Distributed Generation, 

Battery Storage, and 

Combined Heat and Power 

System Characteristics and 

Costs in the Buildings and 

Industrial Sectors

March 2024

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration | Distributed Generation, Battery Storage, and Combined Heat and Power System Characteristics and 

Costs in the Buildings and Industrial Sectors i

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

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

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

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

U.S. Energy Information Administration | Distributed Generation, Battery Storage, and Combined Heat and Power System Characteristics and 

Costs in the Buildings and Industrial Sectors 1

Distributed Generation, Battery Storage, and Combined Heat and 

Power System Characteristics and Costs in the Buildings and 

Industrial Sectors

Distributed generation (DG) in the residential and commercial buildings sectors and in the industrial 

sector refers to onsite, behind-the-meter energy generation. DG often includes electricity from 

renewable energy systems such as solar photovoltaics (PV) and small wind turbines, as well as battery 

energy storage systems that enable delayed electricity use. DG can also include electricity and captured 

waste heat from combined heat and power (CHP) systems. Many factors influence the market for DG, 

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

significantly depending on location, size, and application.

Current and future DG equipment costs are subject to uncertainty. As part of our Annual Energy Outlook 

(AEO), we update projections to reflect the most current, publicly available historical cost data, and we 

use a number of third-party estimates of future costs in the near and long terms. DG system 

characteristics and performance data are likewise based on currently available technology and expert 

projections of future technologies.

Before the AEO2025 reporting cycle, we hired an external consultant to develop a cost and performance 

characterization report of PV, small wind, and CHP installations in residential and commercial buildings 

and the industrial sector.1 The consultant provided cost and performance data for systems of various 

sizes in select historical years, 2012 through 2022.

From this report, we use national-level average annual costs for a typical system size in each sector. The 

consultant adapted the additional information in the report—including equipment degradation rate, 

system life, annual maintenance cost, inverter cost, and conversion efficiency—for the Distributed 

Generation Submodules of the Residential and Commercial Demand Modules of the National Energy 

Modeling System. Abbreviated tables of these system sizes and costs are available in the residential and 

commercial chapters of the Assumptions to the AEO.

As described in the assumptions reports and in our report on Modeling Distributed Generation in the 

Buildings Sectors, other information not included in the report—such as resource availability, avoided 

electricity cost, interconnection limitations, incentive amounts, installed capacity-based cost reductions, 

and other factors—ultimately affect the amount of DG and CHP capacity added within a given sector 

and year.

The report, Analyze Distributed Generation, Battery Storage, and Combined Heat and Power Technology 

Data and Develop Performance and Cost Estimates and Analytic Assumptions for the National Energy 

Modeling System: Final Report, is available in Appendix A. When referencing the report, cite it as a 

report by Z Federal and DNV, prepared for the U.S. Energy Information Administration.

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.
March 2024

U.S. Energy Information Administration | Distributed Generation, Battery Storage, and Combined Heat and Power System Characteristics and 

Costs in the Buildings and Industrial Sectors 2

APPENDIX A
EOP IV CONTRACT #: DE-EI0002895

SOLICITATION #: 89303023REI000093

Distributed Generation, Battery, 

and Combined Heat and Power 

Research – Final Report

U.S. Department of Energy

U.S. Energy Information Administration

Office of Energy Analysis

Date: March 22, 2024
DNV – www.dnv.com Page i

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 DNV 

and Z Federal constitute the opinions of DNV and Z Federal. To the extent that statements, 

information and opinions provided by the client or others have been used in the preparation of this 

report, DNV and Z Federal have relied upon the same to be accurate, and for which no 

assurances are intended and no representations or warranties are made. DNV and Z Federal

make no certification and gives no assurances except as explicitly set forth in this report.
DNV – www.dnv.com Page ii

Table of contents

1 INTRODUCTION.............................................................................................................. 1

1.1 Background 1

1.2 Overview of reviewed technologies 2

1.3 Overview of cost estimation methodology 4

1.3.1 Capital costs 4

1.3.2 O&M costs 5

1.3.3 Cost factors and performance attributes 5

1.3.4 Technology performance specifications 6

1.4 Report organization 7

2 SOLAR PHOTOVOLTAIC SYSTEMS .............................................................................. 9

2.1 Solar PV systems technology attributes and cost data 9

2.1.1 Technology attributes and cost estimation methodology 9

2.1.2 System configurations 9

2.1.3 Generation shapes and technology attributes 12

2.1.4 System performance attributes 12

2.1.5 2022 cost data 15

2.1.6 Historical cost data 18

2.1.7 O&M cost data 20

2.2 Solar PV market discussion 21

2.2.1 Solar PV component trends 21

2.2.2 Resource and material availability trends 22

2.2.3 Technology research and development trends 22

2.2.4 Disposal and recycling costs 23

2.2.5 Federal policies and market incentives 24

2.2.6 Relationship to other DG technologies 26

2.3 Solar PV summary and conclusions 26

3 BATTERY STORAGE .................................................................................................... 28

3.1 Battery storage technology attributes and cost data 28

3.1.1 Overview 28

3.1.2 Technology attributes and cost estimation methodology: Battery storage 28

3.1.3 System configurations 28

3.1.4 Technology attributes and generation shapes 30

3.1.5 System performance attributes 31

3.1.6 2022 cost data 33

3.1.7 Historical cost data 34

3.1.8 O&M cost data 36

3.2 Battery storage market discussion 37

3.2.1 Resource and material availability trends 37

3.2.2 Federal policies 39

3.2.3 Market incentives 41
DNV – www.dnv.com Page iii

3.2.4 Relationship to other DG technologies 43

3.2.5 Technology research and development rates 44

3.2.6 Current and anticipated rates of market adoption by sector 44

3.2.7 Relationship between battery chemistry and applications 44

3.2.8 Trends in battery disposal, recycling, or repurposing 47

4 WIND ENERGY SYSTEMS............................................................................................ 50

4.1 Wind energy systems technology attributes and cost data 50

4.1.1 System configurations 50

4.1.2 Technology attributes and generation shapes 51

4.1.3 System performance attributes 51

4.1.4 2022 cost data 52

4.1.5 Historical cost data 52

4.2 Wind market discussion 54

4.2.1 Resource and material availability trends 54

4.2.2 Federal policies and market incentives 55

4.2.3 Relationship to other technologies 55

4.2.4 Technology research and development rates 56

5 FUEL CELLS.................................................................................................................. 57

5.1 Fuel cell technology attributes and cost data 57

5.1.1 Overview 57

5.1.2 System configurations 57

5.1.3 Technology attributes 58

5.1.4 System performance attributes 59

5.1.5 System cost data 60

5.1.6 O&M cost data 62

5.2 Fuel cell market discussion 63

5.2.1 Resource and material availability trends 63

5.2.2 Government policies and market incentives 64

5.2.3 Relationship to other technologies 65

5.2.4 Technology research and development rates 66

5.2.5 Hydrogen use for fuel cells 67

6 COMBINED-HEAT-AND-POWER SYSTEMS ................................................................ 69

6.1 CHP system technology attributes and cost data 69

6.1.1 Overview 69

6.1.2 System configurations and technology attributes 69

6.1.3 System performance attributes 74

6.1.4 System cost data 79

6.1.5 O&M cost data 81

7 COMMERCIAL AND INDUSTRIAL MARKET DISCUSSION.......................................... 83

7.1 In-depth interview methodology 83

7.2 Economic 84
DNV – www.dnv.com Page iv

7.2.1 Spark spread 84

7.2.2 Reliability 84

7.2.3 Incentives and tax credits 85

7.2.4 Exporting electricity to the grid 85

7.3 Economic risk 86

7.4 Environmental 86

7.5 Regulatory 87

7.5.1 Federal regulations 87

7.5.2 State and local regulations 87

7.5.3 Utility processes 88

7.5.4 Regulatory environment: ISOs versus utility-operated systems 88

7.6 Technical 88

7.6.1 New versus retrofit 88

7.6.2 CHP versus boiler 88

7.6.3 Where is CHP a good fit? 89

7.6.4 Technological innovations 91

7.7 General 93

7.7.1 Cultural factors influencing adoption 93

7.7.2 Barriers to CHP adoption 93

7.8 Non-CHP generation 94

7.8.1 Non-CHP versus CHP self-generation 94

7.8.2 Economics of non-CHP self-generation 95

8 REFERENCES............................................................................................................... 97

List of figures

Figure 2-1. Performance metrics for PV systems ......................................................................... 12

Figure 2-2. U.S. average residential solar PV system capital costs (kW-DC, 2022 $) .................. 18

Figure 2-3. U.S. average commercial solar PV system (100 kW-DC) capital costs ($/kW-DC, 2022 

$) ................................................................................................................................................. 19

Figure 2-4. U.S. average commercial solar PV system (250 kW-DC) capital costs ($/kW-DC, 2022 

$) ................................................................................................................................................. 19

Figure 2-5. U.S. average commercial solar PV system (1,000 kW-DC) capital costs ($/kW-DC, 

2022 $) ........................................................................................................................................ 20

Figure 2-6. U.S. average solar PV historical O&M cost data ($/kW-year-DC, 2022 $) by customer 

sector and system configuration................................................................................................... 21

Figure 3-1. Percentage of solar PV systems with battery storage by segment (2012–2022) ........ 32

Figure 3-2. U.S. average residential standalone storage system capital costs ($/kW-DC, 2022 $)35

Figure 3-3. U.S. average residential solar + storage system capital costs ($/kW-DC, 2022 $) ..... 35

Figure 3-4. U.S. average commercial standalone storage system (medium, 150 kW-DC, 300 kWh) 

capital costs ($/kW-DC, 2022 $)................................................................................................... 36

Figure 3-5. U.S. average commercial solar (250 kW-DC) + storage system (150 kW-DC, 300 kWh 

battery storage) capital costs ($/kW-DC, 2022 $)......................................................................... 36
DNV – www.dnv.com Page v

Figure 3-6. U.S. average battery storage historical O&M cost data ($/kW-yr-DC, 2022 $) by 

customer sector ........................................................................................................................... 37

Figure 3-7. Stationary energy storage battery chemistry market share and forecast all sectors, 

2015–2030................................................................................................................................... 46

Figure 4-1. U.S. average residential distributed wind project cost data (2015–2022, 2022 $)....... 52

Figure 4-2. U.S. average small commercial distributed wind project cost data (2012–2022, 2022 $)

.................................................................................................................................................... 53

Figure 4-3. U.S. average medium commercial distributed wind project cost data (2012–2022, 2022 

$) ................................................................................................................................................. 53

Figure 4-4. U.S. average large commercial distributed wind project cost data (2012–2022, 2022 $)

.................................................................................................................................................... 54

Figure 4-5. Annual daily-averaged complementarity (represented by the Pearson Correlation 

Metric) for 2013 in the contiguous United States .......................................................................... 56

Figure 5-1. U.S. average residential fuel cell system capital costs ($/kW-AC, 2022 $) ................. 61

Figure 5-2. U.S. average commercial fuel cell system capital costs ($/kW-AC, 2022 $) ............... 62

Figure 5-3. U.S. average residential fuel cell system O&M costs ($/kWh, 2022 $) ....................... 63

Figure 5-4. U.S. average commercial fuel cell system O&M costs ($/kWh, 2022 $) ..................... 63

Figure 5-5. Diagram of a solar PV + fuel cell hybrid energy system ............................................. 65

Figure 5-6. Progress of end of test membrane electrode assembly performance with M2FCT 

developed catalysts, 2021–2023.................................................................................................. 67

Figure 6-1. U.S. annual commercial CHP installations (2012–2022) ............................................ 70

Figure 6-2. U.S. annual industrial CHP installations (2012–2022)................................................ 71

Figure 6-3. U.S. average commercial CHP system capital costs ($/kW-AC, 2022 $).................... 80

Figure 6-4. U.S. average industrial CHP system capital costs ($/kW-AC, 2022 $)........................ 81

Figure 6-5. U.S. average commercial CHP system O&M costs ($/kWh, 2022 $).......................... 82

Figure 6-6. U.S. average industrial CHP system O&M costs ($/kWh, 2022 $).............................. 82

Figure 7-1. CHP System Counts and Total Capacity by Industry Sector by Count and MW-AC... 89

Figure 7-2. CHP System Counts and Total Capacity for Manufacturing Industries by Count and 

MW-AC (at 3-Digit NAICS)........................................................................................................... 90

Figure 7-3. CHP System Counts and Total Capacity: Top 10 Five-Digit NAICS Industries by Count 

and MW-AC ................................................................................................................................. 91

Figure 7-4. Annual and cumulative market forecast for battery storage........................................ 96

List of tables

Table 1-1. List of solar and storage technologies assessed and nominal capacity (2022).............. 3

Table 1-2. List of wind, fuel cell, and CHP technologies assessed and nominal capacity (2022).... 4

Table 1-3. Technology performance specifications (2022) ............................................................. 6

Table 2-1. Technology attributes for solar PV configurations and representative systems ........... 11

Table 2-2. Residential solar PV system performance attributes ................................................... 12

Table 2-3. Commercial solar PV system performance attributes for median representative system 

capacity........................................................................................................................................ 13

Table 2-4. Commercial solar PV system (100 kW-DC) performance attributes ............................ 13

Table 2-5. Commercial solar PV system (250 kW-DC) performance attributes ............................ 14

Table 2-6. Commercial solar PV system (500 kW-DC) performance attributes ............................ 14

Table 2-7. Commercial solar PV system (1,000 kW-DC) performance attributes.......................... 15

Table 2-8. Solar PV inverter market share (percentage) by customer sector and year................. 16

Table 2-9. Cost categories and associated assumptions.............................................................. 17

Table 2-10. O&M cost categories for solar PV systems by customer sector and configuration..... 20

Table 3-1. Technology attributes for battery storage configurations and representative systems . 29

Table 3-2. Residential battery storage system performance attributes ......................................... 31
DNV – www.dnv.com Page vi

Table 3-3. Small commercial battery storage system performance attributes............................... 32

Table 3-4. Battery storage cost categories and assumptions for residential and commercial 

systems........................................................................................................................................ 33

Table 3-5. Cost reduction factors for solar + storage systems...................................................... 34

Table 3-6. Example state-level battery storage incentives............................................................ 42

Table 3-7. Common EV battery chemistries globally .................................................................... 45

Table 4-1. Technology attributes for residential and commercial wind configurations and 

representative systems ................................................................................................................ 51

Table 4-2. Residential and commercial wind system performance attributes (2022) .................... 51

Table 5-1. Fuel cell configurations, types, and representative system capacity ............................ 57

Table 5-2. Residential fuel cell system performance attributes..................................................... 59

Table 5-3. Commercial fuel cell performance attributes................................................................ 60

Table 6-1. CHP configurations, types, and representative system capacities............................... 71

Table 6-2. Commercial natural gas reciprocating engine (300 kW-AC) CHP performance attributes

.................................................................................................................................................... 75

Table 6-3. Commercial oil-fired reciprocating engine (350 kW-AC) CHP performance attributes . 75

Table 6-4. Commercial natural gas turbine (3,300 kW-AC) CHP performance attributes.............. 76

Table 6-5. Commercial microturbine (200 kW-AC) CHP performance attributes .......................... 76

Table 6-6. Industrial natural gas reciprocating engine (1,000 kW-AC and 3,000 kW-AC) CHP 

performance attributes ................................................................................................................. 77

Table 6-7. Industrial gas turbine (5,000 kW-AC, 10,000 kW-AC, 25,000 kW-AC, and 40,000 kWAC) CHP performance attributes.................................................................................................. 78

Table 6-8. Industrial combined-cycle (100,000 kW-AC and 375,000 kW-AC) CHP performance 

attributes...................................................................................................................................... 79

Table 6-9. CHP system major overhaul components and replacement timeline ........................... 81
DNV – www.dnv.com Page vii

Acronyms and Abbreviations

AEO Annual Energy Outlook

AC Alternating current

AD/CVD Anti-dumping and countervailing duties

AMO DOE’s Advanced Manufacturing Office

BESS Battery energy storage system

BLS U.S. Bureau of Labor Statistics

BNEF Bloomberg New Energy Finance

BOP Balance of plant

BOS Balance of system

BTM Behind-the-meter

Btu British thermal units

CBECS EIA’s Commercial Buildings Energy Consumption Survey

CBP U.S. Customs and Border Protection Agency

CEC California Energy Commission

CHP Combined heat and power

c-Si Crystalline silicon

C&I Commercial and industrial

DC Direct current

DER Distributed energy resources

DG Distributed generation

DOC U.S. Department of Commerce

DOE U.S. Department of Energy

DRC Democratic Republic of Congo

EBOS Electrical balance of system

EIA U.S. Energy Information Administration

EOL End-of-life

EPA U.S. Environmental Protection Agency

EPC Engineering, procurement, and construction

ESG Environmental, social, and governance

ESS Energy storage system

EUL Effective useful life

EV Electric vehicle

EVA Ethylene vinyl acetate

FCAB Federal Consortium for Advanced Batteries

GHG Greenhouse Gas

GWh Gigawatthour

HFTO DOE’s Hydrogen and Fuel Cell Technologies Office

HHV Higher heating value

H2 Hydrogen

IEA International Energy Agency

LFP Lithium iron phosphate

ILR Inverter loading ratio

IRA Inflation Reduction Act

ITC Investment tax credit

kW Kilowatt

kW-AC Kilowatt alternating current

kW-DC Kilowatt direct current

ES Kilowatthour

LAB Lead acid battery

LBNL Lawrence Berkeley National Laboratory
DNV – www.dnv.com Page viii

MACRS Modified Accelerated Cost Recovery System

MCFC Molten carbonate fuel cell

MECS EIA’s Manufacturing Energy Consumption Survey

MW-AC Megawatt alternating current

MW-DC Megawatt direct current

M2FCT Million Mile Fuel Cell Truck Consortium

NAICS North American Industry Classification System

NEMS National Energy Modeling System

NMC Nickel manganese cobalt

NREL National Renewable Energy Laboratory

O&M Operation and maintenance

OEA EIA’s Office of Energy Analysis

PACE Property assessed clean energy

PAFC Phosphoric acid fuel cell

PEM Polymer electrolyte membrane

PEMFC Polymer electrolyte membrane fuel cell

PERC Passivated emitter and rear cell

PNNL Pacific Northwest National Laboratory

PSPS Public safety power shutoffs

PTC Production tax credit

PV Photovoltaic

R&D Research and development

REAP Rural Energy for America Program

RECS EIA’s Residential Energy Consumption Survey

SAM NREL’s System Advisor Model

SBOS Structural balance of system

SECC Smart Energy Consumer Collaborative

SGIP California’s Self-Generation Incentive Program

SOFC Solid oxide fuel cell

TOPCon Tunnel oxide passivated contract

TTS Lawrence Berkeley National Laboratory’s Tracking the Sun

TWh Terawatthour

UFLPA Uyghur Forced Labor Prevention Act

V Volt

W Watt

WETO Wind Energy Technologies Office

WRO Withhold Release Order
DNV – www.dnv.com Page 1

1 INTRODUCTION

This report presents the Z Federal and DNV analysis and data update for distributed generation 

(DG), battery storage, and combined-heat-and-power (CHP) technology and cost inputs into the 

U.S. Energy Information Administration’s (EIA) National Energy Modeling System (NEMS). This 

document is accompanied by workbooks that map the detailed technology and cost data to inputs 

in NEMS. The workbooks include publicly available versions with summary information and versions 

for EIA’s internal use only that contain proprietary data. EIA published a previous iteration of this 

effort in 2020.1

1.1 Background

EIA’s Office of Energy Analysis (OEA) is responsible for the development, maintenance, and use of 

NEMS. NEMS is the primary analysis tool for the development of mid- and long-term projections of 

domestic energy markets published each year in the Annual Energy Outlook (AEO). Along with the 

annual projections of energy markets, OEA provides a wide array of analyses of current energy and 

environmental issues and their potential impacts on energy markets using NEMS. 

DG in the residential, commercial, and industrial sectors (customer sectors) refers to on-site, behindthe-meter (BTM) generation of energy from distributed energy resources (DER), including solar 

photovoltaic (PV), small-scale wind, fuel cells, and combined-heat-and-power (CHP) systems. An 

emerging technology in the DG market is BTM battery energy storage paired with PV systems. Many 

factors influence the DG market, including resource and material availability, federal and state 

policies, technology research and development, costs, and DG technology interrelationships. This 

report presents the technology cost and performance assessment of DG technologies, BTM battery 

systems, and CHP systems for residential, commercial, and industrial applications. OEA specified 

the technologies selected for assessment in each sector based on the existing technologies 

represented in NEMS. The assessment for each technology includes:

• Operational data for each technology aligned with customer sectors, including expected 

kilowatthour (kWh) output by location as appropriate, usage characteristics by customer sector, 

performance characteristics such as efficiency and capacity factor, useful life expectations, 

incorporation of customer usage as appropriate, long-term degradation curves, and heat rates 

and thermal output.

• Current system costs and system capacity configurations by customer sector, including 

installation, operation and maintenance (O&M), permitting, and capital cost categories. The cost 

analysis includes the following for all technologies and associated configurations:

o Installed cost and O&M costs on a dollar per kilowatt ($/kW) and dollar per kilowatthour 

($/kWh) basis.

o Expected end-use customer-sited installed costs (including dealer and installer markup/margin) over time.

o Buying options (direct purchase, loans, leases, property assessed clean energy [PACE],

etc.).

o Customer sector composite financial analysis/cash flow, levelized cost-of-energy for 

purchase, and lease options.

1 EIA, Distributed Generation, Battery Storage, and Combined Heat and Power System Characteristics and 

Costs in the Buildings and Industrial Sectors, May 2020. 
DNV – www.dnv.com Page 2

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

• The reference residential technologies information for 2015−2022. The reference industrial 

technologies information for 2015 and 2018−2022. The commercial technologies information for 

2012−2022.

• The reference equipment tables provided in this report present cost and performance 

assumptions for new equipment installation, allowing for a direct comparison of new equipment 

across the projection period. Differences in costs and performance by year can occur due to

functional efficiency improvements and equipment and installation cost escalation. 

• The cost estimates include site preparation, structures, equipment, electrical, distribution cost, 

engineering and design, subcontractor fee and budget contingency, and owner’s costs (specific 

to commercial and industrial sectors). All costs are based on 2022 prices and wages for a U.S. 

average with no location impacts (for example, urban construction constraints) or infrastructure 

needs (for example, a project-dedicated interconnection upgrade cost). Performance 

parameters include the electric heat rate based on the higher heating value (HHV) 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, and fixed and 

variable operating costs. 

1.2 Overview of reviewed technologies

This study evaluated the most common DER technologies adopted by residential, commercial, and 

industrial end users in the United States. 

Solar photovoltaic systems

Solar PV systems convert sunlight into electrical energy. DNV determined the average system 

capacity for standalone solar PV systems using a variety of DNV proprietary and public data sources.

Annual hourly generation was modeled for each representative system using DNV’s SolarFarmer 

modeling software and National Renewable Energy Laboratory’s (NREL’s) System Advisor Model

(SAM).

Solar photovoltaic + battery energy storage systems

The solar PV technology in the PV + battery energy storage system (BESS) was modeled using the 

same specifications as the standalone PV technology, with the exception of nameplate capacity. 

DNV determined that average system capacity for PV + BESS configurations are on average larger 

than standalone PV systems. DNV further segmented the PV + BESS technology by new PV + 

BESS installed where the PV and battery were installed and became operational together, and it 

added a Battery Retrofit case where a battery is added to an existing residential solar PV system.

Standalone battery energy storage systems

This report also assessed standalone battery storage systems. DNV assumed a fully integrated 

BESS for the residential and commercial sectors, which includes a battery pack, a bidirectional 

inverter, wiring, disconnect, and casing based on residential and commercial battery energy storage 

manufacturers such as Enphase, Sonnen, and Tesla.

Wind energy systems

Distributed wind technology is a relatively mature DER. Wind turbines generate electricity by 

converting kinetic energy in the wind into rotating shaft power that spins an alternating current (AC)
DNV – www.dnv.com Page 3

generator. BTM small-scale wind systems typically serve rural homes, farms, and manufacturing 

facilities due to their size and land requirements. Wind resources, high retail electricity prices, and 

favorable policies are the key contributing factors to BTM wind system economics. 

Fuel cells

Like BESS, fuel cells are a scalable technology that may contain a few to hundreds of individual fuel 

cells stacked together. An individual fuel cell consists of an electrolyte sandwiched between two 

electrodes. On either side of the cell, bipolar plates are located to help distribute gases and serve 

as current collectors. DNV assumed a combination of polymer electrolyte membrane (PEM) CHP 

configurations and solid oxide fuel cells (SOFC) CHP configurations for the residential fuel cell 

application and a combination of molten carbonate fuel cell (MCFC) and phosphoric acid fuel cell 

(PAFC) CHP configurations for the commercial fuel cell application.

Combined heat and power 

CHP, or cogeneration, is a mature technology that has been used in the power sector and as a 

private generation resource for decades. The two most common CHP technologies for commercial 

and small-to-medium industrial applications are reciprocating engines and microturbines. 

Distributed CHP systems are installed at individual customer sites and are typically sized to provide 

most of the site’s thermal energy (heating and/or cooling). CHP systems can offset a portion of site 

electricity, as well as inject power back into the grid when applicable.

Representative system sizes

Table 1-1 summarizes the representative system capacity for solar PV, solar + storage, and storage 

technologies used in the analysis for this study. Table 1-2 summarizes the representative capacities 

used for wind, fuel cell, and CHP systems.

Table 1-1. List of solar and storage technologies assessed and nominal capacity (2022)

Sector Configuration Technology Technology 

Size Bin

Representative System 

Capacity

Residential

Solar PV (standalone) Solar PV Small 7.1 kW-DC

Solar + Storage

Solar PV Small 7.9 kW-DC

Battery Storage 

(combined w/solar)

Small 5 kW-DC (12.5 kWh-DC)

Battery Storage (retrofit) Small 4.5 kW-DC (10 kWh-DC)

Storage (standalone) Battery Storage (standalone) Small 6.9 kW-DC (13.5 kWh-DC)

Commercial

Solar PV (standalone) Solar PV

Small 1 28.5 kW-DC

Small 2 100 kW-DC

Medium 250 kW-DC

Large 1 500 kW-DC

Large 2 1,000 kW-DC

Solar + Storage

Solar PV

Small 1 28.5 kW-DC

Small 2 100 kW-DC

Medium 250 kW-DC

Large 1 500 kW-DC

Battery Storage

(combined w/solar)

Small 1 20 kW-DC (40 kWh-DC)

Small 2 60 kW-DC (120 kWh-DC)

Medium 150 kW-DC (300 kWh-DC)

Large 1 300 kW-DC (600 kWh-DC)
DNV – www.dnv.com Page 4

Sector Configuration Technology Technology 

Size Bin

Representative System 

Capacity

Storage (standalone) Battery Storage (standalone)

Small 60 kW-DC (120 kWh-DC)

Medium 150 kW-DC (300 kWh-DC)

Large 1 300 kW-DC (600 kWh-DC)

Industrial Storage (standalone) Battery Storage (standalone)

Small 100 kW-DC (400 kWh-DC)

Medium 500 kW-DC (2,000 kWh-DC)

Large 1,000 kW-DC (4,000 kWh-DC)

Note: kW-DC=kilowatt direct current.

Table 1-2. List of wind, fuel cell, and CHP technologies assessed and nominal capacity

(2022)

Sector Configuration Technology

(includes fuel type if applicable)

Technology 

Size Bin

Representative 

System Capacity

Residential

Wind Small Wind Small 9.3 kW-AC

CHP Fuel Cell Small 5.0 kW-AC

Commercial

Wind Small Wind

Small 40 kW-AC

Medium 300 kW-AC

Large 2,000 kW-AC

CHP

Fuel Cell Medium 300 kW-AC

Reciprocating Engine (Gas) Small 300 kW-AC

Reciprocating Engine (Oil) Small 350 kW-AC

Gas Turbine Small 3,300 kW-AC

Microturbine (Gas) Medium 200 kW-AC

Industrial CHP

Reciprocating Engine (Gas)

Medium 1,000 kW-AC

Large 3,000 kW-AC

Gas Turbine

Medium 5,000 kW-AC

Large 1 10,000 kW-AC

Large 2 25,000 kW-AC

Large 3 40,000 kW-AC

Combined Cycle

Small 100,000 kW-AC

Large 375,000 kW-AC

Note: kW-AC=kilowatt alternating current.

1.3 Overview of cost estimation methodology

Capital costs and O&M costs were developed for each individual system detailed in the previous 

two tables, using the process defined in the following sections, with additional detail for individual 

systems provided in the respective technology sections. All cost values included throughout are 

reported on a 2022 constant (real) dollar basis.

1.3.1 Capital costs

Capital costs were developed to include all costs incurred to the point of system installation for each 

technology, identified capacity, and year within the analysis timeframe. All costs are in 2022 constant 

(real) dollars, and for a non-specific location in the United States. Additional capital costs were 

developed for each state for residential and commercial solar PV and battery storage technologies, 

and they are further described in Subsection 1.3.3. Given the variety in the level of detail of source 

data, capital cost estimates were derived from multiple unique categories for each individual 

technology, but they can be generally grouped into the following four categories:
DNV – www.dnv.com Page 5

• Equipment costs include hardware and equipment costs for the specific technology (for 

example, solar PV modules and inverter(s), battery pack(s) and inverter(s), engines, turbines).

• Balance of plant (BOP) or balance of system (BOS) costs include costs of associated 

structural and electrical components (for example, mounts, racking, wiring).

• Installation soft costs include items such as labor, project design and engineering, 

construction management, logistics and miscellaneous costs, and permitting and inspections.

• Other soft costs include items such as taxes, customer acquisition, overhead and margin, and 

general developer costs.

1.3.2 O&M costs

O&M costs refer to expenses required to ensure continuous operation of the technology within its 

specified capacity range and operating parameters after system installation and for the specified 

expected useful system life, considering planned system downtime. DNV developed both fixed and 

variable O&M costs. Fixed O&M costs are typically considered routine costs, which do not change 

based on system output. Fixed costs represent most O&M costs for all technologies. The analysis

included the following six types of fixed O&M costs:

• System cleaning and vegetation management (if applicable)

• System inspection and monitoring

• Part/equipment replacement

• Land leases and property taxes (if applicable)

• Insurance, asset management, and security

• General administration

Annual fixed O&M costs ($/kW, -DC and -AC depending on the technology type) were developed in 

2022 constant (real) dollars, for each technology, identified capacity, and year within the analysis 

timeframe. These costs were assumed to be an average annual cost experienced over the specified 

system life for each technology.

Variable O&M costs were developed only for fuel cell and CHP technologies. Variable costs vary

based on system output and include items such as chemicals, catalysts, lubricants, and other 

engine-related components. Fuel costs were not included in this analysis, although they are 

considered a variable cost for system operation and calculated endogenously in NEMS. Variable 

O&M costs for fuel cell and CHP systems also include some of the fixed O&M cost categories stated 

above.

1.3.3 Cost factors and performance attributes

DNV developed state-level costs for residential and commercial solar PV and battery storage 

technologies using state-level labor costs, taxes, overhead and margin costs, and other installation 

costs where appropriate. State-level performance attributes for these systems were developed and 

accounted for local factors such as solar irradiation and average temperature based on a 

representative location. State-level representative system capacities were also developed for

residential and commercial solar PV and battery storage technologies. These state-level cost and 

performance attributes were developed for use in NEMS modeling, but they are not publicly 

available.

