Distributed Generation and 

Combined Heat & Power System 

Characteristics and Costs in the 

Buildings Sector

April 2017

Independent Statistics & Analysis

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration | Distributed Generation System and CHP Characteristics and Costs in the Buildings Sector i

This report was prepared for 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.
April 2017

U.S. Energy Information Administration | Distributed Generation System and CHP Characteristics and Costs in the Buildings Sector 1

Distributed Generation System Characteristics and Costs in the 

Buildings Sector

Distributed generation in the residential and commercial buildings sectors refers to the on-site 

generation of energy, which is often electricity from renewable energy systems such as solar 

photovoltaics (PV) and small wind turbines. Many factors influence the market for distributed 

generation, including government policies at the local, state, and federal levels, and project costs, which 

vary significantly depending on time, location, size, and application.

As relatively new technologies on the globalized production market, PV and small wind are experiencing 

significant cost changes through technological progress and economies of scale. The current and future 

equipment costs of renewable distributed generation are subject to uncertainty. As part of its Annual 

Energy Outlook (AEO), the U.S. Energy Information Administration (EIA) updates projections to reflect 

the most current, publicly available historical cost data and uses multiple third-party estimates of future 

costs in the near and long terms. Performance data are likewise based on currently available technology 

and expert projections of future technologies.

Before the AEO2017 reporting cycle, EIA contracted with an external consultant to develop cost and 

performance characterizations of PV, small wind, fuel cells, and combined heat and power (CHP)

installations in the building sector.1 Rather than develop two separate paths for residential and 

commercial, the consultant provided cost and performance data for systems of various sizes at five-year 

increments beginning in 2015 and ending in 2040. Two levels of future technology optimism were 

offered: a Reference case and an Advanced case that included lower equipment costs, higher efficiency, 

or both.

From this information, EIA used national-level average annual costs for a typical system size in each 

sector. Abbreviated tables of these system sizes and costs are presented in the residential and 

commercial chapters of the Assumptions to the Annual Energy Outlook. Additional information in the 

contracted report, such as equipment degradation rates, system life, annual maintenance costs, inverter 

costs, and conversion efficiency, was adapted for input in the Distributed Generation Submodules of the 

residential and commercial building sector modules of the National Energy Modeling System.

As described in the assumptions reports, other information not included in the report-such as resource 

availability, avoided electricity cost, interconnection limitations, incentive amounts, installed capacitybased cost reductions, and other factors-ultimately affect the capacity of distributed generation and 

CHP added within a given sector, year, and Census division.

For AEO2017, certain assumptions (mainly system costs) have been updated based on reports from 

Lawrence Berkeley National Laboratory and the National Renewable Energy Laboratory. Table 1 shows 

the cost and efficiency assumptions for residential and commercial solar photovoltaic and small wind 

systems used in AEO2013 and AEO2017, with AEO2017 data updated from this report.

 1 Distributed generation systems often cost more per unit of capacity than utility-scale systems. A separate analysis involves 

assumptions for electric power generation plant costs for various technologies, including utility-scale photovoltaics and both 

onshore and offshore wind turbines used in the Electricity Market Module.
April 2017

U.S. Energy Information Administration | Distributed Generation System and CHP Characteristics and Costs in the Buildings Sector 2

The report, Review of Distributed Generation and Combined Heat and Power Technology Performance 

and Cost Estimates and Analytic Assumptions for the National Energy Modeling System, is available in 

Appendix A. When referencing the report, cite it as a report by Leidos, Inc., prepared for the U.S. Energy 

Information Administration.

Table 1: Efficiency and Capital Cost Assumptions for Selected Years

AEO2013 AEO2017

Year

Representative

System

Size (kW)

Electrical 

Efficiency

Installed

Capital Cost

($2015/kWDC)

Electrical 

Efficiency

Installed

Capital Cost

($2015/kWDC)

Solar 

Photovoltaic

Residential

2010 3.5 0.150 $7,956.12 

2015 4.0 0.175 $5,486.40 0.170 $3,000

2020 5.0 0.192 $4,298.51 0.201 $2,891

2025 5.0 0.197 $4,048.78 0.232 $2,749

2030 5.0 0.200 $3,876.40 0.260 $2,733

2035 5.0 0.200 $3,825.57 0.279 $2,807

Commercial

2010 32.0 0.150 $7,083.15 

2015 35.0 0.175 $4,944.95 0.170 $2,750

2020 40.0 0.192 $3,931.65 0.201 $2,669

2025 40.0 0.197 $3,690.75 0.232 $2,558

2030 45.0 0.200 $3,530.53 0.260 $2,555

2035 45.0 0.200 $3,481.91 0.279 $2,625

Small 

Wind

Residential

2010 2.0 0.130 $8,621.33 

2015 3.0 0.130 $7,716.33 0.130 $8,400

2020 3.0 0.130 $7,297.53 0.130 $9,253

2025 3.0 0.130 $6,888.67 0.130 $9,826

2030 4.0 0.130 $6,686.45 0.130 $10,631

2035 4.0 0.130 $6,522.91 0.130 $11,503

Commercial

2010 32.0 0.130 $5,793.60 

2015 35.0 0.130 $5,210.15 0.130 $5,900

2020 40.0 0.130 $4,737.20 0.130 $6,463

2025 40.0 0.130 $4,390.23 0.130 $6,826

2030 50.0 0.130 $4,107.34 0.130 $7,345

2035 50.0 0.130 $4,007.89 0.130 $7,903

Note: kWDC = kilowatts of direct current
April 2017

U.S. Energy Information Administration | Distributed Generation System and CHP Characteristics and Costs in the Buildings Sector 3

APPENDIX A
EOP III Task 7965, Subtask 11

Review of Distributed Generation and 

Combined Heat and Power Technology 

Performance and Cost Estimates and 

Analytic Assumptions for the National 

Energy Modeling System

U.S. Energy Information Administration

Office of Energy Analysis

Office of Energy Consumption and Efficiency Analysis

May 27, 2016

EOP III Task 7965, Subtask 11

Review of Distributed Generation and 

Combined Heat and Power Technology 

Performance and Cost Estimates and 

Analytic Assumptions for National 

Energy Modeling System

U.S. Energy Information Administration

Office of Energy Analysis

Office of Energy Consumption and Efficiency Analysis

May 2016
This report has been prepared for the use of the client for the specific purposes identified in the 

report. The conclusions, observations and recommendations contained herein attributed to 

Leidos constitute the opinions of Leidos. To the extent that statements, information and opinions 

provided by the client or others have been used in the preparation of this report, Leidos has relied 

upon the same to be accurate, and for which no assurances are intended and no representations 

or warranties are made. Leidos makes no certification and gives no assurances except as 

explicitly set forth in this report.

© 2016 Leidos, Inc.

All rights reserved.
File: EIA | 209089

Review of Distributed Generation and

Combined Heat and Power Technology

U.S. Energy Information Administration

Table of Contents

Table of Contents

List of Tables

List of Figures

Section 1 INTRODUCTION .................................................................................... 1-1

1.1 Technologies Assessed ............................................................................ 1-2

Section 2 GENERAL BASIS FOR TECHNOLOGY EVALUATION 

BASIS ....................................................................................................................... 2-23

2.1 Leidos Background ................................................................................ 2-23

2.2 Base Fuel Characteristics....................................................................... 2-23

2.3 Base Technology Descriptions .............................................................. 2-24

2.3.1 Photovoltaic ............................................................................... 2-24

2.3.2 Wind........................................................................................... 2-27

2.3.3 Fuel Cell..................................................................................... 2-29

2.3.4 Reciprocating Engine................................................................. 2-32

2.3.5 Natural Gas Micro-turbine......................................................... 2-35

2.3.6 Natural Gas Turbine................................................................... 2-36

2.3.7 Combined Cycle......................................................................... 2-38

2.4 Cost Estimation Methodology ............................................................... 2-39

2.4.1 Capital Cost................................................................................ 2-39

2.4.2 Operation and Maintenance (O&M) Expenses.......................... 2-40

Section 3 RESIDENTIAL......................................................................................... 3-1

3.1 Residential - Small Solar Photovoltaic (RSS) ......................................... 3-1

3.1.1 Equipment and Systems............................................................... 3-1

3.1.2 Technology Specifications........................................................... 3-1

3.1.3 Capital Cost Estimate................................................................... 3-2

3.1.4 O&M Estimate ............................................................................. 3-2

3.1.5 Reference Technologies Projections............................................ 3-3

3.1.6 Advanced Technologies Projections............................................ 3-4

3.2 Residential – Wind System (RWS).......................................................... 3-5

3.2.1 Equipment and Systems............................................................... 3-5

3.2.2 Technology Specifications........................................................... 3-5

3.2.3 Capital Cost Estimate................................................................... 3-5

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

3.2.5 Reference Technologies Projections............................................ 3-6
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ii Leidos, Inc. File: EIA | 209089

3.2.6 Advanced Technologies Projections............................................ 3-7

3.3 Residential – Fuel Cell System (RFC)..................................................... 3-9

3.3.1 Equipment and Systems............................................................... 3-9

3.3.2 Technology Specifications........................................................... 3-9

3.3.3 Capital Cost Estimate .................................................................. 3-9

3.3.4 O&M Estimate........................................................................... 3-10

3.3.5 Reference Technologies Projections.......................................... 3-11

3.3.6 Advanced Technologies Projections.......................................... 3-12

Section 4 COMMERCIAL....................................................................................... 4-1

4.1 Commercial – Small Solar Photovoltaic System (CSS).......................... 4-1

4.1.1 Equipment and Systems............................................................... 4-1

4.1.2 Technology Specifications........................................................... 4-1

4.1.3 Capital Cost Estimate .................................................................. 4-2

4.1.4 O&M Estimate............................................................................. 4-2

4.1.5 Reference Technologies Projections............................................ 4-3

4.1.6 Advanced Technologies Projections............................................ 4-5

4.2 Commercial – Large Solar Photovoltaic System (CLS).......................... 4-5

4.2.1 Equipment and Systems............................................................... 4-6

4.2.2 Technology Specifications........................................................... 4-6

4.2.3 Capital Cost Estimate .................................................................. 4-6

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

4.2.5 Reference Technologies Projections............................................ 4-7

4.2.6 Advanced Technologies Projections............................................ 4-9

4.3 Commercial – Wind System (CWS)...................................................... 4-10

4.3.1 Equipment and Systems............................................................. 4-10

4.3.2 Technology Specifications......................................................... 4-10

4.3.3 Capital Cost Estimate ................................................................ 4-10

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

4.3.5 Reference Technologies Projections.......................................... 4-11

4.3.6 Advanced Technologies Projections.......................................... 4-12

4.4 Commercial - Fuel Cell (CFC) .............................................................. 4-15

4.4.1 Equipment and Systems............................................................. 4-15

4.4.2 Technology Specifications......................................................... 4-16

4.4.3 Capital Cost Estimate ................................................................ 4-16

4.4.4 O&M Estimate........................................................................... 4-17

4.4.5 Reference Technologies Projections.......................................... 4-17

4.4.6 Advanced Technologies Projections.......................................... 4-18

4.5 Commercial – Natural Gas Reciprocating Engine (CNE)..................... 4-21

4.5.1 Equipment and Systems............................................................. 4-21

4.5.2 Technology Specifications......................................................... 4-21

4.5.3 Capital Cost Estimate ................................................................ 4-22

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

4.5.5 Reference Technologies Projections.......................................... 4-23

4.5.6 Advanced Technologies Projections.......................................... 4-24

4.6 Commercial – Oil Reciprocating Engine (COE)................................... 4-26

4.6.1 Equipment and Systems............................................................. 4-26
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File: EIA | 209089 Leidos, Inc. iii

4.6.2 Technology Specifications......................................................... 4-26

4.6.3 Capital Cost Estimate................................................................. 4-26

4.6.4 O&M Estimate ........................................................................... 4-27

4.6.5 Reference Technologies Projections.......................................... 4-28

4.6.6 Advanced Technologies Projections.......................................... 4-29

4.7 Commercial – Natural Gas Turbine (CNT) ........................................... 4-30

4.7.1 Equipment and Systems............................................................. 4-30

4.7.2 Technology Specifications......................................................... 4-30

4.7.3 Capital Cost Estimate................................................................. 4-30

4.7.4 O&M Estimate ........................................................................... 4-31

4.7.5 Reference Technologies Projections.......................................... 4-32

4.7.6 Advanced Technologies Projections.......................................... 4-33

4.8 Commercial – Natural Gas Micro-turbine (CNM) ................................ 4-35

4.8.1 Equipment and Systems............................................................. 4-35

4.8.2 Technology Specifications......................................................... 4-35

4.8.3 Capital Cost Estimate................................................................. 4-36

4.8.4 O&M Estimate ........................................................................... 4-36

4.8.5 Reference Technologies Projections.......................................... 4-37

4.8.6 Advanced Technologies Projections.......................................... 4-38

Section 5 INDUSTRIAL........................................................................................... 5-1

5.1 Industrial – Natural Gas Reciprocating Engine-1,000 kW (IRE1).......... 5-1

5.1.1 Equipment and Systems............................................................... 5-1

5.1.2 Technology Specifications........................................................... 5-1

5.1.3 Capital Cost Estimate................................................................... 5-1

5.1.4 O&M Estimate ............................................................................. 5-2

5.1.5 Reference Technologies Projections............................................ 5-3

5.1.6 Advanced Technologies Projections............................................ 5-4

5.2 Industrial – Natural Gas Reciprocating Engine – 3,000 kW (IRE3)

.................................................................................................................. 5-6

5.2.1 Equipment and Systems............................................................... 5-6

5.2.2 Technology Specifications........................................................... 5-6

5.2.3 Capital Cost Estimate................................................................... 5-6

5.2.4 O&M Estimate ............................................................................. 5-7

5.2.5 Reference Technologies Projections............................................ 5-8

5.2.6 Advanced Technologies Projections............................................ 5-9

5.3 Industrial – Natural Gas Turbine (IGT5)............................................... 5-10

5.3.1 Equipment and Systems............................................................. 5-10

5.3.2 Technology Specifications......................................................... 5-10

5.3.3 Capital Cost Estimate................................................................. 5-11

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

5.3.5 Reference Technologies Projections.......................................... 5-13

5.3.6 Advanced Technologies Projections.......................................... 5-15

5.4 Industrial – Natural Gas Turbine – 10,000 kW (IGT10) ....................... 5-15

5.4.1 Equipment and Systems............................................................. 5-15

5.4.2 Technology Specifications......................................................... 5-16

5.4.3 Capital Cost Estimate................................................................. 5-17
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iv Leidos, Inc. File: EIA | 209089

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

5.4.5 Reference Technologies Projections.......................................... 5-19

5.4.6 Advanced Technologies Projections.......................................... 5-20

5.5 Industrial – Natural Gas Turbine – 25,000 kW (IGT25)....................... 5-21

5.5.1 Equipment and Systems............................................................. 5-21

5.5.2 Technology Specifications......................................................... 5-21

5.5.3 Capital Cost Estimate ................................................................ 5-22

5.5.4 O&M Estimate........................................................................... 5-23

5.5.5 Reference Technologies Projections.......................................... 5-24

5.5.6 Advanced Technologies Projections.......................................... 5-25

5.6 Industrial – Natural Gas Turbine – 40,000 kW (IGT40)....................... 5-26

5.6.1 Equipment and Systems............................................................. 5-26

5.6.2 Technology Specifications......................................................... 5-27

5.6.3 Capital Cost Estimate ................................................................ 5-27

5.6.4 O&M Estimate........................................................................... 5-28

5.6.5 Reference Technologies Projections.......................................... 5-29

5.6.6 Advanced Technologies Projections.......................................... 5-30

5.7 Industrial – Combined Cycle – 100,000 kW (ICC)............................... 5-31

5.7.1 Equipment and Systems............................................................. 5-31

5.7.2 Technology Specifications......................................................... 5-32

5.7.3 Capital Cost Estimate ................................................................ 5-32

5.7.4 O&M Estimate........................................................................... 5-33

5.7.5 Reference Technologies Projections.......................................... 5-34

5.7.6 Advanced Technologies Projections.......................................... 5-35

List of Appendices

A Acronyms

B References

C Technology Definitions and Calculations
Table of Contents

File: EIA | 209089 Leidos, Inc. v

List of Tables

Table 1-1 List of Technologies................................................................................... 1-3

Table 2-1 Natural Gas Specification......................................................................... 2-23

Table 2-2 Fuel Oil Specification............................................................................... 2-24

Table 2-3 Technology Performance Specifications.................................................. 2-42

Table 3-1 Base Plant Site Capital Cost Estimate for RSS .......................................... 3-2

Table 3-2 O&M Expenses for RSS (5 kW) ................................................................ 3-3

Table 3-3 Residential O&M - Small PV – Reference New Equipment (1).................. 3-3

Table 3-4 Residential O&M - Small PV – 2015 Degraded Equipment...................... 3-3

Table 3-5 Residential Capital Costs - Small PV – Reference New Equipment.......... 3-4

Table 3-6 Residential O&M - Small PV – Advanced New Equipment...................... 3-4

Table 3-7 Residential Capital Costs - Small PV – Advanced New Equipment......... 3-5

Table 3-8 Base Plant Site Capital Cost Estimate for RWS......................................... 3-6

Table 3-9 O&M Expenses for RWS (10 kW)............................................................. 3-6

Table 3-10 Residential O&M - Wind – Reference New Equipment .......................... 3-6

Table 3-11 Residential O&M - Wind – 2015 Degraded Equipment .......................... 3-7

Table 3-12 Residential Capital Costs - Wind – Reference New Equipment .............. 3-7

Table 3-13 Residential O&M - Wind – Advanced New Equipment .......................... 3-9

Table 3-14 Residential Capital Costs - Wind – Advanced New Equipment .............. 3-9

Table 3-15 Base Plant Site Capital Cost Estimate for RFC...................................... 3-10

Table 3-16 O&M Expenses for RFC ........................................................................ 3-10

Table 3-17 Residential O&M - Fuel Cell – Reference New Equipment .................. 3-11

Table 3-18 Residential O&M - Fuel Cell – 2015 Degraded Equipment................... 3-11

Table 3-19 Residential Capital Costs - Fuel Cell – Reference New Equipment

........................................................................................................................ 3-12

Table 3-20 Residential O&M - Fuel Cell – Advanced New Equipment .................. 3-14

Table 3-21 Residential Capital Costs - Fuel Cell – Advanced New Equipment

........................................................................................................................ 3-14

Table 4-1 Base Plant Site Capital Cost Estimate for CSS .......................................... 4-2

Table 4-2 O&M Expenses for CSS............................................................................. 4-3

Table 4-3 Commercial O&M - Small PV – Reference New Equipment (1)................ 4-3

Table 4-4 Commercial O&M - Small PV - 2015 Degraded Equipment..................... 4-4

Table 4-5 Commercial Capital Costs - Small PV - Reference New Equipment......... 4-4

Table 4-6 Commercial O&M - Small PV - Advanced New Equipment..................... 4-5

Table 4-7 Commercial Capital Costs - Small PV - Advanced New Equipment

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

Table 4-8 Base Plant Site Capital Cost Estimate for CLS Cost.................................. 4-7

Table 4-9 O&M Expenses for CLS system ................................................................ 4-7

Table 4-10 Commercial O&M - Large PV – Reference New Equipment (1).............. 4-8

Table 4-11 Commercial O&M - Large PV – 2015 Degraded Equipment .................. 4-8

Table 4-12 Commercial Capital Costs - Large PV – Reference New Equipment

.......................................................................................................................... 4-9

Table 4-13 Commercial O&M- Large PV – Advanced New Equipment................... 4-9

Table 4-14 Commercial Capital Costs - Large PV – Advanced New Equipment

........................................................................................................................ 4-10
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vi Leidos, Inc. File: EIA | 209089

Table 4-15 Base Plant Site Capital Cost Estimate for Commercial Wind 

System ............................................................................................................ 4-11

Table 4-16 O&M Expenses for CWS system........................................................... 4-11

Table 4-17 Commercial O&M – Wind – Reference New Equipment...................... 4-11

Table 4-18 Commercial O&M – Wind - 2015 Degraded Equipment ...................... 4-12

Table 4-19 Commercial Capital Costs - Wind – Reference New Equipment .......... 4-12

Table 4-20 Commercial O&M – Wind - Advanced New Equipment ...................... 4-14

Table 4-21 Commercial Capital Costs - Wind - Advanced New Equipment........... 4-15

Table 4-22 Commercial – Fuel Cell – 200 kW......................................................... 4-16

Table 4-23 Base Plant Site Capital Cost Estimate for CFC...................................... 4-17

Table 4-24 O&M Expenses for CFC ........................................................................ 4-17

Table 4-25 Commercial O&M - Fuel Cell – Reference New Equipment ................ 4-17

Table 4-26 Commercial O&M - Fuel Cell – 2015 Degraded Equipment................. 4-18

Table 4-27 Commercial Capital Costs - Fuel Cell – Reference New Equipment

........................................................................................................................ 4-18

Table 4-28 Commercial O&M - Fuel Cell – Advanced New Equipment ................ 4-20

Table 4-29 Commercial Capital Costs - Fuel Cell – Advanced New Equipment

........................................................................................................................ 4-21

Table 4-30 Commercial – Natural Gas Reciprocating Engine – 300 kW................. 4-21

Table 4-31 Base Plant Site Capital Cost Estimate for CNE ..................................... 4-22

Table 4-32 O&M Expenses for CNE - 300 kW........................................................ 4-22

Table 4-33 Commercial O&M- Natural Gas Reciprocating Engine – Reference 

New Equipment.............................................................................................. 4-23

Table 4-34 Commercial O&M- Natural Gas Reciprocating Engine – 2015 

Degraded Equipment...................................................................................... 4-23

Table 4-35 Commercial Capital Costs - Natural Gas Reciprocating Engine – 

Reference New Equipment............................................................................. 4-24

Table 4-36 Commercial O&M- Natural Gas Reciprocating Engine – Advanced 

New Equipment.............................................................................................. 4-25

Table 4-37 Commercial Capital Costs - Natural Gas Reciprocating Engine – 

Advanced New Equipment............................................................................. 4-25

Table 4-38 Commercial – Oil Reciprocating Engine – 300 kW............................... 4-26

Table 4-39 Base Plant Site Capital Cost Estimate for COE ..................................... 4-27

Table 4-40 O&M Expenses for COE........................................................................ 4-27

Table 4-41 Commercial O&M - Oil Reciprocating Engine – Reference New 

Equipment ...................................................................................................... 4-28

Table 4-42 Commercial O&M - Oil Reciprocating Engine - 2015 Degraded 

Equipment ...................................................................................................... 4-28

Table 4-43 Commercial Capital Costs - Oil Reciprocating Engine - Reference 

New Equipment.............................................................................................. 4-29

Table 4-44 Commercial O&M - Oil Reciprocating Engine - Advanced New 

Equipment ...................................................................................................... 4-29

Table 4-45 Commercial Capital Costs - Oil Reciprocating Engine - Advanced 

New Equipment.............................................................................................. 4-29

Table 4-46 Commercial – Natural Gas Turbine – 1,000 kW.................................... 4-30

Table 4-47 Base Plant Site Capital Cost Estimate for CNT ..................................... 4-31
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File: EIA | 209089 Leidos, Inc. vii

Table 4-48 O&M Expenses for CNT 1,000 kW ....................................................... 4-31

Table 4-49 Commercial O&M - Natural Gas Turbine – Reference New 

Equipment....................................................................................................... 4-32

Table 4-50 Commercial O&M - Natural Gas Turbine – 2015 Degraded 

Equipment....................................................................................................... 4-32

Table 4-51 Commercial Capital Costs- Natural Gas Turbine – Reference New 

Equipment....................................................................................................... 4-33

Table 4-52 Commercial O&M - Natural Gas Turbine – Advanced New 

Equipment....................................................................................................... 4-34

Table 4-53 Commercial Capital Costs- Natural Gas Turbine – Advanced New 

Equipment....................................................................................................... 4-35

Table 4-54 Commercial – Natural Gas Micro-turbine – 250 kW............................. 4-35

Table 4-55 Base Plant Site Capital Cost Estimate for CNM .................................... 4-36

Table 4-56 O&M Expenses for CNM....................................................................... 4-37

Table 4-57 Commercial O&M- Natural Gas Micro-turbine – Reference New 

Equipment....................................................................................................... 4-37

Table 4-58 Commercial O&M- Natural Gas Micro-turbine - 2015 Degraded 

Equipment....................................................................................................... 4-38

Table 4-59 Commercial Capital Costs- Natural Gas Micro-turbine - Reference 

New Equipment .............................................................................................. 4-38

Table 4-60 Commercial O&M- Natural Gas Micro-turbine - Advanced New 

Equipment....................................................................................................... 4-39

Table 4-61 Commercial Capital Costs- Natural Gas Micro-turbine - Advanced 

New Equipment .............................................................................................. 4-40

Table 5-1 Industrial – Natural Gas Reciprocating Engine – 1,000 kW ...................... 5-1

Table 5-2 Base Plant site Capital Cost Estimate for IRE1.......................................... 5-2

Table 5-3 O&M Expenses for IRE1 ........................................................................... 5-2

Table 5-4 Industrial O&M – Natural Gas Reciprocating Engine – Reference 

New Equipment ................................................................................................ 5-3

Table 5-5 Industrial O&M – Natural Gas Reciprocating Engine – 2015 

Degraded Equipment ........................................................................................ 5-3

Table 5-6 Industrial Capital Costs – Natural Gas Reciprocating Engine –

Reference New Equipment............................................................................... 5-4

Table 5-7 Industrial O&M – Natural Gas Reciprocating Engine – Advanced 

New Equipment ................................................................................................ 5-5

Table 5-8 Industrial Capital Costs – Natural Gas Reciprocating Engine –

Advanced New Equipment............................................................................... 5-5

Table 5-9 Industrial – Natural Gas Reciprocating Engine – 3,000 kW ...................... 5-6

Table 5-10 Base Plant Site Capital Cost Estimate for IRE3 ....................................... 5-7

Table 5-11 O&M Expenses for IRE3.......................................................................... 5-7

Table 5-12 Industrial O&M – Natural Gas Reciprocating Engine – Reference 

New Equipment ................................................................................................ 5-8

Table 5-13 Industrial O&M – Natural Gas Reciprocating Engine – 2015 

Degraded Equipment ........................................................................................ 5-8

Table 5-14 Industrial Capital Costs – Natural Gas Reciprocating Engine –

Reference New Equipment............................................................................... 5-9
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viii Leidos, Inc. File: EIA | 209089

Table 5-15 Industrial O&M – Natural Gas Reciprocating Engine – Advanced 

New Equipment................................................................................................ 5-9

Table 5-16 Industrial Capital Costs – Natural Gas Reciprocating Engine –

Advanced New Equipment............................................................................... 5-9

Table 5-17 Industrial – Natural Gas Turbine – 5,000 kW........................................ 5-11

Table 5-18 Base Plant Site Capital Cost Estimate for IGT5..................................... 5-12

Table 5-19 O&M Expenses for IGT5 ....................................................................... 5-12

Table 5-20 Industrial O&M - Natural Gas Turbine – Reference New 

Equipment ...................................................................................................... 5-13

Table 5-21 Industrial O&M - Natural Gas Turbine – 2015 Degraded 

Equipment ...................................................................................................... 5-14

Table 5-22 Industrial Capital Costs - Natural Gas Turbine – Reference New 

Equipment ...................................................................................................... 5-14

Table 5-23 Industrial O&M - Natural Gas Turbine – Advanced New 

Equipment ...................................................................................................... 5-15

Table 5-24 Industrial Capital Costs - Natural Gas Turbine – Advanced New 

Equipment ...................................................................................................... 5-15

Table 5-25 Industrial – Natural Gas Turbine – 10,000 kW...................................... 5-17

Table 5-26 Base Plant Site Capital Cost Estimate for IGT10................................... 5-18

Table 5-27 O&M Expenses for IGT10 ..................................................................... 5-18

Table 5-28 Industrial O&M - Natural Gas Turbine – Reference New 

Equipment ...................................................................................................... 5-19

Table 5-29 Industrial O&M - Natural Gas Turbine – 2015 Degraded 

Equipment ...................................................................................................... 5-19

Table 5-30 Industrial Capital Costs - Natural Gas Turbine – Reference New 

Equipment ...................................................................................................... 5-20

Table 5-31 Industrial O&M - Natural Gas Turbine – Advanced New 

Equipment ...................................................................................................... 5-20

Table 5-32 Industrial Capital Costs - Natural Gas Turbine – Advanced New 

Equipment ...................................................................................................... 5-21

Table 5-33 Industrial Natural Gas Turbine – 25,000 kW......................................... 5-22

Table 5-34 Base Plant Site Capital Cost Estimate for IGT25................................... 5-23

Table 5-35 O&M Expenses for IGT25 ..................................................................... 5-23

Table 5-36 Industrial O&M - Natural Gas Turbine – Reference New 

Equipment ...................................................................................................... 5-24

Table 5-37 Industrial O&M - Natural Gas Turbine – 2015 Degraded 

Equipment ...................................................................................................... 5-24

Table 5-38 Industrial Capital Costs - Natural Gas Turbine – Reference New 

Equipment ...................................................................................................... 5-25

Table 5-39 Industrial O&M - Natural Gas Turbine – Advanced New 

Equipment ...................................................................................................... 5-25

Table 5-40 Industrial Capital Costs - Natural Gas Turbine – Advanced New 

Equipment ...................................................................................................... 5-26

Table 5-41 Industrial – Natural Gas Turbine – 40,000 kW...................................... 5-27

Table 5-42 Base Plant Site Capital Cost Estimate for IGT40................................... 5-28

Table 5-43 O&M Expenses for IGT40 ..................................................................... 5-28
Table of Contents

File: EIA | 209089 Leidos, Inc. ix

Table 5-44 Industrial O&M - Natural Gas Turbine – Reference New 

Equipment....................................................................................................... 5-29

Table 5-45 Industrial O&M - Natural Gas Turbine – 2015 Degraded 

Equipment....................................................................................................... 5-29

Table 5-46 Industrial Capital Costs - Natural Gas Turbine – Reference New 

Equipment....................................................................................................... 5-30

Table 5-47 Industrial O&M - Natural Gas Turbine – Advanced New 

Equipment....................................................................................................... 5-30

Table 5-48 Industrial Capital Costs - Natural Gas Turbine – Advanced New 

Equipment....................................................................................................... 5-30

Table 5-49 Industrial – Combine Cycle – 100,000 kW ........................................... 5-32

Table 5-50 Base Plant Site Capital Cost Estimate for ICC....................................... 5-33

Table 5-51 O&M Expenses for ICC ......................................................................... 5-33

Table 5-52 Industrial O&M - Combined Cycle – Reference New Equipment......... 5-34

Table 5-53 Industrial O&M - Combined Cycle – 2015 Degraded Equipment......... 5-34

Table 5-54 Industrial Capital Costs - Combined Cycle – Reference New 

Equipment....................................................................................................... 5-35

Table 5-55 Industrial O&M - Combined Cycle – Advanced New Equipment......... 5-37

Table 5-56 Industrial Capital Costs - Combined Cycle – Advanced New 

Equipment....................................................................................................... 5-37
Table of Contents

x Leidos, Inc. File: EIA | 209089

List of Figures

Figure 2.1: Basic Parts of a Small Wind Electrical System..................................... 2-28

Figure 2.2: Alkali Fuel Cell ..................................................................................... 2-30

Figure 2.3: Solid Oxide Fuel Cell............................................................................ 2-30

Figure 2.4: PAFC and PEM Fuel Cells................................................................... 2-31

Figure 2.5: Molten Carbonate Fuel Cell .................................................................. 2-32

Figure 2.6: Gas Engine Basic Components ............................................................. 2-34

Figure 5.1: GT Design Configuration...................................................................... 5-10

Figure 5.2: GT Design Configuration...................................................................... 5-16

Figure 5.3: GT Design Configuration...................................................................... 5-21

Figure 5.4: Industrial Natural Gas Turbine Configuration ...................................... 5-26

Figure 5.5: Industrial Combined Cycle Design Configuration................................ 5-31
File: EIA | 209089

Section 1

INTRODUCTION

This report (Report) presents the Leidos Engineering, LLC (Leidos) technology 

performance and cost assessment of distributed generation (DG) and combined heat and 

power (CHP) systems for residential and commercial building applications and

industrial installations for various technologies. The technologies selected within the 

residential, commercial, and industrial sectors were specified by the Office of Energy 

Analysis within the U.S. Energy Information Administration (EIA) based upon the

existing technologies represented in the National Energy Modeling System (NEMS). 

The assessment for each of the technologies considered includes the following:

 The reference, or first year of operation, is assumed to commence January 2015.

 Forward-looking assumptions are projected through 2040, in intervals of 5-year 

periods.

 The “Reference New Equipment” tables assume new equipment is installed every 

five years starting in 2015 through year 2040. This allows for a comparison of new 

equipment performance and cost estimates across the projection period. Differences 

consistently account for functional efficiency improvements, equipment and 

installation cost reductions due to improvement, and equipment and installation cost 

escalation.

 The degraded equipment tables assume new equipment is installed in 2015 and that 

equipment continues to operate and degrade in performance through 2040, with the 

exception of inverter life expectancies as noted in the individual tables.

 The work presented represents reference year and projected years’ technology 

characterizations for DG and CHP equipment performance.

 The cost estimates includes site preparation, structures, equipment, electrical, 

distributable cost, engineering and design and subcontractor fee and budget 

contingency. All costs are based on prices and wages for the Gulf Coast Region of 

the U.S. with no unusual location impacts (e.g., urban construction constraints) or 

infrastructure needs (e.g., a project-dedicated interconnection upgrade cost). 

