8%

PM % change at Economizer Outlet 0%

CO2 (Derived from Coal) % change at Economizer Outlet -8% (Note 3)

Emissions Control Notes 

1. Emissions are presented as differentials to the baseline, uncontrolled emissions rates

2. In-furnace NOx reduction systems in place; LNBs and OFA

3. Based on a reduction of the coal derived CO2
15-1

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Geothermal Plant, 50 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 15. GEOTHERMAL PLANT, 50 MW

15.1 CASE DESCRIPTION

This case is a hydrothermal-based net 50-MW geothermal power plant using a binary cycle. Capital 

costs for geothermal power are highly site specific and technology specific. There are two distinct types 

of geothermal systems: Enhanced Geothermal System (EGS) and Hydrothermal. EGS technology uses 

fractures, or porous characteristics, in dry, hot rock to create a geothermal reservoir by injecting the 

water into the hot rock before commercial operation. Hydrothermal systems use naturally occurring 

geothermal aquifers that already have hot liquid water and/or steam within fractured or porous 

reservoirs.

Either type of geothermal system can use one of three general technologies for the generation of 

electricity: dry, flash, and binary cycle. The choice of technology is usually based on the temperature of 

the water (liquid, steam, or both) found within the geothermal reservoir (or the temperature of the EGSdeveloped reservoir). In some cases, these technologies may be combined, such as a flash plant with a 

bottoming binary cycle. Dry steam technology is used with geothermal reservoirs that produce 

superheated, dry steam that self-discharges from the production well. These systems are typically 

reserved for the upper range of reservoir temperatures. Flash technology is used with geothermal 

reservoirs that produce steam and water. The steam and water are separated at the surface with the 

steam being routed to a steam generator and the liquid either being reinjected into the well or being 

flashed into steam by a pressure reduction before being routed to a steam generator. This case assumes 

the use of the third technology: binary cycle.

The use of a binary cycle rather than flash would typically be considered for geothermal production 

temperatures of 350°F or less, although there is no firm temperature demarcation point as to when 

binary versus flash technologies should be used. Reservoirs with lower temperatures (approximately 

350°F or less) will typically be produced via wells that will not self-discharge and require a means of 

pumping the fluid from the reservoir up to the surface. This pumping is usually accomplished using 

individual pumps installed into each production well. The binary cycle is also commonly referred to as 

Organic Rankine Cycle.

When using a binary cycle, the produced reservoir fluid is maintained as a pressurized liquid (i.e., at a 

pressure above the saturation pressure corresponding to the fluid’s temperature) within the production 

well, the surface piping and plant equipment, all the way to the injection wells where it is readmitted to 
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Geothermal Plant, 50 MW

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

the reservoir. This pressurized state keeps the hot geothermal fluid from boiling (flashing), and the 

geothermal fluid is never in contact with ambient air. A portion of the heat content of the pressurized 

geothermal fluid is transferred into a working fluid via one or more heat exchanger(s). The working 

fluid is typically vaporized within the heat exchanger(s) and is then sent to a turboexpander where it 

expands and produces mechanical power. The turboexpander drives an electrical generator. Binary 

cycle power plants may use either air-cooling or water-cooling for condensing the turbo-expander 

exhaust back into a liquid. Currently, most geothermal plants operating within the United States use 

flash steam technology; however, this case assumes the use of binary cycle technology due to the lower 

temperatures of remaining unused geothermal resources. 

Utility-scale geothermal power requires high-temperature aquifers to be cost effective. Locating 

aquifers with a sufficiently high temperature and sustainable flow rate is a significant task. The costs 

associated with exploration and drilling of the wells often accounts for over 50% of the total overnight 

capital expenditures for a geothermal project. To isolate the costs of building and maintaining the 

geothermal plant itself, this study has assumed that the geothermal plant was built on a brownfield site. 

This means that a sufficiently hot aquifer has already been identified with production and injection wells 

already developed. While this is rare, it does occasionally occur within the industry. As the geothermal 

well gets hotter, lower flow rates are required to maintain the same output thus reducing capital costs 

and operation costs. This analysis assumes that the geothermal reservoir has a temperature of 300°F.

Mechanical Equipment & Systems

A binary cycle power plant has three independent fluid loops: (1) the geothermal fluid loop, (2) the 

closed working fluid loop, and (3) the open cooling water loop. A simplified image of binary cycle 

including loops (1) and (2) can be seen in Figure 15-1. The open geothermal loop is comprised of the 

production well(s), downhole well pump(s), piping to the power plant, heat exchanger(s) coupled with 

the working fluid, piping to the injection well field, and the injection well(s). The temperature and flow 

rate of the geothermal loop is dependent upon the properties of the reservoir, but it is always kept at a 

pressure above its flash point. A single geothermal production well typically has the potential to convert 

the well’s thermal power into around 3 MW of electric power. A geothermal plant typically has between 

a 2:1 ratio and a 1:1 ratio of production wells to injection wells. This system is assumed to have 17 

production wells and 10 injections wells.

The closed working fluid loop is comprised of a pump for pumping the working fluid in the liquid phase, 

a turboexpander that is connected to a generator, and heat exchanger(s). Heat exchangers transfer heat 
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

from the hot geothermal fluid to the working fluid, essentially boiling the working fluid and the resulting 

vapor is sent through the turboexpander. After the turboexpander, another heat exchanger (condenser) 

transfers heat from the working vapor, condensing it back into a liquid to be pumped back through the 

cycle. The working fluid typically has a low boiling point, which allows for reliable operation, and has a 

high conversion efficiency for good utilization of the geothermal heat. The 50-MW geothermal plant 

uses two working fluid loops, each with its own 25-MW steam turbine and generator.

Figure 15-1 — Geothermal Binary Cycle Power Plant

Source: Office of Energy Efficiency & Renewable Energy, 

Geothermal Technologies Office – U.S. Department of Energy, binaryplant, ND. Digital Image

Retrieved from Energy.gov, https://www.energy.gov/eere/geothermal/electricity-generation (accessed July 9, 2019)

The final loop, which is not shown in the diagram above, is an open loop of cooling water which is 

comprised of a cooling water pump, heat exchanger (condenser), and the cooling tower. The cooling 

system used for this case is a wet cooling tower. Water vapor from the cooling tower is the only emission 

of binary cycle power plants, with the exception of a cooling water blowdown stream from the cooling 
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Geothermal Plant, 50 MW

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

tower. Air-cooled condensers can also be used, but risk declines in power output during periods of high 

ambient temperature.

Electrical & Control Systems

This 50-MW geothermal plant uses two 25-MW turboexpanders with independent generators. 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.

Offsite Requirements

Geothermal plants use renewable heat from within the earth and naturally occurring water sources. This 

allows geothermal facilities to be free from requiring offsite fuel or materials. Water for the cooling 

system is either sourced from offsite or uses nearby natural sources such as a lake, freshwater well, or 

river. Unlike dry steam and flash power plants, binary cycle plants continually reinject all of the 

produced geothermal fluid back into the reservoir, thereby removing the need for brine processing and 

disposal. This reinjection of all produced mass also helps in maintaining reservoir pressure since there 

is no net mass removal from the reservoir.

15.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $2521/kW. Table 15-1 summarizes the cost 

components for this case. This price is dependent on the technology used, reservoir temperature, and 

location of the power plant. This analysis assumes that due to geological constraints, only the west coast 

of the United States should be considered for this cost estimate (i.e., California, Oregon, Washington, 

Nevada, and Idaho).
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 15-1 — Case 15 Capital Cost Estimate

Case 15

EIA – Capital Cost Estimates – 2019 $s

Configuration Geothermal

50 MW

Plant Configuration Binary Cycle

Units

Plant Characteristics

Net Plant Capacity MW 50

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 15%

Project Contingency % of Project Costs 8%

Owner's Services % of Project Costs 12%

Estimated Land Requirement (acres) $ 200

Estimated Land Cost ($/acre) $ 10,000

Electric Interconnection Costs

Transmission Line Cost $/mile 1,200,000

Miles miles 1.00

Substation Expansion $ 0

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 36

Total Lead Time Before COD months 60

Operating Life years 40

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 8,463,000

Mechanical – Steam Turbine $ 18,750,000

Mechanical – Production / Injection System $ 21,644,000

Mechanical – Balance of Plant $ 19,663,000

Mechanical Subtotal $ 60,057,000

Electrical – BOP and I&C $ 5,475,000

Electrical – Substation and Switchyard $ 4,302,000

Electrical Subtotal $ 9,777,000

Project Indirects $ 9,838,000

EPC Total Before Fee $ 88,135,000

EPC Fee $ 13,220,000

EPC Subtotal $ 101,355,000

Owner's Cost Components (Note 2)

Owner's Services $ 12,163,000

Land $ 2,000,000

Electrical Interconnection $ 1,200,000

Owner's Cost Subtotal $ 15,363,000

Project Contingency $ 9,337,000

Total Capital Cost $ 126,055,000

 $/kW net 2,521

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, gas interconnection costs (if applicable), 

and land acquisition costs.
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

15.3 O&M COST ESTIMATE

Different geothermal technologies have different O&M costs. Binary cycle geothermal plants are able to 

maintain the turbine (turboexpander) at a lower cost than other geothermal technologies due to the 

increased quality of the working fluid compared to the geothermal steam that passes through the turbine 

in dry steam and flash plant designs. What binary cycle plants save in turbine maintenance is lost in the 

additional pump maintenance since the other technologies do not require downhole pumps. 

Additionally, for binary cycle plants to produce equivalent net power outputs, they require higher flow 

rates from the production wells and have more overall pumps and piping compared to the other 

geothermal technologies. 

Table 15-2 — Case 15 O&M Cost Estimate

Case 15

EIA – Non-Fuel O&M Costs – 2019 $s

Geothermal

Fixed O&M – Plant (Note 1)

Labor $/year 1,470,000

Steam Turbine Maintenance $/year 3,750,000

Materials and Contract Services $/year 661,800

Administrative and General $/year 545,400

Subtotal Fixed O&M $/year 6,427,200

 $/kW-year $kW-year 128.54 $/kW-year

Variable O&M (Note 2) $/MWh 1.16 $/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, limestone, water, ash disposal, FGD waste disposal, and water discharge 

treatment cost.

15.4 ENVIRONMENTAL & EMISSIONS INFORMATION

While flash and dry geothermal power plants produce small emissions, binary cycle geothermal plants 

produce no regulated environmental emissions. The only emission is water vapor and small amounts of 

blowdown tower water from the cooling tower because the working fluid is kept in a closed loop and the 

geothermal loop is only open to the underground reservoir. Therefore, the emissions of NOx, SO2, and 

CO2 are 0.00 lb/MMBtu.
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Internal Combustion Engines, Landfill Gas, 30 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 16. INTERNAL COMBUSTION ENGINES, 

LANDFILL GAS, 30 MW

16.1 CASE DESCRIPTION

This case is a landfill gas-fired power plant that is powered by four reciprocating internal combustion 

engines. Each engine is nominally rated at 9.1 MW for a net capacity of 35.6 MW. The case only includes 

the power block and does not include any of the landfill gas gathering or filtering systems.

Mechanical Equipment and Systems

The RICE power plant comprises four large-scale gas-fired engines that are coupled to a generator. The 

power plant also includes the necessary engine auxiliary systems, which are fuel gas, lubricated oil, 

compressed air, cooling water, air intake, and exhaust gas.

Each engine is comprised of 10 cylinders in a V configuration. The engines are a four-stroke, sparkignited engine that operates on the Otto cycle. Each engine includes a turbocharger with an 

intercooler that uses the expansion of hot exhaust gases to drive a compressor that raises the 

pressure and density of the inlet air to each cylinder. The turbocharger is an axial 

turbine/compressor with the turbine and the centrifugal compressor mounted on the same shaft. 

Heat generated by compressing the inlet air is removed by a water-cooled “intercooler.” 

Turbocharging increases the engine output due to the denser air/fuel mixture.

The engines are cooled using a water/glycol mixture that circulates through the engine block, 

cylinder heads, and the charge air coolers. The cooling system is a closed-loop system and is divided 

into a high-temperature and a low-temperature circuit. The high-temperature circuit cools the 

engine block, cylinder heads, and the first stage of the charge air cooler. The low-temperature cooler 

cools the second stage of the charge air cooler. Heat is rejected from the cooling water system by 

air-cooled radiators.

Electrical and Control Systems

The electrical generator is coupled to the engine. The generator is a medium voltage, air-cooled, 

synchronous AC generator. 
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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

The engine OEM provides a DCS that allows for a control interface, plant operating data, and historian 

functionality. The control system is in an onsite building. Programmable logic controllers are also 

provided throughout the plant for local operation.

Offsite Requirements

Fuel for combustion is delivered through the landfill gas gathering system. As water consumption is 

minimal at the power plant, water is obtained from the municipal water supply. The power plant also 

includes minimal water treatment for onsite water usage. Wastewater is treated using an oil-water 

separator and then is directed to a municipal wastewater system. Used oil that is no longer filterable is 

stored in a waste oil tank and removed offsite with a vacuum truck. 

The power plant’s onsite switchyard is connected to the transmission system through a nearby 

substation.

16.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1563/kW. Table 19-1 summarizes the cost 

components for this case.

Table 16-1 — Case 16 Capital Cost Estimate

Case 16

EIA – Capital Cost Estimates – 2019 $s

Configuration Internal Combustion Engines

4 x 9.1 MW

Fuel Type Landfill Gas

Units

Plant Characteristics

Net Plant Capacity (60 deg F, 60% RH) MW 35.6

Net Plant Heat Rate, HHV Basis Btu/kWh 8513

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 8%

Owner's Services % of Project Costs 7.5%

Estimated Land Requirement (acres) $ 10

Estimated Land Cost ($/acre) $ 30,000

Interconnection Costs

Electrical Transmission Line Costs $/mile 720,000

Miles miles 1.00

Substation Expansion $ 0

Gas Interconnection Costs

Pipeline Cost $/mile 0

Miles miles 0.00

Metering Station $ 0

Typical Project Timelines
16-3

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Internal Combustion Engines, Landfill Gas, 30 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 16

EIA – Capital Cost Estimates – 2019 $s

Configuration Internal Combustion Engines

4 x 9.1 MW

Fuel Type Landfill Gas

Units

Development, Permitting, Engineering months 12

Plant Construction Time months 18

Total Lead Time Before COD months 30

Operating Life years 30

Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 12,464,000

Engines (Note 3) $ 13,637,000

Mechanical BOP $ 8,735,000

Mechanical Subtotal $ 22,372,000

Electrical Subtotal $ 9,803,000

Project Indirects $ 180,000

EPC Total Before Fee $ 31,182,000

EPC Fee $ 3,118,000

EPC Subtotal $ 34,300,000

Owner's Cost Components (Note 2)

Owner's Services $ 2,573,000

Land $ 300,000

Owner Furnished Equipment (Note 3) $ 13,637,000

Electrical Interconnection $ 720,000

Gas Interconnection $ 0

Owner's Cost Subtotal $ 17,230,000

Project Contingency $ 4,122,000

Total Capital Cost $ 55,652,000

 $/kW net 1,563

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, gas interconnection costs (if applicable), 

and land acquisition costs.

3. Engines and associated auxiliary procured from the engine OEM.

Owner’s costs were reviewed to ensure that utility interconnection costs were accounted for 

appropriately. Specific to the landfill gas case, a natural gas interconnection for engine fuel is not 

required. Additionally, it is expected that some electrical and water utilities will already be available at 

the existing landfill site.

16.3 O&M COST ESTIMATE

The O&M cost estimate includes all tasks discussed in the O&M estimate description.
16-4

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Internal Combustion Engines, Landfill Gas, 30 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 16-2 — Case 16 O&M Cost Estimate

Case 16

EIA – Non-Fuel O&M Costs – 2019 $s

Internal Combustion Engines

Fixed O&M – Plant (Note 1)

 Subtotal Fixed O&M $/kW-year 20.10 $/kW-year

Variable O&M (Note 2) $/MWh 6.20 $/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.

16.4 ENVIRONMENTAL & EMISSIONS INFORMATION

NOx and CO emissions are maintained through an SCR and CO catalyst installed in the exhaust system 

of each engine. SO2 is uncontrolled but minimal and below emission limits because of the low amounts 

of SO2 in the natural gas fuel. Water, wastewater, solid waste, and spent lubricating oil are disposed of 

through conventional means.

Table 16-3 — Case 16 Emissions

Case 16

EIA – Emissions Rates

Internal Combustion Engines

Predicted Emissions Rates – Natural Gas

NOx lb/MMBtu 0.02 (Note 1)

SO2 lb/MMBtu 0.00

CO lb/MMBtu 0.03

CO2 lb/MMBtu 115 (Note 2)

Emissions Control Notes 

1. With SCR

2. Per 40 CFR98 Sub Part C – Table C1
17-1

SL-014940

Hydroelectric Plant, 100 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 17. HYDROELECTRIC PLANT, 100 MW

17.1 CASE DESCRIPTION

This case is based on a “New Stream Reach Development” 100-MW hydroelectric power plant with 75 

feet of available head. 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 17-1 shows 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.

Case 17 is based on a concrete dam with a spillway and diversion tunnel to control the water level in the 

reservoir. There are two identical penstocks approximately 4.5 meters in diameter. Each penstock leads 

to a Francis-type hydro-turbine. Each of the two turbine-generators is rated for 50 MW. Power is 

stepped up from 13.8 kV to 154 kV for distribution.

Figure 17-1 — Storage-Type Hydroelectric Power Plant

Source: Tennessee Valley Authority, How Hydroelectric Power Works, ND. Digital Image.

Retrieved from TVA.gov, https://www.tva.gov/Energy/Our-Power-System/Hydroelectric/How-Hydroelectric-Power-Works

(accessed June 13, 2019).
17-2

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Hydroelectric Plant, 100 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 17-2 shows the dam and spill way of a storage-type hydroelectric power plant. 

Figure 17-2 — Dam and Spillway of Hydroelectric Power Plant

Source: Tennessee Valley Authority, Cherokee, ND. Digital Image.

Retrieved from TVA.gov, https://www.tva.gov/Energy/Our-Power-System/Hydroelectric/Cherokee-Reservoir (accessed June 13, 2019).

Figure 17-3 shows a typical turbine hall for a Francis-type hydropower turbine. The generator is located 

above the turbine and it connected to the same shaft.

Figure 17-3 — Typical Hydroelectric Power Turbine Hall

Source: Tennessee Valley Authority, Raccoon Mountain, ND. Digital Image. 

Retrieved from TVA.gov, https://www.tva.gov/Energy/Our-Power-System/Hydroelectric/Raccoon-Mountain (accessed July 8, 2019).
17-3

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Hydroelectric Plant, 100 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Offsite Requirements

The cost estimate assumes an allowance for a one-mile transmission line. 

17.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $5316/kW. Table 17-1 summarizes the cost 

components for this case. The capital cost estimate is based on an EPC contracting approach.In addition 

to EPC contract costs, the estimate includes owner’s costs that cover owner’s services, project 

development costs, studies, permitting, legal, project management, owner’s engineering, and start-up 

and commissioning. 

Table 17-1 — Case 17 Capital Cost Estimate

Case 17

EIA – Capital Cost Estimates – 2019 $s

Configuration Hydroelectric Power Plant

New Stream Reach Development

Units

Plant Characteristics

Net Power Rating MW 100

Head ft 75

Capital Cost Assumptions 

EPC Fee % of Project Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7%

Estimated Land Requirement (Support buildings only) acres 2

Estimated Land Cost $/acres 10,000

Electric Interconnection Costs

Transmission Line Cost $/mile 1,200,000

Miles miles 1.00

Typical Project Timelines

Development, Permitting, Engineering months 36

Plant Construction Time months 36

Total Lead Time Before COD months 72

Operating Life years 50

Cost Components Breakout Total

Direct Costs

Civil Structural Material and Installation $ 247,865,000

Mechanical Equipment Supply and Installation $ 73,759,000

Electrical / I&C Supply and Installation $ 25,094,000

Direct Cost Subtotal $ 346,718,000

Project Indirects (Note 1) $ 56,686,000

EPC Total Before Fee $ 403,404,000

EPC Fee $ 40,340,400

EPC Subtotal $ 443,744,400
17-4

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Hydroelectric Plant, 100 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 17

EIA – Capital Cost Estimates – 2019 $s

Configuration Hydroelectric Power Plant

New Stream Reach Development

Units

Owner's Cost Components

Owner's Services $ 38,351,000

Land $ 20,000

Electrical Interconnection $ 1,200,000

Owner's Cost Subtotal $ 39,571,000

Project Contingency $ 48,332,000 48,332,000

Total Capital Cost $ 531,647,400

 $/kW net 5,316

Capital Cost Notes

1. Engineering, procurement, scaffolding, project services, construction management, field engineering, and startup and commissioning 

using EPC contracting.

2. Project development, studies, permitting, legal, owner's project management, owner's engineering, and owner's participation in startup 

and commissioning. Excluded: Allowance for Funds Used During Construction, escalation excluded.

17.3 O&M COST ESTIMATE

The O&M cost estimate incorporates the annual cost of the onsite O&M staff as well as contracted 

services for grounds keeping and computer maintenance. The estimate also covers the maintenance of 

the dam, spillway, penstock, turbine, generator, and BOP. The need for various consumables and 

replacement parts are also considered. The annual cost of consumables, such as lubricants, filters, 

chemicals, etc., is estimated as a fixed amount, so the variable cost component is considered to be zero. 

Total annual O&M costs for the New Stream Reach Development 100-MW hydroelectric power plant 

are summarized in Table 17-2.

Table 17-2 — Case 17 O&M Cost Estimate

Case 17

EIA – Non-Fuel O&M Costs – 2019 $s

Hydroelectric Power Plant

Fixed O&M – Plant (Note 1)

 Subtotal Fixed O&M $/kW-year 29.86 $/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 G&A costs. O&M costs exclude property taxes and insurance.

17.4 ENVIRONMENTAL & EMISSIONS INFORMATION

Hydroelectric plants 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. 
18-1

SL-014940

Battery Energy Storage System, 50 MW / 200 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 18. BATTERY ENERGY STORAGE SYSTEM, 50 

MW / 200 MWH

18.1 CASE DESCRIPTION

This case consists of a utility-scale, lithium-ion, battery energy storage system (BESS) with a 50-MW 

power rating and 200-MWh energy rating; the system can provide 50 MW of power for a four-hour 

duration. Case 18 assumes that the BESS will be constructed close to an existing potential 

interconnection point such as grid or generator substation. The cost estimate includes a substation 

consisting of a transformer to step up from the BESS system to the interconnection voltage (480 V to 

13.8 kV) and associated switchgear. 

