August 2012

REPORT ON THE FIRST

QUADRENNIAL QTR TECHNOLOGY REVIEW

TECHNOLOGY ASSESSMENTS
Suggested Citations

Report on the First Quadrennial Technology Review

U.S. Department of Energy. (2011). Report on the First Quadrennial Technology Review. 

DOE/S-0001. Washington, DC. 

Report on the First Quadrennial Technology Review: Technology Assessments

U.S. Department of Energy. (2012). Report on the First Quadrennial Technology Review: 

Technology Assessments. DOE/S-0002. Washington, DC.
Table of Contents | i

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

TABLE OF CONTENTS

Vehicle Efficiency.............................................................................................................................11

Internal Combustion Engines.......................................................................................................................... 12

Lightweighting and Aerodynamics.................................................................................................................. 22

Vehicle Electrification.....................................................................................................................37

Vehicle Electrification...................................................................................................................................... 38

Alternative Hydrocarbon Fuels......................................................................................................55

Alternative Hydrocarbon Fuels........................................................................................................................ 56

Building and Industrial Efficiency.................................................................................................79

Building Efficiency........................................................................................................................................... 80

Industrial Efficiency......................................................................................................................................... 99

Grid Modernization ........................................................................................................................119

Grid Infrastructure ......................................................................................................................................... 120

Grid Storage .................................................................................................................................................. 136

Grid Measuring, Modeling, and Control ....................................................................................................... 147

Clean Power....................................................................................................................................169

Carbon Capture and Storage......................................................................................................................... 170

Concentrating Solar Power ........................................................................................................................... 181

Fuel Cells for Distributed Generation............................................................................................................ 195

Geothermal.................................................................................................................................................... 205

Nuclear Power............................................................................................................................................... 213

Solar Photovoltaics........................................................................................................................................ 223

Water Power ................................................................................................................................................. 237

Wind .............................................................................................................................................................. 248

Glossary............................................................................................................................................281

introduction | 1

This document contains the 17 technology assessments (TAs) that were carried out as 

part of the Department of Energy’s (DOE’s) Quadrennial Technology Review (QTR). 

These are meant to be accessible summaries of the techno-economic aspects (e.g., 

current deployment, historical pace of progress) and research and development 

(R&D) opportunities in the most important energy technologies or systems. Collectively, these assessments support the analysis and judgments of the Report on the 

QTR, available at www.energy.gov/qtr. 

The Report on the QTR developed portfolio principles to apply to these 17 technologies to prioritize energy R&D over the next five years. Its recommendations therefore rest upon the more detailed understanding of individual technologies. Similarly, 

the 17 TAs should play an important role when technology programs articulate R&D 

priorities to guide their activities. The TAs can help decision makers speak from a 

common framework, fact base, and set of analyses. 

These TAs will serve a number of audiences. Policymakers in Congress, DOE, and other federal and local officials can use them when assessing options for energy policy 

and technology R&D. Scientists and technology leaders can use them to inform decisions on what R&D to pursue: whether they pursue priorities identified in the assessments or breakthroughs that alter the view of a technology’s future. Similarly, the 

assessments provide industry with a structured landscape of technology areas―helping companies place their own R&D priorities in broader context. Finally, constituent 

groups focused on particular industries or policy goals can use these assessments to 

inform their interests within a broad context.

INTRODUCTION
 2 | Introduction

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

The following points are important in reading and using these TAs: 

The TAs are not program plans or policy or funding recommendations. While they outline certain research needs and opportunities for risk reduction, they are not statements of the Department’s intended investments. Activities that DOE supports are subject to a number of considerations, including budgets and evolving 

technology landscapes. The principles discussed in the Report on the QTR will be considered as DOE makes 

future investment decisions.

Given the diversity of topics the TA’s cover, they are not fully uniform in style, format, or content. Furthermore, the TAs are descriptive, not prescriptive. In general, they include a discussion of the current state of 

the technology, including the historical pace of development in terms of cost, performance, and deployment, 

and the current state of the industry—in the United States and the world. They then describe the future potential of the technology: a summary of published views on technical headroom to improve cost and performance, 

including a view of key R&D opportunities; a summary of agreements and disagreements among major published roadmaps; and a summary of non-technical factors that would impact the pace of technology progress. 

Finally, the TAs include a summary of DOE’s history, accomplishments, and role.

The cost analyses of the TAs are not based on a single set of metrics and assumptions. As identified in 

the Report on the QTR, the Department needs to develop a strong internal capability in techno-economic and 

policy analysis to support its energy R&D strategy. The Department needs a professional group that can integrate the major functions of technology assessment and cost analysis, program planning and evaluation, economic-impact assessments, industry studies, and energy and technology policy analysis. Such a group would 

harmonize assumptions across technologies and make the analyses transparent in order to inform future QTRs.

Our grouping of technologies among the TAs is necessarily imperfect. As a result, the TAs are clusters of 

interrelated assessments, all of which should be considered to get a complete view. In characterizing the 

energy technologies, we have focused on individual components. For an integrated view of the systems these 

technologies comprise, please consult the Report on the QTR.

The TAs are not meant to be advocacy documents. Energy is plagued by technological advocacy, wherein 

each particular technology in turn is presented as “the solution.” Yet no technology—at present or in the future—can do it all, so an appreciation of the broader context or capabilities of technologies that are competing 

to provide the same service is vital. These assessments have attempted to avoid advocacy and consistently balance optimism with realism, in part through relevant techno-economic data. And in citing the latter, we have 

tried to provide context within which to judge claims. The size of the energy sector can produce big numbers, 

which we also express as fractions of the relevant scale. 

INTRODUCTION

NATURE OF THE 

ASSESSMENTS
Introduction | 3

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

We have avoided projections of deployment. Potential materiality is certainly an important factor in judging 

technologies, and technology improvements can certainly facilitate deployment. However, market and regulatory conditions are even more important factors, and these are largely beyond the purview of DOE. 

The TAs are largely not new technical and performance analyses. Rather, they rely upon published external 

assessments to the greatest extent possible. As such, they do not include the Administration’s analysis of 

these external assessments. The National Research Council’s America’s Energy Future1 reports have been an 

important resource in that regard. 

The TAs do not cover all energy technologies. Among the technologies excluded are those sufficiently mature to not warrant significant DOE R&D support (e.g., gas turbines). Equally omitted are immature technologies that cannot have material impact within two decades (e.g., nuclear fusion). DOE investment in immature 

yet high-reward technologies is important, but cannot substitute for energy technology activities that more 

immediately address urgent energy challenges.

In accordance with the Report on the QTR, the TAs include brief descriptions of DOE’s role in each technology area. There are three categories of DOE activities in energy technology:

•	 Capability: Pre-competitive R&D and fundamental engineering research creates a depth of knowledge 

about new and incumbent energy technologies, harnessing the capability of the national laboratories 

and universities and strengthening those capabilities in our private-sector partners.

•	 Informational: Information collected, analyzed, and disseminated by DOE shapes the policies and 

decisions made by other governmental and private-sector actors.

•	 Targeted Initiatives: Targeted initiatives bring goal-driven, coordinated efforts to bear throughout 

the research, development, and demonstration process to help prove technologies for adoption by the 

private sector.

Operating in any of these modes, DOE has a unique ability to convene energy-sector participants from the 

public and private sectors and coordinate their efforts. We also have opportunities to leverage the globalization 

of innovation, capital, and markets by engaging international partners in energy technology development and 

deployment.

1

 National Academies of Science, National Academies of Engineering, National Research Council. (2009). America’s Energy Future. 

Washington, DC.
 4 | Introduction

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

INTRODUCTION

TIMELINE AND

DELIVERABLES

Consistent with the QTR project plan approved in late January 2010, DOE initiated the QTR’s TA activities in 

early March 2010. After the QTR core team organized the clean-energy landscape into 17 areas, 12 teams 

conducted these 17 assessments. A total of 135 assessment team members were drawn from the DOE 

program offices and the national laboratories. 

Each of the teams was responsible for three deliverables in each assessment: 

•	 A scoping document that mapped the full landscape of technical pathways in each area. Pathways 

that had both sufficient data for assessment and the potential to have significant impact on national 

energy challenges were in scope. The scoping documents also noted those promising technologies 

with insufficient data. 

•	 A team presentation at one or more of the five QTR strategy-specific workshops. These presentations 

provided immediate and interactive feedback on the team’s interim product from thought-leaders in 

industry, academia, and the non-profit sectors. 

•	 The TA included in this document.

Each TA was reviewed in three phases. First, all members of each technology team had the opportunity 

to review all other TAs. Next, several members of the QTR team (Shouvik Banerjee, Megan Chambers, 

Avi Gopstein, Michael Holland, Asa Hopkins, Cynthia Lin, and Laurel Miner) reviewed the assessments, 

normalizing content and providing context. Finally, the TAs were sent to independent energy experts for 

external peer review. 
Introduction | 5

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Technology Assessment Teams (Team leads are in bold)

CONTINUED

DOE-QTR Technology Teams

Strategy Technology Team Member Organization

Transportation 

Efficiency

Internal Combustion 

Engine 

Gurpreet Singh DOE - EERE

Eric Rohlfing DOE - SC

David Shum ARPA-E

George Muntean PNNL

Johney Green ORNL

Bob Carling SNL

Transportation 

Efficiency

Lightweighting and 

Aerodynamics

Ed Owens DOE - EERE

Jerry Gibbs DOE - EERE

Dave Warren ORNL

Kambiz Salari LLNL

Tom Wenzel LBNL

Austin Brown NREL

Transportation 

Electrification

Electrification 

(Storage, Powertrain, 

Grid Integration)

Pat Davis DOE - EERE

Dave Howell DOE - EERE

Sunita Satyapal DOE - EERE

David Danielson ARPA-E

Linda Horton DOE - SC

Ann Schlenker ANL

Claus Daniel ORNL

Tom Wunsch SNL

Ahmad Pesaran NREL

Brenda Garcia-Diaz SRNL

Venkat Srinivasan LBNL

Romesh Kumar ANL
 6 | Introduction

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

CONTINUED

DOE-QTR Technology Teams

Strategy Technology Team Member Organization

Transportation 

Alt. Fuels

Production and 

Conversion

Paul Bryan DOE - EERE

Zia Haq DOE - EERE

Jonathan Burbaum ARPA - E

Jarad Daniels DOE - FE

Alison Goss Eng DOE - EERE

Martin Keller ORNL

Blake Simmons SNL

Kenneth Kern NETL

Tom Foust NREL

Adam Bratis NREL

Ted Krause ANL

Michael Wang ANL

Seth Snyder ANL

Jonathan Male PNNL

Mike Thompson PNNL

Tom Tarka NETL

Sam Tam DOE - FE

Kevin Stork DOE - EERE

Stationary Efficiency

Building Efficiency 

(Systems and 

End Uses)

Roland Risser DOE - EERE

Tony Bouza DOE - EERE

Philip Farese NREL

Colin McCormick DOE - EERE

David Shum ARPA-E

Bing Liu PNNL

Paul Matthews LBNL

Paul Torcellini NREL

Amir Roth DOE - EERE

Michael McCabe DOE - EERE

Ravi Prasher ARPA-E
Introduction | 7

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

CONTINUED

Strategy Technology Team Member Organization

Stationary Efficiency

Building Efficiency 

(Systems and 

End Uses)

Jerry Simmons SNL

James McMahon LBNL

Ed Vineyard ORNL

Stationary Efficiency Industrial Efficiency

Isaac Chan DOE - EERE

Joe Cresko DOE - EERE

Jamie Link DOE - EERE

Aimee McKane LBNL

Richard Doctor ANL

Peter Fuhr ORNL

Phil Farese NREL

Tim Theiss ORNL

Osman Eryilmaz ANL

Ron Ott ORNL

Eric Masanet LBNL

Power Generation

Solar Photovoltaic and 

Concentrating Solar 

Power

Ramamoorthy Ramesh DOE - EERE

Marie Mapes DOE - EERE

Jesse Gary DOE - EERE

Robert Margolis NREL

Ryne Raffaelle NREL

Mike Pelin ANL

Mark Mehos NREL

Ben Kroposki NREL
 8 | Introduction

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

CONTINUED

DOE-QTR Technology Teams

Strategy Technology Team Member Organization

Power Generation

Wind, Geothermal, 

Water, and Fuel 

Cells for Distributed 

Generation 

JoAnn Milliken DOE - EERE

Mark Higgins DOE - EERE

Rajesh Dham DOE - EERE

Tien Nguyen DOE - EERE

Doug Hollett DOE - EERE

Fort Felker NREL

Trudy Forsyth NREL

Jose Zayas DOE - EERE

Walt Musial NREL

Daniel Laird SNL

Mike Sale ORNL

Brendan Smith ORNL

Bob Thresher NREL

Dave Stinton ORNL

Mike Penev NREL

Tom Williams NREL

Charlie Visser NREL

Power Generation

Nuclear, Carbon 

Capture and Storage, 

and Natural Gas

Jarad Daniels DOE - FE

Matt Crozat DOE - NE

Peter Balash DOE - FE

Jay Braitsch DOE - FE

Darren Mollot DOE - FE

Kenneth Kern DOE - FE

Sikander Khan DOE - FE

Chris Nichols DOE - FE

John Wimer DOE - FE

Matt Bowen NE

Philip Finck INL

Mike Goff INL
Introduction | 9

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

CONTINUED

DOE-QTR Technology Teams

Strategy Technology Team Member Organization

Power Generation

Nuclear, Carbon 

Capture and Storage, 

and Natural Gas

Marianne Walk SNL

Paul Kalb BNL

Steve Zinkle ORNL

Harold McFarlane INL

Madhava Syamlal NETL

Bryan Morreale NETL

Curt Oldenburg LBNL

Grid

Infrastructure and 

Power Electronics 

(Bulk System Physical 

Infrastructure, 

Hardware, and 

Planning)

Bill Parks DOE - OE

Kerry Cheung DOE - OE

David Meyer DOE - OE

Rajeev Ram ARPA-E

Jay Caspary SPP

Mike Ingram TVA

Juan Torres SNL

Carl Imhoff PNNL

Tom King ORNL

Tom Baldwin INL

Tom Schneider NREL

Grid

Measuring, Modeling, 

and Control 

(Information Technology, 

System Operation and 

Optimization, Microgrid 

Control)

Gil Bindewald DOE - OE

Carol Hawk DOE - OE

Charlton Clark DOE - EERE

Jeff Dagle PNNL

Joe Gracia ORNL

Joe Eto LBNL

Terry Oliver BPA

Jianhui Wang ANL

Dave Corbus NREL
 10 | Introduction

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Terry Boston, PJM Interconnection

Marilyn Brown, Georgia Institute of Technology

James Degraffenreidt, Jr., WGL Holdings, Inc.

Paul Dimotakis, California Institute 

of Technology

Hamid Elahi, General Electric

Robert Fri, Resources for the Future 

David Goldstein, Natural Resources Defense 

Council 

Charles Goodman, Tulane University

James Katzer, Iowa State University

Mark Lauby, North American Electricity Reliability 

Corporation

Nate Lewis, California Institute of Technology

Franklin Orr, Stanford University

Tom Overbye, University of Illinois, UrbanaChampaign

Jeffrey Peterson, New York State Energy 

Research & Development Authority

Per Peterson, University of California at Berkeley

William Powers, Ford Motor Company, Retired

Michael Ramage, Exxon Mobile Research and 

Engineering Company, Retired

Burt Richter, SLAC National Accelerator 

Laboratory

Maxine Savitz, Honeywell, Retired

Chris Somerville, University of California at 

Berkeley

Dan Sperling, University of California at Davis

Carl Weinberg, Weinberg Associates

Bob Williams, Princeton University

Kurt Yeager, Electric Power Research Institute 

DOE-QTR Technology Teams

Strategy Technology Team Member Organization

Grid Energy Storage 

(Temporal Flexibility)

Hank Kenchington DOE - OE

Imre Gyuk DOE - OE

Kerry Cheung DOE - OE

Mark Johnson ARPA-E

Ross Guttromson SNL

Landis Kannberg PNNL

The TAs have been reviewed in draft form by individuals chosen for their diverse perspectives and technical expertise. The purpose of this independent review was to provide candid and critical comments that assisted the 

QTR team in making the TAs as sound as possible. The following individuals reviewed one or more of the TAs:

This report is being disseminated by DOE. As such, the document was prepared in compliance with Section 515 

of the Treasury and General Government Appropriations Act for Fiscal Year 2001 (Public Law 106-554), as well 

as information quality guidelines issued by the Department. Further, this report could be considered “influential 

scientific information,” as the term is defined in the Office of Management and Budget’s Information Quality 

Bulletin for Peer Review (Bulletin). This report has been peer reviewed pursuant to section II.2 of the Bulletin.
Vehicle Efficiency | 11

VEHICLE 

EFFICIENCY

The assessments in this chapter form the technical base for Improving 

Vehicle Efficiency, a strategy detailed in the corresponding chapter of 

the Report on the Quadrennial Technology Review (QTR). Improving 

vehicle efficiency is the most effective short-term route to reduce liquid 

fuel consumption, and today’s technologies allow new vehicles to be 

twice as efficient as those they replace. This chapter discusses internal 

combustion engines, lightweighting, and aerodynamics; however, there 

are a number of other technologies that can improve vehicle efficiency. 

For more information, see the following reports published by the 

National Academies of Science and National Research Council: America’s 

Energy Future,

1

 Assessment of Fuel Economy Technologies for LightDuty Vehicles,

2

 and Technologies and Approaches to Reducing the Fuel 

Consumption of Medium- and Heavy-Duty Vehicles.

3

While each technology is presented here with a standalone assessment, 

the associated opportunities to impact the energy system are fully 

understood only within the context of an integrated framework that 

spans energy resource, supply, delivery, and consumption. The Report 

on the QTR presents an integrated framework of the energy system 

and contains the systems discussions that tie together these individual 

assessments.

The technology assessments in the Vehicle Efficiency chapter include:

•	 Internal Combustion Engines

•	 Lightweighting and Aerodynamics
 12 | Vehicle Efficiency

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Current internal combustion engines (ICEs) offer outstanding drivability and reliability at a low cost; they are 

able to use natural gas and biofuels, such as ethanol (more than 12 billion gallons in 2010) or biodiesel. Over 

the last 30 years, ICE emissions of criteria pollutants4 have been reduced by more than 99%, while performance 

has increased. ICEs are expected to maintain significant market share for many years in conventional vehicles, 

hybrid electric vehicles, and plug-in hybrid electric vehicles. Integrating electric hybrid powertrains with advanced engines will enable operation at higher efficiencies for additional fuel savings. 

Although ICE technology is more than a century old, there remain substantial opportunities to improve engine efficiency and reduce emissions. Innovations in combustion, emission controls, fuel and air controls, and 

turbomachinery have maintained or improved fuel economy, even as vehicle size and weight have increased. 

Further improvements will be driven by industry compliance with increasing fuel economy standards through 

20165

 and beyond.6 Technical opportunities for increased engine efficiency apply to a range of light-duty gasoline engines, light-duty diesel engines, and heavy-duty diesel engines.

Engine efficiency has improved as a result of reducing energy losses due to throttling, heat transfer, friction, 

exhaust energy, and unburned fuel. There are a number of technologies that have led to these energy-loss 

reductions. In a 2011 National Research Council (NRC) report,7 Tables S.1 and S.2 (pp. 2–3) list more than 30 

light-duty vehicle technologies—a mix of which can be implemented in the near term—including information 

about their effectiveness to improve vehicle fuel economy and estimates of technology costs in 2009 dollars. 

Similarly, a 2010 NRC report8 conducted a review of technologies for medium- and heavy-duty vehicles that 

could be implemented in the near term to improve fuel economy.

While all gasoline vehicles sold in the United States operate with stoichiometric combustion (needed for emission control by the now universal three-way catalyst), higher-efficiency lean-burn gasoline engines are entering 

non-U.S. markets with less stringent emissions regulations. Lean-burn gasoline engines could also enter the 

U.S. market without increasing criteria pollutants by building upon recent advances in after-treatment technologies for diesel engines.

VEHICLE EFFICIENCY

INTERNAL

COMBUSTION ENGINES
Vehicle Efficiency | 13

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Figure 1. Car Engine Technology Penetration After First Significant Use

100%

60%

80%

40%

20%

0%

Production Share

0 5 10 15 20 25 30 35

YEARS AFTER FIRST USE

Continuously Variable 

Transmission

Variable Valve Timing

Port FI Multi-Valve

Front Wheel Drive

Lockup

U.S. Environmental Protection Agency. (2010). Light-Duty Automotive Technology, Carbon Dioxide Emissions, and Fuel 

Economy Trends: 1975 through 2010. Page 69, Figure 28. (EPA-420-R-10-023). Washington, DC. Accessed at http://

www.epa.gov/otaq/cert/mpg/fetrends/420r10023.pdf 

The time it takes for market penetration of light-duty engine technologies varies widely—it can take 3–5 years 

for individual manufacturers to integrate a new technology into their fleet, 5–15 years to penetrate industrywide (Figure 1), and decades to penetrate the majority of the vehicle fleet. Since the invention and adoption 

of the three-way catalyst for emission control in the early 1970s (made possible only by implementation of 

unleaded gasoline), conventional engine efficiency has increased at a steady rate with some variation due to 

new emissions or fuel economy regulations. Regulation-accelerated deployment of advanced catalysts and the 

new Corporate Average Fuel Economy (CAFE) standards are expected to similarly drive deployment of other 

efficiency technologies. 

Diesel engines are also well-suited for light-duty vehicle applications, offering an improvement in fuel economy. 

Diesel engines can achieve 20%–30% higher fuel economy than conventional gasoline engines; they account 

for nearly 50% of new car sales in Europe.9

 Diesel engines re-entered the U.S. passenger vehicle market in 2006 

following engine innovations and ultra-low sulfur diesel fuel, which enabled the machinery to achieve required 

emission levels. However, diesel penetration in the U.S. light-duty vehicle market has been small, primarily due 

to the additional cost of the engine and emission control components, as well as the price of diesel fuel. In 

addition, there is a misperception that emissions from modern diesel engines have disproportionately adverse 

health impacts when compared to other engine technologies, which limits penetration.
 14 | Vehicle Efficiency

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

0.60

0.55

0.50

0.45

0.40

0.35

0.30

Brake Thermal Efficiency

1960 1980 1980 1990 2000 2010 2020

CALENDAR YEAR

2002: EGR

2007: DPF, ULSD

2010: SCR

DPF = diesel particulate filter. ULSD = ultra-low sulfur diesel. EGR = exhaust gas recirculation. SCR = selective 

catalytic reduction. HC = hydrocarbons. NMHC = non-methane hydrocarbons. PM = particulate matter. Adapted 

courtesy of Detroit Diesel Corporation. (2009). Dearborn, Michigan: Directions in Engine-Efficiency and Emissions 

Research Conference. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/deer_2009/session5/

deer09_kalish.pdf 

Figure 2a. Historical Progress in Heavy-Duty Engine Efficiency and the Challenge of 

Simultaneous Emissions Reduction: Efficiency

Heavy-duty diesel is the primary engine for commercial vehicles because of its high efficiency and outstanding 

durability. However, increasingly stringent emission standards over the last decade restrained efficiency gains 

while emissions were reduced by more than 95% (Figure 2a. and 2b.). As regulations for nitrogen oxides (NOx) 

and particulate matter emissions stabilized in 2010, further gains in efficiency are now seen as achievable.

Historically, efficient heavy-duty engine technologies have been quickly adopted by the commercial heavy truck 

fleet where fuel economy and fuel costs are major concerns and vehicle lifetime is shorter. At the level of an 

individual manufacturer, technologies can typically be implemented across a range of engine models within 

one year. Nationally, technologies developed for the Class 8 market (e.g., long-haul tractor-trailers) are typically 

implemented in three years or less. These technologies quickly penetrate into the Class 6 and Class 7 markets 

(e.g., delivery trucks, buses) because of the similarity of the vehicle classes.
Vehicle Efficiency | 15

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

20

15

10

5

0

2.0

1.5

1.0

0.5

0

Oxides of Nitrogen (g/bhp-hr)

Particulate Matter

1970 1975 1980 1985 1990 1995 2000 2005 2010

MODEL YEAR

Steady State Test

NOx

 + HC

NOx

(Unregulated)

NOx + HC

NOx

 + NMHC

Transient Test

NOx

NOx

PM (Unregulated)

 Urban Bus PM PM

90%

90%

Source: 21st Century Truck Partnership. (2006). Roadmap and Technical White Papers. (21CTP-0003). Page 11, Figure 

1.2. Washington, DC: Department of Energy, Office of Energy Efficiency and Renewable Energy. Accessed at 

http://www1.eere.energy.gov/vehiclesandfuels/pdfs/program/21ctp_roadmap_2007.pdf 

Current Industry 

With the exception of sharp declines in 2008 and 2009, energy consumption in the transportation sector has 

grown over the last several decades. This growth is partly due to an increase in miles driven, but is also the result 

of expanding market share for light trucks, which has limited improvements in CAFE for the overall fleet. The 

price of fuel is also an important economic factor that affects the number of miles driven by the current fleet, 

as well as consumer choices that determine the future fleet. The current state of the light-duty and heavy-duty 

vehicle industries is summarized in a recent market report.10

Technology Potential

The maximum efficiency of the slider-crank architecture that dominates current engines can be doubled to 

about 60% if cost is not a constraint.11 This could double the fuel economy of passenger vehicles and increase 

heavy vehicle fuel economy by more than 40%. However, commercially achievable fuel economies are constrained not only by basic chemistry and physics, but also by factors such as cost, consumer driving needs and 

comfort, and environmental regulations. Practical engine efficiencies will depend heavily on the targeted transportation sector; the cost-sensitive commercial trucking sector and its high rate of fuel use results in thermal 

efficiencies for heavy-duty engines that can be as much as 10% higher than light-duty engines.

Figure 2b. Historical Progress in Heavy-Duty Engine Efficiency and the Challenge of 

Simultaneous Emissions Reduction: Emissions
 16 | Vehicle Efficiency

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Near-term options to improve fuel economy were outlined in two recent NRC reports.12 Some of the options 

considered to have the most potential include: (a) lean-burn combustion; (b) homogeneous-charge compression ignition (HCCI); (c) variable compression ratio (VCR); (d) waste heat recovery; and (e) improved particulate 

and NOx aftertreatment. The Department of Energy (DOE) believes that these technologies have the potential 

to contribute to fuel economy improvements of 25%–40% for passenger vehicles and 20%–30% for commercial vehicles.13 Estimates of potential improvements afforded by these technologies vary and are not necessarily 

additive. Further, these technologies must be cost competitive to make a business case for market introduction if their benefits are to be realized. Cost estimates for these technologies vary greatly.14 The success of the 

combustion and emission control technologies is particularly impacted by, or dependent upon, the chemical 

and physical properties of fuels. This interdependence needs to be understood, and preferably exploited, to 

capture efficiency gains.

(a) Lean-Burn (stratified charge) Combustion 

Lean-burn combustion refers to a spark ignition (SI) engine operating with more air than is required to burn the 

fuel. The lean-burn engine with the greatest fuel-efficiency potential is the stratified-charge, lean-burn engine. 

In this type of engine, fuel is directly injected into the cylinder and timed so that a stratified, but combustible, 

fuel-air mixture occurs near the spark plug at the time of spark. The amount of fuel injected is used to control 

the power rather than restricting the intake air flow, as is done in the Port-fuel-injected (PFI) SI engines that are 

dominating the road today.

These engines—which are primarily for automotive and light truck applications—will operate on current gasoline and gasoline/ethanol blends. Moreover, this combustion approach is compatible with the industry trend 

toward engine downsizing and turbo-charging. All major automotive engine producers are investigating this 

technology because of its fuel-efficiency potential. Engines of this type have been produced in the past; however, only two (Mercedes and BMW) are in production today, and they are only being produced for the European market. 

The lean-burn technology will be more expensive than a 2009 baseline PFI-SI engine, but will most likely cost 

less than a 2010 emission-compliant diesel engine. Primary cost drivers include the need for lean NOx emission 

control technology and increased fuel injection system and control system costs. The principal barriers to this 

technology are inadequate understanding of the combustion system; lack of accurate computational models 

for rapidly developing, robust lean-burn combustion systems; and the need for low-cost NOx and particulate 

emission control technology for lean-burn combustion systems. 

(b) Homogeneous-Charge, Compression Ignition Combustion 

HCCI combustion refers to the general class of compression ignition, low-temperature combustion (LTC) strategies for engines. These range from LTC strategies that are more appropriate for diesel-like fuels (often called 

diesel LTC) to strategies that are more appropriate for gasoline-like fuels (most commonly called HCCI). Like 

lean-burn combustion engines, LTC combustion ignition engines operate with a high air-to-fuel ratio, and they 

control power through the amount of fuel injected. There is also long-term potential for even greater efficiency 

when using gasoline or dual fueling with gasoline and diesel fuel.15 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

All major light-duty and heavy-duty engine producers are investigating this technology because of its fuelefficiency potential and prospect for reducing emission control requirements relative to a high-efficiency diesel 

engine. General Motors and Daimler have built vehicles with prototype HCCI engines. Heavy-duty companies 

are widely employing higher fuel-injection pressures, advanced fuel-injection strategies, and exhaust-gas recirculation to force some of the fuel that was injected to burn under LTC conditions, thus minimizing engine out 

emissions.

LTC technologies will be more expensive than a 2009 baseline PFI-SI engine, but will most likely cost less than 

a 2010 emission-compliant diesel engine. Primary cost drivers relative to the PFI-SI will be associated with the 

control system, with fuel injection system and emission control system adding additional costs. Principal barriers include the need for improved understanding of LTC combustion that will allow operation and control 

over the full speed range; lack of accurate computational models for rapidly developing, robust LTC combustion systems; and the potential need for unburned hydrocarbon and carbon monoxide exhaust aftertreatment 

technology for lower-temperature exhaust gases.

(c) Variable Compression Ratio 

VCR could increase efficiency and improve emissions by better matching the compression ratio to engine speed/

power demands. For example, medium- to high-load operation in SI gasoline engines requires a sub-optimal 

spark timing to avoid engine knock. The ability to adjust the compression ratio would allow for more efficient 

spark timing over a wider operating range. Estimated efficiency improvements are 2%–6% for light-duty and 

heavy-duty applications.16 The ability to adjust compression ratio on the fly also expands fuel flexibility by better matching compression and fuel properties. Another important application of VCR technology is enabling 

advanced combustion modes. For example, the sensitivity of HCCI combustion to in-cylinder charge conditions 

makes control of compression ratio necessary to enable and sustain HCCI combustion over a wider range of 

speed/load demands. 

This technology has been, and continues to be, investigated by engine companies, automobile companies, 

suppliers, and research institutions with both light-duty and heavy-duty vehicles. Approaches to VCR include 

using variable valve systems to control the effective compression ratio and new mechanisms to adjust the swept 

volume of the cylinder. VCR has many material, design, and durability challenges due to the harsh environment 

and cyclic loading on the piston, connecting rod, and crank shaft. 

(d) Waste Heat Recovery 

Substantial improvements in engine efficiency will require a reduction in thermal-energy losses. With less than 

half of the fuel energy converted to useful work in a modern engine, there are opportunities to improve engine 

efficiency through the recovery of pressure and thermal energy. Technologies under investigation include turbo-compounding, organic Rankine cycles, and thermoelectric generators. Turbo-compounding has been commercialized to a limited extent in heavy-duty vehicles, but will require further development for more widespread 

use. The other two technologies have not been commercialized for the conversion of waste heat to shaft or 

electrical power. All of these technologies have challenges related to packaging, cost, weight, and drive-cycle 

matching. The usage patterns of heavy-duty vehicles make them a good match for waste heat recovery. 
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(e) Improved Particulate and NOx Aftertreatment 

Particulate and NOx aftertreatment are required to ensure that current, advanced fuel-efficient engines can 

meet emission regulations. Aftertreatment technology is an essential part of the overall engine system. Any 

effort to improve the overall efficiency of this system must address the performance of the emissions controls. Specifically, improvements in aftertreatment effectiveness allow the base engine to be tuned into higher 

thermal-efficiency operation. Optimal fuel efficiency can be attained only through coordinated development of 

both components. Advanced aftertreatment technologies are new versions of catalytic converters that control 

pollution in the oxygen-rich exhaust system of lean engines; these catalysts are similar for both light-duty and 

heavy-duty vehicles. 

Research needs are twofold: (1) catalysts to cost effectively reduce particulate, NOx, carbon monoxide, and 

hydrocarbons with minimal impact on fuel efficiency that are intimately integrated with the engine system; 

and (2) advancements in catalysts to address changing exhaust conditions created by new, renewable/alternative fuels and new, fuel-efficient engine designs. Current catalyst technologies that meet existing regulations 

contain high levels of expensive platinum group metals, which raise total vehicle costs.

Basic research and unique scientific tools can advance combustion research in a variety of ways. Light-based 

examination of combustion phenomena helps provide the insight and data necessary to advance engine combustion technologies. X-rays of varying intensity produced at light sources enable investigation of combustion 

chemistries and dynamics over very short timeframes. X-ray-based capabilities, such as photoionization mass 

spectrometry, have validated combustion theory by confirming the existence of predicted chemical intermediates and enhanced understanding of the chemical mechanisms for engine combustion. Similarly, quantitative 

characterization of fuel spray and imaging of combustion in real engines under full engine speed and load 

have allowed manufacturers to improve component designs from fuel injectors to particulate filters. Longer 

wavelength lasers allow for real-time investigation of engine-based combustion kinetics and exhaust stream 

particulate matter. In combination with a large set of specially designed optically accessible engines and highpressure engine combustion simulators, such laser-based and optical diagnostics allow for investigation of the 

science behind advanced engine combustion approaches, such as stratified-charge ignition or HCCI.

Beyond photon examination, particles like neutrons enable non-destructive characterization and imaging of operating engines and components. Synthesis, modeling, and characterization of catalysts can be used to advance 

the state of exhaust emissions abatement technology for diesel- and gasoline-engine platforms.

Breakthrough Technologies

Advancing engine technology to improve automobile fuel economy by more than 50% and heavy-duty fuel 

economy by more than 30% will require industry to accelerate its pursuance of multiple product development 

cycles, even as it explores innovative designs. The co-evolution of fuels adds additional complexity and opportunities and further highlights the need for efficient product development. Design processes that over-rely on 

“build and test” prototype engineering are too slow. These challenges present a unique opportunity to marshal 

U.S. leadership in science-based simulation to develop new capabilities in predictive computational design and 

predictive simulation to enhance engine performance. Predictive computational design and simulation tools will 

shrink engine development timescales, reduce development costs, and accelerate time to market.
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A potential breakthrough engine design is a free-piston HCCI concept that uses a linear-motion piston that 

is not connected to a crankshaft, but rather coupled to a rebound device (e.g., another opposed combustion 

chamber); it produces electricity for a hybrid electric vehicle via a linear alternator.17 An electronically controlled 

VCR optimizes combustion phasing based on the fuel utilized and intake air/engine temperature. Data from 

single-shot, free-piston experiments demonstrated a thermal efficiency of around 56%. Work on a continuousrunning research engine would begin to quantify efficiencies achievable. Such a design could also find application in distributed power generation. 

Other breakthrough technologies could capture and use waste heat in the vehicle. Thermoelectric generators 

can convert engine waste heat directly to electricity to power vehicle auxiliary loads and accessories. With “zonal” or disbursed thermoelectric heating, ventilation, and air conditioning, the vehicle occupants can be cooled 

more directly than by cooling the whole cabin, thus providing a more energy-efficient alternative to currently 

used mobile air conditioners. Thermoelectric heating, ventilation, and air conditioning is a direct current system 

that can easily convert from cooling the vehicle to heating the vehicle. Over the next five years, production prototype first-generation thermoelectric generators, integrated with engine and electrical systems to augment a 

scaled-down alternator, are expected to be tested and evaluated to quantify real-world fuel economy improvements. A second-generation thermoelectric generator that uses better performing thermoelectric materials 

could eliminate the alternator entirely and improve the fuel economy of a passenger vehicle by 5%–7%. Such 

technologies could also be used for energy harvesting in the stationary sector. 

Assessment of Gaps

Technological barriers to the development of more efficient ICEs include the following: 

•	 Inadequate understanding of fundamentals of in-cylinder combustion/emission-formation processes 

and inadequate capability to accurately simulate them, as well as incomplete understanding and predictive capability for exploiting or accommodating the effects of fuel composition.18

•	 Lack of cost-effective emissions control to meet Environmental Protection Agency standards for oxides 

of nitrogen and particulate matter emissions at smaller penalty in fuel economy. 

•	 Incomplete fundamental understanding of, and insufficient practical experience with, new catalyst 

materials and processes for lean-burn engine emission control. 

•	 Lack of integrated computational models that span engine and emission control processes with vehicle 

loads to predict vehicle fuel economy improvements.

•	 Lack of effective engine controls to maintain robust lean-burn combustion for boosted, down-sized 

engines.

•	 Inadequate durability of new emission control systems for engines operating in novel combustion regimes that need to perform effectively for 120,000 miles in passenger vehicles and 435,000 miles for 

heavy-duty engines.

•	 Lack of actual emissions data on pre-commercial and future combustion engines (for evaluation of 

potential health impacts and unintended consequences).

•	 Lack of thermoelectric-based devices for waste heat recovery. Challenges include improving properties 

of thermoelectric materials, producing such materials at scales and in forms necessary for automotive 

applications, and validating performance in automotive environments (e.g., durability).

•	 High cost of more efficient ICE technologies (LTC engines are expected to be more expensive than 

conventional gasoline engines; thermoelectric devices add cost that must be offset by benefits).
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Past DOE Activities

DOE started pursuing engine research and development (R&D) in 1975 when it supported R&D that improved 

the original catalytic converters, as well as the first use of lasers to visualize the combustion process and emissions formation in an operating engine. 

DOE funding for advanced engine R&D has been relatively constant over the past decade, ranging from $40–

$60 million per year. Some of DOE’s accomplishments19 in light- and heavy-duty engine R&D include: 

•	 Providing tools and knowledge that have helped engine manufacturers improve heavy-duty diesel efficiency by 4%–5% since 2002, as well as heavy-duty engine manufacturers meet 2007 regulations 

that required a 90% reduction in particulate matter emissions4 and a more than 50% reduction in NOx 

emissions. Sandia National Laboratories developed a system of laser and optical diagnostics for optical engine experiments that allows researchers to view and measure detailed combustion processes 

and emissions formation as they occur in real time. These experiments, combined with new models of 

combustion, provided a new understanding of the combustion and emissions formation process in a 

diesel engine that differs significantly from the previous picture. 

•	 Spearheading the development of clean-diesel technologies for passenger vehicles in the 1990s that 

met Environmental Protection Agency 2009 Tier 2 Bin 5 standards as early as 2000, while also boosting 

fuel economy to 30% better than comparable gasoline-powered vehicles. DOE funded three competitively selected, cost-shared projects with diesel engine companies and partnered with passenger car 

original equipment manufacturers (OEMs) and their suppliers to develop diesel engines for light trucks.

•	 Supporting the development of industry-standard engine design software. The KIVA family of modeling software was developed by Los Alamos National Laboratory in collaboration with other national 

laboratories, universities, and industry. It is now used by all engine manufacturers in their engine-design processes. Using this software with data from the optical engine experiments, Cummins was able 

to reduce the development time and cost of its high-efficiency 2007 ISB 6.7-L engine by 10%–15%. 

•	 Supporting catalyst development that helped enable that same Cummins ISB 6.7-L engine to enter the 

commercial market in 2007, meeting the 2010 emission standards. R&D collaboration between Cummins, the company’s catalyst manufacturer Johnson Matthey, and national laboratory scientists used 

DOE’s national scientific facilities to identify and address problems of catalyst deactivation. This work 

enabled the first U.S. introduction of a new catalytic emission control technology, concurrent with the 

deployment of the high-efficiency engine.

•	 Establishing databases for fundamental reaction mechanisms and deactivation processes in new emission control technologies for high-efficiency, lean-burn gasoline and diesel engines. DOE’s collaboration with industry and university partners in the Cross-Cut Lean Exhaust Emissions Reduction Simulation project has identified promising emissions aftertreatment technologies. The collaboration also 

performed fundamental and applied R&D that was aimed at making these simpler and less costly than 

current technologies. Car manufacturers use the large Cross-Cut Lean Exhaust Emissions Reduction 

Simulation compilations of combustion and emissions data in their commercial product development. 

•	 Developing engine and emission control technologies in joint DOE/industry research efforts that were 

adopted by all major engine manufacturers, which enabled them to meet the 2007 heavy-duty emissions standards without efficiency losses.
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In addition to these successes, DOE research showed that specific engine technologies were unpromising. Sufficient cost and performance data were acquired to show that, at the time, the following had no clear efficiency 

and cost advantages, did not meet criteria pollutant standards, or both, for motor-vehicle applications. 

•	 Steam (Rankine cycle) engines (1960s)

•	 Stirling engines (1970s to early 1990s)

•	 Gas turbines (1970s to early 1990s)

•	 Rotary engines (1980s)

•	 Two-stroke engines (1980s to 1990s) 

•	 Adiabatic engines (1980s to early 1990s).

These judgments are revisited as technologies and needs evolve.

DOE Role

DOE’s R&D roles have been to:

•	 Facilitate development of precompetitive technical knowledge base through investments in fundamental and applied R&D

•	 Undertake mid- to long-term pre-competitive research

•	 Provide access to unique national laboratory expertise and facilities

•	 Help create a national consensus on R&D areas of common public and private interest

•	 Enable public-private partnerships to integrate R&D into industrially useful design tools.

DOE has set the following fuel efficiency demonstration targets for its activities on passenger and commercial 

vehicles: 

•	 By 2015: demonstrate engine efficiency improvements that advance the fuel economy of light-duty 

gasoline engines by 25% and light-duty diesel engines by 40%, compared to the baseline 2009 gasoline vehicle. 

•	 By 2015: improve heavy-truck engine thermal efficiency to 50% with demonstration in commercial 

vehicle platforms. This would be about a 20% improvement over current engine efficiency. 

•	 By 2018: further increase the thermal efficiency of a heavy-truck engine to 55%, which would be 

about a 30% improvement over current engines. 

Today, DOE supports a portfolio of engine activities that spans fundamental research, applied technology 

development, and technical support for technology maturation and deployment.20 Basic R&D in combustion 

chemistry, fluid dynamics, advanced laser diagnostics, and combustion model development supports applied 

R&D work. 

Leveraging unique, world-class theoretical and experimental capacity, major research facilities at the national 

laboratories accelerate industry and university R&D by providing capabilities that are too costly for users to 

support on their own. Experimental capabilities relevant to the ICE span from broadly used scientific platforms, 

such as light and neutron sources, to technology specific capabilities, such as engine combustion test beds.

Coupling simulation with experimental validation allows the Department to improve predictive models for the 

complex physics of ICEs, where improved models can accelerate the design of cleaner, more efficient engines.
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VEHICLE EFFICIENCY

LIGHTWEIGHTING 

AND AERODYNAMICS

Vehicle weight and aerodynamics are two major determinants of fuel economy beyond engine efficiency. Rolling resistance, which is related to vehicle weight, is the dominant energy-loss mechanism at low speeds, while 

aerodynamics is the dominant mechanism at high speeds. 

Lighter weight can significantly reduce a vehicle’s fuel consumption at all speeds. For example, a 10% reduction 

in the weight of an ICE vehicle can improve fuel economy some 6%–8%.21 Weight reduction in hybrid electric 

vehicles and plug-in hybrid electric vehicles can similarly increase electric range or overall vehicle efficiency. The 

benefits of lightweighting apply to all vehicle size classes, including heavy-duty trucks. 

Aerodynamic drag is primarily a function of vehicle speed, frontal area, and coefficient of drag. As vehicle frontal area increases, aerodynamics at common highway speeds (60–70 miles per hour) has an increasing impact 

on transport efficiency to the point where more than 65% of usable engine output for Class 8 trucks is used to 

overcome aerodynamic drag.22 Improving the aerodynamics of these vehicles could reduce their fuel consumption by up to 15%.23 There are smaller benefits to improving the aerodynamics of passenger cars, light trucks, 

and sports utility vehicles due to their lower average speeds, smaller frontal area, and better aerodynamic efficiency of current designs.
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Lightweighting

Following the fuel shortages and price spikes of the 1970s and 1980s, as well as the initial regulatory CAFE 

standards for light-duty vehicle fuel economy, average new car weights declined rapidly from about 4,000 

pounds to about 3,100 pounds. These weight reductions were achieved as manufacturers downsized models 

and introduced new materials, such as high-strength steel and lightweight plastics, that allowed for reduced 

thickness of metals in body structures. Following the plateau of CAFE standards in 1985, the market shifted 

toward larger and heavier vehicles. Additionally, manufacturers responded to increasing safety standards by introducing roll-over and side-impact structural reinforcements. These trends, as seen in Figure 3, have continued 

through 2010, and average new passenger car weights have increased from their minimum of 3,100 pounds 

in 1987 to about 3,600 pounds in 2010. In spite of this trend for increasing vehicle weight, today’s passenger 

car has better fuel economy than its 1987 counterpart.

4600

4200

3800

3400

3000

Vehicle Test Weight (lb)

TRUCKS CARS AND TRUCKS CARS

1975 1980 1985 1990 1995 2000 2005 2011

MODEL YEAR

Figure 3. Average Light-Duty Vehicle Weight, 1975–2009

Environmental Protection Agency. (2012). Light-Duty Automotive Technology and Fuel Economy Trends: 1975 

Through 2011. (EPA-420-R-12-001a). Washington, DC. Accessed at http://www.epa.gov/otaq/cert/mpg/

fetrends/2012/420r12001a.pdf
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700

600

500

300

400

100

200

0

Weight Per Vehicle (lb)

HIGH-STRENGTH AND MID-STRENGTH STEEL

MAGNESIUM

POLYMERS AND COMPOSITES

ALUMINUM

1975 1980 1985 1990 1995 2000 2005 2010

PRODUCTION YEAR

For the most part, these materials replace iron or mild-steel. Sources: Wards Communications. (2010). Ward’s Motor 

Vehicle Facts and Figures, 2010, Detroit, MI. Department of Energy. (2004). “Average material consumption for a 

domestic vehicle.” Vehicle Technologies Program Fact of the Week. Washington, DC. Accessed at http://www1.eere.

energy.gov/vehiclesandfuels/facts/2004/fcvt_fotw310.html

As shown in Figure 4, production vehicles have used increasing amounts of advanced materials since 1970: 

aluminum has increased by 84%, magnesium by 33%, high-strength steel by 77%, and composites by 70%. 

These materials, used in today’s cars, reduce weight by 10%.24 

Figure 4. Trends of Lightweight Materials Use in Vehicles
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Current Lightweighting Technology

Today’s average passenger car weighs 3,600 pounds (including passengers)25 and consists of the following materials: 54% iron or mild steel, 9.7% first-generation high-strength steel, 9.4% aluminum, 7.2% plastic, 4% 

glass, and 1% magnesium; the remaining 15% is a mixture of copper, paint, carpeting, padding, insulation, 

and rubber.26 The average selling price of a new car is about $28,000,27 or about $8/pound: raw materials cost 

about $0.60/pound, manufacturing and processing costs are about $4.50/ pound, and the remaining costs are 

shipping, OEM profit, and dealer mark-up. 

Light trucks and vans typically weigh 4,600 pounds28 and have a different architecture (body-on-frame versus 

unibody) and material make-up relative to passenger cars. Heavy-duty trucks typically weigh 18,000 pounds, 

use a body-on-ladder-frame architecture, and are designed to carry very heavy loads.29 The material make-up of 

heavy trucks is significantly different than that of light-duty vehicles, but their selling price is still about $8.00/

pound.

A passenger car’s weight is distributed across four major component groups:30,31

•	 Body 32.6%: The body consists of the body-in-white, closures (doors and hoods), windows, fenders, 

and bumpers. It is the primary structure enclosing the passenger compartment and provides primary 

crash protection; it links the cabin to the suspension and powertrain. Today’s bodies are typically about 

62% mild steel, 23% high-strength steel, 12% glass, and a mix of other materials.

•	 Chassis 18.1%: The chassis is the interface between the vehicle and the road. The chassis includes 

the suspension, steering, and brakes, along with tires and wheels. Today’s vehicle chasses are typically 

about 85% cast iron and steel, 10% rubber, 3% aluminum, and a mix of other materials.

•	 Powertrain 28%: The powertrain consists of the engine, transmission, driveline, axles, exhaust system, starter battery, and fuel system. Today’s vehicle powertrain is typically about 53% mild steel and 

cast iron and 33% cast aluminum, with the balance being a mixture of lead, fluids, plastic, and rubber.

•	 Interior 12.5%: The vehicle interior includes seats, air conditioning, instrument panel, center console, 

carpeting, and other components like sound systems. Today’s vehicle interiors are about 50% plastics 

and 30% mild steel, with the remainder being a mix of aluminum, magnesium, rubber, cloth, and 

numerous electronic devices.

Today’s vehicles are designed to make optimal use of commercial materials available to meet stringent cost, 

strength, weight, and durability requirements based on vehicle operational parameters and consumer preference.

Several commercially available materials, if able to meet cost and manufacturability targets, could be used for 

further vehicle lightweighting. These include carbon fiber composites, sheet aluminum, cast magnesium, and 

titanium. They are used in the aerospace industry, where cost targets are up to an order of magnitude higher, 

and production rates are several orders of magnitude lower than those of the automotive industry (see Figure 

5).
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8

6

4

2

Mild Steel

HSS

AHSS

Aluminum

Magnesium

Plastic/SMC

Glass Fiber

Carbon Fiber

Titanium Alloy

0

10,000

1,000

100

Material Density (g/cm3)

Yield Strength (MPa) and Cost ($/tonne)

YIELD STRENGTH DENSITY COST 

Adapted with permission from Lutsey, Nicholas P. (2010). Review of Technical Literature and Trends Related to 

Automobile Mass-Reduction Technology. (Research Report UCD-ITS-RR-10-10). Page 9, Figure 7. Davis, CA: Institute of 

Transportation Studies, University of California, Davis. Accessed at http://pubs.its.ucdavis.edu/publication_detail.

php?id=1390

There are a number of improved materials under development that may have application in vehicle lightweighting if technical, performance, manufacturing, and cost targets can be achieved. These materials include: nextgeneration high-strength steel (sheet), high-performance cast steel/iron, sheet magnesium, high-performance 

cast magnesium, high-performance cast aluminum, low-cost automotive-grade carbon fiber, hybrid carbon/

glass fiber composites, and low-cost titanium. Most of these materials are being developed and tailored to 

meet automotive requirements and have cost targets up to 50% less than commercially available aircraft-grade 

materials. A comparison of these materials’ properties, costs across a range of different components, and lightweighting potential relative to mild steel is shown in Table 1.

Figure 5. Materials Density, Strength, and Cost
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Material Density 

(g/cm3)

Strength/ 

Density

Modulus/ 

Density Cost

MassReduction 

Potential

Relative to Steel

Mild Steel 7.87 1.00 1.00 1.0 0%

High-Strength Steel 7.87 1.86 1.00 0.90–1.20 10%

Adv High-Strength Steel 7.87 3.00 1.00 0.80–1.50 10%–28%

Gen III High-Strength Steel 7.87 7.00 1.00 1.00–2.00 15%–30%

Ceramics 3.90 0.70 3.05 1.50–3.00 10%–30%

Sheet Molding Compound 1.10–1.90 4.39 1.16 0.50–1.50 20%–30%

Glass Fiber Composites 1.40–2.40 4.74 5.75 0.90–1.50 25%–35%

Plastics 0.90–1.50 0.82 0.08 0.70–3.00 20%–50%

Aluminum 2.70 3.95 1.02 1.30–2.00 30%–60%

Titanium 4.51 4.73 0.98 1.50–10.00 40%–55%

Metal Matrix Composites 1.90–2.70 5.41 35.28 1.50–3.0 50%–65%

Magnesium 1.74 3.66 1.02 1.50–2.5 30%–70%

Carbon Fiber Composites 1.00–1.60 20.9 5.41 1.50–5.0 50%–70%

Powers, W. (2000). “Automotive Materials in the 21st Century.” Advanced Materials Process. 157:38-44.

Table 1. Material Properties, Cost, and Lightweighting Potential Relative to Mild Steel

Technology Potential 

Industry experts have indicated that lightweighting activities should focus on minimizing vehicle weight while 

maintaining vehicle utility, size, and crash-safety performance. Industry and technical experts have projected 

that, by 2050, there is the potential to lightweight passenger cars between 20%–50%,32 resulting in fuel 

economy improvements between 15%–40%,33 respectively. The potential to lightweight light trucks and vans 

has been estimated to be 15%–50%, resulting in fuel economy improvements of 12%–40%. It has also been 

estimated that the freight efficiency of heavy trucks can be improved by up to 50% through a combination 

of lightweighting, aerodynamic drag reduction, and powertrain efficiency improvements.23 Because of the difference in architectures, production rates, operational requirements, and cost tolerances between cars, light 

trucks, vans, and heavy-duty trucks, each vehicle class may provide different opportunities to accelerate deployment of particular lightweighting materials.
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For maximum future vehicle lightweighting, each of the component groups discussed above must contribute 

to the weight reduction. An analysis by the 2011 Materials Roadmapping Workshop of the technical potential 

for lightweighting passenger cars out to 2050 is shown in Table 2. This analysis indicates a pathway to weight 

reduction that will require the vehicle body weight to be reduced by 65%, the chassis/suspension to be reduced 

by 55%, the powertrain to be reduced by 40%, and the interior to be reduced by 35%.34 Each of the four 

component groups has different physical requirements and will therefore require a different mix of engineering 

approaches and lightweighting materials. While cost is a significant determinant of technology deployment, 

cost targets are application-dependent.

Table 2. Timeline to Achieve Technical Potential for Lightweighting Conventional Passenger Cars

Component Group

% weight reduction

2020 2025 2030 2040 2050

Body 35% 45% 55% 60% 65%

Powertrain 10% 20% 30% 35% 40%

Chassis/Suspension 25% 35% 45% 50% 55%

Interior 5% 15% 25% 30% 35%

Completed Vehicle 20% 30% 40% 45% 50%

Department of Energy. Summary Report from the 2011 Advanced Materials Roadmapping Workshop (in draft). 

Detroit, MI. March 8–10, 2011.

Table 3 shows the lightweighting potential of various materials for different component groups, a description 

of current uses, and technical hurdles for lightweighting applications. Although Table 1 shows that titanium 

and metal matrix composites are among those materials with the greatest potential for weight reductions, the 

material properties and present manufacturability of many of these same materials limit their applicability. Other materials, such as carbon fiber composites, could substantially reduce weight in a number of applications. 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Material Current Applications Projected 

Applications

Technical Status 

and Hurdles

Cast Iron Powertrain and 

suspension Same

Baseline for mediumand heavy-duty (HD) 

engines: advanced HD 

engine requirements 

may exceed material 

properties

Mild Steel

Body, suspension, 

chassis, powertrain, 

and interior

Same Baseline material

High-Strength Steel Body, suspension, 

chassis, and interior Same Deployed, represents 

9% of vehicle mass 

Adv High-Strength 

Steel

Limited body, 

suspension, chassis, 

and interior

Body, suspension, 

chassis, and interior

In demonstration, on 

track for deployment

Gen III High-Strength 

Steel Early development Body, suspension, chassis, and interior

In alloy development, 

strength requirements, 

manufacturability, and 

cost

Ceramics Very limited powertrain Limited powertrain Material properties, 

manufacturability, cost

Sheet Molding 

Compound

Limited body and 

interior Body and interior In deployment; manufacturability, cost

Glass Fiber 

Composites

Limited body and 

interior

Limited body and 

interior; bridging 

technology for low-cost 

carbon fiber

Manufacturability and 

cost

Plastics Interior Same Is currently widely 

deployed

Aluminum - Sheet Limited body and 

interior Body and interior

Early deployment; 

manufacturability and 

cost

Aluminum - Cast Powertrain and 

suspension Same

Extensive use in lightduty engines; advanced 

engine requirements 

may exceed material 

properties

Titanium Very limited powertrain 

and suspension

Powertrain and 

suspension

Material properties, 

materials supply, 

manufacturability, cost

Table 3. Vehicle Materials, Technical Hurdles, and Applications
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Material Current Applications Projected 

Applications

Technical Status 

and Hurdles

Metal Matrix 

Composites

Limited powertrain and 

suspension

Powertrain and 

suspension

Material properties, 

manufacturability, cost

Magnesium - Sheet Early development Body and interior

Material properties, 

materials supply, 

manufacturability, cost

Magnesium - Cast Interior

Body, suspension, 

chassis, powertrain, 

and interior

Material properties, 

materials supply, 

manufacturability, cost

Carbon Fiber 

Composites

Very limited body and 

interior

Body, suspension, 

chassis, powertrain, 

and interior

Material properties, 

manufacturability, cost

While there is clear agreement that components using lightweight materials must meet existing safety requirements and OEM durability obligations, there is divergence on the cost targets that range from cost equivalence 

with the displaced conventional material to directly linking the value of displacing a pound in the vehicle to the 

current price of gasoline. There is consensus that the cost target for lightweighting will vary greatly (order of 

magnitude) from one component to another. It is clear that vehicle lightweighting becomes more commercially 

viable as the price of gasoline and demand for high fuel economy increase.

The approach to weight reduction in passenger cars is not to attempt to manufacture an existing design with 

substitute materials. Rather, efficient lightweight designs require a systems approach that redesigns the vehicle 

to take advantage of the unique attributes of specific lightweight materials. Each component of the vehicle will 

have different materials requirements. 

•	 Body: The lightweighting approach here is to use very high-strength sheet materials around the passenger compartment; lightweight sheet materials for enclosures (doors, trunk lid, hood); and a mixture 

of materials that provide strength, energy absorption, and lightweight in the crush zones. Benefits will 

occur over a series of steps as newer materials become technologically validated and economically viable. Advanced high-strength steel, Gen III high-strength steel, aluminum, and glass fiber composites 

are anticipated to play critical roles in achieving lightweighting goals to 2030. Carbon fiber composites, magnesium, advanced aluminum, and lightweight glazings are expected to be required to achieve 

long-term technical targets. 

•	 Suspension and Chassis: The lightweighting approach here is to use very high-strength sheet materials at the corner suspensions; lightweight high-strength cast materials at brakes; and a mixture of 

materials that provide strength, energy absorption, and lightweight at the engine and rear cradles. Advanced high-strength steel, aluminum, and glass fiber composites are anticipated to play critical roles 

in achieving near-term lightweighting goals to 2030. Carbon fiber composites, magnesium, aluminum, 

and titanium are expected to be required to achieve long-term technical targets.

“Baseline” means the historic or primary material used in vehicles.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

•	 Interior: Gen III high-strength steel, aluminum, magnesium, plastics, and glass fiber composites are 

anticipated to play critical roles in achieving near-term lightweighting goals. Carbon fiber composites, 

magnesium, aluminum, and plastics are expected to be required to achieve long-term technical targets. 

•	 Powertrain: Many of these components require substantial strength, high fatigue endurance, and 

high temperature tolerance. A key approach to lightweighting here is to increase the specific power 

density and efficiency of the engine. This will require materials with properties beyond current materials’ strength and thermal-performance limitations. High-performance cast steels, compacted graphite 

iron, cast aluminum, and magnesium are anticipated to play critical roles in achieving near-term lightweighting goals. Advanced cast iron/steel, advanced cast aluminum, compacted graphite iron, metal 

matrix composites, aluminum, ceramics, titanium, and carbon fiber composites are expected to be 

necessary to achieve aggressive, long-term technical targets. 

VEHICLE EFFICIENCY 

Integrated Computational Materials Engineering

Integrated computational materials engineering (ICME) is the optimization of a design (material, 

shape, and manufacturing method) that combines material models and data from different length 

scales (atoms up to bulk) and the processing history of the component or system. By integrating 

models for structure, processing, and performance across multiple processing steps, ICME enables 

optimization of product characteristics that are often difficult to relate, such as cost, chemistry, and 

structural performance. ICME is viewed as a promising method to accelerate materials research, 

improve design innovation, and reduce the cost of new product development. While the potential 

benefits of ICME are quite positive, considerable development is necessary. Computationally efficient models capable of crossing length scales have only been demonstrated for specific problems; 

empirically derived material properties limit the ability to explore beyond experimentally validated 

parameters; informatics and data integration tools in the materials community are far behind other 

fields such as biology. Preliminary ICME work is focused on solving industrially relevant materials 

problems. This will provide proof-of-concept and establish a baseline for continued improvement.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Several materials contained in the body and suspension and chassis have major impacts on long-term objectives: carbon fiber composites, magnesium, aluminum, and titanium. Some of the associated vehicle technologies also face additional technical hurdles as the operating parameters of the vehicle push traditional materials 

beyond their current physical properties. 

Beyond surmounting technical hurdles, manufacturers will need modeling and design tools that incorporate 

the properties of multiple materials into a single vehicle structure. Multi-materials’ vehicle structures will need 

advanced joining techniques that address the strength requirements of the joint while mitigating any undesired 

interactions or property differences between the joint materials. Recycling these complex vehicle systems will 

also challenge OEMs and recyclers as they try to minimize the production costs by recycling materials back to 

high-value products. 

Lightweight materials compete with existing steel manufacturing methods that produce parts rapidly and inexpensively. Most new materials will require new processing equipment, often displacing millions of dollars 

of serviceable equipment. As materials meet their technical targets, each OEM will evaluate their cost effectiveness relative to the OEM’s objectives, consumer preferences, and likely consumer payback based on the 

projected price of fuel. These internal analyses by OEMs will likely result in ad-hoc, early adoption of materials 

until these technologies are fully mature and can achieve their maximum market potential. A multi-material 

portfolio that can address near-, mid-, and long-term materials needs can mitigate deployment risks associated 

with a heterogeneous marketplace.

Aerodynamics

The objectives of vehicle aerodynamics are to reduce drag for improved vehicle efficiency, decrease wind noise, 

and prevent undesirable lift and side forces that could cause aerodynamic instability at high speeds. In some 

cases, it is also important to generate downward aerodynamic forces to improve traction and cornering abilities. 

Vehicle aerodynamics is typically studied using computer modeling and simulations and wind tunnel testing. 

At highway speeds, more than 50% of usable engine output goes to overcome aerodynamic drag.35 The drag 

force varies as the square of speed, resulting in significantly more power being needed to overcome drag at 

higher speeds. 

Passenger car designers over the past decades have substantially improved aerodynamics to attain higher 

speeds and improved efficiency; however, heavy vehicles (trucks) have not followed that path. Since the basic 

configuration of a Class 8 tractor-trailer has not changed in decades, there is significant room for improvements 

in aerodynamics and energy efficiency. However, these improvements may face regulatory and operational 

constraints.36
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

DOE Accomplishments 

DOE has maintained a materials research portfolio that is focused on addressing key issues that confront lightweighting. Materials developed through this research contribute to the continually improving benchmark for 

material properties and costs. In 2000, the potential of some of these technologies was demonstrated in the 

final product of the Partnership for a New Generation of Vehicles,37 in which OEMs used advanced materials to 

reduce the weight of a midsize passenger car by 20%–31%; however, those technologies did not meet cost 

targets for commercialization at that time. 

DOE’s technical advances have helped overcome some of the hurdles to advanced materials commercialization. 

Examples of DOE work to accelerate the development of lightweight materials and parts include: 

•	 Super plastic forming of aluminum, a low-cost process for forming sheet aluminum38

•	 Structural composite pickup truck beds using preform and liquid molding processes developed to reduce production costs39

•	 Carbon fiber body-in-white with a goal of 60% weight-reduction potential40

•	 Composite floor pan and processing methods for targeted use of composites realized a 33% weight 

savings41

•	 Design optimization of cast components demonstrated a 65% weight-reduction potential using advanced casting processes and lightweight metals42

•	 Magnesium engine cradle with a 35% weight reduction relative to aluminum43 

•	 Rear cradle using advanced high-strength steel demonstrated a 28% weight reduction with cost neutrality.44

In these examples, the weight reduction or weight reduction potential has been determined or estimated in 

comparison to a baseline industry component at the time the work was performed. 

DOE ROLE

DOE’s primary roles in vehicle lightweighting are in convening and providing capabilities in the basic and fundamental engineering sciences. The Department leverages industrial partnerships to establish R&D priorities45 that 

serve shared interests and advance the state of knowledge of novel material technologies. The Department’s 

strong materials science capabilities underpin efforts to better understand and address fundamental engineering science challenges related to the joining of dissimilar materials and corrosion resistance. Integrated computational materials engineering is an emerging discipline in which DOE is striving to leverage its capabilities 

in modeling and simulation and materials science to accelerate development of materials and manufacturing 

processes to help enable more rapid transformation of transportation technologies.46

DOE efforts to improve vehicle aerodynamics emphasize the advancement of tools for modeling and simulation. Because vehicle aerodynamic improvement is design-specific, DOE focuses on developing general tools 

and techniques that can speed up the design process, minimize physical testing requirements, and reduce 

process costs.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

1

 National Academies of Science. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National 

Academies Press.

2

 National Research Council. (2010). Assessment of Technologies for Improving Light-Duty Vehicle Fuel Economy. Washington, DC: 

The National Academies Press.

3

 National Research Council. (2010). Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty 

Vehicles. Washington, DC: The National Academies Press.

4

 U.S. Environmental Protection Agency. (2010). Our Nation’s Air: Status and trends through 2008. (EPA Publication No. EPA454/R-09-002). Research Triangle Park, NC.

5

 U.S. Environmental Protection Agency, U.S. Department of Transportation. (2010). Light-Duty Vehicle Greenhouse Gas Emission 

Standards and Corporate Average Fuel Economy Standards; Final Rule. Washington, DC: Federal Register. Accessed at http://

www.nhtsa.gov/staticfiles/rulemaking/pdf/cafe/CAFE-GHG_MY_2012-2016_Final_Rule_FR.pdf 

6

 U.S. Environmental Protection Agency, U.S. Department of Transportation. (2011). 2017-2025 Model Year Light-Duty Vehicle GHG 

Emissions and CAFE Standards: Supplemental Notice of Intent. Washington, DC: Federal Register Accessed at http://www.

nhtsa.gov/staticfiles/rulemaking/pdf/cafe/SNOI_2_for_2017on-09Aug11.pdf 

7

 National Research Council. (2010). Assessment of Technologies for Improving Light-Duty Vehicle Fuel Economy. Washington, DC: 

The National Academies Press.

8

 National Research Council. (2010). Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty 

Vehicles. Washington, DC: The National Academies Press.

9

 U.S. Department of Energy. (2010). Fact #644: October 11, 2010 – Share of Diesel Vehicle Sales Decline in Western Europe. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/facts/2010_fotw644.html 

10 U.S. Department of Energy, Vehicle Technologies Program. (2011). 2010 Vehicle Technologies Market Report. (ORNLTN-2011/28836). Oak Ridge, TN. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/2010_vt_market_rpt.pdf 

11 Oak Ridge National Laboratory. (2010). Report on the Transportation Combustion Engine Efficiency Colloquium Held at USCAR, March 3-4, 2010. (ORNL/TM-2010/265). Oak Ridge, TN. Accessed at http://feerc.ornl.gov/pdfs/Stretch_Report_ORNLTM2010-265_final.pdf 

12 National Research Council. (2010). Assessment of Technologies for Improving Light-Duty Vehicle Fuel Economy. Washington, DC: 

The National Academies Press. 

 National Research Council. (2010).Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty 

Vehicles. Washington, DC: The National Academies Press. 

13 U.S. Department of Energy. (2010). Vehicle Technologies Program Multi-Year Program Plan 2011-2015. Washington, DC. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/program/vt_mypp_2011-2015.pdf 

14 For a more detailed discussion on cost-estimate methodologies for light-duty vehicle fuel economy, see Assessment of Technologies for Improving Light-Duty Vehicle Fuel Economy, National Research Council, 2010.

15 The ideal fuel specifications for LTC are presently unknown. However, it is known that—in the lab—fuel efficiency can be enhanced even more; for example, by dual fueling with E85 and diesel fuel or biodiesel, thus indicating further long-term potential 

for fuel(s) designed specifically for LTC.

16 National Research Council. (2010). Assessment of Technologies for Improving Light-Duty Vehicle Fuel Economy. Table 8.1. Washington, DC: The National Academies Press. 

17 Van Blarigan, P. (2011). Free-Piston Engine. [Presentation at the 2011 Vehicle Technologies Annual Merit Review]. Washington, 

DC. 

18 For more information on this and other basic research needs of ICEs, see: U.S. Department of Energy. (2007). Basic Research 

Needs for Clean and Efficient Combustion of 21st Century Transportation Fuels. Washington, DC. Accessed at http://science.

energy.gov/~/media/bes/pdf/reports/files/ctf_rpt.pdf 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

19 U.S. Department of Energy. (2009). Advanced Combustion Engine R&D: Goals, Strategies, and Top Accomplishments. (DOE/GO102009-2762). Washington, DC. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/adv_combustion_goals.pdf 

20 Individual companies enter into a cooperative R&D agreement with a national lab that has special expertise to help address a 

particular technology barrier to their application of a specific breakthrough. Technology maturation stage is when the company 

further develops the technology before it is ready for deployment.

21 National Research Council. (2010). Assessment of Technologies for Improving Light-Duty Vehicle Fuel Economy. Washington, DC: 

The National Academies Press.

22 National Academies of Science. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National 

Academies Press.

23 National Research Council. (2010). Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty 

Vehicles. Washington, DC: National Academy Press. Accessed at http://www.nap.edu/catalog.php?record_id=12845 

24 Based on a 4,065 pound (lb) car using 310 lbs of aluminum, 12 lbs of magnesium, 630 lbs of high-strength steel, and 340 lbs of 

composites and plastics, assuming all materials replaced steel.

25 U.S. Environmental Protection Agency. (2009). Light-Duty Automotive Technology, Carbon Dioxide Emissions, and Fuel Economy Trends: 1975 Through 2009. (EPA420-R-09-014). Ann Arbor, MI. Accessed at http://www.epa.gov/oms/cert/mpg/

fetrends/420r09014.pdf 

26 Hall, J.N. (Speaker). (2011). Evolution of Advanced High Strength Steels in Automotive Application. Accessed at http://www.

autosteel.org/~/media/Files/Autosteel/Great%20Designs%20in%20Steel/GDIS%202011/20%20-%20Jody%20Hall%20-%20

Evolution%20of%20Advanced%20High-Strength%20Steels%20in%20Automotive%20Applications.ashx 

27 U.S. Federal Trade Commission. (2009). Facts for Consumers. Accessed at www.ftc.gov/bcp/edu/pubs/consumer/autos/aut11.

shtm. 

28 U.S. Environmental Protection Agency. (2009). Light-Duty Automotive Technology, Carbon Dioxide Emissions, and Fuel Economy Trends: 1975 Through 2009. (EPA420-R-09-014). Ann Arbor, MI. Accessed at http://www.epa.gov/oms/cert/mpg/

fetrends/420r09014.pdf 

29 Davis, S.C., et al. (2010). Transportation Energy Data Book: Edition 29. Oak Ridge, TN: Oak Ridge National Laboratory. Accessed 

at http://info.ornl.gov/sites/publications/files/Pub24318.pdf 

30 Stodolsky, F., Vyas, A., and Cuenca, R. (1995). Lightweight Materials in the Light-Duty Passenger Vehicle Market: Their Market 

Penetration Potential and Impacts. (ANL/ES/CP-84474). Argonne, IL: Argonne National Laboratory. 

 Bjelkengren, C. (2008). The Impact of Mass Decompounding on Assessing the Value of Vehicle Lightweighting (LFEE 2008-05 

Report). Cambridge, MA: Massachusetts Institute of Technology. Accessed at http://hdl.handle.net/1721.1/44384 

31 Lotus Engineering, Inc. (2010). An Assessment of Mass Reduction Opportunities for a 2017-2020 Model Year Vehicle Program.

Ann Arbor, MI.

32 National Academies of Science. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National 

Academies Press. 

 Lotus Engineering, Inc. (2010). An Assessment of Mass Reduction Opportunities for a 2017-2020 Model Year Vehicle Program.

Ann Arbor, MI.

 Lutsen, N., (2010). Review of technical literature and trends related to automobile mass-reduction technology. (Report UCDITS-RR-10-10). Davis, CA: University of California Davis. Accessed at http://www.arb.ca.gov/msprog/levprog/leviii/meetings/051810/2010_ucd-its-rr-10-10.pdf 

33 Lutsen, N. (2010). Review of technical literature and trends related to automobile mass-reduction technology. (Report UCDITS-RR-10-10). Davis, CA: University of California Davis. Accessed at http://www.arb.ca.gov/msprog/levprog/leviii/meetings/051810/2010_ucd-its-rr-10-10.pdf 
 36 | Vehicle Efficiency

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

34 U.S. Department of Energy, Vehicle Technologies Program. Heavy-Duty Vehicles Materials Technical Roadmap. Washington, DC. 

(REPORT FORTHCOMING)

 U.S. Department of Energy, Vehicle Technologies Program. Light-Duty Vehicles Materials Technical Roadmap. Washington, DC. 

(REPORT FORTHCOMING)

35 National Academies of Science. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National 

Academies Press. 

36 U.S. Department of Energy. (2009). Research and Development Opportunities for Heavy Trucks. Washington, DC. Accessed at 

http://www1.eere.energy.gov/vehiclesandfuels/pdfs/truck_efficiency_paper_v2.pdf 

37 National Research Council. (2001). Review of the Research Program of the Partnership for a New Generation of Vehicles: 

Seventh Report. Washington, DC: The National Academies Press. Accessed at http://books.nap.edu/openbook.php?record_

id=10180&page=2 

38 U.S. Department of Energy, Vehicle Technologies Program. (2009). FY 2009 Progress Report for Lightweighting Materials. p. 

2–57. Washington, DC. 

39 National Research Council. (2001). Review of the Research Program of the Partnership for a New Generation of Vehicles: Seventh 

Report. p. 59. National Academy Press: Washington, DC. 

40 U.S. Department of Energy, Vehicle Technologies Program. (2010). FY 2010 Progress Report for Lightweighting Materials. p. 

3–13. Washington, DC. 

41 U.S. Department of Energy, Vehicle Technologies Program. (2011). FY 2011 Progress Report for Lightweighting Materials. p. 4–3. 

Washington, DC. 

42 US AMP. (2008). AMD 601 High Integrity-Magnesium Automotive Components (HI-MAC). Slide 11. Washington, DC. Accessed at 

http://www1.eere.energy.gov/vehiclesandfuels/pdfs/merit_review_2008/lightweight_materials/merit08_mccarty_9.pdf 

43 U.S. Department of Energy, Vehicle Technologies Program. (2005). FY 2005 Progress Report for Automotive Lightweighting Materials. p. 58. Washington, DC. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/alm_05/2g_osborne.pdf 

44 U.S. Department of Energy, Vehicle Technologies Program. (2009). FY 2009 Progress Report for Lightweighting Materials. p. 

5–61. Washington, DC. 

45 See, for instance: http://www1.eere.energy.gov/vehiclesandfuels/technologies/materials/index.html 

46 National Research Council. (2008). Integrated Computational Materials Engineering: A Transformational Discipline for Improved 

Competitiveness and National Security. Washington, DC. Accessed at http://www.nap.edu/catalog.php?record_id=12199
Vehicle Electrification | 37

VEHICLE 

ELECTRIFICATION

The assessment in this chapter forms the technical base 

for Electrifying the Vehicle Fleet, a strategy detailed in the 

corresponding chapter of the Report on the Quadrennial 

Technology Review (QTR). Electrification (whether 

partial or full) provides fuel diversification beyond dropin hydrocarbons and therefore mitigates economy-wide 

impacts of oil price volatility. Electrification is more viable 

for light-duty than heavy-duty vehicles.

While each technology is presented 

here with a standalone assessment, the 

associated opportunities to impact the 

energy system are fully understood only 

within the context of an integrated 

framework that spans energy resource, 

supply, delivery, and consumption. The 

Report on the QTR presents an integrated 

framework of the energy system and 

contains the systems discussions that tie 

together these individual assessments.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Introduction

Degrees of electrification range from mild and strong hybrid electric vehicles (HEVs), through plug-in hybrid 

electric vehicles (PHEVs), to battery-powered all-electric vehicles (AEVs1) and fuel cell electric vehicles (FCEVs). 

Electrification Technology Adoption

Though petroleum presently powers over 90% of the Nation’s transportation, electric and fuel cell vehicles have 

been on American roads for decades. At the beginning of the 20th century, 34% of automobiles in New York, 

Chicago, and Boston2 were powered by electricity; fuel cells vehicles were first demonstrated in the 1960s.3 

However, neither technology has penetrated the contemporary market significantly due largely to cost, performance, and infrastructure challenges.

Three types of electric-drive vehicles are at different stages of technical maturity and market penetration: conventional HEVs, grid connected PHEVs and AEVs, and FCEVs. HEVs, first commercially introduced in 1999, now 

account for 3% of new light-duty vehicle sales (see Figure 6). More than 2 million HEVs have been sold in the 

United States,4 and more than 40 hybrid makes and models were available in 2011.5 

VEHICLE ELECTRIFICATION

VEHICLE 

ELECTRIFICATION
Vehicle Electrification | 39

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Figure 6. U.S. HEV Sales History 

400

300

200

100

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

0

4.0

3.0

2.0

1.0

0.0

Number of Vehicles (thousands)

Market Share (%)

YEAR

HEV SALES HEV MARKET SHARE

HEV sales are calendar year sales. HEV market share calculated against total light-duty vehicle model year sales. 

Sources: Alternative Fuels and Advanced Vehicles Data Center. (2011). Table: Light-Duty Vehicles Sold in the U.S.

Washington, DC: Department of Energy, Office of Energy Efficiency and Renewable Energy. Accessed at http://www.

afdc.energy.gov/afdc/data/docs/ldv_sales.xls 

Alternative Fuels and Advanced Vehicles Data Center. (2011). Table: HEV Sales by Model. Washington, DC: Department 

of Energy, Office of Energy Efficiency and Renewable Energy. Accessed at http://www.afdc.energy.gov/afdc/data/

docs/hev_sales.xls 

HEV powertrains are 5%–50% more efficient than traditional powertrains, depending on the degree of hybridization, the size of the battery, power electronics, and electric motor components, and the driving conditions. 

Micro-hybrids using lead-acid batteries that provide only start/stop capability, but no regenerative braking, have 

incremental costs of several hundred dollars, while PHEVs can have an incremental cost of more than $10,000. 

HEVs are roughly $2,500 more expensive than comparable conventional vehicles.6 

Grid-connected vehicles (PHEVs and AEVs) have recently come to market and manufacturers are expanding 

vehicle availability and consumer options. The Tesla Roadster, with a range greater than 200 miles, was the 

first production AEV to use lithium-ion batteries, and more than 1,500 cars have been sold since 2008. Tesla 

stopped production of the luxury Roadster in 2011 and is planning to bring the Model S to market by 2012. In 

2010, General Motors (GM) delivered the first mass produced PHEV (Chevy Volt) and Nissan delivered the first 

mass produced AEV (Nissan Leaf). Through February 2012, about 9,000 Chevy Volts and 11,000 Nissan Leafs 

have been sold in the United States. None of these is currently cost-competitive with comparable conventional 

vehicles.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

The Department of Energy (DOE) estimates that auto manufacturers would be able to domestically produce, 

subject to market conditions, more than one million PHEVs and AEVs by 2015.7 Electric drive vehicles have the 

potential to eventually be a large share of the light-duty fleet, as well as some share of the urban heavy-duty 

fleet. Projections of market penetration rates vary widely, ranging from less than 10% in 2050 to 90%–95% 

in 2050.8

Fuel cell vehicles (including 155 FCEVs built by GM, Ford, Mercedes, and Hyundai) have been tested through 3 

million miles of road travel. Industry and DOE are learning from the operating data from these FCEVs and approximately 60 U.S. hydrogen fueling stations. In 2009, seven of the world’s leading automakers issued a joint 

a Letter of Understanding9 in support of commercial introduction of fuel cell vehicles from 2015 onward and 

anticipated—subject to a variety of prerequisites and conditions—that a “few hundred thousand units” could 

be commercialized around the world over the initial products’ life cycles, although this is equivalent to less than 

0.1% of new vehicle sales projected over that timeframe. 