Regional cost factors can be used to adjustment costs for each EMM region (see

Table 2-4 in Section 2).

 Performance parameters include electric heat rate based on the higher heating value1

of the fuel, electric generating efficiency, total CHP efficiency, and fuel input rate.

 Other reported design and financial parameters include overnight construction costs, 

first year of residential/commercial/industrial application, typical unit size, 

contingencies, fixed and variable operating costs,..

 1 The higher heating value of a fuel is defined as the amount of heat released by a specified quantity once 

it is combusted and the products have returned to a temperature of 25oC, which takes into account the 

latent heat of vaporization of water in the combustion products.
Section 1

1-2 Leidos, Inc. File: EIA | 209089

 The analysis was conducted so that the overnight cost estimates developed for use in 

the NEMS for electric generating technologies are consistent in scope, accounting 

for overnight construction costs of power generating equipment, including the 

provisions for the basic interconnection to the grid at the site, but excluding 

development and financing costs.

 The cost estimates are broken down into primary categories of equipment, 

installation materials and labor, and miscellaneous other costs, which include 

engineering, construction management, and contingency. 

 All cost values presented in this report are reported on a current dollar (nominal 

dollar) basis. This is done to account for application of a consolidated producer price 

index (PPI) for equipment and labor escalation projections.2 These nominal values 

that can be consistently deflated in NEMS using a national price deflator (GDP 

deflator) to adjust them to real dollars for required model frame of reference.

 [The key factors expected to drive each technology’s costs and the advanced 

technology descriptions. To come with the information to be provided in the 

Advanced Technology additions to this Report.]

1.1 Technologies Assessed

The following table lists all technologies to be assessed in this project.

 2 The 2015 technology costs have been using a consolidated PPI index based on the IHS 2014 Q1 

industry PPI projections.
INTRODUCTION

File: 000000/99-99999-99999-9999 Leidos, Inc. 1-3

Table 1-1. List of Technologies and Nominal System Capacity

TECHNOLOGY NOMINAL SYSTEM CAPACITY

RESIDENTIAL

Residential – Small Solar Photovoltaic (<10 kW (1)) 5 kW

Residential – Wind 10 kW

Residential – Fuel Cell 10 kW

COMMERCIAL

Commercial – Small Solar Photovoltaic (<100 kW) 40 kW

Commercial – Large Solar Photovoltaic (100-1,000 kW) 500 kW

Commercial – Wind 100 kW

Commercial – Fuel Cell 200 kW

Commercial – Natural Gas Engine 300 kW

Commercial – Oil-fired Engine 300 kW

Commercial – Natural Gas Turbine 1,000 kW

Commercial – Natural Gas Micro-turbine 250 kW

INDUSTRIAL

Industrial – Reciprocating Engine 1,000 kW

Industrial – Reciprocating Engine 3,000 kW

Industrial – Natural Gas Turbine 5,000 kW

Industrial – Natural Gas Turbine 10,000 kW

Industrial – Natural Gas Turbine 25,000 kW

Industrial – Natural Gas Turbine 40,000 kW

Industrial – Combined Cycle (2) 100,000 kW

(1) Kilowatt-alternating current (kW)

(2) Combined Cycle configuration is (2) 40 megawatt (MW) natural gas combustion turbines and 

(1) 20 MW steam turbine.

GENERAL BASIS FOR TECHNOLOGY EVALUATION BASIS

File: EIA | 209089 Leidos, Inc. 2-23

Section 2

GENERAL BASIS FOR TECHNOLOGY EVALUATION BASIS

This Section specifies the general evaluation basis used for all technologies reviewed 

herein.

2.1 Leidos Background

Leidos is a science and technology solutions leader working to address some of the 

world’s toughest challenges in national security, health and engineering. The company’s 

20,000 employees support vital missions for our government and the commercial sector, 

develop innovative solutions to drive better outcomes and defend our Nation’s digital 

and physical infrastructure from ‘new world’ threats. Our engineering business makes 

‘What If’ possible for utility; manufacturing and industrial; lender and developer; oil, 

gas, and chemical; and government clients. Particularly, Leidos has supported the 

purchase, sale, financing, and owner’s advisory consulting for tens-of-billions of dollars 

of power plants across the world in all commercial power generating technologies, as 

well as many emerging technologies. This background has supported Leidos’ acumen 

with respect to construction costs, operating costs, technology development and 

evolution, as well as trends in environmental regulation and compliance.

2.2 Base Fuel Characteristics

This Section provides a general fuel basis for each of the fuel types utilized by the 

technologies considered in this Report and listed in Table 1-1. Each of the technologies 

that combust a fuel has the ability to operate over a range of fuels; thus, Table 2-1 and 

Table 2-2 show a typical fuel specification for natural gas and fuel oil, respectively. 

For equipment that might engage in fuel oil operations, the fuel oil specifications 

imposed by the original equipment manufacturer typically follow those 

recommendations provided for in American Standards for Testing and Materials D396 -

Standard Specification for Fuel Oils, Grades No. 1, 2, 4, and 4 (Light).

Table 2-1. Natural Gas Specification

Component Volume Percentage

Methane CH4 93.9

Ethane C2H6 3.2

Propane C3H8 0.7

n-Butane C4H10 0.4

Carbon Dioxide CO2 1.0

Nitrogen N2 0.8

 Total 100.0
2-24 Leidos, Inc. File: EIA | 209089

Table 2-1. Natural Gas Specification

Component Volume Percentage

LHV (1) HHV (2)

kJ/kg (3)

MJ/scm (4)

47.764

35

52,970

39

Btu/lb (5)

Btu/scf (6)

20,552

939

22,792

1,040

(1) Lower Heat Value (LHV).

(2) Higher Heat Value (HHV).

(3) Kilo joules per kilogram (kJ/kg).

(4) Mega joules per standard cubic meter (MJ/scm).

(5) British thermal units per pound (Btu/lb).

(6) Btu/standard cubic feet (Btu/scf).

Table 2-2. Fuel Oil Specification

Component Volume Percentage

General Hydrocarbon CxHy (1)4 100

LHV HHV

kJ/kg 32,000-45,000 35,520-49,950

Btu/lb 13,757-19,347 15,271-21,475

(1) CxHy with “x” being greater than 6.

2.3 Base Technology Descriptions

This Section provides the descriptions of the base technologies analyzed.

2.3.1 Photovoltaic

Large, utility scale photovoltaic (PV) projects require extensive resources to design, 

develop and finance. DG PV has certain advantages in residential and commercial 

markets, where smaller PV facilities at multiple sites can address energy needs, as 

opposed to a single large generating facility. DG has an advantage in that the energy is 

used where it is generated, eliminating the need for transmission and related losses and 

expenses from transmission.

DG is the domain of individual residential and commercial customers who install PV 

modules on rooftops to serve part or all of their own electrical energy needs.

A PV array produces direct current (DC) electricity from sunlight absorbed by PV 

modules. Multiple PV modules are connected together to create a PV array, and thereby 

increasing the amount of DC electricity produced. However, alternating current (AC) 

electricity is used in homes and buildings, which requires the use of a DC-to-AC 
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inverter, where the DC electricity is converted to AC electricity. The AC electricity is 

then connected to the electrical infrastructure of the host’s site and can either be 

consumed by the host or sold back to the utility.

Residential and commercial PV arrays are typically installed on rooftops, but can also 

be mounted on shade structures, carports, or on ground-mounted racking. The size of a 

residential PV array depends on the available rooftop area with adequate solar resource, 

most often south facing roofs free of shading obstructions. The size of commercial PV 

installations also varies depending on the available roof space; a small stand-alone 

commercial building, such as a small retail store, will have a smaller PV capacity 

compared to a large retail store, industrial warehouse, or distribution center.

One of the main advantages of DG PV is that there are no transmission requirements 

and the generation can be electrically connected to the host’s existing electric service. 

Electrical transformers, which increase the voltage of the generated electricity up to 

transmission voltage, are not necessary. PV systems for residential and commercial 

applications are typically connected to the grid, allowing for delivery of surplus 

electricity generation back to the utility. Grid connection is required to meet the host’s 

electrical needs when the PV array is not generating power, such as during night time 

and on low-irradiance days.

A DG PV installation generally consists of PV modules, electrical wiring and conduit, 

DC-to-AC inverters, racking hardware, protection, disconnection and metering 

equipment. PV modules are generally the same size and shape, whether installed in 

residential, commercial, or utility-scale facilities.

PV systems are generally designed with a higher DC versus AC capacity to optimize 

the amount of electrical generation per installed DC capacity. A typically designed 

DC:AC ratio is 1.3:1, yet it can vary depending on each specific design anywhere from 

1:1 to 1.4:1.

Residential systems can use string inverters, micro-inverters, or a combination of DC 

power optimizers and string inverters. The use of string inverters requires that 

individual modules be wired in series prior to being connected to the inverter. These 

series-wired configurations of solar modules are referred to as strings; hence, the 

terminology “string inverter.” In residential installations, string inverters are typically 

mounted on an external wall or near the existing electrical box in the garage or 

basement.

A micro-inverter is a module-level inverter, where the DC power of each individual 

module is directly converted to AC power. Micro-inverters allow the output of each 

module to be controlled individually, which can be an advantage in residential 

installations where shading may impact the modules.

A DC optimizer is a module-level DC-to-DC convertor that controls the DC output of 

each module, thereby minimizing mismatch losses between the modules in a string. In 

the case of a DC optimizer, the modules are still connected in strings, which are in turn 

connected to a string inverter.

Large commercial installations typically use string inverters or central inverters. In the 

former case, multiple string inverters may be mounted on a commercial rooftop. In the 
2-26 Leidos, Inc. File: EIA | 209089

latter case, one or more large central inverters may be located externally on the groundlevel (such as in a parking lot area) or inside the building’s electrical room. Smaller 

retail buildings do not typically have the space for larger central inverters, and are more 

likely to use either string inverters or micro-inverters.

In addition to power losses from the inverter during the conversion of DC electricity to 

AC electricity, other power losses are inherent in PV installations. These losses include 

system-level degradation, shading, soiling, snow, and wiring losses. Generally, Leidos 

considers a system-level degradation of approximately 0.75 percent per year as standard 

for a system utilizing standard, high quality crystalline silicon PV modules. (Most 

module manufacturers do not have 25-years of module performance data, and typically 

only warrant ~0.7% annual module degradation beyond the first year of operation.) 

Shading losses depend on the specific site conditions, such as nearby trees, roof 

structures, and adjacent buildings. Soiling losses are caused by dirt and other organic 

build-up on the modules. In regions with appreciable snowfall, there will be losses 

associated with snow cover on the panels during the winter months.

The orientation angle of the PV modules with respect to the sun impacts the production 

of the modules. The ideal orientation is for the PV modules to be as near as possible to 

direct 90 degree (°) alignment with the sun at all times. To accomplish this, some 

installations utilize single-axis tracking equipment, which tilt the modules to follow the 

sun throughout the day, albeit along a single axis. Single-axis trackers are most common 

in utility-scale installations in high irradiance areas, such as the southwest United States 

(U.S.). Tracking equipment is not typically used in DG installations, as it requires 

additional equipment, design, and cost; the space and load constraints of rooftop 

installations rule out the use of such tracking systems. Dual axis tracking systems are 

more commonly used in concentrating PV systems, and are not typically used with 

conventional PV panels.

PV installations without tracking capabilities are known as fixed-tilt systems. Most 

residential PV arrays are mounted at the prevailing angle of the existing roof. For 

commercial and industrial roofs, which are typically low-slope or flat, there are options 

to install modules flat or build racking systems to tilt the modules at an angle. The 

factors that need to be considered include space constraints, allowable roof loads, wind 

exposure, maintenance, and shading from roofing structures or adjacent buildings.

The optimum tilt angle is close to the latitude of the installation. However, larger tilt 

angles (such as those used in ground-mount installations) would cause large up-lift 

forces on rooftop-mounted modules due to wind loads. Thus, most commercial rooftop 

systems utilize ballasted racking with the modules tilted at a slight angle, typically no 

more than 10° from horizontal.

Crystalline silicon and thin film are two major PV module technologies used in 

residential, commercial, and utility-scale installations. Crystalline silicon PV modules 

are the most common PV technology for residential and commercial installations, while 

thin film sees the majority of its use in utility-scale installations.

There are two types of thin film PV that have reached an appreciable installed base in 

the PV market: cadmium telluride (CdTe) PV modules and copper indium gallium 

diselenide (CIGS) PV modules. CdTe is used in the form of mono-crystalline thin films, 
File: 000000/99-99999-99999-9999 Leidos, Inc. 2-27

whereas CIGS is mainly used in the form of polycrystalline thin films. While, the 

differences between these two types are fairly significant, module construction 

differences of mono versus poly are not that significant, and for the purposes of this 

report, a discussion of mono versus poly does not add much to the discourse. First Solar 

is the leading manufacturer of CdTe PV modules and Solar Frontier is the leading 

manufacturer of CIGS PV modules. Both of these thin film manufacturers utilize rigid 

glass modules, which are similar in mechanical construction to crystalline silicon 

modules. Certain types of thin film PV technology is well-suited for flexible substrates, 

and several companies have worked on developing flexible modules for buildingintegrated or building-applied PV applications (i.e., as shingles or laminates to be 

directly adhered to a roof). However, none of these technologies have reached an 

appreciable installed base in the marketplace.

DG PV installations are growing rapidly. In the first quarter of 2014, a total of 1,330 

MW-DC of PV generating capacity was added in the U.S., of which 232 MW DC was 

residential and 225 MW-DC was commercial. Additionally, the first quarter of 2014 

was the first time since 2002 that residential PV installation capacity exceeded

commercial installations within the U.S. per “Solar Market Insight Report 2014 Q1,” 

GTM Research and the Solar Energy Industries Association Solar Energy Industries 

Association First Quarter Study.” The residential installations in the first quarter of 

2014 are a 38 percent increase over the capacity installed in the first quarter of 2013.

The scope of this Report includes the review of distributed solar technology at the 5-kW 

size for residential applications, and 40-kW and 500-kW sizes for commercial 

applications. For all of these cases, the use of crystalline silicon modules has been 

assumed.

2.3.2 Wind

Distributed wind, as defined by the U.S. Department of Energy, Energy Efficiency and 

Renewable Energy Wind and Water Power Technologies, is based on a wind project’s 

location to the end user and power distribution infrastructure and not on the size of 

technology or project. Distributed wind energy systems are connected either on the 

customer side of the meter or directly to the local grid, in comparison to the utility 

wholesale power generated from large wind farms that is sent via a transmission line to 

substations for distribution. Distributed wind energy systems are commonly installed 

on residential, agricultural, commercial, institutional, and industrial sites. Distributed 

wind systems can vary in size from a 1 kW or smaller wind turbine, which is off the 

grid, to a 10 kW turbine at a home site to several multi-MW turbines at a manufacturing 

site or university campus.

Wind energy systems typically include a rotor, a tail, a tower, a generator, wiring, and 

balance of plant components such as inverters, controllers and potentially batteries. The 

wind passes through the blades of the rotor causing the mechanical rotary motion to 

drive the generator. The generator produces AC electricity.

Small wind turbines are considered in two groups, either horizontal axis or vertical axis. 

The most common are the horizontal axis turbines, which typically have two or three 

blades that are made of a composite material like fiberglass. The rotor diameter defines 

the swept area, that is the quantity of wind intercepted by the wind turbine. The rotor 
2-28 Leidos, Inc. File: EIA | 209089

assembly, generator, and tail assembly are all attached to the top of a tower. The tower 

can be two types – either a free-standing, self-supporting tower or a guy-wired tower

(guyed towers). Guyed towers could be comprised of lattice sections, pipe or tubing 

with guy wires and a foundation. The radius for guy wires on guyed towers are typically 

one-half to three-quarters of the tower height resulting in a space issue. Tilt down 

towers can be lowered to the ground to allow for maintenance but are typically for wind 

turbines that are 5 kW or smaller.

Source: U.S. Department of Energy, Energy Efficiency and Renewable Energy

Figure 2-1. Basic Parts of a Small Wind Electrical System

During the 11-year period between 2003 and 2013, approximately 842 MW of 

distributed wind turbine capacity was installed in the U.S., representing approximately 

72,000 turbines. The 842 MW of distributed wind turbine capacity at the end of 2013 

compares to 812 MW of capacity at the end of 2012, or approximately 3.7 percent 

higher. In 2013, approximately 30.4 MW (2,700 turbines) of new distributed wind 

capacity was installed in the U.S., compared to approximately 175 MW (3,800 turbines) 

of new distributed wind capacity installed during 2012. Of the 30.4 MW installed 

during 2013, 24.8 MW was represented by 18 turbines, with sizes over 100 kW, on nine 

projects. The remaining 5.6 MW installed in 2013 was represented by the remaining 

approximately 2,682 turbines with sizes below 100 kW. Of the 175 MW installed 

during 2012, 138 MW was for turbines sized greater than 1 MW, 19 MW was for 

turbines sized between 100 kW and 1 MW, and the remaining 18.4 MW was for 

turbines sized below 100 kW.

The reasons for the reduction of installed capacity from 2012 to 2013 of approximately 

83 percent include phased out incentives, such as the U.S. Treasury cash grant in-lieu 

of a 30-percent investment tax credit program along with other state and federal 

programs; reduced funding through the U.S. Department of Agriculture Rural Energy 

for America Program, which funded 25 wind projects in 2013 with $1.2 million in grants 

as compared to funding 57 wind projects in 2012 with $2.6 million in grants; 

competitive photovoltaic and natural gas prices; and lack of consumer confidence in

turbine reliability.
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The scope of this Report includes the review of distributed wind technology of up to the 

10-kW level for residential applications and from 10 kW to 100 kW for commercial 

applications. Midsize turbines that range in size between 101 kW and 1 MW and utility 

turbines greater than 1 MW were not included in the review.

2.3.3 Fuel Cell

A fuel cell is a device that generates electricity through a chemical reaction. Every fuel 

cell has one positive electrode and one negative electrode. The electrodes are where the 

reactions take place that produce electricity. Every fuel cell has an electrolyte, which 

carries electrically charged ions from one electrode to the other and a catalyst, which 

increases the speed of the reactions at the electrodes.

Fuel cells work by hydrogen atoms entering at the anode where a chemical reaction 

strips electrons and the hydrogen atoms are ionized – carrying a positive electrical 

charge. The negatively charged electrons provide current to produce electricity. If AC 

is required, the DC output from the fuel cell is routed to an inverter for conversion from 

DC to AC. Oxygen enters the fuel cell at the cathode where it either combines with the 

electrons returning from the electrical circuit and the hydrogen ions that have traveled 

through the electrolyte from the anode or the oxygen picks up electrons and then travels 

through the electrolyte to the anode and there it combines with the hydrogen ions. Some 

fuel cells require pure hydrogen and, therefore, require equipment such as a reformer to 

purify the fuel to the fuel cell.

Since each fuel cell develops a relatively low voltage, the cells are stacked to produce a 

higher, more useful voltage. Depending on the type of fuel cell, high temperature waste 

heat from the process may be available for cogeneration applications.

There are five main types of fuel cells: alkali, solid oxide fuel cell (SOFC), phosphoric 

acid fuel cell (PAFC), proton exchange membrane (PEM), and molten carbonate fuel 

cells (MCFC). Alkali, MCFC, and PAFC all use liquid electrolytes, whereas, PEM and 

SOFC use solid electrolytes. All five types of fuel cells are discussed in detail below.

Alkali Fuel Cell

Alkali fuel cells operate on compressed hydrogen and oxygen. They typically use a 

solution of potassium hydroxide in water as the electrolyte. Alkali fuel cells have an 

efficiency of about 70 percent with operating temperatures between 150 to 200 degrees 

Celsius (°C) (about 300 to 400 degrees Fahrenheit (°F)). The output from alkali fuel 

cells can vary between 300 watts to 5 kW.
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Source: Fuel Cell Basics

Figure 2-2. Alkali Fuel Cell

Solid Oxide Fuel Cell (SOFC)

SOFCs use a ceramic compound such as calcium oxide or zirconium oxide as the 

electrolyte. Efficiency of SOFC is about 60 percent with operating temperatures of 

about 1,000 °C (1,800 °F). SOFC cells can output up to 100 kW. The waste heat, due 

to the high operating temperatures, can be recycled to make additional electricity.

Source: Fuel Cell Basics

Figure 2-3. Solid Oxide Fuel Cell
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Phosphoric Acid Fuel Cell (PAFC)

PAFCs use phosphoric acid as the electrolyte. The efficiency for PAFC ranges between 

40 and 80 percent with operating temperatures between 150 to 200 °C (about 300 to 

400 °F). PAFC have outputs of up to 200 kW and units as large as 11 MW have been 

tested.

Source: Fuel Cell Basics

Figure 2-4. PAFC and PEM Fuel Cells

Proton Exchange Membrane (PEM)

PEM fuel cells work with a polymer electrolyte in the form of a thin, permeable sheet. 

The efficiency of PEM fuel cells is about 40 to 50 percent with operating temperatures 

of about 80 °C (175 °F). The output from PEM fuel cells is typically in the range of 50 

to 250 kW. Because these fuel cells operate at low temperatures, they can be used for 

homes and automobiles.

Molten Carbonate Fuel Cell (MCFC)

MCFC use high temperature compounds of salt carbonates such as sodium or 

magnesium for the electrolyte. MCFC efficiencies are in the typically in the range of 

60 to 80 percent with operating temperatures of about 650 °C (1,200 °F). The MCFC 

have been built with output of up to 2 MW and designs of up to 100 MW.
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Source: Fuel Cell Basics

Figure 2-5. Molten Carbonate Fuel Cell

The use of fuel cells in DG installations has increased greatly over the last few years. 

Based on the ICF International CHP installation database, the number of fuel cell units 

installed has increased from 57 units in 2008 to 154 units as of July 2013. In terms of 

capacity, in 2008, there were 18.7 MWs and as of July 2013 the capacity 68.13 MWs, 

which is an increase of 49.3 MWs. Additionally, this data also shows that the capacity 

per installation has increased since 2008 from 0.33 MWs to 0.44 MWs. As of 

July 2013, 82 percent of the installed fuel cell units in the U.S. are located in three states 

with incentive programs: California (78 units), New York (26 units), and Connecticut 

(22 units).

The scope of this report includes the review of distributed fuel cell technology at the 

50 kW size for residential applications, and 200 kW size for commercial applications

using proton exchange membrane technology.

2.3.4 Reciprocating Engine

Reciprocating engines have been used across multiple industries and are a mature and 

well-known technology. A reciprocating engine is an internal combustion engine, 

which utilizes fuel gas or fuel oil as its fuel supply. Also known as a piston engine, a 

reciprocating engine mixes fuel with air compressed by a piston in a cylinder, which is 

ignited, causing controlled combustion producing additional pressure used to drive a 

piston. The energy released by sequential combustion in multiple cylinders is converted 

from reciprocating motion of pistons into rotational motion using connecting rods 

attached to a crankshaft. The rotating crankshaft drives an electric generator. Heat 

released by combustion can be recovered to produce hot water and/ or steam. 

Reciprocating engines can be either 4-stroke cycle or 2-stroke cycle, the former being 

more prevalent and is the type considered in this Report. There are also other 

configurations, including multiple crankshafts, which are untypical. Reciprocating

engines may be either naturally aspirated, using the suction from the piston to entrain 

the combustion air, turbocharged, using an exhaust-driven turbine-compressor to 

pressurize the combustion air supply, or to a lesser degree, equipped with 
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mechanically-driven combustion air blowers. Turbocharged and blower-equipped units 

produce a higher power output for a given engine displacement, whereas, naturally

aspirated units have lower output but also lower initial costs and require less 

maintenance. Natural gas-fueled engines are typically the engine of choice due to 

emission requirements in the U.S.; however, diesel, heavy fuel oil, landfill gas, and 

biofuels can also be used to power reciprocating engines.

Reciprocating engines require fresh air, fuel, and a combustion source for each power 

stroke. There are two methods used to initiate combustion in the cylinders of 

reciprocating engines, spark ignition and compression ignition. Oil-based fuels such as 

diesel, heavy fuel oil, and biofuels, will auto-ignite in compression ignition engines

without the need of a spark; however, gas fuels, such as natural gas or landfill gas, must 

use either spark ignition or pilot oil (dual fuel) to initiate combustion because these fuels 

do not ignite spontaneously upon compression (auto-ignite) at the operating pressures 

of these engines. The use of dual-fuel engines has more recently fallen out of favor due 

to the higher emissions that result from using pilot oil ignition.

Electric generation efficiencies of reciprocating engines range from 30 percent to 

40 percent LHV for small naturally aspirated engines, and near 50 percent for larger 

turbocharged engines. Commercially available reciprocating engines for power 

generation range from 0.5 kW to over 14 MW. Reciprocating engines can be used in a 

variety of ways due to their relatively large power output to unit size (power density), 

well-developed technology, attractive lead times, and recoverable thermal output. 

Applications for reciprocating engines include continuous or prime power generation, 

peak shaving, backup power, remote power, stand-by power, and CHP. Reciprocating 

engines are also used extensively as direct mechanical drives in applications such as 

water pumping, air and gas compression, chilling/refrigeration, and vehicle and ship 

propulsion.

There are four sources of useable waste heat from a reciprocating engine: exhaust gas, 

engine jacket, lube oil, and turbocharger. Recovered heat is in the form of hot water or 

low pressure steam (<30 pounds per square inch gauge (psig)). Some industrial CHP 

applications use the engine exhaust gas heat directly for process drying. Generally, the 

hot water and low pressure steam produced by reciprocating engine CHP systems is 

appropriate for low to moderate temperature process needs, space heating, potable water 

heating, and chilled water production, air conditioning, and/or refrigeration (via 

absorption chillers). Commercial and industrial uses of engine-produced CHP where 

hot water or low pressure steam is required include hospitals, universities, water 

treatment facilities, factories, steel mills, and food processing plants.

Reciprocating engines can operate at air-to-fuel ratios from 16:1 to more than 50:1, and

compression ratios typically ranging between 14:1 and 23:1. Emissions control 

equipment is often required due to the composition of the exhausting combustion gases. 

The primary pollutants from reciprocating engines are nitrogen oxides (NOX), carbon 

monoxide (CO), and volatile organic compounds.

Reciprocating engine technology has improved dramatically over the past three decades, 

primarily driven by economic and environmental pressures for power density 

improvements, increased fuel efficiency and reduced emissions. The emissions 
2-34 Leidos, Inc. File: EIA | 209089

signature of natural gas spark ignition engines in particular has improved significantly 

in the last decade through better design and control of the combustion process and 

through the use of exhaust catalysts. Low NOX level emissions are available with 

advanced lean burn natural gas engines. Manufacturers often supply emissions 

equipment that can be added to the diesel fired engines in order to comply with U.S. 

Environmental Protection Agency (EPA) Tier-4 emissions levels. In addition, there are 

third-party providers who offer the same emissions-related options.

Source: Clarke-Energy

Figure 2-6. Gas Engine Basic Components

Oil Fired Reciprocating Engine

Reciprocating engines of the commercial size considered for this study (300 kW) are 

typically packaged as a generator set designed for standby, peaking, or rental duty, 

which is typically in the range of 500-2,000 hours per year.

The scope of this Report includes the review of distributed oil-fired reciprocating engine 

technology at the 300-kW level for commercial applications, which operate at 

1,800 revolutions per minute (RPM), have 6 cylinders, and have compression ignition, 

but are re-rated at a lower output for continuous duty. The scope of this Report does 
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not include larger oil-fired engines, because of the emissions limitations placed upon 

stationary electric generating service in the U.S.

Gas-Fired Reciprocating Engine

Compared to the commercial oil-fired reciprocating engines, all engines in these 

categories are spark-ignited. The scope of this Report includes the review of distributed 

natural gas-fired reciprocating engine technology at the 300-kW level for commercial 

applications, which are rated for continuous duty, operate at 1,200 RPM, and have 8 

cylinders.

The scope of this Report includes the review of distributed reciprocating engine 

technology at the 1,000-kW and 3,000-kW level for industrial applications, which are 

rated for continuous duty, operate at 1,800 RPM and 900 RPM, respectively, and have 

16 cylinders and 12 cylinders, respectively.

2.3.5 Natural Gas Micro-turbine

Micro-turbines are small electricity generators that most commonly burn natural gas, 

although alternative fuels such as gasoline, kerosene, and diesel fuel/distillate heating 

oil can also be used. Much in the way conventional gas turbines burn natural gas, microturbines use the fuel to create high-speed rotation utilizing the Brayton Cycle, which in 

turn rotates an electrical generator, which produces electricity. Micro-turbines are 

typically configured with one or two shafts. Micro-turbines often have operating speeds 

in the 60,000 to 120,000 RPM range depending on the manufacturer.

In some cases, Micro-turbines can be utilized in CHP operation and widely used in 

distributed generation applications. In the CHP application, the exhaust heat from the 

Micro-turbine passes, if equipped, through a recuperator, which further heats the outlet

air from the compressor prior to combustion resulting in higher gas turbine efficiencies. 

The exhaust gas from the turbine pass through the recuperator then through a heat 

exchanger, which transfers the heat to a fluid (usually water), which can then be utilized 

for secondary purposes such as central heating, domestic hot water production, chilled 

water, and ice storage systems. In current applications, exhaust temperatures from 

Micro-turbines might range from 500 °F to upwards of 750 °F, depending on the 

manufacturer.

Field testing on microturbines began in 1997.3 In 2005 the microturbine technologies 

were rapidly evolving, and a 2005 report to the World Bank cited the leading 

manufacturers as promising a 50% reduction in capital costs over twenty years.4

Commercially available, cost effective Micro-turbine technology has been in the 

marketplace since about 2000. Some of the advantages realized by utilizing 

 3 Kalam, A., A. King, E. Moret, and U. Weerasinghe. “Combined heat and power systems: economic and 

policy barriers to growth.” Chemistry Central Journal. 2012, 6(Suppl 1)S3. 

http://journal.chemistrycentral.com/content/6/S1/S3. 4 Chubu Electric Power Co. et al. Technical and Economic Assessment: Off Grid, Mini-Grid and Grid 

Electrification Technologies: Summary Report. 2005 Prepared for Energy Unit, Energy and Water 

Department, The World Bank. Last accessed from 

https://cdm.unfccc.int/filestorage/3/F/V/3FV3HUZOKY7DRMRLUZHDSP4KI4MLLK/Enclosure%20

2.pdf?t=OGt8bm1yMHJwfDAQmZH_kyA7opTJrE4fHilP on April 13, 2015.
2-36 Leidos, Inc. File: EIA | 209089

Micro-turbine technology include a high power-to-weight ratio, lower emissions as 

compared to other technologies, fewer moving parts, and advanced foil-air bearings 

along with air cooling, which result in fewer maintenance intervals. Another advantage 

of Micro-turbines is the use of advanced electronic power switching technology, which 

in some cases, may result in the elimination of the generator having to be synchronized 

with the power system to which it is connected.

Micro-turbines are usually manufactured with all of the previously mentioned 

sub-components in a single, skid-mounted unit about the size of an industrial sized air 

compression unit. The use of an integrated unit makes field installation and 

interconnection to the required utilities relatively simple for the end user. Today’s 

marketplace typically offers size ranges between 10 kW to 250 kW in size. 

To date, the stationary microturbine market has made strides in applications where CHP 

and combined cooling, heating and power are important (e.g., UPS Data Center). It has 

also reached markets where fuel gas quality is more variable (e.g., landfill gases, 

anaerobic digester gases, and waste gases in oil fields) without fuel conditioning. For 

example, the FlexEnergy MT250 unit allows operating gas concentrations to range from 

30 to 100%.5

Despite the various applications, the microturbine industry has not resulted in 

significant mass production compared to other technologies in this report. Capstone 

Turbine Corporation is the world’s largest manufacturer of microturbines with most of 

the market share, but has only produced approximately 8,000 units worldwide since 

1998.6 However, with less expensive natural gas projected for the future, some sources 

estimate that upwards of 19 to 57 MW of capacity due to Micro-turbines could be 

installed over the next five years.

The scope of this Report includes the review of distributed Micro-turbine technology at 

the 250-kW level, which is a common size for commercial applications.

2.3.6 Natural Gas Turbine

Industrial gas turbines typically range from capacities of 1 to 225 MW. Gas turbines 

are used to power industrial or processing plants, building complexes, aircraft, trains, 

ships, and electrical generators.

Gas turbines are a type of internal combustion engine that operate using the Brayton 

cycle. They have an upstream rotating compressor coupled to a downstream turbine, 

with a combustion chamber located between the compressor and the turbine sections. 

The gas turbine uses air, which flows through a compressor section that pressurizes the 

air to high pressure. Energy is then added by spraying fuel into the air and igniting it so 

the combustion generates a high temperature flow. The high temperature pressurized

gas expands through the turbine section. The work produced by the turbine is used to 

drive the compressor and in most cases also powers an electric generator. The energy 

 5 FlexEnergy, 2011. Presentation to Federal Utility Partnership Working Group on October 25, 2011. Last 

accessed from http://energy.gov/eere/femp/downloads/flexenergy on April 15, 2015. 6 Capstone Turbine Corporation. Press Releases: “Capstone Flattens Organizational Structure to Lower 

Cost, Increase Adaptability as well as Foster Innovation and Creativity.” April 10, 2015. Last accessed 

from http://www.capstoneturbine.com/news/story.asp?id=760 on April 15, 2015.
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not used for shaft work remains in the exhaust gases, so these have either a high 

temperature or a high velocity. 