The BESS consists of 25 modular, pre-fabricated battery storage container buildings that contain the 

racks and appurtenances to store the initial set of batteries and accommodate battery augmentation for 

the life of the project. The BESS uses utility-scale lithium-ion batteries. Approximately 3% 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 18.3.) Each 

battery container is equipped with fire detection and suppression systems and HVAC monitoring and 

control systems. The pre-fabricated battery containers are approximately 40 feet long x 10 feet 

wide x 8 feet high. Each battery container has an associated inverter-transformer building, which is 

approximately 20 feet long x 10 feet wide x 8 feet high. The inverter-transformer building houses the 

inverters, transformers, and associated electrical equipment for each battery container. 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 18-1 shows a typical utility-scale lithium-ion battery. Several battery cells make a battery module, 

which is independently monitored and controlled. Several battery modules are contained in a battery 

rack, and there are several battery racks in a battery container.
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Battery Energy Storage System, 50 MW / 200 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 18-1 — 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 200 MWh of lithium-ion batteries connected in strings and 

twenty-five 2-MW inverters. Battery energy storage systems are DC systems; however, most electric 

power generation is produced and distributed as AC power. The BESS is equipped with a power 

conversion system to convert between AC power for charging and distribution and DC power for storage. 

The power conversion system includes transformers and associated switchgear that supports battery 

charging and discharging by converting power between 13.8 kV and 480 V-direct-current. Power is 

provided by the BESS at a three-phase output voltage of 480 AC. The output voltage is stepped up by a 

transformer to 34.5 kV and connects to the grid at a substation. This interconnecting substation is not 

part of the project.

Figure 18-2 — BESS Flow Diagram
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Battery Energy Storage System, 50 MW / 200 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Each battery container is equipped with electronic protection such as current limiters, sensors, and 

disconnect switches to isolate strings of batteries. The BESS is equipped with multiple levels of 

monitoring and controls. Each battery module and battery string are monitored and can be controlled 

by its Battery Management Unit and Battery String Management Unit, respectively. The power 

conversion system is also monitored and controlled. 

The BESS site is equipped with a Supervisory Control and Data Acquisition (SCADA) system that 

collects performance data from the Battery Management Units, Battery String Management Units, and 

power conversion system. The BESS can be monitored and controlled remotely through the SCADA 

system. Some BESS site may be programmed to respond to conditions in the grid through the SCADA 

system.

Figure 18-3 shows a cut-away view of a typical battery storage container.

Figure 18-3 — Typical Battery Storage Container

Source: Office of Scientific and Technical Information – U.S. Department of Energy, ND. Digital Image. Retrieved from OSTI.gov, 

https://www.osti.gov/biblio/1409737 (accessed July 15, 2019).
18-4

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Battery Energy Storage System, 50 MW / 200 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Offsite Requirements

Typically, BESS projects are built at the site of existing generators or near substations where the system 

can easily tie into a grid for charging and discharging power. This cost estimate includes an allowance 

for a substation consisting of a transformer to step up to the distribution voltage (480 V to 13.8 kV), 

associated switchgear, and transmission line to nearby tie-in so that the BESS can receive and distribute 

13.8 kV-alternating current power. 

The capital cost estimate assumes that road access is available and does not include the cost to build 

roads. Our cost estimate does not include an allowance for onsite storage of tools, chemicals, or other 

O&M necessities. The O&M cost estimate assumes the O&M contractor will bring all necessities to the 

BESS site.

18.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1389/kW or $347/kWh. Both the $/kW and 

$/kWh are provided to clearly describe the system estimate. Table 18-1 summarizes the cost 

components for this case. The capital cost estimate is based on a BESS with a power rating of 50 MW 

and energy rating of 200 MWh (equivalent to a four-hour rating). The cost estimate includes civil works, 

foundations, buildings, electrical equipment and related equipment, substation, switchyard, 

transformers, transmission lines, cabling, controls, and instrumentation. 

Table 18-1 — Case 18 Capital Cost Estimate

Case 18

EIA – Capital Cost Estimates – 2019 $s

Configuration

Battery Energy Storage System

50 MW | 200 MWh

Greenfield

Battery Type Lithium-ion

Service Life 10 years

Total Charging Cycles in Service Life 3,000

Units

Plant Characteristics

Power Rating MW 50

Energy Rating MWh 200

Duration hour 4

Capital Cost Assumptions 

 EPC Contracting Fee % of Project Costs 5%

 Project Contingency % of Project Costs 5%

 Owner's Services % of Project Costs 4%

 Estimated Land Requirement acre 2

 Estimated Land Cost $/acre 30,000
18-5

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Battery Energy Storage System, 50 MW / 200 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 18

EIA – Capital Cost Estimates – 2019 $s

Configuration

Battery Energy Storage System

50 MW | 200 MWh

Greenfield

Battery Type Lithium-ion

Service Life 10 years

Total Charging Cycles in Service Life 3,000

Units

Electric Interconnection Costs

 Transmission Line Cost $/mile 1,200,000

 Miles miles 0.00

Typical Project Timelines

 Development, Permitting, Engineering months 4

 Plant Construction Time months 6

 Total Lead Time Before COD months 10

EPC Cost Components (Note 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 8,314,000

 Batteries $ 40,037,000

 Inverters $ 5,237,000

 Grounding Wiring, Lighting, Etc. $ 254,000

 Transformers $ 533,000

 Cable $ 618,000

Electrical Subtotal $ 46,679,000

Raceway, Cable tray & Conduit $ 258,000

Control & Instrumentation $ 22,000

Transformer Switchgear, Circuit Breaker & Transmission Line $ 305,000

Other Equipment & Material Subtotal $ 585,000

Project Indirects $ 4,595,000

EPC Total Before Fee $ 60,173,000

EPC Fee $ 3,009,000

EPC Subtotal $ 63,182,000

Owner's Cost Components (Note 2)

Owner's Services $ 2,906,000

Land $ 60,000

Electrical Interconnections (Note 3) $ 0

Owner's Cost Subtotal $ 2,966,000

Project Contingency $ 3,308,000

Total Capital Cost $ 69,456,000

 $/kW net 1,389

 $/kWh 347

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, gas interconnection costs (if applicable), 

and land acquisition costs.

3. The BESS is assumed to be located sufficient close to an existing substation, such that any transmission costs are covered in the 

project electrical equipment cost. A separate electric transmission cost is not necessary.
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Battery Energy Storage System, 50 MW / 200 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

18.3 O&M 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 3000 

full charge-discharge cycles, which is a relatively typical basis in the industry. A full charge-discharge 

cycle occurs when a battery is fully charged, demand requires the full discharge of the energy, and then 

the battery is fully charged again. A service life of 3000 full cycles in a 10-year period equates to slightly 

fewer than 1 cycle per day. BESS projects that serve ancillary markets may not experience full charge 

and discharge cycle every day or may experience partial charge cycles. and The BESS service life depends 

on the charge and discharge pattern; therefore, a system that experiences partial charge cycles or 

multiple full cycles each day will have a different service life than described. The 3000 full-cycle service 

life is a typical industry basis to determine the cost and technical specifications for an energy storage 

system. 

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 review of equipment conditions and cable connections, grounds maintenance, and labor 

involved in battery augmentation. During the service life of a BESS, a percentage of the batteries are 

expected to significantly decrease in efficiency or stop functioning. Instead of removing and replacing 

those batteries, BESS are designed with excess racking to accommodate additional batteries to augment 

the lost capacity. The entire BESS will be removed when it is decommissioned at the end of its service 

life. This approach reduces the costs associated with removing and transporting failed batteries each 

year. Typically, BESS designs estimate that approximately 3% of the battery capacity will be needed to 

be augmented each year. This O&M cost estimate uses the 3% battery augmentation factor and 

incorporates that cost in the annual fixed O&M cost. The O&M cost include an annual allowance for 

G&A costs. The fixed O&M costs are $24.80/kW-year. The variable costs are $0.00/MWh, since there 

are no consumables linked to energy output. Augmentation is included with fixed cost in this case since 

the case assumes the same number of charging cycles each year during the service life of the project.

The O&M costs do not include the cost of energy to charge the system.
18-7

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Battery Energy Storage System, 50 MW / 200 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 18-2 — Case 18 O&M Cost Estimate

Case 18

EIA – Non-Fuel O&M Costs – 2019 $s

Battery Energy Storage System - 50 MW | 200 MWh - Greenfield

Fixed O&M – Plant (Note 1)

General & Administrative and Contract Services (Remote monitoring, 

on-site O&M, battery augmentation labor, grounds keeping, etc.) $/year 70,000

 Battery Augmentation $/year 1,170,000

 Subtotal Fixed O&M $/year 1,240,000

 $/kW-year $/kW-year 24.80 $/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.

18.4 ENVIRONMENTAL & EMISSIONS INFORMATION

Battery energy storage systems 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.
19-1

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Battery Energy Storage System, 50 MW / 100 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 19. BATTERY ENERGY STORAGE SYSTEM, 50 

MW / 100 MWH

19.1 CASE DESCRIPTION

This case is nearly identical to Case 18 with the exception that this is a BESS system with half the energy 

rating (100 MWh) and therefore half the duration (two hours). Since the energy rating for this case is 

half of Case 18, there will be half as many batteries. Therefore, this case will also have half as many 

battery containers. Case 19 assumes lithium-ion batteries are used, and the cost of civil works, 

foundations, buildings, electrical equipment and related equipment, substation, switchyard, 

transformers, transmission lines, cabling, and controls and instrumentation are included in the cost 

estimate. Case 19 assumes 3% of the initial set of batteries will require augmentation each year.

Refer to Case 18 for a more in-depth description of BESSs.

Offsite Requirements

Typically, BESS projects are built at the site of existing generators or near substations where the system 

can easily tie into a grid for charging and discharging power. This cost estimate includes an allowance 

for a substation consisting of a transformer to step up to the distribution voltage (480 V to 13.8 kV), 

associated switchgear, and transmission line to nearby tie-in so that the BESS can receive and distribute 

13.8 kV-alternating current power. 

19.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $845/kW or $423/kWh. Both the $/kW and 

$/kWh are provided to clearly describe the system estimate. Table 19-1 summarizes the cost 

components for this case. The capital cost estimate is based on a BESS with a power rating of 50 MW 

and energy rating of 100 MWh. Therefore, the BESS provides 50 MW of power for a duration of two 

hours. The capital cost estimate is based on an EPC contracting approach.

Typical project-related costs are included, such as owner’s services, project development costs, studies, 

permitting, legal, project management, owner’s engineering, and start-up and commissioning.
19-2

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Battery Energy Storage System, 50 MW / 100 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 19-1 — Case 19 Capital Cost Estimate

Case 19

EIA – Capital Cost Estimates – 2019 $s

Configuration

Battery Energy Storage System

50 MW | 100 MWh

Greenfield

Battery Type Lithium-ion

Service Life 10 years

Total Charging Cycles in Service Life 3,000

Units

Plant Characteristics

Power Rating MW 50

Energy Rating MWh 100

Duration hour 2

Capital Cost Assumptions 

EPC Contracting Fee % of Project Costs 5%

Project Contingency % of Project Costs 5%

Owner's Services % of Project Costs 4%

Estimated Land Requirement acre 1.2

Estimated Land Cost $/acre 30,000

Electric Interconnection Costs (Note 1)

Transmission Line Cost $/mile 1,200,000

Miles miles 0.00

Typical Project Timelines

Development, Permitting, Engineering months 4

Plant Construction Time months 5

Total Lead Time Before COD months 9

Cost Components (Notes 1) Breakout Total

Civil/Structural/Architectural Subtotal $ 6,071,000

Batteries $ 20,019,00

Inverters $ 5,237,000

Grounding Wiring, Lighting, Etc. $ 143,000

Transformers $ 533,000

Cable $ 370,000

Electrical Equipment Subtotal $ 26,302,000

Raceway, Cable tray & Conduit $ 155,000

Control & Instrumentation $ 22,000

Transformer Switchgear, Circuit Breaker & Transmission Line $ 305,000

Other Equipment & Material Subtotal $ 482,000

Project Indirects $ 3,679,000

EPC Total Before Fee $ 36,534,000

EPC Fee $ 1,827,000

EPC Subtotal $ 38,361,000

Owner's Cost Components (Note 2)

Owner's Services $ 1,850,000

Land $ 36,000

Electrical Interconnection Cost (Note 3) $ 0

Owner's Cost Subtotal $ 1,886,000

Project Contingency $ 2,013,000

Total Capital Cost $ 42,260,000

 $/kW net 845

 $/kWh 423
19-3

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Battery Energy Storage System, 50 MW / 100 MWh

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 19

EIA – Capital Cost Estimates – 2019 $s

Configuration

Battery Energy Storage System

50 MW | 100 MWh

Greenfield

Battery Type Lithium-ion

Service Life 10 years

Total Charging Cycles in Service Life 3,000

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, gas interconnection costs (if applicable),

and land acquisition costs.

3. The BESS is assumed to be located sufficient close to an existing substation, such that any transmission costs are covered in the 

project electrical equipment cost. A separate electric transmission cost is not necessary.

19.3 O&M COST ESTIMATE

The O&M cost estimate considers the ongoing O&M cost through the life of a BESS project. As 

mentioned in Case 18, the service life of a BESS depends on how it is used. This case assumes that the 

BESS will have a service life of 3000 full charge-discharge cycles, which is a relatively typical basis in 

the industry. A full charge-discharge cycle occurs when a battery is fully charged, demand requires the 

full discharge of the energy, and then the battery is fully charged again. A service life of 3000 full cycles 

in a 10-year period equates to slightly fewer than 1 cycle per day. BESS projects that serve ancillary 

markets may not experience a full charge and discharge cycle every day or may experience partial charge 

cycles. The BESS service life depends on the charge and discharge pattern; therefore, a system that 

experience partial charge cycles or multiple cull cycles each day will have a different service life than 

described. The service life of 3000 full cycles is a typical industry basis to determine the cost and 

technical specifications for an energy storage system. 

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 review of equipment conditions and cable connections, grounds maintenance, and labor 

involved in battery augmentation. During the service life of a BESS, a percentage of the batteries are 

expected to significantly decrease in efficiency or stop functioning. Instead of removing and replacing 

those batteries, BESS are designed with excess racking to accommodate additional batteries to augment 

the lost capacity. This approach reduces the costs associated with removing and transporting failed 

batteries each year. Typically, BESS designs estimate that approximately 3% of the total number of 

batteries installed will need to be augmented each year. The entire BESS will be removed when it is 
19-4

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Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

decommissioned at the end of its service life. This O&M cost estimate uses the 3% battery augmentation 

factor and incorporates that cost in the annual fixed O&M cost. The O&M cost includes an annual 

allowance for G&A costs. The fixed costs are $12.90/kW-year. The variable costs are $0.00/MWh, since 

there are no consumables linked to energy output. Augmentation is included with fixed cost in this case 

since the case assumes the same number of charging cycles each year during the service life of the 

project.

The O&M costs do not include the cost of energy to charge the system.

Table 19-2 — Case 19 O&M Cost Estimate

Case 19

EIA – Non-Fuel O&M Costs – 2019 $s

Battery Energy Storage System - 50 MW | 100 MWh – Greenfield

Fixed O&M – Plant (Note 1)

General & Administrative and Contract Services (Remote monitoring, on-site 

O&M, battery augmentation labor, grounds keeping, etc.) $/year 60,000

Battery Augmentation $/year 585,000

Subtotal Fixed O&M $/year 645,000

 $/kW-year $/kW-year 12.90 $/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 & EMISSIONS INFORMATION

Battery energy storage systems 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. 
20-1

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Onshore Wind, Large Plant Footprint, 200 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 20. ONSHORE WIND, LARGE PLANT 

FOOTPRINT, 200 MW

20.1 CASE DESCRIPTION

This case is an onshore wind power project located in the Great Plains region of the United States with 

a total project capacity of 200 MW. The Great Plains region, reflective of the central United States, has 

an abundance of land that is suitable for wind turbine siting and is generally not subject to land 

constraints that would otherwise limit project size. 

20.2 MECHANICAL EQUIPMENT & SYSTEMS

This Great Plains region onshore wind project is based on a 200 MW total project capacity. Parameters 

that affect project cost and performance include turbine nameplate capacity, rotor diameter, and hub 

height. The case configuration assumes 71 wind turbines with a nominal rating of 2.8 MW with a 125-

meter rotor diameter, and a 90-meter hub height. These features reflect modern wind turbines that 

employ larger rotor diameter and greater hub heights. The primary advantage of taller hub heights and 

larger rotor diameters include access to better wind profiles at higher altitudes and increased turbine 

swept area, enabling the unit to capture more energy. 

Wind turbine generators convert kinetic wind energy into electrical power. The most ubiquitous type of 

wind turbine used 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 that turns a generator located inside of the nacelle, which is 

the housing positioned atop the wind turbine tower.
20-2

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Onshore Wind, Large Plant Footprint, 200 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 20-1 — Wind Turbine Generator Drivetrain

Source: Office of Energy Efficiency & Renewable Energy, Wind Energy Technologies Office – U.S. Department of Energy, 

windTurbineLabels, ND. Digital Image (Image 1 of 17).

Retrieved from Energy.gov, https://www.energy.gov/eere/wind/inside-wind-turbine (accessed May 31, 2019).

Electrical & Control Systems 

Each wind turbine generator (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 that further steps up the voltage for interconnection with the transmission system 

with a voltage of 230 kV. 

A 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 project as a whole.

Offsite Requirements 

Wind projects harness power from wind and therefore do not require fuel or fuel infrastructure. The 

offsite requirements are limited to construction of site and wind turbine access roads, the O&M 

building, and electrical interconnection to the transmission system.
20-3

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Onshore Wind, Large Plant Footprint, 200 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

20.3 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1265/kW. Table 20-1 summarizes the cost 

components for this case.

Capital cost were broken down into the following categories:

• Civil/Structural Costs: These costs include the WTG spread footing and substation 

foundations, access roads, crane pads, road improvements, and O&M building.

• Mechanical Costs: These costs include the purchase price for the WTGs from the OEM (i.e., 

blades, hub, drivetrain, generator, tower, and electronics), transportation and delivery to the 

project site, and assembly and erection on site.

• Electrical Costs: These costs include pad-mounted transformers, underground collection 

system, and the project substation.

• Project Indirect Costs: These costs include construction management, engineering, and G&A

costs.

• EPC Fee: The EPC fee is a markup charged by the construction contractor. 

• Project Contingency Costs: Contingency is an allowance considered to cover the cost of 

undefined or uncertain scope of work, including EPC change orders or costs associated with 

schedule delays.

• Owner Costs: These costs include Project development costs that cover project feasibility 

analyses, wind resource assessments, geotechnical studies, contracting for land access, 

transmission access and permitting. However, estimates exclude project financing costs. 

Table 20-1 — Case 20 Capital Cost Estimate

Case 20

EIA – Capital Cost Estimates – 2019 $s

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 & Indirect 

Costs 8%

Project Contingency % of Project Costs 4%

Owner's Services % of Project Costs 7%

Electric Interconnection Costs

Transmission Line Cost $/mile 1,200,000

Miles miles 1.00
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Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 20

EIA – Capital Cost Estimates – 2019 $s

Configuration

Onshore Wind – Large Plant 

Footprint: Great Plains Region

200 MW | 2.8 MW WTG

Hub Height (m) 90

Rotor Diameter (m) 125

Units

Typical Project Timelines

Development, Permitting, Engineering months 12

Plant Construction Time months 9

Total Lead Time Before COD months 21

Operating Life years 25

Cost Components (Note 1) Total

Civil/Structural/Architectural Subtotal $ 24,297,000

WTG Procurement and Supply $ 155,209,000

WTG Erection $ 7,502,000

Mechanical Subtotal $ 162,711,000

Electrical – Substation Electrical Equipment $ 7,679,000

Electrical – Pad Mount Transformers and Collection 

System $ 10,711,000

Electrical Subtotal $ 18,390,000

Project Indirects $ 5,183,000

EPC Total Before Fee $ 210,581,000

EPC Fee $ 16,846,000

EPC Subtotal $ 227,427,000

Owner' Cost Components (Note 2)

Owner's Cost Subtotal $ 15,919,890

Project Contingency $ 9,734,000

Total Capital Cost $ 253,080,890

 $/kW net 1,265

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.

20.4 O&M 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 estimate excludes site-specific owner's costs such as 

land lease royalties, property taxes, and insurance. However, average land lease cost in Great Plains 

region is $2.84/kW-yr. Table 20-2 summarizes the average annual O&M expenses projected for an 

assumed 25-year project life.
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Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 20-2 — Case 20 O&M Cost Estimate

Case 20

EIA – Non-Fuel O&M Costs – 2019 $s

Onshore Wind – Large Plant Footprint: Great Plains Region

Fixed O&M – Plant (Note 1)

WTG Scheduled Maintenance $/year 2,294,000

WTG Unscheduled Maintenance $/year 2,167,000

Balance of Plant Maintenance $/year 806,000

 Subtotal Fixed O&M $/year 5,267,000

 $/kW-year $/kW-year 26.34 $/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.

2. O&M Costs estimates reflect Full Service Agreement and exclude site specific owner's costs such as land lease, royalties, property 

taxes, and insurance. Average land lease costs in Great Plains region is $2.80/kW-year.

3. Average FSA term considered: 25 years

20.5 ENVIRONMENTAL & 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.
21-1

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Onshore Wind, Small Plant Footprint, 50 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 21. ONSHORE WIND, SMALL PLANT 

FOOTPRINT, 50 MW

21.1 CASE DESCRIPTION

This case is an onshore wind project with a total project capacity of 50 MW. “Coastal” refers to the area 

that is reflective of the Mid-Atlantic, Northeast, and Pacific regions of the United States. Due to assumed 

land availability constraints for this region, the project capacity is limited. 

Mechanical Equipment & Systems

The onshore wind project in the Coastal region is based on a 50-MW total project capacity. Parameters 

that affect project cost and performance include turbine nameplate capacity, rotor diameter, and hub 

height. The case configuration assumes 17 wind turbines with a nominal rating of 2.8 MW with 125-

meter rotor diameters and 90-meter hub heights. These features reflect modern wind turbines that 

employ larger rotor diameter and greater hub heights. The primary advantage of taller hub heights and 

larger rotor diameters include access to better wind profiles at higher altitudes and increased turbine 

swept area, enabling the unit to capture more energy. 

Wind turbine generators convert kinetic wind energy into electrical power. The most ubiquitous type of 

wind turbine used 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 that turns a generator located inside of the nacelle, which is 

the housing positioned atop the wind turbine tower.
21-2

SL-014940

Onshore Wind, Small Plant Footprint, 50 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Figure 21-1 — Wind Turbine Generator Drivetrain

Source: Office of Energy Efficiency & Renewable Energy, Wind Energy Technologies Office – U.S. Department of Energy, 

windTurbineLabels, ND. Digital Image (Image 1 of 17).

Retrieved from Energy.gov, https://www.energy.gov/eere/wind/inside-wind-turbine (accessed May 31, 2019).

Electrical & 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 that further 

steps up the voltage for interconnection with the transmission system with a voltage of 230 kV. 

A 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 project as a whole.

Offsite Requirements

Wind projects harness power from wind and therefore do not require fuel or fuel infrastructure. The 

offsite requirements are limited to construction of site and wind turbine access roads, the O&M 

building, and electrical interconnection to the transmission system.
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Onshore Wind, Small Plant Footprint, 50 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

21.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1677/kW. Table 21-1 summarizes the cost 

components for this case.

Capital cost estimates were broken down into the following categories:

• Civil/Structural Costs: These costs include the WTG spread footing and substation 

foundations, access roads, crane pads, road improvements, and O&M building.