U.S. average cost and performance attributes were developed for all technologies and sectors and 

are publicly available in the accompanying data files.
DNV – www.dnv.com Page 6

1.3.4 Technology performance specifications

Table 1-3. Technology performance specifications (2022)

Technology Fuel System Capacity Heat Rate

(HHV) Capital Cost Fixed O&M Variable O&M

Residential Solar PV 

(Standalone) Solar 7.1 kW-DC N/A $2,854/kW-DC $31.13/kW-yrDC N/A

Residential Solar PV + 

Storage Solar

7.9 kW-DC Solar

5.0 kW-DC Storage

(12.5 kWh-DC)

N/A $4,261/kW-DC

(by PV capacity)

$115.20/kW-yrDC N/A

Residential Solar PV + 

Storage (Storage 

Retrofit)

Electric

6.9 kW-DC Solar

4.5 kW-DC Storage

(10 kWh-DC)

N/A

$3,135/kW-DC

(by storage

capacity)

$87.19/kW-yrDC N/A

Residential Storage 

(Standalone)

Electric 6.9 kW-DC

(13.5 kWh-DC) N/A $3,875/kW-DC $96.88/kW-yrDC N/A

Residential Wind Wind 9.3 kW-AC N/A $7,411/kW-AC $38.04/kW-yrDC N/A

Residential Fuel Cell

(Gas)

Natural 

Gas 5.0 kW-AC 7,638Btu/kWh $9,758/kW-AC N/A $0.036/kWh-AC

Commercial Solar PV 

(Standalone, Small 1) Solar 28.5 kW-DC N/A $2,041/kW-DC $19.06/kW-yrDC N/A

Commercial Solar PV 

(Standalone, Small 2)

Solar 100 kW-DC N/A $2,041/kW-DC $19.06/kW-yrDC N/A

Commercial Solar PV 

(Standalone, Medium) Solar 250 kW-DC N/A $1,903/kW-DC $19.06/kW-yrDC N/A

Commercial Solar PV 

(Standalone, Large 1)

Solar 500 kW-DC N/A $1,786/kW-DC $19.06/kW-yrDC N/A

Commercial Solar PV 

(Standalone, Large 2)

Solar 1,000 kW-DC N/A $1,340/kW-DC $18.03/kW-yrDC N/A

Commercial Solar PV + 

Storage (Small 1) Solar

28.5 kW-DC Solar

20 kW-DC Storage

(40 kWh-DC)

N/A $3,911/kW-DC

(by PV capacity)

$75.94/kW-yrDC N/A

Commercial Solar PV + 

Storage (Small 2)

Solar

100 kW-DC Solar

60 kW-DC Storage

(120 kWh-DC)

N/A $3,358/kW-DC

(by PV capacity)

$68.66/kW-yrDC N/A

Commercial Solar PV + 

Storage (Medium) Solar

250 kW-DC

150 kW-DC 

Storage

(300 kWh-DC)

N/A $3,170/kW-DC

(by PV capacity)

$66.80/kW-yrDC N/A

Commercial Solar PV + 

Storage (Large) Solar

500 kW-DC

300 kW-DC 

Storage

(600 kWh-DC)

N/A $3,019/kW-DC

(by PV capacity)

$65.52/kW-yrDC N/A

Commercial Storage 

(Standalone, Small)

Electric 60 kW-DC

(120 kWh-DC)

N/A $2,621/kW-DC $65.53/kW-yrDC N/A

Commercial Storage 

(Standalone, Medium)

Electric 150 kW-DC

(300 kWh-DC) N/A $2,492/kW-DC $62.30/kW-yrDC N/A

Commercial Storage 

(Standalone, Large)

Electric 300 kW-DC

(600 kWh-DC) N/A $2,406/kW-DC $60.14/kW-yrDC N/A

Industrial Storage 

(Standalone)

Electric 100 kW-DC

(400 kWh-DC) N/A $3,034/kW-DC $75.86/kW-yrDC N/A

Industrial Storage 

(Standalone) Electric 500 kW-DC(2,000 kWh-DC) N/A $2,638/kW-DC $65.95/kW-yrDC N/A

Industrial Storage 

(Standalone) Electric 1,000 kW-DC(4,000 kWh-DC) N/A $2,276/kW-DC $56.91/kW-yrDC N/A

Commercial Wind 

(Small) Wind 40 kW-AC N/A $6,231/kW-AC $38.04/kW-yrAC N/A

Commercial Wind 

(Medium) Wind 300 kW-AC N/A $4,057/kW-AC $38.04/kW-yrAC N/A

Commercial Wind 

(Large) Wind 2,000 kW-AC N/A $3,036/kW-AC $38.04/kW-yrAC N/A

Commercial Fuel Cell

(Gas)

Natural 

Gas 300 kW-AC 8,012Btu/kWh $7,150/kW-AC N/A $0.041/kWh-AC

Commercial 

Reciprocating Engine 

(Gas)

Natural 

Gas 300 kW-AC 10,431Btu/kWh $3,769/kW-AC N/A $0.020/kWh-AC

Commercial 

Reciprocating Engine 

(Oil)

Oil 350 kW-AC 10,139

Btu/kWh $3,075/kW-AC N/A $0.019/kWh-AC

Commercial Gas 

Turbine

Natural 

Gas 3,300 kW-AC 13,801Btu/kWh $3,942/kW-AC N/A $0.015/kWh-AC
DNV – www.dnv.com Page 7

Technology Fuel System Capacity Heat Rate

(HHV) Capital Cost Fixed O&M Variable O&M

Commercial 

Microturbine

Natural 

Gas 200 kW-AC 11,350Btu/kWh $3,134/kW-AC N/A $0.016/kWh-AC

Industrial 

Reciprocating Engine 

(Gas, Small)

Natural 

Gas 1,000 kW-AC 9,210Btu/kWh $3,125/kW-AC N/A $0.020/kWh-AC

Industrial 

Reciprocating Engine 

(Gas, Medium)

Natural 

Gas 3,000 kW-AC 8,417Btu/kWh $2,586/kW-AC N/A $0.016/kWh-AC

Industrial Gas Turbine 

(Gas, Medium)

Natural 

Gas 5,000 kW-AC 12,185Btu/kWh $2,628/kW-AC N/A $0.015/kWh-AC

Industrial Gas Turbine 

(Gas, Large 1)

Natural 

Gas 10,000 kW-AC 12,091Btu/kWh $2,020/kW-AC N/A $0.013/kWh-AC

Industrial Gas Turbine 

(Gas, Large 2)

Natural 

Gas 25,000 kW-AC 9,720Btu/kWh $1,697/kW-AC N/A $0.010/kWh-AC

Industrial Gas Turbine 

(Gas, Large 3)

Natural 

Gas 40,000 kW-AC 9,611Btu/kWh $1,448/kW-AC N/A $0.010/kWh-AC

Industrial Combined 

Cycle (Gas, Small)

Natural 

Gas 100,000 kW-AC 6,749Btu/kWh $1,632/kW-AC N/A $0.004/kWh-AC

Industrial Combined 

Cycle (Gas, Large)

Natural 

Gas 375,000 kW-AC 6,246Btu/kWh $1,383/kW-AC N/A $0.003/kWh-AC

Note: Btu=British thermal units; $/kW-yr=dollar per kilowatt per year.

Notes: All cost values are reported on a 2022 constant (real) dollar basis.

1.4 Report organization

This report contains separate chapters for each examined technology:

• Solar PV 

• Battery storage

• Wind energy 

• Fuel cells

• CHP

Each chapter contains two subsections. The first subsection in each chapter details the technology 

and cost data to input into NEMS and the methodology used to determine those inputs. The second 

subsection in each chapter discusses topics such as resource and material availability trends, 

government policies and market incentives, research and development rates, relationships to other 

technologies, and trends in disposal, recycling, or repurposing. Section 6, CHP, does not include a 

discussion subsection. Instead, the CHP discussion is grouped with Section 7, industrial DER 

market discussion, which leverages in-depth interviews with eight installers of CHP systems and six 

end users of CHP systems.

As mentioned above, this report is accompanied by workbooks of technology and cost data inputs 

for NEMS. The accompanying workbooks contain relevant data used to inform assumptions 

contained within the report. The data are used in final cost and performance data calculations. The 

workbooks include “Summary” data tables for each representative technology referenced 

throughout the report. Three workbooks are publicly available:

• “Res_Tech&Cost_Data.xlsx” and “Com_Tech&Cost_Data.xlsx” contain detailed technology 

attributes and cost data for distributed representative residential and commercial systems. 

Summary tabs provide all relevant performance attributes, capital cost, and O&M cost data 

for each sector and system capacity within each representative technology. These tabs 

contain relevant mapping variables and data units for each performance and cost metric 

used in NEMS, such as equipment type, fuel type, NEMS file, and historical year, depending 

on the sector.
DNV – www.dnv.com Page 8

• “Ind_Tech&Cost_Data.xlsx” contains all relevant technology attributes and cost data for 

representative industrial CHP and battery storage systems. The “Summary_Tables” tab 

provides a single table with all performance attributes, capital cost, and O&M cost data for 

each representative system, system capacity, and year for use in NEMS.
DNV – www.dnv.com Page 9

2 SOLAR PHOTOVOLTAIC SYSTEMS

2.1 Solar PV systems technology attributes and cost data

The following subsections provide an overview of solar PV performance attributes and cost data for 

representative residential and commercial systems, and highlight key factors influencing future 

pricing, adoption, and technology deployment trends. 

2.1.1 Technology attributes and cost estimation methodology

DNV developed detailed distributed generation technology cost and performance data for use in 

NEMS. Technology attributes and cost data for BTM solar PV technologies were developed and 

aligned with relevant residential and commercial customer sectors. Attributes and cost data for 

standalone solar PV systems were developed in addition to solar + storage configurations, which 

are detailed in subsequent report sections. State and U.S. representative system capacities for 

residential and commercial solar PV systems were developed using a variety of DNV proprietary 

and public data sources. Annual hourly generation profiles were modeled for each standalone solar 

PV configuration to gather detailed operational data, and additional relevant performance data was 

assembled for all system configurations. The final step was to develop 2022 constant (real) dollar

estimates from publicly available data and align associated cost estimates and attributes with 

previous years of EIA sector-level surveys: Residential Energy Consumption Survey (RECS), 

Commercial Buildings Energy Consumption Survey (CBECS), and Manufacturing Energy 

Consumption Survey (MECS).

2.1.2 System configurations

DNV first collected recent BTM solar PV installation data from Lawrence Berkeley National 

Laboratory’s (LBNL) Tracking the Sun (TTS) database through 2022 and segmented the data to 

identify statistically significant representative residential and commercial system sizes for each 

relevant year in the analysis timeframe (2015–2022 for residential and 2012–2022 for commercial) 

for each state contained in the database. DNV used proprietary project trackers and databases for 

smaller distributed systems to confirm sizes and extrapolate to similar states based on relevant 

technical factors and subject matter expertise. DNV also cross-referenced this data with EIA’s Form 

EIA-861 data that contains data on distributed solar PV capacity in specific utility territories. This 

process allowed DNV to identify residential representative system capacities for each state, with an 

average U.S. system capacity of 7.1-kilowatt direct current (kW-DC) for year 2022. Similarly, the 

representative commercial system capacity was 28.5 kW-DC across all commercial installations. 

The state-level representative system capacity and performance attribute data for residential solar 

PV systems is available in the accompanying data files. Although state-level cost data was gathered 

and used in NEMS modeling, this data is proprietary and not available for public dissemination.

Due to the range of capacities of commercial solar PV installations, DNV also identified four 

additional commercial solar PV capacities to capture this variation across the United States. These

capacities are also aligned with Wood Mackenzie’s U.S. Solar PV System Pricing report, which was 

an important component of the capital cost data used in this assessment.2 These capacities were 

compared with LBNL’s TTS installation data and DNV proprietary project libraries to confirm that 

they represent the range in the current commercial installation market and the potential future growth 

opportunities as larger commercial sites take advantage of decreasing system costs and state and 

federal incentives. 

2 Wood Mackenzie, US Solar PV system pricing: H2 2022, November 21, 2022. 
DNV – www.dnv.com Page 10

As discussed further in Subsection 0, DNV used a blended approach to develop cost data for each 

representative system based on typical inverter types present in recent year installations and trends 

in previous years. Table 2-1 shows which approach was selected for each market segment and size.

Table 2-1 also highlights the standalone solar PV system configuration capacities, along with solar

+ storage technology. Solar + storage configurations are further discussed in Section 3, but they are 

presented here for comparison and consistency.

Two different technology configurations for solar PV are modeled: Solar PV (standalone) and Solar 

PV and storage (solar + storage). Solar + storage systems’ PV components were modeled using 

the same specifications as the standalone PV configuration, except for PV nameplate capacity. The 

residential solar + storage technology configuration is further segmented by new solar + storage

systems that were installed and became operational together and a retrofit case where a battery is 

added to an existing PV system. Residential and commercial battery energy storage systems can 

be installed as a standalone system, added to an existing PV system, or installed with a new PV 

system. DNV assumed all representative battery installations that are co-located with a PV system 

have an AC-coupled configuration and that all standalone battery storage systems would be 

installed in a DC-coupled configuration. 

PV system racking is the equipment that affixes solar panels to surfaces, such as roofs, carports, 

or the ground. Racking equipment is typically made from metal, such as aluminum and steel, and 

sets the orientation and tilt of the solar array. In terms of system costs, racking is commonly defined 

as the structural BOS. Racking and mounting systems are site-dependent, and although a wide 

variety of options exist, residential pitched-roof, commercial flat-roof (ballasted), and commercial 

fixed-tilt ground mounted systems represent most customer-sited PV racking systems. Commercial 

flat-roof ballasted racking systems require less material, equipment, and labor than the groundmounted racking system. However, installed extra-large commercial ground-mounted systems (1 

megawatt [MW] or more) provide economies of scale, thereby reducing BOS costs.

3

Solar PV system inverters are power electronics devices that convert DC to AC. PV panels produce

DC power that must be converted to AC power if the system is grid-connected. Single-phase string 

inverters are the oldest and most common type of PV system inverter used today. They are 

centralized systems that connect multiple strings of solar panels to transform the DC power 

produced by the panels into usable AC power for the site. An alternative approach to the single 

inverter system involves each PV module having its own microinverter mounted directly onto the 

backside of each panel. The advantage to this system lies in its increased flexibility; having an

inverter installed on each module avoids the risk of shade or a poorly performing module bringing 

down an entire string or an inverter malfunction taking down the entire array. Individual 

microinverters also facilitate granular remote monitoring, which can help identify and isolate 

performance issues at the module level. The advantages of microinverters come at a cost—a singlephase string inverter is cheaper on a dollar-per-watt ($/W) basis, especially for larger arrays. DC 

power optimizer systems are a middle ground between a single-phase string and microinverters. 

These systems include power optimizers installed on each module that connect to a single-phase 

string inverter for power conversion. Similar to microinverters, DC optimizer systems reduce the 

impact of single-panel malfunction on system performance and offer module-level performance 

monitoring. 

3 Ramasamy, Vignesh and Jarett Zuboy, U.S. Solar Photovoltaic System and Energy Storage Cost 

Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022, National Renewable Energy 

Laboratory (September 2022). 
DNV – www.dnv.com Page 11

The representative module type modeled for all sectors was the mono passivated emitter rear cell 

(PERC) type, which is made from p-type monocrystalline silicon cells with PERC cell architecture. 

Monocrystalline and multicrystalline (also known as polycrystalline) silicon PERC cells have 

comprised the majority of global market share over the last decade, as they have had the best 

combination of efficiency and production costs. Since 2015, material use has trended toward 

monocrystalline silicon because it yields higher cell efficiencies due to having fewer material defects 

and chemical impurities than multicrystalline silicon. Although multicrystalline panels are less 

expensive than monocrystalline panels, the improved performance in higher temperatures, higher 

overall efficiencies, and improving panel costs in recent years have made monocrystalline panels 

more attractive to installers. PERC cell architecture has also grown in popularity since 2015. Its 

market share grew from 10% in 2015 to over 80% by 2020 because it improves standard cell 

efficiencies. As of 2020, the global market share of mono PERC-type modules was 64%.4

Table 2-1. Technology attributes for solar PV configurations and representative systems

Market 

Sector Configuration Representative System Capacity

Racking 

Solution Inverter Type Module Type

Residential

(Small)

Solar PV (standalone) 7.1 kW-DC

Pitched roof

(roof-mount)

Blended based on 

segment market 

share: string 

inverter, 

microinverter, DC 

optimizer

Mono PERC 

module (blended

based on market 

share of standard 

and highefficiency models)

Solar + storage 7.9 kW-DC PV (5 kW-DC,

12.5 kWh Battery Storage)

Solar + storage

(retrofit)

6.9 kW-DC PV (6.9 kWDC, 14.5 kWh-DC Battery 

Storage)

Commercial

(Small 1)

Solar PV (standalone) 28.5 kW-DC

Flat roof

(roof-mount)

Blended based on 

segment market 

share: string 

inverter, 

microinverter, DC 

optimizer

Mono PERC 

module (blended 

based on market 

share of standard 

and highefficiency models)

Solar + storage

28.5 kW-DC PV (20 kWDC, 40 kWh-AC Battery 

Storage)

Commercial

(Small 2)

Solar PV (standalone) 100 kW-DC

Flat roof

(roof-mount)

Blended based on 

segment market 

share: string 

inverter, 

microinverter, DC 

optimizer

Mono PERC 

module (blended 

based on market 

share of standard 

and highefficiency models)

Solar + storage

100 kW-DC PV (60 kWDC, 120 kWh-DC Battery 

Storage)

Commercial

(Medium)

Solar PV (standalone) 250 kW-DC

Flat roof

(roof-mount)

Blended based on 

segment market 

share: string 

inverter, 

microinverter, DC 

optimizer

Mono PERC 

module (blended 

based on market 

share of standard 

and highefficiency models)

Solar + storage

250 kW-DC PV (150 kWDC, 300 kWh-DC Battery 

Storage)

Commercial

(Large 1)

Solar PV (standalone) 500 kW-DC

Flat roof

(roof-mount)

Blended based on 

segment market 

share: string 

inverter, 

microinverter, DC 

optimizer

Mono PERC 

module (blended 

based on market 

share of standard 

and highefficiency models)

Solar + storage

500 kW-DC PV (300 kWDC, 600 kWh-DC Battery 

Storage)

Commercial

(Large 2)

Solar PV (standalone) 1,000 kW-DC

Commercial 

fixed-tilt 

(groundmount)

String inverter

Mono PERC 

module (blended 

based on market 

share of standard 

and highefficiency models)

Note: kW/yr=kilowatt per year.

4 Woodhouse, Michael and David Feldman, Research and Development Priorities to Advance Solar 

Photovoltaic Lifecycle Costs and Performance, National Renewable Energy Laboratory (October 2021). 
DNV – www.dnv.com Page 12

2.1.3 Generation shapes and technology attributes

After developing technology system configurations and representative capacities, DNV modeled 

each representative system using DNV’s SolarFarmer modeling software and the NREL’s System 

Advisor Model (SAM) to collect hourly generation shapes and associated performance metrics. 

Figure 2-1 shows the performance metrics that were collected for each representative system in 

each state using a representative location in each year within the analysis timeframe. As mentioned 

previously, state-level representative system capacities and performance attributes are available in 

the accompanying data files.

Figure 2-1. Performance metrics for PV systems

2.1.4 System performance attributes 

Table 2-2 through a b Degradation values represent the year one or annual degradation percentage compared to the 

rated system capacity at 100% in the identified year.

Table 2-7 details performance attributes for representative U.S. average residential and commercial 

solar PV systems summarized from the data developed in the previous subsections. The data are

presented to align with previous years of EIA sector-level surveys for each customer segment 

(RECS, CBECS, and MECS) starting with the residential sector from 2015 to 2022. Although singlefamily residential solar PV installations are typically smaller than most commercial installations, roofmounted systems in both sectors have many performance and operational similarities. 

Table 2-2. Residential solar PV system performance attributes

Year Rep. System 

Capacity 

Module 

Efficiency 

Inverter 

Efficiency 

Capacity 

Factor

Year One

Degradation a

Average

Annual 

Degradation b

Average

Annual 

System 

Losses

2015 6.5 kW-DC 19.0% 98.0% 17.3% 97.10% 99.10% 14.0%

2016 6.7 kW-DC 19.0% 98.0% 17.4% 97.10% 99.10% 14.0%

2017 6.8 kW-DC 19.0% 98.0% 17.4% 97.10% 99.10% 14.0%

2018 6.9 kW-DC 19.0% 98.0% 17.5% 97.10% 99.10% 14.0%

2019 7.0 kW-DC 19.5% 98.0% 17.5% 97.10% 99.10% 14.0%

2020 7.0 kW-DC 20.4% 98.0% 17.5% 97.10% 99.10% 14.1%

2021 7.1 kW-DC 20.4% 98.0% 17.5% 97.10% 99.10% 14.1%

2022 7.1 kW-DC 20.4% 98.0% 17.6% 97.10% 99.10% 14.1%

a b Degradation values represent the year one or annual degradation percentage compared to the rated system capacity

at 100% in the identified year.

The average U.S. residential solar PV system capacity increased steadily from 2015 to 2022 due to 

many factors such as home size, available rooftop space, increased home energy use, and 

Hourly System 

Generation (kWh-h)

PV System 

Equipment Effective 

Useful Life (EUL)

Inverter Effective 

Useful Life (EUL)

PV Module Efficiency 

(%)

Inverter Efficiency 

(%)

PV Module Efficiency 

(%)

Inverter Loading 

Ratio (ILR) Capacity Factor (%) Annual System Degradation (%)

Average Annual 

System Losses (%)
DNV – www.dnv.com Page 13

electrification of end uses. Performance characteristics have improved over the same period largely 

due to increased component efficiencies. Commercial solar PV installations and system 

performance follow similar trends.

As mentioned above, cost and performance data were developed for multiple commercial solar PV 

representative system capacities in addition to the representative system capacity developed from 

LBNL’s TTS and other data sources. Unlike residential single-family buildings, which are relatively 

similar in size, in rooftop configuration and area, and in their requirements for solar PV installations, 

commercial systems are installed in facilities with varying rooftop sizes, space considerations, and 

energy end uses. The following tables detail U.S. average performance attributes for commercial 

solar PV systems. Table 2-3 highlights the representative median size developed from LBNL’s TTS 

data, and the subsequent tables summarize performance attributes for the remaining commercial 

sizes. 

Table 2-3. Commercial solar PV system performance attributes for median representative 

system capacity

Year Rep. System 

Capacity 

Module 

Efficiency 

Inverter 

Efficiency 

Capacity 

Factor 

Year One 

Degradation a

Average 

Annual 

Degradation b

Average 

Annual 

System 

Losses 

2012 28.3 kW-DC 19.8% 95.9% 17.5% 97.02% 99.15% 14.0%

2013 30.6 kW-DC 19.8% 96.8% 17.5% 97.20% 99.20% 14.0%

2014 29.9 kW-DC 19.8% 97.5% 17.5% 97.37% 99.25% 14.0%

2015 27.2 kW-DC 20.0% 98.0% 17.5% 97.72% 99.35% 14.0%

2016 29.3 kW-DC 20.0% 98.0% 17.6% 97.72% 99.35% 14.0%

2017 32.7 kW-DC 20.2% 98.0% 17.6% 97.72% 99.35% 14.0%

2018 33.4 kW-DC 20.2% 98.0% 17.6% 97.72% 99.35% 14.1%

2019 30.2 kW-DC 20.8% 98.0% 17.6% 97.72% 99.35% 14.1%

2020 29.3 kW-DC 20.8% 98.0% 17.7% 97.72% 99.35% 14.1%

2021 26.8 kW-DC 21.0% 98.0% 17.7% 97.72% 99.35% 14.1%

2022 28.5 kW-DC 21.0% 98.0% 17.7% 97.72% 99.35% 14.1%

a b Degradation values represent the year one or annual degradation percentage compared to the rated system capacity 

at 100% in the identified year.

Median capacities for representative commercial solar PV systems have fluctuated over the last 10

years due to a variety of factors. The large sample size and variety of installation types throughout 

the United States contribute significantly to this variability. However, performance attributes 

generally do not change when moving from the smallest representative capacity to the 100 kW-DC

system or even to the larger roof-mounted systems. The capacity factor rises slightly when the

system size increases. 

Table 2-4. Commercial solar PV system (100 kW-DC) performance attributes

Year

Rep. 

System 

Capacity 

Module 

Efficiency 

Inverter 

Efficiency 

Capacity 

Factor

Year One 

Degradation a

Average 

Annual 

Degradation b

Average 

Annual 

System 

Losses

2012 100 kW-DC 19.8% 95.9% 17.5% 97.02% 99.15% 14.0%

2013 100 kW-DC 19.8% 96.8% 17.5% 97.20% 99.20% 14.0%
DNV – www.dnv.com Page 14

Year

Rep. 

System 

Capacity 

Module 

Efficiency 

Inverter 

Efficiency 

Capacity 

Factor

Year One 

Degradation a

Average 

Annual 

Degradation b

Average 

Annual 

System 

Losses

2014 100 kW-DC 19.8% 97.5% 17.5% 97.37% 99.25% 14.0%

2015 100 kW-DC 20.0% 98.0% 17.5% 97.72% 99.35% 14.0%

2016 100 kW-DC 20.0% 98.0% 17.6% 97.72% 99.35% 14.0%

2017 100 kW-DC 20.2% 98.0% 17.6% 97.72% 99.35% 14.0%

2018 100 kW-DC 20.2% 98.0% 17.6% 97.72% 99.35% 14.1%

2019 100 kW-DC 20.8% 98.0% 17.6% 97.72% 99.35% 14.1%

2020 100 kW-DC 20.8% 98.0% 17.7% 97.72% 99.35% 14.1%

2021 100 kW-DC 21.0% 98.0% 17.7% 97.72% 99.35% 14.1%

2022 100 kW-DC 21.0% 98.0% 17.7% 97.72% 99.35% 14.1%

a b Degradation values represent the year one or annual degradation percentage compared to the rated system capacity 

at 100% in the identified year.

Table 2-5. Commercial solar PV system (250 kW-DC) performance attributes

Year Rep. System 

Capacity 

Module 

Efficiency 

Inverter 

Efficiency 

Capacity 

Factor 

Year One 

Degradation a

Average 

Annual 

Degradation b

Average 

Annual 

System 

Losses 

2012 250 kW-DC 19.8% 95.9% 17.6% 97.02% 99.15% 14.0%

2013 250 kW-DC 19.8% 96.8% 17.6% 97.20% 99.20% 14.0%

2014 250 kW-DC 19.8% 97.5% 17.6% 97.37% 99.25% 14.0%

2015 250 kW-DC 20.0% 98.0% 17.7% 97.72% 99.35% 14.0%

2016 250 kW-DC 20.0% 98.0% 17.7% 97.72% 99.35% 14.0%

2017 250 kW-DC 20.2% 98.0% 17.7% 97.72% 99.35% 14.0%

2018 250 kW-DC 20.2% 98.0% 17.8% 97.72% 99.35% 14.1%

2019 250 kW-DC 20.8% 98.0% 17.8% 97.72% 99.35% 14.1%

2020 250 kW-DC 20.8% 98.0% 17.8% 97.72% 99.35% 14.1%

2021 250 kW-DC 21.0% 98.0% 17.8% 97.72% 99.35% 14.1%

2022 250 kW-DC 21.0% 98.0% 17.8% 97.72% 99.35% 14.1%

a b Degradation values represent the year one or annual degradation percentage compared to the rated system capacity 

at 100% in the identified year.

Table 2-6. Commercial solar PV system (500 kW-DC) performance attributes

Year Rep. System 

Capacity 

Module 

Efficiency

Inverter 

Efficiency 

Capacity 

Factor

Year One 

Degradation a

Average 

Annual 

Degradation b

Average 

Annual 

System 

Losses 

2012 500 kW-DC 19.8% 95.9% 17.7% 97.02% 99.15% 14.0%

2013 500 kW-DC 19.8% 96.8% 17.7% 97.20% 99.20% 14.0%

2014 500 kW-DC 19.8% 97.5% 17.7% 97.37% 99.25% 14.0%

2015 500 kW-DC 20.0% 98.0% 17.7% 97.72% 99.35% 14.0%

2016 500 kW-DC 20.0% 98.0% 17.7% 97.72% 99.35% 14.0%
DNV – www.dnv.com Page 15

Year Rep. System 

Capacity 

Module 

Efficiency

Inverter 

Efficiency 

Capacity 

Factor

Year One 

Degradation a

Average 

Annual 

Degradation b

Average 

Annual 

System 

Losses 

2017 500 kW-DC 20.2% 98.0% 17.8% 97.72% 99.35% 14.0%

2018 500 kW-DC 20.2% 98.0% 17.8% 97.72% 99.35% 14.1%

2019 500 kW-DC 20.8% 98.0% 17.8% 97.72% 99.35% 14.1%

2020 500 kW-DC 20.8% 98.0% 17.9% 97.72% 99.35% 14.1%

2021 500 kW-DC 21.0% 98.0% 17.9% 97.72% 99.35% 14.1%

2022 500 kW-DC 21.0% 98.0% 17.9% 97.72% 99.35% 14.1%

a b Degradation values represent the year one or annual degradation percentage compared to the rated system capacity 

at 100% in the identified year.

Table 2-7. Commercial solar PV system (1,000 kW-DC) performance attributes

Year Rep. System 

Capacity 

Module 

Efficiency 

Inverter 

Efficiency 

Capacity 

Factor

Year One 

Degradation a

Average 

Annual 

Degradation b

Average 

Annual 

System 

Losses 

2012 1,000 kW-DC 19.8% 95.9% 17.7% 97.02% 99.15% 14.0%

2013 1,000 kW-DC 19.8% 96.8% 17.8% 97.20% 99.20% 14.0%

2014 1,000 kW-DC 19.8% 97.5% 17.8% 97.37% 99.25% 14.0%

2015 1,000 kW-DC 20.0% 98.0% 17.8% 97.72% 99.35% 14.0%

2016 1,000 kW-DC 20.0% 98.0% 17.8% 97.72% 99.35% 14.0%

2017 1,000 kW-DC 20.2% 98.0% 17.9% 97.72% 99.35% 14.0%

2018 1,000 kW-DC 20.2% 98.0% 17.9% 97.72% 99.35% 14.1%

2019 1,000 kW-DC 20.8% 98.0% 17.9% 97.72% 99.35% 14.1%

2020 1,000 kW-DC 20.8% 98.0% 18.0% 97.72% 99.35% 14.1%

2021 1,000 kW-DC 21.0% 98.0% 18.0% 97.72% 99.35% 14.1%

2022 1,000 kW-DC 21.0% 98.0% 18.0% 97.72% 99.35% 14.1%

a b Degradation values represent the year one or annual degradation percentage compared to the rated system capacity 

at 100% in the identified year.

2.1.5 2022 cost data

Capital cost data were collected for each system configuration within each state for years 2020–

2022 using Wood Mackenzie’s U.S. Solar PV System Pricing reports for the respective years.5

These data were used as a component of building the final costs datasets, consisting of additional 

scaling and market adjustment factors.

6 DNV used a blended approach to develop capital cost data 

based on inverter type for the representative systems. Inverter type is based on installation data 

and aligned with NREL’s approach to developing national cost estimates in its annual cost 

benchmark reports.7 For example, the majority of residential installations use DC optimizers with 

5 Wood Mackenzie, US Solar PV system pricing: H2 2022, November 21, 2022. 

6 State-level capital cost data by individual category for distributed solar PV systems is proprietary and not 

contained within the public data files or used directly in this report.

7 Ramasamy, Vignesh and Jarett Zuboy, U.S. Solar Photovoltaic System and Energy Storage Cost 

Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022, National Renewable Energy 

Laboratory (September 2022).
DNV – www.dnv.com Page 16

string inverters and microinverters, which together comprised over 80% of the 2022 installed market, 

whereas in recent years, most commercial installations, comprising over 70% market share, use 

string inverters. Specific market share percentages used in the capital cost modeling are shown in

Table 2-8.

Table 2-8. Solar PV inverter market share (percentage) by customer sector and year

Year Customer Sector String Inverter Optimizer Solution Microinverter

2020

Residential 14.6% 49.8% 35.6%

Commercial 55.2% 39.2% 5.6%

2021

Residential 14.8% 50.5% 34.7%

Commercial 74.8% 20.0% 5.3%

2022

Residential 16.4% 44.5% 39.1%

Commercial 74.5% 19.1% 6.4%

DNV combined this data with DNV proprietary project installation data obtained from developers

and direct project experience to provide scaling criteria for specific cost categories based on market 

factors present within the last three years for installed residential and commercial distributed solar 

PV systems. Market factors found included decreasing PV module and inverter costs, based on 

proprietary DNV data, as well as increasing labor costs since 2020. DNV gathered cost data for 

each state and system configuration in years 2020–2022 using the above approach, and then it 

compiled the data into 13 summary capital cost categories to align with historical capital cost data. 

The detailed cost categories and associated assumptions are described further in Table 2-9. 
DNV – www.dnv.com Page 17

Table 2-9. Cost categories and associated assumptions

Cost Category Residential Commercial

(Roof-mounted)

Commercial

(Ground-mounted)

Module ▪ PERC P-type Mono c-Si a

Inverter

▪ String: 600V 3-phase inverter

▪ DC Optimizer: 1-unit/module

▪ Microinverter: 1-

microinverter/module

▪ String: 1,000V 3-phase 

inverter 

▪ DC Optimizer: 1-unit/module

▪ String: 1,500V 3-phase 

inverter 

Electrical balance of 

system (EBOS)

▪ Includes wiring, conduit, and module connectors, rapid shutdown, 

pass-through box, junction box, surge protection, combiner box and 

AC subpanel (if applicable), monitoring

▪ Includes wiring, conduit, and 

module connectors, passthrough box, junction box, surge 

protection, combiner box and 

AC subpanel (if applicable), 

monitoring

Structural balance of 

system (SBOS)

▪ Includes mounting, module 

clamps and wire management, 

MLPE mount, inverter rack and 

accessories

▪ Includes mounting, ballast 

blocks, module clamps and wire 

management, MLPE mount, 

inverter rack and accessories

▪ Includes mounting, module 

clamps and wire management, 

foundation, inverter rack and 

accessories

Labor a

▪ Includes AC/DC electrical (AC 

only for microinverter systems), 

module and racking installs

▪ Based on wages from BLS

▪ Includes AC/DC electrical, 

module and racking installs

▪ Based on wages from BLS

▪ Includes AC/DC electrical, 

module and racking installs, 

foundation install

▪ Based on wages from BLS

Design and engineering ▪ Includes site design and 

layout, and residential permits

▪ Includes site design and 

layout, structural and electrical 

engineering

▪ Includes site design and 

layout, civil, structural and 

electrical engineering

Permitting and 

Inspection ▪ Solar and building permit inspection, and interconnection

Supply chain, logistics, 

and miscellaneous

▪ Includes mobilization, travel/shipping to site

▪ Assumes oversea freight costs included in component cost 

(oversea freight for inverters included)

▪ 10% distribution markup for modules, 5% for inverters included

▪ Includes mobilization, travel, 

and shipping to site

▪ Assumes oversea freight 

costs included in component 

cost (oversea freight for 

inverters included)

Civil engineering ▪ N/A ▪ General site preparation work

Taxes ▪ Blended sales tax for U.S. average, individual state sales tax

Customer acquisition

and origination ▪ General customer acquisition and origination

Overhead and margin ▪ Site assessment, general project and contract management, EPC 

margin

▪ Site assessment, general 

project and contract 

management, EPC margin, 

contingency

EPC costs ▪ Assumes single EPC 

company, no developer costs ▪ Turnkey EPC ▪ Turnkey EPC

Developer cost ▪ N/A

▪ Interconnection, origination, 

environmental and other 

permitting, due diligence, other 

general management

▪ Interconnection, origination, 

environmental and other 

permitting, due diligence, other 

general management, land 

acquisition

a Wages are represented in 2022 constant (real) dollars.

Note: BLS=U.S. Bureau of Labor Statistics8.

Note: c-Si=Crystalline silicon; V=volt; EPC=Engineering, Procurement and Construction.

8 U.S. Bureau of Labor Statistics, Occupational Employment and Wage Statistics, Tables Created by BLS, 

May 2022
DNV – www.dnv.com Page 18

2.1.6 Historical cost data

Baseline historical capital cost data were collected from NREL annual cost benchmark reports and 

data files at the national level and then disaggregated using a variety of factors to produce statelevel cost data for each year in the analysis timeframe.9 DNV used labor costs, sales tax, and 

components of supplemental Wood Mackenzie PV system pricing data to disaggregate historical 

PV system configurations into state-level cost data for five individual capital cost categories.10 These 

data are combined with current cost data detailed in the previous subsection and summarized for 

the residential customer sector. Figure 2-2 shows the U.S. average residential solar PV system 

capital costs in 2022 constant (real) dollars.

Residential solar PV system capital costs have decreased over the past eight years due to declines 

in module prices from technology advancements and increased module power density. Supply chain 

challenges and labor shortages have increased some specific cost categories in recent years, but

decreases in soft costs such as margin, overhead, and customer acquisition helped to lower total 

capital costs for residential solar PV systems in 2022. 

Figure 2-2. U.S. average residential solar PV system capital costs (kW-DC, 2022 $)

U.S. average cost data for commercial solar PV systems were also computed. Figure 2-3 shows 

capital costs for a 100-kW-DC system (that is, string inverter and DC optimizer) used for the inverter 

category in the smallest commercial size range based on the blended cost approach. Figure 2-4

shows historical capital cost data for a 250 kW-DC roof-mounted system with string inverters. Lastly,

Figure 2-5 shows capital costs for a 1,000 kW-DC ground-mounted system. 

9 Ramasamy, Vignesh and Jarett Zuboy, U.S. Solar Photovoltaic System and Energy Storage Cost 

Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022, National Renewable Energy 

Laboratory (September 2022). 