Batteries

Battery cost and performance are key determinants of the economics and utility of electric-drive vehicles, as 

batteries are a significant fraction of vehicle costs today. The recent cost history of PHEV batteries is shown in 

Figure 7. Research, expanded domestic manufacturing, and advances in consumer electronics reduced lithiumion battery costs from $1,000 per kilowatt hour (kWh) in 2008 to roughly $650/kWh today (Figure 7).11 The 

Department has contributed to this cost reduction through both research support and manufacturing grants. 

Historic milestones in the progress of battery technology include nickel/metal hydride batteries in the 1990s, 

which helped pave the way for HEVs, and lithium-ion batteries, first introduced for consumer products in 1990 

and now used in most AEVs. 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Figure 7. DOE Estimates of PHEV Battery Cost 

Baseline Cost

1200

1000

800

600

400

200

0

Cost ($/kWh)

2008 2009 2010 2011 2012 2013 2014 2015 2016

FISCAL YEAR

Projected Improvements Current Technology

Current technology costs are modeled at a production level of 100,000 units per year. DOE uses a standardized 

battery cost model developed in partnership with the U.S. Advanced Battery Consortium available at http://www.

uscar.org/guest/article_view.php?articles_id=143. Projected technology costs are based on DOE achieving its 

technical targets and are modeled using BatPaC,11 available at http://www.cse.anl.gov/batpac/ 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Technology Potential 

Battery technology is far from its theoretical limit. In the near term, within existing lithium-ion technology, 

battery energy density could be as much as doubled by high-capacity cathode materials, higher-voltage electrolytes, and the use of silicon or tin-based intermetallic alloys to replace graphite anodes. 

There is potential to improve battery storage technology and reduce costs from about $1,000/kWh in 2008 to 

$300/kWh by 2014, based on useable energy at the battery pack level, at a modeled annual production rate 

of 100,000 units (Table 4).

Table 4. Performance Requirements and Potential Costs of Electric Drive Vehicle Batteries

Energy Storage Goalsa HEV 

(2010)

PHEV 

(2015)

AEV 

(2020)

FCEV 

(2020)

Equivalent Electric Range, 

miles <1 10–40 200–300 330

Discharge Pulse Power (10 

seconds), kilowatts (kW) 25–45 38–50 80–120 80

Regenerative Pulse Power (10 

seconds), kW 20–25 25–30 40 N/A

Cold Cranking Power at -30°C 

(2 seconds), kW 5–7 7 N/A 5–7

Available Energy, kWh 0.3–0.5 3.5–11.6 40–60 100b

Calendar Life, years 15 10+ 10+ 15

Cycle Life, cycles 300,000 

shallow cycles

3,000–5,000 

deep cycles

1,000 deep 

cycles

1,500 1⁄4 tank 

to full

System Weight, kilograms 40–60 60–120 300 230d

System Volume, liters 32–45 40–80 133 200d

Operating Temperature Range, 

Celsius -30–52 -30–52 -40–85 -30–52

Production Cost at 100,000 

units/yearc N/A $270/kWh $150/kWh $33/kWd

Met in Production Vehicle Met in Demonstration Vehicle

Met in Laboratory Not Met

a

 As indicated, many of these metrics have been met in production or demonstration vehicles, but not at the cost 

goals.

b

 Based on total net power from 5.0 kg H2 fuel cell system at 60% conversion efficiency (lower heating value).

c

 Costs are for usable capacity.

d

 Fuel cell system includes fuel cell ($30/kW), H2 storage ($12/kWh), and all ancillary components (i.e., valves, 

regulators, mounting brackets, insulation, added cooling capacity, and/or other balance-of-plant components), 

excluding any hybrid battery or ultracapacitor. 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

These performance requirements were established in partnership with U.S. automakers12 and are reviewed and 

revised as necessary to reflect changing market conditions.13 Battery performance projections were developed 

using component modeling and simulation tools and hardware-in-the-loop simulations. They reflect the typical operation of a battery under standard drive cycles and are consistent with external technical assessments.14 

For example, batteries must be able to accommodate the power necessary to charge in a time compatible with 

consumer needs. Electric vehicles with longer electric ranges, and therefore batteries with higher capacity, will 

require higher power charging.

R&D Opportunities: Batteries 

Near-term applied research and development (R&D) should focus on lithium-ion batteries, including the development of cells using high-voltage (5V) and/or high-capacity (>300mAh/g) cathodes; alloy or lithium metal anodes; lithium/air and lithium/sulfur systems; and high-voltage and solid-polymer composite electrolytes. While 

lithium-ion batteries are currently used in electric vehicles, improvements are needed in thermal stability, deepdischarge cycle life, and cost.15 Additional research is required to develop additives that prevent overcharging, 

additives that form a good interface between the electrode and the electrolyte for improved life and fast charge 

capability, and electrolyte formulations and additives for low-temperature operation. As batteries become larger, abuse-tolerance becomes more of a concern and enhanced thermal management becomes more important. 

Nanoscale materials and architectures are important for electrical energy storage. There are also synergies between electrical energy storage materials and hydrogen storage materials, such as metal hydrides. Such materials can have superior performance in high pulse discharge, recharge power, and low-temperature operation. 

New diagnostic tools and techniques will be required to investigate these materials.

Battery recycling will be important as battery use grows because it both recovers high-value materials, providing 

cost savings and conserving finite resources, and avoids the costs and environmental concerns associated with 

battery disposal. Future activity is needed to develop battery recycling technology, improving the efficiency and 

cost effectiveness of current recycling processes, enhancing recycling processes to recover more materials, and 

restoring or refurbishing partially spent batteries to approach new-battery performance levels. Future research 

should address potential electric vehicle battery secondary use. Information on battery end-of-life performance 

should be collected, second-use applications evaluated, and testing conducted to assess the suitability of used 

batteries for secondary use.

Advanced battery prototyping can move new battery technologies closer to market by improving understanding of their behavior in simulated drive conditions. The design and development of pre-production battery prototypes provides valuable data that would assist in driving down battery cost through optimization of battery 

cell and pack designs.

Battery materials and cell manufacturing could benefit from incorporating automated and metrological methods into existing processes. 

Development of advanced, computer-aided engineering tools could accelerate design cycles, reduce the number of prototypes needed, reduce battery development cost, and provide a competitive advantage to U.S. 

original equipment manufacturers (OEMs), suppliers, and battery manufacturers.

Basic research needs for electrical energy storage and for hydrogen and fuel cells have also been identified.16 

Improved technical approaches for developing standards for battery design, performance ratings, commonality 

in labeling, and safety would further strengthen the industry. 
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Fuel Cells

Fuel cells convert the chemical energy in fuels, such as hydrogen or natural gas, directly into electricity. They 

do so without combustion by combining the fuel with oxygen from the air in an electrochemical cell. The only 

local product when hydrogen is used, besides electricity and heat, is water vapor–with no other emissions from 

the vehicle. However, commercial production of hydrogen is currently solely from fossil fuels.

In an FCEV, the fuel cell stack (the “stack,” composed of a number of individual cells) converts a fuel to electricity to power the electric motor. A small battery is typically included to provide additional power and take 

advantage of regenerative braking. FCEVs can be refueled in a few minutes, can be used for a wide range of 

vehicle sizes, and can achieve a driving range of more than 300 miles. However, the cost of fuel cells and the 

availability of a hydrogen production, distribution, and fueling infrastructure are major barriers. There are also 

additional technical barriers to FCEV deployment, including on-board hydrogen storage density, use of precious 

metal catalysts, and durability.

Fuel cell characteristics depend on the electrolyte used (e.g., phosphoric acid, molten carbonate, solid oxide, 

alkaline, and polymer electrolyte membrane fuel cells) and of these, the most widely used fuel cell in current 

prototype automotive applications is the polymer electrolyte membrane fuel cell. This is primarily due to their 

low-temperature operation (roughly 80°C), which allows for rapid start up and shut down and the good transient response required for a range of automotive operating conditions.

R&D Opportunities: Fuel Cells

The Department believes that continued R&D could possibly reduce fuel cell costs by an additional 40%,17

while doubling durability.18 This would make the total ownership costs (vehicles + fuel + maintenance) of 

FCEVs comparable to those of other advanced vehicle technologies. To enable these improvements, innovations are required to reduce fuel cell catalyst loading and to reduce the cost and improve the durability of hightemperature membranes, bipolar plates, and membrane electrode assemblies with high proton conductivity. 

The 50%–60% efficiency of fuel cell systems can be improved and future work in hydrogen storage packaging 

could improve practical ranges to more than 400 miles.19

Studies estimate that $2–$4 per gallon of gasoline equivalent (or “gge,” roughly equal to 1 kilogram (kg) of 

hydrogen) is required for FCEVs to be competitive.20 Reforming natural gas is the most mature and lowest cost 

method to produce hydrogen; it is used to produce over 90% of the 9 million tons of merchant hydrogen annually in the United States (equivalent in energy capacity to about 7% of today’s U.S. gasoline consumption). 

R&D has advanced the state of hydrogen production from distributed natural gas so that it could be technically 

possible to achieve high-volume production costs of approximately $3/gge.21 Documents provided by industry 

during the Report on the QTR process have indicated a more realistic high-volume cost of $7/kg over the near 

term.22 

Production of hydrogen from renewable sources (biomass, algae, solar, etc.) offers lower greenhouse gas 

emissions, but is less mature and more costly at present; there are also serious scaling issues in some of these 

sources. A primary R&D need to enable photoelectrochemical hydrogen production is to develop materials with 

the appropriate bandgap to both absorb sunlight and electrolyze water in a single device, rather than relying 

on electrolysis. Biological approaches require fundamental research in a number of areas, such as direct water 

splitting using microalgae or cyanobacteria and optimization in photosynthesis through genetic engineering of 

chlorophyll and efficient light utilization.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Hydrogen delivery research is needed to enable low-cost materials for high-capacity tube trailers and pipelines 

that are not susceptible to hydrogen embrittlement. Compressor and liquefaction technologies are also required to enable high-pressure (700 bar) refueling and efficient, high energy density liquid delivery. Additional 

long-term R&D is required to develop metal hydrides, sorbents, and chemical carriers that can store hydrogen 

at low pressures with maximum energy density and specific energy, while near-term needs include carbon fiber 

research to reduce the cost of high-pressure tanks. 

Novel approaches to addressing the infrastructure challenge include combined heat, hydrogen, and power 

(poly-generation or tri-generation) concepts using a high-temperature methane-powered fuel cell to provide 

both power and heat for buildings, as well as hydrogen for FCEVs. 

The DOE roadmap includes additional activities in manufacturing R&D, technology validation, safety, codes 

and standards, and systems analysis.23 Although transportation fuel cells have different requirements than stationary fuel cells, there are synergies in cost reduction that would benefit both applications. Increasing use of 

polymer electrolyte membrane fuel cells for other applications, such as backup power or small-scale combined 

heat and power, could improve manufacturing learning and help drive down the cost of automotive fuel cells. 

The Department’s perspective on FCEV pathways and costs24 was developed through numerous workshops and 

technical team meetings through the U.S. DRIVE government-industry partnership, which stands for Driving 

Research and Innovation for Vehicle efficiency and Energy sustainability; it is consistent with external assessments.25 Specific technical requirements developed by U.S. DRIVE are shown in Table 5.

Table 5. Projected Requirements for Fuel Cell Development

Characteristic 2010 Status 201726

Energy Efficiency @ 25% of Rated Power 59% 60%

Power Density 400 W/L 650 W/L

Specific Power 400 W/kg 650 W/kg

Production Cost at High Volumes $50/kW $30/kW

Durability with Cycling 2,500 hours 5,000 hours

Two other key requirements are onboard hydrogen storage density of 7.5% by tank weight and hydrogen fuel 

cost of $2–$4/gge, dispensed to the vehicle.

Factors that Affect Market Prospects

Widespread adoption will depend on the cost and durability fuel cells, low-cost and compact hydrogen storage 

systems, and the availability of a hydrogen infrastructure. While Japan and Germany have announced plans for 

up to 1,000 hydrogen stations,27 market penetration in the United States has been focused in California where 

plans call for up to 40 hydrogen stations funded primarily through state and industry activities. Industry plans 

in February 2009 included projections of approximately 50,000 FCEVs in California by the 2018 timeframe,28

or some 0.2% of the current California light-duty vehicle fleet, although deployments in the few years since 

publication have already fallen significantly behind initial projections.29 
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Electric Motors and Power Electronics

Because today’s electric propulsion components add significant cost to electric drive vehicles (e.g., $2,000 for 

a 100 kilowatt (kW) system not including the battery pack), R&D is needed to decrease cost, weight, volume, 

and improve thermal management of power electronics (inverters and capacitors) and electric motors. One issue with today’s technology is the rare earth metals required in permanent magnet motors, which are popular 

because of their high power density, specific power, and efficiency. Current production of rare earth metals 

is concentrated in China. Limited supply and sustained high costs of rare earth metals could impact the commercial viability of electric drive systems. 

While electric drive systems are more than 90% energy efficient, there are still opportunities to reduce cost, 

weight, and volume, while increasing efficiency and ensuring a domestic supply chain. R&D is needed on advanced packaging, enhanced reliability, and improved manufacturability. 

The recent cost history of electric traction drives is shown in Figure 8. DOE projected the cost of an electric drive 

system (not including the battery pack) that can deliver 55 kW of peak power for 18 seconds and 30 kW of 

continuous power, as estimated in high-volume manufacturing, will decrease from $22/kW in 2008, to $12/

kW ($7/kW for the motor) in 2015, and $8/kW ($4.70/kW for the motor) in 2020, while meeting performance 

requirements for power density, efficiency, and lifetime.

Baseline (Commercially Available Technology 2005)

40

35

25

30

20

10

15

5

0

Cost ($/kW Peak)

200520062007200820092010201120122013201420152016

FISCAL YEAR

Projected Improvements Current Technology

This figure is a ground-up cost estimate based on proprietary data and cost models developed by an industry OEM.

Figure 8. Electric Drive Cost
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

The projection of potential pathways and costs (Table 6) was developed through numerous workshops with 

industry experts and stakeholders (e.g., automakers, component suppliers, university researchers) and is consistent with external assessments.30

Table 6. DOE Technical Targets for Electric Traction System31

2010 2015 2020

Cost, $/kW <19 <12 <8

Specific power, kW/kg >1.06 >1.20 >1.40

Power density, kW/L >2.6 >3.5 >4.0

Efficiency (10%–100% speed at 20% 

rated torque) >90% >93% >94%

R&D Opportunities: Electric Motors and Power Electronics 

The opportunities in power electronics R&D are inverters and motors (permanent magnet and non-permanent 

magnet), Direct Current-to-Direct Current converters, Silicon Carbide/Gallium Nitride components, low-cost 

permanent magnet materials, high-temperature capacitors, advanced thermal systems, and motor control systems to meet future passenger vehicle hybrid systems requirements. Work in these areas will address the 

performance requirements for vehicle electrification, including utilizing power electronics to provide plug-in 

capability by integrating the battery charging function into the traction drive, thereby reducing electric propulsion system cost.

Other key areas of focus are capacitor dielectric material development, wide bandgap materials, and semiconductor power electronics packaging R&D. Extending beyond the transportation sector, advances in these areas 

can benefit a wide range of energy applications. 

Reducing the need for rare earth materials in electric motors is a key R&D priority.32 Specifically, near-term 

research will seek to reduce the amount of rare earth materials in current-generation magnets and to improve 

the performance of motor technologies that do not require permanent magnets. 
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Advanced Technologies

In addition to the technologies and roadmaps discussed above, several disruptive, breakthrough pathways for 

vehicle electrification can be imagined. These early-stage opportunities have not produced sufficient cost and 

performance data to be evaluated against the more developed pathways, but deserve further consideration 

for their significant potential.

Table 7. Technology Opportunities for Vehicle Electrification

DOE History and Accomplishments

The Department’s battery investments have yielded many advances, some of which have been adopted by 

industry. These include: 

•	 DOE-sponsored R&D created the nickel/metal-hydride battery technology upon which the batteries 

used in the Toyota Prius and many other HEVs are in part based upon.33,34

•	 Unique lithium-metal oxide electrode materials were developed at Argonne National Laboratory35 and 

have subsequently been licensed by GM and LG Chem Power for use in the Chevrolet Volt,36 with additional licenses to materials suppliers BASF, Toda America, and Envia Systems.

•	 Lithium-ion battery technology developed in part with DOE funding at Compact Power, Inc. (now 

named LG Chem Power) is being used in GM’s Chevrolet Volt; also selected for the upcoming Ford 

Focus AEV battery.37 

•	 HEVs on the market from BMW and Mercedes are using lithium-ion technology developed under 

projects with Johnson Controls-Saft, a company supported by DOE and industry through the U.S. 

Advanced Battery Consortium.38

•	 Eaton announced that it would use batteries from LG Chem Power for future Eaton hybrid drive heavy 

vehicles,39 while Johnson Controls-Saft began supplying lithium-ion battery packs to Azure Dynamics 

for electric delivery vans built on the Ford Transit Connect platform.40

•	 A123 Systems, started with the help of a DOE Small Business Innovation Research grant, will supply 

lithium-ion batteries for the Fisker Karma electric vehicle.41 

Technology Description

Lithium-Metal and Metal-Air 

Batteries (e.g., Lithium/air, 

Lithium/Sulfur)

Batteries that utilize metallic lithium anodes and/or air cathodes. 

These offer a potential 10x improvement in energy density and 5x 

improvement in cost over today’s lithium-ion batteries. 

Rare-Earth-Free Magnets and 

Electric Motors

Electric motors with magnetic materials that do not contain rare 

earths—either through non-rare earth magnet materials or new 

designs. These could reduce motor cost by 75% with no loss in 

performance. 

Platinum-Free Fuel Cells Eliminating platinum or other precious metals could reduce the cost 

of automotive fuel cell stacks by one-third. 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Over the past decade, DOE has invested approximately $150 million per year in R&D of transportation fuel 

cells, along with work on hydrogen production, delivery, and storage technologies. That investment has helped 

produce more than 300 patents and 30 commercial technologies, primarily early market applications and 

components.42 Examples include fuel cell catalysts and membrane technologies used by suppliers such as 3M, 

DuPont, and BASF.

By focusing on reducing the amount of platinum catalyst in fuel cells and improving power densities, R&D 

supported by DOE in conjunction with industry has helped reduce fuel cell cost in the last few years—more 

than 80% since 2002, from $275/kW43 to approximately $50/kW today, based on projections of costs to highvolume manufacturing (Figure 9).44 

300

250

200

150

100

50

0

FC System Cost ($/kW)

2002 2006 2007 2008 2009 2010 2011

YEAR

INITIAL ESTIMATE

STACK 

BALANCE OF PLANT (INCLUDES ASSEMBLY & TESTING)

$275/kW

$108/kW

$94/kW

$73/kW

$61/kW $51/kW $49/kW

Modeled costs are based on an analysis of state-of-the-art components demonstrated at the laboratory scale and on 

projection to high-volume manufacturing. Source: Hydrogen and Fuel Cell Technologies Program. (2011). DOE Hydrogen 

Program Record: Fuel Cell Systems Cost—2011. (Record #11012). Washington, DC: Department of Energy. Accessed 

at http://www.hydrogen.energy.gov/pdfs/11012_fuel_cell_system_cost.pdf

Figure 9. Modeled Fuel Cell System Cost at 500,000 Units (80 kW) per Year
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

DOE-funded efforts in the last 5 years have contributed to more than doubling the durability of automotive fuel 

cell systems operating under real-world conditions.45 A partnership of automobile and energy companies with 

DOE has also demonstrated 24 hydrogen stations and 155 FCEVs on the road, traveling more than 3 million 

miles. 

Innovations coming from the R&D of pre-competitive technologies have been transferred to and implemented 

by industry partners as a business case has developed for these technologies through the U.S. DRIVE publicprivate partnership.46 For example, advances in lithium-ion battery technology developed under the partnership 

have been transferred to the U.S. battery manufacturing facilities supported under the American Recovery and 

Reinvestment Act of 2009.

DOE Role

In vehicle electrification, DOE is expanding beyond the capability and informational roles to targeted initiatives. 

In addition to the fundamental engineering science and materials capabilities that the Department commits 

to electric vehicle R&D, DOE is pursuing an ambitious technical goal for batteries and electric drives, working 

with industry and academic partners toward that goal. In addition, DOE is using its convening power to bring 

together major standards-setting organizations, battery manufacturers, and automotive OEMs to speed the 

development and adoption of these standards. DOE continues to support basic and fundamental engineering 

research in these areas through diverse funding mechanisms from individual grants to Energy Frontier Research 

Centers to the batteries hub.47

In small-scale fuel cells for vehicles, DOE is focused on its informational and capability roles. As with batteries 

and electric powertrains, DOE’s convening power brings together stakeholders across the fuel cell industry, 

from fuel cell manufacturers to automotive OEMs to hydrogen suppliers.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

1

 We use the term “all-electric vehicle,” or AEV, for vehicles that carry no chemical fuel, but derive all of their primary energy from 

the electrical grid.

2 Sulzberger, C. (2004). “An Early Road Warrior: Electric Vehicles in the Early Years of the Automobile.” IEEE Power & Energy 

Magazine. 2(3):66-71. 

3

 Hakim, D. (2002). “An Electrovan, Not an Edsel.” New York Times. New York, NY. Accessed at http://www.nytimes.

com/2002/11/17/business/private-sector-an-electrovan-not-an-edsel.html?pagewanted=all&src=pm 

4

 Ward, J., and Davis, S. (2011). 2010 Vehicle Technologies Market Report. Washington, DC: Department of Energy. Accessed at 

http://www1.eere.energy.gov/vehiclesandfuels/pdfs/2010_vt_market_rpt.pdf 

5 U.S. Department of Energy. (2011). “Compare Hybrids Side-by-Side.” Washington, DC. Accessed at http://www.fueleconomy.

gov/feg/hybrid_sbs.shtml 

6 Oak Ridge National Laboratory. (2012) 2011 Vehicle Technology Market Report. (ORNL/TM-2012/016). Oak Ridge, TN. Accessed 

at http://cta.ornl.gov/vtmarketreport/pdf/2011_vtmarketreport_full_doc.pdf 

7 U.S. Department of Energy. (2011). One Million Electric Vehicles By 2015, February 2011 Status Report. Washington, DC. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/1_million_electric_vehicles_rpt.pdf. 

8

 Low estimate from Robert Lutz: Terlep, S. (2010). “GM Exec: Hybrids unlikely to take more than 10% of US market.” Market Watch. 

Accessed at http://www.marketwatch.com/story/gm-exechybrids-unlikely-to-take-more-than-10-of-us-market-2010-02-13 

High estimate from Electrification Coalition. (2009). Electrification Roadmap. Washington, DC. 

Electric Power Research Institute and Natural Resources Defense Council. (2007). Environmental Assessment of Plug-In Hybrid 

Electric Vehicles. Atlanta, GA, and Washington, DC.

National Academy of Sciences. (2009). Real Prospects for Energy Efficiency in the United States. The National Acadamies Press. 

Washington, DC.

9

 Daimler, Ford, GM/Opel, Honda, Hyundai/KIA, the Alliance Renault/Nissan, Toyota. (2009). “Letter of Understanding on the 

Development and Market Introduction of Fuel Cell Vehicles.” Accessed at http://www.cleancaroptions.com/Auto_OEM_letter_on_FCEVs.pdf

10 Current technology costs are modeled at a production level of 100,000 units per year. The Department of Energy uses a standardized battery cost model developed in partnership with the U.S. Advanced Battery Consortium, which is available at http://www.

uscar.org/guest/article_view.php?articles_id=143 

11 For more information about BatPaC, see: Nelson, P. A., Gallagher, K. G., Bloom, I., and Dees, D. W. (2011). Modeling the Performance and Cost of Lithium-Ion Batteries for Electric Drive Vehicles. (ANL-11/32). Argonne, IL: Argonne National Laboratory. 

Accessed at http://www.ipd.anl.gov/anlpubs/2011/10/71302.pdf

12 United States Council for Automotive Research. “Energy Storage System Goals.” Accessed on February 2, 2012 at http://www.

uscar.org/guest/article_view.php?articles_id=85 

13 U.S. Department of Energy. (2010). Vehicle Technologies Program Multi-Year Program Plan 2011-2015. Washington, DC. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/program/vt_mypp_2011-2015.pdf 

14 America’s Energy Future and the International Energy Agency’s Technology Roadmap for Electric and Plug-in Hybrid Electric 

Vehicles.

15 National Research Council. (2011). Assessment of Fuel Economy Technologies for Light-Duty Vehicles. Washington, DC. Available at http://www.nap.edu/catalog.php?record_id=12924 

16 U.S. Department of Energy. BES Workshop on Basic Research Needs for Electrical Energy Storage (EES), April 2–4, 2007; Basic 

Research Needs for the Hydrogen Economy, May 13–15, 2003.

17 The Department of Energy target for fuel cell cost is $30 per kilowatt in 2017, a 40% decrease from the 2011 cost of $49 per 

kilowatt. 
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 U.S. Department of Energy. (2011). Fuel Cell Technologies Program Accomplishments Fact Sheet. Washington, DC. Accessed at 

http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/accomplishments.pdf

18 McKinsey & Company/EU Powertrain Coalition. (2010). “A portfolio of power-trains for Europe: A fact-based analysis. The role of 

Battery Electric Vehicles, Plug-in Hybrids and Fuel Cell Electric Vehicles.” Exhibit 21. Accessed at http://www.europeanclimate.

org/documents/Power_trains_for_Europe.pdf

19 Wipke, K., et al. (2009). “Evaluation of Range Estimates for Toyota FCHV-adv Under Open Road Driving Conditions,” Savannah 

River Site, SC. National Renewable Energy Laboratory and Savannah River National Laboratory. (SRNS‐STI‐2009‐00446). Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/toyota_fchv-adv_range_verification.pdf

20 U.S. Department of Energy. (2011). “Hydrogen Threshold Cost Calculation.” Washington, DC. Accessed at http://www.hydrogen.

energy.gov/pdfs/11007_h2_threshold_costs.pdf 

21 Assumes widespread deployment of 500 fueling stations per year and production of 1,500 kilograms per day at each station.

National Renewable Energy Laboratory. (2006). “Distributed Hydrogen Production from Natural Gas,” Golden, CO. (NREL/BK-150-

40382). Accessed at www.hydrogen.energy.gov/pdfs/40382.pdf; 

22 Ex parte communications received by the Report on the QTR team from Air Products and Chemicals, Inc. on April 18, 2011. Available at http://energy.gov/downloads/qtr-ex-parte-communications

23 U.S. Department of Energy. (2007). Fuel Cell Program Multi-Year Research Development and Demonstration Plan. Washington, 

DC. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/mypp/index.html

24 U.S. Department of Energy. (2007). Fuel Cell Program Multi-Year Research Development and Demonstration Plan. Washington, 

DC. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/mypp/index.html

 U.S. Department of Energy. (2009). Fuel Cell System Cost for Transportation - 2008 Cost Estimate. Washington, DC. Accessed at 

http://www.hydrogen.energy.gov/pdfs/45457.pdf

 U.S. Department of Energy. (2004). Fuel Cell Roadmap. Washington, DC. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/program/fuel_cell_roadmap.pdf

25 Hydrogen Technology Advisory Committee. (2010). 2010 Annual Report of the Hydrogen and Fuel Cell Technology Advisory Committee. Washington, DC. Accessed at http://www.hydrogen.energy.gov/pdfs/2010_htac_annual_report.pdf

National Research Council. (2008). Transitions to Alternative Transportation Technologies - A Focus on Hydrogen. Washington, 

DC: National Academies Press. Accessed at http://www.nap.edu/catalog.php?record_id=12222

National Research Council. (2010). Review of the Research Program of the FreedomCAR and Fuel Partnership: Third Report.

Washington, DC: National Academies Press. Accessed at http://www.nap.edu/catalog.php?record_id=12939

26 U.S. DRIVE. (2012). Target Tables from the U.S. Drive Fuel Cell Technical Team Technology Roadmap. Washington, DC. Accessed 

at http://www.uscar.org/guest/teams/17/U-S-DRIVE-Fuel-Cell-Tech-Team 

27 International Partnership for Hydrogen and Fuel Cells. (2010). 2010 Hydrogen and Fuel Cell Global Commercialization & Development Update. Berlin, Germany. Accessed at http://www.iphe.net/docs/Resources/IPHE_FINAL_SON_press_quality.pdf

28 California Fuel Cell Partnership. (2009). Hydrogen Fuel Cell Vehicle and Station Deployment Plan. West Sacramento, CA. Accessed at http://www.fuelcellpartnership.org/hydrogen-fuel-cell-vehicle-and-station-deployment-plan 

29 Initial projections called for 370 FCEVs deployed in California by the end of 2010, as well as 712 FCEVs by the end of 2011. 

30 National Research Council. (2010). Review of the Research Program of the FreedomCAR and Fuel Partnership: Third Report. 

Washington, DC: National Academies Press. Accessed at http://www.nap.edu/catalog.php?record_id=12939

The Electrification Coalition. (2009). Electrification Roadmap: Revolutionizing Transportation and Achieving Energy Security. 

Washington, DC.

Energy and Environmental Analysis, Inc. (2007). Technology and Cost of MY 2007 Toyota Camry HEV. Arlington, VA. (ORNL/TM2007/132).
Vehicle Electrification | 53

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Fessler, R. R. (2011). Assessment of Motor Technologies for Traction Drives of Hybrid and Electric Vehicles. Washington, DC: 

Department of Energy. (ORNL/TM-2011/73).

31 United States Council for Automotive Research. (2010). Electrical and Electronics Technical Team Roadmap. Washington, DC. 

Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/program/eett_roadmap_12-7-10.pdf. 

32 U.S. Department of Energy. (2011). Critical Materials Strategy. Washington, DC. Available at http://energy.gov/sites/prod/files/

DOE_CMS2011_FINAL_Full.pdf 

33 Ruegg, T. (2008). Linkages of DOE’s Energy Storage R&D to Batteries and Ultracapacitors for Hybrid, Plug-InHybrid, and Electric 

Vehicles. TIA Consulting, Inc. and 1790 Analytics LLC: Washington, DC. Accessed at http://www1.eere.energy.gov/ba/pba/pdfs/

vehicle_energy_storage_r_and_d_linkages.pdf 

34 EV World. (2002). “Texaco Ovonic Battery Systems Announces Award of Contract Under the FreedomCar Initiative.” Richester 

Hills, MI. Accessed at http://evworld.com/news.cfm?newsid=2568 

35 U.S. Patents 6,677,082 (2001); 6,680,143 (2001); and 7,135,252 (2006). Lithium metal oxide electrodes for lithium cells and batteries.

36 General Motors. (2011). “GM and LG Chem Sign Deal with Argonne to Use Advanced Battery Material for Next Gen Ghevy 

Volt.” Accessed at http://gm-volt.com/2011/01/07/gm-and-lg-chem-sign-deal-with-argonne-to-use-advanced-battery-materialfor-next-gen-chevy-volt/ 

37 Ford. (2010). “Ford Selects Compact Power as Lithium-Ion Battery Pack Supplier for Ford Focus Electric on Sale in 2011.” Dearborn, MI. Accessed at http://media.ford.com/article_display.cfm?article_id=32959 

38 U.S. Department of Energy. (2008). Energy Storage Research and Development: 2008 Vehicle Technologies Program Annual Progress Report. Washington, DC. Accessed at http://www1.eere.energy.gov/vehiclesandfuels/pdfs/program/2008_energy_storage.pdf 

39 Eaton. (2010). “Eaton Selects LG Chem Subsidiary to Supply Battery Technology for Hybrid Power Systems; Battery Cells to be 

Manufactured in Holland, Mich.” Holland, MI. Accessed at http://www.eaton.com/Eaton/OurCompany/NewsEvents/NewsReleases/CT_288654 

40 Ford. (2010). “Michigan Gov. Granholm Hails Collaboration by Ford, Azure Dynamics, Johnson Controls-Saft and AM General 

to Deliver New Ford Transit Connect Electric.” Oak Park, MI. Accessed at http://media.ford.com/article_display.cfm?article_

id=33278 

41 A123 Systems. (2010). “A123 Systems Signs Multi-Year Battery System Supply Agreement with Fisker Automotive.” Watertown, 

MA. Accessed at http://ir.a123systems.com/releasedetail.cfm?ReleaseID=437662 

42 Pacific Northwest National Laboratory. (2010 and 2011). Pathways to Commercial Success: Technologies and Products Supported 

by the Fuel Cell Technologies Program.

43 http://www.hydrogen.energy.gov/pdfs/5005_fuel_cell_cost.pdf

44 U.S. Department of Energy. (2011). FY 2010 Progress Report for the DOE Hydrogen Program. (DOE/GO-102011-3178). Washington, DC.

45 Fuel Cell Technologies Program. (2012). Accomplishments Fact Sheet. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/accomplishments.pdf

Fuel Cell Technologies Program. Multi-Year Research, Development and Demonstration Plan. Accessed at http://www1.eere.

energy.gov/hydrogenandfuelcells/mypp/index.html

46 Driving Research and Innovation for Vehicle Efficiency and Energy Sustainability, formerly the FreedomCAR and Fuels Partnership.

47 U.S. Department of Energy. (2012). “Opportunity: Energy Innovation Hub-Batteries and Energy Storage.” Washington, DC. Accessed at https://www.fedconnect.net/FedConnect/?doc=DE-FOA-0000559&agency=DOE

Alternative Hydrocarbon Fuels | 55

ALTERNATIVE 

HYDROCARBON 

FUELS

The assessment in this chapter forms the technical base 

for Deploying Alternative Hydrocarbon Fuels, a strategy 

detailed in the corresponding chapter of the Report on the 

Quadrennial Technology Review (QTR). Liquid hydrocarbon 

fuels will remain important to the transportation sector 

for the foreseeable future. This technology assessment 

describes the pathways to producing non-crude-derived 

hydrocarbon fuels.

While each technology is presented here with a standalone 

assessment, the associated opportunities to impact the 

energy system are fully understood only within the context 

of an integrated framework that spans energy resource, 

supply, delivery, and consumption. The Report on the QTR 

presents an integrated framework of the energy system 

and contains the systems discussions that tie together these 

individual assessments.
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Petroleum-derived gasoline and diesel are the primary fuels for transportation, both domestically and globally. 

While efficiency and electrification can reduce light-duty vehicle dependence on oil, other segments of the 

transportation sector (e.g., heavy-duty vehicles, airplanes, and civilian ships) will continue to require the energy 

density of liquid fuels. Alternative (non-crude-derived) liquid fuels for these markets are therefore necessary to 

further reduce greenhouse gas (GHG) emissions. Feedstocks and conversion pathways that generate diesel and 

jet fuels may therefore have greater long-term significance than gasoline substitutes. Feedstocks for alternative 

fuels include both fossil fuels (i.e., natural gas and coal) and biomass (e.g., sugar- and starch-based crops, crop 

residues, woody biomass, plant-derived lipids). All alternative fuels have significant barriers related to energy 

density, cost of production, infrastructure compatibility, materiality of impact, and/or ease of transport and use.

Brazil and the United States lead the world in production of biofuels (primarily ethanol). Several other countries 

have developed ethanol programs, including China, India, Canada, Thailand, Argentina, Australia, Colombia, 

and European Union member countries.1

 Global ethanol fuel production was some 22.5 billion gallons in 

2010,2 roughly 10% of global gasoline consumption by volume. This level of production allows reliable estimates of feedstock costs, cost of production, fuel characteristics, and GHG emissions.

In 2010, the United States produced 13 billion gallons of ethanol from corn grain, an 800% increase from 

2000.3 That production accounted for 10% by volume (7% by energy) of motor gasoline consumption. A more 

modest rate of increase in ethanol production from corn grain is expected over the next 10 years.4 Biodiesel 

produced from oilseed crops peaked in 2008 at 691 million gallons (some 1% of diesel consumption) and declined to 315 million gallons in 2010.5

 

Other alternative hydrocarbon fuels currently deployed include compressed natural gas (CNG), propane, and 

liquid petroleum gas; however, these fuels supply less than 0.2% of the energy used by the transportation sector, the majority of which is in fleets.

ALTERNATIVE HYDROCARBON FUELS

ALTERNATIVE 

HYDROCARBON FUELS
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Figure 10. Summary of Feedstocks, Pathways, and Products for 

Alternative Hydrocarbon Fuels

Cellulosic Sugar Platform

Pyrolysis Oil Platform

Fast

Pyrolysis Upgrading Liquid

Bio-Oil

Syngas Platform

Gasification Filtration &

Clean-up

Raw

Syngas

Lipid (Oil) Platform

Algal and

other Bio-Oils Catalytic Upgrading

Transesterification

Other Enzymatic/Biochemical Methods

FEEDSTOCKS PRODUCTS REFINING

PLATFORMS/PATHWAYS

Feedstock

Production

& Logistics

Energy Crops

Agricultural

By-Products

Waste Streams

Algae

Coal

Natural Gas

Ethanol

Methanol

Butanol

Olefins

Aromatics

Gasoline

Diesel

Jet

Dimethyl

Ether

Heat and

Power

Co- or ByProducts

Power

Enzymic

Hydrolysis Sugars Fermentation

Alternative hydrocarbon fuels comprise a wide variety of molecular structures, including alcohols and other 

oxygenates, as well as drop-in hydrocarbons. These fuels can be made from a wide variety of carbon sources. 

Conversion pathways include enzymatic and thermochemical, among others (Figure 10). The cost of producing alternative fuels is dependent on feedstock price (including production, processing, and transportation), 

conversion, and distribution (including potential infrastructure changes).

Certain fuel characteristics, including GHG intensity and domestic provenance, are determined by the feedstock. Although oil resources of differing quality have unique lifecycle carbon characteristics,6

 the U.S. Environmental Protection Agency has established a baseline for conventional fuel GHG intensity.7

 In general, 

biomass-based fuels typically have lower carbon intensity than fossil-based fuels (Figure 11). Recent analyses 

have indicated that certain alternative fossil-based fuels coupled with carbon sequestration technologies could 

approach carbon intensities similar to their petroleum-derived counterparts; however, these studies are based 

on models and assumptions that have not been validated in commercial facilities and therefore may not be 

realistic for actual operation.8,9 
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Biofuels made from the sugars, starches, lipids, and lignocellulosic components of biomass can serve as substitutes for petroleum-based fuels. Renewable biological feedstocks include grains, oilseeds, sugars, perennial 

grasses, energy crops, agricultural and forestry residues, municipal solid waste, and algae. Biofuels conversion 

processes based on these feedstocks vary significantly in their technical maturity, economics, potential materiality, and production infrastructure required. Comprehensive analyses of biomass feedstock production, cost, 

and technologies can be found elsewhere.10 

The social, economic, and environmental effects of domestic biofuels have been mixed. Diverting corn, soybean oil, or other food crops to biofuel production could induce competition between food, feed, and fuel, 

but increases in crop price have helped to revive rural economies. On a global scale, high commodity prices are 

expected to accelerate clearing of rain forest and savanna.

Figure 11. Lifecycle Carbon Emissions for Various Transportation Fuels

1.2

1.0

0.8

0.2

0.4

0.2

0.0

-0.2

-0.4

-0.6

-0.8

CTL CTL-CCS Corn

Ethanol

Cellulosic

Ethanol

BTL BTL-CCS CBTL CBTL-CCS Gasoline

New CO2 (Tonnes per Barrel 

Gasoline – Equivalent Product)

The GHG emissions from some alternative fuels are less than those from conventional fuels, while others are higher. 

The production and extraction of feedstocks also have environmental impacts. CTL = coal-to-liquids, CCS = carbon 

capture and storage, BTL = biomass-to-liquids, CBTL = coal-and-biomass-to-liquids. There are many analyses for 

lifecycle carbon emissions from transportation fuels available, each with a unique perspective. This was adapted from 

America’s Energy Future Panel on Alternative Liquid Transportation Fuels. (2009). p. 250. Washington, DC: National 

Academy of Sciences, National Academy of Engineering, National Research Council. Accessed at http://www.nap.edu/

openbook.php?record_id=12620&page=250
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Sustainably produced biomass might provide additional benefits beyond GHG emission reduction, such as 

lowering the risk of forest fire (by removing excess combustible biomass), increasing crop yield (by harvesting 

otherwise wasted corn stover), reducing the need for landfills (by using municipal solid waste), and restoring wildlife habitat (by reestablishing diverse prairies for growing dedicated fuel crops). However, any direct 

conversion of natural ecosystems into cropland to accommodate dedicated biofuel crops could threaten those 

ecosystems and incur losses of biomass and soil carbon to the atmosphere that exceed associated GHG savings. 

In addition, removing biomass and crop residues could increase soil erosion and deplete soil carbon reserves, 

ultimately affecting water entry, retention, runoff, nutrient cycling, productivity, and other critical functions. 

Therefore, a systems approach is required for sustainable biomass production to ensure that it has a low impact 

on global food, feed, and fiber production, and to make sure that addressing the biofuel problem does not aggravate other challenges.11 More comprehensive analyses of the social, economic, and environmental impacts 

of expanded biomass feedstock production are available elsewhere.12

The energy needs of the transportation sector are significant. The masses of coal and natural gas used today 

are comparable to that of petroleum, while the availability of biomass feedstock is small by comparison. One 

estimate of potential sustainable biomass production by 2030 is more than 1 billion tons annually.13 Since 

1 billion tons of biomass could produce about 60 billion gallons of fuel, or 1/4 of current U.S. consumption,14 

biofuels could have a material impact on the nation’s fuel supply. 

The carbon flows of various feedstocks in the United States are a convenient, albeit imperfect, gauge for their 

significance in the economy, as all alternative hydrocarbon fuels must contain carbon. Figure 12 shows annual 

U.S. carbon content in various substances. Gasoline and diesel fuels contain 450 million tonnes (Mt) of carbon. 

To have a substantial impact on oil consumption (say at the level of 15% or more), a non-oil feedstock containing at least 70 Mt of carbon is required, assuming 100% conversion efficiency, as illustrated by the green line.15

Among other fossil fuels, the carbon flow in today’s coal use is of sufficient scale, natural gas is somewhat 

smaller (350 Mt), and other fossil fuel streams are smaller yet. Using these feedstocks for transportation fuels 

would require either diverting that flow from current uses (power and heat generation) or increasing resource 

production. 

Among the agricultural sources, there is about 100 Mt of carbon content in the annual, edible U.S. corn crop, 

which would enable it to displace as much as 20% of transportation fuels if most other uses were curtailed; 

the other agricultural streams are far too small to be material. Municipal waste,16 if fully exploited, could reach 

the 15% threshold. There is currently about 100 Mt of carbon from biomass supplying the energy sector. As 

described above, recent estimates of 1 billion tons of potential annual sustainable biomass production, which is 

equivalent to about 500 Mt carbon, could make a difference. Increasing the production of biomass feedstocks 

to these levels would have direct and indirect environmental impacts, ranging from residue removal to land-use 

change.
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The molecular composition and associated characteristics (e.g., infrastructure compatibility, energy density) of 

a fuel are determined by the conversion pathway. This assessment focuses on liquid hydrocarbon fuels and is 

organized according to three conversion pathway categories: biochemical, thermochemical, and “other.” Gaseous hydrocarbon fuels, such as CNG and propane, are mature technologies with principal challenges related 

to infrastructure. Detailed discussions of those technologies have been published elsewhere.18

Fuels generated by the three conversion pathways could displace, or at least supplement, the petroleumderived gasoline, diesel, and jet fuel that dominate the domestic and global markets. The three pathways and 

their feedstock resources differ in their technological maturity, economics, and lifecycle GHG emissions. 

600

500

400

300

200

100

0

Gasoline

Diesel

Coal

Natural Gas

Other Crude Oil

Corn

Soy

Woodpulp

Wheat

Paper

Edible Fats & Oils

Meat & Poultry

Cotton

Biomass Today

Biomass Potential (2030)

Municipal Solid Waste

U.S. Annual Carbon Source (million tonnes)

15% transportation fuels

PETROLEUM-DERIVED FUELS OTHER FOSSIL FUELS AGRICULTURAL SOURCES

BIOMASS FOR ENERGY MUNICIPAL SOLID WASTE

Figure 12. Annual U.S. Carbon Flows (in MtC)

As shown by the height of the green line, some 70 Mt of carbon in non-oil feedstocks would be required to replace 

15% of current transport fuels if no carbon were lost in the conversion process. Existing technologies are about 50% 

efficient at converting feedstock to fuel.17
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Prior to 2012, there were two key policy drivers associated with biofuel production: the Renewable Fuel Standard (RFS) and the Volumetric Ethanol Excise Tax Credit. To stimulate U.S. biofuels production, Congress initiated an expanded RFS program, referred to as RFS2, as a component of the Energy Independence and Security 

Act of 2007. The RFS2 set a goal of 36 billion gallons per year of renewable transportation fuels by 2022, 

of which a maximum of 15 billion gallons may be corn ethanol and a minimum of 21 billion gallons will be 

advanced biofuels.19 The Volumetric Ethanol Excise Tax Credit was a tax incentive ($0.45/gallon) for ethanol 

blenders that ended in December 2011. 

Without mandates, deployment of alternative fuels depends on their cost relative to the petroleum-derived 

incumbents with which they compete. Cellulosic or algal fuels must also overcome other challenges, including 

high construction costs for demonstrations and first-of-a-kind commercial facilities; lack of financing options; 

and technical, environmental, and safety requirements at scale. As the scale of biofuels production increases, 

so do concerns related to land use, biodiversity, and water availability. 

As with biomass-derived fuels, the military and aviation communities have expressed interest in the ability 

of synthetic fuels produced from coal, biomass, and natural gas to replace petroleum-derived fuels. Various 

military and commercial aircraft have been tested and certified to use blends of up to 50% synthetic fuels and 

50% petroleum-derived fuels. Because the Energy Independence and Security Act of 2007 prohibits the federal 

government from purchasing alternative fuels whose use results in greater lifecycle GHG emissions than petroleum-derived fuels, coal will be suitable as a feedstock only if it is blended with biomass and if it incorporates 

carbon capture and storage (CCS) in the conversion process. 

Biomass Feedstock Processing

To enable widespread commercialization of advanced biofuels, biomass feedstock processing technologies 

must be commercially available, cost competitive, and sustainable. Opportunities to address these challenges 

include research on feedstock genetics and agronomy, the material properties of biomass, and sustainable 

harvesting. Other opportunities include development of quality and monitoring processes; improved systems 

for storage, material handling, and transportation; and integration and scale-up of components into processing 

systems. Algal feedstock processing presents its own set of challenges that it must overcome, many of which 

are the same barriers faced by other feedstock processing.

In 2011, the Department of Energy (DOE) estimated that processing corn stover, a possible feedstock for biochemical conversion, would cost $37.80/dry ton if state-of-the-art technology were commercially scaled. Processing woody biomass, a more likely feedstock for thermochemical pathways, was estimated to cost $67.50/

dry ton at the 2010 state of technology.20 The Department projected potential cost reductions to $35/dry ton 

and $47/dry, respectively, by 2012.

Lipid feedstocks that are currently used to produce biodiesel, including soybean oil, are not considered advanced feedstocks. However, conventional biodiesel conversion technologies, such as the upgrading and isomerization of waste grease fats, could be adapted to advanced sources of lipids, including algae.
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Biochemical Methods

Biochemical conversion entails breaking down biomass to make the plant carbohydrates available for conversion into simple sugars, which can then be converted into biofuels using microorganisms and other catalysts. 

Cell walls are tough and complex structures that include long, strong, linear chains of sugars called cellulose 

and amorphous multi-sugar chains called hemicellulose. Biomass’ resistance to chemical breakdown (“recalcitrance”) must be overcome to access the sugars that can be, in turn, converted into fuels. Approaches include 

a combination of pretreatment, acid or enzymatic hydrolysis, and sugar conversion to alcohols or hydrocarbons; 

although, the diversity of feedstocks and the need to address substrate-specific issues does not allow for a 

single approach to biochemical conversion.

The pretreatment process breaks down hemicellulose into a mixture of soluble five- and six-carbon sugars and 

separates cellulose from lignin. This step makes the remaining cellulose more accessible for later enzyme hydrolysis,21 increasing its speed and productivity.22 A large number of pretreatment options are available,23 with each 

being suited to particular combinations of feedstocks and downstream conversion processes.22

Hydrolysis, also termed saccharification, is the process by which the cellulose is broken down into five- and sixcarbon sugars using either enzymes or acids,21 which often takes days.24 

Following hydrolysis, the released sugars are converted into fuel. This is often accomplished through biological 

processing (e.g., fermentation) to create alcohol fuels such as ethanol or butanol. Chemical or catalytic conversion can replace or supplement fermentation to convert hydrolysis products directly into desired fuel types. 

Although fermentation has been used for food and beverage production for millennia, chemical conversion 

of sugars into non-alcohol fuels is a newer, developing science. Commercial processes have not yet been developed that can achieve all of the desired parameters, including process efficiency, feedstock utilization, cost, 

sustainability, and finished product characteristics.25 Table 8 shows estimates of current conversion costs for 

corn starch and corn stover.

Most data on advanced biofuels come from laboratory and pilot-scale operations. More than 35 domestic 

biorefineries for cellulosic biomass are being designed or are in construction, many with federal financial support.29 Three commercial-scale facilities (one each in Denmark, Finland, and Singapore) are in operation and six 

commercial-scale biorefineries are expected to begin production in the United States in 2013 or 2014. These 

pioneer facilities will drive down cellulosic biofuel production costs through learning, process optimization, and 

technology improvements. Lessons learned will also reduce risk for future biofuels deployments. 

Emerging pathways that use current products as intermediates toward the conversion of higher-value end 

products could enable production of cost-effective, drop-in biofuels. These could include repurposing a corn 

ethanol refinery to convert isobutanol to butenes to diesel or jet fuel; conversion of clean sugars or starches to 

renewable jet fuel and diesel; conversion of methanol or ethanol to gasoline; and hydrolysis of pulp mills waste 

to provide clean, lower-cost, cellulosic-based sugars for drop-in fuel conversion. 
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Technology Headroom

Based on the current availability of feedstocks, DOE estimates that more than 400 million tons of biomass could 

be sustainably harvested in the United States each year. By 2030, this could increase to as much as 1 billion 

tons annually.30 This estimate does not include potentially significant sources of non-terrestrial biomass, such 

as algae.31 

Technology barriers in biochemical conversion include biomass variability and recalcitrance, pretreatment 

chemistry and costs, enzyme production costs and loading, cleanup/separations, catalyst development, process 

integration, and biochemical/thermochemical interfaces. Of these barriers, the greatest potential for overall 

conversion cost improvement lies in pretreatment (which mitigates the impacts of biomass variability and recalcitrance and can improve enzyme costs and loading), saccharification (which affects enzyme costs and loading), 

and fermentation (which affects separations and cleanup barriers).32 

Analysis is underway to determine the headroom for technologies related to the production of gasoline, diesel, 

and jet fuel.33

Breakthrough Technologies

There are a number of high-risk technologies still in their infancy that have the potential to transform biofuels. 

Table 9 summarizes these, along with an indication of hoped-for technical characteristics that, if achieved on a 

pilot scale by 2015, could justify continued research and development (R&D) interest. 

$/Gallon of Fuel

Conventional Corn Starch to Ethanol $0.7526

Biochemical Corn Stover to Ethanol $1.9527

Note: Conventional ethanol plant costs can vary widely. The cost given here is for a 100 million gallon per year 

nameplate capacity facility that operates at 110% capacity28 and was built in 2007. The plant produces 2.8 gallons of 

ethanol and 16.5 pounds of distillers dried grain per bushel of corn. Carbon dioxide is not captured. Assumed capital 

costs were $1.97/gallon of nameplate capacity. Capital and operating costs (primarily natural gas) are included, but 

the cost of feedstock is excluded to compare conversion technologies on a purely technology basis.

Biochemical corn stover to ethanol costs include all capital and operating costs for Nth plant with 2010 state of 

technology. Feedstock costs were left out to enable technology comparison. 

Table 8. Conversion Costs (in 2007 dollars)
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Technology Description

Sugar-Utilization or 

Biotransformation 

Catalysts

Develop organic/inorganic catalysts that utilize biomass intermediates 

(e.g., carbohydrates, lipids, proteins, acids) to produce green gasoline/jet/

diesel, biochemicals, or intermediates thereof via biochemical conversion 

processes. These fuels have energy densities at least 33% higher than 

ethanol. 

Thermochemical 

IntermediatesUpgrading Catalysts

Develop catalyst breakthroughs, which are integral to production of gasoline/

diesel/jet and products from biomass because they enable upgrading of 

biomass-intermediates (e.g., bio oils, synthesis gas, mixed oxygenates) 

created by thermochemical conversion routes. 

Uniform-Format Solid 

Feedstock Supply 

System34

Develop the ability to convert a diverse, low-density, perishable feedstock 

resource into an aerobically stable, dense, uniform-format, cost-effective, 

bulk-solid resource that can enter the existing agricultural bulk-solid 

commodity infrastructure.

Multipurpose and HighPerformance Biomass 

Feedstocks

Develop genetically tractable energy crops metabolic pathways that are 

enhanced or modified for production of renewable chemicals and commercial 

enzymes.

Table 9. Potential Biofuel Breakthroughs

Thermochemical Methods

Although thermochemical processes have been known for almost a century, they are not widely deployed commercially. Carbon is fungible; there are well-established thermochemical techniques to take carbon from one 

form (feedstock) and convert it into another (product), breaking or making carbon-carbon bonds and appending or removing hydrogen or oxygen. 

Thermochemical processes either convert a feedstock directly to a liquid fuel, or they convert a feedstock to a 

synthesis-gas intermediate (i.e., syngas—a mixture of hydrogen and carbon monoxide) that is then catalytically 

converted to fuels and/or chemicals. The former process is known as direct liquefaction, and the latter process 

is called indirect liquefaction, which is based on gasification. Thermochemical processes can be applied to coal, 

biomass, a combination of coal and biomass, or natural gas. While there is some potential for incremental 

technical improvements, the greatest hurdles to deployment of this technology are economic, not technical. 

Compared to other conventional methods for producing fuels, thermochemical conversion has both higher 

production and capital costs. Several facilities of this type have been built in other countries (see below), and 

industry is therefore well poised to deploy should economic conditions warrant.

Research opportunities in the thermochemical pathway for biofuels include biomass feedstocks tailored for 

gasification and pyrolysis systems, pyrolysis of biomass and bio-oil stabilization, syngas cleanup and conditioning, catalysts for fuel synthesis and intermediate upgrading, sensors and controls, and thermochemical process 

integration. Of these, the greatest potential for improvement lies in syngas cleanup and catalysis.35
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Indirect Liquefaction

After gasification, impurities like sulfur are removed and the syngas is converted into an ultra-clean transportation fuel via catalytic synthesis (most commonly using the Fischer-Tropsch (F-T) process). Globally, indirect 

liquefaction facilities that use F-T synthesis produce more than 370,000 barrels per day (bpd) of liquid fuels and 

specialty chemicals, which is about 0.4% of global liquid fuels production. Newer F-T facilities use natural gas 

as the feedstock for gasification; older facilities use coal. Syngas can also be converted to methanol and then to 

gasoline via the Mobil process. From 1985 to 1996, there was a plant in New Zealand using the Mobil process 

that had a production capacity of 14,500 bpd. While indirect liquefaction is a mature technology for converting 

coal and gas to liquids, incorporating biomass into these processes would require significant research, development, and demonstration.

The majority of thermochemical conversion R&D conducted in recent years has focused on the indirect liquefaction pathway. Table 10 shows the current state of these technologies.

Table 10. Current State of Technology for Producing Liquid Fuels Through Gasification

Pathway Maturity Global Deployment 

(largest facility)

Opportunities 

for R&D

Gas-to-Liquids (GTL) Commercially deployed 210 kbpd (140 kbpd)36 Limited

Coal-to-Liquids (CTL) Commercially deployed 163 kbpd (160 kbpd)37 Incremental changes

Coal- and Biomass-toLiquids (CBTL) Not yet demonstrated Not deployed Step changes

The United States presently has no major domestic facilities in operation for the production of synthetic fuel 

from coal and natural gas. Currently operating commercial and demonstration facilities are primarily located in 

Qatar, South Africa, Malaysia, and China.

Four gas-to-liquids (GTL) facilities worldwide produce more than 200,000 bpd of liquid fuels, lubricants, and 

specialty chemicals: two in Qatar (which began production in 2005 and 2011), one in South Africa, and one in 

Malaysia. Qatar accounts for more than 80% of the total production, and its facilities employ the latest technologies. These plants have been built to monetize stranded gas. GTL can be viewed as a commercial, but not 

fully mature, technology.

Three coal-to-liquids (CTL) facilities operate worldwide. A high-temperature F-T 160,000 bpd indirect liquefaction facility in Secunda, South Africa, was commissioned in the late 1970s. A 24,000 bpd CTL facility in Inner 

Mongolia, China, began production in 2010; the first commercial-scale direct liquefaction plant built in more 

than 60 years. Finally, an indirect liquefaction, methanol-to-gasoline (MTG) demonstration plant in Shanxi Province, China, began production in 2009. 

Table 11 provides a summary of the current technology status and costs of the different pathways for thermochemical conversion of biomass, natural gas, and coal. Although none of the operating facilities currently 

employ CCS, the cost of the CTL and coal and biomass to liquids (CBTL) pathways shown includes those costs. 

Using current technology, thermochemical conversion costs for woody biomass to ethanol via gasification 

would be about $2.50/gasoline gallon equivalent38 ($1.65/gallon) at scale (2,000 tonnes/day).
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Pathway

Installed 

Capital Cost 

($/daily 

barrel)

Crude Oil 

Equivalent 

Price39

$/gal 

PetroleumProduct 

Equivalent 

Price40

Technology 

Status

CTL w/ CCS F-T $130,000–

$150,000

$97/barrel 

(bbl) $2.8041 Not yet demonstrated

CBTL w/ 

CCS (15 wt% 

switchgrass)

F-T $140,000–

$160,000 $106/bbl $3.0041 Not yet 

demonstrated

GTL F-T $70,000–

$90,000

$80–$120/

bbl42 $2.30–$3.4043 Commercial

CTL w/ CCS MTG $140,000–

$160,000 $101/bbl $2.7044 Not yet 

demonstrated

Table 11. CTL, CBTL, and GTL Pathways, Costs, and Technology Status

Note: All costs are 2010 estimates of Nth plants expressed in 2009 dollars, with the exception of the MTG cost 

estimate, which is expressed in 2007 dollars.

National Energy Technology Laboratory. (2011). Production of Zero Sulfur Diesel Fuel from Domestic Coal: 

Configuration Options to Reduce Environmental Impact. Morgantown, WV. 

National Energy Technology Laboratory. (2010). Baseline Analysis of Sub-Bituminous Coal and Biomass to Gasoline 

(Indirect Liquefaction via Methanol Synthesis). DOE/NETL-40/092310. Morgantown, WV.

Memorandum from David Gray, Noblis, Inc., April 25, 2011.

Current studies suggest that45 GTL can be economically viable at crude oil prices above $80–$120/barrel (bbl), 

while CTL with CCS can be viable at crude oil prices above $97/bbl. The large capital outlays associated with 

CTL, CBTL, and GTL facilities—normally built at 50,000 bpd or greater to maximize economies of scale—present a significant risk to potential investors, especially given oil price volatility. At the capital cost shown in Table 

11, a 150,000 bpd CTL with CCS plant is a $14 billion bet that crude prices will average above $97/bbl over 

the amortization period. 

Because gasification produces relatively pure carbon dioxide (CO2

) streams, the incremental costs of CCS in a 

CTL or GTL process are only those of compression, transportation, and storage. The incremental cost of sequestering CO2

 captured at indirect liquefaction facilities in a geologic formation is less than $0.12/gallon of diesel.46

Advanced gasification technologies already in development could cumulatively reduce the crude oil break-even 

prices for CTL/CBTL systems by 25%.47 These technologies include warm gas cleanup/desulfurization; advanced 

turbines with higher firing temperature and capacity to improve efficiency and economy of scale; ion-transfer 

membrane for oxygen production to reduce capital costs; chemical looping integrated with the F-T system to 

reduce capital costs and increase conversion of carbon in coal to fuels; and compact gasification technologies, 

which can reduce cost and oxygen consumption.
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A DOE scoping study identified opportunities to achieve an 11% cost reduction at the pilot scale by 2022, 

which would enable F-T-based CTL with CCS systems to be commercially viable at a crude oil price of $86/bbl 

and CBTL48 with CCS systems viable at $94/bbl (2009 dollars).49 The study projected that commercial viability 

at crude-oil-equivalent prices of $73/bbl (CTL with CCS) and $80/bbl (CBTL with CCS) might be technically 

feasible by 2025. Advanced gasification technologies could also be applied to the CTL with CCS process for 

gasoline production, potentially enabling wholesale gasoline costs as low as $2/gallon by 2025.

To date, no detailed public analysis on the benefits of integrating advanced technologies into GTL systems has 

been done; however, modest cost reductions of 3%–6% by 2020 appear likely. These could reduce wholesale 

diesel prices to $2.20–$3.20/gallon at natural gas prices of $5–$10/one million British thermal unit, respectively. 

CTL, CBTL, and GTL systems would benefit from: (1) the system-level integration of state-of-the-art technologies, (2) the demonstration of facilities that integrate state-of-the-art technologies with carbon sequestration, 

and (3) the pursuit of advanced R&D that could dramatically reduce the costs of these systems. More information about CCS is contained in the Carbon Capture and Storage technology assessment.

Direct Liquefaction

Direct liquefaction involves the application of high pressure, high temperature, and a hydrogen source to coal, 

with or without biomass, in the presence of a catalyst. This technology pathway, which was developed with assistance from the U.S. government in the late 1970s and early 1980s, produces a crude-petroleum-like product 

that can be refined into transportation fuels. While direct liquefaction has recently been demonstrated in China 

at the 24,000 bpd scale, no facilities have been proposed domestically. As a less mature technology, cost and 

performance benchmarks for direct liquefaction are not well-established. Because of chemical differences in 

the feedstocks, the process to convert coal directly to liquids (direct liquefaction) is different from those that 

convert biomass directly to liquids (pyrolysis or other liquefaction techniques). Pyrolysis and other liquefaction 

processes result in liquid bio-oil intermediates that are catalytically upgraded to fuels and/or refinery-ready 

intermediate streams. Pyrolysis of biomass is currently more expensive than gasification, with an estimated 

conversion cost of woody biomass to gasoline or diesel of $5/gallon.50 

Algae and Other Conversion Pathways

Conversion of non-edible oils (e.g., from algae) and other hybrid approaches (e.g., fermentative conversion of 

syngas or catalytic conversion of sugars) leverage various combinations of biochemical, catalytic, and thermochemical technologies. Algae have long been cultivated for high-value products like pharmaceuticals. There is 

potential for material algae production and processing for fuels, but there are significant challenges in production and harvesting efficiencies and cost. The basic resources required for large-scale cultivation of algae 

for fuel production are land with suitable topography, climate, and sunlight; water of acceptable quality and 

abundance; and concentrated sources of CO2

. Many of the challenges related to algal biofuel production are 

engineering matters associated with how and where to grow the algae to achieve needed productivity. For 

example, closed photobioreactors can substantially lower the risk of culture contamination and the amount of 

water used, but capital costs of such systems are high. Technologies for developing algal strains with desirable 

traits for biofuel production include classical strain improvement, metabolic engineering, and synthetic biology. In addition, it is imperative to gain a better understanding of the environmental impacts of water use and 

disposal.51

The current minimum selling price for algal diesel via open pond-photo bioreactor is $8.70–$18.00/ gasoline 

gallon equivalent.52
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Natural Gas and Propane

Natural gas is already a significant alternative fuel in some applications, such as transit buses in the United 

States. It offers the potential for fuel cost savings, reduced dependence on oil, and decreased CO2 and other 

engine emissions. The barriers to natural gas deployment include limited availability of CNG refueling stations 

and CNG vehicles, as well as limited vehicle range. 

Fuels that are not fungible with gasoline and diesel fuels require new fueling infrastructure; fleet vehicles offer 

the most attractive opportunities due to the associated captive fleet fueling infrastructure. Natural gas vehicles 

(NGVs) are appearing in fleets of buses, refuse trucks, drayage trucks, and taxis.53 Worldwide, there are approximately 11 million NGVs. In the United States, there are approximately 100,000 NGVs in use, the vast 

majority of which are medium- and heavy-duty vehicles.54 NGVs comprise about 4% of the heavy-duty vehicle 

fleet. About 20% of transit buses in use (and 20% of new buses) are fueled by natural gas.

Greater market penetration of NGVs would require increased natural gas production. Satisfying 50% of current 

light-duty vehicle energy needs would increase natural gas demand by 30% (see Figure 13 in the Report on the 

QTR). Widespread penetration would also require considerable investment in natural gas fuel stations—today, 

there are roughly 160,000 retail fueling stations in the United States,55 but only 890 natural gas stations,56 not 

all of which are publically accessible. 

Table 12 summarizes the current costs associated with CNG fueling stations at a scale comparable to that of a 

retail gasoline fueling station.57 Such a natural gas (CNG or liquefied natural gas [LNG]) fueling station is estimated to have a capital cost of up to $2 million.58

There are relatively few LNG fueling stations because they are generally considered to be only for heavy-duty 

commercial vehicles. The cost of LNG fueling stations is approximately $20,000–$25,000 per truck serviced.59 

Globally, propane is the most widely used alternative fuel. Outside of the United States, propane—or liquefied 

petroleum gas—is commonly referred to as “autogas” when used as an automotive fuel. According to Energy 

Information Administration estimates, roughly 147,000 propane vehicles60 operate in the United States and 

use 130 million gasoline-equivalent gallons of propane fuel a year61 (which is a bit more than 0.1% of total 

gasoline use), while there are more than 14.5 million propane-fueled vehicles worldwide.62 Propane vehicles in 

the United States are primarily used in fleet or rural (e.g., farming) applications. Propane fueling stations, the 

most abundant of all alternative fuels, are unevenly distributed around the country.

Virtually all propane is produced as a co-product of natural gas processing or an oil refinery product. The world 

supply of liquefied petroleum gas grew steadily during the 2000–2008 period, from about 200 million tons in 

2000 (about 6.2 million bbl/day) to 239 million tons (7.7 million bbl/day) in 2008. 

Table 12. Estimated Costs of Natural Gas Fueling Station Components

Component Cost

Electric Compression Cost (estimated at 1kWh/gge) $0.09–$0.15/gge

Maintenance/Repair/Service Fund $0.15–$0.35/gge

Capital Amortization of Equipment $0.35–$0.65/gge
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Future Drivers and Directions

The greatest need for innovation within the natural gas pathway is fueling infrastructure improvements. A 

market is beginning to develop for LNG long-haul trucks. If the current price differential between natural gas 

and diesel fuel persists, as many believe is probable, LNG infrastructure will likely expand through private investment. The development of this market will primarily depend on sharing the operating cost benefit (i.e., lower 

natural gas price relative to diesel price) among the various market participants (i.e., trucking fleets, fueling 

station owners, and natural gas suppliers).

CNG, which is mainly used in heavy-duty vehicles, would be more viable as a light-duty vehicle fuel if lowcost home refueling appliances and bi-fuel gasoline-CNG vehicles were available to address consumer convenience concerns. Improved on-board gas storage—such as practical adsorbents, conformable CNG fuel tanks, 

or cheaper and lighter LNG tanks—could improve the viability of NGVs by extending the vehicle range.

Finally, as with all alternative vehicle technologies, more variety in original equipment manufacturer-integrated 

vehicle platforms and lower vehicle price premiums would encourage potential buyers of NGVs. This is particularly true for light-duty personal vehicles because consumers pay less attention than do commercial users 

to total cost of ownership relative to purchase price.63 Vehicle resale value is also a consumer consideration.

DOE History and Accomplishments

Biochemical Methods

From the 1970s to the present, DOE has invested more than $3.7 billion (including more than $900 million in 

American Recovery and Reinvestment Act of 2009 funds) in a variety of research, development, and demonstration programs covering the areas of biofuels (particularly cellulosic ethanol), biomass feedstocks, and bio-based 

products. Funding for this program has varied, with the bulk coming since 2005. The majority of DOE’s support 

has been for the development of biofuels technologies that do not depend on food crop feedstocks. DOE has 

provided analysis of the lifecycle impact of corn ethanol in comparison to fossil fuels and cellulosic biofuels. 

DOE-supported basic research includes genomics-based systems biology and work on the principles of catalyst 

design and catalytic transformations of biomass for the production of cellulosic biofuels. This research is led 

by three Bioenergy Research Centers.64 Development work has focused on improving engineering and process 

technologies, such as prehydrolysis, saccharification, fermentation, tar reforming, and fuel synthesis. In recent 

years, DOE has expanded its activities beyond alcohol fuels to renewable diesel, jet fuels, and gasoline. 

DOE has developed industry-academia-laboratory consortia (such as the National Advanced Biofuels Consortium) to bridge the R&D gap between basic research and integrated demonstration and deployment activities. 

These are strategic partnerships to achieve technical improvements that reduce cost and risk in large-scale 

demonstrations. R&D efforts are focused on both individual process steps and integrated process development. 

Industrial partners have played an integral part in the development of commercial products, such as enzyme 

packages (for hydrolysis of biomass to sugars) and catalysts (for bio-oil upgrading, fuel synthesis, and syngas 

processing). 

DOE is supporting the design, construction, and operation of 14 pilot-scale, 9 demonstration-scale, and 6 

commercial-scale biorefinery projects that will produce a variety of biofuels, including ethanol; butanol; and 

renewable gasoline, diesel, and jet fuel. More information about the DOE-sponsored integrated biorefineries 

is available.65
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Thermochemical Conversion

CTL research began in the late 1920s at the U.S. Bureau of Mines, but didn’t ramp up until after World War II 

when German synthetic fuels technologies were tested and expanded upon. In 1948, liquid fuels laboratories and pilot plants—for both direct and indirect liquefaction—were completed. This research continued through the 1970s, including work that was focused on both the fundamentals of CTL technologies and 

gasification technologies. Gasification constitutes a majority of the costs of indirect liquefaction. 

Catalyst development and gas cleanup was the focus of thermochemical research in the 1980s and 1990s, 

which expanded to include GTL. Early in the 1980s, DOE provided a loan guarantee for the construction of 

the coal-fed Great Plains Gasification facility in North Dakota. The facility produces syngas from coal at a scale 

sufficient to produce 50,000 bpd of synthetic fuels. Its products include synthetic natural gas, ammonia, and 

numerous specialty chemicals. The CO2 from the process is captured and sold for enhanced oil recovery and 

permanent carbon sequestration in Saskatchewan, Canada. Over the past decade, research efforts have focused on the effects of impurities on various catalysts, the performance of new process configurations, and the 

integration of new technologies into CTL systems.

DOE accomplishments in this area include:

•	 Demonstration of three large-scale, direct coal liquefaction (DCL) technologies and extensive research 

of other DCL technologies at bench and pilot scales. A DCL pilot plant in China is based on these processes. DOE is working with the Chinese DCL plant to better characterize the environmental impacts 

of DCL. 

•	 Development and commercial-scale demonstration of a liquid-phase methanol reactor, which can be 

used to improve the MTG process, especially if coal is the feedstock.

•	 Involvement in the development of a process for the conversion of coal to methanol to gasoline.

•	 Development, demonstration, and commercialization of gasification technologies required for the indirect liquefaction pathway.

Other Alternative Fuels

Algal biofuels research is a subject of DOE’s longer-term R&D.66 Four separate algal consortia, representing 

more than 60 academic, industry, and national laboratory organizations, focus on a variety of advanced algal 

biofuels production technologies.67 

In addition to algal biofuels research, DOE funds R&D for other advanced research concepts, such as fuels 

from sunlight and breeding plants that are better able to capture and convert solar energy.68 DOE has funded 

R&D on natural gas as a transportation fuel since 1992, though funding levels have varied widely. In 1998, the 

interagency Partnership for a New Generation of Vehicles terminated light-duty vehicle work, partly because 

of the then-high natural gas prices. Heavy-duty vehicle work continued through the early 2000s, tapering off 

as projects reached completion. DOE also supported work over roughly the same time period on conformable 

and low-weight natural gas tanks for vehicles, vehicle platform integration, and fueling infrastructure (including 

renewable natural gas use at landfills).

DOE has not invested significantly in propane vehicle technology, largely because it is mature and propane has 

not been positioned as an on-road fuel. 
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DOE Role

The Department’s roles in alternative hydrocarbon fuels are as diverse as the fuels themselves. DOE does not 

have a significant technical role in corn ethanol processes, but instead fulfills an informational role by conducting analysis of the lifecycle impact of corn ethanol in comparison to fossil fuels and cellulosic biofuels. 

DOE supports both informational and capability activities for advanced biofuels. For example, data from DOEand USDA-funded integrated biorefineries and loan guarantee recipients helps investors better estimate the 

risk involved with biorefinery projects. The Integrated Biorefinery Research Facility at the National Renewable 

Energy Laboratory provides industry partners with the opportunity to operate, test, and develop their own biorefining technology and equipment. DOE supports basic R&D capabilities in biofuels through its Bioenergy Research Centers—team-based, multi-institutional centers that focus on innovative research to achieve the basic 

science breakthroughs needed to develop sustainable and effective methods of producing cellulosic biofuels.

The Department’s role in alternative fossil fuels, such as CTL, GTL, CBTL, and CNG, is also primarily to provide 

information and basic research capability. DOE assesses technology opportunities to improve the viability of 

CNG and LNG for long-haul trucks, including hybrid electrification, storage volume, engine efficiency, waste 

heat recovery, and aerodynamics. In addition, the Department supports analysis of the carbon intensity of the 

extraction, transport, and processing of various fossil fuels for transportation applications.
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1

 International Energy Agency. (2011). Technology Roadmap–Biofuels for Transport. Paris, France. Accessed at http://www.iea.org/

papers/2011/biofuels_roadmap.pdf

2

 Global Renewable Fuels Alliance. (2010). “Global ethanol production to reach 85.9 billion litres in 2010: Global Renewable Fuels 

Alliance releases 2010 biofuels production forecast.” Toronto, ON. Accessed at http://www.globalrfa.org/pr_032110.php 

3

 Renewable Fuels Association. (2011). 2011 Ethanol Industry Outlook. Washington, DC. Accessed at http://www.ethanolrfa.org/

page/-/2011%20RFA%20Ethanol%20Industry%20Outlook.pdf?nocdn=1 

4

 Perlack, R. D., and Stokes, B. J. (Leads), U.S. Department of Energy. (2011). U.S. Billion-Ton Update: Biomass Supply for a Bioenergy and Bioproducts Industry. (DOE/EE-0363). Oak Ridge, TN: Oak Ridge National Laboratory.

5

 National Biodiesel Board. (2010). “Estimated US Biodiesel Production by Calendar Year.” Accessed at http://www.biodiesel.org/

pdf_files/fuelfactsheets/Estimated_Production_Calendar_Years_05-10.ppt 

6

 National Energy Technology Laboratory. (2008). Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels. Pittsburgh, PA. (DOE/NETL-2009/1346). Accessed at http://www.netl.doe.gov/energy-analyses/

pubs/NETL%20LCA%20Petroleum-based%20Fuels%20Nov%202008.pdf 

7

 U.S. Environmental Protection Agency. (2009). EPA Lifecycle Analysis of Greenhouse Gas Emissions from Renewable Fuels. 

Washington, DC. (EPA-420-F09-024). Accessed at http://www.epa.gov/otaq/renewablefuels/420f09024.pdf 

8

 Noblis. (2011). Production of Zero Sulfer Diesel Fuel from Domestic Coal: Configurational Options to Reduce Environmental Impact. Falls Church, VA. (Contract GS-10F-0189T-Order DE-NT0005816). (REPORT FORTHCOMING)

9

 National Energy Technology Laboratory. (2011). Cost and Performance Baseline for Fossil Energy Plants; Volume 4: Coal-toLiquids via Fischer-Tropsch Synthesis. Pittsburgh, PA. (DOE/NETL-2011-1477). (REPORT FORTHCOMING)

10 Perlack, R. D., and Stokes, B. J. (Leads), U.S. Department of Energy. (2011). U.S. Billion-Ton Update: Biomass Supply for a Bioenergy and Bioproducts Industry. (DOE/EE-0363). Oak Ridge, TN: Oak Ridge National Laboratory.

National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). America’s Energy Future 

Panel on Alternative Liquid Transportation Fuels. Washington, DC: National Academies Press. Accessed at http://www.nap.edu/

openbook.php?record_id=12620&page=250

National Research Council. (2011). Renewable Fuel Standard: Potential Economic and Environmental Effects of U.S. Biofuel 

Policy. Washington, DC. Accessed at http://www.nap.edu/catalog.php?record_id=13105 

11 National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). America’s Energy Future 

Panel on Alternative Liquid Transportation Fuels. Washington, DC: National Academies Press. Accessed at http://www.nap.edu/

openbook.php?record_id=12620&page=250

12 National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). America’s Energy Future 

Panel on Alternative Liquid Transportation Fuels. Washington, DC: National Academies Press. Accessed at http://www.nap.edu/

openbook.php?record_id=12620&page=250

National Research Council. (2011). Renewable Fuel Standard: Potential Economic and Environmental Effects of U.S. Biofuel 

Policy. Washington, DC. Accessed at http://www.nap.edu/catalog.php?record_id=13105 

13 Perlack, R. D., and Stokes, B. J. (Leads), U.S. Department of Energy. (2011). U.S. Billion-Ton Update: Biomass Supply for a Bioenergy and Bioproducts Industry. (DOE/EE-0363). Oak Ridge, TN: Oak Ridge National Laboratory. 

14 A dry tonne of biomass can be converted to about 90 gallons of ethanol, or about 60 gallons of gasoline equivalent.

Humbird, D., et al. (2011). Process Design and Economics for Biochemical Conversion of Lignocellulosic Biomass to Ethanol. 

(NREL/TP-5100-47764). Golden, CO: National Renewable Energy Laboratory.

15 Note that this assumes 100% carbon efficiency in converting from feedstock to fuel; existing conversion technologies are about 

50% efficient.

16 Municipal solid waste consists of everyday items we use and then throw away, such as product packaging, grass clippings, 

furniture, clothing, bottles, food scraps, newspapers, appliances, paint, and batteries. Some of this waste, such as food scraps 

and newspapers, would double-count carbon flows on the supply side.
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17 Coal

The United States consumed 1,000 million short tons of coal in 2009. http://www.eia.gov/totalenergy/data/annual/txt/ptb0701.

html

Carbon content of coal is approximately 51%. http://www.eia.gov/todayinenergy/detail.cfm?id=2670

Natural Gas

The United States used 22.839 trillion cubic feet of natural gas in 2009. http://www.eia.gov/dnav/ng/hist/n9140us2A.htm 

Carbon content of natural gas (assuming 100% methane CH4) is 15 g C per cubic feet NG. Based on 122 pound CO2/1,000 cubic 

feet NG. http://cdiac.ornl.gov/pns/faq.html

Gasoline

U.S. supply of gasoline was 3,284 million barrels in 2009. http://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_mbbl_a.htm

Carbon content in gasoline is 2,421 grams carbon per gallon. Code of Federal Regulations. (40 CFR 600.113) http://www.epa.gov/

otaq/climate/420f05001.htm#calculating

Diesel

 U.S. supply of diesel is 1,038 million barrels/year (Distillate Fuel Oil: 15 ppm and under Sulfur). http://www.eia.gov/dnav/pet/

pet_cons_psup_dc_nus_mbbl_a.htm 

Carbon content in diesel is 2,778 grams carbon/gallon. http://www.epa.gov/otaq/climate/420f05001.htm#calculating

Other Crude Oil

The United States consumed 6,851 million barrels of crude in 2009. http://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_

mbbl_a.htm

Crude is 85% carbon by weight (http://cdiac.ornl.gov/pns/convert.html). Subtract gasoline and diesel carbon. 