• Mechanical Costs: These costs include the purchase price for the WTGs from the OEM 

(blades, hub, drivetrain, generator, tower, and electronics), transportation and delivery to the 

project site, and assembly and erection on site.

• Electrical Costs: These costs include pad-mounted transformers, collection system, and 

project substation.

• Project Indirect Costs: These costs include construction management, engineering, and G&A 

costs.

• EPC Fee: The EPC fee is a markup charged by the construction contractor. 

• Project Contingency Costs: Contingency is an allowance considered to cover the cost of 

undefined or uncertain scope of work, including EPC change orders or costs associated with 

schedule delays.

• Owner Costs: These costs include Project development costs that cover project feasibility 

analyses, wind resource assessments, geotechnical studies, contracting for land access, 

transmission access, and permitting. However, estimates exclude project financing costs. 

Table 21-1 — Case 21 Capital Cost Estimate

Case 21

EIA – Capital Cost Estimates – 2019 $s

Configuration

Onshore Wind – Small Plant 

Footprint: Coastal Region

50 MW | 2.8 MW WTG

Hub Height (m) 90

Rotor Diameter (m) 125

Units

Plant Characteristics

Net Plant Capacity MW 50

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 8%

Project Contingency % of Project Costs 6%

Owner's Services % of Project Costs 10%

Electric Interconnection Costs

Transmission Line Cost $/mile 1,200,000

Miles miles 1.00
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Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Case 21

EIA – Capital Cost Estimates – 2019 $s

Configuration

Onshore Wind – Small Plant 

Footprint: Coastal Region

50 MW | 2.8 MW WTG

Hub Height (m) 90

Rotor Diameter (m) 125

Units

Typical Project Timelines

Development, Permitting, Engineering months 12

Plant Construction Time months 6

Total Lead Time Before COD months 18

Operating Life years 25

Cost Components (Note 1) Total

Civil/Structural/Architectural Subtotal $ 10,529,000

WTG Procurement and Supply $ 44,881,000

Turbine Erection $ 3,539,000

Mechanical Subtotal $ 48,419,000

Electrical – Substation Electrical Equipment $ 510,000

Electrical – Pad Mount Transformers and Collection System $ 3,495,000

Electrical Subtotal $ 6,005,000

Project Indirects $ 1,618,000

EPC Total Before Fee $ 66,571,000

EPC Fee $ 5,326,000

EPC Subtotal $ 71,897,000

Owner's Cost Subtotal (Note 2) $ 7,189,700

Project Contingency $ 4,745,000

Total Capital Cost $ 83,831,700

 $/kW net 1,677

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.

21.3 O&M 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 

land lease royalties, property taxes and insurance. However, average land lease costs in Coastal region 

is $3.60/kW-yr. Table 21-2 summarizes the average annual O&M expenses projected for an assumed 

25-year project life.
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Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 21-2 — Case 21 O&M Cost Estimate

Case 21

EIA – Non-Fuel O&M Costs – 2019 $s

Onshore Wind – Small Plant Footprint: Coastal Region

Fixed O&M – Plant ($/kW-year) (Note 1)

WTG Scheduled Maintenance $/year 765,000

WTG Unscheduled Maintenance $/year 723,000

Balance of Plant Maintenance $/year 269,000

 Subtotal Fixed O&M $/year 1,757,000

 $/kW-year $/kW-year 35.14 $/kW-year

Variable O&M ($/MWh) (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.

2. O&M Costs estimates reflect Full Service Agreement and exclude site specific owner's costs such as land lease, royalties, 

property taxes and insurance. Average land lease costs in Coastal region is $3.60/kW-year.

3. Average FSA term considered: 25 years

21.4 ENVIRONMENTAL & 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.
22-1

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Offshore Wind, 400 MW

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 22. OFFSHORE WIND, 400 MW

22.1 CASE DESCRIPTION

This case is an offshore wind project with a total 400-MW project capacity. The case configuration 

assumes wind turbines rated at 10 MW each, located 30 miles offshore in waters with a depth of 100 

feet, and assumes a five-mile onshore cable run.

Mechanical Equipment & Systems

The offshore wind project is based on a total project capacity of 400 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 10 MW each. They are located 30 miles 

offshore in waters with a 100-foot depth. An onshore cable run of five miles is also assumed.

For the purposes of this study, it has been assumed that wind turbines installed employ fixed-type 

foundation structures; monopile substructures were taken into consideration. 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 related to cable lengths and installation costs.

Wind turbine generators convert kinetic wind energy into electrical power. The most ubiquitous type of 

wind turbine used 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 that turns a generator located inside of the nacelle, which is 

the housing positioned atop the wind turbine tower.

Electrical & Control Systems

Each wind turbine consists of a doubly-fed induction generator with high-speed electrical slip rings that 

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 33–66 kV 

through a dedicated transformer at the WTG. Array cables, which are buried in the sea floor, transmit 

electricity to the offshore substation where the voltage is increased to 138 kV. It is then transmitted to 

an onshore substation via export cables. The power from this substation is supplied for interconnection 

with the transmission system.
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Offshore Wind, 400 MW

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

A SCADA system is responsible for communications between the wind turbines and substation. The 

SCADA system allows the operations staff to remotely control and monitor each wind turbine and the 

wind project as a whole.

Offsite Requirements

Since wind is a clean source of energy, scope of offsite works is limited to construction of offshore-toshore submarine cables, port infrastructures, installation vessels (construction and cable laying) and 

electrical interconnection to the transmission system.

22.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $4375/kW. Table 22-1 summarizes the cost 

components for this case.

Capital cost estimates were broken down into the following categories:

• Civil/Structural Costs: These costs include the port staging, WTG, and offshore substation 

foundations.

• Mechanical Costs: These costs include the purchase price for the WTGs from the OEM. This 

price includes the cost of the WTG equipment (blades, hub, drivetrain, generator, tower, and 

electronics), support vessels, transportation and delivery to port, and erection on site. 

• Electrical Costs: These cost include interconnection, offshore and onshore transmission that 

includes inter array cabling, export cabling, and substations.

• Project Indirect Costs: These costs include construction management, engineering, and G&A 

costs.

• EPC Fee: The EPC fee is a markup charged by the construction contractor. 

• Project Contingency Costs: Contingency is an allowance considered to cover the cost of 

undefined or uncertain scope of work, including EPC change orders or costs associated with 

schedule delays.

• Owner Costs: These costs include Project development costs that cover project feasibility 

analyses, wind resource assessments, offshore geotechnical and environmental loading studies, 

obtaining offshore leases, transmission access, and permitting. However, the estimates exclude 

project financing costs. 
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Table 22-1 — Case 22 Capital Cost Estimate

Case 22

EIA – Capital Cost Estimates – 2019 $s

Configuration

Fixed-bottom Offshore Wind: 

Monopile Foundations

400 MW | 10 MW WTG

Offshore Cable Length (mi) 30

Onshore Cable Length (mi) 5

Water Depth (ft) 100

Units

Plant Characteristics

Net Plant Capacity MW 400

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 5%

Typical Project Timelines

Development, Permitting, Engineering months 24

Plant Construction Time months 12

Total Lead Time Before COD months 36

Operating Life years 25

Cost Components (Note 1) Total

Civil/Structural/Architectural Subtotal $ 240,648,000

WTG Procurement and Supply $ 653,008,000

WTG Assembly/Installation $ 125,792,000

Mechanical Subtotal $ 778,800,000

Interconnection $ 60,995,000

Offshore Transmission & eBOP $ 213,947,000

Onshore Transmission $ 60,172,000

Electrical Subtotal $ 335,114,000

Project Indirects $ 74,800,000

EPC Total Before Fee $ 1,429,362,000

EPC Fee $ 85,762,000

EPC Subtotal $ 1,515,124,000

Owner's Cost Subtotal (Note 2) $ 75,756,200

Project Contingency $ 159,088,000

Total Capital Cost $ 1,749,968,200

 $/kW net 4,375

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.

22.3 O&M COST ESTIMATE

Operating expenditures cover all maintenance expenses during operations, including management, 

labor, equipment and vessel rentals, parts, and consumables for both scheduled and unscheduled 

maintenance of the WTGs and BOP systems, as well as operations monitoring.
22-4

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Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 22-2 — Case 22 O&M Cost Estimate

Case 22

EIA – Non-Fuel O&M Costs – 2019 $s

Fixed-bottom Offshore Wind: Monopile Foundations

Fixed O&M – Plant 

Subtotal Fixed O&M $/kW-year 110.00 $/kW-year

Variable O&M $/MWh 0.00 $/MWh

22.4 ENVIRONMENTAL & 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.
23-1

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Concentrating Solar Plant, 100 MW, 8-hr Storage

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

CASE 23. CONCENTRATING SOLAR PLANT, 100 MW, 

8-HR STORAGE

23.1 CASE DESCRIPTION

This case is a concentrating solar thermal power plant (CSP) with eight hours of thermal storage. This 

type of plant is typically referred to as a “solar power tower” due to the central receiver tower, which is 

surrounded by a field of reflectors. The solar power tower uses a field of thousands of solar reflectors, 

called heliostats, to direct solar radiation energy to a central receiver, which is located at the top of the 

tower. The heliostats can rotate and pitch to direct the sunlight toward the receiver as the sun passes 

across the horizon. 

The plant for this case is rated for 115 MW gross power, and an auxiliary load of approximately 15 MW 

is expected. Power is generated at 15.5 kV and 60 Hz. It is stepped up to 230 kV for transmission.

Figure 23-1 shows a diagram of the system assumed for this case. The plant is equipped with two molten 

salt tanks: one hot tank and one cold tank. Molten salt pumps move molten salt from the cold salt tank 

to the heat exchanger in the receiver where it absorbs energy from the solar radiation concentrated on 

the surface of the receiver. The hot molten salt flows down the tower to the hot molten salt tank. A 

molten salt pump from the power block moves molten salt from the hot salt tank through a steam 

generating heat exchanger to the cold salt tank. Superheated steam is generated in the heat exchanger, 

which is used to drive a steam turbine to turn a generator. The steam is condensed in an ACC. The plant 

is equipped with water treatment facilities to support the steam cycle. The plant control system operates 

both the power block and the solar field. As mentioned, the solar field may consist of thousands of 

individual heliostat reflectors. Some solar power tower projects include more than 10,000 heliostats. 

Recent advances in control technology have eliminated the need for control and power cabling to each 

heliostat. Instead, each heliostat is equipped with a photovoltaic (PV) solar panel and BESS to power 

the heliostat movement. Each heliostat has a control unit that communicates with a central controller 

wirelessly.
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Figure 23-1 — Concentrating Solar Power Tower System Diagram

Source: U.S. Department of Energy, 2014: The Year of Concentrating Solar Power, May 2014. PDF. 

Retrieved from Energy.gov, https://www.energy.gov/sites/prod/files/2014/10/f18/CSP-report-final-web.pdf (accessed June 13, 2019)

The thermal storage system is based on the amount of “hot” molten salt that is stored in the hot salt 

tank when the solar resource is no longer available after the sun goes down. The duration of storage is 

contingent on the amount of hot molten salt and its temperature that can be collected in a “solar day,” 

which depends on the solar resource available during that time.

Figure 23-2 shows an aerial view of a concentrating solar power tower plant. The central receiver can 

be seen on the top of a tower surrounded by thousands of heliostats. The ACC and hot and cold molten 

salt tanks are clearly shown. Buildings that house the control room, work shop, and spare parts 

warehouse are also shown. 
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Figure 23-2 — Aerial View of Concentrating Solar Power Tower Project

Crescent Dunes 

Source: Loan Programs Office – U.S. Department of Energy, DOE-LPO_Project-Photos_CSP_Crescent-Dunes_02, ND. Digital Image.

Retrieved from Energy.gov, https://www.energy.gov/lpo/crescent-dunes (accessed June 5, 2019)

Figure 23-3 shows the direct normal solar irradiance across the United States. The solar irradiance is 

used to determine the best location to capture solar energy.
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Figure 23-3 — United States Solar Resource

Source: U.S. Department of Energy, National Renewable Energy Laboratory, Direct Normal Solar Irradiance, ND. 

Retrieved from NREL.gov, https://www.nrel.gov/gis/images/solar/solar_ghi_2018_usa_scale_01.jpg (accessed June 5, 2019).

Offsite Requirements

The cost estimate assumes an allowance for a one-mile transmission line. The estimates include the cost 

of onsite roads and a connection to an existing nearby highway. The estimate includes the cost of water 

supply infrastructure onsite; however, potable water and sewer tie-in are nearby. 

23.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $7221/kW. Table 23-1 summarizes the cost 

components for this case. The capital cost is based on the latest cost information for mechanical and 

electrical components and considerations for implementing the latest available technology.

The cost estimate includes the cost for land, site clearing, civil works, drainage, roads on the plant site, 

and water supply infrastructure. The complete heliostat field cost includes the reflector, foundation 

pedestal, supports, and power and controls for each unit. The receiver tower is based on a concrete 

structure with an internal space for an elevator, molten salt piping, and related equipment. The molten 
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salt circulation system includes the molten salt pumps, piping, heat tracing, insulation, and related 

controls equipment. The costs consider the construction of the hot and cold molten salt tanks, their 

foundations, insulation, heat tracing, the molten salt itself, and related equipment. The steam cycle 

equipment (i.e., the steam generating superheater, ACC, water treatment system, piping, valves, 

foundation, instrumentation and controls, and all related equipment) are included. All electrical BOP, 

fire protection equipment, and other equipment and materials needed to complete construction are 

included in the cost estimate. All labor and equipment needed for construction is included with the cost 

estimate.

In the past few years, concentrating solar power technology has been implemented in the Middle East 

more frequently than the United States. Therefore, much of the publicly available cost information 

indicates a $/installed kW significantly lower than the estimate in this report, which is for a project 

constructed in the United States. The installed project cost for an identical project in the Middle East 

(e.g., United Arab Emirates) can be expected to be lower by a significant amount. The lower costs are a 

result of several factors, including labor cost, which can be nearly half the cost as in the United States3;

government assistance with financial costs (in the forms of favorable loan programs, low taxes, and 

other incentives); low profit margins; and aggressive contracting.

The capital cost estimate is based on an EPC contracting approach.

Typical project related costs are included, such as Owner’s services, project development costs, studies, 

permitting, legal, project management, owner’s engineering, and start-up and commissioning.

Table 23-1 — Case 23 Capital Cost Estimate

Case 23

EIA – Capital Cost Estimates – 2019 $s

Configuration Concentrating Solar Power Tower

with Molten Salt Thermal Storage

Units

Plant Characteristics

Gross Power Rating MW 115

Net Power Rating MW 100

Thermal Storage hr 8

Capital Cost Assumptions 

EPC Contracting Fee % of Project Costs 10%

Project Contingency % of Project Costs 10%

Owner's Services % of Project Costs 7%

Estimated Land Requirement acres 2,000

Estimated Land Cost $/acre 10,000

 3 https://arstechnica.com/science/2018/10/are-super-cheap-solar-fields-in-the-middle-east-just-loss-leaders/
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Case 23

EIA – Capital Cost Estimates – 2019 $s

Configuration Concentrating Solar Power Tower

with Molten Salt Thermal Storage

Units

Electric Interconnection Costs

Transmission Line Cost $/mile 1,200,000

Miles miles 1.00

Typical Project Timelines

Development, Permitting, Engineering months 15

Plant Construction Time months 30

Total Lead Time Before COD months 33

Operating Life years 30

Cost Components (Note 1) Total

Direct Costs

Site Preparation $ 18,474,000

Heliostat Field $ 157,437,000

Tower $ 24,816,000

Receiver $ 74,081,000

Thermal Energy Storage System (TES) $ 65,276,000

Balance of Plant – Steam System $ 11,310,000

Balance of Plant – Electrical, Instrumentation and Controls $ 9,186,000

Balance of Plant – Foundations & Support Structures $ 15,917,000

Power Block (Steam Turbine, steam cycle, related systems) $ 122,077,000

Direct Costs Subtotal $ 498,574,000

Project Indirect $ 37,135,000

EPC Total Before Fee $ 535,709,000

EPC Fee $ 53,571,000

EPC Subtotal $ 589,280,000

Owner's Cost Components (Note 2)

Owner's Services $ 46,000,000

Land $ 20,000,000

Electrical Interconnection $ 1,200,000

Owner's Cost Subtotal $ 67,200,000

Project Contingency $ 65,648,000

Total Capital Cost $ 722,128,000

 $/kW net 7,221 

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, gas interconnection costs (if applicable), 

and land acquisition costs.

23.3 O&M COST ESTIMATE

The O&M cost estimate incorporates the annual cost of the onsite O&M staff as well as contracted 

services for grounds keeping, mirror washing, water treatment, and computer maintenance. The O&M 

cost also incorporates the estimated annual water requirements, which will be purchased. The need for 

various consumables and replacement parts are also considered. Since the annual cost of consumables 
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for the plant can be estimated, the entire O&M cost is captured as a fixed amount. The variable cost is 

considered to be $0.00/MWh.

Table 23-2 — Case 23 O&M Cost Estimate

Case 23

EIA – Non-Fuel O&M Costs – 2019 $s

Concentrating Solar Power Tower

Fixed O&M – Plant (Note 1)

Subtotal Fixed O&M $/kW-year 85.39 $/kW-year

Variable O&M (Note 2) $/MWh 0.00 $/MWh

O&M Cost Notes 

1. Fixed O&M costs include labor, materials, utilities, 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.

23.4 ENVIRONMENTAL & EMISSIONS INFORMATION

Concentrating solar power plants do not produce regulated environmental 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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CASE 24. SOLAR PHOTOVOLTAIC, 150 MWAC

24.1 CASE DESCRIPTION

This case is a nominal 150-MWAC solar photovoltaic (PV) facility with single-axis tracking. With 

continued advances in technical efficiency and lower module price, solar PV cost has decreased 

significantly in the past decade. This case uses 195 MWDC of 1,500-V monocrystalline PERC modules 

with independent row trackers that are placed in a north-south orientation with east-west tracking. The 

case also uses 150 MWAC of central inverters, resulting in a DC/AC ratio of 1.3. The simplicity of solar 

PV projects is that 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 and create room for tracking rotation. 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 24-1 — Solar Photovoltaic Project

Foothills Solar Project using single-axis tracking in Loveland, Colorado.

Source: American Public Power Association, gray solar panel lot, 2017. Digital Image.

Retrieved from: Unsplash.com, https://unsplash.com/photos/dCx2xFuPWks (accessed June 12, 2019).

Mechanical Equipment & Systems

PV refers to the conversion of light into electricity. Solar PV modules convert incident solar radiation 

into a potential difference within individual solar cells that produces DC electricity. The solar PV facility 
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assumed for this study is comprised of 487,500 individual 400-watt, 1500-V monocrystalline solar 

modules with PERC architecture for increased efficiency. These modules are connected in series to each 

other in strings of 30 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 east to west. One variation in tracking mechanics that can impact the overall price 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. 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.

Figure 24-2 — Single-Axis Tracking
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Electrical & Control Systems

Each block within a PV is 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 currently used in new projects are typically rated 

between 1,500 kW and 4000 kW. There are also two types of solar inverters: central and string. This 

system uses two 2500-kW central inverters with one 5.05-MW medium voltage transformer within each 

PV block.

A solar facility’s nominal capacity is typically defined by the net AC capacity of the inverters across all 

blocks. 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.

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 as well as water for the purpose of 

cleaning the solar modules. Additionally, cleaning is regionally dependent. In regions with significant 
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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 two cleanings per year.

24.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1313/kW. Table 24-1 summarizes the cost 

components for this case. Solar prices have been dropping due to reductions in equipment costs as well 

as the required construction labor. As solar modeling software advances, projects are able to optimize 

layouts and ground coverage for lowest levelized cost of energy, thereby allowing for reduced civil 

expenditures on a per kilowatt basis. Solar modules that are arriving on the market have a net potential 

of 1500 V rather than the previous standard of 1000 V. This increased net potential allows for lower 

wiring losses, which increases the net energy yield and lower wiring material costs to reduce the capital 

cost. Additionally, strides have been made to make modules more efficient to increase their power rating 

and lighter in weight to allow for reduced transportation and installation cost. Electrical components 

have been dropping in price, especially the inverters. As solar development advances and matures, EPC

contractors and developers have also been bearing less contingency and overhead, further reducing a 

solar project’s overall price. 

Table 24-1 — Case 24 Capital Cost Estimate

Case 24

EIA – Capital Cost Estimates – 2019 $s

Configuration Solar PV w/ Single Axis Tracking 

150 MWAC

DC / AC Ratio 1.3

Module Type Crystalline

Units

Plant Characteristics

Net Plant Capacity MW_AC 150

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 5%

Project Contingency % of Project Costs 5%

Owner's Services % of Project Costs 4%

Estimated Land Requirement (acres) (Note 1) $ 400

Typical Project Timelines

Development, Permitting, Engineering months 12

Plant Construction Time months 6

Total Lead Time Before COD months 18

Operating Life years 30
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Case 24

EIA – Capital Cost Estimates – 2019 $s

Configuration Solar PV w/ Single Axis Tracking 

150 MWAC

DC / AC Ratio 1.3

Module Type Crystalline

Units

Cost Components (Note 2) Breakout Total

Civil/Structural/Architectural Subtotal $ 7,935,000

Mechanical – Racking, Tracking, & Module Installation $ 36,391,000

Mechanical Subtotal $ 36,391,000

Electrical – Inverters $ 9,430,000

Electrical – BOP and Miscellaneous $ 28,328,000

Electrical – Transformer, Substation, & MV System $ 17,756,000

Electrical – Backup Power, Control, & Data Acquisition $ 3,733,000

Electrical Subtotal $ 59,247,000

Project Indirects $ 2,114,000

EPC Total Before Fee $ 105,687,000

EPC Fee $ 5,284,000

EPC Subtotal $ 110,971,000

Owner's Cost Components (Note 3)

Owner's Services $ 4,439,000

Modules (Note 3) $ 72,150,000

Owner's Costs Subtotal $ 76,589,000

Project Contingency $ 9,378,000

Total Capital Cost $ 196,938,000

 $/kW net 1,313

Capital Cost Notes

1. Land is typically leased and not considered in CAPEX.

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.

3. Modules purchased by Owner

24.3 O&M COST ESTIMATE

Operations and maintenance costs associated with 150-MWAC, single-axis tracking solar PV project have 

also been decreasing. 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. Cleaning is also 

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. Additionally, inverter manufacturers have begun to offer 

extended warranties up to a 10-year period and at roughly the same cost as the assumed inverter reserve 
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amount. Decreasing inverter prices also allows for a smaller inverter reserve to be set aside. 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.

Table 24-2 — Case 24 O&M Cost Estimate

Case 24

EIA – Non-Fuel O&M Costs – 2019 $s

Solar PV w/ Single Axis Tracking

Fixed O&M – Plant ($/year) (Note 1)

Preventative Maintenance $/year 1,104,000

Module Cleaning (Note 2) $/year 613,000

Unscheduled Maintenance $/year 96,000

Inverter Maintenance Reserve $/year 342,000

Land Lease (Note 3) $/year 133,000

Subtotal Fixed O&M $/year 2,288,000

 $/kW-year $/kW-year 15.25 $/kW-yr

Variable O&M ($/MWh) $/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. 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.