10 Wood Mackenzie, US Solar PV system pricing: H2 2022, November 21, 2022. 
DNV – www.dnv.com Page 19

Figure 2-3. U.S. average commercial solar PV system (100 kW-DC) capital costs ($/kW-DC, 

2022 $)

Historical capital cost data for a commercial 100 kW-DC system follows a similar declining trend as

residential solar PV systems over the same time period. Although historically cost savings were 

achieved through module, inverter, and BOS cost reductions, more recently these costs have 

remained relatively consistent due to supply chain issues in recent years. 

Figure 2-4. U.S. average commercial solar PV system (250 kW-DC) capital costs ($/kW-DC, 

2022 $)

Medium and large roof-mounted commercial solar PV installations also showed similar cost 

improvements over the same period to the smaller commercial systems but were slightly more 

affected in recent years by supply chain and labor cost increases. More significant cost reductions 

were achieved in margin and customer acquisition costs due to developers pursuing a portfolio sales 

approach that can optimize on economies of scale. This approach has helped to level total system 

costs for recent years (2020–2022). Note, although costs have decreased since 2020, 1,000 kWDC systems are the only capacity group to have an increase in capital costs from 2019 to 2020 and 

that has 2022 costs higher than 2019.
DNV – www.dnv.com Page 20

Figure 2-5. U.S. average commercial solar PV system (1,000 kW-DC) capital costs ($/kW-DC, 

2022 $)

Larger capacity ground-mounted systems experienced cost fluctuations in recent years as the 

supply chain and labor cost effects directly affected these larger systems, more similar to utilityscale installations than the smaller commercial systems. Of the representative commercial solar PV 

systems, the 1,000 kW-DC system was the only one to experience an increase in average capital 

costs since 2019.

2.1.7 O&M cost data

DNV used a similar approach to compile O&M cost data for 2022 and historical years within the 

analysis timeframe. O&M cost data in 2022 constant (real) $/kW-yr-DC for nine separate categories 

was collected from NREL annual PV cost benchmarks and confirmed by internal DNV installation 

data and reported individual project experience for 2022. DNV then created scalars for individual 

states to normalize individual cost categories based on relevant property taxes in individual states 

and align O&M labor costs for individual categories. DNV used historic wage data to scale O&M 

cost categories to each year in the analysis timeframe. The O&M cost categories included in this 

assessment are shown in Table 2-10, including the percentage breakdown for specific categories 

relative to the respective customer segment and solar PV configuration.

Table 2-10 shows the mix of O&M costs for each customer sector and system configuration. Overall, 

differences exist in the distribution of O&M costs between each customer sector due to the physical 

and site-specific factors affecting the need for various types of maintenance. Annual historical O&M 

costs for each customer sector and configuration are shown in Table 2-10.

Table 2-10. O&M cost categories for solar PV systems by customer sector and 

configuration

O&M Cost Category Residential Commercial

(Roof-mounted)

Commercial

(Ground-mounted)

Module cleaning & vegetation management 5% 16% 21%

System inspection & monitoring 13% 22% 12%

Component parts replacement 31% 8% 4%

Module replacement 6% 9% 8%

Inverter replacement 24% 13% 13%

Land lease 0% 0% 13%

Property tax 7% 10% 10%
DNV – www.dnv.com Page 21

O&M Cost Category Residential Commercial

(Roof-mounted)

Commercial

(Ground-mounted)

Insurance, asset management, and security 3% 15% 14%

Operations administration 12% 8% 4%

Note: Column percentages may not add up to 100% due to rounding.

As shown in Figure 2-6, residential O&M costs for solar PV systems are higher than commercial 

system costs due to higher insurance and component replacement costs. O&M costs for solar PV 

system typically range between 0.5% and 0.75% per year of total system cost, but given labor 

shortages, property insurance premium increases, and other market factors affecting smaller 

systems, O&M costs in recent years for residential systems have increased to over $30/kW-yr-DC. 

Figure 2-6. U.S. average solar PV historical O&M cost data ($/kW-year-DC, 2022 $) by 

customer sector and system configuration

Note: Residential data for 2012—2014 is not included due to data being gathered in alignment with previous years of 

EIA sector-level surveys for each customer segment (RECS, CBECS, and MECS). The last year of alignment for 

residential data was 2015.

2.2 Solar PV market discussion

The following subsections provide an overview of factors affecting solar PV system pricing and 

overall market adoption of systems. Although individual component (for example, module, inverter)

costs and related supply chain considerations play an important role in overall capital costs, several

other factors can affect future system pricing and shift overall market dynamics. The availability of

raw materials will continue to play an increasing role in determining component prices, and research 

and development efforts can focus on cost-effective products and approaches. Finally, the 

emergence of new federal and evolving state incentives affects adoption across various markets,

customer sectors, and system technologies. 

2.2.1 Solar PV component trends

The domestic content requirements under the Inflation Reduction Act (IRA) aim to support and 

strengthen U.S.-based production industries by incentivizing the use of domestically sourced 

materials and components in renewable energy products. To qualify for the domestic content bonus, 

all structural steel or iron products used in the project must be produced in the United States and a 

required percentage of the total costs of manufactured products (including components) of the 

system need to be mined, produced, or manufactured in the United States. Executive Order 14017 

America’s Supply Chains directed the Secretary of Energy to submit a report on supply chains for 
DNV – www.dnv.com Page 22

the energy sector industrial base. In response, the U.S. Department of Energy (DOE) prepared and 

issued a series of assessments of supply chains for 11 different technology sectors, including solar 

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

renewable technologies, including raw material, feedstock processing, and finished product 

manufacturing and assembly. Manufacturing capacity of components for solar PV is expected to 

expand in the United States, as companies secure funding through the production tax credit (PTC) 

system that is part of the IRA.

2.2.2 Resource and material availability trends

The global solar market has been affected by a wide array of supply chain issues, as well as 

macroeconomic and geopolitical factors. Manufacturing lines and product availability are at risk due 

to the impacts of the COVID-19 pandemic and elevated raw material prices. Increased raw material 

costs such as for polysilicon, PV glass, ethylene vinyl acetate (EVA), and aluminum, along with 

increased freight costs, contributed to higher module prices beginning in 2021 and 2022. Polysilicon 

prices initially increased due to limited production availability because of the COVID-19 pandemic, 

followed by high demand. The price of polysilicon increased over 200% between 2021 and 2022, 

but prices have since declined by 35%, as of June 2023. A large amount of new manufacturing 

capacity is slated to come on line in the next five years, and global production is expected to double 

by 2025. This increase in module supply and decrease in polysilicon price is expected to lead to 

decreasing module costs. Electrical and structural balance of system component costs are expected 

to continue rising as raw materials such as copper, aluminum, and steel remain high due to supply 

chain issues hampering availability.11

The COVID-19 pandemic also spurred an increase in global freight costs as a result of high demand, 

labor shortages, and a shortage of shipping containers. These factors caused shipping port 

congestion and shipment delays across the solar industry beginning in 2020 and continued to have 

lasting impacts on elevated freight prices through 2023.12 PV module prices in the United States are 

particularly exposed to international freight cost fluctuations because most product is imported from 

countries in Southeast Asia such as Vietnam, Thailand, and Malaysia. Further, although steel 

foundations are likely to be procured domestically, other racking equipment is typically imported, 

and thereby exposed to high international freight costs and delays. Demand for U.S.-produced steel 

is expected to increase as developers try to meet the domestic content requirement to qualify for

the 10% bonus investment tax credit (ITC) from the IRA for large, 1-MW-AC-plus systems. Although

electrical and structural balance of system component costs are expected to continue increasing, 

the effect on total system cost will be offset by decreasing module costs.

2.2.3 Technology research and development trends

Successful R&D investments in the PV market have resulted in increased performance and lower 

manufacturing costs for PV systems over the last decade. Impactful production technology 

advancements to date for crystalline silicon (c-Si) cells include larger ingot and wafer sizes, the 

switch to PERC production, and improved cell metallization and cell interconnection approaches 

that reduce the derate factor in efficiency from cells to modules. Tunnel oxide passivated contract 

(TOPCon) cell architecture is the newest PV cell type to appear in commercial production. At the 

cell-level, TOPCon cells currently have a 0.5%–1.0% absolute efficiency gain over PERC cells and 

11 Wood Mackenzie, US solar PV system pricing: H1 2023, June 19, 2023. 

12 Lerh, Jeslyn, “Global port congestion, high shipping rates to last into 2023 - execs,” Reuters (June 15, 

2022). 
DNV – www.dnv.com Page 23

use many of the same manufacturing steps and equipment.13 Industry trends indicate most new 

commercial-scale systems will migrate to n-type TOPCon modules by the mid- to late 2020s as 

p--type PERC technology gets phased out.14 Improving module efficiency remains a prominent route 

for reducing system capital costs and therefore remains a primary focus for R&D efforts. 

Another route for achieving system cost reductions has historically been through improvements to 

system power electronics, such as increasing inverter efficiency. Continuing advancements in 

inverter efficiency improvements is seen as a key area to reduce systems costs in the future.15

2.2.4 Disposal and recycling costs

Expanded solar PV adoption in the United States has spurred environmental and resource concerns, 

including raw material requirements and plans for managing system components that reach end of 

life. To date, PV module recycling is the current focus of most research, investment, and policy 

related to end-of-life (EOL) management for photovoltaics.16 Historically, recycling R&D has focused 

less on recovery of trace materials and more on recovery of bulk materials such as glass, aluminum, 

and silicon at EOL. With the rising cost of raw trace materials such as copper, better trace material 

recycling processes in c-Si PV recycling are increasingly needed. A circular economy approach to 

EOL PV management goes farther than recycling-only to retain the value of materials and products 

for as long as possible by recirculating recovered materials at all stages of the PV life cycle (that is,

manufacturing, operation, and EOL).

17 Strategies beyond recycling, such as reducing material 

demands through dematerialized designs or recovery and reuse of manufacturing scrap materials,

have been shown to retain a greater portion of the value of the original products and provide greater 

environmental and economic benefits. 

According to NREL, recycling a solar panel in the United States can cost $15–$45, while disposing 

of a panel at the landfill costs only $1–$5. Based on NREL estimates, about 10% of solar PV panels 

are recycled in the United States, and very few have 100% of their material recovered. For context, 

driven by national policies that mandate PV module recycling, recycling costs in Europe are 

estimated to be as low as $0.70 per module, and recycling rates are as high as 95%.18

No federal law, regulation, or standardized testing process currently exists regarding solar panel 

reuse or disposal management in the United States. However, numerous states are discussing

public policy to recycle and repurpose retired solar panels. As of 2022, California, Illinois, Maryland, 

New Jersey, North Carolina, and Washington State have either created commissions or 

implemented rules for the reuse and recycling of PV modules. In March 2022, DOE released a five13 Woodhouse, Michael and David Feldman, Research and Development Priorities to Advance Solar 

Photovoltaic Lifecycle Costs and Performance, National Renewable Energy Laboratory (October 2021). 

14 Fischer, Anne, ”Falling costs, 15 GW of US solar module production, TOPCon trends,“ pv magazine 

(January 26, 2023).

15 Ibid

16 Heath, Garvin and Dwarakanath Ravikumar, Environmental and Circular Economy Implications of Solar 

Energy in a Decarbonized U.S. Grid, National Renewable Energy Laboratory (February 2022). 

17 Heath, Garvi and Dwarak Ravikumar, A Critical Review of the Circular Economy for Lithium-Ion Batteries 

and Photovoltaic Modules: Status, Challenges, and Opportunities, National Renewable Energy 

Laboratory (June 30, 2022).

18 Curtis, Taylor L. and Heather Buchanan, A Circular Economy for Solar Photovoltaic System Materials: 

Drivers, Barriers, Enablers, and U.S. Policy Considerations, National Renewable Energy Laboratory, 

revised April 2021. 
DNV – www.dnv.com Page 24

year action plan to enable safe and cost-effective recycling of PV EOL materials and reduce the 

environmental impact of solar energy modules.19

2.2.5 Federal policies and market incentives

PV module supply issues in the United States are further compounded by policy uncertainty. Tariff 

uncertainty remains as the market awaits further updates on Section 301 tariffs, which affect PV 

modules and inverters imported from China.

20 Additionally, Section 201 tariffs have been extended 

through to February 2026, with a bifacial module exemption, which affects PV modules imported 

from China and Southeast Asia. In June 2021, the U.S. Customs and Border Protection agency 

(CBP) placed a Withhold Release Order (WRO) on imported items containing metallurgical-grade 

silicon from Hoshine Silicon Industry (Shanshan) Co., the world’s largest manufacturer of 

metallurgical-grade silicon, which is based in the Xinjiang region of China. According to the CBP,

this WRO was issued based on concerns of the use of forced labor in the manufacturing process 

for certain silica-based components.21

At the end of 2021, the Uyghur Forced Labor Prevention Act (UFLPA) was signed into law.22 The 

purpose of the UFLPA is to prevent goods that were made with forced labor from entering the United 

States; any product made in the Xinjiang Uyghur Autonomous Region in China will be presumed to 

have been made with forced labor, and importers must provide proof to contrary to ensure release 

of goods. PV module shipments were being detained as a result of the multiple policies’ enforcement. 

In addition to Sections 201 and 301 tariffs and supply chain complexities related to the UFLPA, the 

anti-dumping and countervailing duties (AD/CVD) currently in place for solar cells imported from 

China were proposed to be expanded to other countries in Southeast Asia.23

In late March 2022, the U.S. Department of Commerce (DOC) initiated an anti-circumvention 

investigation into Chinese solar cell and module companies in Malaysia, Vietnam, Thailand, and 

Cambodia. The DOC released its preliminary determination on the investigation in December 2022 

and found four of the eight manufacturers investigated to be circumventing restrictions.

24 The 

potential tariff rate on these manufacturers may be as high as 255%, which is the current Chinese 

country-wide tariff. 25 The preliminary ruling provided some clarity on which manufacturers are 

deemed safe, which has helped alleviate some industry uncertainty that developers and their 

procurement teams were facing.

While imported PV modules are facing challenges, recent policy developments support an increase 

in domestic PV production across the supply chain. The IRA, which was signed into law in August 

2022, includes tax credit incentives for the domestic manufacturing of PV system components. 

19 U.S. Department of Energy, Office of Energy Efficiency & Renewable Energy, DOE Releases Action Plan 

For Photovoltaic Systems End-Of-Life Management, March 18, 2022. 

20 U.S. Trade Representative, Issue Areas, Section 301 Investigations, Section 301-China Technology 

Transfer, China Section 301-Tariff Actions and Exclusion Process, accessed January 24, 2024. 

21 U.S. Customs and Border Protection, Newsroom, National Media Release, “The Department of Homeland 

Security Issues Withhold Release Order on Silica-Based Products Made by Forced Labor in Xinjiang,” 

Press Release (June 24, 2021).

22 U.S. Customs and Border Protection, Trade, Forced Labor Uyghur Forced Labor Prevention Act, updated 

January 26, 2024.

23 Sylvia, Tim, ”US government to move forward with PV anti-circumvention investigation,” pv magazine

(March 29, 2022). 

24 U.S. Department of Commerce, News, Press Release, “Department of Commerce Issues Preliminary 

Determination of Circumvention Inquiries of Solar Cells and Modules Produced in China,” Press 

Release (December 27, 2022). 

25 Wood Mackenzie, US solar PV system pricing: H1 2023, June 19, 2023. 
DNV – www.dnv.com Page 25

Since the passing of the IRA, the federal ITC has been extended 10 years past its original expiration 

date. For systems beginning construction before January 1, 2025, the Bill sets the ITC for up to 30% 

of the cost of installed equipment for 10 years and then steps the credit down to 26% in 2033 and 

22% in 2034. For projects beginning construction after 2019 that were placed in service before 

January 1, 2022, the ITC was set at 26%. In addition to the new federal ITC schedule for generating 

facilities (that is, systems), the updated ITC includes credits for standalone energy storage with a 

capacity of at least 3 kWh for residential customers and 5 kWh for non-residential customers. The 

bill also includes a five-year Modified Accelerated Cost Recovery System (MACRS) depreciation 

schedule for non-residential energy storage. 

Balance of system, engineering, and labor costs continue to rise as inflation increases wages and 

the cost of production. The IRA also has prevailing wage and apprenticeship requirements that could 

further push costs upwards.

Incentives for solar PV include, but are not limited to:

• Federal and state tax incentives

• State and/or utility rebates

• Avoided cost of kWh not purchased from utility

• kWh sold back to the grid (net metering or net billing export credits)

Residential solar PV has the highest level of awareness among customers among all DER offerings

(for example, demand response programs, electric vehicles, customer-sited generation, and battery 

storage) and is consistently high among all demographics. Early adopters of solar PV were 

motivated primarily by the desire to support clean energy technology applications. With solar PV 

costs declining and state, local, and/or utility incentives continuing, customers were motivated not 

only by supporting clean energy but also by a favorable economic environment to purchase solar. 

In a recent survey of homeowners with solar PV systems, more than 80% received an incentive 

(that is, rebate and/or net metering export credits) for their solar project.26 With traditional net 

metering DER compensation schemes, utility customers receive export credits for excess 

generation at the same dollar-per-kWh rate that they would have otherwise paid to purchase 

electricity from the grid.

Retail tariff structures such as time-of-use, tiered tariffs, and rates that include high demand charges 

generally increase the value of solar + storage configurations compared with PV-Only configurations,

while other factors such as load profiles and DER compensation mechanisms can minimize the 

impact of such tariffs on the customer economics of solar + storage systems. The following attributes 

for load profiles can have a favorable effect on customer economics for solar + storage systems:

• Coincident peak demand with high solar irradiation

• Short duration peak demand that is not coincident with solar

• The ability to maintain a firm power supply throughout a 24-hour period

Net billing is a second-generation DER compensation mechanism that incentivizes solar + storage 

co-adoption, as customers can lower their electricity bills by charging their batteries with excess PV 

generation and dispatching their batteries to meet on-site load during times of day when retail energy 

prices are high. From the sole perspective of utility bill savings, solar + storage systems may not be 

a cost-effective option for many customers. Customers who seek the resiliency and reliability of 

26 Smart Energy Consumer Collaborative, Distributed Energy Resources: Meeting Consumer Needs, 

December 11, 2019.
DNV – www.dnv.com Page 26

backup power show more of a willingness to pay for this product, especially if they reside in areas 

that are prone to outages and severe weather events.

2.2.6 Relationship to other DG technologies 

Although solar PV benefits from being a familiar option to customers as a method of procuring clean 

energy under favorable economic conditions, customers don’t necessarily perceive the same 

degree of benefits to battery storage adoption. Adoption of battery storage systems by customers 

is largely dependent on the value the customer places on accessing reliable backup power. So, 

battery storage adoption is more closely linked to the customer’s perception and quantification of 

resiliency needs, and solar is more closely linked to a customer’s desire to achieve energy savings 

or access clean energy.

Storage adoption can be motivated by severe weather events leading to outages or other dangerous 

scenarios. Natural disasters such as hurricanes, floods, wildfires, and other events can leave 

marked impressions on the customer’s psyche and will influence how the customer prioritizes

resilience and backup power for everyday needs or medical needs.27,28,29 The ability of a battery 

storage system to provide backup power in the event of an outage or other emergency is an 

important attribute that sets these systems apart from the broad category of DERs. Most utilities 

adhere to safety and interconnection rules that prevent customers with solar-only (that is, not solar

+ storage) from using solar PV electricity during an outage event. Incorporating battery storage 

along with solar PV enables customers to use their electricity generated in response to different 

events such as weather or billing tariffs. Solar + storage is unique in that it empowers customers to 

bolster their resiliency at their home or business while also reducing greenhouse gas emissions by 

generating and storing clean power.

The potential value of a battery storage system that a customer can obtain is dependent on available

programs and pricing structures. Peak shaving and dispatching a battery storage system in 

response to pricing or outage events on the grid will be influenced by the dispatching incentives, 

peak pricing, and other factors determined by the grid energy provider.30

The Smart Energy Consumer Collaborative (SECC) survey found that among residential utility 

customers with solar PV systems, adoption of plug-in electric vehicles, home energy management 

systems, battery storage, and small wind turbines is more common.

31

2.3 Solar PV summary and conclusions

Overall, solar PV throughout the residential and commercial sectors has experienced growth in 

recent years as customers continue to adopt the technology due to lower system costs, energy bill 

savings, environmental benefits, and resilience or reliability especially when combined with energy 

storage. Although system costs have been decreasing due to improved module efficiencies and 

other component improvement factors, recent supply chain issues, labor shortages, and other tariff 

27 Stevens, Pippa, “Extreme weather events are pushing consumers to solar and residential storage,” CNBC 

(August 25, 2021). 

28 Swim, Janet and Susan Clayton, Psychology and Global Climate Change: Addressing a Multi-faceted 

Phenomenon and Set of Challenges, American Psychological Association, accessed November 14, 

2023. 

29 Chavez, Maria, “Energy Storage Can Help People With Disabilities Through Extreme Weather Events,” 

Clean Technica, accessed April 12, 2023.

30 Prasanna, Ashreeta and Kevin McCabe, Storage Futures Study: Distributed Solar and Storage Outlook: 

Methodology and Scenarios, National Renewable Energy Laboratory, 2021. 

31 Smart Energy Consumer Collaborative, 2023 State of the Consumer Report and Webinar, March 22, 

2023.
DNV – www.dnv.com Page 27

and geopolitical factors have limited overall cost reductions for both the residential and commercial 

sectors. Cost reductions are expected to continue in the coming years as component markets 

stabilize, component efficiencies continue to improve, customers and developers take advantage of 

federal and state incentives, and developers achieve economies of scale through alternative sales 

strategies. Additionally, capacities of both residential and commercial systems are expected to 

increase similar to recent years to amortize costs more efficiently and to take advantage of evolving 

site space and energy end-use factors. 
DNV – www.dnv.com Page 28

3 BATTERY STORAGE

3.1 Battery storage technology attributes and cost data

3.1.1 Overview

Battery systems typically consist of a number of batteries wired in series and parallel combinations 

to achieve the desired ampere-hour capacity and voltage rating. When paired with a solar PV system, 

battery systems store any excess power produced from the array during the day. The stored energy 

can later be used to meet evening demand. In addition to storing energy, batteries provide several 

other important energy services for solar PV systems, including the ability to provide surges of 

current that are much higher than the instantaneous current available from the array. 

The following subsections provide an overview of battery storage performance attributes and cost 

data for representative residential and commercial systems, as well as highlight key factors 

influencing future pricing, adoption, and technology deployment trends. This section also highlights 

storage systems paired with solar PV in both the residential and commercial segments. Although

the solar PV section identifies specific configurations, this section provides more detail on the 

configuration assumptions as well as detailed performance and cost data for solar + storage

systems. 

3.1.2 Technology attributes and cost estimation methodology: Battery storage

DNV developed technology attributes and cost data for BTM battery storage systems and battery 

storage systems combined with solar PV systems, aligned with relevant residential and commercial 

customer segments. These attributes and cost data are also aligned with solar PV system capacities

determined in Section 2.1.2 based on representative installed systems. DNV first developed state 

and U.S. average representative system capacities for residential and commercial battery storage 

and solar + storage using a variety of internal and public data sources. DNV then modeled annual 

hourly generation profiles for each standalone battery storage system and solar + storage

configuration to gather detailed operational data and assembled additional relevant performance 

data for all system configurations. The final step was to develop 2022 constant (real) dollar cost 

estimates from available data and align associated cost estimates and attributes with previous years 

of EIA sector-level surveys: RECS, CBECS, and MECS. The process is described in the following 

subsections.

3.1.3 System configurations

DNV first collected recent BTM battery storage and solar PV installation data from LBNL’s TTS 

database through 2022 and segmented the data to identify statistically significant representative 

residential and commercial system sizes for each relevant year in the analysis period (2015–2022 

for residential and 2012–2022 for commercial) for each state contained in the database. Although

most of the priority states for solar + storage deployment are represented in this database, notable 

exceptions include Georgia, Kansas, Missouri, Montana, Oklahoma, and South Carolina. DNV

identified representative sizes for all configurations including standalone solar PV, solar + storage

(new), solar + storage (retrofit), and standalone battery storage. The solar + storage (new) 

configuration is used to represent new combined solar + storage installations, whereas the solar + 

storage (retrofit) configuration is used to represent storage systems installed on existing solar PV 

systems. Cost data for the solar + storage (retrofit) configuration is only provided for the storage 

component, as it is unknown what year the existing solar PV systems were installed in. Additionally, 

this retrofit configuration was only applied to residential systems.
DNV – www.dnv.com Page 29

DNV then used its project trackers and databases for smaller, distributed systems to confirm 

capacities and extrapolate to similar states based on relevant technical factors and its subject matter 

expertise. DNV also cross-referenced this data with EIA’s Form EIA-861 data, which contains data 

on distributed storage and solar PV capacity in specific utility territories. These processes were also 

used to identify representative system capacities for states not contained within the TTS data. This 

process allowed DNV to identify residential representative system sizes for 2022 for each state, with 

an average U.S. system capacity of 6.9 kW-DC for standalone storage systems, 5 kW-DC for new 

storage systems paired with solar PV, and 4.5 kW-DC for retrofit storage systems. Similarly, the 

representative commercial system capacity was determined to be 50 kW-DC for standalone storage 

systems and 20 kW-DC for new solar + storage systems across all commercial installations. 

DNV also developed representative battery storage system capacities aligned with each of the roofmounted commercial solar PV capacities previously defined in the Solar PV section. These 

capacities were also used as the representative sizes for commercial standalone storage 

configurations. As discussed in the previous section, these capacities are aligned with system 

capacity bins in Wood Mackenzie’s U.S. Solar PV System Pricing report.32 These capacities were 

also compared with TTS installation data and DNV proprietary project databases to confirm that 

they represent the range in the current commercial installation market and potential future growth 

opportunities.

Table 3-1 highlights configurations and system capacities for solar + storage or standalone storage 

systems. Standalone solar PV configurations are also repeated for certain market segments for 

comparison purposes. 

Table 3-1. Technology attributes for battery storage configurations and representative 

systems

Market Sector Configuration Representative Solar PV 

System Capacity

Representative Battery 

Storage System Capacity

Residential

(Small)

Solar PV (standalone) 7.1 kW-DC N/A

Solar + storage (new) 7.9 kW-DC 5 kW-DC, 12.5 kWh-DC

Solar + storage (retrofit) 6.9 kW-DC 4.5 kW-DC, 10 kWh-DC

Storage (standalone) N/A 6.9 kW-DC, 13.5 kWh-DC

Commercial

(Small 1)

Solar PV (standalone) 28.5 kW-DC N/A

Solar + storage (new) 28.5 kW-DC 20 kW-DC, 40 kWh-DC

Storage (standalone) N/A N/A

Commercial

(Small 2)

Solar PV (standalone) 100 kW-DC N/A

Solar + storage (new) 100 kW-DC 60 kW-DC, 120 kWh-DC

Storage (standalone) N/A 60 kW-DC, 120 kWh-DC

Commercial

(Medium)

Solar PV (standalone) 250 kW-DC N/A

Solar + storage (new) 250 kW-DC 150 kW-DC, 300 kWh-DC

Storage (standalone) N/A 150 kW-DC, 300 kWh-DC

Commercial Solar PV (standalone) 500 kW-DC N/A

32 Wood Mackenzie, US solar PV system pricing: H2 2022, November 21, 2022. 
DNV – www.dnv.com Page 30

Market Sector Configuration Representative Solar PV 

System Capacity

Representative Battery 

Storage System Capacity

(Large 1)

Solar + storage (new) 500 kW-DC 300 kW-DC, 600 kWh-DC

Storage (standalone) N/A 300 kW-DC, 600 kWh-DC

AC-coupled installations use both a grid-tied inverter for the solar PV system and an inverter for the 

battery, allowing both systems to be dispatched independently. Multi-inverter AC-coupled systems 

are commonly used for grid-connected installations and make it technically easier to add battery 

systems to existing solar PV systems (retrofit configuration). DC-coupled systems share an inverter 

and grid interconnection point, resulting in decreased installation costs and higher efficiency when 

compared with AC-coupled systems. However, AC-coupled systems are the most popular solar + 

storage configuration historically and currently for the representative systems in this analysis due to 

their flexibility and versatility of installation and their ability to provide enhanced resilience given the 

system redundancy.

3.1.4 Technology attributes and generation shapes

DNV assumed a fully integrated BESS product for the residential and commercial sectors, which 

includes a battery pack, a bidirectional inverter, wiring, disconnect, and casing provided by a 

residential and commercial battery energy storage manufacturer with high market penetration such 

as Enphase, Sonnen, or Tesla. DNV modeled the costs for each component separately, and 

performance attributes and cost data for these installed systems were then used as comparison 

metrics for fully integrated systems at both the national and state level. 

Battery degradation was modeled using DNV’s Battery AI, a data-driven battery analytics tool that 

predicts short-term and long-term useable energy capacity degradation under different usage 

conditions. In this analysis, Battery AI modeled several current-generation, commercially available 

nickel manganese cobalt (NMC) cells to predict expected degradation performance of generic cells. 

Both cycling and calendar effects were considered in the degradation assessment. The analysis

assumed the battery cell temperature will be controlled to be around 25°C for most of the time, using 

proper thermal management. DNV notes that temperature, both hot and cold, plays a key role in 

battery degradation. Continuous operation under extreme low or high temperatures will accelerate 

degradation in battery state of health. 

DNV used its proprietary solar + storage operational modeling tool, Lightsaber, to model battery 

dispatch. Battery dispatch strategy dictates the flow of energy between the solar PV system, battery, 

and the grid. The dispatch model is capable of modeling dispatch strategies such as peak shaving, 

energy arbitrage, and manual dispatch. Self-consumption was modeled for all sectors’ BESS control 

strategy, which utilizes the battery by charging only from excess solar PV generation and 

discharging only if solar PV production falls below load. For the residential sector, the dispatch 

model used energy arbitrage to reduce time-of-use charges. For the commercial sector, the dispatch 

model used energy arbitrage to reduce demand charges and time-of-use charges, where applicable. 

This approach facilitated the development of hourly generation profiles for all storage configurations, 

which resulted in additional performance metrics. The following performance metrics were collected 

for each system in each state using a representative location in each year within the analysis 

timeframe. 
DNV – www.dnv.com Page 31

3.1.5 System performance attributes 

Table 3-2 details performance attributes for representative U.S. average residential storage and 

solar + storage systems summarized from the data developed in the previous subsections. The data 

are presented to align with previous years of EIA sector-level surveys for each customer sector

starting with the residential sector from 2015 to 2022. Although single-family residential storage and 

solar + storage installations are typically smaller than most commercial installations, many 

performance and operational similarities exist between residential and smaller commercial systems. 

Table 3-2. Residential battery storage system performance attributes

Year

Standalone 

Storage Rep. 

System 

Capacity

Solar + storage

Rep. System 

Capacity

Round-Trip 

Efficiency a

BESS 

Inverter 

Efficiency 

AC Line 

Losses b

Cycles/

Year EUL c

2015 5.9 kW-DC 4.6 kW-DC 86.0% 96.0% 0.5% 365 15 years

2016 6.0 kW-DC 4.7 kW-DC 86.0% 96.0% 0.5% 365 15 years

2017 6.2 kW-DC 4.7 kW-DC 86.0% 96.5% 0.5% 365 15 years

2018 6.4 kW-DC 4.9 kW-DC 87.0% 96.5% 0.5% 365 15 years

2019 6.4 kW-DC 4.9 kW-DC 87.0% 97.0% 0.5% 365 15 years

2020 6.7 kW-DC 4.9 kW-DC 87.0% 97.0% 0.5% 365 15 years

2021 6.8 kW-DC 5.0 kW-DC 88.0% 97.5% 0.5% 365 15 years

2022 6.9 kW-DC 5.0 kW-DC 88.0% 97.5% 0.5% 365 15 years

a Round-trip efficiency is the ratio of total energy input from the grid to total energy output by the system.

b AC line losses (percentage, %) are included to show the average losses from the delivery of grid power to the on-site 

storage system. Battery cycling assumes that the average residential system will cycle once per day to minimize grid 

power consumption or shift energy to lower cost time-of-use (TOU) periods.

c EUL=estimated useful life.

Although historical and 2022 storage system capacities are presented separately, performance 

attributes and costs detailed in the next subsections were modeled using similar system

configurations. Overall, representative standalone storage system sizes have increased moderately 

over the last seven years, but standalone residential storage installations have had very little 

penetration throughout the United States. Solar + storage system installations in the United States 

have significantly increased in recent years for both residential and small commercial sectors. 

Although individual state differences are present, Figure 3-1 shows the increasing penetration of 

solar + storage systems at the national level within the last 10 years.
DNV – www.dnv.com Page 32

Figure 3-1. Percentage of solar PV systems with battery storage by segment (2012–2022)

Data source: LBNL, Tracking the Sun

Storage performance attributes for small commercial standalone storage and solar + storage

configurations are presented in Table 3-3. As for residential configurations, although historical and 

current storage system capacities are presented separately, performance attributes and costs 

detailed in the next subsections were modeled using the same systems for all configurations. 

Additionally, DNV assumed the same historical performance attributes shown in Table 3-3 for the 

larger commercial solar + storage and standalone storage systems and assumed the same historical 

representative system capacities.

Table 3-3. Small commercial battery storage system performance attributes

Year

Solar + Storage

Rep. System 

Capacity

Round-Trip 

Efficiency a

BESS Inverter 

Efficiency 

AC Line Losses 

b

Cycles/

Year EUL c

2012 19.9 kW-DC 85.0% 95.0% 0.5% 365 15 years

2013 22.0 kW-DC 86.0% 95.0% 0.5% 365 15 years

2014 20.4 kW-DC 86.0% 96.0% 0.5% 365 15 years

2015 19.3 kW-DC 87.0% 96.0% 0.5% 365 15 years

2016 19.5 kW-DC 87.0% 96.0% 0.5% 365 15 years

2017 22.8 kW-DC 87.0% 96.5% 0.5% 365 15 years

2018 23.1 kW-DC 88.0% 96.5% 0.5% 365 15 years

2019 22.5 kW-DC 88.0% 97.0% 0.5% 365 15 years

2020 21.4 kW-DC 89.0% 97.0% 0.5% 365 15 years

2021 19.2 kW-DC 90.0% 97.5% 0.5% 365 15 years

2022 20.0 kW-DC 90.0% 97.5% 0.5% 365 15 years

a Round-trip efficiency is the ratio of total energy input from the grid to total energy output by the system.

b AC line losses (percentage, %) are included to show the average losses from the delivery of grid power to the on-site 

storage system. Battery cycling assumes that the average residential system will cycle once per day to minimize grid 

power consumption or shift energy to lower cost time-of-use (TOU) periods.

c EUL=estimated useful life.
DNV – www.dnv.com Page 33

Median capacities for representative commercial standalone storage systems within solar + storage

configurations have fluctuated over the last 10 years due to a variety of factors, even in smaller 

commercial installations. The solar + storage median capacities follow a similar trend to standalone 

solar PV systems. However, performance attributes generally do not change when moving from the 

smallest representative capacity (less than 20 kW-DC) to the 100 kW-DC system or even to the 

larger (more than 100 kW-DC) roof-mounted systems. The capacity factor slightly rises when the

system capacity rises. 