Corn

U.S. supply of corn was 13,091,862,000 bushel in 2009. http://www.nass.usda.gov/Statistics_by_Subject/result.php?2A34ECC7-

2E42-3883-BF81-9AEFA12F396E§or=CROPS&group=FIELD%20CROPS&comm=CORN

Carbon content of dry corn is 32%. http://www.bio.net/bionet/mm/plantbio/1993-August/001498.html 

Paper 

U.S. supply of paper was 87,632 thousand tons in 2008. www.census.gov/compendia/statab/2010/tables/10s0859.xls 

Carbon content of paper is similar to woodpulp (29% carbon content). http://www.sou.edu/envirostudies/Gutrich5.pdf

Soy

U.S. supply of soy was 3,359,011,000 bushels in 2009. http://www.nass.usda.gov/Statistics_by_Subject/result.php?9D5F2C2B331F-31F9-99E9-EE8D69415D1C§or=CROPS&group=FIELD%20CROPS&comm=SOYBEANS

Soy is 13% moisture by weight, and the carbon content of dry soy is 42.6%. http://www.grains.org/conversion-factors

Woodpulp 

U.S. supply of woodpulp was 57,964 thousand tons in 2008. www.census.gov/compendia/statab/2010/tables/10s0859.xls 

Carbon content of woodpulp is about 29% (range 23%–35%). http://www.sou.edu/envirostudies/Gutrich5.pdf 

Wheat

U.S. supply of wheat was 2,218,061,000 bushels in 2009. http://www.nass.usda.gov/Statistics_by_Subject/result.

php?739ECD5D-4641-3D15-AA41-E64A5856106E§or=CROPS&group=FIELD%20CROPS&comm=WHEAT 

Carbon content of wheat is about 46%. http://biomassmagazine.com/articles/5317/codigesting-crop-residues
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Edible Fats/Oils

U.S. supply of edible fats and oils was 26,442 million pounds in 2008. http://usda.mannlib.cornell.edu/usda/ers/89002/2009/

index.html

Carbon content of soybean oil is 77%. http://www.biodiesel.org/pdf_files/fuelfactsheets/Weight&Formula.PDF

Meat/Poultry

U.S. supply of livestock was 72,942,000,000 pounds in 2009. http://www.nass.usda.gov/Statistics_by_Subject/result.

php?A295F1C9-B063-3B13-8A6B-0FF11AE25ED1§or=ANIMALS%20%26%20PRODUCTS&group=LIVESTOCK&comm=LIVE

STOCK%20TOTALS 

U.S. supply of poultry was 41,787,000,000 pounds in 2009. http://www.nass.usda.gov/Statistics_by_Subject/result.

php?A5C4E649-B4FB-3770-B69E-C886FCF83259§or=ANIMALS%20%26%20PRODUCTS&group=POULTRY&comm=POULT

RY%20TOTALS 

Carbon content of flesh is about 18%. http://www.daviddarling.info/encyclopedia/E/elbio.html 

Cotton

U.S. supply of cotton was 5,850,000,000 pounds. http://www.nass.usda.gov/Statistics_by_Subject/result.php?D93C704C-D0F7-

3A06-AC27-5FE78C79A5F9§or=CROPS&group=FIELD%20CROPS&comm=COTTON

Carbon content of cotton fiber is 42%. http://cottontoday.cottoninc.com/Sustainability-About/Life-Cycle-Inventory-Data-ForCotton/Life-Cycle-Inventory-Data-For-Cotton.pdf 

Biomass

The United States currently uses 214 million dry tons of biomass for fuels. U.S. Billion-Ton Update, Table ES1. http://www.

ascension-publishing.com/BIZ/Billion-Ton-2.pdf

Carbon content of bioenergy feedstocks is about 45%. http://bioenergy.ornl.gov/papers/misc/energy_conv.html

Biomass Potential

The United States could produce 1,046–1,305 million dry tons in 2030 (averaged to 1,175). 

U.S. Billion-Ton Update. http://www.ascension-publishing.com/BIZ/Billion-Ton-2.pdf 

Municipal Solid Waste

The United States produced 243 million short tons of municipal solid waste in 2009. http://www.epa.gov/waste/nonhaz/municipal/index.htm 

Carbon content of municipal solid waste is about 34% by weight. http://www.ipcc-nggip.iges.or.jp/public/gp/bgp/5_3_Waste_

Incineration.pdf

18 National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). Liquid Transportation Fuels 

From Coal and Biomass: Technological Status, Costs, and Environmental Impacts. Washington, DC: National Academies Press. 

Accessed at http://www.nap.edu/catalog.php?record_id=12620 

19 Advanced biofuel is defined as a renewable fuel other than ethanol derived from corn starch and for which lifecycle GHG emissions are at least 50% less than the gasoline or diesel fuel it displaces.

The EPA can grant waivers for these mandates. For example, acknowledging the lack of U.S. capacity to produce adequate 

volumes of cellulosic biofuels, EPA reduced the required annual volumes of cellulosic biofuels from the original statutory goal of 

100, 250, and 500 million gallons per year (MGY) in 2010, 2011, and 2012 to 6.5 MGY, 6.6 MGY, and 8.65 MGY, respectively. 

Energy Independence and Security Act of 2007 § 202.

20 For stover, includes harvesting, storage, transport, and preprocessing and plant receiving. For woody biomass, includes harvesting, landing preprocessing, transport, and receiving. 
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 U.S. Department of Energy. (2011). Biomass Multi-Year Program Plan. Washington, DC. Accessed at http://www1.eere.energy.

gov/biomass/pdfs/mypp_april_2011.pdf

21 U.S. Department of Energy. (2009). Biochemical Conversion Platform Review Report: An Independent Evaluation of Platform 

Activities for FY2008 and FY2009. Washington, DC. Accessed at http://www.obpreview2011.govtools.us/review/documents/

OBP_BC-Conversion_Platform_Review_Report_EERE_Standard_Cover%20%28FINAL_V1%29.pdf 

22 National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). Liquid Transportation Fuels 

From Coal and Biomass: Technological Status, Costs, and Environmental Impacts. Washington, DC: National Academies Press. 

Accessed at http://www.nap.edu/catalog.php?record_id=12620

23 Kazi, F. K., et al. (2010). Techno-Economic Analysis of Biochemical Scenarios for Production of Cellulosic Ethanol. (NREL/TP6A2-46588). Golden, CO: National Renewable Energy Laboratory. Accessed at http://www.nrel.gov/docs/fy10osti/46588.pdf 

24 Humbird, D., et al. (2011). Process Design and Economics for Biochemical Conversion of Lignocellulosic Biomass to Ethanol: 

Dilute-Acid Pretreatment and Enzymatic Hydrolysis of Corn Stover. (NREL/TP-5100-47764). Golden, CO: National Renewable 

Energy Laboratory.

25 U.S. Department of Energy. (2011). Biomass Multi-Year Program Plan. Washington, DC. Accessed at http://www1.eere.energy.

gov/biomass/pdfs/mypp_april_2011.pdf 

26 Urbanchuck, J. (2010). Current State of the U.S. Ethanol Industry. Washington, DC: Department of Energy. Accessed at http://

www1.eere.energy.gov/biomass/pdfs/current_state_of_the_us_ethanol_industry.pdf 

Table 4 (p. 5-2) provides cost estimates for total production cost and feedstock costs. The $0.75 estimate was derived by calculating the operating costs (Total cost per gallon – Feedstock cost per gallon = Operating cost) and adding the amortized capital costs 

(assumed to be $0.15 based on a standard amortization of assumed nameplate capital costs of $1.97).

27 Humbird, D., et al. (2011). Process Design and Economics for Biochemical Conversion of Lignocellulosic Biomass to Ethanol. 

(NREL/TP-5100-47764). Golden, CO: National Renewable Energy Laboratory. Accessed at http://www.nrel.gov/biomass/

pdfs/47764.pdf 

Table 41 (p. 82) provides estimates for total MESP, as well as feedstock, enzyme, and non-enzyme conversion costs. The conversion costs were calculated by adding the enzyme and non-enzyme portions of the conversion costs from the 2010 SOT column of 

the table.

28 The analysis is based on a plant designed and built to a given nameplate capacity in 2007. Since then, improvements in technology and operations enable production levels greater than 100% of that nameplate capacity. We report nameplate capacity 

because it is what the capital costs are based on. We also report total (actual) capacity in support of operating costs.

29 U.S. Department of Energy, Biomass Program. “Integrated Biorefineries.” Washington, DC. Accessed at http://www1.eere.energy.gov/biomass/integrated_biorefineries.html 

30 Perlack, R. D., and Stokes, B. J. (Leads), U.S. Department of Energy. (2011). U.S. Billion-Ton Update: Biomass Supply for a Bioenergy and Bioproducts Industry. (DOE/EE-0363). Oak Ridge, TN: Oak Ridge National Laboratory.

31 Wigmosta, M. S., Coleman, A. M., Skaggs, R., Huesemann, M. H., and Lane, L. J. (2011). “National microalgae biofuel production 

potential and resource demand.” Water Resources Research. 47: Article No. W00H04 (13 April 2011).

32 U.S. Department of Energy. (2011). Biomass Multi-Year Program Plan. (DOE/EE-0405). Washington, DC. Accessed at http://

www1.eere.energy.gov/biomass/pdfs/mypp_april_2011.pdf 

33 U.S. Department of Energy. (2011). Biomass Multi-Year Program Plan. (DOE/EE-0405). Washington, DC. Accessed at http://

www1.eere.energy.gov/biomass/pdfs/mypp_april_2011.pdf 

34 Hess, J. R., Kenney, K. L., Park Ovard, L., Searcy, E. M., and Wright, C. T. (2009). Uniform-Format Solid Feedstock Supply System: A 

Commodity-Scale Design to Produce an Infrastructure Compatible Bulk Solid from Lignocellulosic Biomass. (INL/EXT-08-14752). 

Idaho Falls, ID: Idaho National Laboratory. Accessed at http://www.inl.gov/bioenergy/uniform-feedstock 

Tumuluru, J. S., Wright, C. T., Hess, J. R., and Kenney, K. L. (2011). “A review of biomass densification systems to develop uniform 

feedstock commodities for bioenergy application.” Biofuels, Bioproducts and Biorefining. 1932-1031. Accessed at http://dx.doi.

org/10.1002/bbb.324
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35 U.S. Department of Energy. (2011). Biomass Multi-Year Program Plan. (DOE/EE-0405). Washington, DC. Accessed at http://

www1.eere.energy.gov/biomass/pdfs/mypp_april_2011.pdf 

36 The Shell Pearl GTL plant in Qatar produces 140,000 bpd, while smaller plants in Qatar (Sasol’s Oryx plant), Malaysia (Shell’s 

Bintulu plant), and South Africa (PetroSA’s Mossel Bay plant) contribute the balance.

37 The Sasol Secunda plant in South Africa produces 160,000 bpd and is the only commercial CTL plant in operation. Two plants in 

China (one in Inner Mongolia and another in Shanxi Province) contribute the balance.

38 Anex, R. P., et al. (2010). “Techno-economic comparison of biomass-to-transportation fuels via pyrolysis, gasification, and biochemical pathways.” FUEL. 89(1):S29-S35. doi:10.1016/j.fuel.2010.07.015.

39 Crude oil price at which the facility is economically viable and can meet its 12% Internal Rate of Return on Equity.

40 Gasoline or diesel price at which the facility is economically viable and can meet its 12% Internal Rate of Return on Equity.

41 National Energy Technology Laboratory. (2011). Production of Zero Sulfur Diesel Fuel from Domestic Coal: Configuration Options 

to Reduce Environmental Impact.

42 At natural gas prices ranging from $5–$10/mm Btu, and assuming a 10% Capital Charge Factor.

43 Memorandum from David Gray, Noblis, Inc., April 25, 2011.

44 National Energy Technology Laboratory. (2010). Baseline Analysis of Sub-Bituminous Coal and Biomass to Gasoline (Indirect 

Liquefaction via Methanol Synthesis). (DOE/NETL-40/092310). Morgantown, WV.

45 Tarka, T. J., Shah, V., et al. (2011). Cost and Performance Baseline for Fossil Energy Plants, Volume 4: Coal-to-Liquids via FischerTropsch Synthesis. (DOE/NETL-2011/1477). Morgantown, WV: National Energy Technology Laboratory. 

White, C., and Gray, D. (2011). Production of Zero Sulfur Diesel Fuel from Domestic Coal: Configurational Options to Reduce 

Environmental Impact. Morgantown, WV: National Energy Technology Laboratory. 

46 Tarka, T. J., et al. (2009). Affordable, Low-Carbon Diesel Fuel from Domestic Coal and Biomass. (DOE/NETL-2009/1349). Morgantown, WV: National Energy Technology Laboratory. Accessed at http://www.netl.doe.gov/energy-analyses/pubs/CBTL%20

Final%20Report.pdf

47 Internal DOE analysis performed by the National Energy Technology Laboratory, May 5, 2011.

48 Converted using the Fischer-Tropsch process with 15% biomass to 85% coal.

49 Internal DOE analysis performed by the National Energy Technology Laboratory, May 5, 2011.

50 U.S. Department of Energy. (2011). Biomass Multi-Year Program Plan. (DOE/EE-0405). Washington, DC. Accessed at http://

www1.eere.energy.gov/biomass/pdfs/mypp_april_2011.pdf 

51 National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). Liquid Transportation Fuels 

From Coal and Biomass: Technological Status, Costs, and Environmental Impacts. Washington, DC: National Academies Press. 

Accessed at http://www.nap.edu/catalog.php?record_id=12620

52 Davis, R., et al. (2011). “Techno-economic analysis of autotrophic microalgae for fuel production.” Applied Energy. 88(10):3524-

3531. doi:10.1016/j.apenergy.2011.04.018.

53 The Clean Vehicle Education Foundation estimates there are approximately 3,000 natural gas refuse haulers, 2,800 natural gas 

school buses, and 16,000–18,000 medium-duty NGVs (such as airport shuttles and delivery vans). Honda has sold light-duty CNG 

vehicles since 2007, and other OEMs have recently offered new models.

 Argonne National Laboratory. (2010). Natural Gas Vehicles – Status, Barriers, Opportunities. (ANL/ESD/10-4) p.7–8. Argonne, IL. 

Accessed at http://www.afdc.energy.gov/afdc/pdfs/anl_esd_10-4.pdf

54 NGV Communications Group. http://www.ngvgroup.com 

55 Energy Information Administration. “Other FAQs about Gasoline.” Washington, DC. Accessed at http://www.eia.gov/tools/faqs/

faq.cfm?id=25&t=10 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

56 U.S. Department of Energy. (2011). “Alternative Fueling Station Total Counts by State and Fuel Type.” Washington, DC. Accessed 

at http://www.afdc.energy.gov/afdc/fuels/stations_counts.html 

57 Argonne National Laboratory. (2010). Natural Gas Vehicles – Status, Barriers, Opportunities. (ANL/ESD/10-4). p.7–8. Argonne, 

IL. Accessed at http://www.afdc.energy.gov/afdc/pdfs/anl_esd_10-4.pdf 

58 http://www.pnl.gov/main/publications/external/technical_reports/PNNL-19745.pdf 

59 Westport Innovations, Inc. Presentation at the Northwest Gas Association Meeting. March 18, 2011.

60 Energy Information Administration. (2011). “Estimated Number of Alternative Fueled Vehicles in Use in the United States, by Fuel 

Type, 2005–2009.” Alternatives to Traditional Transportation Fuels. Washington, DC. Accessed at http://www.eia.gov/renewable/alternative_transport_vehicles/pdf/attf_V1.pdf 

61 Energy Information Administration. (2011). “Estimated Consumption of Vehicle Fuels in the United States, by Fuel Type, 2005–

2009.” Alternatives to Traditional Transportation Fuels. Washington, DC. Accessed at http://www.eia.gov/renewable/alternative_transport_vehicles/pdf/attf_c1.pdf 

62 World LP Gas Association. “Autogas Consumption, Vehicles, and Dispensing Sites.” Key Autogas Data. Neuilly-sur-Seine, 

France. Accessed at http://www.worldlpgas.com/gain/key-autogas-data 

63 National Academy of Sciences. (2009). Real Prospects for Energy Efficiency in the United States. p.127. Washington, DC: The 

National Acadamies Press.

64 See http://science.energy.gov/bes/efrc/

65 See http://www1.eere.energy.gov/biomass/integrated_biorefineries.html and http://obpreview2011.govtools.us/IBR/

66 U.S. Department of Energy. (2010). National Algal Biofuels Technology Roadmap. Washington, DC. Accessed at http://www1.

eere.energy.gov/biomass/pdfs/algal_biofuels_roadmap.pdf 

67 See http://www.naabb.org/; http://asulightworks.com/research-centers/sabc; http://algae.ucsd.edu/index.html; and http://cellana.com/

68 For example, the Joint Center for Artificial Photosynthesis. Find more at http://solarfuelshub.org/ 

Building and Industrial Efficiency | 79

BUILDING AND 

INDUSTRIAL 

EFFICIENCY

The assessments in this chapter form the technical base 

for Improving Building and Industrial Efficiency, a strategy 

detailed in the corresponding chapter of the Report on 

the Quadrennial Technology Review (QTR). Increasing 

energy efficiency provides a net economic advantage 

by decreasing energy expenditures for the same level of 

service. Improving building and industrial energy efficiency 

will enhance U.S. economic competitiveness while reducing 

environmental impacts.

While each technology is presented here with a standalone 

assessment, the associated opportunities to impact the 

energy system are fully understood only within the context 

of an integrated framework that spans energy resource, 

supply, delivery, and consumption. The Report on the QTR 

presents an integrated framework of the energy system 

and contains the systems discussions that tie together 

these individual assessments.

The technology assessments in the Building and Industrial 

Efficiency chapter have been organized alphabetically and 

include:

•	 Building Efficiency

•	 Industrial Efficiency
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BUILDING AND INDUSTRIAL EFFICIENCY

BUILDING EFFICIENCY

After losses in generating and delivering electricity, about 11 Quads of fossil fuels and 9 Quads of electricity 

were consumed in buildings in 2009. That energy was principally used for heating, ventilation, and air conditioning (HVAC); lighting; water heating; and electronics. Electricity accounts for 40% and 53% of site energy 

use in residential and commercial buildings, respectively; fuels for heating and cooking comprise the balance. 

Commercial buildings use 75% more energy per square foot than residential buildings.1 There are ample opportunities to improve the energy efficiency in buildings—through improved components, as well as better 

design and operation of the building as a system. 

U.S. residential and commercial building energy use has increased continuously since the 1950s (Figure 13). 

However, per capita building energy use (Figure 13) has slowed since the 1970s. Many factors influence 

these trends, including the pace of economic growth, structural shifts in the U.S. economy, and demographic 

changes.
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25 0.08

0.07

0.06

0.05

0.04

0.03

0.02

0.01

0

20

15

10

5

0

Building Energy Use (Quads)

Per Capita Building Energy Use (MBTU)

RESIDENTIAL TOTAL COMMERCIAL TOTAL

RESIDENTIAL PER CAPITA COMMERCIAL PER CAPITA

194919541959196419691974

1979198419891994199920042009

YEAR

Figure 13. Residential (orange) and Commercial (blue) Building Primary Energy Use (solid 

lines) and Per Capita Primary Energy Use (dotted lines) Since the 1950s 

Energy Information Administration. (2011). “Population, U.S. Gross Domestic Product, and Implicit Price Deflator, 

1949-2010.” Annual Energy Review. Washington, DC. Accessed October 2011 at http://www.eia.gov/totalenergy/

data/annual/showtext.cfm?t=ptb1501; Energy Information Administration. (2011). “Energy Consumption Estimates 

by Sector, 1949-2010.” Annual Energy Review. Washington, DC. Accessed October 2011 at http://www.eia.gov/

totalenergy/data/annual/showtext.cfm?t=ptb0201a

Those factors related to energy efficiency include:

•	 State and Federal Appliance Standards: Introduced into law in 1987, federal appliance standards 

reduced U.S. appliance electricity use by 2.5% (1.3 Quads) in 2000, by a projected 6.9% (3.1 Quads) 

in 2010, and by 9.1% (5.2 Quads) in 2020.2

•	 Technology Development: In the past three decades, public and private research and development 

(R&D) has introduced many energy-saving products into the marketplace, including electronic ballasts 

and compact fluorescent lighting. For example, some of the Department of Energy’s (DOE’s) most successful R&D programs are estimated to have cumulatively saved the nation about 5 Quads of primary 

energy by 1999, a net economic benefit of around $30 billion.3

•	 Multiple Efforts: Additional policies and actors at the local, state, and federal levels have contributed 

to reducing energy consumption, tax credits, Energy Efficiency Resource Standards, building codes, a 

broad set of utility incentives, and activities by non-government organizations.
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Building construction and renovation industries account for less than 10% of U.S. gross domestic product 

(GDP).4 In 2007, residential and commercial building renovations were valued at $450 billion, and new building construction was valued at $785 billion. Appliances and equipment is a $166 billion industry in the United 

States.5 Given the size and relatively large energy use, as explained above, there is significant interest in the potential of reducing energy use in buildings. For example, a number of recent reports have surveyed the potential 

for building energy efficiency in the U.S. economy. Among these are Real Prospects for Energy Efficiency in the 

United States from the National Academy of Sciences,6 Unlocking Energy Efficiency in the U.S. Economy from 

McKinsey & Company,7 and Energy Future: Think Efficiency from the American Physical Society.8 However, 

multiple barriers hinder adoption of cost-effective technologies. Although a comprehensive analysis of these 

barriers is beyond the scope of this assessment, examples include: 

•	 Market Failures: Fragmentation of suppliers and customer base, incomplete or poor communication 

of information (e.g., specific appliance operating cost) to consumers, and principal-agent disconnects 

between the parties that select equipment (i.e., landlords, contractors, builders) and those who pay 

the energy bills (i.e., tenants, building owners/operators). The latter are commonly known as “split 

incentives.”

•	 Short-Term Consumer Decision Making: Focus groups show that when considering only costs, 

consumers demand payback periods far shorter than the service life of the equipment (e.g., 1–1.5 year 

paybacks for high-efficiency HVAC systems).9 Consumers accept longer payback periods when nonenergy benefits beyond efficiency are considered, as in the case of the comfort, health, and productivity benefits of modern HVAC equipment.

•	 Long Equipment Lifetimes: Refrigerators, water heaters, and HVAC equipment have 10–20 year 

lifetimes that slow deployment of newer technologies.10 This is especially true for HVAC equipment; 

studies have estimated median heat pump service life at close to 20 years.11,12

•	 Embedded Infrastructure: Deployed infrastructure (e.g., lighting fixtures and dimmers, HVAC ducts) 

designed for old technology is suboptimal for newer technologies, thereby limiting adoption and benefits of modern equipment.

Policy Context 

Federal, state, and local government influence building energy efficiency in four ways: R&D, codes, standards, 

and market priming. Standards, codes, and market priming are discussed briefly here, while the remainder of 

the Building Efficiency technology assessment focuses on technology R&D.

Appliance and Equipment Standards: DOE develops test procedures and minimum efficiency standards for 

residential appliances and commercial equipment.

Building Codes: Building energy codes and standards are adopted and enforced by individual states, though 

some counties have building energy standards that exceed statewide standards. They are often based on model 

energy codes and standards developed by industry groups with support from DOE. Model energy codes were 

established by the Energy Conservation and Production Act of 1976, in which codes are “designed to achieve 

the maximum practicable improvements in energy efficiency.”
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Market Priming: Governments have used a number of mechanisms to ease technology deployment by reducing non-technical barriers to adoption. Some of the most significant activities of this type include: 

•	 Retrofitting Existing Residential Buildings: DOE’s Weatherization and Intergovernmental and Better Buildings Programs both deploy commercially available energy efficiency measures, including air 

sealing, insulation, and efficient HVAC equipment to low-income and other homes. These activities 

have laid the groundwork for further deployment by establishing “best practices” in the industry. 

•	 Guidelines and Certification: DOE’s Weatherization Assistance Program, in conjunction with experts 

and professionals in the residential energy efficiency market, has set the standard for how work will be 

performed in homes and what knowledge and abilities workers require to perform the various tasks 

by developing the Workforce Guideline for Home Energy Upgrades. This effort is complemented by a 

training accreditation and worker certification initiative to standardize the workforce, improve service 

delivery, and increase the confidence for consumers investing in energy efficiency. 

•	 Training Curricula: The Weatherization Assistance Program has developed standardized training curricula for the classroom, as well as hands-on instruction to improve skills and maintain quality output. 

•	 Retrofitting Existing Commercial Buildings: Similarly, the recently launched Better Buildings Initiative seeks to reduce total commercial building energy consumption by 20% by 2020 (about 4 Quads 

per year).

•	 New Buildings: Various initiatives, including the building codes program, Building America, and model building designs, seek to improve the way new buildings are built. These measures have their greatest effects in the long term due to the long lifetime of existing buildings. 

•	 Ratings: Ratings like ENERGY STAR® and Leadership in Energy and Environmental Design allow builders to distinguish themselves from their competitors through the energy efficiency of their products. 

Home Performance with ENERGY STAR and various private, local, and state-level programs retrofit 

existing buildings to improve their efficiency.

•	 Mandatory Energy Performance Disclosure: Several states have enacted policies that require the 

rating and disclosure of energy performance of public, commercial, or residential buildings.13 
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Appliance and Equipment Efficiency

Despite the availability of cost-effective energy-saving technologies, today’s appliances, equipment, and lighting systems consume more energy than necessary. Deploying technologies that are commercially available 

today, as well as those that would be available with low-risk R&D over the next two decades could reduce total 

building-related energy consumption by 40% (17.4 Quads per year).14 

This assessment is divided between end-use-specific emerging technology R&D (which tends to be what manufacturers can commercialize in under 10 years), crosscutting research (which tends to have a 10–20 year horizon), and longer-term breakthrough R&D. 

In order to determine the scope of this assessment, we started with a top-down frame that split building end 

use into eight major categories. We then evaluated the latest thinking to determine the current consumption 

and future technical potential in those categories. Opportunities for technology improvements are shown in 

Table 13. These include:

•	 Modernizing HVAC systems

•	 Advancing lighting technology

•	 Improving water heating

•	 Addressing miscellaneous electric loads

•	 Advancing refrigeration technology 

•	 Reducing laundry energy consumption

•	 Exploring innovative cooking appliances 

•	 Optimizing dishwashing appliances.
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End Uses to Address

HVAC Water Heating Lighting Refrigera- tion MELs Laundry Cooking Dishwash- ing

 Near-Term Emerging Technology

• Coldclimate heat 

pump

• Integrated 

heat pump

• “CO2” heat 

pump

• Gas absorption heat 

pump

Solid state (i.e., LEDs)

• Linear and 

variable speed compressors

• System improvements

Various Various Various

Insulation

X

X

X

X

X

X

X

Heat Exchangers

X

X

X

X

X * X

Motors

X

X

X

X

X * X

Working Fluids

X

X

X *

DC Equipment * * X * X * * *

Cascading and Storage

X

X

X

X

 Not-in-Kind Research and Development

• Moisture 

transport membranes

• Indirect 

evaporative

• Liquid desiccants

Multi-photonphosphors

• Thermoaccoustic 

and magnetic

• Solid-state 

technology

• Sterling 

cycle

• Absorption 

and adsorption

OLED displays Non-thermal cooking

Crosscutting Technologies

Table 13. Technology Opportunities for End-Use Technologies“X” Indicates applicability “*” Indicates limited applicability Gray boxes indicate few opportunities
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End-Use R&D

HVAC, lighting, water heating, and plug loads total 87% of the 34 Quads of primary energy consumption that 

has well-identified end uses.

 Table 14. Summary of Energy Consumption and Savings Potential with Major End Uses

End Use Technology 

Opportunities

Today’s Energy 

Use (Quads)

DOE Assessment of 

Possible Technical 

Reduction

HVAC

• Combustion heating

• Cold-climate heat 

pumps

• Integrated heat 

pumps

• Ground-source heat 

pumps

15 10%–60%

Lighting

• Solid state

• Outdoor lighting 

advances

• Sensors and controls

5.4 70%–90%

Water Heating

• Electric heat pump 

water heaters (HPWH)

• Gas absorption 

HPWH

• Solar water heating

• Demand reduction

3.7 50%–75%

Miscellaneous 

Electric Loads

• Energy management 

controls

• Standby power 

reduction

• Component 

improvements

5.7 50%15

Refrigeration

• “Max tech” appliance 

could yield ~40% 

energy savings16

2.6 20%–40%

Cooking

• Induction cook tops

• Dual cavity ovens

• Low-emissivity 

heating elements

• Increased microwave 

oven use

0.83 10%–50%
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

End Use Technology 

Opportunities

Today’s Energy 

Use (Quads)

DOE Assessment of 

Possible Technical 

Reduction

Laundry

• Reduced hot water 

use

• Improved machine 

efficiency

• Reduced drying need

0.74 40%–70%

Dishwashing

• Advanced hydraulics

• Sorption-assisted 

drying

• Improved food filters

• Efficient motors

• Advanced controls

0.28 35%–50%

Heating and Cooling: These applications represent 15 Quads of energy consumption in buildings, and DOE 

believes that they offer 10%–60% energy savings. There is modest opportunity to significantly improve the 

efficiency of conventional combustion space heating technologies, such as gas-fired furnaces and boilers. For 

example, increasing the Annual Fuel Utilization Efficiency from the current stock-weighted value of 0.81 to the 

maximum technology of 0.98 would save 0.86 Quads of energy per year and provide corresponding environmental benefits. There are few technological hurdles to achieve these gains; furnaces and boilers with Annual 

Fuel Utilization Efficiencies greater than 0.95 are widely commercialized. Non-combustion technologies that 

potentially offer far greater energy savings include: 

•	 Cold Climate Heat Pumps: Improve air-source heat pumps to operate at higher efficiencies under 

cold ambient temperature conditions; this technology could reduce space heating and cooling energy 

in Northern climate residences and small commercial buildings. Research opportunities include multistage vapor compression systems, improved icing controls, and adequate data reporting to enable 

simulations that accelerate product development. This technology can also improve efficiencies of 

refrigeration systems for frozen food.

•	 Integrated Heat Pump: Develop prototype systems to cut energy consumption for space heating, 

cooling, and water heating combined by 44%–60%. These pursue two-speed air source, variable 

speed air source, and variable speed ground-source heat pump technologies. 

•	 Ground-Source Heat Pump: Improved ground coupling, reduced drilling costs, and improved analyses and opportunity assessments can lead to lower first costs and broader consumer adoption.

•	 Air-Conditioning-Only Systems can be improved through variable speed vapor compression technologies (including roof-top units and scroll compressors in commercial applications). 

Lighting: Though currently responsible for 5.4 Quads of annual energy use, advanced lighting technologies are 

developing to reduce lighting energy consumption.17 DOE believes that they could technically reduce lighting 

energy consumption by 70%–90%. Transitioning from the incandescent light bulb to compact fluorescent to 

solid-state lighting (SSL) in homes, and retrofitting low-efficiency T12 and T8 fixtures with high-efficiency T5 

and SSL fixtures in commercial buildings can achieve significant savings.
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In 2010, the average efficacy of lighting installed in the United States was 58 Lumens per Watt (Lm/W).18 DOE 

targets for light-emitting diode (LED) luminaire efficacy are 139 Lm/W by 2015 and 202 Lm/W by 2020.19 If 

these targets are achieved, due to the increased penetration of LED lighting, by 2020 consumers could reduce 

lighting energy consumption by 19%, a reduction of about 1.3 Quads of primary energy per year.20 Manufacturers are designing luminaires for SSL with greater light utilization; improving SSL compatibility with control 

systems could further reduce consumption. Additional opportunities include:

•	 Replacing standard high-intensity discharge lamps with induction technology lamps to reduce energy 

use in large-area indoor and outdoor lighting applications.21 

•	 Deploying occupancy and photo sensors, and integrating these controls with daylighting.1 

•	 Reducing the cost of organic light–emitting diodes, which are even more energy efficient than semiconductor-based LEDs. 

Water Heating: This end use is responsible for 3.7 Quads of primary energy use. Modern technologies, advanced distribution systems, and advanced controls offer greater savings than the simple technologies developed in the late 19th and early 20th centuries. Demand reduction through water-conserving fixtures and 

appliances offers additional energy and water savings. 

DOE believes that several technologies can lead to 50%–75% end-use savings.22 Energy consumption can 

be reduced by electric heat pump water heaters with benefits most clearly available in cooling-dominated 

Southern climates. Current research focuses on developing heat pump water heaters that use gas absorption 

or carbon dioxide (CO2) as the refrigerant. These technologies have the potential to reduce energy consumption by 40%–50% (gas absorption) or 70% (CO2

 refrigerant) and reduce emissions from refrigerant release. 

In appropriate regions of the country, solar water heating could reduce demand by another 50% or more, for 

a 70%–85% reduction in total primary energy demand for water heating.23 Improved water heating controls, 

such as temperature setbacks or demand recirculation systems, could provide additional savings. 

Miscellaneous Electric (i.e., plug) Loads: Plug load24 energy consumption, which currently accounts for 5.7 

Quads, is growing faster than any other equipment segment driven by electronics, such as personal computers, 

televisions and set-top boxes, and office equipment.25 Scenario-based projections have estimated that technologies could reduce miscellaneous electric loads energy consumption by 50%.26 Crosscutting energy-savings 

technologies include energy management controls (at the appliance and chip level), standby power reduction, 

and component improvements (e.g., broadly deploying technologies to extend battery life). Replacing the 

current stock of electronics with best-on-market could increase efficiency by 10%–15%; engineering new 

products with best-available components and practices would be an even larger improvement. Organic light–

emitting diodes display technology has the potential to reduce energy use by 50%–70%. Automated control 

systems provide real-time feedback to help realize savings. For example, grid-responsive, user-friendly control 

systems that provide feedback along with real-time, remote diagnostics could deliver large energy savings; one 

study found that such systems could reduce individual residential electricity use by 4%–12%.27

1 For example, see:

 Pacific Northwest National Laboratory. (2011). Preliminary Scoping Report on Nanolens Coatings for Daylighting 

Applications. (PNNL-20520). Richland, WA.
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Other Appliances: The remaining end uses of refrigeration, laundry, cooking, and dishwashing also offer 

cost-effective technology-related opportunities to improve energy efficiency; these uses total some 4.4 Quads 

of primary energy.

•	 Refrigeration: While there are multiple approaches to reduce refrigerator energy consumption, no 

single commercialized device uses them all. Aggregating these into a “max tech” appliance would 

yield approximately 40% energy savings, reducing energy use to roughly half of the maximum permitted by new federal standards. Among the technologies and practices that could be incorporated are 

efficient compressor systems (linear, variable speed, and/or separate cold food/freezer compressors), 

optimized refrigerant (and air) temperatures, top-mounting condensing coils, vacuum‐insulated panels, better gasket seals, adaptive defrosting and anti-sweat heaters, improved heat exchangers, and 

direct current (DC) fan motors.28 

•	 Cooking: DOE estimates that, in aggregate, four strategies could reduce the primary energy consumption of cooking by 10%–50%. 

▪ Switch to induction cook tops and dual cavity ovens. 

▪ Increase the thermal efficiency of electric household ovens from 12.7% to 23% with low-emissivity heating element designs to provide 50% energy savings.29

▪ Develop combined infrared-microwave technology to allow use of efficient microwave ovens for 

baking with no loss in quality.30 However, this hybridization requires changes to the typical kitchen 

infrastructure.31 

•	 Laundry: Recent technical advances offer significant energy-savings potential;32 DOE believes there is 

technical potential for a 40%–70% reduction in laundry-related energy consumption. For example, 

Consortium for Energy Efficiency-tier 2 washers provide 43% energy savings33 over the current standard. An additional 50% can be achieved through low-temperature detergents, advanced fill controls, 

and water recirculation techniques to reduce hot water use; advanced agitation techniques34 and highefficiency motors35 to improve machine efficiency; and higher washer spin speeds, modulating gas dryers, heat pump dryers,36 improved drum insulation, and waste heat recovery to reduce drying energy. 

•	 Dishwashing: DOE believes that there is technical potential to reduce dishwashing energy consumption by 35%–50%. The Super-Efficient Home Appliances Initiative, adopted in August 2009,37 is currently promoting energy-efficient dishwashers that use 17% less electricity and 35% less water than 

the federal minimum. Over 20% additional energy savings can be achieved with other technologies, 

including advanced hydraulics,38 sorption assisted drying,39 improved food filters, efficient motors, and 

advanced controls.40
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Crosscutting Technologies

25

20

15

10

5

0

Primary Energy Consumption Impacted (TBTU)

Insulation Heat

exchangers

Motors DC & 

off grid

Working

fluids

Figure 14. Five Crosscutting Technologies that Have the Potential to 

Impact Energy Consumption 

Energy cascading and storage is not included in this figure because there is no available estimate of savings potential. 

Source: Department of Energy analysis using 2010 residential and commercial building energy consumption data from 

the Energy Information Administration. (2011). Annual Energy Review 2011. Washington, DC: Department of Energy. 

Accessed at http://www.eia.gov/forecasts/aeo/data.cfm

Several material breakthroughs would provide significant performance benefits in multiple energy end uses; 

the following are the most significant. Figure 14 shows the annual primary energy consumption that could be 

affected by improvements in these crosscutting technologies.

Insulation: Insulation is ubiquitous in both building envelopes and equipment/appliances. Technical headroom includes increasing thermal insulation per unit thickness through advanced foams, nanotechnology, or 

vacuum-insulating panels. 

Heat Exchangers: Heat exchangers are used in refrigeration, heating, air conditioning, and nearly every application that generates waste heat (e.g., computing), consuming 21 Quads (53%) of building energy consumption. Advancing heat exchanger materials to be cheaper, lighter, stronger, and more conductive could double 

the heat transfer coefficient to provide 0.7 to 1.1 Quads of annual energy savings.41 Additional advances include 

improvements to heat exchanger and fan design (e.g., whale fins) to increase efficacy with existing materials. 
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Motors: Motors account for an estimated 20%–40% of building-related electric use (8.5 Quads of primary 

energy) and 40%–50% of U.S. electricity use (approximately 18 Quads of primary energy).42 They are used in 

fans, pumps, compressors, and other assemblies in a vast number of appliances. The energy-savings potential 

depends on application; in aggregate, improved motors could reduce total U.S. electricity consumption by 12% 

or more through three approaches:43

•	 Variable Speed Motors: These could save 30%–50% more energy than their single-speed counterparts in various applications, including compressors, pumps, blowers, dishwashers, refrigerators, and 

air-conditioning systems. 

•	 Permanent Magnet Motors: Replacing induction motors with permanent magnet and variable reluctance motors could provide additional savings, especially for small motors. These designs are about 

15% better than today’s average induction motor and 5% better than the practical limit for induction 

motors.

•	 Material Improvements: Using today’s premium materials, motors can be more than 96.2% efficient;44 superconducting materials, amorphous steel, or other material advances could achieve efficiencies of 98.0%–99.5%, but could require considerable research to be cost effective.

DC and Off-Grid Equipment: Items using DC-based technology, such as modern-day electronics, efficient 

fluorescent and LED lighting, and motors, are a large and growing part of the electrical load. They currently total 11 Quads (28% of building-related energy consumption).45 Crosscutting breakthroughs that could improve 

efficiency include:46

•	 Eliminating DC-AC-DC Conversion: With the expected deployment of onsite photovoltaics and 

plug-in electric vehicles, the advantages of using DC power directly increase the benefits of a buildingwide DC bus system. Standards are under development to facilitate this transition. Solar-assisted cooling equipment offers one attractive application as power generation and cooling load are synchronized 

and direct-DC operation can improve efficiency. 

•	 Expanding the Use of Low-Power Circuits: The energy-saving integrated circuits and circuit designs 

used in portable electronics could be expanded to consumer electronics not traditionally focused on 

energy efficiency because they are not limited by battery life.

•	 Improving Power Conversion Efficiency: There are multiple approaches to improve power conversion efficiency, each offering up to 3% improvement for a total of more than 5% improvement at 

nearly zero cost.47

•	 Designing Advanced Semiconductor Materials: To reduce energy consumption and waste heat 

generation.
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Working Fluids: Today’s air conditioners, refrigerators, and heat pumps use compression cycle technology 

with high Global Warming Potential (GWP) working fluids. Advanced refrigeration technologies could both 

provide energy savings and eliminate these working fluids. U.S. emissions of high GWP gasses represent more 

than 135 million metric tons CO2 equivalent,48 equal to 2.4% of U.S. energy-related CO2 emissions. Refrigerant manufacturers are therefore developing new low GWP refrigerants, such as hydrofluoroolefins (HFOs), to 

meet new international regulations. For example, a Life Cycle Climate Performance analysis on the refrigerant 

HFO-1234yf49 shows it could remove 5.2 to 5.9 million metric tons CO2 equivalent on a global basis by the 

year 2017 if used in all new vehicle air-conditioning.50 This impact can be increased if HFO-R1234yf or refrigerant blends with HFO components, or if other low GWP refrigerants are used in residential and commercial air 

conditioning and refrigeration. The transition to low GWP refrigerants requires addressing chemical stability, 

flammability, and toxicity. It is worth noting that the compression cycle modification necessary to accommodate non-HFC working fluids can simultaneously improve cycle efficiency. 

Energy Cascading and Storage: Energy cascading is the process of using the waste heat from one process 

as the energy source for another. It can be integrated with distributed energy generation to minimize wasted 

energy. 

Breakthrough Technologies

Innovative technologies can transform the way energy is used for services. These opportunities tend to be higher risk, face additional barriers to development and deployment, and have a longer time horizon until impact; 

however, they can represent a “step-change” in energy consumption, economic feasibility, and/or American 

competitiveness. The timing and impact of these benefits are naturally difficult to predict. Innovative technologies under consideration or being researched include:

•	 Improved Dehumidification, Latent, and Sensible Cooling approaches and materials, including 

moisture transport membranes (ideally dynamically controlled) and liquid desiccants. Significant savings, on the order of 50%–90%, are possible for technologies optimized for specific climates and 

applications.51 

▪ Non-Vapor Compression (VC) Cycle Refrigeration technologies can improve efficiencies for refrigeration and HVAC application. These can be characterized by their theoretical Carnot efficiency, current state of development, developmental barriers, and current level of activity.52 Thermoacoustic and magnetic cooling are most likely to compete with vapor compression,53 and they could 

provide up to 30% improvement if they achieve their thermodynamic limits. Other candidates 

include solid-state technology (magnetocalorics, thermoelectrics, thermoelastic, thermoioinic, and 

thermotunneling), gas-based cycles (e.g., Stirling cycle), and alternative cycles (absorption, adsorption, and Vuilleumier cycles).54 Though some are commercially available today, research is needed 

to develop materials and improve engineering to make these systems compact.

•	 Multi-Photon Phosphors could provide an alternative to SSL and offer slightly higher efficacy if successful.

•	 Broadly Applicable Nanotechnology advances could provide significant, but difficult-to-quantify 

benefits through advanced material properties such as high-k dielectrics or high energy density storage.
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Buildings as Systems

Building system integration includes designing buildings to incorporate component operations, deploying integrated control systems, and operating and maintaining the building using those systems.55 It requires an iterative approach to reducing internal loads, controlling heat gain and loss through the envelope, refining building 

design, sizing and selecting HVAC equipment, and designing and integrating operating systems. All of these 

elements together comprise systems integration: they incorporate architectural design, engineering, and building use to meet building needs efficiently without compromising occupant safety or health. 

Residential and commercial buildings can be designed and operated to improve comfort and safety while 

reducing their lifecycle cost and environmental impact through enhanced efficiency. An integrated approach 

to building design and operation can provide energy savings that exceed 50% in new buildings and 30% in 

retrofit applications.56 Some whole-building techniques even show 80% savings over current designs.57 

Capturing those savings requires developing strategies to set goals, designing buildings (ideally from the outset) 

to meet those goals, and managing construction and operation to accomplish those goals . Strategies include:

•	 Reduce Internal Loads through Systems Integration:

58 Efficiency of individual appliances and 

pieces of equipment are covered in the companion technology assessment. However, the expected 

appliance and equipment thermal load fundamentally affects building design. 

•	 Improve the Building Envelope: The envelope, especially thermal insulation, is typically thought to 

provide only protection from the environment. Considering the envelope as an integrated component 

that manages solar heating gains, lighting, and ventilation can create energy efficiency and occupant 

health and comfort benefits. 

•	 Deploy Sensors, Controls, and Software: These modern components should be properly integrated 

into a building’s operation to automate systems, improve use of building information and occupant 

behavior, improve operations through retro- and continuous- commissioning, and leverage connection 

to the smart grid. 

•	 Whole-Building Energy Modeling is a critical enabling component of whole-building integration to 

minimize energy use and provide accurate and transparent predictions of energy performance. Further, with well-collected national data, it allows identification of technology gaps to better prioritize 

research, development, and deployment activities.

Systems Integration

A systems integration approach faces diverse barriers that arise from the existing building design and construction process. The current design and construction process decomposes the creation of a building into a 

large number of small steps, each with experts who advise on their particular component. Most buildings are 

assembled component-wise with fragmented decision making and responsibility. Therefore, many of the inefficiencies in modern buildings are system integration failures. 
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The integrated design process recognizes that reliable, high-performance designs require all relevant stakeholders and experts to discuss and resolve problems collectively. This has to begin early in the process, with appropriate decision-support tools available to evaluate the impacts of any proposed changes. Integrated design 

leverages advances in Building Information Modeling with new energy modeling for fast, responsive decision 

making. It extends the value of this process to include construction, commissioning, and handoff of the building, and then continues with operations and facility management. Because the benefits of system integration 

are not as easily quantifiable as those of individual appliance engineering, communicating its value is difficult. 

Design Guides: The Advanced Energy Design Guides, inspired by successful designs of actual buildings, use 

energy models to “pre-calculate” solutions applicable to commercial buildings. They have had broad market 

appeal with high recognition among practitioners and benefits estimate for hundreds of buildings.59 

Building Performance Labeling: Benchmarking and disclosing the energy performance of buildings can improve understanding of the costs and benefits of efficiency and raise awareness of and demand for high-performance buildings to “prime the market.” The Environmental Protection Agency has shown that labeling can 

be successful with appliances through its ENERGY STAR®60 program. Benchmarking and labeling programs like 

ENERGY STAR® and Leadership in Energy and Environmental Design are voluntary, but they have high awareness and brand recognition among consumers. Many cities and states have mandated energy benchmarking 

and disclosure for all commercial buildings.61 

Building Envelopes 

Building envelopes impact every element of building habitation. Energy lost through building envelopes accounts for 13% of U.S. primary energy, costing consumers more than $230 billion ($700 per person per year).62

Envelope and windows industries have historically had very slow product development and implementation 

cycles. Despite its higher lifecycle cost, single pane glass is still sold in Southern markets while double pane low 

e-glass has taken more than two decades to reach the existing buildings market. Stud walls (i.e., 2×4) with 

cavity insulation are still the norm, and conventional asphalt shingles on roof trusses continue to dominate the 

construction market; these technologies have gone almost unchanged since World War II. 

There are solutions that can save 20%–50% of that energy in existing buildings and, when coupled with other 

technologies, even more in new buildings or at times of equipment replacement and home improvement. Considering the envelope as an integrated component that manages solar heating gains, lighting, and ventilation, 

can provide additional benefits such as energy storage, superior task lighting, and improve indoor environmental quality. For example, the effective use of daylighting can reduce lighting energy consumption by 20%–60%, 

and the envelope can be designed so the building collects and stores energy.63

Improving building envelopes is complicated by the variety of climates in the United States and the differences 

in approach for new and existing buildings. Technical opportunities and efforts underway include: 

•	 Advanced Roofing Designs: R&D proceeds on a number of next-generation attic and roofing technologies,64 including durable white roofs, “cool color” low-emissivity roofing, above sheathing ventilation, radiant barriers, phase change materials,65 and increased deployment of conventional insulations 

to raise roof insulation levels to climate-appropriate levels as high as R-6066 or more.

•	 Highly Insulating and Dynamic Windows: Highly insulating windows require low thermal conductivity (i.e., R-values of 5–10), low infiltration, and climate-appropriate infrared emissivity. Cost-effective 

R-5 highly insulating windows were commercialized in 2010. Dynamic control of optical properties 

can manage summer solar gain and optimize winter gain to make windows a net provider of energy.
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•	 Wall and Basement Building Retrofits: Cost reduction of building retrofits can be achieved through 

improved installation techniques and business models of conventional insulation (e.g., “drill-and-fill,” 

exterior foam sheathing). Demonstration efforts focus on exterior insulation fitting systems that can 

yield R-values of 40–60.

•	 Highly Insulating Wall and Basement Approaches for New Buildings: New building codes will 

likely draw on technologies previously mentioned, as well as advanced approaches to framing and 

manufactured homes.

•	 Daylighting Research: Properly designed buildings can bring in high-quality light to reduce electricity 

consumption through integration with daylighting controls. Continued efforts focus on daylighting 

components for active light control; daylight solutions for deep perimeter zones in commercial buildings; double-skinned, ventilated façades; dynamic shading, and 3-D window products.

Envelopes can also solve or introduce occupancy issues; research areas include:

•	 Moisture: As the building enclosure becomes more efficient, moisture control issues must also be addressed to ensure that moisture does not collect in building components and cause durability or health 

problems. 

•	 Indoor Environmental Quality: In addition to reducing energy, efficient building designs can also 

improve occupant comfort and health. Detecting and eliminating building pollutants, including radon, 

combustion by-products, and chemicals (e.g., volatile organic compounds), remains an important area 

of research.67 

Building Sensors, Controls, and Diagnostics 

Building sensors, controls, and diagnostics can maximize the value of other building components and systems. High-performance buildings require reliable and standardized communications, information technology 

infrastructure, and protocols at both the component and whole-building level. Controls can be integrated 

through computerized building management systems that optimize energy use and interface with energy 

systems through a modernized grid. Buildings that use these systems can have lower maintenance and energy 

costs, better thermal comfort, and improved indoor air quality.68 

The limited penetration of whole-building instrumentation69 can be explained, in part, by the historically high 

cost of wiring and configuration, calibration and stability concerns, and the uniqueness of each building. With 

recently developed wireless technologies, improved sensors, and powerful and flexible software and computer 

systems, many of these barriers can be overcome. Wireless sensor networking70 may provide low-cost, lowpower, and reliable networks that can lower total ownership cost and improve building performance. Four 

potential benefits of sensors, controls, and software can now be realized: 

•	 System Automation: Device-level or whole-building sensors and controls can provide energy savings, increased convenience and operational simplicity, and decreased maintenance costs. Successful 

examples include inactivity-based timers, occupancy sensing, daylighting controls, and whole-home 

automation. For example, electric “plug load” use only decreases by 30%–40%71 when buildings are 

unoccupied; full instrumentation could improve this reduction to more than 90%.72
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•	 Improved Data Use: Reliable, timely, and easy-to-understand information facilitates informed decisions about energy conservation. Even systems that currently collect large datasets fail to translate this 

data into actionable information. Energy information systems can better inform facilities operators 

and help them achieve expected performance.73 They allow for rigorous energy analyses that include 

normalization, standards-based calculations, anomaly detection, and forecasting. Some are exploring 

simplified approaches to expand such tools to homes.74 Advanced billing information can also be a 

tool here. Providing more detailed and frequent usage information to homeowners through accepted 

channels, such as energy bills, can also reduce energy consumption, with at-scale deployment reductions of 1.5%–3.5%75 in household electricity use.

•	 Commissioning and “Re-Tuning:” Poor operation of commercial buildings wastes energy; buildings need regular tune-ups and quality checks to sustain peak energy performance and ensure that 

they are being operated according to design intent after construction. This sensor-enabled process 

of commissioning or “re-tuning” can provide significant energy savings and extend equipment life at 

a very low cost. A study of commissioning projects in more than 600 buildings nationwide showed 

median whole-building energy savings of 16% and 13% in existing buildings and new construction, 

respectively, with median payback times of 1.1 and 4.2 years, respectively.76 Similarly, re-tuning large 

commercial buildings enabled by energy management and control systems can reduce HVAC energy 

use by 5%–20%.77 

•	 Smart Grid: Dynamic information exchange between the electrical system and the building can improve the overall efficiency and reduce the cost of the power system. These benefits are realized by 

moving building loads from “on-demand” usage to intelligent usage, a shift made possible by building energy storage (thermal or electric) and flexible, interactive appliances (e.g., demand-managed 

air-conditioning, time-delayed dishwashing cycles). Significant infrastructure investment in both the 

grid and buildings is needed to capture such benefits. A necessary prelude to this type of investment 

is standardization.78 

Data-Enabled Building Modeling

Whole-building modeling, involving “engines” and “applications,” can improve the accuracy of building system performance predictions. “Engines” deal with the numerical analysis of building physics and mechanical 

systems, while applications model usage scenarios, such as building design, building operation, or building 

portfolio analysis for code development. “Applications” are the user interface and other software that use the 

core physics the engines provide. 

Historically, the focus has been on engine development (first DOE2 and then EnergyPlus) with smaller investments in testing and validation; only recently has there been a focus on user interfaces. A building energy modeling software would be enabled by the development of standards and interoperability for both model input 

and model output data; collecting and publishing repositories of component, system, and building models; and 

automated model acquisition and calibration research. 

The view of buildings as systems continues to be challenged by a dearth of data. The Residential Energy Consumption Survey, the Commercial Buildings Energy Consumption Survey, and other databases, such as the 

California Commercial End-Use Survey, are critical data resources; although, they lack metered end-use energy 

data and system and operational characteristics. The ENERGY STAR® portfolio manager tool provides generalized information for some building types. Other tools may be developed for niche applications (e.g., specialty 

building types or tools for a specific region or market segment). Sharing data on measured energy performance 

would enable innovation in building performance, as well as in tool development. 
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DOE History and Accomplishments

Building and appliance-related work in DOE ranges from emerging technologies through technology validation 

and market development to standards and analysis. Deployment activities in the form of weatherization are 

the largest part of building-related spending, averaging $275 million annually from 2001 to 2010.79 Over the 

past decade, building technology funding has more than tripled, increasing from $59 million to $219 million 

(Figure 15). 

700

650

550

500

450

600

400

350

300

250

200

150

100

50

0

Annual Budget Appropriations to Buildings 

(2010 $million)

1985 1990 1995 2000 2005 2010

FEDERAL ENERGY MANAGEMENT PROGRAM

WEATHERIZATION, STATE AND LOCAL, INTERGOVERNMENTAL ACTIVITIES

BUILDINGS TECHNOLOGIES

YEAR

Figure 15. Historical Funding of DOE Building and Appliance Programs

Sources: (1985–2002) Current Congressional Appropriations from DOE CFO, Office of Budget; (2003–2008) DOE EERE 

Budget Office (http://www1.eere.energy.gov/ba/pba/budget_archives.html); (2009– 2010) 2011 FY11 Congressional 

Budget for DOE EERE (http://www1.eere.energy.gov/ba/pba/pdfs/fy11_budget.pdf). Converted to 2010 $million using 

consumer price index from the U.S. Department of Labor, Bureau of Labor Statistics (ftp://ftp.bls.gov/pub/special.

requests/cpi/cpiai.txt).
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Together, equipment standards, the $30 million Golden Carrot Award from the Super Efficiency Refrigerator 

Program, and the ENERGY STAR program reduced the energy consumption of residential refrigerators by 70% 

between 1974 and 2006, even as the average retail price decreased by 40% between 1980 and 2006 and 

capacity increased by 15%.80 

Recent accomplishments include:

•	 Legislation and standard rulemakings completed between 1987 and 2010 reduced primary energy use 

by 3 Quads (about 3%) in 2010, a cumulative energy consumption reduction over that period of 26 

Quads.81 These rulemakings are projected to save another 126 Quads between 2010 and 2070, with 

annual energy savings peaking at nearly 5 Quads between 2020 and 2025. 

•	 Codes adopted and implemented between 1990 and 2008 provide more than $3 billion per year in annual cost savings through more than 0.25 Quads of annual energy savings.82 In 2011, DOE-sponsored 

proposals passed into model energy codes to achieve 30% energy savings in residential and commercial buildings compared to a 2006 baseline.83

•	 Completing 13 standards since January 2009. These are estimated to save consumers hundreds of billions of dollars over the next two decades. 

•	 Demonstrating advanced SSL technologies: a small-form factor LED light source of 350 lm at 80 lm/W; 

deep green LEDs achieving peak internal quantum efficiency of 50%; and commercial, high-power 

white LEDs delivering 121 lm/W (a typical 100 W incandescent bulb is 17 lm/W).

•	 Supporting research that inspired a commercialized hybrid water heater that is 50% more energy efficient than the traditional 50 gallon electric resistance water heater.

DOE Role

The Department’s role in building energy efficiency lies primarily in its informational and R&D capability activities. Since the primary barriers to increasing building efficiency are largely non-technical, the availability of 

high-quality information to a wide range of decision makers affects deployment of building technologies. In 

addition, the diversity of both technologies and stakeholders involved in building efficiency makes it difficult to 

gather the information critical to technology development and deployment. There is a great lack of data about 

how and how much energy is used in buildings. The Department’s Energy Information Administration conducts 

the Residential Energy Consumption Survey and the Commercial Buildings Energy Consumption Survey, which 

are critical to providing information to decision makers. 

DOE collaborates with industry groups to develop model energy codes and design guides that provide valuable 

direction in the design and construction of new buildings. Further, DOE is currently rolling out a home energy 

score tool, which also informs development of a national standard for commercial building rating and labeling. 

The commercial labeling scheme takes into account the building envelope, mechanical and electrical systems, 

and major energy-using equipment.

DOE also maintains base research capabilities in building efficiency. The Department’s modeling and simulation, materials science, and fundamental engineering science capabilities help advance building efficiency technologies. Furthermore, the Department’s Greater Philadelphia Innovation Cluster Energy Innovations Hub not 

only performs R&D, but also demonstrates and assesses efficiency technologies. The Department’s regulatory 

authority to set efficiency standards for appliances serves an informational role. Building on its R&D capability 

and through stakeholder engagement, DOE sets baseline efficiency for many household and commercial appliances.84
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BUILDING AND INDUSTRIAL EFFICIENCY

INDUSTRIAL EFFICIENCY

Industrial Materials and Processes

The U.S. industrial base is diverse, with about two-thirds of end-use energy85 being consumed by energy- intensive industries, including chemicals, forestry products, petroleum refining, iron and steel, glass, aluminum, 

metal-casting foundries, and cement.86 It also includes a wide array of manufacturing operations that convert 

raw materials into finished products–from the foods we eat to the infrastructure that surrounds us. In 2009, 

manufacturing accounted for 11% of GDP and directly employed 12 million people,87 supplied 57% of U.S. 

exports,88 and produced nearly 20% of the world’s manufacturing value added.89 

The industrial sector uses about one-third of U.S. primary energy. It is the most diverse sector, both in the 

types of energy services required and in the mix of energy sources that provide those services. Industrial energy 

use results in significant CO2 emissions from combustion of fuels, and industrial processes generate a range 

of other greenhouse gases, such as nitrous oxide, methane, halons, and others with high GWP. In 2006, U.S. 

industry accounted for approximately 28% of total energy-related CO2 emissions.90 Industrial greenhouse gas 

emissions can be reduced significantly through changes in energy use, development of new materials, and 

improvement of process efficiencies. 

Over the past two decades, as U.S. manufacturing has faced growing global competition and market pressures, 

production technology has advanced at different rates across different industrial subsectors. This is due to differences in the rate of product innovation, whether technology improvements require new manufacturing processes, and product commoditization, among others. For example, technological advance is relatively rapid in 

automotive, semiconductors, and electronics industries, and relatively slow in the steel and cement industries. 

In general, energy-intensive heavy industries are mature and slower to adopt technological innovation due in 

part to large sunk capital; for example, equipment changeovers can take from 20–50 years in these industries 

and require significant capital investment.91 

Today’s manufacturing sectors must continually improve productivity and efficiency to remain competitive. The 

new, efficient manufacturing plants built in developing economies compared to the older domestic manufacturing base adversely affect U.S. competitiveness. Between 1980 and 2009, U.S. industrial energy intensity 

(Quads/$GDP) fell nearly 50% as the structure of industry changed, new technologies were deployed, and firms 

improved the efficiency of their operations (Figure 16). 
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220

200

180

160

140

120

100

80

60

40

Index (1980 = 100)

INDUSTRIAL GDP* INDUSTRIAL ENERGY CONSUMPTION INDUSTRIAL INTENSITY

* Change in real value-added for industrial sector 1980 1983 1986 1989 1992

199519982001200420072010

YEAR

Figure 16. U.S. Industrial Output, Energy Consumption, and Intensity from 1980 to 2009

Sources: Energy Information Administration. (2010). Annual Energy Review. Washington, DC: U.S. Department of 

Energy. Accessed at http://www.eia.gov/totalenergy/data/annual/pdf/sec2_9.pdf 

Bureau of Economic Analysis. GDP by Industry. Washington, DC: U.S. Department of Commerce. Accessed at http://

www.bea.gov/industry/gdpbyind_data.htm

The steel industry provides an example of reductions in energy intensity that resulted, in part, from new technology. For example, advances in electric arc furnace technology and the development of thin-slab casting 

helped the steel industry greatly expand the use of scrap steel. Adoption of electric arc furnace and other technology improvements were largely responsible for a decrease in steel industry energy intensity from about 58 

million British thermal units (MBtu)/ton in 1950 to 50 MBtu/ ton in 1975 to about 12 MBtu/ton in recent years.92
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Technology Status

The industrial sector is highly diverse, using thousands of processes to produce tens of thousands of products. 

However, energy use can be characterized by several key systems, with thermal processes dominating, as 

shown in Figure 17. Motor systems constitute the largest industrial use of energy for non-thermal processes.

Steam is produced in boilers for applications that range from process use to cogeneration (combined heat and 

power, or CHP). Electricity is used to drive machines, such as pumps, fans, compressors, and materials-handling 

equipment. Energy is also used for space heating and lighting. Where economically feasible, recovery systems 

capture waste heat for beneficial uses, such as material preheating or steam generation.

6.4 Quads

6.1 Quads

5.4 Quads

2.3 Quads

1.8 

Quads

Other Processes

Steam

Process Heating

Machine Drive

Non-process

Figure 17. Industrial Primary Energy Use (Quads)

Industrial primary energy use is dominated by thermal processes. Note: Approximately half of the energy required 

to generate steam use is additionally attributable to process heating energy demand. Source: Manufacturing Energy 

and Carbon Footprint Analysis on select energy-intensive industries, based on MECS data. Energy Information 

Administration. (2009). 2006 Manufacturing Energy Consumption Survey. Washington, DC: Department of Energy. 

Accessed at http://www.eia.gov/emeu/mecs/mecs2006/2006tables.html; Industrial Technologies Program. (2011). 

Washington, DC: Department of Energy. Accessed at http://www1.eere.energy.gov/industry/rd/footprints.html
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Figure 18 shows the crosscutting nature of important energy delivery systems for energy-intensive manufacturing sectors. These systems include: 

•	 Steam Systems (6.4 Quads) provide energy for process heating (3.2 Quads), machine drives (0.4 

Quad), and buildings HVAC (0.2 Quad), with conversion and distribution losses comprising the balance (2.6 Quads). That energy includes steam production and generation losses on manufacturing sites 

from conventional boilers (2.1 Quads8) and CHP systems (3.1 Quads8), as well as offsite steam production and losses (1.2 Quads8

). Common end-use equipment that uses steam includes heat exchangers, 

turbines, fractionating towers, strippers, and chemical reaction vessels. Industrial boiler efficiency can 

be improved by innovations, such as high-intensity heat transfer; high-efficiency, low-emission burners; intelligent control systems; efficient preheating; flame radiation; and other enhancements.

•	 Process Heating (6.1 Quad) requires approximately 5 Quads of mostly fossil fuels and 1.1 Quads 

of electricity (comprising 0.75 Quad of generation and distribution losses and 0.38 Quad of useful 

energy). When including the 3.2 Quads of steam used for processes heat, more than 9.3 Quads of 

energy is used for process heating.93 Common process heating systems include furnaces, ovens, heat 

exchangers, digesters, evaporators, kilns, dryers, and melters. This equipment is used for separation 

and reactor preheating, evaporation, curing, drying, agglomeration, sintering, forming, smelting, and 

other specialized heating processes. Energy losses occur from system or box losses, which may include 

radiation and convection losses; insulation losses; wall, door, or opening losses; or cooling losses. 

Losses also occur through flue or exhaust gases. 

•	 Machine Drive Systems (5.42 Quads) used throughout manufacturing account for more than 5.17 

Quads of primary energy producing electricity (3.42 of losses and 1.75 of useful energy);8 0.25 Quad 

of mostly fossil fuel; and 0.64 Quad of steam use (0.26 of losses and 0.38 of useful energy).8 In many 

cases, efficiency can be improved by upgrading the motor (e.g., variable speed drives, high-efficiency 

motor). The efficiency of common motor systems, such as pumps, fans, compressed air, and materialhandling systems, can also be increased by system optimization. 

•	 Other Uses (4.4 Quads) include non-process energy and other process energy. Non-process energy 

(2.26 Quads) includes buildings HVAC and lighting, other facility support, and onsite transportation; 

additionally, 0.32 Quad of steam energy (0.13 of losses and 0.19 of useful energy) support building 

HVAC. Other process energy (1.82 Quads) includes electro-chemical processes, process cooling, and 

refrigeration. There are diverse opportunities to decrease energy consumption, including next-generation processes and heat pump systems.

Any industry that has both electrical and thermal requirements could potentially benefit from CHP. The higher 

efficiency inherent to CHP combined with the benefits of onsite power generation, which eliminates transmission and distribution losses, reduces primary energy use and lowers greenhouse gas emissions. Overall efficiencies of 70% or higher are achievable by generating electricity and producing useful thermal energy from a 

single fuel source (natural gas, coal, oil, and alternative fuels). This thermal energy can be used for direct process applications, or it can be used indirectly to produce steam, hot water, hot air for drying, refrigeration, or 

chilled water for process cooling. CHP generally consists of a prime mover, a generator, a heat recovery system, 

and electrical interconnection equipment configured into an integrated system. 
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2

1

0

Forest Chemicals

Products

Petroleum

Refining

Iron and

Steel

Other Energy

Intensive Subsectors**

Primary Energy (Quads)

NON-PROCESS OTHER PROCESS* MACHINE DRIVE PROCESS HEATING STEAM SYSTEMS

* Process cooling & refrigeration, electrochemical, other processes

** Alumina & aluminum, cement, glass, founderies

Figure 18. Energy Use by Industrial System by Industry Subsector* 

Process cooling & refrigeration, electrochemical, other processes. **Alumina & aluminum, cement, glass, foundries. 

Source: Manufacturing Energy and Carbon Footprint Analysis on select energy-intensive industries, based on MECS 

data. Energy Information Administration. (2009). 2006 Manufacturing Energy Consumption Survey. Washington, DC: 

Department of Energy. Accessed at http://www.eia.gov/emeu/mecs/mecs2006/2006tables.html; 

Industrial Technologies Program. (2011). Washington, DC: Department of Energy. Accessed at http://www1.eere.

energy.gov/industry/rd/footprints.html 
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CHP systems are typically identified by their technology types (“prime movers”), which include reciprocating 

engines, combustion or gas turbines, steam turbines, microturbines, and fuel cells. Waste heat CHP systems 

recover energy from hot exhaust for conversion into electricity through a Rankine power cycle. Steam is most 

often used in Rankine cycles and in industrial applications to generate power from operations with hot exhaust 

gases, such as coke oven batteries and cement kilns. Lower temperatures often found in heat recovery applications allow other working fluids, such as hydrocarbons, to be used as well. Low-quality recovered heat can be 

used for a variety of applications, from absorption cooling to food processing.

CHP is already an important resource for the United States—there is 85 gigawatts of CHP capacity at more 

than 3,600 industrial and commercial facilities, which represents approximately 8% of current U.S. generating 

capacity and more than 12% of annual power generation.94 CHP can be utilized in a variety of applications 

that have significant, and coincident, power and thermal loads. Eighty-eight percent of existing CHP capacity is 

found co-located with or in industrial applications, providing power and steam to energy-intensive industries, 

such as chemicals, paper, refining, food processing, and metals manufacturing. Countries such as Denmark 

and the Netherlands have a much higher percentage of their total power supplied by CHP (50% and 30%, 

respectively) than the United States. A 2008 Oak Ridge National Laboratory study indicated that the potential 

exists in the United States to more than double existing CHP capacity, increasing CHP’s contribution to 20% of 

total generation by 2030, which would save an estimated 5.3 Quads of fuel annually.95 

Although CHP is a mature technology, market deployment is impeded by technical and investment challenges.96 Improper installation or lack of coordination between developers and utilities in CHP planning and installation can result in grid operation technical complications. Improvements in the energy and environmental performance of CHP and thermal energy recovery technologies are needed to lower capital costs. Increasing fuel 

flexibility of combustion systems with no degradation of emissions profile, performance, reliability, availability, 

maintainability, and durability will reduce operating costs and the impacts of fuel price volatility. 

Using alternative fuels requires modifications to a CHP system’s prime mover for acceptable levels of performance, emissions, durability, and ease of maintenance. It also requires investment in fuel gathering, handling, 

treatment, and storage equipment, which often adds a parasitic load to the system. All of these elements affect 

the lifecycle cost/benefit analysis. Finally, capital cost reductions in CHP systems can be made with better integration of major subsystems into packages. This is particularly valuable in the mid- to small-size CHP market. 

System designs that incorporate intelligent controls, sensors, and facility energy management systems with 

generation and heat recovery technology would offer value. 

Market Potential 

Transformational developments in next-generation manufacturing concepts can enable revolutionary advances 

in energy efficiency and carbon abatement. This includes innovating the next generation of processes and materials with lower embodied energy and lifecycle costs for all manufactured products. 

Innovative enabling technologies for energy-efficient and low CO2-equivalent emission products and processes 

can take advantage of developments in sensors and controls, catalysis, nanotechnology, micro-manufacturing, 

and reducing the GWP of industrial gases. As shown in Table 15, there can be substantial improvement over 

the next decade at negative cost. 
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Several studies have evaluated the potential for both cost-effective energy efficiency improvements and opportunities to advance current state-of-the-art technology toward practical energy minimums. For example, one 

study estimated that the industrial sector can reduce energy use by 18% by 2020 with existing technologies 

and net present value-positive investments (i.e., energy cost savings resulting from technologies financed with 

loans would yield positive cash flow).98 On a primary energy basis, this study estimated 2.1 Quads in costeffective available savings in 2020 from energy support systems, including steam, motors, and buildings, and 

an additional 0.9 Quads available through increased industrial CHP adoption; available savings from specific 

industrial processes were estimated to be an additional 2.9 Quads. The National Academies has also surveyed 

a range of studies, which estimated the savings potential from deployment of existing and emerging technologies to be 4.9 to 7.7 Quads by 2020, inclusive of the potential for CHP.99

The Energy Information Administration currently projects a 54% increase in industrial shipments between 2009 and 

2035 in the AEO2011 reference case, but only projects a 25% increase in industrial primary energy consumption during 

this time.100 Energy consumption growth is moderated by a shift in the mix of output and improvements in energy 

efficiency. Overall energy intensity in the industrial sector declines by 19% in the reference case. Also of note from the 

Energy Information Administration is a side case where industrial technology is “frozen” at current levels—in 

this case, industrial consumption (outside of refining) is projected to be 2.66 Quads higher than the reference 

case in 2035, highlighting the impact of expected future technology development.101

Technology Potential

Because the opportunity for industrial energy efficiency is diverse, it is difficult to assess comprehensively. The 

efficiency potential for ubiquitous adoption of existing state-of-the-art technologies and best practices, as well 

as the potential for advanced technologies that have yet to be fully developed, is shown in Table 16. The energy consumption with known, yet unrealized technology opportunities are considered the practical minimum, 

while physical laws dictate the theoretical minimum. 

Sector

Primary 

Energy 

Savings

Payback 

Time

Investment 

Required

Savings 

Achieved 

(2009$)

Scope of 

Potential 

Opportunity

Manufacturing 

and Other 

Industrial

5 

Quad/year 2.4 years $113 billion $442 billion

330,000 

establishments

Table 15. Opportunity for Energy Efficiency Savings between 2010 and 2020 for Investments that 

Are Net Present Value Positive

Source: McKinsey. (2009) Unlocking Energy Efficiency in the U.S. Economy.

97
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Other analyses identify cost-effective potential energy savings of 4.9 to 7.7 Quads per year by 2020, a reduction 

of 14%–22% from the AEO2010 industrial baseline.110 

Recent reports discussing industrial efficiency include:

Energy Materials Blue Ribbon Panel. (2010 and 2011). Linking Transformational Materials and Processing for an Energy-Efficient 

and Low-Carbon Economy: Creating the Vision and Accelerating Realization. Warrendale, PA: The Minerals, Metals, and 

Materials Society. 2010 Report accessed at http://energy.tms.org/docs/pdfs/VisionReport2010.pdf. 2011 report accessed at 

http://energy.tms.org/docs/pdfs/Opportunity_Analysis_for_MSE.pdf

National Academy of Sciences. (2009). Real Prospects for Energy Efficiency in the United States. The National Acadamies Press. 

Washington, DC. Accessed at http://www.nap.edu/catalog.php?record_id=12621 

Science and Technology Policy Institute. (2010). “The White Papers on Advanced Manufacturing Questions.” Washington, DC. 

Accessed at http://www.whitehouse.gov/sites/default/files/microsites/ostp/advanced-manuf-papers.pdf 

International Energy Agency. (2007). Tracking Industrial Energy Efficiency and CO2 Emissions. Paris, France. Accessed at 

http://www.iea.org/textbase/nppdf/free/2007/tracking_emissions.pdf

Industrial

Subsector

Average 2008a Energy Use, Quads/Year (% efficiency 

improvement over 2008 average)

Total

Energy

Quads

Energy

Intensity

(MMBtu/$)

State-ofthe-Art

Quads (%)

Practical

Minimumb

Quads (%)

Theoretical

Minimumb

Quads (%)

Chemicals102 6.9 30 5.70 (18) 2.00 (71%) 0.82 (88%)

Pulp & Paper103 2.2 14 1.60 (26) 1.30 (39%) 1.20 (43%)

Petrol Refining104 3.9 18 2.80 (30) 2.40 (38%) 1.10 (71%)

Iron & Steel105 1.5 20 1.20 (22) 1.10 (39%) 0.06 (84%)

Aluminum106 0.4 13 0.34 (12) 0.11 (72%) 0.01 (61%)

Glass107 0.2 9 0.14 (34) 0.01 (52%) 0.01 (61%)

Cement 0.4 54 0.30 (30)c N/A N/A

Table 16. Average, State-of-the-Art, and Potential Improvements for Major Industrial Subsectors

a

AEO108; bDOE Industrial Technologies Program Bandwidth Studies103,104,105,106,107,108; cIEA data109; N/A: not available.
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Next-Generation Manufacturing Processes

Highly efficient processing can be achieved by reducing and integrating process steps; developing alternative, 

low-energy pathways; and developing entirely new processes and unit operations.

Technology areas that are expected to have large energy benefits across a variety of industries include:

•	 Reactions and Separations: New technologies with improved energy efficiency and process intensification applicable to a wide range of industries, such as oil refining, food processing, and chemical 

production. Examples include separation processes that rely on high-performance membranes and 

catalysts.

•	 Waste Heat Minimization and Recovery: Technology advances in ultra-efficient steam production, 

high-performance furnaces, and innovative waste heat recovery that contribute to sustainability, reduced water use, and a lower energy footprint. 

•	 Advanced Forming and Fabrication Technology: Allows for the manufacture of components in 

near-final form, limiting post-processing of components, which lessens required materials and energy 

input. 

•	 Biomimetic Processing: New production systems that mimic the low-emission, low-temperature fabrication of living systems. Replacement of traditional processing routes in areas such as chemical catalysis and polymer manufacturing could enable lower energy usage and carbon emissions. 

•	 Alternatives to High-Temperature Processing: Improvements in producing/recovering materials 

that exploit lower-energy or non-thermal alternatives to conventional, high-temperature processing 

technologies. Examples include water-based selective extraction of critical materials from low-grade 

ores, processes relevant to obsolete electronic equipment and waste landfills, and low-temperature / 

high-efficiency chemical or electrochemical processes. 

•	 Sensors and Process Control: Sensors and process controls would lead to highly automated processes with efficient, intelligent feedback control through continuous monitoring and diagnosis. Sensors are used for inferential controls, real-time and nondestructive sensing and monitoring, wireless 

technology, and distributed intelligence.

•	 Motors and Drive Systems: A next generation of motor and drive improvements is on the horizon, 

including motors with high-temperature superconducting materials. Superconductors can be used to 

increase the magnetic field in a motor, thereby dramatically reducing motor size, weight, and energy 

losses

Electrolytic processing of titanium powder is one example of order-of-magnitude reduction in energy use that 

is achievable through low-temperature processing (as discussed in the Report on the QTR).111 Selective heating of composite parts is a second example of the energy savings that have been demonstrated using nextgeneration processes. More efficient is electromagnetic heating that can be tailored to the susceptibility of 

materials. By putting energy only where it is needed, a manufacturer can selectively heat the composite part; 

alternatively, the thin face of the die can be selectively heated. In both cases, the entire autoclave does not need 

to be heated, which significantly reduces energy use. While energy savings is an important factor, this type of 

selective electromagnetic heating can enable other advantages over traditional thermal processes, including 

highly controllable heating rates, bulk volumetric heating, reduced processing time, improved yield, and smaller 

equipment footprint.112
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Next-Generation Materials

Next-generation materials could achieve order-of-magnitude improvements (e.g., extend service life tenfold) in 

products and components via unprecedented materials properties, reducing embedded energy. These materials 

and associated production technologies can reduce energy use, costs, and pollution, and also improve product 

quality. With the manufacture of new energy technologies growing, it may be important to develop substitutes 

for a range of critical materials (e.g., magnetic materials containing rare earth elements used in electric motors, 

phosphors used in SSL).

Some examples of next-generation materials categories that could reduce energy consumption across the 

economy include the following. For a more comprehensive list, see the vision report of the Energy Materials 

Blue Ribbon Panel.113

•	 Lightweight Materials: For example, inexpensive, high-performance carbon fibers.

•	 High-Performance, Low-Cost Heat Transfer Materials: For example, low-cost titanium. 

•	 Functional Coatings and Interfaces: For example, coatings and thin films that provide functional 

surface interactions, enabling a new generation of smart products.

•	 Thermal and Degradation Resistant Materials: Materials with extended lifespan at higher temperatures can improve productivity, reduce or eliminate plant down time, and reduce energy intensity. 

•	 Critical Materials: Critical materials are used directly in products (e.g., photovoltaics, LEDs, and alloying compounds), as well as in process steps (e.g., platinum catalysts or palladium and rhodium 

electrodes). Several approaches include finding new sources of such materials, discovering ways to 

reduce content of such critical elements in existing components, and identifying new compositions 

and approaches that do not rely on them. For example, technologies that decrease the cost of separating critical elements from recycle streams and ores, in some cases requiring next-generation process 

technologies.

•	 Bio-Materials; Bio-Products: Materials derived from renewable biomass resources can replace petrochemical precursors and feedstocks. Today, more than 90% of key organic chemicals are derived 

from petroleum feedstocks.114 Product examples include packaging, polymers, engineered plastics, and 

resins that can be blended with traditional plastics to increase recyclability. Direct use of biomass can 

include wood fibers for textiles, and composites produced from nanocrystalline cellulose for aerospace 

applications.

•	 Materials for Harsh Environments: High-performance materials, such as ceramics, engineered polymers, and metallics, can operate in extreme environments. 

•	 Amorphous Materials: Bulk amorphous (non-crystalline) metallic materials have achieved combinations of mechanical properties that improve performance (strength, wear, and corrosion) at a low cost 

compared to those of comparable conventional alloys. Amorphous magnetic materials can directly 

impact energy consumption, such as by reducing hysteresis and eddy current losses in motor cores.
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Policy Context and Market Barriers

National and state policies can impact the deployment of efficient industrial technologies and projects. For 

example, motor efficiency standards first passed in the Energy Policy Act of 1992 helped transform the marketplace for high-efficiency motors, resulting in significant energy savings. As a result of these standards, motor 

manufacturers created the voluntary labeling program NEMA Premium, which is backed by the National Electrical Manufacturers Association. Motor standards have been recently strengthened by the Energy Independence 

and Security Act of 2007.

The Energy Independence and Security Act of 2007 also included incentives for recovering industrial waste 

energy, improving data center energy efficiency, and deploying CHP. Limited data is available to assess the effectiveness of these measures.