24.4 ENVIRONMENTAL & 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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CASE 25. SOLAR PHOTOVOLTAIC WITH BATTERY 

ENERGY STORAGE SYSTEM, 150 MWAC

25.1 CASE DESCRIPTION

This case is based on a nominal 150-MWAC solar PV plant with 200 MWh of lithium-ion battery storage. 

Solar PV has increasingly been coupled with battery storage in recent years due to price reductions in 

solar PV and lithium-ion batteries. The factors driving cost reductions of solar PV projects are shared 

with systems coupled with battery storage: Modeling technology optimizes design and reduces civil 

costs per kW, higher power modules, lower priced inverters, and lower risk. Batteries can be either ACor DC-coupled to the solar array. DC-coupled systems connect the battery directly to the solar array via 

DC wiring. This estimate assumes an AC-coupled system; this configuration is more prevalent in recent

projects. 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 ACcoupled system 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.

Mechanical Equipment & 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 standalone solar PV facility: 400-watt solar 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 40 

containers, each 40 feet in length and containing 5,000 kWh of battery storage. Smaller 20-feet 

containers are sometimes used depending on constraints with site availability and project size. Both the 

20-foot and 40-foot containers are always installed with extra space inside to allow for annual 

installation of more batteries so that the entire container keeps a constant year-on-year net output 

despite battery degradation. There are more containers in a PV system with battery storage over a 

standalone BESS due to the increased project life of PV. The additional containers allow for more 

augmentation over the life of the PV project rather than the life of the battery storage.
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Electrical & 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-direction 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 significantly more expensive than solar inverters.

Figure 25-1 — 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.

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 
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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 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.

25.2 CAPITAL COST ESTIMATE

The base cost estimate for this technology case totals $1755/kW. Table 25-1 summarizes the cost 

components for this case.

Table 25-1 — Case 25 Capital Cost Estimate

Case 25

EIA – Capital Cost Estimates – 2019 $s

Configuration Solar PV w/ Single Axis Tracking + 

Battery Storage

Battery Configuration AC Coupled

DC / AC Ratio 1.3

Module Type Crystalline

Battery Type Lithium-ion

Units

Plant Characteristics

Net Solar Capacity MW_AC 150

Net Battery Capacity MW_AC 50

Capital Cost Assumptions 

EPC Contracting Fee % of Direct & Indirect Costs 5%

Project Contingency % of Project Costs 5%

Owner's Services % of Project Costs 4%

Estimated Land Requirement (acres) Note 1 $ 401

Typical Project Timelines

Development, Permitting, Engineering months 12

Plant Construction Time months 6

Total Lead Time Before COD months 18

Operating Life years 30

Cost Components (Note 2) Breakout Total

Civil/Structural/Architectural Subtotal $ 17,596,000

Mechanical – Racking, Tracking, & Module Installation $ 36,391,000

Mechanical Subtotal $ 36,391,000

Electrical – Batteries $ 40,037,000

Electrical – Inverters $ 14,459,000

Electrical – BOP and Miscellaneous $ 28,453,000

Electrical – Transformer, Substation, & MV System $ 18,647,000

Electrical – Backup Power, Control, & Data Acquisition $ 3,755,000

Electrical Subtotal $ 105,350,000

Project Indirects $ 4,202,000

EPC Total Before Fee $ 163,539,000

EPC Fee $ 8,177,000

EPC Subtotal $ 171,716,000

Owner's Cost Components (Note 3)

Owner's Services $ 6,869,000
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Case 25

EIA – Capital Cost Estimates – 2019 $s

Configuration Solar PV w/ Single Axis Tracking + 

Battery Storage

Battery Configuration AC Coupled

DC / AC Ratio 1.3

Module Type Crystalline

Battery Type Lithium-ion

Units

Modules (Note 3) $ 72,150,000

Owner's Cost Subtotal $ 79,019,000

Project Contingency $ 12,537,000

Total Capital Cost $ 263,272,000

 $/kW net 1,755

Capital Cost Notes

1. Land is typically leased and not considered in CAPEX.

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.

3. Modules purchased directly by owner.

25.3 O&M 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 

maintenance reserve, and the land lease. Descriptions of all the factors except the battery maintenance 

reserve can be found in Section 24.3. The typical lifetime of a battery is 3000 cycles, which yields a 

lifetime of roughly 10 years (based on approximately one cycle per day). Battery systems typically 

account for degradation and a 10-year battery lifetime by leaving physical space within the BESS 

containers for additional batteries to be installed to augment the system each year. The battery reserve 

in this case is higher than standalone battery storage because it accounts for battery augmentation as 

well as additional battery replacements every 10 years to allow for a 30-year system life.
25-5

SL-014940

Solar Photovoltaic with Battery Energy Storage System, 150 MWAC

Final - Rev. 1

Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Table 25-2 — Case 25 O&M Cost Estimate

Case 25

EIA – Non-Fuel O&M Costs – 2019 $s

Solar PV w/ Single Axis Tracking + Battery Storage

Fixed O&M – Plant (Note 1)

Preventative Maintenance $/year 1,545,000

Module Cleaning (Note 2) $/year 613,000

Unscheduled Maintenance $/year 115,000

Inverter Maintenance Reserve $/year 455,000

Battery Maintenance Reserve $/year 1,963,000

Land Lease (Note 3) $/year 134,000

Subtotal Fixed O&M $/year 4,825,000

 $/kW-year $/kW-year 32.17 $/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 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.

25.4 ENVIRONMENTAL & 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.
Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Appendix A. Location-Based Adjustment Factors 
 Capital Cost Study

Cost and Performance Estimates 

for New Utility-Scale Electric Power 

Generating Technologies

Location-Based 

Adjustment Factors

Prepared by

Sargent & Lundy

FINAL

Contract No. 89303019CEI00022

Project No. 13651-005

Prepared for

U.S. Energy Information 

Administration

55 East Monroe | Chicago, IL 60603 | sargentlundy.com
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 3,676 0.97 (128) 3549

Arizona Phoenix 3,676 1.05 199 3875

Arkansas Little Rock 3,676 0.96 (133) 3543

California Bakersfield 3,676 1.26 973 4649

California Los Angeles 3,676 1.27 989 4665

California Modesto (instead of Redding) 3,676 1.28 1,017 4694

California Sacramento 3,676 1.29 1,076 4752

California San Francisco 3,676 1.37 1,367 5043

Colorado Denver 3,676 1.03 100 3776

Connecticut Hartford 3,676 1.24 877 4554

Delaware Dover 3,676 1.22 801 4477

District of Columbia Washington 3,676 1.08 307 3983

Florida Tallahassee 3,676 0.95 (194) 3483

Florida Tampa 3,676 0.97 (127) 3549

Georgia Atlanta 3,676 0.99 (46) 3630

Idaho Boise 3,676 1.03 105 3781

Illinois Chicago 3,676 1.28 1,018 4694

Illinois Joliet 3,676 1.24 869 4545

Indiana Indianapolis 3,676 1.02 74 3750

Iowa Davenport 3,676 1.05 173 3850

Iowa Waterloo 3,676 0.97 (97) 3579

Kansas Wichita 3,676 0.98 (85) 3592

Kentucky Louisville 3,676 1.01 26 3702

Louisiana New Orleans 3,676 0.97 (104) 3572

Maine Portland 3,676 1.03 114 3790

Maryland Baltimore 3,676 1.02 86 3762

Massachusetts Boston 3,676 1.29 1,050 4726

Michigan Detroit 3,676 1.12 459 4135

Michigan Grand Rapids 3,676 1.05 168 3844

Minnesota Saint Paul 3,676 1.11 411 4087

Mississippi Jackson 3,676 0.95 (186) 3490

Missouri St. Louis 3,676 1.13 461 4137

Missouri Kansas City 3,676 1.08 297 3974

Montana Great Falls 3,676 0.97 (104) 3572

Nebraska Omaha 3,676 0.98 (78) 3599

New Hampshire Concord 3,676 1.14 510 4186

New Jersey Newark 3,676 1.24 881 4557

New Mexico Albuquerque 3,676 0.99 (47) 3629

New York New York 3,676 1.57 2,109 5785

New York Syracuse 3,676 1.13 487 4163

Nevada Las Vegas 3,676 1.15 556 4233

North Carolina Charlotte 3,676 0.96 (144) 3532

North Dakota Bismarck 3,676 1.04 133 3810

Oklahoma Oklahoma City 3,676 1.01 30 3707

Oklahoma Tulsa 3,676 0.93 (261) 3415

Ohio Cincinnati 3,676 0.93 (262) 3414

Oregon Portland 3,676 1.16 584 4261

Pennsylvania Philadelphia 3,676 1.30 1,092 4769

Pennsylvania Wilkes-Barre 3,676 1.15 561 4238

Rhode Island Providence 3,676 1.21 781 4457

South Carolina Charleston 3,676 0.96 (159) 3518

South Carolina Spartanburg (Asheville, NC) 3,676 0.97 (116) 3561

South Dakota Rapid City 3,676 0.98 (73) 3603

Tennessee Knoxville (Nashville) 3,676 0.97 (104) 3573

Texas Houston 3,676 0.93 (260) 3416

Utah Salt Lake City 3,676 0.98 (60) 3617

Vermont Burlington 3,676 1.05 167 3843

Virginia Alexandria 3,676 1.08 280 3956

Virginia Lynchburg 3,676 1.02 70 3746

Washington Seattle 3,676 1.14 505 4182

Washington Spokane 3,676 1.06 210 3886

West Virginia Charleston 3,676 1.04 162 3839

Wisconsin Green Bay 3,676 1.06 209 3886

Wyoming Cheyenne 3,676 0.99 (20) 3656

Table 1 1 — Location Adjustment for Non-New Source Performance Standard Compliant Ultra-Supercritical Coal (NSPS for NOX, Sox, PM, Hg) 

(2019 Dollars)

Case Configuration: 650 MW Net
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 4,558 0.97 (155) 4,403

Arizona Phoenix 4,558 1.05 250 4,808

Arkansas Little Rock 4,558 0.97 (129) 4,429

California Bakersfield 4,558 1.24 1,114 5,672

California Los Angeles 4,558 1.25 1,132 5,690

California Modesto (instead of Redding) 4,558 1.26 1,162 5,721

California Sacramento 4,558 1.27 1,227 5,785

California San Francisco 4,558 1.34 1,547 6,105

Colorado Denver 4,558 1.03 139 4,697

Connecticut Hartford 4,558 1.22 1,000 5,558

Delaware Dover 4,558 1.20 905 5,463

District of Columbia Washington 4,558 1.08 371 4,929

Florida Tallahassee 4,558 0.95 (209) 4,349

Florida Tampa 4,558 0.97 (135) 4,423

Georgia Atlanta 4,558 0.99 (42) 4,516

Idaho Boise 4,558 1.03 120 4,678

Illinois Chicago 4,558 1.25 1,118 5,676

Illinois Joliet 4,558 1.21 954 5,513

Indiana Indianapolis 4,558 1.02 88 4,646

Iowa Davenport 4,558 1.04 190 4,748

Iowa Waterloo 4,558 0.98 (107) 4,451

Kansas Wichita 4,558 0.98 (93) 4,465

Kentucky Louisville 4,558 1.01 35 4,593

Louisiana New Orleans 4,558 0.98 (101) 4,458

Maine Portland 4,558 1.03 128 4,686

Maryland Baltimore 4,558 1.02 96 4,654

Massachusetts Boston 4,558 1.26 1,191 5,749

Michigan Detroit 4,558 1.11 504 5,062

Michigan Grand Rapids 4,558 1.04 184 4,742

Minnesota Saint Paul 4,558 1.10 444 5,002

Mississippi Jackson 4,558 0.96 (202) 4,356

Missouri St. Louis 4,558 1.11 523 5,081

Missouri Kansas City 4,558 1.07 327 4,885

Montana Great Falls 4,558 0.97 (116) 4,442

Nebraska Omaha 4,558 0.98 (85) 4,473

New Hampshire Concord 4,558 1.13 603 5,162

New Jersey Newark 4,558 1.21 970 5,528

New Mexico Albuquerque 4,558 0.99 (37) 4,521

New York New York 4,558 1.52 2,351 6,910

New York Syracuse 4,558 1.12 567 5,125

Nevada Las Vegas 4,558 1.14 623 5,182

North Carolina Charlotte 4,558 0.97 (158) 4,400

North Dakota Bismarck 4,558 1.03 139 4,697

Oklahoma Oklahoma City 4,558 1.01 32 4,590

Oklahoma Tulsa 4,558 0.94 (288) 4,270

Ohio Cincinnati 4,558 0.94 (289) 4,269

Oregon Portland 4,558 1.15 687 5,245

Pennsylvania Philadelphia 4,558 1.27 1,234 5,793

Pennsylvania Wilkes-Barre 4,558 1.14 649 5,208

Rhode Island Providence 4,558 1.20 896 5,455

South Carolina Charleston 4,558 0.97 (144) 4,414

South Carolina Spartanburg (Asheville, NC) 4,558 0.97 (119) 4,439

South Dakota Rapid City 4,558 0.98 (88) 4,470

Tennessee Knoxville (Nashville) 4,558 0.98 (100) 4,458

Texas Houston 4,558 0.94 (285) 4,273

Utah Salt Lake City 4,558 0.99 (52) 4,506

Vermont Burlington 4,558 1.05 210 4,768

Virginia Alexandria 4,558 1.07 341 4,899

Virginia Lynchburg 4,558 1.02 108 4,666

Washington Seattle 4,558 1.12 569 5,127

Washington Spokane 4,558 1.05 236 4,795

West Virginia Charleston 4,558 1.04 178 4,736

Wisconsin Green Bay 4,558 1.05 221 4,779

Wyoming Cheyenne 4,558 0.99 (25) 4,533

Table 1 2 — Location Adjustment for New Source Performance Standard Compliant Ultra-Supercritical Coal (with 30% CCS or Other Compliance Technology) (2019 Dollars)

Case Configuration: 650 MW Net
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 5,876 0.98 (126) 5750

Arizona Phoenix 5,876 1.04 232 6108

Arkansas Little Rock 5,876 0.98 (99) 5777

California Bakersfield 5,876 1.22 1,278 7153

California Los Angeles 5,876 1.22 1,300 7176

California Modesto (instead of Redding) 5,876 1.23 1,333 7209

California Sacramento 5,876 1.24 1,408 7284

California San Francisco 5,876 1.30 1,778 7654

Colorado Denver 5,876 1.02 99 5974

Connecticut Hartford 5,876 1.19 1,114 6990

Delaware Dover 5,876 1.17 972 6848

District of Columbia Washington 5,876 1.06 381 6257

Florida Tallahassee 5,876 0.96 (235) 5640

Florida Tampa 5,876 0.98 (143) 5733

Georgia Atlanta 5,876 1.00 (21) 5855

Idaho Boise 5,876 1.03 155 6031

Illinois Chicago 5,876 1.22 1,310 7186

Illinois Joliet 5,876 1.19 1,118 6994

Indiana Indianapolis 5,876 1.02 126 6001

Iowa Davenport 5,876 1.04 221 6097

Iowa Waterloo 5,876 0.98 (125) 5751

Kansas Wichita 5,876 0.98 (111) 5765

Kentucky Louisville 5,876 1.01 64 5939

Louisiana New Orleans 5,876 0.99 (74) 5802

Maine Portland 5,876 1.03 157 6033

Maryland Baltimore 5,876 1.02 118 5993

Massachusetts Boston 5,876 1.23 1,341 7216

Michigan Detroit 5,876 1.10 590 6466

Michigan Grand Rapids 5,876 1.04 214 6090

Minnesota Saint Paul 5,876 1.08 497 6372

Mississippi Jackson 5,876 0.96 (230) 5645

Missouri St. Louis 5,876 1.11 667 6543

Missouri Kansas City 5,876 1.07 383 6259

Montana Great Falls 5,876 0.98 (142) 5734

Nebraska Omaha 5,876 0.98 (99) 5777

New Hampshire Concord 5,876 1.12 682 6558

New Jersey Newark 5,876 1.20 1,146 7022

New Mexico Albuquerque 5,876 1.00 3 5879

New York New York 5,876 1.46 2,675 8551

New York Syracuse 5,876 1.10 602 6477

Nevada Las Vegas 5,876 1.13 772 6648

North Carolina Charlotte 5,876 0.97 (186) 5690

North Dakota Bismarck 5,876 1.02 137 6013

Oklahoma Oklahoma City 5,876 1.01 32 5908

Oklahoma Tulsa 5,876 0.94 (341) 5535

Ohio Cincinnati 5,876 0.94 (342) 5534

Oregon Portland 5,876 1.13 782 6658

Pennsylvania Philadelphia 5,876 1.24 1,382 7258

Pennsylvania Wilkes-Barre 5,876 1.12 700 6576

Rhode Island Providence 5,876 1.17 1,005 6881

South Carolina Charleston 5,876 0.99 (72) 5804

South Carolina Spartanburg (Asheville, NC) 5,876 0.98 (113) 5763

South Dakota Rapid City 5,876 0.98 (128) 5748

Tennessee Knoxville (Nashville) 5,876 0.99 (71) 5804

Texas Houston 5,876 0.94 (331) 5545

Utah Salt Lake City 5,876 1.00 (18) 5858

Vermont Burlington 5,876 1.06 334 6209

Virginia Alexandria 5,876 1.06 346 6222

Virginia Lynchburg 5,876 1.01 71 5947

Washington Seattle 5,876 1.12 713 6589

Washington Spokane 5,876 1.05 298 6173

West Virginia Charleston 5,876 1.04 206 6082

Wisconsin Green Bay 5,876 1.04 229 6105

Wyoming Cheyenne 5,876 0.99 (40) 5836

Table 1 3 — Location Adjustment for Ultra-Supercritical Coal (with 90% CCS) 

(2019 Dollars)

Case Configuration: 650 MW Net
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,810 0.97 (48) 1,762

Arizona Phoenix 1,810 0.98 (32) 1,778

Arkansas Little Rock 1,810 0.98 (32) 1,777

California Bakersfield 1,810 1.16 292 2,102

California Los Angeles 1,810 1.17 303 2,112

California Modesto (instead of Redding) 1,810 1.16 292 2,102

California Sacramento 1,810 1.17 314 2,124

California San Francisco 1,810 1.26 465 2,275

Colorado Denver 1,810 0.97 (57) 1,752

Connecticut Hartford 1,810 1.14 252 2,062

Delaware Dover 1,810 1.10 176 1,985

District of Columbia Washington 1,810 1.02 42 1,852

Florida Tallahassee 1,810 0.96 (80) 1,730

Florida Tampa 1,810 0.97 (61) 1,749

Georgia Atlanta 1,810 0.99 (17) 1,793

Idaho Boise 1,810 1.02 36 1,846

Illinois Chicago 1,810 1.21 382 2,191

Illinois Joliet 1,810 1.18 320 2,129

Indiana Indianapolis 1,810 1.02 37 1,846

Iowa Davenport 1,810 1.04 66 1,876

Iowa Waterloo 1,810 0.98 (33) 1,777

Kansas Wichita 1,810 0.98 (27) 1,782

Kentucky Louisville 1,810 1.01 13 1,823

Louisiana New Orleans 1,810 0.98 (27) 1,782

Maine Portland 1,810 1.01 27 1,836

Maryland Baltimore 1,810 1.02 36 1,845

Massachusetts Boston 1,810 1.18 320 2,129

Michigan Detroit 1,810 1.09 161 1,971

Michigan Grand Rapids 1,810 1.02 42 1,852

Minnesota Saint Paul 1,810 1.08 148 1,958

Mississippi Jackson 1,810 0.96 (78) 1,731

Missouri St. Louis 1,810 1.12 210 2,019

Missouri Kansas City 1,810 1.07 118 1,928

Montana Great Falls 1,810 0.98 (39) 1,770

Nebraska Omaha 1,810 0.99 (24) 1,785

New Hampshire Concord 1,810 1.06 117 1,927

New Jersey Newark 1,810 1.19 342 2,152

New Mexico Albuquerque 1,810 1.00 1 1,811

New York New York 1,810 1.37 673 2,483

New York Syracuse 1,810 1.05 96 1,906

Nevada Las Vegas 1,810 1.12 224 2,034

North Carolina Charlotte 1,810 0.97 (56) 1,754

North Dakota Bismarck 1,810 1.00 8 1,818

Oklahoma Oklahoma City 1,810 1.00 2 1,811

Oklahoma Tulsa 1,810 0.94 (101) 1,709

Ohio Cincinnati 1,810 0.94 (101) 1,709

Oregon Portland 1,810 1.09 157 1,966

Pennsylvania Philadelphia 1,810 1.18 326 2,136

Pennsylvania Wilkes-Barre 1,810 1.06 108 1,918

Rhode Island Providence 1,810 1.12 217 2,027

South Carolina Charleston 1,810 0.99 (15) 1,795

South Carolina Spartanburg (Asheville, NC) 1,810 0.98 (39) 1,770

South Dakota Rapid City 1,810 0.98 (40) 1,770

Tennessee Knoxville (Nashville) 1,810 0.99 (15) 1,794

Texas Houston 1,810 0.94 (108) 1,702

Utah Salt Lake City 1,810 1.00 0 1,809

Vermont Burlington 1,810 1.05 94 1,904

Virginia Alexandria 1,810 1.02 35 1,844

Virginia Lynchburg 1,810 0.97 (57) 1,753

Washington Seattle 1,810 1.13 231 2,041

Washington Spokane 1,810 1.04 65 1,874

West Virginia Charleston 1,810 1.03 55 1,864

Wisconsin Green Bay 1,810 1.03 55 1,865

Wyoming Cheyenne 1,810 0.99 (18) 1,791

Table 1 4 — Location Adjustment for Internal Combustion Engines (Natural Gas or Oil-fired Diesel) 

(2019 Dollars)

Case Configuration: 20 MW (4x 5.6 MW)
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,175 0.96 (53) 1,122