3.1.6 2022 cost data

Capital cost data for battery storage systems were collected for each system configuration for 2020–

2022 using NREL’s Annual Technology Baseline (ATB) reports and data files and were further 

segmented to individual states using state-level labor rates, sales tax rates, and developer overhead 

and margin rates.33 DNV verified and provided slight cost adjustments where appropriate to align 

with representative system capacity assumptions based on DNV databases and reported individual 

project experiences for 2022. The battery storage cost categories and associated assumptions are 

detailed further in Table 3-4 for residential and commercial sectors.

Table 3-4. Battery storage cost categories and assumptions for residential and commercial 

systems

Cost Category Residential Commercial

Battery pack ▪ Lithium-ion 

▪ Applied residential battery supply premium

▪ Lithium-ion 

▪ Applied commercial battery supply premium

Battery inverter Standard battery central inverter price

Battery cabinet N/A Battery packs and containers, thermal management 

system, and fire suppression system

BOS

Meter, communications device, AC panel & DC 

disconnect, charge controller, breaker box, and 

all conduit, wiring, and cabling

▪ SBOS a: Foundation, inverter house

▪ EBOS b: Conduit, wiring, cabling, energy 

management system, switchgear, transformer, and 

container monitoring and controls systems

Supply chain State-level percentages applied to battery module/pack, battery inverter, and BOS costs

Sales tax Blended sales tax for U.S. average, individual state sales tax

Labor & installation

Includes blended non-unionized labor rates for 

U.S. average costs, individual non-unionized 

labor rates by state

▪ Includes blended non-unionized labor rates for U.S. 

average costs, individual non-unionized labor rates 

by state

▪ Also includes required rental equipment costs (RS 

Means)

Engineering Includes flat engineering design fees N/A

Permitting, 

interconnection, and 

inspection (PII)

Solar and building permit inspection, and 

residential interconnection

Construction permit, interconnection study, 

inspection, and fees

Sales & marketing General sales costs N/A

Overhead Includes general project expenses not included 

in Permitting, Interconnection, and Inspection

▪ EPC overhead included as percentage of 

equipment costs (inventory, shipping, etc.)

▪ Developer overhead includes payroll, facilities, 

administration, finance, etc.

33 Ramasamy, Vignesh and Jarett Zuboy, U.S. Solar Photovoltaic System and Energy Storage Cost 

Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022, National Renewable Energy 

Laboratory, September 2022.
DNV – www.dnv.com Page 34

Cost Category Residential Commercial

Profit Fixed rate applied to battery, inverter, BOS, 

labor, supply chain, and sales tax

▪ Contingency included as markup applied to 

battery, inverter, BOS, labor, sales tax, and EPC 

overhead

▪ Fixed rate applied to all costs

a SBOS=structural balance of system.

b EBOS=electrical balance of system; EPC= engineering, procurement, and construction.

To estimate capital costs for solar + storage systems, DNV applied cost reduction factors for seven 

of the combined solar + storage cost categories based on DNV project experience and NREL’s ATB 

reports and data files. Different cost reduction factors were applied to both new solar + storage

systems and retrofit storage systems added onto existing solar PV systems. These reduction factors 

were applied due to the cost efficiency improvements achieved when battery and solar PV 

installations are combined. Capital cost categories assumed to have cost efficiencies for combined 

systems include electrical and structural balance of system, installation labor, design and 

engineering, permitting, interconnection, inspection, customer acquisition, supply chain and logistics, 

and overhead and profit. The associated cost reduction factors are shown in Table 3-5.

Table 3-5. Cost reduction factors for solar + storage systems

Combined Cost Category 

(Solar PV & Battery Storage)

Residential Solar + 

Storage (New)

Residential Solar + 

Storage (Retrofit)

Commercial Solar + 

Storage (New)

Balance of system 90% 95% 90%

Installation labor 90% 95% 90%

Design and engineering 95% 95% 90%

Permitting, Interconnection, and Inspection 50% 50% 70%

Customer acquisition 50% 50% 90%

Supply chain and logistics 75% 90% 90%

Overhead and profit 80% 80% 90%

3.1.7 Historical cost data

Baseline historical capital cost data were collected from NREL annual cost benchmark reports,

34

including NREL’s ATB reports and national-level data files. DNV then disaggregated state-level data 

for specific cost categories to produce state-level cost estimates for each year in the analysis period. 

DNV used historic labor costs, sales tax, and calculated supply chain costs to produce state-level 

estimates. Like current year cost estimates, these cost categories were also used to estimate 

overhead and margin costs that provided additional state-level disaggregation. Additionally, 

historical storage system equipment costs were included when available and scaled to 2022 

constant (real) dollar values based on annual chain-type price indexes for electrical equipment and 

associated components available in EIA’s Annual Energy Outlook. These historical costs were 

combined with current cost data detailed in the previous subsection.

Residential standalone storage system costs, shown in Figure 3-2, are based on limited historical 

installation data due to limited use cases on single-family homes. However, increased penetration 

is occurring in certain markets and could continue given the development of certain incentives or 

34 Ramasamy, Vignesh and Jarett Zuboy, U.S. Solar Photovoltaic System and Energy Storage Cost 

Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022, National Renewable Energy 

Laboratory, September 2022. 
DNV – www.dnv.com Page 35

attractive market opportunities that provide additional benefits. For example, to provide resiliency in 

the event of Public Safety Power Shutoffs (PSPS) in California, some residential customers are 

exploring the benefits of standalone storage to protect themselves from short and planned grid 

disruptions. Certain locational constraints (for example, shading, homeowner association 

restrictions) may limit the ability to install rooftop solar, so standalone battery storage may also be 

an attractive alternative given the IRA tax credit expansions for standalone storage systems.

Similarly, while residential solar + storage systems have experienced limited historical penetration, 

significant market interest exists given cost declines coupled with additional opportunities for value 

stacking in recent years. 

Figure 3-2. U.S. average residential standalone storage system capital costs ($/kW-DC, 

2022 $)

As shown in Figure 3-3 for the residential sector, solar + storage systems are experiencing 

installation cost reductions in the labor, hardware, permitting, customer acquisition, and overhead 

and profit categories. Depending on storage duration and total energy capacity, capital cost 

reductions in the past seven years range between 10% and 25%.

Figure 3-3. U.S. average residential solar + storage system capital costs ($/kW-DC, 2022 $)

Commercial storage systems have also realized cost reductions over the past 10 years. However, 

battery pack and cabinet costs increased in 2022, contributing to an average installed cost of 

$2,492/kW-DC for a medium, 150 kW, 300 kWh system (Figure 3-4).
DNV – www.dnv.com Page 36

Figure 3-4. U.S. average commercial standalone storage system (medium, 150 kW-DC, 300 

kWh) capital costs ($/kW-DC, 2022 $)

Commercial solar + storage systems also see significant cost reductions when co-locating the solar 

PV and storage systems (Figure 3-5). Larger cost reductions are realized in overall site preparation, 

the sharing of hardware, installation labor, and general overhead and profit for solar + storage

systems. Capital costs have decreased roughly 50% for solar + storage systems in the commercial 

sector over the past 10 years.

Figure 3-5. U.S. average commercial solar (250 kW-DC) + storage system (150 kW-DC, 300 

kWh battery storage) capital costs ($/kW-DC, 2022 $)

3.1.8 O&M cost data

DNV compiled fixed O&M costs ($/kW-DC) for all storage systems and configurations included in 

this study. O&M costs for battery storage systems include costs required for normal operation as 

specified by the manufacturer that adhere to the system design and specified use cases throughout 

the useful life of the system. Fixed O&M costs are all required costs that are not determined by the 

systems use case. Variable O&M costs are typically not included and are not a factor in this 

assessment due to the simplified on-site use cases assessed for the commercial and residential 

sectors. Battery storage systems typically have O&M costs under $100/kW-DC due to the limited 

maintenance from less mechanical components and moving parts compared with CHP and wind 

energy systems. Commercial sector fixed O&M costs include assumed annual component 

replacements or system augmentation (adding battery modules and/or packs) due to system 
DNV – www.dnv.com Page 37

degradation to return the system to its nameplate capacity. DNV also assumed O&M cost reduction 

factors similar to capital cost efficiencies for solar + storage configurations. 

Compared with solar PV O&M cost categories, battery storage cost categories were simplified for 

both standalone and solar + storage configurations. DNV compiled annual fixed O&M cost data for 

current and historical years using NREL annual cost benchmark reports and NREL’s ATB reports, 

and then it scaled this data to real dollar values for additional data years based on blended historical 

hourly labor rates associated with energy storage O&M activities.35 Figure 3-6 shows historical O&M 

cost data by customer sector for battery storage systems.

Figure 3-6. U.S. average battery storage historical O&M cost data ($/kW-yr-DC, 2022 $) by 

customer sector

Average battery storage system O&M costs typically include asset management and security, 

periodic parts replacement and cleaning, inverter replacement, general system inspection, and 

insurance, and these costs have generally decreased over time in both the residential and 

commercial sectors. Commercial O&M costs have decreased at a faster rate due to cost efficiencies 

achieved in system maintenance and monitoring over time. Residential O&M costs are typically 

limited to homeowner discretion and have experienced little change in real dollar value over the past 

five years. 

3.2 Battery storage market discussion

3.2.1 Resource and material availability trends

Batteries consist of three major components: cathode, anode, and electrolyte. These three 

components make up approximately 60% of a battery’s raw material costs. These components 

together make up the battery cell and can contain critical minerals, which are vulnerable to supply 

chain disruptions and price fluctuations. The battery cells are put together into a module and then 

into a container that can be made of metal, usually aluminum or steel, and lastly into a pack that 

can have a plastic, composite, or metal outer casing. The increased use of batteries, specifically 

lithium-ion batteries, across industries, such as in consumer electronics, transportation, and energy 

storage, has led to increased demand for critical and rare minerals needed to produce batteries. 

35 Ramasamy, Vignesh and Jarett Zuboy, U.S. Solar Photovoltaic System and Energy Storage Cost 

Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022, National Renewable Energy 

Laboratory, September 2022. 
DNV – www.dnv.com Page 38

As with other manufacturing sectors, the production of batteries has been affected by supply chain 

issues due to the COVID-19 pandemic, as well as macroeconomic and geopolitical issues. For 

instance, battery prices for electric vehicles (EVs) increased in 2022 due to a rise in raw material 

prices, increase in component prices, inflation, and supply chain constraints. The annual Bloomberg 

New Energy Finance (BNEF) Battery Price Survey for 2022 found that battery pack prices for EVs 

had increased by 7% year-on-year in 2022 to $151/kWh, after seeing a continual decline in price 

since 2010.36 As a result, carmakers will tend to use lower-cost battery chemistries, such as lithium 

iron phosphate (LFP) batteries, which contain neither cobalt nor nickel or other battery chemistries 

that contain lower levels of cobalt. According to the Institute for Energy Research, battery costs 

make up around 30% to 40% of the total EV cost, and carmakers are looking to reduce this cost to 

make EVs profitable.37 In response, battery makers are focusing on developing new, lower-cost 

battery chemistries and new battery architectures. 

The U.S. Geological Survey defines a critical mineral as a non-fuel mineral that is essential to 

economic or national security and may be vulnerable to supply chain disruptions. Critical minerals

include aluminum, cobalt, graphite, lithium, manganese, nickel, and vanadium.38 Of these, cobalt, 

lithium, nickel, and vanadium are especially critical to U.S. battery production because these 

minerals are primarily imported.39,40,41,42 A battery may contain these critical minerals, however, the 

actual amounts of these minerals used depends on the type of battery and battery chemistry. The 

cathode currently makes up the largest part of the battery cost because it contains many critical and 

rare minerals. The anode is currently made of graphite or sometimes silicon, which are considered 

critical minerals. Adding to the supply chain risk is that reserves of some of these critical minerals 

are concentrated in a handful of countries. For example, about 50% of the world’s cobalt reserves 

are in the Democratic Republic of Congo (DRC), and Chile holds the world’s largest reserve of 

lithium.43,44 Additionally, some of these critical minerals are imported from Russia, and these imports 

have been curtailed since Russia’s full-scale invasion of Ukraine in 2022. The geographical 

concentration of these critical minerals coupled with ongoing geopolitical issues will continue to 

affect the availability and price of these raw materials for battery production.

The current production makeup of the battery industry is dominated by non-U.S. entities. According 

to BNEF, in 2022, 806 gigawatthours (GWh) of batteries were produced globally, of which 74% were 

produced in China, 16% in Europe, 7% in the United States, 2% in South Korea, and 1% in Japan.45

The major companies that produce batteries are also non-U.S. companies, with the leading 

companies headquartered in Asia. The top five battery-producing companies in 2022 were CATL 

36 Bloomberg New Energy Finance, “Lithium-ion Battery Pack Prices Rise for the First Time to an Average of 

$151/kWh,” December 6, 2022. 

37 Institute for Energy Research, Commentary, Electric Vehicle Battery Costs Soar, April 25, 2022. 

38 U.S. Geological Survey, National News Release, U.S. Geological Survey Releases 2022 List of Critical 

Minerals, Press Release (February 22, 2022). 

39 U.S. Geological Survey, Cobalt, 2023. 

40 U.S. Geological Survey, Lithium, 2023. 

41 U.S. Geological Survey, Nickel, 2023. 

42 U.S. Geological Survey, Vanadium, 2023. 

43 White House, FACT SHEET: Biden-Harris Administration Announces Supply Chain Disruptions Task 

Force to Address Short-Term Supply Chain Discontinuities, June 8, 2021.

44 Office of the United States Trade Representative, Policy Offices, Press Office, Fact Sheets, 2023, March, 

FACT SHEET: USTR Releases 2023 Trade Policy Agenda and 2022 Annual Report.

45 Bloomberg New Energy Finance, Research, Commodities, Race to net zero: Pressures of the battery 

boom in five charts, July 15, 2022. 
DNV – www.dnv.com Page 39

(China), BYD (China), LG Chem (South Korea), Panasonic (Japan), and Samsung SDI (South 

Korea).46

In response, the government is trying to spur domestic production of batteries and establish a 

domestic supply chain. Under the American Battery Innovation Act, DOE issued the National 

Blueprint for Lithium Batteries to assist in developing a domestic lithium-ion battery manufacturing 

supply chain, from mineral mining to production to recycling, with the Bipartisan Infrastructure Law 

providing $2.8 billion in grants.47,48,49 NREL manages the NAATBatt Lithium-Ion Battery Supply 

Chain Database, which lists North American companies that are active in the lithium-ion supply 

chain. As of June 2023, 446 companies with 509 facilities are listed in the database.50 Multilateral 

efforts to coordinate and cooperate in the supply of critical minerals are also taking place. In August 

2023, Australia, Canada, and the United States announced that they would cooperate on sharing 

technical data related to critical minerals.51 Argonne National Laboratory estimates that EV battery 

manufacturing capacity in the United States will increase by almost 20-fold between 2021 and 

2030.52 EV battery manufacturing capacity is interconnected with battery production capacity for 

energy storage and other uses, as some of this production capacity may be dedicated to non-EV 

use batteries.53

3.2.2 Federal policies 

The supply chain disruptions caused by the COVID-19 pandemic, geopolitical events, and trade 

issues with major U.S. trading partners such as China and Russia have highlighted the need to 

develop a domestic battery supply chain. Most of the critical minerals needed for the manufacturing 

of batteries are imported, and leading battery manufacturers are currently headquartered in Asia. 

All these factors affect battery cost and reliability of supply. The government has begun addressing 

some of these issues, starting with the Infrastructure Investment and Jobs Act in 2021 and followed 

by the IRA and CHIPS and Science Act in 2022. These acts combined will provide more than $135 

billion to build a battery supply chain, from critical minerals sourcing and processing to 

manufacturing. 54 Additionally, in October 2022, the American Battery Material Initiative was 

launched to help develop an end-to-end battery supply chain.55 As of August 2023, over $55 billion 

46 Irwin, John, “EV growth puts battery suppliers into auto industry’s top ranks,” Automotive News (June 25, 

2023).

47 The White House, FACT SHEET: Biden-Harris Administration Driving U.S. Battery Manufacturing and 

Good-Paying Jobs, October 19, 2022. 

48 U.S. Department of Energy, Vehicle Technologies Office, National Blueprint for Lithium Batteries, June 7, 

2021. 

49 U.S. Department of Energy, “Biden Administration, DOE to Invest $3 Billion to Strengthen U.S. Supply 

Chain for Advanced Batteries for Vehicles and Energy Storage,“ February 11, 2022. 

50 National Renewable Energy Laboratory, Transportation & Mobility Research, NAATBatt Lithium-Ion 

Battery Supply Chain Database, updated June 2023.

51 U.S. Geological Survey, Technical Announcement, Australia, Canada and US Unify Critical Minerals 

Data, August 17, 2023.

52 Sagoff, Jared, “A new look at the electric vehicle supply chain as battery-powered cars hit the roads en 

masse,” Argonne National Laboratory, May 4, 2023. 

53 Solar Energy Industries Association, Energizing American Battery Storage Manufacturing, November 

2023, p.7.

54 The White House, FACT SHEET: Biden-Harris Administration Driving U.S. Battery Manufacturing and 

Good-Paying Jobs, October 19, 2022. 

55 U.S. Department of Energy, Biden-Harris Administration Awards $2.8 Billion to Supercharge U.S. 

Manufacturing of Batteries for Electric Vehicles and Electric Grid, October 19, 2022. 
DNV – www.dnv.com Page 40

in investments in battery-related projects have been announced by numerous companies in the 

United States.56

Some federal resources available for battery storage project developers include the following:

• The Battery Policies and Incentives Search, developed by the NREL, can be accessed from the 

DOE website.57 This tool provides access to incentives and policies, both on a state and federal 

level, related to batteries for EVs and BESS.

• The Battery Energy Storage System Procurement Checklist developed by DOE’s Federal 

Energy Management Program provides federal agencies with a standard set of tasks, questions, 

and reference points to assist in early stages of BESS project development.58

• NREL developed The Grid-Scale Battery Storage Frequently Asked Questions report, which can 

be used as a project toolkit for battery storage projects.59

• The National Blueprint for Lithium Batteries 2021–2030 by the Federal Consortium for Advanced 

Batteries is aimed at developing and supporting the domestic manufacturing of batteries, 

increasing a battery supply chain, and creating a battery chain workforce through education and 

training.60

The battery industry is also subject to tariff uncertainty, driven by geopolitical issues. The Uyghur 

Forced Labor Prevention Act (UFLPA), which was signed into law in December 2021, looks to 

prevent goods that were made with forced labor from entering the United States.61 Initially, the 

UFLPA affected solar modules because polysilicon is listed as high-priority, however, now minerals 

and components used in lithium-ion batteries are coming under scrutiny.62 This shift is partially due 

to the U.S. Department of Labor adding lithium-ion batteries to its list of products produced by forced 

or child labor in 2022, not only for China but also for the DRC.63 The CBP had previously placed a 

Withhold Release Order on artisanal cobalt mined in the DRC. 64 In January 2023, the U.S. 

government signed a memorandum of understanding with the DRC and Zambia in an effort to make 

cobalt mining more responsible and strengthen the battery value chain.65

To mitigate supply chain risk, the United States has several bilateral and multilateral trade 

agreements in place, as well as some that are under negotiation, that include batteries and critical 

minerals:

56 Moore, Daniel, “US Battery Hype Spurred by Climate Law Faces Hurdles From China,” Bloomberg Law

(August 28, 2023). 

57 U.S. Department of Energy, Vehicle Technologies Office, Battery Policies and Incentives Search,

accessed November 13, 2023. 

58 U.S. Department of Energy, Battery Energy Storage System Procurement Checklist, February 3, 2023. 

59 National Renewable Energy Laboratory, Grid-Scale Battery Storage – Frequently Asked Questions, 

updated September 2019.

60 Federal Consortium for Advanced Batteries, Executive Summary: National Blueprint for Lithium Batteries 

2021–2030, June 2021. 

61 U.S. Customs and Border Protection, Trade, Forced labor, Uyghur Forced Labor Prevention Act, updated 

January 26, 2024. 

62 Groom, Nichola, “EV battery imports face scrutiny under US law on Chinese forced labor,” Reuters 

(August 19, 2023). 

63 U.S. Department of Labor, 2022 List of Goods Produced by Child Labor or Forced Labor, September 

2022. 

64 U.S. Customs and Border Protection, Withhold Release Orders and Findings List, accessed November 

13, 2023. 

65 U.S. Department of State, “The United States Releases Signed Memorandum of Understanding with the 

Democratic Republic of Congo and Zambia to Strengthen Electric Vehicle Battery Value China,” Press 

Release (January 18, 2023). 
DNV – www.dnv.com Page 41

• The U.S.–Japan Agreement on Strengthening Critical Minerals Supply Chains was announced 

in March 2023, establishing commitments for cooperation on critical minerals for batteries.66

• U.S.–EU negotiations regarding an agreement on critical minerals was announced in March 

2023.67

• The U.S.–Mexico–Canada Agreement went into force in 2020. It replaces the North American 

Free Trade Agreement and includes provisions to facilitate trade in energy products and critical 

minerals.68

• The U.S.–EU Trade and Technology Council was established in 2021 and aims to foster 

cooperation and coordination on a range of trade and technology issues, such as the 

development of secure and sustainable supply chains for critical technologies, including 

batteries.69

• The U.S.–UK Trade Agreement has been under negotiation since 2020. It covers a range of 

sectors, including critical minerals and battery components, and in June 2023, critical minerals

were specifically added, similar to the EU agreement being negotiated.70

• In April 2023, the Indonesian government announced it would propose a limited Free Trade 

Agreement to cover critical minerals, in particular nickel, of which Indonesia is the largest 

producer globally.71

Currently, China is the largest producer of batteries globally, and many of the critical minerals are 

either mined in China or Chinese companies have access to these minerals through investments in 

various producing countries. In 2020, the Chinese government put into place the Export Control Law, 

which allows the government to restrict the exports of goods and technologies that are deemed a 

national security risk, which could include critical minerals, especially rare earth minerals. 72

Accordingly, in July 2023, the Chinese government announced that it would restrict the export of 

gallium and germanium, which are primarily used in semiconductor production. Semiconductors are 

used in the power electronics for wind turbines, solar modules, BESS, and battery management 

systems.

73 As a result, U.S.–China trade relations can affect supply chains across energy industries, 

not only for batteries.

3.2.3 Market incentives

The capital and cost estimates made in this report do not take into consideration any ITCs and PTCs 

that are available for renewable energy projects under the IRA or any other applicable tax incentives. 

66 U.S. Trade Representative, Agreement Between the Government of the United States of America and the 

Government of Japan on Strengthening Critical Minerals Supply Chains, March 28, 2023. 

67 European Commission, Statement, Joint Statement by President Biden and President von der Leyen, 

March 10, 2023. 

68 U.S. Trade Representative, United-States-Mexico-Canada Agreement, accessed November 13, 2023. 

69 U.S. Trade Representative, Countries & Regions, Europe & Middle East, Europe, Trade and Technology 

Council (TTC), U.S.-E.U. Trade and Technology Council (TTC), accessed November 13, 2023. 

70 U.S. Trade Representative, Countries & Regions, Europe & Middle East, Europe, United Kingdom, 

accessed November 13, 2023. 

71 Medina, Ayman Falak, ”Indonesia Proposed Limited FTA with the United States,” ASEAN Briefing (June 

28, 2023). 

72 U.S. Department of Commerce, International Trade Administration, China - Country Commercial Guide, 

U.S. Export Controls, updated April 7, 2023. 

73 Areddy, James T. and Sha Hua, “China Restricts Exports of Two Minerals Used in High-Performance 

Chips,“ The Wall Street Journal (July 4, 2023)
DNV – www.dnv.com Page 42

The IRA, which was signed into law by the Biden administration in August 2022, extended tax credits 

to promote the adoption of renewable energy systems.74 ITCs and PTCs are available for renewable 

energy projects, but generally a project cannot claim both; however, a project could claim different 

credits for co-located systems, such as solar + storage, depending on Internal Revenue Service 

(IRS) guidance.75,76

One change the IRA brings is the decoupling of storage and generation. Section 13102 of the IRA 

amends Section 48 of the Internal Revenue Code of 1986 to add an ITC for standalone energy 

storage technology, which previously was only available to storage projects that were part of a new 

solar generation facility and only if the storage facility was charged 80% by the solar facility. The 

new ITC applies to standalone energy storage technology with a minimum capacity of 5 kWh, is not 

limited to batteries, and includes other storage technologies. Additionally, Section 13702 of the IRA

provides ITC for clean energy generation and energy storage projects placed in service after 

December 31, 2024. Battery storage projects could qualify for a bonus rate of 30% if they satisfy 

wage and apprenticeship requirements. Further ITCs could be applied for meeting domestic content 

requirements and for being located within an energy community. The IRS also outlines credits and 

deductions available for individuals under the Residential Clean Energy Credit.

In addition to the federal-level incentives, some states are offering financial incentives and/or tax 

incentives for BTM battery storage projects to businesses and/or consumers. In some states, utilities

are offering incentives for battery storage projects to customers within their service territory. For 

example, a Vermont utility, Green Mountain Power (GMP), offers a range of programs for a

residential energy storage program called Bring Your Own Device, where homeowners can install

a storage system and enroll in GMP’s program. Table 3-6 lists examples of state-level incentives. A 

more comprehensive database of state-level incentives and policies can be accessed through the 

Database of State Incentives for Renewables and Efficiency (DSIRE), which has an interactive map 

that is searchable by state. 

Table 3-6. Example state-level battery storage incentives

State Incentive Program Scope/Incentive

California Self-Generation Incentive 

Program (SGIP)

$1 billion through 2024; $850/kWh for equity 

and $1,000/kWh for equity resiliency (each 

has its own eligibility criteria)

Connecticut

Public Utilities Regulatory 

Authority (PURA) Energy 

Storage Solutions Program

Residential customers can receive around 

$200/kWh, with a maximum of $7,500 per 

project; commercial and industrial customers 

can receive a maximum incentive of 50% of 

the project cost

Hawaii Green Energy Market 

Securitization (GEMS) Program

Provides long-term financing with no upfront 

costs for residential and commercial BESS

Maryland Maryland Energy Storage 

Income Tax Credit Program

$750,000 in energy storage income tax credit 

certificates available per year on a first come, 

first served basis through 2024

74 The White House, Building A Clean Energy Economy: A Guidebook to the Inflation Reduction Act’s 

Investments in Clean Energy and Climate Action, Version 2, January 2023. 

75 U.S. Department of Energy, Energy Efficiency & Renewable Energy, Solar Energy Technologies Office, 

Federal Solar Tax Credits for Businesses, updated June 2023. 

76 U.S. Environmental Protection Agency, Renewable Electricity Production Tax Credit information, updated 

February 22, 2023. 
DNV – www.dnv.com Page 43

State Incentive Program Scope/Incentive

New York NYSERDA’s Retail Energy 

Storage Incentives

$3 million budget with $498,210 available; 

incentive is $250/kWh; aim to reach 1,500 

MW-DC of energy storage by 2025 and 

3,000 MW-DC by 2030

Oregon Oregon Solar + Storage Rebate 

Program

$1.2 million in funding available for low- and 

moderate-income households; $2.1 million 

non-income restricted; rebates are issued to 

approved contractors that pass savings on to 

customers

Vermont Bring Your Own Device (BYOD)

Energy storage owners can enroll in the 

BYOD program and receive an upfront 

payment of $850/kW-DC for a three-hour 

discharge and $950/kW-DC for a four-hour 

discharge. If customers retrofit their existing 

solar system with storage in a constrained 

area of the grid, they can receive an extra 

$100/kW-DC per discharge.

Data source: DSIRE, state, and utility websites.

Note: MW-DC=megawatt direct current.

3.2.4 Relationship to other DG technologies 

While solar PV benefits from being a familiar option to customers as method of procuring clean 

energy under favorable economic conditions, battery storage systems are typically not purchased 

solely on the basis of customer economics. Adoption of battery storage systems by customers is 

largely dependent on the value the customer places on accessing reliable backup power. Thus, 

battery storage adoption is more closely linked to the customer’s perception and quantification of 

resiliency needs, and solar is more closely linked to a customer’s desire to achieve energy savings 

or access clean energy.

Storage adoption can be motivated by severe weather events leading to outages. Natural disasters 

such as hurricanes, floods, wildfires, and other events can leave marked impressions on the 

customer’s psyche and will influence how the customer prioritizes resiliency and backup power for

everyday needs. The ability of a battery storage system to provide backup power in the event of an 

outage or other emergency is an important attribute that sets these systems apart from the broad 

category of DERs. Most utilities adhere to safety and interconnection rules that prevent customers 

with PV-only (not solar + storage) from using PV electricity during an outage event. Incorporating 

battery storage along with solar enables customers to use their system in response to different 

events. Solar + storage is unique in that it empowers customers to bolster their resiliency at their 

home or business while also reducing greenhouse gas emissions by generating and storing clean 

power. Pairing generating capacity with BESS is increasingly being deployed to enhance grid 

reliability, flexibility, and efficiency. Batteries can be used to store energy during low demand times 

and dispatched during periods of peak demand. 

Literature and research on BTM standalone batteries is limited, likely due to the overwhelming 

customer preference for solar + storage co-adoption. Currently, standalone battery systems are 

ineligible for the federal ITC and therefore have a higher $/kW-DC cost than a solar + storage system

after applying the tax incentives.

Battery storage pairs well with renewable energy sources, such as solar and wind. These energy 

sources are intermittent, meaning that they do not generate electricity all the time and they require 

energy storage to match demand and supply. Battery storage can be used to store excess electricity 

generation during periods of low demand then discharge it back into the grid during periods of high 

demand, allowing for price arbitrage. Consumers are also investing in battery storage to reduce 
DNV – www.dnv.com Page 44

energy bills and add reliability. Some of this demand will be coupled with the growth in EV adoption, 

as companies such as Tesla offer consumers combined EV charging and energy storage products, 

such as the Powerwall, which can also be coupled with solar energy.77

The potential value of a battery storage system that a customer can obtain is dependent on the 

programs and pricing structures available. Peak shaving and dispatching a battery storage system 

in response to pricing or outage events on the grid will be influenced by the dispatching incentives, 

peak pricing, and other factors determined by the grid energy provider.78 According to a recent 

survey of residential utility customers across the United States, demand response participants have 

a significantly higher rate of battery adoption and battery EVs than the national average.79

3.2.5 Technology research and development rates

Battery energy storage systems can provide value through a variety of services or use cases, but 

the key values of distributed BTM storage are backup power and bill savings. For the purposes of 

this study, this section will focus on technology R&D in distributed BTM battery storage applications. 

Lithium-ion battery technology was first researched in the 1970s and has been the battery of choice 

in consumer electronics since the 1990s.80 Lithium-ion batteries remain the technology of choice for 

the vast majority of EVs and BTM energy applications and are projected to continue to lead in market 

share. Transportation sector applications are expected to be the primary driver of battery technology 

development and potential cost declines. 

3.2.6 Current and anticipated rates of market adoption by sector

Recent studies from NREL found that cost reductions and the value of backup power increase 

adoption of BTM battery storage.81 Between 2021 and 2022, both residential and commercial and 

industrial (C&I) battery storage deployment in terms of megawatthour (MWh) capacity increased by 

36% and 115%, respectively. Wood Mackenzie’s 2022–2026 U.S. energy storage forecast expects 

annual growth of 2.1 GW of residential and 1 GW of non-residential new BTM battery capacity.82

3.2.7 Relationship between battery chemistry and applications

New battery chemistries and architectures are emerging and are being tested for both energy 

storage and the transportation sector, but lithium-ion batteries will continue to be the current 

mainstay for both sectors. Some of the changes in what battery chemistry will be used for certain 

applications and the demand for certain battery chemistries will be driven by cost and the

performance requirements of the battery.

The largest consumer of lithium-ion batteries currently is the transportation sector, and the rate of 

adoption of EVs globally will directly affect demand and battery prices.83 This increase in demand 

will also drive R&D in batteries to develop new battery chemistries and battery technologies, which 

in the long term is expected to create cheaper, more energy dense, and safer batteries. Six common 

77 Tesla, Powerwall, accessed November 13, 2023.

78 Prasanna, Ashreeta and Kevin McCabe, Storage Futures Study: Distributed Solar and Storage Outlook: 

Methodology and Scenarios, National Renewable Energy Laboratory, 2021.

79 Smart Energy Consumer Collaborative, Distributed Energy Resources: Meeting Consumer Needs, 2019.

80 Augustine, Chad and Nate Blair, Storage Futures Study – Storage Technology Modeling Input Data 

Report, National Renewable Energy Laboratory, 2021.

81 Blair, Nate and Chad Augustine, Storage Futures Study – Key Learnings for the Coming Decades, 

National Renewable Energy Laboratory, 2022.

82 Wood Mackenzie, Q2 2022 US Energy Storage Monitor, 2022. 

83 U.S. Department of Energy, Vehicle Technologies Office, National Blueprint for Lithium Batteries, June 7, 

2021.
DNV – www.dnv.com Page 45

types of lithium-ion batteries are used in various types of EVs as outlined in Table 3-7 with NMC

being the most common battery chemistry.