Gas turbines undergo three thermodynamic processes: isentropic compression, isobaric 

combustion, and isentropic expansion. Together, these make up the Brayton cycle. In 

a gas turbine, mechanical energy is irreversibly transformed into heat when gases are 

compressed due to internal friction and turbulence. Passage through the combustion 

chamber, where heat is added and the specific volume of the gases increase is 

accompanied by a slight loss in pressure. During expansion amidst the stator and rotor 

blades of the turbine irreversible energy transformation once again occurs. If the device 

has been designed to power a shaft, as with an industrial generator, the exit pressure will 

be as close to the entry pressure as possible. It is necessary that some pressure remain 

at the outlet in order to fully expel the exhaust gases. In the case of a jet engine, only 

enough pressure and energy is extracted from the flow to drive the compressor and other 

components. The remaining high pressure gases are accelerated to provide a pressure

stream that can be used to propel an aircraft.

Blade tip speed determines the maximum pressure ratios that can be obtained by the 

turbine and the compressor. This limits the maximum power and efficiency that can be 

obtained by the engine.

Mechanically, gas turbines can be less complex than internal combustion piston engines. 

However, the required precision manufacturing for components and temperature 

resistant alloys necessary for high efficiency often makes the construction of a simple 

turbine more complicated than piston engines. More sophisticated turbines may have 

multiple shafts, hundreds of turbine blades, movable stator blades, and a vast system of 

complex piping, combustors, and heat exchangers. Thrust bearings and journal bearings 

are a critical part of gas turbine design. Traditionally, gas turbines have been supplied 

with hydrodynamic oil bearings or oil cooled ball bearings, but may be equipped with 

roller type bearings as well. These types of bearings are being surpassed by foil 

bearings, which have been successfully used in micro-turbines and auxiliary power 

units.

Industrial gas turbines are closely integrated with the devices they power, often an 

electric generator and the secondary energy equipment that is used to recover residual 

energy, which is largely heat. Gas turbines range in sizes. Industrial gas turbines used 

solely for mechanical drive or used in collaboration with a recovery steam generator 

differ from power generating sets in that they are often smaller and feature a dual shaft 

design as opposed to single shaft. The power range varies from 1 MW up to 225 MW. 

These engines can be connected directly to either a pump or a compressor assembly for 

use in pipeline applications. The majority of these types of installations are used within 

the oil and gas industries. Oil and gas platforms require these engines to drive 

compressors to inject gas into the wells to force oil up another bore, gas and oil 

separation or to compress gases or liquids for transportation. Gas turbines are often 

used to provide power for the host platform. These platforms do not need to use the 

engine in collaboration with a CHP system due to getting the gas at an extremely 

reduced cost. The same types of companies who use gas turbines for oil or liquid 

compression may use pump sets to drive the fluids to land and across pipelines in 

various intervals. Other uses for gas turbines are powering chemical and pharmaceutical 
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plants, food and beverage plants, automotive plants, mining, pulp and paper, and 

textiles. Gas turbines can also power hospitals, universities, and other building 

complexes.

The scope of this Report includes the review of distributed natural gas turbine

technology at the 1,000-kW size for commercial applications, and 5,000-kW, 

10,000-kW, 25,000-kW and 40,000-kW sizes for industrial applications.

2.3.7 Combined Cycle

A combined cycle (CC) power plant utilizes both a natural gas combustion turbine 

generator (CTG) and captures the waste combustion heat to create steam, which can be 

used to generate electricity. This combination of two power generation cycles enhances 

the efficiency of the plant. While the electrical efficiency of a simple cycle plant power 

plant without waste heat utilization typically ranges between 25 percent and 40 percent, 

a CC can achieve electrical efficiencies of 60 percent or more. Supplementary firing in 

the boiler further enhances the overall power output but can lower efficiency. The high 

fuel utilization factor of this type of plant configuration contributes to low lifecycle 

costs.

The major equipment components of a CC facility include a combustion turbine and 

generator, a heat recovery steam generator boiler (HRSG) and a steam turbine and 

generator (STG). CC facilities can be set up with dual, and even triple, sets of CTGs 

and HRSGs in order to increase the amount of steam created and sent to the STG. 

Associated equipment needed in a CC facility include generator step-up transformers, 

auxiliary transformers, control systems, a dedicated substation and numerous pumps, 

motors and other auxiliary equipment. The CTG is subject to variation in output 

depending on the density of the air, as affected by temperature and humidity. Output 

will decrease in warm weather and increase in cold weather as the density changes affect 

mass flow through the gas turbine.

In the CC arrangement, fuel is fired in the CTG, which utilizes the Brayton power cycle. 

In this type of cycle, the hot combustion gases are expanded through a turbine, which 

drives an electric generator. Hot exhaust gas from the combustion turbine is passed 

through a HRSG, which is incorporated into a traditional steam Rankine cycle wherein

water is vaporized in the HRSG to produce superheated steam, which is then supplied 

to the STG. The HRSGs typically produce steam at three pressure levels and can be 

provided with supplemental firing to augment the steam production, which acts to 

increase STG electric output. The exhaust steam from the STG is condensed to liquid 

in the condenser, non-condensable gases are removed and are then collected in the 

condenser hot well. Makeup water from the demineralized water system is deaerated 

and supplied to the condenser hot well. Condensate pumps discharge the condensate

water from the condenser hot well to the deaerator often via a condensate preheater 

section in the HRSG. Feedwater pumps discharge feedwater from the deaerator to the 

low pressure, intermediate and high-pressure economizer sections of the HRSG, which 

preheat the feedwater prior to discharge to the steam drums. In steam drums, the 

feedwater is heated to steam conditions, directed through moisture reducing separators

and then superheated to complete the cycle.
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The scope of this Report includes the review of distributed CC natural gas technology 

at the 100,000-kW level for industrial applications.

2.4 Cost Estimation Methodology

The approach taken in the cost analysis of capital and operating estimates is defined 

below. All costs in this Report are nominal or current costs associated with the year 

specified. Conversion to real or constant dollar basis will require the use of an 

appropriate price deflator index that is consistent with that currently used in NEMS. 

2.4.1 Capital Cost

A summary base capital cost estimate (Cost Estimate) was developed for each system 

technology, based on a generic facility of a certain size (capacity) and configuration, 

and assuming a non-specific U.S. location with no unusual location impacts (e.g., urban 

construction constraints) or infrastructure needs (e.g., a project-dedicated 

interconnection upgrade cost).

Each Cost Estimate was developed assuming costs in first quarter 2015 dollars on an 

“overnight” capital cost basis. In each Cost Estimate, the total project engineering, 

procurement, and construction (EPC) cost was organized into the following categories:

 Equipment supply

 Installation – labor and materials

 Project engineering, construction management, and contingency (including project 

indirect costs)

In addition to the base Cost Estimate provided for the given technology, projected cost 

estimates for the installed system costs were made in 5-year increments from the base 

year of 2015 to 2020, 2025, 2030, 2035, and 2040.

Costing Scope

The equipment supply includes major equipment, including but not limited to, boilers, 

selective catalytic reduction (SCR), cooling tower, STG, PV modules, combustion 

turbine (CT), as well as auxiliary equipment such as pumps, condensers, electrical 

transformers, switchgear, motor control centers distributed control systems (DCS), and 

balance of plant (BOP) equipment such as fire protection, as applicable to a given 

technology.

The installation labor and materials include bulk materials and commodities, such as 

pipe, fasteners, instrumentation, wire, cable tray, and lighting.

The estimated line item for engineering, construction management, and contingency

include engineering, distributable labor and materials, craft labor overtime and 

incentives, scaffolding costs, construction management, and start-up and 

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

profit, and construction contingency. Contingency in this category is considered 

“contractor” contingency, which would be held by a given contractor to mitigate its risk 

in the construction of a project.
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The owner’s costs, which are not addressed in the scope of this report, typically include 

development costs, preliminary feasibility and engineering studies, environmental 

studies and permitting, legal fees, project management (including third-party 

management), insurance costs, infrastructure interconnection costs (e.g., gas, 

electricity), Owner’s Contingency, and property taxes during construction. The 

electrical interconnection cost includes an allowance for the plant switchyard and a 

subsequent interconnection to an “adjacent” (e.g., within a mile) of the plant, but does 

not include significant transmission system upgrades.

2.4.2 Operation and Maintenance (O&M) Expenses

O&M expenses consist of non-fuel O&M costs, owner’s expenses, and fuel-related 

expenses. In evaluating the non-fuel O&M expenses for use in the Electricity Market 

Module of NEMS, this Report focuses on the non-fuel O&M costs associated with the 

direct operation of the given power plant technology, referred to here as the “Production 

Related Non-Fuel O&M Expenses,” which allows for comparison of O&M costs on the 

same basis across the various technologies.

Production Related Non-Fuel O&M Expenses include the following categories:

 Fixed O&M (FOM)

 Variable O&M (VOM)

 Major Maintenance

Presented below is a brief summary of the expense categories included within the 

categories of Fixed O&M, Variable O&M, and Major Maintenance. Further, Sections 3 

through 5 provide more specific information related to Production-Related Non-Fuel 

O&M Expenses for each technology as related to the residential, commercial and 

industrial segments.

Owner’s expenses, which are not addressed in this Report, include expenses paid by 

plant owners that are plant specific and can vary significantly between two virtually 

identical plants in the same geographic region. Examples of owner’s expenses might 

include, depending on the project, property taxes, asset management fees, energy 

marketing fees, and insurance.

Fixed O&M (FOM)

FOM expenses are those expenses incurred at a power plant that do not vary 

significantly with generation and generally include the following categories:

 Staffing and monthly fees under pertinent operating agreements

 Typical bonuses paid to the given plant operator

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

 Plant-related general and administrative expenses (postage, telephone, etc.)

 Routine preventive and predictive maintenance performed during operations

 Maintenance of structures and grounds
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 Other fees required for a project to participate in the relevant National Electric 

Reliability Council region and be in good standing with the regulatory bodies

Routine preventive and predictive maintenance expenses do not require an extended 

plant shutdown and include the following categories:

 Maintenance of equipment such as water circuits, feed pumps, main steam piping, 

and demineralizer systems

 Maintenance of electric plant equipment, which includes service water, DCS, 

condensate system, air filters, and plant electrical

 Maintenance of miscellaneous plant equipment such as communication equipment, 

instrument and service air, and water supply system

 Plant support equipment which consists of tools, shop supplies and equipment rental, 

and safety supplies

Variable O&M (VOM)

VOM expenses are production-related costs, which vary with electrical generation and 

are generally included in the following categories, as applicable to the given power plant 

technology: 

 Raw water

 Waste and wastewater disposal expenses

 Purchased power (which is incurred inversely to operating hours), demand charges 

and related utilities

 Chemicals, catalysts, and gases

 Ammonia (NH3) for SCR, as applicable

 Lubricants

 Consumable materials and supplies

Major Maintenance

Major maintenance expenses generally require an extended outage, are typically 

undertaken no more than once per year; and are assumed to vary with electrical 

generation or the number of plant starts based on the given technology and specific 

original equipment manufacturer recommendations and requirements. These major 

maintenance expenses include the following expense categories:

 Scheduled major overhaul expenses for maintaining the prime mover equipment at 

a power plant and/or costs associated with long-term service agreements associated 

with the prime movers

 Major maintenance labor

 Major maintenance spares parts costs
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 BOP major maintenance, which is categorized as major maintenance on the 

equipment at the given plant that cannot be accomplished as part of routine 

maintenance or while the unit is in commercial operation.

2.4.3 Regional Cost Factors

Table 2-4 makes use of specified regional cost factors to adjust the original technology 

capital costs, which used the Gulf Coast as the basis for the reference facility cost 

estimate. These factors generally account for major location differences (e.g., average 

temperatures, remote locations), labor and wage productivity differences, owner cost 

differences, and overhead cost differences.

Table 2-3. Technology Performance Specifications - 2015

Technology Fuel

Nominal 

Capacity

(kW) (1)

Nominal

Heat Rate

(Btu/kWh) (2)

Capital Cost 

($/kW) (3)

Fixed O&M 

($/kW-yr) (4)

Variable 

O&M 

($/kWh) (5)

Residential – Small Solar Photovoltaic Solar 5 AC N/A 3,000 16.27 N/A

Residential – Wind Wind 10 N/A 8,400 N/A 0.0023

Residential – Fuel Cell Gas 10 8,533 11,989 332.00 0.065

Commercial – Small Solar Photovoltaic Solar 40 AC N/A 2,750 19.75 N/A

Commercial – Large Solar Photovoltaic Solar 500 AC N/A 2,505 21.00 N/A

Commercial – Wind Wind 100 N/A 5,900 N/A 0.0023

Commercial – Fuel Cell Gas 200 9,481 5,458 332.00 0.045

Commercial – Natural Gas Engine Gas 373 10,405 2,176 20.00 0.011

Commercial – Oil-Fired Engine Oil 340 10,348 2,016 24.00 0.020

Commercial- Natural Gas Turbine Gas 1,210 14,045 2,224 41.80 0.0102

Commercial – Natural Gas Micro-turbine Gas 250 13,200 3,404 18.22 0.0138

Industrial – Reciprocating Engine – NG Gas 1312 9,614 1,899 18.00 0.011

Industrial – Reciprocating Engine – NG Gas 3,000 7,810 1,742 8.00 0.009

Industrial – Natural Gas Turbine Gas 5,300 12,688 1,509 79.02 0.010

Industrial – Natural Gas Turbine Gas 9,950 12,037 1,281 79.02 0.0042

Industrial – Natural Gas Turbine Gas 25,210 10,189 999 18.43 0.006

Industrial – Natural Gas Turbine Gas 39,986 9,305 822 17.88 0.005

Industrial – Combined Cycle Gas 103,128 8,353 1,594 19.88 0.0064

Notes to Table 2-3:

(1) Capacity is net of auxiliary loads.

(2) Heat Rate is on a HHV basis for British thermal units per kW-hour (Btu/kWh).

(3) Capital Cost excludes financing-related costs (e.g., fees, interest during construction). Dollars per kW

(4) FOM expenses exclude owner’s costs (e.g., insurance, property taxes, and asset management fees).

(5) VOM expenses include major maintenance.

(6) Million Btu (MMBtu).
GENERAL BASIS FOR TECHNOLOGY EVALUATION BASIS

File: EIA | 209089 Leidos, Inc. 2-23

Table 2-4. Regional Cost Multiplication Factors

Region 

Number REGION NAME Factor for Region

1 ERCT 0.94

2 FRCC 1.00

3 MORE 1.21

4 MROW 1.00

5 NEWE 1.05

6 NYCW 1.38

7 NYLI 1.32

8 NYUP 1.05

9 RFCE 1.06

10 MICHIGAN 1.00

11 RFCW 0.95

12 SRDA 0.97

13 SRGW 1.05

14 SOUTHERN 0.98

15 TVA 0.95

16 SRVC 0.92

17 SPNO 1.00

18 SPSO 0.80

19 DSW 1.03

20 NP15 1.12

21 NWPP 1.05

22 ROCKIES 1.00

File: EIA | 209089

Section 3

RESIDENTIAL

3.1 Residential – Small Solar Photovoltaic (RSS)

3.1.1 Equipment and Systems

This section describes the Residential – Small Solar Photovoltaic system (RSS), for 

which we have assumed an installed PV module capacity of 5.5 kW-direct current 

(“DC”) and an installed inverter capacity of 5.0 kW. The assumed system has a DC to 

AC capacity of 1.1, which is typical for residential installations. Unless otherwise

noted, “kW-DC” refers to DC capacity and “kW” refers to AC capacity.

3.1.2 Technology Specifications

For the purposes of the reference technologies projection, we considered a standard 

rooftop-mounted, fixed-tilt PV array utilizing standard, commercially available 

crystalline silicon modules. The array is assumed to be equipped with string inverters 

and a remote monitoring system purposed to provide real-time and historical production 

data of the facility along with alarm functionality in the event system or equipment 

anomalies occur. A facility of this type is typically unmanned, and monitoring and 

alarm functionality is assumed to be remote in nature.

Standard PV modules have a ten-year materials and workmanship warranty, and a 25 

year linear power warranty. String inverters typically have a ten-year warranty, with 

extensions to cover 20 years total. With these warranty terms in mind, we have assumed 

25 years as the lifetime for the PV modules and 15 years as the lifetime for the string 

inverters. Certain micro-inverters and DC optimizers are available with 25-year 

warranties.

For cost projections, we have considered module efficiency as the main driver of cost 

reductions over time. In the reference technologies case, our projection assumes the use 

of p-type crystalline silicon, with a switch to n-type crystalline silicon in 2025. The 

switch to n-type silicon allows for higher efficiencies and a lower degradation rate in 

the first year of operation from the elimination of light induced degradation. PV 

modules utilizing n-type silicon are available today, but are not widely adopted in the 

market. With time and scale, this technology may see wider adoption.

The advanced technologies case assumes a 5-year acceleration in module efficiency 

improvements from the reference technologies case, with a new, higher efficiency PV 

module technology introduced in 2030. Generally, to be adopted, the new technology 

should have both higher efficiency and lower manufacturing costs. Heterojunction and 

multi-junction cells show higher efficiencies relative to standard devices; however, the 

manufacturing costs for these technologies are also higher. Over time, technological or 

manufacturing innovations may drive the costs down far enough to enable wider 

adoption in the marketplace. 
Section 3

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3.1.3 Capital Cost Estimate

The base Cost Estimate for the Residential – Small Solar Photovoltaic system (RSS)

with a nominal capacity of 5 kW is $3,000/kW-AC (2015 dollars). 

The cost estimate for the RSS assumes being installed on residential roofs, homes that 

can lend the roof orientation to satisfy maximum efficiency of solar irradiancy, usually 

having a footprint of the structure roof surface area. The cost estimate is based on actual 

quotations for work already installed. Peripheral electrical equipment necessary to 

complement the intermittent power plant needs has been added to the estimate. The 

cost estimate includes site preparation, structures, equipment, electrical, distributable 

cost, engineering and design and subcontractor fee and budget contingency. All 

numbers in these estimates are based on prices and wages for the Gulf Coast Region of 

the U.S. Costs for other EMM regions can be estimated based on the regional 

multiplication factors listed in Table 2-4.

Table 3-1 summarizes the Cost Estimate categories for the RSS system.

Table 3-1. Base Plant Site Capital Cost Estimate for RSS

Technology: RSS

Nominal Capacity (ISO) (1): 5 kW-AC

Nominal Heat Rate (ISO): N/A

Capital Cost Category

($/kW-AC)

(January 1, 2015 $)

PV Modules 935 (2)

Racks 225

Inverters 225

Equipment Supply Subtotal 1,385

Installation Materials and Labor 1,288

Engineering/Construction Management/Contingency (3) 327

Total Project EPC ($/kW-AC) 3,000

(1) International Standards Organization (ISO).

(2) The module capital cost in this table assumes 5.5 kW-DC of PV module capacity at a cost of $850/kW-DC, as 

referenced to the 5 kW AC capacity assumed for the RSS system.

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

3.1.4 O&M Estimate

Table 3-2 presents the O&M expenses for the RSS. Fixed O&M expenses for an RSS 

might typically include those expenses associated with scheduled and unscheduled 

maintenance, washings and costs associated with remote monitoring. There are 

typically no variable O&M costs associated with a PV system, as the expenses do not 

typically vary with capacity factor (CF).
RESIDENTIAL

File: EIA | 209089 Leidos, Inc. 3-3

Table 3-2. O&M Expenses for RSS (5 kW-AC)

Technology: RSS

Fixed O&M Expense $16.27/kW-year

Variable O&M Expense N/A

3.1.5 Reference Technologies Projections

The following tables present the performance characteristics and cost projections for 

RSS.

Table 3-3. Residential O&M - Small PV – Reference New Equipment (1)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 5.5 5.5 5.5 5.5 5.5 5.5

Inverter Capacity (kW-AC) 5.0 5.0 5.0 5.0 5.0 5.0

Capacity Factor (%) 17.0 17.0 17.0 17.0 17.0 17.0

Hours of Operation (hrs) 1,489 1,489 1,489 1,489 1,489 1,489

Module Efficiency (%) 17.0 20.1 23.2 26.0 27.9 28.1

First Year Degradation (%)(2) 3.0 3.0 1.0 1.0 1.0 1.0

Module Life (years) 25 25 25 25 25 25

Inverter Life (years) (3) 15 20 25 25 25 25

Variable O&M Costs ($/kWh)(4) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(5) 16.27 18.34 20.75 23.47 26.54 30.02

(1) Assumes new system installed every five years.

(2) Assumes switch to n-type silicon wafers in 2025 (higher efficiency and a lower first year degradation).

(3) String inverters generally come with a standard 10-year warranty, with warranty extensions available to 20-years. 

An inverter lifetime of 15-years has been assumed in 2015, improving to 25-years in 2025.

(4) There will be minimal O&M costs for residential inverters; the units are replaced if defective.

(5) Fixed O&M costs represented in current dollars.

Table 3-4. Residential O&M - Small PV – 2015 Degraded Equipment (1)

Year 2015 2020 2025 2030 2035 2040

Inverter Capacity (kW-AC) 5.0 4.9 4.7 4.5 4.3 4.1

Capacity Factor (%) 17.0 17.0 17.0 17.0 17.0 17.0

Hours of Operation (hrs) 1,489 1,489 1,489 1,489 1,489 1,489

Module Efficiency (%) 17.0 16.0 15.3 14.7 14.1 13.4

System Level Degradation (%) (2) 3.0 6.0 9.8 13.5 17.3 21.0

Module Life (years) 25 20 15 10 5 0

Inverter Life (years) (3) 15 10 5 10 5 0

Variable O&M Costs ($/kWh) (4) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(5) 16.27 18.71 22.07 26.08 30.86 36.61

(1) Assumes system installation in 2015, with O&M performed to maintain system over its 25-year lifetime.

(2) System level degradation, as referenced to the initial installed DC capacity of 5.5 kW-DC. Assumes 3 percent 

degradation in the first year of operation and 0.75 percent annually thereafter.

(3) Assumes a lifetime of 15 years for the string inverters.
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3-4 Leidos, Inc. File: EIA | 209089

(4) There will be minimal O&M costs for residential inverters; the units are replaced if defective.

(5) Fixed O&M costs represented in current dollars.

(6) Includes cost of new inverter

Table 3-5. Residential Capital Costs - Small PV – Reference New Equipment (1,4)

Year 2015 2020 2025 2030 2035 2040

PV Modules ($/kW-DC) 850 798 740 720 731 791

PV Modules for RSS Reference Case ($/kW-AC)(2) 935 878 814 791 804 870

Racks ($/kW-AC) 225 211 196 190 193 209

Inverters ($/kW-AC) 225 230 230 237 241 261

Equipment ($/kW-AC) 1,385 1,319 1,240 1,219 1,238 1,340

Installation Labor and Materials ($/kW-AC) 1,288 1209 1121 1090 1107 1199

Engineering/Construction Management/Contingency(3) 327 363 388 423 461 503

Total Installed Cost ($/kW-AC) 3,000 2,891 2,749 2,733 2,807 3,042

(1) Capital cost of a new system installed every 5 years.

(2) Cost for 5.5 kW-DC of modules, referenced to the RSS inverter capacity of 5 kW.

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

(4) Costs are presented as current dollars.

3.1.6 Advanced Technologies Projection

The following tables present the performance characteristics and cost projections for 

advanced RSS. Module efficiency is assumed to increase at a faster rate compared to 

the reference case.

Table 3-6. . Residential O&M - Small PV – Advanced New Equipment(1,2)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 5.5 5.5 5.5 5.5 5.5 5.5

Inverter Capacity (kW) 5.0 5.0 5.0 5.0 5.0 5.0

Module Efficiency (%) (3) 17.0 23.2 27.8 30.9 32.5 33.1

First Year Degradation 

(%)(3) 3.0 1.0 1.0 1.0 1.0 1.0

Module Life (Years) 25 25 25 25 25 25

Inverter Life (Years) (4) 15 20 25 25 25 25

Variable O&M Costs 

($/kWh)(5) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kWyear) (6) 16.27 18.34 20.75 23.47 26.54 30.02

(1) For the advanced technologies reference case, module efficiency is assumed to increase at a faster rate compared to 

the reference case.

(2) Assumes new system installed every five years.

(3) Assumes switch to n-type silicon wafers in 2025 (these will have lower first year degradation).

(4) String inverters generally come with a standard 10-year warranty, with warranty extensions available to 20-years. An 

inverter lifetime of 15-years has been assumed in 2015, improving to 25-years in 2025.

(5) There will be minimal O&M costs for residential inverters; the units are replaced if defective.

(6) Fixed O&M costs represented in current dollars.
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Table 3-7. Residential Capital Costs - Small PV – Advanced New Equipment(1,4)

Year 2015 2020 2025 2030 2035 2040

PV Modules ($/kW-DC) 850 691 617 605 628 671

Module Cost - Advanced RSS ($/kW-AC)(2) 935 760 679 666 691 739

Racks ($/kW-AC) 225 183 163 160 166 178

Inverters ($/kW-AC) 225 216 213 220 228 245

Equipment ($/kW-AC) 1,385 1,160 1,055 1,046 1,086 1,161

Installation Labor and Materials ($/kW-AC) 1,288 1048 935 917 952 1017

Engineering/Construction Management/

Contingency(3) ($/kW-AC)

327 363 388 423 461 503

Total Installed Cost ($/kW-AC) 3,000 2,571 2,379 2,387 2,499 2,681

(1) Capital cost of a new system installed every 5 years.

(2) Cost for 5.5 kW-DC of modules, referenced to the RSS inverter capacity of 5 kW.

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

(4) Costs are presented as current dollars.

3.2 Residential – Wind System (RWS)

3.2.1 Equipment and Systems

The system configuration for the residential wind system (RWS) is evaluated in this 

section of the report. 

3.2.2 Technology Specifications

For the purposes of the analysis, a typical 10-kW residential wind turbine readily 

available in the commercial marketplace was considered. The turbine is assumed to be 

equipped with a locally mounted inverter (if required), a remote monitoring system 

whose purpose is to provide real time and historical production data of the facility along 

with alarm functionality in the event system or equipment anomalies occur. The RWS 

is also assumed to be equipped with remote starting and stopping capabilities along with 

automatic furling functionality in the event that high wind speed events occur. A facility 

of this type is typically unmanned, and monitoring and alarm functionality is assumed 

to be remote in nature.

3.2.3 Capital Cost Estimate

The base Cost Estimate for the RWS Facility, with a nominal capacity of 10 kW, is 

$8,400/kW. The cost estimate for the RWS 10 kW, assumes having a small site adjacent 

to the end use (rural area). For the RWS, a residential back yard site is needed to accept 

underground utilities such as electric and communications controls. The RWS

equipment price was obtained from a quotation by a small wind turbine generator 

manufacturer, and was stated by the manufacturer to be used for budgetary purposes 

only. Peripheral electrical equipment necessary to complement the residential power 

generation has been added to the cost estimate. The cost estimate includes site 

preparation, foundation structure, equipment, electrical, distributable cost, engineering 

and design and subcontractor fee and budget contingency. All estimated costs are 

expressed in $/kW. All numbers in these estimates are based on prices and wages for 

the Gulf Coast Region of the U.S. Costs for other EMM regions can be estimated based 

on the regional multiplication factors listed in Table 2-4.
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The capital cost estimate was based on Table 3-8, which summarizes the Cost Estimate 

categories for the RWS facility.

Table 3-8. Base Plant Site Capital Cost Estimate for RWS

Technology: RWS

Nominal Capacity (ISO)(1): 10 kW

Nominal Heat Rate (ISO): N/A

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 3,200

Installation – Labor and Materials 5,200

Engineering/Construction Management/Contingency(2)

Total Project EPC 8,400

(1) International Standards Organization (ISO)

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

3.2.4 O&M Estimate

Table 3-9 presents the variable O&M expenses associated with a typical RWS facility.

Fixed O&M expenses for an RSS might typically include those expenses associated 

with scheduled and unscheduled maintenance, washings and costs associated with 

remote monitoring. There are typically no variable O&M costs associated with an RWS 

system as the O&M costs are typically fixed O&M costs for insurance, property taxes, 

site maintenance, legal fees, turbine warranty, and the remainder is tied to maintenance 

labor rates, royalties, remote monitoring, and other costs.

Table 3-9. O&M Expenses for RWS (10 kW)

Technology: RWS

Fixed O&M Expense $0.0023/kWh

Variable O&M Expense N/A

3.2.5 Reference Technologies Projections

The following tables present the performance characteristics and cost projections for 

RWS.

Table 3-10. Residential O&M - Wind – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 10.00 10.00 10.00 10.00 10.00 10.00

Capacity Factor (%) 27.0 27.0 27.0 27.0 27.0 27.0

Hours of Operation (hrs) 2,365 2,365 2,365 2,365 2,365 2,365

Variable O&M Costs ($/kWh) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kWyear)(2)

0.0023 0.0026 0.0029 0.0033 0.0038 0.0043

(1) Assumes new system installed every five years.

(2) Fixed O&M costs represented in current dollars.
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Table 3-11. Residential O&M - Wind – 2015 Degraded Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 10.00 9.97 9.93 9.90 9.87 9.84

Capacity Factor (%) 27.0 27.0 27.0 27.0 27.0 27.0

Hours of Operation (hrs) 2,365 2,365 2,365 2,365 2,365 2,365

Variable O&M Costs ($/kWh) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kWyear)(2)

0.0023 0.0026 0.0029 0.0033 0.0039 0.0044

(1) Assumes system installation in 2015, with O&M performed to maintain system over its 25-year lifetime.

(2) Fixed O&M costs represented in current dollars.

Table 3-12. Residential Capital Costs - Wind – Reference New Equipment(2)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 3,200 3481 3650 3899 4165 4449

Installation Labor and Materials ($/kW) 5,200 5,772 6,176 6,732 7,338 7,998

Engineering/Construction 

Management/Contingency (1) - - - - - -

Total Installed Cost ($/kW) 8,400 9,253 9,826 10,631 11,503 12,447

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

(2) Costs presented are in current dollars.

3.2.6 Advanced Technologies Projections

The manufacturing of wind turbines is generally considered a mature field. However, 

the DOE Energy Efficiency & Renewable Energy (ERRE) Program7 expects that future 

cost reductions for onshore wind power technologies (ranging from residential to utility 

level) will be based on:

• Plant-level design and management aimed at optimizing production

• Advanced control systems

• Improved numerical methods to understand wind resources

• Blade innovations

• More reliable drivetrain technologies

• Better scaling to low-wind speed sites

Based on historical data and model projections from multiple recent references, the 

onshore wind turbine capital costs are compared in Figure 3-1with the capital costs in 

the reference year. Five of these more recent studies agreed well for the first twentyfive years beyond the study baseline.

 7 Wiser, Ryan. “Wind Energy Cost, Performance and Pricing Trends: Past & Future.” Part of the StateFederal RPS Collaborative Webinar on December 17, 2013. Sponsored by CleanEnergy States Alliance 

and last accessed from http://www.cesa.org/assets/Uploads/RPS-Webinar-Presentation-Cost-andTechnology-Projections-for-Solar-and-Wind.pdf on April 9, 2015.
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Figure 3-1. Literature Descriptions of Wind Turbine Capital Cost Reductions 

Over Time

The average fractional capital costs from those five studies were determined at five-year 

increments, and average factors are shown in Figure 3-1 with error bars depicting one 

standard deviation in the numbers among those five studies. The tops of the error bars 

were considered to represent the Reference Technology Case (factors of 0.99 in five 

years, 0.96 in ten years, 0.94 in fifteen years, 0.92 in twenty years, and 0.91 in twentyfive years). The bottoms of the error bars were assumed to represent the more aggressive 

Advanced Technology Case (factors of 0.98 in five years, 0.95 in ten years, 0.92 in 

fifteen years, 0.90 in twenty years, and 0.89 in twenty-five years). Because the 

technology is already mature, the Advanced Technology Case only offers one or two 

percent savings over the Reference Technology Case. The resultant Advanced 

Technology capital cost (constant 2015 dollars) is shown below in Figure 3-2.

Figure 3-2. Residential Capital Costs – Wind Turbines – Advanced New 

Equipment (Constant 2015 $)

Year 2015 2020 2025 2030 2035 2040

Wind Turbine Equipment Cost 3,200 3,366 3,302 3,273 3,330 3,501

Total Installed Cost ($/kW) 8,400 8,232 7,980 7,728 7,560 7,476

Table 3-13 presents the variable O&M costs for wind turbines in the future years, 

maintaining the 10 kW output capacity.
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Table 3-13. Residential O&M - Wind – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 10.00 10.00 10.00 10.00 10.00 10.00

Capacity Factor (%) 27.0 27.0 27.0 27.0 27.0 27.0

Hours of Operation (hrs) 2,365 2,365 2,365 2,365 2,365 2,365

Variable O&M Costs ($/kWh) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year) 0.0023 0.0026 0.0029 0.0033 0.0038 0.0043

Table 3-14 presents Advanced Technology capital costs based on the above discussion 

and reference case allocation of capital costs.

Table 3-14. Residential Capital Costs - Wind – Advanced New Equipment(2)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 3,200 3,366 3,302 3,273 3,330 3,501

Installation Labor and Materials ($/kW) 5,200 5,772 6,176 6,732 7,338 7,998

Engineering/Construction Management/Contingency (1) - - - - - -

Total Installed Cost ($/kW) 8,400 9,138 9,478 10,005 10,668 11,499

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

(2) Costs presented are in current dollars.

3.3 Residential – Fuel Cell System (RFC)

3.3.1 Equipment and Systems

The Residential Fuel Cell System (RFC) is evaluated in this section of the report.

3.3.2 Technology Specifications

For the purposes of the analysis, a typical 10-kW RFC, readily available in the 

commercial marketplace and utilizing proton exchange membrane (PEM) technology,

was considered. PEMFC is currently the technology of choice for small scale residential 

applications with 40,000+ installations in Japan.8 The RFC is assumed to be equipped 

with a remote monitoring system whose purpose is to provide real time and historical 

production data of the facility along with alarm functionality in the event system or 

equipment anomalies occur. The RFC is also assumed to be equipped with remote 

starting and stopping capabilities along with on-board automatic control functionality,

which allow for continuous unmanned operations.