Arizona Phoenix 1,175 0.98 (26) 1,149

Arkansas Little Rock 1,175 0.96 (49) 1,126

California Bakersfield 1,175 1.16 192 1,367

California Los Angeles 1,175 1.18 206 1,381

California Modesto (instead of Redding) 1,175 1.17 199 1,374

California Sacramento 1,175 1.19 218 1,393

California San Francisco 1,175 1.31 359 1,534

Colorado Denver 1,175 0.97 (39) 1,136

Connecticut Hartford 1,175 1.15 172 1,347

Delaware Dover 1,175 1.13 157 1,331

District of Columbia Washington 1,175 1.02 28 1,203

Florida Tallahassee 1,175 0.94 (67) 1,107

Florida Tampa 1,175 0.96 (52) 1,123

Georgia Atlanta 1,175 0.98 (29) 1,145

Idaho Boise 1,175 1.01 14 1,189

Illinois Chicago 1,175 1.23 270 1,445

Illinois Joliet 1,175 1.20 234 1,409

Indiana Indianapolis 1,175 1.01 9 1,184

Iowa Davenport 1,175 1.03 39 1,214

Iowa Waterloo 1,175 0.96 (41) 1,133

Kansas Wichita 1,175 0.97 (38) 1,137

Kentucky Louisville 1,175 0.99 (6) 1,168

Louisiana New Orleans 1,175 0.96 (45) 1,130

Maine Portland 1,175 1.00 6 1,181

Maryland Baltimore 1,175 1.02 19 1,194

Massachusetts Boston 1,175 1.20 229 1,404

Michigan Detroit 1,175 1.11 128 1,303

Michigan Grand Rapids 1,175 1.03 35 1,210

Minnesota Saint Paul 1,175 1.09 106 1,281

Mississippi Jackson 1,175 0.94 (65) 1,109

Missouri St. Louis 1,175 1.11 129 1,304

Missouri Kansas City 1,175 1.07 82 1,256

Montana Great Falls 1,175 0.96 (42) 1,133

Nebraska Omaha 1,175 0.97 (32) 1,142

New Hampshire Concord 1,175 1.05 59 1,233

New Jersey Newark 1,175 1.22 253 1,428

New Mexico Albuquerque 1,175 0.98 (27) 1,148

New York New York 1,175 1.43 500 1,675

New York Syracuse 1,175 1.06 69 1,244

Nevada Las Vegas 1,175 1.12 146 1,321

North Carolina Charlotte 1,175 0.96 (49) 1,126

North Dakota Bismarck 1,175 1.02 22 1,196

Oklahoma Oklahoma City 1,175 1.00 (1) 1,173

Oklahoma Tulsa 1,175 0.93 (82) 1,092

Ohio Cincinnati 1,175 0.93 (83) 1,092

Oregon Portland 1,175 1.08 96 1,271

Pennsylvania Philadelphia 1,175 1.21 251 1,426

Pennsylvania Wilkes-Barre 1,175 1.06 73 1,248

Rhode Island Providence 1,175 1.12 138 1,313

South Carolina Charleston 1,175 0.95 (55) 1,120

South Carolina Spartanburg (Asheville, NC) 1,175 0.96 (47) 1,128

South Dakota Rapid City 1,175 0.97 (33) 1,142

Tennessee Knoxville (Nashville) 1,175 0.97 (31) 1,144

Texas Houston 1,175 0.93 (84) 1,091

Utah Salt Lake City 1,175 0.97 (34) 1,141

Vermont Burlington 1,175 1.02 27 1,202

Virginia Alexandria 1,175 1.02 21 1,195

Virginia Lynchburg 1,175 0.96 (52) 1,123

Washington Seattle 1,175 1.14 160 1,334

Washington Spokane 1,175 1.04 45 1,220

West Virginia Charleston 1,175 1.04 43 1,218

Wisconsin Green Bay 1,175 1.04 44 1,219

Wyoming Cheyenne 1,175 0.99 (14) 1,161

Table 1 5 — Location Adjustment for Combined-Cycle Oil/Natural Gas Turbine 

(2019 Dollars)

Case Configuration: 100 MW, 2 x LM6000
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 713 0.95 (33) 680

Arizona Phoenix 713 0.98 (16) 696

Arkansas Little Rock 713 0.96 (30) 683

California Bakersfield 713 1.17 122 834

California Los Angeles 713 1.18 130 843

California Modesto (instead of Redding) 713 1.18 126 839

California Sacramento 713 1.19 138 851

California San Francisco 713 1.32 227 940

Colorado Denver 713 0.97 (25) 688

Connecticut Hartford 713 1.15 109 821

Delaware Dover 713 1.14 99 811

District of Columbia Washington 713 1.03 18 731

Florida Tallahassee 713 0.94 (42) 670

Florida Tampa 713 0.95 (33) 680

Georgia Atlanta 713 0.97 (18) 695

Idaho Boise 713 1.01 9 722

Illinois Chicago 713 1.24 170 883

Illinois Joliet 713 1.21 147 860

Indiana Indianapolis 713 1.01 6 719

Iowa Davenport 713 1.03 25 738

Iowa Waterloo 713 0.96 (26) 687

Kansas Wichita 713 0.97 (24) 689

Kentucky Louisville 713 0.99 (4) 709

Louisiana New Orleans 713 0.96 (28) 685

Maine Portland 713 1.01 4 717

Maryland Baltimore 713 1.02 12 725

Massachusetts Boston 713 1.20 145 857

Michigan Detroit 713 1.11 81 794

Michigan Grand Rapids 713 1.03 22 735

Minnesota Saint Paul 713 1.09 66 779

Mississippi Jackson 713 0.94 (41) 672

Missouri St. Louis 713 1.12 82 795

Missouri Kansas City 713 1.07 51 764

Montana Great Falls 713 0.96 (27) 686

Nebraska Omaha 713 0.97 (20) 692

New Hampshire Concord 713 1.05 37 750

New Jersey Newark 713 1.22 160 873

New Mexico Albuquerque 713 0.98 (16) 696

New York New York 713 1.44 315 1,028

New York Syracuse 713 1.06 43 756

Nevada Las Vegas 713 1.13 92 805

North Carolina Charlotte 713 0.96 (31) 682

North Dakota Bismarck 713 1.02 13 726

Oklahoma Oklahoma City 713 1.00 (1) 712

Oklahoma Tulsa 713 0.93 (52) 661

Ohio Cincinnati 713 0.93 (52) 661

Oregon Portland 713 1.09 61 774

Pennsylvania Philadelphia 713 1.22 159 871

Pennsylvania Wilkes-Barre 713 1.06 46 759

Rhode Island Providence 713 1.12 88 800

South Carolina Charleston 713 0.95 (33) 679

South Carolina Spartanburg (Asheville, NC) 713 0.96 (29) 683

South Dakota Rapid City 713 0.97 (21) 692

Tennessee Knoxville (Nashville) 713 0.97 (19) 694

Texas Houston 713 0.93 (53) 660

Utah Salt Lake City 713 0.97 (21) 692

Vermont Burlington 713 1.03 18 731

Virginia Alexandria 713 1.02 13 726

Virginia Lynchburg 713 0.95 (33) 680

Washington Seattle 713 1.14 101 814

Washington Spokane 713 1.04 29 742

West Virginia Charleston 713 1.04 27 740

Wisconsin Green Bay 713 1.04 27 740

Wyoming Cheyenne 713 0.99 (9) 704

Table 1 6 — Location Adjustment for Combined-Cycle Oil/Natural Gas Turbine 

(2019 Dollars)

Case Configuration: 1 x 240 MW, F-Class
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 958 0.95 (51) 907

Arizona Phoenix 958 1.05 50 1,008

Arkansas Little Rock 958 0.95 (49) 910

California Bakersfield 958 1.28 270 1,229

California Los Angeles 958 1.30 285 1,243

California Modesto (instead of Redding) 958 1.29 278 1,236

California Sacramento 958 1.31 298 1,256

California San Francisco 958 1.46 442 1,401

Colorado Denver 958 1.04 36 994

Connecticut Hartford 958 1.26 252 1,210

Delaware Dover 958 1.25 238 1,196

District of Columbia Washington 958 1.11 104 1,063

Florida Tallahassee 958 0.93 (64) 894

Florida Tampa 958 0.95 (50) 908

Georgia Atlanta 958 0.97 (29) 929

Idaho Boise 958 1.01 13 971

Illinois Chicago 958 1.27 257 1,216

Illinois Joliet 958 1.23 223 1,181

Indiana Indianapolis 958 1.01 8 966

Iowa Davenport 958 1.04 38 996

Iowa Waterloo 958 0.96 (40) 919

Kansas Wichita 958 0.96 (36) 922

Kentucky Louisville 958 0.99 (7) 951

Louisiana New Orleans 958 0.95 (45) 913

Maine Portland 958 1.01 5 963

Maryland Baltimore 958 1.02 18 977

Massachusetts Boston 958 1.32 310 1,269

Michigan Detroit 958 1.13 122 1,081

Michigan Grand Rapids 958 1.03 33 992

Minnesota Saint Paul 958 1.11 102 1,061

Mississippi Jackson 958 0.93 (62) 896

Missouri St. Louis 958 1.13 120 1,079

Missouri Kansas City 958 1.08 78 1,036

Montana Great Falls 958 0.96 (40) 919

Nebraska Omaha 958 0.97 (31) 927

New Hampshire Concord 958 1.14 134 1,092

New Jersey Newark 958 1.25 241 1,200

New Mexico Albuquerque 958 0.97 (28) 931

New York New York 958 1.61 589 1,548

New York Syracuse 958 1.15 146 1,105

Nevada Las Vegas 958 1.14 137 1,095

North Carolina Charlotte 958 0.95 (47) 912

North Dakota Bismarck 958 1.02 22 980

Oklahoma Oklahoma City 958 1.00 (1) 957

Oklahoma Tulsa 958 0.92 (78) 880

Ohio Cincinnati 958 0.92 (79) 880

Oregon Portland 958 1.09 90 1,048

Pennsylvania Philadelphia 958 1.35 333 1,292

Pennsylvania Wilkes-Barre 958 1.16 150 1,109

Rhode Island Providence 958 1.23 217 1,175

South Carolina Charleston 958 0.94 (57) 901

South Carolina Spartanburg (Asheville, NC) 958 0.95 (46) 912

South Dakota Rapid City 958 0.97 (30) 929

Tennessee Knoxville (Nashville) 958 0.97 (32) 927

Texas Houston 958 0.92 (80) 878

Utah Salt Lake City 958 0.96 (35) 924

Vermont Burlington 958 1.02 21 979

Virginia Alexandria 958 1.10 96 1,055

Virginia Lynchburg 958 1.02 22 981

Washington Seattle 958 1.16 150 1,108

Washington Spokane 958 1.04 42 1,001

West Virginia Charleston 958 1.04 41 999

Wisconsin Green Bay 958 1.05 43 1,002

Wyoming Cheyenne 958 0.99 (13) 945

Table 1 7 — Location Adjustment for Combined-Cycle Oil/Natural Gas Turbine 

(2019 Dollars)

Case Configuration: 1100 MW, H-Class, 2x2x1
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,084 0.96 (49) 1,035

Arizona Phoenix 1,084 1.10 114 1,197

Arkansas Little Rock 1,084 0.96 (47) 1,036

California Bakersfield 1,084 1.30 324 1,407

California Los Angeles 1,084 1.31 337 1,421

California Modesto (instead of Redding) 1,084 1.31 331 1,415

California Sacramento 1,084 1.32 350 1,434

California San Francisco 1,084 1.45 489 1,573

Colorado Denver 1,084 1.09 100 1,184

Connecticut Hartford 1,084 1.28 308 1,391

Delaware Dover 1,084 1.27 296 1,380

District of Columbia Washington 1,084 1.15 166 1,249

Florida Tallahassee 1,084 0.94 (60) 1,024

Florida Tampa 1,084 0.96 (47) 1,037

Georgia Atlanta 1,084 0.97 (28) 1,056

Idaho Boise 1,084 1.01 11 1,095

Illinois Chicago 1,084 1.22 238 1,322

Illinois Joliet 1,084 1.19 206 1,290

Indiana Indianapolis 1,084 1.01 6 1,090

Iowa Davenport 1,084 1.03 35 1,119

Iowa Waterloo 1,084 0.97 (37) 1,047

Kansas Wichita 1,084 0.97 (34) 1,050

Kentucky Louisville 1,084 0.99 (8) 1,076

Louisiana New Orleans 1,084 0.96 (43) 1,040

Maine Portland 1,084 1.00 4 1,088

Maryland Baltimore 1,084 1.02 17 1,100

Massachusetts Boston 1,084 1.34 364 1,447

Michigan Detroit 1,084 1.10 113 1,197

Michigan Grand Rapids 1,084 1.03 31 1,115

Minnesota Saint Paul 1,084 1.09 96 1,180

Mississippi Jackson 1,084 0.95 (58) 1,026

Missouri St. Louis 1,084 1.10 108 1,192

Missouri Kansas City 1,084 1.07 72 1,156

Montana Great Falls 1,084 0.97 (36) 1,047

Nebraska Omaha 1,084 0.97 (29) 1,055

New Hampshire Concord 1,084 1.18 192 1,276

New Jersey Newark 1,084 1.21 223 1,306

New Mexico Albuquerque 1,084 0.97 (27) 1,056

New York New York 1,084 1.58 634 1,717

New York Syracuse 1,084 1.19 206 1,290

Nevada Las Vegas 1,084 1.11 124 1,208

North Carolina Charlotte 1,084 0.96 (43) 1,040

North Dakota Bismarck 1,084 1.02 22 1,105

Oklahoma Oklahoma City 1,084 1.00 (1) 1,083

Oklahoma Tulsa 1,084 0.93 (72) 1,011

Ohio Cincinnati 1,084 0.93 (72) 1,011

Oregon Portland 1,084 1.21 229 1,313

Pennsylvania Philadelphia 1,084 1.36 387 1,470

Pennsylvania Wilkes-Barre 1,084 1.19 210 1,294

Rhode Island Providence 1,084 1.25 273 1,357

South Carolina Charleston 1,084 0.95 (57) 1,027

South Carolina Spartanburg (Asheville, NC) 1,084 0.96 (43) 1,040

South Dakota Rapid City 1,084 0.98 (26) 1,058

Tennessee Knoxville (Nashville) 1,084 0.97 (32) 1,052

Texas Houston 1,084 0.93 (74) 1,009

Utah Salt Lake City 1,084 0.97 (34) 1,050

Vermont Burlington 1,084 1.01 15 1,098

Virginia Alexandria 1,084 1.15 158 1,242

Virginia Lynchburg 1,084 1.08 87 1,171

Washington Seattle 1,084 1.13 136 1,220

Washington Spokane 1,084 1.03 38 1,122

West Virginia Charleston 1,084 1.04 38 1,122

Wisconsin Green Bay 1,084 1.04 42 1,126

Wyoming Cheyenne 1,084 0.99 (11) 1,072

Table 1 8 — Location Adjustment for Combined-Cycle Single Shaft 

(2019 Dollars)

Case Configuration: 430 MW, H-Class 1x1x1
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 2,481 0.98 (49) 2,432

Arizona Phoenix 2,481 0.99 (26) 2,454

Arkansas Little Rock 2,481 0.98 (42) 2,439

California Bakersfield 2,481 1.08 191 2,672

California Los Angeles 2,481 1.08 205 2,685

California Modesto (instead of Redding) 2,481 1.08 198 2,679

California Sacramento 2,481 1.09 217 2,697

California San Francisco 2,481 1.14 353 2,834

Colorado Denver 2,481 0.98 (39) 2,442

Connecticut Hartford 2,481 1.07 169 2,650

Delaware Dover 2,481 1.06 152 2,632

District of Columbia Washington 2,481 1.01 28 2,509

Florida Tallahassee 2,481 0.97 (66) 2,415

Florida Tampa 2,481 0.98 (50) 2,431

Georgia Atlanta 2,481 0.99 (26) 2,454

Idaho Boise 2,481 1.01 15 2,496

Illinois Chicago 2,481 1.11 264 2,745

Illinois Joliet 2,481 1.09 228 2,709

Indiana Indianapolis 2,481 1.00 12 2,492

Iowa Davenport 2,481 1.02 38 2,519

Iowa Waterloo 2,481 0.98 (41) 2,440

Kansas Wichita 2,481 0.98 (38) 2,443

Kentucky Louisville 2,481 1.00 (4) 2,477

Louisiana New Orleans 2,481 0.98 (40) 2,441

Maine Portland 2,481 1.00 6 2,487

Maryland Baltimore 2,481 1.01 19 2,500

Massachusetts Boston 2,481 1.09 225 2,706

Michigan Detroit 2,481 1.05 125 2,606

Michigan Grand Rapids 2,481 1.01 34 2,515

Minnesota Saint Paul 2,481 1.04 101 2,582

Mississippi Jackson 2,481 0.97 (64) 2,417

Missouri St. Louis 2,481 1.05 131 2,612

Missouri Kansas City 2,481 1.03 80 2,561

Montana Great Falls 2,481 0.98 (42) 2,439

Nebraska Omaha 2,481 0.99 (31) 2,449

New Hampshire Concord 2,481 1.02 61 2,542

New Jersey Newark 2,481 1.10 248 2,729

New Mexico Albuquerque 2,481 0.99 (22) 2,459

New York New York 2,481 1.20 489 2,970

New York Syracuse 2,481 1.03 67 2,548

Nevada Las Vegas 2,481 1.06 146 2,627

North Carolina Charlotte 2,481 0.98 (48) 2,433

North Dakota Bismarck 2,481 1.01 19 2,499

Oklahoma Oklahoma City 2,481 1.00 (2) 2,479

Oklahoma Tulsa 2,481 0.97 (81) 2,400

Ohio Cincinnati 2,481 0.97 (81) 2,400

Oregon Portland 2,481 1.04 98 2,579

Pennsylvania Philadelphia 2,481 1.10 246 2,727

Pennsylvania Wilkes-Barre 2,481 1.03 72 2,552

Rhode Island Providence 2,481 1.06 137 2,618

South Carolina Charleston 2,481 0.98 (42) 2,438

South Carolina Spartanburg (Asheville, NC) 2,481 0.98 (44) 2,437

South Dakota Rapid City 2,481 0.99 (35) 2,446

Tennessee Knoxville (Nashville) 2,481 0.99 (25) 2,456

Texas Houston 2,481 0.97 (82) 2,399

Utah Salt Lake City 2,481 0.99 (28) 2,453

Vermont Burlington 2,481 1.01 35 2,516

Virginia Alexandria 2,481 1.01 21 2,502

Virginia Lynchburg 2,481 0.98 (51) 2,430

Washington Seattle 2,481 1.06 160 2,641

Washington Spokane 2,481 1.02 46 2,527

West Virginia Charleston 2,481 1.02 42 2,523

Wisconsin Green Bay 2,481 1.02 40 2,521

Wyoming Cheyenne 2,481 0.99 (15) 2,466

Table 1 9 — Location Adjustment for Combined-Cycle Gas Turbine (with 90% CCS) 

(2019 Dollars)

Case Configuration: 430 MW, H-Class 1x1x1
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 6,700 0.99 (66) 6,634

Arizona Phoenix 6,700 0.99 (74) 6,626

Arkansas Little Rock 6,700 1.00 10 6,710

California Bakersfield 6,700 1.13 858 7,558

California Los Angeles 6,700 1.14 907 7,607

California Modesto (instead of Redding) 6,700 1.13 892 7,592

California Sacramento 6,700 1.14 953 7,652

California San Francisco 6,700 1.19 1,284 7,983

Colorado Denver 6,700 0.98 (157) 6,543

Connecticut Hartford 6,700 1.11 729 7,429

Delaware Dover 6,700 1.07 463 7,163

District of Columbia Washington 6,700 1.02 144 6,844

Florida Tallahassee 6,700 0.97 (205) 6,495

Florida Tampa 6,700 0.98 (136) 6,564

Georgia Atlanta 6,700 1.00 32 6,731

Idaho Boise 6,700 1.02 147 6,847

Illinois Chicago 6,700 1.16 1,051 7,750

Illinois Joliet 6,700 1.13 874 7,573

Indiana Indianapolis 6,700 1.02 161 6,861

Iowa Davenport 6,700 1.03 190 6,890

Iowa Waterloo 6,700 0.99 (63) 6,637

Kansas Wichita 6,700 0.99 (57) 6,643

Kentucky Louisville 6,700 1.01 97 6,797

Louisiana New Orleans 6,700 1.00 14 6,713

Maine Portland 6,700 1.01 97 6,797

Maryland Baltimore 6,700 1.02 131 6,831

Massachusetts Boston 6,700 1.14 905 7,605

Michigan Detroit 6,700 1.07 455 7,154

Michigan Grand Rapids 6,700 1.02 119 6,819

Minnesota Saint Paul 6,700 1.06 391 7,091

Mississippi Jackson 6,700 0.97 (205) 6,495

Missouri St. Louis 6,700 1.10 684 7,384

Missouri Kansas City 6,700 1.05 338 7,038

Montana Great Falls 6,700 0.98 (106) 6,594

Nebraska Omaha 6,700 0.99 (39) 6,661

New Hampshire Concord 6,700 1.07 450 7,150

New Jersey Newark 6,700 1.14 961 7,661

New Mexico Albuquerque 6,700 1.02 108 6,808

New York New York 6,700 1.27 1,834 8,533

New York Syracuse 6,700 1.04 254 6,954

Nevada Las Vegas 6,700 1.10 693 7,393

North Carolina Charlotte 6,700 0.98 (138) 6,562

North Dakota Bismarck 6,700 1.00 9 6,708

Oklahoma Oklahoma City 6,700 1.00 0 6,700

Oklahoma Tulsa 6,700 0.96 (268) 6,431

Ohio Cincinnati 6,700 0.96 (270) 6,430

Oregon Portland 6,700 1.07 496 7,196

Pennsylvania Philadelphia 6,700 1.13 892 7,592

Pennsylvania Wilkes-Barre 6,700 1.05 325 7,024

Rhode Island Providence 6,700 1.10 650 7,349

South Carolina Charleston 6,700 1.02 156 6,856

South Carolina Spartanburg (Asheville, NC) 6,700 0.99 (56) 6,644

South Dakota Rapid City 6,700 0.98 (111) 6,589

Tennessee Knoxville (Nashville) 6,700 1.01 51 6,751

Texas Houston 6,700 0.96 (270) 6,429

Utah Salt Lake City 6,700 1.02 113 6,813

Vermont Burlington 6,700 1.07 458 7,157

Virginia Alexandria 6,700 1.02 124 6,824

Virginia Lynchburg 6,700 0.98 (118) 6,582

Washington Seattle 6,700 1.11 705 7,405

Washington Spokane 6,700 1.04 243 6,943

West Virginia Charleston 6,700 1.02 149 6,848

Wisconsin Green Bay 6,700 1.02 113 6,812

Wyoming Cheyenne 6,700 0.99 (66) 6,633

Table 1 10 — Location Adjustment for Fuel Cell (Molten Carbonate or Other Commercially Viable Technology) 

(2019 Dollars)

Case Configuration: 10 MW (4 x 2.8 MW MCFC)
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 6,041 0.99 (53) 5,988