National and state policies, ranging from tax policy to environmental and permitting regulations, also impact 

technology deployment. Tax credits designed to encourage technology adoption can be limited by other tax 

policies, such as tax credit ceilings or depreciation rules. Environmental regulations, such as the Clean Air Act, 

have improved industrial energy efficiency in order to reduce criteria pollutants from the combustion of fuels.

A recent McKinsey & Company report115 outlined some of the key barriers to development and adoption of 

energy-efficient technologies in the industrial sector. Among these barriers are:

•	 Competition between energy efficiency improvements and many other corporate priorities for limited 

capital

•	 Low awareness of the benefits and applications for more efficient technologies, especially among top 

management

•	 Adverse view of higher-risk transformational technology projects

•	 Constraints on procurement/ distributor availability

•	 Transaction barriers that include space constraints and business disruption.

Similar barriers, in addition to tax codes/depreciation rules and regulatory requirements, have been noted in 

other studies.116 
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DOE History and Accomplishments

The Federal Non-Nuclear Energy Research and Development Act of 1974 established The Industrial Energy 

Conservation Program in 1975 to improve industrial energy efficiency through R&D on high-risk, innovative 

technologies. The program was further shaped by the Department of Energy Organization Act of 1977. Subsequent DOE activities addressed both the basic process industries (industry-specific technologies) and process 

peripherals (crosscutting technologies). The Energy Analysis and Diagnostic Center program was instituted at 

universities throughout the country to provide energy audits for small- and medium-sized manufacturers who 

lacked internal expertise in energy efficiency, as well as training for engineering students in energy efficiency 

practices.

As global competition increased in the 1980s, projects emphasized productivity, capital efficiency, and quality, in addition to energy efficiency. With growing environmental regulations, industrial waste reduction and 

pollution prevention also became part of the R&D portfolio, as did fuel flexibility. By 1994, investments were 

focused on the most energy-intensive industries, working with the private sector to identify the precompetitive 

technologies critical to future success. 

More recently, DOE partnered with industry to reduce industrial energy use, carbon emissions, and waste, 

while also boosting productivity and economic competitiveness. It does so through R&D, as well as technical 

assistance activities that enable industrial subsectors to improve their energy efficiency. 

The Department has supported more than 600 separate R&D projects that have produced more than 200 commercial technologies. In addition to direct energy savings, industry has also benefitted from improved productivity, reduced resource consumption, decreased emissions, and enhancements to product quality associated 

with these technological advances. In addition, many projects have expanded basic knowledge about complex 

industrial processes and have laid the foundation for developing future energy-efficient technologies. 

Beyond R&D, DOE provides tools, training, assessments, and technical assistance to help industrial plants identify process improvement opportunities with near-term payback. Since their inception in 1976, the Industrial 

Assessment Centers have conducted more than 15,000 assessments, resulting in more than 100,000 recommendations with an average payback period of about one year and implementation rate of about 50%.117 

An important DOE goal is to foster improved energy management across industry by establishing scalable 

mechanisms to identify, deploy, certify, and reward effective industrial energy management practices and individuals. DOE does this by helping to develop tools and protocols to enable industry to measure and manage 

energy usage and by promoting education and hands-on training for a new generation of energy management 

engineers (Industrial Assessment Centers and university-based consortia that focus on precompetitive manufacturing R&D).
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1

 These averages hide wide variation by size, climate, and building type, as well as by occupancy and use; there can be up to a 

10:1 difference between “similar” buildings.

Energy Information Administration. (April 2011). “Residential Sector Key Indicators and Consumption, Reference Case.” Annual 

Energy Outlook 2011. Washington, DC. Accessed at http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2011&subject=0-

AEO2011&table=4-AEO2011®ion=0-0&cases=ref2011-d020911a 

Energy Information Administration. (April 2011). “Commercial Sector Key Indicators and Consumption, Reference Case.” Annual 

Energy Outlook 2011. Washington, DC. Accessed at http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2011&subject=0-

AEO2011&table=5-AEO2011®ion=0-0&cases=ref2011-d020911a 

2

 National Academy of Sciences. (2009). Real Prospects for Energy Efficiency in the United States. The National Acadamies Press. 

Washington, DC. 

3

 National Research Council. (2001). Energy Research at DOE: Was It Worth It? Washington, DC: The National Acadamies Press. 

Accessed at http://www.nap.edu/catalog/10165.html?onpi_newsdoc071701 

4 U.S. Department of Energy. (2010). “Value of New Building Construction Relative to GDP, by Year ($2009 Billion).” Buildings 

Energy Data Book. Washington, DC. Accessed at http://buildingsdatabook.eren.doe.gov/ChapterIntro1.aspx

5

 In 2007, major appliances, HVAC, and commercial refrigeration was $60 billion; lighting manufacturing was $14 billion; and 

electronics (other than appliances) was $92 billion. 

6

 National Academy of Sciences. (2009). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National 

Acadamies Press. 

7

 Grenade, H.C., et al. (2009). Unlocking Energy Efficiency in the U.S. Economy. Washington, DC: McKinsey & Company. Accessed 

at http://www.mckinsey.com/Client_Service/Electric_Power_and_Natural_Gas/Latest_thinking/Unlocking_energy_efficiency_in_the_US_economy.aspx

8

 American Physical Society. (2008). Energy Future: Think Efficiency. Washington, DC. Accessed at http://www.aps.org/energyefficiencyreport/report/aps-energyreport.pdf

9

 Goetzler, W. (2010). “Air Conditioning Market and Technology Trends.” ARPA-E BEETIT presentation. Arlington, VA: Navigant 

Consulting.

10 Research & Markets. (2011). U.S. Appliance Industry: Market Value, Life Expectancy, & Replacement Picture for 2005-2012. 

Dublin, Ireland.

11 Lovvorn, N. (2001). Heat Pump Life in Alabama - Revisited. Electric Power Research Institute. Palo Alto, CA.

12 Pientka, K. (1987). Heat Pump Service Life and Compressor Longevity in a Northern Climate. ASHRAE Trans. 93(1):1087-1101.

13 Institute for Market Transformation. (2012). Building Energy Performance Benchmarking and Disclosure. Washington, DC. Accessed at http://www.imt.org/rating 

14 National Academy of Sciences. (2009). Real Prospects for Energy Efficiency in the United States. The National Acadamies Press. 

Washington, DC.

15 Roth, K., et al. (2007). Residential Miscellaneous Electric Loads: Energy Consumption Characterization and Savings Potential. 

Cambridge, MA: TIAX LLC.

16 Desroches, L.‐B., and Garbesi, K. (2011). Max Tech and Beyond. (LBNL-4998E). Berkeley, CA: Lawrence Berkeley National Laboratory. Accessed at http://efficiency.lbl.gov/drupal.files/ees/MTAB%20Final%20LBNL%20Report.pdf 

17 U.S. Department of Energy. (2011). Solid-State Lighting Research and Development: Multi Year Program Plan. Washington, DC. 

Accessed at http://apps1.eere.energy.gov/buildings/publications/pdfs/ssl/ssl_mypp2011_web.pdf 

18 U.S. Department of Energy. (2012). 2010 U.S. Lighting Market Characterization. Washington, DC. Accessed at http://apps1.eere.

energy.gov/buildings/publications/pdfs/ssl/2010-lmc-final-jan-2012.pdf 

19 U.S. Department of Energy. (2011). Solid-State Lighting Research and Development: Multi Year Program Plan. Washington, DC. 

Accessed at http://apps1.eere.energy.gov/buildings/publications/pdfs/ssl/ssl_mypp2011_web.pdf 
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20 U.S. Department of Energy. (2012). Energy Savings Potential of Solid-State Lighting in General Illumination Applications. Washington, DC. Accessed at http://apps1.eere.energy.gov/buildings/publications/pdfs/ssl/ssl_energy-savings-report_jan-2012.pdf 

21 U.S. Department of Energy. (2004). Technical Support Document: Energy Efficiency Program for Commercial and Industrial Equipment: High-Intensity Discharge Lamps Analysis of Potential Energy Savings. Washington, DC.

Navigant Consulting. (2005). U.S. Lighting Market Characterization Volume II: Energy Efficient Lighting Technology Options. 

Washington, DC.

22 For example, see: Baxter et al. (2005). “Residential Heat Pump Water Heater (HPWH) Development Status - USA.” Proceedings 

of the 8th IEA Heat Pump Conference. Las Vegas, NV.

23 Cassard, H., Denholm, P., and Ong, S. (2011). Break-Even Cost for Residential Solar Water Heating in the United States: Key Drivers and Sensitivities. (TP-6A20-48986). Golden, CO: National Renewable Energy Laboratory. 

24 Example miscellaneous plug loads include home electronics, computer, televisions, networking equipment, set-top boxes, printers, and small kitchen appliances.

25 Residential MELs include categories: color televisions and set-top boxes, personal computers and related equipment, and other 

uses; commercial MELs include categories: office equipment (PC) and office equipment (non-PC). 

Energy Information Administration. (2011). “Residential Sector Key Indicators and Consumption” and “Commercial Sector Key 

Indicators and Consumption.” Annual Energy Outlook 2011. Washington, DC: Department of Energy. Accessed at http://www.

eia.gov/oiaf/aeo/tablebrowser/ 

26 Roth, K., et al. (2007). Residential Miscellaneous Electric Loads: Energy Consumption Characterization and Savings Potential. 

Cambridge, MA: TIAX LLC.

27 Ehrhardt-Martinez, K., Donnelly, K. A., and Laitner, J. A. (2010). Advanced Metering Initiatives and Residential Feedback Programs. Washington, DC: American Council for an Energy-Efficient Economy.

28 Desroches, L.‐B., and Garbesi, K. (2011). Max Tech and Beyond. (LBNL-4998E). Berkeley, CA: Lawrence Berkeley National Laboratory. Accessed at http://efficiency.lbl.gov/drupal.files/ees/MTAB%20Final%20LBNL%20Report.pdf 

29 Shaughnessy, B. M. and Newborough, M. (2000). “Energy performance of a low emissivity electrically heated oven.” Applied 

Thermal Engineering. 20:813–830.

30 Sumnu, G., Sahin, S., and Sevimli, M., (2005). “Microwave, infrared, and infrared-microwave combination baking of cakes.” 

Journal of Food Engineering. 71(2):150-155.

31 Personal Communications: Omar Abdelaziz, Scott Welham, and David Najewicz. January 5, 2011. Appliance Park, Louisville, KY 

40225.

32 U.S. Department of Energy. (2009). Energy Conservation Standards Rulemaking Framework Document for Residential Clothes 

Washers. Washington, DC.

33 Consortium for Energy Efficiency. (2009). Residential Home Appliance Strategic Plan. Boston, MA.

34 MDI. (2006). “Get Ready for the next wave of energy-efficient washers.” Machine Design International. 78(11):34–37.

35 Teschler. (2008). Motors move toward more efficiency. Machine Design International. p. 74–78.

36 Heat pumps will save the most energy in cooling-dominated Southern climates.

37 Consortium for Energy Efficiency. (2009). Super-Efficient Home Appliances Initiative Appliance Strategic Plan. Boston, MA. Accessed at http://www.cee1.org/resid/seha/seha-plan.php3

38 Dries, J. (2008). Improving dishwasher efficiency. Appliance Magazine. Accessed at http://www.applianceMagazine.com

39 Heibler, H., and Laevemann, E. (2009). “Large energy savings by sorption-assisted dishwasher.” 5th International conference on 

Energy Efficiency in Domestic Appliances and Lighting (EEDAL’09). Berlin, June 16–18. Accessed at http://www.eedal.eu/index.

php?id=11575, 

40 Consortium for Energy Efficiency. (2009). Super-Efficient Home Appliances Initiative Appliance Strategic Plan. Boston, MA. Accessed at http://www.cee1.org/resid/seha/seha-plan.php3
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41 Westphalen, D. R. (2006). “Heat transfer enhancement.” ASHRAE Journal. 48(4):68-71.

42 Wade, P., and Brunner, C. U. (2011). “Energy-Efficiency Policy Opportunities for Electric Motor-Driven Systems.” Energy Efficiency 

Series. Paris, France.

43 Desroches, L.‐B., and Garbesi, K. (2011). Max Tech and Beyond. (LBNL-4998E). Berkeley, CA: Lawrence Berkeley National Laboratory.

44 A NEMA Premium 4-pole 200 HP enclosed motor is 96.2% efficient; motor efficiency varies with motor power and speed, among 

other factors.

45 Calculated as the sum of Lighting, Color Televisions and Set-Top Boxes, Personal Computers and Related Equipment, Office 

Equipment (PC), and Office Equipment (non-PC). 

Energy Information Administration. (2011). “Residential Sector Key Indicators and Consumption, Reference Case.” Annual Energy 

Outlook 2011. Washington, DC.

Energy Information Administration. (2011). “Commercial Sector Key Indicators and Consumption, Reference Case.” Annual Energy Outlook 2011. Washington, DC

46 Garbesi, K., Vossos, V., and Shen, H. (2011). Catalog of DC Appliances and Power Systems. Lawrence Berkeley National Laboratory. Berkeley, CA. 

47 Desroches, L.‐B., and Garbesi, K. (2011). Max Tech and Beyond. (LBNL-4998E). Berkeley, CA: Lawrence Berkeley National Laboratory.

48 U.S. Environmental Protection Agency. (2011). 2011 U.S. Greenhouse Gas Inventory Report. Washington, DC. Accessed at http://

epa.gov/climatechange/emissions/usinventoryreport.html

49 R-1234yf offers similar thermophysical properties.

50 U.S. Environmental Protection Agency. (2011). Presidential Green Chemistry Challenge Awards Program: Summary of 2011 

Award Entries and Recipients. Washington, DC.

51 For example: Bill Scanlon. (2010). “Energy Saving A/C Conquers All Climates.” National Renewable Energy Laboratory. Boulder, 

CO. 

Desroches, L.‐B., and Garbesi, K. (2011). Max Tech and Beyond. (LBNL-4998E). Berkeley, CA: Lawrence Berkeley National Laboratory.

52 Brown, D., Dirks, J., Fernandez, N., and Stout, T. (2010). The Prospects of Alternatives to Vapor Compression Technology for 

Space Cooling and Food Refrigeration Applications. Pacific Northwest National Laboratory. Richland, WA. Accessed at http://

www.pnl.gov/main/publications/external/technical_reports/PNNL-19259.pdf 

53 Thermoacoustic and magnetic technologies look relatively attractive because many working prototypes have already been built, 

the development barriers appear moderate, and the potential efficiencies are medium to high.

54 Fisher, S. (2000). Not-In-Kind Technologies for Residential and Commercial Unitary Equipment. Oak Ridge National Laboratory. 

Oak Ridge, TN.

55 Issues including integrating the building into grid operations, integrating building designs and financing into urban planning issues, and integrating building optimization into policy decisions are beyond the scope of this document.

56 Griffith, B. T. (2007). Assessment of the Technical Potential for Achieving Net Zero-Energy Buildings in the Commercial Sector.

National Renewable Energy Laboratory. Golden, CO.

 American Society of Heating, Refrigerating and Air-Conditioning. (2011). Advanced Energy Design Guides. Retrieved May 5, 

2011, from ASHRAE: www.ashrae.org/aedg

Office of Energy Efficiency and Renewable Energy. (2010). Commercial Buildings Initiative: Commercial Building Partnerships. 

Retrieved May 5, 2011, from EERE: http://www1.eere.energy.gov/buildings/commercial_initiative/building_partnerships.html
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National Renewable Energy Laboratory. (2011). NREL: Sustianable NREL - Research Support Facilitity. Retrieved May 5, 2011, 

from NREL: http://www.nrel.gov/sustainable_nrel/rsf.html

Office of Energy Efficiency and Renewable Energy. (2011). Building Technologies Program: Building America. Retrieved May 5, 

2011, from EERE: http://www1.eere.energy.gov/buildings/building_america/

57 Lovins, A. (2005). Energy End-Use Efficiency. Snowmass, CO: Rocky Mountain Institute.

58 Often improved HVAC performance is considered after solar gain and envelope improvements.

59 Energy Center of Wisconsin. (2010). Evaluation Of The Market Impact Of The Advanced Energy Design Guides. ASHRAE.

60 U.S. Environmental Protection Agency. (2009). ENERGY STAR® and Other Climate Protection Partnerships, Annual report. Washington, DC.

61 Institute for Market Transformation. (2011). Building Energy Transparency: A Framework for Implementing U.S. Commercial Building Energy Rating & Disclosure Policy. Washington, DC. Accessed at http://www.buildingrating.org/Building_Energy_Transparency_Implementation_Report 

62 Calculated by applying percentage of building energy lost through the envelope from Buildings Energy Data Book to energy used 

for heating and cooling in Annual Energy Outlook and applying energy prices from State Energy Data System:

 U.S. Department of Energy. (1998). “2.1.15 Aggregate Residential Building Energy Loads as of 1998.” Buildings Energy Data 

Book. Washington, DC.

 U.S. Department of Energy. (1998). “3.1.12 Aggregate Commercial Building Energy Loads as of 1998.” Buildings Energy Data 

Book. Washington, DC.

Energy Information Administration. (2011). “Residential Sector Key Indicators and Consumption, Reference Case.” Annual Energy 

Outlook 2011. Washington, DC.

Energy Information Administration. (2011). “Commercial Sector Key Indicators and Consumption, Reference Case.” Annual Energy Outlook 2011. Washington, DC

Energy Information Administration. (2009). “Primary Energy, Electricity, and Total Energy Price Estimates, 2009.” State Energy 

Data System. Washington, DC.

63 Brambley, M. R., et al. (2005). Advanced Sensors and Controls for Building Applications: Market Assessment and Potential R&D 

Pathways. (PNL-15149). Richland, WA: Pacific Northwest National Laboratory. Accessed at http://www.pnl.gov/main/publications/external/technical_reports/pnnl-15149.pdf 

64 Research includes applications for new and existing buildings in the residential and commercial sectors. Research considers 

both steep- and low-slope roofs and hot, moderate, and cold climates. 

65 Walls and insulation materials can be designed to provide temporary thermal storage and optimize building load profiles relative to critical utility peaks and grid-connected renewable electric generation. There are multiple technologies to increase the 

thermal storage occurring naturally in buildings, including commercial ice storage systems and phase-change materials. These 

technologies offer limited benefits (i.e., under 0.5 Quad/year even if adopted by all buildings).

66 R-value is a measure of thermal resistance. A typical 4-inch-thick wall with fiberglass insulation may have an R-value of 12 

(http://coloradoenergy.org/procorner/stuff/r-values.htm).

67 Budnitz, J., Berk, J., Hollowell, C., Nazaroff, W., Nero, A., and Rosenfeld, A. (1979). “Human disease from radon exposures: the 

impact of energy conservation in buildings.” Energy Build. 2:209-215.

68 Brambley, M. R., et al. (2005). Advanced Sensors and Controls for Building Applications: Market Assessment and Potential R&D 

Pathways. (PNNL-15149). Richland, WA: Pacific Northwest National Laboratory. Accessed at http://www.pnl.gov/main/publications/external/technical_reports/pnnl-15149.pdf 

69 For example, of the 64.7 Bft2

 of non-mall commercial floor space, only 15.6 Bft2 has an energy management control system used 

for HVAC.
Building and Industrial Efficiency | 115

QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Energy Information Administration. (2006). “Table B41. Cooling Equipment, Floorspace for Non-Mall Buildings, 2003.” Commercial Buildings Energy Consumption Survey. Washington, DC: Department of Energy. Accessed at http://www.eia.gov/emeu/

cbecs/cbecs2003/detailed_tables_2003/2003set8/2003pdf/b41.pdf 

70 The ZigBee Alliance, an association of companies, is pursing these goals through ZigBee technologies, which conform to a global 

communications protocol and digital radio frequency standard. 

71 Hart, R., Mangan, S., and Price, W. Eugene Water & Electric Board. (2004). “Who Left the Lights On? Typical Load Profiles 

in the 21st Century.” Washington, DC: American Council for an Energy-Efficient Economy. Accessed at http://www.aceee.org/

proceedings-paper/ss04/panel07/paper08 

72 Torcellini, P., Pless, S., Deru, M., Griffith, B., Long, N., and Judkoff, R. (2006). Lessons Learned from Case Studies of Six HighPerformance Buildings. (NREL/TP-550-37542).

73 Granderson, J., Piette, M., Ghatikar, G., Price, P. (2009). Building Energy Information Systems: State of the Technology and User 

Case Studies. Technical report. (LBNL 2899E). Lawrence Berkeley National Laboratory. 

74 ‘Hohm’ (http://www.microsoft-hohm.com/) uses a home electricity monitor to transmit real-time energy consumption data wirelessly to the home computer.

75 Navigant Consulting. (2011). Evaluation Report: OPOWER SMUD. Chicago, IL. OPOWER. (2010). Overview/OPOWER. Retrieved 

May 5, 2011, from OPOWER: http://www.opower.com/Results/Overview.aspx

76 Mills, E. (2009). Building Commissioning: A Golden Opportunity for Reducing Energy Costs and Greenhouse-Gas Emissions. 

Lawrence Berkeley National Laboratory. Berkeley, CA.

77 Pacific Northwest National Laboratory. (2010). PNNL Building Re-tuning. Richland, WA. Accessed May 2011, from http://www.

pnl.gov/buildingretuning/index.stm

78 National Institute for Standards and Technology. (2011). Integrating Building Automation Systems with a Smart Utility Grid Project. Gaithersburg, MD.

79 U.S. Department of Energy. (2010). “Refrigerator-Freezer Sizes and Energy Factors (Shipment-Weighted Averages).” Buildings Energy Data Book. Accessed at http://buildingsdatabook.eren.doe.gov/TableView.aspx?table=5.7.5http://buildingsdatabook.eren.

doe.gov/TableView.aspx?table=5.7.5

Association of Home Appliance Manufacturers. Major Appliance Fact Book (published annually; data from 2006 and earlier editions). Washington, DC.

80 U.S. Department of Energy. (2010). “Refrigerator-Freezer Sizes and Energy Factors (Shipment-Weighted Averages).” Buildings 

Energy Data Book. Accessed at http://buildingsdatabook.eren.doe.gov/TableView.aspx?table=5.7.5

Association of Home Appliance Manufacturers. Major Appliance Fact Book (published annually; data from 2006 and earlier editions). Washington, DC.

81 Meyers, S., Williams, A., and Chan, P. (2011). Energy and Economic Impacts of U.S. Federal Energy and Water Conservation 

Standards Adopted From 1987 Through 2010. (LBNL-5291E). Berkeley, CA: Lawrence Berkeley National Laboratory. 

82 Belzer, D. B., McDonald, S. C., and Halverson, M. A. (2010). A Retrospective Analysis of Commercial Building Energy Codes: 

1990 – 2008. (PNNL-19887). Richland, WA: Pacific Northwest National Laboratory. 

83 American Society of Heating, Refrigerating and Air-Conditioning Engineers. (2011). Advanced Energy Design Guides. Accessed 

May 5, 2011, from ASHRAE: www.ashrae.org/aedg

84 Greater Philadelphia Innovation Cluster for Energy-Efficient Buildings. http://gpichub.org/http://gpichub.org/

85 End-use energy, also referred to as site energy, is directly consumed by end users, and primary energy is site energy plus the 

energy consumed in the production and delivery of electricity, natural gas, fuel oil, etc. Except where noted, this technology assessment expresses energy in terms of primary energy data, which is important for understanding broader environmental and 

policy issues, such as carbon emissions from energy sources. 
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86 Energy Information Administration. (2009). An Updated Annual Energy Outlook 2009 Reference Case Reflecting Provisions of the 

American Recovery and Reinvestment Act and Recent Changes in the Economic Outlook. Washington, DC. Accessed at http://

www.eia.gov/oiaf/servicerpt/stimulus/index.html 

87 U.S. Department of Commerce, Bureau of Economic Analysis. (2011). Gross Domestic Product (GDP) by Industry Data. Washington, DC. Accessed at http://www.bea.gov/industry/gdpbyind_data.htm

88 The Manufacturing Institute. (2009). The facts about modern manufacturing. Washington, DC. Accessed at http://www.nist.gov/

mep/upload/FINAL_NAM_REPORT_PAGES.pdf 

89 United Nations National Accounts Main Aggregates Database. (2010). GDP and its breakdown at current prices in US Dollars. 

New York, NY: United Nations. Accessed at http://unstats.un.org/unsd/snaama/dnlList.asp

90 Energy Information Administration. (2009). Emissions of Greenhouse Gases in the United States 2009. Washington, DC. Accessed at http://www.eia.gov/environment/emissions/ghg_report/pdf/tbl7.pdf 

91 University of Texas at Austin, Oak Ridge National Laboratory, and the American Institute of Chemical Engineers. (2005). Hybrid 

Separations/Distillation Technology: Research Opportunities for Energy and Emissions Reduction. Accessed at http://www1.

eere.energy.gov/industry/chemicals/pdfs/hybrid_separation.pdf 

92 The National Academies. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National Academies Press. Accessed at http://www.nap.edu/catalog.php?record_id=12621

93 U.S. Department of Energy, Industrial Technologies Program. (2006). Manufacturing Energy and Carbon Footprint. Washington, 

DC: Energetics, Inc. Accessed at http://www1.eere.energy.gov/industry/pdfs/mfg_footprint.pdf 

94 Oak Ridge National Laboratory. (2008). Combined Heat and Power: Effective Energy Solutions for a Sustainable Future. (ORNL/

TM-2008/224). Oak Ridge, TN. Accessed at http://www1.eere.energy.gov/industry/distributedenergy/pdfs/chp_report_12-08.

pdf 

95 Oak Ridge National Laboratory. (2008). Combined Heat and Power: Effective Energy Solutions for a Sustainable Future. (ORNL/

TM-2008/224). Oak Ridge, TN. Accessed at http://www1.eere.energy.gov/industry/distributedenergy/pdfs/chp_report_12-08.

pdf

96 The National Academies. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National Academies Press. Accessed at http://www.nap.edu/catalog.php?record_id=12621

97 McKinsey & Company. (2009). Unlocking Energy Efficiency in the U.S. Economy. Washington, DC. Accessed at http://www.

mckinsey.com/en/Client_Service/Electric_Power_and_Natural_Gas/Latest_thinking/Unlocking_energy_efficiency_in_the_

US_economy.aspx 

98 McKinsey & Company. (2009). Unlocking Energy Efficiency in the U.S. Economy. Washington, DC. Accessed at http://www.

mckinsey.com/en/Client_Service/Electric_Power_and_Natural_Gas/Latest_thinking/Unlocking_energy_efficiency_in_the_

US_economy.aspx 

99 The National Academies. (2010) Real Prospects for Energy Efficiency in the United States. Washington, DC. Accessed at http://

www.nap.edu/catalog.php?record_id=12621

100 U.S. Energy Information Administration. (2011). Annual Energy Outlook. Washington, DC. Accessed at http://www.eia.gov/forecasts/aeo/pdf/0383(2011).pdf 

101 U.S. Energy Information Administration. (2011). Annual Energy Outlook, Table D2. Washington, DC. Accessed at http://www.eia.

gov/forecasts/aeo/pdf/0383(2011).pdf 

102U.S. Department of Energy. (2006). Chemical Bandwidth Study. Washington, DC. Accessed at http://www1.eere.energy.gov/

manufacturing/industries_technologies/chemicals/pdfs/chemical_bandwidth_report.pdf 

103U.S. Department of Energy. (2006). Pulp and Paper Industry Energy Bandwidth Study. Washington, DC. Accessed at http://www1.

eere.energy.gov/manufacturing/industries_technologies/forest/pdfs/doe_bandwidth.pdf 
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104U.S. Department of Energy. (2006). Energy Bandwidth for Petroleum Refining Processes. Washington, DC. Accessed at http://

www1.eere.energy.gov/manufacturing/industries_technologies/petroleum_refining/pdfs/bandwidth.pdf 

105U.S. Department of Energy. (2006). Steel Industry Energy Bandwidth Study. Washington, DC. Accessed at http://www1.eere.

energy.gov/manufacturing/industries_technologies/steel/pdfs/steelbandwidthstudy.pdf 

106U.S. Department of Energy. (2007). U.S. Energy Requirements for Aluminum Production. Washington, DC. Accessed at http://

www1.eere.energy.gov/manufacturing/industries_technologies/aluminum/pdfs/al_theoretical.pdf 

107U.S. Department of Energy. (2006). Industrial Glass Bandwidth Analysis. Washington, DC. Accessed at http://www1.eere.energy.

gov/manufacturing/industries_technologies/glass/pdfs/industrial_bandwidth.pdf 

108 Energy Information Administration. (2009). An Updated Annual Energy Outlook 2009 Reference Case Reflecting Provisions of the 

American Recovery and Reinvestment Act and Recent Changes in the Economic Outlook. Washington, DC. Accessed at http://

www.eia.gov/oiaf/servicerpt/stimulus/index.html

109 International Energy Agency. (2007). Tracking Industrial Energy Efficiency and CO2

 Emissions. Paris, France.

110 The National Academies. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National Academies Press. Accessed at http://www.nap.edu/catalog.php?record_id=12621 

111Oak Ridge National Laboratory. (2011). Internal Analysis Report. Oak Ridge, TN. 

112 The National Academies. (1994). Microwave Processing of Materials. Washington, DC: The National Academies Press. Accessed 

at http://www.nap.edu/openbook.php?record_id=2266&page=3 

113 Energy Materials Blue Ribbon Panel. (2010). Linking Transformational Materials and Processing for an Energy Efficient and LowCarbon Economy: Creating the Vision and Accelerating Realization. Washington, DC: Department of Energy. Accessed at http://

energy.tms.org/Docs/pdfs/VisionReport2010.pdf 

114 U.S. Department of Energy and U.S. Department of Agriculture. (2005). Biomass as a Feedstock for Bioenergy and Bioproducts 

Industry: The Technical Feasibility of a Billion Ton Annual Supply. (DOE/GO-102995-2135). Washington, DC. Accessed at http://

feedstockreview.ornl.gov/pdf/billion_ton_vision.pdf 

115McKinsey & Company. (2009). Unlocking Energy Efficiency in the U.S. Economy. Washington, DC. Accessed at http://www.

mckinsey.com/en/Client_Service/Electric_Power_and_Natural_Gas/Latest_thinking/Unlocking_energy_efficiency_in_the_

US_economy.aspx 

116American Council for an Energy-Efficient Economy. (2009). “Barriers to energy efficiency investments and energy management in 

the U.S. industrial sector.” Washington, DC. Accessed at http://www.aceee.org/files/pdf/fact-sheet/ACEEE-Barriers_to_industrial_EE_10-20-09.pdf 

The National Academies. (2010). Real Prospects for Energy Efficiency in the United States. Washington, DC: The National Academies Press. Accessed at http://www.nap.edu/catalog.php?record_id=12621

117 U.S. Department of Energy. (2012). “ARC Implementation Rates.” Industrial Assessment Centers Database. Washington, DC. 

Accessed May 2012 at http://iac.rutgers.edu/database/arcImpRate/

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Grid Modernization | 119

GRID 

MODERNIZATION

The assessments in this chapter form the technical base for 

Modernizing the Grid, a strategy detailed in the corresponding 

chapter of the Report on the Quadrennial Technology Review 

(QTR). The Nation needs an electrical grid that is adaptable, 

secure, reliable, resilient, and can accommodate changing loads, 

generation technologies, and operating business models. The 

Report on the QTR focused on the subset of technical issues 

most relevant to the Department’s research and development 

capabilities and strategy, not on larger grid modernization 

policies and barriers.

While each technology is presented here with a standalone 

assessment, the associated opportunities to impact the energy 

system are fully understood only within the context of an 

integrated framework that spans energy resource, supply, 

delivery, and consumption. The Report on the QTR presents 

an integrated framework of the energy system and contains 

the systems discussions that tie together these individual 

assessments.

The technology assessments in the Grid Modernization chapter 

include:

•	 Grid Infrastructure

•	 Grid Storage

•	 Grid Measuring, Modeling, and Control
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GRID MODERNIZATION

GRID

INFRASTRUCTURE

Context

Electrification of the United States was a major cornerstone of the economic development and prosperity of 

the post-WWII era and has since become an essential service to virtually every household and business in the 

nation. As described in Modernizing the Grid in the Report on the QTR, today’s power transmission and distribution grid is technically adequate for providing basic electrical services. But, as described in the Report on the 

QTR, the grid will become increasingly stressed as the technologies that generate and consume power continue 

to evolve. Current operational and business models are still adapting to the more segmented, less regulated 

conditions that exist today and are expected for the future. The mix of old and new technologies within the 

system adds to the stress caused by increased demand and changing operations that adversely affects reliability 

and power quality. Overcoming these stresses requires innovations to enable new functions and capabilities 

while ensuring reliability, adequacy, and security. This section reviews technical opportunities to improve the 

grid’s physical infrastructure, while the other assessments examine technologies in grid storage, and measurements, modeling, and control. 

The physical system of the U.S. grid includes 180,000 miles of high-voltage transmission lines, 11 million miles 

of distribution lines, and 15,000 generators that are owned by 3,170 utilities and serve over 143 million customers across North America. There are also 15,000 transmission substations and 60,000 distribution substations that form the major “nodes” of this system.1

 Figure 19 is an illustrated representation of the grid’s major 

components and their connectivity. The regulatory, market, and business structures that influence innovations 

in the grid are directly impacted by federal, state, regional, and local issues, adding to its complexity.
Grid Modernization | 121

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Generating 

Station

Transmission Customer

138kV or 230kV

Transmission Lines

765, 500, 345, 230, and 138kV

Generating

Step Up

Transformer

Substation

Step Down

Transformer Subtransmission

Customer

26kV and 69kV

Primary

Customer

13kV and 4kV

Secondary

Customer

120V and 240V

Generation Transmission Distribution Customer

Figure 19. Simplified Schematic Showing Major Elements of the Electric Grid

Source: U.S.-Canada Power System Outage Task Force. (2004). Final Report on the August 14, 2003 Blackout in the 

United States and Canada: Causes and Recommendations. Page 5. Accessed at http://www.ferc.gov/industries/

electric/indus-act/reliability/blackout/ch1-3.pdf
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9,000

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

0

Investment in Transmission System (2007 $millions)

1975 1980 1985 1990 1995 2000 2005 2010

YEAR

Figure 20. Investment in Transmission Systems (1975–2007)

Transmission investment by integrated and stand-alone transmission companies. The investor-owned regulated 

utilities’ data cover only 80% of the transmission system. All investment is shown in 2007 dollars. Data were adjusted 

as necessary using the Handy-Whitman index of Public Utility Construction Costs. Source: Adapted with permission 

from The National Academies. (2009). America’s Energy Future: Technology and Transformation. Page 570, Figure 9.5 

(1975–2003 from EEI, 2005; 2000–2007 from Owens, 2008). Washington, DC: National Academies Press. Accessed 

at http://www.nap.edu/catalog/12091.html

Overall, today’s grid has components that are aging and operating closer to the edge of reliability. Slow 

demand growth and overbuilding in the 1970s and 1980s allowed the annual investment in the grid to 

decrease over the last quarter of the 20th Century (Figure 20) without significant capacity issues. However, 

by 2007, electricity demand had expanded by about 30% (to about 4 trillion kilowatt hours [kWh])2 relative 

to 1990, stressing local distribution systems. Despite the upturn in annual investment since 2000 (Figure 20), 

the number of line congestion events and disturbance events continues to rise (Figure 21). Within this context, today’s system loses about 7% of the electricity generated (300 billion kWh annually) to inefficiencies.3

 

Nonetheless, the U.S. transmission and distribution system, recognized by the National Academy of Engineering as the most significant engineering accomplishment of the 20th century,

4

 has been exceptionally reliable 

and driven economic vitality over the last century. 
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600

500

400

300

200

100

0

Events

199719981999200020012002200320042005200620072008

YEAR

MONTHLY EVENTS 12 MONTH ROLLING AVERAGE

90

80

70

60

50

40

30

20

10

0

Number of Major System Disturbances

19941996199820002002200420062008

YEAR

Figure 21. (Top) Transmission Loading Relief (TLR) Events (Bottom) Major Transmission 

System Disturbances Reported to the North American Electric Reliability Council

(Top) The number of transmission loading relief events is not an outage measure; it is the number of times a 

congestion limit is reached. Although this measure has been used to characterize transmission reliability, congestion 

limits can be reached purely for market reasons.

(Bottom) Disturbances include electric service interruptions, unusual occurrences, demand and voltage reductions, 

public appeals, fuel supply problems, and acts of sabotage that can affect the reliability of the bulk electric systems. 

Source: Adapted with permission from The National Academies. (2009). America’s Energy Future: Technology and 

Transformation. Washington, DC: National Academies Press. Accessed at http://www.nap.edu/catalog/12091.html
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Today’s electric infrastructure and its major components were designed for efficiency, reliability, ease of 

operation, and consumer benefit at minimum cost. Going forward, the system must continue to meet these 

requirements while supporting the integration of renewable generation and the deployment of electric vehicles, meeting the higher power-quality demands of digital devices, and enabling consumer participation in 

electricity markets.

Past operational methods and system components are increasingly inadequate for a modernizing grid. Rapid 

advances in information technology, material science, and computational capabilities are creating opportunities to address the many challenges facing the grid. 

Framing the Assessment

Table 17 frames the key components of the grid broken down by the five levels of the legacy delivery system. 

“Generation” refers to bulk generators. “Transmission” refers to step-up power transformers, extra-high voltage lines, direct current interties between interconnections, and wholesale electricity markets. “Substation” 

refers to the major “nodes” of the transmission system, including the interface with the distribution system at 

distribution substations. “Distribution” refers to distribution feeders, pole transformers, and distribution lines. 

“End-use” refers to billing meters and beyond, in other words, the load within residential and commercial 

buildings and industrial complexes. Each of these levels has challenges associated with grid modernization, as 

well as crosscutting technical and non-technical issues. 

This section assesses the grid’s physical system: the infrastructures and components that control, transmit, and 

convert electricity and powerflow. Storage and crosscutting elements of the system are covered in other assessments.
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Generation Transmission Substation Distribution End Use

Key Elements 

of Legacy 

System 

Pumped 

Storage, 

Breakers,

Switches, 

Controllers

Transformers, 

Extra-High 

Voltage Lines, 

Towers,

Arrestors,

Converters

Transformers,

Breakers,

Switches, 

Arrestors, 

Flexible 

Alternate 

Current 

Transmission 

Systems 

(FACTS) Devices

Transformers,

Lines, Utility 

Poles

Communications Hardware and Software, Operational and Planning Models and 

Platforms, Limited Supervisory Control and Data Acquisition (SCADA), Limited WideArea Control Systems and Wide-Area Monitoring Systems 

Key Additional 

Elements of 

a Modernized 

System 

Converters 

High-Voltage 

Direct Current 

Lines, Fault 

Current 

Limiters, 

Phasor 

Measurement 

Units (PMUs)

Converters, 

Fault Current 

Limiters, PMUs

Alternating 

Current/Direct 

Current Lines

Converters,

Breakers,

Switches, 

Controllers 

Communications Hardware and Software, Information Technology, Operational and 

Planning Models and Platforms, SCADA, Limited Wide-Area Control Systems and WideArea Monitoring Systems, Sensors and Advanced Metering Infrastructure, Storage

Systems Level 

Challenges

Renewable 

Integration, 

Changing 

Generation Mix

Increasing 

Capacity, 

Congestion on 

Lines, Under 

Utilization 

Increased Data 

Flow, Two-Way 

Power Flow, 

Microgrids

Two-Way Power 

Flow, Vehicle 

Electrification, 

Distributed 

Generation, 

Microgrids

Demand 

Response, 

Energy 

Management 

Systems, 

Distributed 

Generation

Table 17. Key Elements and Challenges Facing the Grid

Technical Roadmaps

A key objective of this assessment is to develop a framework that organizes the physical components of the 

grid and facilitate better understanding of potential investments in new grid technologies. This is a more 

fundamental discussion than in most of the other technical assessments, which summarize well-established 

roadmaps. Table 18 lists key infrastructure components grouped by their functionality and denotes the basic 

services they will need to maintain, the new services that they can enable, and crosscutting technologies that 

can directly impact their performance. Some services have more value to the end-user, while others have more 

value to system operators. Towers and poles have been left out of the table due to their passive nature. d user, 

while others have more value to system operators. Towers and poles have been left out of the table due to 

their passive nature.
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X-Formers Cables & 

Conductors

Power 

Converters

FACTS & 

Controllers

Switches & 

Breakers

Arresters & 

Limiters

Basic Services

Delivery X X X

Efficiency X X X X

Reliability X X X

New Services

Bulk 

Renewable 

Generation

X X X

Distributed 

Generation X O O O

Electric 

Vehicles O X X O O O

Power Quality O O O

Optimization O O O O

Resiliency O O O O O

Complex 

Loads 

(Distributed 

Renewables, 

Microgrids)

O O O O O

Crosscuts

Dielectrics & 

Insulators X X X X X X

Power 

Electronics O X X O O

Magnetics X X X

Wires X X X

Cooling/Thermal Management

X X X X X

X = near-term application, O = future application

*Note: Flexible AC Transmission Systems (FACTS)

Table 18. Key Components and the Services They Provide, Along with Crosscutting Technologies
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A Brattle Group study5 in 2008 estimated the cost of grid modernization over the next 20 years to be $233 

billion in the transmission system and $675 billion in the distribution system. These values are consistent with 

an Electric Power Research Institute (EPRI) study6 conducted in 2002, which estimated a cost of $225 billion in 

transmission and $640 billion in distribution. The EPRI study also reported that basic expansion of the system to 

meet growing loads and replace aging components would cost $175 billion in transmission and $470 billion in 

distribution. The difference between these estimates ($50 billion in transmission and $170 billion in distribution 

over 20 years) provides an estimate of the incremental cost of enabling new functionalities and capabilities.

EPRI estimates the benefits to society from the incremental investment in modernization would be about 

$640–$800 billion over the next 20 years.7 They also estimated that blackouts and service interruptions, which 

are generally related to distribution failures and power quality respectively, cost the U.S. economy $80–$100 

billion annually. Line congestion, inefficiencies (the system loses about 2% in transmission and 5% in distribution), and underuse of assets also have direct economic costs. On the other hand, it is difficult to estimate the 

economic growth that would arise from new markets, services, and business models. Some potential benefits 

from grid modernization may be difficult to monetize, such as improving safety and security, or a cleaner environment. As distributed generation technologies become less expensive, there will be more power generation 

on the distribution grid, which will necessitate protection and control of two-way power flows.

Infrastructure and Power Electronic Components

Infrastructure and power electronic components interact with the physical flow of electricity and power. Historically, transformers, power lines, switches, and breakers have been sufficient. Advanced components such 

as Flexible Alternating Current Transmission Systems (FACTS) devices, controllers, and other power electronics 

can improve flexibility, enable new functions, and enhance current capabilities. Legacy components can also 

be retrofitted and redesigned to provide desired capabilities. This section summarizes roadmaps for key components of the grid’s physical system. In general, these components would benefit from improved performance 

and reduced cost. 

Opportunities in the electric power system include capabilities that

•	 Enable informed participation of customers

•	 Accommodate diverse generation and storage options

•	 Provide increased resiliency to disturbances, attacks, and natural disasters

•	 Provide the power quality commensurate for a range of needs

•	 Optimize asset utilization and operating efficiency 

•	 Enable the introduction of new products, services, and markets.
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Towers and Poles

Towers and poles support the above ground-conductors in the transmission and distribution networks. Towers 

transport power from distant generators to load centers. Utility poles are prevalent in most distribution grids, 

except in dense urban centers, where underground cables distribute power.

In regard to centralized power generation, towers will be needed for transmission of power generated far from 

load centers. (Distributed and on-site generation do not have the need for long-distance transmission.) Towers must be strong to withstand impacts of severe weather events. Design improvement allows better use of 

limited rights-of-way and potentially lessens the visual footprint. The value of these innovations has not been 

fully assessed.

New composite materials that are stronger and lighter, as well as analysis of new structural designs, could improve towers and poles. Europe leads in tower and pole design and materials. Bonneville Power Administration 

has developed software to develop stronger and more efficient tower designs, saving costs through reduced 

material use. 

Power and Distribution Transformers

Transformers change the voltage of electricity, increasing voltage to transmit power efficiently over long distances and decreasing it for final delivery to end users. Power transformers are located at generating plants and 

substations, while distribution transformers are located in residential and commercial areas. Most manufacturing for these components has moved abroad, resulting in long order lead times. Standardization of transformer 

designs would shorten lead times and reduce the required inventory of spare transformers. Power transformers 

cost millions of dollars, while distribution transformers cost $5,000–$15,000 depending on rating. 

As transmission and distribution networks integrate in a modernizing grid, the performance requirements 

and operational characteristics of transformers will evolve. They must maintain high reliability and efficiency 

(99.5%–99.7%) while accommodating two-way power flows, higher temperatures and operating voltages, 

and more reactive loads (electric vehicles, light-emitting diode [LED] lights, etc.). The average age of the U.S. 

transformer fleet is 40 years—approaching their expected operational lifetime (Figure 22).8 There is potential to 

decrease transformer weight, significantly easing siting, increasing fault current capabilities for reliability, and 

enabling safe two-way flow of power to improve grid flexibility.9 

Research pathways include applied materials research in core materials for higher flux to reduce transformer 

weight, improved insulators for operating at higher temperatures and voltages, low-loss wires for improved 

windings for increased efficiency, and cost-effective thermal management that can handle overloading or enable high-temperature superconducting cables (HTSC). Protection schemes, material ratings, and controls are 

several factors that need to be addressed in future transformer designs to accommodate two-way power flows. 

Early demonstrations of advanced transformers with multi-functional capabilities are underway. Solid state 

transformers that leverage advances in power electronics will provide voltage and volt-ampere reactive (VAR) 

support for power quality, while transformers with embedded sensors for equipment diagnostics and real-time 

performance assessment will help identify and respond to disturbances.
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Cables and Conductors

Cables and conductors carry and deliver electricity. Overhead conductors are mainly used with towers. Highvoltage direct-current (HV-DC) technology has become more prominent in usage because it is more efficient 

and cost-effective for transmitting large amounts of power [>500 megawatts (MW)] over long distances (>300 

miles).10 These components are considered mature and have price ranges between $0.1–$4.0 million/mile depending on rating, type, and terrain. Underground cables, which have lower voltages, are used in urban centers 

where real-estate costs, safety concerns, and aesthetics restrict the use of overhead lines. Underground cables 

are also used where overhead lines are hard to locate or when environmental impacts are a concern.

Advanced cables and conductors can have both higher power densities, which enable them to accommodate 

the growth in electrical demand in limited rights-of-way, and lower losses, to efficiently access remote energy 

resources. Reconductoring, the process of using advanced cables to increase capacity in existing corridors, has 

been the preferred solution. Reduced line sag (which can lead to safety hazards and power failures when cables 

contact other objects), increased ampacity (the maximum amount of electrical current a conductor can carry), 

longer lifetimes, and better thermal management can handle higher operating temperatures, severe weather 

events, and the mechanical and electrical stresses of high power densities. There is potential for enhanced 

cables and conductors that have up to five times the capacity11 and an installed cost comparable to today’s 

technologies. 

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

0 10 20 30 40 50 60 70 80 90 100

Hazard Function

AGE

Figure 22. Potential Hazard of Failure Versus Transformer Age 

Source: Bartley, William H. Analysis of Transformer Failures. (2003). Presented at the International Association of 

Engineering Insurers 36th Annual Conference, Stockholm, 2003. Page 7, Figure 3. Hartford, CT: The Hartford Steam 

Boiler Inspection & Insurance Co. Accessed at http://www.imia.com/library_imia_papers.php
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Research pathways include applied materials research and advanced cable and conductor concepts for the 

development of extra-high voltage/HV-DC lines, enhanced underground cables, high-temperature low-sag 

cables, high-phase order cables, and HTSC. These innovations require parallel developments in associated 

technologies, such as new transformers for high-phase order cables and cryogenic coolers for HTSC. Other innovations, such as embedded self-healing and diagnostics, can improve disturbance response, while coatings 

to reduce corrosion and icing can extend lifetimes. 

Power Converters

Power conversion systems change high power electric from direct current to alternating current (inverters) and 

alternating current to direct current (rectifiers). These components are used in a wide range of applications 

and are particularly critical for wind and solar photovoltaic electrical generation, grid-scale storage, electric 

vehicle charging, and HV-DC usage. Power converters can also allow power routing with multi-terminal HV-DC 

stations, VAR control and voltage support for more reactive loads, and frequency response to ensure system 

stability. 

These components enable the connection of asynchronous systems through HV-DC interties, allowing power 

transfer between the three major U.S. interconnections. Power converters are considered mature, but still suffer from inefficiencies, high costs, and rated voltage/current limitations. Conversion systems comprise a large 

portion of HV-DC substation price ($250–$500 million/unit12), thus limiting the wide-scale deployment of HVDC. While high-voltage alternating-current (HV-AC) substation costs $10–$60 million,13 HV-AC line inefficiencies make them less economic over long distances.

There is potential for HV-DC power converters with improved system efficiencies, improved reliability, and 

significantly lower costs.14 Basic research on wide band-gap semiconductor materials can improve the next 

generation transistors and thyristors to reduce power converter price. Improvement of Silicon Carbide (SiC) and 

Gallium Nitride (GaN)-on-Silicon processing to enhance material quality for device reliability is a promising research and development (R&D) area. New functions and capabilities can be added to existing power converter 

designs that help modulate oscillatory dynamics and provide VAR control for voltage support. Thermal management and cooling of these power systems and embedded sensors are other potentially important R&D topics.

FACTS Devices and Controllers

FACTS devices provide enhanced power transfer capabilities and controllability that help alleviate line congestion and increase asset utilization. This family of components can control line impedances, terminal voltages, 

and voltage angles quickly and effectively to improve dynamic system behavior and enhance system stability. 

They can also provide VAR support and frequency response historically provided by other controllers (such as 

synchronous condensers). The introduction of high voltage systems for inter-regional exchanges spurred the 

development of high-power FACTS devices. Deployment of these technologies have been limited over the 

past 30 years due to costs and reliability issues, used only where space and siting constraints make traditional 

solutions impractical. FACTS devices include universal power flow controllers, static synchronous compensator, 

static VAR compensators, and many others.
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There is a need for increased control and flexibility to manage more reactive loads (e.g., LED lighting, electric vehicles) and to mitigate the lack of system inertia and primary frequency response associated with high 

penetration of intermittent renewable generation. Greater deployment of distributed generation, the use of 

microgrid technologies, and increased customer participation in electricity markets will require power flow controllers on the distribution grid. In addition to improved components, R&D can explore controller designs and 

development for use in the distribution system. FACTS devices could provide VAR support significantly faster 

than current technologies and with lowered system costs through improved power electronic devices.15

FACTS devices will benefit from applied materials research for their constituent transistors and thyristors. Research on distributed static series compensators and distributed series reactance modules that can be clipped 

onto wires to control their impedance can be built upon to develop new controllers. 

Switches and Breakers

Switches and breakers are protective technologies, which include network interrupters, sectionalizers, and reclosers, used to separate and isolate sections of the grid during a disturbance. Automated switches help restore 

power after a fault and can provide load control and voltage regulation. Circuit breakers interrupt the current 

that flows during a fault. These technologies are considered mature, but are very expensive; circuit breakers 

can cost a few million dollars.

A modernized grid will likely include two-way power flows, more complex operations, higher voltages, direct 

current circuits, and advanced distribution systems. As more HV-DC circuits are deployed, HV-DC protection 

devices will be needed. However, there are no cost-effective mechanisms that force the current to zero for 

an HV-DC circuit breaker, without which, arcing and contact wear degrade reliability.16 Cost-effective and enhanced insulators can improve current switches and breakers for HV-AC circuits, while new materials may be 

needed to develop a HV-DC breaker. Research on power electronic devices and materials can also be leveraged 

for solid-state switches. 

Arresters and Current Limiters

Arrestors and current limiters protect equipment such as converters, transformers, and FACTS in the event of 

faults, lightning strikes, or other grid interruptions by redirecting, dissipating, or limiting surge currents. This 

family of devices has an important role in the security and reliability of the grid. The value of these protective 

functions has not been fully assessed. Increased use of critical components and power electronics would raise 

susceptibility to electric fault currents. The expected growth in distributed generation, community storage, and 

electric vehicles could produce significantly larger fault currents than previously experienced on the distribution 

system. The key challenge for innovation in this area is the development of reliable and cost-effective devices 

that can handle the larger currents that may occur. 

Materials research could lead to improved insulators that can withstand greater currents and voltages. Other 

materials research offers opportunities to improve current limiters since surge currents increase wire resistance.
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Crosscutting Technologies

Crosscutting technologies include materials and subcomponents that can provide benefits to many infrastructure and power electronic components (see Table 18) as the grid moves towards higher voltages or currents, 

experiences increased strain from severe weather and thermal fluctuations, and handles faster operations with 

complex electronics. 

Dielectrics and Insulators

Dielectrics and insulators are used in overhead lines, transformers, underground cables, circuit breakers, and 

many other components. Virtually every electrical device on the grid needs dielectrics or insulators to isolate 

the current-carrying segments from ground and to provide mechanical support while being able to withstand 

the high voltages involved. Dielectrics and insulators can be gases (such as sulfur hexaflouride), liquids (such as 

oils), or solids (such as ceramics and plastics), all with different properties and different applications. Failures in 

dielectric or insulator materials can lead to costly power outages, loss of equipment, and loss of service.

Materials innovations could improve mechanical, thermal, electrical, and lifetime properties of dielectrics and 

insulators. New materials such as smart materials and nanocomposites that can self-heal or provide new functionalities could transform this space. 

Power Electronics

Transistors and thyristors are the building blocks of power electronic systems, so their cost and performance 

limits the deployment of power converters and FACTS devices. Cost-effective power electronic devices with 

higher voltage/current limits, improved efficiencies, increased reliability, and higher operating temperatures are 

needed. Wide band gap semiconductors such as GaN, SiC, Zinc Oxide, and diamond have significant potential 

for advanced devices. Today, the most promising materials for near-term applications are SiC and GaN, which 

have breakdown voltages ~50 and ~30 times higher than silicon respectively.17 While diamond is still very early 

in development as a semiconductor, it has over 500 times the breakdown voltage of silicon.18 The U.S. Department of Energy (DOE) has set goals of developing GaN on Silicon devices that operate at 5 kilovolts (kV) and 15 

amps (A) within 5 years, and SiC switches that can operate at 20 kV, 100 A, temperatures greater than 200°C, 

and switching frequencies of 20 kilohertz (kHz).19

Power electronics would be improved through include basic materials research, the exploration of new device 

architectures, processing methodologies, thermal management, and device packaging. Improved materials will 

increase the reliability and fundamental limits of the devices, whereas new architectures, thermal management, 

and packaging will improve the devices operational performance.

Wires

Wires and conductor materials are the building blocks of the conductors and cables that transmit electricity, as 

well as the windings for transformers. Higher strength-to-weight ratios, improved high-temperature strength, 

improved electrical and thermal conductivity, and lower losses are desirable for wires. Fundamental materials 

research can lead to innovation in this space.
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Cooling/Thermal Management

Technologies such as cryogenic coolers and high-temperature packaging will be necessary to dissipate the 

heat generated by the higher power densities of a modern grid. Materials degrade at their temperature limits, 

possibly resulting in permanent component failures. Most grid components are cooled passively today, which 

can be a hazard in extreme weather conditions. Mechanical cooling has contributed to system reliability, but 

requires improvements in the costs and performance. Active and passive cooling innovations will make systems 

more resilient to thermal issues. Reliable and rugged refrigeration systems are necessary for the use of superconducting components. 

Magnetics

Magnetic materials are used in transformers and power electronics. Fundamental materials research to improve 

magnetic properties (high flux, high coercivity), increased operating temperatures, and lower losses will impact 

grid components. Improved magnetics can lead to smaller and lighter transformers and power electronics.

Non-Technical Barriers 

Many of the technologies that could improve efficiency and operations of the grid are constrained by nontechnical issues. Technological innovation, system operation, and overall performance of the electric grid are 

intricately linked to the system’s market, policy, and regulatory structures. 

Systems Integration and Demonstration

Systems integration and demonstration are crucial for the deployment and adoption of new technologies 

because the industry is risk averse and sensitive to changes. Utility involvement in this process is critical to the 

success of new technologies and the new services they can provide. Systems-oriented demonstrations enable 

understanding, ensuring that various grid technologies won’t adversely impact one another. Well-designed 

demonstrations provide valuable information for the research community, as well as the cost and performance 

data needed to inform regulators and legislators. Below are key technology issues and demonstrations that 

could advance grid modernization.

Interoperability Framework and Standards: With the rapid advances in technologies that will interact on 

the grid, standards are necessary to provide a framework to guide interoperability. This multi-stakeholder activity includes activities from the federal government,20 to the private sector, to nonprofit and standards organizations.

Distributed Energy Resources: Increasing use of distributed generation, energy management systems, and 

distributed resources present operational challenges and technology issues. The complex interactions between 

these technologies on the distribution/regional level can provide valuable insight into the grid as a whole. Deployment of distributed generation at scale will depend on understanding how these technologies will impact 

the grid on all levels, from a circuit to a region. Various studies have explored these issues,21,22 and through 

American Recovery and Reinvestment Act of 2009 (ARRA) funding, additional demonstration projects have 

been initiated that integrate several distributed technologies. 
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Advanced Metering Infrastructure (AMI) and Demand Response: The use of AMI and dynamic pricing 

to provide demand response requires the evaluation of consumer reactions to price signals. Understanding 

consumer behavior and the aggregated impact of this distributed resource is important to guide future developments. The ARRA-funded AMI deployment is an opportunity to collect data and information on how this 

technology can work in practice and at scale. Benefits derived from this technology will be evaluated and disseminated to interested stakeholders. The unprecedented scale of this demonstration required close coordination with suppliers, utilities, and regulators.

Microgrids: Microgrids turn a set of localized distributed energy resources and loads into a single entity. This 

entity has the ability to connect and disconnect from the grid when necessary, such as during a fault or when 

load shedding is desired. While disconnected, a microgrid can operate autonomously to provide energy to the 

loads. Seamless separation and reconnection from the grid has not yet been demonstrated and evaluated for 

safety and efficacy. The grid components and technologies that will be needed to form a microgrid require 

demonstration. 

Planning and Policy Support

The electric industry is comprised of numerous stakeholders with different priorities, business models, and 

jurisdictions. Addressing the policy, market, regulation, siting, permitting, and planning issues that involve 

these various stakeholders in conjunction with technology development and deployment are important to grid 

modernization. The industry currently uses multiple models and tools that may result in divergent conclusions. 

System Architecture: Accurate assessment of the optimal combination of infrastructure assets, locally and 

nationally, is important to ensure affordable and reliable electricity. Exploring the costs and benefits of onshore vs. off-shore technologies, overhead vs. underground transmission, two-way communication and control, hybrid AC/DC circuits, HV-DC backbones, and other system architectures are important for modernization. 

Advanced topologies such as high-frequency DC links and the use of HV-DC within interconnections to boost 

transfer capacity are gaining attention and require evaluation.

Stakeholder Coordination: The organic evolution of the electric grid and the varying perspectives of its stakeholders have made it difficult for entities to work seamlessly together. The issues facing the grid require collaboration and coordination between numerous stakeholders to arrive at technical, market, and policy solutions 

in a timely and cost-effective manner. Collaborative long-term analysis and planning for the Eastern, Western, 

and Texas electricity interconnections will provide a comprehensive look across each of the three transmission 

interconnections to assess transmission needs for future scenarios. This will help states, utilities, grid operators, 

and others prepare for grid modernization.23 

Markets and Regulations: Markets and regulations drive how certain grid technologies are used and implemented. Accurate and unbiased techno-economic reasoning for incentives, cost-allocation, pricing schemes, 

market changes, and technology choices is valuable to decision makers and legislators who are tasked with formulating policies. Many existing statutes and regulatory requirements (e.g., permitting and cost-minimization) 

strongly impact current planning practices, while new regulations and policies could unintentionally change 

grid planning. 

Environmental Considerations: Changes in the generation mix and the adoption of new technologies have 

led to some environmental concerns. Issues such as water usage and waste management of generation, ecosystem impacts of transmission, and land-usage of renewable resources impact grid planning and policies. 
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DOE History and Accomplishments

In the 1980s and 1990s, DOE grid infrastructure technology investments were generally about $20–$30 million 

annually, the majority of which was dedicated to HTS. In the 2000s, they increased to around $40–$70 million 

annually. DOE’s major grid technology successes include the introduction of wide area visualization tools for 

the transmission level and the development of phasor measurement units (PMUs). Component-level technical 

successes included the development of fault current limiters. There was also some success with Smart Wire 

modules and aluminum conductor composite reinforced advanced conductors. ARRA funded the deployment 

of PMUs and made a major push to demonstrate storage, although this represents a modest subset of grid 

infrastructure technologies. In the past year, the Advanced Research Projects Agency – Energy (ARPA-E) has 

targeted projects in grid infrastructure technologies.

The HTS program received the majority of DOE funding for grid infrastructure technologies from 1987 through 

2010. Funding ranged from $12–$22 million annually for the first 13 years, increasing to $20–$50 million 

annually from 2000–2010, about $640 million over the course of the program. The program developed HTS 

materials and devices for a wide variety of applications, with an emphasis on underground cables. This program 

concluded with the successful demonstration of HTS technology in the Long Island Power Authority’s installation of the world’s highest rated HTS cable (138 kV).

After the 2003 Northeast blackout, the U.S. Secretary of Energy and the Canadian Minister of Natural Resources were appointed to chair the joint U.S.-Canada Power System Outage Task Force. That Task Force was 

assigned the responsibility of investigating the outage to determine the cause, as well as why it was not contained. A secondary task was to develop recommendations to reduce the possibility of future outages and to 

reduce the scope of any that did occur. Three working groups were created comprising of state and provincial 

representatives, federal employees, and contractors to address the two tasks. The final Blackout Report24 was 

released in April 2004 identifying the cause of the blackout and listing 46 recommendations. These recommendations guided DOE R&D direction such as cybersecurity and the deployment of PMUs.

DOE Role

Public comments and technology roadmaps25 indicate that non-technical barriers could slow grid modernization, and DOE has a role in providing information to decision makers who can address those barriers. DOE 

is well placed to convene multiple parties to achieve collaborations, discussions, and planning for the future 

grid. DOE also serves as a valuable resource for the collection and dissemination of unbiased grid technology 

performance and cost information. 

The Department possesses unique capabilities in materials discovery and design for high-voltage and hightemperature control of electricity, including wide bandgap semiconductors. The Department also has a unique 

set of integrated testbed capabilities, such as the National Supervisory Control and Data Acquisition (SCADA) 

Test Bed Program at Idaho National Laboratory,26 that allow for verification, validation, and prediction of in situ 

device performance for new grid infrastructure technologies.
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GRID MODERNIZATION

GRID STORAGE

Context

Grid storage can facilitate the transformation of the U.S. energy system and the modernization of the electrical 

grid. Storage technologies can provide balancing services to support renewable generation, reduce or mitigate 

electrical outages, and defer transmission and distribution upgrades. Additionally, storage can support the 

deployment of electric vehicles and will play a role in the evolving smart grid. 

Systems that store energy for later use can extend and optimize the grid’s operating capabilities, especially in integrating variable renewable generation. Grid storage and other operational strategies, like demand 

response,27 can provide valuable grid services that span a broad range of power, energy, and discharge times. 

Figure 23 shows the power, corresponding discharge times, and grid services provided by various storage technologies. Power quality services, including frequency regulation, requires response times in seconds to minutes, 

while transmission and distribution (T&D) grid support (load shifting, peak management, and bridging power 

services) operates on minutes to hours. Frequency regulation is required to maintain system stability, while 

power quality services mitigate the brief outages and disturbances that cost the U.S. economy more than $80 

billion annually.28 Load shifting and peak management provide the ramping services needed to accommodate 

the diurnal cycles in load, and can also help defer transmission and distribution upgrades. Bridging power 

provides reliability by balancing against the short-term intermittency of some renewable sources. Finally, bulk 

power management has timescales of hours and is mainly used for energy arbitrage. 
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Li-ion Battery

NaNiCl2 Battery

Discharge Time at Rated Power

High-Energy

Supercapacitors

Advanced Lead-Acid Battery

NaS Battery

Flow Batteries:

Zn-Cl Zn-Air Zn-Br VBR PSB New Chemistries

CAES

Pumped

Hydro

Lead-Acid Battery

NiCd

NiMH

High-Power Flywheels

High-Power Supercapacitators SMES

HOURS MINUTES SECONDS

Power Quality

Services T&D Grid Support Bulk Power Mgt

1 kW 10 kW 100 kW 1 MW 10 MW 100 MW 1 GW

System Power Ratings, Module Size

Figure 23. Classification of Energy Storage Technologies by Power, Discharge Times, 

and Primary Grid Service 

The technologies in Figure 23 also have secondary applications beyond those shown. For example, the Bonneville Power Administration has used pumped storage hydropower (PSH) for load shifting and, in some cases, 

power quality services. However storage technologies are generally optimized around the performance requirements and economics of a single application and might therefore be suboptimal for secondary applications.

In 2010, a DOE-funded multi-stakeholder workshop on grid storage identified five primary applications spanning the key service areas characterized in Figure 23. Table 19 summarizes those grid applications and highlights the performance and cost targets needed to make each economically viable. Due to differences in cost 

and performance, most storage technologies are optimized to a primary application—although some have the 

potential for use in several applications.

Power is a measure of how quickly energy can be released, while discharge times give a measure of how much 

energy can be supplied at a given power level. Credit: Rastler, D., et al. (2010). Electricity Energy Storage Technology 

Options: A White Paper Primer on Applications, Costs and Benefits. (Report #1020676). Page ES-7, Figure ES-6. 

Palo Alto, CA: Electric Power Research Institute. Accessed at http://my.epri.com/portal/server.pt?Abstract_

id=000000000001020676
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Grid Application Purpose Key Performance Targets

Balancing Area and 

Frequency Regulation 

(short duration)

• Reconciles momentary differences 

between supply and demand within 

a given area 

• Maintains grid frequency 

Service Cost: $20/MW per hour

System Lifetime: 10 years

Discharge Duration: 

15 minutes to 2 hours

Response Time: < 1 sec

Roundtrip Efficiency: 75%–90%

Renewables Grid 

Integration (short duration)

• Offsets fluctuations of shortduration variation of renewables 

generation output 

Capacity: 1–20 MW

System Lifetime: 10 years

Response Time: 1–2 seconds

Roundtrip Efficiency: 75%–90%

Transmission and 

Distribution Upgrade 

Deferral and Substitution 

(long duration)

• Delays or avoids the need to 

upgrade transmission and/or 

distribution infrastructure using 

relatively small amounts of storage 

• Reduces loading on existing 

equipment to extend equipment 

life

Cost: $500/kWh

Capacity: 1–100 MW

System Lifetime: 10 years

Discharge Duration: 2–4 hours

Reliability: 99.9%

Load Following (long 

duration)

• Changes power output in response 

to the changing balance between 

energy supply and demand 

• Operates at partial output or input 

without compromising performance 

or increasing emissions 

• Responds quickly to load increases 

and decreases 

Capital Cost: $1,500/kW or 

$500/kWh for 3 hour duration

Operations and Maintenance 

Cost: $500/MWh

Discharge Duration: 2–6 hours

Electric Energy Time Shift 

(long duration)

• Stores inexpensive energy 

during low demand periods and 

discharges the energy during times 

of high demand (often referred to 

as arbitrage) 

• Accommodates renewables 

generation at times of high grid 

congestion by storing energy and 

transmitting energy when there is 

no congestion 

Capital Cost: $1,500/kW or 

$500/kWh

Operations and Maintenance 

Cost: $250–500/MWh

Discharge Duration: 2–6 hours

Response Time: 5–30 minutes

Roundtrip Efficiency: 70%–80%

Table 19. Grid Application Performance and Cost Metrics with Targets

Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. page 13. Albuquerque, NM. 

Accessed at http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf
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A storage option’s economic viability depends on the value of the services that it provides compared to competing solutions. Bulk power management is most cost-effective with wide spreads in peak and off-peak electricity 

prices, while load shifting and peak management are most cost-effective when line congestion drives up the 

cost of electricity. Aside from technical challenges, factors such as siting, market structures, safety, policies, and 

operational paradigms all impact the economics of storage options. Ultimately, the true value of grid storage 

and temporal flexibility will depend highly upon local system needs.

Current State of the Technology

Grid storage technologies have been in various stages of development over the past 120 years; PSH is the 

most mature for these applications. Figure 24 shows the worldwide installed capacity of storage technologies, 

including commercial plants and demonstrations. Worldwide stationary storage capacity is expected to grow 

from 127 gigawatts (GW) today (some 3% of generating capacity), to more than 400 GW in 2030, with approximately half of that growth forecast to use batteries.29

127 GW

Compressed Air Energy Storage

440 MW

Sodium-Sulfur Battery

330 MW

Lithium-Ion Battery

128 MW

Lead Acid Battery

46 MW

Flywheel

29 MW

Nickel Cadmium Battery

29 MW

Redox-Flow Battery

17 MW

Pumped Hydro

Figure 24. Installed Worldwide Grid Energy Storage Capacity

Rastler, D., et al. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, Costs and 

Benefits. (Report #1020676). Page ES-3, Figure ES-1. Palo Alto, CA: Electric Power Research Institute. Accessed at 

http://my.epri.com/portal/server.pt?Abstract_id=000000000001020676

China Energy Storage Alliance. (2012). “CNESA Industry Trends 2012-03.” Beijing, China. Accessed at http://www1.

cnesa.org/do/bencandy.php?fid=110&id=1129 
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100

10

1

0.1

Lead-Acid

Ni-Cd

Li-ion

Na-S

ZEBRA

Flow batteries

CAES

Pump-hydro

Capital cost (¢)

Energy (kWh) x Life (cycles) x Efficiency

Capital cost (¢/kWh/cycle-output)

Figure 25. Normalized Capital Cost for Bulk Energy Management Grid Storage Technologies

Electricity Storage Association. Accessed at http://www.electricitystorage.org/technology/storage_technologies/

technology_comparison 

In 2003, the United States cycles 2.5% of its electricity through storage, while Europe and Japan cycled 10% 

and 15% respectively.30 Most of this capacity is PSH, which comprises 99% of the world’s storage capacity. 

There are currently 22 GW of installed PSH in the United States (some 2% of generating capacity), while an 

additional 25 GW is in development, but faces significant siting and permitting barriers.31 Other available technologies include Compressed Air Energy Storage (CAES) and Sodium Sulfur (NaS) batteries. Globally, 400 MW 

of CAES have been installed and operational for over 20 years at two facilities, one of which is in the United 

States.32 ARRA funding initiated the design and development of an additional 450 MW in the United States.33

There are 330 MW of NaS batteries installed worldwide, primarily in Japan. The installed capacity of NaS batteries is expected to grow to 606 MW in 2012.34 Other storage technologies presented in Figure 24, such as 

flywheels and redox flow batteries (RFB), are currently only deployed in small-scale demonstrations, but have 

significant technical headroom.

The recent increases in renewable energy generation have spurred interest in storage technologies to provide 

grid services. Though not essential to renewable energy integration, storage technologies provide a way to 

maximize the use of variable power generated by renewable sources. Figure 25 shows the range of capital costs 

for various storage options in cents/kWh, normalized by their deep-discharge cycle-life and efficiency. Most 

battery grid storage options are currently too expensive and have limitations in efficiency, durability, cycle life, 

and other important metrics. Broad deployment of grid-scale storage requires improving the cost and performance of multiple technologies.
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Advanced PSH is used primarily for peak shifting and diurnal energy management for renewable generation, 

but can also provide ancillary services. PSH facilities in the United States owe much of their existence to the 

need in the 1970s and 1980s for alternatives that were less expensive than oil and more flexible than nuclear. In 

contrast, newer PSH projects require pump-turbine and motor-generator technology that can provide ancillary 

services to power systems and are justified by the value of those services. 

Technology classes for PSH facilities installed worldwide include traditional synchronous-speed pump-turbine 

units, advanced hydraulic feedback units with modulated output, variable speed PSH units,35 and extremely 

fast-response ternary pump-turbine units that can swing hundreds of megawatts of capacity on sub-minute 

timescales. The U.S. PSH fleet includes only synchronous-speed integrated pump-turbine technology. Hydraulic 

feedback units with modulated output, variable speed PSH units, and extremely fast-response ternary pumpturbine units provide enhanced flexibility and services with only marginal increases in capital and operating 

costs.36 Most PSH facilities in the United States were built between 1965 and 1985 and have a generating capacity greater than 500 MW, with the largest facilities having individual units approaching 500 MW and total 

capacity exceeding 2,000 MW.37 Modern pump-turbine and motor-generator designs achieve greater than 

90% peak efficiency in both the pumping and generating modes for storage-cycle efficiency above 80%.38 For 

more information about the technical headroom and barriers to PSH, see the Water Power technology assessment.

This assessment focuses on energy storage technologies such as batteries that have the potential for broad 

deployment and substantial technical headroom and scalable operational concepts, like demand response. 

Technical Roadmaps 

Several DOE roadmaps39 address grid-scale storage with significant agreement on the technology potential 

and pathways forward. The DOE energy storage planning document establishes a roadmap for energy storage 

systems, whereas the other two roadmaps focus on the fundamental material innovations needed. The performance and cost of energy storage technologies depend strongly on the materials used and are the targets 

of basic R&D. Development of advanced materials, processing techniques, and methods to incorporate new 

materials into devices are needed to reach performance and cost targets. Relevant work includes basic materials 

research, exploration of advanced electrochemical combinations, solid state ionics, improved membranes and 

seals, use of new nanomaterials, and development of novel cell stack designs. New developments in crosscutting technologies such as advanced control systems, power electronics, and thermal management would facilitate effective deployment of storage technologies; those elements are covered in greater detail in the other 

grid technology assessments.

Technology Potential

Lead-Acid Batteries: Conventional lead-acid batteries are a mature technology with large retail sales and 

extensive use in vehicles.40 Several small-scale demonstrations of the use of lead-acid batteries for grid-scale 

storage around the world were conducted worldwide in the 1980s, and a 250 kW project was funded by DOE 

in the early 1990s. However, the use of this technology for grid-scale applications has been limited by weight, 

volume, cycle-life limitations, and reliability issues arising from the traditional chemistry.
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Lead-carbon batteries are the most significant technological opportunity for this technology family. Research 

on lead-carbon battery technologies,41 similar to prototypes funded through ARRA,42 has shown the potential 

for an order of magnitude improvement in cycle-life durability at manufacturing costs comparable to conventional lead-acid batteries. Such a development would dramatically reduce the levelized capital costs.

R&D in this space could improve cycle-life (from the commercially available 1,000 cycles and demonstrated 

8,000 cycles to 10,000 cycles).43 Generic research agendas that could address issues from maintenance requirements to high-voltage operation have been suggested, although specific technical targets have not been identified.44 A firm understanding of the lead-carbon electrode and the modified chemistry can move this space. 

Lighter weight and higher voltages will broaden the utility and applications of this technology.

Lithium-Ion Batteries: Lithium-ion technology is considered mature for consumer electronics, with production volumes of 10–12 gigawatt hours (GWh) a year, but it has not been used extensively for grid applications.45 Present lithium-ion technology is poorly suited to bulk energy services because of its short deep-cycle 

life, thermal management and safety issues, and high material costs. However, the power densities and fast 

response times offered by lithium-ion batteries make them well suited for frequency regulation, and the high 

energy densities make them very attractive for electric and hybrid vehicle applications. 

Manufacturing volumes of lithium-ion batteries are projected to reach 35 GWh annually by 2015, primarily 

driven by vehicle applications.46 As a result, secondary use of vehicle batteries for grid storage applications is 

now under consideration. Early trials of multi-MW systems are underway for commercial service and demonstrations in frequency regulation markets.47 Also, portable/transportation-derived designs have been adapted 

for stationary deployment. In total, there are now 50MW of grid connected lithium-ion batteries, with additional capacity under construction. 

Further R&D can help increase deep discharge cycle-life, reduce costs, and improve the safety of this technology. Enhanced system understanding, improved packaging designs, and new materials can move the technology forward. Up to a two-fold reduction in total systems costs (from $1,000/kWh) in approximately 5 years48

and a five-fold increase in cycle-life (from 1,000) could be achieved from these innovations. 

Sodium Batteries: Sodium-based battery technologies are attractive for their high efficiency and their use of 

abundant, low-cost sodium. Their primary challenges are high operating temperatures (up to 350°C depending 

on the Na-conducting membranes) and relatively high system costs.49 Conventional NaS systems are considered mature, with significant deployment primarily in Japan.50 The DOE co-funded the first U.S. installation of 

this technology in 2002.51 More advanced configurations using Sodium-Nickel Chloride (Na-NiCl2) chemistry 

(referred to as ZEBRA) are also nearing commercialization. Despite the relative maturity of these technologies, 

issues remain with system costs, reliability, durability, and performance. Safety concerns also inhibit the wide 

market penetration of older generations of this technology. The high operating temperatures raise issues of 

thermal management, material selection, and system life, which can increase costs and lower reliability.

Applied materials R&D can drive down operating temperatures to improve durability and safety. Lower temperatures can open the door to new system designs and material selection for lower costs and enhanced performance.52
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Flow Batteries: Flow batteries are essentially regenerative fuel cells that store electricity in the liquid electrolyte 

instead of in the electrodes. Therefore, they can be designed to optimize power delivery and energy storage capacity separately. This family of technologies is relatively immature, with limited deployment around the world. 

While a variety of redox couples are possible, the most mature is the all-vanadium RFB, which can have a life of 

10,000 or more cycles at 100% depth-of-discharge.53 Zinc-Bromine (Zn/Br) and Zinc-Chloride (Zn/Cl) RFBs are 

less mature, but are in the early stages of demonstration. Iron-Chromium (Fe/Cr) and Zinc-Air RFB chemistries 

are generally less well-developed but are attractive due to the potential for very low system costs. Technical 

challenges associated with these technologies include controlling the transfer of active chemical species across 

the separating membrane, improving the durability and stability of membranes and electrolytes, and increasing 

the ion concentrations in the electrolytes. Improved stack architectures can also help improve performance and 

reliability, while improved hydraulic subsystems can reduce costs, increase durability, and ensure safety.

Further R&D can help develop new chemistries, increase charge densities of the electrolyte, and address other 

pressing technical issues to further develop this promising technology. DOE believes it is possible to double energy densities (from 20 Wh/kg), double power densities (from 50 mW/cm2), improve efficiencies (from 70%), 

and halve costs (from $500/kWh).54

Compressed Air Energy Storage: CAES is a commercially available, utility scale, bulk electricity storage technology that uses high-pressure air as a storage medium. Large-scale, airtight storage volumes can be developed 

in geologic formations such as underground salt domes and saline aquifers. In conventional CAES, stored compressed air is released through a modified gas turbine that uses approximately one-third the natural gas of a 

conventional turbine, making CAES a hybrid storage/generation technology. Conventional CAES is considered 

a fairly mature technology, based on well proven gas-turbine technology and with two plants operating for 

over two decades.55 Two additional CAES plants are under development following ARRA funding to demonstrate the viability of CAES in different geologic environments.56 Research is ongoing into adiabatic CAES that 

does not require natural gas combustion.

Electrochemical Capacitors: Some storage applications, including frequency regulation and power quality, 

prioritize power delivery over energy capacity; high-performance electrochemical capacitors are well suited 

here. Electrochemical capacitors are currently expensive, and their electrolytes are not optimized for highvoltage grid applications.57 Further R&D can lead to the development of new materials for electrodes and electrolytes in supercapacitors. Improved materials can lower costs and raise the operating voltages of capacitors 

to make them more applicable for high power grid services.

Flywheel Storage: Flywheels are also well-suited for applications requiring high power. Flywheels have demonstrated very rapid response times, deep discharge cycles, and are very efficient (over 90% round-trip).58 Their 

power densities are 5–10 times greater than batteries, with a very long cycle-life estimated to be over 100,000. 