Table 3-7. Common EV battery chemistries globally

Battery Type Battery Chemistry Used in EVs in 2022

NMC Lithium nickel manganese cobalt 60%

LFP Lithium iron phosphate 30%

NCA Lithium nickel cobalt aluminum 8%

LCO Lithium cobalt oxide <1%

LMO Lithium manganese oxide <1%

LTO Lithium titanium oxide <1%

Data Source: International Energy Agency

Carmakers have been favoring NMC batteries because this battery chemistry has been available

since the 1980s and has one of the higher energy densities among existing, commercially available 

battery chemistries—NCA batteries also have a high energy density, however, this battery chemistry 

was developed by Panasonic in 2019 for Tesla. Energy density refers to how much energy can be 

stored in each battery and is usually measured by volume. NMC batteries today have an energy 

density range of between 150 watthours per kilogram (Wh/kg) to 250 Wh/kg, compared with LFP 

batteries with an energy density range of 150 Wh/kg–190 Wh/kg, and NCA batteries with 200 

Wh/kg–260 Wh/kg.84 Research is continuing to try to develop new battery chemistries that are lower

in cost and high in energy density. For example, sodium-ion batteries are being commercialized, 

which are lower in cost, as they do not contain critical minerals, but can only provide about 160 

Wh/kg in energy density.85

Energy density is an important characteristic for EVs because cars have limited space to house a 

battery and the weight of the battery affects vehicle performance. However, for most BESS, the size 

and weight of the battery are not major restricting factors for deployment, and in that sense, 

customers have more flexibility to consider battery chemistries that have lower energy densities or 

are heavier. For example, lead acid batteries (LABs) are still widely used in mini-grid and off-grid 

applications in developing countries, because these batteries are low cost, use proven technology, 

and in most cases are part of a circular economy and are easily recycled.86 However, LABs typically 

have a very low energy density of around 30 Wh/kg–40 Wh/kg.87 Another option for stationary 

battery storage is the vanadium redox flow battery, which has a much longer life cycle and lower

level of degradation when compared with lithium-ion batteries. However, it uses a critical mineral, 

vanadium, as well as a more complex and large pump mechanism, making it unsuitable for EVs or 

84 Pacios, Roberto and Inigo Careaga, “Cathode Composition of Battery Cells: A Three-way War,” CIC 

energi GUNE (January 18, 2022). 

85 CATL, “CATL Unveils Its Latest Breakthrough Technology by Releasing Its First Generation of Sodiumion Batteries,” Press Release (July 29, 2021).

86 Augustine, Chad and Nate Blair, Storage Futures Study – Storage Technology Modeling Input Data 

Report, National Renewable Energy Laboratory, 2021.

87 Crawford, Alasdair J. and Qian Huang, “Lifecycle comparisons of selected Li-ion battery chemistries 

under grid and electric vehicle duty cycle combinations,” Journal of Power Sources (March 15, 2018), 

p.185–193.
DNV – www.dnv.com Page 46

consumer electronics applications. The Pacific Northwest National Laboratory (PNNL) is working 

with companies to commercialize this technology for BESS.

88

Figure 3-7 shows the market share of various battery chemistry types from 2015 forecast to 2030. 

Since 2019, lithium-ion batteries have been the most common type of batteries used in BESS.

89

Batteries used in energy storage tend to prioritize energy density over power density, whereas EV 

batteries prioritize power density over energy density. Power density refers to the amount of power 

a battery can deliver per volume or mass. To date, NMC batteries have been the most common 

battery chemistry for BESS, and for the cost profile used in this report, NMC storage batteries were 

modeled. However, NREL’s ATB for utility-scale battery storage found that LFP batteries are 

becoming the primary chemistry for stationary storage batteries. 90 Home or consumer battery 

storage units used NMC or NCA batteries because of the limited space available and higher energy 

density requirement. 91 However, these systems may be shifting from NMC to LFP batteries, 

primarily due to battery cost.92 For instance, Tesla announced in April 2023 that it will be switching 

the batteries it uses in its Powerwall3 for homes from NMC to LFP.93

Figure 3-7. Stationary energy storage battery chemistry market share and forecast all sectors, 

2015–2030

Data source: Wood Mackenzie

Developing new chemistries that use fewer critical minerals without loss of energy density or 

creating new higher energy density batteries are R&D goals for battery developers and carmakers.94

Additionally, developing batteries that are safer and less susceptible to thermal runaway (which can 

lead to fires) and improving the life cycle of batteries (the number of times a battery can be charged 

88 Maisch, Marija, “New US license to bring vanadium Redox flow batteries to market,” pv magazine (March 

3, 2022). 

89 Augustine, Chad and Nate Blair, Storage Futures Study - Storage Technology Modeling Input Data 

Report, National Renewable Energy Laboratory, 2021.

90 National Renewable Energy Laboratory, Annual Technology Baseline, Utility-Scale Battery Storage, 2023. 

91 International Energy Agency, Energy system, Electricity, Grid-scale Storage, accessed November 13, 

2023. 

92 Wood Mackenzie. News Release, “LFP to overtake NMC as dominant stationary storage chemistry by 

2030,” Press Release (August 17, 2020).

93 Agatie, Cristian, “Tesla Switches to Using LFP Prismatic Cells in Upcoming Powerwall 3,” Autoevolution 

(April 14, 2023). 

94 International Energy Agency, Global EV Outlook 2023—Trends in Batteries, April 2023. 
DNV – www.dnv.com Page 47

and discharged) are also important. Numerous new battery chemistries are currently under 

development, but solid-state batteries, of which there are various chemistries, are considered the

most promising, especially for EVs. Solid-state batteries do not use a liquid electrolyte, which 

increases safety, requires less cooling, uses fewer critical minerals, and could potentially have much 

higher energy density than the current lithium-ion batteries.95,96 In October 2023, Toyota announced 

that it will be ready to mass produce solid-state batteries for EVs by 2027–2028. 97 These 

technological developments in EV batteries are important because they are likely to impact BESS

technologies and costs as well.

New developments in battery architecture are also helping to reduce battery cost and improve 

reliability. Japan’s Panasonic developed the cylindrical electrode design in its 4680 batteries for 

Tesla, which reduces the electrical path and increases power output.98 China’s BYD developed the 

cell-to-pack, or module-free, battery architecture, which eliminates battery modules and directly 

integrates the battery cells into the pack, reducing materials used, increasing space utilization, and 

reducing battery weight.99 Such changes in battery architecture could reduce material usage, reduce 

battery cost, and increase battery safety for BESS as well. 

3.2.8 Trends in battery disposal, recycling, or repurposing

Lithium-ion batteries contain critical minerals, such as aluminum, cobalt, lithium, and nickel, which 

can be recycled to supplement the supply chain, reduce cost, and help create a more sustainable 

circular economy. Recycling batteries is currently not an easy, cheap, or environmentally friendly 

process; however, new and different methods of recycling batteries and materials are beginning to 

emerge. The International Energy Agency (IEA) estimates that globally only 5% of lithium-ion 

batteries are currently being recycled. In contrast, LABs, which have been around for much longer,

have a well-developed circular economy and have a recycling rate of over 90%.100 Increasing the 

level of recycling for lithium-ion batteries will help reduce the need for sourcing additional critical 

minerals as well as reduce material cost and make battery production more sustainable. However, 

currently, very little regulation for battery recycling exists, and regulation will have to grow in tandem 

to build up a circular economy for lithium-ion batteries. According to Call2recycle, 19 states currently 

have battery recycling requirements in effect, and 11 states require battery producers to offer or 

fund battery recycling.101

Recycling lithium-ion batteries is a growing business and an estimated 70%–90% of critical minerals 

can be recovered during the recycling process. 102 According to NREL’s NAATBatt Lithium-Ion 

Battery Supply Chain Database, 44 companies are currently active in the EOL/recycling supply 

chain in the United States. The three leading companies in the United States are Li-Cycle 

Corporation, Redwood Materials, and Retriev Technologies. These recycling companies have 

partnered with battery makers, carmakers, and other companies to recycle batteries. For example, 

95 Harmon, Joseph E., “New design for lithium-air battery could offer much longer driving range compared 

with the lithium-ion battery,” Argonne National Laboratory, Press Release (February 22, 2023). 

96 International Energy Agency, Global EV Outlook 2023, April 2023. 

97 Toyota Motors, “Idemitsu and Toyota Announce Beginning of Cooperation towards Mass Production of 

All-Solid-State Batteries for BEVs,” Press Release (October 12, 2023). 

98 Panasonic Energy, Technological Strategy of Panasonic Energy - for Sustainability and Well-Being, 

Presentation, February 8, 2023. 

99 BYD, BYD’s New Blade Battery Set to Redefine EV Safety Standards, accessed November 13, 2023. 

100 International Energy Agency, Global EV Outlook 2023, April 2023.

101 Call2recycle, Recycling Laws By State, accessed November 13, 2023.

102 Gregoir, Liesbet, Metals for Clean Energy: Pathways to solving Europe’s raw material challenge, KU 

Leuven, April 2022. 
DNV – www.dnv.com Page 48

Li-Cycle recycles various types of lithium-ion batteries at four operating plants and claims it can 

recover up to 95% of the critical materials in lithium-ion batteries.103 However, recycling lithium-ion 

batteries faces numerous hurdles:

• Lack of regulation: Little regulation exists throughout the recycling process, from the 

mandate to recycle, assessment of batteries, the recycling process, and quality of recycled 

output.

• Cost: Costs vary depending on the recycling process that is used, with the most common 

processes being mechanical, hydrometallurgy, and pyrometallurgy. Depending on the 

recycling process, the disassembly of batteries can be labor intensive and costly. For 

example, the battery pack for the Nissan Leaf EV is considered to have the highest 

disassembly cost, followed by the Porsche Taycan EV, while the Tesla battery pack is 

considered the least costly.104 Costs also exist beyond the recycling process, such as the 

transportation costs of the EOL batteries to the recycling facility, the cost of transporting the 

recycled materials, and the cost of disposal of the waste material from the recycling process 

itself. The cost distribution of who will pay for what or if some of these costs can be 

subsidized will affect the recycling industry. Cost distribution could potentially include a 

combination of manufacturers, consumers, companies, and the U.S. government. The DOE, 

under the BIL, is providing about $74 million in funding for 10 projects to advance EV battery 

recycling and reuse.105

• Types of batteries: Currently, batteries come in numerous varieties, both in capacity, size, 

type, and chemistry, that recycling companies need to be able to process. The bulk of the 

EV batteries currently being recycled are those replaced under vehicle warranty, and the EV 

battery replacement cycle will begin in about five years, when the first wave of EV batteries 

reaches their EOL. In 2018, more than 300,000 EVs were sold in the United States, and 

assuming a 10- to 15-year battery lifecycle, 2028–2033 would mark an increase in 106￼

Battery recycling companies have stated that EV batteries will be the bulk of their business, 

but whether they recycle batteries from EVs or BESS does not affect their cost or business 

model—the 107￼￼Different minerals and amounts of minerals will be recovered depending 

on the battery chemistry. For battery recycling companies, which battery chemistry will 

ultimately become the mainstay chemistry remains uncertain, and until that it is clear, it is 

difficult to streamline, concentrate, or scale the recycling process, as well as project the 

profitability of recycling.

• Profits: The profits of recycling companies will depend on the materials that can be 

recovered from the recycled batteries. If future batteries contain fewer or no critical minerals, 

then recycling becomes less commercially viable for these companies. This possibility

103 Li-Cycle, Creating a Circular and Sustainable Battery Supply Chain, Investor Presentation, August 2023. 

104 Lander, Laura and Tom Cleaver, “Financial viability of electric vehicle lithium-ion battery recycling,” 

iScience (July 23, 2021). 

105 U.S. Department of Energy, Biden-Harris Administration Announced Nearly $74 Million To Advance 

Domestic Battery Recycling And Reuse, Strengthen Nation’s Battery Supply Chain, November 16, 

2022. 

106 U.S. Department of Energy, Alternative Fuels Data Center, U.S. Plug-in Electric Vehicle Sales by Model, 

January 2020. 

107 Colthorpe, Andy, “North America’s largest Li-ion battery recycling giga-facility to ‘take on as much as 

possible’ from ESS sector,” Energy Storage News (January 14, 2022). 
DNV – www.dnv.com Page 49

cannot be determined until the mainstay battery chemistry for each application is determined, 

which currently is unclear. 

The level of recycling of lithium-ion batteries, at least for EVs, may be spurred by the Clean Vehicle 

Tax Credit (CVTC), which applies to vehicles purchased after April 18, 2023, that meet critical 

mineral and battery component requirements to qualify. The CVTC requires 40% or more of the 

battery’s critical minerals be extracted or processed in the United States or have been recycled in 

North America. This requirement gradually increases to 80% in 2027.108 These requirements could 

be a catalyst to increase the recycling of batteries for all sectors that use batteries, not just EVs. 

Unlike recycling lithium-ion batteries, some batteries have been repurposed for other applications, 

mostly for BESS. Repurposing batteries has its own challenges and costs. Battery cells need to be 

assessed and tested before they can be repurposed, and currently no standards for repurposing

exist, which makes quality control difficult. This market is still limited, but this may change if EVs 

make up a larger portion of total vehicle stock and more EV batteries reach their EOL. 

In Asia and Europe, EV batteries are being repurposed as energy storage batteries, as more EVs 

have been sold there than in the United States. In Japan, Toyota has been repurposing EOL EV 

batteries together with electric utilities for energy storage since 2018.109 Repurposing EV batteries 

for energy storage usually requires batteries modules and packs to be disassembled, cells tested, 

and bad cells replaced. The cells then reconnected and reconfigured to create a larger integrated 

system. In terms of cost of repurposing EV batteries, NREL provides a free tool to model the cost 

of repurposing EV batteries in a secondary market, Battery Second-Use Repurposing Cost 

Calculator. According to this tool, the total cost of a second-life EV battery could be in the range of 

$40/kWh–$160/kWh, which can be compared with BNEF’s 2022 EV battery pack cost of 

$151/kWh.110 It is expected that as more EV batteries reach EOL, more will be repurposed into 

BESS. It Is estimated that 2.1 terawatthours (TWh) to 4.8 TWh of repurposed batteries could 

become available globally by 2050.111 To put this amount in context, the International Renewable 

Energy Agency estimates a global need for 9 TWh of energy storage by 2050.112

Many U.S. states have regulations regarding the disposal of batteries, which can include LABs, 

lithium-ion batteries, nickel-metal hydride batteries, and others. However, states must follow federal 

regulatory requirements for waste batteries as issued by the U.S. Environmental Protection 

Agency.113 DOE’s Vehicle Technologies Office also offers an online tool, the Battery Policies and 

Incentives Search, which allows users to look for federal and state policies and incentives related 

to batteries for EVs and energy storage, including waste regulations and incentives.

108 Internal Revenue Service, Credits for New Clean Vehicles Purchased in 2023 or After, updated June 22, 

2023. 

109 Cogan, Ron, “Toyota Aims at Reuse of EV Batteries,” Green Car Journal (March 30, 2018). 

110 Bloomberg New Energy Finance, “Lithium-ion Battery Pack Prices Rise for the First Time to an Average 

of $151/kWh,” December 6, 2022.

111 Xu, Chengjian and Paul Behrens, “Electric vehicle batteries alone could satisfy short-term grid storage 

demand by as early as 2030,” Nature Communications (January 17, 2023). 

112 International Renewable Energy Agency, Global Renewables Outlook: Energy Transformation 2050, 

2020.

113 U.S. Environmental Protection Agency, Hazardous Waste, Used Lithium-Ion Batteries, accessed 

November 13, 2023.
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4 WIND ENERGY SYSTEMS

DNV developed technology attributes and cost data for BTM wind energy systems for three 

representative commercial sector customer segments and one residential sector customer segment. 

These attributes and cost data were developed at the national level and assumed to be relatively 

similar throughout individual states. DNV then modeled annual hourly generation profiles for each 

wind energy configuration to gather detailed operational data, and it further assembled additional 

relevant performance data for all system configurations. The final step was to develop current year 

(2022) cost estimates from available data and align associated cost estimates and attributes with 

previous years of EIA’s RECS, CBECS, and MECS. The process is described in the following 

subsections.

4.1 Wind energy systems technology attributes and cost data

4.1.1 System configurations

DNV used PNNL’s distributed wind database and its most recent Distributed Wind Market Report to 

identify and classify representative residential and commercial system capacities for the 

development of performance attributes and cost data. 114 , 115 This information was verified by 

reviewing DNV proprietary project trackers for distributed wind energy systems. DNV’s tracker 

database contains over 2,500 unique projects of varying sizes of distributed or BTM wind installed 

within the last 25 years. DNV consolidated all relevant commercial installation types (agriculture, 

government, and institutional subsectors) where project capacities aligned with representative 

commercial size ranges and identified representative sizes based on the distribution of installed 

commercial projects within the last 10 years. Additionally, DNV updated residential installation data 

to only include relevant representative system capacities based on the representative capacity

range categorized for residential installations in this analysis. For example, DNV assumed larger 

installations classified as residential (more than 40 kW-AC) would better align with another customer 

segment (that is, agricultural) and so removed them from residential analysis. 

Residential wind systems installed in the United States are almost all small, distributed wind projects 

(less than 100 kW-AC) and are typically closer to between 5 kW-AC and 25 kW-AC in capacity. 

Small and large distributed projects (more than 1 MW-AC) represent the majority of installations and 

overall installed capacity in the commercial distributed wind market. The medium commercial size 

range (100 kW-AC–1 MW-AC) represents a very small portion of total installations and installed 

capacity in recent years (2019–2022) due to the limited turbine products available in this size range. 

However, costs for a midsize system were modeled and included as a representative system size, 

given that installed capacity for midsize turbine installations historically represented a larger portion 

than current annual penetration, the stimulating effect of the IRA incentives available in the future, 

and increasing interest in midsize turbines among developers and R&D efforts.

Table 4-1 shows the residential and commercial wind energy representative system capacities and 

additional relevant characteristics used to develop performance attributes and cost estimates. The

data used to classify representative system sizes were filtered to remove installations with 

insufficient data to accurately include as representative for the respective size bin. 

114 Pacific Northwest National Laboratory, Research, Sustainable Energy, Renewable Energy, Wind Energy, 

Distributed Wind, Distributed Wind Market Report, Distributed Wind Project Database, accessed 

November 13, 2023.

115 Pacific Northwest National Laboratory, Distributed Wind Market Report: 2023 Edition, August 2023.
DNV – www.dnv.com Page 51

Table 4-1. Technology attributes for residential and commercial wind configurations and 

representative systems

System Configuration

Representative 

System Capacity

Range

Representative 

System Capacity Historical Installations and Installed Capacity 

Residential Distributed Wind 1–40 kW-AC 9.3 kW-AC 127 installations, ~1.35 kW-AC (2015–2022)

Small Distributed Wind <100 kW-AC 40 kW-AC 710 installations, ~32.2 MW-AC (2012–2022)

Medium Distributed Wind 100–1,000 kW-AC 300 kW-AC 63 installations, ~44.5 MW-AC (2012–2022)

Large Distributed Wind >1,000 kW-AC 2,000 kW-AC 125 installations, ~480 MW-AC (2012–2022)

4.1.2 Technology attributes and generation shapes

After developing technology system configurations and representative capacities for 2022, DNV 

modeled each individual system using NREL’s SAM to collect hourly generation shapes and 

associated performance metrics. DNV modeled representative locations in individual states to 

generate a blended U.S. average of annual system performance data for residential and individual 

commercial systems. The blended approach involved weighting representative locations based on 

the number of recent installations and installed capacity for each segment and capacity range. 

States such as Iowa, Minnesota, California, Ohio, and Massachusetts were weighted higher for 

large installations, whereas states such as New York, Nevada, Alaska, and California were weighted 

higher for smaller installations. This weighting directly influenced modeled annual system production 

(kWh) and ultimately the average capacity factor for representative commercial wind energy 

systems. 

4.1.3 System performance attributes 

Table 4-2 shows performance attributes for representative U.S. residential and commercial wind 

energy systems summarized from the data developed in the previous subsections. The data are

presented to align with current year (2022) performance attributes but were collected to represent 

previous years of EIA segment-level surveys for the residential sector from 2015 to 2022 and the 

commercial sector from 2012 to 2022. 

Table 4-2. Residential and commercial wind system performance attributes (2022)

Performance Attribute Residential

(1-40 kW-AC)

Small

(<100 kW-AC)

Medium

(100-1,000 kW-AC)

Large

(>1,000 kW-AC)

Turbine Rating 9.3 kW-AC 40 kW-AC 300 kW-AC 2,000 kW-AC

Number of Turbines 1 1 1 1

Power Rating 165 W/m2 167 W/m2 170 W/m2 325 W/m2

Hub Height 25 m 32.5 m 45 m 90 m

Rotor Diameter 12.5 m 20 m 60 m 120 m

Average Net Capacity Factor 18.9% 20.2% 20.4% 26.5%

Availability a 99.0% 99.0% 99.0% 99.0%

Total System Losses 11.5% 11.5% 11.5% 11.5%

a Availability percentage (%) refers to system availability considering planned downtime for maintenance and not as a 

function of system performance related to overall capacity factor.
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Overall, larger commercial systems have a higher capacity factor due to turbine configuration and 

assuming a pitch-regulated power curve. Availability and total system losses are assumed to be the 

same for all system sizes.

4.1.4 2022 cost data

Capital cost data for commercial wind energy systems were collected at a national level for each 

system capacity for 2020–2022 using NREL’s recent cost of wind energy review.116 DNV verified 

and provided slight cost adjustments where appropriate to align with exact representative system 

capacity assumptions, based on DNV proprietary project databases and reported individual project 

experience for 2022, and PNNL’s Distributed Wind Market Report capacity-weighted installed costs. 

Distributed wind energy capital cost categories are split entirely between turbine (that is, equipment) 

costs and BOS costs. Turbine costs consist of a rotor, nacelle, and tower, whereas BOS costs 

consist of general foundation and site costs, electrical infrastructure, and relevant development, 

engineering, and labor costs.

4.1.5 Historical cost data

Baseline historical capital cost data were collected from NREL’s ATB reports and data files at the 

national level for both the residential and commercial sectors. DNV used historical labor costs, sales 

taxes, and calculated supply chain costs to further scale individual cost categories to align with BOS 

cost subcategories in historical years. These historical costs, presented in 2022 constant (real) 

dollars, were combined with current cost data detailed in the previous subsection and summarized 

for the residential and commercial system capacities in Figure 4-1 through Figure 4-4. 

Similar to other technologies, residential distributed wind has the highest capital costs compared 

with various capacities of commercial installations (Figure 4-1). Capital costs in the residential sector

has been declining over the past seven years. Cost increases in the most recent data year (2022) 

are largely due to higher BOS costs and increases in turbine costs in 2022. 

Figure 4-1. U.S. average residential distributed wind project cost data (2015–2022, 2022 $)

Small, distributed wind project costs increased in 2022 on a $/kW-AC basis, largely due to higher 

BOS costs and slight increases in turbine costs, while costs generally declined in the preceding 

years back through 2012 (Figure 4-2). Out of all installation sizes, $/kW-AC installed costs for small 

and medium distributed wind installations increased the most in 2022.

116 Stehly, Tyler and Patrick Duffy, “2021 Cost of Wind Energy Review,” National Renewable Energy 

Laboratory, Presentation (December 2022). 
DNV – www.dnv.com Page 53

Figure 4-2. U.S. average small commercial distributed wind project cost data (2012–2022, 

2022 $)

Cost similarly rose for medium (Medium or midsize) commercial distributed wind projects in 2022, 

with an average installed cost of $4,057/kW-AC (Figure 4-3). Medium commercial wind installations 

have been limited in recent years, so DNV also used PNNL’s Distributed Wind Market Report and 

associated data, as well as proprietary DNV project tracker data, as an additional verification of cost 

data from 2017 to 2022.

Figure 4-3. U.S. average medium commercial distributed wind project cost data (2012–2022, 

2022 $)

Large commercial distributed wind projects hold the largest market share by total number of 

installations and capacity and are the most cost-effective distributed wind projects based on $/kWAC installed costs (Figure 4-4). Although capital costs for large distributed systems increased in 

2022 ($3,036/kW-AC), the average cost remains below the average system cost for small and 

midsize systems and continues to be a strong market segment for end users. 
DNV – www.dnv.com Page 54

Figure 4-4. U.S. average large commercial distributed wind project cost data (2012–2022, 

2022 $)

4.2 Wind market discussion

Distributed wind technology is a relatively mature DER. Wind turbines generate electricity by 

converting kinetic energy in the wind into rotating shaft power that spins an AC generator. BTM 

small-scale wind systems typically serve rural homes, farms, and manufacturing facilities due to 

their size and land requirements. Wind resource, high retail electricity prices, and favorable policies 

are the key contributing factors to favorable BTM wind system economics. 

According to a recent survey of residential utility customers across the United States, perceptions 

of not having access to small wind turbines is the main barrier for adoption of this DER in the 

residential sector. Residential wind system adoption is quite low in the United States—the survey 

found that system owners represent a very small portion of total residential utility customers. 117

Adoption is constrained to properties with at least one acre of land and no local ordinances against 

tall towers, so adoption typically only occurs outside of metropolitan and urban regions.

Cumulative installed capacity of BTM wind turbines in the United States is 1,075 MW-AC, as of 2021. 

The 2023 PNNL Distributed Wind Market Report found that 13 states added 29.5 MW-AC of new 

distributed wind capacity in 2022, which represents a $84 million investment in 1,755 turbine units.118

Of the 29.5 MW-AC of distributed wind added in 2022, 92% came from projects using large turbines 

(greater than 1 MW-AC), no new capacity came from medium turbines (100 kW-AC–1,000 kW-AC), 

and the remaining 8% came from small turbines (less than 100 kW-AC). In terms of capacity 

installed by customer type, utility customers represented 78% of the new capacity installed in 2022, 

followed by industrial customers at 20%. 

4.2.1 Resource and material availability trends

BTM distributed wind potential applications are constrained by local load, and NREL’s most recent 

Distributed Wind Energy Futures Study found that adoption is most correlated with electricity 

consumption, electricity rates, and windy land.119 Wind energy is dependent on a number of factors,

117 Smart Energy Consumer Collaborative, Distributed Energy Resources: Meeting Consumer Needs, 2019. 

118 Pacific Northwest National Laboratory, Distributed Wind Market Report: 2023 Edition, August 2023.

119 McCabe, Kevin and Ashreeta Prasanna, Distributed Wind Energy Futures Study, National Renewable 

Energy Laboratory, May 2022. 
DNV – www.dnv.com Page 55

including the characteristics of the machine (for example, rotor, gearbox, tower, controls), the 

location of the system, and the wind regime (for example, speed, timing, predictability). 

The power available in wind depends on the size of the wind turbine and the length of its blades. 

The power output is proportional to the swept area of the turbine rotor and the cube of the wind 

speed. For example, doubling the wind speed increases the power by eight-fold. Most wind turbines 

are not turned on in low-speed winds, so site selection for small-scale wind systems is a key 

constraining factor to resource availability. Wind power is proportional to the square of the wind 

turbine blade diameter, so doubling the blade diameter increases the power available by a factor of 

four. This observation drives the economies of scale that go with larger wind turbines. However, the 

cost of a wind turbine increases with the increased blade diameter. According to NREL, wind 

turbines are predominantly made of steel.120 Reducing the overall size and weight of the generator 

affects the weight and cost of the wind turbine tower and foundation.121 Research supported by DOE 

is looking to develop lightweight and long wind turbine blades by using carbon fiber composites 

rather than fiberglass. Carbon fiber materials are considered a key technology to enable larger wind 

turbine blades at a lower overall cost. Other areas of growth in wind turbine materials include the 

development of next-generation drivetrain technologies that are lighter than the current technology. 

Lightweight generators are being developed with high-temperature and low-temperature 

superconducting materials that reduce generator mass as compared with current technologies.

4.2.2 Federal policies and market incentives

DOE has a Wind Energy Technologies Office (WETO) that provides global leadership in all areas 

aimed at enabling low-cost wind energy. For distributed wind, WETO has funded research projects 

to advance wind technology competitiveness as a DER.122

Since the passing of the IRA of 2022, the federal ITC has been extended for 10 years past its original 

expiration date. For facilities beginning construction before January 1, 2025, the IRA will extend the 

ITC for up to 30% of the cost of installed equipment. The ITC steps down to 26% in 2033 and 22% 

in 2034. For projects that began construction after 2019 and were placed into service before January 

1, 2022, the ITC was set at 26%. Small-scale wind projects are eligible for the federal ITC.

Additionally, the IRA provided $820.25 million through fiscal year 2031 for the Rural Energy for 

America Program (REAP). REAP provides grants and guaranteed financing to small businesses 

and agricultural producers in areas with populations of 50,000 or fewer. Funds can be used to 

support small and large wind generation along with other DERs and energy efficiency upgrades.

Incentives for commercial wind include but are not limited to:

• Federal and state tax incentives

• State and/or utility rebates

• Avoided cost of kWh not purchased from utility

• kWh sold back to the grid (net metering or net billing export credits)

4.2.3 Relationship to other technologies

Distributed wind turbines and solar PV systems, sometimes paired with batteries, can offer 

complementary solutions for the supply of clean electricity at the customer site. Complementarity 

depends on the location of the system. Highly complementary applications would be installed 

120 Mone, Christopher and Maureen Hand, 2015 Cost of Wind Energy Review, National Renewable Energy 

Laboratory, revised May 2017.

121 U.S. Department of Energy, 2020 Wind Energy Research and Development Highlights, January 2021. 

122 Ibid
DNV – www.dnv.com Page 56

somewhere that has a high solar resource during the day and a high wind resource at night. Lower 

complementarity occurs in locations where the timing of the wind and solar resources overlap, 

creating periods of too much and too little electricity. A recent study conducted by NREL studied 

seasonal and diurnal patterns in wind and solar profiles across the contiguous United States to 

illustrate sites where the combined wind and solar profiles were complementary.123 The study used 

the Pearson coefficient, where a positive value means the generation from each resource type 

occurs at the same time and a negative value means they occur at different times (making the 

resources complementary). Figure 4-5 shows the results of this study, where dark orange 

represents sites that have more complementary resource profiles and dark blue represents noncomplementary resource profiles.

The results of the NREL analysis show that regions in the Great Plains, Midwest, and Southeast are 

well-suited for co-located distributed wind and solar systems. The regions in blue, where wind and 

solar are not complementary, would be better suited for wind and battery co-located systems. 

Figure 4-5. Annual daily-averaged complementarity (represented by the Pearson 

Correlation Metric) for 2013 in the contiguous United States

Data source: NREL

4.2.4 Technology research and development rates

Distributed wind technology is a relatively mature DER. Distributed wind research areas in the 

United States have a large focus on improving the competitiveness of the technology through 

system design optimization, uniform testing and certification for turbines and power electronics, and 

reducing hardware costs through advanced manufacturing processes.124 Discussion of materials 

research and development rates can be found in Section 4.2.1.

123 Clark, Caitlyn E. and Aaron Barker, Wind and Solar Hybrid Power Plants for Energy Resilience, National 

Renewable Energy Laboratory, January 2022.

124 U.S. Department of Energy, 2020 Wind Energy Research and Development Highlights, January 2021.
DNV – www.dnv.com Page 57

5 FUEL CELLS

5.1 Fuel cell technology attributes and cost data

5.1.1 Overview

Fuel cells are a distributed generation technology that generate electricity without fuel combustion 

but rather through an electrochemical process that converts chemical energy contained within fuel 

into electricity. Similar to battery energy storage, a single fuel cell element contains a cathode, anode, 

and an electrolyte. Hydrogen is fed to the anode and oxygen to the cathode, generating a chemical 

reaction in the presence of a catalyst to generate DC electricity and water. Fuel cells consist of a 

cell “stack” typically made up of at least 100 individual cells as well as a fuel processor to convert 

the fuel supply into hydrogen for the stack and a power conditioner to convert the DC electricity 

generated into AC power. 

DNV developed technology attributes and cost data for behind-the-meter fuel cell systems aligned 

with relevant residential and commercial customer segments. We assumed a combination of PEM 

CHP configuration and SOFC CHP configuration for the residential fuel cell application and a 

combination of MCFC and PAFC CHP configuration for the commercial fuel cell application. 

Although most stationary fuel cells installed in the United States at commercial sites are SOFC, we 

used MCFC and PAFC to represent CHP configurations more accurately at commercial sites with 

power requirements of more than 25 kW. 

DNV reviewed fuel cell installation data in the United States and globally to identify recent system 

deployment trends in the residential and commercial market sectors and confirm appropriate system 

configurations and associated performance attributes and costs. We used industry reports to gather 

relevant U. S. fuel cell attribute and cost data and scaled costs to align with current year (2022) cost 

estimates for this analysis. We also used developer data sheets for specific products to confirm 

accurate performance attributes for the most relevant systems installed in the United States today. 

Finally, we used historical industry cost reports to identify and scale cost estimates and attributes 

with previous years of EIA segment-level surveys: RECS, CBECS, and MECS. The process is 

described in the following sections.

5.1.2 System configurations

DNV used CHP fuel cell installation data from DOE’s Advanced Manufacturing Office (AMO),

stationary fuel cell (≥ 25 kW-AC) installation data from the Hydrogen Analysis Resource Center

(HARC), and project data from California’s Self-Generation Incentive Program (SGIP) to identify 

representative system capacities for both the residential and commercial sectors and the 

appropriate fuel cell technologies assigned to each segment. These data were also useful in 

identifying fuel cell types, developers, and specific models installed in recent years. 

Table 5-1. Fuel cell configurations, types, and representative system capacity

Market Segment Configuration Fuel Cell Type Fuel Type Representative Fuel Cell 

System Capacity

Residential CHP Fuel Cell PEMFC

a

, SOFC a Natural Gas 5 kW-AC

Commercial CHP Fuel Cell MCFC c, PAFC d Natural Gas 300 kW-AC

a PEMFC=polymer electrolyte membrane fuel cell.

b SOFC=solid oxide fuel cells.

c MCFC=molten carbonate fuel cell.

d PAFC= phosphoric acid fuel cell.
DNV – www.dnv.com Page 58

The majority (>95%) of U.S. CHP fuel cell installations in the last 10 years in the representative 

residential sector have been from developer ClearEdge who has since filed for bankruptcy and was 

acquired by Doosan in 2014.125 Although its 5 kW-AC modular PEM fuel cell was used in residential 

applications, it was also installed commercially in multifamily buildings, schools, and hotels. 

Although data from residential installations in Japan and Europe support smaller systems (1 kW-AC

to 2 kW-AC), data from the DOE CHP Installation Database and California’s SGIP (CPUC 2023) 

support the 5 kW-AC representative system size. The availability of micro-CHP (less than (<50kWAC) fuel cell products is currently limited in the United States, with only a small number of non-fuel 

cell micro-CHP systems available for installation. Additionally, micro-CHP residential CHP 

installations in the United States are typically installed in larger homes with higher energy 

requirements than the average U.S. home.

Information from additional developers present in the global market was also used to confirm 

attribute and cost data for polymer electrolyte membrane fuel cell (PEMFC) and SOFC systems,

given the lack of developer data for this size and application in the United States. The PEMFC and 

SOFC types were chosen to represent the residential sector given the availability of relevant 

developer attribute and cost data and their popularity outside the United States. The majority of nonCHP stationary fuel cell commercial installations in the United States within the last 10 years have 

been SOFC, mainly from developer Bloom Energy with its Bloom Energy Server 5 and Energy 

Server 5.5 products at 300 kW-AC and 310 kW-AC, respectively. 126 , 127 Other developers with 

success deploying CHP fuel cells in the United States market include Doosan Fuel Cell with 

phosphoric acid fuel cells and Fuel Cell Energy with molten carbonate fuel cells and SOFCs. 