3.3.3 Capital Cost Estimate

The base Cost Estimate for the RFC Facility with a nominal capacity of 10 kW is 

$11,989/kW (2015 dollars). 

The cost estimate for the RFC 10 kW assumes having a small site adjacent to the end 

use. The RFC requires a residential back yard site to accept underground utilities such 

 8 Fuel Cells for Stationary Applications, ETSAP, January 2013.

http://ieaetsap.org/web/Highlights%20PDF/E13_STFuel%20Cells_%20AH_Jan2013_Final_GSOK%201.pdf
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3-10 Leidos, Inc. File: EIA | 209089

as water, gas, electric, sewage, drainage, etc. The RFC equipment price was obtained 

from in-house information gathered from a manufacturer, and to be used for budgetary 

purposes only. Peripheral electrical equipment necessary to complement the residential 

power plant needs has been added to the estimate. The cost estimate includes site 

preparation, gas line tapping costs, structures, equipment, electrical, distributable cost, 

engineering and design and subcontractor fee and budget contingency. All numbers in 

these estimates are based on prices and wages for the Gulf Coast Region of the U.S.

Costs for other EMM regions can be estimated based on the regional multiplication 

factors listed in Table 2-4.

Table 3-15 summarizes the Cost Estimate categories for the RFC facility.

Table 3-15. Base Plant Site Capital Cost Estimate for RFC

Technology: RFC

Nominal Capacity (ISO): 10 kW

Nominal Heat Rate (ISO): 7,491 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 7,045

Installation – Labor and Materials 3,705

Engineering, Construction Management, and Contingency(1) 1,239

Total Project EPC 11,989

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

3.3.4 O&M Estimate

The major maintenance expenses are included with the VOM expense for this 

technology and are given on an average basis across the kW-hours (kWh) incurred. 

Typically, significant overhauls on a RFC facility occur no less frequently than 

16,000 operating hour intervals and the expenses associated with such intervals are 

primarily related to restacking fees. Normal course of business expenses (fixed and 

variable) would be associated with routine scheduled and unscheduled maintenance, 

and those costs associated with remote monitoring. Table 3-16 presents the O&M 

expenses for the RFC facility.

Table 3-16. O&M Expenses for RFC

Technology: Conventional RFC

Fixed O&M Expense $332.00/kW-year

Variable O&M Expense $0.065/kWh
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3.3.5 Reference Technologies Projections

The following tables present the performance characteristics and cost projections for 

RFC.

Table 3-17. Residential O&M - Fuel Cell – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 10 10 10 10 10 10

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh)(2) 8,533 8,448 8,363 8,280 8,197 8,115

Electric Efficiency, HHV (%) 40.0 40.4 40.8 41.2 41.6 42.1

Fuel Input (MMBtu/hr) 0.085 0.084 0.084 0.083 0.082 0.081

Thermal Output (MMBtu/hr) 0.035 0.035 0.034 0.034 0.034 0.033

Total CHP Efficiency (%) 81.0 81.4 81.8 82.2 82.7 83.1

Power to Thermal Output Ratio 0.98 0.98 0.99 1.00 1.02 1.03

Net Heat Rate (Btu/kWh) 6,201 6,228 6,167 6,106 6,045 5,985

Variable O&M Costs ($/kWh)(3) 0.065 0.074 0.083 0.094 0.107 0.121

Fixed O&M Costs ($/kW-year) (3) 332 375.63 424.99 480.83 544.02 615.51

(1) Assumes new system installed every five years.

(2) Heat rate improvement projected to be 1% per 5 years

(3) Variable and Fixed O&M costs represented in current dollars. Assumed to increase 2.5%/year.

Table 3-18. Residential O&M - Fuel Cell – 2015 Degraded Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 10 9.5 9.4 8.9 8.8 8.4

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 8,533 8,982 9,072 9,550 9,646 10,154

Electric Efficiency, HHV (%) 40.00 38.00 37.62 35.74 35.38 33.61

Fuel Input (MMBtu/hr) 0.085 0.085 0.085 0.085 0.085 0.085

Thermal Output (MMBtu/hr) 0.035 0.037 0.037 0.039 0.040 0.042

Total CHP Efficiency (%) 81 79 78.6 76.7 76.4 74.6

Power to Thermal Output Ratio 0.98 0.93 0.92 0.87 0.86 0.82

Net Heat Rate (Btu/kWh) 6,201 6,622 6,689 7,041 7,112 7,486

Variable O&M Costs ($/kWh)(2) 0.065 0.077 0.089 0.106 0.121 0.143

Fixed O&M Costs ($/kW-year) (2) 332.00 395.40 452.11 540.26 618.21 732.75

(1) Assumes system installation in 2015, with O&M performed to maintain system over its 25-year lifetime.

(2) Variable and Fixed O&M costs represented in current dollars.

Assumptions used in the preparation of Table 3-18 would include an assumed CF of 

93 percent, a standard commercially available fuel supply with typical heating values 

associated with those of pipeline quality natural gas and standard overhaul cycles 

inclusive of those expenses related to restacking which would typically occur on a 

7-year cycle given the assumed CF.
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Table 3-19. Residential Capital Costs - Fuel Cell – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 7,045 6,256 5,690 5,582 5,780 5,985

Installation Labor and Materials ($/kW)(3) 3,705 3,907 3,971 4,112 4,258 4,410

Engineering/Construction Management/ 

Contingency(4,5)

1,239 1,238 1,192 1,169 1,147 1,125

Total Installed Cost ($/kW) 11,989 11,401 10,853 10,863 11,185 11,520

(1) Costs presented are in current dollars.

(2) Real cost reduction assumed to be 4 %/year through 2020, 3%/yr through 2025, 2%/yr through 2030, 1 %/yr through 2035, 

1 %/yr through 2040

(3) Real cost reduction assumed to be 1%/year

(4) Real cost reduction assumed to be 2 %/ yr

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

3.3.6 Advanced Technologies Projections

Advance fuel cell equipment cost reductions accompany growth in production rates and 

will generally reflect “learning by doing.” Less mature technologies experience more 

substantial cost reductions than more mature technologies. The manufacturing of 

residential and commercial PEMFC systems has been a less mature technology in the 

U.S., but Japanese installations have resulted in hundreds of thousands of installations 

over the last ten years.9 Cost reductions have accompanied the increased production and 

translated to other parts of Asia and Europe. Future cost reductions for all sizes of 

PEMFC10 are expected based on:

• Designs that reduce the system complexity

• Elimination of fuel processing stages

• Reduction in catalyst content

• Increases in power density

• Standardization of minor components among manufacturers

• Mass production techniques

• Mass production economies-of-scale

Fuel cell efficiency projections are based on DOE Fuel Cell Technologies Office MultiYear Research, Development, and Demonstration Plan, updated as of November 201411

covering 1–10 kWe residential combined heat and power and distributed generation fuel 

cell systems operating on natural gas. The following performance targets were 

specified:

• 2015: 42.5% efficiency (LHV basis) or 38.6% (HHV basis)

o CHP Efficiency 87.5%; Operating lifetime 40,000 hrs

• 2020: > 45% efficiency (LHV basis) or > 40.6% (HHV basis)

 9 Staffell and Green, 2013 10 Dodds et al., 2015 11 http://energy.gov/eere/fuelcells/downloads/fuel-cell-technologies-office-multi-year-researchdevelopment-and-22
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o CHP Efficiency 90.0%; Operating lifetime 60,000 hrs

The efficiency projection assumptions for the remaining years in the projection are:

• 2025: 2.5% reduction from 2020 value

• 2030: 3% reduction from 2025 value

• 2035: 3.5% reduction from 2030 value

• 2040: 4% reduction from 2035 value

Based on historical data and model projections from multiple recent references, the total 

equipment prices of PEMFC systems are compared in Figure 3-4 with their full 

equipment system prices in the reference year.12 Differences between the data points 

may be attributed to geography, time periods, differences in market growth 

assumptions, and other factors.

Figure 3-3. Literature Descriptions of PEMFC Price Reductions over Time

The best logarithmic fit to those data points is also shown in Figure 3-5. This 

investigation used the best logarithmic fit to determine the costs in future years relative 

to the costs in 2015 (factors of 0.44 in 2020, 0.31 in 2025, 0.22 in 2030, 0.15 in 2035, 

and 0.10 in 2040). The resultant Advanced Technology costs are shown in Figure 3-5.

Figure 3-4. Residential Capital Costs – Fuel Cell – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Total System Equipment Cost ($/kW) 7,045 3,100 2,184 1,550 1,057 705

Expressed in constant 2015 dollars

As discussed previously, the major maintenance expenses are included with the VOM 

expense for this technology and are given on an average basis across the MW-hours

(MWh) incurred. Typically, significant overhauls on a RFC facility are assumed to 

 12 Reference years range from 2003 to 2013. Historical values are shown as points and modeled values 

as line segments.
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occur no less frequently than 16,000 operating hour intervals in 2015 and the expenses 

associated with such intervals are primarily related to restacking fees. These overhauls 

are projected to occur less frequently as follows:

• 2020: 20,000 hours

• 2025: 24,000 hours

• 2030: 28,000 hours

• 2035: 30,000 hours

• 2040: 32,000 hours

Normal course of business expenses (fixed and variable) would be associated with 

routine scheduled and unscheduled maintenance, and those costs associated with 

remote monitoring. 

Table 3-20. Residential O&M - Fuel Cell – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW)(1) 10 10 10 10 10 10

Electric Heat Rate, HHV (Btu/kWh) 8,533 8,362 8,153 7,909 7,632 7,327

Electric Efficiency, HHV (%)(2) 40.0 40.8 41.9 43.2 44.7 46.6

Fuel Input (MMBtu/hr) 0.090 0.084 0.082 0.079 0.076 0.073

Thermal Output (MMBtu/hr) 0.035 0.034 0.033 0.032 0.031 0.030

Total CHP Efficiency (%) 81 81.83 82.88 84.17 85.74 87.60

Power to Thermal Output Ratio 0.98 1.00 1.02 1.05 1.09 1.14

Net Heat Rate (Btu/kWh) 6,200 5,618 5,478 5,314 5,128 4,922

Variable O&M Costs ($/kWh) 0.065 0.068 0.075 0.083 0.090 0.098

Fixed O&M Costs ($/kW-year) 332 317.74 370.67 428.34 516.59 586.43

(1) Output capacity maintained constant

(2) See description on page 3-13

Table 3-21. Residential Capital Costs - Fuel Cell – Advanced New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 7,045 3,441 2,594 2,006 1,491 1,084

Installation Labor and Materials ($/kW)(3) 3,705 3,701 3,564 3,497 3,430 3,365

Engineering/Construction Management/ 

Contingency(4,5)

1,239 1,238 1,192 1,169 1,147 1,125

Total Installed Cost ($/kW) 11,989 8,380 7,350 6,672 6,068 5,574

(1) Costs presented are in current dollars.

(2) See Figure 3-5 for real cost reduction factors relative to baseline cost

(3) Real cost reduction assumed to be 2%/year

(4) Real cost reduction assumed to be 2 %/ yr

(5) Includes engineering, distributable costs, scaffolding, construction management, and start-up..
File: EIA | 209089

Section 4

COMMERCIAL

4.1 Commercial – Small Solar Photovoltaic System (CSS)

4.1.1 Equipment and Systems

This section describes the Commercial – Small Solar Photovoltaic system (CSS), for 

which we have assumed an installed PV module capacity of 52 kW-DC and an installed 

inverter capacity of 40 kW. The assumed system has a DC to AC capacity of 1.3, which 

within the range typically seem for commercial rooftop installations. Unless otherwise 

noted, “kW-DC” refers to DC capacity and “kW” refers to AC capacity.

4.1.2 Technology Specifications

For the purposes of the analysis, a standard ballasted, rooftop mounted, fixed tilt 

photovoltaic array utilizing polycrystalline panels readily available in the commercial 

marketplace was considered. The array is assumed to be equipped with string level 

inverters and a remote monitoring system whose purpose is to provide real time and 

historical production data of the facility along with alarm functionality in the event 

system or equipment anomalies occur. A facility of this type is typically unmanned,

and monitoring and alarm functionality is assumed to be remote in nature.

Standard PV modules have a ten-year materials and workmanship warranty, and a 25 

year linear power warranty. String inverters typically have a ten-year warranty, with 

extensions to cover 20 years total. With these warranty terms in mind, we have assumed 

25 years as the lifetime for the PV modules and 15 years as the lifetime for the string 

inverters. Certain micro-inverters and DC optimizers are available with 25-year 

warranties.

For cost projections, we have considered module efficiency as the main driver of cost 

reductions over time. In the reference technologies case, our projection assumes the use 

of p-type crystalline silicon, with a switch to n-type crystalline silicon in 2025. The 

switch to n-type silicon allows for higher efficiencies and a lower degradation rate in 

the first year of operation from the elimination of light induced degradation. PV 

modules utilizing n-type silicon are available today, but are not widely adopted in the 

market. With time and scale, this technology may see wider adoption.

The advanced technologies case assumes a 5-year acceleration in module efficiency 

improvements from the reference technologies case, with a new, higher efficiency PV 

module technology introduced in 2030. Generally, to be adopted, the new technology 

should have both higher efficiency and lower manufacturing costs. Heterojunction and 

multi-junction cells show higher efficiencies relative to standard devices; however, the 

manufacturing costs for these technologies are also higher. Over time, technological or 

manufacturing innovations may drive the costs down far enough to enable wider 

adoption in the marketplace.
Section 4

4-2 Leidos, Inc. File: EIA | 209089

4.1.3 Capital Cost Estimate

The base Cost Estimate for the Commercial – Small Solar Photovoltaic system (CSS)

with a nominal capacity of 40 kW-AC is $2,750/kW-AC (2015 dollars).

The cost estimate for the CSS, Roof Top, 40 kW, 52 kW-DC, assumes being installed 

on commercial building roofs, that can lend the roof orientation to satisfy maximum 

efficiency of solar irradiancy, usually having a footprint of the structure roof surface 

area. The cost estimate is based on in-house numbers from actual quotations for work 

already installed. Peripheral electrical equipment necessary to complement the 

intermittent power plant needs has been added to the estimate. The cost estimate 

includes site preparation, structures, equipment, electrical, distributable cost, 

engineering and design and subcontractor fee and budget contingency. All numbers in 

these estimates are based on prices and wages for the Gulf Coast Region of the U.S. 

Costs for other EMM regions can be estimated based on the regional multiplication 

factors listed in Table 2-4.

Table 4-1 summarizes the Cost Estimate categories for the CSS facility. 

Table 4-1

Base Plant Site Capital Cost Estimate for CSS

Technology: CSS

Nominal Capacity (ISO)(1): 40 kW-AC

Nominal Heat Rate (ISO): N/A

Capital Cost Category

($/kW-AC)

(January 1, 2015 $)

PV Modules (2) 1,040

Racks 200

Inverters 200

Equipment Supply 1,440

Installation – Labor and Materials 1,000

Engineering/ Construction Management / Contingency (3) 310

Total Project EPC 2,750

(1) International Standards Organization (ISO).

(2) Capital cost assumes 52 kW-DC PV module capacity at a cost of $800/kW-DC, referenced to the 40 kW inverter capacity 

assumed for the CSS system.

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

4.1.4 O&M Estimate

Table 4-2 presents the O&M expenses for the CSS facility. Fixed O&M expenses for a

CSS will typically include those expenses associated with scheduled and unscheduled 

maintenance, washings and costs associated with remote monitoring. In some cases, 

major maintenance reserve funding (MMRF) is included, on a levelized basis, in the 

fixed costs for a CSS. For the purposes of our analysis, we have assumed $1.25/kW-yr 

as the amount utilized for the MMRF mechanism. There are typically no variable O&M 
COMMERCIAL

File: EIA | 209089 Leidos, Inc. 4-3

costs associated with a PV solar system, as the expenses do not typically vary with 

capacity factor.

Table 4-2

O&M Expenses for CSS

Technology: CSS

Fixed O&M Expense $19.75/kW-year

Variable O&M Expense N/A

4.1.5 Reference Technologies Projections

The following tables present the reference performance characteristics and cost 

projections for CSS.

Table 4-3

Commercial O&M - Small PV – Reference New Equipment (1,4)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 52 52 52 52 52 52

Inverter Capacity (kW-AC) 40 40 40 40 40 40

Capacity Factor (%) 17.0 17.0 17.0 17.0 17.0 17.0

Hours of Operation (hrs) 1,489 1,489 1,489 1,489 1,489 1,489

Module Efficiency (%) (2) 17.0 20.1 23.2 26.0 27.9 28.1

First Year Degradation (%) (2) 3.0 3.0 1.0 1.0 1.0 1.0

Module Life (years) 25 25 25 25 25 25

Inverter Life (years) (3) 15 20 25 25 25 25

Variable O&M Costs ($/kWh)(4) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(5) 19.75 22.34 25.26 28.57 32.32 36.55

(1) Assumes new system installed every five years.

(2) Assumes switch to n-type silicon wafers in 2025 (these will have lower first year degradation).

(3) String inverters generally come with a standard 10-year warranty, with warranty extensions available to 20-years. An inverter 

lifetime of 15-years has been assumed in 2015, improving to 25-years in 2025.

(4) There will be minimal O&M costs for residential inverters; the units are replaced if defective.

(5) Fixed O&M costs represented in current dollars.
Section 4

4-4 Leidos, Inc. File: EIA | 209089

Table 4-4

Commercial O&M - Small PV - 2015 Degraded Equipment (1)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 52.0 48.9 46.9 45.0 43.0 41.1

Inverter Capacity (kW) 40 37.6 36.1 34.6 33.1 31.6

Capacity Factor (%) 17.0 17.0 17.0 17.0 17.0 17.0

Hours of Operation (hrs) 1,489 1,489 1,489 1,489 1,489 1,489

Module Efficiency (%) 17 16.5 15.8 15.1 14.4 13.7

System Level Degradation (%) (2) 3.00 6.00 9.75 13.50 17.25 21.00

Module Life (years) 25 20 15 10 5 0

Inverter Life (years) (3) 15 10 5 15 10 5

Variable O&M Costs ($/kWh)(4) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(5) 19.75 23.77 27.99 33.03 248.06(6) 46.27

(1) Assumes system installation in 2015, with O&M performed to maintain system over its 25-year lifetime.

(2) Cumulative system level degradation, as referenced to the initial installed DC capacity of 52 kW-DC. Assumes 3 percent 

degradation in the first year of operation and 0.75 percent annually thereafter.

(3) Assumes the use of three-phase string inverters with a 20-year lifetime.

(4) There will be minimal O&M costs for commercial inverters; the units are replaced if defective.

(5) Fixed O&M costs represented in current dollars.

(6) Includes cost of new inverter

Table 4-5

Commercial Capital Costs - Small PV - Reference New Equipment(1,4)

Year 2015 2020 2025 2030 2035 2040

PV Modules ($/kW-DC) 800 751 696 677 688 744

PV Modules for CSS Reference Case ($/kW)(2) 1040 976 905 880 894 968

Racks 200 205 207 214 217 236

Inverters 200 205 207 214 217 236

Equipment ($/kW) 1,440 1,386 1,319 1,307 1,328 1,440

Installation Labor and Materials ($/kW) 1,000 939 870 846 860 931

Engineering/Construction Management/Contingency(3) 310 344 368 401 437 477

Total Installed Cost ($/kW) 2,750 2,669 2,558 2,555 2,625 2,848

(1) Capital cost of a new system installed every 5 years.

(2) PV module cost for CSS case assumes 52 kW-DC of PV module capacity at a cost of $800/kW-DC, referenced to a 40 kW 

inverter capacity system.

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

(4) Costs are presented as current dollars.
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File: EIA | 209089 Leidos, Inc. 4-5

4.1.6 Advanced Technologies Projections

The following tables present the performance characteristics and cost projections for 

advanced CSS. Module efficiency is assumed to increase at a faster rate compared to 

the reference case.

Table 4-6

Commercial O&M – Small PV – Advanced New Equipment(1,2)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 52.0 52.0 52.0 52.0 52.0 52.0

Inverter Capacity (kW) 40.0 40.0 40.0 40.0 40.0 40.0

Module Efficiency (%)(3) 17.0 23.2 27.8 30.9 32.5 33.1

First Year Degradation (%)(3) 3.0 1.0 1.0 0.5 0.5 0.5

Module Life (years) 25 25 25 25 25 25

Inverter Life (years)(4) 15 20 25 25 25 25

Variable O&M Costs ($/kWh)(5) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(6) 19.75 22.34 25.26 28.57 32.32 36.55

(1) For the advanced technologies reference case, module efficiency is assumed to increase at a faster rate compared to the 

reference case.

(2) Assumes new system installed every five years.

(3) Assumes switch to n-type silicon wafers in 2025 (these will have lower first year degradation).

(4) String inverters generally come with a standard 10-year warranty, with warranty extensions available to 20-years. An inverter 

lifetime of 15-years has been assumed in 2015, improving to 25-years in 2025.

(5) There will be minimal O&M costs for residential inverters; the units are replaced if defective.

(6) Fixed O&M costs represented in current dollars.

Table 4-7

Commercial Capital Costs – Small PV – Advanced New Equipment(1,4)

Year 2015 2020 2025 2030 2035 2040

PV Modules ($/kW-DC) 800 651 510 407 325 260

PV Modules for Advanced CSS Case ($/kW)(2) 1040 846 663 530 423 338

Racks 200 205 205 211 217 237

Inverters 200 205 205 211 217 237

Equipment ($/kW) 1,440 1,255 1,073 952 858 812

Installation Labor and Materials ($/kW) 1,000 813 726 712 739 790

Engineering/Construction Management/Contingency(3) 310 344 368 401 437 477

Total Installed Cost ($/kW) 2,750 2,413 2,167 2,065 2,035 2,078

(1) Capital cost of a new system installed every 5 years.

(2) Cost for 52 kW-DC of modules, referenced to the CSS inverter capacity of 40 kW.

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

(4) Costs are presented as current dollars.
Section 4

4-6 Leidos, Inc. File: EIA | 209089

4.2 Commercial – Large Solar Photovoltaic System (CLS)

4.2.1 Equipment and Systems

This section describes the Commercial – Large Solar Photovoltaic system (CLS), for 

which we have assumed an installed PV module capacity of 650 kW-DC and an installed 

inverter capacity of 500 kW. The assumed system has a DC to AC capacity of 1.3, 

which within the range typically seem for commercial rooftop installations. 

4.2.2 Technology Specifications

For the purposes of the analysis, a ballasted, rooftop-mounted, fixed-tilt photovoltaic 

array utilizing polycrystalline panels readily available in the commercial marketplace 

was considered for the CLS system. The array is assumed to be equipped with threephase string inverters and a remote monitoring system whose purpose is to provide real 

time and historical production data of the facility along with alarm functionality in the 

event system or equipment anomalies occur. A facility of this type is typically 

unmanned, and monitoring and alarm functionality is assumed to be remote in nature. 

Systems of this size may also use central inverters; however, string inverters can be 

mounted on the rooftop in close proximity to the PV modules. This can reduce 

installation costs compared to a central inverter, which may require a mounting pad in 

next to the building. Other specifications are the same as used for the CSS. 

4.2.3 Capital Cost Estimate

The base Cost Estimate for the CLS Facility with a nominal capacity of 500 kW is 

$2,505/kW – AC.

The cost estimate for the CLS system assumes being installed on commercial structures 

like warehouse or large retail store roofs without shadowing from other structures or 

vegetation with the orientation to satisfy maximum efficiency of solar irradiancy, 

usually having a footprint of the structure’s roof surface area. The cost estimate is based 

on in-house numbers from actual quotations for work already installed. Peripheral 

electrical equipment necessary to complement the intermittent power producer needs 

has been added to the estimate. The cost estimate includes site preparation, structures, 

equipment, electrical, distributable cost, engineering and design, and subcontractor fee 

and budget contingency. All numbers in these estimates are based on prices and wages 

for the Gulf Coast Region of the U.S. Costs for other EMM regions can be estimated 

based on the regional multiplication factors listed in Table 2-4.

Table 4-8 summarizes the Cost Estimate categories for the CLS System.
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File: EIA | 209089 Leidos, Inc. 4-7

Table 4-8

Base Plant Site Capital Cost Estimate for CLS Cost

Technology: CLS

Nominal Capacity (ISO)(1): 500 kW-AC

Nominal Heat Rate (ISO): N/A

Capital Cost Category

($/kW-AC)

(January 1, 2015 $)

PV Modules (2) 975

Racks 190

Inverters 190

Equipment Supply 1,355

Installation – Labor and Materials 900

Engineering, Construction Management, and Contingency(3) 250

Total Project EPC 2,505

(1) International Standards Organization (ISO).

(2) Capital cost assumes 650 kW-DC of PV module capacity at a cost of $750/kW-DC, referenced to the 500 kW inverter 

capacity assumed for the CLS system. 

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

4.2.4 O&M Estimate

Table 4-9 presents the O&M expenses for the CLS system. Fixed O&M expenses for 

an CLS might typically include those expenses associated with scheduled and 

unscheduled maintenance, washings and costs associated with remote monitoring. In 

some cases, MMRF is included, on a levelized basis, in the fixed costs for a CSS. For 

the purposes of our analysis, we have assumed $1.25/kW-year as the amount utilized 

for the MMRF mechanism. There are typically no variable O&M costs associated with 

a PV system, as the expenses do not typically vary with capacity factor.

Table 4-9

O&M Expenses for CLS system

Technology: CLS

Fixed O&M Expense $21.00/kW-year

Variable O&M Expense N/A

4.2.5 Reference Technologies Projections

The following tables present the reference performance characteristics and cost 

projections for CLS.
Section 4

4-8 Leidos, Inc. File: EIA | 209089

Table 4-10

Commercial O&M - Large PV – Reference New Equipment (1,4)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 650 650 650 650 650 650

Inverter Capacity (kW-AC) 500 500 500 500 500 500

Capacity Factor (%) 17.0 17.0 17.0 17.0 17.0 17.0

Hours of Operation (hrs) 1,489 1,489 1,489 1,489 1,489 1,489

Module Efficiency, (%)(2) 17.0 20.1 23.2 26.0 27.9 28.1

First Year Degradation (%) (2) 3.0 3.0 1.0 1.0 1.0 1.0

Module Life (years) 25 25 25 25 25 25

Inverter Life (years) (3) 15 20 25 25 25 25

Variable O&M Costs ($/kWh)(4) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(5) 21.00 23.75 26.86 30.38 34.36 38.86

(1) Assumes new system installed every five years.

(2) Assumes switch to n-type silicon wafers in 2025 (these will have lower first year degradation).

(3) String inverters generally come with a standard 10-year warranty, with warranty extensions available to 20-years. An 

inverter lifetime of 15-years has been assumed in 2015, improving to 25-years in 2025.

(4) There will be minimal O&M costs for residential inverters; the units are replaced if defective.

(5) Fixed O&M costs represented in current dollars.

Table 4-11

Commercial O&M - Large PV – 2015 Degraded Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 650 611 587 562 538 514

Inverter Capacity (kW) 500 500 500 500 500 500

Capacity Factor (%) 17.0 17.0 17.0 17.0 17.0 17.0

Hours of Operation (hrs) 1,489 1,489 1,489 1,489 1,489 1,489

Module Efficiency, (%) 17.0 16.0 15.3 14.7 14.1 13.4

System Level Degradation (%)(2) 3.0 6.0 9.8 13.5 17.3 21.0

Module Life (years) 25 20 15 10 5 0

Inverter Life (years) (3) 20 15 10 5 20 15

Variable O&M Costs ($/kWh)(4) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(5) 21.00 25.27 29.76 35.12 248.03(6) 49.19

(1) Assumes system installation in 2015, with O&M performed to maintain system over its 25-year lifetime.

(2) Cumulative system level degradation, as referenced to the initial installed DC capacity of 650 kW-DC. Assumes 3 percent 

degradation in the first year of operation and 0.75 percent annually thereafter.

(3) Assumes the use of three-phase string inverters with a 20-year lifetime.

(4) There will be minimal O&M costs for commercial inverters; the units are replaced if defective.

(5) Fixed O&M costs represented in current dollars

(6) Includes the cost of a new inverter
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Table 4-12

Commercial Capital Costs - Large PV – Reference New Equipment(1,4)

Year 2015 2020 2025 2030 2035 2040

PV Modules ($/kW-DC) 750 704 653 635 645 698

PV Module Cost for CLS Reference Case ($/kW)(2) 975 915 849 825 838 907

Racks 190 194 194 200 207 225

Inverters 190 194 194 200 207 225

Equipment ($/kW) 1,355 1,304 1,237 1,226 1,251 1,357

Installation Labor and Materials ($/kW) 900 845 783 762 774 837

Engineering/Construction Management/Contingency(3) 250 278 297 324 353 385

Total Installed Cost ($/kW) 2,505 2,427 2,318 2,311 2,378 2,579

(1) Capital cost of a new system installed every 5 years.

(2) PV module cost for CSS case assumes 650 kW-DC of PV module capacity at a cost of $750/kW-DC, referenced to a 500 

kW inverter capacity system.

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

(4) Costs are presented as current dollars.

4.2.6 Advanced Technologies Projections

The following tables present the performance characteristics and cost projections for 

advanced CSS. Module efficiency is assumed to increase at a faster rate compared 

to the reference case.

Table 4-13

Commercial O&M- Large PV – Advanced New Equipment(1,2)

Year 2015 2020 2025 2030 2035 2040

Module Capacity (kW-DC) 650 650 650 650 650 650

Inverter Capacity (kW) 500 500 500 500 500 500

Module Efficiency (%)(3) 17.0 23.2 27.8 30.9 32.5 33.1

Module Life (years) 25 25 25 25 25 25

First Year Degradation (%)(3) 3.0 1.0 1.0 0.5 0.5 0.5

Inverter Life (years)(4) 15 20 25 25 25 25

Variable O&M Costs ($/kWh)(5) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(6) 21.00 23.75 26.86 30.38 34.36 38.86

(1) For the advanced technologies reference case, module efficiency is assumed to increase at a faster rate compared to 

the reference case.

(2) Assumes new system installed every five years.

(3) Assumes switch to n-type silicon wafers in 2025 (these will have lower first year degradation).

(4) String inverters generally come with a standard 10-year warranty, with warranty extensions available to 20-years. An 

inverter lifetime of 15-years has been assumed in 2015, improving to 25-years in 2025.

(5) There will be minimal O&M costs for residential inverters; the units are replaced if defective.

(6) Fixed O&M costs represented in current dollars.
Section 4

4-10 Leidos, Inc. File: EIA | 209089

Table 4-14

Commercial Capital Costs - Large PV – Advanced New Equipment(1,4)

Year 2015 2020 2025 2030 2035 2040

PV Modules ($/kW-DC) 750 610 545 529 554 592

PV Module Cost for Advanced CLS Case ($/kW)(2) 975 793 708 688 721 770

Racks 190 194 194 200 207 225

Inverters 190 194 194 200 207 225

Equipment ($/kW) 1,355 1,182 1,097 1,088 1,134 1,220

Installation Labor and Materials ($/kW) 900 732 654 635 665 711

Engineering/Construction Management/Contingency(3) 250 278 297 324 353 385

Total Installed Cost ($/kW) 2,505 2,192 2,048 2,047 2,152 2,316

(1) Capital cost of a new system installed every 5 years.

(2) Cost for 650 kW-DC of modules, referenced to the CSS inverter capacity of 500 kW.

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

(4) Costs are presented as current dollars.

4.3 Commercial – Wind System (CWS)

4.3.1 Equipment and Systems

The Commercial Wind System (CWS) produces 100 kW of electricity using a single 

wind turbine.

4.3.2 Technology Specifications

For the purposes of the analysis, a typical 100-kW commercial-type wind turbine readily 

available in the commercial marketplace was considered. The turbine is assumed to be 

equipped with a locally mounted inverter (if applicable), a remote monitoring system 

whose purpose is to provide real time and historical production data of the facility along 

with alarm functionality in the event system or equipment anomalies occur. The CWS 

is also assumed to be equipped with remote starting and stopping capabilities along with 

automatic furling functionality in the event that high wind speed events occur. A facility 

of this type is typically unmanned, and monitoring and alarm functionality is assumed 

to be remote in nature.

4.3.3 Capital Cost Estimate

The base Cost Estimate for the CWS with a nominal capacity of 100 kW is $5,900/kW.

The cost estimate for the CWS 100 kW assumes having a small site adjacent to the end 

use (rural area). The cost estimate requires a site able to accept underground utilities 

such as electric and communications controls. The CWS equipment price was obtained 

from a quotation by a small wind turbine generator manufacturer, and to be used for 

budgetary purposes only. Peripheral electrical equipment necessary to complement the 

commercial wind turbine power generation needs has been added to the estimate. The 

cost estimate includes site preparation, foundation structure, equipment, electrical, 

distributable cost, engineering and design, and subcontractor fee and budget 
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File: EIA | 209089 Leidos, Inc. 4-11

contingency. All estimated costs are expressed in $/kW. All numbers in these estimates 

are based on prices and wages for the Gulf Coast Region of the U.S.

Table 4-15 summarizes the Cost Estimate categories for the CWS facility. 

4.3.4 O&M Estimate

Table 4-16 presents the O&M expenses for the CWS system. For the purposes of our 

analysis we have taken into consideration those fixed expenses typically associated with 

a CWS system. There are typically no variable O&M costs associated with an RWS 

system as the O&M costs are typically fixed O&M costs for insurance, property taxes, 

site maintenance, legal fees, turbine warranty, and the remainder is tied to maintenance 

labor rates, royalties, remote monitoring, and other costs.