However, flywheels suffer from low energy densities and high system costs.59 Through ARRA, DOE has funded 

several multi-MW demonstrations of flywheel technology for frequency regulation.60

R&D in flywheel designs, along with new materials for the hub (the spinning mass), can raise the efficiency, 

lower system costs, and improve reliability. It may be possible for costs of flywheels to be reduced eight-fold 

from the current $2,000/kW.61

Potential headroom for the battery technologies assessed in this section is summarized in Table 20.
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Technology Metric Current Headroom

Lead-Carbon Batteries62 Cycle life 

Energy density

3,000 cycles 

25-40 Wh/kg

10,000 cycles

70 Wh/kg

Lithium-Ion Batteries63 Cycle life 

Costs

1,000–4,000 cycles 

$1,000/kWh

5,000 cycles

$500/kWh

Sodium Batteries64

Power density 

Energy density 

Costs

100 W/kg 

150–240 Wh/kg 

$550/kWh

Mature

Mature

Mature

Flow Batteries65

Power density 

Energy density 

Costs

50 mW/cm2

10–20 Wh/kg 

$500/kWh

100 mW/cm2

40 Wh/kg

$250/kWh

Emerging Technologies and Breakthroughs: There are a number of high-risk technologies that could transform grid-scale storage, but are currently in their infancy. Table 21 lists those emerging technologies and 

breakthroughs, along with an indication of technical milestones that, if achieved, could justify continued R&D 

interest.

Table 20. Summary of Storage Technologies and Current Performance and Technical Headroom

Note: Each battery storage technology has different design, structure, and operation, which limit their application for 

certain grid services. Metrics cited here are used to reflect those most important to their applications.
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Breakthroughs Description 

Ambient Temperature 

Sodium-Based Batteries

Operation at ambient temperature will simplify the design and thus costs; 

sodium is low cost and more abundant compared to lithium

Nitrogen-Oxygen Batteries Highest energy density by using N2 and O2 as anode and cathode; using 

ambient materials will be safe and low cost

Metal-Air Batteries Low-cost metal negative electrode and positive air electrode for large 

energy capacity and low costs; can offer 10× energy density of Li-ion

Advanced Flow Batteries New electrolyte chemistries, stack/cell designs, and electrode materials 

can reduce costs (2× with zinc-iron to <$150/kWh)

Liquid Metal Batteries Uses liquid metals for electrodes and molten salt as electrolyte; can 

have 10× current of high-end batteries

Next-Gen Lithium-Ion 

Batteries

Improved component materials will lower costs and improve safety; 

replace cobalt in cathode with manganese; replace electrolyte with solid 

polymeric material; higher energy densities with nano silicon-carbon 

composite electrode

Advanced Flywheels

Will have high energy density instead of just high power; incorporate new 

fiber and nano-materials into rotor composite for increased speed and 

energy density; hubless designs with magnetic nanoparticles can also 

increase strength

Table 21. Breakthrough Technologies

Policy Context

Grid-scale storage can help ensure system integrity with a generating mix that has a higher fraction of renewable energy resources. However, current market structures fail to capture value across the multiple services 

(Table 19) that many storage technologies can provide. That deficiency, combined with market and policy 

uncertainty in how to treat storage institutionally (e.g., Is it a generator? Can it sell wholesale? Retail? Who 

regulates it?), has slowed innovation in, and the deployment of, grid-scale storage technologies.

Barriers

Energy storage technologies face a number of barriers to widespread deployment beyond the challenges in 

meeting performance and cost targets. These barriers include:

•	 Market Structures: Markets do not address or value storage and many of the services it can provide. 

•	 Limited Large-Scale Demonstrations: Many storage technologies lack the performance data from 

real-world, large-scale demonstrations needed to inform utilities and regulators.

•	 Lack of Standards and Models: There is little effort to develop the necessary standards for comparative evaluation of storage technologies and models for use by grid planners.

•	 Stakeholder Understanding: Benefits of storage have not been established, clearly articulated, or 

communicated to key stakeholders.
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Storage technologies require more performance data from real-world, large-scale demonstrations before they 

can be deployed widely.66 Many of the current testing sites for storage cannot accommodate grid-scale systems, nor do they reflect real-world conditions.66 This limits the size, scale, and fidelity of simulations that can 

be used to evaluate device cost, efficiency, durability, reliability, and safety. Testing and demonstration of 

various technologies in multiple applications and regions across the country are the foundation for data and 

analysis that will support commercialization. Information from existing demonstration projects (such as those 

funded by ARRA) can provide a firm foundation for the technologies demonstrated.

Today’s analysis tools and models do not adequately incorporate grid storage and the services that it can provide. This limitation hampers R&D, as well as stakeholder understanding of storage and its benefits. Analysis of 

market and policy structures with validated models and tools enable the changes necessary for the commercial 

development and deployment of storage. System planners and engineers also need to understand how to compare storage technologies accurately against other supply, delivery, and demand-side options. The lack of testing standards and simulation models prevents cross-evaluation and the development of accurate performance 

specifications for energy efficiency, cost, and other key attributes.66

DOE History and Accomplishments

DOE development and demonstration funding for grid-scale energy storage ranged from $2–$4 million annually from 2005–2009 and was $13.6 million in Fiscal Year 2010; funding has increased again to about $20 

million starting in 2011. ARRA provided $185 million for the development and demonstration of grid-scale storage. These funds encouraged an additional $585 million cost-share investment by the private sector to further 

develop and demonstrate these technologies. 

DOE also supports basic and applied materials research and novel chemistries for grid-scale storage, partially 

through six Energy Frontier Research Centers.67 

DOE Role

DOE’s focus in grid storage is on its R&D capability and informational role. Building on existing capabilities 

ranging from modeling and simulation to testbeds, and leveraging data from large-scale storage demonstration projects funded by ARRA, DOE is uniquely positioned to measure, validate, and disseminate performance 

information for grid-integrated storage technologies. 

The Department’s scientific and experimental capabilities allow it to develop testing protocols for large-scale energy storage and standards for technology validation. By developing the analytic tools necessary to assess and 

predict value and service as a function of operation and location, the Department helps quantify the benefits 

of storage under various operating conditions and provide this information so that industry and regulators alike 

can fully assess the value of deployed storage capacity. The Department also lends its R&D capability to technical issues related to lead carbon, mixed electrolyte, and metallic, ionic, liquid-flow battery R&D to increase 

energy density, cycle life, and cost-effectiveness.
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GRID MODERNIZATION

GRID MEASURING, 

MODELING, AND CONTROL

“Software” has been an important part of electric grid operations and planning since the 1960s when the 

increasing complexity of the physical transmission system began to require models, algorithms, and operating 

tools. These tools improved understanding of the system and helped ensure reliable service while delivering 

electricity to consumers at the lowest cost. By design, the approach was compartmentalized along the operational and jurisdictional boundaries that characterized the electric system at the time. The grid was managed 

very conservatively–with wide operating margins and significantly under-utilized assets–because of limitations 

in the underlying sensing, communication, and computing technologies then available.

Today, “smart grid” technologies are moving toward dynamic optimization of the grid, from generators all the 

way to the customer. Deploying smart grid technologies can produce data of unprecedented quality and quantity, on all aspects of grid operations. As various stakeholders–generators, grid operators, consumers–exploit 

those data to understand, control, and forecast aspects of the grid in real-time, the electric power system will 

develop an unprecedented level of flexibility. 

Smart grid technologies can address evolving challenges that include variable generation from renewable resources; uncertainty in load profiles resulting from distributed generation, demand response, and plug-in electric vehicles; reduced generation and transmission margins; evolving opportunities for, and valuation of, ancillary services; and cybersecurity. Such capabilities will allow economically optimal accommodation of changing 

generation and load, while supporting the affordability, power quality, and reliability required by consumers. 

However, this growing overlay of information technology on grid operations and control will require greater 

focus on security to mitigate the threat of cyber intrusion by those with nefarious intent.

Innovation along three pathways will facilitate this transformation:

•	 Measurement and Controls: Acquiring, sharing, and (real-time) processing of data throughout the 

electric system 

•	 Communications and Security: Enabling a secure, resilient information backbone

•	 Modeling and Analysis: System understanding (primarily off-line) to support better grid operations, 

planning, markets, and policy making.
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Measurement and Controls68

Improved awareness of, and control over, the grid system and its many components is central to a future smart 

grid. The ability to acquire, process, and act upon data will improve asset utilization, allow system operation 

closer to thermal, voltage and stability limits, and improve reliability. Enhanced real-time monitoring, operator 

awareness, adaptive relaying/protection, and automated network switching are important underlying capabilities. 

Context 

Operating an electric grid requires continuous and real-time matching of energy supply with energy demand. 

Today’s U.S. electric system is operated by adjusting generator output to meet constantly changing system 

loads and responding immediately to system contingencies (with occasional re-configuration of the transmission network). The approach is predicated on little to no control over electricity demand, so that generators 

alone must respond to changes.69 This has been the operational paradigm since the inception of the utility 

industry in the late 1800s. Control is achieved through local control and monitoring system conditions (e.g., 

from energy management and SCADA systems) conveyed to a central control center, where a combination of 

automated controls and human decision making ensures system reliability at reasonable cost.

Today, the primary monitors of electric grid elements are current sensors (current transformers) and voltage 

sensors (voltage transformers and potential transformers). The SCADA system, which monitors current flow 

through lines, transformers, and other components into delivery points, typically makes measurements every 

2 to 6 seconds. While that sampling rate has proven adequate for steady-state operations, it is insufficient to 

understand (or even detect70) the details of transient phenomena with timescales of milliseconds (one 60 Hz 

cycle is 16 milliseconds).71 

Demand response has been used by some utilities for over 20 years to provide cost-effective temporal flexibility.72 Interruptible contracts for commercial entities and industry, as well as direct load control schemes to 

manage residential water heating and air conditioning loads, have been very effective in peak-shifting. Other 

demand response programs being explored require AMI and dynamic pricing to allow customers to respond 

voluntarily to price signals. 

The value and potential of this technology has not been fully assessed.
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Current State

System monitoring by operators 

with real-time data sampled 

every 2–10s. Real-time system 

monitoring by operators is 

supported by offline engineering 

and operational analyses, many 

of which are performed manually 

(high latency).

System is operated to high 

reliability requirements. Since 

operations must account for 

uncertainty in underlying data 

and analysis techniques, 

assets are under-utilized.

System monitoring by 

operators with real-time 

data sampled every 10–100 

milliseconds. This would 

entail the deployment and 

use of sensors, switches, and 

supporting communications 

technology across the electric 

system.

Operators view system conditions 

in real time, enabling a more 

immediate, precise response 

and increased system 

efficiency.

Automated adaptively 

reconfigurable network.

Mid-Term (2016) Long-Term (2020+)

Figure 26. Pathway for Grid Modeling and Control

Note that some mid-term technologies are already employed by some operators.

Attributes of today’s operating methods include: (1) limited communication and sharing of operational data 

and system models across the broader community, (2) operational procedures and controls that are optimized 

to local needs/benefits rather than the broader system, (3) inaccurate system models, (4) poor communication between planning and operations models, and (5) reliance on offline (lengthy, non-real-time) analysis to 

set operating limits. The latter impacts the pace of innovation and the consumer’s ability to co-optimize their 

behavior/processes (in the case of large industry). A sensor network (such as the one shown in Figure 27) that 

provides time-synchronized dynamic data over the entire grid (e.g., voltages, currents, power flows, equipment 

performance, and weather) is a key enabler of the future grid’s real-time measurement and control system.73

Although the private sector will continue to refine these sensors as applications evolve, the underlying sensor 

technologies are not expected (or needed) to evolve significantly.

Trends and Technology Potential
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Oak Ridge National Laboratory. (2004). Advanced Sensors for Grid Modernization: White Paper on Issues and Benefits. 

Oak Ridge, TN.

Communications (High Speed/Wide Bandwidth) & Data

Acquisition/Processing (High Performance) Systems

POWER GRID SENSORS

POWER GRID CONTROL

Transmission

Line Sag

Transmission

Line Current

Transformer

Status

DER Real

& Reactive

Power

SCADA 

and Load 

Monitoring

Dynamic

Transmission

Line Loading

Power Line

Flow Control

Dynamic

Transformer

Loading

DER Power

Control

Load Control

(i.e., price

controls)

Figure 27. Example of Sensors as an Enabling Technology for the Control of the Future Grid

GPS time-synchronization technology allows temporally precise measurements of voltage, current, and frequency, typically sampled at 10 Hz (for GridEye Frequency Disturbance Recorders) to 30 Hz (for PMUs).74

Sampling rates are expected to rise to 120 Hz as the new PMU infrastructure comes online.75 While today the 

GridEye and PMU data are used for post-event analysis, the technology is suitable for matching energy supply 

and demand in real time, providing insights (through more dynamic measurement) critical to system stability.

Beyond 120 Hz, sampling is the digital fault recorder domain, with sampling rates up to 8 kHz.76 Integrating 

and harmonizing datasets across the various time resolutions into a consolidated toolkit will create a unified 

view of the system, with insights into the instantaneous behavior of the grid, the generators, and the loads.
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Through the Smart Grid Investment Grant program, DOE is supporting the deployment of more than 800 

PMUs across the Nation—a five-fold increase of the presently installed base.77 That network will provide timesynchronized information at the transmission level across entire interconnections. The primary need now is 

for advanced software tools and platforms that can fully exploit the information that will soon become available from this network. Today’s PMU-based applications have focused on wide-area monitoring and forensic analysis of grid disturbances,78 while future applications will likely include real-time control of wide-area 

networks,79 automatically and dynamically balancing supply side variability with demand side flexibility (see 

Figure 28). Industry Needs

VALUE OF SYNCHRONIZED MEASUREMENT

16

6 10

15

4

11 12

8 13

2 3

5 1

14

7

9

Critical

Moderate

Minor

Requires More

Investigation

Offers Additional 

Benefit

Necessary

1. Angle/Freq. Monitoring

2. Voltage Stability Monitoring

3. Thermal Overload Monitoring

4. Real-Time Control

5. State Estimation (Improvement)

6. State Estimation (Boundary Conditions)

7. State Measurement (Linear)

8. WA Stabilization (WA-PSS)

9. Adaptive Protection

10. Congestion Management

11. Power-System Restoration

12. Post-Mortem Analysis (Including

 Compliance Monitoring)

13. Model Benchmarketing; Parameter

 Estimation (Steady-State)

14. Model Benchmarketing; Parameter

 Estimation (Dynamic)

15. Planned Power-System Seperation

16. DG/IPP Applications

Low Med High

Deployment Challenges

Number of PMU’s

Communication Req.

Application Needs

Figure 28. Phasor-Based Applications 

Adapted with permission from: Novosel, D., Madani, V., Bhargava, B., Vu, K., and Cole, J. (2008). Dawn of the Grid 

Synchronization. Page 58, Figure 9. IEEE Power & Energy Magazine, Volume 6, Issue 1. Can be purchased from http://

ieeexplore.ieee.org/xpl/freeabs_all.jsp?arnumber=4412940 
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Area Action

Sensor Deployment including 

Phasors (after ARRA)

Expand, as necessary, sensor network to enhance situational 

visibility and to improve system flexibility

Control Methodologies and 

Protection Schemes 

Demonstrate concepts that enable automated controls for 

transmission and demand response and that increase transmission 

system throughout 

Operator Tools 

Develop and demonstrate phasor-based technology platforms for 

real-time operations and power system planning, such as inter-area 

oscillation detection and voltage stability monitoring

Deployment/Adoption

of Tools and Methodologies

On an ongoing basis, adopt emerging real-time tools and platforms 

that analyze electric system data and can maintain reliability by 

balancing (dynamically and automatically) demand-side flexibility and 

supply-side variability

Data Sharing Establish a method for sharing data across the electric system and 

its various stakeholders

Standards Facilitate the adoption of interoperability standards

Table 22. Opportunities for Technology Improvement

Communications and Security

In 2005, energy owners and operators, in collaboration with DOE, developed a technology strategy for better securing energy control systems going forward. The resulting Roadmap to Secure Control Systems in the 

Energy Sector (2006)80 lays out a vision to research, develop, deploy, and maintain energy delivery systems that 

can survive an intentional cyber assault without the loss of critical function. Updated in 2011 as the Roadmap 

to Achieve Energy Delivery Systems Cybersecurity,

81 it provides the strategic framework developed by industry 

through this effort.

Cybersecurity for energy delivery systems has emerged as one of the Nation’s most serious grid modernization 

and infrastructure protection issues. Intelligence reports indicate that cyber adversaries are becoming increasingly targeted, sophisticated, and better financed. The Stuxnet worm—designed to attack a specific control 

system—underscores the seriousness of targeted cyber attacks on energy control systems. The Roadmap acknowledges that the energy sector must research, develop, and deploy new cybersecurity capabilities faster 

than adversaries can launch new attack tools and techniques. With so many vital services and critical infrastructures interconnected with energy systems, a large-scale cyber attack could disrupt power and cause cascading 

failures, affecting the economy and public safety of large communities. Operational reliance (and automatic 

system controls) based on real-time data, such as GPS technology, reinforces the need to address potential 

cybersecurity vulnerabilities—assuring the signal is bona fide and always available when needed.

In addition to sensors and controls, the future grid will require wide bandwidth, high-speed, and secure communications. Current smart grid communication technologies and protocols are evolving from legacy devices 

using serial links to routable and wireless communications. Cybersecurity and privacy protections become more 

important as data availability and consumer engagement increase.
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Home Intelligence Feeder Automation Substation Automation Transmission Automation

Home Area Network (HAN) Local Area Network 

70o

Electric Vehicles Distribution Poles

Fiber 

Optic

AMI

Collector

Communications

Tower

Utility Central

Operations

ISO

Line 

Switch

with Radio

Transceiver

Smart Thermostat

Smart 

Meter

000003

Wide Area Network 

Customer Meter Collector Substation ISO Utility Central 

Operations

Broadband Wireless Fiber Optical Network

Network

Wireless Mesh 

Network

Home Area 

Network

Smart

Substations

(Transmission

& Distribution)

Power

Delivery WAN

Figure 29. Representative Communications Architecture

Figure 29 illustrates notional communications architecture. Energy control systems are uniquely designed and 

operated to control real-time physical processes that deliver continuous and reliable power to support national 

and economic security. The computers and networks that control our Nation’s power grid are very different 

from those on our desks in several important ways. 

•	 Energy delivery system communications must be fast. Data communications in substations require 

responses within 4 milliseconds for protective relaying, while wide-area situational awareness of transmission lines requires communications within a second. A cascading power failure might be prevented 

by changing the path of power flows within a tenth of a second. 

•	 Energy delivery system computers and networks must always be available. They cannot be patched 

or upgraded without extensive testing and validation, normally planned weeks or months in advance, 

to ensure that the change does not jeopardize power system operations. Often the vendor’s warranty 

for these systems prevents the change from being implemented at all. Energy delivery systems include 

decades-old legacy components with limited computation and bandwidth. As these legacy devices 

perform their function well, there is no immediate business case to replace them, but they were designed decades ago when the Internet did not exist and cybersecurity was not a central concern.

AMI = automated metering infrastructure, ISO = independent system operator.
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•	 Energy delivery systems have predictable communication patterns and predictable behavior, so they 

can be designed to allow only expected actions and deny others. In contrast desktop cybersecurity 

measures are designed to allow any actions not explicitly denied. Energy delivery systems require complex access controls, including secure remote access for maintenance and operations support. Multiple 

workers need different levels of access to the same device, and these access needs can change depending on operating mode. Most importantly, access controls must never jeopardize system availability, which could create problems during an emergency response. Energy delivery systems have critical 

components that are widely distributed across extensive territories, and are, by necessity, located outdoors, where they could be vulnerable to physical tampering. Finally, control systems security involves 

ensuring the timely and proper operation of cyber-physical devices (e.g., opening a digital relay or 

changing settings on transformers). Thus, cyber attacks on control systems can cause physical damage 

to expensive electric grid components like generators that can take months to replace.82

Trends and Technology Potential

Current State

Energy delivery systems 

vulnerabilities are identified 

by the National SCADA Test 

Bed and mitigation strategies 

recommended periodically

Security monitoring by operators 

with offline analysis that requires 

utilities to perform operations 

manually

Refining cybersecurity 

requirements and system 

needs

A near-real-time security 

situational awareness capability 

informs operator decisions

A secure gateway for exchanging 

power system data (e.g., PMU 

and SCADA data) protects 

communications between energy 

control centers

A secure communications 

capabilitiy protects data and 

detects physical tampering of 

remote field devices (e.g., AMI)

Resilient energy delivery 

systems are designed, installed, 

operated, and maintained to 

survive a cyber event while 

sustaining critical functions

Mid-Term (2016) Long-Term (2020+)

Figure 30. Pathway for Security and Communications

In 2011, a partnership of energy infrastructure cybersecurity leaders from government and industry developed 

the Roadmap to Achieve Energy Delivery Systems Cybersecurity, which outlines a strategic framework to design, install, operate, and maintain energy delivery systems that can survive an intentional cyber assault without 

the loss of critical function. 
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The updates of the Roadmap included:

Changing Landscape: New infrastructure components and the increased use of mobile devices in energy 

infrastructure environments introduce new digital vulnerabilities and additional physical access points. New 

applications such as managing energy consumption involve new stakeholders (e.g., retail service providers, energy and financial market traders, industrial, commercial, and residential consumers) and require protection of 

private customer and energy market information. The roadmap has a broad focus on energy delivery systems, 

which include control systems, smart grid technologies, and the interface of cyber and physical security—where 

physical access to system components can impact cybersecurity.

Advancing Threat Capabilities: Energy delivery systems are vulnerable to cyber attack and the threat is real. 

Adversaries have pursued progressively destructive means to exploit flaws in system components, telecommunication methods, and common operating systems found in modern energy delivery systems with the intent to 

infiltrate and sabotage them. 

Building on Successes and Addressing Gaps: Roadmap update participants identified the following new 

priorities: enhancing vulnerability disclosure between government, researchers, and industry; optimizing the 

limited time and resources of stakeholders through innovative partnerships; improving the metrics of progress; 

and addressing gaps to further advance cybersecurity technologies.

Emphasizing a Culture of Security: While regulations or standards can be used to raise security baselines, a 

focus on compliance alone will not produce resilient energy delivery systems. A culture focused on security that 

permeates the sector is needed. Social and human factors are particularly important because cybersecurity is a 

sensitive issue in which trust and careful stewardship are paramount. Sustaining a secure and resilient energy 

infrastructure will not be possible without people trained in developing and implementing the best available 

security policies, procedures, and technologies tailored to the energy delivery systems operational environment.

Critical future activities fall primarily into two themes: (1) building trusted systems from un-trusted components, and (2) achieving system resiliency by maintaining critical functions in the midst of a cyber event/incident. Because the threat landscape is constantly evolving, the energy sector security posture must also evolve 

dynamically. Privacy protection of customer energy-usage data is of the utmost importance. Greater access 

to system data will be required as the electricity consumer becomes an integrated part of the control system. 

Advanced data collection, communication, and information sharing capabilities are being rigorously secured 

to protect energy-consumer privacy. In addition, diverse types of energy-sector data–financial and operational–travel across smart grid communications links, are owned by different parties, and have different security 

requirements. 

A strategic research focus into tailored trustworthy spaces fits naturally within the smart grid cybersecurity 

arena where diverse data with differing cybersecurity priorities travel together in multi-party data streams. As 

the type and context of data change, cybersecurity solutions capable of real-time responses that balance confidentiality, integrity, and availability become more valuable. As an example, cybersecurity protections in place 

during normal operations may be dynamically tailored to the needs of emergency responders.
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Many entities have an interest in smart grid standards and interoperability work. Progress along the path of 

standardization and interoperability is accelerating and increasingly measurable. The Smart Grid Interoperability 

Panel (SGIP), a public-private partnership coordinated by the National Institute of Standards and Technology, 

published its first interoperability framework and roadmap in 2010, which identified key standards and gaps 

that required attention, as well as the evolution plan of the SGIP and a testing and conformance program. Version 2 of this framework has been recently published, marking progress to date and setting new goals.83 SGIP 

is also assembling a catalog of standards that will encompass, over time, relevant standards measured against 

common criteria such as cybersecurity, architectural position, and openness. 

Outside of the SGIP, the GridWise Architecture Council is working to create an Interoperability Maturity model 

that will be a practical benchmarking and goal-setting tool for organizations across the smart grid. In addition, the North American Electric Reliability Corporation Smart Grid Task Force has provided a comprehensive 

Reliability Considerations from Integration of Smart Grid report and a follow-on Cybersecurity working group 

evaluating pathways for harmonizing and coordinating common practices, regulations, and standards. Furthermore, in 2011, the National Science and Technology Council outlined unifying policy strategies that would 

enable a smart grid.84

Modeling and Analysis

Integrating large amounts of variable generation, mass deployment of plug-in vehicles, and actively engaged 

end-users will all increase temporal and spatial uncertainty in grid operations. Market structures to attract and 

retain new sources of firming generation add additional modeling and analysis requirements. Innovative highfidelity real-time modeling and simulation tools will be required for better grid operations, planning, and policy 

support.
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Transmission 

Siting & 

Construction

Power Plant

Siting & 

Construction

Closed-loop Control 

and Relay Setpoint 

Selection

Closed-loop

Control and

Relay Action

Maintenance

Scheduling

Long-term

Forward Markets

Day Ahead Market

w/ Unit Commitment

Load

Forecasting

Hour Ahead

Market

Five Minute

Market

15 years 10 years 5 years 1 year 1 month 1 week 1 day 5 

minutes

seconds

Figure 31. Time Scales Over Which Various Processes in Electric System and 

Markets Operate 

Source: Graphic by C. DeMarco. Presented at the Computational Needs for the Next Generation Electric Grid 

Proceedings: April 19–20, 2011. Ferris, M. (2011). White Paper: Coupled Optimization Models for Planning and 

Operation of Power Systems on Multiple Scales. Page 2-2. Madison, WI: University of Wisconsin-Madison. 

Context

Modeling and analysis of electric systems and markets cover both physical and behavioral (i.e., human) processes. These processes have different time scales and geographic scopes (Figure 31).

There is limited potential for human interactions on the shortest time scales (seconds). Modeling and analysis 

here is focused on understanding the physical characteristics of the electric system and the actions of automatic controls. Human decision making has a more significant role on longer time scales, so that modeling and 

analysis of human decision making figures prominently in understanding how the electric system and markets 

perform.
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Long-standing classes of modeling and analysis tools, listed from the shortest to longest time scales, include:

•	 The Electro-Magnetic Transients Program for the very shortest time scales of micro- to milliseconds. 

These are applied to both high-voltage transmission and low-voltage distribution systems. 

•	 Dynamic simulation tools for the high-voltage transmission system for time scales of milliseconds to 

seconds. 

•	 Positive sequence (i.e., balanced three phase) load flow tools for steady-state conditions on the transmission system. 

•	 Single and multi-area generation unit-commitment and dispatch simulation tools that seek to minimize 

the total production cost of meeting aggregated customer demands on an hourly or sub-hourly basis, 

while respecting transmission limits (with varying treatments of the dynamic nature of these limits) and 

simulating contingencies. 

•	 Optimal generation (and, to a lesser extent, transmission) expansion planning tools that look ahead a 

decade or more. 

The basic algorithms underlying all of these models were developed in the 1960s and early 1970s. These models capture the economic dispatch of the electrical system and match generation and load, while adhering to 

the underlying physical constraints associated with power flow (e.g., Kirchoff’s laws). 

Over the past two decades, computing speeds and resources have increased impressively, allowing more computationally intensive programs. The power industry has begun to apply state-of-the-art optimization techniques in its operation and planning processes. Widely used optimizers have achieved dramatic performance 

improvements.85 Although challenges remain in solving extra-large-scale problems with existing modeling and 

computing techniques, many regional system operators like Pennsylvania New Jersey Maryland Interconnection 

have begun to use more advanced mix-integer programming-based planning tools. Mix-integer programmingbased tools replace traditional Lagrangian relaxation-based tools in a number of application software products, 

ranging from capacity market, day-ahead market, and reliability commitment to time-coupled, real-time dispatch.86 In addition, over the last decade, DOE has invested heavily in the development of advanced optimization solvers and has investigated related opportunities in advanced grid modeling and simulation.87
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Current State

Static, slow, and regional view 

of the grid

Static power flows calculated in 

seconds; minutes are required to 

to solve coarse approximations 

of transient stability equations

Operators make fast decisions 

during and after a disturbance, 

sometimes with incomplete data

Static, but fast, and provides 

a global view of the grid

Few seconds to solve nonlinear 

transient stability equations 

on parallel computers, with 

some voltage stability analysis 

included

Integration of mathematical 

techniques and understanding 

into transmission system tools 

and demonstrating adaptive 

protective relaying at a utility

Dynamic, fast, global, and 

predictive view of the grid

30 milliseconds to solve 

equations with predictive ability

Improved security-constrained 

unit commitment and optimal 

power flow models

Integrated model platforms

Mid-Term (2016) Long-Term (2020+)

Figure 32. Pathway for Modeling and Analysis

Since these modeling and analysis tools were first introduced, the electricity industry has experienced three 

major changes that stress the current suite of modeling and analysis tools:

•	 Structural: In regions where there are markets, transmission and generation are no longer planned 

and operated on an integrated basis; market forces, not utility planners, determine the location and 

types of new generation that will be built. Optimal generation expansion tools do not adequately 

capture these decisions. Institutional mechanisms for coordinating planning of new (especially, interregional) transmission are in their infancy, with many unresolved issues (such as cost-allocation and 

siting). The current generation of unit-commitment and dispatch tools that minimize production cost 

cannot represent competitive wholesale electricity markets. Simultaneously, many parts of the United 

States still operate vertically integrated utilities, so market-based solutions must co-exist with more 

traditional company structures.

•	 Resource: Growing generation from variable renewable sources requires transmission from remote 

sites that cannot be modeled traditionally, as policy, rather than techno-economic, constraints are 

dominant. Variable renewable generation also presents new and unfamiliar operational challenges 

that cannot be captured in the hourly time step of current simulation tools.

•	 Technology: The traditional assumption of fixed or price-inelastic loads inherent in some planning 

tools is no longer appropriate. Customers are becoming empowered to make decisions that will influence how the grid is operated in response to either price or control signals in near real time. 

Trends and Technology Potential
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Traditional metrics for computational research (such as time to solution or size of problem) are of lesser importance in advancing grid modeling and analysis. Some key challenges are more basic and reflect the difficulty in 

capturing phenomena, such as (a) competitive suppliers in wholesale electricity markets; (b) millions of consumers (and their smart grid appliances, building and process controls) responding to dynamic prices or dispatch 

commands; and (c) electricity generators responding to uncertain future national energy and environmental 

policies.

From the perspective of maintaining system reliability, the business case for modeling and analysis improvements will continue to hinge on the requirements set by mandatory reliability rules. Changes in these rules will 

have direct implications for the modeling and analysis capabilities that industry will be expected to employ. 

For example, the “N-1” philosophy–where the system is managed so that operation can continue through any 

singe potential outage–has served the industry very well,88 but assigns every potential outage the same likelihood of occurring. Risks could be better managed, and assets better prioritized, by assigning probabilities to 

the various contingencies. Reliability rules depend on advances in modeling and simulation techniques to support potential rules such as “N-k”–or multiple outage–contingency analysis criteria. 

Over the last several years, DOE has held workshops to bring together the mathematics, computation, and 

power system communities, along with industry and software tool developers. These venues play an important 

role not only in improving the tools themselves, but also in ensuring that the research is addressing emerging 

problems with solutions that the industry can use effectively. This philosophy extends further to the role of 

operator simulation environments as a platform for validation of the impact of the tools and techniques on 

decision-making processes. Decision support, cognitive task analysis, and visualization (i.e., human factors side 

of planning and operations) will be important to the effective implementation of new tools and models.

Emerging areas for future electric system and market modeling and analysis research include:

•	 Coordinating generation and transmission expansion. Challenges include: long lead times for transmission compared to generation, the lumpiness of both transmission and generation assets, the enabling 

role that transmission can play in creating new markets for generation, and the difficulty of representing the investment decisions in competitive markets.

•	 Integration of variable renewable generation. Integration presents both steady state and transient 

stability challenges due to the inherent variability and uncertainty of renewable generation output in 

combination with operator decision making (including operator errors) in starting up generation and 

managing ancillary services.

•	 Aggregate behavior of electricity consumers responding to dynamic prices or dispatch signals from 

grid operators. Challenges include the multitude of decision-making criteria/objectives and capabilities 

of consumers, the many types (and latencies) of information that will inform these decisions, and the 

degree of automation and/or sophistication of the technologies through which these decisions will be 

translated into actions.

•	 Framework for data integration. State estimators, SCADA, SynchroPhasor measurements, dynamic 

models of the system, and simulation programs co-exist, but they are not fully integrated into operational or planning models. Data integration will improve system model accuracy through model 

verification/tuning.

•	 Operator interface. Effective tools must take into account how they are used by grid operators, and 

should provide decision support, cognitive task analysis, and visualization. 

All of these areas are opportunities for research.
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DOE Role

The Department’s role in grid software is focused on informational and convening authorities. Recent deployments of advanced and time-synchronized sensing devices and the availability of high-speed data communications systems also point to the importance of DOE’s capabilities in modeling, simulation, and cybersecurity.

Leveraging the PMU, smart meter, and other high-quality data acquisition device deployment activities under ARRA, the Department is cataloging, validating, and widely disseminating data, while respecting security, 

privacy, and business sensitivity limitations. The Department has unique capabilities to analyze complex systems—including developing and validating models—supported by world-leading high-performance computing 

facilities. DOE applies that capability to improving grid models for more effective grid operation and planning. The Department convenes the power industry and the high-performance computing community to share 

knowledge and resources, advancing the industry’s understanding of the technical opportunities for the next 

generation analytic toolsets.

In its role as a convener, the Department strengthens approaches to transmission planning through proactive 

support of stakeholders in their broad set of regional planning activities. The Department is continuing to develop capabilities in modeling and analytics to support stakeholders as they develop long-term regional policies 

and plans. 

DOE’s extensive capabilities in information security and computing are valuable assets for the power grid community in the development of cybersecurity technologies and best practices. The federal emphasis on smart 

grid interoperability standards is on collaboration, acceleration, interoperability, stakeholder balance, technical 

coexistence, and engagement.
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1

 The National Academies. (2009). America’s Energy Future: Technology and Transformation. Washington, DC: National Academies 

Press.

2

 The National Academies. (2009). America’s Energy Future: Technology and Transformation. Washington, DC: National Academies 

Press.

3

 Energy Information Administration. (2011). How much electricity is lost in transmission and distribution in the United States? 

Washington, DC. Accessed at http://www.eia.gov/tools/faqs/faq.cfm?id=105&t=3 

4

 National Academy of Engineering. (2003). Greatest Engineering Achievements of the 20th Century. Washington, DC. Accessed at 

http://www.greatachievements.org/?id=2949 

5 Transforming America’s Power Industry: The Investment Challenge 2010-2030. (2008). Referenced from The National Academies. 

(2009). America’s Energy Future: Technology and Transformation. Washington, DC: National Academies Press.

6 Power Delivery System of the Future: A Preliminary Study of Costs and Benefits. (2004). Referenced from The National Academies. (2009). America’s Energy Future: Technology and Transformation. Washington, DC: National Academies Press.

7

 Electric Power Research Institute. (2004). Power Delivery System of the Future: A Preliminary Study of Costs and Benefits. Palo 

Alto, CA. 

8

 Bartley, W. (2003). Analysis of Transformer Failures. Hartford, CT: The Hartford Steam Boiler Inspection and Insurance Co.

9 Oak Ridge National Laboratory. (2003). “A White Paper: Materials Research and Development for Electric Transmission and 

Distribution: What Could Make a Difference?” Oak Ridge, TN.

10 Oak Ridge National Laboratory. (2005). Power Electronics for Distributed Energy Systems and Transmission and Distribution Applications. (ORNL/TM-2005/230). Oak Ridge, TN. 

11 U.S. Department of Energy. (2005). “GridWorks Multi-Year Plan.” Washington, DC. Archived at http://sites.energetics.com/gridworks/ 

12 Oak Ridge National Laboratory. (2005). Power Electronics for Distributed Energy Systems and Transmission and Distribution Applications. (ORNL/TM-2005/230). Oak Ridge, TN. 

13 Oak Ridge National Laboratory. (2005). Power Electronics for Distributed Energy Systems and Transmission and Distribution Applications. (ORNL/TM-2005/230). Oak Ridge, TN. 

14 Oak Ridge National Laboratory. (2005). Power Electronics for Distributed Energy Systems and Transmission and Distribution Applications. (ORNL/TM-2005/230). Oak Ridge, TN.

15 Oak Ridge National Laboratory. (2005). Power Electronics for Distributed Energy Systems and Transmission and Distribution Applications. (ORNL/TM-2005/230). Oak Ridge, TN.

16 Oak Ridge National Laboratory. (2003). “A White Paper: Materials Research and Development for Electric Transmission and 

Distribution: What Could Make a Difference?” Oak Ridge, TN.

17 Oak Ridge National Laboratory. (2005). Power Electronics for Distributed Energy Systems and Transmission and Distribution Applications. (ORNL/TM-2005/230). Oak Ridge, TN.

18 Oak Ridge National Laboratory. (2005). Power Electronics for Distributed Energy Systems and Transmission and Distribution Applications. (ORNL/TM-2005/230). Oak Ridge, TN.

19 U.S. Department of Energy. (2011) Power Electronics Research and Development Program Plan. Washington, DC. 

20 National Institute on Standards and Technology. (2010). NIST Framework and Roadmap for Smart Grid Interoperability Standards, 

Release 1.0. Gaithersburg, MD. 

21 National Renewable Energy Laboratory. (2008). Renewable Systems Interconnection: Executive Summary. (NREL/TP-581-42292). 

Golden, CO. Accessed at http://www.nrel.gov/docs/fy08osti/42292.pdf 

22 U.S. Department of Energy. (2008). Solar Energy Grid Integration System – ES Program Concept Paper. Washington, DC. Accessed at http://www1.eere.energy.gov/solar/pdfs/segis_concept_paper.pdf 
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23 U.S. Department of Energy and Federal Energy Regulatory Commission. (2009). Memorandum of Understanding Between U.S. 

Department of Energy and Federal Energy Regulatory Commission. Washington, DC.

24 U.S.-Canada Power System Outage Task Force. (2004). Final Report on the August 14, 2003 Blackout in the United States and 

Canada. Washington DC: Department of Energy. Accessed at https://reports.energy.gov/

25 International Energy Agency. (2011). Smart Grids Technology Roadmap. Paris, France. Accessed at http://www.iea.org/papers/2011/smartgrids_roadmap.pdf 

Electricity Advisory Committee. (2009). Keeping the Lights on in a New World. Washington, DC. Accessed at http://energy.gov/

sites/prod/files/oeprod/DocumentsandMedia/adequacy_report_01-09-09.pdf 

U.S. Department of Energy. (2004). National Electric Delivery Technologies Roadmap. Washington, DC. Accessed at http://energy.gov/oe/downloads/national-electric-delivery-technologies-roadmap-transforming-grid-revolutionize 

Electric Power Research Institute. (2003). Electricity Technology Roadmap. Palo Alto, CA. Accessed at http://mydocs.epri.com/

docs/CorporateDocuments/StrategicVision/Roadmap2003.pdf 

26 Idaho National Laboratory. (2012). “National SCADA Test Bed Program.” Idaho Falls, ID. Accessed at http://www.inl.gov/scada/ 

27 See the Report of the QTR for a more extensive discussion of demand response and the role it plays in the system.

28 Electric Power Research Institute. (2004). Power Delivery System of the Future: A Preliminary Study of Costs and Benefits. Palo 

Alto, CA.

29 Boston Consulting Group. (2011). Revisiting Energy Storage. Boston, MA. Accessed at http://www.bcg.com/documents/

file72092.pdf 

30 Key, Kamath, Mears, and Gotschall. (2003). EPRI-DOE Handbook of Energy Storage for Transmission and Distribution Applications. Electric Power Research Institute. Palo Alto, CA. Report No. 1001834, p. 1-1. Accessed at http://www.sandia.gov/ess/

publications/ESHB%201001834%20reduced%20size.pdf 

31 Electricity Advisory Committee. (2011). Energy Storage Activities in the United States Electricity Grid. p.3. Washington, DC. Accessed at http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/FINAL_DOE_Report-Storage_Activities_5-1-11.pdf 

32 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. p. 9. Albuquerque, NM. Accessed at 

http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf

33 U.S. Department of Energy. (2010). Grid Storage Report: Report to Congress. Washington, DC.

34 Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, Costs, and Benefits. Report No. 1020676. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/

static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf 

35 Suul, J. A. (2009). “Variable Speed Pumped Storage Hydropower Plants for Integration of Wind Power in isolated Power Systems.” Renewable Energy. T.J. Hammons (Ed.). Accessed at http://www.intechopen.com/source/pdfs/9345/InTech-Variable_

speed_pumped_storage_hydropower_plants_for_integration_of_wind_power_in_isolated_power_systems.pdf 

36 Pumped Storage Hydropower: Summary Report on a Summit Meeting Convened by Oak Ridge National Laboratory, the National 

Hydropower Association, and the Hydropower Research Foundation. Meeting held in Washington, DC, on September 20–21, 

2010. Accessed at http://www.esd.ornl.gov/WindWaterPower/PSHSummit.pdf 

37 Energy Information Administration. (2009). “Form EIA-860, “Annual Electric Generator Report,” – Generator (Existing) File.” 

Washington, DC. Accessed at http://www.eia.gov/cneaf/electricity/page/capacity/existingunitsbs2008.xls 

38 Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. p. 4–2. Report No. 1020676. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/

static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf

39 U.S. Department of Energy. (2011). Energy Storage Program Planning Document. Washington, DC. Accessed at http://energy.

gov/sites/prod/files/oeprod/DocumentsandMedia/OE_Energy_Storage_Program_Plan_Feburary_2011v3.pdf 
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 U.S. Department of Energy. (2010). Advanced Materials and Devices for Stationary Electrical Energy Storage Applications. Washington, DC. Accessed at http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/AdvancedMaterials_12-30-10_FINAL_

lowres.pdf

 Basic Energy Science Advisory Committee. (2010). Science for Energy Technology: Strengthening the Link between Basic Research and Industry. Washington, DC: Department of Energy. Accessed at http://science.energy.gov/~/media/bes/pdf/reports/

files/set_rpt.pdf 

40 Electric Power Research Institute. (2003). EPRI-DOE Handbook of Energy Storage for Transmission and Distribution Applications.

41 Fernandez, M., Valenciano, J., Trinidad, F., and Munoz, N. (2010). “The use of activated carbon and graphite for the development 

of lead-acid batteries for hybrid vehicle applications.” Journal of Power Sources. Vol. 195(14):4458-4469.

42 Nexight Group. (2010). Advanced Materials and Devices for Stationary Electrical Energy Storage Applications. p. 18. Albuquerque, NM. Accessed at http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf 

43 Fernandez, M., Valenciano, J., Trinidad, F., and Munoz, N. (2010). “The use of activated carbon and graphite for the development 

of lead-acid batteries for hybrid vehicle applications.” Journal of Power Sources. Vol. 195(14):4458-4469.

44 Nexight Group. (2010). Advanced Materials and Devices for Stationary Electrical Energy Storage Applications. p. 19. Albuquerque, NM. Accessed at http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf 

 45 Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. Report No. 1020676. p. 4–17 and 4–18. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf

46 Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. Report No. 1020676. p. 4–17 and 4–18. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf

47 ”AES Wind Generation and AES Energy Storage Introduce AES Laurel Mountain.” Power Engineering. November 16, 2011. 

Accessed at http://www.power-eng.com/news/2011/11/1535632055/aes-wind-generation-and-aes-energy-storage-introduceaes-laurel-mountain.html 

48 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. p. 21. Albuquerque, NM. Accessed at 

http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf

49 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications, p. 25–28. Albuquerque, NM. Accessed 

at http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf

50 Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. Report No. 1020676. p. 4–9 and 4–10. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf

51 Key, Kamath, Mears, and Gotschall. (2003). EPRI-DOE Handbook of Energy Storage for Transmission and Distribution Applications. Electric Power Research Institute. Palo Alto, CA. Report No. 1001834. p. 8-1. Accessed at http://www.sandia.gov/ess/

publications/ESHB%201001834%20reduced%20size.pdf

52 Nexight Group. (2010). Advanced Materials and Devices for Stationary Electrical Energy Storage Applications. p. 25–28. Albuquerque, NM. Accessed at http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf 

53 Raster, D. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, Costs, and Benefits. Palo 

Alto, CA: Electric Power Research Institute. Accessed at http://www.electricitystorage.org/images/uploads/static_content/

technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf 

54 Li, et al. (2011). “Large-Scale Energy Storage: A Stable Vanadium Redox-Flow Battery with High Energy Density for LargeScale Energy Storage.” Advanced Energy Materials. Vol. 1(3):394-400. Accessed at http://onlinelibrary.wiley.com/doi/10.1002/

aenm.201100008/abstract

55 Parformack, P. W. (2012). Energy Storage for Power Grids and Electric Transportation: A Technology Assessment. Washington, 

DC: Congressional Research Service. Accessed at http://www.fas.org/sgp/crs/misc/R42455.pdf 
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56 U.S. Department of Energy. (2010). Grid Storage Report: Report to Congress. Washington, DC. 

57 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications, p. 29. Albuquerque, NM. Accessed at 

http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf

58 Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. Report No. 1020676. p. 4–15. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf

59 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. p. 33. Albuquerque, NM. Accessed at 

http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf

60 Electricity Advisory Committee. (2011). Energy Storage Activities in the United States Electricity Grid. Washington, DC. Accessed 

at http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/FINAL_DOE_Report-Storage_Activities_5-1-11.pdf

61 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. p. 34. Albuquerque, NM. Accessed at 

http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf

62 Nexight Group. (2010). Advanced Materials and Devices for Stationary Electrical Energy Storage Applications. p. 17. Albuquerque, NM. Accessed at http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf 

Fernandez, M., Valenciano, J. Trinidad, F., and Munoz, N. (2010). “The use of activated carbon and graphite for the development 

of lead-acid batteries for hybrid vehicle applications.” Journal Power Sources. 195(14):4458–4469. 

Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. Report No. 1020676. p. 4–7. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/

static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf

Yang, Z., Zhang, J., Kintner-Meyer, M. C. W., Lu, X., Choi, D., Lemmon, J. P., and Liu, J. (2011). “Electrochemical Energy Storage 

for a Green Grid.” Chemical Reviews. 111(5):3577–3613. Accessed at http://energyenvironment.pnnl.gov/ei/pdf/Chemical%20

Reviews.pdf 

63 Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. Report No. 1020676. p. 4–17. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf 

Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. p. 21. Albuquerque, NM. Accessed at 

http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf 

Yang, Z., Zhang, J., Kintner-Meyer, M. C. W., Lu, X., Choi, D., Lemmon, J. P., and Liu, J. (2011). “Electrochemical Energy Storage 

for a Green Grid.” Chemical Reviews. 111(5):3577–3613. Accessed at http://energyenvironment.pnnl.gov/ei/pdf/Chemical%20

Reviews.pdf 

64 Nexight Group. (2010). Advanced Materials and Devices for Stationary Electrical Energy Storage Applications. p. 25–28. Albuquerque, NM. Accessed at http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf 

Electric Power Research Institute. (2010). Electricity Energy Storage Technology Options: A White Paper Primer on Applications, 

Costs, and Benefits. Report No. 1020676. p. 4–9. Palo Alto, CA. Accessed at http://www.electricitystorage.org/images/uploads/

static_content/technology/resources/ESA_TR_5_11_EPRIStorageReport_Rastler.pdf

Yang, Z., Zhang, J., Kintner-Meyer, M. C. W., Lu, X., Choi, D., Lemmon, J. P., and Liu, J. (2011). “Electrochemical Energy Storage 

for a Green Grid.” Chemical Reviews. 111(5):3577–3613. Accessed at http://energyenvironment.pnnl.gov/ei/pdf/Chemical%20

Reviews.pdf 

65 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. p. 29. Albuquerque, NM. Accessed at 

http://energy.tms.org/docs/pdfs/Advanced_Materials_for_SEES_2010.pdf 

 Li, et al. (2011). “Large-Scale Energy Storage: A Stable Vanadium Redox-Flow Battery with High Energy Density for LargeScale Energy Storage.” Advanced Energy Materials. Vol. 1(3):394–400. Accessed at http://onlinelibrary.wiley.com/doi/10.1002/

aenm.201100008/abstract
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Yang, Z., Zhang, J., Kintner-Meyer, M. C. W., Lu, X., Choi, D., Lemmon, J. P., and Liu, J. (2011). “Electrochemical Energy Storage 

for a Green Grid.” Chemical Reviews. 111(5):3577–3613. Accessed at http://energyenvironment.pnnl.gov/ei/pdf/Chemical%20

Reviews.pdf 

66 Nexight Group. (2010). Electric Power Industry Needs for Grid-Scale Storage Applications. Albuquerque, NM. p. 23. Accessed at 

http://energy.tms.org/docs/pdfs/Electric_Power_Industry_Needs_2010.pdf 

67 http://science.energy.gov/bes/efrc/centers/external-efrc-websites/ 

68 Controls “Hardware” is discussed in the Grid Components technology assessment. 

69 There are a few instances where system operators can centrally control loads through demand response, such as ERCOT’s load 

resource program (http://www.ercot.com/services/programs/load/vlrp/index).

70 North American Electric Reliability Corporation. (2010). Real-Time Application of Synchrophasors for Improving Reliability. p. 9. 

Washington, DC. Accessed at https://www.naspi.org/site/StaticPDF/resource/rapir_final_20101017.pdf 

71 Midwest ISO. (2010). Synchrophasor Integration into Planning and Operational Reliability Processes. Carmel, IN. Accessed at 

https://www.midwestiso.org/_layouts/MISO/ECM/Redirect.aspx?ID=28862. 

72 U.S. Department of Energy. (2006). Benefits of Demand Response in Electricity Markets and Recommendations for Achieving 

Them. p. 36. Washington, DC. Accessed at http://eetd.lbl.gov/ea/ems/reports/congress-1252d.pdf. 

73 Oak Ridge National Laboratory. (2004). “Advanced Sensors for Grid Modernization: White Papers on Issues and Benefits.” Oak 

Ridge, TN.

74 Oak Ridge National Laboratory. Grid Eye Fact Sheet. Oak Ridge, TN. Accessed at http://www.ornl.gov/sci/electricdelivery/pdfs/

GridEye%20Fact%20Sheet.pdf 

75 For more information on synchrophasor infrastructure, see the North American SynchroPhasor Initiative at https://www.naspi.

org/ 

76 For example, see the Schweitzer Engineering Laboratories, Inc. SEL-421 Protection and Automation System: http://www.selinc.

com/SEL-421/ 

77 U.S. Department of Energy. SmartGrid.gov. Accessed at http://www.smartgrid.gov/ 

78 U.S. Department of Energy and Federal Energy Regulatory Commission. (2006). Steps to Establish a Real-Time Transmission 

Monitoring System for Transmission Owners and Operators within the Eastern and Western Interconnections: A Report to Congress Pursuant to Section 1839 of EPACT 2005. Washington, DC. Accessed at http://energy.gov/sites/prod/files/oeprod/DocumentsandMedia/final_1839.pdf 

79 North American Electric Reliability Corporation. (2010). Real-Time Application of Synchrophasors for Improving Reliability. p. 9. 

Washington, DC. Accessed at https://www.naspi.org/site/StaticPDF/resource/rapir_final_20101017.pdf 

80 Energetics Incorporated. (2006). Roadmap to Secure Control Systems in the Energy Sector. Washington, DC: U.S. Department of 

Energy, U.S. Department of Homeland Security. Accessed at http://www.cyber.st.dhs.gov/docs/DOE%20Roadmap%202006.pdf 

81 Energy Sector Control Systems Working Group. (2011). Roadmap to Achieve Energy Delivery Systems Cybersecurity. Washington, DC: U.S. Department of Energy. Accessed at http://energy.gov/oe/downloads/roadmap-achieve-energy-delivery-systemscybersecurity-2011 

82 Office of the National Counterintelligence Executive. (2011). Foreign Spies Stealing U.S. Economic Secrets in Cyberspace: Report 

to Congress on Foreign Economic Collection and Industrial Espionage, 2009–2011. Washington, DC. Accessed at http://www.

dni.gov/reports/20111103_report_fecie.pdf 

North American Electric Reliability Corporation. Critical Infrastructure Protection Program. Washington, DC. Accessed at http://

www.nerc.com/page.php?cid=6|69 

Energy Sector Control Systems Working Group. (2011). Roadmap to Achieve Energy Delivery Systems Cybersecurity. Washington, DC: U.S. Department of Energy. Accessed at http://energy.gov/sites/prod/files/Energy%20Delivery%20Systems%20Cybersecurity%20Roadmap_finalweb.pdf 
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83 U.S. National Institute for Standards and Technology. (2011). NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 2.0 DRAFT (Posted for Public Comment via Federal Register Notice, October 25, 2011). Washington, DC. Accessed 

at http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/IKBFramework 

84 National Science and Technology Council. (2011). A Policy Framework for the 21st Century Grid: Enabling Our Secure Energy 

Future. Washington, DC: Executive Office of the President. Accessed at http://www.whitehouse.gov/sites/default/files/microsites/ostp/nstc-smart-grid-june2011.pdf 

85 IBM ILOG CPLEX Optimizer Performance Benchmarks. Accessed at http://www-01.ibm.com/software/integration/optimization/

cplex-optimization-studio/cplex-optimizer/cplex-performance/#improvements 

86 Ott, A. L. (2010). “Evolution of Computing Requirements in the PJM Market: Past and Future.” 2010 IEEE Power & Energy Society 

General Meeting. p. 1–4. 

87 U.S. Department of Energy. (2009). Computational Issues and Challenges of the 21st Century Power System. Technical Workshop 

Results. Gaithersburg, MD.

88 U.S.-Canada Power System Outage Task Force. (2004). Final Report on the August 14, 2003 Blackout in the United States and 

Canada. p. 7. Washington DC: Department of Energy. Accessed at https://reports.energy.gov/

Clean Power | 169

CLEAN POWER

The assessments in this chapter form the technical base 

for Deploying Clean Electricity, a strategy detailed in the 

corresponding chapter of the Report on the Quadrennial 

Technology Review (QTR). Deployment of clean electricity will 

reduce emissions of greenhouse gasses and other pollutants 

that lead to smog, cause acid rain and haze, impact human 

health, and increase the risks of climate change. Developing 

and manufacturing clean electricity technologies will create 

jobs and strengthen U.S. economic competitiveness.

While each technology is presented here with a standalone 

assessment, the associated opportunities to impact the 

energy system are fully understood only within the context 

of an integrated framework that spans energy resource, 

supply, delivery, and consumption. The Report on the QTR

presents an integrated framework of the energy system 

and contains the systems discussions that tie together these 

individual assessments.

The technology assessments in the Clean Power chapter have 

been organized alphabetically and include:

•	 Carbon Capture and Storage

•	 Concentrating Solar Power

•	 Fuel Cells for Distributed Generation

•	 Geothermal Power

•	 Nuclear Power

•	 Solar Photovoltaics

•	 Water Power

•	 Wind Power
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CLEAN POWER

Fossil fuels currently dominate U.S. and global electricity generation and total energy supply,1 with coal and 

natural gas fueling 70% of U.S. electricity generation. U.S. fossil-fuel-based electricity generation and industrial 

processes emit 3.5 billion tonnes of carbon dioxide (CO2) into the atmosphere every year,2 more than 10% of 

the global total.3 Carbon capture and storage (CCS) is one of the primary options to reduce CO2 emissions from 

fossil fuels, although variations among modeling assumptions (such as the future costs of gas and CCS) lead to 

somewhat different energy mixes. Long-term planning for increased penetration of intermittent renewables is 

often based upon natural gas backup, a paradigm that will persist for the foreseeable future. Recent developments for the production of shale gas give the United States vast natural gas resources that, when converted 

to reserves, could have a major impact on the world’s energy balance. 

“Business as usual” forecasts, such as those shown in Table 23, suggest that coal-fueled electricity generation 

could continue to grow for at least the next 25 years. CCS technologies present an opportunity to produce 

affordable, clean electricity from more than 15% of the more than 3,000 gigawatts of electric energy (GWe) 

of global coal-fueled electricity expected by 2035.4 The development of lower-cost CCS is especially important 

for reducing potential greenhouse gas (GHG) emissions from coal-rich developing countries, such as China and 

India. Those nations currently rely on coal for more than 70% of electricity and are unlikely to limit their rapid 

domestic economic development by reducing coal-fired generation.5 Recent International Energy Agency analysis suggests that eliminating CCS from the available mix of low- or zero-carbon technologies could increase by 

70% the overall costs to reduce CO2 emissions to 2005 levels by 2050.6 

Table 23. Projected Global Coal Generation Capacity 

Coal Generation Capacity (GWe)

2008 2020 2035 2008–2050 

% Increase

United States 334 353 348 4

India 84 201 441 425

China 563 1,011 1,540 174

World 1,514 2,184 3,056 102

International Energy Agency. (2010). 2010 World Energy Outlook. Paris, France.

CARBON CAPTURE 

AND STORAGE
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CCS technology can also be applied to natural gas combustion, alternative fuels production, and biomass 

combustion. For alternative fuels production, CCS can reduce CO2 emissions from any hydrocarbons-to-liquids 

process, such as coal-to-liquids and gas-to-liquids. CCS technology integrated with biomass-based combustion 

processes, such as co-firing coal with biomass, could result in net negative lifecycle CO2 emissions. For more 

information on alternative transportation fuels, see the Alternative Hydrocarbon Fuels technology assessment 

and the Report on the QTR. 

Current Status of Technology

CCS is a three-step process that includes capture and compression of CO2 from power plants or industrial 

sources; transport of the captured CO2; and permanent and safe storage of that CO2 in geologic formations, 

such as deep saline formations, oil and gas reservoirs, and unmineable coal seams. The three dominant approaches to CO2

 capture are post-combustion from flue gas, post-combustion using oxyfuel, and pre-combustion using gasification. Technologies exist for all three components of CCS:

Separation and Capture: CO2

 has been captured from industrial gas streams since the 1930s using a variety 

of approaches to separate it from other gases. These processes are used in the natural gas industry to produce 

pipeline quality natural gas7 and to produce food- and chemical-grade CO2. However, commercially available 

CO2 separation processes are currently too costly for power applications. 

Transport: The history of transporting CO2 via pipelines in the United States spans nearly 40 years. The United 

States transports some 72 million tons of CO2 annually8 through 4,100 miles of existing CO2 pipelines.9 

Storage: Globally, four commercial carbon sequestration facilities with 25 cumulative years of experience inject 

CO2 into deep geologic formations and apply a suite of technologies to monitor and verify that the CO2 remains 

sequestered. Industry experience in subsurface CO2 injection has also been accumulated over several decades 

via enhanced oil recovery (EOR) activities. The Department of Energy (DOE) estimates that there are hundreds 

of years of available storage resource in geologic formations in North America.10

Estimates of the Nth plant incremental costs11 of new coal-fired plants with CCS relative to new pulverized coal 

(PC)-fired plants typically range from $60–$85/tonne of CO2 avoided. Approximately 70%–90% of that cost is 

associated with capture and compression.12 

According to the Global CCS Institute’s Report, The Global Status of CCS: 2010:

•	 In 2010, there were 234 active or planned CCS projects around the world and across a range of technologies, project types, and sectors. Seventy-seven of these projects are large-scale integrated projects 

(LSIPs);13 of which, eight are in operation, four are in execution, and the remaining 65 are in various 

stages of planning.

•	 The eight LSIPs in operation, as well as the four in execution are linked to the oil and gas sector: they 

either capture CO2 in natural gas processing or inject CO2 for EOR. There are 42 LSIPs in development 

planning in the power generation sector, 2 iron and steel projects, 1 cement project, and 1 pulp and 

paper project.

•	 Most LSIPs are in developed countries (notably the United States, Europe, Canada, and Australia), with 

a few in emerging markets like China.

•	 Separate pre- or post-combustion capture technologies have attained greater deployment than LSIPs, 

especially in the power industry. There are four proposed demonstrations of CO2

 capture using oxyfuel 

combustion.
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Though CCS technologies exist, the scaling and integration of CCS with power generation has not yet been 

demonstrated. Scale-up of existing CCS processes for use with coal or natural-gas-based power generation 

poses significant technical, economic, and regulatory challenges. CCS technology challenges associated with 

scaling and integration are discussed in detail in the August 2010 Report of the Interagency Task Force on 

Carbon Capture and Storage.

Historical Pace of Development and Market Diffusion

Although CO2 capture is new to coal-based power generation, removal of CO2 from industrial gas streams is 

not a new process (see callout box). Gas absorption processes that use chemical solvents to separate CO2 from 

gas streams containing 3%–25% of the chemical compound have been in use since the 1930s, particularly in 

the natural gas industry and to produce food- and chemical-grade CO2.

14 In the 1950s and 1960s, gas adsorption processes were developed to separate CO2

 from gas streams associated with hydrogen production (in oil 

refineries), nitrogen separation, and dehydration. In the 1970s and 1980s, gas separation membranes were 

developed for EOR (oil/gas separation) and natural gas processing applications.

While the processes developed by these industries are relevant to coal plants, they are typically implemented 

at a smaller scale and at a very high cost per ton of CO2

. There are five commercially operating facilities that 

capture CO2 at scales relevant to electricity generation (i.e., more than 1 million tonnes of CO2 per year). The 

largest (a natural gas processing operation in Wyoming) captures 3.6 million tonnes per year.15 However, it is 

unclear how transferable the experience with natural gas processing is to separation of power plant flue gases, 

as the two gas feeds have very different chemical compositions. 

Industry has safely stored CO2 since the 1970s at scales relevant to power generation in the context of enhanced EOR. The long atmospheric lifetime of CO2

 requires confinement times of more than a century (leak 

rates of less than 1% per year) if CCS is to be an effective mitigating technology. While there are no direct 

measurements currently guaranteeing this level of integrity, there is circumstantial evidence supporting it.16

The licensing history of the Econamine FG process—a technology that removes carbon dioxide 

(CO2) from oxygen-rich streams—is a good example of past applications of CO2 removal technologies. Prior to 1999, 25 facilities were built with CO2 capture capacities ranging from 635–365,000 

tonnes per year using this process. Three were coal-fired applications that captured 600–1,600 

tonnes of CO2 per year. The captured CO2 from these facilities was used for enhanced oil recovery 

and urea production, as well as in the food and beverage industry. The markedly different amounts 

captured for these facilities reflect the fact that they were built to serve a specific commercial 

market for CO2. Other amine-based processes (e.g., ABB/Lummus) were implemented at similar 

capture rates during this period. By comparison, a single 550 megawatt net output coal-fired power 

plant capturing 90% of the emitted CO2 will need to separate 3–5 million tonnes of CO2 per year. 

Scaling-up these existing processes represents a significant technical challenge and a potential 

barrier to widespread commercial deployment in the near term. 
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There is also international experience with storing CO2. Since 1996, about 1 million tonnes of CO2 per year–

about one-third of the CO2 emitted by an average 500–megawatt (MW) coal plant–have been injected into 

the Sleipner reservoir off the coast of Norway. CO2 that is produced along with natural gas is separated on the 

production platform and re-injected into a sandstone formation at a depth of about 1,000 meters below sea 

level to prevent venting the gas to the atmosphere.17

Injection of CO2 enhances oil production by some combination of re-pressurizing the reservoir, invading zones 

not swept by injected water, and by creating mixtures of oil and CO2 in the subsurface that can efficiently displace more oil. Typical productivity estimates range from 2–4 barrels of oil produced via EOR per tonne of CO2 

(i.e., about two atoms of carbon produced for each atom of carbon injected).18 Although some features of CO2 

storage may differ from EOR operations, these activities have developed many of the reservoir management 

and operational tools needed for large-scale CO2 injection and storage. 

Approximately 60 million tonnes of CO2 (0.8% of U.S. emissions) are injected in the United States each year 

for EOR, produced with the oil, captured, and then re-injected.19 These are large-scale operations, with some 

injecting millions of tonnes of CO2 per year, and some having already accumulated (stored) tens of millions of 

tonnes. As of year-end 2010, there were 114 CO2-EOR projects within the United States producing 272,000 

barrels of oil per day.20 Because of its limited scale, EOR as the storage mechanism for carbon cannot significantly reduce national emissions. Still, EOR’s main benefit is to enhance the economics of early projects to allow 

demonstration and reduction of CCS costs.21 

Technology Potential

One long-term goal for CCS technology is at least 90% capture and safe storage at electricity costs of $62/

megawatt hour (MWh), which approaches today’s supercritical PC plant cost without CCS ($59/MWh).22 This 

requires the development of advanced, lower-cost CCS technologies using different types of coals and storing 

CO2 in a variety of geologic settings. 

In capture, while major technology thrusts associated with advanced solvents, solid sorbents, and membranes 

have made significant progress, these pathways are not expected to reach cost and performance characteristics 

that support overall CCS goals until around 2015. Goals for post-combustion and oxyfuel CCS are a cost premium of 35% relative to a conventional supercritical PC plant, and the goal for pre-combustion CCS is a cost 

premium of 10% relative to integrated gasification combined cycle.23

Research and development (R&D) programs can help reduce project uncertainty, decrease technology cost, and 

improve plant performance. Building on the separate demonstration of CO2

 capture and CO2 storage technologies, the focus of CCS R&D is to: 

•	 Demonstrate the operation of current CCS technologies integrated at a scale necessary to prove safe 

and reliable capture and storage. 

•	 Develop improved CO2 capture component technologies and advanced power generation technologies to significantly reduce the cost of CCS.
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There are technical challenges associated with CCS integration and scale at all steps in the process. For CO2 

capture, these include maintaining adequate gas and/or liquid flow distribution in the larger absorption and 

regeneration reactors required for power plant applications. For commercial-scale, coal-based power plants, 

challenges include the energy penalty arising from high capture and compression auxiliary power loads and the 

impacts of flue gas contaminants on the CO2 capture system. For storage, demonstration at scale is needed to 

ensure the effectiveness of monitoring, verification, and accounting tools, all of which are important components of managing a geologic storage project and ensuring that the CO2

 plume and associated pressure front 

are moving through the subsurface as predicted. In addition, the potential of multiple commercial projects in a 

particular basin creates a new set of concerns (e.g., brine displacement, overlap of pressure fronts, spatial variation in depositional environments, etc.) that cannot be effectively evaluated with models and small-scale tests. 

One challenge for CO2 integration with power production is accommodating cycling as the plant follows load. 

First-generation CCS plants can operate at cost premiums of about 80% for coal or 45% for natural gas, when 

compared to new construction of similarly fueled generation without CCS.24 Note that the cost per ton of CO2

avoided is significantly higher for a natural gas combined cycle (NGCC) plant compared to a supercritical PC 

plant because of the low concentration of CO2 in the NGCC plant flue gas. However, this same low concentration makes the cost per megawatt hour lower for NGCC. 

The most promising second-generation technologies for coal plants would reduce this premium to around 

22%, while integrated gasification fuel cells hold considerably more promise. Table 24 is based on detailed 

engineering analysis and simulations carried out by the National Energy Technology Laboratory, which are 

documented in a series of studies available on the laboratory’s website.25

Table 24. Estimates of Cost of Electricity (COE) Increases for Three CCS Technology Generations

COE Increase vs. Current SCPC Plants w/o CCS

New Coal Plant 

Type with CCS Generation 1 Generation 2 Transformational

Super Critical 

Pulverized Coal (SCPC) $48/MWh (81%) $21/MWh (35%)

Oxy-Combustion $37/MWh (63%) $21/MWh (35%)

Integrated Gasification 

Combined Cycle $47/MWh (79%) $13/MWh (22%)

Integrated Gasification 

Fuel Cell n/a $14/MWh (23%) <$3/MWh (<5%)

COE Increase vs. Current NGCC Plants w/o CCS

New Gas Plant Type 

with CCS Generation 1 Generation 2 Transformational

Natural Gas CombinedCycle (NGCC) $27/MWh (46%) - -

National Energy Technology Laboratory Baseline and Pathway Studies. Links include http://www.netl.doe.gov/

energy-analyses/baseline_studies.html and http://www.netl.doe.gov/energy-analyses/refshelf/PubDetails.

aspx?Action=View&PubId=284
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R&D on second-generation technologies applicable to PC and gasification-based power plants might reduce 

the cost of CCS by more than half compared to first-generation technologies. R&D focusing on conventional 

PC plants addresses the technical barriers associated with acceptance and implementation of CCS technologies 

that can retrofit today’s existing coal plants. Of particular interest are the energetics (operating temperatures, 

regeneration), process size (capacity, permeability), product purity (selectivity), and material stability (thermal, 

chemical, and mechanical robustness) associated with capture technologies, including solvents, sorbents, and 

membranes. 

Oxy-combustion is a PC option that simplifies the capture process, but is more expensive than gasificationbased technologies because it requires far more oxygen. Different approaches are under investigation for 

reducing the cost of oxygen, such as introduction of an oxygen transport membrane, as well as R&D on oxycombustion flame characteristics, burner, and coal-feed design. Analysis of the interactions between oxy-combustion products and boiler materials is necessary to the development of low-cost and efficient oxy-combustion 

power plant systems. 

Gasification-based power generation is far less mature than PC technology, but is believed by many26 to be the 

pathway leading to the most cost-effective CCS options. One R&D pathway focuses on power plants that use 

oxygen instead of air in the gasifier and convert coal into a gas stream consisting of CO2 and hydrogen. CO2 

is separated before the hydrogen is combusted to generate electricity and, as a result, is referred to as “precombustion capture.” The relatively high pressure and concentration of the CO2

 in the gas stream reduce the 

cost of capturing and compressing the CO2. However, electricity from first-generation integrated gasification 

combined cycle plants without CCS is estimated to cost about 30% more than conventional PC plants.27 Oxygen, typically obtained via air separation, is a significant component of this increased cost. R&D is focusing on 

reducing this cost, as well as key advances in several other major plant components (e.g., turbine, gas cleanup). 

Demonstration of commercial-scale CCS coal plants could be initiated in the mid-2010s, which could enable 

industry to deploy commercial-generation plants beginning in the 2020s.28 

Several monitoring techniques are currently available for CO2 and/or brine leak detection. These can mainly be 

divided into techniques that focus on (1) atmospheric, surface, or near-surface detection; and (2) deep subsurface for the purposes of early leak detection. Research needs for near-surface monitoring technologies are to 

improve sensitivity of detection and/or increase the range of applicability so that very large areas can be covered 

more efficiently and cost effectively. Research needs for deep subsurface technologies include increased detection sensitivity, improved techniques for interpretation of signals to account for subsurface heterogeneity, and 

integration of signals from multiple monitoring tools.

Consistency with Other CCS Roadmaps

A number of groups have developed CCS roadmaps, including the following:

•	 Carbon Sequestration Leadership Forum29 

•	 International Energy Agency30

•	 Coal Utilization Research Council/Electric Power Research Institute31 

•	 America’s Energy Future32

•	 Massachusetts Institute of Technology.33
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These roadmaps generally agree on the R&D areas that should be pursued, milestones, and that 2020–2030 

is a desirable timeframe for achieving cost-effective, commercially viable CCS. One difference is that some 

roadmaps (e.g., Coal Utilization Research Council/Electric Power Research Institute/ Electric Power Research 

Institute, International Energy Agency) provide detail on the demonstrations that would be needed in order to 

reach Nth plant cost for advanced CCS technology. 

Policy Context and Deployment Barriers

In 2010, the President’s Interagency Task Force on Carbon Capture and Storage (Task Force) found that there 

are no insurmountable technological, legal, institutional, or other barriers that prevent CCS deployment. The 

Task Force found the lack of comprehensive climate change legislation to be the key barrier to CCS deployment; without a carbon price and appropriate financial incentives for new technologies, there is no framework 

for investment in CCS technology.34 

Significant federal incentives for early deployment of CCS are in place, including tax credits and loan guarantees. Today, many CCS projects are being planned by the private sector in anticipation of requirements to 

reduce GHG emissions. The foremost economic challenge to these projects is ongoing policy uncertainty regarding the value of GHG emissions reductions. 

Even with financial support, legal and regulatory uncertainties hinder the development of CCS projects. The 

Environmental Protection Agency (EPA) has taken significant steps to address regulatory uncertainty of carbon 

storage. In late 2010, EPA promulgated the Underground Injection Control Class VI injection well manual, 

which created a regulatory regime for siting, construction, operation, closure, and post-closure site care for 

CO2

 injection wells, and established monitoring requirements for CO2 plumes.35 They concurrently promulgated 

Subparts RR and UU of the GHG reporting rule, which create a scheme for reporting CO2 sequestration to EPA. 

Finally, EPA is developing a rule to address the relationship between CCS and the Resource Conservation and 

Recovery Act. A major regulatory hurdle was overcome with the promulgation of regulations consistent with 

the Safe Drinking Water Act.36

The Task Force identified a range of views concerning potential long-term liabilities (i.e., those arising after 

closure of a CO2 storage site) and the extent of potential impacts on widespread deployment. Many states planning CCS projects are taking steps to address long-term liabilities associated with geologic storage of CO2

. The 

Task Force’s preliminary assessment is that the existing federal and state legal framework should be adequate 

for at least an initial group of 5 to 10 commercial-scale projects. However, because of divergent views on the 

topic and limited time to analyze a complex set of underlying issues and drivers, additional analysis is needed 

to determine the most appropriate legal or regulatory structures for addressing potential long-term liabilities 

associated with widespread deployment. 

Aggregation of pore space and associated property rights are also important for CCS projects. Historically, 

pore space issues have been handled by states. Several states are taking actions to address aggregation of pore 

space for geologic storage on private lands.37 

Public awareness and support are critical to the development of new energy technologies and are widely 

viewed as vital for CCS projects. Whether the public will support or oppose commercial-scale CCS projects is 

largely unknown, and the public’s reaction may be project-specific. Integration of public information, education, and outreach efforts throughout the lifecycle of CCS projects will help identify key issues, foster public 

understanding, and build trust between communities and project developers. 

Many of these barriers will be addressed through improved monitoring technologies and processes, as discussed in the Technology Potential section above.
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Factors that Affect Market Prospects

Driving down the cost of CCS will require successful R&D. A value for carbon mitigation will ultimately be 

needed for commercial viability of CCS technology. In the event that carbon mitigation value is established, 

CCS will need to compete with other low-carbon technologies in the market. 

In light of current and projected high oil prices, EOR may provide a market for CO2 captured from power generation, thereby reducing the level of support needed to demonstrate CCS. Currently, about 50 million tonnes 

per year of naturally occurring CO2 from underground reservoirs is used for EOR, with another 10 million tonnes 

supplied by natural gas processing facilities.38 The CO2 is geographically limited, and costs are mostly associated 

with infrastructure for CO2 transport (approximately $5–$15/tonne39). Other sources of CO2 are ammonia and 

natural gas processing, which can produce CO2 at $15–$30/tonne. The EOR market could potentially grow to 

300 million tonnes per year at $40/tonne CO2 and $85/barrel oil40—this is a modest market compared to the 

current U.S. CO2 emissions of about 5.5 billion tonnes per year.41 When injected for EOR, some of the CO2 is 

permanently sequestered, while the remaining CO2

 is produced with the oil. That CO2 is typically captured and 

reinjected so that all of the CO2 is eventually permanently stored in the reservoir.

The installation of new, higher-efficiency power plants—configured to be capture-ready—would provide plants 

that could be retrofitted within 10 years from coming online, well before the construction of greenfield sites. 

The estimated capital cost premium for a capture-ready PC plant is roughly $450/kilowatt (kW), while an integrated gasification combined cycle plant would incur an additional $130/kW to be capture-ready.42

CO2 storage tests are required to develop best practices and a better understanding of overall risk. Public acceptance is an important factor, especially with subsurface technology like CO2

 storage. 

The need for significant expansion of CO2 pipelines is sometimes cited as an infrastructure concern; however, 

the pipeline requirements associated with aggressive CCS deployment scenarios are not inconsistent with past 

natural gas pipeline experience.43

Adoption of currently available CCS technology for fossil-fueled power plants can increase water use and 

competition for water supplies. Amine-based, post-combustion carbon capture technologies are extremely 

water-intensive and can double the water consumption and withdrawal associated with fossil power production (Figure 33). However, the advanced pre-combustion CCS technologies based on coal gasification that may 

be available in the 2020s will have lower water requirements. 
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1,400

1,200

1,000

1,800

1600

400

200

0

Subcritical

 PC

Subcritical

PC w/ amine

CO2 Capture

Supercritical

PC

Supercritical

PC w/ amine

CO2 Capture

IGCC IGCC 

w/ CO2

Capture

Supercritical

w/ oxy CO2

Capture

NGCC NGCC w/ CO2

Capture

Water (gal/MWhr)

WITHDRAWAL CONSUMPTION

Figure 33. Relative Water Usage for New PC and IGCC Plants

Estimates based on recirculating cooling technologies. Source: National Energy Technology Laboratory. (2010). 

Estimating Freshwater Needs to Meet Future Thermoelectric Generation Requirements: 2010 Update. (DOE/NETL400/2010/1339). Page 27, Figure 12. Morgantown, WV. Accessed at http://www.netl.doe.gov/energy-analyses/

pubs/2010_Water_Needs_Analysis.pdf 

Breakthrough CCS Technologies

Integrated gasification fuel cell systems and chemical looping are breakthrough technologies that could be 

available by 2030. The integrated gasification fuel cell system includes a high-efficiency, solid-oxide fuel cell 

that is fueled by high methane syngas. The efficient electrochemical energy conversion in the fuel cell allows 

for a net plant efficiency of 50%–60% (higher heating value, or HHV, basis), the lower value for an atmospheric fuel cell system and the higher value for a more advanced pressurized system. Additionally, the fuel 

cell system provides separation of CO2

 as a natural part of operation, greatly simplifying CO2 capture. Further 

advantages of the integrated gasification fuel cell system include minimal water use and no nitrogen oxide or 

sulfur oxide emissions. Continued R&D on power density improvement, reliability enhancement, and cost reduction is required to meet the projected cost of electricity target, which is comparable to today’s supercritical 

PC without CCS. The 5-year goal is to scale current 10 kilowatt of electric energy (kWe) test cells to 250 kWe 

and complete at least 5,000 hours of operation. The ultimate goal is to enable the manufacture of highly efficient, multi-megawatt, coal-fueled solid-oxide fuel cells power generation systems with greater than 99% CO2

capture.44
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Chemical looping involves the use of a metal oxide or other compound as an oxygen carrier to transfer oxygen 

from the air to the fuel. This combustion process produces a highly concentrated stream of CO2 and water, 

eliminating the need for an air separation unit or subsequent CO2 capture. Some versions of chemical looping 

can also be used to produce hydrogen. R&D is needed to improve oxygen carrier properties, optimize solids 

handling and process design, optimize process heat integration, and lower capital and operating cost. The 

durability and economics of an oxygen carrier that can be reused for an extended period of time may be demonstrated in 5 years.

Breakthrough technologies for characterizing subsurface geologies and phenomena applicable to CO2 storage 

would lessen the uncertainty surrounding long-term storage. One example is continuous active source seismic 

monitoring to achieve ultra-high resolution subsurface maps. Another is deployment of large arrays of tiny, 

wireless sensors or “motes” that have the potential to monitor geophysical/geochemical properties in a package of centimeter-scale or less. Dedicated field tests and associated modeling and monitoring could rapidly 

increase understanding of key geophysical and geochemical phenomena pertinent to energy technologies and 

also provide opportunities to answer the fundamental questions that may inhibit their large-scale implementation. A collective approach could accelerate subsurface technology breakthroughs well beyond current nonintegrated approaches. 

In addition to geologic storage, other carbon storage options have been described, although the costs of these 

options are unknown. The first is deep ocean storage, where CO2 is injected directly into the deep ocean, 

whereby the injected CO2 would remain sequestered until the surface and deep waters mix and CO2 concentrations equilibrate with the atmosphere. The second is mineral carbonization, which involves converting CO2

 to 

solid inorganic carbonates, such as CaCO3 (limestone), using chemical reactions.

DOE History and Accomplishments

The Department’s efforts in CCS have focused on basic materials research for carbon capture, reservoir characterization for sequestration, and technology demonstration.

Examples of progress in novel compounds include:

•	 The development of an ionic liquid that exhibits 40 times more CO2 solubility than previous ionic 

liquids.