Japan and Europe have experienced significant market growth compared to the respective history 

in deployment of PEMFC, SOFC, MCFC, and PAFC fuel cell CHP installations, with over 400,000 

units installed in Japan through 2022128 and over 18,000 in Europe through 2020.129 This growth is 

largely due to incentives for residential applications and government deployment and pilot programs 

significantly reducing unit costs. Additionally, high electricity prices contribute to a more attractive 

spark spread130 when compared with the U.S. market, further stimulating market growth in these 

regions. Data from developers such as Panasonic, Elcore, and PowerCell Group were also used to 

further align industry attribute and cost data for current year (2022) estimates, and used to update 

relevant attributes and cost metrics where limited data was available due to the lack of current U.S. 

market activity in specific segments. 

5.1.3 Technology attributes 

DNV assumed representative residential and commercial fuel cell systems are installed at sites with 

the appropriate space characteristics to site the system and accept the underground utilities 

125

“South Korea's Doosan buys U.S. fuel cell maker ClearEdge for $32.4 million,” Reuters (July 20, 2014).

126 Bloomenergy, The Bloom Energy Server, accessed February 25, 2024.

127 Bloomenergy, The Bloom Energy Server 5.5, accessed February 25, 2024.

128 Simander, Guenter and Patrick Vidovic, “Success factors for demonstration projects of small-scale 

stationary fuel cells in residential buildings,” E3S Web Conference, Presentation, 2022. 

129 European Parliament FCH 2 JU Governing Board, Assessment of the Fuel Cells and Hydrogen 2 Joint 

Undertaking (FCH 2 JU) Consolidated Annual Activity Report (AAR) 2020 by the FCH 2 JU Governing 

Board, 2020. 

130 Spark spread is a metric commonly used to estimate the viability for CHP and other fuel-based systems 

given differences between electricity and natural gas (or other fuel prices) between different regions. 

The spark spread identifies the difference between the cost of electricity and the cost of fuel on a per 

energy unit basis, indicating if the cost of additional fuel needed for the system would be cheaper than

purchasing electricity.
DNV – www.dnv.com Page 59

required for system operation (for example, fuel, water, electric).

131 Although low-temperature 

(LTPEM) and high-temperature (HTPEM) systems exist, DNV used only LTPEM systems when 

developing attribute and cost data due to the maturity of LTPEM stack technology and lack of market 

availability of HTPEM systems.132 For commercial systems, while DNV assumed a nominal power 

output of 300 kW-AC as the representative system size for an average commercial installation, the 

modularity of these units could be used to achieve a higher power output for other commercial 

applications. 

Additionally, DNV assumed these systems were not installed in remote locations where no grid 

power is available, but instead it assumed systems were installed in sites connected to the utility 

grid. In other words, systems had relatively consistent operational parameters over the life of the 

system, even if load following requires significant swings in power output to the site, typically 

provided by grid power. DNV also assumed natural gas was the primary fuel for each system, with 

additional discussion related to hydrogen-fueled systems and the relevant attribute and cost metrics.

5.1.4 System performance attributes 

Table 5-2 details performance attributes for fuel cell systems installed in the United States for 

representative residential installations. The data are presented to align with previous years of EIA 

segment-level surveys for each customer segment starting with the residential sector from 2015 to 

2022. Performance attributes for micro-CHP PEMFC and SOFC systems are similar and therefore 

are represented as a combined single system type for the residential sector. The performance 

attributes of this representative residential fuel cell system have not changed significantly over the 

last eight years, with overall system efficiency at nearly 80%.

Table 5-2. Residential fuel cell system performance attributes

Year

Fuel Cell Rep. 

System 

Capacity

Overall

Efficiency 

Capacity 

Factor Fuel Input Useful Thermal Output Heat Rate EUL 

2015 4.5 kW-AC 85.0% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,668 Btu/kWh 10 years

2016 4.5 kW-AC 85.0% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,664 Btu/kWh 10 years

2017 5.0 kW-AC 85.2% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,660 Btu/kWh 10 years

2018 5.0 kW-AC 85.2% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,655 Btu/kWh 10 years

2019 5.0 kW-AC 85.2% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,651 Btu/kWh 10 years

2020 5.0 kW-AC 85.4% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,647 Btu/kWh 10 years

2021 5.0 kW-AC 85.5% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,642 Btu/kWh 10 years

2022 5.0 kW-AC 85.5% 95% 8,764 MMBtu/hr (HHV) 2,385 MMBtu/hr 7,638 Btu/kWh 10 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour.

Table 5-3 highlights performance attributes for fuel cell systems installed in the United States for 

representative commercial installations aligning with previous years of EIA sector-level surveys for 

the commercial sector from 2012 to 2022. As in the residential sector, performance attributes for the 

combined representative commercial micro-CHP PEMFC and SOFC systems have not changed 

significantly over the last 10 years, while average representative commercial system capacities have 

generally increased. 

131 For commercial systems, sufficient space is assumed to be 40,000 square feet. 

132 Battelle Memorial Institute, Manufacturing Cost Analysis: 1, 5, 10 and 25 kW Fuel Cell Systems for 

Primary Power and Combined Heat and Power Applications, January 2017.
DNV – www.dnv.com Page 60

Table 5-3. Commercial fuel cell performance attributes

Year Fuel Cell Rep. 

System Capacity

Overall

Efficiency 

Capacity 

Factor Fuel Input (Btu/hr, HHV) Useful Thermal Heat Rate (Btu/kWh)

2012 200 kW-AC 80.0% 95% 3,480 MMBtu/hr (HHV) 929 Btu/hr 8,118 Btu/kWh

2013 200 kW-AC 80.0% 95% 3,477 MMBtu/hr (HHV) 927 Btu/hr 8,073 Btu/kWh

2014 200 kW-AC 80.2% 95% 3,473 MMBtu/hr (HHV) 926 Btu/hr 8,057 Btu/kWh

2015 250 kW-AC 80.2% 95% 3,464 MMBtu/hr (HHV) 925 Btu/hr 8,050 Btu/kWh

2016 250 kW-AC 80.4% 95% 3,449 MMBtu/hr (HHV) 922 Btu/hr 8,044 Btu/kWh

2017 250 kW-AC 80.5% 95% 3,449 MMBtu/hr (HHV) 922 Btu/hr 8,034 Btu/kWh

2018 250 kW-AC 80.5% 95% 3,449 MMBtu/hr (HHV) 922 Btu/hr 8,022 Btu/kWh

2019 300 kW-AC 80.5% 95% 3,449 MMBtu/hr (HHV) 922 Btu/hr 8,019 Btu/kWh

2020 300 kW-AC 80.6% 95% 3,448 MMBtu/hr (HHV) 922 Btu/hr 8,019 Btu/kWh

2021 300 kW-AC 80.6% 95% 3,448 MMBtu/hr (HHV) 922 Btu/hr 8,017 Btu/kWh

2022 300 kW-AC 80.6% 95% 3,447 MMBtu/hr (HHV) 922 Btu/hr 8,012 Btu/kWh

Note: Btu/hr=British thermal units per hour; Btu/kWh=British thermal units per kilowatthour.

5.1.5 System cost data

Capital costs for residential and commercial fuel cells were collected for multiple categories to 

accurately represent the differences in component costs and labor and installation costs throughout 

the analysis timeframe. The five cost categories were:

• Stack capital costs

• Manufacturing capital costs

• CHP hardware costs

• Fuel cell BOP hardware costs

• System assembly and installation costs

Capital cost data for fuel cell systems were collected for each system configuration using a blended 

approach from multiple data sources to capture the average representative system cost 

characteristics in 2022 constant (real) dollars. Historical cost data for the residential segment 

(PEMFC and SOFC) was gathered from Battelle’s cost analysis for 1-, 5-, 10-, and 25-kW-AC fuel 

cell CHP systems and from the California Energy Commission’s (CEC) assessment of small CHP 

applications in California.133,134 This cost data were then scaled to the current year (2022) using 

relevant labor and manufacturing costs for their respective cost categories and appropriate GDP 

chain-type price indices to scale hardware costs when costs were not explicitly available.

As mentioned previously, residential fuel cell CHP installations in the United States have 

experienced overall limited growth in deployment in recent years due to high capital costs and the 

lack of market applicability and consumer demand for these systems at the residential level. 

However, cost declines (supported by markets outside of the United States) in recent years due to 

technology advances which could stimulate increased market growth in the residential sector, 

133 Battelle Memorial Institute, Manufacturing Cost Analysis: 1, 5, 10 and 25 kW Fuel Cell Systems for 

Primary Power and Combined Heat and Power Applications, January 2017. 

134 California Energy Commission, A Comprehensive Assessment of Small Combined Heat and Power 

Technical and Market Potential in California, March 2019. 
DNV – www.dnv.com Page 61

especially if a continued need exists for more resilient backup systems in single-family and smaller 

multifamily applications (Figure 5-1).

Figure 5-1. U.S. average residential fuel cell system capital costs ($/kW-AC, 2022 $)

Capital cost data for commercial fuel cell systems were collected using a similar blended approach 

from multiple data sources to capture the average representative system cost characteristics 

presented in 2022 constant (real) dollars. Historical cost data for the commercial segment (MCFC 

and PAFC) were gathered from DOE’s CHP Cost and Performance fact sheet for fuel cells and from 

the CEC’s assessment of small CHP applications in California.135,136 These cost data were then 

scaled to the current year (2022) using relevant labor and manufacturing costs for their respective 

cost categories and appropriate GDP chain-type price indices to scale hardware costs when not 

explicitly available.137 DNV also used actual installed system costs for multiple systems in different 

years throughout the analysis timeframe to benchmark and scale base-year and current-year 

system costs. These costs were gathered from the DOE CHP Project Profiles Database138 and from 

conversations with select developers.

Figure 5-2 shows U.S. average commercial fuel cell system capital costs. Although costs are high 

compared with other distributed generation technologies, commercial fuel cell CHP systems are 

more cost-effective than residential installations, largely due to economies of scale in unit production, 

general customer awareness and aligned use cases in the commercial sector, and more appropriate 

facility attributes such as more stable load profiles and aligned thermal and power requirements. 

Capital and performance incentives as well as alternative CHP fuel rates (depending on the 

jurisdiction anywhere between the wholesale and retail fuel rates) present in some jurisdictions have 

made commercial fuel cell CHP systems cost-effective in many cases, and declining system costs 

have also contributed to steady deployment in the commercial sector.

135 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Project Profiles Database, accessed 

October 11, 2023.

136 U.S. Department of Energy, Energy Efficiency & Renewable Energy, Combined Heat and Power 

Technology Fact Sheet Series, Fuel Cells, July 2016.

137 California Energy Commission, A Comprehensive Assessment of Small Combined Heat and Power 

Technical and Market Potential in California, March 2019. 

138 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Project Profiles Database, accessed 

October 11, 2023.
DNV – www.dnv.com Page 62

Figure 5-2. U.S. average commercial fuel cell system capital costs ($/kW-AC, 2022 $)

5.1.6 O&M cost data

DNV compiled variable O&M costs ($/kWh) in 202 constant (real) dollars for all fuel cell systems, 

including estimates for both general system maintenance and parts replacement as well as fuel 

costs. DNV assumed annual contracted maintenance costs for both residential and commercial 

systems were included, representing general maintenance labor costs for routine system inspection, 

ancillary part (for example, filters, sensors, spark plugs, gaskets, valves) adjustments, and/or 

replacements. Major system overhauls and large parts (for example, catalyst, stack) replacement 

were also included and annualized over a 5–10-year period to determine the final $/kWh costs 

component. DNV did not include a separate discounted CHP fuel rate but instead used U.S. average 

residential and commercial natural gas delivery rates over the analysis timeframe (2012--2022) from 

EIA.139

DNV assembled variable O&M costs using DOE’s CHP Fact Sheet Series and from the CEC’s

assessment of small CHP applications in California as a baseline and supplemented with developer 

data where appropriate. 140 , 141 Baseline O&M costs for general system maintenance and stack 

replacement were gathered for 2019 and scaled to the current year (2022) and subsequent historical 

years (2021 and 2020) using relevant U.S. average labor costs and the annual consumer price index 

(CPI) to adjust for inflation. 

Figure 5-3 shows U.S. average residential fuel cell system O&M costs. O&M costs for fuel cell CHP 

systems have generally been consistent over the past 10 years for both residential and commercial 

applications. Labor costs and part replacement costs have not changed significantly enough to 

produce large cost swings in either the residential or commercial sectors. 

139 U.S. Energy Information Administration, Natural Gas Prices annual data, accessed November 8, 2023. 

140 U.S. Department of Energy, Energy Efficiency & Renewable Energy, Combined Heat and Power 

Technology Fact Sheet Series, Fuel Cells, 2016.

141 California Energy Commission, A Comprehensive Assessment of Small Combined Heat and Power 

Technical and Market Potential in California, March 2019.
DNV – www.dnv.com Page 63

Figure 5-3. U.S. average residential fuel cell system O&M costs ($/kWh, 2022 $)

Figure 5-4 shows U.S. average commercial fuel cell system O&M costs. Total (including fuel costs) 

commercial variable O&M costs are generally lower than residential O&M costs for fuel cell systems 

largely due to lower fuel costs for the commercial sector. Routine maintenance, inspection, and 

general parts replacement is lower in residential systems due to the smaller system size and simpler 

system complexity compared with the variety of commercial installation types and use cases. 

Figure 5-4. U.S. average commercial fuel cell system O&M costs ($/kWh, 2022 $)

5.2 Fuel cell market discussion

5.2.1 Resource and material availability trends

The fuel cells analyzed in this study require a source of hydrogen for the anodic reactions. Systems 

that operate at higher temperatures, MCFCs and SOFCs, can include a methane reformation 

process to produce hydrogen as a part of the fuel cell system itself.

142 However, generally obtaining 

a supply of hydrogen of sufficient purity and at a reasonable cost is the biggest resource availability 

hurdle that fuel cells face. Hydrogen is not naturally available in the environment, like natural gas, 

so it must be manufactured. Manufacturing hydrogen requires an energy investment to create the 

142 This study modeled MCFCs and SOFCs that include a methane reformer.

 0.079 0.07 0.0 0 0.077 0.076 0.077 0.0 0

 0.0 5

 0.000

 0.010

 0.020

 0.030

 0.040

 0.050

 0.060

 0.070

 0.0 0

 0.090

2015 2016 2017 201 2019 2020 2021 2022

O&M Cost ( kWh, 2022 )

Variable O&M Cost Fuel Cost
DNV – www.dnv.com Page 64

desired hydrogen fuel. The main technologies currently in use for hydrogen production are steam 

reforming of methane, partial oxidation, and electrolysis of water. Steam reforming of methane 

accounts for almost all the commercially available hydrogen produced in the United States.143

5.2.2 Government policies and market incentives

The United States has identified fuel cells as a key component of its U.S. National Clean Hydrogen 

Strategy and Roadmap.144 DOE’s Hydrogen and Fuel Cell Technologies Office supports the fuel cell 

industry by supporting research, development, and demonstrations of fuel cell technologies. 145

Currently, the United States’ interventions relating to fuel cells focus mostly on supporting R&D,

which is discussed in more detail in Section 5.2.4. In addition to R&D programs, the United States 

offers various financial incentives to support the implementation of fuel cell projects.

The main federally offered financial incentive for fuel cells is the 2022 expansion by the IRA of the 

48C Advanced Energy Project Credit.146 The expansion increased the funding of this competitively 

awarded tax credit to $10 billion. Projects can receive an investment tax credit of up to 30%. Property 

must be placed in service after being awarded the 48C credit by the IRS to be eligible for the credit. 

The IRS will award all Round 1 48C credits by March 31, 2024.147 Any project that expands clean 

energy manufacturing and recycling, further develops critical material refining, or reduces 

greenhouse gas (GHG) emissions at industrial facilities can qualify. About 40% of funds are

dedicated to projects in communities with closed coal plants or mines. The IRA also includes the 

Elective Payment for Energy Property credit, which allows non-tax-paying organizations such as 

government and non-profits to transfer the 48C tax credit to a tax-paying entity such as a contractor 

who can then discount the project for the end user.

For homeowners, the Residential Clean Energy Tax Credit supports fuel cells. For projects placed 

in service in 2022 through 2032, the tax credit can cover 30% of the project costs at a maximum of 

$500 per half kW-AC of power capacity. Qualifying fuel cells must have at least 0.5 kW-AC of 

capacity and an electricity-only generation efficiency of at least 30%. Qualifying project costs for the 

Residential Clean Energy Tax Credit for fuel cells include property costs for “an integrated system 

comprised of a fuel cell stack assembly and associated balance of plant components that convert a 

fuel into electricity using electrochemical means” as well as “any labor costs properly allocable to 

the on-site preparation, assembly, or original installation of the [fuel cell] property and for piping or 

wiring to interconnect such property to the home.”

148

Seventeen states offer financial incentives for fuel cells and an additional four states have legislation 

to encourage the growth of fuel-cell industries within their borders.149 The vast majority of the 

incentive programs focus on fuel cell use in vehicles including for facility fleets that may be behindthe-meter; however, the states of New Jersey, Virginia, Colorado, and South Carolina have 

initiatives that could support fuel cells in buildings. In 2020, New Jersey created the New Jersey 

Fuel Cell Task Force tasked with increasing the use of fuel cells in the state through supporting fuel 

143 U.S. Energy Information Administration, Hydrogen explained: Production of hydrogen, accessed October 

11, 2023. 

144 U.S. Department of Energy, U.S. National Clean Hydrogen Strategy and Roadmap, accessed October 

11, 2023.

145 U.S. Department of Energy, Hydrogen and Fuel Cells Technology Office, accessed October 6, 2023. 

146 U.S. Department of Energy, Qualifying Advance Energy Project Credit (48C) Program, accessed October 

6, 2023. 

147 U.S. Internal Revenue Service, Frequently Asked Questions about the Qualifying Advanced Energy 

Project (48C) Credit, accessed January 2, 2024. 

148 U.S. Internal Revenue Service, Instruction for Form 5695, accessed January 2, 2024. 

149 U.S Department of Energy, Hydrogen Laws and Incentives, accessed October 6, 2023. 
DNV – www.dnv.com Page 65

cell infrastructure and public education. Additionally, New Jersey’s Clean Energy Program offers 

financial incentives for CHP and Fuel Cell installations.150 Projects can receive a maximum of 30% 

of project costs up to $1 million if they achieve an annual electric system efficiency of at least 40%. 

Virginia’s Green Jobs Tax Credit offers employers a 500 tax credit for each new green job created 

with a salary of $50,000 or more and targets the hydrogen and fuel cell industry. In 2021, Colorado 

directed its Department of Natural Resources to create an industry-driven energy sector career 

pathway for the 2022–2023 academic year that includes careers relating to hydrogen fuel cell 

technology. South Carolina offers a 100% sales tax exemption to any equipment powered by fuel 

cells or any equipment used predominantly to manufacture fuel cells.151 Lastly, utility companies 

have provided some incentives for fuel cell technologies. For example, PSEG Long Island offered 

a Fuel Cell Feed-in Tariff with enrollment from 2016 to 2017 to encourage the connection of fuel cell 

technologies to the grid. Ultimately, three commercial or industrial projects representing 39.8 MW 

were accepted into the program.152

5.2.3 Relationship to other technologies

Hydrogen produced by electrolysis has the advantage of being highly purified, which eliminates the 

problems of catalytic carbon-monoxide poisoning that some fuel cells are subject to. When the 

electricity for electrolysis is generated using a renewable energy system, such as wind or solar PV, 

the hydrogen is produced without emitting any GHGs. 

Figure 5-5 illustrates how a solar PV system can be paired with battery storage and a fuel cell to 

produce carbon-free electricity at the building site. Hybrid fuel cell systems paired with a renewable 

DER system can provide energy to the building site whenever it is needed, while a small-scale wind 

or solar PV DER system is subject to the diurnal nature of the wind and solar resource. The hybrid 

system depicted in the figure below consists of a solar PV system coupled with an electrolyzer to 

produce hydrogen, a fuel cell that converts hydrogen to electricity, a hydrogen storage tank, and a 

battery storage system.

Figure 5-5. Diagram of a solar PV + fuel cell hybrid energy system

Data source: Solar PV-Hydrogen-PEM Fuel Cell System153

150 New Jersey Clean Energy Program, Combined Heat and Power, accessed October 6, 2023. 

151 U.S Department of Energy, Hydrogen Laws and Incentives, accessed October 6, 2023. 

152 PSEG Long Island, Fuel Cell Feed-in Tariff IV, accessed January 2, 2024. 

153 Al-Baghdadi, Maher, Solar PV-Hydrogen-PEM Fuel Cell System, Scholarly Community Encyclopedia, 

updated October 29, 2020.
DNV – www.dnv.com Page 66

5.2.4 Technology research and development rates

Although this study aims to characterize the stationary fuel cell market, most R&D efforts in the 

United States have focused on the automotive industry. The automotive industry’s fuel cell R&D can 

be used to scale up fuel cell production and help reduce costs for other markets such as for buildings. 

The focus of R&D for heavy duty applications is on materials and components as well as systems 

in the United States. These efforts support clean hydrogen end use and broader market adoption 

objectives as outlined in the National Clean Hydrogen Strategy and Roadmap.

154

Material and components research areas include:

• High activity, durable catalysts and electrodes

• Innovative membranes and ionomers

• Durable high-performance membrane-electrode assemblies

• Advanced bipolar plates and coatings

Systems research includes:

• System design and operating conditions

• Standardized stacks and modular systems

• Improved manufacturing and supply chain

• Advanced BOP components and subsystems

• Advanced recycling of systems and stacks

DOE’s Hydrogen and Fuel Cell Technologies Office (HFTO) has funded fuel cell R&D since 2006. 

The fuel cell R&D activities are to address critical technical hurdles including, “cost, durability, 

efficiency, and overall performance of components such as the polymer electrolyte membranes, 

oxygen reduction electrodes, advanced catalysts, bipolar plates, etc.”155 The HFTO is targeting 

achieving long-haul truck fuel systems that cost $80/kW-AC and have 25,000 hours of durability by 

2030.

156 Other areas of research include advanced manufacturing to reduce cost and enhance 

reliability, as well as hydrogen fuel production and delivery (commonly referred to as hydrogen 

infrastructure). Many fuel cell companies are transitioning their manufacturing processes to highthroughput methods to meet volume and cost targets. As previously discussed in Section 5.2.2, the 

2022 IRA includes tax credits and other incentives for clean hydrogen and fuel cell technologies—

either by extending existing federal tax credits, increasing existing federal tax credits, or creating 

new federal tax credits. The new Clean Hydrogen Production tax credit (45V) creates a new 10-year 

incentive for clean hydrogen production that can be further increased by tax credits claimed under 

Section 48. This new tax credit is expected to jump-start the domestic hydrogen fuel industry.

The Million Mile Fuel Cell Truck Consortium (M2FCT) is a DOE-funded consortium of national labs 

that was formed to overcome durability and efficiency challenges in Polymer electrolyte membrane 

fuel cells (PEMFCs) for heavy-duty vehicle applications. The M2FCT uses a “team of teams 

approach” with many private companies to advance efficiency and durability of PEMFCs for heavy 

duty vehicle applications at a lower cost than what is currently available. This consortium has had 

several recent breakthroughs in the research it is conducting in materials and components—

154 U.S. Department of Energy, U.S. National Clean Hydrogen Strategy and Roadmap, accessed October 

11, 2023.

155 U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office Budget, accessed October 11, 

2023. 

156 Papageorgopoulos, Dimitrios, Fuel Cell Technologies Overview, U.S. Department of Energy, The 

Hydrogen and Fuel Cell Technologies Office, Presentation, June 6, 2023. 
DNV – www.dnv.com Page 67

specifically, high-performance, membrane-electrode assemblies. Recent M2FCT research on new 

electrode design in PEMFCs showed improved performance of up to 50%, compared to PEMFCs 

with state-of-the-art conventional electrodes. 157 Another recent development by the M2FCT 

improved membrane-electrode assembly performance by more than 45% compared with a 

commercial baseline. Innovations in catalysts developed by the consortium led to the performance 

improvement.158 Figure 5-6 shows the progress timeline of the M2FCT research between 2021 and 

2023. 

Figure 5-6. Progress of end of test membrane electrode assembly performance with M2FCT 

developed catalysts, 2021–2023

Data source: U.S. Department of Energy Hydrogen and Fuel Cell Technologies Office

Fuel cell research and development rates are expected to continue increasing in the United States,

with the increased funding and interest in hydrogen as a means to reduce fossil fuel use.

5.2.5 Hydrogen use for fuel cells

With the exception of direct methanol fuel cells, fuel cells require a source of hydrogen for the anodic 

reactions. Hydrogen can either be supplied directly from a supply tank or it can be produced on-site. 

The main technologies in use for hydrogen production are steam reforming of methane, partial 

oxidation, gasification of biomass or other solid fuels (for example, coal and municipal waste), and 

electrolysis of water. 

Currently, DOE does not use a color code to characterize the source, production technology, and 

carbon capture of hydrogen—which is something that some producers and other organizations use 

to categorize hydrogen. For example, green hydrogen is commonly categorized as hydrogen formed 

through electrolysis powered by renewable electricity. Green hydrogen is produced without any

greenhouse gas emissions, but it currently makes up a small portion of the overall hydrogen 

157 Choi, Charles, “Hydrogen Fuel Cells Find Their Groove,” IEEE Spectrum (June 14, 2023). 

158 Papageorgopoulos, Dimitrios, Fuel Cell Technologies Overview, U.S. Department of Energy, The 

Hydrogen and Fuel Cell Technologies Office, Presentation June 6, 2023. 
DNV – www.dnv.com Page 68

produced because its production is expensive. Current green hydrogen production is very limited, 

and large upscaling in electrolyzer capacity would be necessary to expand production.

Although many current natural gas-fired equipment may be adapted to operate with a blended 

hydrogen and natural gas mixture, fuel cells require pure hydrogen. In the future, where hydrogen 

may be blended into existing natural gas pipelines, hydrogen separation technologies would be 

required at the point of use for fuel cells. On-site hydrogen production for fuel cells is one of the 

biggest limiting factors for customer-sited systems. In the residential sector, the majority of the fuel 

cell installations are at the demonstration level, and they use an on-site electrolyzer and solar panels 

to convert solar energy to hydrogen. 

Hydrogen end users need access to hydrogen, either through production of hydrogen on-site or 

from a nearby hydrogen production facility to avoid high transportation costs, and their facility needs

hydrogen storage and handling equipment. According to DNV proprietary project data, blending of 

hydrogen with natural gas is already possible, and demonstration projects are ongoing for both 

blending into natural gas pipelines and site-level blending at the point of use. The maximum blending 

percentage possible in existing equipment depends on the burner type. The current industry 

assumption for industrial end users is that blending up to 20% (by volume) can be safely done 

without changing the burners of the hydrogen-fired equipment. This assumption is generally the 

same assumption made for hydrogen fuel blending in commercial and industrial CHP equipment, 

based on DNV proprietary project data. 
DNV – www.dnv.com Page 69

6 COMBINED-HEAT-AND-POWER SYSTEMS

6.1 CHP system technology attributes and cost data

6.1.1 Overview

DNV developed technology attributes and cost data for behind-the-meter CHP systems aligned with 

relevant commercial and industrial customer segments. CHP, or cogeneration, is a set of mature 

technologies that provide both electricity and thermal energy from a single generation source. 

Distributed CHP systems are installed at individual customer sites and are typically sized to meet a 

site's thermal energy requirements (heating and/or cooling) and can offset a portion of the site’s

electricity, as well as inject power back into the grid when applicable. DNV reviewed CHP installation 

data in the United States to identify recent system deployment trends in the commercial and 

industrial market sector and confirm appropriate system configurations and associated performance 

attributes and costs. This data informed the selection of specific prime mover types and sizes to 

accurately reflect installation trends within the most prominent market segments and associated site 

characteristics within the commercial and industrial sectors. The term prime mover refers to the 

specific engine, turbine, or fuel cell converting the air and fuel supply into kinetic energy used in a 

generator or heat exchanger to produce electricity or thermal energy for on-site use.

DNV used DOE and U.S. Environmental Protection Agency (EPA) reports and fact sheets to gather 

current and historical CHP performance and historical cost data, and then it scaled costs to align 

with 2022 constant (real) dollar cost estimates for this analysis. Additionally, DNV also used 

developer data sheets for specific products and DOE CHP project profiles to confirm accurate 

performance attributes for the most relevant systems installed within the analysis timeframe. Finally, 

DNV used historical industry cost reports to identify and scale cost estimates and attributes with 

previous years of EIA’s CBECS and MECS. The process is described in the following subsections.

6.1.2 System configurations and technology attributes 

DNV used CHP installation data from DOE159 supplemented with project data from California’s 

SGIP160 to identify representative system capacities for both the commercial and industrial sectors

and the appropriate CHP prime mover types assigned to each sector. DNV identified three separate 

prime movers and capacities to represent commercial CHP systems, and it identified three prime 

movers and eight capacities to represent industrial CHP systems. 

Annual installations and overall capacity installed in the commercial CHP sector has decreased over 

the past five years largely due to price competitiveness with other distributed generation 

technologies and the increasing ability for other technology configurations to provide similar 

resiliency and reliability benefits for commercial end uses. The COVID-19 pandemic also contributed 

to a decrease in the number of installations within the past three years.

Figure 6-1 shows annual commercial CHP installations, annual capacity installed over the last 10

years, and average site-level system capacities for each year by prime mover type. This commercial 

data includes natural gas- and oil-fueled reciprocating engines, natural gas-fueled gas turbines, and 

microturbine CHP systems to align with the commercial systems included in this analysis. The 

emergence of packaged CHP systems during this time period allowed for smaller systems to be 

159 U.S. Department of Energy, Better Buildings, Onsite Energy, Microgrid and CHP Installation Databases, 

accessed October 11, 2023.

160 California Public Utilities Commission, Download Data, Self Generation Incentive Program (SGIP) Data, 

accessed October 11, 2023. 
DNV – www.dnv.com Page 70

installed in commercial and institutional facilities,

161 further aligning with the system capacities 

evaluated for the commercial sector. Commercial CHP installations in the last 10 years have largely 

been natural gas reciprocating engines, whereas the majority of commercial CHP capacity is from 

gas turbines installed in commercial facilities with greater power and thermal requirements. 

Microturbines also make up a small portion of installations and overall capacity in the commercial 

sector.

Figure 6-1. U.S. annual commercial CHP installations (2012–2022)

Figure 6-2 shows U.S. industrial CHP installations from 2012 through 2022. Average system

capacities for industrial CHP applications are much larger than commercial installations when 

comparing based on the prime movers included in this analysis. However, given the large system 

capacities and complex engineering required to deploy systems in the industrial sector, annual 

installation trends are more variable than in the commercial sector. Largely due to the effects of the 

COVID-19 pandemic, industrial installations also declined from 2020 to 2022. Figure 6-2 shows 

annual industrial CHP installations and capacity installed over the last 10 years, including 

reciprocating engines, gas turbines, and combined-cycle CHP systems fueled only by natural gas

to align with the industrial systems included in this analysis. 

161 Institutional facilities in this context are a subset of the commercial sector, representing facilities typically 

pursuing social, charitable, religious, and educational activities, such as colleges and universities, 

prisons, and other government and/or campus-type facilities.

Average Capacity (MW-AC) 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Reciprocating Engine 1.2 0.5 0.6 0.4 0.5 0.4 0.9 0.8 1.0 1.0 0.7

Gas Turbine 15.3 4.9 4.8 10.1 7.9 12.0 9.1 14.2 9.4 3.6 3.4

Microturbine 0.4 0.4 0.5 0.1 0.4 0.4 0.4 0.5 0.7 0.3 0.3

0

50

100

150

200

250

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Capacity (MW-AC)

Installed Capacity (MW-AC)

Reciprocating Engine

Gas Turbine

Microturbine

0

20

40

60

80

100

120

140

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Sites

Sites

Reciprocating Engine

Gas Turbine

Microturbine
DNV – www.dnv.com Page 71

Figure 6-2. U.S. annual industrial CHP installations (2012–2022)

DNV collected performance and cost data on the following representative CHP systems to reflect 

recent capacity trends in the commercial and industrial CHP sectors. DNV based representative 

system capacities on the most common commercial and industrial segments to align with previous 

years of EIA’s CBECS and MECS. DNV also based performance and cost data on the most common 

thermal recovery option for selected systems where applicable as identified in DOE’s CHP Fact 

Sheet Series162 for specific technologies. Different prime movers are configured for specific thermal 

applications at specific capacities, and different prime movers have multiple thermal recovery 

options based on the end-use application. These selections also aligned with thermal recovery types 

for the most prevalent commercial and industrial subsectors. Table 6-1 shows the CHP configuration, 

prime mover and thermal recovery types, and representative system capacities used in this study.

Table 6-1. CHP configurations, types, and representative system capacities

Market Segment Prime Mover Type Thermal Recovery Fuel Type Representative System 

Capacity

Commercial

Reciprocating Engine

(Gas) Hot Water (Rich burn) Natural Gas 300 kW-AC

Reciprocating Engine

(Oil) Hot Water Distillate fuel oil 350 kW-AC

Gas Turbine Hot Water & Steam Natural Gas 3,300 kW-AC

Microturbine Hot Water & Steam Natural Gas 200 kW-AC

Industrial

Reciprocating Engine

(Gas)

Hot Water & Steam 

(Lean burn) Natural Gas

1,000 kW-AC

3,000 kW-AC

Gas Turbine

Process Heat, Hot 

Water & Steam

Natural Gas

5,000 kW-AC

10,000 kW-AC

Process Heat & 

Steam

25,000 kW-AC

40,000 kW-AC

Combined Cycle Process Heat & 

Steam Natural Gas

100,000 kW-AC

375,000 kW-AC

162 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Technology Fact Sheets, accessed 

October 11, 2023.

Average Capacity (MW-AC) 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Gas Turbine 9.6 5.4 92.2 33.0 9.0 16.2 18.3 19.3 61.5 22.3 4.6

Reciprocating Engine 2.2 2.1 3.2 3.9 0.8 6.4 3.7 3.6 5.1 2.3 2.5

Combined Cycle - 111.0 - 21.1 - 145.0 - 54.7 37.0 309.8 - 

0

100

200

300

400

500

600

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Capacity (MW-AC)

Installed Capacity (MW-AC)

Gas Turbine

Reciprocating Engine

Combined Cycle

0

2

4

6

8

10

12

14

16

18

20

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Sites

Sites

Gas Turbine

Reciprocating Engine

Combined Cycle
DNV – www.dnv.com Page 72

DNV assumed representative commercial and industrial CHP systems are installed at sites with the 

appropriate space characteristics to site the system and accept the underground utilities required 

for system operation (for example, fuel, water, electric). DNV assumed all representative systems 

were fueled by natural gas, except for the oil-fired reciprocating engine, which was assumed to be 

fueled by distillate fuel oil. In some instances when developing cost and performance attributes, 

assumptions for low-sulfur diesel engines were used given its similarity to distillate fuel oil. 