Arizona Phoenix 6,041 0.98 (147) 5,894

Arkansas Little Rock 6,041 1.02 122 6,163

California Bakersfield 6,041 1.22 1,305 7,346

California Los Angeles 6,041 1.22 1,339 7,380

California Modesto (instead of Redding) 6,041 1.22 1,358 7,399

California Sacramento 6,041 1.24 1,443 7,484

California San Francisco 6,041 1.30 1,830 7,871

Colorado Denver 6,041 0.96 (227) 5,815

Connecticut Hartford 6,041 1.16 946 6,987

Delaware Dover 6,041 1.10 602 6,643

District of Columbia Washington 6,041 1.02 146 6,188

Florida Tallahassee 6,041 0.95 (280) 5,761

Florida Tampa 6,041 0.97 (151) 5,890

Georgia Atlanta 6,041 1.01 61 6,103

Idaho Boise 6,041 1.04 258 6,300

Illinois Chicago 6,041 1.23 1,415 7,456

Illinois Joliet 6,041 1.20 1,207 7,249

Indiana Indianapolis 6,041 1.05 274 6,315

Iowa Davenport 6,041 1.04 231 6,272

Iowa Waterloo 6,041 0.98 (134) 5,907

Kansas Wichita 6,041 0.98 (130) 5,912

Kentucky Louisville 6,041 1.03 204 6,245

Louisiana New Orleans 6,041 1.02 95 6,137

Maine Portland 6,041 1.04 217 6,258

Maryland Baltimore 6,041 1.03 160 6,202

Massachusetts Boston 6,041 1.20 1,216 7,257

Michigan Detroit 6,041 1.10 634 6,675

Michigan Grand Rapids 6,041 1.04 225 6,267

Minnesota Saint Paul 6,041 1.06 389 6,430

Mississippi Jackson 6,041 0.95 (294) 5,747

Missouri St. Louis 6,041 1.18 1,061 7,103

Missouri Kansas City 6,041 1.07 418 6,459

Montana Great Falls 6,041 0.97 (186) 5,855

Nebraska Omaha 6,041 0.98 (100) 5,941

New Hampshire Concord 6,041 1.11 649 6,690

New Jersey Newark 6,041 1.21 1,297 7,338

New Mexico Albuquerque 6,041 1.03 196 6,237

New York New York 6,041 1.42 2,560 8,601

New York Syracuse 6,041 1.06 344 6,385

Nevada Las Vegas 6,041 1.18 1,095 7,136

North Carolina Charlotte 6,041 0.97 (203) 5,838

North Dakota Bismarck 6,041 1.00 (4) 6,037

Oklahoma Oklahoma City 6,041 1.00 4 6,045

Oklahoma Tulsa 6,041 0.94 (387) 5,654

Ohio Cincinnati 6,041 0.94 (389) 5,652

Oregon Portland 6,041 1.13 777 6,818

Pennsylvania Philadelphia 6,041 1.20 1,204 7,245

Pennsylvania Wilkes-Barre 6,041 1.08 463 6,504

Rhode Island Providence 6,041 1.15 893 6,935

South Carolina Charleston 6,041 1.07 407 6,448

South Carolina Spartanburg (Asheville, NC) 6,041 0.99 (50) 5,992

South Dakota Rapid City 6,041 0.95 (287) 5,754

Tennessee Knoxville (Nashville) 6,041 1.03 197 6,238

Texas Houston 6,041 0.94 (339) 5,703

Utah Salt Lake City 6,041 1.04 239 6,280

Vermont Burlington 6,041 1.15 892 6,933

Virginia Alexandria 6,041 1.02 110 6,151

Virginia Lynchburg 6,041 0.96 (214) 5,827

Washington Seattle 6,041 1.18 1,059 7,100

Washington Spokane 6,041 1.07 447 6,488

West Virginia Charleston 6,041 1.03 210 6,252

Wisconsin Green Bay 6,041 1.01 63 6,105

Wyoming Cheyenne 6,041 0.98 (107) 5,935

Table 1 11 — Location Adjustment for Advanced Nuclear AP 1000 (Brownfield Site) 

(2019 Dollars)

Case Configuration: 2 x 1117 MW, PWR
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 6,191 0.97 (204) 5,987

Arizona Phoenix 6,191 0.98 (97) 6,094

Arkansas Little Rock 6,191 0.97 (166) 6,025

California Bakersfield 6,191 1.20 1,242 7,433

California Los Angeles 6,191 1.21 1,270 7,461

California Modesto (instead of Redding) 6,191 1.21 1,309 7,500

California Sacramento 6,191 1.23 1,402 7,593

California San Francisco 6,191 1.30 1,855 8,046

Colorado Denver 6,191 0.97 (212) 5,979

Connecticut Hartford 6,191 1.17 1,033 7,224

Delaware Dover 6,191 1.14 850 7,041

District of Columbia Washington 6,191 1.02 135 6,326

Florida Tallahassee 6,191 0.94 (345) 5,845

Florida Tampa 6,191 0.96 (228) 5,963

Georgia Atlanta 6,191 0.99 (70) 6,121

Idaho Boise 6,191 1.03 202 6,392

Illinois Chicago 6,191 1.27 1,673 7,864

Illinois Joliet 6,191 1.23 1,429 7,620

Indiana Indianapolis 6,191 1.03 165 6,356

Iowa Davenport 6,191 1.05 282 6,473

Iowa Waterloo 6,191 0.97 (160) 6,031

Kansas Wichita 6,191 0.98 (142) 6,049

Kentucky Louisville 6,191 1.01 85 6,276

Louisiana New Orleans 6,191 0.98 (135) 6,056

Maine Portland 6,191 1.03 202 6,393

Maryland Baltimore 6,191 1.02 151 6,342

Massachusetts Boston 6,191 1.21 1,311 7,502

Michigan Detroit 6,191 1.12 754 6,944

Michigan Grand Rapids 6,191 1.04 274 6,465

Minnesota Saint Paul 6,191 1.10 628 6,819

Mississippi Jackson 6,191 0.95 (340) 5,851

Missouri St. Louis 6,191 1.14 867 7,058

Missouri Kansas City 6,191 1.08 490 6,681

Montana Great Falls 6,191 0.97 (182) 6,009

Nebraska Omaha 6,191 0.98 (126) 6,065

New Hampshire Concord 6,191 1.08 510 6,701

New Jersey Newark 6,191 1.24 1,467 7,658

New Mexico Albuquerque 6,191 0.99 (37) 6,154

New York New York 6,191 1.47 2,941 9,132

New York Syracuse 6,191 1.07 404 6,595

Nevada Las Vegas 6,191 1.16 999 7,189

North Carolina Charlotte 6,191 0.96 (238) 5,953

North Dakota Bismarck 6,191 1.03 170 6,361

Oklahoma Oklahoma City 6,191 1.01 40 6,231

Oklahoma Tulsa 6,191 0.93 (436) 5,755

Ohio Cincinnati 6,191 0.93 (438) 5,753

Oregon Portland 6,191 1.10 634 6,825

Pennsylvania Philadelphia 6,191 1.22 1,359 7,550

Pennsylvania Wilkes-Barre 6,191 1.08 525 6,716

Rhode Island Providence 6,191 1.15 902 7,093

South Carolina Charleston 6,191 0.98 (127) 6,064

South Carolina Spartanburg (Asheville, NC) 6,191 0.97 (187) 6,004

South Dakota Rapid City 6,191 0.97 (168) 6,023

Tennessee Knoxville (Nashville) 6,191 0.99 (84) 6,107

Texas Houston 6,191 0.93 (422) 5,769

Utah Salt Lake City 6,191 1.00 (16) 6,175

Vermont Burlington 6,191 1.07 444 6,635

Virginia Alexandria 6,191 1.01 93 6,284

Virginia Lynchburg 6,191 0.96 (245) 5,946

Washington Seattle 6,191 1.15 923 7,114

Washington Spokane 6,191 1.06 385 6,576

West Virginia Charleston 6,191 1.04 263 6,454

Wisconsin Green Bay 6,191 1.05 285 6,476

Wyoming Cheyenne 6,191 0.99 (53) 6,138

Table 1 12 — Location Adjustment for Small Modular Reactor (SMR) Nuclear Power Plant

(2019 Dollars)

Case Configuration: 600 MW
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 4,097 0.96 (160) 3,937

Arizona Phoenix 4,097 1.11 457 4,554

Arkansas Little Rock 4,097 0.96 (144) 3,953

California Bakersfield 4,097 1.30 1,247 5,344

California Los Angeles 4,097 1.32 1,318 5,415

California Modesto (instead of Redding) 4,097 1.31 1,259 5,356

California Sacramento 4,097 1.33 1,360 5,457

California San Francisco 4,097 1.47 1,907 6,004

Colorado Denver 4,097 1.09 381 4,478

Connecticut Hartford 4,097 1.29 1,203 5,300

Delaware Dover 4,097 1.27 1,124 5,221

District of Columbia Washington 4,097 1.17 685 4,782

Florida Tallahassee 4,097 0.95 (214) 3,883

Florida Tampa 4,097 0.96 (170) 3,927

Georgia Atlanta 4,097 0.98 (71) 4,026

Idaho Boise 4,097 1.02 73 4,170

Illinois Chicago 4,097 1.23 947 5,044

Illinois Joliet 4,097 1.20 806 4,903

Indiana Indianapolis 4,097 1.02 77 4,174

Iowa Davenport 4,097 1.04 153 4,250

Iowa Waterloo 4,097 0.98 (96) 4,001

Kansas Wichita 4,097 0.98 (81) 4,016

Kentucky Louisville 4,097 1.00 (2) 4,095

Louisiana New Orleans 4,097 0.97 (127) 3,970

Maine Portland 4,097 1.02 72 4,169

Maryland Baltimore 4,097 1.03 121 4,218

Massachusetts Boston 4,097 1.34 1,403 5,500

Michigan Detroit 4,097 1.10 418 4,515

Michigan Grand Rapids 4,097 1.03 142 4,240

Minnesota Saint Paul 4,097 1.09 385 4,482

Mississippi Jackson 4,097 0.95 (210) 3,887

Missouri St. Louis 4,097 1.11 464 4,562

Missouri Kansas City 4,097 1.07 291 4,388

Montana Great Falls 4,097 0.97 (106) 3,991

Nebraska Omaha 4,097 0.99 (52) 4,045

New Hampshire Concord 4,097 1.19 774 4,872

New Jersey Newark 4,097 1.22 891 4,988

New Mexico Albuquerque 4,097 1.00 (1) 4,096

New York New York 4,097 1.61 2,505 6,602

New York Syracuse 4,097 1.19 782 4,879

Nevada Las Vegas 4,097 1.14 553 4,650

North Carolina Charlotte 4,097 0.96 (161) 3,936

North Dakota Bismarck 4,097 1.01 56 4,153

Oklahoma Oklahoma City 4,097 1.00 (12) 4,085

Oklahoma Tulsa 4,097 0.93 (272) 3,825

Ohio Cincinnati 4,097 0.93 (273) 3,824

Oregon Portland 4,097 1.22 919 5,016

Pennsylvania Philadelphia 4,097 1.37 1,531 5,629

Pennsylvania Wilkes-Barre 4,097 1.21 853 4,950

Rhode Island Providence 4,097 1.26 1,055 5,152

South Carolina Charleston 4,097 0.96 (151) 3,946

South Carolina Spartanburg (Asheville, NC) 4,097 0.97 (124) 3,973

South Dakota Rapid City 4,097 0.98 (66) 4,031

Tennessee Knoxville (Nashville) 4,097 0.97 (124) 3,973

Texas Houston 4,097 0.93 (297) 3,801

Utah Salt Lake City 4,097 0.98 (65) 4,032

Vermont Burlington 4,097 1.02 93 4,190

Virginia Alexandria 4,097 1.16 661 4,758

Virginia Lynchburg 4,097 1.09 353 4,451

Washington Seattle 4,097 1.13 542 4,639

Washington Spokane 4,097 1.04 144 4,241

West Virginia Charleston 4,097 1.04 152 4,249

Wisconsin Green Bay 4,097 1.04 154 4,251

Wyoming Cheyenne 4,097 1.00 (6) 4,091

Table 1 13 — Location Adjustment for Dedicated Biomass Plant 

(2019 Dollars)

Case Configuration: 50 MW, Wood
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 705 0.94 (43) 662

Arizona Phoenix 705 0.98 (15) 690

Arkansas Little Rock 705 0.94 (41) 664

California Bakersfield 705 1.21 145 850

California Los Angeles 705 1.23 159 864

California Modesto (instead of Redding) 705 1.21 148 852

California Sacramento 705 1.24 168 873

California San Francisco 705 1.39 278 983

Colorado Denver 705 0.96 (25) 680

Connecticut Hartford 705 1.20 138 843

Delaware Dover 705 1.18 125 830

District of Columbia Washington 705 1.05 35 740

Florida Tallahassee 705 0.92 (53) 652

Florida Tampa 705 0.94 (44) 661

Georgia Atlanta 705 0.97 (23) 682

Idaho Boise 705 1.02 15 720

Illinois Chicago 705 1.30 214 919

Illinois Joliet 705 1.26 182 887

Indiana Indianapolis 705 1.02 15 720

Iowa Davenport 705 1.05 35 740

Iowa Waterloo 705 0.97 (22) 683

Kansas Wichita 705 0.97 (18) 687

Kentucky Louisville 705 1.00 (2) 702

Louisiana New Orleans 705 0.95 (36) 668

Maine Portland 705 1.02 16 720

Maryland Baltimore 705 1.04 27 732

Massachusetts Boston 705 1.25 178 883

Michigan Detroit 705 1.13 95 799

Michigan Grand Rapids 705 1.05 32 737

Minnesota Saint Paul 705 1.13 89 794

Mississippi Jackson 705 0.93 (52) 653

Missouri St. Louis 705 1.14 101 806

Missouri Kansas City 705 1.09 66 770

Montana Great Falls 705 0.97 (24) 681

Nebraska Omaha 705 0.98 (12) 693

New Hampshire Concord 705 1.07 50 755

New Jersey Newark 705 1.28 201 905

New Mexico Albuquerque 705 0.99 (8) 696

New York New York 705 1.57 400 1,105

New York Syracuse 705 1.08 55 759

Nevada Las Vegas 705 1.17 122 827

North Carolina Charlotte 705 0.95 (36) 668

North Dakota Bismarck 705 1.02 15 719

Oklahoma Oklahoma City 705 1.00 (2) 702

Oklahoma Tulsa 705 0.91 (61) 644

Ohio Cincinnati 705 0.91 (61) 643

Oregon Portland 705 1.11 79 784

Pennsylvania Philadelphia 705 1.29 205 909

Pennsylvania Wilkes-Barre 705 1.10 69 774

Rhode Island Providence 705 1.15 108 813

South Carolina Charleston 705 0.93 (46) 658

South Carolina Spartanburg (Asheville, NC) 705 0.95 (34) 670

South Dakota Rapid City 705 0.98 (13) 692

Tennessee Knoxville (Nashville) 705 0.95 (32) 673

Texas Houston 705 0.90 (67) 638

Utah Salt Lake City 705 0.97 (18) 687

Vermont Burlington 705 1.02 14 719

Virginia Alexandria 705 1.04 30 735

Virginia Lynchburg 705 0.96 (31) 673

Washington Seattle 705 1.17 119 824

Washington Spokane 705 1.04 31 736

West Virginia Charleston 705 1.05 35 739

Wisconsin Green Bay 705 1.05 37 742

Wyoming Cheyenne 705 1.00 (1) 704

Table 1 14 — Location Adjustment for Biomass Co-firing Retrofit onto Existing Coal Plant 

(2019 Dollars)

Case Configuration: 300 MWnet with 30 MW of Added Biomass
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 2,521 1.14 356 2,877

California Los Angeles 2,521 1.15 377 2,898

California Modesto (instead of Redding) 2,521 1.15 373 2,894

California Sacramento 2,521 1.16 401 2,922

California San Francisco 2,521 1.22 560 3,081

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 2,521 1.02 50 2,571

Illinois Chicago N/A N/A N/A N/A

Illinois Joliet 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 Jackson 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 Concord 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 2,521 1.11 277 2,798

North Carolina Charlotte N/A N/A N/A N/A

North Dakota Bismarck N/A N/A N/A N/A

Oklahoma Oklahoma City N/A N/A N/A N/A

Oklahoma Tulsa N/A N/A N/A N/A

Ohio Cincinnati N/A N/A N/A N/A

Oregon Portland 2,521 1.07 183 2,704

Pennsylvania Philadelphia N/A N/A N/A N/A

Pennsylvania Wilkes-Barre 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 Carolina Spartanburg (Asheville, NC) N/A N/A N/A N/A

South Dakota Rapid City N/A N/A N/A N/A

Tennessee Knoxville (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 Lynchburg N/A N/A N/A N/A

Washington Seattle 2,521 1.11 276 2,797

Washington Spokane 2,521 1.04 89 2,610

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 15 — Location Adjustment for Geothermal (Representative Plant Excluding Exploration and Production of Resource) 

(2019 Dollars)

Case Configuration: 50 MW
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,563 0.98 (39) 1,525

Arizona Phoenix 1,563 0.98 (28) 1,536

Arkansas Little Rock 1,563 0.99 (23) 1,540

California Bakersfield 1,563 1.16 249 1,812

California Los Angeles 1,563 1.16 258 1,821

California Modesto (instead of Redding) 1,563 1.16 248 1,812

California Sacramento 1,563 1.17 267 1,831

California San Francisco 1,563 1.25 394 1,957

Colorado Denver 1,563 0.97 (49) 1,515

Connecticut Hartford 1,563 1.14 213 1,776

Delaware Dover 1,563 1.09 146 1,709

District of Columbia Washington 1,563 1.02 36 1,599

Florida Tallahassee 1,563 0.96 (67) 1,497

Florida Tampa 1,563 0.97 (50) 1,513

Georgia Atlanta 1,563 0.99 (12) 1,551

Idaho Boise 1,563 1.02 32 1,595

Illinois Chicago 1,563 1.20 320 1,884

Illinois Joliet 1,563 1.17 268 1,831

Indiana Indianapolis 1,563 1.02 33 1,596

Iowa Davenport 1,563 1.04 55 1,619

Iowa Waterloo 1,563 0.98 (27) 1,536

Kansas Wichita 1,563 0.99 (23) 1,540

Kentucky Louisville 1,563 1.01 13 1,576

Louisiana New Orleans 1,563 0.99 (20) 1,543

Maine Portland 1,563 1.01 23 1,586

Maryland Baltimore 1,563 1.02 31 1,594

Massachusetts Boston 1,563 1.17 270 1,833

Michigan Detroit 1,563 1.09 135 1,698

Michigan Grand Rapids 1,563 1.02 36 1,599

Minnesota Saint Paul 1,563 1.08 122 1,685

Mississippi Jackson 1,563 0.96 (66) 1,497

Missouri St. Louis 1,563 1.12 180 1,744

Missouri Kansas City 1,563 1.06 99 1,663

Montana Great Falls 1,563 0.98 (34) 1,530

Nebraska Omaha 1,563 0.99 (20) 1,543

New Hampshire Concord 1,563 1.06 101 1,664

New Jersey Newark 1,563 1.18 288 1,851

New Mexico Albuquerque 1,563 1.00 4 1,567

New York New York 1,563 1.36 566 2,129

New York Syracuse 1,563 1.05 81 1,644

Nevada Las Vegas 1,563 1.12 191 1,755

North Carolina Charlotte 1,563 0.97 (47) 1,517

North Dakota Bismarck 1,563 1.00 5 1,568

Oklahoma Oklahoma City 1,563 1.00 1 1,564

Oklahoma Tulsa 1,563 0.95 (85) 1,479

Ohio Cincinnati 1,563 0.95 (85) 1,478

Oregon Portland 1,563 1.09 135 1,698

Pennsylvania Philadelphia 1,563 1.18 274 1,838

Pennsylvania Wilkes-Barre 1,563 1.06 91 1,654

Rhode Island Providence 1,563 1.12 184 1,747

South Carolina Charleston 1,563 1.00 (5) 1,558

South Carolina Spartanburg (Asheville, NC) 1,563 0.98 (31) 1,532

South Dakota Rapid City 1,563 0.98 (35) 1,528

Tennessee Knoxville (Nashville) 1,563 0.99 (9) 1,554

Texas Houston 1,563 0.94 (90) 1,473

Utah Salt Lake City 1,563 1.00 3 1,567

Vermont Burlington 1,563 1.06 86 1,650

Virginia Alexandria 1,563 1.02 30 1,593

Virginia Lynchburg 1,563 0.97 (48) 1,516

Washington Seattle 1,563 1.13 198 1,761

Washington Spokane 1,563 1.04 56 1,619

West Virginia Charleston 1,563 1.03 46 1,609

Wisconsin Green Bay 1,563 1.03 44 1,607

Wyoming Cheyenne 1,563 0.99 (16) 1,547

Table 1 16 — Location Adjustment for 30-MW Internal Combustion Engines (4 x 9.1MW) 

(2019 Dollars)

Case Configuration: 1100 MW, H-Class, 2x2x1
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 5,316 1.16 871 6,187

California Los Angeles 5,316 1.12 659 5,975

California Modesto (instead of Redding) 5,316 1.21 1,100 6,417

California Sacramento 5,316 1.21 1,092 6,408

California San Francisco 5,316 1.27 1,420 6,737

Colorado Denver 5,316 1.02 94 5,410

Connecticut Hartford 5,316 1.17 920 6,236

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 5,316 0.75 (1,345) 3,971

Illinois Chicago N/A N/A N/A N/A

Illinois Joliet 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 5,316 1.03 163 5,479

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 Jackson N/A N/A N/A N/A

Missouri St. Louis 5,316 1.15 771 6,088

Missouri Kansas City 5,316 1.06 332 5,648

Montana Great Falls 5,316 0.97 (141) 5,175

Nebraska Omaha N/A N/A N/A N/A

New Hampshire Concord 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 N/A N/A N/A N/A

North Carolina Charlotte 5,316 0.97 (161) 5,155

North Dakota Bismarck N/A N/A N/A N/A

Oklahoma Oklahoma City N/A N/A N/A N/A

Oklahoma Tulsa N/A N/A N/A N/A

Ohio Cincinnati 5,316 0.94 (318) 4,998

Oregon Portland 5,316 1.11 565 5,881

Pennsylvania Philadelphia N/A N/A N/A N/A

Pennsylvania Wilkes-Barre 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 Carolina Spartanburg (Asheville, NC) N/A N/A N/A N/A

South Dakota Rapid City 5,316 0.96 (198) 5,119

Tennessee Knoxville (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 Lynchburg N/A N/A N/A N/A

Washington Seattle 5,316 1.15 780 6,096

Washington Spokane 5,316 1.06 329 5,645

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 17 — Location Adjustment for Hydroelectric (Representative Plant in New-Stream-Reach Location) 

(2019 Dollars)

Case Configuration: 100 MW
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,389 1.02 24 1,413

Arizona Phoenix 1,389 0.99 (15) 1,374

Arkansas Little Rock 1,389 1.04 56 1,445

California Bakersfield 1,389 1.04 57 1,446

California Los Angeles 1,389 1.04 60 1,449

California Modesto (instead of Redding) 1,389 1.04 55 1,444

California Sacramento 1,389 1.04 57 1,446

California San Francisco 1,389 1.04 60 1,449

Colorado Denver 1,389 0.99 (12) 1,377

Connecticut Hartford 1,389 1.02 23 1,412

Delaware Dover 1,389 0.99 (17) 1,373

District of Columbia Washington 1,389 1.01 9 1,398

Florida Tallahassee 1,389 1.00 0 1,389

Florida Tampa 1,389 1.01 7 1,396

Georgia Atlanta 1,389 1.02 25 1,414

Idaho Boise 1,389 1.01 19 1,408

Illinois Chicago 1,389 1.01 15 1,404

Illinois Joliet 1,389 1.01 12 1,401

Indiana Indianapolis 1,389 1.02 29 1,418

Iowa Davenport 1,389 1.00 1 1,390

Iowa Waterloo 1,389 1.00 (1) 1,388

Kansas Wichita 1,389 1.00 (2) 1,387

Kentucky Louisville 1,389 1.02 28 1,417

Louisiana New Orleans 1,389 1.03 44 1,434

Maine Portland 1,389 1.01 11 1,400

Maryland Baltimore 1,389 1.01 8 1,397

Massachusetts Boston 1,389 1.02 32 1,421

Michigan Detroit 1,389 1.00 5 1,394

Michigan Grand Rapids 1,389 1.00 0 1,390

Minnesota Saint Paul 1,389 0.99 (21) 1,368

Mississippi Jackson 1,389 1.00 (4) 1,385

Missouri St. Louis 1,389 1.05 71 1,460

Missouri Kansas City 1,389 1.00 5 1,394

Montana Great Falls 1,389 0.99 (8) 1,381

Nebraska Omaha 1,389 1.00 1 1,390

New Hampshire Concord 1,389 1.03 47 1,436

New Jersey Newark 1,389 1.02 23 1,412

New Mexico Albuquerque 1,389 1.04 49 1,438

New York New York 1,389 1.03 37 1,426

New York Syracuse 1,389 1.00 5 1,394

Nevada Las Vegas 1,389 1.04 56 1,445

North Carolina Charlotte 1,389 1.00 (2) 1,387

North Dakota Bismarck 1,389 0.98 (29) 1,360

Oklahoma Oklahoma City 1,389 1.00 (6) 1,383

Oklahoma Tulsa 1,389 0.99 (8) 1,381

Ohio Cincinnati 1,389 0.99 (8) 1,381

Oregon Portland 1,389 1.04 53 1,442

Pennsylvania Philadelphia 1,389 1.02 22 1,411

Pennsylvania Wilkes-Barre 1,389 1.01 8 1,397

Rhode Island Providence 1,389 1.02 33 1,422

South Carolina Charleston 1,389 1.08 114 1,503

South Carolina Spartanburg (Asheville, NC) 1,389 1.02 22 1,411

South Dakota Rapid City 1,389 0.98 (31) 1,358

Tennessee Knoxville (Nashville) 1,389 1.04 57 1,446

Texas Houston 1,389 1.00 0 1,389

Utah Salt Lake City 1,389 1.04 54 1,443

Vermont Burlington 1,389 1.08 109 1,498

Virginia Alexandria 1,389 1.01 9 1,398

Virginia Lynchburg 1,389 1.00 (4) 1,385

Washington Seattle 1,389 1.04 61 1,450

Washington Spokane 1,389 1.02 26 1,415

West Virginia Charleston 1,389 1.00 (1) 1,389

Wisconsin Green Bay 1,389 0.98 (33) 1,356

Wyoming Cheyenne 1,389 0.99 (13) 1,376

Table 1 18 — Location Adjustment for Battery Storage: 4 Hours 

A battery energy storage project designed primarily to provide resource adequacy and bulk energy storage. 