•	 Advances in oligomeric solvents that could reduce the cost for post-combustion CCS.45 

Founded in 2003 through a competitive DOE funding announcement, the Regional Carbon Sequestration 

Partnership is comprised of seven partnerships that span 43 states, 4 Canadian provinces, and more than 400 

organizations, including non-governmental organizations. The program is being implemented in three phases, 

with the initial phases resulting in:

•	 Completion of 18 small-scale field tests throughout the United States. In aggregate, these tests injected more than 1.22 million metric tons of CO2

 in various types of geologic reservoirs, including 

saline, depleted oil field, and unmineable coal seams. This effort contributed to the development and 

publishing of a series of best practices manuals in seven key areas related to CO2 storage.46

•	 Release of the third edition of the Carbon Sequestration Atlas of the United States and Canada,47

which provides estimates of potential CO2 storage resources that have been determined by a peer-reviewed methodology and applied consistently across the Regional Carbon Sequestration Partnerships. 
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Up to eight integrated first-generation CCS demonstrations funded under the Clean Coal Power Initiative and 

American Recovery and Reinvestment Act of 2009 (ARRA) are expected to be operational around the mid 

2010s. These demonstrations will primarily focus on integrating technologies to achieve reliable operation.

The National Carbon Capture Center, partially supported by DOE, commissioned the Post-Combustion Capture 

Center to support development of multiple post-combustion CO2 capture technologies at several scales. 

DOE Role

The Department’s roles in CCS are primarily informational and R&D capability. Initiatives such as the Regional 

Carbon Sequestration Partnership serve both of these roles by establishing a base of knowledge about the 

technical challenges, risks, and opportunities of carbon sequestration, and sharing that knowledge with stakeholders. The Department also uses its fundamental engineering science and materials science capabilities to 

develop technologies that could drive down the cost of CCS. In addition, the Department leverages information 

gathered from existing CCS demonstrations to disseminate data and analyses to stakeholders.

The Regional Carbon Sequestration Partnerships is a government-industry cooperative effort responsible for 

developing guidelines for the most suitable technologies, regulations, and infrastructure needs for CCS in different regions of the United States and Canada. These activities demonstrate how safe CO2

 storage plays an 

important role in providing information for policy makers and regulators. 
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CLEAN POWER

CONCENTRATING 

SOLAR POWER

Current Status of Technology and Industry

At the end of 2010, nearly 1,200 MW of concentrating solar power48 (CSP) capacity was in operation worldwide (about 0.1% of total capacity), with 508 MW in the United States (about 0.05% of total capacity). At the 

same time, nearly 2,600 MW of CSP was under construction globally, the majority of which is in the United 

States and Spain.49 CSP primarily serves the wholesale power market at utility-scale, while photovoltaic (PV) 

systems can be both at utility-scale and behind the meter.

CSP technologies convert sunlight into thermal energy, which is used to generate electricity. As with other 

thermoelectric power technologies, plant efficiency increases with temperature. CSP’s thermal inertia can provide stability in plant output during slight changes in solar irradiation, such as when a cloud passes overhead. 

Because CSP uses thermal energy, it can also incorporate thermal energy storage (TES) or fossil-fuel backup/

hybridization for stability, dispatchability, and increased duration of energy output. These attributes allow CSP 

plants to operate much like fossil fuel power systems. 

The United States has nearly 7,500 gigawatts (GW) of total resource capacity for CSP generation in seven 

Southwestern states.50 This total is being refined by the joint DOE-Bureau of Land Management Programmatic 

Environmental Impact Statement, designed to identity the best practices for locating utility-scale solar plants.
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Historical Pace of Market Diffusion

At the end of 2008, 430 MW of grid-tied CSP capacity was in commercial operation worldwide, more than 

95% of which was in the southwestern United States.51 Most of the capacity additions during 2009–2010 were 

in Spain, and at the end of 2010, Spain accounted for about 57% of all global CSP capacity.52 

Worldwide, CSP is seeing a resurgence of interest, especially in the United States, Spain, the Middle East and 

North Africa region, Australia, China, and India. That interest has been driven by greater demand for renewable 

energy, government-supported R&D, and improved economics through technology advancements and policy 

initiatives. Since 2007, multiple utility-scale plants have been built and almost 12 GW of capacity were under 

construction or under contract worldwide during 2010.53 Of this total, almost 10 GW were CSP plants with 

signed power purchase agreements under development in the southwest United States.54

Current Status of CSP Technology

There are four major pathways in CSP technology: parabolic trough, linear Fresnel, power tower (also called 

central receiver), and dish/engine (Table 25). All of these technologies convert sunlight into thermal energy, 

which then drives an engine. The first three have been demonstrated in hybrid configurations with fossil fuel 

technologies and/or adapted to use TES to provide operating flexibility and greater reliability. With troughs or 

power towers, the choice of wet, dry, or hybrid cooling systems can influence water use, cycle performance, 

and cost.

Table 25. Major CSP Technologies55

Technology Temp. Design 

Efficiency56

Annual Avg. 

Efficiency57

Capacity Factor 

Without Storage 

and Solar 

Multiple of One58

Parabolic Trough 390°C 25% 13%–15% 25%

Linear Fresnel 350°C 20% 8%–10% 25%

Power Tower 565°C 20% 14%–18% 20%

Dish-Engine 800°C 30% 20%–22% 25%
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Parabolic Trough Technology was first commercialized in 1984 and accounts for 96% of global CSP deployment.59 Parabolic trough power plants consist of large fields of mirrored parabolic trough collectors; a heattransfer fluid (HTF)/steam-generation system; a power system, such as a Rankine steam turbine/generator; and 

optional TES and/or fossil-fuel-fired backup systems (Figure 34). They have a footprint of approximately 5 acres/

MW without TES and 8 acres/MW with TES (a 1,500 MW plant would therefore occupy a square plot some 2 

miles on a side).60 The oil currently used as the HTF thermally degrades at 400°C,61 so these systems operate 

between 250°C–400°C. They generally have a concentration ratio (collector aperture divided by receiver diameter; higher concentration ratios allow the receiver to achieve higher working temperatures) of 50 and use 

1-axis tracking to follow the sun. The current design-point solar-to-electric efficiency—the net efficiency in the 

ideal case when the sun is directly overhead—for a parabolic trough plant ranges from 24%–26%, and the 

overall annual average conversion efficiency is about 13%–15%.62

Electricity

Generator

Turbine

Thermal

Storage Tanks

Steam

Condenser

Parabolic Troughs

Receiver

Figure 34. Parabolic Trough System

Courtesy of: National Renewable Energy Laboratory. (1996). Linear Concentrator Solar Power Plant Illustration. 

Washington, DC: Department of Energy. Accessed at https://www.eeremultimedia.energy.gov/solar/graphics/linear_

concentrator_solar_power_plant_illustration
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Electricity

Generator

Turbine

Steam

Condenser

Receiver

Linear Frensel

Reflectors

Figure 35. Linear Fresnel System

Courtesy of: National Renewable Energy Laboratory. (2000). Linear Fresnel Power Plant Illustration. Washington, DC: 

Department of Energy. Accessed at https://www.eeremultimedia.energy.gov/solar/graphics/linear_fresnel_power_

plant_illustration

Linear Fresnel Reflectors approximate the parabolic shape of a traditional trough collector with long, groundlevel rows of flat or slightly curved reflectors that reflect the solar rays up onto an overhead linear receiver (Figure 35). Flat reflectors and fixed receivers require lower capital costs compared to a traditional trough-based 

plant, but are less efficient on a solar-to-electricity basis. Recently, superheated steam at about 380°C has been 

demonstrated in a Linear Fresnel Reflector plant, and there are proposals for producing steam at 450°C.63 Because Linear Fresnel Reflectors are in the demonstration phase of development, their cost relative to parabolic 

troughs is unknown. 
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Power Tower Technology accounts for 3% of global CSP capacity and is in the demonstration to early-commercialization stage of development.64 Power tower systems use a field of 2-axis tracking collectors (heliostats) 

to reflect sunlight onto a central receiver; a large power tower plant can require anywhere from several thousand to more than one hundred thousand heliostats, each under computer control (Figure 36). This technology 

uses a Rankine or Brayton Cycle for power conversion. Most, but not all, power tower designs have a slightly 

larger footprint than an equivalent trough plant. Power towers have a concentration ratio of 500–1,500 suns 

and can achieve higher temperatures than other CSP technologies. Power tower designs currently use either 

molten salt as an HTF to move energy from the receiver to the steam generator, or to produce steam directly in 

the receiver. Both systems can operate at slightly less than 600°C. Because of their higher operating temperatures, power towers can achieve higher-efficiency and lower-cost TES compared to today’s trough technology. 

The heliostat field can constitute about 50% of the plant cost, making it important to optimize heliostat design. 

The annual average solar-to-electric conversion efficiency of a power tower is about 14%–18%, with directsteam towers slightly higher than molten-salt towers. The design-point efficiency is about 20%.

Electricity

Generator

Turbine

Heliostats

Steel Drum

Steam

Condenser Receiver

Feedwater

Reheater

Figure 36. Power Tower System

Courtesy of: National Renewable Energy Laboratory. (1996). Concentrating Solar Power Tower Plant Illustration. 

Washington, DC: Department of Energy. Accessed at https://www.eeremultimedia.energy.gov/solar/graphics/

concentrating_solar_power_tower_plant_illustration 
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Electricity

Concentrator

Power

Conversion

Unit

Figure 37. Dish-Engine System

Courtesy of: National Renewable Energy Laboratory. (1996). Solar Dish/Engine Power Plant Illustration. Washington, 

DC: Department of Energy. Accessed at https://www.eeremultimedia.energy.gov/solar/graphics/solar_dishengine_

power_plant_illustration

Dish/Engine Systems were first demonstrated in the 1980s. They use a parabolic dish concentrator with an 

engine on each dish, instead of central steam generators like other CSP technologies. Dish systems currently 

use one of three engines: kinematic Stirling, free-piston Stirling, or Brayton turbine-alternator based (Figure 

37). Although some companies are exploring TES, current dish/engine systems cannot use thermal storage 

because electricity is generated at each receiver instead of at a central steam turbine generator. Some dish/

engine technology can be installed on relatively uneven land—with 5% or higher slope—reducing the cost of 

site preparation for new projects. Dish/engine systems use the least water of CSP technologies because they 

use closed loop cooling systems (similar to an automobile engine) and don’t use a steam cycle. Dish/Stirling 

systems have demonstrated the highest recorded design-point solar-to-electric efficiency (31.4%) and have an 

estimated annual conversion efficiency in the low 20% range.65
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TES Systems allow CSP systems to dispatch power beyond the daytime hours. Normally, incorporating TES is 

accompanied by increasing the size of the collector area to produce excess thermal energy during the day that 

can be put into the TES system for later use. The additional capital cost required to incorporate TES is offset 

by increased operational hours. The most common thermal storage design is currently a two-tank molten-salt 

system. To store thermal energy, heat is transferred to the salt storage media. When the stored heat is needed, 

the system runs in reverse, transferring heat from the salt storage media. This type of thermal storage system is 

currently in commercial operation in Spain66 and will soon be operational in the United States.

As the operating temperature of the storage medium increases, the amount of heat transferred to and from 

the medium also increases. Likewise, as the operating temperature increases, less of the storage medium is 

necessary to transfer the same amount of heat. This significant reduction in storage-material mass and the associated reduction in costs make it possible to economically add higher TES capacities. However, at least for the 

near term, most troughs and towers will likely be built with low levels (6 hours or less) of storage or none at all 

since electricity demand, and therefore value, is highest during the day and early evening. Still, higher levels of 

thermal storage may improve the economics of some projects; for example, 300 MW of the current CSP fleet 

include up to 7.5 hours of storage, and systems with up to 15 hours of storage are under construction.67

Storage can not only lower a CSP plant’s levelized cost of electricity (LCOE), but also adds value by decreasing 

variability, increasing predictability, and providing firming capacity.68 CSP plants with TES can bid into ancillary 

services and capacity markets where they exist to realize additional revenue. Even in the absence of explicit 

markets, CSP with TES can improve resource planning and help system planners and operators maintain grid 

reliability.

HTFs currently include molten nitrate salt, steam, synthetic oil, air, hydrogen, and helium. For power towers, 

the current state-of-the-art HTF, a 60/40 mixture of NaNO3/KNO3, is only capable of operating up to a temperature of about 600°C. Above this temperature, the nitrates degrade into nitrites, affecting performance. Other 

common fluids used as HTFs are not thermally stable at 600°C, have too high of a melting point, contain rare 

materials, or are gases with high-pressure requirements for necessary thermal transport rates. 

Current Costs

The estimated direct capital costs for building a 100–400 MW CSP plant today are about $4,000–$8,500/kW. 

The upper end of the range reflects plants with TES, whereas the lower end includes no-TES troughs, directsteam generation towers, and dish/engine systems. Plant capacity factors extend from 20%–28% for plants 

with no TES and 40%–50% for plants with 6.0–7.5 hours of TES.69 Larger amounts of TES and higher capacity factors are technically viable, but subject to project economics. The LCOE varies greatly depending on the 

location, values of key financing terms, available financial incentives, and other factors. For locations in the 

southwestern United States, the LCOE is currently about 19¢/kilowatt hour (kWh).70 

One of the most recent utility-scale CSP plants built in the United States is the Nevada Solar One parabolic 

trough plant, which came online in 2007 at a reported cost of about $4,100/kW (cost of $266 million, capacity factor of approximately 23%, and nominal 64 MW capacity).71 Several trough plants similar in size have 

been built in Spain, including the Andasol plants that include TES; however, those project costs have not been 

disclosed. 
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Manufacturing and Supply Chain

The CSP supply chain is largely domestic. Most, if not all, materials needed to build a CSP plant can be found 

in the United States. However, substantial increases in the manufacturing capacity of CSP components will be 

required to meet a significant increase in CSP deployment. CSP plants require a number of components; some 

are similar to other industrial components and others are unique to the industry. Power block components and 

systems are mature and well-understood technologies, and thermodynamic power cycles currently used with 

CSP are more-or-less conventional and can be found elsewhere in the power generation industry. There may 

be R&D opportunities in automating the manufacture and installation of solar field components, which must 

be mass-produced and installed in large numbers.

Technology Potential

Assuming fixed financial inputs, the LCOE of a CSP plant can be reduced in two ways: (1) by lowering capital 

or operation and maintenance (O&M) costs, and (2) by increasing annual performance. The capital equipment 

for a CSP plant involves solar components (e.g., solar collector field, heat-transfer piping, and TES system) and 

more-or-less conventional thermodynamic power-cycle components (e.g., pump, turbine, and generator). The 

O&M cost per megawatt hour, of which staff is the largest contributor, decreases with an increase in plant size 

or co-location of multiple units.72 

The operating temperature of a CSP plant is a major driver of conversion efficiency, and therefore system efficiency. Table 26 shows the current, theoretical, and target operating temperatures for three CSP technologies. 

Linear Fresnel systems would be similar to parabolic trough values. 

Table 26. Current, Theoretical, and Target Operating Temperatures for CSP Systems 

Parabolic Trough Power Tower Dish/Engine

Current Concentration ~40 ~800 ~3,000

Maximum Theoretical Concentration ~215 ~45,300 ~45,300

Current Operating Temperature (°C) ~390 ~565 ~800

Maximum Theoretical Temperature 

(°C) ~1,120 ~5,080 ~5,080

DOE 2020 Target Temperature (°C) ~500-600 ~600-950 ~800-1,000

Based on: Kaltschmitt, M., Streicher, W., and Wiese, A. ed. (2007). “Renewable Energy: Technology, Economics and 

Environment.” New York, NY: Springer.

Reduced capital cost will be a consequence of manufacturing and installation scale-up, as well as technology 

advancements through R&D aimed at cost reduction and performance improvements. A number of component- and system-level advancements are currently being pursued, which generally can be classified into five 

subsystems: solar field, HTF, TES, cooling technology, and power block.73 

Power towers may have the highest potential for cost reduction due to their combination of high optical concentration, high temperature, ease of TES integration, and ability to scale over a wide range of capacities.

The solar collector field (materials plus labor) represents the single largest capital investment in a CSP plant and, 

as such, represents the greatest potential for LCOE reduction among capital equipment costs. The key to reducing solar field costs is reducing the cost of the collector support structure, reflectors, and receivers.
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For commercial parabolic trough systems, the maximum operating temperature is limited by the HTF. The maximum practical concentration ratio possible coupled with the lowest practical heat loss from the receiver tubes 

suggest an upper temperature limit of approximately 500°C for parabolic trough systems. Water/steam and 

molten-salt HTFs can be used at this temperature; however, there are concerns with the freezing temperature 

of molten salts, as well as a need for salt-compatible components. In contrast, molten salt and direct steam are 

currently used as the HTFs in power tower systems that operate at temperatures near 565°C. This is possible 

because of the considerably smaller amount of piping required for the HTF in a tower system. Owing to higher 

concentration ratios associated with tower systems as compared with parabolic troughs, operating temperatures of 1,000°C or higher may be feasible, depending on the medium used for the HTF.

The current CSP power block for trough, Fresnel, and power tower systems uses many conventional steam Rankine cycle components. It consists of a steam generator that feeds a subcritical Rankine cycle with reheat. The 

main cost-reduction potential in the current power block is correlated to increased size. The next-generation 

power cycle is likely to be the supercritical steam Rankine cycle because it readily exists at commercial, utilityscale fossil plants. Operating at temperatures above 650°C may require advanced cycles, such as supercritical 

CO2

 Brayton or Air-Brayton, which could provide high thermodynamic efficiencies compared to a traditional 

Rankine cycle. Regardless of the power-cycle design, achieving the greatest cost reduction will require significant decreases in collector costs, while also minimizing optical efficiency losses. It is essential to remove 

material weight from the solar field while maintaining adequate wind-load rigidity and optical accuracy. The 

primary cost components of heliostats include the reflector module, support structure and pylon, drive systems, 

wiring, and manufacturing infrastructure. Proposed improvements include polymeric or thin-glass reflectors, 

anti-soiling coatings to maintain reflectivity while decreasing O&M costs, novel structures with significantly reduced material content, low-cost drives with wireless field controls, and highly automated manufacturing and 

installation procedures. 

The development and testing of new solar receiver designs and materials will be necessary to accommodate 

the deployment of advanced, high-temperature power cycles. Air-Brayton systems running at temperatures of 

1,000°C and higher may require volumetric receivers or designs with secondary concentrators; such designs are 

currently being investigated as part of the European Solugas project. Although supercritical CO2 systems will 

run at lower temperatures (600°C–800°C), they will still require analysis of compatible materials and receiver 

designs for high-pressure CO2 systems. Selective receiver tube surface coatings that maintain high absorptivity while minimizing emissivity and are stable at high temperatures in air are needed for new receiver designs. 

Initial research suggests that candidate materials may be found among those originally investigated for trough 

receiver coatings.

Last, as temperatures are increased and new HTFs are deployed, TES systems will need to advance in order to 

maintain the relatively high efficiency and low cost of current CSP TES systems. Supercritical steam and CO2 are 

compatible with thermocline and two-tank storage concepts, but salts with stability and low corrosivity at the 

proposed higher temperatures may be required. Air-Brayton cycles would benefit from low-cost, solid-phase 

storage media or other novel TES concepts.

Significant work is required to improve the accuracy of global resource potential measurements. Highly accurate data on direct normal irradiance is critical to the deployment of CSP plants, as are the availability of 

reliable, sub-hourly, and sub-km datasets. Most solar resource data is satellite-based and several kilometers in 

resolution. Currently, there are only a few dozen quality, ground-based solar measurement stations operating 

in the United States, and only a subset of these stations have been operating long enough to provide accurate 

information on the inter-annual variability and long-term trend of the solar resource. 

Table 27 provides a summary of R&D opportunities for CSP cost reduction.
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SunShot Initiative

In 2011, DOE launched the SunShot Initiative, a collaborative national initiative to make solar energy cost 

competitive with other forms of energy by the end of the decade. The SunShot target is for CSP to reach 

$0.06/kWh, including 14 hours storage by 2020—a value that would make CSP competitive with base-load 

coal plants. This stretches further than the projected improvement developed by DOE in 2009 of $0.09/

kWh by 2020, and requires advanced CSP technological improvements and breakthroughs beyond previous 

estimates.74

Subsystem Pathways

Solar Field

• Polymeric and thin-glass front-surface reflectors

• Anti-soiling coatings and low-to-no H2O cleaning

• Low-cost drives

• Accurate controls

• Optimized support structure

• Autonomous power and control

• Automated manufacturing

• Rapid installation, minimal site prep

• Mass production

Power Plant/Balance of Plant

• High-efficiency power cycles

• Combined cycle configurations

• High-temperature heat exchangers

• High-temperature hardware/instrumentation

• Modular plant designs

• Operation and maintenance optimization

Solar Receiver

• High-temperature materials

• Solar selective coatings

• Alternative designs

Thermal Storage

• High-temperature storage concepts

• Molten-salt additives

• Advanced, low-cost heat transfer fluids

• Single-tank configurations

• Chemical storage concepts

• Corrosive-resistant, high-temperature hardware

Table 27. CSP Technology Development Areas
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Table 28 outlines current and future CSP costs75 based on the DOE roadmap exercises and a hypothetical 

combined-cycle power tower for the more aggressive cost-reduction SunShot case. Costs for 2010 are estimated based on a 100-MW parabolic trough plant with no TES, while the costs for 2015 are based on a 250-

MW parabolic trough plant with 6 hours of TES and a 100-MW molten-salt power tower plant with 6 hours 

of TES. After 2015, salt-HTF trough and tower systems are assumed to be proven technologies with expanding 

deployment that leads to reduced costs via learning and manufacturing volume. The 2020 tower roadmap case 

is based on a 150-MW molten-salt HTF tower with a supercritical steam power cycle at 650°C. The SunShot 

case requires more aggressive performance improvements and cost reductions than assumed by the roadmap 

cases and is based on a 200-MW supercritical CO2 power tower.76 That level of cost reductions likely includes 

an increase in system efficiency by moving to higher-temperature operation (i.e., maximizing power-cycle efficiency) without sacrificing efficiency elsewhere in the system (i.e., minimizing optical and thermal efficiency 

losses). Likewise, reducing the cost of the solar field and developing high-temperature TES compatible with 

high-efficiency, high-temperature power cycles are critical to driving costs down further. The primary source of 

efficiency gains is the development and implementation of advanced power cycles, with the leading candidates 

for CSP applications being supercritical CO2

 Brayton and Air-Brayton power cycles.

Table 28. Current and Projected Costs and Performance Estimates for CSP Trough 

 and Tower Technologies

Case 2010 

Trough

2015 

Trough

Roadmap

2015 

Tower

Roadmap

2020 

Trough

Roadmap

2020 

Tower

Roadmap

2020

SunShot

Target

Design Assumptions

Technology Oil-HTF 

Trough

Oil-HTF 

Trough Salt Tower Salt-HTF Trough Salt Tower

Supercrit CO2

CombinedCycle 

Tower

Solar Multiple 1.3 2.0 1.8 2.8 2.8 2.7

TES (hours) - 6 6 12 14 14

Plant Capacity (MW, net) 100 250 100 250 150 200

Power Cycle Gross 

Efficiency 0.377 0.356 0.416 0.397 0.470 0.550

Cooling Method wet dry dry dry dry dry

Cost Assumptions

Site Preparation ($/m2) 20 20 20 20 20 10

Solar Field ($/m2) 295 245 165 190 120 75

Power Plant ($/kW) 940 875 1,140 875 1,050 880

HTF System or Tower/

Receiver ($/m2 or $/kWth) 90 90 180 50 170 110
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Factors that Affect Market Prospects

Financing presents a significant hurdle to the commercialization of new and existing CSP technologies. The size 

and term of capital expenditure for CSP (a 100-MW plant currently requires $400–$800 million, depending 

on storage)77 are inappropriate for venture capital. CSP projects largely use first-of-a-kind technology and are 

therefore viewed as too risky for traditional project finance. 

Project financing can be aided by modularity of the technology. Dish/engine systems are modular, with systems 

built to scale to meet the needs of each individual project site, potentially satisfying loads from kilowatt to gigawatt. This scalability makes dish/engine technology applicable for both distributed and utility-scale generation. 

CSP demonstrations typically range between 1–10 MW. Most CSP projects in Spain are 50 MW, a size driven 

by policy rather than technical optimization. Based on a technical optimization, the optimal size of a CSP plant 

is approximately 150–250 MW.78 

Obtaining permits, access to the grid, and access to water and gas networks for backup adds time, cost, and 

uncertainty to project development. For CSP plants with wet cooling, the significant water consumption can 

present both a logistical and sustainability challenge. Dry and hybrid cooling can reduce CSP water consumption substantially, although these systems can increase cost and reduce efficiency compared to wet cooling. 

CSP plants also require a relatively large plot of land; for example, a 100-MW project requires almost 1 square 

mile of land.79 This land must be selected in a way that minimizes environmental and ecological effects. A wide 

range of habitats, plant and animal species, and cultural and economic activities could be affected by widespread solar development, particularly in the southwestern United States. 

Case 2010 

Trough

2015 

Trough

Roadmap

2015 

Tower

Roadmap

2020 

Trough

Roadmap

2020 

Tower

Roadmap

2020

SunShot

Target

Cost Assumptions

Thermal Storage 

($/kWhth) - 80 30 25 20 14

Contingency 10% 10% 10% 10% 10% 10%

Indirect (% of direct costs 

+ contingency) 17.6% 17.6% 17.6% 17.6% 17.6% 13%

O&M ($/kW-yr) 70 60 65 50 50 40

Performance and Cost

Capacity Factor 25.3% 42.2% 43.1% 59.1% 66.4% 66.6%

Total Installed Cost 

($/kW) 4,500 7,870 5,940 6,530 6,430 3,770

LCOE (c/kWh, real) 

[SunShot financial 

assumptions]

20.4 19.4 14.4 11.6 9.8 6.0

Department of Energy. (2012). SunShot Vision Study. Washington, DC. Performance and cost values generated using 

the National Renewable Energy Laboratory’s System Advisor Model, available at https://www.nrel.gov/analysis/sam/
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Electricity demand centers are often situated long distances from the best CSP resources, requiring access to or 

the build out of long-distance transmission lines.80 Most transmission lines in the Southwest are already at or 

near full capacity, making access to transmission difficult.

DOE History and Accomplishments

Federal funding for CSP began in 1974 with National Science Foundation support for power tower system studies, followed by construction of the National Solar Thermal Test Facility at the Sandia National Laboratories. In 

1979, two engineering prototype parabolic trough modules were assembled at Sandia National Laboratories 

to provide a documented indication of the performance potential of parabolic trough solar collectors. This 

demonstration provided a baseline for glass reflector technology and set a near-term performance goal for 

the collector manufacturing industry. Over the next several years, a number of other trough systems were 

developed, primarily for industrial process heat and irrigation pumping applications. However, emphasis subsequently shifted to focus solely on power production. R&D from the late 1970s to the mid 1980s improved 

trough technology to the point where Luz International first commercialized CSP in the 1980s with the Solar 

Energy Generating Systems (SEGS)—nine parabolic trough plants in the Mojave Desert of southern California, 

totaling 354 MW. The SEGS facilities were completed in 1991. Sandia was involved in the testing and evaluation of developmental and commercial trough collector hardware, with the SEGS plants in California leveraging 

much of this work. Sandia worked with the SEGS III-VII plants at Kramer Junction, California, throughout the 

1990s to reduce O&M costs. 

As a more recent example, DOE began funding R&D for advanced trough collector design projects in 2007. 

Solar Millennium’s design has been built and tested through a DOE award at a 1-MW test loop at the SEGS 

plants in California. Abengoa Solar’s design has been built and tested at the 1-MW Cameo project in Colorado.

Power tower development can also be traced through DOE-funded activities. Solar One—a joint undertaking 

of the Department, Southern California Edison Company, Los Angeles Department of Water and Power, and 

California Energy Commission—was a 10-MW water-steam power tower built in Barstow, California, between 

1979 and 1981. Solar One was instrumental in helping to prove that power tower technology is effective, reliable, and practical for utility-scale generation. It operated from 1982 to 1988 and ultimately achieved 96% 

availability during hours of sunshine. In the 1990s, the Solar One steam-receiver plant was redesigned into a 

power tower plant named Solar Two, which employed a molten-salt receiver and TES system. The change from 

steam to a molten-salt working fluid was made largely due to the ease of integrating a highly efficient (about 

99%) and low-cost energy storage system into a molten-salt plant design. The project was developed by DOE 

with a consortium of utilities led by Southern California Edison. Solar Two operated from 1996 to 1999 and 

helped validate nitrate salt technology and reduce the technical and economic risks of power towers, which is 

critical to CSP power tower commercialization. Solar One was a precursor to commercial direct steam power 

tower projects. Similarly, Solar Two served as a precursor to commercial molten-salt power tower projects with 

molten-salt thermal storage. Furthermore, the molten-salt storage validated at Solar Two has been commercially deployed at parabolic trough plants.

As for dishes, early DOE-funded work was carried out through the Jet Propulsion Laboratory in Pasadena, 

California, and later transferred to Sandia National Laboratories. Throughout the 1970s and 1980s, several 

dish/engine prototypes and hardware (e.g., concentrators, receivers, engines, transport, storage, and controls) 

were developed and tested. These experiments demonstrated the technical readiness of dish systems in electric 

power and process heat applications. Dish/electric modules based on Rankine-, Stirling-, and Brayton-cycle 

technology were explored. DOE has worked with industry to improve the reliability of the dish engine, primarily 

the Stirling engine, and is presently working on concepts to enable the technology to store energy. 
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DOE Role

DOE’s role in CSP is expanding beyond R&D capability, convening, and informational to targeted initiatives. 

This means that, in addition to the fundamental engineering science and materials capabilities that the Department commits to CSP R&D, DOE has announced an ambitious technical goal—less than $4/watt (W)—and 

will work with industry and academic partners toward that goal. This initiative, called SunShot, focuses on the 

installed system as a whole, including both technical and non-technical costs. For non-technical costs, areas of 

DOE focus include partnering with other federal and state entities to perform a programmatic environ¬mental 

impact statement, identifying suitable federal land for utility-scale solar project development, and identifying 

best locations for new transmission corridors. 

Linear Fresnel technology has primarily been developed in Europe and Australia; DOE has had limited involvement to date. 

DOE funding for CSP technologies has varied greatly since its first year of funding in 1974 (see Figure 38).

65

60

60

40

45

50

55

35

30

25

20

15

10

5

0

Annual Budget Appropriations to Solar CSP

(2010 $million)

198519901995200020052010

FISCAL YEAR

Figure 38. Historical DOE Funding for CSP Technologies

Sources: (1985–2000) Current Congressional Appropriations from DOE CFO, Office of Budget; (2000–2002) DOE CFO, 

Office of Budget (http://www.cfo.doe.gov/budget/02budget/es/solar.pdf); (2003–2008) DOE EERE Budget Office 

(http://www1.eere.energy.gov/ba/pba/budget_archives.html); (2009–2010) 2011 FY11 Congressional Budget for 

DOE EERE (http://www1.eere.energy.gov/ba/pba/pdfs/fy11_budget.pdf). Converted to 2010 $million using consumer 

price index from Department of Labor, Bureau of Labor Statistics (ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.

txt).
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CLEAN POWER

FUEL CELLS FOR 

DISTRIBUTED GENERATION

Current Status of Technology

Fuel cells for distributed generation have low emissions (60% reductions compared to coal power and 22% 

compared to a natural gas combined-cycle central station81), high electrical efficiency (greater than 60% of low 

heating value in select cases,82 see Figure 39), nearly silent and vibration-free operation, potential to increase 

direct current (DC) power system reliability,83 low maintenance, and the ability to use an existing natural gas 

fuel supply, as well as biogas, hydrogen, and other fuels. Global distributed fuel cell capacity is 100–150 megawatts of electric energy (MWe), including about 50 MWe operating in the United States (some 0.005% of total 

generating capacity). The market is small, but it is rapidly growing (increasing annually by 27% between 2008 

and 201084) as capital costs have approximately halved over the past 5 years.85 

70%

60%

50%

40%

30%

20%

10%

0%

Steam

Turbines

Recip.

Engines

Gas

Turbines

MicroturbinesFuel

Cells

Higher Heating Value Efficiency

Figure 39. Efficiency of Various Distributed Generation Technologies

No combined cycle assumed. Source: Environmental Protection Agency. (2008). Catalog of CHP Technologies. Table III 

of Introduction on page 7. Washington, DC. Accessed at http://www.epa.gov/chp/documents/catalog_chptech_full.pdf
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Many of the first applications of distributed fuel cells have been in markets that require high reliability: data 

centers, telecommunications towers, emergency response and life support systems, and national defense and 

homeland security applications. Notably, these applications also have high load factors (i.e., require nearconstant power), which justify the capital expense of fuel cells. 

Costs of fuel cells for distributed generation are more than $4,500/kW today. Greater penetration of the commercial and residential markets requires that capital and installation costs fall to less than $2,000/kWe and 

durability (i.e., useful lifetime of the fuel stack) increase by at least 50%.86 To date, fuel cells have been built 

at relatively low volumes, which has contributed to their high cost. Technology improvements, economies of 

scale, and advanced manufacturing techniques offer the potential for significant cost reductions. 

Target capital costs for fuel cells using natural gas are several fold greater than those of a natural gas combinedcycle plant (projected to be less than $1,200/kW with CCS, or less than $600/kW today without CCS for a 

560-MWnet power plant).87 However, fuel cell systems are expected to compete with microturbines to supply the 

distributed generation market if the installed cost is reduced below $2,000/kWe. Microturbines with combined 

heat and power (CHP) have an installed cost of $2,400–$3,000/kW (compared to current $5,000–$6,500/kW 

installed costs for fuel cells with CHP).88 Since they compete with residential power prices rather than wholesale 

prices, distributed generation systems can be economic with higher LCOE than utility-scale systems. 

Distributed generation technologies can reduce peak electrical demand and congestion on the grid and provide local CHP for residential, commercial, and industrial applications. High-temperature waste heat from fuel 

cells can also be used to power absorption chillers and reduce the energy used to cool buildings. Verizon, for 

example, installed more than 1.4 MW of fuel cells to provide reliable power, as well as heating and cooling for 

one of its telecommunications centers.89 

Natural gas and biogas from sources such as wastewater treatment plants and landfills are already available as 

fuels. The development of low-carbon fuels (e.g., hydrogen from biomass or microbial pathways) would reduce 

fuel cell GHG emissions even further. 

Fuel cells used for CHP can provide heat and power more efficiently (70%–90% total efficiency on a lower 

heating value basis),90 while avoiding the losses involved in electricity transmission and distribution. 

The ability of fuel cells to follow load changes varies with fuel cell technology and system design. In general, 

lower-temperature systems are able to respond more quickly to transient power demands. For instance, polymer electrolyte membrane fuel cell (PEMFC) systems for automotive applications can transition from 10%–90% 

of rated power in less than 1.5 seconds.91 Low-temperature PEMFC systems for small-scale CHP applications 

can transition from 10%–90% of rated power in less than 10 seconds. Higher-temperature systems are less 

capable of rapid response, with solid oxide fuel cells (SOFCs) currently achieving 5 minutes for 10%–90% 

transients.92

The major types of distributed generation fuel cells are described in Table 29.
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Beyond the need to reduce cost, there are specific technical challenges for each of these technologies (see 

Table 30).

Table 30. Technical Challenges for Fuel Cell Platforms 

Table 29. Characteristics of Commercially Available Stationary Fuel Cell Types

 for Distributed Generation

Fuel Cell 

Type

Operating 

Temperature oC Efficiency

Unit 

Capacity 

(MW)

Fuel Stack 

Lifetime (hours) Characteristics

Phosphoric 

Acid (PAFC) 150o

C–200oC 40% e90% CHP 0.4 MW 80,000 

Load following 

between 50%–100% 

of rated capacity

Molten 

Carbonate 

(MCFC)

600oC–700oC >45% eLoad following 

between 

50%–100% of 

rated capacity

40,000

Ammonia and 

carbon monoxide 

tolerant

Polymer 

Electrolyte 

Membrane 

(PEMFC)

50o

C–100oC 40% e- <1 MW 20,000–40,000 

Most relevant for 

residential and light 

commercial CHP

Solid Oxide 

(SOFC) 700o

C–900oC 50%–60% 

e- <1 MW 20,000

Ammonia and 

carbon monoxide 

tolerant

“e-“ percentage is the efficiency of electricity generation only, CHP percentage is the efficiency from combining electricity 

production with waste heat use. 

PAFC MCFC PEMFC SOFC

Low power density ● ●

Short stack lifetime ● ● ●

Cost/complexity of manufacturing ● ● ●

Requirement for contaminant 

removal from fuel stream ● ● ● ●

Costly catalysts ● ●

Poor transient response ●

PAFC = phosphoric acid, MCFC = molten carbonate, PEMFC = polymer electrolyte membrane, 

SOFC = solid oxide fuel cells
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There are fuel cell systems that are a cross between PEMFCs and phosphoric acid fuel cells (PAFCs), which have 

similar operation to PAFCs, but with a polymer-phosphoric acid electrolyte (such as BASF’s gel-type polybenzimidazole). These would allow for enhanced performance and higher tolerance to carbon monoxide impurities 

in the fuel when operating in the 130oC–180oC range. 

Advanced manufacturing techniques for fuel cells include membrane and electrode fabrication; online automated measurement tools for characterization, sampling, and testing; and advanced bonding processes for 

high-temperature membrane electrode assemblies.

Another potential application of fuel cell and hydrogen technologies is the storage of electricity, the need for 

which is likely to grow along with intermittent renewable generation. For example, solar or wind electricity can 

power electrolyzers that split water into hydrogen and oxygen. However, electrolysis will not be cost effective 

until efficiencies greatly improve. Hydrogen and/or oxygen can be stored and converted back to electricity using fuel cells or fuel cells combined with turbines. Reversible fuel cells can operate in either electrolyzer or fuel 

cell mode. 

The global market for fuel cells in all applications grew to approximately $500 million in 2009,93 most of which 

was for distributed generation fuel cells. Approximately 15,000 fuel cells were shipped in 2010, which was 

about double the number in 2008.94 U.S. manufacturers account for roughly 40% of the global production of 

fuel cells on a megawatt basis.95 

Historical Pace of Development and Market Diffusion

The capital costs of some fuel cell stacks for distributed generation have come down by approximately 50% 

over the past 5 years.96 The number of non-automotive fuel cells sold annually by U.S. manufacturers has increased by a factor of 5 from 2005 (see Table 31). The United States, South Korea, Germany, and Japan are 

the fuel cell market leaders (see Figure 40). As of 2008, there were 13 MW of PEMFCs installed in the United 

States, including 10 MW for backup power.97
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100

75

50

25

0

2008 2009 2010

Fuel Cells Shipped (MW)

U.S. JAPAN SOUTH KOREA GERMANY REST OF WORLD

Figure 40. Fuel Cell Shipments in Major Countries (including exports)

Adapted with permission from Pike Research (www.pikeresearch.com).

2005 2006 2007 2008 2009 2010

Polymer Electrolyte Membrane Fuel Cells (PEMFC) (5 kW equivalent units)

PEMFC Material Handling 0 0 123 211 477 803

PEMFC Backup Power 135 158 219 435 894 1,221

PEMFC Combined Heat and 

Power 71 71 71 71 71 250

Larger Non-PEMFCs 

PAFC (400 kW equivalent units) 10 10 10 10 50 75

MCFC (MWs) 6 5 12 24 32 32

Table 31. Estimated Production of Non-Automotive Fuel Cells by U.S. Manufacturers

Compiled by Oak Ridge National Laboratory from information provided by manufacturers, annual reports, and other 

published sources.
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Figure 41 shows the cost-reduction potential for a fuel cell with the capability to use either natural gas or 

biogas. Currently, the biogas option for operating a fuel cell system includes a $2,200–$2,600/kW increase in 

installed cost for gas cleaning with existing technology. 

At this time, reliable cost information for SOFCs is not available; however, estimates of $8,000/kW have been 

reported.100 In 2010, an independent panel judged that factory costs for small-scale SOFC systems could be 

reduced from $1,300–$4,500/kW to $1,000–$2,000/kW by 2020.101

Technology Roadmap

There is significant room to improve the cost and performance of fuel cells. Fuel cells for distributed generation 

cost more than $4,500/kW today. Roadmaps developed in consultation with industry suggest that there are no 

clear pathways below a first cost of $2,000/kW for molten carbonate fuel cells (MCFCs) or PAFCs.98 However, 

roadmaps developed by DOE that take into account cost reduction through increased production volumes and 

innovative R&D have identified paths to reduce installed costs to approximately $2,100/kW for systems operating on biogas and $1,500/kW for systems operating on natural gas (Figure 41).99 

8000

7000

6000

5000

4000

3000

2000

1000

0

Installed Cost ($/kW)

MEDIUM-SCALE FUEL CELL CHP WITH BIOGAS MEDIUM-SCALE FUEL CELL CHP WITH NATURAL GAS

2010

Cost Status

Fuel Flexibility

& Gas 

Cleanup

Stack 

R&D

Manuf R&D

and Volume

2020 Cost

Target

Figure 41. Cost-Reduction Potential Through 2020

Analysis by the U.S. Department of Energy’s Fuel Cell Technologies Program. (2011). Washington, DC.
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There are several opportunities to achieve this technical potential. Reducing platinum content by 50% would 

reduce costs by roughly 3% for both PAFCs and PEMFCs.102 Improved manufacturing methods could bring 

costs down by at least 10% for PEMFCs and PAFCs. Industry experts believe that R&D could increase durability 

by 50%–100% for certain fuel cells (PEMFC, MCFC, SOFC), which would reduce the cost of electricity by more 

than 10%.103 

Some R&D opportunities include:

•	 Developing improved catalysts and electrolytes

•	 Identifying degradation mechanisms and approaches for mitigating their effects

•	 Characterizing and optimizing transport phenomena to improve cell and stack performance

•	 Investigating and quantifying effects of impurities on performance

•	 Developing low-cost, durable system balance-of-plant components

•	 Developing advanced manufacturing and diagnostics technology

•	 Developing innovative concepts for fuel cell technologies.

Potential Improvements

Tables 32 and 33 show potential improvements for fuel cells used in CHP applications. PEMFCs (up to 10 kWe 

for individual homes) are assumed to use natural gas, whereas larger systems for commercial and apartment 

buildings (MCFCs and PAFCs) are assumed to use either natural gas or biogas. These potential improvements 

are driven by the requirement to compete with incumbent technologies and based on an assessment of costreduction potential that is founded on cost engineering models and stakeholder feedback. These improvements, based on learning curve models, may not occur by 2020 if manufacturing volumes do not reach the 

assumed 100 MW per year.104 

($/kWe)

2011 2015 2020

Natural 

Gas 4,600 3,000 1,500

Biogas 6,800 4,100 2,100

 From Fuel Cell CHP (¢/kWh)

2011 2015 2020

Natural 

Gas 17 12 7.9

Biogas 21 14 8.8

Costs do not include federal and state incentives.

Natural gas prices from Annual Energy Outlook 2011 (commercial rates).

Biogas prices assumed equal to natural gas prices.

Table 32. Costs of Fuel Cell CHP System Table 33. Levelized Cost of Electricity
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Near-Term Research Opportunities

The four major fuel cell pathways have different operating characteristics that make them suitable for different applications. For example, MCFCs and SOFCs are best for applications where high efficiency is desired, 

while PAFCs are more suitable for applications where the longest possible lifetime is required, and PEMFCs are 

desirable in applications where the fastest possible startup is required. Fuel type and quality, requirements for 

cogeneration of heat and/or hydrogen, and requirements for reliability and availability will also determine the 

best technology in a given application. Continued development may eventually allow one or more of these 

technologies to capture a more significant market share.

Key distributed generation R&D that is required includes tailoring electrode structures to increase power 

density, reduce polarization losses, improve durability, and reduce the amount of precious metal catalysts. 

Industry and DOE analyses have shown that both the fuel cell stack and balance-of-plant have significant 

headroom.105 The following activities are therefore important: 

•	 Conducting research on fuel cell stack components (such as catalysts, electrodes, interconnects, and 

electrolytes) 

•	 Improving manufacturing processes (reducing cost, number of parts, and time of assembly) and developing advanced diagnostics that can quickly identify defective components on assembly lines 

•	 Investigating new materials, new architectures, and operating conditions for low- and high-temperature fuel cells, or new structures and/or morphologies for existing materials. 

The development of low-cost, durable, high-performance balance-of-plant components and subsystems is a 

critical element of distributed generation fuel cells.

Factors that Affect Market Prospects 

Small distributed generation fuel cell systems have simpler and streamlined interconnection fees, standby/

backup charges, engineering review, and contracting requirements. Presently, the “soft costs” for a small system are the same as that for larger systems (e.g., greater than 2 MWe).106 

For large and small distributed generation systems, there are uncertainties regarding the cost of additional liability insurance, the rate at which excess distributed generation electricity can be sold to the grid, and the rate 

charged by the utility for standby/backup. 

Breakthrough Technologies

Several innovative technologies have the potential to dramatically improve fuel cell performance at a lower 

cost. These technologies are early in the development phase, sufficiently out of the commercial mainstream to 

be viewed as “high-risk and high-return” R&D investments. Existing public and private sector R&D endeavors 

of this sort include:

Reversible Fuel Cells: Reversible fuel cells (such as reversible SOFCs) can improve the integration of intermittent renewable generation and could enable a smarter grid. However, the performance of this technology in 

the electrolyzer mode needs to be made more stable, and its ability to handle transients needs to be improved. 
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Durable Ultra-Low Platinum Group Metal Catalysts: The high cost of platinum group metal catalysts in 

PEMFCs and PAFCs drives the need to minimize their use. Innovative concepts with very low platinum group 

metal content are being studied with advanced theoretical and computational methods to understand and 

engineer new catalysts and catalyst layers, to investigate catalyst-support interactions and their effects on durability and mass activity, and to test and characterize new materials.

Innovative Hydrogen Storage and Delivery Technologies: Full commercialization of hydrogen fuel cells 

will require advances in technologies for storing hydrogen. Storage requires very high pressures, low temperatures, or material-based processes (as opposed to high-pressure storage, for example, using controllable lowpressure adsorbants) to be stored in a compact container. Research is ongoing to increase filling and discharge 

rates, improve pressure and temperature management, and achieve cost-effective packaging into integrated 

systems. Additional research is needed for larger-scale material production and handling methods. 

Deployment Barriers

Fuel cells are currently competitive in niche applications, such as emergency backup power and distributed generation in California. In addition to the state of the technology, certain institutional and economic barriers, such 

as non-uniform codes and standards and the lack of public awareness and understanding of the technologies, 

impact the competitiveness of fuel cells. 

The recent growth of the stationary fuel cell market has been facilitated by the federal investment tax credit of 

$3,000/kW (or 30%, whichever is lower) of the capital cost for a fuel cell system, as well as by additional incentives in states such as California. Fuel cells can be competitive in regions where natural gas prices are low and 

electricity prices are high. More recently, Section 1603 of the tax code has provided grants (cash payments) in 

lieu of tax credits, which allows entities that do not pay substantial taxes (and hence don’t benefit from a tax 

credit) to obtain incentives equivalent to the investment tax credit. 

State policies with respect to CHP will also affect the deployment of fuel cells. These policies include energy 

efficiency resource standards and renewable portfolio standards (RPS). Thirteen states have portfolio standards 

that include CHP, using both renewable fuels and fossil fuels such as natural gas. There are no standard methods to compute the energy efficiency contribution of CHP for RPS purposes.

DOE History and Accomplishments

DOE has supported the development of PEMFCs, PAFCs, MCFCs, and SOFCs for more than three decades, 

helping to enable their commercial introduction. Fuel cells have been demonstrated with a variety of fuels, 

including hydrogen, pipeline natural gas, propane, bio-gas derived from landfills and waste water treatment 

plants, and fuel from coal gasification. 

DOE’s efforts have focused on the R&D of materials, stack components, balance-of-plant subsystems, and integrated fuel cell systems, targeting lower cost and enhanced durability, with an emphasis on the science and 

engineering at the cell level and on integration and component interactions at the system level. To complement 

R&D, DOE has also conducted demonstrations to verify the performance of pre-commercial technologies. These 

demonstrations have involved multiple types of fuel cells and a variety of applications, ranging from small residential, backup power, or portable systems to hundreds of kilowatts for buildings or industrial processes. DOE 

also identifies strategic opportunities to grow early markets for fuel cells and has directly assisted in commercial 

and near-commercial fuel cell system deployment in these markets through ARRA. 
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DOE achievements related to distributed generation fuel cells include:

•	 Reduced the cost of gas diffusion layers by more than 50% for PEMFCs.107

•	 Demonstrated the potential for 25% reduction in costs through a novel, three-layer membrane electrode assembly (MEA) manufacturing process.108

•	 Demonstrated more than 11,000 hours of durable, kilowatt-scale SOFC operation in 2011–more than 

double the 2010 durability of 4,500 hours.109

•	 Provided technical assistance, project development, and data collection support to several federal 

agencies, including assistance with early adoption demonstrations by the Department of Defense, the 

Federal Aviation Administration, and the U.S. Postal Service.110

•	 Deployed more than 800 fuel cell systems in emergency backup power, material handling, and CHP 

applications through $42 million in ARRA funds, matched by $54 million in cost-share.111

Over the past 11 years, DOE has invested approximately $95 million in fuel cell R&D for small-scale distributed 

generation, at about $5–$10 million per year ($42 million of ARRA funding not included). In addition, a significant portion of the work on automotive fuel cells is applicable to PEMFCs for distributed generation. Some 

of the R&D on hydrogen storage, production, and delivery technologies is applicable to distributed generation. 

Finally, market transformation activities and a portion of other crosscutting activities (e.g., safety, codes, and 

standards; systems analysis; and outreach) are applicable to fuel cells for power generation. 

In recent years, emphasis has shifted from PEMFC research to include other types of fuel cells, with a portfolio 

of technology-neutral, application-driven activities. In addition, R&D on the balance-of-plant of fuel cells (components other than the fuel cell stack; e.g., the gas cleanup system, reformer, process control system, heat 

exchangers, water management system, and power conditioning section) has started to receive increasing attention for both low-temperature and high-temperature technologies. 

DOE Role

DOE maintains mostly informational and R&D capability activities related to fuel cells. For example, the Department’s core capabilities in materials science enable R&D activities related to improving fuel cell materials. The 

Department uses its informational role to help develop codes and standards related to fuel cells and fuels for 

both transportation and stationary applications.
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CLEAN POWER

GEOTHERMAL

Current Status of Technology

Geothermal technology emits few GHGs and is one of the few renewable energy technologies that can provide 

base-load power absent of energy storage. Geothermal resources range from shallow ground to hot water to 

rock that is located several miles below the earth’s surface. Technologies designed to use this resource base fall 

under two primary categories: power production and energy efficiency.

Geothermal power production uses wells to access naturally occurring heat within the earth to produce steam 

to drive turbines and generate electricity. The United States first generated geothermal electricity in the 1960s 

with the development of the Geysers geothermal field. The United States is the world leader in power production from geothermal resources; although, the 3.2 GWe total installed capacity112 generated less than 0.4% of 

the Nation’s electricity in 2009.113

The domestic resource for geothermal power generation can be divided into conventional hydrothermal, enhanced geothermal systems (EGS), and low-temperature categories. The estimated domestic resource for conventional hydrothermal power production is 30 GWe, with 5–10 GWe that could be developed in the near 

term.114 The EGS resource is potentially large but uncertain, with estimates ranging from 500 GWe115 to 16,000 

GWe;116 although, the practically recoverable resource is certain to be significantly less, as is the case with all 

energy sources. Low-temperature geothermal energy is defined as heat obtained from the geothermal fluid in 

the ground at temperatures of 300°F or less. These resources are typically used in direct-use applications, such 

as district heating, greenhouses, fisheries, mineral recovery, and industrial process heating. However, some 

low-temperature resources can be harnessed to generate electricity. There is, as yet, no reliable assessment of 

the low-temperature geothermal resource; therefore, it has not been included in this assessment. 

Geothermal energy is also used in energy efficiency applications. Ground-source (or geothermal) heat pump 

(GHP) systems heat and/or cool buildings using the constant temperature of the shallow subsurface to extract 

or reject heat. GHP systems use 23%–44% less electricity than conventional air-source heat pumps and can 

lower GHG emissions.117 Less common direct-use applications for geothermal heat include district and space 

heating, greenhouse and aquaculture, spas and laundries, and wood drying and food dehydration. Currently, 

more than 12.6 GWt of geothermal energy (0.3 Quad annually) is used for energy efficiency or direct-use applications, 84% of which is for GHP systems.118
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Historical Pace of Development and Market Diffusion

The Geysers 11-MWe plant in California, commissioned in 1960, is the oldest geothermal power facility in the 

United States. The late 1970s marked the beginning of two decades of high growth for the geothermal industry, as shown in Figure 42. Government R&D and legislative policies, including the Public Utility Regulatory 

Policies Act, are cited by the geothermal industry as having an impact on market growth through the 1980s.119

This specific act provided a simple approach to contracting a power sales agreement to utilities, and the mandated rates available in the agreements were sufficient to support a reasonable return on investment for the 

project developers.

Industry growth has stagnated from the mid-1990s, likely due to the increasing cost of finding and developing 

new geothermal prospects. Early development focused on the lowest-risk geothermal areas (i.e., those with 

obvious surface manifestations) and resources with the highest economic value due to size, temperature, brine 

chemistry, and more. Once these low-cost resources had been developed, discovery and confirmation of other 

resources became much more challenging. The marginal economics of remaining known resources and the 

decline of new resource discovery ultimately limited industry’s ability to deploy new geothermal generating 

capacity.

There are a number of technical and policy barriers to broader deployment of geothermal power in the United 

States. These include the high upfront cost of exploration and drilling, as well as their associated risk, and the 

need to find new resource areas for development. Unlike other renewable energy sources, such as wind and 

solar, a geothermal resource is not confirmed until a well is drilled into the reservoir, which costs millions of 

dollars.120 Currently, the exploration success rate for identifying a hydrothermal resource is only around 35%,121

leaving upfront costs for early development and associated risk as the primary deterrent for rapid development. 

The current low success rate for discovering geothermal resources is a major barrier to expanding the utilization, efficiency, and understanding of geothermal systems. The high upfront risk and cost deters investors and 

developers from exploring unknown areas, which hinders the industry’s already limited knowledge of geothermal systems and why they occur. The consequences of this are significant, as the ability to accurately identify 

potential geothermal resources and increase utilization depends on the exploration of currently uninvestigated 

locations.
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500

450

400

350

300

250

200

150

100

50

0

19711976198119861991199620012006

Annual Installed Geothermal Capacity (MW)

YEAR

The figure does not include development prior to 1971 (e.g., Geysers) or geothermal facilities that were retired prior 

to 2008. Source: Energy Information Administration. (2008). Existing Electric Generating Units by Energy Source. Form 

EIA-860. Washington, DC: Department of Energy. Accessed at http://www.eia.gov/cneaf/electricity/page/capacity/

existingunitsbs2008.xls 

Figure 42. Initial Year of Operation of Current U.S. Geothermal Capacity112

Current Industry

Conventional hydrothermal resources are primarily found in the western United States, as are most of the industry players. Over the past 5 years, the industry has added 0.365 GWe capacity.122 Approximately 0.75 GWe 

of new geothermal plants are in the drilling and construction phase.122

Direct-use projects are usually small and developed by individuals or private companies to utilize geothermal 

heat. There are 20 district heat projects in the United States, all of which are operated by municipalities.123

Shipments of GHP have grown at a rate of 23% annually124 between 2004 and 2009 and account for approximately 84% of the direct-use market, while other direct-use applications have remained static. 
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Technology Potential

Key areas for geothermal technology development include:

•	 Applied R&D targeting exploration and drilling in geothermal environments, the high-cost and highrisk areas of current geothermal projects.125 

•	 R&D to develop and manage geothermal reservoirs, including EGS in the long term.

•	 Innovative technologies to reduce the cost of energy conversion and system components. 

•	 Shared information on technology development across the geothermal community.

Innovative exploration technologies are needed to increase exploration success rates.126 They include improved, 

non-invasive geophysical techniques, such as remote sensing and improved geochemical survey methods that 

incorporate advanced reaction transport models and geomicrobiological influences. Innovation in data processing is also making exploration surveys more effective. By jointly inverting several geophysical datasets, scientists 

can yield higher-fidelity results. Opportunities also lie in technology transfer from the oil and gas industry, as a 

number of exploration methods that have been successfully applied there could possibly be adapted for use in 

geothermal with further R&D (e.g., advanced seismic). 

Figure 43 shows a cost analysis for undiscovered hydrothermal, as well as scenarios for reducing LCOE. Currently, LCOE for EGS is significantly higher than it is for undiscovered hydrothermal. Cost elements for both 

undiscovered hydrothermal and EGS include the high cost of drilling and the high cost of capital, which is due 

in part to resource uncertainty. Power plant and O&M improvements are largely the role of industry. For undiscovered hydrothermal resources, technologies are needed that lower the cost and risk of exploration to reduce 

the number of holes drilled, thereby reducing the cost of capital. For EGS reservoir modeling and engineering 

and well-completion, technologies are R&D opportunities. 
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14

12

10

8

6

4

2

0

Current

Technology

Level

Resource

Identification

& Development

Turbine, 

Generator &

Condenser

Balance 

of Plant

O&M 2020 Target 

Level

Cost reductions ((cents symbol)/kWh)

ADDITIONAL COSTS OF CAPITAL

O&M AND ROYALTY BALANCE OF PLANT

RESOURCE IDENTIFICATION & DEVELOPMENT

TURBINE, GENERATOR, & CONDENSER

Technology 

Cost Reduction

4.9

2.4

2.5

1.5

0.4

1.8

2.5

3.0

0.7

2.0 2.0

15%-30%

7% Cost of

Capital

7%

13.1¢/kWh 4.4¢

1.0¢

0.3¢ 1.2¢

6.2¢/kWh

Reducing the cost and risk of 

exploration through technology 

development will reduce the 

upfront cost of capital

Reduction in 

Cost of Capital

Cost of 

Capital

2020 cost assumes the following reductions:

50% in exploration and drilling costs

50% in O&M cost

40% in power plant

One year reduced from permitting

Cost of capital for all development stages 

is 7% (reduced from 15%-30% during 

resource identification and development)

Figure 43. Cost Elements and Cost-Reduction Scenario for Levelized Cost of Electricity 

(LCOE) from Undiscovered Hydrothermal Resources

The 2020 cost assumes the following reductions: Cost reduction of 50% in exploration and drilling, 50% in O&M, and 

40% in power plant; one-year reduction from permitting time; and cost of capital reduction of 7% for all development 

stages (reduced from 15%–30% during resource identification and development). The reduction in upfront cost of 

capital is due to the reduction in the cost and risk of exploration. Source: Analysis by the Department of Energy’s 

Geothermal Technologies Program. (2011). Washington, DC.

High-Risk Technology Breakthroughs

EGS offers the opportunity to use CO2 as the subsurface HTF rather than water. This approach could remove 

the need for a source of water at the geothermal power facility and thereby expand the geography of siting 

options. The potential efficiency and cost advantages of this approach could improve the economics relative to 

water-based EGS.
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Factors that Affect Market Prospects

There are a number of issues surrounding land leasing and permitting of geothermal sites, including differences in how individual states view geothermal resources (i.e., mineral versus water), duplication in permitting 

requirements between state and federal regulatory agencies, and lack of continuity between state and federal 

regulations (e.g., split estates or geothermal leases on both federal and state land).

The current regulatory environment is complex and time-consuming. Specific regulatory challenges facing the 

geothermal sector can include a general lack of familiarity with hydrothermal and EGS development; the need 

to implement new protocols for issues such as induced seismicity; overlap and coordination issues between 

regulatory bodies; prioritization of geothermal regulatory filings relative to other permitting processes; and the 

need for separate regulatory approvals for each of several steps in the exploration through development process. In total, these factors can combine to make the regulatory process up to 50% of the total timeline from 

exploration start to first production.

Near-term market prospects require exploration risk reduction. For the long term, lower drilling costs are 

needed. Market prospects for EGS could be affected by the risk associated with induced seismicity. Industry, 

academic groups, and DOE acknowledge the need for safety protocols to address induced seismicity, but see 

the risk as manageable with further research and technology development.127 Other environmental impacts, 

including ground water use and contamination, are discussed in depth elsewhere.128

Because drilling is often required to validate technologies and models, geothermal R&D project costs tend to be 

higher than other renewable energy projects. 

DOE History and Accomplishments

DOE’s work in geothermal technologies has focused on four broad areas: exploration, drilling technology, geothermal reservoir engineering, and energy conversion. 

Exploration: Exploration efforts have helped the geothermal industry find and delineate new geothermal 

resources. This was accomplished through collaboration with the United States Geological Survey (USGS) to 

complete regional and national resource assessments,115 as well as a number of programs to cost-share exploration and drilling activities. R&D aimed at developing improved exploration techniques helped develop the best 

practices employed by industry today. The Department’s exploration activities have played a significant role in 

the growth of geothermal power generation in the late 1980s.129 

Drilling Technology: The cost of drilling and well completion together can constitute 30% or more of the total 

cost of a geothermal power plant. To reduce these costs, DOE-funded research areas have included improving 

drill bits, detecting and mitigating lost circulation, high-temperature instrumentation, and better communications with the downhole environment. These efforts have resulted in R&D 100 Awards and technology transfer 

agreements in areas that include polycrystalline diamond compact drill bit wear code, high-temperature (up 

to 300°C) unshielded electronics and logging tools, high-performance cement, and diagnostics-while-drilling 

systems.

Geothermal Reservoir Engineering: One example of a reservoir engineering effort is the Fenton Hill project, 

which focused on trying to create an EGS reservoir from “hot dry rock,” and ran from the late 1970s until the 

early 1990s. Many key learnings regarding rock stimulation had their origin in this project. Fenton Hill provides 

key technical and operational lessons learned that are being leveraged in current demonstration projects, and 

will be incorporated into future test sites.
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More recently, DOE has made investments to develop and validate technologies to exploit the EGS resource. 

Projects focus on high-temperature tools, reservoir fracture network characterization, advanced stimulation 

technologies, predictive modeling for fracture stimulation and induced seismicity, the use of supercritical CO2 

as a geofluid, development of integrated modeling approaches to the thermo-hydro-mechanical-chemical system, improvement of tracers and tracer interpretation models, and several pilot-scale demonstration projects. 

These projects constitute the majority of global EGS activities and are providing critical information in a variety 

of geologic settings. 

Energy Conversion: DOE-supported energy conversion R&D has been aimed at reducing the cost of power 

generation through improved efficiency and reduced equipment costs. Projects of this type include developing longer-lasting materials that are able to withstand corrosive brines, engineering more efficient conversion 

cycles and more robust systems that are capable of handling time-varying ambient conditions, developing 

advanced condenser systems, and focusing on hybrid wet/dry cooling. This body of work has lowered the temperature of geothermal resource that can be developed economically. 

DOE geothermal funding peaked in 1981 (at about $150 million) and has been relatively stable (at less than 

$50 million per year) since the mid 1980s, with two notable exceptions: (1) the program was nearly cancelled 

in Fiscal Year 2007, and (2) the $368.2 million in ARRA funding received in 2009 (Figure 44, ARRA funds not 

included).

65

60

40

45

50

55

35

30

25

20

15

10

5

0

Annual Budget Appropriations to Geothermal 

(2010 $million)

198519901995200020052010

FISCAL YEAR

Figure 44. Annual DOE Budget for Geothermal R&D

Sources: (1985–2002) Current Congressional Appropriations from DOE CFO, Office of Budget; (2003–2008) DOE EERE 

Budget Office (http://www1.eere.energy.gov/ba/pba/budget_archives.html); (2009–2010) 2011 FY11 Congressional 

Budget for DOE EERE (http://www1.eere.energy.gov/ba/pba/pdfs/fy11_budget.pdf). Converted to 2010 $million 

using consumer price index from the Department of Labor, Bureau of Labor Statistics (ftp://ftp.bls.gov/pub/special.

requests/cpi/cpiai.txt).
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A recent Blue Ribbon Panel of geothermal experts130 convened by DOE provided recommendations for new 

program structures. The panel recommended a focus on regional reconnaissance to characterize known geothermal resources, exploration technologies to lower the cost and increase the success rate of confirming 

undiscovered resources, and EGS. The panel was not enthusiastic about low-temperature and co-produced 

resources due to the absence of technology challenges, the low quality of those resources, and the lack of 

industry interest. 

DOE Role

DOE’s roles in geothermal technology are informational, R&D capability, and convening. The Department has 

substantial capabilities in subsurface science that can benefit the industry. Further, the Department contributes 

valuable information to the geothermal field through resource characterization.

DOE reservoir engineering efforts focus on developing:

•	 Technologies to more effectively operate and manage geothermal resources already under production.

•	 Techniques for establishing the physical and chemical properties of reservoir rocks and fluids.

•	 Site-specific case studies of reservoir behavior in different geological environments. Efforts to date include developing geothermal reservoir simulators that improve understanding of geothermal resources 

and their response to utilization for electricity generation. 
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Status of Technology

Nuclear energy currently produces 14% of the world’s electricity131 and has been in commercial operation since 

1954. Twenty-nine countries operate 440 nuclear power plants with a total capacity of 374 GWe (some 8% of 

total installed capacity132). Sixty-five additional units are under construction, which will take the global capacity 

to 437 GWe.133 The majority of nuclear power plants in operation are in North America and Europe, but most 

of the near-term growth is expected in Asia, as shown in Figure 45. More than 60 additional countries have approached the International Atomic Energy Agency, expressing interest in nuclear power. The agency anticipates 

that about 15 of these emerging nuclear nations will deploy new reactors over the next decade or two. Several 

of these new entrants have already committed to construction, although it remains unclear how the recent 

nuclear accident in Fukushima, Japan, will affect these plans.

CLEAN POWER

NUCLEAR POWER

25

20

20

15

10

10

5

0

North

America

Western

Europe

Eastern

Europe

Asia South

America

Africa

Worldwide Deployment of Nuclear Power (GW)

UNDER CONSTRUCTION EXISTING

Figure 45. New Nuclear Construction Primarily in Asia 

Source: International Atomic Energy Agency. (2011). Power Reactor Information System Database. Vienna, Austria. 

Accessed at http://www.iaea.org/programmes/a2/
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The United States produces more nuclear energy than any other nation, operating 104 reactors that have a 

total capacity of 101 GWe.134 Although this is only 10% of total U.S. electric generation capacity, these reactors 

produce 20% of total U.S. electricity, as their average capacity factor exceeds 90% compared to 20%–65% for 

non-nuclear generators. The Nuclear Regulatory Commission (NRC) recently approved combined construction 

and operating licenses for 4 new nuclear reactors, docketed applications for 16 additional nuclear units, and 

docketed applications for 24 additional new nuclear units.135 The Westinghouse AP-1000, which features passive safety systems, has been certified by the NRC and licensed for construction at the Vogtle site. While all U.S. 

reactors that are either in operation or being considered for deployment are variants of the light water reactor 

(LWR) technology, approximately 13% of today’s global nuclear capacity is in non-LWRs.136

History

DOE’s predecessor agency, the Atomic Energy Commission, laid the foundation for commercial nuclear energy 

development and then partnered with industry in deploying first-of-a-kind reactor technology. The Shippingport Atomic Power Station began service in 1957 as the first commercial U.S. nuclear-generating plant. While 

the pressurized water reactor technology selected for submarine propulsion provided an advantage for initial 

commercial deployment, the Atomic Energy Commission also developed another successful LWR technology—

the boiling water reactor. Research efforts in the 1950s and 1960s included other reactor technologies, such as 

sodium graphite, fast breeder, and high-temperature systems. These did not find immediate acceptance, but 

are being reinvestigated in today’s Generation IV programs. 

Nuclear construction expanded greatly in the 1970s. A total of 42 GWe of capacity entered commercial operation in the decade; another 57 GWe of capacity was ordered during the 1970s, but would not enter service 

until later. At the peak of deployment (1974–1976), 23 reactors with a combined 20 GWe of capacity were 

brought online in three years.137 The 1979 accident at Three Mile Island led to a series of regulatory and design 

changes that extended the construction time of many projects underway at that time. The combination of 

high construction costs and mediocre operational performance during the 1980s, combined with slower-thanexpected growth in electricity demand, resulted in no new orders of Generation II plants. 

Beginning in the late 1980s and continuing through the 1990s, the operational performance of the nuclear 

fleet improved dramatically. Capacity factors rose from less than 60% to around 90% by 2000, where they 

have remained since.138 Such efficient operation of depreciated capital assets with low fuel and operating 

costs led to a wave of license renewals that allowed the reactors to operate beyond their initial 40-year license 

horizon. However, commercial interest in construction of a new generation of nuclear power plants remains 

tempered, largely due to high capital costs and low natural gas prices. 

From early in the development of commercial nuclear power, the safe storage and disposal of used fuel and 

radioactive waste was recognized as a critical need. The NRC was given the responsibility of assuring that used 

fuel would be managed safely, while the task of R&D for the “backend” of the nuclear fuel cycle became the 

purview of DOE. In 1982, the Nuclear Waste Policy Act139 delegated responsibility to DOE to “manage and 

dispose of high-level radioactive waste and spent nuclear fuel in a manner that protects health, safety, and 

the environment; enhances national and energy security; and merits public confidence.” Early research was 

devoted to determining the suitability of various potential geologic repository environments. Amendments to 

this act in 1987 terminated these studies, and Congress mandated the decision to build the first U.S. spent 

fuel and high-level nuclear waste repository deep beneath Yucca Mountain in Nevada.140 Subsequently, it was 

determined that Yucca Mountain was not a workable option, and in 2010 the Administration terminated the 

project along with the associated Office of Civilian Radioactive Waste Management.141
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Current Industry

Calder Hall (GCR)

Douglas Point

(PHWR/CANDU)

Dresden-1 (BWR)

Fermi-1 (SFR)

Kola 1-2 (PWR/VVER)

Peach Bottom 1 (HTGR)

Shippingport (PWR)

Bruce (PHWR/CANDU)

Calver Cliffs (PWR)

Flamanville 1-2 (PWR)

Fukushima II 1-4 (BWR)

Grand Gulf (BWR)

Kalinin (PWR/VVER)

Kursk 1-4 (LWGR/RBMK)

Palo Verde (PWR)

GCR

LFR

MSR

SFR

SCWR

VHTR

ABWR (GE-Hitachi; Toshiba)

ACR 1000 

(AECL CANDU PHWR)

AP1000 

(Westinghouse-Toshiba PWR)

APR-1400 (KHNP PWR)

APWR (Mitsubishi PWR)

Atmea (Areva NP 

Mitsubishi PWR)

Candu 6 (AECL PHWR)

EPR (AREVA NP PWR)

ESBWR (GE-Hitachi BWR)

Small Modular Reactors

Atomenergoproekt PWR

B&W mPower PWR

India DAE AHWR

KAERI SMART PWR

NuScale PWR

Westinghouse IRIS PWR

VVER-1200 

(Gidropress PWR)

Early

Protypes

Large-Scale

Power Stations

Evolutionary

Designs

Revolutionary

Designs

GENERATION II GENERATION III/III+ GENERATION IV

gas-cooled fast

reactor

lead-cooled fast

reactor

molten salt reactor

sodium-cooled

fast reactor

supercritical 

water-cooled reactor

very high temperature 

reactor

1950 1970 1990 2010 2030 2050 2070 2090

GENERATION I

Figure 46. Generation Classification of Nuclear Power Plants

Figure 46 depicts the four generations of deployed and proposed nuclear reactors. Almost all nuclear power 

plants deployed today are second generation. Timelines at the bottom of the figure are notional, as the pace 

of development varies significantly across different countries.

The NRC regulates commercial nuclear power plants through licensing, inspection, and enforcement of its 

requirements. The NRC responds when new information becomes available that is relevant to reactor security—

as following September 11, 2001—and to reactor safety—as has occurred with the accident in Fukushima, 

Japan, in March 2011. The NRC also grants early site permits, design certifications, and licenses to construct 

and operate new nuclear plants. The process takes multiple years for the well-understood LWR technology, 

and even longer for more exotic designs. If new nuclear technologies are to be deployed, the NRC must be 

confident that these systems will not pose unacceptable risks to the public. 

Courtesy of Idaho National Laboratory.
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Roadmap

Current Fleet

The oldest of the current fleet of reactors entered service in 1968; more than 100 additional reactors followed. 

These reactors were given 40-year operating licenses and were rated for a maximum generating capacity based 

upon then-current understanding of what would ensure safe operation with adequate margin. As operational 

experience grew and technological improvements were incorporated, reactor operators applied to the NRC to 

increase their power and/or to renew their operating licenses for an additional 20 years. If this process of uprating and renewing is to continue, the technical understanding underpinning those decisions must continue to 

improve.

To date, 68 of the 104 current reactors have received 20-year license renewals, and an additional 31 applications are either currently under review by the NRC or expected to be so in the future.142 Similarly, the NRC has 

allowed 6 GWe of uprates since 1977143 and expects applications for an additional 3 GWe.144 Approval of these 

uprate requests would increase nuclear generation by about 3%. 

While the current fleet has already seen significant uprates and lifetime extension, there could be more. An 

optimistic estimate, based on preliminary modeling and assuming a significant number of power uprates that 

could each add 7%–20% to the capacity of a reactor, would be a total of 10 GWe of uprates beyond the 

current plants.145 A similarly optimistic view of license renewals, assuming the additional round of renewals follows the pattern of the first renewals with widespread interest and acceptance by the NRC, would be for all of 

the current reactors to receive, at minimum, a single 20-year renewal, and for 75 of them to receive a second 

renewal that would allow an extension of the reactors’ operational life to 80 years. 

There is a generally attractive business case for increasing the capacity or extending the life of existing reactors 

because the capital expense of initial construction has already been repaid. The additional investment that is 

likely required for a life extension or capacity uprate (less than $1,500/kW146) is much smaller than the cost of 

building a new nuclear plant (about $6,000/kW147), and is less than the cost of many competing generation 

technologies. 

The principal technical barrier to extending or uprating reactors is demonstrating that structural materials in 

nuclear power plants will safely withstand extended service.148 The NRC will evaluate these requests based 

upon a strong scientific understanding of the expected behaviors of the reactor systems over time, and reactor 

operators will only apply for uprates and license renewals if they are confident that the NRC will approve the 

safety case. 

Applications for uprates and life extension for plants beyond 40 years have traditionally been based on empirical approaches. For example, material samples placed in the reactors can be used to validate predictions of 

neutron radiation damage. Empirical methods become less adequate beyond 60 years, as more complex aging 

mechanisms affect a broader variety of materials and components.149 A science-based predictive approach will 

likely be needed to address these issues, where R&D will bring understanding of the fundamental phenomenology of aging and degradation mechanisms. 
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Advanced LWR fuels development for the current fleet focuses primarily on enhanced accident tolerance. For 

example, fuel clad with materials that can safely reach higher temperatures would better withstand accident 

conditions, such as those faced at Fukushima.150 Research in new instrumentation and control mechanisms 

will provide more information about reactor conditions and help enable control strategies to further optimize 

operations and manage off-normal conditions. Improving risk-informed methodologies to characterize safety 

margins and predictive computational techniques in normal, degraded, and accident operations are important 

research goals. 

Generation III/III+

Generation III plants incorporate evolutionary improvements in the technologies used in currently deployed 

LWRs. These improvements can include passive safety features and modular construction techniques. Generation III systems include reactors from Westinghouse, GE-Hitachi, Areva, Mitsubishi, and Toshiba.151 DOE supported the development of Generation III technologies through its Advanced Light Water Reactor program in 

the 1980s and 1990s.152 The subsequent Nuclear Power 2010 program cost-shared the licensing and finalization of the designs, as well as applications for early site licenses by utilities. 

The first Generation III reactors constructed were Advanced Boiling Water Reactors that entered commercial 

service in Japan in 1996; two more followed within the last decade. Other Generation III reactors are under 

construction in China, Japan, Taiwan, Finland, and France.153 The NRC has recently authorized construction to 

begin on the first U.S. Generation III project.154 

The designs for the first set of Generation III plants to be built in the United States are mature and largely fixed; 

significant alterations would likely require a new NRC review, which could delay deployment. These designs 

would be improved upon in successive waves of deployment that incorporates lessons learned from the initial 

projects, as well as subsequent technological advances. The development of advanced computational methodologies could increase confidence in operational and during-accident behaviors, facilitate licensing activities, 

and help optimize future designs. Development of new materials and fabrication techniques, such as new 

welding methods for major reactor components and construction methods such as steel/concrete composites, 

could also reduce future capital and operational costs. 

Investment costs are the most significant challenge to building these new nuclear plants. Because no Generation III reactors have been constructed in the United States to date, estimates of their cost have varied broadly. A 

2009 report from the National Academies set the range of overnight costs155 between $3,000/kW and $6,000/

kW.156 Overnight costs are the starting point to determine the amount of investment needed to bring the plant 

into operation. Factoring in financing costs and the effects of cost escalation, the total investment cost can be 

about 50% more than the overnight cost, with long-timeline or high-risk projects being higher. Construction 

costs for new reactor designs in Japan and Korea dropped by 25%–30% after 4–5 units were built.157

Altogether, the total investment for a typical large new reactor design is estimated to be about $10 billion.158

That sum is a challenge even for larger U.S. nuclear utilities, which typically have annual revenues under $15 

billion.159 A second factor will be safety concerns among stakeholders, especially in light of the recent events in 

Fukushima, Japan. Finally, improved interim storage solutions and long-term disposal of used fuel and radioactive waste will impact decisions on deployment of these and all future commercial nuclear reactors. 
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LWR Small Modular Reactors

Several U.S. companies are developing small modular reactor (SMR) concepts and designs based on traditional 

LWR technology, but with significant modifications to improve safety and security. These designs range from 

less than 50 MWe to more than 200 MWe, compared to the greater than 1,000 MWe for Generation II and 

III reactors. The proposed designs would use natural circulation and passive cooling to further enhance safety 

in a station black-out scenario, such as the situation that recently occurred in Japan. Compared with current 

large reactors, LWR SMRs will have less piping, simpler safety systems, and less fuel per reactor.160 Underground 

siting of the reactors should increase intrinsic security and minimize personnel costs to maintain a secure plant, 

while at the same time providing seismic safety advantages. Factory fabrication and standardized siting could 

bring down cost and improve quality while enabling multiple units to be deployed at a single site. 

SMRs could help address the financing issue caused by the large upfront capital cost of conventional reactors 

and mitigate the risk of cost overruns and schedule delays. The projected smaller initial capital outlay means 

that SMRs are not necessarily “bet the company” propositions. However, the economics of SMRs are still uncertain. To the extent that overruns and delays depended upon how the large reactors are built, the SMR approach 

removes some of those concerns. 

A handful of SMRs are in the early stages of design in the United States; there are also proposals from other 

nations, notably South Korea.161 The cost target is to be economically competitive with large LWRs, although 

the first-of-a-kind units are not expected to achieve that goal.162 Many issues will factor into whether SMRs are 

able to achieve cost-competitiveness. In particular, the economics of factory fabrication will need to be considered against the economies of scale of larger reactor designs. Factory construction is expected to minimize the 

challenges and costs of nuclear-quality workmanship in a field setting. The modular approach builds directly 

on the U.S. Navy’s experience with modular construction techniques in its submarine builds, which dramatically 

reduced labor hours and defects. From the perspective of a utility, these attributes would mean that the reactor vendor could have a shorter schedule, may be less vulnerable to potential delays, and may be able to offer 

firmer price guarantees to the purchaser.

These systems use the same fuel cycle as the current fleet of large LWRs. There are also technical issues that 

remain to be solved for SMRs, such as developing a well-established technical basis for regulation. For example, 

the cost and complexity of operating an SMR plant may be reduced if multiple reactors are controlled from a 

single control room, but the staffing requirements for such a concept need to be evaluated by the NRC. Similarly, the appropriate size of a security force may need to be evaluated in light of SMR plant characteristics, such 

as underground siting and other issues.163 Less radioactive material in each reactor core could translate into a 

smaller emergency planning zone, expanding the range of feasible sites.

Any reactors built in the United States would require both NRC design certification and first-mover utilities that 

are willing to apply for a license to build and operate these plants. 