Table 4-16

O&M Expenses for CWS system

Technology: CWS

Fixed O&M Expense $0.0023/kW-year

Variable O&M Expense N/A

4.3.5 Reference Technologies Projections

The following tables present the performance characteristics and cost projections for 

CWS.

Table 4-17

Commercial O&M – Wind – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 100.0 100.0 100.0 100.0 100.0 100.0

Table 4-15

Base Plant Site Capital Cost Estimate for Commercial Wind System

Technology: CWS

Nominal Capacity (ISO)(1): 100 kW

Nominal Heat Rate (ISO): N/A

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 3,853

Installation – Labor and Materials 2,047

Engineering, Construction Management, and Contingency (1) -

Total Project EPC 5,900

(1) International Standards Organization (ISO)

(2) Includes engineering, distributable costs, scaffolding, construction management, and start-up. (Costs included in 

Installation – Labor and Materials above.)
Section 4

4-12 Leidos, Inc. File: EIA | 209089

Capacity Factor (%) 27.0 27.0 27.0 27.0 27.0 27.0

Hours of Operation (hrs) 2,365 2,365 2,365 2,365 2,365 2,365

Variable O&M Costs ($/kWh) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year)(2) 0.0023 0.0026 0.0029 0.0033 0.0038 0.0043

(1) Assumes new system installed every five years.

(2) Fixed O&M costs represented in current dollars.

Table 4-18

Commercial O&M – Wind - 2015 Degraded Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 100.0 99.7 99.3 99.0 98.7 98.4

Capacity Factor (%) 27.0 27.0 27.0 27.0 27.0 27.0

Hours of Operation (hrs) 2,365 2,365 2,365 2,365 2,365 2,365

Variable O&M Costs ($/kWh) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kWyear)(2) 0.0023

0.0026 0.0029 0.0033 0.0039 0.0044

(1) Assumes system installation in 2015, with O&M performed to maintain system over its 25-year lifetime.

(2) Fixed O&M costs represented in current dollars.

Table 4-19

Commercial Capital Costs - Wind – Reference New Equipment(2)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 3,853 4,191 4,395 4,695 5,015 5,357

Installation Labor and Materials ($/kW) 2,047 2,272 2,431 2,650 2,889 3,149

Engineering/Construction 

Management/Contingency (1) - - - - - -

Total Installed Cost ($/kW) 5,900 6,463 6,826 7,345 7,903 8,505

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

(2) Costs presented are in current dollars.

4.3.6 Advanced Technologies Projections

The manufacturing of wind turbines is generally considered a mature field. 

However, the DOE Energy Efficiency & Renewable Energy (ERRE) Program13

 13 Wiser, Ryan. “Wind Energy Cost, Performance and Pricing Trends: Past & Future.” Part of the StateFederal RPS Collaborative Webinar on December 17, 2013. Sponsored by CleanEnergy States Alliance 

and last accessed from http://www.cesa.org/assets/Uploads/RPS-Webinar-Presentation-Cost-andTechnology-Projections-for-Solar-and-Wind.pdf on April 9, 2015.
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expects that future cost reductions for onshore wind power technologies (ranging 

from residential to utility level) will be based on:

• Plant-level design and management aimed at optimizing production

• Advanced control systems

• Improved numerical methods to understand wind resources

• Blade innovations

• More reliable drivetrain technologies

• Better scaling to low-wind speed sites

Based on historical data and model projections from multiple recent references, the 

onshore wind turbine capital costs are compared in Figure 3-1with the capital costs 

in the reference year. Five of these more recent studies agreed well for the first 

twenty-five years beyond the study baseline.

Figure 4-1. Literature Descriptions of Wind Turbine Capital Cost Reductions 

Over Time

The average fractional capital costs from those five studies were determined at fiveyear increments, and average factors are shown in Figure 3-1 with error bars 

depicting one standard deviation in the numbers among those five studies. The tops 

of the error bars were considered to represent the Reference Technology Case 

(factors of 0.99 in five years, 0.96 in ten years, 0.94 in fifteen years, 0.92 in twenty 

years, and 0.91 in twenty-five years). The bottoms of the error bars were assumed 

to represent the more aggressive Advanced Technology Case (factors of 0.98 in five 

years, 0.95 in ten years, 0.92 in fifteen years, 0.90 in twenty years, and 0.89 in 

twenty-five years). Because the technology is already mature, the Advanced 

Technology Case only offers one or two percent savings over the Reference 

Technology Case. The resultant Advanced Technology capital cost (constant 2015 

dollars) is shown below in Figure 4-2.

Figure 4-2. Commercial Capital Costs – Wind Turbines – Advanced New 

Equipment

Year 2015 2020 2025 2030 2035 2040
Section 4

4-14 Leidos, Inc. File: EIA | 209089

Total Installed Cost ($/kW) 5,900 5,758 5,611 5,449 5,333 5,228

A 2008 DOE NREL report14 cites that fixed O&M costs are for insurance, property 

taxes, site maintenance, and legal fees, so these are expected to remain constant. 

Fifty percent of the variable O&M costs are for the turbine warranty, and the 

remainder is tied to labor rates, royalties, and other costs. As turbine reliability 

improves and the scale of wind turbines increases, the warranty costs (and associated 

variable O&M costs) are expected to drop. Three studies reported decreasing 

variable O&M costs in future years Figure 3-3.

Figure 4-3. Studies Reporting Variable O&M Cost Reductions – Wind 

Turbines

Study

Fraction of 2015 Variable O&M Costs

2015 2020 2025 2030 2035 2040

MiniCAM 2008 1.00 0.85 0.83 0.81 0.79 0.77

Logan et al., 2008 1.00 0.93 0.90 0.87 0.87 0.87

Mai et al., 2012 1.00 0.91 0.84 0.82 0.80 0.80

Logan’s numbers were the most conservative, so they were considered to represent 

the Reference Technologies Case. MiniCAM’s numbers were the most aggressive 

and thus associated with the Advanced Technologies Case. Table 3-13 presents the 

variable O&M costs for wind turbines in the future years, maintaining the 10 kW 

output capacity.

Table 4-20

Commercial O&M – Wind - Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 100.0 100 100 100 100 100

Capacity Factor (%) 27.0 27.0 27.0 27.0 27.0 27.0

Hours of Operation (hrs) 2,365 2,365 2,365 2,365 2,365 2,365

Variable O&M Costs ($/kWh) N/A N/A N/A N/A N/A N/A

Fixed O&M Costs ($/kW-year) 0.0023 0.0023 0.0024 0.0027 0.0030 0.0034

Table 4-21 presents Advanced Technology capital costs based on the above discussion 

and reference case allocation of capital costs.

 14 DOE National Renewable Energy Laboratory, 20% Wind Energy by 2030: Increasing Wind Energy’s 

Contribution to U.S. Electricity Supply. July 2008. DOE/GO-102008-2567. Last accessed from 

http://www.nrel.gov/docs/fy08osti/41869.pdf on April 9, 2015.
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Table 4-21

Commercial Capital Costs - Wind - Advanced New Equipment(2)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 3,853 4,119 4,233 4,404 4,637 4,893

Installation Labor and Materials ($/kW) 2,047 2,272 2,431 2,650 2,889 3,149

Engineering/Construction Management/Contingency (1)

Total Installed Cost ($/kW) 5,900 6,391 6,664 7,054 7,525 8,041

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

(2) Costs presented are in current dollars.

4.4 Commercial - Fuel Cell (CFC)

The Commercial Fuel Cell System (CFC) is evaluated in this section of the report.

4.4.1 Equipment and Systems

The Commercial Fuel Cell (CFC) facility utilizes one proton membrane type fuel cell 

unit, with a nominal power output of 200 kW. The fuel cells convert chemical energy 

directly into electricity from natural gas and air vapor and produce heat and water vapor 

as byproducts. The fuel (the reactant) is introduced continuously to the anode side of 

the unit cell while air (the oxidant) is introduced continuously into the cathode side via 

a blower. In a fuel cell, electricity is produced by ionic transfer across an electrolyte 

that separates the fuel from the air. A high temperature fuel cell produces electricity by 

splitting a molecule of the oxidant into its ionic components at the cathode, passing ions 

through the electrolyte (e.g., in the case of the CFC facility, a phosphoric acid ion) and 

then reacting the ions with the fuel at the anode to produce heat to allow the reaction to 

occur. During this ionic transfer process, two electrons are stripped from each ion to 

which develops a voltage and current. Since each fuel cell develops a relatively low 

voltage, the cells are stacked to produce a higher, more useful voltage. Depending on 

the type of fuel cell, high temperature waste heat from the process may be available for 

CHP applications.

Current examples of commercial-scale stationary fuel cells are8

:

Manufacturer Product Name Type Output

Ballard Power Systems 

(Canada) 

ClearGen PEM Multi-500 kW power 

banks 

Bloom Energy (U.S.) ES-5400 SOFC 100 kW 

ES-5700 SOFC 200 kW 

UPM-570 SOFC 160 kW 

ClearEdge Power (U.S.) PureCell System Model 400 PAFC 400 kW 

FuelCell Energy (U.S.) DFC 300 DFC 300 MCFC DFC 300 MCFC 300 kW M 

Fuji Electric (Japan) FP-100i PAFC 100 kW 
Section 4

4-16 Leidos, Inc. File: EIA | 209089

4.4.2 Technology Specifications

For the purposes of the analysis, a typical 200 kW CFC unit readily available in the 

commercial marketplace and utilizing proton exchange membrane technology was 

considered. The CFC is assumed to be equipped with a remote monitoring system 

whose purpose is to provide real time and historical production data of the facility along 

with alarm functionality in the event system or equipment anomalies occur. The CFC 

is also assumed to be equipped with remote starting and stopping capabilities along with 

on-board automatic control functionality, which allow for continuous unmanned 

operations. A unit of this type is typically unmanned, and monitoring and alarm 

functionality is assumed to be remote in nature.

The technology specifications for the CFC are presented in Table 4-22:

Table 4-22

Commercial – Fuel Cell – 200 kW

Life Cycle 2015

Output Capacity (kW) 200.0

Electric Heat Rate, HHV (Btu/kWh) 9,481

Electric Efficiency, HHV (%) 36.0

Fuel Input (MMBtu/hr) 1.90

Thermal Output (MMBtu/hr) 0.79

Total CHP Efficiency (%) 77.7

Power to Thermal Output Ratio 0.86

Net Heat Rate (Btu/kWh) 6,913

Variable O&M Costs ($/kWh) 0.045

Fixed O&M Costs ($/kW-year) 332.00

4.4.3 Capital Cost Estimate

The base Cost Estimate for the Commercial Fuel Cell facility with a nominal capacity 

of 200 kW is $5,458/kW (2015 dollars). The cost estimate for the CFC 200 kW assumes 

having a small site adjacent to the end use. A one-acre site is needed to be able to accept 

underground utilities such as water, gas, electric, sewage, drainage, etc. The CFC

equipment price was obtained from in-house information gathered from a manufacturer, 

and to be used for budgetary purposes only. Peripheral electrical equipment necessary 

to complement the commercial power plant needs has been added to the estimate. The 

cost estimate includes site preparation, gas line tapping costs, structures, equipment, 

electrical, distributable cost, engineering and design, and subcontractor fee and budget 

contingency. All estimated costs are expressed in $/kW. All numbers in these estimates 

are based on prices and wages for the Gulf Coast Region of the U.S. Costs for other 

EMM regions can be estimated based on the regional multiplication factors listed in 

Table 2-4.

Table 4-23 summarizes the Cost Estimate categories for the CFC facility.
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Table 4-23

Base Plant Site Capital Cost Estimate for CFC

Technology: CFC

Nominal Capacity (ISO): 200 kW

Nominal Heat Rate (ISO): 10,405 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 4,781

Installation – Labor and Materials 238

Engineering, Construction Management, and Contingency (1) 439

Total Project EPC 5,458

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

4.4.4 O&M Estimate

Table 4-24 presents the O&M expenses for the CFC system. Assumptions used in the 

preparation of Table 4-24 would include an assumed CF of 93 percent, a standard 

commercially available fuel supply with typical heating values associated with those of 

pipeline quality natural gas and standard overhaul cycles inclusive of those expenses 

related to restacking, which would typically occur on a 7-year cycle given the assumed 

CF. 

Table 4-24

O&M Expenses for CFC

Technology: CFC

Fixed O&M Expense $332.00/kW-year

Variable O&M Expense $0.045/kWh

4.4.5 Reference Technologies Projections

Table 4-25

Commercial O&M - Fuel Cell – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 200 200 200 200 200 200

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh)(2) 9,481 9,386 9,292 9,199 9,107 9,016

Electric Efficiency, HHV (%) 36.0 36.4 36.7 37.1 37.5 37.9

Fuel Input (MMBtu/hr) 1.90 1.88 1.86 1.84 1.82 1.80

Thermal Output (MMBtu/hr) 0.79 0.78 0.77 0.77 0.76 0.75

Total CHP Efficiency (%) 77.7 78.02 78.39 78.76 79.14 79.52

Power to Thermal Output Ratio 0.86 0.87 0.88 0.89 0.9 0.91

Net Heat Rate (Btu/kWh) 7,200 6,845 6,777 6,710 6,643 6,578

Variable O&M Costs ($/kWh)3 0.045 0.051 0.058 0.065 0.074 0.083

Fixed O&M Costs ($/kW-year)3 332.00 375.63 424.99 480.83 544.02 615.51

(1) Assumes new system installed every five years.

(2) Heat rate improvement projected to be 1% per 5 years

(3) Variable and Fixed O&M costs represented in current dollars. Costs escalated at 2.5%/year.
Section 4

4-18 Leidos, Inc. File: EIA | 209089

Table 4-26

Commercial O&M - Fuel Cell – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 200 190 188 179 177 168

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 9,481 9,980 10,080 10,611 10,718 11,282

Electric Efficiency, HHV (%) 36 34.2 33.9 32.2 31.8 30.3

Fuel Input (MMBtu/hr) 1.9 1.9 1.9 1.9 1.9 1.9

Thermal Output (MMBtu/hr) 0.79 0.79 0.79 0.79 0.79 0.79

Total CHP Efficiency (%) 77.7 75.9 75.5 73.8 73.5 71.9

Power to Thermal Output Ratio 0.86 0.82 0.81 0.77 0.76 0.73

Net Heat Rate (Btu/kWh) 6,913 7,277 7,351 7,737 7,816 8,227

Variable O&M Costs ($/kWh) 0.045 0.054 0.062 0.073 0.084 0.099

Fixed O&M Costs ($/kW-year) 332 395.40 452.11 537.25 614.71 732.75

Table 4-27

Commercial Capital Costs - Fuel Cell – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 4,781 4,192 3,768 3,656 3,745 3,838

Installation Labor and Materials 

($/kW)(3)

238 251 255 264 274 283

Engineering/Construction 

Management/ Contingency(4,5) 439 439 422 414 406 399

Total Installed Cost ($/kW) 5,458 4,882 4,446 4,334 4,425 4,520

(1) Costs presented are in current 2015 dollars.

(2) Real cost reduction assumed to be 4 %/year through 2020, 3%/yr through 2025, 2%/yr through 2030, 1 %/yr through 

2035, 1 %/yr through 2040

(3) Real cost reduction assumed to be 1%/year

(4) Real cost reduction assumed to be 2 %/ yr

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

4.4.6 Advanced Technologies Projections

Advance fuel cell equipment cost reductions accompany growth in production rates and 

will generally reflect “learning by doing.” Less mature technologies experience more 

substantial cost reductions than more mature technologies. The manufacturing of 

residential and commercial fuel cell systems has been a less mature technology, but 

Japanese installations have resulted in hundreds of thousands of installations over the 

last ten years. Cost reductions have accompanied the increased production and 

translated to other parts of Asia and Europe. Future cost reductions for all sizes of 

PEMFC are expected based on:
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• Designs that reduce the system complexity

• Elimination of fuel processing stages

• Reduction in catalyst content

• Increases in power density

• Standardization of minor components among manufacturers

• Mass production techniques

• Mass production economies-of-scale

Fuel cell efficiency projections are based on DOE Fuel Cell Technologies Office MultiYear Research, Development, and Demonstration Plan, updated as of November 201415

covering 100 kWe – 3 MWe commercial combined heat and power and distributed 

generation fuel cell systems operating on natural gas. The following performance 

targets were specified:

• 2015: 45% efficiency (LHV basis) or 40.9% (HHV basis)

o CHP Efficiency 87.5%; Operating lifetime 50,000 hrs

• 2020: > 50% efficiency (LHV basis) or > 45.1% (HHV basis)

o CHP Efficiency 90.0%; Operating lifetime 80,000 hrs

Since the commercial fuel cell efficiency for year 2015 was determined to be less than 

the DOE goal, the assumed 2020 improvement is assumed to be 4 percentage points 

higher in value. The efficiency projection assumptions for the remaining years in the 

projection are:

• 2025: 2.5% reduction from 2020 value

• 2030: 3% reduction from 2025 value

• 2035: 3.5% reduction from 2030 value

• 2040: 4% reduction from 2035 value

Based on historical data and model projections from multiple recent references, the total 

equipment prices of PEMFC systems are compared in Figure 4-4 with their full 

equipment system prices in the reference year.16 Differences between the data points 

may be attributed to geography, time periods, differences in market growth 

assumptions, and other factors.

The best logarithmic fit to those data points is also shown in Figure 4-5. This 

investigation used the best logarithmic fit to determine the costs in future years relative 

to the costs in 2015 (factors of 0.44 in 2020, 0.31 in 2025, 0.22 in 2030, 0.15 in 2035, 

and 0.10 in 2040). The resultant Advanced Technology costs are shown in Figure 3-5.

 15 http://energy.gov/eere/fuelcells/downloads/fuel-cell-technologies-office-multi-year-researchdevelopment-and-22 16 Reference years range from 2003 to 2013. Historical values are shown as points and modeled values 

as line segments.
Section 4

4-20 Leidos, Inc. File: EIA | 209089

Figure 4-4. Literature Descriptions of PEMFC Price Reductions over Time

Figure 4-5. Residential Capital Costs – Fuel Cell – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Total System Equipment Cost ($/kW) 5,458 3,011 2,412 1,691 1,344 1,350

Expressed in 2015 dollars

Table 4-28

Commercial O&M - Fuel Cell – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 200 200 200 200 200 200

Electric Heat Rate, HHV (Btu/kWh) 9,481 8,533 8,319 8,070 7,787 7,476

Electric Efficiency, HHV (%) 36.0 40.0 41.0 42.3 43.8 45.7

Fuel Input (MMBtu/hr) 1.90 1.71 1.66 1.61 1.56 1.50

Thermal Output (MMBtu/hr) 0.79 0.711 0.693 0.672 0.649 0.623

Total CHP Efficiency (%) 77.70 81.66 82.69 83.96 85.49 87.32

Power to Thermal Output Ratio 0.86 0.96 0.98 1.02 1.05 1.10

Net Heat Rate (Btu/kWh) 6,913 5,689 5,546 5,380 5,192 4,984

Variable O&M Costs ($/kWh) 0.045 0.046 0.051 0.055 0.061 0.066

Fixed O&M Costs ($/kW-year) 332 317.74 370.67 428.34 516.59 586.43
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Table 4-29

Commercial Capital Costs - Fuel Cell – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 4781 2,335 1,760 1,052 717 735

Installation Labor and Materials ($/kW) 238 238 229 225 220 216

Engineering/Construction Management/Contingency (1) 439.0 438.6 422.3 414.3 406.4 398.7

Total Installed Cost ($/kW) 5,458 3,011 2,412 1,691 1,344 1,350

(1) Costs presented are in current dollars.

(2) See Figure 4-5 for real cost reduction factors relative to baseline cost

(3) Real cost reduction assumed to be 2%/year

(4) Real cost reduction assumed to be 2 %/ yr

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

4.5 Commercial – Natural Gas Reciprocating Engine 

(CNE)

4.5.1 Equipment and Systems

The following describes the Commercial Natural Gas Reciprocating Engine (CNE), 

which is a nominal 300 kW net power output.

4.5.2 Technology Specifications

The technology specifications for the CNE are presented in Table 4-30:

Table 4-30

Commercial – Natural Gas Reciprocating Engine – 300 kW

Life Cycle 2015

Output Capacity (kW) 373.0

Electric Heat Rate, HHV (Btu/kWh) 10,405

Electric Efficiency, HHV (%) 32.8

Fuel Input (MMBtu/hr) 3,881

Thermal Output (MMBtu/hr) 1.809

Total CHP Efficiency (%) 79.4

Power to Thermal Output Ratio 0.704

Net Heat Rate (Btu/kWh) 4,343

Variable O&M Costs ($/kWh) 0.011

Fixed O&M Costs ($/kW-year) 20.00
Section 4

4-22 Leidos, Inc. File: EIA | 209089

4.5.3 Capital Cost Estimate

The base Cost Estimate for the CNE with a nominal capacity of 300 kW is $2,176/kW. 

The cost estimate for the CNE 300 assumes having a small site adjacent to the end use. 

A one-acre site is required to be cleared, leveled and conditioned to accept underground 

utilities such as water, gas, electric, sewage, drainage, just as what is found at any large 

facility. The CNE price was obtained as a budgetary quotation for estimating purposes 

only from a local diesel generator supplier. Peripheral electrical equipment necessary 

to complement the commercial power plant needs has been added to the estimate. The 

cost estimate includes site preparation, gas tapping costs, structures, equipment, 

electrical, distributable cost, engineering and design, and subcontractor fee and budget 

contingency. All estimated costs are expressed in $/kW. All numbers in these estimates 

are based on prices and wages for the Gulf Coast region of the U.S. 

Table 4-31 summarizes the Cost Estimate categories for the CNE facility.

Table 4-31

Base Plant Site Capital Cost Estimate for CNE

Technology: CNE

Nominal Capacity (ISO): 300 kW

Nominal Heat Rate (ISO): 10,405 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015$)

Equipment Supply 938

Installation – Labor and Materials 662

Engineering, Construction Management, and Contingency (1) 576

Total Project EPC 2,176

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

4.5.4 O&M Estimate

Table 4-32 presents the O&M expenses for the CNE facility.

Table 4-32

O&M Expenses for CNE - 300 kW

Technology: CNE

Fixed O&M Expense $20.00/kW-year

Variable O&M Expense $0.011/kWh
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4.5.5 Reference Technologies Projections

Table 4-33

Commercial O&M- Natural Gas Reciprocating Engine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 373 373 373 373 373 373

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV 

(Btu/kWh)

10,405 10,380 10,354 10,328 10,302 10,276

Electric Efficiency, HHV (%) 32.8 32.9 33.0 33.0 33.1 33.2

Fuel Input (MMBtu/hr) 3.881 3.872 3.862 3.852 3.843 3.833

Thermal Output (MMBtu/hr) 1.809 1.80 1.80 1.80 1.79 1.79

Total CHP Efficiency (%) 79.4 79.49 79.6 79.7 79.7 79.8

Power to Thermal Output Ratio 0.704 0.705 0.707 0.709 0.711 0.713

Net Heat Rate (Btu/kWh) 4,343 4,332 4,321 4,311 4,300 4,289

Variable O&M Costs ($/kWh)(1) 0.011 0.0124 0.0141 0.0159 0.0180 0.0204

Fixed O&M Costs ($/kW-year)(1) 20.00 22.63 25.60 28.97 32.77 37.08

(1) Costs presented are in current 2015 dollars. Costs escalated at 2.5% per year.

Table 4-34

Commercial O&M- Natural Gas Reciprocating Engine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 373 370 367 365 362 359

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV(Btu/kWh) 10,405 10,458 10,510 10,563 10,616 10,670

Electric Efficiency, HHV (%) 32.8 32.6 32.5 32.3 32.1 32.0

Fuel Input (MMBtu/hr) 3.881 3.872 3.862 3.852 3.843 3.833

Thermal Output (MMBtu/hr) 1.809 1.809 1.809 1.809 1.809 1.809

Total CHP Efficiency (%) 79.4 79.4 79.3 79.3 79.2 79.2

Power to Thermal Output Ratio 0.704 0.698 0.693 0.688 0.683 0.678

Net Heat Rate (Btu/kWh) 4,343 4,350 4,356 4,363 4,369 4,375

Variable O&M Costs ($/kWh) 0.011 0.013 0.014 0.016 0.019 0.021

Fixed O&M Costs ($/kW-year) 20 22.80 25.99 29.63 33.77 38.50
Section 4

4-24 Leidos, Inc. File: EIA | 209089

Table 4-35

Commercial Capital Costs - Natural Gas Reciprocating Engine –

Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 938 1,039 1,109 1,205 1,311 1,425

Installation Labor and Materials ($/kW)(3) 662 735 786 857 934 1,018

Engineering/Construction 

Management/Contingency (4,5) 576 639 684 746 813 886

Total Installed Cost ($/kW) 2,176 2,413 2,579 2,808 3,057 3,329

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

4.5.6 Advanced Technologies Projections

Compared to most other technologies discussed in this report, the reciprocating engine 

technology is considered very mature technology. Some advances continue to be made

on these power generators (e.g., laser ignition which has been shown to increase 

efficiency). However, reducing installation costs is not the primary focus area. The DOE 

Advanced Reciprocating Engine System (ARES) program17 aims to achieve 50% brake 

thermal efficiency (80+% with CHP), a maximum of 0.1 g/bhp-hr NOx emissions, 

maintenance cost below $0.01/EkW-hr, and a continued cost competitiveness. Two of 

the three industry partners (Caterpillar and GE Dresser Waukesha) withdrew from the 

ARES program based on business considerations with regard to distributed energy 

technologies.

Cost reductions historically accompany the deployment of a technology from one sales 

volume to a relatively higher sales volume, but millions of reciprocating engines have 

already been produced over the last century. The reciprocating engines also compete 

with the renewable technologies, NGCCs, and other electricity generators in the 

electricity market, but do not appear to grow in significant numbers in modeling results 

because of their costs relative to other technologies. In five simulations for EPRI in 

2013, the unit capital costs ($/kW) did not drop from 2015 levels until the year 2045.18

Advances in other electricity-generating technologies may also improve the efficiency 

of reciprocating engines. For example, fifty research projects at DOE NETL address 

hydrogen turbines. Natural gas turbines and reciprocating engines operating in CHP 

systems, which meet regulatory emission requirements, could also benefit from the 

 17 DOE EERE, 2015. “Advanced Reciprocating Engine System (ARES).” Last accessed at 

http://www.energy.gov/eere/amo/downloads/advanced-reciprocating-engine-system-ares on April 22, 

2015.

18 Azevedo, I. P. Jaramillo, E. Rubin, and S. Yeh. Modeling Technology Learning for Electricity Supply 

Technologies. Phase II Report to Electric Power Research Institute. June 2013. Last accessed from 

http://www.cmu.edu/epp/iecm/rubin/PDF%20files/2013/FINAL%20PHASE%20II%20REPORT%20T

O%20EPRI_June%2030.pdf on April 22, 2015.
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improvements in combined cycle units. However, their current deployment is more 

often for peaking or emergency conditions (because of the short startup times), thus 

extending the expected payback periods for these units.

Because of the uncertainties associated with a competitive marketplace environment 

and the general acknowledgement that these technologies are very mature, the advanced 

technology cases for natural gas turbines and reciprocating engines were not assumed 

to have lower unit costs ($/kW) than those in the reference cases. Modest efficiency 

improvements of 2% lower than the reference case value are assumed to account for 

general improvements.

Table 4-36

Commercial O&M- Natural Gas Reciprocating Engine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 373 373 373 373 373 373

Electric Heat Rate, HHV (Btu/kWh) 10,405 10,172 10,147 10,121 10,096 10,070

Electric Efficiency, HHV (%) 32.8 33.6 33.6 33.7 33.8 33.9

Fuel Input (MMBtu/hr) 3.881 3.794 3.785 3.775 3.766 3.756

Thermal Output (MMBtu/hr) 1.809 1.77 1.76 1.76 1.76 1.75

Total CHP Efficiency (%) 79.4 80.2 80.2 80.3 80.4 80.5

Power to Thermal Output Ratio 0.704 0.720 0.722 0.723 0.725 0.727

Net Heat Rate (Btu/kWh) 4,343 4,246 4,235 4,225 4,214 4,203

Variable O&M Costs ($/kWh) 0.011 0.012 0.014 0.016 0.018 0.020

Fixed O&M Costs ($/kW-year) 20 22.63 25.60 28.97 32.77 37.08

(1) Costs presented are in current 2015 dollars

Table 4-37

Commercial Capital Costs - Natural Gas Reciprocating Engine –

Advanced New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 938 1,039 1,109 1,205 1,311 1,425

Installation Labor and Materials ($/kW)(3) 662 735 786 857 934 1,018

Engineering/Construction Management/Contingency (4,5) 576 639 684 746 813 886

Total Installed Cost ($/kW) 2,176 2,413 2,579 2,808 3,057 3,329

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

(5) Includes engineering, distributable costs, scaffolding, construction management, and start-up.
Section 4

4-26 Leidos, Inc. File: EIA | 209089

4.6 Commercial – Oil Reciprocating Engine (COE)

4.6.1 Equipment and Systems

The plant configuration for the Oil Reciprocating Engine (COE) system case produces 

300 kW of net power.

4.6.2 Technology Specifications

The technology specifications for the COE are presented in Table 4-38:

Table 4-38

Commercial – Oil Reciprocating Engine – 300 kW

Life Cycle 2015

Output Capacity (kW) 340.0

Electric Heat Rate, HHV (Btu/kWh) 10,348

Electric Efficiency, HHV (%) 33.0

Fuel Input (MMBtu/hr) 3.518

Thermal Output (MMBtu/hr) 1.554

Total CHP Efficiency (%) 77.2

Power to Thermal Output Ratio 0.747

Net Heat Rate (Btu/kWh) 4,635

Variable O&M Costs ($/kWh) 0.020

Fixed O&M Costs ($/kW-year) 24.00

4.6.3 Capital Cost Estimate

The base Cost Estimate for the COE system with a nominal capacity of 300 kW is 

$2,016/kW. 

The cost estimate for the COE 300 kW assumes having a small site adjacent to the end 

use. A one-acre site is required to be cleared, leveled and conditioned to accept 

underground utilities such as water, gas, electric, sewage, drainage, just as what is found 

at any large facility. The COE price was obtained as a budgetary quotation for 

estimating purposes only from a local diesel generator supplier. Peripheral electrical 

equipment necessary to complement the commercial power plant needs has been added 

to the estimate.

Included in the estimate are site preparation, Diesel fuel tank, structures, equipment, 

electrical, distributable cost, engineering and design and subcontractor fee and budget 

contingency. All estimated costs are expressed in $/kW. All numbers in these estimates 

are based on prices and wages for the Gulf Coast Region of the U.S. 

Table 4-39 summarizes the Cost Estimate categories for the COE system.
COMMERCIAL

File: EIA | 209089 Leidos, Inc. 4-27

Table 4-39

Base Plant Site Capital Cost Estimate for COE

Technology: COE

Nominal Capacity (ISO): 300 kW

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

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 780

Installation – Labor and Materials 660

Engineering, Construction Management, and Contingency (1) 576

Total Project EPC 2,016

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

4.6.4 O&M Estimate

Table 4-40 presents the O&M expenses for the COE system.

Table 4-40

O&M Expenses for COE

Technology: COE

Fixed O&M Expense $24.00/kW-year

Variable O&M Expense $0.020/kWh
Section 4

4-28 Leidos, Inc. File: EIA | 209089

4.6.5 Reference Technologies Projections

Table 4-41

Commercial O&M - Oil Reciprocating Engine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 340.0 340.0 340.0 340.0 340.0 340.0

Capacity Factor (%) 93.0 93.0 93.0 93.0 93.0 93.0

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV 

(Btu/kWh)

10,348 10,311 10,296 10,280 10,249 10,219

Electric Efficiency, HHV (%) 33 33.1 33.15 33.2 33.3 33.4

Fuel Input (MMBtu/hr) 3.518 3.506 3.501 3.495 3.485 3.474

Thermal Output (MMBtu/hr) 1.554 1.548 1.546 1.544 1.539 1.535

Total CHP Efficiency (%) 77.2 77.27 77.3 77.4 77.5 77.6

Power to Thermal Output Ratio 0.747 0.749 0.751 0.752 0.754 0.756

Net Heat Rate (Btu/kWh) 4,635 4,618 4,611 4,604 4,591 4,577

Variable O&M Costs ($/kWh) 0.020 0.023 0.026 0.029 0.033 0.037

Fixed O&M Costs ($/kW-year) 24.00 27.15 30.72 34.76 39.33 44.49

Table 4-42

Commercial O&M - Oil Reciprocating Engine - 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 340 337 335 333 330 328

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 10,348 10,405 10,437 10,502 10,567 10,599

Electric Efficiency, HHV (%) 33 32.8 32.7 32.5 32.3 32.2

Fuel Input (MMBtu/hr) 3.518 3.506 3.501 3.495 3.485 3.474

Thermal Output (MMBtu/hr) 1.554 1.554 1.554 1.554 1.554 1.554

Total CHP Efficiency (%) 77.2 77.13 77.1 77.0 76.9 76.9

Power to Thermal Output Ratio 0.747 0.740 0.737 0.731 0.724 0.720

Net Heat Rate (Btu/kWh) 4,635 4,640 4,645 4,665 4,676 4,673

Variable O&M Costs ($/kWh) 0.02 0.023 0.026 0.030 0.034 0.038

Fixed O&M Costs ($/kW-year) 24 27.40 31.14 35.51 40.54 46.15
COMMERCIAL

File: EIA | 209089 Leidos, Inc. 4-29

Table 4-43

Commercial Capital Costs - Oil Reciprocating Engine - Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 780 863 922 1,003 1,090 1,185

Installation Labor and Materials 

($/kW)(3)

660 733 784 854 931 1,015

Engineering/Construction 

Management/Contingency (4,5)

576 639 684 746 813 886

Total Installed Cost ($/kW) 2,016 2,235 2,390 2,603 2,834 3,086

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

4.6.6 Advanced Technologies Projections

See section 4.5.6 – similar assumptions for the advanced technology.