(2019 Dollars)

Case Configuration: 
50 MW / 200 MWh
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 845 1.02 15 860

Arizona Phoenix 845 0.99 (9) 836

Arkansas Little Rock 845 1.04 34 879

California Bakersfield 845 1.04 35 880

California Los Angeles 845 1.04 36 881

California Modesto (instead of Redding) 845 1.04 33 878

California Sacramento 845 1.04 34 880

California San Francisco 845 1.04 37 882

Colorado Denver 845 0.99 (7) 838

Connecticut Hartford 845 1.02 14 859

Delaware Dover 845 0.99 (10) 835

District of Columbia Washington 845 1.01 5 851

Florida Tallahassee 845 1.00 0 845

Florida Tampa 845 1.00 4 849

Georgia Atlanta 845 1.02 15 860

Idaho Boise 845 1.01 12 857

Illinois Chicago 845 1.01 9 854

Illinois Joliet 845 1.01 7 853

Indiana Indianapolis 845 1.02 18 863

Iowa Davenport 845 1.00 1 846

Iowa Waterloo 845 1.00 (1) 844

Kansas Wichita 845 1.00 (1) 844

Kentucky Louisville 845 1.02 17 862

Louisiana New Orleans 845 1.03 27 872

Maine Portland 845 1.01 6 852

Maryland Baltimore 845 1.01 5 850

Massachusetts Boston 845 1.02 19 865

Michigan Detroit 845 1.00 3 848

Michigan Grand Rapids 845 1.00 0 845

Minnesota Saint Paul 845 0.99 (13) 833

Mississippi Jackson 845 1.00 (3) 843

Missouri St. Louis 845 1.05 43 888

Missouri Kansas City 845 1.00 3 848

Montana Great Falls 845 0.99 (5) 840

Nebraska Omaha 845 1.00 0 846

New Hampshire Concord 845 1.03 28 874

New Jersey Newark 845 1.02 14 859

New Mexico Albuquerque 845 1.04 30 875

New York New York 845 1.03 23 868

New York Syracuse 845 1.00 3 848

Nevada Las Vegas 845 1.04 34 879

North Carolina Charlotte 845 1.00 (1) 844

North Dakota Bismarck 845 0.98 (18) 827

Oklahoma Oklahoma City 845 1.00 (4) 841

Oklahoma Tulsa 845 0.99 (5) 840

Ohio Cincinnati 845 0.99 (5) 840

Oregon Portland 845 1.04 32 877

Pennsylvania Philadelphia 845 1.02 14 859

Pennsylvania Wilkes-Barre 845 1.01 5 850

Rhode Island Providence 845 1.02 20 865

South Carolina Charleston 845 1.08 69 914

South Carolina Spartanburg (Asheville, NC) 845 1.02 13 859

South Dakota Rapid City 845 0.98 (19) 826

Tennessee Knoxville (Nashville) 845 1.04 34 879

Texas Houston 845 1.00 0 845

Utah Salt Lake City 845 1.04 33 878

Vermont Burlington 845 1.08 66 911

Virginia Alexandria 845 1.01 5 850

Virginia Lynchburg 845 1.00 (2) 843

Washington Seattle 845 1.04 37 882

Washington Spokane 845 1.02 16 861

West Virginia Charleston 845 1.00 0 845

Wisconsin Green Bay 845 0.98 (20) 825

Wyoming Cheyenne 845 0.99 (7) 839

Table 1 19 — Location Adjustment for Battery Storage: 2 hours 

(2019 Dollars)

Case Configuration: 50 MW / 100 MWh
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,265 1.01 12 1,277

Arizona Phoenix 1,265 0.99 (16) 1,249

Arkansas Little Rock 1,265 1.03 35 1,301

California Bakersfield 1,265 1.05 60 1,325

California Los Angeles 1,265 1.05 63 1,329

California Modesto (instead of Redding) 1,265 1.05 58 1,323

California Sacramento 1,265 1.05 62 1,327

California San Francisco 1,265 1.06 76 1,342

Colorado Denver 1,265 0.99 (13) 1,252

Connecticut Hartford 1,265 1.03 32 1,298

Delaware Dover 1,265 1.00 (1) 1,265

District of Columbia Washington 1,265 1.01 9 1,274

Florida Tallahassee 1,265 1.00 (6) 1,259

Florida Tampa 1,265 1.00 0 1,265

Georgia Atlanta 1,265 1.01 14 1,280

Idaho Boise 1,265 1.01 16 1,281

Illinois Chicago 1,265 1.03 37 1,302

Illinois Joliet 1,265 1.03 32 1,297

Indiana Indianapolis 1,265 1.02 23 1,288

Iowa Davenport 1,265 1.00 4 1,269

Iowa Waterloo 1,265 0.99 (7) 1,259

Kansas Wichita 1,265 1.00 (6) 1,259

Kentucky Louisville 1,265 1.01 19 1,284

Louisiana New Orleans 1,265 1.02 28 1,293

Maine Portland 1,265 1.01 8 1,274

Maryland Baltimore 1,265 1.01 7 1,272

Massachusetts Boston 1,265 1.04 46 1,311

Michigan Detroit 1,265 1.01 15 1,281

Michigan Grand Rapids 1,265 1.00 3 1,268

Minnesota Saint Paul 1,265 1.00 (5) 1,261

Mississippi Jackson 1,265 0.99 (9) 1,256

Missouri St. Louis 1,265 1.05 63 1,328

Missouri Kansas City 1,265 1.01 12 1,277

Montana Great Falls 1,265 0.99 (9) 1,256

Nebraska Omaha 1,265 1.00 (3) 1,263

New Hampshire Concord 1,265 1.03 38 1,304

New Jersey Newark 1,265 1.03 42 1,307

New Mexico Albuquerque 1,265 1.03 33 1,298

New York New York 1,265 1.06 74 1,339

New York Syracuse 1,265 1.01 11 1,277

Nevada Las Vegas 1,265 1.04 55 1,320

North Carolina Charlotte 1,265 1.00 (6) 1,259

North Dakota Bismarck 1,265 0.98 (21) 1,245

Oklahoma Oklahoma City 1,265 1.00 (5) 1,260

Oklahoma Tulsa 1,265 0.99 (13) 1,252

Ohio Cincinnati 1,265 0.99 (13) 1,252

Oregon Portland 1,265 1.04 47 1,312

Pennsylvania Philadelphia 1,265 1.03 41 1,306

Pennsylvania Wilkes-Barre 1,265 1.01 11 1,276

Rhode Island Providence 1,265 1.03 37 1,302

South Carolina Charleston 1,265 1.06 76 1,342

South Carolina Spartanburg (Asheville, NC) 1,265 1.01 11 1,277

South Dakota Rapid City 1,265 0.98 (25) 1,240

Tennessee Knoxville (Nashville) 1,265 1.03 36 1,301

Texas Houston 1,265 0.99 (8) 1,257

Utah Salt Lake City 1,265 1.03 34 1,300

Vermont Burlington 1,265 1.06 79 1,345

Virginia Alexandria 1,265 1.01 8 1,273

Virginia Lynchburg 1,265 0.99 (9) 1,257

Washington Seattle 1,265 1.05 57 1,323

Washington Spokane 1,265 1.02 21 1,286

West Virginia Charleston 1,265 1.00 4 1,269

Wisconsin Green Bay 1,265 0.99 (19) 1,247

Wyoming Cheyenne 1,265 0.99 (10) 1,255

Table 1 20 — Location Adjustment for Onshore Wind, Large Plant Footprint: Great Plains Region 

(2019 Dollars)

Case Configuration: 200 MW, 2.8-MW WTG
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,677 1.01 14 1,691

Arizona Phoenix 1,677 0.99 (23) 1,653

Arkansas Little Rock 1,677 1.03 46 1,722

California Bakersfield 1,677 1.05 89 1,765

California Los Angeles 1,677 1.06 94 1,770

California Modesto (instead of Redding) 1,677 1.05 86 1,762

California Sacramento 1,677 1.05 91 1,768

California San Francisco 1,677 1.07 116 1,793

Colorado Denver 1,677 0.99 (19) 1,658

Connecticut Hartford 1,677 1.03 50 1,727

Delaware Dover 1,677 1.00 4 1,680

District of Columbia Washington 1,677 1.01 13 1,689

Florida Tallahassee 1,677 0.99 (11) 1,666

Florida Tampa 1,677 1.00 (3) 1,674

Georgia Atlanta 1,677 1.01 18 1,695

Idaho Boise 1,677 1.01 22 1,699

Illinois Chicago 1,677 1.04 61 1,737

Illinois Joliet 1,677 1.03 53 1,729

Indiana Indianapolis 1,677 1.02 32 1,709

Iowa Davenport 1,677 1.00 7 1,683

Iowa Waterloo 1,677 0.99 (11) 1,666

Kansas Wichita 1,677 0.99 (10) 1,667

Kentucky Louisville 1,677 1.02 25 1,702

Louisiana New Orleans 1,677 1.02 36 1,712

Maine Portland 1,677 1.01 11 1,688

Maryland Baltimore 1,677 1.01 10 1,686

Massachusetts Boston 1,677 1.04 71 1,747

Michigan Detroit 1,677 1.02 25 1,702

Michigan Grand Rapids 1,677 1.00 5 1,681

Minnesota Saint Paul 1,677 1.00 (2) 1,674

Mississippi Jackson 1,677 0.99 (15) 1,662

Missouri St. Louis 1,677 1.05 90 1,767

Missouri Kansas City 1,677 1.01 19 1,695

Montana Great Falls 1,677 0.99 (14) 1,663

Nebraska Omaha 1,677 1.00 (5) 1,672

New Hampshire Concord 1,677 1.03 54 1,731

New Jersey Newark 1,677 1.04 67 1,743

New Mexico Albuquerque 1,677 1.03 44 1,720

New York New York 1,677 1.07 118 1,795

New York Syracuse 1,677 1.01 18 1,695

Nevada Las Vegas 1,677 1.05 80 1,756

North Carolina Charlotte 1,677 0.99 (10) 1,666

North Dakota Bismarck 1,677 0.98 (27) 1,649

Oklahoma Oklahoma City 1,677 1.00 (7) 1,670

Oklahoma Tulsa 1,677 0.99 (21) 1,656

Ohio Cincinnati 1,677 0.99 (21) 1,655

Oregon Portland 1,677 1.04 67 1,744

Pennsylvania Philadelphia 1,677 1.04 65 1,742

Pennsylvania Wilkes-Barre 1,677 1.01 17 1,694

Rhode Island Providence 1,677 1.03 55 1,732

South Carolina Charleston 1,677 1.06 101 1,778

South Carolina Spartanburg (Asheville, NC) 1,677 1.01 14 1,690

South Dakota Rapid City 1,677 0.98 (35) 1,642

Tennessee Knoxville (Nashville) 1,677 1.03 46 1,723

Texas Houston 1,677 0.99 (14) 1,662

Utah Salt Lake City 1,677 1.03 45 1,722

Vermont Burlington 1,677 1.06 108 1,785

Virginia Alexandria 1,677 1.01 11 1,688

Virginia Lynchburg 1,677 0.99 (14) 1,663

Washington Seattle 1,677 1.05 83 1,760

Washington Spokane 1,677 1.02 29 1,705

West Virginia Charleston 1,677 1.00 6 1,683

Wisconsin Green Bay 1,677 0.99 (24) 1,653

Wyoming Cheyenne 1,677 0.99 (15) 1,662

Table 1 21 — Location Adjustment for Onshore Wind, Small Plant Footprint: Coastal Region 

(2019 Dollars)

Case Configuration: 50 MW, 2.8-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 4,375 1.03 152 4,527

California Los Angeles 4,375 1.58 2,548 6,923

California Modesto (instead of Redding) 4,375 1.52 2,264 6,639

California Sacramento 4,375 1.58 2,538 6,912

California San Francisco 4,375 1.90 3,944 8,318

Colorado Denver N/A N/A N/A N/A

Connecticut Hartford 4,375 1.01 41 4,416

Delaware Dover 4,375 1.31 1,344 5,719

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 4,375 1.02 87 4,462

Idaho Boise N/A N/A N/A N/A

Illinois Chicago 4,375 1.00 (7) 4,368

Illinois Joliet 4,375 1.65 2,842 7,217

Indiana Indianapolis 4,375 1.06 277 4,652

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 4,375 1.01 31 4,405

Maryland Baltimore 4,375 1.04 180 4,555

Massachusetts Boston 4,375 1.64 2,815 7,190

Michigan Detroit 4,375 1.32 1,409 5,784

Michigan Grand Rapids 4,375 1.07 318 4,693

Minnesota Saint Paul 4,375 1.29 1,286 5,661

Mississippi Jackson 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 Concord N/A N/A N/A N/A

New Jersey Newark 4,375 1.01 27 4,402

New Mexico Albuquerque N/A N/A N/A N/A

New York New York 4,375 1.01 27 4,402

New York Syracuse 4,375 1.22 962 5,337

Nevada Las Vegas N/A N/A N/A N/A

North Carolina Charlotte 4,375 1.00 0 4,375

North Dakota Bismarck N/A N/A N/A N/A

Oklahoma Oklahoma City N/A N/A N/A N/A

Oklahoma Tulsa N/A N/A N/A N/A

Ohio Cincinnati N/A N/A N/A N/A

Oregon Portland 4,375 1.00 (12) 4,363

Pennsylvania Philadelphia N/A N/A N/A N/A

Pennsylvania Wilkes-Barre N/A N/A N/A N/A

Rhode Island Providence 4,375 1.01 27 4,402

South Carolina Charleston 4,375 0.81 (819) 3,556

South Carolina Spartanburg (Asheville, NC) 4,375 0.89 (494) 3,881

South Dakota Rapid City N/A N/A N/A N/A

Tennessee Knoxville (Nashville) N/A N/A N/A N/A

Texas Houston 4,375 0.98 (102) 4,273

Utah Salt Lake City N/A N/A N/A N/A

Vermont Burlington N/A N/A N/A N/A

Virginia Alexandria 4,375 1.04 182 4,557

Virginia Lynchburg 4,375 0.91 (375) 4,000

Washington Seattle 4,375 1.35 1,531 5,905

Washington Spokane 4,375 1.05 209 4,584

West Virginia Charleston N/A N/A N/A N/A

Wisconsin Green Bay 4,375 1.02 81 4,455

Wyoming Cheyenne N/A N/A N/A N/A

Table 1-22 — Location Adjustment for Offshore Wind 

(2019 Dollars)

Case Configuration: 40 x 10 MW WTG
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 7221 1.01 67 7288

Arizona Phoenix 7221 0.97 (201) 7021

Arkansas Little Rock 7221 1.05 370 7591

California Bakersfield 7221 1.17 1,220 8441

California Los Angeles 7221 1.18 1,269 8490

California Modesto (instead of Redding) 7221 1.17 1,242 8463

California Sacramento 7221 1.18 1,307 8529

California San Francisco 7221 1.24 1,738 8959

Colorado Denver 7221 0.97 (241) 6980

Connecticut Hartford 7221 1.11 782 8003

Delaware Dover 7221 1.05 346 7568

District of Columbia Washington 7221 1.02 144 7365

Florida Tallahassee 7221 0.97 (212) 7009

Florida Tampa 7221 0.99 (88) 7134

Georgia Atlanta 7221 1.02 151 7372

Idaho Boise 7221 1.03 247 7468

Illinois Chicago 7221 1.14 1,030 8252

Illinois Joliet 7221 1.12 881 8102

Indiana Indianapolis 7221 1.04 305 7527

Iowa Davenport 7221 1.02 144 7365

Iowa Waterloo 7221 0.98 (129) 7092

Kansas Wichita 7221 0.98 (138) 7083

Kentucky Louisville 7221 1.04 256 7477

Louisiana New Orleans 7221 1.04 275 7496

Maine Portland 7221 1.02 138 7359

Maryland Baltimore 7221 1.02 128 7350

Massachusetts Boston 7221 1.14 1,040 8261

Michigan Detroit 7221 1.07 470 7692

Michigan Grand Rapids 7221 1.02 132 7353

Minnesota Saint Paul 7221 1.02 128 7350

Mississippi Jackson 7221 0.97 (244) 6978

Missouri St. Louis 7221 1.16 1,126 8347

Missouri Kansas City 7221 1.04 313 7535

Montana Great Falls 7221 0.97 (206) 7015

Nebraska Omaha 7221 0.99 (105) 7117

New Hampshire Concord 7221 1.09 666 7888

New Jersey Newark 7221 1.14 1,027 8248

New Mexico Albuquerque 7221 1.05 355 7577

New York New York 7221 1.27 1,982 9203

New York Syracuse 7221 1.04 255 7477

Nevada Las Vegas 7221 1.14 1,033 8254

North Carolina Charlotte 7221 0.98 (175) 7046

North Dakota Bismarck 7221 0.98 (180) 7041

Oklahoma Oklahoma City 7221 0.99 (38) 7184

Oklahoma Tulsa 7221 0.95 (332) 6889

Ohio Cincinnati 7221 0.95 (333) 6888

Oregon Portland 7221 1.11 829 8050

Pennsylvania Philadelphia 7221 1.14 986 8207

Pennsylvania Wilkes-Barre 7221 1.05 326 7548

Rhode Island Providence 7221 1.11 791 8012

South Carolina Charleston 7221 1.12 865 8086

South Carolina Spartanburg (Asheville, NC) 7221 1.01 58 7280

South Dakota Rapid City 7221 0.94 (409) 6812

Tennessee Knoxville (Nashville) 7221 1.06 452 7673

Texas Houston 7221 0.96 (255) 6966

Utah Salt Lake City 7221 1.06 408 7630

Vermont Burlington 7221 1.16 1,174 8396

Virginia Alexandria 7221 1.02 114 7335

Virginia Lynchburg 7221 0.97 (196) 7025

Washington Seattle 7221 1.16 1,124 8345

Washington Spokane 7221 1.06 442 7664

West Virginia Charleston 7221 1.02 140 7361

Wisconsin Green Bay 7221 0.98 (167) 7054

Wyoming Cheyenne 7221 0.98 (174) 7048

Note: Location adjustment factors are provided for all locations for the Concentrated Solar Power case. However, concentrated solar power is only feasible in locations with sufficient solar resource; therefore, 

it is unlikely that a concentrated solar power plant would be built in some of the locations for which factors are provided.