Additionally, while CHP installations that serve remote communities and/or off-grid sites are 

common, DNV only used cost and performance characteristics for natural gas systems assumed to 

be already connected to the utility grid and not installed in remote locations where no grid power is 

available. This approach assumes relatively consistent operational parameters over the lifetime of 

the system, even if load following requires significant swings in power output to the site, typically 

provided by grid power. Oil-fired reciprocating engines have largely been installed for utility or 

municipal sites to enhance resiliency and redundancy and to provide for standby applications at 

remote locations. Therefore, we have focused on cost and performance data that align with these 

characteristics for oil-fired reciprocating engine CHP systems. 

6.1.2.2 Natural gas reciprocating engine CHP Systems

The most commonly used (by both installed capacity and number of installations) CHP technology 

in the commercial and industrial sectors are natural gas reciprocating engines, providing hot water, 

chilled water, steam, and (in some cases) chilled thermal fluid for a variety of thermal end-uses. Gas 

reciprocating engines less than 1 MW-AC are typically installed in multifamily buildings, office 

buildings, athletic facilities, hotels, nursing homes, schools, small hospitals, and small universities. 

Institutional installations are commercial facilities or groups of facilities that typically require larger 

than 1 MW-AC CHP systems. Industrial installations are also typically larger than 1 MW-AC and can 

be installed in a variety of industries such as chemicals, food processing, and general manufacturing. 

Gas reciprocating engine installations larger than 1 MW-AC are also common at institutional 

buildings and campuses such as hospitals, universities, and nursing homes. Although diesel 

reciprocating engines are more efficient than gas engines, gas engines are now widely used in CHP 

applications due to their lower emissions.

Natural gas reciprocating engines operate using a spark ignition cycle (that is, Otto Cycle). DNV 

assumed hot water thermal recovery for the representative commercial reciprocating engine and 

hot water and steam for industrial systems. Rich burn engines have higher thermal efficiencies in 

the production of hot water and are common in smaller systems; therefore, they were used for 

performance and cost data when assessing smaller systems. Rich burn engines operate with a 

match of air and fuel quantities that result in complete combustion, whereas lean burn engines 

operate with air-to-fuel ratios higher than the stoichiometric ratio. For lean burn engines, this higher 

ratio results in lower combustion chamber temperatures and therefore results in lower nitrogen oxide 

(NOx) emissions. Lean burn engines are common in systems above 1 MW and were used when 

collecting performance and cost data based on hot water and steam recovery in industrial systems.

6.1.2.3 Oil-fired reciprocating engine CHP systems

Oil-fired reciprocating engines are a mature technology that have been installed in the United States

for traditional power applications throughout the past century and for CHP applications since the 

1980s. Oil-fired reciprocating engines operate using a compression ignition cycle, which makes

them more efficient than spark ignition engines because of the higher compression ratio. The 

majority of oil-fired reciprocating engine CHP systems are installed at remote sites to provide backup 

power, improve resiliency and power reliability, and supplement grid power and thermal energy. 
DNV – www.dnv.com Page 73

These installations generally provide power applications that serve remote government facilities, 

critical infrastructure, and remote community and village sites.163

Based on the data from DOE’s CHP Installation Database, only nine oil-fired reciprocating engine 

CHP systems have been installed in the United States since 2012, and the last was installed in 2016 

to provide power and thermal energy to Saint Paul Island, a remote island in Alaska.164 As mentioned 

above, while federal and state emission requirements have limited the deployment of oil-fired CHP 

systems compared with natural gas-fired systems, fuel costs have played a bigger role in limiting 

the deployment of these systems to remote locations where access to natural gas is limited.

6.1.2.4 Gas turbine CHP systems

Gas turbine CHP systems are available in larger capacities and serve different application types 

compared with the other representative commercial and industrial CHP systems. Compared with

larger combined-cycle gas turbine systems, the representative systems in this category are all 

simple cycle and typically serve 5 MW-AC to 40 MW-AC applications. Microturbines are also smaller 

simple cycle gas turbines but are characterized differently based on their applications serving lower 

power and thermal requirements. 

Representative gas turbines are common at a variety of industrial and institutional sites (e.g., large 

colleges and universities and hospital campuses) because the turbines can produce hightemperature exhaust efficiently. High-temperature exhaust is typically used as process heat in 

industrial applications or to generate steam for industrial and institutional facilities and/or campuses. 

Hot water and chilled water can also be produced, and this ability is more common among smaller 

gas turbine installations. Gas turbine efficiency generally increases according to size. The smallest 

representative size system in the commercial sector is the least efficient and least cost-effective, on 

a per-unit basis, and large industrial systems (more than 20 MW-AC) are more efficient and highly 

cost-effective compared with other prime mover types. 

6.1.2.5 Microturbine CHP systems

Although larger gas turbine CHP systems have existed for several decades, microturbine CHP 

systems have been installed in greater frequency recently compared to historical installation trends

due to their flexibility in interconnection and ability to serve smaller, diverse loads efficiently. Similar 

to gas turbines, microturbines produce high exhaust heat that can be used directly or used to 

produce hot water, chilled water, and steam. 

Although microturbines are used at small industrial applications, the representative commercial 

systems included in this analysis assume common application types such as office buildings, hotels, 

and other similar commercial sites. Even though capacity requirements within these application 

types typically vary from 50 kW-AC to 1 MW-AC, a representative microturbine capacity of 200 kWAC was used to capture the most common packaged system capacity and the ability for microturbine

packages to be stacked to serve larger loads. 

6.1.2.6 Combined-cycle CHP systems

Combined-cycle gas turbine power plants are a common form of electric power generation in the 

United States that include heat recovery steam generators (HRSG) and can provide large-scale 

CHP applications for large industrial sites and campuses. The use of HRSGs to recover heat from 

traditional gas turbine power plants for additional power through a steam turbine can improve overall 

163 Residential sites are excluded from analysis but are included in the discussion identifying the existing 

market.

164 U.S. Department of Energy, Better Buildings, Onsite Energy, Microgrid and CHP Installation Databases, 

accessed October 11, 2023.
DNV – www.dnv.com Page 74

generation efficiency compared to traditional power generation by roughly 10%. However, they have

limited applications due to the size required to be cost-effective and limited number of sites that can 

support 100 MW-AC to 400 MW-AC installations. 

Combined-cycle CHP systems contribute significantly to meeting site baseload power needs and

can also provide financial benefits when configured to export power back onto the grid. When used 

at institutional settings such as college campuses, combined-cycle CHP systems typically produce 

hot water and steam for use in a district energy system that can distribute heat to multiple buildings 

throughout the campus.

6.1.3 System performance attributes 

System performance data for CHP systems is intended to represent average systems available in 

the marketplace for each year in the analysis timeframe. Where appropriate, DNV proprietary

individual project data and/or developer data was used, but performance data was primarily 

collected for each system for specific years from DOE and EPA reports and fact sheets.

165, 166 These

data were then scaled to the remaining years using data from the DOE project profiles database167

for specific installations and the DOE packaged CHP eCatalog168 for specific commercially available 

systems. The data were supplemented further from the CEC’s assessment of small CHP 

applications in California.169 Table 6-2 through Table 6-8 detail performance attributes for CHP 

systems installed in the United States for representative commercial installations, and Table 6-6

through Table 6-8 detail the performance attributes for representative industrial installations. The 

data are presented to align with previous years of EIA sector-level surveys for the commercial sector

from 2012 to 2022 and the industrial sector for 2015 and 2018–2022. 

Natural gas reciprocating engine performance characteristics for the commercial sector have shown 

minor improvements over the past 10 years due to e product maturity and widespread deployment 

among CHP technologies (Table 6-2). The representative reciprocating engine is the most efficient 

among the selected commercial systems with an overall system efficiency approaching 80%.

165 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Technology Fact Sheets, accessed 

October 11, 2023.

166 U.S. Environmental Protection Agency, Combined Heat and Power (CHP) Partnership, CHP 

Technologies, accessed October 11, 2023.

167 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Project Profiles Database, accessed 

October 11, 2023.

168 U.S. Department of Energy, Combined Heat & Power eCatalog, DOE Recognized CHP Packaged 

Systems and Suppliers, accessed October 11, 2023.

169 California Energy Commission, A Comprehensive Assessment of Small Combined Heat and Power 

Technical and Market Potential in California, March 22, 2019. 
DNV – www.dnv.com Page 75

Table 6-2. Commercial natural gas reciprocating engine (300 kW-AC) CHP performance 

attributes

Year Overall Efficiency Fuel Input Useful Thermal 

Output Electric Heat Rate Equipment Life

2012 78.8% (HHV) 3,298 Btu/hr (HHV) 1,480 Btu/hr 10,995 Btu/kWh 25 years

2013 79.0% (HHV) 3,297 Btu/hr (HHV) 1,479 Btu/hr 10,990 Btu/kWh 25 years

2014 79.2% (HHV) 3,291 Btu/hr (HHV) 1,477 Btu/hr 10,969 Btu/kWh 25 years

2015 79.6% (HHV) 3,285 Btu/hr (HHV) 1,475 Btu/hr 10,950 Btu/kWh 25 years

2016 79.6% (HHV) 3,263 Btu/hr (HHV) 1,471 Btu/hr 10,877 Btu/kWh 25 years

2017 79.7% (HHV) 3,241 Btu/hr (HHV) 1,470 Btu/hr 10,805 Btu/kWh 25 years

2018 79.7% (HHV) 3,229 Btu/hr (HHV) 1,470 Btu/hr 10,763 Btu/kWh 25 years

2019 79.7% (HHV) 3,222 Btu/hr (HHV) 1,470 Btu/hr 10,740 Btu/kWh 25 years

2020 79.7% (HHV) 3,134 Btu/hr (HHV) 1,470 Btu/hr 10,445 Btu/kWh 25 years

2021 79.7% (HHV) 3,130 Btu/hr (HHV) 1,470 Btu/hr 10,434 Btu/kWh 25 years

2022 79.7% (HHV) 3,129 Btu/hr (HHV) 1,470 Btu/hr 10,431 Btu/kWh 25 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour; HHV=Higher 

heating value.

Oil-fired reciprocating engine performance characteristics have remained relatively constant over 

the last 10 years due to diesel engine maturity and the large-scale production history for traditional 

and backup power generation (Table 6-3). Although oil-fired reciprocating engines have lower 

capital costs compared with other CHP prime mover technologies, they produce more emissions 

than other comparative natural gas systems. 

Table 6-3. Commercial oil-fired reciprocating engine (350 kW-AC) CHP performance 

attributes

Year Overall Efficiency Fuel Input Useful Thermal

Output Electric Heat Rate Equipment Life 

2012 80.5% (HHV) 3,594 Btu/hr (HHV) 1,665 Btu/hr 10,269 Btu/kWh 30 years

2013 80.9% (HHV) 3,591 Btu/hr (HHV) 1,664 Btu/hr 10,260 Btu/kWh 30 years

2014 81.1% (HHV) 3,586 Btu/hr (HHV) 1,662 Btu/hr 10,246 Btu/kWh 30 years

2015 81.1% (HHV) 3,581 Btu/hr (HHV) 1,661 Btu/hr 10,232 Btu/kWh 30 years

2016 81.2% (HHV) 3,576 Btu/hr (HHV) 1,659 Btu/hr 10,217 Btu/kWh 30 years

2017 81.3% (HHV) 3,568 Btu/hr (HHV) 1,657 Btu/hr 10,195 Btu/kWh 30 years

2018 81.3% (HHV) 3,560 Btu/hr (HHV) 1,656 Btu/hr 10,173 Btu/kWh 30 years

2019 81.3% (HHV) 3,555 Btu/hr (HHV) 1,655 Btu/hr 10,158 Btu/kWh 30 years

2020 81.3% (HHV) 3,551 Btu/hr (HHV) 1,655 Btu/hr 10,146 Btu/kWh 30 years

2021 81.3% (HHV) 3,550 Btu/hr (HHV) 1,654 Btu/hr 10,141 Btu/kWh 30 years

2022 81.3% (HHV) 3,549 Btu/hr (HHV) 1,653 Btu/hr 10,139 Btu/kWh 30 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour; HHV=Higher 

heating value.

Similarly, gas turbine performance characteristics have shown minor efficiency improvements over 

the past 10 years due to its maturity in CHP applications (Table 6-4). Natural gas turbine efficiency 

generally increases as capacity increases, with the smallest representative capacity system 

(included in Table 6-4) in the commercial segment being the least efficient and least cost-effective, 

and large industrial systems (capacities more than 20 MW-AC) being more efficient and highly costeffective compared with other prime mover types. Smaller gas turbine systems can still provide 

benefits to sites where power and thermal needs for the site match with that of the natural gas 

turbine system.
DNV – www.dnv.com Page 76

Table 6-4. Commercial natural gas turbine (3,300 kW-AC) CHP performance attributes

Year Overall Efficiency Fuel Input Useful Thermal 

Output Electric Heat Rate Equipment Life 

2012 65.5% (HHV) 47,094 Btu/hr (HHV) 18,802 Btu/hr 14,271 Btu/kWh 25 years

2013 65.5% (HHV) 47,079 Btu/hr (HHV) 18,798 Btu/hr 14,266 Btu/kWh 25 years

2014 65.7% (HHV) 47,044 Btu/hr (HHV) 18,773 Btu/hr 14,256 Btu/kWh 25 years

2015 65.7% (HHV) 47,015 Btu/hr (HHV) 18,765 Btu/hr 14,247 Btu/kWh 25 years

2016 65.7% (HHV) 46,619 Btu/hr (HHV) 18,747 Btu/hr 14,127 Btu/kWh 25 years

2017 65.8% (HHV) 46,224 Btu/hr (HHV) 18,729 Btu/hr 14,007 Btu/kWh 25 years

2018 65.8% (HHV) 45,960 Btu/hr (HHV) 18,718 Btu/hr 13,927 Btu/kWh 25 years

2019 65.8% (HHV) 45,585 Btu/hr (HHV) 18,710 Btu/hr 13,814 Btu/kWh 25 years

2020 65.8% (HHV) 45,575 Btu/hr (HHV) 18,710 Btu/hr 13,811 Btu/kWh 25 years

2021 65.8% (HHV) 45,564 Btu/hr (HHV) 18,709 Btu/hr 13,807 Btu/kWh 25 years

2022 65.8% (HHV) 45,543 Btu/hr (HHV) 18,708 Btu/hr 13,801 Btu/kWh 25 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour; HHV=Higher 

heating value.

Microturbine overall efficiency has improved most among representative commercial systems over 

the past 10 years, largely due to new packaged systems being developed and introduced into the 

marketplace (Table 6-5). Although not as efficient as reciprocating engines, microturbines still 

provide benefits for commercial facilities in their thermal flexibility and emissions reduction potential. 

They can provide both heating and cooling for year-round applications in small hotels, and office 

buildings, among many other commercial applications. 

Table 6-5. Commercial microturbine (200 kW-AC) CHP performance attributes

Year Overall Efficiency Fuel Input Useful Thermal

Output Electric Heat Rate Equipment Life 

2012 66.4% (HHV) 2,582 Btu/hr (HHV) 888 Btu/hr 11,999 Btu/kWh 25 years

2013 66.8% (HHV) 2,580 Btu/hr (HHV) 887 Btu/hr 11,985 Btu/kWh 25 years

2014 66.8% (HHV) 2,573 Btu/hr (HHV) 886 Btu/hr 11,972 Btu/kWh 25 years

2015 66.9% (HHV) 2,565 Btu/hr (HHV) 885 Btu/hr 11,958 Btu/kWh 25 years

2016 67.2% (HHV) 2,517 Btu/hr (HHV) 884 Btu/hr 11,945 Btu/kWh 25 years

2017 67.8% (HHV) 2,468 Btu/hr (HHV) 882 Btu/hr 11,918 Btu/kWh 25 years

2018 68.0% (HHV) 2,419 Btu/hr (HHV) 880 Btu/hr 11,890 Btu/kWh 25 years

2019 68.2% (HHV) 2,365 Btu/hr (HHV) 870 Btu/hr 11,755 Btu/kWh 25 years

2020 68.5% (HHV) 2,328 Btu/hr (HHV) 867 Btu/hr 11,715 Btu/kWh 25 years

2021 68.6% (HHV) 2,317 Btu/hr (HHV) 855 Btu/hr 11,553 Btu/kWh 25 years

2022 68.8% (HHV) 2,300 Btu/hr (HHV) 840 Btu/hr 11,350 Btu/kWh 25 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour; HHV=Higher 

heating value.

Similar to the commercial sector reciprocating engine CHP system, the representative industrial 

systems show minor performance improvements over the past 10 years due to their maturity within 

industrial applications. The most common industrial subsectors that use reciprocating engines within 

the 1 MW-AC to 3 MW-AC capacity range are chemical manufacturing and food processing facilities 

that typically use the process heat or process cooling with the addition of an absorption chiller as 

the type of thermal recovery.170

170 U.S. Department of Energy, Better Buildings, Onsite Energy, Microgrid and CHP Installation Databases, 

accessed October 11, 2023.
DNV – www.dnv.com Page 77

Table 6-6. Industrial natural gas reciprocating engine (1,000 kW-AC and 3,000 kW-AC) CHP 

performance attributes

Year Capacity Overall 

Efficiency Fuel Input

Useful 

Thermal 

Output

Electric Heat 

Rate Equipment Life

2015 1,000 kW-AC 78.4% (HHV) 9,206 Btu/hr (HHV) 4,320 Btu/hr 9,206 Btu/kWh 25 years

2018 1,000 kW-AC 78.5% (HHV) 9,209 Btu/hr (HHV) 4,044 Btu/hr 9,209 Btu/kWh 25 years

2019 1,000 kW-AC 78.7% (HHV) 9,210 Btu/hr (HHV) 4,015 Btu/hr 9,210 Btu/kWh 25 years

2020 1,000 kW-AC 78.7% (HHV) 9,210 Btu/hr (HHV) 3,880 Btu/hr 9,210 Btu/kWh 25 years

2021 1,000 kW-AC 78.7% (HHV) 9,210 Btu/hr (HHV) 3,885 Btu/hr 9,210 Btu/kWh 25 years

2022 1,000 kW-AC 78.7% (HHV) 9,210 Btu/hr (HHV) 3,890 Btu/hr 9,210 Btu/kWh 25 years

2015 3,000 kW-AC 78.3% (HHV) 25,232 Btu/hr (HHV) 10,670 Btu/hr 8,411 Btu/kWh 25 years

2018 3,000 kW-AC 78.6% (HHV) 25,240 Btu/hr (HHV) 10,250 Btu/hr 8,413 Btu/kWh 25 years

2019 3,000 kW-AC 78.8% (HHV) 25,251 Btu/hr (HHV) 10,120 Btu/hr 8,417 Btu/kWh 25 years

2020 3,000 kW-AC 78.8% (HHV) 25,251 Btu/hr (HHV) 9,710 Btu/hr 8,417 Btu/kWh 25 years

2021 3,000 kW-AC 78.8% (HHV) 25,251 Btu/hr (HHV) 9,695 Btu/hr 8,417 Btu/kWh 25 years

2022 3,000 kW-AC 78.8% (HHV) 25,251 Btu/hr (HHV) 9,680 Btu/hr 8,417 Btu/kWh 25 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour; HHV=Higher 

heating value.

Gas turbine CHP systems are more common in the industrial sector compared with commercial 

sector gas turbine installations, given the wide range of industrial facility types and site power and 

thermal requirements. The four systems represent the potential range of common industrial 

installations. Given their popularity for power generation and CHP applications since the 1990s, the 

performance characteristics of gas turbine CHP systems for industrial applications has seen minor 

improvements over the last eight years. When comparing individual systems, overall system 

efficiencies generally improve as system capacity increases. 
DNV – www.dnv.com Page 78

Table 6-7. Industrial gas turbine (5,000 kW-AC, 10,000 kW-AC, 25,000 kW-AC, and 40,000

kW-AC) CHP performance attributes

Year Capacity Overall 

Efficiency Fuel Input Useful Thermal Output

Electric Heat 

Rate Equipment Life 

2015 5,000 kW-AC 67.6% (HHV) 64,560 Btu/hr (HHV) 28,115 Btu/hr 12,912 Btu/kWh 30 years

2018 5,000 kW-AC 67.6% (HHV) 63,186 Btu/hr (HHV) 27,212 Btu/hr 12,637 Btu/kWh 30 years

2019 5,000 kW-AC 67.6% (HHV) 62,144 Btu/hr (HHV) 27,355 Btu/hr 12,429 Btu/kWh 30 years

2020 5,000 kW-AC 68.8% (HHV) 60,924 Btu/hr (HHV) 27,497 Btu/hr 12,185 Btu/kWh 30 years

2021 5,000 kW-AC 68.8% (HHV) 60,924 Btu/hr (HHV) 27,444 Btu/hr 12,185 Btu/kWh 30 years

2022 5,000 kW-AC 68.8% (HHV) 60,924 Btu/hr (HHV) 27,415 Btu/hr 12,185 Btu/kWh 30 years

2015 10,000 kW-AC 68.0% (HHV) 124,799 Btu/hr (HHV) 60,358 Btu/hr 12,480 Btu/kWh 30 years

2018 10,000 kW-AC 68.0% (HHV) 123,328 Btu/hr (HHV) 60,209 Btu/hr 12,333 Btu/kWh 30 years

2019 10,000 kW-AC 68.1% (HHV) 122,053 Btu/hr (HHV) 59,506 Btu/hr 12,205 Btu/kWh 30 years

2020 10,000 kW-AC 68.2% (HHV) 120,779 Btu/hr (HHV) 58,803 Btu/hr 12,078 Btu/kWh 30 years

2021 10,000 kW-AC 68.3% (HHV) 121,294 Btu/hr (HHV) 58,708 Btu/hr 12,129 Btu/kWh 30 years

2022 10,000 kW-AC 68.4% (HHV) 120,907 Btu/hr (HHV) 58,338 Btu/hr 12,091 Btu/kWh 30 years

2015 25,000 kW-AC 69.3% (HHV) 256,619 Btu/hr (HHV) 85,230 Btu/hr 10,265 Btu/kWh 30 years

2018 25,000 kW-AC 69.3% (HHV) 253,383 Btu/hr (HHV) 85,015 Btu/hr 10,135 Btu/kWh 30 years

2019 25,000 kW-AC 69.3% (HHV) 251,508 Btu/hr (HHV) 84,655 Btu/hr 10,060 Btu/kWh 30 years

2020 25,000 kW-AC 69.3% (HHV) 249,634 Btu/hr (HHV) 84,296 Btu/hr 9,985 Btu/kWh 30 years

2021 25,000 kW-AC 69.3% (HHV) 249,506 Btu/hr (HHV) 84,135 Btu/hr 9,980 Btu/kWh 30 years

2022 25,000 kW-AC 69.3% (HHV) 243,004 Btu/hr (HHV) 83,974 Btu/hr 9,720 Btu/kWh 30 years

2015 40,000 kW-AC 68.8% (HHV) 384,993 Btu/hr (HHV) 135,760 Btu/hr 9,625 Btu/kWh 30 years

2018 40,000 kW-AC 69.3% (HHV) 384,993 Btu/hr (HHV) 134,180 Btu/hr 9,625 Btu/kWh 30 years

2019 40,000 kW-AC 69.8% (HHV) 384,993 Btu/hr (HHV) 133,201 Btu/hr 9,625 Btu/kWh 30 years

2020 40,000 kW-AC 70.2% (HHV) 384,993 Btu/hr (HHV) 132,222 Btu/hr 9,625 Btu/kWh 30 years

2021 40,000 kW-AC 70.3% (HHV) 384,711 Btu/hr (HHV) 132,112 Btu/hr 9,618 Btu/kWh 30 years

2022 40,000 kW-AC 70.3% (HHV) 384,429 Btu/hr (HHV) 132,003 Btu/hr 9,611 Btu/kWh 30 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour; HHV=Higher 

heating value.

Only 10 combined-cycle CHP systems have been installed in the United States since 2015 because 

of their limited applicability to specific industrial installation types and need for high site power and 

thermal requirements. These systems have been installed primarily in large manufacturing 

applications such as petroleum refining, food processing, chemical manufacturing, and pulp and 

paper manufacturing.

171 They have also been used in district energy applications serving large 

campuses, such as the Holland Energy Plant in Holland, Michigan.

172 Performance characteristics 

have seen minor improvements over the past eight years due to high technology maturity. 

Compared with all other CHP systems, combined-cycle plants have the longest average equipment 

life at 35 years.

171 U.S. Department of Energy, Better Buildings, Onsite Energy, Microgrid and CHP Installation Databases, 

accessed October 11, 2023.

172 Holland Energy Park, Holland Energy Park cogeneration plant commissioned, October 3, 2017. 
DNV – www.dnv.com Page 79

Table 6-8. Industrial combined-cycle (100,000 kW-AC and 375,000 kW-AC) CHP 

performance attributes

Year Capacity Overall 

Efficiency Fuel Input Useful Thermal Output

Electric Heat 

Rate Equipment Life 

2015 100,000 kW-AC 64.9% (HHV) 683,820 Btu/hr (HHV) 347,100 Btu/hr 6,838 Btu/kWh 35 years

2018 100,000 kW-AC 65.2% (HHV) 680,251 Btu/hr (HHV) 345,381 Btu/hr 6,803 Btu/kWh 35 years

2019 100,000 kW-AC 65.4% (HHV) 678,533 Btu/hr (HHV) 344,491 Btu/hr 6,785 Btu/kWh 35 years

2020 100,000 kW-AC 65.5% (HHV) 676,814 Btu/hr (HHV) 343,602 Btu/hr 6,768 Btu/kWh 35 years

2021 100,000 kW-AC 65.5% (HHV) 675,882 Btu/hr (HHV) 342,414 Btu/hr 6,759 Btu/kWh 35 years

2022 100,000 kW-AC 65.5% (HHV) 674,895 Btu/hr (HHV) 341,226 Btu/hr 6,749 Btu/kWh 35 years

2015 375,000 kW-AC 62.6% (HHV) 2,389,541 Btu/hr (HHV) 694,032 Btu/hr 6,372 Btu/kWh 35 years

2018 375,000 kW-AC 63.2% (HHV) 2,356,891 Btu/hr (HHV) 688,925 Btu/hr 6,285 Btu/kWh 35 years

2019 375,000 kW-AC 63.2% (HHV) 2,350,986 Btu/hr (HHV) 687,015 Btu/hr 6,269 Btu/kWh 35 years

2020 375,000 kW-AC 63.3% (HHV) 2,350,986 Btu/hr (HHV) 685,104 Btu/hr 6,269 Btu/kWh 35 years

2021 375,000 kW-AC 63.3% (HHV) 2,345,429 Btu/hr (HHV) 684,162 Btu/hr 6,254 Btu/kWh 35 years

2022 375,000 kW-AC 63.3% (HHV) 2,342,123 Btu/hr (HHV) 683,247 Btu/hr 6,246 Btu/kWh 35 years

Note: MMBtu/hr=million British thermal units per hour; Btu/kWh=British thermal units per kilowatthour; HHV=Higher 

heating value.

6.1.4 System cost data

Capital costs for commercial and industrial CHP systems were collected for multiple categories to 

accurately represent the differences in component and equipment costs, BOP, and labor and 

installation costs throughout the analysis timeframe. The cost categories were summarized across 

all representative systems to include:

• CHP equipment costs

• BOP and installation costs (includes labor costs)

Capital cost data for CHP systems represent an average of typical systems available in the 

marketplace for each year in the analysis timeframe. Where appropriate, individual project data 

and/or developer data were used, but cost data were gathered to reflect a blended average of 

commercially available systems for both the commercial and industrial sectors. Cost data were

primarily collected for each representative system for specific years in the analysis timeframe from 

DOE and EPA reports and fact sheets173, 174 where applicable and scaled to the remaining years 

using data from the DOE project profiles database,

175 the DOE packaged CHP eCatalog,176 and the 

CEC’s assessment of small CHP applications in California.177 Labor and installation costs were 

scaled within specific years to reflect annual wages included in the labor and installation portion of 

overall system capital costs. These cost data were then scaled to 2022 constant (real) dollars using 

appropriate GDP chain-type price indices to scale hardware costs when not explicitly available.

173 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Technology Fact Sheets, accessed 

October 11, 2023.

174 U.S. Environmental Protection Agency, Combined Heat and Power (CHP) Partnership, CHP 

Technologies, accessed October 11, 2023.

175 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Project Profiles Database, accessed 

October 11, 2023.

176 U.S. Department of Energy, Combined Heat & Power eCatalog, DOE Recognized CHP Packaged 

Systems and Suppliers, accessed October 11, 2023.

177 California Energy Commission, A Comprehensive Assessment of Small Combined Heat and Power 

Technical and Market Potential in California, March 22, 2019. 
DNV – www.dnv.com Page 80

Capital costs for the representative natural gas reciprocating engine and microturbine decreased 

the most in the past 10 years, largely due to the emergence of packaged systems becoming 

available for each of these prime mover types, which reduced site engineering and design costs

and interconnection costs and alleviated installation challenges through replicability. Microturbines 

generally present the most cost-effective option for smaller commercial applications largely due to 

the improvements in packaged CHP systems and lower interconnection costs for microturbines. The 

representative gas turbine system does not provide for the same types of applications as the 

representative reciprocating engine and microturbine, but capital costs for the system still slightly 

declined over the past 10 years. The oil-fired reciprocating engine capital costs have remained 

relatively constant over the same period because the technology is largely mature and has limited 

application types.

Figure 6-3. U.S. average commercial CHP system capital costs ($/kW-AC, 2022 $)

Similar to the commercial sector, capital costs for all representative industrial CHP systems have 

declined over the last five years (only 2015 and 2018–2022 costs are shown in Figure 6-4 due to 

limited data availability from 2016 to 2017). Capital costs for nearly all prime mover types slightly 

decreased due to system technical maturity and these systems’ long history of deployment in the 

industrial sector. In particular, system capital costs for the 5 MW-AC gas turbine have decreased 

the most since 2015. As mentioned previously, gas turbine efficiency and cost-effectiveness 

increase as capacity increases, as demonstrated in the declining capital costs moving from the 

lowest capacity system (5 MW-AC) to the highest (40 MW-AC). 
DNV – www.dnv.com Page 81

Figure 6-4. U.S. average industrial CHP system capital costs ($/kW-AC, 2022 $)

6.1.5 O&M cost data

DNV compiled variable O&M costs ($/kWh) for all CHP systems, including estimates for both general 

system maintenance and parts replacement. DNV assumed annual contracted maintenance costs 

for both commercial and industrial systems were included, representing general maintenance labor 

costs for routine system inspection, ancillary part (for example, filters, sensors, spark plugs, gaskets, 

valves) adjustments, and/or replacements. Fixed costs including major system overhauls and large 

parts (for example, catalyst, stack) replacement were also included and annualized over a 5–10-

year period to incorporate them into the final $/kWh cost component. DNV also characterized these 

major system overhauls or system components that are typically replaced prior to complete system 

shutdown for each system in Table 6-9. These categories include average replacement costs and 

the typical interval timeline for overhaul or major parts replacement.

Table 6-9. CHP system major overhaul components and replacement timeline

CHP System Sector Components Included in Major Overhaul

Average Interval 

of Major Overhaul

Natural Gas Reciprocating 

Engine (300 kW-AC) Commercial

Complete inspection and piston/liner replacement, 

replacement of bearings and seals, and crankshaft 

inspection

~55,000 hours

Oil-Fired Reciprocating (~10 years)

Engine (350 kW-AC)

Gas Turbine (3,300 kW-AC) Commercial

Complete inspection (turbine and compressor, 

dimensional inspections, etc.) and rebuild of turbine 

components (rotor, bearings, blades, seals, etc.)

~40,000 hours 

(~8 years)

Microturbine (200 kW-AC) Commercial Replacement of electronic components (electronic 

control module, power boards, etc.) and engine

~40,000 hours 

(~8 years)

Reciprocating Engine 

(1 MW-AC) Industrial

Complete inspection and piston/liner replacement, 

replacement of bearings and seals, and crankshaft 

inspection

~55,000 hours 

Reciprocating Engine (~8 years)

(3 MW-AC)

Gas Turbine (5 MW-AC)

Industrial

Complete inspection (turbine and compressor, 

dimensional inspections, etc.) and rebuild of turbine 

components (rotor, bearings, blades, seals, etc.)

~40,000 hours 

(~6 years)

Gas Turbine (10 MW-AC)

Gas Turbine (25 MW-AC)

Gas Turbine (40 MW-AC)

Combined Cycle 

(100 MW-AC) Industrial

Complete inspection (turbine, compressor, and electric 

generator) and rebuild of turbine components (rotor, 

bearings, blades, seals, etc.)

~50,000 hours 

Combined Cycle (~8 years)

(375 MW-AC)

DNV assembled variable O&M costs using DOE’s CHP Fact Sheet Series and the CEC’s

assessment of small CHP applications in California as a baseline, and it supplemented these costs
DNV – www.dnv.com Page 82

with DNV proprietary developer data where appropriate.178,179 Baseline O&M costs for general 

system maintenance and equipment replacement were gathered for multiple years throughout the 

analysis timeframe and scaled to 2022 constant (real) dollars and subsequent historical years using 

relevant U.S. average labor costs and annual CPI to adjust for inflation. Figure 6-5 shows 

commercial CHP system average O&M costs over the past 10 years. O&M costs have generally 

been consistent with minor fluctuations due to labor costs changes within the past five years, and 

parts replacement costs have not changed significantly enough to introduce large O&M cost swings. 

Figure 6-5. U.S. average commercial CHP system O&M costs ($/kWh, 2022 $)

Figure 6-6 shows industrial CHP system average O&M costs. Reciprocating engines which typically 

have the highest O&M cost of any prime mover type. The lower costs in the industrial sector are 

largely due to economies of scale when servicing larger installations because smaller sites may 

have more variety in system configurations, interconnection applications, and other related 

components. Combined-cycle CHP plants have significantly lower O&M costs when compared with

other prime mover types mainly due to economies of scale.

Figure 6-6. U.S. average industrial CHP system O&M costs ($/kWh, 2022 $)

178 U.S. Department of Energy, Better Buildings, Onsite Energy, CHP Technology Fact Sheets, accessed 

October 11, 2023.