There may also be R&D that could advance manufacturing technology generic to SMR designs, such as new 

welding techniques. The fabrication of SMRs may, to some degree, need to draw on new or advanced manufacturing technologies that are in use in other areas, such as military systems, that have yet to be applied to 

nuclear reactors. Of particular interest in design-related research is advanced materials to improve corrosion 

and non-normal event performance and, in the longer term, make certain designs more compact. Development 

of advanced computational methodologies will be very helpful in better understanding and exploiting passive 

safety features. 
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Generation IV

Generation IV nuclear systems use very different technologies than the LWR nuclear-generating stations of 

Generation II and III, and they also require much more R&D before they would be commercially viable. Some 

Generation IV systems may be able to simultaneously address the sustainability, safety, economic, and nonproliferation issues that hinder expanded nuclear deployment. 

A broad international consortium called the Generation-IV International Forum164 provides an arrangement 

under which advanced nuclear technology nations collaborate on R&D activities for six categories of systems. 

Of these concepts, two are nearer term:

A Very High-Temperature Reactor would operate at much higher temperatures than current nuclear technology, producing electricity with a greater thermodynamic efficiency, as well as process heat for many industrial applications.165 A very high-temperature reactor would require new structural materials to increase 

operating temperatures from the currently achievable 700°C to the target of 1,000°C.166 U.S. high-temperature 

reactor R&D has focused on gas-cooled reactors as a source of electricity and process heat. These reactors 

could provide a non-GHG-emitting source of energy, but must compete with the economics of natural gas 

combustion,167 which is expected to remain lower than historic norms due to growing unconventional gas 

production.168

The Sodium-Cooled Fast Reactor is one of three fast neutron-spectrum reactor concepts being investigated 

by international partners in Generation IV, primarily for fuel-cycle optimization.169 Cost reduction is a major focus for sodium-cooled fast reactor development because these systems are expected to be even more 

capital-intensive than current LWR technology. France plans to construct a prototype reactor in the 2020–2025 

timeframe; the Russian Federation is moving at a somewhat faster pace; and the Indian nuclear program plans 

construction of five 500-MWe units by 2020 in order to develop an industrial base.170 The United States has 

built and operated experimental sodium-cooled fast reactors at Idaho National Laboratory and Hanford, neither 

of which is currently in use. 

R&D applicable across many of the Generation IV approaches includes high-performance materials compatible with the proposed coolant types and capable of extended service at elevated temperatures; new fuels and 

cladding capable of irradiation to high burnup and resistant to the type of fuel damage experienced at Three 

Mile Island and Fukushima-Daiichi; and advanced heat delivery and energy conversion systems for increased 

efficiency of electricity production. 

Used Fuel Management Technologies

Some 60,000 tonnes of commercial-used fuel is currently stored in either water pools or dry casks, primarily at 

U.S. reactors sites that are in operation or shut down; an additional 2,000 tonnes is generated each year.171 The 

once-though fuel cycle—where used uranium fuel is removed from the reactor, stored for some period of time, 

and then directly disposed into a repository—is the Nation’s current process for managing used nuclear fuel. 
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In January 2010, the Secretary of Energy convened a Blue Ribbon Commission on America’s Nuclear Future 

to conduct a comprehensive review of policies for managing the backend of the nuclear fuel cycle, including 

alternatives for storage, processing, and disposal. The Commission’s final report 172 recommendations include 

developing a new process to site disposal and consolidated storage facilities; initiating the search for a new 

geologic disposal facility; establishing consolidated interim storage locations to remove used fuel from reactor 

sites; reorganizing how the government performs these functions and how they are financed; and continued 

exploration for improved technologies for waste management. Many of these recommendations will require 

new legislation to implement. 

Management of used fuel has both near-term and long-term components. Research on extending dry cask 

storage supports the continued operation of today’s reactors and provides confidence that used fuel from new 

reactors can be managed effectively.

Some key factors that will affect the final choice of fuel cycles include economics, nuclear waste management, 

resource utilization, safety, security, environmental impacts, technical maturity, and proliferation risks. In the 

unexpected event that uranium supplies become scarce, interest in fuel cycles that more efficiently use uranium 

may grow.

There are two technical classes of long-term management of civilian nuclear waste: direct disposal and recycling. Direct disposal of spent fuel requires packaging, transportation, and disposition in a repository. Recycling 

approaches would remove useful elements from spent fuel for subsequent reuse in reactors; they would also 

require packaging, transportation, and disposition of wastes in a repository. Recycling approaches are more 

complex than direct disposal. Any specific approach has unique technical challenges and economic issues that 

will be considered and clarified as a long-term path forward is developed.173 

Most waste management options would benefit from advanced fuels for improved performance with respect 

to burnup and radiation damage. For approaches that incorporate some form of recycling, many significant 

technical, economic, and proliferation hurdles will need to be overcome. Separations approaches would need 

to be improved upon beyond the current systems that only extract uranium and plutonium. For example, advanced fuels would be needed to hold all of the elements intended for recycle and to ensure that these fuels 

perform as predictably and reliably as current uranium fuels. Full recycle, including the minor actinides, creates 

additional challenges because the fuel fabrication must be performed remotely in hot cells. Waste forms will be 

needed to immobilize all of the elements that will be disposed.

Any waste management option will require storage of used nuclear fuel; one or more well-characterized geological disposal facilities will be needed for disposal of nuclear wastes. R&D on storage is already ongoing. Research will be needed to understand how key radioactive elements move in the environment near any potential 

geologic disposal facility and how such geologies may evolve over the hundreds of thousands of years needed 

for high-level waste disposal. The work characterizing Yucca Mountain is a foundation for such research, as will 

be similar work on other domestic and international geologies. 
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Research Breakthroughs

A number of high-risk technologies with the potential to improve the safety, efficiency, and cost of nuclear 

power are being investigated. 

Table 34. Technology Opportunities for Nuclear Power

Technology Description and DOE Support Challenges

Silicon Carbide LWR 

Fuels

The zirconium cladding of LWR fuel can 

produce hydrogen in some accident 

scenarios. Silicon carbide fuels would 

improve safety while enabling more 

energy to be extracted. 

Lack of mature fuel design 

concept with qualified joining 

techniques.

Molten Salt Coolants

These coolants are efficient for 

transporting heat from the reactor 

core at high temperatures. Molten salt 

systems may also facilitate the use of 

thorium fuels as well.

Proof of principle compatibility 

with structural materials 

systems.

Uranium Recovery from 

Seawater

Uranium is abundant in the oceans at 

very low concentrations. If it could be 

economically recovered, then concerns 

about uranium scarcity would no longer 

influence fuel-cycle decisions. 

State-of-the-art technology still 

far from meeting necessary 

technical and economic targets.

TRISO (TristructuralIsotropic) Fuel

TRISO particle fuel was developed for 

high-temperature gas-cooled reactors, 

but has other potential applications. 

The fuel is potentially much safer than 

current LWR fuel under upset conditions.

Complete qualification, including 

performance validation, of fuel 

would be required if it were to be 

adopted commercially.

DOE Role

DOE and its predecessor, the Atomic Energy Commission, have had a long history in the development of commercial nuclear power technologies. While the Atomic Energy Commission’s approach was to build large-scale 

demonstration facilities, DOE’s model focuses on R&D applicable across a broad range of nuclear energy technologies.

DOE is a leader in applying the capabilities of high-performance computing to create science-based predictive 

models for nuclear technologies. The Consortium for Advanced Simulation of LWRs Hub is applying these capabilities to LWRs.174 One focus of the Consortium is corrosion residual unidentified deposit formation, which is 

important for extending fuel lifetime and ensuring fuel reliability. That understanding can then be incorporated 

into predictive tools that will allow plant operators and regulators to estimate failure probabilities of diverse 

components.
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With its experts and facilities, the Department provides capabilities to the nuclear community. DOE maintains 

the world’s largest test reactor for fuel and material irradiation. It also maintains testing capabilities for irradiated fuels that support fuel-cycle R&D activities. R&D built upon these capabilities could lead to new technologies that improve the safety and reliability of existing nuclear power plants.

DOE is implementing a technical support program to help accelerate the commercialization of SMR technology through a competitive cost-share program to support industry teams of reactor vendors and utilities on 

engineering related to design and licensing of LWR-based SMRs for deployment in the United States.175 Further, 

DOE has already started to engage the NRC on regulatory issues unique to SMRs.

DOE is responsible for long-term management of used nuclear fuel, an issue critical to the long-term sustainability of current or future nuclear technology. Through ongoing R&D, the Department develops technical information that could help winnow down the broad set of fuel-cycle options to those worthy of further technical 

development, when needed, and provides information necessary for future decision-making.
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CLEAN POWER

SOLAR 

PHOTOVOLTAICS

Current Status of Technology and Industry

In 2010, global PV capacity increased by 16.6 GW (30% annual increase) to 40 GW (1% of global capacity) and 

generated 0.3% of global electricity.176 In 2011, the United States installed almost 2 GW of capacity, reaching 

a total of approximately 4 GW,177 which generated 0.03% of U.S. electricity in 2010.178

In 2010, the U.S. solar industry was $6 billion.179 At the state level, California represented 32% of new capacity in 2010 compared to 49% in 2009, indicating stronger growth in other states.180 Historically, residential 

and commercial applications have dominated the U.S. PV market. However, deployment of utility-scale PV has 

grown from nearly zero in 2006 to one-third of PV capacity installed in 2010.181 

Innovations across the three module technologies covered in this review—crystalline silicon (c-Si), thin-film 

materials (e.g., cadmium telluride [CdTe], copper indium gallium selenide [CIGS], amorphous silicon [a-Si]), 

and concentrating PV—continue to drive down costs through improved cell efficiency and manufacturing processes. Each technology has relative advantages and disadvantages, meaning that no single module technology 

is likely to dominate the entire market in the future. 

Historical Pace of Technology Development 

Over the past couple of decades, R&D has led to a steady increase in the efficiency of PV cells. Increases in efficiency not only improve overall system performance, but when coupled with declining module costs over time, 

also drive reductions in cost per watt. Since the mid-1970s, laboratory efficiency has increased from about 13% 

to 25% for c-Si, from about 6% to 20.3% for CIGS, from about 9% to 16.7% for CdTe, from about 1% to 

12.5% for a-Si, and from about 16% to 42% for multi-junction concentrating cells (Figure 47). U.S. scientists 

have been leaders for much of this improvement. However, opportunities remain to close the gap between 

industry production efficiencies and research efficiencies.
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Figure 47. Best Research-Cell Efficiencies for PV

Improvements in cell efficiencies driven by advancements in material science and semiconductor processing. The highest-efficiency research cell was achieved in 2010 in a multi-junction concentrator, at 42.3% efficiency. Source: National Renewable Energy Laboratory. (2011). Best Research-Cell Efficiencies. Golden, CO. Accessed at http://www.nrel.gov/ncpv/images/efficiency_chart.jpg
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$100

$10

$1

$.10

Global Module Average Selling Price (2009 $US/Wp

)

c-Si CdTe

1 10 100 1,000

CUMULATIVE PRODUCTION VOLUME (MW)

10,000 100,000 1,000,000

Figure 48. Solar PV Experience Curves 

Leading Technologies: Crystalline Silicon (c-Si), Cadmium Telluride (CdTe) Source: (CdTe) Adapted with permission from 

(CdTe) First Solar Earnings Presentation, SEC Filings; (c-Si) Navigant, Bloomberg NEF, NREL internal cost models.

Since the 1970s, engineering and manufacturing scale have been bringing down manufacturing costs. Historically, for every doubling of cumulative production capacity, the PV industry has experienced a 16%–20% 

reduction in cost. In turn, the price of PV modules has declined significantly; the price of c-Si modules has fallen 

from $3.80/Wp in 1999182 to $1.95/Wp. in 2010,183 reaching $1.05/W in the fourth quarter of 2011.184 The 

price of thin-film modules has fallen from $3/Wp, reaching a spot price of $0.85/Wp in the fourth quarter of 

2011.185 

Even with reduction in costs to date, roadmaps agree that there are significant improvement opportunities in 

both the near and long term.

Pathways for PV Technologies

Three categories of PV cells are used in today’s commercial PV modules: c-Si, thin films, and multi-junction PV. 

The c-Si category, which includes monocrystalline and multicrystalline PV cells, dominates the global market, 

accounting for about 86% of globally manufactured PV in 2010. These cells produce electricity via c-Si semiconductor material derived from highly refined polysilicon feedstock. Thin films have the second largest market 

share, accounting for 13% of shipments in 2010.186
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Silicon, the base material of c-Si cells, is a highly abundant benign raw material with well-understood physical 

properties. The cost of refined silicon is a significant contributor to overall manufacturing costs. Monocrystalline 

cells, made of single silicon crystals, are more efficient than multicrystalline cells, but they are more expensive 

to manufacture. 

Thin-film PV technology produces electricity via extremely thin layers of semiconductor material made of CdTe, 

CIGS, a-Si, or copper indium diselenide (CIS). Thin-film technology uses very little active material and has a relatively inexpensive fabrication process, which can make it less expensive on average than crystalline technologies 

on a dollar per watt basis. CdTe is the most common thin-film technology. CIGS technology is transitioning 

from pilot-scale to full-scale production as a number of new manufacturing facilities are coming online. CIGS 

theoretical efficiency is similar to wafer-based silicon, although the current industry average and best lab cell 

are significantly lower. There are also some issues pertaining to toxicity and availability of materials, though 

they are generally believed to not be as significant as with CdTe. Roadmaps include the possibility of using more 

abundant and benign materials. 

a-Si modules, a subset of thin-film PV, are non-crystalline and developed by deposition technologies that use 

significantly less Si than wafer-based modules, although their efficiency (approximately 8%) is significantly 

lower. In addition, the cost of manufacturing a-Si is high relative to its efficiency. a-Si can be manufactured with 

a flexible form factor and has been demonstrated as a potential building integrated PV product, although this 

niche is also being targeted by CIGS manufacturers. 

Multi-junction cells use multiple layers of semiconductor material (from group III and V elements of the periodic 

table of chemical elements) to absorb and convert more of the solar spectrum into electricity than is converted 

by single-junction cells. Current multi-junction cell efficiencies are above 40%. Combined with light-concentrating optics, known as concentrating photovoltaics (CPV), and sophisticated sun-tracking systems, these cells 

have demonstrated the highest sunlight-to-electricity conversion efficiencies of any PV technologies; however, 

the cells have a higher cost per watt than c-Si and thin film technologies, to date. Currently, multi-junction cell 

technology is scaling from pilot to full-scale production. 

Reliability, Risk, and LCOE

The current industry norm for warranty lifetime is 25 years, with some going up as high as 30 years. A long lifetime is critical to reducing the LCOE, and reliability testing is critical to understanding the warranty and financing risks. Since c-Si technology has been under development for more than 30 years, failure mechanisms are 

well understood and reliability tests are well documented for this pathway. The failure mechanisms for thin-film 

technologies are moderately understood; although the recent reliability results for current technology (glassglass sealed packaging) are quite good, more work needs to be done to verify testing protocol and long-term 

reliability prediction. The first lifetime tests for concentrating PV systems are being undertaken, predominantly 

in the United States and Spain. Maintaining research in reliability testing is especially critical as the technologies 

and their manufacturing processes continue to evolve.

Thin-film, c-Si, and concentrating PV technologies perform differently, depending on environmental conditions. 

For example, humid environments tend to expose weaknesses in thin-film encapsulates. However, at high 

temperatures, thin-film technologies tend to perform closer to their rated power than crystalline technologies. 

Concentrating PV requires more direct sunlight, while non-concentrating PV takes advantage of diffuse and 

direct light. 
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Balance of System

Balance of System (BOS) comprises the non-module, non-inverter components and procedures required to 

produce a complete PV system. “Hardware” BOS elements include such items as support structures (including trackers), mounting hardware, wiring, racking, and monitoring equipment. “Soft” BOS elements include 

system design and engineering, customer and site acquisition, installation, permitting, interconnection, inspection, financing, contracting, and local regulatory costs.

For fixed-axis utility-scale systems based on standard silicon modules, non-hardware BOS costs account for 

roughly 30% percent of installed prices today.187 Nevertheless, significant variation can exist due to site and 

project specific parameters, including local regulatory costs, site preparation requirements, regional wage rates, 

system architecture, and proximity to transmission infrastructure. Increased module efficiency reduces BOS 

costs on a per watt basis by requiring less land, racking hardware, and installation labor.

There are BOS differences between utility-scale and distributed PV applications. Utility-scale PV is typically 

ground-mounted, while distributed PV is roof-mounted. Depending on localized factors, rack mounting can be 

used for both ground-mounted and roof-mounted systems. However, land requirements, along with greater 

permitting and siting regulatory compliance, are BOS elements unique to utility-scale PV.

Tracking the Sun III, a review of installed PV costs in the United States by Lawrence Berkeley National Laboratory, shows that implied BOS costs188 fell by $2.5/W (40%) from 1998–2009.189 Please note that for the 

purposes of the analysis, the inverter was also included in BOS, along with such items as mounting hardware, 

labor, permitting and fees, shipping, overhead, taxes, and installer profit. Average installed cost varied by as 

much as 63% across countries in 2009 ($4.70/W in Germany versus $7.70/W in the United States).190 With average prices for both modules and inverters varying by significantly less, local factors included in soft BOS (e.g., 

permitting requirements, labor rates, and sales tax exemptions) strongly influence PV system costs.
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Pathway R&D Opportunity

c-Si

• Development of thinner or kerfless wafers 

• Development of electroplating methodologies that solve adhesion problems

• Development of laser-based techniques to allow for improvements in device 

manufacturing 

a-Si

• Development of an organic/a-Si device architecture to increase device efficiency via upconversion

• Development of a nanocrystalline-Si/amorphous-Si device architecture to exploit hot 

carrier collection for increased efficiency

• Development of an organic/a-Si device architecture, without a p-n junction, to increase 

device efficiency

CdTe

• Development of transparent conductive oxides with high conductivity, transparency, and 

environmental stability 

• Improvement of alternative superstrates that provide low Fe glass transparency 

• Improvement of continuous, all dry processing, substrate approach (roll-to-roll)

• Increased photocurrent generation

CPV

• Declined mirror cost through reduction in material inputs (e.g., stainless steel) and 

development of non-metal reflectors (e.g., polymers and emissive nanoparticles)

• Increased module efficiency through improved triple junction and novel 4+ junction 

modules

• Advanced computer algorithms and sensing materials to improve tracking systems

CIS/CIGS • Development of a highly efficient, wide bandgap CIS/CIGS technology 

• Development of alternative electron collection layers

R&D Opportunities

Table 35 and 36 highlight PV research opportunities by technology and value chain component.

Table 35. PV R&D Opportunities by Technology
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Value Chain 

Component R&D Activity

Module

• Increase efficiency through high Voc (open-circuit voltage), Isc (short-circuit 

current), and FF (fill factor) while reducing recombination

• Reduce raw material inputs to decrease manufacturing costs 

• Develop earth abundant absorbers for thin films

• Develop solution-deposited metal oxides for back contacts for thin films

• Improve transparent conducting oxides to decrease losses from series 

resistance

• Reduce module costs through manufacturing scale-up

• Develop passivation techniques to allow for use of lower-cost metals as 

contacts

Inverter • Increase reliability and lifetime

• Reduce losses from string mismatch with advancements in power monitoring

Hardware BOS

• Streamline hardware integration through innovations in building integrated PV 

• Facilitate the development of new building code language that will enable 

safe, low-cost, high-reliability designs

Soft BOS

• Facilitate development of model codes and standards that offer improved 

effectiveness in supporting PV deployment while ensuring safety, reliability, 

and performance by developing new solar power generation models to 

evaluate protocols for grid interconnection and safe and reliable equipment 

operation

• Develop IT solutions to support the solar industry in working with authorities 

that have jurisdiction, support local jurisdictions in streamlining permitting 

process, and provide transparency to the solar industry as a whole

• Investigate and communicate policy and regulatory barriers, as well as utility 

business and operational challenges acting as barriers that limit the size of 

the U.S. solar market

Resource Potential

The U.S solar resource suitable for PV is both excellent and geographically widespread; across the United 

States, the solar resource ranges over approximately 1,000–2,500 kWh/m2/yr. Germany, which currently has 

the world’s largest installed PV capacity, has a solar resource comparable to that of Alaska on an annual basis. 

The total U.S. land area suitable for PV, including rooftops, is significant and is not expected to limit PV deployment. In addition, the fact that PV can be installed on dedicated land, commercial rooftops, or residential 

rooftops creates significant technical potential for both large-scale and distributed PV installations. 

Table 36. PV R&D Opportunities by Value Chain Component
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Technology Potential

In 2010, DOE held workshops with industry and other stakeholders to develop a roadmap to reach the goal 

of $1/W installed price of utility-scale PV systems, $1.25/W for commercial systems (200 kW), and $1.50/W 

for residential (5 kW) systems by 2017.191 Because the PV module is only one of the factors in installed system 

price, these goals require innovation on the installed system as a whole, including technical and non-technical 

barriers to installing and integrating solar energy into the grid. 

Pathways for Cost Reduction: Module production costs vary by technology and manufacturer. For example, 

while cost leaders for c-Si modules have cited prices as low as $1.05/W, this manufacturing cost is not representative of all manufacturing processes, products, and financial assumptions.192 Typical module prices in 2010 

were about $2/W.193 In order to increase deployment of PV technology, the industry will not only need to dramatically reduce module cost, but also reduce costs across the entire PV value chain (inverters, hardware BOS, 

soft BOS). A combination of advancements, ranging from manufacturing processes to installation, is required 

to achieve significantly reduced installed system costs. 

Key barriers to advancing PV performance and cost declines can be characterized into two areas: cost drivers 

(materials, fabrication, and quality control) and efficiency improvements (short-circuit current, open-circuit voltage, and fill factor). For c-Si cells, decreasing manufacturing costs through reduced raw material inputs (i.e., 

thinner or kerfless wafers) will be a main driver of PV cost reduction. Additional cost reductions can be achieved 

through the use of alternate, lower-cost contact materials, as well as through improved quality control. Concurrently, increasing the efficiency of commercial cells will also reduce cost over time.

For thin films, manufacturing cost reduction can be achieved through lower-cost substrates, more abundant 

materials, and increasing roll-to-roll processing speed. Alongside improvements in manufacturing, efficiency 

gains will be achieved through several pathways, such as the use of higher band gap buffer layers, monolithic integration, and improved transparent conducting oxides. Future improvements to CPV technologies will 

involve the ability to maintain high device efficiencies with even higher levels of sunlight concentration and 

concomitant higher temperatures. For BOS, cost reduction can be achieved through advancements such as 

building integrated PV that requires less hardware and mounting, as well as streamlining permitting processes. 

Continued R&D, coupled with declines in soft costs spurred by market barrier reduction, is expected to enable 

wide-scale PV adoption (Table 37).
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Technology Drivers

CostReduction 

Potential

Technical 

Risk Pathways

c-Si

Wafers High Medium

Thinner or kerfless wafers, 

continuous Czochralski 

crystals, or epitaxial film 

approaches

Contact materials 

(silver and aluminum 

paste)

High Low

New pastes and/or 

deposition methods with 

lower-cost earth abundant 

materials

CIGS

Materials cost and 

availability (indium, 

selenium, cadmium)

High Medium

Thinner layers or 

replacement with earth 

abundant and benign 

materials (e.g., copper zinc 

tin sulfide, zinc sulfide)

Transparent conductors High Low

Indium tin oxide alternative 

materials and/or 

deposition methodologies

Large-scale spatial 

uniformity and improved 

throughput with same or 

lower cost of capital

High Medium

Improved In-situ metrology, 

thermal control, and 

elimination of chemical 

bath cadmium sulfide

CdTe

Glass cost, thermal 

properties, and 

transparency

High Medium

Alternative superstrate 

approach that provides low 

iron glass transparency 

(currently $8.5/m2 vs. 

$2.5/m2 for soda lime) 

or alternative substrate 

approach

Transparent conductive 

oxides (TCO)/buffer 

layers

High Medium

Develop TCO with high 

conductivity, transparency, 

environmental stability 

(e.g., AZO, FTZrO)

In-line step processing 

for better throughput Medium Low

Continuous, all-dry 

processing, substrate 

approach (roll-to-roll)

Multi-Junction

High cost of single 

crystal substrates 

(gallium arsenide, 

germanium)

High Medium

Metamorphic growth on 

silicon, direct deposition 

on foil, lift-off and 

regrowth/substrate reuse

Table 37. PV Cost Drivers and Pathways to Cost Reduction with the Greatest Potential 

 by Technology
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Power Electronics

Power electronics include inverters—which convert DC electricity produced by the PV module into alternating 

current electricity used by the grid—and transformers—which step the electricity up to the appropriate voltage. These are often combined into a single integrated device and referred to as the inverter. Specific power 

electronics strategies include the following:

•	 Increase inverter efficiency (from 95% to greater than 98%), reliability (from a 10- to 20-year lifetime194), and improve module peak power management.

•	 Replace traditional electrolytic capacitors and magnets with high-frequency, solid-state circuits and use 

advanced magnetic materials to reduce size and cost and increase operational lifetime. 

•	 Integrate wires and components to minimize electrical connections. Integrate micro-inverters into 

modules, thereby reducing installation effort, maximizing system power output, and achieving further 

cost reductions through mass production.

Emerging PV Options 

A number of other PV technologies with the potential for improved efficiency, durability, and cost over current technologies—frequently referred to as third-generation PV—are being developed, but have associated 

technical risks. Dye-sensitized solar cells, which use dye molecules adsorbed onto a nanostructured substrate 

and immersed in a liquid or gel electrolyte to absorb solar radiation, have demonstrated laboratory efficiencies 

as high as 12%. Organic solar cells, based on polymers or small molecules with semiconductor properties, have 

demonstrated laboratory cell efficiencies above 8%; organic modules have the potential for low-cost manufacturing using existing printing and lamination technologies.195 Quantum dots—nanospheres with physical 

properties similar to both semiconductors and molecules—absorb solar radiation at multiple frequencies, but 

they have not yet been used to produce efficient PV cells.

Challenges to the commercialization of these technologies include the stability of the materials against oxygen 

and water ingress, which could potentially be overcome by developing improved, cost-effective encapsulants. 

Alternatively, for organic solar cells, materials exist that are stable in air and can be deposited under a small 

vacuum or in a solution. Further R&D is needed to improve the efficiency of materials for these emerging technologies. 

Factors that Affect Market Prospects

Even when technical issues are addressed, companies commercializing new PV technologies must address 

significant market challenges, including both manufacturing scale-up and demonstration of product reliability. 

The scale-up of manufacturing requires significant investment capital–amounts larger than typical venture 

capital and at risk levels higher than traditional equity or debt financing. In addition, validation of new PV technologies to reduce risk may require testing of standard products by an independent third party for 1 to 2 years.
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To enable greater grid penetration by solar technologies, real and perceived risks to grid operations and stability 

need to be addressed. These include: 

•	 Impacts on voltage and current flows, voltage regulation, reactive power flow, and system protection

•	 Integrating variable and uncertain solar generation into grid operations and planning

•	 Unfamiliarity of grid operators with PV system designs and their operating characteristics

•	 Inadequate accounting of capacity and energy valuation from variable renewable energy and energy 

storage technologies in traditional utility rates and costing methods

•	 Risk and uncertainty that surrounds predicting the availability of solar resource on a small-time and 

spatial scale. 

For more information about energy storage, see the Grid Storage technology assessment.

Hardware and soft BOS costs—independent of module technology costs—must also be reduced to enable 

market growth for PV. Companies face high soft BOS costs when deploying systems, including complex and 

varied permitting and interconnection processes, along with barriers such as access to transmission lines for 

utility-scale systems. Other market barriers include interconnection or net metering caps, legal restrictions on 

financing mechanisms, and siting restrictions.

The economics of solar PV are aided by the fact that PV generation peaks at the same time as electricity demand; as a result, its price is highest. Reaching ‘grid parity’ with conventional electricity generation will not 

occur at one particular point in time, but will instead occur at differing price points across the United States. 

Indeed, in areas with high solar resource and high electricity prices, residential solar PV electricity is currently at 

parity with conventional electricity.196

The traditional consumer of electricity generation equipment is a company dedicated to generating and selling 

electricity. Although this is sometimes the consumer of PV systems, the consumer base is much broader and 

includes all electricity consumers–both at the household and company level. For some of these non-traditional 

consumers who are used to buying electricity on a monthly basis, financing the upfront investment of buying 

electricity-generating equipment can potentially be challenging.

PV technologies use a number of materials that could be subject to shortages or demand-driven price increases 

at high production levels, including tellurium, indium, selenium, gallium, germanium, ruthenium, copper, silver, 

and molybdenum; the biggest concerns are tellurium and indium. One or more of the following strategies could 

help avoid potential material shortages for any of the PV technologies: increased efficiency (using less material 

per delivered watt); reduced material use through thinner layers; improved process utilization and in-process 

recycling; recycling at the end of module life; increased efficiency and amount of ore extraction and refining; 

and shift to materials that are more abundant. For more information, see the DOE Critical Materials Strategy.197

Market and Policy Context

In 2000, the United States accounted for 30% of global PV shipments, but then lost market share over the 

next decade—first to Japan, then to Germany, and finally to China and Taiwan.198 In 2010, China and Taiwan 

accounted for 53% of global PV shipments.199
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In the 1980s, U.S. and global PV demand was dominated by off-grid applications, typically very small systems 

with installed capacities measured in hundreds of watts. During the late 1990s, grid-connected systems—with 

installed capacities measured initially in kilowatts and later in megawatts—began dominating global demand. 

As this transition occurred, system cost declined significantly owing to a combination of R&D advances and 

economies of scale on the production and installation sides. In the United States, the transition to a market 

dominated by grid-connected systems occurred slightly later, driven by state and federal incentives. 

Two of the major federal policies impacting PV installations are the 30% investment tax credit and the 5-year 

accelerated depreciation (modified accelerated cost-recovery schedule). At the state and local levels, policies 

impacting PV include net-metering and interconnection rules, regulations regarding third-party financing models, RPS, performance-based incentives, and tax benefits.200 

Historically, California has been the strongest state market for PV. The California Solar Initiative, enacted in 

December 2005, provides solar rebates for California consumers that are customers of investor-owned utilities. 

California continues to encourage solar and other renewable energy technologies through various policies, 

including a strong RPS, a diverse portfolio of incentives, and utility involvement. Other U.S. markets that have 

grown significantly during the past few years are Arizona, Colorado, New Mexico, New Jersey, New York, and 

Nevada. In 2010, California represented 28% of new installations, with 16 states installing more than 10 MWDC

of PV.201 

50% 16,000

14,000

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10%

0%

19971998199920002001200220032004200520062007200820092010

U.S. Market Share 

PV Module Shipments (MW)

REST OF WORLD CHINA & TAIWAN EUROPE JAPAN U.S.

YEAR

Figure 49. U.S. Solar PV Market Share

Source: Adapted with permission from Navigant Consulting. (2011). Photovoltaic Manufacturer Shipments, Capacity 

& Competitive Analysis 2010/2011. Original report can be purchased from http://www.navigant.com/~/media/site/

downloads/energy/manufacturer_shipments_report.ashx
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DOE History and Accomplishments

Since 1975, investments made by the Department (see Figure 50), along with direct DOE-industry partnerships, 

have made significant contributions to the development of PV technology and markets. These investments 

include those that were made under four major programs—Flat-Plate Solar Array Project (1975–1985), PV 

Manufacturing Technology Project (1991–2008), Thin-Film PV Partnerships (1994–2008), and Measurement, 

Characterization, and Reliability R&D (1975–present). According to a retrospective benefit-cost evaluation, DOE 

investments of cost sharing, technical expertise, and technology infrastructure greatly contributed to declining 

production costs—without these investments, module cost per watt in 2008 (2008 dollars) would have been 

slightly more than $5, as opposed to the actual cost of nearly $2202 (see Figure 51). Similarly, DOE investments 

have accelerated the introduction of warranties (currently 25 years) into the marketplace.

150

120

140

130

80

90

100

110

70

60

50

40

30

20

10

0

Annual Budget Appropriations to Solar PV

(2010 $million)

198519901995200020052010

FISCAL YEAR

Figure 50. Historical DOE Solar PV Budget

Budget Sources: (1985–2000) Current Congressional Appropriations from DOE CFO, Office of Budget; (2000–2002,) 

DOE CFO, Office of Budget (http://www.cfo.doe.gov/budget/02budget/es/solar.pdf); (2003–2008) DOE EERE Budget 

Office (http://www1.eere.energy.gov/ba/pba/budget_archives.html); (2009–2010 excluding 2009 ARRA funds) 2011 

FY11 Congressional Budget for DOE EERE (http://www1.eere.energy.gov/ba/pba/pdfs/fy11_budget.pdf). Converted to 

2010 $million using consumer price index from the Department of Labor, Bureau of Labor Statistics (ftp://ftp.bls.gov/

pub/special.requests/cpi/cpiai.txt).

Along with the above contributions, DOE-funded laboratories have made continuous improvements in cell efficiencies across technologies (see Figure 47). 
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$100

$20

$10

$2

$1

19761978198019821984198619881990199219941996199820002002200420062008

Production Cost Per Watt (2008$)

COUNTERFACTUAL COST CURVE WITHOUT FSA, PVMaT, OR TFP

ACTUAL WEIGHTED AVERAGE COST CURVE

YEAR

Figure 51. Annual and Counterfactual PV Module Production Cost per Watt Curves (2008$)

Counterfactual analysis provides an estimate of the circumstances that would have prevailed had a new policy or 

policy change not been introduced. These analyses help to retroactively attribute causality to a specific program or 

initiative. Source: RTI International (Alan C. O’Connor, Ross J. Loomis, and Fern M. Braun). (2010). Retrospective 

Benefit-Cost Evaluation of DOE Investment in Photovoltaic Energy Systems. Washington, DC: Department of Energy. 

Accessed at http://www1.eere.energy.gov/solar/pdfs/pv_evaluation.pdf

The DOE Solar PV Subprogram launched at least five research initiatives between 1975 and 2009, all of which 

entailed the formation of direct contractual relationships between DOE and companies to advance solar PV 

technology. More than 160 different companies have participated in DOE PV partnerships. Many of the established DOE-industry partnerships have resulted in patents and publications, in addition to prototype devices, 

systems, processes, test data, and demonstrations.203

DOE Role

The Department is not only investing in informational and capability activities for solar PV, but is also investing 

in targeted initiatives. The SunShot initiative is a good example of this. Through SunShot,204 the Department has 

set ambitious goals ($1/W utility, etc.) and is leading a coordinated effort to meet those goals. The Department 

is partnering with industry and academia to support promising technologies across the supply chain toward 

achieving the goals. In addition, DOE maintains core capabilities in applied R&D on PV technologies, including 

testing facilities. 
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CLEAN POWER

WATER POWER

There are two major ways to convert water power into electricity: conventional hydropower (CH) and a range 

of emerging marine and hydrokinetic (MHK) technologies. This assessment treats them separately.

Conventional Hydropower and Pumped Storage Hydropower

The total installed capacity of U.S. hydropower facilities is approximately 100 GW, including 78 GW of conventional and 22 GW of pumped storage hydropower (PSH; for more information about PSH, see the Grid Storage 

technology assessment). In 2009, hydropower accounted for nearly 8% of U.S. net generating capacity and 

more than 60% of the Nation’s renewable electricity generation.205 In 2009, hydropower accounted for 7% 

of U.S. electricity generated. For more information about PSH, see the Grid Storage technology assessment.

The Corps of Engineers and Bureau of Reclamation operate and maintain 21.6 GW and 15.1 GW of installed 

hydropower capacity, respectively. Energy produced at these federal facilities is marketed by four power marketing administrations: Bonneville, Western, Southwestern, and Southeastern. The Tennessee Valley Authority 

operates, maintains, and markets energy produced from 5.4 GW of installed hydropower capacity. Investorowned utilities, state utilities, and local public utilities own, operate, and market the remaining 57 GW. Installation costs for much of this capacity have been amortized over historical production. Overnight capital costs 

are highly site-specific. An Energy Information Administration estimate for a reference plant is overnight capital 

cost of approximately $3,100/kW206 and LCOE of $0.08/kWh;207 O&M costs ranged from $4.7–$9.7/MWh over 

the time period of 1999 to 2009.208 

In 2008, hydropower accounted for just over 16% (3,288 terawatt hours [TWh])209 of worldwide generation; it was approximately 21% of capacity (723 GW) in 2010.210 As of 2006, China is the largest producer of 

hydroelectricity (431 TWh per year), followed by Canada (352 TWh per year), Brazil (345 TWh per year), and 

the United States (289 TWh per year). Norway is a leader among developed nations in using CH to meet the 

country’s electricity needs, generating 98.9% from hydropower in 2006. Many nations with developing economies, including Bhutan, Mozambique, and Paraguay,211 rely on hydropower to provide more than 99% of their 

electricity due to the availability of the resource and limited demand. 

Figure 52 illustrates the slowing of U.S. capacity growth since the 1970s. Worldwide hydroelectricity production growth has occurred largely in Asia and Latin America in the last 40 years.212 

Hydropower projects are currently under construction in about 80 countries. Several nations, including China, 

India, Iran, and Turkey, are undertaking large-scale hydropower development programs. 
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100

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194919521955195819611964196719701973197619791982198519881991199419972000200320062009

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YEAR

Figure 52. U.S. Installed Capacity of Conventional Hydropower, 1950–2010

Source: Energy Information Administration. (2011). Annual Energy Review 2011, Table 8.11a Electric Net Summer 

Capacity: Total (All Sectors), 1949-2010. Washington, DC: Department of Energy. Accessed at http://www.eia.gov/

totalenergy/data/annual/showtext.cfm?t=ptb0811a

Hydropower Deployment in the United States

In the 1700s, Americans used mechanical hydropower extensively for milling and pumping. The first U.S. hydroelectric power plant opened on the Fox River near Appleton, Wisconsin, in 1882. Niagara Falls was the first 

American site developed for major hydroelectric generation and remains a source of electric power today. By 

the early 1900s, hydroelectric power accounted for more than 40% of the Nation’s generation. In the 1940s, 

hydropower provided about 75% of all the electricity consumed in the West and Pacific Northwest and about 

one-third of total U.S. electrical energy.213 With the rise of other generation technologies, hydropower’s share 

has slowly declined and today provides about 7% of the Nation’s electricity. 

The early hydroelectric plants were DC stations built to power arc and incandescent lighting from about 1880 

to 1895. The advent of the electric motor spurred demand and hydroelectric design rapidly changed, with 

deployment of a wide variety of plant styles between 1895 and 1915.214 Hydroelectric plant design became 

fairly standardized after 1920. The Nation’s soaring electricity demand drove rapid expansion in hydropower 

generation capacity. Between 1921 and 1940, CH capacity in the United States tripled and almost tripled again 

between 1940 and 1980.215 Since 1980, the development of new hydropower has slowed due to the high cost 

of sustainable hydropower development compared to other generation sources, increased regulation, competing uses of water, and public concerns about the environmental effects of hydroelectric dams; however, there 

is potential for further expansion through modernizing existing hydropower facilities, new technologies, and 

adding generation to existing non-powered dams.
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Status of the Technology

Modern hydropower turbine-generators have mechanical-electrical efficiencies greater than 92%.216 Innovations in metal alloys, mechanical bearing design, and lubrication technologies allow the machines to run reliably 

and efficiently. However, there are increasing demands for dispatch flexibility—operation significantly above or 

below design flow rates and pressures, and increased frequency of stops and starts—with uncertain impacts 

on O&M costs and reliability. In anticipation of increasing deployment of wind and solar power, hydroelectric 

industry stakeholders are beginning to study the linkages between increased dispatch flexibility and O&M 

costs.217

Just over half of U.S. hydropower capacity is Francis turbine technology (fixed-blade, shrouded water wheel), 

which exhibits a relatively steep tradeoff between dispatch flexibility and efficiency and operating costs.218

Auto-aerating Francis turbine technology, which can mitigate water quality (dissolved oxygen) deficiencies in 

water releases, is available from multiple turbine equipment vendors. Outcomes of first- and second-generation 

aerating technology have been successful thus far, but limited to upgrades of major facilities by large electric 

utilities that have been able to accommodate the risks and incremental costs of the new technology. Francis 

turbines are generally assumed to be unsuitable as a fish passage alternative. 

Kaplan turbine technology (adjustable blade propeller) provides roughly one-fifth of U.S. hydropower 

capacity.219 Kaplan turbines provide dispatch flexibility with relatively minor decreases in efficiency. However, 

Kaplan technology is applicable primarily to large rivers with low-to-moderate hydraulic head (typically 100 

feet or less). A limited number of advanced “fish-friendly” Kaplan turbines have been successfully deployed on 

the Columbia River (Washington), but the site-specific and species-specific costs of verifying “fish-friendliness” 

have limited application to large federal operators and public utilities that can accommodate the technical and 

financial risks. The mechanical and hydrodynamic complexity of adjustable blade designs has stymied the development of auto-aerating technology for Kaplan turbines, although such technology would have application 

if it was available as an alternative to more expensive water quality improvement technology. 

Small hydropower facilities use a variety of turbine technologies. High-head, low-flow sites generally find 

lowest-cost using Pelton turbine technology (water jets drive the turbine at atmospheric pressure) or other 

medium-to-high head technology without the need for new dam construction. At the other extreme, new 

low-head, low-power sites must use higher-cost and/or lower-efficiency turbine-generator technologies, and 

require relatively expensive civil works to guide water into powerhouses and through large diameter, high-cost, 

low-speed turbines. 
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Future Deployment Potential

The Electric Power Research Institute (EPRI) has estimated as much as 60 GW of new hydropower could be 

developed.220 In comparison, updated resource assessments by DOE’s Water Power Program estimate that 

development of new CH assets can occur across four classes, which are listed here in approximate order of 

increasing cost: 

•	 16 GW of new capacity through expansion or upgrade at existing hydropower facilities221 

•	 12.6 GW of new capacity through the addition of hydropower facilities at non-powered dams222 

•	 Harvesting unused energy within constructed waterways and water distribution systems 

•	 Developing new hydropower sites. 

The resource potential across the United States at undeveloped sites is more than 100 GW;223 however, developing most of this potential is contingent on significant capital investment, as well as other factors such as the 

availability of advanced turbine and environmental mitigation technologies. 

Technology Potential

There are opportunities to reduce hydropower LCOE through better water utilization and reduced technology 

costs. The Energy Information Administration estimates that capital costs for a new reference hydropower plant 

are approximately $3,100/kW.224 However, hydropower costs are highly site-dependent and can range from 

more than $5,000/kW for very low-head projects225 to less than $1,500/kW226 for modernization of existing 

sites. Advances in water utilization will require new machine designs and materials that provide generation 

and capacity reliably and sustainably over wider operating ranges, with more intense duty cycles. New and 

improved environmental mitigation technologies would enable hydropower facilities to use more of the water 

in rivers, rather than being required to bypass flows. Advanced control and decision support systems for powerhouses would improve overall long-term system efficiencies. 

Technology costs can be reduced through advances in construction, manufacturing, and materials that will decrease capital and maintenance costs for hydropower equipment and civil structures. In particular, development 

of modular technology for in-stream civil structures and electrical interconnection would reduce those costs for 

small hydropower deployment. Continued evolution of environmental mitigation technologies would reduce 

their costs and uncertainties and increase stakeholder acceptance, with the potential for dramatic reductions in 

licensing and compliance costs for new and upgrading facilities. These opportunities are currently under intense 

study as the Department initiates formal technology roadmapping development.227

The major factors driving future deployment, particularly of small and low-head hydropower facilities, will likely 

be cost and environmental performance. Costs are generally higher for lower-head hydropower installations 

because greater flow is required to achieve a given capacity. This increases the turbine runner size, which raises 

the direct costs of manufacturing and transporting the runner, as well as structural and construction costs. 

Environmental performance can also raise cost because mitigation technologies and strategies, such as the bypass of flow for fish passage, are necessary for environmental sustainability. The absence of widely-applicable, 

accepted, low-risk, low-cost environmental mitigation technologies is a critical factor in the stagnation of hydropower capacity growth over the last two decades.
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How changing hydrologic patterns might affect future deployment is described in detail elsewhere.228 For example, droughts have decreased the generating performance of the top 10 hydropower-generating U.S. states 

by 1%–28% in recent years (2007–2009) compared to their historical averages.

Factors that Affect Market Prospects

Federal and non-federal hydropower assets employ the same technologies and can benefit equally from technology innovation. However, the financial incentive and regulatory structure that determines the improvement 

feasibility and timing is different. Technology improvements at non-federal assets result from investment decisions of owners who, as for-profit entities, prioritize energy production over competing uses and therefore 

must implement improvements dictated by licensing requirements. Hydropower technology improvements at 

the Corps of Engineers and Bureau of Reclamation facilities result from a complex set of factors, including the 

business objectives of power marketing administration customers and the authorized and appropriated budgets of the Corps and Reclamation. Hydropower production is not typically identified as the top priority for 

capital investments and water management policy. 

The major deployment challenges facing the CH industry are related to technology risk and financial risk. Additional challenges involve non-technical barriers, such as uncertain power resource characterization, regulatory 

risk, environmental risk, and public acceptance.

•	 Capital Costs: High capital costs and long payback period; lack of capital for technology upgrades, 

enhancing or adding CH generation; statutory exclusion from renewable energy markets; licensing 

costs and time for very small hydropower projects are large relative to other costs, making initial explorations for sites risky.

•	 Technology Risk: Lack of data on cost and performance of advanced technologies (e.g., small hydropower, advanced PSH, fish-friendly, and aerating turbines).

•	 Resource Characterization: Water power resource characterization is inadequate to fully understand 

the deployment potential.

•	 Public Acceptance: Project development can raise concerns about potential impacts on species diversity; alternative land uses, such as recreation and farming; and property values.

•	 Regulatory Risk: Risk in not attaining licenses reduces early investment for new development; exposure to reopening existing Federal Energy Regulatory Commission licenses during upgrades that can 

require additional studies and mitigation. 

•	 Environment and Siting Risk: Difficulty of evaluating non-monetary benefits (ecosystem restoration); uncertainty of impacts and the need for new mitigation and environmental protection.

Environmental considerations and regulatory requirements are important factors in new deployment of CH 

technology.229 Minimizing environmental impacts in recent years has resulted in generation and capacity reductions.
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Marine and Hydrokinetic Technologies

MHK technologies convert wave, tidal, ocean current, river in-stream, ocean thermal, and salinity-gradient 

power into electricity. These emerging technologies have potential to provide a low-carbon energy supply for 

many regions of the United States, including the following: 

•	 Ocean wave energy along the Pacific coast (from Point Conception, California, to Alaska) and Hawaii.

•	 Ocean tidal hydrokinetic energy in East and West Coast locations that have narrow passageways between a bay and the ocean (e.g., Western Passage Maine, East River New York, Admiralty Inlet Washington, Golden Gate San Francisco, and multiple locations in Alaska).

•	 Open-ocean current hydrokinetic energy off the Atlantic Southeast coast.

•	 River hydrokinetic energy in most states.

Preliminary estimates indicate that the total MHK resource could potentially supply some 10% of the U.S. demand for electricity, though many factors—such as electrical transmission capabilities, economic viability, environmental concerns, and socio-economic considerations—may impose additional limits onto these resources 

that substantially alter full development potential.230 Much of the U.S. population lives near the coast, and 

ocean wave or tidal current technologies will be located close to these load centers, potentially reducing overall 

transmission needs. Compared to more variable renewable energy sources, ocean thermal, in-stream current, 

and ocean current resources have the potential to provide relatively constant energy, while tidal energy benefits 

from resource predictability. However, as in all generating technologies, many factors beyond resource potential will ultimately determine deployment and impact, most notably cost and scale. LCOE is currently too high 

for MHK technologies to be competitive, and there is uncertainty in the extent to which costs can be reduced 

and potential resources could be exploited.

Current Status 

Globally, installed tidal capacity is about 530 MW, nearly 500 MW of which is from two facilities (one in France 

and one in Korea). Capacity of devices that do not utilize reservoirs is only 5 MW worldwide.231 The current 

installed wave energy capacity is about 3 MW worldwide. These figures are one-millionth the scale of total 

worldwide generating capacity of 4 TW. No ocean thermal energy conversion devices are deployed worldwide, 

and salinity gradient energy converters are only at a laboratory scale.232

The MHK industry is clearly a nascent industry, comprising only 0.005% of global capacity. While a handful of 

projects are deployed now at varying scales, there are no full-scale, multiple-device commercial deployments. 

Europe, particularly the United Kingdom, is leading the development of MHK technologies. Technology development in the United States is accelerating, but requires assessment of technical and economic viability. More 

than 40 different MHK technologies are being pursued in the United States, with individual devices ranging 

from 10 kW to approximately 1 MW. DOE maintains an online technology database of devices being developed 

worldwide;233 they number in the hundreds.

MHK activity has increased during the past 5 years. The number of companies engaging in the industry, as well 

as patent applications filed and patents issued have increased substantially each year since 2008.234 A number 

of MHK prototype and pilot-scale devices have been installed. 
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Table 38. Description of MHK Technologies

Wave Technologies

Absorbers

The movement of a buoy, relative to the ocean floor with the rise and 

fall of waves, is converted to electrical energy through a linear or rotary 

generator.

Attenuators The relative motion of the device (when oriented parallel to the incoming 

wave) drives a generator as the wave passes.

Oscillating Water Columns

A partly submerged structure (‘collector’), which is open to the sea 

below the water surface so that it contains a column of water. Air is 

trapped above the surface of the water column. As waves enter and 

exit the collector, the water column moves up and down and acts like 

a piston on the air, pushing it back and forth. The air is channeled 

towards a turbine and forces it to turn. The turbine is coupled to a 

generator to produce electricity.

Overtopping Devices

Waves lift water over a barrier, which fills a reservoir that is drained 

through a hydro-turbine. Similar to low-head hydro facilities, as they 

convert the potential energy of the elevated water to generate power.

Inverted Pendulum Devices

The surge motion of waves rotates a large hinged paddle back and 

forth. This motion drives hydraulic pumps that then drive electrical 

generators.

Tidal, Ocean, and River Current Technologies

Tidal, ocean, and river current turbines convert the kinetic energy in flowing water into electricity in the 

same manner a wind turbine uses the kinetic energy in wind. 

Axial-Flow Turbines

Two or three blades mounted on a horizontal shaft form a rotor; the 

kinetic motion of the water current creates lift, causing the rotor to turn 

driving a mechanical generator. These turbines must be oriented in the 

direction of flow. There are shrouded and open rotor models.

Cross-Flow Turbines

While similar to axial-flow turbines, cross-flow turbines, however, can 

operate with flow from multiple directions without reorientation. These 

turbines typically have two or three blades mounted along a vertical or 

horizontal shaft to form a rotor.

Articulated Oscillating 

Hydrofoil Generators

The flow of water produces lift or drag of an oscillating part transverse 

to the flow direction, which can be induced by a vortex, the Magnus 

effect, or by flow flutter.
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Wave Technologies

Tidal Barrage

Tidal barrage converts potential energy to electrical energy by allowing large reservoirs to fill during 

high tide and then releasing the water through CH turbines during low tide. This technology is not being 

considered for application in the United States due to detrimental environmental effects.

Ocean Thermal Energy Conversion (OTEC)

OTEC uses the potential energy difference between warm surface seawater and colder deep seawater 

to generate electricity. Open-cycle technologies use the warm surface ocean water as the working fluid, 

which is drawn into a vacuum vessel that causes the working fluid to vaporize, which drives a turbine. 

Closed-cycle OTEC uses a working fluid, such as ammonia, that boils at a lower temperature than water. 

The ammonia is vaporized by the warm surface water, which drives a turbo generator. 

Salinity Gradient

Salinity gradient power generation uses the potential energy available when saltwater and freshwater 

mix. Osmotic pressure drives the freshwater through the membrane to the saltwater side, increasing 

the pressure and the flow in the saltwater channel of the module. The high-pressure, higher-flow rate 

channel is then passed through a turbine to produce electricity.

Technology Potential and Innovations

As MHK technology is nascent, it is likely that significant opportunities to improve cost and performance exist, 

although the extent is not known at this time. It is expected that costs will be reduced over time by a combination of factors, including the following:

•	 R&D on MHK components and systems.

•	 MHK design refinement through extended testing and advanced modeling and simulation.

•	 Economies of scale through deployments of multiple devices instead of the current, predominantly 

singular device deployments.

•	 Advances in production methods as developers shift toward larger production runs. 

•	 Refinement of O&M and capital expense estimates after extended testing of full-scale devices.

Devices must survive the harsh marine environment and maximally extract energy from the resource. R&D of 

MHK can leverage some past investments in wind technology, offshore oil and gas expertise, and the accumulated knowledge in naval architecture. In some cases, project sites are extremely harsh environments and have 

forced innovation in device deployment and recovery methods. The high density of water (800 times denser 

than air) means that there can be significant energy transfer to the device, but device developers are challenged 

to ensure that this occurs in a controlled manner. 

Most of the innovation in the sector is focused on refining existing devices and improving design tools, performance prediction, and cost modeling methods to move from proof of concept to a commercializable device. 

The following areas have shown the most recent development:
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•	 Computational Codes: There has been significant innovation in the development and adaptation of 

computational design tools to model fluid flow. Refinements of existing computational fluid dynamics 

codes (many developed by the wind industry) can support the next generation of MHK devices. An 

emergent area is using advanced modeling tools to predict the performance of an array of devices, 

both the interactions among devices and the environmental impacts of the array.

•	 Innovative Power Take-Offs: Power take-off (PTO) is a broad category of MHK device components 

that convert mechanical motion to electrical energy. Some PTOs are intermediaries that convert oscillating motion to rotary motion that is suitable for a conventional generator, and some are integral to 

the device. Improvements in PTO efficiency directly impact the power output, reliability, and cost of 

MHK devices. Several R&D efforts for PTO are underway, ranging from direct-drive, rotary designs to 

the use of magnetorestrictive alloys. Reverse magnetostriction offers the possibility of converting the 

strain on MHK mooring tethers directly into electricity with no moving parts.

•	 Manufacturing: MHK devices today are produced only in small numbers, and developers are actively 

pursuing techniques and design methods that will support the cost-effective production of multiple 

devices. Tools and techniques developed at composite boat builders, national laboratories, and in 

other industries are helping to accelerate that process. Developers are beginning to tap into automotive manufacturing expertise to ascertain the production scalability of their designs. Many have also 

used rapid prototyping to accelerate the design process. 

To move into commercialization, the MHK industry needs to reduce technology risk related to performance 

uncertainties for each technology.

DOE History and Accomplishments

Conventional Hydropower

DOE’s involvement with the hydropower industry dates back to the late 1970s and a Small Hydropower Demonstration Program that was established as part of a growing focus on renewable energy. DOE’s early focus 

was on small hydropower technology assessment, resource assessment, and analyses of environmental and 

policy issues. In 1993, emphasis of DOE’s hydropower activities began to shift toward enabling new turbine 

technologies that would reduce environmental impacts to make the hydropower industry more competitive. 

That work was temporarily halted in 2006 when program funding was zeroed out, but it was restarted in 2008 

(Figure 53). 
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55

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Annual Budget Appropriations to Hydropower

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Figure 53. Annual DOE Budget for Water Power

Sources: (1985–2002) Current Congressional Appropriations from DOE CFO, Office of Budget; (2003-2008) DOE EERE 

Budget Office (http://www1.eere.energy.gov/ba/pba/budget_archives.html); (2009–2010) 2011 FY11 Congressional 

Budget for DOE EERE (http://www1.eere.energy.gov/ba/pba/pdfs/fy11_budget.pdf). Converted to 2010 $million 

using consumer price index from the Department of Labor, Bureau of Labor Statistics (ftp://ftp.bls.gov/pub/special.

requests/cpi/cpiai.txt).

Some of DOE’s recent accomplishments include:

•	 Installation and testing of an advanced, fish-friendly Kaplan turbine that has both energy and environmental benefits (14% more energy with a 3% increase in water-use efficiency, plus fish mortality of 

less than 3%) at the Wanapum project.235

•	 Installation and testing of new turbine designs that increase dissolved oxygen concentrations in an 

energy-efficient manner at the Osage project.236

•	 Development of an innovative runner with combined energy (greater than 90% conversion 

efficiency237) and environmental benefits (less than 2% fish mortality) called an Alden turbine.238
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Marine and Hydrokinetic

The Energy Policy Act of 2005 authorized DOE to conduct research on all water power technologies, and the 

Energy Independence and Security Act of 2007 called for DOE to establish a program of research, development, 

demonstration, and commercial application activities to expand MHK renewable energy production. 

The United States Marine Hydrokinetic Renewable Energy Technology Roadmap239 is focused primarily on scientific and technical steps to overcome barriers to the widespread use of MHK technologies. Europe has MHK 

expertise and the U.S. roadmap is aligned with similar roadmapping efforts that have been conducted internationally.240 The U.S. Technical Advisory Group of the International Electro-technical Commission Technical 

Committee TC-114 assists in the development of international standards for the MHK industry. 

DOE has developed a diverse MHK portfolio. In 2010, DOE awarded more than $37 million over 3 years to accelerate the technological and commercial readiness of MHK technologies. Twenty-seven cost-shared projects 

were funded, ranging from concept studies and component design research to prototype development and 

in-water device testing. National assessments of wave, tidal, ocean current, ocean thermal, and in-stream hydrokinetic resources have also been funded. Three national test centers have been established that will allow 

machine developers to efficiently test devices in a realistic environment. 

DOE has provided technical support or funding to a number of deployed or proposed U.S. projects, including 

the following: 

•	 Wave energy converter in Puget Sound, Washington, controlled remotely from Corvallis, Oregon.241 

•	 River in-stream turbine in the Mississippi River (Louisiana) (40 kW)242

•	 The proposed Admiralty Inlet Pilot Tidal Project . 

The data generated through these demonstrations will illuminate the viability of these technologies and pathways for cost reduction. 

DOE Role

DOE’s contributions in CH center on resource characterization and information dissemination, as well as a 

capability role for fundamental engineering related to reducing environmental impacts. DOE’s role in MHK 

focuses on informational and convening activities. For example, the Department is supporting the introduction 

of a multi-national data-sharing effort that will leverage the current MHK development work in the European 

Union, and is also pursuing bi-lateral data-sharing agreements with Canada (another leader in MHK). In addition, DOE is building a broad understanding of these emerging MHK technologies and facilitating rapid innovation and engineering development. DOE is also leveraging its convening ability to address barriers to industry 

collective action.
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CLEAN POWER

WIND

Global wind power capacity today exceeds 197 GW,243 some 4% of total generating capacity. China leads the 

world with more than 44 GW installed, followed by the United States where more than 40 GW of wind power 

generates 2.3% of the Nation’s electricity.244 Wind power’s potential for providing 20% of American electricity 

has been evaluated by DOE as a technically and economically feasible scenario.245 Higher penetrations would 

be possible if grid transmission and integration barriers could be overcome. A 2007 report prepared for the 

American Wind Energy Association found technical potential of 8,000 GW of land-based resource and 4,000 

GW of offshore resource, although actual deployments will be significantly less.246 The highest-quality U.S. 

wind resources are concentrated in the Midwest and offshore.247

Current Status of Technology

Wind turbine technology has evolved into three major technology pathways, each at a different stage of maturity and deployment (Table 39).

Table 39. Major Wind Pathways

Global 

Deployment

Installed 

Costs (price of 

electricity248)

Turbine Size 

(plant size) Siting Factors

Land-Based

98% of world’s 

wind power, 35 

GW installed in 

2009

$2,120/kW249 

($61/MWh250)

100 kW–3 MW 

(varies)

Wind resource and 

grid access

Fixed Bottom 

Offshore

3 GW, 97% of 

which is in Europe

$4,250/kW251 

($270/MWh252) 

2–5 MW 

(100–400 MW)

Wind resource 

quality, proximity 

to load centers

Floating Platform 

Offshore

No commercial 

installations Unknown Unknown

Significant wind 

resource (>3,000 

GW) in deep water
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Historically, two factors have driven down the cost of electricity from land-based and offshore turbines: larger 

systems (which provide economies of scale) and improved energy capture. Taller towers and larger rotors provide access to better winds and more energy, thereby increasing both resource availability and capacity factor 

(capacity factor, the ratio of average power produced to rated capacity, is typically about one-third for wind 

installations253). Improved turbine energy conversion efficiency has also helped increase annual energy production and capacity factor. These same scaling principals and efficiency improvements are applicable to existing 

technology to further reduce costs. An integrated systems perspective of the entire wind plant that could improve overall performance and mitigate intra-array effects will be necessary to fully realize this potential. 

Floating platform offshore wind has two potential benefits: providing access to significant resources (greater 

than 3,000 GW) in deep water, and allowing mass production of turbine platforms independent of bathymetry 

and foundation design.

Small wind turbines (1–100 kW) can be deployed for distributed generation. There is about 175 MW of small 

wind power in the United States.254 The United States is the world leader in small wind systems, with two-thirds 

(about 18 MW) of the turbines sold globally in 2009 having been manufactured by U.S. companies.255 Since 

small wind is unlikely to be material by 2030 due to economics and quality of the distributed resource, it is not 

addressed in this technology assessment. However, many of the technology innovations discussed in this assessment are applicable to small-scale wind.

140

120

100

60

80

20

40

0

Rotor Diameter in Meters

OFFSHORE LAND BASED

1980 1985 1990 1995 2000 2005 2010 2015

YEAR

50kW

100kW 300kW

500kW

750kW

1.5 MW

2.5 MW

3.6 MW

5 MW

Figure 54. Evolution of Wind Technology

Turbines have steadily increased in size and rated capacity. Source: Department of Energy. (2008). 20% Wind Energy 

by 2030. (DOE/GO-102008-2567). Washington, DC.
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LCOE for wind technologies is higher than current average electricity prices, though in various settings wind 

technologies are economically competitive without subsidies. Unfortunately, there are no good data available 

on the cost of electricity of deployed wind projects; all data are the price paid by utilities, which is depressed 

by federal and state subsidies.256 Both land and offshore wind technologies have potential for LCOE reductions 

through technology development to improve the economics of wind energy.257 Wind technologies must also 

overcome various financial, regulatory, and public acceptance barriers. The principal technology cost drivers 

include:

•	 Installed capital cost of the wind plant system. 

•	 Plant capacity factor and related system annual energy production. 

•	 O&M costs and component reliability.

•	 Perceived financial risk, including performance and energy delivery potential.

Specific technology improvement options addressing LCOE reduction and market barriers for the land and 

offshore pathways are examined in the sections below.

Historical Pace of Development and Market Diffusion

Global wind power capacity grew by 22% in 2010, with 38.3 GW in new installations comprising a $65 billion industry.258 In the United States, the wind industry installed just over 5 GW of new capacity, comprising a 

$10 billion industry. Installations in 2010 were half that in 2009 due to lower wholesale electricity prices and 

a depressed demand for electricity.259 Since 2006, the U.S. wind industry has grown at an average annual rate 

of more than 36%.260 An estimated 71% of U.S. wind power capacity has come online since 2006; 94% has 

come online since 2000 (Figure 55).261 Texas is the state leader in installed wind power capacity, with nearly 

one-quarter of the U.S. fleet (10,085 MW).262 

The domestic content of U.S. installations grew from 15% in 2006 to an estimated 61% in 2009. In addition, the United States has begun modest export of turbines and components to neighbors in the Western 

Hemisphere and to China.263 Today’s expanding U.S. wind manufacturing capacity consists of OEM nacelle 

and drivetrain assembly plants, OEM and tier-one blade and tower manufacturers, and lower-tier component 

manufacturers.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

12 45

40

35

30

25

20

15

10

5

0

10

8

6

4

2

0

198119831985198719891991199319951997199920012003200520072009

Annual Additions to U.S. Wind Capacity (GW)

Cumulative U.S. Wind Capacity (GW)

CUMULATIVE U.S. WIND CAPACITY ANNUAL U.S. WIND CAPACITY ADDITION

YEAR

Figure 55. Annual Installed Wind Capacity and Total Installed Wind Capacity 

in the United States

Source: Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Page 3, Figure 1. Washington, DC: 

Department of Energy. Accessed at http://eetd.lbl.gov/ea/ems/reports/lbnl-3716e.pdf 

The installed cost of wind power fell steadily from more than $3,000/kW in the mid-1980s to $1,200–$1,400/

kW in the early 2000s due to technical and manufacturing improvements, and then rose again to roughly 

$2,100/kW in 2009 (Figure 56).264 The average installed costs are expected to decline in the near future due to 

greater supply and an easing of commodity and energy prices.
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5,000

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

0

198219861990199419982002

2006

2010

Installed Project Cost (2010 $/kW)

CAPACITY-WEIGHTED AVERAGE PROJECT COST 

INDIVIDUAL PROJECT COST 

POLYNOMIAL TREND LINE

YEAR

Figure 56. Installed Cost ($/kW) for Land-Based Wind Installations

Source: Wiser, R., and Bolinger, M. (2011). 2010 Wind Technologies Market Report. Page 47, Figure 28. Washington, 

DC: Department of Energy. Accessed at http://www1.eere.energy.gov/wind/pdfs/51783.pdf 

The factors that drove up the capital cost of wind installations in 2008—higher commodity prices, a relatively 

weak dollar and reliance on European supply, supply/demand constraints, and increased labor costs—increased 

in 2010. Insufficient transmission access in the best wind resource areas has also forced developers into lower 

wind resource classes, raising the cost of energy. 

Installed costs for fixed-bottom shallow offshore wind plants have historically been 50%–100% higher than 

installed costs for land-based wind facilities, and were roughly $4,000/kW in 2010. Data for proposed U.S. and 

European projects suggest shallow offshore installed capital costs will not decrease in the near future.265 Comparable data for deep water floating technology does not yet exist. Offshore wind installation costs have also 

been driven upward by increased siting complexity. Limited offshore installation and operational experience 

demands higher construction and operation risk premiums.266
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

U.S. land-based wind costs for projects completed in 2010 appear to be similar to 2009. However, the most 

recent trends indicate cost reductions on the order of 25% for projects to be built 1 to 2 years into the future.267

These cost reductions result from increased domestic content (which helps to hedge against exchange rate fluctuations), build-out of new manufacturing capacity, slowing demand for wind turbine equipment, and greater 

competition in wind turbine supply.

The price of electricity from wind projects in the first half of the decade ranged from $30–$40/MWh, while 

projects completed more recently have ranged from $20–$90/MWh (Figure 57). The price of electricity is based 

on many factors, including regional differences in wind resource, installation and development costs, wholesale 

electricity prices, demand for renewable energy associated with state policies, and applicable federal and state 

subsidies.268 

120

100

80

60

40

20

0

Installed Project Cost (2010 $/kW)

CAPACITY-WEIGHTED AVERAGE 2010 WIND POWER PRICE (BY PROJECT VINTAGE)

INDIVIDUAL PROJECT 2010 WIND POWER PRICE (BY PROJECT VINTAGE)

2010

26 

projects

2,361 MW

2009

48

projects

3,819 MW

2008

31 

projects

2,669 MW

2007

23

projects

3,013 MW

2006

14 

projects

742 MW

2004-05

21 

projects

1,269 MW

2002-03

33 

projects

1,648 MW

2000-01

22

projects

856 MW

1998-99

14

projects

655 MW

Figure 57. Wind Power Price ($/MWh)

Bars show the capacity-weighted average wind power price paid by utilities by project vintage. Yellow circles show 

individual project wind power price. Prices are depressed by applicable federal and state subsidies. Source: Wiser, R., 

and Bolinger, M. (2011). 2010 Wind Technologies Market Report. Page 39, Figure 21. Washington, DC: Department of 

Energy. Accessed at http://www1.eere.energy.gov/wind/pdfs/51783.pdf
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Current Industry in the United States and the World 

Wind turbines are only part of the overall capital costs associated with wind farms (Figure 58). The related 

BOS hardware and support infrastructure represents a greater portion of the overall wind plant cost drivers for 

offshore deployment.

Turbine

74%

Grid 

Connection

11%

Other

Costs

12%

Civil

Works

23%

Grid 

Connection

22%

Civil

Works

11%

Other

Costs

7%

Turbine

43%

Figure 58. Capital Cost of Land-Based (left) and Offshore (right) Wind Power by Component 

Source: Wiser, R., et al. (2011). Chapter 7: Wind Energy. In IPCC Special Report on Renewable Energy Sources and 

Climate Change Mitigation. Page 66, Table 7.4. [O. Edenhofer, R. Pichs Madruga, Y. Sokona, K. Seyboth, P. Matschoss, 

S. Kadner, T. Zwickel, P. Eickemeier, G. Hansen, S. Schlömer, C. von Stechow (eds)]. Cambridge, United Kingdom, and 

New York, NY, USA: Cambridge University Press. Accessed at http://srren.ipcc-wg3.de/report

The principal materials used in wind turbines include steel, copper, fiberglass, carbon fiber, and polymer resins, 

while turbine foundations are primarily concrete. The industry has identified potential issues in the availability 

of fiberglass and carbon fiber, the latter being relatively costly.269 Similarly, increased demand for permanent 

magnets, used in many industrial applications, has created some concern about the reliable availability and cost 

of rare earth permanent magnets used in wind generators.270 

Technology Potential

The installed costs of land-based wind power are expected to decline by as much as 25%–35% over the next 

two decades, even as stronger, longer blades and towers will be needed for increasingly larger systems.271 For 

the less mature offshore industry, installed costs are expected to decline by 9%–44% by 2030.272 At the same 

time, performance for both land-based and offshore wind is expected to continue to improve. In combination, 

these changes will increase energy capture, lower capital costs, and improve reliability, all of which lower the 

cost of electricity. 
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

Figure 59 shows technical targets for the LCOE of land-based wind energy that the Department believes are 

feasible though increased capacity factor and decreased capital costs.

1.2

0.8

1

0.6

0.4

0.2

0

Fraction of Today’s Value

$/kW 2010 ¢/kW 2010 $/kW 2020 ¢/kWh 2020 $/kW 2030 ¢/kWh 2030

Capacity Factor

1.5 MW Turbine on 

80 meter tower

3.5 MW Turbine on 

110 meter tower

5 MW Turbine on 

133 meter tower

Cost of Energy reductions

coming from combination

of capital cost reductions 

and capacity factor 

improvement

$ /kW Cents /kWh

6.0 ¢/kwh

8.2 ¢/kwh

4.2 ¢/kwh

MARKET BARRIER COSTS

BALANCE OF STATION

TOWER

DRIVE TRAIN

ROTOR

REPLACEMENT COSTS

O&M

FINANCING COST

TOTAL CAPITAL COST

Figure 59. Projected Decrease in Turbine Costs (orange bars), Levelized Cost of Electricity 

(blue bars), and Associated Increase in Capacity Factor273, 274

Source: Internal Department of Energy Wind and Water Program Strategic Analysis, as part of roadmapping analysis.
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The private sector, in part supported by DOE, continues to conduct R&D efforts that could reduce the LCOE of 

both land-based and offshore wind power. Activities to achieve significant LCOE reduction are sorted into three 

primary pathways, each with specific research objectives:

•	 Next-Generation Wind Turbine Component Development: Developing larger light-weight turbine 

architectures (larger rotors, taller towers) that reduce overall mass (cost) and provide access to better resource and improved systems performance (capacity factor). Innovations in wind turbine components can improve energy capture and performance. Component material improvements (cost, 

strength, weight, fatigue) can facilitate turbine scaling and improve reliability. Research opportunities 

include development and validation of next-generation drivetrain and rotor concepts; integrated active rotor control for load mitigation; adaptive controls; integrated health monitoring; and advanced 

sensor systems. 

•	 Wind Plant Production and Underperformance: Next generation of advanced modeling capability 

will be better able to evaluate wind plant performance and provide operational information for control 

and dispatch of power that will have a direct impact on current underperformance issues. Vital to these 

efforts is a shift in approach, from turbine-level performance to a plant-wide, systems-level perspective. Research opportunities include the use of advanced modeling and computational capabilities to 

predict intra-array flow dynamics and to assess impacts on macro and micro climatology and facilitate 

complex terrain installations, large multiple arrays, and optimized siting; design tools to assess wind 

turbine design and performance as an integrated subsystem; grid modeling simulation to address 

dynamic stability and penetration effects from intermittency; and forecasting tools to provide high 

confidence projections of resource and power production.

•	 Wind Plant Reliability: Reliability innovations can lead to significant reductions in O&M costs and 

levelized replacement costs for large, expensive components, such as blades, gearboxes, and generators. O&M and replacement costs can be particularly significant for offshore wind plants. Research 

opportunities include damage and defect surveys to characterize problems in the field; studies to 

determine how defects affect the strength and life of wind turbine components; validation of failure 

analysis models; real-time performance monitoring, including gearbox and blade reliability, reliability 

and operational database failure and maintenance tracking, development of active condition monitoring systems for rotors, drivetrains, power conversion systems, as well as adaptive controls research to 

maximize power production while minimizing detrimental loads; and collection of industry-wide reliability, availability, and maintainability data.

Deep water floating platform technology has the greatest potential to reduce offshore costs, open significant 

wind resources, and overcome visual public acceptance barriers that limit onshore and shallow-water projects. 

Significant innovation is required in several technologies for floating platform architectures to achieve commercial viability. These innovations, many of which are equally applicable to land and shallow-water systems, 

are technically challenging but have the potential to drastically reduce LCOE. The greatest technical challenges 

in offshore innovation include:

•	 Lightweight Turbine Architectures: Floating offshore platforms will require lightweight turbines 

designed for the marine environment and accommodating unique logistics, installation, and maintenance requirements.275 Every kilogram removed above the water line reduces the subsurface mass 

needed to achieve buoyancy by 5–6 kilograms. The principal technical challenge in making floating 

technology viable is stability of a lightweight, dynamically soft turbine mounted on a floating platform 

and subjected to coupled wind and wave loading.
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

•	 Installation Vessels and Techniques: Installation, operation, and maintenance in a marine environment are major technology considerations. In many marine operations, dockside construction and assembly is about four times more expensive than factory construction and assembly, and marine operations are eight times more expensive than land-based operations. Hardware options requiring minimal 

marine assembly, the development of specific installation vessels, enhanced installation techniques, 

component longevity, and performance options reducing on-station maintenance and replacement 

will likely be more costly than what is used in land-based systems.

•	 Condition Monitoring: O&M is a major cost driver (about 20% LCOE) for shallow-water systems already deployed in Europe due to the harsh marine operating environment and access windows limited 

by weather and sea conditions;276 deep water floating systems will likely have even more stringent access limitations. Advanced condition system monitoring must be developed and implemented to limit 

maintenance trips and facilitate reductions in O&M. More thorough remote monitoring systems are 

needed for rotors, drivetrains, and power electronics, as well as the associated assessment technologies for predictive failure and maintenance. 

Summary of Roadmap Agreements and Disagreements

The United States and European Union have different wind energy goals and objectives, although both project 

substantial future power generation from wind. For example, the International Energy Administration published a Wind Technology Roadmap in December 2009,277 describing projected contributions for wind power 

worldwide through 2050, along with actions required to achieve those projections. The International Energy 

Administration projects some 2,700 TWh per year of wind energy generated by 2030, providing some 9% of 

worldwide electricity. In comparison, DOE has evaluated wind power’s potential for providing 20% of American 

electricity as a technically and economically feasible scenario.278 

High-Risk Technology Breakthroughs

Several innovative technologies that are radical departures from conventional approaches are being investigated. These technologies are early in the development and demonstration phases at the prototype scale R&D 

investments. Existing public and private sector R&D endeavors of this sort include:

Wind Turbine Augmenter/Diffuser Technologies: Recent advances in turbine augmentation technology 

can overcome the limitations of diffuser technologies. Shrouded or ducted rotor technologies to enhance wind 

turbine performance were initially proposed in the 1950s. Shrouds were designed to increase the turbine inlet 

to exit area ratio and reduce the exit pressure, thereby increasing the mass flow through the rotor inlet. A 

theoretical two-to-three fold improvement in performance is possible but has not been field validated. Performance discrepancies are due to flow separation from the shroud when the turbine turns with changes in wind 

direction. Augmenting rotor wake through integrated diffuser design mitigates these separation effects. Potential advantages include achieving a two-to-three fold improvement in energy capture and minimizing wake 

dispersion and coherency effects. Anticipated technical challenges remain the weight and thrust loading of the 

shroud, key drivers of total cost of energy when scaled to multi-megawatt platforms.
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Active Blade Control Technologies: Active blade augmentation to control aerodynamic performance includes 

a wide range of well-documented technologies that have been used in aerospace applications. Most common 

are actuators (e.g., flaps, spoilers, etc.) to change the airfoil shape to achieve a specific performance objective. 

Another approach is flow augmentation for similar performance changes without physical manipulation of 

the blade geometry. High-pressure air directed through slots along the blade alters blade performance characteristics. This technology can be used to enhance aerodynamic performance to overcome design constraints. 

For example, large blades (greater than 80 meters) have blade widths that exceed acceptable transportation 

envelopes. Similarly, using a thick cross section for large blades is less aerodynamically efficient. Active blowing 

control can overcome aerodynamic performance degradation. Anticipated technical challenges include design 

life, duty cycle, maintaining active control systems, and the potential for increased aeroacoustic noise. 

Airborne Power Generation Technologies: Aerospace architectures (e.g., wing and helicopter unibody 

structures, rotors, flight controls, etc.) used to collect energy at altitude, connected through a power cable 

tether. Advantages of these technologies include order of magnitude reduction in system mass by eliminating 

foundation and tower support infrastructure; scalability to multi-megawatt architectures; access to significantly 

improved wind resources aloft; and rapid deployment potential both on and offshore. Anticipated technical 

challenges and opportunities include addressing fatigue, critical structural design constraints, improved LCOE 

through lower-cost composites, longevity and design life, OEM and potential aviation deployment barriers, and 

safety concerns.

Deployment Barriers 

Key barriers to the domestic deployment of wind power include: 

•	 Transmission Access and Availability: Lack of transmission access and necessary infrastructure, such 

as offshore installation vessels, drives wind deployment to lesser quality resources, thereby increasing 

the cost of electricity. Sites for projects deployed in 2008 averaged a Class III resource, continuing 

a downward trend over the past decade (Figure 60). Research opportunities focus on providing the 

information necessary to improve system-wide planning and include grid integration studies to assess 

technical solutions to wind resource variability, assessments of offshore infrastructure needs and costs, 

and conceptual design studies. A more detailed discussion of transmission and integration issues can 

be found elsewhere.279 

•	 Siting and Enviromental Barriers: Proposed sites for wind farms often face opposition based upon 

wildlife impacts, civilian and military radar interactions, and competing land/sea use. The construction 

and operation of wind power facilities can have real or perceived negative impacts on wildlife, radar, 

and other land and ocean uses, and these concerns may become more significant as the footprint of 

wind energy expands. These risks are not always fully understood, nor have methods for mitigating 

these impacts been demonstrated. Options to reduce these risks, whether perceived or actual, include 

research on reducing radar interference and acoustic signature; risk mitigation for wildlife and other 

environmental impacts; and better understanding interactions of wind farms with other industries, 

such as agriculture (land-based) and navigation (offshore). Public acceptance concerns related to these 

barriers could be addressed by increased availability of objective information and decision tools on 

wind energy to stakeholders and policymakers, direct and indirect technical support to state and local 

governments, and scientific research on issues of public concern.
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900

800

700

600

500

400

300

200

100

0

Wind Power Density

(Average, W/m2 @ 50m)

WEIGHTED AVERAGE

2007

42 projects

5,001 MW

2006

31 projects

2,394 MW

2004-05

37 projects

2,680 MW

2002-03

34 projects

2,227 MW

2000-01

33 projects

1,446 MW

1998-99

32 projects

935 MW

Class 7

Class 6

Class 5

Class 4

Class 3

Class 2

Class 1

Figure 60. Wind Power Density of Installed Plants by Project Vintage

Source: Wiser, R., and Bolinger, M. (2011). 2010 Wind Technologies Market Report. Page 39, Figure 21. Washington, 

DC: Department of Energy. Accessed at http://www1.eere.energy.gov/wind/pdfs/51783.pdf

•	 Cost of Electricity: Wind power is more expensive than traditional fossil fuel generation. Costs due to 

wind’s variable output may increase with its greater penetration. Policies like the Production Tax Credit 

and RPS at the state and federal level affect the cost of electricity. Uncertainty about the existence and 

stability of these policies affects wind deployment. 