Table 1 23 — Location Adjustment for Concentrated Solar Thermal Plant (CSP), Power Tower, 8-hour Thermal Storage 

(2019 Dollars)

Case Configuration: 100 MW
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,313 0.95 (68) 1,244

Arizona Phoenix 1,313 0.97 (40) 1,273

Arkansas Little Rock 1,313 0.98 (29) 1,284

California Bakersfield 1,313 1.07 87 1,400

California Los Angeles 1,313 1.09 116 1,429

California Modesto (instead of Redding) 1,313 1.06 74 1,386

California Sacramento 1,313 1.08 99 1,412

California San Francisco 1,313 1.18 235 1,548

Colorado Denver 1,313 0.98 (28) 1,285

Connecticut Hartford 1,313 1.08 104 1,417

Delaware Dover 1,313 1.04 56 1,369

District of Columbia Washington 1,313 1.02 24 1,337

Florida Tallahassee 1,313 0.96 (50) 1,263

Florida Tampa 1,313 0.97 (37) 1,276

Georgia Atlanta 1,313 0.98 (24) 1,289

Idaho Boise 1,313 0.98 (32) 1,281

Illinois Chicago 1,313 1.08 108 1,421

Illinois Joliet 1,313 1.09 124 1,437

Indiana Indianapolis 1,313 1.01 15 1,328

Iowa Davenport 1,313 1.01 20 1,333

Iowa Waterloo 1,313 0.97 (40) 1,273

Kansas Wichita 1,313 0.98 (27) 1,286

Kentucky Louisville 1,313 0.99 (8) 1,305

Louisiana New Orleans 1,313 0.98 (27) 1,286

Maine Portland 1,313 1.00 4 1,317

Maryland Baltimore 1,313 1.01 13 1,326

Massachusetts Boston 1,313 1.10 137 1,450

Michigan Detroit 1,313 1.04 55 1,368

Michigan Grand Rapids 1,313 1.01 13 1,326

Minnesota Saint Paul 1,313 1.04 55 1,368

Mississippi Jackson 1,313 0.97 (41) 1,272

Missouri St. Louis 1,313 1.06 83 1,396

Missouri Kansas City 1,313 1.03 38 1,351

Montana Great Falls 1,313 0.98 (25) 1,288

Nebraska Omaha 1,313 0.98 (21) 1,292

New Hampshire Concord 1,313 1.02 20 1,333

New Jersey Newark 1,313 1.11 151 1,464

New Mexico Albuquerque 1,313 1.00 (5) 1,308

New York New York 1,313 1.22 287 1,600

New York Syracuse 1,313 1.03 34 1,347

Nevada Las Vegas 1,313 1.07 87 1,399

North Carolina Charlotte 1,313 0.97 (38) 1,274

North Dakota Bismarck 1,313 0.99 (17) 1,296

Oklahoma Oklahoma City 1,313 0.98 (29) 1,284

Oklahoma Tulsa 1,313 0.95 (60) 1,253

Ohio Cincinnati 1,313 0.95 (61) 1,252

Oregon Portland 1,313 1.05 65 1,378

Pennsylvania Philadelphia 1,313 1.13 173 1,486

Pennsylvania Wilkes-Barre 1,313 1.02 24 1,337

Rhode Island Providence 1,313 1.04 55 1,368

South Carolina Charleston 1,313 1.03 44 1,357

South Carolina Spartanburg (Asheville, NC) 1,313 1.04 55 1,368

South Dakota Rapid City 1,313 0.96 (50) 1,263

Tennessee Knoxville (Nashville) 1,313 1.00 (1) 1,312

Texas Houston 1,313 0.99 (19) 1,294

Utah Salt Lake City 1,313 0.97 (41) 1,272

Vermont Burlington 1,313 0.97 (40) 1,273

Virginia Alexandria 1,313 1.00 (6) 1,307

Virginia Lynchburg 1,313 0.98 (25) 1,288

Washington Seattle 1,313 1.03 41 1,354

Washington Spokane 1,313 0.97 (43) 1,269

West Virginia Charleston 1,313 1.06 77 1,390

Wisconsin Green Bay 1,313 0.99 (16) 1,297

Wyoming Cheyenne 1,313 1.01 13 1,326

Table 1 24 — Location Adjustment for Solar Photovoltaic, Single-Axis Tracking (with 1.3 Inverter Loading Ratio) 

(2019 Dollars)

Case Configuration: 150 MW 
State City Base Project Cost ($/kW ) Location Variation Delta Cost Difference ($/kW) Total Location Project Cost ($/kW)

Alabama Huntsville 1,755 0.98 (42) 1,713

Arizona Phoenix 1,755 0.98 (36) 1,719

Arkansas Little Rock 1,755 0.99 (11) 1,744

California Bakersfield 1,755 1.07 129 1,884

California Los Angeles 1,755 1.09 151 1,906

California Modesto (instead of Redding) 1,755 1.07 116 1,871

California Sacramento 1,755 1.08 137 1,892

California San Francisco 1,755 1.14 243 1,998

Colorado Denver 1,755 0.98 (32) 1,723

Connecticut Hartford 1,755 1.07 125 1,881

Delaware Dover 1,755 1.04 64 1,819

District of Columbia Washington 1,755 1.02 29 1,785

Florida Tallahassee 1,755 0.97 (45) 1,710

Florida Tampa 1,755 0.98 (31) 1,724

Georgia Atlanta 1,755 0.99 (11) 1,744

Idaho Boise 1,755 1.00 (3) 1,753

Illinois Chicago 1,755 1.09 162 1,918

Illinois Joliet 1,755 1.09 152 1,908

Indiana Indianapolis 1,755 1.01 26 1,781

Iowa Davenport 1,755 1.02 28 1,783

Iowa Waterloo 1,755 0.98 (32) 1,723

Kansas Wichita 1,755 0.99 (18) 1,737

Kentucky Louisville 1,755 1.00 5 1,760

Louisiana New Orleans 1,755 0.99 (10) 1,745

Maine Portland 1,755 1.01 14 1,769

Maryland Baltimore 1,755 1.01 18 1,773

Massachusetts Boston 1,755 1.09 164 1,919

Michigan Detroit 1,755 1.04 68 1,824

Michigan Grand Rapids 1,755 1.01 19 1,775

Minnesota Saint Paul 1,755 1.04 68 1,823

Mississippi Jackson 1,755 0.98 (41) 1,714

Missouri St. Louis 1,755 1.06 114 1,869

Missouri Kansas City 1,755 1.03 53 1,808

Montana Great Falls 1,755 0.99 (23) 1,732

Nebraska Omaha 1,755 0.99 (16) 1,740

New Hampshire Concord 1,755 1.03 47 1,802

New Jersey Newark 1,755 1.10 173 1,928

New Mexico Albuquerque 1,755 1.01 12 1,768

New York New York 1,755 1.19 332 2,087

New York Syracuse 1,755 1.03 48 1,803

Nevada Las Vegas 1,755 1.07 118 1,873

North Carolina Charlotte 1,755 0.98 (33) 1,722

North Dakota Bismarck 1,755 0.99 (11) 1,744

Oklahoma Oklahoma City 1,755 0.99 (18) 1,737

Oklahoma Tulsa 1,755 0.97 (59) 1,696

Ohio Cincinnati 1,755 0.97 (60) 1,696

Oregon Portland 1,755 1.05 84 1,839

Pennsylvania Philadelphia 1,755 1.10 181 1,937

Pennsylvania Wilkes-Barre 1,755 1.02 42 1,797

Rhode Island Providence 1,755 1.05 93 1,848

South Carolina Charleston 1,755 1.01 13 1,768

South Carolina Spartanburg (Asheville, NC) 1,755 1.00 (7) 1,748

South Dakota Rapid City 1,755 0.99 (26) 1,729

Tennessee Knoxville (Nashville) 1,755 0.99 (16) 1,739

Texas Houston 1,755 0.97 (56) 1,699

Utah Salt Lake City 1,755 1.01 16 1,771

Vermont Burlington 1,755 1.02 43 1,798

Virginia Alexandria 1,755 1.02 33 1,788

Virginia Lynchburg 1,755 0.98 (43) 1,712

Washington Seattle 1,755 1.06 114 1,869

Washington Spokane 1,755 1.01 17 1,772

West Virginia Charleston 1,755 1.01 21 1,776

Wisconsin Green Bay 1,755 1.01 12 1,767

Wyoming Cheyenne 1,755 1.00 (6) 1,749

Table 1 25 — Location Adjustment for Solar Photovoltaic, Single-Axis Tracking (with 1.3 Inverter Loading Ratio) with Battery Hybrid

 (2019 Dollars)

Case Configuration: PV with tracking
150 MW PV
50 MW/200 MWh BESS
Cost & Performance Estimates for New Utility-Scale Electric Power Generating Technologies Project 13651.005

Appendix B. Combustion Turbine Capacity Adjustments
Capital Cost Study

Cost and Performance Estimates 

for New Utility-Scale Electric Power 

Generating Technologies

Performance 

Adjustment Factors

Prepared by

Sargent & Lundy

FINAL

Contract No. 89303019CEI00022

Project No. 13651-005

Prepared for

U.S. Energy Information 

Administration

55 East Monroe | Chicago, IL 60603 | sargentlundy.com
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 HR Net MW Net HR Net MW Net HR Net MW Net HR Net 

ISO ISO - 0 59.0 100.0% 100.0% 100.0% 100.0% 105.1 8,220 232.6 8,923 418.3 5,793 406.9 5,955 1,083.3 5,739 1,026.5 6,056

Alabama Huntsville 723230 624 61.7 96.8% 100.3% 97.2% 100.3% 101.7 8,242 225.1 8,947 406.4 5,809 395.3 5,971 1,052.5 5,754 997.4 6,072

Alaska Anchorage 997381 10 37.4 108.6% 97.8% 105.4% 98.9% 114.1 8,042 252.6 8,730 440.7 5,731 428.7 5,891 1,141.4 5,677 1,081.6 5,991

Alaska Fairbanks 702610 432 28.0 110.7% 96.9% 106.1% 98.5% 116.3 7,965 257.5 8,646 443.9 5,709 431.8 5,868 1,149.6 5,655 1,089.4 5,967

Arizona Phoenix 722780 1,107 75.2 89.9% 101.6% 92.2% 101.0% 94.5 8,353 209.1 9,068 385.8 5,853 375.3 6,017 999.1 5,798 946.8 6,118

Arkansas Little Rock 723400 563 61.6 97.0% 100.3% 97.4% 100.2% 101.9 8,241 225.7 8,946 407.4 5,808 396.3 5,970 1,055.0 5,753 999.8 6,071

California Los Angeles 722950 97 63.2 98.0% 100.4% 98.6% 100.2% 103.0 8,254 227.9 8,961 412.5 5,807 401.3 5,969 1,068.3 5,752 1,012.3 6,070

California Redding 725920 497 62.8 96.8% 100.4% 97.3% 100.3% 101.7 8,251 225.1 8,957 407.1 5,810 396.0 5,973 1,054.3 5,755 999.1 6,073

California Bakersfield 723840 489 65.7 95.7% 100.7% 96.6% 100.4% 100.5 8,275 222.5 8,983 404.2 5,819 393.2 5,981 1,046.9 5,764 992.1 6,082

California Modesto 724926 73 63.0 98.1% 100.4% 98.7% 100.2% 103.1 8,253 228.3 8,959 413.0 5,806 401.8 5,968 1,069.7 5,751 1,013.7 6,069

California Sacramento 724839 23 61.9 98.8% 100.3% 99.2% 100.1% 103.8 8,244 229.7 8,949 414.9 5,802 403.6 5,964 1,074.6 5,747 1,018.3 6,065

California San Francisco 724940 8 58.1 100.3% 99.9% 100.2% 100.0% 105.4 8,212 233.4 8,915 419.1 5,791 407.7 5,953 1,085.4 5,736 1,028.6 6,053

Colorado Denver 725650 5,414 51.0 83.6% 99.2% 82.7% 100.7% 87.9 8,154 194.6 8,852 345.8 5,833 336.4 5,996 895.6 5,778 848.7 6,097

Connecticut Hartford 725087 19 52.3 102.6% 99.3% 101.6% 99.7% 107.8 8,165 238.7 8,863 425.0 5,774 413.4 5,936 1,100.7 5,720 1,043.0 6,036

DC Washington 745940 282 56.4 100.0% 99.7% 99.7% 99.9% 105.1 8,199 232.7 8,900 416.8 5,789 405.5 5,951 1,079.6 5,735 1,023.0 6,051

Delaware Dover 724088 28 56.1 101.1% 99.7% 100.6% 99.9% 106.2 8,196 235.1 8,897 420.9 5,785 409.4 5,947 1,090.1 5,731 1,033.0 6,047

Florida Tallahassee 722140 55 68.2 96.1% 100.9% 97.5% 100.5% 101.0 8,295 223.6 9,005 407.9 5,821 396.8 5,983 1,056.3 5,766 1,001.0 6,084

Florida Tampa 722110 19 73.5 94.1% 101.5% 96.3% 100.7% 98.9 8,339 219.0 9,052 402.8 5,836 391.9 5,999 1,043.3 5,781 988.7 6,100

Georgia Atlanta 722190 1,027 63.0 94.9% 100.4% 95.4% 100.4% 99.7 8,253 220.7 8,959 399.2 5,817 388.3 5,980 1,033.9 5,762 979.8 6,080

Hawaii Honolulu 911820 7 77.8 92.5% 101.9% 95.3% 100.9% 97.2 8,374 215.1 9,091 398.5 5,848 387.7 6,012 1,032.1 5,793 978.1 6,113

Idaho Boise 726810 2,814 52.9 92.4% 99.4% 91.5% 100.3% 97.0 8,170 214.8 8,869 382.8 5,808 372.4 5,971 991.5 5,753 939.6 6,071

Illinois Chicago 997338 663 50.0 101.2% 99.1% 99.9% 99.7% 106.3 8,146 235.4 8,843 417.8 5,775 406.4 5,937 1,081.9 5,720 1,025.3 6,037

Indiana Indianapolis 724380 790 53.6 99.3% 99.5% 98.5% 99.9% 104.4 8,175 231.1 8,875 412.2 5,787 401.0 5,949 1,067.5 5,732 1,011.6 6,049

Iowa Davenport 725349 753 49.7 101.0% 99.1% 99.6% 99.7% 106.1 8,143 234.9 8,840 416.7 5,775 405.4 5,937 1,079.2 5,721 1,022.7 6,037

Iowa Waterloo 725480 686 47.9 101.9% 98.9% 100.3% 99.6% 107.1 8,129 237.1 8,824 419.6 5,769 408.1 5,931 1,086.6 5,715 1,029.7 6,030

Kansas Wichita 724500 1,321 57.6 95.9% 99.9% 95.7% 100.2% 100.8 8,208 223.1 8,911 400.3 5,805 389.4 5,967 1,036.8 5,750 982.5 6,068

Kentucky Louisville 724230 488 58.3 98.6% 99.9% 98.5% 100.1% 103.6 8,214 229.3 8,917 411.8 5,797 400.6 5,959 1,066.6 5,742 1,010.8 6,060

Louisiana New Orleans 722316 2 68.7 96.1% 101.0% 97.6% 100.5% 101.0 8,300 223.6 9,010 408.1 5,822 397.0 5,984 1,056.9 5,767 1,001.6 6,085

Maine Portland 726060 45 47.1 104.6% 98.8% 102.8% 99.4% 109.9 8,122 243.3 8,817 430.0 5,760 418.3 5,921 1,113.7 5,705 1,055.4 6,020

Maryland Baltimore 724060 56 56.0 101.0% 99.7% 100.6% 99.9% 106.1 8,195 234.9 8,896 420.6 5,785 409.1 5,947 1,089.3 5,731 1,032.2 6,047

Massachusetts Boston 725090 12 52.0 102.8% 99.3% 101.7% 99.7% 108.0 8,162 239.0 8,861 425.4 5,773 413.8 5,935 1,101.8 5,719 1,044.1 6,035

Michigan Detroit 725375 626 51.0 100.9% 99.2% 99.8% 99.7% 106.1 8,154 234.8 8,852 417.3 5,778 405.9 5,939 1,080.7 5,723 1,024.1 6,039

Michigan Grand Rapids 726350 803 48.9 101.1% 99.0% 99.6% 99.7% 106.3 8,137 235.2 8,833 416.8 5,773 405.4 5,935 1,079.4 5,719 1,022.9 6,035

Minnesota Saint Paul 726584 700 46.6 102.4% 98.8% 100.6% 99.5% 107.6 8,118 238.2 8,812 420.7 5,766 409.2 5,927 1,089.5 5,711 1,032.4 6,027

Mississippi Jackson 722350 330 65.1 96.4% 100.6% 97.3% 100.4% 101.3 8,270 224.3 8,977 407.1 5,815 396.1 5,978 1,054.4 5,760 999.2 6,078

Missouri St. Louis 724340 531 57.5 98.7% 99.9% 98.5% 100.0% 103.8 8,208 229.7 8,910 412.0 5,795 400.8 5,957 1,067.1 5,741 1,011.2 6,058

Missouri Kansas City 724463 742 57.0 98.2% 99.8% 97.9% 100.0% 103.2 8,203 228.4 8,905 409.4 5,796 398.3 5,958 1,060.4 5,742 1,004.9 6,059

Montana Great Falls 727750 3,364 45.2 93.1% 98.6% 91.3% 100.0% 97.8 8,106 216.6 8,800 381.8 5,792 371.4 5,954 988.7 5,737 936.9 6,055

Nebraska Omaha 725530 1,332 51.6 98.2% 99.3% 97.1% 99.9% 103.2 8,159 228.3 8,857 406.1 5,787 395.1 5,949 1,051.9 5,733 996.8 6,050

Nevada Las Vegas 724846 2,203 69.1 88.6% 101.0% 90.0% 100.9% 93.1 8,303 206.0 9,013 376.3 5,848 366.0 6,012 974.5 5,793 923.5 6,113

New Hampshire Concord 726050 346 47.0 103.5% 98.8% 101.8% 99.5% 108.8 8,121 240.8 8,816 425.6 5,763 414.0 5,924 1,102.3 5,708 1,044.5 6,024

New Jersey Newark 725020 7 55.8 101.3% 99.7% 100.8% 99.8% 106.4 8,194 235.5 8,894 421.5 5,784 410.0 5,946 1,091.7 5,730 1,034.5 6,046

New Mexico Albuquerque 723650 5,310 58.1 81.7% 99.9% 81.6% 101.0% 85.9 8,212 190.1 8,915 341.3 5,852 332.0 6,016 883.9 5,797 837.6 6,117

New York New York 725053 130 55.3 101.0% 99.6% 100.5% 99.8% 106.2 8,189 235.0 8,890 420.2 5,784 408.8 5,946 1,088.3 5,730 1,031.3 6,046

New York Syracuse 725190 413 48.9 102.5% 99.0% 101.0% 99.6% 107.8 8,137 238.5 8,833 422.6 5,769 411.1 5,930 1,094.6 5,714 1,037.3 6,030

North Carolina Asheville 723150 2,117 56.2 93.6% 99.7% 93.2% 100.3% 98.4 8,197 217.8 8,898 390.0 5,810 379.4 5,972 1,010.0 5,755 957.1 6,073

North Carolina Charlotte 723140 728 61.3 96.6% 100.2% 96.9% 100.3% 101.5 8,239 224.6 8,944 405.3 5,809 394.2 5,971 1,049.6 5,754 994.6 6,072

North Dakota Bismarck 727640 1,651 43.3 100.1% 98.4% 97.9% 99.5% 105.2 8,091 232.9 8,783 409.6 5,767 398.4 5,928 1,060.7 5,712 1,005.2 6,028

Ohio Cincinnati 724297 490 55.0 99.9% 99.6% 99.3% 99.9% 104.9 8,187 232.3 8,887 415.2 5,788 403.9 5,949 1,075.3 5,733 1,019.0 6,050

Oklahoma Oklahoma City 723530 1,285 61.2 94.7% 100.2% 95.0% 100.4% 99.5 8,238 220.2 8,943 397.3 5,815 386.5 5,977 1,028.9 5,760 975.0 6,078

Oklahoma Tulsa 723560 650 61.3 96.8% 100.2% 97.2% 100.2% 101.8 8,239 225.2 8,944 406.4 5,808 395.3 5,970 1,052.5 5,753 997.4 6,071

Oregon Portland 726980 19 54.6 101.7% 99.6% 101.0% 99.8% 106.9 8,184 236.6 8,884 422.6 5,781 411.1 5,943 1,094.5 5,726 1,037.2 6,043

Pennsylvania Philadelphia 724080 10 56.6 100.9% 99.8% 100.6% 99.9% 106.1 8,200 234.8 8,902 420.6 5,787 409.2 5,948 1,089.4 5,732 1,032.3 6,049

Pennsylvania Wilkes-Barre 725130 930 50.3 100.1% 99.1% 98.8% 99.8% 105.2 8,148 232.9 8,845 413.5 5,779 402.2 5,941 1,070.8 5,724 1,014.7 6,041

Puerto Rico San Juan 994043 16 80.3 91.4% 102.1% 94.6% 101.1% 96.1 8,395 212.7 9,113 395.8 5,855 385.0 6,019 1,025.0 5,800 971.3 6,121

Rhode Island Providence 997278 33 53.0 102.3% 99.4% 101.4% 99.7% 107.5 8,171 237.9 8,870 424.1 5,776 412.5 5,938 1,098.3 5,722 1,040.7 6,038

South Carolina Charleston 722080 40 66.5 96.9% 100.8% 98.0% 100.4% 101.8 8,282 225.3 8,990 409.9 5,816 398.7 5,978 1,061.5 5,761 1,005.9 6,079

South Carolina Spartanburg 723120 943 61.2 95.8% 100.2% 96.2% 100.3% 100.7 8,238 223.0 8,943 402.2 5,811 391.3 5,973 1,041.8 5,756 987.2 6,074

South Dakota Rapid City 726620 3,160 47.4 93.1% 98.8% 91.5% 100.0% 97.8 8,125 216.5 8,820 382.8 5,796 372.4 5,958 991.4 5,742 939.5 6,059

Tennessee Knoxville 723260 962 59.5 96.4% 100.1% 96.5% 100.2% 101.3 8,224 224.3 8,928 403.7 5,806 392.7 5,968 1,045.5 5,751 990.7 6,069

Tennessee Nashville 723270 600 60.2 97.4% 100.1% 97.6% 100.2% 102.4 8,230 226.6 8,934 408.3 5,804 397.2 5,966 1,057.3 5,749 1,002.0 6,067

Texas Houston 722436 32 70.6 95.3% 101.2% 97.0% 100.6% 100.1 8,315 221.6 9,027 405.7 5,827 394.6 5,990 1,050.7 5,772 995.7 6,091

Utah Salt Lake City 725720 4,225 53.5 87.1% 99.5% 86.4% 100.6% 91.5 8,175 202.6 8,874 361.3 5,826 351.5 5,989 935.8 5,771 886.8 6,090

LOCATION

Gas Turbine Based Capacity and Heat Rate Adjustments

Adjustment Basis Simple Cycle Combined Cyle 2 x LM6000PF+ 1 x 7F.05 1 x 7HA.01 WCT 1 x 7HA.01 ACC 2 x 7HA.02 WCT 2 x 7HA.02 ACC
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 HR Net MW Net HR Net MW Net HR Net MW Net HR Net 

LOCATION

Gas Turbine Based Capacity and Heat Rate Adjustments

Adjustment Basis Simple Cycle Combined Cyle 2 x LM6000PF+ 1 x 7F.05 1 x 7HA.01 WCT 1 x 7HA.01 ACC 2 x 7HA.02 WCT 2 x 7HA.02 ACC

Vermont Burlington 726170 330 46.6 103.7% 98.8% 101.9% 99.4% 109.0 8,118 241.3 8,812 426.3 5,761 414.7 5,922 1,104.0 5,707 1,046.1 6,022

Virginia Alexandria 724050 10 58.7 100.1% 100.0% 100.0% 100.0% 105.2 8,217 232.8 8,920 418.4 5,793 407.1 5,955 1,083.7 5,738 1,027.0 6,055

Virginia Lynchburg 724100 940 56.6 97.6% 99.8% 97.3% 100.1% 102.6 8,200 227.1 8,902 406.9 5,797 395.9 5,959 1,053.9 5,743 998.7 6,060

Washington Seattle 994014 7 53.2 102.3% 99.4% 101.4% 99.7% 107.5 8,172 238.0 8,871 424.2 5,777 412.7 5,938 1,098.7 5,722 1,041.2 6,038

Washington Spokane 727850 2,353 48.1 95.8% 98.9% 94.3% 99.9% 100.6 8,130 222.8 8,826 394.3 5,789 383.6 5,951 1,021.1 5,734 967.7 6,051

West Virginia Charleston 724140 910 55.9 98.0% 99.7% 97.6% 100.0% 103.0 8,194 228.0 8,895 408.1 5,795 397.0 5,957 1,056.9 5,740 1,001.6 6,057

Wisconsin Green Bay 726450 687 45.5 102.9% 98.7% 100.9% 99.5% 108.1 8,109 239.3 8,803 422.0 5,762 410.5 5,923 1,092.9 5,708 1,035.7 6,023

Wyoming Cheyenne 725640 6,130 46.6 82.4% 98.8% 81.0% 100.6% 86.6 8,118 191.8 8,812 338.7 5,828 329.5 5,991 877.2 5,773 831.3 6,092