Table 4-44

Commercial O&M - Oil Reciprocating Engine - Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 340 340 340 340 340 340

Electric Heat Rate, HHV (Btu/kWh) 10,348 10,105 10,090 10,075 10,044 10,014

Electric Efficiency, HHV (%) 33 33.8 33.8 33.9 34.0 34.1

Fuel Input (MMBtu/hr) 3.518 3.436 3.431 3.425 3.415 3.405

Thermal Output (MMBtu/hr) 1.554 1.518 1.515 1.513 1.508 1.504

Total CHP Efficiency (%) 77.2 77.9 78.0 78.0 78.1 78.3

Power to Thermal Output Ratio 0.747 0.765 0.766 0.767 0.769 0.772

Net Heat Rate (Btu/kWh) 4,634 4,526 4,519 4,512 4,499 4,485

Variable O&M Costs ($/kWh) 0.02 0.023 0.025 0.028 0.032 0.036

Fixed O&M Costs ($/kW-year) 24 27.15 30.72 34.76 39.33 44.49

Table 4-45

Commercial Capital Costs - Oil Reciprocating Engine - Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 780 780 863 922 1,003 1,090

Installation Labor and Materials ($/kW) 660 660 733 784 854 931

Engineering/Construction Management/Contingency (1) 576 576 639 684 746 813

Total Installed Cost ($/kW) 2,016 2,235 2,390 2,603 2,834 3,086

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr
Section 4

4-30 Leidos, Inc. File: EIA | 209089

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

4.7 Commercial – Natural Gas Turbine (CNT)

4.7.1 Equipment and Systems

The Commercial – Natural Gas Turbine (CNT) system consists of a natural gas turbine 

producing 1,000 kW.

4.7.2 Technology Specifications

For the purposes of the analysis, a typical 1,000 kW packaged gas turbine readily 

available in the commercial marketplace and fueled by pipeline quality natural gas was 

considered. The CNT is assumed to be equipped with a remote monitoring system 

whose purpose is to provide real time and historical production data of the facility along 

with alarm functionality in the event system or equipment anomalies occur. The CNT

is also assumed to be equipped with remote starting and stopping capabilities along with 

on-board automatic control functionality, which allow for continuous unmanned 

operations with periodic inspections to be conducted by O&M personnel and/or 

subcontracted labor.

The technology specifications for the CNT are presented in Table 4-46:

Table 4-46

Commercial – Natural Gas Turbine – 1,000 kW

Life Cycle 2015

Output Capacity (kW) 1,210

Electric Heat Rate, HHV (Btu/kWh) 14,045

Electric Efficiency, HHV (%) 24.3

Fuel Input (MMBtu/hr) 17.0

Thermal Output (MMBtu/hr) 7.072

Total CHP Efficiency (%) 65.9

Power to Thermal Output Ratio 0.58

Net Heat Rate (Btu/kWh) 6,739

Variable O&M Costs ($/kWh) 0.01

Fixed O&M Costs ($/kW-year) 41.77

4.7.3 Capital Cost Estimate

The base Cost Estimate for the CNT system with a nominal capacity of 1,000 kW is 

$2,224/kW.

Table 4-47 summarizes the Cost Estimate categories for the CNT facility.
COMMERCIAL

File: EIA | 209089 Leidos, Inc. 4-31

Table 4-47

Base Plant Site Capital Cost Estimate for CNT

Technology: CNT

Nominal Capacity (ISO): 1,000 kW

Nominal Heat Rate (ISO): 14,025 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 1,007

Installation – Labor and Materials 618

Engineering, Construction Management, and Contingency (1) 599

Total Project EPC 2,224

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

4.7.4 O&M Estimate

In addition to the general items discussed in the Section of this Report entitled O&M 

Estimate, the CNT facility includes provisions for major maintenance on the electric 

generators, BOP systems, and other auxiliary systems. Table 4-48 presents the O&M 

expenses for the CNT facility. O&M cost assumptions include labor, provisions for the 

completion of scheduled and unscheduled maintenance as well as major maintenance 

intervals. For the analysis, a CF of 93 percent was assumed.

Table 4-48

O&M Expenses for CNT 1,000 kW

Technology: CNT

Fixed O&M Expense $41.77/kW-year

Variable O&M Expense $0.01/kWh
Section 4

4-32 Leidos, Inc. File: EIA | 209089

4.7.5 Reference Technologies Projections

Table 4-49

Commercial O&M - Natural Gas Turbine – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 1,210 1,210 1,210 1,210 1,210 1,210

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh)(2) 14,045 13,906 13,769 13,632 13,497 13,364

Electric Efficiency, HHV (%) 24.3 24.5 24.8 25.0 25.3 25.5

Fuel Input (MMBtu/hr) 17.0 16.8 16.7 16.5 16.3 16.2

Thermal Output (MMBtu/hr) 7.072 7.00 6.93 6.86 6.80 6.73

Total CHP Efficiency (%) 65.9 66.2 66.4 66.7 66.9 67.2

Power to Thermal Output Ratio 0.58 0.59 0.60 0.60 0.61 0.61

Net Heat Rate (Btu/kWh) 6,739 6,673 6,607 6,541 6,476 6,412

Variable O&M Costs ($/kWh) 0.0102 0.0115 0.0130 0.0148 0.0167 0.0189

Fixed O&M Costs ($/kW-year) 41.77 47.26 53.47 60.50 68.45 77.44

(1) Assumes new system installed every five years.

(2) Heat rate improvement projection

(3) Variable and Fixed O&M costs represented in current dollars. Assumed to increase 2.5%/year.

Table 4-50

Commercial O&M - Natural Gas Turbine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 1,210 1,185 1,160 1,135 1,110 1,085

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 14,045 14,340 14,648 14,969 15,305 15,656

Electric Efficiency, HHV (%) 24.3 23.8 23.3 22.8 22.3 21.8

Fuel Input (MMBtu/hr) 17.0 17.0 17.0 17.0 17.0 17.0

Thermal Output (MMBtu/hr) 7.072 7.072 7.072 7.072 7.072 7.072

Total CHP Efficiency (%) 65.9 65.4 64.9 64.4 63.9 63.4

Power to Thermal Output Ratio 0.58 0.57 0.56 0.55 0.54 0.52

Net Heat Rate (Btu/kWh) 6,739 6,881 7,029 7,183 7,344 7,512

Variable O&M Costs ($/kWh) 0.0102 0.0118 0.0136 0.0157 0.0182 0.0211

Fixed O&M Costs ($/kW-year) 41.77 48.25 55.77 64.48 74.58 86.32
COMMERCIAL

File: EIA | 209089 Leidos, Inc. 4-33

Table 4-51

Commercial Capital Costs- Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 1,007 1,104 1,172 1,263 1,365 1,471

Installation Labor and Materials ($/kW) 618 686 734 800 872 951

Engineering/Construction 

Management/Contingency (1) 599 665 711 775 845 921

Total Installed Cost ($/kW) 2,224 2,455 2,617 2,838 3,082 3,343

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

4.7.6 Advanced Technologies Projections

Natural gas single cycle turbine technologies were significantly developed from the 

1950s through the 1990s when new systems were being widely deployed. These 

developments paved the route for more cost-effective next-generation techniques, such 

as natural gas combined cycle (NGCC) systems. As a reference, Lazard cites the 

levelized cost of energy (LCOE) from NGCCs to range from $61 to $87 per MWh, but 

the gas peaking units have LCOEs of $179 to $230 per MWh.19 NGCC systems carry 

the benefit of low emissions for oxides of nitrogen and for carbon dioxide.

Compared to most other technologies discussed in this report, the gas turbine 

technologies are considered very mature technologies. Cost reductions historically 

accompany the deployment of a technology from one sales volume to a relatively higher 

sales volume, but gas turbines have already been produced in high volumes over decades 

of deployment. The gas turbines also compete with the renewable technologies, 

NGCCs, and other electricity generators in the electricity market but do not appear to 

grow in significant numbers in modeling results because of their costs relative to other 

technologies. In five simulations for EPRI in 2013, the unit capital costs ($/kW) for gas 

turbines did not drop from 2015 levels until the year 2045.20

However, significant advances on these technologies continue to be made in the 

transportation sector. For example, Federal contract awards have led to the development 

of new turbine engines for aircraft that use ceramic membrane composites to achieve 

turbine operation at higher temperatures than previously possible. These efforts lead to 

turbines that can operate both in high power and in low fuel usage modes.21

 19 Lazard, 2014. “Lazard’s Levelized Cost of Energy Analysis—Version 8.0.” September 2014. Last 

accessed from http://www.lazard.com/PDF/Levelized%20Cost%20of%20Energy%20-

%20Version%208.0.pdf on April 23, 2015.

20 Azevedo, I. P. Jaramillo, E. Rubin, and S. Yeh. Modeling Technology Learning for Electricity Supply 

Technologies. Phase II Report to Electric Power Research Institute. June 2013. 

http://www.cmu.edu/epp/iecm/rubin/PDF%20files/2013/FINAL%20PHASE%20II%20REPORT%20TO%2

0EPRI_June%2030.pdf. 21 GE Aviation, 2015. “GE Successfully Tests World’s First Rotating Ceramic Matrix Composite 

Material for Next-Gen Combat Engine.” Press Center. February 10, 2015. 

http://www.geaviation.com/press/military/military_20150210.html.
Section 4

4-34 Leidos, Inc. File: EIA | 209089

Advances in other electricity-generating technologies may also improve the efficiency 

of gas turbines. For example, fifty research projects at DOE NETL address hydrogen 

turbines. Natural gas turbines operating in CHP systems that meet regulatory emission 

requirements could also benefit from the improvements in combined cycle units. 

However, the current deployment of natural gas turbines and reciprocating engines is 

more often for peaking or emergency conditions (because of the short startup times), 

thus extending the expected payback periods for these units. 

Lazard (2014)19 cites fuel costs as representing 18 to 26% of the costs for gas peaking 

units, so future efficiency improvements (e.g., laser ignition) would result in lower fuel 

costs. However, natural gas fuel costs are not considered directly in this report. Itron 

(2011) compared cost historical cost trends and worldwide production of small gas 

turbines in 2006-2009 on a MW basis to develop projected costs through 2020. The 

installed cost ($/kW) for small gas turbines (under 2 MW) dropped 6 percent from 2015 

to 2020, and the installed cost ($/kW) for large gas turbines (2-5 MW) dropped 7 percent 

from 2015 to 2020. However, a curve propagated so heavily from 2008-2009 data may 

not be representative of long-term trends (growth rates were negative from 2008 to 

2009).

Because of the uncertainties mentioned in the preceding paragraphs in a competitive 

environment and the general acknowledgement that these technologies are mature, the 

advanced technology cases for natural gas turbines were not assumed to have lower unit 

costs ($/kW) than those in the reference cases.

Table 4-52

Commercial O&M - Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 1,210 1,210 1,210 1,210 1,210 1,210

Electric Heat Rate, HHV (Btu/kWh) 14,045 13,628 13,494 13,359 13,227 13,097

Electric Efficiency, HHV (%) 24.3 25.0 25.3 25.5 25.8 26.1

Fuel Input (MMBtu/hr) 17.0 16.5 16.3 16.2 16.0 15.8

Thermal Output (MMBtu/hr) 7.072 6.86 6.79 6.73 6.66 6.59

Total CHP Efficiency (%) 65.9 66.7 66.9 67.2 67.4 67.7

Power to Thermal Output Ratio 0.58 0.60 0.61 0.61 0.62 0.63

Net Heat Rate (Btu/kWh) 6,739 6,539 6,475 6,410 6,347 6,284

Variable O&M Costs ($/kWh) 0.0102 0.0115 0.013 0.0148 0.0167 0.0189

Fixed O&M Costs ($/kW-year) 41.77 47.26 53.47 60.50 68.45 77.44
COMMERCIAL

File: EIA | 209089 Leidos, Inc. 4-35

Table 4-53

Commercial Capital Costs- Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 1,007 1,104 1,172 1,263 1,365 1,471

Installation Labor and Materials ($/kW) 618 686 734 800 872 951

Engineering/Construction Management/Contingency (1) 599 665 711 775 845 921

Total Installed Cost ($/kW) 2,224 2,455 2,617 2,838 3,082 3,343

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

4.8 Commercial – Natural Gas Micro-turbine (CNM)

4.8.1 Equipment and Systems

The Commercial – Natural Gas Micro-turbine (CNM) is sized at 250 kW.

4.8.2 Technology Specifications

For the purposes of the analysis, a typical 250 kW packaged gas fired micro-turbine 

readily available in the commercial marketplace and fueled by pipeline quality natural 

gas was considered. The CNM is assumed to be equipped with a remote monitoring 

system whose purpose is to provide real time and historical production data of the 

facility along with alarm functionality in the event system or equipment anomalies 

occur. The CNM is also assumed to be equipped with remote starting and stopping 

capabilities along with on-board automatic control functionality, which allow for 

continuous unmanned operations with periodic inspections to be conducted by O&M 

personnel and/or subcontracted labor.

The technology specifications for the CNM are presented in Table 4-54:

Table 4-54

Commercial – Natural Gas Micro-turbine – 250 kW

Life Cycle 2015

Output Capacity (kW) 250.0

Electric Heat Rate, HHV (Btu/kWh) 13,200

Electric Efficiency, HHV (%) 25.9

Fuel Input (MMBtu/hr) 3.3

Thermal Output (MMBtu/hr) 1.33

Total CHP Efficiency (%) 66.3

Power to Thermal Output Ratio 0.64

Net Heat Rate (Btu/kWh) 6,533

Variable O&M Costs ($/kWh) 0.0138

Fixed O&M Costs ($/kW-year) 18.22
Section 4

4-36 Leidos, Inc. File: EIA | 209089

4.8.3 Capital Cost Estimate

The base Cost Estimate for the CNM facility with a nominal capacity of 250 kW is 

$3,404/kW. 

The cost estimate for the CNM 250 kW assumes having a small site adjacent to the end 

use. A one-acre site is required to be cleared, leveled and conditioned to accept 

underground utilities such as water, gas, electric, sewage, drainage, just as what is found 

at any large facility. The CNM price was obtained from Gas Turbine World 2013 TW 

Handbook Volume 30. The equipment cost for the 250 kW machine was obtained from 

pricing of a 200 kW and factored for size using the six-tenths estimating rule, plus 

freight delivery to the site. Peripheral electrical equipment necessary to complement 

the Peaking power plant needs has been added to the estimate. The cost estimate 

includes site preparation, gas tapping costs, structures, equipment, electrical, 

distributable cost, engineering and design and subcontractor fee and budget 

contingency. All estimated costs are expressed in $/kW. All numbers in these estimates 

are based on prices and wages for the Gulf Coast Region of the U.S. 

Table 4-55 summarizes the Cost Estimate categories for the CNM facility.

Table 4-55

Base Plant Site Capital Cost Estimate for CNM

Technology: CNM

Nominal Capacity (ISO): 250 kW

Nominal Heat Rate (ISO): 13,080 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 1,455

Installation – Labor and Materials 1,069

Engineering, Construction Management, and Contingency (1) 880

Total Project EPC 3,404

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

4.8.4 O&M Estimate

In addition to the general items discussed in the Section of this Report entitled O&M 

Estimate, the CNM facility include the major maintenance for the CT, as well as the 

BOP, including the associated electric generator, and emissions reduction catalysts. 

These major maintenance expenses are included with the VOM expense for this 

technology and are given on an average basis with an assumed CF of 93 percent. 

Table 4-56 presents the O&M expenses for the CNM Facility.
COMMERCIAL

File: EIA | 209089 Leidos, Inc. 4-37

Table 4-56

O&M Expenses for CNM

Technology: CNM

Fixed O&M Expense $18.22/kW-year

Variable O&M Expense $0.0138/kWh

4.8.5 Reference Technologies Projections

The following tables present the reference performance characteristics and cost 

projections for CNM.

Table 4-57

Commercial O&M- Natural Gas Micro-turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW)(1) 250 250 250 250 250 250

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV 

(Btu/kWh)2

13,200 13,069 12,940 12,812 12,685 12,559

Electric Efficiency, HHV (%) 25.86 26.12 26.38 26.64 26.91 27.18

Fuel Input (MMBtu/hr) 3.30 3.27 3.24 3.20 3.17 3.14

Thermal Output (MMBtu/hr) 1.33 1.32 1.31 1.29 1.28 1.27

Total CHP Efficiency (%) 66.26 66.52 66.78 67.04 67.31 67.58

Power to Thermal Output Ratio 0.64 0.65 0.65 0.66 0.67 0.67

Net Heat Rate (Btu/kWh) 6,533 6,468 6,405 6,341 6,278 6,216

Variable O&M Costs ($/kWh)3 0.0138 0.0153 0.0164 0.0179 0.0195 0.0212

Fixed O&M Costs ($/kW-year)3 18.22 20.22 21.63 23.59 25.71 28.02

(1) Leidos has assumed a constant turbine output capacity across the projection period and new system installed every five 

years.

(2) Heat rate improvement projected to be 0.06% for 5 years and 1% per 5 years after 2020.

(3) Fixed and variable O&M costs represented in current 2015 dollars.
Section 4

4-38 Leidos, Inc. File: EIA | 209089

Table 4-58

Commercial O&M- Natural Gas Micro-turbine - 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 250 244 238 238 223 214

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 13,200 13,538 13,886 13,886 14,812 15,406

Electric Efficiency, HHV (%) 26.1 25.2 24.6 24.6 23 22.2

Fuel Input (MMBtu/hr) 3.30 3.30 3.30 3.30 3.30 3.30

Thermal Output (MMBtu/hr) 1.33 1.33 1.33 1.33 1.33 1.33

Total CHP Efficiency (%) 66.26 65.57 64.92 64.92 63.41 62.60

Power to Thermal Output Ratio 0.64 0.62 0.61 0.61 0.57 0.55

Net Heat Rate (Btu/kWh) 7,200 7,385 7,574 7,574 8,080 8,403

Variable O&M Costs ($/kWh) 0.0138 0.0157 0.0172 0.0188 0.0218 0.0248

Fixed O&M Costs ($/kW-year) 18.22 20.72 22.73 24.78 28.82 32.74

Table 4-59

Commercial Capital Costs- Natural Gas Micro-turbine - Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 1,455 1,599 1,694 1,828 1,973 2,129

Installation Labor and Materials ($/kW) 1,069 1,187 1,270 1,384 1,508 1,644

Engineering/Construction 

Management/Contingency (1) 880 977 1,045 1,139 1,242 1,354

Total Installed Cost ($/kW) 3,404 3,762 4,009 4,351 4,723 5,127

(1) Capital cost of a new system installed every 5 years.

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

(3) Costs are presented as current dollars.

4.8.6 Advanced Technologies Projections

Partnered with Capstone, the ORNL is developing microturbines with greater electrical 

efficiencies. In demonstration trials, a low pressure spool microturbine achieved 35% 

LHV electrical efficiency (32% HHV) at 70°F to deliver 278 kW. The second phase of 

the current project (2013-2015) aims to develop a higher temperature combustion 

system to achieve a 42% LHV electrical efficiency using advanced materials at the 

higher temperatures.

Because a major DOE research focus for microturbines has been on improved electrical 

efficiency and because the electrical efficiencies of current products on the market are 

higher than the reference case, this study used electrical efficiency as the basis for 
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File: EIA | 209089 Leidos, Inc. 4-39

predicting future costs (on a per kW basis) for the advanced technology case. Table X1 below shows the efficiencies discussed in the preceding paragraphs and assigns them 

to particular future years.

Table 4-59a

Assignment of Electrical Efficiencies to New Microturbine Units for Current and 

Future Years in Advanced Technology Case

Year HHV Electrical 

Efficiency

Basis

2015 26.1% Reference case from Table 4-57

2020 30% Current manufacturer’s rating on Capstone microturbines with ratings 

of 200 kW, 600 kW, 800 kW, and 1000 kW

2025 32% Low pressure spool rating already achieved by ORNL with existing 

materials and meeting CARB emission standards

2040 38% Goal for ORNL R&D units by the end of 2015; 25-year horizon allows 

time to develop cost-competitive high-temperature materials

Table 4-60

Commercial O&M- Natural Gas Micro-turbine - Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW)(1) 250 250 250 250 250 250

Electric Heat Rate, HHV (Btu/kWh)(2) 13,200 11,377 10,666 10,038 9,481 8,982

Electric Efficiency, HHV (%) 26.1 30 32 34 36 38

Fuel Input (MMBtu/hr)(3) 3.3 2.84 2.67 2.51 2.37 2.25

Thermal Output (MMBtu/hr)(4) 1.33 1.15 1.08 1.01 0.96 0.91

Total CHP Efficiency (%) 62.2 70.40 72.40 74.40 76.40 78.40

Power to Thermal Output Ratio 0.72 0.74 0.79 0.84 0.89 0.94

Net Heat Rate (Btu/kWh) 6,533 5,631 5,279 4,968 4,692 4,445

Variable O&M Costs ($/kWh)(5) 0.0138 0.0142 0.0155 0.0185 0.0184 0.0202

Fixed O&M Costs ($/kW-year)(6) 18.22 20.22 21.64 23.59 25.71 28.02

1) Output capacity maintained at 250 kW

2) Heat rates estimated based on ORNL R&D goals

3) Fuel input based on unit capacity and heat rate values

4) Thermal output adjusted based on heat input values

5) VOM adjusted based on incremental efficiency improvement; represented in current dollars

6) FOM reference values remain unchanged; represented in current dollars
Section 4

4-40 Leidos, Inc. File: EIA | 209089

Table 4-61

Commercial Capital Costs- Natural Gas Micro-turbine - Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(1) 1,455 1,411 1,451 1,504 1,586 1,684

Installation Labor and Materials ($/kW) (2) 1,069 1,187 1,270 1,384 1,508 1,644

Engineering/Construction Management/Contingency (3) 880 977 1,045 1,139 1,242 1,354

Total Installed Cost ($/kW) 3,404 3,575 3,766 4,027 4,336 4,682

1) Equipment cost of reference case adjusted based on the ratio of heat rate for advanced case to reference 

case, using a scaling exponent of 0.9 for year 2020, 0.85 for 2025, 0.8 for 2030, 0.75 for 2035, and 

0.7 for 2040. Scaling exponent values represent increasing challenges of manufacturing for higher 

efficiencies. 

2) Assumes no change in values from reference values.

3) Includes engineering, distributable costs, scaffolding, construction management, and start-up.

Assumes no change in values from reference values.
File: EIA | 209089

Section 5

INDUSTRIAL

5.1 Industrial – Natural Gas Reciprocating Engine1,000 kW (IRE1)

5.1.1 Equipment and Systems

The Industrial Natural Gas Reciprocating Engine Facility with 1,000 kW capacity 

(IRE1) is discussed below .

5.1.2 Technology Specifications

Table 5-1

Industrial – Natural Gas Reciprocating Engine – 1,000 kW

Life Cycle 2015

Output Capacity (kW) 1,312

Electric Heat Rate, HHV (Btu/kWh) 9,614

Electric Efficiency, HHV (%) 35.5

Fuel Input (MMBtu/hr) 12.614

Thermal Output (MMBtu/hr) 5.42

Total CHP Efficiency (%) 78.50

Power to Thermal Output Ratio 0.826

Net Heat Rate (Btu/kWh) 4,446

Variable O&M Costs ($/kWh) 0.011

Fixed O&M Costs ($/kW-year) 18.00

The IRE1 facility is controlled using a DCS. The DCS provides centralized control of 

the facility by integrating the control systems provided with the reciprocating engineer

and associated electric generator and the control of BOP systems and equipment.

5.1.3 Capital Cost Estimate

The base Cost Estimate for the IRE1 Facility with a nominal capacity of 1,000 kW is 

$1,899/kW. 

The cost estimate for the IRE1 - 1000 kW assumes having a small site adjacent to the 

end use or transmission line. A two-acre site is assumed to be required to be cleared, 

leveled and conditioned to accept underground utilities such as water, gas, electric, 

sewage, drainage, just as what is found at any large facility. The IRE1 engine price was 

obtained from a local dealer. Peripheral electrical equipment necessary to complement 

the industrial power plant needs has been added to the estimate, also included is a diesel 
Section 5

5-2 Leidos, Inc. File: EIA | 209089

storage tank. The cost estimate includes site preparation, structures, equipment, 

electrical, distributable cost, engineering and design and subcontractor fee and budget 

contingency. All estimated costs are expressed in $/kW. All numbers in these estimates 

are based on prices and wages for the Gulf Coast Region of the U.S. 

Table 5-2 summarizes the Cost Estimate categories for the IRE1 Facility.

Table 5-2

Base Plant site Capital Cost Estimate for IRE1

Technology: IRE1

Nominal Capacity (ISO): 1,000 kW

Nominal Heat Rate (ISO): 9,614 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 984

Installation – Labor and Materials 400

Engineering, Construction Management, and Contingency (1) 515

Total Project EPC 1,899

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

5.1.4 O&M Estimate

In addition to the general items discussed in the Section of this Report entitled O&M 

Estimate, the IRE1 facility includes the major maintenance for the reciprocating engine

and associated electric generator, as well as the BOP. These major maintenance 

expenses are included with the VOM expense for this technology and are given on an 

average basis across the MWh incurred. Typically, significant overhauls on a IRE1

facility occur no less frequently than 6 to 8 years. Table 5-3 presents the O&M expenses 

for the IRE1 facility.

Table 5-3

O&M Expenses for IRE1

Technology: IRE1

Fixed O&M Expense $18.00/kW-year

Variable O&M Expense $0.011/kWh

Variable Costs

Variable O&M costs include minor (20,000 - 25,000 hours) and major maintenance 

(60,000 – 100,000 hours) parts and labor. For engines 1,000 kW and above (which are

assumed to be lean burn technology), add to this 10 percent of cost of fuel to cover the 

cost of urea for the SCR system. Smaller engines (such as in the 300 kW range) are 

assumed to be rich burn, and use an oxidation catalyst which does not require urea. Also 
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File: EIA | 209089 Leidos, Inc. 5-3

included in variable O&M costs are routine maintenance consumables such as 

lubricating oil and filters.

Fixed Costs

There are likely to be minimal or no direct fixed costs attributable to the operating of 

small engines, because it is assumed to be unlikely that a dedicated facility would be 

constructed and maintained to support a small engine. More likely, a small engine 

would be installed in a larger facility such a central heating plant, which would already 

have a staff for maintaining the overall facility, and there would be no additional fixed 

costs attributable directly to the small engine. While this could also be the case with a 

larger engine (such as 1,000 kW and above), as such an engine could be installed as a 

stand-alone installation which would require its own operating staff, and could,

therefore, depending on the situation of the installation, fixed costs could be attributable 

such an installation.

5.1.5 Reference Technologies Projections

Table 5-4

Industrial O&M – Natural Gas Reciprocating Engine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 1,312 1,312 1,312 1,312 1,312 1,312

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 9,614 9,590 9,566 9,542 9,519 9,495

Electric Efficiency, HHV (%) 35.50 35.59 35.68 35.77 35.85 35.95

Fuel Input (MMBtu/hr) 12.61 12.58 12.55 12.52 12.49 12.46

Thermal Output (MMBtu/hr) 5.42 5.41 5.40 5.38 5.37 5.36

Total CHP Efficiency (%) 78.50 78.59 78.68 78.77 78.85 78.95

Power to Thermal Output Ratio 0.826 0.828 0.830 0.832 0.834 0.836

Net Heat Rate (Btu/kWh) 4,446 4,435 4,424 4,413 4,403 4,391

Variable O&M Costs ($/kWh) 0.011 0.012 0.014 0.016 0.018 0.020

Fixed O&M Costs ($/kW-year) 18.00 20.37 23.04 26.07 29.50 33.37

Table 5-5

Industrial O&M – Natural Gas Reciprocating Engine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 1,312 1,305 1,299 1,292 1,286 1,280

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147
Section 5

5-4 Leidos, Inc. File: EIA | 209089

Electric Heat Rate, HHV 

(Btu/kWh)

9,614 9,662 9,711 9,760 9,809 9,858

Electric Efficiency, HHV (%) 35.50 35.32 35.15 34.97 34.79 34.62

Fuel Input (MMBtu/hr) 12.61 12.61 12.61 12.61 12.61 12.62

Thermal Output (MMBtu/hr) 5.42 5.42 5.42 5.42 5.42 5.43

Total CHP Efficiency (%) 78.50 78.32 78.15 77.97 77.79 77.62

Power to Thermal Output Ratio 0.83 0.82 0.82 0.81 0.81 0.81

Net Heat Rate (Btu/kWh) 4,446 4,469 4,491 4,514 4,537 4,559

Variable O&M Costs ($/kWh) 0.011 0.013 0.014 0.016 0.018 0.021

Fixed O&M Costs ($/kW-year) 18.00 20.47 23.27 26.47 30.09 34.21

(1) Costs presented are in current 2015 dollars

Table 5-6

Industrial Capital Costs – Natural Gas Reciprocating Engine – Reference New 

Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 984 1,090 1,163 1,264 1,375 1,495

Installation Labor and Materials ($/kW) 400 444 475 518 564 615

Engineering/Construction 

Management/Contingency (1) 515 572 612 667 727 792

Total Installed Cost ($/kW) 1,899 2,105 2,250 2,449 2,666 2,902

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.1.6 Advanced Technologies Projections

Compared to most other technologies discussed in this report, the reciprocating engine 

technology is considered very mature technology. Some advances continue to be made 

on these power generators (e.g., laser ignition which has been shown to increase 

efficiency). However, reducing installation costs is not the primary focus area. The DOE 

Advanced Reciprocating Engine System (ARES) program aims to achieve 50% brake 

thermal efficiency (80+% with CHP), a maximum of 0.1 g/bhp-hr NOx emissions, 

maintenance cost below $0.01/EkW-hr, and a continued cost competitiveness. Two of 

the three industry partners (Caterpillar and GE Dresser Waukesha) withdrew from the 

ARES program based on business considerations with regard to distributed energy 

technologies.

Cost reductions historically accompany the deployment of a technology from one sales 

volume to a relatively higher sales volume, but millions of reciprocating engines have 

already been produced over the last century. The reciprocating engines also compete 

with the renewable technologies, NGCCs, and other electricity generators in the 
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File: EIA | 209089 Leidos, Inc. 5-5

electricity market, but do not appear to grow in significant numbers in modeling results 

because of their costs relative to other technologies. In five simulations for EPRI in 

2013, the unit capital costs ($/kW) did not drop from 2015 levels until the year 2045.

Advances in other electricity-generating technologies may also improve the efficiency 

of reciprocating engines. For example, fifty research projects at DOE NETL address 

hydrogen turbines. Natural gas turbines and reciprocating engines operating in CHP 

systems, which meet regulatory emission requirements, could also benefit from the 

improvements in combined cycle units. However, their current deployment is more 

often for peaking or emergency conditions (because of the short startup times), thus 

extending the expected payback periods for these units.

Because of the uncertainties associated with a competitive marketplace environment 

and the general acknowledgement that these technologies are very mature, the advanced 

technology cases for natural gas turbines and reciprocating engines were not assumed 

to have lower unit costs ($/kW) than those in the reference cases. Modest efficiency 

improvements of 2% lower than the reference case value are assumed to account for 

general improvements.

Table 5-7

Industrial O&M – Natural Gas Reciprocating Engine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 1,312 1,312 1,312 1,312 1,312 1,312

Electric Heat Rate, HHV (Btu/kWh) 9,614 9,398 9,375 9,351 9,329 9,305

Electric Efficiency, HHV (%) 35.5 36.32 36.41 36.50 36.59 36.68

Fuel Input (MMBtu/hr) 12.61 12.33 12.30 12.27 12.24 12.21

Thermal Output (MMBtu/hr) 5.42 5.30 5.29 5.28 5.26 5.25

Total CHP Efficiency (%) 78.50 79.32 79.41 79.50 79.59 79.68

Power to Thermal Output Ratio 0.826 0.845 0.847 0.849 0.851 0.853

Net Heat Rate (Btu/kWh) 4,446 4,347 4,336 4,325 4,314 4,304

Variable O&M Costs ($/kWh) 0.011 0.0124 0.0141 0.0159 0.0180 0.0204

Fixed O&M Costs ($/kW-year) 18 20.37 23.04 26.07 29.50 33.37

(1) Costs presented are in current 2015 dollars

Table 5-8

Industrial Capital Costs – Natural Gas Reciprocating Engine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 984 1,090 1,163 1,264 1,375 1,495

Installation Labor and Materials ($/kW) 400 444 475 518 564 615

Engineering/Construction Management/Contingency (1) 515 572 612 667 727 792

Total Installed Cost ($/kW) 1,899 2,105 2,250 2,449 2,666 2,902

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.
Section 5

5-6 Leidos, Inc. File: EIA | 209089

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.2 Industrial – Natural Gas Reciprocating Engine –

3,000 kW (IRE3)

5.2.1 Equipment and Systems

The Industrial Natural Gas Reciprocating Engine Facility produces a nominal 3,000 kW 

capacity (IRE3).