179 California Energy Commission, A Comprehensive Assessment of Small Combined Heat and Power 

Technical and Market Potential in California, March 22, 2019. 
DNV – www.dnv.com Page 83

7 COMMERCIAL AND INDUSTRIAL MARKET DISCUSSION

The following subsections provide an overview of key factors influencing future CHP pricing, 

adoption, and technology deployment trends in the commercial and industrial (C&I) sectors. 

Additionally, the following subsections include findings from interviews conducted between October 

and November of 2023 with eight installers/developers and five end users of CHP systems. These

conversations also sought to gain insights into whether prospects for non-CHP (e.g., conventional 

generators and intermittent DERs) self-generation exist and to characterize economic, technical, 

regulatory, and general issues surrounding motivations and barriers to CHP or non-CHP adoption.

Systems that produce both electricity and useful thermal energy in a sequential process from a 

single source of fuel can be referred to as cogeneration systems, or CHP systems. The waste heat 

produced by heat engines producing electricity can be captured and used for water heating, space 

heating, or process heat for industry. Waste heat can also be used to cool buildings using absorption 

or adsorption heat pumps.

Burning a fuel to generate electricity and then capturing and using the waste heat produced can 

reduce primary energy demand by as much as 40% compared with separate grid electricity and 

fuel-fired boilers. The efficiency gains in energy demand also translate into GHG emissions 

reductions. The temperature of the waste heat produced determines its applicable end uses; high 

temperature waste heat is more versatile, while low temperature heat may only be applicable for 

water heating and heating/cooling conditioned space (including cooling tower water or other water 

used for cooling systems). Finding applications where the timing and magnitude of electric and 

thermal demands are aligned is a key consideration for CHP project economics. For example, if the 

waste heat is used for space heating alone, then the heat may have no value during summertime;

whereas if it is used for space heating and cooling, it may be useful all year. Steady heating demand 

in industrial processes is the prime target for CHP. Project economics are also enhanced when the 

waste heat is displacing the need to purchase a more expensive fuel.

Non-CHP generation includes grid-connected renewables such as solar or wind as well as other 

technologies such as power-only fuel cells, batteries, and gas-fired generators. Renewables have 

zero or low GHG emissions. However, the intermittency of solar and wind generation means that 

they cannot guarantee reduced customer peak electricity and corresponding peak demand charges 

(this limitation is especially true in two- and three-shift facilities). Also, due to the typical long duration 

of this peak demand, the battery capacity required to reduce demand charges presents a barrier. 

On-site gas generators offer on-demand, non-intermittent, power but they are only generators that 

do not recover waste heat to displace fuel use elsewhere at the site. Finally, non-CHP systems often 

require more space to produce the same amount of electricity when compared to CHP systems. 

Generally, CHP systems tend to serve different needs than non-CHP systems, and therefore are 

not competing with each other. Going forward, on-site industrial generation will likely include a mix 

of technologies depending on the specific needs, goals, and location of each facility. 

7.1 In-depth interview methodology

The remainder of Section 7 details the findings from in-depth interviews with installers/developers

and end users of CHP systems as well as secondary research on economic, technical, regulatory, 

and general topics surrounding CHP and non-CHP systems. DNV interviewed eight 

installers/developers. Four operate nationwide: one operates in the Northeast, Midwest, and eastern 

Canada; one targets the Eastern Seaboard from Maine to Maryland; one targets the Midwest; and 

one operates in Indiana. DNV also interviewed six end users (one of which was only a partial 

interview). Two interviewees worked in the industrial sector in a beverage manufacturer and a 
DNV – www.dnv.com Page 84

semiconductor company. The remaining end-user interviews were with commercial end users, 

namely, two health care systems, one university, and a partial interview with a community center.

The interviews and research sought to answer the following questions:

• How do the economics and risks (for example, environmental or regulatory) of installing a CHP 

system compare with a conventional boiler?

• To what degree is the ability to sell electricity to the grid important in CHP installation decisions?

• What factors affect the industrial use of purchased electricity versus non-CHP self-generation?

• How widespread is the use of non-CHP self-generation in the industrial sector, in what industries 

is non-CHP self-generation likely to grow most in the future, and what type of self-generation 

(for example, renewable, natural gas) is likely to prevail?

• Is the regulatory environment for CHP different in regions with independent system operators or 

regional transmission operators than in regions where a local utility operates the transmission 

system?

• How has state regulation affected installation of industrial CHP? 

• How has the IRA affected plans for industrial CHP capacity?

• Which regulations most influence whether a facility uses purchased electricity versus non-CHP 

industrial self-generation?

• Are facilities with CHP more likely to be designed as using CHP, or does adoption occur in 

existing facilities? And for those existing facilities adopting CHP to replace existing boiler heat, 

which industries are the most apt to switch? What innovations have occurred in the CHP industry 

or technology in the past five years?

• What, if any, cultural (that is, non-economic and non-regulatory) factors influence CHP 

installation (for example, CHP is not installed when there is a good business case for it)?

• What are the primary barriers to CHP adoption?

7.2 Economic

7.2.1 Spark spread

The economics of CHP systems are largely driven by the difference between the cost of electricity 

and price of natural gas, called the “spark spread.” CHP systems reduce the amount of electricity 

purchased from the grid and replace it with electricity generated on-site using natural gas. The lower 

the price of natural gas is relative to the price of electricity, the more economically beneficial CHP 

becomes. In contrast, facilities facing higher natural gas rates and lower electric rates would achieve 

less economic advantage from installing CHP.

One installer interviewed cited Maine as an example of how a changing spark spread increased the 

demand for CHP. Historically, Maine had low electric rates when compared with natural gas rates 

resulting in a spark spread that was unfavorable to CHP, despite having long, cold winters where 

the technology would otherwise seem beneficial. Recently, Maine has seen an increase in electricity

costs, which the respondent indicated had opened the market for CHP. Another installer identified

the Pacific Northwest and the “southern belt” as having electricity rates that were too low (an 

unfavorable spark spread) for CHP to make economic sense for most facilities.

7.2.2 Reliability

Two end-user survey respondents and four surveyed installers mentioned reliability or resiliency as 

factors that could influence a facility’s decision to install CHP, even in situations where the spark 

spread is less favorable. Although difficult to quantify, reliable power is critical for some customers. 

For example, it is a key reason that hospitals choose CHP. In the manufacturing sector, power 
DNV – www.dnv.com Page 85

outages shut down production lines, cause loss of materials and production time, and potentially 

damage equipment. An example of the latter is plastics extrusion, where an extended loss of power 

could cause melted plastic to cool and set inside the machine thereby damaging the equipment. 

Industries such as pharmaceuticals, biotechnology, and food processing often rely on refrigeration 

to preserve perishable raw materials and/or finished products necessitating reliable power because 

outages can result in costly spoilage or contamination.

In addition to variation across business activities, the value of the resiliency that CHP offers depends 

on the reliability of utility power, which is driven by many factors, including weather, utility 

infrastructure, transmission grid reliability, and a facility’s location on the grid (that is, remote 

locations are at higher risk for prolonged outages). For example, in California, utilities may shut off 

power to certain areas when the risk of damaged power lines sparking a wildfire is high (typically in 

high wind conditions in late summer and fall).

7.2.3 Incentives and tax credits

Programs and government policies can help defray the cost of CHP. According to DOE, 22 utilities 

spanning at least 12 states offered CHP incentive programs as of 2020.180 Those totals include both 

electric and gas utilities but do not include small or municipal utilities. One installer interviewed noted 

that fewer utilities were offering incentives in the Midwest, although secondary research showed 

programs exist in Illinois, Wisconsin, and Iowa.

Additional financial incentives are available under the IRA in the form of tax credits for qualifying 

CHP systems that begin construction before January 1, 2025. The base tax credit rate is 6%, but it 

increases to 30% if the project meets or is exempt from prevailing wage and apprenticeship 

requirements.

The installers interviewed uniformly saw market benefits or anticipated future benefits resulting from 

these IRA tax credits. Some reported impacts have been limited so far due to uncertainty about how 

the IRA would be implemented and its governing rules and guidelines. However, installers indicated 

the IRA has increased awareness of and interest in CHP, and they are mentioning the IRA’s 

incentives in their marketing. One installer noted that the inclusion of CHP in the IRA increases 

awareness of CHP technology for customers who may otherwise only consider renewable

technologies.

7.2.4 Exporting electricity to the grid

DNV asked both installers and end users whether the ability to export electricity to the grid was 

important in the decision to install CHP. Typically, CHP systems are sized to the thermal load of the 

facility. One end user characterized the sizing decision this way: “In order to get the payback you 

have to be able to use 100% of the steam you produce.” When system sizing is driven by thermal 

load, exporting electricity is often not the driving factor in the decision-making process. To design a 

CHP system based on electrical need, the systems would most likely need to be designed larger 

than to meet thermal needs and would therefore be more expensive. Additionally, when the systems 

are bigger, they run at a lower percentage of output and thus do not operate as cost effectively even 

with the ability to export or sell power back to the grid. One installer noted that for CHP systems 

designed to provide peak saving power (that is, providing power during peak periods to offset load 

and reduce peak), the ability to produce electricity is more valuable because rates are generally 

higher during peak periods and the generated electricity could reduce peak demand, thereby 

180 U.S. Department of Energy, Office of Energy Efficiency & Renewable Energy, Utility Combined Heat and 

Power Programs, April 2020. 
DNV – www.dnv.com Page 86

reducing demand charges.

181 However, based on interviews, CHP system sizing for peak savings 

is less common than sizing the system for base thermal load.

Of the six installers who indicated that exporting to the electric grid was possible in their service 

territory, four said that the ability to export was unimportant in their decision to install CHP. Similarly, 

four of the five end users interviewed did not export electricity to the grid, although one of the four 

that did not export electricity said that could change after the facility completes a solar PV project. 

Some industries produce biogas as part of their processing, for example landfills, wastewater 

treatment facilities, dairy farms, including food processing facilities using anaerobic digesters. A 

facility that produces biogas would be an exception to the aforementioned decision-making criteria

because a CHP system for these facilities would be sized based on the amount of biogas produced 

rather than the facility’s base thermal load requirement. 

7.3 Economic risk

Potential changes in spark spread introduces risk to a CHP project. A facility owner bases the

financial decision to install a CHP project on expectations (that is, forecasts) about future electricity 

rates, rate structures, and gas prices, which are uncertain. One end user interviewed indicated that 

they would not have installed the CHP project if they had foreseen the rate structure changes 

implemented by the utility after the project was committed. Although the environmental benefits met 

expectations, the spark spread dropped when the utility rate structure changed from one with a 

relatively low demand charge and higher energy rates to one with a higher demand charge and 

lower energy rates. In other words, unless the CHP unit operated without interruption and reduced 

demand charges, it would not affect total energy cost savings as much as it would have under the 

previous rate structures.

One end user interviewed indicated that while utility incentives helped justify the purchase of the 

CHP system by supporting a quicker payback, some concern existed about whether the company

would receive the incentive. One of the installers noted that it was sometimes easier not to deal with 

the utility because the incentive and interconnection processes could slow down the project. This 

comment suggests that at least some of the projects completed by this installer are not connected

to the grid; however, most responses that mentioned interconnection (from both installers and end 

users) focused on navigating the interconnection process rather than avoiding it.

Additional economic risks associated with CHP systems result from their complexity. CHP

installations are more complex than boilers and may require additional staff or at least training for 

existing staff for long-term operations and maintenance. One facility manager representing an end

user during interviews described a challenge in training staff on the CHP system: “fourteen staff 

members were trained and seven of them embraced it. Some of them are afraid of the CHP system

and would prefer to let others take care of it.”

182

7.4 Environmental

CHP typically increases Scope 1 emissions (direct GHG emissions from the fuel used on-site) but 

decreases Scope 2 emissions (indirect emissions associated with electricity from the utility, 

accounting for transmission and distribution losses). CHP has an environmental benefit if it results 

in a small increase in Scope 1 emissions but a large decrease in Scope 2 emissions. Or if a company 

181 As per installer interview.

182 As per end-user interview.
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decides to use renewable fuel, CHP increases Scope 1 emissions with no effect on Scope 2 

emissions.183

There are different ways to assess the environmental impacts of a CHP project. The industry 

standard for GHG emission reporting, the GHG Protocol’s GHG Inventory Accounting methodology, 

uses the average grid emissions as the basis for Scope 2 reporting. The GHG Inventory Accounting 

methodology can sometimes estimate CHP systems to result in negative GHG emissions savings

as Scope 1 emissions can increase more than Scope 2 emissions decrease. Another methodology, 

the GHG Protocol’s Project Protocol is based on marginal emissions. The Project Protocol can allow

companies to report Scope 2 savings in ways similar to how Renewable Energy Credits are reported.

7.5 Regulatory

7.5.1 Federal regulations

Two of the end users interviewed mentioned Title V of the Clean Air Act,

184 which requires any “major 

source” of actual or potential emissions above a specified threshold to obtain an operating permit. 

One end user indicated that the end user’s facility was not a Title V facility prior to the CHP 

installation, but is now well under the threshold. The CHP system of the second end user was owned 

and operated by the end user’s utility, so the system was outside the end user’s emissions reporting 

responsibility. The end user expected that the utility’s ownership of the CHP system would allow the 

end user to phase out of Title V to an air quality permit with less demanding requirements. It was 

not clear, due to the ownership structure, whether the CHP system had reduced emissions 

compared with the original system. These two end users had emissions nearing the Title V threshold. 

For facilities farther from the Title V threshold, a CHP system would not likely affect permitting 

requirements. A third end user mentioned having to revise the air quality permit but presented it as 

a routine compliance hurdle.

7.5.2 State and local regulations

CHP installers indicated concern about electrification trends from both a regulation standpoint and 

a public relations standpoint. They cited New York and Massachusetts as states that have adopted 

electrification goals. On a local level, New York City passed Local Law 97, which requires most 

buildings over 25,000 square feet to meet GHG emissions limits starting in 2024.185

One stated concern about such regulations is that they may indirectly affect attitudes toward natural 

gas use across the board. One installer supported CHP by suggesting it could reduce emissions 

now while electrification from renewables will take years and require infrastructure upgrades. 

Moreover, an installer indicated the industrial sector is more difficult to electrify compared with the 

buildings sector, and some industrial processes may require other approaches to decarbonization, 

such as low carbon fuels or carbon capture and storage. Installers also mentioned that CHP can 

reduce emissions now while the supply chain for hydrogen grows and then be converted to hydrogen 

fuel once hydrogen is more widely available.

One installer commended the DOE CHP e-database for supporting CHP with agencies, utilities, and 

advocates. The installer described the Maryland Energy Commission as forward leaning on CHP

183 While Title V is discussed below, the discussion here on Scope 1 and Scope 2 is not a Title V issue.

184 U.S. Environmental Protection Agency, Current Regulation and Regulatory Actions, Recent Regulatory 

Actions Related to Title V, accessed October 11, 2023. 

185 City of New York, NYC Sustainable Buildings, Local Law 97, accessed October 11, 2023.
DNV – www.dnv.com Page 88

and noted that the Delaware Department of Natural Resources and Environmental Control offers 

CHP incentives.

One end user also indicated needing to conduct a noise study before installing the system due to 

the end user’s location near a residential area.

7.5.3 Utility processes

Four of the five end users interviewed mentioned utility interconnections as at least a minor hurdle. 

Half of the installers also mentioned utility interconnection regulations or processes as barriers. They 

noted that different utilities have different rules and processes, but they also said that municipal 

utilities are often unfamiliar with CHP and often have no defined CHP interconnection process.

7.5.4 Regulatory environment: ISOs versus utility-operated systems

When asked, none of the end users or installers interviewed mentioned any regulatory differences 

between regions with independent system operators (ISOs) and regions where a local utility 

operates the transmission system. Generally, CHP systems are connected at the local distribution 

level, so variation between utilities is more significant than how the transmission grid is operated.

7.6 Technical

7.6.1 New versus retrofit

Most CHP systems are installed in existing facilities (that is, retrofit). Only one of the eight installers 

interviewed said that his or her business was mostly new facilities, and another said that his or her

business was 50/50 retrofit/new. The remaining installers said their business was mostly retrofit. For 

the five end users interviewed, the CHP system was installed in an existing facility.

Rather than replacing an existing boiler, most CHP systems are add-ons, running in parallel to the 

heating system or retaining the old boilers as back-up. One installer commented, “We almost always 

tell [the customer], ‘Leave the existing boiler in place.’” The CHP system, as noted earlier, is typically 

sized for base thermal load, so the boilers are available for heating peaks and to provide redundancy.

7.6.2 CHP versus boiler

Neither the installers nor the end users interviewed saw CHP as a replacement for a boiler, so rather 

than the question, “Should I choose a CHP system or a boiler?”, it was “Should I add a CHP system 

to my boilers?” One installer described CHP as a “nice to have rather than a need to have,” saying 

that someone who needs to replace a boiler probably wouldn’t have the funds to also install a CHP 

system, especially since CHP is significantly more expensive than a boiler.

Adding a CHP system may extend the life of the existing boiler, which can then operate less often 

and at lower capacity. CHP also provides resiliency. In contrast, installing a boiler system without

CHP may only provide efficiency improvements.

CHP systems are more complex than boilers, and therefore, installers and end users note increased 

long term operation and maintenance risk. Utility interconnections potentially affect project timelines

and cost. A CHP system needs to tie into electrical, gas, and thermal systems, making it challenging 

to avoid operation disruptions during installation. If a company acquires CHP under an energy 

services agreement (ESA), where the system is owned and operated by an energy services 

company, the long-term contract may also be viewed as a risk.

With respect to regulation, installers saw little difference between CHP and boilers.
DNV – www.dnv.com Page 89

7.6.3 Where is CHP a good fit?

Installers were asked what industries were the most likely candidates for CHP. In response, they 

identified characteristics that would most benefit from CHP systems. These characteristics include:

• Large electrical and thermal loads

• Use for heat generated from an engine or unit

• Need for hot water both for space heating and domestic water heating (applies to commercial 

and multifamily residential facilities more than industrial facilities)

• 24/7/365 thermal loads, for example a three-shift industrial facility. Also, colleges, universities, 

and hospitals.

• Need for resiliency

• High electric rates with comparatively low natural gas rates (favorable spark spread)

• Available biogas, biomass, or other “waste” fuels (such as still gas in the petroleum industry) 

from industrial operations that can be used as fuel for the CHP

We reviewed DOE’s CHP project profiles database to see what types of industrial facilities were 

installing CHP systems. We looked at 1,786 CHP systems that could broadly be classified as 

industrial in agriculture; mining, quarrying, and oil and gas extraction; utilities; construction; and 

manufacturing. Figure 7-1 shows the breakout of both number of systems and installed capacity by 

category (Construction, with only 6 systems and 20 MW of capacity, was omitted from the chart).

Figure 7-1. CHP System Counts and Total Capacity by Industry Sector by Count and MWAC

While manufacturing makes up 56% of systems, it represents 85% of capacity, reflecting largerthan-average system sizes. Utilities and agriculture, in contrast, have a smaller average system size

making their capacity share much smaller than their system share.

We took a deeper look at the manufacturing sector at the three-digit North American Industry 

Classification System (NAICS) level, shown in Figure 7-2. Chemicals, an energy-intensive industry 

with high thermal loads, had the largest share by both number of systems (14%) and capacity (31%

of all industrial capacity). Paper had the second highest system count (10%) and third highest 

capacity (16%). In addition to being an energy-intensive industry with high thermal loads, the nature 
DNV – www.dnv.com Page 90

of the raw materials to make paper products results in biomass that can be used as fuel (this 

characteristic is shared by the wood products industry, which represents 4% of systems, and to a 

lesser extent by the food industry). The petroleum and coal products industry ranks second by 

capacity (fourth by number of systems). As crude oil is refined into salable products, some 

components remain that the industry uses for fuel. This fuel source makes CHP a cost-effective

choice for the industry. Food and primary metals round out the top 5 industries by capacity (6% and 

5% of total, respectively), with the food industry accounting for 9% of systems.

Figure 7-2. CHP System Counts and Total Capacity for Manufacturing Industries by Count 

and MW-AC (at 3-Digit NAICS)

To further refine which industry sectors opt for CHP, we looked at the 5-digit NAICS level across all 

industries. Figure 7-3 shows the top 10 industries by number of systems (blue), accounting for 56% 

of total systems, and by capacity (green), accounting for 70% of total capacity.

There is substantial overlap between the two top 10 lists, with 6 industries appearing on both: 

petroleum refineries, paper mills, other basic organic chemical manufacturing, electric power 

generation, oil and gas extraction,186 and steam and air conditioning supply (e.g., district heat). Of 

the top 10 by number of systems that do not appear on both lists, three have available biomass or 

biogas (sewage treatment, dairy cattle and milk production, and sawmills). This fuel availability 

makes CHP cost effective at a smaller scale. Rounding out the capacity top 10 list are other basic 

inorganic chemical manufacturing, resin and synthetic rubber manufacturing, industrial gas 

manufacturing, and petrochemical manufacturing. Seven of the capacity top ten are manufacturing 

industries, characterized by high thermal load and high overall energy demand. District heat is 

similar in those characteristics. The electric power generation capacity is almost all fossil fuel 

generation (97% NAICS 221112).

186 The facilities included in this category are listed in the DOE CHP database as NAICS 21111, which is not 

a valid NAICS code. We categorized it as oil and gas extraction based on the first four digits.
DNV – www.dnv.com Page 91

Figure 7-3. CHP System Counts and Total Capacity: Top 10 Five-Digit NAICS Industries by 

Count and MW-AC

7.6.4 Technological innovations

CHP systems produce electricity and useful thermal energy in a sequential process from a single 

source of fuel. As a result, CHP systems often operate with an overall efficiency of 70% to 80%. 

Installers cited a number of technological and other innovations in the CHP market.

• Inverter-based generators are increasingly supplanting synchronous and induction generators 

for CHP, particularly for smaller systems.

187 Inverter-based CHP has several advantages over 

the older technologies, notably a standardized interconnection following the UL 1741 

187 Davidson, Keith, and Rod Hite, A Comprehensive Assessment of Small Combined Heat and Power 

Technical and Market Potential in California, California Energy Commission, updated March 22, 2019.
DNV – www.dnv.com Page 92

standard.188 This nationally recognized standard allows CHP to be treated more like solar when 

connecting to the distribution network. About seven years ago, the CHP market began adopting 

inverter-based technology in smaller reciprocating engine systems for the utility interconnect, 

allowing this CHP technology to also be treated more like solar. With that change, the utility must 

be able to control the inverter. Synchronous and induction generators, in contrast, often face 

greater utility resistance and hurdles to interconnection. Other advantages of inverter-based 

CHP over induction generators include black start capability (the system can operate during a 

blackout), high power quality, no reactive power, and variable-speed capability that provides 

efficient part-load performance.

• Through technology advancements, CHP systems can provide frequency regulation benefits to 

the end user and the utility through grid service market participation.

• CHP start times have improved, with units achieving full speed much faster than in the past.

• One installer noted that some third-party heat exchangers have improved.

Customer-sited CHP systems in the commercial building and industrial sectors are considered a 

mature DER technology, and the use of clean hydrogen in CHP systems is seen as the next step in 

the technology’s evolution. These systems will need access to hydrogen, either through production 

of hydrogen on-site or by selecting a location near a hydrogen production facility to avoid high 

transportation costs. Their facility also needs hydrogen storage and handling equipment. Blending 

hydrogen with natural gas is already possible, and demonstration projects are ongoing for both 

blending into natural gas pipelines and site-level blending at the end-use customer location. If 

configuring CHP with a boiler, the maximum blending percentage possible depends on the boiler 

burner type. The current industry assumption for industrial end users is that blending up to 20% (by 

volume) can be safely done without changing the burners of the end-using equipment. This 

assumption is generally the same assumption made for hydrogen fuel blending in commercial and 

industrial CHP equipment. Manufacturers are working to decarbonize natural gas by blending it with 

different fuels such as hydrogen, renewable natural gas, and possibly even ammonia. Four installers 

mentioned transitioning to engines that burn hydrogen, with one stating that he or she has 22 units 

operating on pure hydrogen, although we were not able to confirm that number and it was not clear 

if all those units were part of CHP systems. The DOE CHP eCatalog lists 63 CHP packages with 

hydrogen blending capability ranging from 5% to 40% and five 100% hydrogen systems.189

In May 2022, Caterpillar announced a demonstration project of a hydrogen-fueled CHP system to 

start in 2023.190,191 The company offers a 1,250 kW-AC generator set that can operate on 100% 

hydrogen, although it is only available on a designed-to-order basis. Among its standard product 

offerings are models that can operate with natural gas/hydrogen blends with up to 25% hydrogen.192

A Siemens industrial gas turbine featured in a demonstration project in France produced and stored

188 Panora, Robert and Jean Roy, “Top 10 Reasons to Choose Inverter-Based Engine CHP,” Tecogen, 

accessed October 11, 2023 

189 U.S. Department of Energy, Combined Heat & Power eCatalog, DOE Recognized CHP Packaged 

Systems and Suppliers, accessed October 11, 2023.

190 Caterpillar, News, Corporate Press Releases, Corporate Press Release Archive, ”Caterpillar to Launch 

Demonstration Project Using Hydrogen-Fueled Combined Heat and Power,” Press Release (May 31, 

2022).

191 Singh, Jaswinder, “Flexible Natural Gas/Hydrogen CHP System Development & Demonstration,” 

Caterpillar, Presentation, June 5–8, 2023. 

192 Caterpillar, New Products, Power Systems, Electric Power, Gas Generator Sets, accessed October 11, 

2023. 
DNV – www.dnv.com Page 93

100% renewable hydrogen and then used it to fuel the turbine to produce electricity.193 Capstone 

released a CHP product that runs on a blend of up to 10% hydrogen and is working to develop 

products that run on fuel mixes with a higher hydrogen content.194 The current cost of hydrogen, 

whether renewably produced or produced from natural gas, is higher than natural gas.

Lastly, one installer mentioned the role of CHP in microgrids. With other distributed energy 

technologies, such as solar plus battery storage, CHP can allow a building, campus, or community 

to operate independently of the grid when necessary, improving resilience.

Although not a technological innovation, the business model of an energy services company (or in 

the case of one end user, the utility) owning and operating a CHP system for the end user is making 

CHP accessible to a wider range of customers.

7.7 General

7.7.1 Cultural factors influencing adoption

Many companies have environmental, social, and governance (ESG) goals or policies. One element 

of such policies can be GHG emission reduction goals. CHP can further such goals by trading an

increase in Scope 1 emissions for a larger decrease in Scope 2 emissions. However, some 

companies may see burning fossil fuels in any capacity as in opposition to their ESG goals.

Corporate decision-making can stymie an investment in CHP. In any given year, a company may 

have multiple capital projects under consideration. Replacing an aging boiler may be seen as more 

urgent than adding CHP. That perspective may be exacerbated by lack of knowledge about CHP, 

which one installer said was viewed as “exotic.” Many facilities could benefit from CHP but are 

unaware of the technology or don’t fully understand its benefits and risks. One installer interviewed 

cited the need for someone within an organization to be knowledgeable about the technology and 

act as a champion. Corporate decision-makers need to understand the technology, financing, and 

benefits to authorize the capital investment required for a CHP system.

Installers’ concerns about the impacts of electrification policies tie into cultural factors. One of their 

fears is that such policies convey the message, intentionally or not, that all gas use is bad and that 

therefore CHP is an undesirable technology. One comment installers made about the IRA was that 

providing tax credits for CHP conveyed fuel neutrality with solar and storage. 

7.7.2 Barriers to CHP adoption

Both technical and informational barriers exist for CHP adoption. 

Technical barriers to CHP adoption include:

• Some facilities do not have the physical space to house the CHP equipment.

• Depending on a facility’s thermal needs, a CHP system may not be able to provide enough 

steam at the necessary temperature to support processes which require high temperatures.

• CHP is most applicable for applications where the timing and magnitude of electric and thermal 

demands are aligned, and may not be appropriate technology for all types of facilities/industries. 

193 Siemens Energy, ”HYFLEXPOWER consortium successfully operates a gas turbine with 100 percent 

renewable hydrogen, a world first,” Press Release (October 13, 2023). 

194 Capstone Green Energy, News, Press Releases, “Capstone Green Energy Corporation (NASDAQ: 

CGRN) outlines its ongoing hydrogen development program and pursuit of external funding 

opportunities,” Press Release (April 26, 2021). 
DNV – www.dnv.com Page 94

Information barriers include:

• Facility owners might not be aware of CHP technology and its benefits.

• Installers and end users may not understand the overall environmental impact of CHP. 

• In areas with aggressive decarbonization/electrification policies, the future use, cost, and 

availability of natural gas is uncertain.

• Federal, state, and local regulations might be triggered due to an increase in fossil fuel use for 

the CHP.

• CHP systems are complex, with electrical, thermal, and gas connections that require complex 

engineering and understanding.

With the installation of CHP systems, hidden costs and cost uncertainty exist. Utility interconnections 

could add time and cost, for example, if the customer has to pay for an impact study that could 

identify costly substation upgrades.

7.8 Non-CHP generation

7.8.1 Non-CHP versus CHP self-generation

Conventional (non-CHP) electricity generation is also present in the industrial sector at facilities that 

have reliability needs but do not have the heating loads to justify CHP. 

However, conventional generation accounts for a much smaller share of industrial electricity 

generation than CHP. MECS reports fuel consumption for both CHP and conventional electricity 

generation. The 2018 MECS reports non-negligible values for fuel use for conventional electricity 

generation for only four industrial subsectors (at the NAICS three-digit level): petroleum, paper, food, 

and chemicals. In contrast, 14 subsectors had non-negligible consumption for CHP. Across all 

manufacturing subsectors and fuels, more than 1,900 trillion British thermal units went to CHP, 

compared with 31 trillion British thermal units going to conventional electricity generation (only 1.6% 

of the CHP value). Even with conservative estimates of power-to-heat ratios, conventional 

generation accounts for only a small share of the total electricity produced.195,196

Non-CHP self-generation also includes intermittent renewables, such as solar, which can be paired 

with storage to partially address the issue of intermittency. These technologies are different from 

CHP, which addresses base load and thermal load, and provides resiliency. Because of these 

different operational characteristics, CHP and non-CHP technologies are generally not seen as 

being in competition with each other, but rather they are complementary technologies serving 

different needs. To the extent that any interviewees saw them as competing, it was related to 

marketing, awareness, incentives, and electrification policies rather than performance and suitability.

Two CHP installers interviewed mentioned installing CHP as one component of a microgrid that also 

included solar and energy storage. For one project, the CHP was sized around thermal needs 

(thermal load), while the solar and storage were designed to address electric needs (electric load). 

However, such systems are more common for residential and commercial projects than for industrial.

Roof and/or land availability can be a limiting factor when designing a solar system. CHP can 

generate more electricity than solar. One CHP installer said that the amount of solar that could be 

195 New technologies typically have power-to-heat ratios of 1.0 or higher, while older systems could have 

ratios as low as 0.3.

196 Fahl, Ulrich and Audrey Dobbins, Europe’s Energy Transition, Chapter 29 – District Heating in Europe: 

Opportunities for Energy Savings, Business, and Jobs, 2017, p.249–259.
DNV – www.dnv.com Page 95

installed would be “window dressing” and “a drop in the bucket” relative to the energy needs of the 

typical CHP-using facility.

For companies with ESG goals, renewables may be adopted to achieve those goals, regardless of 

limiting factors. For example, solar provides a visible sign of commitment to GHG reduction that may 

have public relations value.

Two of the CHP end users interviewed had rejected solar or solar plus storage solutions due to 

intermittency and reliability issues, such as storage only being appropriate for bridging short-term 

needs at current prices and performance factors. One end user cited the need for redundancy during 

storms when outages are more likely but solar production may be minimal or offline.

The value of solar and wind depend on location. Wind speeds and consistency differ widely by 

region, and insolation varies with latitude, weather patterns, and season. At northern latitudes, solar 

production is lower in the winter, which reduces its value for space heating loads or for industrial 

process loads that tend to be consistent across the year.

7.8.2 Economics of non-CHP self-generation

7.8.2.1 Rates

Rates are a critical factor in determining the economic feasibility of renewables. Much like the spark 

spread for CHP, renewables are attractive when the cost of self-generation is less than the cost to 

purchase energy from the utility. Industrial electric tariffs are usually demand based except for the 

smallest facilities. Demand rates charge customers based on the facility’s maximum monthly 

kilowatts of demand for a specified duration, for example, the facility’s highest 15-minute demand 

for the month. The financial benefits that intermittent renewables have on energy bills may decrease 

as demand charges increase, because the potential of the renewable resource (e.g., wind or solar 

power) generation being non-coincident with facility’s peak demand. The question is not just how 

much self-generation the system (kilowatthour) produces—it matters when that energy is produced

and whether it can consistently coincide with the facility’s peak.

Small industrial customers are numerous but represent only a small share of total industrial energy 

use. Small industrial customers are more likely to be on an energy-based small general service rate 

along with small commercial customers. For example, a one-person jewelry-making studio would 

be classified as industrial but would have low electricity consumption and have less process energy 

use relative to space heating and space cooling. For these customers, the economic proposition for 

solar is similar to that of small commercial. The calculation is simply whether it is less expensive per 

kilowatthour to produce electricity than to buy it from the utility.

7.8.2.2 Predominance and growth of non-CHP self-generation

We found limited literature discussing how widespread non-CHP self-generation is in the industrial 

sector. Wood Mackenzie forecasts battery storage adoption in the non-residential sector (not 

industrial specifically), which is often paired with renewables. This forecast provides an indirect 

indicator of the growth in non-CHP self-generation, with the non-residential sector called “CCI” and

displayed in red (Figure 7-4).
DNV – www.dnv.com Page 96

Figure 7-4. Annual and cumulative market forecast for battery storage

Data source: Wood Mackenzie, US Energy Storage Monitor Q4 2023

As with CHP, industry subsector is not the key factor in determining where growth will occur in 

non-CHP self-generation. Factors that will determine growth include:

• Electricity rate structure

• Cost of purchased electricity

• Facility load shapes, for example, facilities with flat loads benefit less from storage 

• Corporate ESG goals and policies

7.8.2.3 Regulations affecting non-CHP industrial self-generation

No regulations limiting non-CHP self-generation for industrial facilities were identified. However, 

installers perceived that certain policies favored renewables over CHP. Particularly, under 

electrification initiatives, renewables can be seen more favorably than natural-gas-based technology. 

Historically, federal tax credits have been higher for renewables than for CHP (although the IRA has 

leveled the playing field through the end of 2024).
DNV – www.dnv.com Page 97

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