5.2.2 Technology Specifications

The technology specifications for the IRE3 are presented in Table 5-9:

Table 5-9

Industrial – Natural Gas Reciprocating Engine – 3,000 kW

Life Cycle 2015

Output Capacity (kW) 3,000

Electric Heat Rate, HHV (Btu/kWh) 7,810

Electric Efficiency, HHV (%) 43.7

Fuel Input (MMBtu/hr) 23.43

Thermal Output (MMBtu/hr) 9.864

Total CHP Efficiency (%) 85.80

Power to Thermal Output Ratio 1.038

Net Heat Rate (Btu/kWh) 3,700

Variable O&M Costs ($/kWh) 0.009

Fixed O&M Costs ($/kW-year) 8.00

5.2.3 Capital Cost Estimate

The base Cost Estimate for the IRE3 facility with a nominal capacity of 3 MW is 

$1,742/kW. 

The cost estimate for the IRE3 3,000 kW assumes having a small site adjacent to the 

end use or transmission line. A two-acre site is assumed to be required to be cleared, 

leveled and conditioned to accept underground utilities such as water, gas, electric, 

sewage, drainage, just as what is found at any large facility. The IRE3 engine price 

was obtained from a local dealer. Peripheral electrical equipment necessary to 

complement the Industrial power plant needs has been added to the estimate, also 

included is a diesel storage tank. The cost estimate includes site preparation, structures, 

equipment, electrical, distributable cost, engineering and design and subcontractor fee 

and budget contingency. All estimated costs are expressed in $/kW. All numbers in 

these estimates are based on prices and wages for the Gulf Coast Region of the U.S.

Table 5-10 summarizes the Cost Estimate categories for the IRE3 facility.
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Table 5-10

Base Plant Site Capital Cost Estimate for IRE3

Technology: IRE3

Nominal Capacity (ISO): 3,000 kW

Nominal Heat Rate (ISO): 7,810 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 991

Installation – Labor and Materials 377

Engineering, Construction Management, and Contingency (1) 374

Total Project EPC 1,742

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

5.2.4 O&M Estimate

Table 5-11 presents the O&M expenses for the IRE3 facility. 

Table 5-11

O&M Expenses for IRE3

Technology: IRE3

Fixed O&M Expense $8.00/kW-year

Variable O&M Expense $0.009/kWh
Section 5

5-8 Leidos, Inc. File: EIA | 209089

5.2.5 Reference Technologies Projections

Table 5-12

Industrial O&M – Natural Gas Reciprocating Engine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 3,000 3,000 3,000 3,000 3,000 3,000

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 7,810 7,791 7,771 7,752 7,732 7,713

Electric Efficiency, HHV (%) 43.70 43.81 43.92 44.03 44.14 44.25

Fuel Input (MMBtu/hr) 23.43 23.37 23.31 23.26 23.20 23.14

Thermal Output (MMBtu/hr) 9.86 9.84 9.81 9.79 9.77 9.74

Total CHP Efficiency (%) 85.80 85.91 86.02 86.13 86.24 86.35

Power to Thermal Output Ratio 1.038 1.041 1.043 1.046 1.048 1.051

Net Heat Rate (Btu/kWh) 3,700 3,691 3,682 3,673 3,663 3,654

Variable O&M Costs ($/kWh) 0.009 0.010 0.012 0.013 0.015 0.017

Fixed O&M Costs ($/kW-year) 8.00 9.05 10.24 11.59 13.11 14.83

(1) Costs presented are in current 2015 dollars

Table 5-13

Industrial O&M – Natural Gas Reciprocating Engine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 3,000 2,985 2,970 2,955 2,940 2,926

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 7,810 7,849 7,889 7,928 7,968 8,008

Electric Efficiency, HHV (%) 43.70 43.48 43.26 43.05 42.83 42.62

Fuel Input (MMBtu/hr) 23.43 23.43 23.43 23.43 23.43 23.43

Thermal Output (MMBtu/hr) 9.864 9.913 9.964 10.013 10.064 10.114

Total CHP Efficiency (%) 85.80 85.79 85.79 85.79 85.79 85.78

Power to Thermal Output Ratio 1.038 1.028 1.017 1.007 0.997 0.987

Net Heat Rate (Btu/kWh) 3,700 3,698 3,695 3,692 3,689 3,687

Variable O&M Costs ($/kWh) 0.009 0.010 0.012 0.013 0.015 0.017

Fixed O&M Costs ($/kW-year) 8 9.10 10.34 11.77 13.38 15.21

(1) Costs presented are in current 2015 dollars
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Table 5-14

Industrial Capital Costs Natural Gas Reciprocating Engine – Reference New 

Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 991 1,097 1,171 1,273 1,384 1,505

Installation Labor and Materials 

($/kW)(3)

377 418 448 488 532 580

Engineering/Construction 

Management/Contingency (4,5)

374 415 444 484 528 575

Total Installed Cost ($/kW) 1,742 1,931 2,063 2,246 2,444 2,660

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.2.6 Advanced Technologies Projections

See section 5.2.5 discussion.

Table 5-15

Industrial O&M – Natural Gas Reciprocating Engine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 3,000 3,000 3,000 3,000 3,000 3,000

Electric Heat Rate, HHV (Btu/kWh) 7,810 7,635 7,616 7,597 7,577 7,559

Electric Efficiency, HHV (%) 43.7 44.70 44.82 44.93 45.04 45.15

Fuel Input (MMBtu/hr) 23.43 22.91 22.85 22.79 22.73 22.68

Thermal Output (MMBtu/hr) 9.864 9.86 9.84 9.81 9.79 9.77

Total CHP Efficiency (%) 85.8 87.76 87.88 87.99 88.11 88.22

Power to Thermal Output Ratio 1.038 1.038 1.041 1.043 1.046 1.049

Net Heat Rate (Btu/kWh) 3,700 3,525 3,516 3,508 3,498 3,490

Variable O&M Costs ($/kWh) 0.009 0.01 0.012 0.013 0.015 0.017

Fixed O&M Costs ($/kW-year) 8 9.05 10.24 11.59 13.11 14.83

Table 5-16

Industrial Capital Costs Natural Gas Reciprocating Engine – Advanced New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 991 1,097 1,171 1,273 1,384 1,505

Installation Labor and Materials ($/kW) 377 418 448 488 532 580

Engineering/Construction Management/Contingency (4,5) 374 415 444 484 528 575

Total Installed Cost ($/kW) 1,742 1,931 2,063 2,246 2,444 2,660

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year
Section 5

5-10 Leidos, Inc. File: EIA | 209089

(4) Real cost reduction assumed to be 0 %/ yr

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

5.3 Industrial – Natural Gas Turbine (IGT5)

5.3.1 Equipment and Systems

The Industrial Natural Gas Turbine System for 5,000 kW (IGT5) produces 5 kW net of 

electricity. The facility uses a 5 MW natural gas turbine.

Figure 5.1: GT Design Configuration

5.3.2 Technology Specifications

The IGT5 facility has one natural gas turbine mechanically coupled to an electric

generator. The generator is a 60 Hertz (Hz) machine rated at approximately 6 megavolt-amperes (MVA) with an output voltage of 13.8 kilovolt (kV). The electric 

generator is connected to a high-voltage bus in the facility switchyard via a dedicated 

generator circuit breaker, Generator Step-up (GSU) transformer, high-voltage circuit 

breaker, and a disconnect switch. The GSU increases the voltage from the electric 

generator from 13.8 kV to interconnected transmission system high voltage.

The IGT5 facility is controlled using a DCS. The DCS provides centralized control of 

the facility by integrating the control systems provided with the GT and associated 

electric generator, and the control of BOP systems and equipment.

The technology specifications for the IGT5 are presented in Table 5-17:
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Table 5-17

Industrial – Natural Gas Turbine – 5,000 kW

Life Cycle 2015

Output Capacity (kW) 5,300

Electric Heat Rate, HHV (Btu/kWh) 12,688

Electric Efficiency, HHV (%) 26.9

Fuel Input (MMBtu/hr) 67.245

Thermal Output (MMBtu/hr) 35.573

Total CHP Efficiency (%) 79.80

Power to Thermal Output Ratio 0.509

Net Heat Rate (Btu/kWh) 4,298

Variable O&M Costs ($/kWh) 0.010

Fixed O&M Costs ($/kW-year) 79.02

5.3.3 Capital Cost Estimate

The base Cost Estimate for the IGT5 facility with a nominal capacity of 5 MW is 

$1,509/kW. 

The cost estimate for the IGT5 5,000 kW assumes having a small site located adjacent 

to the end use. A two-acre site is assumed to be required to be cleared, leveled and 

conditioned to accept underground utilities such as water, gas, electric, sewage, 

drainage, just as what is found at any large facility. The combustion turbine price was 

obtained from Gas Turbine World 2013 TW Handbook Volume 30. The equipment 

cost for the 5,000 kW machine was obtained from pricing of a 5,245 kW and factored 

for size using the six-tenths estimating rule, plus freight delivery to the site. Peripheral 

electrical equipment necessary to complement the peaking power plant needs has been 

added to the estimate. The cost estimate includes site preparation, gas tapping costs, 

structures, equipment, electrical, distributable cost, engineering and design and 

subcontractor fee and budget contingency. All estimated costs are expressed in $/kW.

All numbers in these estimates are based on prices and wages for the Gulf Coast Region 

of the U.S.

Table 5-18 summarizes the Cost Estimate categories for the IGT5 facility.
Section 5

5-12 Leidos, Inc. File: EIA | 209089

Table 5-18

Base Plant Site Capital Cost Estimate for IGT5

Technology: 1GT5

Nominal Capacity (ISO): 5,000 kW

Nominal Heat Rate (ISO): 12,660 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 647

Installation – Labor and Materials 450

Engineering, Construction Management, and Contingency (1) 412

Total Project EPC 1,509

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

5.3.4 O&M Estimate

In addition to the general items discussed in the Section of this Report entitled O&M 

Estimate, the GT facility includes major maintenance on the electric generator (each 

approximately every six years dependent upon the unit’s capacity factor). O&M cost 

assumptions include labor, provisions for the completion of scheduled and unscheduled 

maintenance as well as major maintenance intervals. For the analysis, a CF of 93 

percent was assumed. Table 5-19 presents the FOM and VOM expenses for the GT 

facility. 

Table 5-19

O&M Expenses for IGT5

Technology: IGT5

Fixed O&M Expense $79.02/kW-year

Variable O&M Expense $0.010/kWh
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5.3.5 Reference Technologies Projections

See section 5.2.5 discussion.

Table 5-20

Industrial O&M - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 5,300 5,300 5,300 5,300 5,300 5,300

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 12,688 12,562 12,438 12,315 12,193 12,072

Electric Efficiency, HHV (%) 26.90 27.17 27.44 27.71 27.99 28.27

Fuel Input (MMBtu/hr) 67.25 66.58 65.92 65.27 64.62 63.98

Thermal Output (MMBtu/hr) 27.91 27.63 27.36 27.09 26.82 26.55

Total CHP Efficiency (%) 68.40 68.67 68.94 69.21 69.49 69.77

Power to Thermal Output Ratio 0.648 0.655 0.661 0.668 0.674 0.681

Net Heat Rate (Btu/kWh) 6,106 6,045 5,986 5,927 5,868 5,810

Variable O&M Costs ($/kWh) 0.010 0.011 0.013 0.014 0.016 0.018

Fixed O&M Costs ($/kW-year) 79.02 89.40 101.15 114.45 129.48 146.50

(1) Assumptions based on recent projects along with the Solar Turbine data cut sheets for CHP and performance from Solar 

Turbine’s website. 

(2) Assumes new system installed every five years.

(3) Heat rate improvement projection assumes 1% every 5 years

(4) Variable and Fixed O&M costs represented in current dollars. Assumed to increase 2.5%/year.
Section 5

5-14 Leidos, Inc. File: EIA | 209089

Table 5-21

Industrial O&M - Natural Gas Turbine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 5,300 5,038 4,938 4,840 4,743 4,649

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 12,688 13,347 13,618 13,894 14,176 14,464

Electric Efficiency, HHV (%) 26.90 25.57 25.06 24.56 24.08 23.60

Fuel Input (MMBtu/hr) 67.25 67.24 67.25 67.25 67.24 67.24

Thermal Output (MMBtu/hr) 27.907 27.907 27.907 27.907 27.907 27.907

Total CHP Efficiency (%) 68.40 67.07 66.56 66.06 65.58 65.10

Power to Thermal Output Ratio 0.648 0.616 0.604 0.592 0.580 0.569

Net Heat Rate (Btu/kWh) 6,106 6,423 6,554 6,687 6,821 6,961

Variable O&M Costs ($/kWh) 0.01 0.012 0.014 0.015 0.018 0.021

Fixed O&M Costs ($/kW-year) 79.02 94.05 108.57 125.33 144.69 167.01

(1) Assumptions based on recent projects along with the Solar Turbine data cut sheets for CHP and performance from Solar 

Turbine’s website. 

(2) Fixed and variable assume 93% CF.

(3) Thermal output assumed constant

Table 5-22

Industrial Capital Costs - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 647 711 753 813 877 947

Installation Labor and Materials ($/kW) 450 500 534 583 635 692

Engineering/Construction 

Management/Contingency (1) 412 457 489 533 581 634

Total Installed Cost ($/kW) 1,509 1,668 1,777 1,929 2,094 2,273

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

File: EIA | 209089 Leidos, Inc. 5-15

5.3.6 Advanced Technologies Projections

See the discussion in Section 4.7.6 – same assumptions apply.

Table 5-23

Industrial O&M - Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 5,300 5,300 5,300 5,300 5,300 5,300

Electric Heat Rate, HHV (Btu/kWh) 12,688 12,311 12,189 12,069 11,949 11,831

Electric Efficiency, HHV (%) 26.9 27.72 28.00 28.28 28.56 28.85

Fuel Input (MMBtu/hr) 67.25 65.25 64.60 63.96 63.33 62.70

Thermal Output (MMBtu/hr) 27.91 27.08 26.81 26.55 26.28 26.02

Total CHP Efficiency (%) 68.40 69.22 69.50 69.78 70.06 70.35

Power to Thermal Output Ratio 0.509 0.668 0.675 0.681 0.688 0.695

Net Heat Rate (Btu/kWh) 6,106 5,925 5,866 5,808 5,751 5,693

Variable O&M Costs ($/kWh) 0.01 0.011 0.013 0.014 0.016 0.018

Fixed O&M Costs ($/kW-year) 79.02 89.4 101.15 114.45 129.48 146.5

(1) Assumptions are based on recent projects along with the Solar Turbine data cut sheets for CHP and performance from their 

website. 

(2) Fixed and variable assume 93% CF.

Table 5-24

Industrial Capital Costs - Natural Gas Turbine – Advanced New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 647 711 753 813 877 947

Installation Labor and Materials ($/kW)(3) 450 500 534 583 635 692

Engineering/Construction Management/Contingency (4,5) 412 457 489 533 581 634

Total Installed Cost ($/kW) 1,509 1,668 1,777 1,929 2,094 2,273

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.4 Industrial – Natural Gas Turbine – 10,000 kW (IGT10)

5.4.1 Equipment and Systems

The industrial natural gas turbine facility (IGT10) produces 10 MW net of electricity. 

The IGT10 facility consists primarily of one commercially available, factory packaged

combustion turbine with 10 MW capacity. The design output of the natural gas turbine

is approximately 9,950 kW of net capacity
Section 5

5-16 Leidos, Inc. File: EIA | 209089

Figure 5.2: GT Design Configuration

5.4.2 Technology Specifications

There would be one turbine generator at the IGT10 facility. The turbine generator is to 

be rated for approximately 10 MW. The IGT10 facility has one natural gas turbine 

mechanically coupled to an electric generator. The generator is a 60 Hz machine rated 

at approximately 11.5 MVA with an output voltage of 13.8 kV. The electric generator 

is connected to a high-voltage bus in the facility switchyard via a dedicated generator 

circuit breaker, GSU, high-voltage circuit breaker and a disconnect switch. The GSU 

increases the voltage from the electric generator from 13.8 kV to interconnected 

transmission system high voltage.

The IGT10 Facility is controlled using a DCS. The DCS provides centralized control 

of the facility by integrating the control systems provided with the GT and associated 

electric generator, and the control of BOP systems and equipment.

The technology specifications for the IGT10 are presented in Table 5-25:
INDUSTRIAL

File: EIA | 209089 Leidos, Inc. 5-17

Table 5-25

Industrial – Natural Gas Turbine – 10,000 kW

Life Cycle 2015

Output Capacity (kW) 9,950.0

Electric Heat Rate, HHV (Btu/kWh) 12,037

Electric Efficiency, HHV (%) 28.4

Fuel Input (MMBtu/hr) 119.765

Thermal Output (MMBtu/hr) 62.571

Total CHP Efficiency (%) 80.60

Power to Thermal Output Ratio 0.543

Net Heat Rate (Btu/kWh) 4,176

Variable O&M Costs ($/kWh) 0.004

Fixed O&M Costs ($/kW-year) 79.02

5.4.3 Capital Cost Estimate

The base Cost Estimate for the IGT10 facility with a nominal capacity of 10 MW is 

$1,281/kW.

The cost estimate for the IGT10 9,950 kW assumes having a small site located adjacent 

to the end use. A five-acre site is assumed to be required to be cleared, leveled and 

conditioned to accept underground utilities such as water, gas, electric, sewage, 

drainage, just as what is found at any large facility. The combustion turbine price was 

obtained from Gas Turbine World 2013 TW Handbook Volume 30. The equipment 

cost for the 10,000 kW machine was obtained from pricing of a 11,250 kW and factored 

for size using the six-tenths estimating rule, plus freight delivery to the site. Peripheral 

electrical equipment necessary to complement the peaking power plant needs has been 

added to the estimate. The cost estimate includes site preparation, gas tapping costs, 

structures, equipment, electrical, distributable cost, engineering and design, and 

subcontractor fee and budget contingency. All estimated costs are expressed in $/kW. 

All numbers in these estimates are based on prices and wages for the Gulf Coast Region 

of the U.S.

Table 5-26 summarizes the Cost Estimate categories for the IGT10 facility.
Section 5

5-18 Leidos, Inc. File: EIA | 209089

Table 5-26

Base Plant Site Capital Cost Estimate for IGT10

Technology: IGT10

Nominal Capacity (ISO): 10,000 kW

Nominal Heat Rate (ISO): 12,037 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 623

Installation – Labor and Materials 370

Engineering, Construction Management, and Contingency (1) 288

Total Project EPC 1,281

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

5.4.4 O&M Estimate

In addition to the general items discussed in the Section of this Report entitled O&M 

Estimate, the IGT10 facility includes major maintenance on the turbines, electric 

generator (each approximately every six years) maintenance. O&M cost assumptions 

include labor, provisions for the completion of scheduled and unscheduled maintenance 

as well as major maintenance intervals. For the analysis, a CF of 93 percent was 

assumed. 

Table 5-27 presents the FOM and VOM expenses for the IGT10 facility. 

Table 5-27

O&M Expenses for IGT10

Technology: IGT10

Fixed O&M Expense $79.02/kW-year

Variable O&M Expense $0.004/kWh
INDUSTRIAL

File: EIA | 209089 Leidos, Inc. 5-19

5.4.5 Reference Technologies Projections

Table 5-28

Industrial O&M - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 9,950 9,950 9,950 9,950 9,950 9,950

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 12,037 11,918 11,800 11,683 11,567 11,452

Electric Efficiency, HHV (%) 28.35 28.64 28.92 29.21 29.51 29.80

Fuel Input (MMBtu/hr) 119.77 118.58 117.41 116.25 115.09 113.95

Thermal Output (MMBtu/hr) 50.30 49.81 49.31 48.82 48.34 47.86

Total CHP Efficiency (%) 70.35 70.64 70.92 71.21 71.51 71.80

Power to Thermal Output Ratio 0.675 0.682 0.689 0.696 0.703 0.710

Net Heat Rate (Btu/kWh) 5,718 5,661 5,605 5,549 5,494 5,440

Variable O&M Costs ($/kWh) 0.004 0.0045 0.0051 0.0058 0.0066 0.0074

Fixed O&M Costs ($/kW-year) 79.02 89.40 101.15 114.45 129.48 146.50

(1) Assumptions based on recent projects along with the Solar Turbine data cut sheets for CHP and performance from Solar 

Turbine’s website. 

(2) Assumes new system installed every five years.

(3) Heat rate improvement projection

(4) Variable and Fixed O&M costs represented in current dollars. Assumed to increase 2.5%/year.

Table 5-29

Industrial O&M - Natural Gas Turbine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 9,950 9,459 9,270 9,086 8,905 8,728

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 12,037 12,662 12,919 13,182 13,449 13,722

Electric Efficiency, HHV (%) 28.35 26.95 26.42 25.89 25.38 24.87

Fuel Input (MMBtu/hr) 119.77 119.77 119.76 119.77 119.76 119.77

Thermal Output (MMBtu/hr) 50.30 50.30 50.30 50.30 50.30 50.30

Total CHP Efficiency (%) 70.35 68.95 68.42 67.89 67.38 66.87

Power to Thermal Output Ratio 0.675 0.642 0.629 0.617 0.604 0.592

Net Heat Rate (Btu/kWh) 5,718 6,015 6,136 6,262 6,388 6,518

Variable O&M Costs ($/kWh) 0.004 0.005 0.005 0.007 0.008 0.009

Fixed O&M Costs ($/kW-year) 79.02 94.04 108.57 125.33 144.67 167.01

(1) Assumptions based on recent projects along with the Solar Turbine data cut sheets for CHP and performance from Solar 

Turbine’s website. 

(2) Fixed and variable assume 93% CF.
Section 5

5-20 Leidos, Inc. File: EIA | 209089

Table 5-30

Industrial Capital Costs - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 623 685 725 783 845 912

Installation Labor and Materials ($/kW) 370 411 439 479 522 569

Engineering/Construction 

Management/Contingency (1)

288 320 342 373 406 443

Total Installed Cost ($/kW) 1,281 1,415 1,507 1,635 1,773 1,924

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.4.6 Advanced Technologies Projections

See the discussion in Section 4.7.6 – same assumptions apply.

Table 5-31

Industrial O&M - Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 9,950 9,950 9,950 9,950 9,950 9,950

Electric Heat Rate, HHV (Btu/kWh) 12,037 11,680 11,564 11,449 11,336 11,223

Electric Efficiency, HHV (%) 28.35 29.22 29.51 29.81 30.11 30.41

Fuel Input (MMBtu/hr) 119.77 116.21 115.06 113.92 112.79 111.67

Thermal Output (MMBtu/hr) 50.30 48.81 48.33 47.85 47.37 46.90

Total CHP Efficiency (%) 70.35 71.22 71.51 71.81 72.11 72.41

Power to Thermal Output Ratio 0.675 0.696 0.703 0.710 0.717 0.724

Net Heat Rate (Btu/kWh) 5,718 5,548 5,493 5,438 5,384 5,331

Variable O&M Costs ($/kWh) 0.004 0.0045 0.0051 0.0058 0.0066 0.0074

Fixed O&M Costs ($/kW-year) 79.02 89.40 101.15 114.44 129.48 146.50

(1) Assumptions based on recent projects along with the Solar Turbine data cut sheets for CHP and performance from Solar 

Turbine’s website. 

(2) Fixed and variable assume 93% CF.
INDUSTRIAL

File: EIA | 209089 Leidos, Inc. 5-21

Table 5-32

Industrial Capital Costs - Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 623 685 725 783 845 912

Installation Labor and Materials ($/kW) 370 411 439 479 522 569

Engineering/Construction Management/Contingency (1) 288 320 342 373 406 443

Total Installed Cost ($/kW) 1,281 1,415 1,507 1,635 1,773 1,924

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.5 Industrial – Natural Gas Turbine – 25,000 kW (IGT25)

5.5.1 Equipment and Systems

The industrial natural gas turbine facility with 25 MW capacity (IGT25) generates

approximately 25 MW. The IGT25 facility consists of a SwiftPac 25 combustion 

turbine.

Figure 5.3: GT Design Configuration

5.5.2 Technology Specifications

There would be one turbine generator at the IGT25 facility utilizing aeroderivative 

technology commercially available in the marketplace. The turbine generator is to be 

rated for approximately 25 MW. The IGT25 facility has one natural gas turbine 

mechanically coupled to an electric generator. The generator is a 60 Hz machine rated 

at approximately 28.5 MVA with an output voltage of 13.8 kV. The electric generator 
Section 5

5-22 Leidos, Inc. File: EIA | 209089

is connected to a high-voltage bus in the facility switchyard via a dedicated generator 

circuit breaker, GSU, high-voltage circuit breaker and a disconnect switch. The GSU 

increases the voltage from the electric generator from 13.8 kV to interconnected 

transmission system high voltage.

The IGT25 facility is controlled using a DCS. The DCS provides centralized control of 

the facility by integrating the control systems provided with the GT and associated 

electric generator, and the control of BOP systems and equipment.

The technology specifications for the IGT25 are presented in Table 5-33:

Table 5-33

Industrial Natural Gas Turbine – 25,000 kW

Year 2015

Output Capacity (kW) 25,210

Electric Heat Rate, HHV (Btu/kWh) 10,189

Electric Efficiency, HHV (%) 33.5

Fuel Input (MMBtu/hr) 256.864

Thermal Output (MMBtu/hr) 105.065

Total CHP Efficiency (%) 70.50

Power to Thermal Output Ratio 0.905

Net Heat Rate (Btu/kWh) 5,477

Variable O&M Costs ($/kWh) 0.006

Fixed O&M Costs ($/kW-year) 18.43

5.5.3 Capital Cost Estimate

The base Cost Estimate for the IGT25 facility with a nominal capacity of 25 MW is 

$999/kW.

The cost estimate for the IGT25 25,000 kW assumes having a small site located adjacent 

to the end use. A ten-acre site is assumed to be required to be cleared, leveled and 

conditioned to accept underground utilities such as water, gas, electric, sewage, 

drainage, just as what is found at any large facility. The combustion turbine price was 

obtained from Gas Turbine World 2013 TW Handbook Volume 30. The equipment 

cost for the 25,000 kW machine was obtained from pricing of a 25,455 kW and factored 

for size using the six-tenths estimating rule, plus freight delivery to the site. Peripheral 

electrical equipment necessary to complement the peaking power plant needs has been 

added to the estimate. The cost estimate includes site preparation, gas tapping costs, 

structures, equipment, electrical, distributable cost, engineering and design and 

subcontractor fee and budget contingency. All estimated costs are expressed in $/kW.

All numbers in these estimates are based on prices and wages for the Gulf Coast Region 

of the U.S.

Table 5-34 summarizes the Cost Estimate categories for the IGT25 facility.
INDUSTRIAL

File: EIA | 209089 Leidos, Inc. 5-23

Table 5-34

Base Plant Site Capital Cost Estimate for IGT25

Technology: IGT25

Nominal Capacity (ISO): 25,000 kW

Nominal Heat Rate (ISO): 10,189 Btu/kWh-HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 548

Installation – Labor and Materials 224

Engineering, Construction Management, and Contingency (1) 227

Total Project EPC 999

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

5.5.4 O&M Estimate

The O&M cost assumptions for the IGT25 facility include labor, provisions for the 

completion of scheduled and unscheduled maintenance as well as major maintenance 

intervals. For the analysis, a CF of 93 percent was assumed.

Table 5-35 presents the O&M expenses for the IGT25 facility.

Table 5-35

O&M Expenses for IGT25

Technology: IGT25

Fixed O&M Expense $18.43/kW-year

Variable O&M Expense $0.006/kWh
Section 5

5-24 Leidos, Inc. File: EIA | 209089

5.5.5 Reference Technologies Projections

Table 5-36

Industrial O&M - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 25,210 25,210 25,210 25,210 25,210 25,210

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 10,189 10,088 9,988 9,889 9,791 9,694

Electric Efficiency, HHV (%) 33.50 33.83 34.17 34.51 34.86 35.21

Fuel Input (MMBtu/hr) 256.86 254.32 251.80 249.30 246.83 244.39

Thermal Output (MMBtu/hr) 95.04 94.10 93.17 92.24 91.33 90.42

Total CHP Efficiency (%) 70.50 70.83 71.17 71.51 71.86 72.21

Power to Thermal Output Ratio 0.905 0.914 0.924 0.933 0.942 0.952

Net Heat Rate (Btu/kWh) 5,477 5,422 5,369 5,315 5,263 5,211

Variable O&M Costs ($/kWh) 0.006 0.0068 0.0077 0.0087 0.0098 0.0111

Fixed O&M Costs ($/kW-year) 18.43 20.85 23.59 26.69 30.20 34.17

(1) LM 2500 + DLE technology at STP.

(2) Utilized GE APPS Model for performance results.

(5) Assumes new system installed every five years.

(6) Heat rate improvement projection

(7) Variable and Fixed O&M costs represented in current dollars. Assumed to increase 2.5%/year.

Table 5-37

Industrial O&M - Natural Gas Turbine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 25,210 24,860 24,239 24,239 22,722 21,846

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 10,189 10,332 10,597 10,597 11,304 11,757

Electric Efficiency, HHV (%) 33.50 33.03 32.21 32.21 30.19 29.03

Fuel Input (MMBtu/hr) 256.86 256.85 256.86 256.86 256.85 256.84

Thermal Output (MMBtu/hr) 95.04 95.04 95.04 95.04 95.04 95.04

Total CHP Efficiency (%) 70.50 70.03 69.21 69.21 67.20 66.03

Power to Thermal Output Ratio 0.905 0.893 0.870 0.870 0.816 0.785

Net Heat Rate (Btu/kWh) 5,477 5,553 5,696 5,696 6,076 6,319

Variable O&M Costs ($/kWh) 0.006 0.007 0.007 0.008 0.011 0.013

Fixed O&M Costs ($/kW-year) 18.43 21.14 24.54 27.76 33.51 39.43

(1) LM 2500 + DLE technology at STP.

(2) Utilized GE APPS Model for performance results.

(3) Model Produced Heat Rate (LHV).
INDUSTRIAL

File: EIA | 209089 Leidos, Inc. 5-25

Table 5-38

Industrial Capital Costs - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 548 602 638 689 743 802

Installation Labor and Materials ($/kW) 249 266 290 316 345 249

Engineering/Construction 

Management/Contingency (1)

252 270 294 320 349 252

Total Installed Cost ($/kW) 999 1,103 1,174 1,272 1,379 1,496

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.5.6 Advanced Technologies Projections

See the discussion in Section 4.7.6 – same assumptions apply.

Table 5-39

Industrial O&M - Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 25,210.0 25,210 25,210 25,210 25,210 25,210

Electric Heat Rate, HHV (Btu/kWh) 10,189 10,189 9,886 9,788 9,691 9,595

Electric Efficiency, HHV (%) 33.5 33.50 34.52 34.87 35.22 35.57

Fuel Input (MMBtu/hr) 256.864 256.86 249.23 246.76 244.32 241.89

Thermal Output (MMBtu/hr) 105.065 95.04 92.22 91.30 90.40 89.50

Total CHP Efficiency (%) 74.40 70.50 71.52 71.87 72.22 72.57

Power to Thermal Output Ratio 0.819 0.905 0.933 0.942 0.952 0.961

Net Heat Rate (Btu/kWh) 4,979 5,477 5,314 5,261 5,209 5,157

Variable O&M Costs ($/kWh) 0.006 0.0068 0.0077 0.0087 0.0098 0.0111

Fixed O&M Costs ($/kW-year) 18.43 20.85 23.59 26.69 30.2 34.17

(1) LM 2500 + DLE technology at STP.

(2) Utilized GE APPS Model for performance results.

(3) Costs presented are in current 2015 dollars

.
Section 5

5-26 Leidos, Inc. File: EIA | 209089

Table 5-40

Industrial Capital Costs - Natural Gas Turbine – Advanced New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(2) 548 602 638 689 743 802

Installation Labor and Materials ($/kW)(3) 224 249 266 290 316 345

Engineering/Construction Management/Contingency (4,5) 227 252 270 294 320 349

Total Installed Cost ($/kW) 999 1,103 1,174 1,272 1,379 1,496

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr

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

5.6 Industrial – Natural Gas Turbine – 40,000 kW (IGT40)

5.6.1 Equipment and Systems

There would be one turbine generator at the IGT40 facility utilizing aeroderivative 

technology commercially available in the marketplace. The turbine generator is to be 

rated for approximately 40 MW. The IGT40 facility has one natural gas turbine 

mechanically coupled to an electric generator. The generator is a 60 Hz machine rated 

at approximately 48.5 MVA with an output voltage of 13.8 kV. The electric generator 

is connected to a high-voltage bus in the facility switchyard via a dedicated generator 

circuit breaker, GSU, high-voltage circuit breaker and a disconnect switch. The GSU 

increases the voltage from the electric generator from 13.8 kV to interconnected 

transmission system high voltage.

The IGT40 facility is controlled using a DCS. The DCS provides centralized control of 

the facility by integrating the control systems provided with the GT and associated 

electric generator, and the control of BOP systems and equipment.

Figure 5.4: Industrial Natural Gas Turbine Configuration
INDUSTRIAL

File: EIA | 209089 Leidos, Inc. 5-27

5.6.2 Technology Specifications

The IGT40 facility has one aeroderivative natural gas turbine generator.

The technology specifications for the IGT40 are presented in Table 5-41:

Table 5-41

Industrial – Natural Gas Turbine – 40,000 kW

Year 2015

Output Capacity (kW) 39,986

Electric Heat Rate, HHV (Btu/kWh) 9,305

Electric Efficiency, HHV (%) 36.7

Fuel Input (MMBtu/hr) 372.06

Thermal Output (MMBtu/hr) 121

Total CHP Efficiency (%) 69.20

Power to Thermal Output Ratio 1.128

Net Heat Rate (Btu/kWh) 5,523

Variable O&M Costs ($/kWh) 0.005

Fixed O&M Costs ($/kW-year) 17.88

5.6.3 Capital Cost Estimate

The base Cost Estimate for the IGT40 facility with a nominal capacity of 40 MW is 

$822/kW.

The cost estimate for the IGT40 40,000 kW assumes having a small site located adjacent 

to the end use. A 15-acre site is assumed to be required to be cleared, leveled and 

conditioned to accept underground utilities such as water, gas, electric, sewage, and

drainage, just as what is found at any large facility. The combustion turbine price was 

obtained from Gas Turbine World 2013 TW Handbook Volume 30. The equipment cost 

for the 40,000 kW machine was obtained from pricing of a 42,100 kW and factored for 

size using the six-tenths estimating rule, plus freight delivery to the site. Peripheral 

electrical equipment necessary to complement the peaking power plant needs has been 

added to the estimate. The cost estimate includes site preparation, gas tapping costs, 

structures, equipment, electrical, distributable cost, engineering and design, and 

subcontractor fee and budget contingency. All estimated costs are expressed in $/kW. 

All numbers in the estimate are based on prices and wages for the Gulf Coast Region of 

the U.S.

Table 5-42 summarizes the Cost Estimate categories for the IGT40.
Section 5

5-28 Leidos, Inc. File: EIA | 209089

Table 5-42

Base Plant Site Capital Cost Estimate for IGT40

Technology: IGT40

Nominal Capacity (ISO): 40,000 kW

Nominal Heat Rate (ISO): 9,305 Btu/kWh – HHV

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 464

Installation – Labor and Materials 177

Engineering, Construction Management, and Contingency (1) 181

Total Project EPC 822

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

5.6.4 O&M Estimate

In addition to the general items discussed in the Section 2.4.2 of the Report entitled 

Operation and Maintenance (O&M) Expenses, O&M cost assumptions include labor, 

provisions for the completion of scheduled and unscheduled maintenance as well as 

major maintenance intervals, which are usually conducted approximately every 6 years. 

For the analysis, a CF of 93 percent was assumed. 

Table 5-43 presents the O&M expenses for the IGT40 facility.

Table 5-43

O&M Expenses for IGT40

Technology: IGT40

Fixed O&M Expense $17.88/kW-year

Variable O&M Expense $0.005/kWh
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File: EIA | 209089 Leidos, Inc. 5-29

5.6.5 Reference Technologies Projections

Table 5-44

Industrial O&M - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 39,986 39,986 39,986 39,986 39,986 39,986

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 9,305 9,213 9,121 9,031 8,942 8,853

Electric Efficiency, HHV (%) 36.68 37.05 37.42 37.79 38.17 38.55

Fuel Input (MMBtu/hr) 372.07 368.39 364.71 361.11 357.55 354.00

Thermal Output (MMBtu/hr) 120.99 119.80 118.60 117.43 116.27 115.12

Total CHP Efficiency (%) 69.20 69.56 69.94 70.31 70.69 71.07

Power to Thermal Output Ratio 1.128 1.139 1.151 1.162 1.174 1.186

Net Heat Rate (Btu/kWh) 5,523 5,468 5,413 5,360 5,307 5,254

Variable O&M Costs ($/kWh) 0.005 0.0057 0.0064 0.0072 0.0082 0.0093

Fixed O&M Costs ($/kW-year) 17.88 20.23 22.89 25.90 29.30 33.15

(1) LM6000 PC Steam Injected at STP.

(2) Utilized GE APPS Model for performance results.

(3) Assumes new system installed every five years.

(4) Heat rate improvement projection assumes 1% every 5 years

(5) Variable and Fixed O&M costs represented in current dollars. Assumed to increase 2.5%/year.

Table 5-45

Industrial O&M - Natural Gas Turbine – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 39,986.0 39,431.0 38,445.0 38,445.0 36,040.0 34,651.0

Capacity Factor (%) 93.0 93.0 93.0 93.0 93.0 93.0

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 9,305 9,436 9,678 9,678 10,324 10,738

Electric Efficiency, HHV (%) 36.7 36.2 35.3 35.3 33.1 31.8

Fuel Input (MMBtu/hr) 372.062 372.1 372.1 372.1 372.1 372.1

Thermal Output (MMBtu/hr) 120.994 121.0 121.0 121.0 121.0 121.0

Total CHP Efficiency (%) 69.20 68.7 67.8 67.8 65.6 64.3

Power to Thermal Output Ratio 1.128 1.11 1.08 1.08 1.02 0.98

Net Heat Rate (Btu/kWh) 5,523 5,600 5,744 5,744 6,127 6,373

Variable O&M Costs ($/kWh) 0.005 0.006 0.007 0.008 0.009 0.011

Fixed O&M Costs ($/kW-year) 17.88 20.51 23.81 26.93 32.51 38.25

(1) LM6000 PC Steam Injected at STP.

(2) Utilized GE APPS Model for performance results.

(3) Model Produced Heat Rate (LHV).
Section 5

5-30 Leidos, Inc. File: EIA | 209089

Table 5-46

Industrial Capital Costs - Natural Gas Turbine – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 464 510 540 583 629 679

Installation Labor and Materials ($/kW) 177 196 210 229 250 272

Engineering/Construction 

Management/Contingency (1) 181 201 215 234 255 278

Total Installed Cost ($/kW) 822 907 965 1,046 1,134 1,230

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

5.6.6 Advanced Technologies Projections

See the discussion in Section 4.7.6 – same assumptions apply.

Table 5-47

Industrial O&M - Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 39,986 39,986 39,986 39,986 39,986 39,986

Electric Heat Rate, HHV (Btu/kWh) 9,305 9,305 9,029 8,939 8,850 8,763

Electric Efficiency, HHV (%) 36.7 36.68 37.80 38.18 38.56 38.95

Fuel Input (MMBtu/hr) 372.062 372.07 361.02 357.42 353.89 350.40

Thermal Output (MMBtu/hr) 120.994 120.99 117.40 116.23 115.08 113.95

Total CHP Efficiency (%) 69.20 69.20 70.32 70.70 71.08 71.47

Power to Thermal Output Ratio 1.128 1.128 1.162 1.174 1.186 1.198

Net Heat Rate (Btu/kWh) 5,522 5,523 5,359 5,305 5,253 5,201

Variable O&M Costs ($/kWh) 0.005 0.0057 0.0064 0.0072 0.0082 0.0093

Fixed O&M Costs ($/kW-year) 17.88 20.23 22.89 25.90 29.30 33.15

(1) LM6000 PC Steam Injected at STP.

(2) Utilized GE APPS Model for performance results.

(3) Model Produced Heat Rate (LHV).

Table 5-48

Industrial Capital Costs - Natural Gas Turbine – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 464 510 540 583 629 679

Installation Labor and Materials ($/kW) 177 196 210 229 250 272

Engineering/Construction Management/Contingency (1) 181 201 215 234 255 278

Total Installed Cost ($/kW) 822 907 965 1,046 1,134 1,230

(1) Costs presented are in current 2015 dollars

(2) Real cost reduction assumed to be 0% due to the mature nature of the technology.

(3) Real cost reduction assumed to be 0%/year

(4) Real cost reduction assumed to be 0 %/ yr
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File: EIA | 209089 Leidos, Inc. 5-31

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

5.7 Industrial – Combined Cycle – 100,000 kW (ICC)

5.7.1 Equipment and Systems

The industrial 100-MW combined cycle facility (ICC) is composed of two 40 MW 

aeroderivative type turbine generator units and one 20-MW steam turbine generator. 

Figure 5-5 presents the ICC process flow diagram.

Figure 5.5: Industrial Combined Cycle Design Configuration

The ICC facility has two natural gas fired combustion turbines in combined-cycle with 

a steam turbine generator Each electric generator is connected to a high-voltage bus in 

the facility switchyard via dedicated generator circuit breakers, GSUs, high-voltage 

circuit breakers, and one or more disconnect switches. The GSU increases the voltage 

from the electric generator voltage to the interconnected transmission system high 

voltage.

The ICC facility is controlled using a DCS. The DCS provides centralized control of 

the facility by integrating the control systems provided with the turbine and associated 

electric generator and the control of BOP systems and equipment.
Section 5

5-32 Leidos, Inc. File: EIA | 209089

5.7.2 Technology Specifications

There would be two gas turbine generators at the ICC facility utilizing aeroderivative 

technology commercially available in the marketplace. The turbine generators are to be 

rated for approximately 48 MW. The ICC facility has two natural gas turbines 

mechanically coupled to dedicated electric generators along with a nominally rated 

20 MW steam turbine generator. For the gas turbines, the packaged generators are

60 Hz machines rated at approximately 68.5 MVA with an output voltage of 13.8 kV. 

The STG would be mechanically coupled to a dedicated generator with a nominal rating 

of approximately 22.5 MVA. The electric generators are connected to a high-voltage 

bus in the facility switchyard via dedicated generator circuit breakers, GSUs, highvoltage circuit breakers, and disconnect switches. The GSUs increase the voltage from 

the electric generators from 13.8 kV to interconnected transmission system high 

voltage.

The ICC facility is controlled using a DCS. The DCS provides centralized control of 

the facility by integrating the control systems provided with the GT and associated 

electric generator, and the control of BOP systems and equipment.

The technology specifications for the ICC are presented in Table 5-49:

Table 5-49

Industrial – Combine Cycle – 100,000 kW

Year 2015

Output Capacity (kW) 103,128

Electric Heat Rate, HHV (Btu/kWh) 8,353

Electric Efficiency, HHV (%) 40.9

Fuel Input (MMBtu/hr) 861.43

Thermal Output (MMBtu/hr) 65.792

Total CHP Efficiency (%) 48.50

Power to Thermal Output Ratio 5.350

Net Heat Rate (Btu/kWh) 7,556

Variable O&M Costs ($/kWh) 0.0064

Fixed O&M Costs ($/kW-year) 19.88

5.7.3 Capital Cost Estimate

The base Cost Estimate for the ICC Facility with a nominal capacity of 100 MW is 

$1,594/kW. 

The cost estimate for the ICC 100,000 kW assumes having a site located within the 

vicinity of a transmission line and close to the end use. A 40-acre site is assumed to be 

required to be cleared, leveled and conditioned to accept underground utilities such as 

water, gas, electric, sewage, and drainage, just as what is found at any large facility. 

The ICC price was obtained from Gas Turbine World 2013 TW Handbook Volume 30. 

The equipment cost for the 100,000 kW machine was obtained from pricing of a 

111,400 kW and factored for size using the six-tenths estimating rule, plus freight 
INDUSTRIAL

File: EIA | 209089 Leidos, Inc. 5-33

delivery to the site. The power arrangement consists of two aeroderivative gas turbines, 

two heat recovery steam generators, and one steam turbine rated at 20,000 kW. 

Peripheral electrical equipment necessary to complement the industrial power plant 

needs has been added to the estimate. The cost estimate includes site preparation, gas 

tapping costs, structures, equipment, electrical, cooling system, distributable cost, 

engineering and design and subcontractor fee and budget contingency. All estimated 

costs are expressed in $/kW. All numbers in these estimates are based on prices and 

wages for the Gulf Coast region of the U.S.

Table 5-50 summarizes the Cost Estimate categories for the ICC facility. The 

construction costs of the ICC are impacted by the existing infrastructure that may be 

leveraged in the development, design, and construction.

Table 5-50

Base Plant Site Capital Cost Estimate for ICC

Technology: ICC

Nominal Capacity (ISO): 100,000 kW

Nominal Heat Rate (ISO): 8,353 Btu/kWh-HHV 

Capital Cost Category

($/kW)

(January 1, 2015 $)

Equipment Supply 994

Installation – Labor and Materials 320

Engineering, Construction Management, and Contingency (1) 280

Total Project EPC 1,594

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

5.7.4 O&M Estimate

Table 5-51 presents the O&M expenses for the ICC facility. O&M cost assumptions 

include labor, provisions for the completion of scheduled and unscheduled maintenance 

as well as major maintenance intervals. In addition, provisions have been estimated for 

maintenance required on the BOP and auxiliary systems. For the analysis, a CF of 

93 percent was assumed. 

Table 5-51

O&M Expenses for ICC

Technology: ICC

Fixed O&M Expense $19.88/kW-year

Variable O&M Expense $0.0064/kWh
Section 5

5-34 Leidos, Inc. File: EIA | 209089

5.7.5 Reference Technologies Projections

Table 5-52

Industrial O&M - Combined Cycle – Reference New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 103,128 103,128 103,128 103,128 103,128 103,128

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 8,353 8,270 8,188 8,107 8,027 7,947

Electric Efficiency, HHV (%) 40.86 41.27 41.68 42.10 42.52 42.95

Fuel Input (MMBtu/hr) 861.43 852.87 844.41 836.06 827.81 819.56

Thermal Output (MMBtu/hr) 65.79 65.14 64.49 63.85 63.22 62.59

Total CHP Efficiency (%) 48.50 48.91 49.32 49.74 50.16 50.58

Power to Thermal Output Ratio 5.350 5.404 5.458 5.512 5.567 5.623

Net Heat Rate (Btu/kWh) 7,556 7,480 7,406 7,333 7,261 7,188

Variable O&M Costs ($/kWh) 0.006 0.0072 0.0082 0.0093 0.0105 0.0119

Fixed O&M Costs ($/kW-year) 19.88 22.49 25.45 28.79 32.58 36.86

(1) LM6000 PC Steam Injected at STP.

(2) Utilized GE APPS Model for performance results.

(3) Model Produced Heat Rate (LHV).

Table 5-53

Industrial O&M - Combined Cycle – 2015 Degraded Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 103,128 101,696 99,154 99,154 92,950 89,368

Capacity Factor (%) 93 93 93 93 93 93

Hours of Operation (hrs) 8,147 8,147 8,147 8,147 8,147 8,147

Electric Heat Rate, HHV (Btu/kWh) 8,353 8,470 8,688 8,688 9,267 9,639

Electric Efficiency, HHV (%) 40.9 40.30 39.28 39.28 36.83 35.41

Fuel Input (MMBtu/hr) 861.4 861.37 861.45 861.45 861.37 861.42

Thermal Output (MMBtu/hr) 66.00 66.00 66.00 66.00 66.00 66.00

Total CHP Efficiency (%) 48.5 47.96 46.95 46.95 44.49 43.07

Power to Thermal Output Ratio 5.33 5.259 5.127 5.127 4.807 4.621

Net Heat Rate (Btu/kWh) 7,555 7,659 7,856 7,856 8,379 8,716

Variable O&M Costs ($/kWh)(4) 0.0064 0.0073 0.0085 0.0096 0.0116 0.0137

Fixed O&M Costs ($/kW-year)(5) 19.88 22.81 26.47 29.95 36.14 42.53

(1) LM6000 PC Steam Injected at STP.

(2) Utilized GE APPS Model for performance results.

(3) Model Produced Heat Rate (LHV).

(4) VOM adjusted for output capacity post-2015

(5) FOM adjusted for output capacitypost-2015
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File: EIA | 209089 Leidos, Inc. 5-35

Table 5-54

Industrial Capital Costs - Combined Cycle – Reference New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW) 994 1,092 1,157 1,249 1,348 1,455

Installation Labor and Materials ($/kW) 320 352 373 402 434 468

Engineering/Construction 

Management/Contingency(2)

280 308 326 352 380 410

Total Installed Cost ($/kW) 1,594 1,752 1,856 2,003 2,161 2,332

(1) Costs presented in current dollars. Costs adjusted for output capacity increase post-2015.

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

5.7.6 Advanced Technologies Projections

Several studies regard NGCC (without carbon capture and storage) as a mature 

technology without significant cost savings forecast for units in future years.22 

However, advances continue to be made in the turbine design. The advanced combined 

cycle units use G- or H-class turbines to achieve combined cycle efficiencies exceeding 

60%. In 2011 Siemens reported that their SGT-8000H turbines would reduce the 

investment costs per kW. Therefore, any costs cited in 2015 should likely reflect the 

advanced combined cycle units rather than those consisting solely of F-class turbines 

(the predominant class in the late 1980s). One 2014 article cites that advances in the 

combined cycle technologies over the remainder of the decade will include:

• Additive manufacturing (aka 3D printing)

• Aerodynamic 3D blading

• Use of ceramics

• Higher firing temperatures

• Better sealing

• Improved heat transfer

These advances may lead to a 63% combined cycle efficiency by the end of the decade 

using air cooling, and beyond that, according to one GE expert, air cooling systems may 

be able to yield 65% combined cycle efficiencies. The advantage to air-cooled systems 

is the relatively short start up times compared with steam-cooled systems.

The utility sizes (300-500 MW) now being released commercially have efficiencies 

above 60%. Three sets of numbers were identified that considered how advanced 

NGCCs might reduce unit costs in future years: four model runs from Azevedo23 et al. 

 22 See Original EPRI data in Azevedo, I. P. Jaramillo, E. Rubin, and S. Yeh. Modeling Technology 

Learning for Electricity Supply Technologies. Phase II Report to Electric Power Research Institute. June 

2013. Last accessed from: http://www.cmu.edu/epp/iecm/rubin/PDF%20files/2013/FINAL%

20PHASE%20II%20REPORT%20TO%20EPRI_June%2030.pdf on April 22, 2015.

23 Azevedo, I., P. Jaramillo, E. Rubin, and S. Yeh, 2013. Modeling Technology Learning for Electricity 

Supply Technologies Phase II Report: Implied Learning Rates from REGEN Scenarios and Comparisons 

with Literature Values. Report to Electric Power Research Institute. June 2013. Last accessed from: 

http://www.cmu.edu/epp/iecm/rubin/PDF%20files/2013/FINAL%20PHASE%20II%20

REPORT%20TO%20 EPRI_June %2030.pdf on April 27, 2015.
Section 5

5-36 Leidos, Inc. File: EIA | 209089

2013, expert opinion from Varley24 2014, and the Mini Climate Assessment Model25

(2008). Those costs were normalized to the 2015 year and plotted in Figure 5-1. The 

variation within Azevedo’s work illustrates how climate change policies and 

uncertainties in natural gas prices can affect deployment of NGCCs and thus the 

learning rates and associated relative costs.

Figure 5-1. Projections of Cost Reductions for NGCCs from Three Studies

Siemens and General Electric pushed the advanced NGCCs to the market more rapidly 

than had been predicted five years ago, and this early adoption explains why the 2008 

Mini Climate Assessment Model was the only study that did not predict cost reductions 

before 2020. 

The average multipliers for the six cases (four from Azevedo et al. 2013) are also shown 

in Figure 5-1. These multipliers were used to derive the capital costs shown in Figure 

5-2, relative to the 2015 capital costs in the Reference Technology Case. The figure also 

uses the MiniCAM estimates for reductions in O&M costs, relative to the 2015 costs 

from the Reference Technology Case. Costs are presented in constant 2015 dollars.

Figure 5-2. Costs for New Equipment- ICC – Advanced Technology Case

Costs/Year 2015 2020 2025 2030 2035 2040

Variable O&M Costs ($/kWh) 0.0064 0.0064 0.0062 0.0060 0.0059 0.0057

Fixed O&M Costs ($/kW-year) 19.88 19.88 19.38 18.69 18.29 17.59

Total Equipment Cost ($/kW) 994 1,563 1,532 1,511 1,495 1,473

 24 Varley, J. 2014. “GE’s new all-air-cooled H class turbine.” Modern Power Systems. 10 April 2014. 

Last accessed from http://www.modernpowersystems.com/features/featureges-new-all-air-cooled-hclass-turbine-4212530/ on April 27, 2015. 25 Mini Climate Assessment Model (2008). Data from MiniCAM model, Pacific Northwest National 

Laboratory.
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Table 5-55

Industrial - Combined Cycle – Advanced New Equipment

Year 2015 2020 2025 2030 2035 2040

Output Capacity (kW) 103,128 103,128 103,128 103,128 103,128 103,128

Electric Heat Rate, HHV (Btu/kWh) 8,353 7,584 6,826 6,205 5,688 5,688

Electric Efficiency, HHV (%) 40.86 45 50 55 60 60

Fuel Input (MMBtu/hr) 861.43 782.17 703.95 639.91 586.59 586.59

Thermal Output (MMBtu/hr) 65.79 59.74 53.76 48.87 44.80 44.80

Total CHP Efficiency (%) 48.50 52.64 57.64 62.64 67.64 67.64

Power to Thermal Output Ratio 5.35 5.892 6.547 7.202 7.856 7.856

Net Heat Rate (Btu/kWh) 7556 6,860 6,174 5,613 5,145 5,145

Variable O&M Costs ($/kWh) 0.0064 0.0071 0.0074 0.0078 0.0083 0.0087

Fixed O&M Costs ($/kW-year) 19.88 22.07 23.02 24.19 25.81 27.06

(1) LM6000 PC Steam Injected at STP.

(2) Utilized GE APPS Model for performance results.

(3) Costs represented as current dollars.

Table 5-56

Industrial - Combined Cycle Capital Costs – Advanced New Equipment(1)

Year 2015 2020 2025 2030 2035 2040

Equipment ($/kW)(1) 994 1081 1133 1222 1318 1407

Installation Labor and Materials ($/kW)(2) 320 352 373 402 434 468

Engineering/Construction 

Management/Contingency (3)

280 308 326 352 380 410

Total Installed Cost ($/kW) 1,594 1741 1832 1976 2132 2284

(1) Costs represented as current dollars

(2) Equipment cost of reference case adjusted based on Figures 5-1 and 5-2.

(3) Assumes no change in values from reference values.

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

Assumes no change in values from reference values

File: EIA | 209089

Appendix A

ACRONYMS

AC Alternating Current

BOP Balance-of-Plant

Btu British Thermal Unit

Btu/kWh British Thermal Unit per kilowatt-hour

Btu/lb British Thermal Unit per pound

Btu/scf British Thermal Unit per standard cubic feet

C2H6 Ethane

C3H8 Propane

C4H10 n-Butane

CC Combined Cycle

CdTe Cadmium Telluride

CF Capacity Factor

CFC Commercial Fuel Cell

CH4 Methane

CHP Combined Heat and Power

CIGS Copper Indium Gallium Diselenide

CLS Commercial Large Solar Photovoltaic System

CNE Commercial – Natural Gas Engine

CNM Commercial – Natural Gas Micro-turbine

CNT Commercial – Natural Gas Turbine

CO Carbon Monoxide

CO2 Carbon Dioxide

COE Commercial – Oil Reciprocating Engine

Cost Estimate Base Capital Cost Estimate

CSS Commercial – Small Solar Photovoltaic System

CT Combustion Turbine

CTG Combustion Turbine and Generator

CWS Commercial – Wind System

CxHy General Hydrocarbon

° Degree

°C Degrees Celsius

°F Degrees Fahrenheit

DC Direct Current

DCS Distributed Control System

DG Distributed Generation

EIA U.S. Energy Information Administration

EPA Environmental Protection Agency

EPC Engineering, Procurement and Construction

FOM Fixed O&M

GSU Generator Step-up Transformer

HHV High(er) Heating Value
Appendix A

A-2 Leidos, Inc. File: EIA | 209089

HRSG Heat Recovery Steam Generator

Hz Hertz

ICC Industrial – Combined Cycle

IGT5 Industrial – Natural Gas Turbine

IGT10 Industrial – Natural Gas Turbine – 10,000 kW

IGT25 Industrial – Natural Gas Turbine – 25,000 kW

IGT40 Industrial – Natural Gas Turbine – 40,000 kW

IRE1 Industrial – Reciprocating Engine-1

IRE3 Industrial – Reciprocating Engine-3

ISO International Standard Organization

kg Kilograms

KJ Kilojoules

kJ/kg Kilojoules per kilogram

kV Kilovolt

kW Kilowatt

kWh Kilowatt-hour

lb Pound

Leidos Leidos Engineering, LLC

LHV Low(er) Heating Value

MCFC Molten Carbonate Fuel Cells

MJ Megajoules

MJ/scm Megajoules per standard cubic meter

MMBtu Million Btu

MMRF Major Maintenance Reserve Fund

MVA Mega-volt-amperes

MW Megawatt

MWh Megawatt-hour

N2 Nitrogen

NEMS National Energy Modeling System

NGCC Natural Gas Combined Cycle

NH3 Ammonia

NOX Nitrogen Oxides

O&M Operation and Maintenance

PAFC Phosphoric Acid Fuel Cell

PEM Proton Exchange Membrane

psig Pounds per Square Inch Gauge

PV Photovoltaic

Report This Report

RFC Residential Fuel Cell System

RPM Revolutions per Minute

RSS Residential Small Solar Photovoltaic

RWS Residential Wind System

scf Standard Cubic Feet

scm Standard Cubic Meters

SCR Selective Catalytic Reduction

SOFC Solid Oxide Fuel Cell
ACRONYMS

File: EIA | 209089 Leidos, Inc. A-3

ST Steam Turbine

STG Steam Turbine and Generator

U.S. United States

VOM Variable Operating and Maintenance

File: EIA | 209089

Appendix B

References

Distributed Generation System Characteristics and Costs in the Buildings Sector, 

U.S. Energy Information Administration, August 7, 2013, 

http://www.eia.gov/analysis/studies/distribgen/system/

Combined Heat and Power Database, ICF International, July 25, 2013, http://www.eeainc.com/chpdata/

2012 Wind Technologies Market Report, Energy Efficiency & Renewable Energy, 

U.S. Department of Energy, August 2013,

https://www1.eere.energy.gov/wind/pdfs/2012_wind_technologies_market_rep

ort.pdf

2012 Market Report on Wind Technologies in Distributed Applications, Energy 

Efficiency & Renewable Energy, U.S. Department of Energy, August 2013, 

http://www1.eere.energy.gov/wind/pdfs/2012_distributed_wind_technologies_

market_report.pdf

Fact Sheet: 2013 Distributed Wind Market Report, Energy Efficiency & Renewable 

Energy, U.S. Department of Energy, August 2013, 

http://energy.gov/eere/wind/downloads/fact-sheet-2013-distributed-windmarket-report

Annual Energy Outlook 2014 with projections to 2040, U.S. Energy Information 

Administration, DOE/EIA-0383(2014), April 2014

http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf

Fuel Cell Basics, ©2008 Smithsonian Institution,

http://americanhistory.si.edu/fuelcells/basics.htm

State of the States: Fuel Cells in America 2013, Fuel Cells 2000/U.S. Department of 

Energy, Energy Efficiency and Renewable Energy, October 2013

http://energy.gov/eere/fuelcells/downloads/state-states-fuel-cells-america-2013

http://energy.gov/sites/prod/files/2014/03/f12/state_of_the_states_2013.pdf

Small Wind Electric Systems, An Indiana Consumers Guide, U.S. Department of 

Energy, Energy Efficiency and Renewable Energy,

http://apps2.eere.energy.gov/wind/windexchange/pdfs/small_wind/small_wind

_in.pdf

High Efficiency Microturbine with Integral Heat Recovery, U.S. Department of Energy, 

Energy Efficiency and Renewable Energy, Industrial Technologies Program

http://www1.eere.energy.gov/manufacturing/distributedenergy/pdfs/capstone.p

df

2013IRP_CHP-Memo-LCOEexcel_10-04-12.pdf
Appendix C

C-2 Leidos, Inc. File: EIA | 209089

SGIP_CE_Report_Final.pdf

Industrial Distributed Energy, U.S. Department of Energy, Energy Efficiency & 

Renewable Energy, 

http://www1.eere.energy.gov/manufacturing/distributedenergy/

2.4 Microturbine/Combined Heat and Power (CHP) Technologies, Environmental 

Technology Verification (ETV) Program, Environmental Protection Agency

http://www.epa.gov/chp/documents/microturbine_tech.pdf

Microturbines, by Barney L. Capehart, PhD, CEM, College of Engineering, University 

of Florida, National Institute of Building Sciences, Whole Building Design 

Guide (WBDG), August 31, 2010

http://www.wbdg.org/resources/microturbines.php

http://www.epa.gov/ttnchie1/ap42/ch03/final/c03s02.pdf

GE’s Jenbacher Gas Engines, Clarke Energy,

http://www.clarke-energy.com/gas-engines/

Solar Energy Industries Association First Quarter Study, Solar Energy Industries 

Association.

Appendix C
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Appendix D

Technology Definitions and Calculations

Key Terms Used in Calculating CHP Efficiency – EPA Guidelines26

Calculating a CHP system’s efficiency requires an understanding of several key terms, 

described below.

CHP system. The CHP system includes the unit in which fuel is consumed (e.g. turbine, 

boiler, engine), the electric generator, and the heat recovery unit that transforms 

otherwise wasted heat to useable thermal energy.

• Total fuel energy input (QFUEL). The thermal energy associated with the 

total fuel input. Total fuel input is the sum of all the fuel used by the CHP 

system. The total fuel energy input is often determined by multiplying the 

quantity of fuel consumed by the heating value of the fuel.

• Net useful power output (WE). Net useful power output is the gross power 

produced by the electric generator minus any parasitic electric losses―in other 

words, the electrical power used to support the CHP system. (An example of a 

parasitic electric loss is the electricity that may be used to compress the natural 

gas before the gas can be fired in a turbine.)

• Net useful thermal output (ΣQTH). Net useful thermal output is equal to the 

gross useful thermal output of the CHP system minus the thermal input. An 

example of thermal input is the energy of the condensate return and makeup 

water fed to a heat recovery steam generator (HRSG). Net useful thermal 

output represents the otherwise wasted thermal energy that was recovered by 

the CHP system.

Calculating Total System Efficiency

The most commonly used approach to determining a CHP system’s efficiency is to 

calculate total system efficiency. Also known as thermal efficiency, the total system 

efficiency (ηo) of a CHP system is the sum of the net useful power output (WE) and net 

useful thermal outputs (Σ QTH) divided by the total fuel input (QFUEL), as shown below:

ηO = WE + Σ QTH

 QFUEL

The calculation of total system efficiency is a simple and useful method that evaluates 

what is produced (i.e., power and thermal output) compared to what is consumed (i.e., 

fuel). CHP systems with a relatively high net useful thermal output typically correspond 

to total system efficiencies in the range of 60 to 85 percent.

Note that this metric does not differentiate between the value of the power output and 

the thermal output; instead, it treats power output and thermal output as additive 

 26 U.S. EPA, Catalog of CHP Technologies – Appendix A: Expressing CHP Efficiency, March 2015.
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properties with the same relative value. In reality and in practice, thermal output and 

power output are not interchangeable because they cannot be converted easily from one 

to another. However, typical CHP applications have coincident power and thermal 

demands that must be met. It is reasonable, therefore, to consider the values of power 

and thermal output from a CHP system to be equal in many situations.

Calculating Effective Electric Efficiency

Effective electric efficiency calculations allow for a direct comparison of CHP to 

conventional power generation system performance (e.g., electricity produced from 

central stations, which is how the majority of electricity is produced in the United

States). Effective electric efficiency (εEE) can be calculated using the equation below, 

where (WE) is the net useful power output, (ΣQTH) is the sum of the net useful thermal 

outputs, (QFUEL) is the total fuel input, and a equals the efficiency of the conventional 

technology that otherwise would be used to produce the useful thermal energy output if 

the CHP system did not exist:

εEE = WE 

 QFUEL – Σ (QTH / α)

For example, if a CHP system is natural gas fired and produces steam, then α represents 

the efficiency of a conventional natural gas-fired boiler. Typical α values for boilers 

are: 0.8 for natural gas-fired boiler (used in this report), 0.75 for a biomass-fired boiler, 

and 0.83 for a coal-fired boiler.

The calculation of effective electric efficiency is essentially the CHP net electric output 

divided by the additional fuel the CHP system consumes over and above what would 

have been used by conventional systems to produce the thermal output for the site. In 

other words, this metric measures how effectively the CHP system generates power 

once the thermal demand of a site has been met.

Typical effective electrical efficiencies for combustion turbine-based CHP systems are 

in the range of 51 to 69 percent. Typical effective electrical efficiencies for reciprocating 

engine-based CHP systems are in the range of 69 to 84 percent.

Many CHP systems are designed to meet a host site’s unique power and thermal demand 

characteristics. As a result, a truly accurate measure of a CHP system’s efficiency may 

require additional information and broader examination beyond what is described in this 

report.

Reciprocating Engine Calculation Basis

Electric Heat Rate, HHV (Btu/kWh) = 3413 / efficiency of conversion of fuel energy 

input to net electrical generation output. There are 3,413 Btu per kWh; this is the 

conversion factor used. 

Thermal Output (MMBtu/hr) = useful thermal output generated by the engine 

recovered as heat energy from engine jacket water and exhaust gas generating hot water 

at 120 °C.
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Total CHP Efficiency (%) = (Thermal Output + Thermal equivalent of Electrical 

Output) / Fuel Input. Thermal equivalent of Electrical Output = Output Capacity (kW) 

* 3413 Btu/kWh.

Power to Thermal Output Ratio = Electric Efficiency / Thermal Efficiency. Thermal 

Efficiency = Total CHP Efficiency – Electric Efficiency.

Net Heat Rate = (total fuel energy input – fuel that would normally be used to generate 

the equivalent thermal output as the CHP system thermal output) / CHP electric output. 

In this analysis, displaced boilers are assumed to be 80 percent efficient.

Natural Gas Turbine Calculation Basis

Electric Heat Rate = Fuel Input/Electric Capacity

Fuel Input = Calculated based on heat rate and net power output

Thermal Output = useful thermal output generated by the engine recovered as heat 

energy from engine jacket water and exhaust gas generating hot water at 120 °C.

Total CHP Efficiency (%) = (Thermal Output + Thermal equivalent of Electrical 

Output) / Fuel Input. Thermal equivalent of Electrical Output = Output Capacity (kW) 

* 3413 Btu/kWh.

Power to Thermal Output Ratio = Electric Efficiency / Thermal Efficiency. Thermal 

Efficiency = Total CHP Efficiency – Electric Efficiency.

Net Heat Rate = (total fuel energy input – fuel that would normally be used to generate 

the equivalent thermal output as the CHP system thermal output) / CHP electric output. 

In this analysis, displaced boilers are assumed to be 80 percent efficient.