•	 Manufacturing Capability: Improvements in manufacturing processes to minimize material inputs 

and waste could reduce costs and improve industry production efficiency. Opportunities include researching advanced materials and manufacturing process, as well as workforce development, especially for manufacturers and those involved in wind power implementation, such as installers, operators, 

and technicians.
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Potential issues that will warrant more attention at higher wind power penetration include the following:

•	 Possible impacts to micro- and macro-climatology from large turbine arrays. Micro- and macro- climatology impacts are potential alterations of the atmospheric boundary layer resource by the presence of 

a large multi-array wind farm. Micro effects include alterations to the flow at wind plant dimensional 

scales and below; effects include the inter-array flow field changing power production, turbine loads, 

and individual turbine wakes, impacting subsequent turbines aligned in multiple arrays. Micro also 

refers to the aggregated wake effect downstream of a farm that may impact agriculture, including surface humidity and temperature. Macro effects include impacts from multiple large wind farms, including changes in circulation patterns, precipitation patterns, and valuation of the wind energy resource 

when impacted by upstream wind farms.

•	 National and regional power forecasts, dispatch and integration strategies for accomodating more 

intermittent and variable power sources on the grid, deeper analysis and understanding of operational 

constraints, and associated government regulatory roles and responsibilities.280

DOE History and Accomplishments 

Annual inflation-adjusted DOE wind R&D funding peaked in the late 1970s at $160 million, fell sharply in the 

late 1980s to $15 million, and remained near $40–$50 million a year from 1996 through 2008, before increasing in recent years (Figure 57). 

90

80

70

60

50

40

30

20

10

0

Annual Budget Appropriations to Wind Power

 (2010 $million)

198519901995200020052010

FISCAL YEAR

Figure 61. DOE Wind Energy R&D Budget

Sources: (1985–2002) Current Congressional Appropriations from DOE CFO, Office of Budget; (2003-2008) DOE EERE 

Budget Office (http://www1.eere.energy.gov/ba/pba/budget_archives.html); (2009–2010) 2011 FY11 Congressional 

Budget for DOE EERE (http://www1.eere.energy.gov/ba/pba/pdfs/fy11_budget.pdf). Converted to 2010 $million 

using consumer price index from the Department of Labor, Bureau of Labor Statistics (ftp://ftp.bls.gov/pub/special.

requests/cpi/cpiai.txt). 
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Notable technology contributions resulting from this investment include modeling and early-phase R&D, as well 

as technology evaluation and demonstration activities.281

Modeling and Early-Phase R&D:

•	 Measurements of the wind turbulence field and development of stochastic models. Established a 

causal relationship between atmosperic turbulence and turbine failure and provided fast and efficient 

methods for numerical simulation of turbulence in design codes (1980–present).

•	 Development and validation of numerous structural, aerodynamic, and controls codes used extensively 

by industry in the design and development of innovative technology and commercial architectures 

(1990s–present).

•	 Turbine blade and rotor material characterization and analytical modeling. Creation of a composites 

materials database used extensively by industry for blade and rotor design (1990s–present).

•	 Development of the first integrated tool for modeling offshore deep water floating platform structures (barge, spar buoy, tension leg platform), incorporating coupled hydrodynamic and aeroelastic 

response to atmosperic turbulence and wave interaction called HydroDYN. This model is becoming the 

standard tool in modeling innovative offshore concepts and designs (2005–present).

Technology Evaluation and Demonstration:

•	 Development and demonstration of the first multi-megawatt wind turbines (1980s). 

•	 Co-location of field, dynamometer, and blade test facilities with a national engineering center dedicated to advanced technology and model development at the National Wind Technology Center (1996).

•	 Validated emerging turbine design performance (1990s).

•	 Through technology development programs (e.g., WindPact, Low Wind Speed Turbine), aided industry’s development and demonstration of larger commercial wind turbines that could reach higher wind 

regimes and achieve greater energy capture (1995–2006).

•	 Established the global benchmark dataset for codes validation of turbine aerodynamics and wakes via 

the Unified Aerodynamics Experiment field and measurement campaigns, which were conducted at 

the National Wind Technology Center in conjunction with full turbine testing at a National Aeronautics 

and Space Administration wind tunnel (1990s).

DOE Role

DOE’s primary roles in wind power focus on R&D capability and information. The Department has core scientific 

and technical capabilities for wind resource characterization, modeling of intra-array flow dynamics, analytic 

tool development for wind forecasting, and materials science. These capabilities allow DOE to lend its basic and 

fundamental engineering science resources to precompetitive solutions to challenges to wind power production. For example, the Department’s National Wind Technology Center provides unique testing capabilities to 

help industry partners develop and refine turbine designs. The Department also provides valuable informational 

resources to various stakeholders through reports like 20% Wind Energy by 2030.

282 Furthermore, DOE works 

with the Department of Interior to remove barriers to siting wind projects, providing information to stakeholders on the costs and benefits of wind power projects.283
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1 Energy Information Administration. (2011). “Total Energy Supply, Disposition, and Price Summary, Reference Case.” Annual 

Energy Outlook. Washington, DC. Accessed at http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2011&subject=0-

AEO2011&table=1-AEO2011®ion=0-0&cases=ref2011-d020911a 

2 Energy Information Administration. (2011). “Growth of Carbon Emissions Slows in Projections.” Annual Energy Outlook. Washington, DC. Accessed at http://www.eia.gov/forecasts/aeo/MT_emissions.cfm#carbon 

3 Energy Information Administration. (2011). “Total Carbon Dioxide Emissions from the Consumption of Energy.” International Energy Statistics. Washington, DC. Accessed November 2011 at http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.

cfm?tid=90&pid=44&aid=8 

4

 International Energy Agency. (2010). Energy Technology Perspective 2010. Paris, France. 

5 Energy Information Administration. (2011). “China.” Country Analysis Brief. Accessed at http://www.eia.gov/countries/cab.

cfm?fips=CH

Energy Information Administration. (2011). “India.” Country Analysis Brief. Accessed at http://www.eia.gov/countries/cab.

cfm?fips=IN 

6 International Energy Agency. (2008). CO2

 Capture and Storage. p. 16. Paris, France. Accessed at http://www.iea.org/textbase/

nppdf/free/2008/CCS_2008.pdf 

7 The gas produced from a well can have more than 20% carbon dioxide, which must be separated and removed before the hydrocarbons are transported in a pipeline.

8

 National Energy Technology Laboratory. (2011). Improving Domestic Energy Security and Lowering CO2 Emissions with “Next 

Generation” CO2-Enhanced Oil Recovery (CO2-EOR). (DOE/NETL-2011/1504). Morgantown, WV. Accessed at http://www.netl.

doe.gov/energy-analyses/pubs/NextGen_CO2_EOR_06142011.pdf 

9 Interstate Oil and Gas Compact Commission. A Policy, Legal, and Regulatory Evaluation of the Feasibility of a National Pipeline 

Infrastructure for the Transport and Storage of Carbon Dioxide, p. 21. Oklahoma City, OK. Accessed at http://www.iogcc.state.

ok.us/Websites/iogcc/Images/PTTF%20Final%20Report%202011.pdf 

10 National Energy Technology Laboratory. (2010). Carbon Sequestration Atlas of the United States and Canada – Third Edition. 

Morgantown, WV. Accessed at http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIII/index.html 

11 “Nth plant” costs assume that several plants using the same technology have already been built and are operating. In other 

words, the assumption reflects a future in which a successful industry has been established with many operating plants.

12 Drawn from p. 5 of the following report. Comparing Case 1 (76.3 mills/kWh) to the capture Case 2 (105.6 mills/kWh), the additional 29.3 mills/kWh cost increase in the capture scenario includes 5.2 mills/kWh for transmission, storage, and monitoring of 

carbon dioxide, with the remaining 82% of the cost increase attributed to capture and compression. 

National Energy Technology Laboratory. (2010). Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous 

Coal and Natural Gas to Electricity. (DOE/NETL-2010/1397). Morgantown, WV. Accessed at http://www.netl.doe.gov/energyanalyses/pubs/BitBase_FinRep_Rev2.pdf

13 An ‘integrated’ carbon capture and storage (CCS) project links together the whole CCS chain of capture, transport, and storage of 

carbon dioxide (CO2) with a scale of 1 million metric tonnes per annum or greater of CO2 captured and stored.

14 Interagency Task Force on Carbon Capture and Storage. (2010). Report of the Interagency Task Force on Carbon Capture and Storage. Washington, DC. Accessed at http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf

15 Interagency Task Force on Carbon Capture and Storage. (2010). Report of the Interagency Task Force on Carbon Capture and Storage. Washington, DC. Accessed at http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf

16 Interagency Task Force on Carbon Capture and Storage. (2010). Report of the Interagency Task Force on Carbon Capture and Storage. Washington, DC. Accessed at http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf

17 Intergovernmental Panel on Climate Change. (2005). IPCC Special Report on Carbon Dioxide Capture and Storage. New York, NY. 

Accessed at http://www.ipcc-wg3.de/publications/special-reports/.files-images/SRCCS-WholeReport.pdf 
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18 Kinder Morgan. (2006). Permian Basin Overview. Houston, TX. Accessed at http://www.pacificorp.com/content/dam/pacificorp/

doc/Environment/Stakeholder_Groups/CORP_Permian_Basin_overview_Kinder_Morgan_10_25_06.pdf

19 Dipietro, P., Melzer, S., Kuuskraa, V., and Balash, P. (June 2011). “The Role of Underground CO2 Accumulations in the Emergence 

of CO2 Enhanced Oil Recovery.” Submitted to SPE Journal of Economics and Management.

20 Moritis, G. (2010). “EOR/Heavy Oil Survey: CO2

 Miscible, Steam Dominate Enhanced Oil Recovery Processes.” Oil and Gas Journal. 108(14):41.

21 Dooley, J. J., Dahowski, R. T., and Davidson, C. L. (2010). CO2

-Driven Enhanced Oil Recovery as a Stepping Stone to What? (PNNL19557). Richland, WA: Pacific Northwest National Laboratory.

22 National Energy Technology Laboratory Baseline and Pathway Studies. Links include http://www.netl.doe.gov/energy-analyses/

baseline_studies.html and http://www.netl.doe.gov/energy-analyses/refshelf/PubDetails.aspx?Action=View&PubId=284

23 U.S. Department of Energy. (2011). Strategic Plan. p. 18. (DOE/CF-0067). Washington, DC. Accessed at http://energy.gov/sites/

prod/files/2011_DOE_Strategic_Plan_.pdf 

24 National Energy Technology Laboratory. (2011). DOE/NETL Advanced Carbon Dioxide Capture Program: Technology Update. p. 

5 and 86. Morgantown, WV. Accessed at http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/CO2CaptureTechUpdate051711.pdf 

Natural Gas Combined Cycle (NGCC) fuel costs in the cited report are based on $6.55/MMBtu. The projected cost premium for 

NGCC with carbon capture and storage (CCS) has been adjusted to include $4/MMBtu gas prices for consistency with other 

assessments in the Quadrennial Technology Review. This increases the cost premium for NGCC with CCS to 65% provided here 

from the 40% in the cited report. 

25 For information on National Energy Technology Laboratory Baseline Studies, go to http://www.netl.doe.gov/energy-analyses/

baseline_studies.html 

26 Interagency Task Force on Carbon Capture and Storage. (2010). Report of the Interagency Task Force on Carbon Capture and 

Storage. Appendix E. Washington, DC. Accessed at http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf

27 National Energy Technology Laboratory. (2010). Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous 

Coal and Natural Gas to Electricity. Exhibit ES-2. Morgantown, WV. Accessed at http://www.netl.doe.gov/energy-analyses/

pubs/BitBase_FinRep_Rev2.pdf

28 National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). America’s Energy Future: 

Technology and Transformation. p. 382–383. Washington, DC: National Academies Press. Accessed at http://www.nap.edu/

catalog/12091.html 

29 Carbon Sequestration Leadership Forum. (2010). Carbon Sequestration Leadership Forum Technology Roadmap. Washington, DC. 

Accessed at http://www.cslforum.org/publications/documents/CSLF_Technology_Roadmap_2010.pdf 

30 International Energy Agency. (2010). Technology Roadmap: Carbon Capture and Storage. Paris, France. Accessed at http://www.

iea.org/papers/2009/CCS_Roadmap.pdf 

31 Coal Utilization Research Council and Electric Power Research Institute. (2012). The CURC-EPRI Coal Technology Roadmap. 

Washington, DC. Accessed at http://www.coal.org/roadmap/

32 National Academy of Sciences, National Academy of Engineering, National Research Council. (2009). America’s Energy Future: 

Technology and Transformation, p. 382–383. Washington, DC: National Academies Press. Accessed at http://www.nap.edu/

catalog/12091.html

33 Massachusetts Institute of Technology. (2007). The Future of Coal. Cambridge, MA. Accessed at http://web.mit.edu/coal/The_

Future_of_Coal.pdf 

34 Interagency Task Force on Carbon Capture and Storage. (2010). Report of the Interagency Task Force on Carbon Capture and Storage. Washington, DC. Accessed at http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf
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QUADRENNIAL TECHNOLOGY REVIEW TECHNOLOGY ASSESSMENTS 2012

35 U.S. Environmental Protection Agency. Geologic Sequestration Guidance Documents. Washington, DC. Accessed at http://water.

epa.gov/type/groundwater/uic/class6/gsguidedoc.cfm 

36 Interagency Task Force on Carbon Capture and Storage. (2010). Report of the Interagency Task Force on Carbon Capture and Storage. p. 12. Washington, DC. Accessed at http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf

37 Pore spaces are the spaces within a rock body that are unoccupied by solid material. Pore spaces include spaces between grains, 

fractures, vesicles, and voids formed by dissolution.

38 Dipietro, P., Melzer, S., Kuuskraa, V., and Balash, P. (June 2011). “The Role of Underground CO2 Accumulations in the Emergence 

of CO2 Enhanced Oil Recovery.” Submitted to SPE Journal of Economics and Management. 

39 National Energy Technology Laboratory. (2010). Carbon Dioxide Enhanced Oil Recovery. Morgantown, WV. Accessed at http://

www.netl.doe.gov/technologies/oil-gas/publications/EP/small_CO2_eor_primer.pdf 

40 National Energy Technology Laboratory. (2011). Improving Domestic Energy Security and Lowering CO2

 Emissions with “Next 

Generation” CO2-Enhanced Oil Recovery (CO2-EOR). (DOE/NETL-2011/1504). p. 9. Morgantown, WV. Accessed at http://www.

netl.doe.gov/energy-analyses/pubs/NextGen_CO2_EOR_06142011.pdf 

41 Energy Information Administration. (2012). Annual Energy Outlook 2012 Early Release Overview. Washington, DC: Department 

of Energy. Accessed at http://www.eia.gov/forecasts/aeo/er/executive_summary.cfm 

42 National Energy Technology Laboratory. (2008). CO2

 Capture Ready Coal Power Plants. (DOE/NETL-2007/1301). p. 8 and 11. Morgantown, WV. Accessed at http://www.netl.doe.gov/technologies/carbon_seq/refshelf/analysis/pubs/CO2%20CaptureReadyCoalPowerPlants%20Final.pdf 

43 Cost estimates for constructing new carbon dioxide (CO2

) pipelines and for transporting CO2 through these pipelines depend on 

a variety of factors, including the distance between the capture and storage points, the terrain the pipeline has to pass through, 

the anticipated flow rate of CO2, and the population and infrastructure development density. In certain circumstances, it may 

be more economical to transport CO2 a longer distance to a lower-cost, high-quality storage formation than to transport it over 

a short distance to a more expensive storage operation in a lower-quality storage field. Local costs for labor and materials will 

also affect overall CO2 transportation costs. Recent studies have shown that CO2 pipeline transport costs for a 100-kilometer (62 

mile) pipeline transporting 5 million tonnes per year range from approximately $1–$3/tonne, depending on the factors discussed 

above.

McCollum, D. L., and Ogden, J. M. (2006). “Techno-Economic Models for Carbon Dioxide Compression, Transport, and Storage & 

Correlations for Estimating Carbon Dioxide Density and Viscosity.” Institute of Transportation Studies. University of California, 

Davis. (Research Report UCD-ITS-RR-06-14). Accessed at http://pubs.its.ucdavis.edu/publication_detail.php?id=1047 

McCoy, S. T., and Rubin, E. S. (2008). Variability and Uncertainty in the Cost of Saline Formation Storage. Proceedings of the 9th 

International Conference on Greenhouse Gas Control Technologies. Accessed at http://www.cmu.edu/epp/iecm/rubin/PDF%20

files/2009/2009b%20McCoy%20GHGT-9.pdf 

44 National Energy Technology Laboratory. “Solid State Energy Conversion Alliance.” Accessed at http://www.netl.doe.gov/technologies/coalpower/fuelcells/seca/ 

45 U.S. Department of Energy. (2011). DOE/NETL Advanced Carbon Dioxide Capture R&D Program: Technology Update. Washington, 

DC. Accessed at http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/CO2CaptureTechUpdate051711.pdf 

46 Carbon dioxide storage quantities are metered at the injection wells using purchase pumps or volume meters. Carbon dioxide 

storage locations are monitored and verified using surface and subsurface monitoring, verification, and accounting technologies, 

as well as various modeling programs. 

47 National Energy Technology Laboratory. (2010). Carbon Sequestration Atlas of the United States and Canada. Morgantown, WV. 

Accessed at http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlas/ 

48 Concentrating solar power may also be called concentrating solar thermal power or solar thermal electric power.

49 Renewable Energy Policy Network for the 21st Century. (2011). Renewables 2011 Global Status Report. Paris, France. Accessed 

at http://www.ren21.net/Portals/97/documents/GSR/REN21_GSR2011.pdf 
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50 U.S. Department of Energy. (2012). SunShot Vision Study. (DOE/GO-102012-3037). Washington, DC. Accessed at http://www1.

eere.energy.gov/solar/sunshot/vision_study.html 

Estimates are based on locations in the Southwest with characteristics ideal for concentrating solar power systems, including 

direct normal irradiance greater than 6.0 kWh/m2/day (2,200 kWh/m2/year) and land slope of less than 1°, excluding bodies of 

water, urban areas, national parks and preserves, wilderness areas, and wildlife refuges. Because the economics of utility-scale 

solar facilities favor large size, land areas smaller than 1 square kilometer (km2) are also excluded.

51 Emerging Energy Research. (2010). “Global Concentrated Solar Power Markets and Strategies: 2009-2020.” Cambridge, MA.

52 Emerging Energy Research. (2010). “Global Concentrated Solar Power Markets and Strategies: 2009-2020.” Cambridge, MA.

53 Emerging Energy Research. (2010). “Global Concentrated Solar Power Markets and Strategies: 2009-2020.” Cambridge, MA.

54 Solar Energy Industries Association. (2010). “U.S. Solar Market Insight, 2nd Quarter 2010.” Washington, DC. Accessed at http://

seia.org/galleries/pdf/SEIA_Q2_2010_EXEC_SUMMARY.pdf 

55 These values are representative of those collected from a variety of sources. For example:

Sargent & Lundy LLC. (2003). “Assessment of Parabolic Trough and Power Tower Solar Technology Cost and Performance 

Forecasts.” (NREL/SR-550-34440). Golden, CO: National Renewable Energy Laboratory. 

Kolb, G. (2011). “An Evaluation of Possible Next-Generation High-Temperature Molten-Salt Power Towers (Draft Report).”

Turchi, C. (2010). “Parabolic Trough Reference Plant for Cost Modeling with the Solar Advisor Model (SAM).” (NREL/TP-550-

47605). Golden, CO: National Renewable Energy Laboratory.

Turchi, C., Wagner, M., and Kutscher, C. (2010). “Water Use in Parabolic Trough Power Plants: Summary Results from WorleyParsons’ Analyses.” (NREL/TP-5500-49468). Golden, CO: National Renewable Energy Laboratory.

Andraka, C. E. (2008). “Cost/Performance Tradeoffs for Reflectors used in Solar Concentrating Dish Systems.” Energy Sustainability. (ES2008-54048). Jacksonville, FL. 

56 Design point efficiency is the solar-to-electric efficiency at solar noon on the summer solstice (best conditions).

57 Annual average efficiency is the average solar-to-electric efficiency throughout the year. 

58 Capacity factor is the total energy delivered over the course of a year divided by the energy that would be delivered by the rated 

system capacity over the course of a year.

59 U.S. Department of Energy. (1997). “Solar Trough Power Plants.” Washington, DC. Accessed at http://www.osti.gov/accomplishments/documents/fullText/ACC0196.pdf

National Renewable Energy Laboratory. Solar Power and Chemical Energy Systems. Boulder, CO. Accessed at http://www.nrel.

gov/csp/solarpaces/

60 The number increases with thermal energy storage because solar collector area increases, but power block capacity does not.

61 Therminol. “Therminol VP-1 Vapor Phase/Liquid Phase Heat Transfer Fluid.” Accessed at http://www.therminol.com/pages/

products/vp-1.asp

National Renewable Energy Laboratory. Solar Power and Chemical Energy Systems. Boulder, CO. Accessed at http://www.nrel.

gov/csp/solarpaces/

62 The design-point values represent an ideal case that is useful for comparing between different components, such as two different receiver designs. This metric is also used for evaluating photovoltaic panels. The annual average efficiency provides a better 

assessment of actual operation.

63 See the AREVA Solar Kimberlina, Kogan Creek, and Sundt projects. AREVA Solar. (2012). “AREVA Solar: Projects.” Accessed May 

2012 at http://www.areva.com/EN/solar-209/areva-solar-projects.html 

64 National Renewable Energy Laboratory. Solar Power and Chemical Energy Systems. Boulder, CO. Accessed at http://www.nrel.

gov/csp/solarpaces/
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65 Andraka, C. E., and Powell, M. P. (2008). “Dish Stirling Development for Utility-Scale Commercialization.” 14th Biennial CSP 

SolarPACES Symposium. Las Vegas, NV.

66 European Solar Thermal Electricity Association. (2012). “Andasol-1 and Andasol-2: Dispatchable Thermosolar Power Plants.” 

Accessed May 2012 at http://www.estelasolar.eu/index.php?id=32 

67 National Renewable Energy Laboratory. Solar Power and Chemical Energy Systems. Boulder, CO. Accessed at http://www.nrel.

gov/csp/solarpaces/

68 U.S. Department of Energy. (2012). “Concentrating Solar Power: Technologies, Cost, and Performance.” SunShot Vision Study. 

Washington, DC. Accessed at http://www1.eere.energy.gov/solar/pdfs/47927_chapter5.pdf

69 U.S. Department of Energy. (2012). “Concentrating Solar Power: Technologies, Cost, and Performance.” SunShot Vision Study.

Washington, DC. Accessed at http://www1.eere.energy.gov/solar/pdfs/47927_chapter5.pdf 

70 The 30% investment tax credit can reduce the levelized cost of electricity to the ¢0.12–¢0.18/kWh range.

71 Cohen, G. E. (2008). “Solar Steam at Nevada Solar One.” SolarPaces 2008. Las Vegas, NV. Accessed at http://solarpaces2008.

sandia.gov/SolarPACES%20PLENARIES/2%20WEDNESDAY%20INDUSTRY%20DAY%20SESSIONS/1%20PLEN%20CSP%20

PLANTS%20TODAY/01%20Acciona%20Cohen%20SOLARPACES%202008.pdf 

72 Sargent & Lundy. (2003). Assessment of Parabolic Trough and Power Tower Solar Technology Cost and Performance Forecasts. 

(NREL/SR-550-34440). National Renewable Energy Laboratory. Chicago, IL. Accessed at http://www.nrel.gov/docs/fy04osti/34440.pdf 

73 U.S. Department of Energy. (2012). “Concentrating Solar Power: Technologies, Cost, and Performance.” SunShot Vision Study. 

Washington, DC. Accessed at http://www1.eere.energy.gov/solar/pdfs/47927_chapter5.pdf 

74 U.S. Department of Energy. (2012). “Concentrating Solar Power: Technologies, Cost, and Performance.” SunShot Vision Study. 

Washington, DC. Accessed at http://www1.eere.energy.gov/solar/pdfs/47927_chapter5.pdf 

75 U.S. Department of Energy. (2012). “Concentrating Solar Power: Technologies, Cost, and Performance.” SunShot Vision Study. 

Washington, DC. Accessed at http://www1.eere.energy.gov/solar/pdfs/47927_chapter5.pdf 

76 Turchi, C. S. (2011). “Power Tower Reference Plant for Cost Modeling with the System Advisor Model.” (NREL/TP-5500-47461). 

Golden, CO: National Renewable Energy Laboratory. 

77 Kolb, G. J., et al. (2011). Power Tower Technology Roadmap and Cost Reduction Plan. (SAND2011-2419). Albuquerque, NM: 

Sandia National Laboratories. Accessed at http://prod.sandia.gov/techlib/access-control.cgi/2011/112419.pdf

National Renewable Energy Laboratory. (2003). Assessment of Parabolic Trough and Power Tower Solar Technology Cost and 

Performance Forecasts. (NREL/SR-550-34440). Boulder, CO. Accessed at http://www.nrel.gov/csp/pdfs/34440.pdf

National Renewable Energy Laboratory. Parabolic Trough FAQs. Boulder, CO. Accessed at http://www.nrel.gov/csp/troughnet/

faqs.html

78 Solar Energy Industries Association. (2011). Utility–Scale Solar Projects in the United States Operating, Under Construction, or 

Under Development. Washington, DC. Accessed at http://www.seia.org/galleries/pdf/Major%20Solar%20Projects.pdf

National Renewable Energy Laboratory. Solar Power and Chemical Energy Systems. Boulder, CO. Accessed at http://www.nrel.

gov/csp/solarpaces/

Kolb, G. J., et al. (2011). Power Tower Technology Roadmap and Cost Reduction Plan. (SAND2011-2419). Albuquerque, NM: 

Sandia National Laboratories. Accessed at http://prod.sandia.gov/techlib/access-control.cgi/2011/112419.pdf

Kutscher, C., et al. (2010). Line-Focus Solar Plant Cost Reduction Plan. Goldon, CO: National Renewable Energy Laboratory. Accessed at http://www.nrel.gov/docs/fy11osti/48175.pdf

79 National Renewable Energy Laboratory. (2011). Parabolic Trough FAQs. Golden, CO. Accessed at http://www.nrel.gov/csp/

troughnet/faqs.html
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80 National Renewable Energy Laboratory. (2010). Western Wind and Solar Integration Study. Boulder, CO. Accessed at http://

www.nrel.gov/wind/systemsintegration/wwsis.html

81 Based on currently deployed technologies for fuel cells, boilers, and central power stations. The assumed fuel cell efficiency 

is based on current molten carbonate fuel cell offerings from the FuelCell Energy website (http://www.fuelcellenergy.com/

dfc300ma.php), and the assumed efficiencies of boilers and central power stations are from the Energy Information Administration’s estimate of the current national average efficiencies.

82 Solid oxide fuel cells can achieve this efficiency. Molten carbonate fuel cells can achieve this efficiency only in hybrid cycles that 

capture waste heat to produce steam to drive a turbine to produce electricity.

83 Blanchard, J. (2007). Site Reliability: Fuel Cells Add Reliability to TeleCom Sites. IEEE 2007 Interlec Proceedings. Rome, Italy. 

Accessed at www.relion-inc.com/pdf/ReliOn_Intelec07_final.pdf

84 Pike Research. (2011). Stationary Fuel Cells: Fuel Cells for UPS, Residential, and Large Stationary Applications: Market Analysis 

and Forecasts. Boulder, CO. Accessed at http://www.giiresearch.com/report/pike195796-stationary-fuel-cells-fuel-cells-upsresidential.html 

85 Farooque, M. (2009). DFC Opportunities. Presentation at the MCFC and PAFC R&D Workshop. Palm Springs, CA. Accessed at 

http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/mcfc_pafc_workshop_farooque.pdf

86 Spendelow, J., et al. (2011). Medium-Scale CHP Fuel Cell System Targets. (Program Record #11014). Washington, DC: Department of Energy. Accessed at http://www.hydrogen.energy.gov/pdfs/11014_medium_scale_chp_target.pdf

Remick, R. J., Wheeler, D., and Singh, P. (2010). MCFC and PAFC R&D Workshop Report. Washington, DC: Department of Energy. 

Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/mcfc_pafc_workshop_summary.pdf

87 Klara, J. National Renewable Energy Laboratory. 32nd International Technical Conference on Coal Utilization & Fuel Systems. 

June 13, 2007. Clearwater, FL. http://www.netl.doe.gov/KMD/cds/disk50/Clearwater%20Conference%20Final%20v2.pdf

88 U.S. Environmental Protection Agency. (2008). Catalog of CHP Technologies. Washington, DC. Accessed at http://www.epa.gov/

chp/documents/catalog_chptech_full.pdf

89 U.S. Department of Energy. (2010). “Case Study: Fuel Cells Provide Combined Heat and Power at Verizon’s Garden City Central 

Office.” Washington, DC. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/fccs_verizon10.pdf 

90 Spendelow, J., et al. (2011). Medium-Scale CHP Fuel Cell System Targets. (Program Record #11014). Washington, DC: Department of Energy. Accessed at http://www.hydrogen.energy.gov/pdfs/11014_medium_scale_chp_target.pdf

Remick, R. J., Wheeler, D., and Singh, P. (2010). MCFC and PAFC R&D Workshop Report. Washington, DC: Department of Energy. 

Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/mcfc_pafc_workshop_summary.pdf

91 U.S. Department of Energy. (2007). Fuel Cell Technologies Program Multi-Year Research, Development and Demonstration Plan. 

p. 3.4–14. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/mypp/index.html 

92 National Renewable Energy Laboratory. (2010). 1–10 kW Stationary Combined Heat and Power Systems Status and Technical Potential. (NREL/BK-6A10-48265). p. 7. Golden, CO. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/48265.

pdf 

93 SBI Energy. (2010). Fuel Cell Technologies Worldwide. Rockville, MD.

94 Information provided by Pike Research in early 2011.

95 U.S. Department of Energy. (2011). 2010 Fuel Cell Technologies Market Report. Washington, DC. Accessed at http://www1.eere.

energy.gov/hydrogenandfuelcells/pdfs/2010_market_report.pdf 

96 Farooque, M. (2009). DFC Opportunities. Presentation at the MCFC and PAFC R&D Workshop. Palm Springs, CA. Accessed at 

http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/mcfc_pafc_workshop_farooque.pdf 

97 Technology Transition Corporation. (2010). Hydrogen and Fuel Cells: The U.S. Market Report, 2010. p. xiii. Washington, DC. 

Accessed at http://www.fchea.org/core/import/PDFs/Technical%20Resources/H2_and_FCs-The_US_Market_Report_by_the_

NHA_2010.pdf
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98 Remick, R., and Wheeler, D. (2010). Molten Carbonate and Phosphoric Acid Stationary Fuel Cells: Overview and Gap Analysis. 

(NREL/TP-560-49072). Golden, CO: National Renewable Energy Laboratory and DJW Technology, LLC. Accessed at http://www.

nrel.gov/docs/fy10osti/49072.pdf.

99 Spendelow, J., et al. (2011). Medium-Scale CHP Fuel Cell System Targets. (Program Record #11014). Washington, DC: Department of Energy. Accessed at http://www.hydrogen.energy.gov/pdfs/11014_medium_scale_chp_target.pdf 

100 Jenkins, J. (2010). “Doing the Math on Bloom Energy.” Forbes. February 25, 2010. Accessed at http://www.forbes.com/2010/02/25/

fuel-cell-costs-technology-ecotech-bloom-energy.html

101Maru, H., Singhal, S., Stone, C., and Wheeler, D. (2010). 1-10 kW Stationary Combined Heat and Power Systems Status and 

Technical Potential. (NREL/BK-6A10-48265). Golden, CO: National Renewable Energy Laboratory. Accessed at http://www1.

eere.energy.gov/hydrogenandfuelcells/pdfs/48265.pdf 

102Current platinum loading is more than 4 g per kW for phosphoric acid fuel cells, compared with approximately 1 g per kW for 

stationary polymer electrolyte membrane fuel cells. Platinum supply is unlikely to become a bottleneck.

103 Brookhaven Lab’s Fuel Cell Catalyst Increases Durability: http://ae-plus.com/technology/brookhaven-labs-fuel-cell-catalystincreases-durability

U.S. Department of Energy. (2007). Multi-Year Program Plan, Hydrogen, Fuel Cells and Infrastructure Technologies. Washington, 

DC. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/mypp/pdfs/fuel_cells.pdf

Greene, D. L., Duleep, K. G., and Upreti, G. (2011). Status and Outlook for the U.S. Non-Automotive Fuel Cell Industry: Impacts of 

Government Policies and Assessment of Future Opportunities. (ORNL/TM-2011/101). Oak Ridge, TN: Oak Ridge National Laboratory. Accessed at http://cta.ornl.gov/cta/Publications/Reports/ORNL_TM2011_101_FINAL.pdf

104 Farooque, M. (2009). DFC Opportunities. Presentation at the MCFC PAFC Workshop. Palm Springs, California. Accessed at http://

www1.eere.energy.gov/hydrogenandfuelcells/pdfs/mcfc_pafc_workshop_farooque.pdf

Greene, D. L., Duleep, K. G., and Upreti, G. (2011). Status and Outlook for the U.S. Non-Automotive Fuel Cell Industry: Impacts of 

Government Policies and Assessment of Future Opportunities. (ORNL/TM-2011/101). Oak Ridge, TN: Oak Ridge National Laboratory. Accessed at http://cta.ornl.gov/cta/Publications/Reports/ORNL_TM2011_101_FINAL.pdf

In addition, DOE uses models to analyze the sensitivity of costs to durability and other parameter; for example, the fuel cell 

combined heat and power cost model at DOE Office of Energy Efficiency and Renewable Energy headquarters. The model is 

based on a levelized cost-of-generation model developed for the California Energy Commission: http://www.energy.ca.gov/reti/

documents/2011-04-18_Documentation_for_COG_Model.pdf

Prices of natural gas and electricity used in the modeling activity are from the Energy Information Administration’s Annual Energy 

Outlook 2011. 

The assumed discount rate used in the modeling activity is based on: 

Short, W., Packey, D. J., and Holt, T. (1995). A Manual for the Economic Evaluation of Energy Efficiency and Renewable Energy 

Technologies. Golden, CO: National Renewable Energy Laboratory. Accessed at http://www.nrel.gov/docs/legosti/old/5173.pdf

105Remick, R., and Wheeler, D. (2010). Molten Carbonate and Phosphoric Acid Stationary Fuel Cells: Overview and Gap Analysis. 

(NREL/TP-560-49072). Golden, CO: National Renewable Energy Laboratory and DJW Technology, LLC. Accessed at http://www.

nrel.gov/docs/fy10osti/49072.pdf.

Greene, D. L., Duleep, K. G., and Upreti, G. (2011). Status and Outlook for the U.S. Non-Automotive Fuel Cell Industry: Impacts of 

Government Policies and Assessment of Future Opportunities. (ORNL/TM-2011/101). Oak Ridge, TN: Oak Ridge National Laboratory. Accessed at http://cta.ornl.gov/cta/Publications/Reports/ORNL_TM2011_101_FINAL.pdf

106 Aldefer, R. B., Elridge, M., and Starrs, T. (2000). Making Connections. Case Studies of Interconnection Barriers and Their Impact 

on Distributed Generation Projects. (NREL/SR-200-28053). Golden, CO: National Renewable Energy Laboratory. Accessed at 

http://www.nrel.gov/docs/fy00osti/28053.pdf

Shirley, W. (2006). “Overview of Distributed Generation Interconnection Issues.” Washington, DC: Environmental Protection 

Agency. Accessed at http://www.epa.gov/statelocalclimate/documents/pdf/2_9_06_Overview_DG_Interconnection_Shirley.

pdf
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Brooks, S., Elswick, B., and Elliott, R. N. (2006). Combined Heat and Power: Connecting the Gaps Between Markets and Utility Interconnection and Tariff Practices (Part 1). Report No. 1E062. Washington, DC: American Council for an Energy-Efficient Economy. 

Accessed at http://www.aceee.org/sites/default/files/publications/researchreports/ie062.pdf 

107Morgan, J. (2010). “Reduction in Fabrication Costs of Gas Diffusion Layers.” Presentation at the Hydrogen and Fuel Cells Program Annual Merit Review and Peer Evaluation. Arlington, VA. Accessed at http://www.hydrogen.energy.gov/pdfs/review11/

mn002_morgan_2011_o.pdf

108 Busby, C. F. (2011). “Manufacturing of Low-Cost, Durable Membrane Electrode Assemblies Engineered for Rapid Conditioning.” 

Presentation at the Hydrogen and Fuel Cells Program Annual Merit Review and Peer Evaluation. Arlington, VA. Accessed at 

http://www.hydrogen.energy.gov/pdfs/review11/mn004_busby_2011_o.pdf 

109 Bessette, N. (2011). “Development of a Low Cost 3-10 kW Tubular SOFC Power System.” Presentation at the Hydrogen and Fuel 

Cells Program Annual Merit Review and Peer Evaluation. Arlington, VA. Accessed at http://www.hydrogen.energy.gov/pdfs/

review11/fc032_bessette_2011_o.pdf

110Gross, T. J., Poche, A. J., Jr., and Ennis, K. C. (2011). “Beyond Demonstration: The Role of Fuel Cells in DoD’s Energy Strategy.” 

Washington, DC: LMI. Accessed at http://www.ballard.com/files/PDF/Media/DoD-Fuel-Cell_10-19-11.pdf

 U.S. Department of Energy and U.S. Department of Defense. (2010). “Concerning Cooperation in a Strategic Partnership to Enhance Energy Security.” Memorandum of Understanding. Washington, DC. Accessed at http://energy.gov/sites/prod/files/edg/

media/Enhance-Energy-Security-MOU.pdf 

 U.S. Postal Service. (2011). U.S. Postal Service Fleet Alternative Vehicle Program Report for Fiscal Year 2010. Washington, DC. 

Accessed at http://about.usps.com/what-we-are-doing/green/news/afv-program-2010-report.htm

 U.S. Department of Energy. (2011). Market Transformation. Washington, DC. Accessed at http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/market_transformation.pdf

111Simon, M., Tyler, R., and Dillich, S. (2011). “Recovery Act Projects to Enable Fuel Cell Market Transformation.” Presentation at 

the Fuel Cell Seminar. Orlando, FL.

112 Energy Information Administration. (2008). Existing Electric Generating Units by Energy Source. Washington, DC. Accessed at 

http://www.eia.gov/cneaf/electricity/page/capacity/existingunitsbs2008.xls

113 Energy Information Administration. (2010). “Table 8.2a – Electricity Net Generation: Total (All Sectors), 1949-2009.” Annual 

Energy Review 2009. Accessed at http://205.254.135.24/emeu/aer/txt/stb0802a.xls

114 The National Academies. (2009) America’s Energy Future – Electricity From Renewable Resources. Washington, DC: The National Academies Press.

115Williams, C. F., Reed, M. J., Mariner, R. H., DeAngelo, J., and Galanis, S. P. J. (2008). Assessment of Moderate- and High-Temperature Geothermal Resources of the United States. U.S. Geological Survey Fact Sheet (2008-3082). Washington, DC: Department 

of Interior. Accessed at http://pubs.usgs.gov/fs/2008/3082 

This assessment considered 11 states in the western United States and depths between 3 km and 6 km.

116 Augustine, C., et al. (2010). Updated U.S. Geothermal Supply Curve. (NREL/CP-6A2-47458). Golden, CO: National Renewable 

Energy Laboratory. Accessed at http://www.nrel.gov/docs/fy10osti/47458.pdf

Most of the roughly 16,000-GWe deep enhanced geothermal system resource reported here is attributed to heat stored at depths 

greater than 6 km.

117 L’Ecuyer, C., et al. (1993). Space Conditioning: The Next Frontier. (EPA 430-R-93-004). Washington, DC: Environmental Protection 

Agency.

118 Lund, J. W., et al. (2010). Direct Utilization of Geothermal Energy 2010 Worldwide Review. [Proceedings World Geothermal 

Congress 2010]. Bali, Indonesia.

119 Doris, E., Kreycik, C., and Young, K. (2009). Policy Overview and Options for Maximizing the Role of Policy in Geothermal Electricity Development. (TP-6A2-46653). Golden, CO: National Renewable Energy Laboratory. Accessed at http://www1.eere.energy.

gov/geothermal/pdfs/policy_overview.pdf
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120 U.S. Department of Energy. (2011). Innovative Exploration Technologies Technology Needs Assessment. Washington, DC: Energetics, Inc. Accessed at http://www1.eere.energy.gov/geothermal/pdfs/iet_needs_assessment_06-2011.pdf

121Young, K. R., Augustine, C., and Anderson, A. (2010). Report on the U.S. DOE Geothermal Technologies Program’s 2009 Risk Assessment. (NREL/CP-6A2-47388). Golden, CO: National Renewable Energy Laboratory. Accessed at http://www.nrel.gov/docs/

fy10osti/47388.pdf 

122 Jennejohn, D. (2011). Annual Geothermal Power Production and Development Report. Washington, DC: Geothermal Energy Association. 

123 Lund, J., Gawell, K., Boyd, T., and Jennejohn, D. (2010). The United States of America Country Update 2010. Proceedings of the 

Thirty-Fifth Workshop on Geothermal Reservoir Engineering. Accessed at http://ere.stanford.edu/pdf/IGAstandard/SGW/2010/

lund.pdf 

124 Energy Information Administration (2009). Geothermal Heat Pump Manufacturing Activities. Washington, DC. Accessed at http://

www.eia.gov/cneaf/solar.renewables/page/ghpsurvey/ghpssurvey.html 

125Massachusetts Institute of Technology. (2006). The Future of Geothermal Energy. Cambridge, MA. Accessed at http://geothermal.inel.gov/publications/future_of_geothermal_energy.pdf 

126 For more information on innovative exploration technologies, see:

 U.S. Department of Energy. (2011). Innovative Exploration Technologies Technology Needs Assessment. Washington, DC: Energetics, Inc. Accessed at http://www1.eere.energy.gov/geothermal/pdfs/iet_needs_assessment_06-2011.pdf

Young, K., Reber, T., and Witherbee, K. “Hydrothermal Exploration Best Practices and Geothermal Knowledge Exchange on 

OPENEI.” Proceedings of the Thirty-Seventh Workshop on Geothermal Reservoir Engineering. Stanford University. Stanford, CA. 

January 30, 2012–February 1, 2012. Accessed at http://pangea.stanford.edu/ERE/pdf/IGAstandard/SGW/2012/Young.pdf 

 U.S. Department of Energy. (2012). “Geothermal Technologies Program Projects Database.” Washington, DC. Accessed February 

2012 at http://www4.eere.energy.gov/geothermal/projects 

127Majer, E. L. (2010). Final Report and Recommendations, Workshop on Induced Seismicity Due to Fluid Injection/production from 

Energy Related Applications. Berkeley, CA: Lawrence Berkeley National Laboratory. Accessed at http://www.escholarship.org/

uc/item/6rk229pv 

128Massachusetts Institute of Technology. (2006). The Future of Geothermal Energy. Cambridge, MA. Accessed at http://geothermal.inel.gov/publications/future_of_geothermal_energy.pdf 

129 U.S. Department of Energy. (2010). Exploration 1976-2006: A History of Geothermal Energy Research and Development in the 

United States. Washington, DC. Accessed at http://www1.eere.energy.gov/geothermal/pdfs/geothermal_history_1_exploration.pdf 

130 U.S. Department of Energy. (2011). Geothermal Technology Program Blue Ribbon Panel Report. Washington, DC. Accessed at 

http://www1.eere.energy.gov/geothermal/brp.html 

131 Energy Information Administration. (2011). International Energy Statistics. Washington, DC. Accessed June 2011 at http://www.

eia.gov/countries/data.cfm 

132 Energy Information Administration. (2011). “Total Electricity Installed Capacity.” International Energy Statistics. Washington, DC. 

Accessed November 2011 at http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid=2&aid=7 

133 International Atomic Energy Agency. (2011). Power Reactor Information System. Vienna, Austria. Accessed at http://www.iaea.

org/programmes/a2/

134 Energy Information Administration. (2011). U.S. Nuclear Statistics. Washington, DC: Energy Information Administration. Accessed at http://www.eia.gov/cneaf/nuclear/page/operation/statoperation.html. 

135Nuclear Regulatory Commission. (2011). Expected New Nuclear Power Plant Applications. Washington, DC. Accessed at http://

www.nrc.gov/reactors/new-reactors/new-licensing-files/expected-new-rx-applications.pdf
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136 International Atomic Energy Agency. (2011). Power Reactor Information System. Vienna, Austria. Accessed at http://www.iaea.

org/programmes/a2/

137 Energy Information Administration. (2009). Annual Energy Review 2009. (DOE/EIA-0384(2009). Washington, DC. Accessed at 

http://www.eia.gov/totalenergy/data/annual/index.cfm 

138 Energy Information Administration. (2009). Annual Energy Review 2009, Table 9.2. (DOE/EIA-0384(2009). Washington, DC. Accessed at http://www.eia.gov/totalenergy/data/annual/index.cfm 

139Nuclear Waste Policy Act of 1982 42 U.S.C. 10101 (1987). Accessed at http://epw.senate.gov/nwpa82.pdf 

140US Code - Section 10172: Selection of Yucca Mountain site. 42 U.S.C. § 10172 (1987).

141Office of Management and Budget. (2009). A New Era of Responsibility: Renewing America’s Promise FY 2010 Budget Request. 

Washington, DC. Accessed at http://www.whitehouse.gov/sites/default/files/omb/assets/fy2010_new_era/A_New_Era_of_

Responsibility2.pdf. 

142Nuclear Regulatory Commission. (2011). Status of License Renewal Applications and Industry Activities. Washington, DC. Accessed at http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html, 

143Nuclear Regulatory Commission. (2011). Approved Applications for Power Uprates. Washington, DC. Accessed at http://www.

nrc.gov/reactors/operating/licensing/power-uprates/status-power-apps/approved-applications.html

144Nuclear Regulatory Commission. (2011). Pending Applications for Power Uprates. Washington, DC. Accessed at http://www.nrc.

gov/reactors/operating/licensing/power-uprates/status-power-apps/pending-applications.html

Nuclear Regulatory Commission. (2011). Expected Applications for Power Uprates. Washington, DC. Accessed June 2011 at 

http://www.nrc.gov/reactors/operating/licensing/power-uprates/status-power-apps/expected-applications.html 

145Oak Ridge National Laboratory. (2010). Consortium for Advanced Simulation of LWRs, A Project Summary. Oak Ridge, TN. Accessed at http://www.casl.gov/wp-content/uploads/2011/01/CASL_Project_Summary11-24-10.pdf.

By way of comparison, the Consortium for Advanced Simulation of Light-Water Reactors Hub has considered potential uprates 

as high as 20 GWe, while the reference case of the Energy Information Administration’s Annual Energy Outlook includes an additional 7.3 GWe in uprates (Table A9, fn. 5).

146 International Atomic Energy Agency. (2002). Cost drivers for the assessment of nuclear power plant life extension. (IAEA-TECDOC-1309). Vienna, Austria. Accessed at http://www-pub.iaea.org/MTCD/publications/PDF/te_1309_web.pdf 

147 Derived from: Georgia Power. (2011). “Plant Vogtle Units 3 & 4: Fourth Semi-Annual Construction Monitoring Report.” Submitted 

to the Georgia Public Service Commission, Docket No. 29849, Document 134428. 

148U.S. Department of Energy, Office of Nuclear Energy. (2009). Light Water Reactor Sustainability Research and Development 

Program Plan, FY 2009 – 2013. (INL/MIS-08-14918). Accessed at http://www.ne.doe.gov/pdfFiles/LWR_sustainabilty_program_

plan.pdf 

149U.S. Department of Energy, Office of Nuclear Energy. (2009). Light Water Reactor Sustainability Research and Development 

Program Plan, FY 2009 – 2013. (INL/MIS-08-14918). Accessed at http://www.ne.doe.gov/pdfFiles/LWR_sustainabilty_program_

plan.pdf 

150U.S. Department of Energy, Office of Nuclear Energy. (2009). Light Water Reactor Sustainability Research and Development 

Program Plan, FY 2009 – 2013. (INL/MIS-08-14918). Accessed at http://www.ne.doe.gov/pdfFiles/LWR_sustainabilty_program_

plan.pdf 

151 International Atomic Energy Agency. (2004). Status of Advanced Light Water Reactor Designs, 2004. (IAEA-TECDOC-1391). Vienna, Austria. 

152Nuclear Energy Research Advisory Committee. (2001). Subcommittee on Generation IV Technology Planning, A Roadmap to 

Deploy New Nuclear Power Plants in the United States by 2010. Washington, DC. 

153 International Atomic Energy Agency. (2011). Power Reactor Information System Database. Vienna, Austria. 
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154 U.S. Nuclear Regulatory Commission. (2012). “NRC Concludes Hearing on Vogtle New Reactors, First-Ever Combined Licenses to 

be Issued.” Washington, DC. Accessed at http://pbadupws.nrc.gov/docs/ML1204/ML120410133.pdf 

155Overnight costs reflect how much it would cost to build a plant without consideration of time effects or financing costs. The key 

distinction is that overnight costs capture the cost of the technology, whereas the total investment cost also reflects the financial 

characteristics of the company planning to build the plant and the schedule they choose.

156 The National Academies. (2009). America’s Energy Future. Washington, DC: The National Academy Press.

157 Du, Y., and Parsons, J. (2009). Update on the Cost of Nuclear Power. Cambridge, MA: Center for Energy and Environmental Policy 

Research, Massachusetts Institute of Technology. Accessed at http://web.mit.edu/mitei/docs/spotlights/nuclear-fuel-cycle-du.

pdf 

Nuclear Energy Institute. (2011). The Cost of New Generating Capacity in Perspective. Washington, DC. 

Electric Power Research Institute. (2011). Program on Technology Innovation: Integrated Generation Technology Options. Palo 

Alto, CA.

158 Du, Y., and Parsons, J. (2009). Update on the Cost of Nuclear Power. Cambridge, MA: Center for Energy and Environmental Policy 

Research. Massachusetts Institute of Technology. Accessed at http://web.mit.edu/mitei/docs/spotlights/nuclear-fuel-cycle-du.

pdf 

Nuclear Energy Institute. (2011). The Cost of New Generating Capacity in Perspective. Washington, DC. 

Electric Power Research Institute. (2011). Program on Technology Innovation: Integrated Generation Technology Options. Palo 

Alto, CA.

159 Energy Information Administration. (2010). “Statement of Income.” Electric Power Operations. Washington, DC. Accessed at 

http://www.eia.gov/pub/energy.overview/frs/s5810.xls 

160 Economic Co-Operation and Development Nuclear Energy Agency. (2011). Current Status, Technical Feasibility and Economics of 

Small Nuclear Reactors. Issy-les-Moulineaux, France: Nuclear Energy Agency.

161 Economic Co-Operation and Development Nuclear Energy Agency. (2011). Current Status, Technical Feasibility and Economics of 

Small Nuclear Reactors. Issy-les-Moulineaux, France: Nuclear Energy Agency. 

162Rosner, R., and Goldberg, S. (2011). “Small Modular Reactors – Key to Future Nuclear Power Generation in the U.S.” Chicago, IL: 

Energy Policy Institute at Chicago, University of Chicago. Accessed at http://harrisschool.uchicago.edu/centers/hepi/SMR%20

Final%20White%20Paper%207-11.pdf 

163 American Nuclear Society. (2010). Interim Report of the American Nuclear Society President’s Special Committee on Small and 

Medium Sized Reactor (SMR) Generic Licensing Issues. 

Nuclear Regulatory Commission. (2010). Potential Policy, Licensing, and Key Technical Issues for Small Modular Nuclear Reactor 

Designs. (SECY-10-0034). Washington, DC. Accessed at http://pbadupws.nrc.gov/docs/ML0932/ML093290268.pdf 

164Generation IV International Forum. (2010) Overview of GIF. Issy-les-Moulineaux, France: Nuclear Energy Agency. Accessed at 

http://www.gen-4.org/PDFs/GIF_Overview.pdf 

165 U.S. Department of Energy. (2010). Nuclear Energy Research and Development Roadmap Report to Congress. Washington, DC. 

Accessed at http://www.nuclear.gov/pdfFiles/NuclearEnergy_Roadmap_Final.pdf 

166National Research Council of the National Academies. (2008). Review of DOE’s Nuclear Energy Research and Development 

Program. Washington, DC: National Academies Press.

167 Idaho National Laboratory. (2011). High Temperature Gas-Cooled Reactor Projected Marketes and Preliminary Economics. (INL/

EXT-10-19037). Idaho Falls, ID.

168 Energy Information Administration. (2011). “Natural Gas Prices.” Monthly Energy Review, Table 9.11. Washington, DC. Accessed 

July 2011 at http://www.eia.gov/totalenergy/data/monthly/pdf/sec9_17.pdf 
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169Generation IV International Forum. (2009). GIF R&D Outlook for Generation IV Nuclear Energy Systems. Issy-les-Moulineaux, 

France: Nuclear Energy Agency. Accessed at http://www.gen-4.org/PDFs/GIF_RD_Outlook_for_Generation_IV_Nuclear_Energy_Systems.pdf 

170World Nuclear Association. (2011). Fast Neutron Reactors. London, England.

171Nuclear Energy Institute. (2010). Safely Managing Used Nuclear Fuel. Washington, DC. 

172 Blue Ribbon Commission on America’s Nuclear Future. (2011). Blue Ribbon Commission on America’s Nuclear Future Report to 

the Secretary of Energy. Washington, DC. Accessed at http://brc.gov/sites/default/files/documents/brc_finalreport_jan2012.pdf 

173 U.S. Department of Energy. (2010). Nuclear Energy Research and Development Roadmap Report to Congress. Washington, DC. 

Accessed at http://www.nuclear.gov/pdfFiles/NuclearEnergy_Roadmap_Final.pdf 

174Oak Ridge National Laboratory. (2010). Consortium for Advanced Simulation of LWRs, A Project Summary. Oak Ridge, TN. Accessed at http://www.casl.gov/wp-content/uploads/2011/01/CASL_Project_Summary11-24-10.pdf.

175 U.S. Department of Energy. (2011). Small Modular Reactors Fact Sheet. Washington, DC. Accessed at http://www.ne.doe.gov/

pdfFiles/factSheets/2012_SMR_Factsheet_final.pdf 

176Assuming a 1% increase in global electricity supply from 2008 to 2010 and a 16% average capacity factor for photovoltaic. In 

2008, global electricity generation totaled 20,260,838 GWh. 

International Energy Agency. (2008). Electricity/Heat Energy Statistics 2008. Paris, France. Accessed at http://www.iea.org/

stats/electricitydata.asp?COUNTRY_CODE=29 

177Solar Energy Industry Association. (2011). US Solar Market Insight – 2010 Year in Review. Washington, DC: GTM Research.

178 Energy Information Administration. (2011). “Electricity Net Generation: Total (All Sectors).” Annual Energy Review. Washington, 

DC. Accessed November 2011 at http://www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb0802a 

179 The $6 billion figure includes revenue associated with the sale of photovoltaic in the United States. 

Solar Energy Industry Association. (2010). US Solar Market Insight – 2010 Year in Review. Washington, DC: GTM Research. 

180Solar Energy Industry Association. (2010). US Solar Market Insight – 2010 Year in Review. Washington, DC: GTM Research.

181Sherwood, L. (2011). U.S. Solar Market Trends 2010. Latham, NY: Interstate Renewable Energy Council. Accessed at http://

irecusa.org/wp-content/uploads/2011/07/IREC-Solar-Market-Trends-Report-revised070811.pdf

182 Prices in current U.S. dollars.

183Mints, P. (2011). Photovoltaic Manufacturer Shipments, Capacity, & Competitive Analysis 2010/2011. (Report # NPS-Supply6). 

Palo Alto, CA: Navigant Consulting Photovoltaic Service Program.

184 Bloomberg New Energy Finance. (2012). “February Solar Spot Price Index.” New York, NY.

185 UBS. (2012). Global Solar Industry Update. Volume 6. April 19, 2012.

186Mints, P. (2011). Photovoltaic Manufacturer Shipments, Capacity, & Competitive Analysis 20010/2011. (Report # NPS-Supply6). 

Palo Alto, CA: Navigant Consulting Photovoltaic Service Program.

187Goodrich, A., et al. (2011). Residential, Commercial, and Utility-Scale Photovoltaic System Prices in the United States: Current 

Drivers and Cost Reduction Opportunities. (NREL/TP-6A20-53347). Boulder, CO: National Renewable Energy Laboratory. 

188 Implied non-module costs were calculated by the difference between the installed cost and the module cost. 

189 Lawrence Berkley National Laboratory. (2010). Tracking the Sun III. The Installed Cost of Photovoltaics in the US from 1998–2009. 

(LBNL-4121E). Berkeley, CA. 

190 The average installed cost of 3–5 kW residential photovoltaic installations in 2009 (excluding sales/value-added tax) was significantly lower in both Germany ($4.7/W) and Japan ($5.9/W) than in the United States ($7.7/W). Average installed costs vary 

widely across states; among ≤10 kW systems completed in 2009, average costs range from a low of $7.1/W in Texas to a high 

of $9.6/W in Minnesota. 
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 Lawrence Berkley National Laboratory. (2010). Tracking the Sun III. The Installed Cost of Photovoltaics in the US from 1998–2009. 

(LBNL-4121E). Berkeley, CA. Accessed at http://eetd.lbl.gov/ea/ems/reports/lbnl-4121e.pdf 

191 U.S. Department of Energy. (2012). SunShot Vision Study. (DOE/GO-102012-3037). Washington, DC. Accessed at http://www1.

eere.energy.gov/solar/pdfs/47927.pdf 

192 PV Tech. “Balancing act: Study finds solid US solar exports, value accrual; developer sees falling module cost.” August 31, 2011. 

193Mints, P. (2010). Photovoltaic Manufacturer Shipments, Capacity, & Competitive Analysis 2009/2010. (Report # NPS-Supply5). 

Palo Alto, CA: Navigant Consulting Photovoltaic Service Program.

194Residential scale system. Note, utility scale inverters have a longer average lifetime than residential scale system inverters. 

195Shaheen, S. E., Ginley, D. S., and Jabbour, G. E. (2005). “Organic-Based Photovoltaics: Toward Low-Cost Power Generation.” 

MRS Bulletin. 30( 1):10-15.

196 Denholm, P., Margolis, R., Ong, S., and Roberts, B. (2009). Break-Even Cost for Residential Photovoltaics in the United States: Key 

Drivers and Sensitivities. (NREL/TP-6A2-46909). Golden, CO: National Renewable Energy Laboratory. 

197 U.S. Department of Energy. (2010). Critical Materials Strategy. Washington, DC. Accessed at http://energy.gov/sites/prod/files/

edg/news/documents/criticalmaterialsstrategy.pdf 

198Mints, P. (2011). Photovoltaic Manufacturer Shipments, Capacity, & Competitive Analysis 2010/2011. (Report # NPS-Supply6). 

Palo Alto, CA: Navigant Consulting Photovoltaic Service Program.

199Mints, P. (2011). Photovoltaic Manufacturer Shipments, Capacity, & Competitive Analysis 2010/2011. (Report # NPS-Supply6). 

Palo Alto, CA: Navigant Consulting Photovoltaic Service Program.

200See www.dsireusa.org for the most up-to-date information on state, utility, and local policies regarding renewable energy and 

energy efficiency.

201Solar Energy Industry Association. (2010). US Solar Market Insight – 2010 Year in Review. Washington, DC: GTM Research.

202RTI International. (2010). Retrospective Benefit-Cost Evaluation of DOE Investment in Photovoltaic Energy Systems. Research 

Triangle Park, NC.

203Ruegg, R., and Thomas, P. (2011). Linkages from DOE’s Solar Photovoltaic R&D to Commercial Renewable Power from Solar 

Energy. (DOE/EE-0403). Washington, DC: Department of Energy. 

204U.S. Department of Energy. (2012). SunShot Vision Study. (DOE/GO-102012-3037). Washington, DC. Accessed at http://www1.

eere.energy.gov/solar/pdfs/47927.pdf 

205 Energy Information Administration. (2011). Electric Power Annual 2009. Washington, DC. Accessed at http://www.eia.gov/

cneaf/electricity/epa/epa_sum.html

206 Energy Information Administration. (2010). Updated Capital Cost Estimates for Electricity Generation Plants. Washington, DC. 

Accessed at http://www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf 

207 Energy Information Administration. (2011). Annual Energy Outlook 2011, Levelized Cost of New Generation Resources. Washington, DC. Accessed at http://www.eia.gov/oiaf/aeo/electricity_generation.html 

208 Energy Information Administration. (2011). FERC Form 1. Washington, DC.

209 International Energy Agency. (2010). Renewable Energy Essentials: Hydropower. Paris, France. Accessed at http://www.iea.org/

papers/2010/Hydropower_Essentials.pdf

210 International Energy Agency. (2010). Energy Systems Technology Analysis Program Technology Brief: Hydropower. Paris, France. 

Accessed at http://www.etsap.org/E-techDS/PDF/E07-hydropower-GS-gct.pdf

211 Energy Information Administration. (2011). “Hydroelectric Net Generation” and “Total Electricity Net Generation.” International 

Energy Statistics. Washington, DC: Department of Energy. 

212 International Energy Agency. (2010). Key World Energy Statistics 2010. Paris, France. Accessed at http://www.iea.org/textbase/

nppdf/free/2010/key_stats_2010.pdf
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213 Bureau of Reclamation. (2009). “The History of Hydropower Development in the United States.” Washington, DC. Accessed at 

http://www.usbr.gov/power/edu/history.html

214Bureau of Reclamation. (2009). “The History of Hydropower Development in the United States.” Washington, DC. Accessed at 

http://www.usbr.gov/power/edu/history.html

215 Idaho National Laboratory. (2012). “Hydropower’s Historical Progression.” Idaho Falls, ID. Accessed at http://hydropower.inel.

gov/hydrofacts/historical_progression.shtml 

216Gordon, J. L. (2001). Hydraulic Turbine Efficiency. Canadian Journal of Civil Engineering. 28(2):238–253.

217 For example, the Electric Power Research Institute’s efforts in quantifying the full value of hydropower on the electric grid 

(more information at http://my.epri.com/portal/server.pt?open=512&objID=396&&PageID=241272&mode=2&in_hi_

userid=2&cached=true); the International Energy Agency’s Implementing Agreement for Hydropower Technologies and Programmes, Annex IV: Hydropower Services (more information at http://www.ieahydro.org/Hydropower_Services3.html); and the 

International Energy Agency’s Task 24 on Integrating Wind and Hydropower Systems (more information at http://www.ieawind.

org/summary_page_24.html). 

218National Hydropower Asset Assessment Project. “Existing Hydropower Assets.” Washington, DC: Department of Energy. Accessed at http://nhaap.ornl.gov/content/existing-hydropower-assets

219National Hydropower Asset Assessment Project. “Existing Hydropower Assets.” Washington, DC: Department of Energy. Accessed at http://nhaap.ornl.gov/content/existing-hydropower-assets

220 Electric Power Research Institute. (2007). Assessment of Waterpower Potential and Development Needs. Palo Alto, CA. Accessed at http://www.aaas.org/spp/cstc/docs/07_06_1ERPI_report.pdf 

221March, P. A., and Wolff, P. J. (2003). Optimization-Based Hydro Performance Indicator. Proceedings of WaterPower XIII. 

U.S. Department of the Interior, U.S. Department of the Army, U.S. Department of Energy. (2007). Potential Hydroelectric Development at Existing Federal Facilities. Washington, DC: Government Printing Office.

222 U.S. Department of Energy. (2011). An Assessment of Energy Potential at Non-Powered Dams in the United States. Oak Ridge, 

TN. Accessed at http://nhaap.ornl.gov/content/non-powered-dam-potential

223 U.S. Department of Energy. (2004). Water Energy Resources of the United States with Emphasis on Low Head/Low Power Resources. (DOE/ID-11111). Washington, DC. Accessed at http://hydropower.inel.gov/resourceassessment/pdfs/03-11111.pdf 

224 Energy Information Administration. (2010). Updated Capital Cost Estimates for Electricity Generation Plants. Washington, DC. 

Accessed at http://www.eia.gov/oiaf/beck_plantcosts/ 

225Cost estimates for American Municipal Power’s low-head Ohio River lock and dam projects lie at the higher end of this range. 

See http://amppartners.org/generation-assets/hydroelectric/ for more information. 

226 Despite being a small project at 5 MW, the redevelopment of the Boulder Canyon Hydroelectric Facility has cost only $1,000/kW, 

reflecting high power density and favorable site characteristics. See http://www.bouldercolorado.gov/index.php?option=com_

content&view=article&id=12679&Itemid=4608 for more information. 

227Oak Ridge National Laboratory. (2010). Summary Report of the 2010 Summit Meeting on Environmental Mitigation Technology 

for Hydropower. Oak Ridge, TN. Accessed at http://www.esd.ornl.gov/WindWaterPower/EMTSSummit.pdf 

228 U.S. Department of Energy and U.S. Department of Homeland Security. (2011). Dams and Energy Sectors Interdependency Study. 

Washington, DC. Accessed at http://energy.gov/sites/prod/files/Dams-Energy%20Interdependency%20Study.pdf 

229 Division of Hydropower Administration Compliance. (2004). Compliance Handbook. Washington, DC: Federal Energy Regulatory 

Commission. Accessed at http://www.ferc.gov/industries/hydropower/gen-info/handbooks/compliance_handbook.pdf 

230 Bedard, R. (2009). Testimony on Marine and Hydrokinetic Technologies: Finding the Pathway to Commercialization. [House Committee on Science and Technology, Subcommittee on Energy and Environment]. Washington, DC: Government Printing Office. 

Accessed at http://gop.science.house.gov/Media/hearings/energy09/dec3/Bedard.pdf
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231 Ocean Energy Systems. (2011). Annual Report 2011: Implementing Agreement on Ocean Energy Systems. p. 122. Lisbon, Portugal. Accessed at http://www.ocean-energy-systems.org/documents/17069_oes_annual_report_web_21marv2.pdf/

232 International Energy Agency. (2011). Implementing Agreement on Ocean Energy Systems (OES-IA), Annual Report 2010, Implementing Agreement on Ocean Energy Systems. Paris, France. Accessed at http://www.iea-oceans.org/_fich/6/2010_Annual_

Report.pdf

233 U.S. Department of Energy. (2011). Marine and Hydrokinetic Technology Database. Washington, DC. Accessed at http://www1.

eere.energy.gov/water/hydrokinetic/default.aspx 

234 Data retrieved from CleanTech PatentEdgeTM online patent and intellectual property research service. 

235U.S. Department of Energy. (2006). DOE Hydropower Program Biennial Report 2005-2006. Oak Ridge, TN. Accessed at http://

hydropower.inel.gov/techtransfer/pdfs/binennial_report_fy_2005_2006.pdf

236U.S. Department of Energy. (2006). DOE Hydropower Program Biennial Report 2005-2006. Oak Ridge, TN. Accessed at http://

hydropower.inel.gov/techtransfer/pdfs/binennial_report_fy_2005_2006.pdf

237 Efficiency is defined as the power generated by the turbine (as measured by torque force and RPM) divided by the power available in the water at the inlet of the turbine (a function of head, flow, and water density).

238 Electric Power Research Institute. (2011). “Fish Friendly” Hydropower Turbine Development and Deployment: Alden Turbine 

Preliminary Engineering and Model Testing. Palo Alto, CA. 

239 Thresher, R. (2010). First Draft Roadmap: The United States Marine Hydrokinetic Renewable Energy Technology Roadmap. Golden, 

CO: National Renewable Energy Laboratory. Accessed at http://www.oceanrenewable.com/wp-content/uploads/2010/05/1stdraft-roadmap-rwt-8april10.pdf

240 U.K. Department of Energy and Climate Change. (2009). Marine Energy Action Plan 2010, Executive Summary & Recommendations. London, England. Accessed at http://www.decc.gov.uk/en/content/cms/meeting_energy/wave_tidal/funding/marine_action/marine_action.aspx 

241Columbia Power Technologies is a renewable energy company developing wave energy convertors. Accessed at http://www.

businesswire.com/news/home/20110308006644/en/Columbia-Power-Technologies-Secures-Governmental-Private-Funding

242 Free Flow Power is a hydropower developer focusing on conventional hydropower, pumped storage hydropower, and marine and 

hydrokinetic energy. Accessed at http://www.free-flow-power.com/news__and__events#mp1

243Global Wind Energy Council. (2010) Global Wind Report: Annual Market Update 2010. Brussels, Belgium. Accessed at http://

www.gwec.net/fileadmin/images/Publications/GWEC_annual_market_update_2010_-_2nd_edition_April_2011.pdf 

244Generation data for 2010 from the U.S. Department of Energy’s Energy Information Administration (does not account for a full 

year’s production from 2010 installations because new wind farms were being added throughout the year).

245 U.S. Department of Energy. (2008). 20% Wind Energy by 2030. (DOE/GO-102008-2567). Washington, DC. Accessed at http://

www.nrel.gov/docs/fy08osti/41869.pdf 

246Black & Veach. (2007). 20 Percent Wind Energy Penetration in the United States: A Technical Analysis of the Energy Resource. 

Walnut Creek, CA. Accessed at http://www.20percentwind.org/Black_Veatch_20_Percent_Report.pdf 

247National Renewable Energy Laboratory. (2012). U.S. 80m Wind Resource Maps. Golden, CO. Accessed at http://www.nrel.gov/

gis/wind.html 

248 Electricity costs include neither transmission costs nor firming costs. Land-based wind power prices are prices charged to utilities from real projects. They are suppressed by the receipt of available state and federal incentives and do not represent the 

costs to produce the electricity. Offshore price reflects the 2010 cost of a shallow water monopile platform and does not include 

subsidies. Because there are no domestic offshore wind power projects, these two prices cannot be directly compared.

249Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf
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250Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf

251Musial, W., and Ram, B. (2010). Large-Scale Offshore Wind Power in the United States: Assessment of Opportunities and Barriers. (TP-500-40745). Golden, CO: National Renewable Energy Laboratory. Accessed at http://www.nrel.gov/wind/pdfs/40745.

pdf

252 U.S. Department of Energy. (2011). A National Offshore Wind Strategy: Creating an Offshore Wind Industry in the United States. 

Washington, DC: U.S. Department of Energy and U.S. Department of the Interior. Accessed at http://www1.eere.energy.gov/

wind/pdfs/national_offshore_wind_strategy.pdf 

253 Energy Information Administration. (2010). Levelized Cost of New Generation Resources in the Annual Energy Outlook 2011. 

Washington, DC. Accessed at http://www.eia.gov/oiaf/aeo/pdf/2016levelized_costs_aeo2011.pdf 

254 American Wind Energy Association. (2010). Small Wind Turbine Global Market Study. Washington, DC. Accessed at http://www.

awea.org/learnabout/smallwind/upload/2011_turbine_market_report.pdf 

255 American Wind Energy Association. (2010). Small Wind Turbine Global Market Study. Washington, DC. Accessed at http://www.

awea.org/learnabout/smallwind/upload/2011_turbine_market_report.pdf

256 Intergovernmental Panel on Climate Change. (2011). IPCC Special Report on Renewable Energy Sources and Climate Change 

Mitigation, Summary for Policymakers. Cambridge, United Kingdom, and New York, NY, USA: Cambridge University Press. Accessed at http://srren.ipcc-wg3.de/report 

257 Intergovernmental Panel on Climate Change. (2011). IPCC Special Report on Renewable Energy Sources and Climate Change 

Mitigation, Wind Energy. Cambridge, United Kingdom, and New York, NY, USA: Cambridge University Press. Accessed at http://

www.ipcc.ch/news_and_events/docs/ipcc33/SRREN_FD_SPM_final.pdf 

258Global Wind Energy Council. (2011). Global Wind Report: Annual Market Update 2010. Brussels, Belgium. Accessed at http://

www.gwec.net/fileadmin/documents/Publications/Global_Wind_2007_report/GWEC%20Global%20Wind%20Report%20

2010%20low%20res.pdf 

259U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. (2011). 2010 Wind Technologies Market Report. 

Washington, DC. (DOE/GO-102011-3322). Accessed at http://www1.eere.energy.gov/wind/pdfs/51783.pdf 

260National Renewable Energy Laboratory estimate based on data from the American Wind Energy Association. 

 American Wind Energy Association. (2011). Year End 2010 Market Report. Washington DC. Accessed at: http://www.awea.org/

documents/reports/4Q10_market_outlook_public.pdf 

Wiser, R., and M. Bolinger. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf

261 American Wind Energy Association. (2011). Year End 2010 Market Report. Washington DC. Accessed at http://www.awea.org/

documents/reports/4Q10_market_outlook_public.pdf 

Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf

262 American Wind Energy Association. (2011). Year End 2010 Market Report. Washington DC. Accessed at http://www.awea.org/

documents/reports/4Q10_market_outlook_public.pdf 

263Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf 

264 Installed cost data are reported as overnight capital costs and are adjusted from total capital cost. 

Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf

265Musial, W., and Ram, B. (2010). Large-Scale Offshore Wind Power in the United States: Assessment of Opportunities and Barriers. (TP-500-40745). Golden, CO: National Renewable Energy Laboratory. Accessed at http://www.nrel.gov/wind/pdfs/40745.

pdf
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266Greater uncertainty in actual installation and operations and maintenance costs requires that project owners, as well as construction and maintenance firms maintain additional financial reserves (which translates into higher costs) to address potential 

cost overruns or other unforeseen costs.

267Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf 

268 Power prices noted in the text and in Figure 4 include Renewable Energy Credits (REC), but do not reflect the value of the federal 

tax credits, state and local incentives, or environmental attributes not captured in REC payments and therefore do not represent 

wind energy generation costs. The prices would be at least $20/MWh higher without the production tax credit, investment tax 

credit, or treasury grant. 

Wiser, R., and Bolinger, M. (2010). 2009 Wind Technologies Market Report. Washington, DC: Department of Energy. (DOE/GO102010-3107). Accessed at http://eetd.lbl.gov/ea/emp/reports/lbnl-3716e.pdf 

269 U.S. Department of Energy. (2008). 20% Wind Energy by 2030. Washington, DC. (DOE/GO-102008-2567). Accessed at http://

www.nrel.gov/docs/fy08osti/41869.pdf

270 U.S. Department of Energy. (2010). Critical Materials Strategy. Washington, DC. Accessed at http://energy.gov/sites/prod/files/

edg/news/documents/criticalmaterialsstrategy.pdf 

271 U.S. Department of Energy. (2008). 20% Wind Energy by 2030. Washington, DC. (DOE/GO-102008-2567). Accessed at http://

www.nrel.gov/docs/fy08osti/41869.pdf 

European Renewable Energy Council and Greenpeace International. (2008). Energy [R]evolution: A Sustainable World Energy 

Outlook. Brussels, Belgium. Accessed at http://www.energyblueprint.info/fileadmin/media/documents/energy_revolution.pdf 

 Lemming, J. K., Morthorst, P. E., Clausen, N. E., and Hjuler Jensen, P. (2009). Contribution to the Chapter on Wind Power in Energy 

Technology Perspectives 2008. (Risø-R-1674(EN)). Roskilde, Denmark: Risø National Laboratory for Sustainable Energy. Accessed 

at http://130.226.56.153/rispubl/reports/ris-r-1674.pdf 

Tidball, R., Bluestein, J., Rodriguez, N., and Knoke, S. (2010). Cost and Performance Assumptions for Modeling Electricity Generation Technologies. (NREL/SR-6A20-48595). Fairfax, VA: ICF International. Accessed at http://www.nrel.gov/docs/fy11osti/48595.

pdf 

272 U.S. Department of Energy. (2008). 20% Wind Energy by 2030. (DOE/GO-102008-2567). Washington, DC. Accessed at http://

www.nrel.gov/docs/fy08osti/41869.pdf 

European Renewable Energy Council and Greenpeace International. (2008). Energy [R]evolution: A Sustainable World Energy 

Outlook. Brussels, Belgium. Accessed at http://www.energyblueprint.info/fileadmin/media/documents/energy_revolution.pdf 

 Lemming, J. K., Morthorst, P. E., Clausen, N. E., and Hjuler Jensen, P. (2009). Contribution to the Chapter on Wind Power in Energy 

Technology Perspectives 2008. (Risø-R-1674(EN)). Roskilde, Denmark: Risø National Laboratory for Sustainable Energy. Accessed 

at http://130.226.56.153/rispubl/reports/ris-r-1674.pdf 

 U.S. Department of Energy. (2011). 2010 Wind Technologies Market Report. (DOE/GO-102011-3322). Washington, DC. Accessed 

at http://www1.eere.energy.gov/wind/pdfs/51783.pdf 

273 The trends would be similar for Class III resources because the technology advances associated with larger rotors, taller towers, 

and improved component reliability that lead to these projections are not dependent upon the wind resource class.

274 Levelized cost of electricity (LCOE) and capital cost are presented as a percentage change of the 2010 baseline and reflect the 

values indicated in the DOE projected goals table. LCOE is obtained by dividing the capital cost by the annual energy production. Here the capital cost is decreasing (red) while the capacity factor (red line) and corresponding annual energy production 

increases. The combined effect of lower capital cost and increased annual energy production lowers the associated LCOE below 

the capital cost as shown.

275Offshore turbines are expected to be larger than their onshore counterparts to minimize foundation, interconnection, and electrical infrastructure, as well as the number of trips to and from port. In addition, offshore-specific turbines will be designed to 

maximize the ease and efficiency of maintenance trips to individual turbines.
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276Musial, W., and Ram, B. (2010). Large-Scale Offshore Wind Power in the United States: Assessment of Opportunities and Barriers. Golden, CO: National Renewable Energy Laboratory. (TP-500-40745).

277 International Energy Agency. (2009). Technology Roadmap, Wind Energy. Paris, France. Accessed at http://www.ieawind.org/

wnd_info/IEA_Paris/Wind_Roadmap.pdf 

278 U.S. Department of Energy. (2008). 20% Wind Energy by 2030. Washington, DC. (DOE/GO-102008-2567). Accessed at http://

www.nrel.gov/docs/fy08osti/41869.pdf

279Mills, A., Wiser, R., and Porter, K. (2009). The Cost of Transmission for Wind Energy: A Review of Transmission Planning Studies. 

(LBNL-1471E). Berkeley, CA: Lawrence Berkeley National Laboratory.

280Mills, A., Wiser, R., and Porter, K. (2009). The Cost of Transmission for Wind Energy: A Review of Transmission Planning Studies. 

(LBNL-1471E). Berkeley, CA: Lawrence Berkeley National Laboratory.

281 U.S. Department of Energy. (2008). U.S. Department of Energy Wind and Hydropower Technologies: Top Ten Program Accomplishments. (DOE/GO-102008-2622). Washington, DC. 

282 U.S. Department of Energy. (2008). 20% Wind Energy by 2030. Washington, DC. (DOE/GO-102008-2567). Accessed at http://

www.nrel.gov/docs/fy08osti/41869.pdf

283 U.S. Department of Energy. (2012). “Environmental Impacts and Siting of Wind Projects.” Washington, DC. Accessed May 2012 

at http://www1.eere.energy.gov/wind/impacts_siting.html

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ABWR Advanced Boiling Water Reactor

AECL Atomic Energy of Canada Limited

AEV All-Electric Vehicle

AHWR Advanced Heavy Water Reactor

AMI Advanced Metering Infrastructure

ANL Argonne National Laboratory

ARCO Atlantic Richfield Company

ARPA-E Advanced Research Projects Agency-Energy

ARRA American Recovery and Reinvestment Act of 2009

a-Si Amorphous Silicon

AZO Aluminum Doped Zinc Oxide

bbl Barrel

BOS Balance of System

bpd Barrel per Day

BWR Boiling Water Reactor

C Celsius

CAES Compressed Air Energy Storage

CAFE Corporate Average Fuel Economy

CANDU Canada Deuterium Uranium

CBTL Coal and Biomass to Liquids

CCS Carbon Capture and Storage

CdTe Cadmium Telluride

CH Conventional Hydropower

CHP Combined Heat and Power

CIGS Copper Indium Gallium Selenide

CIS Copper Indium Diselenide

CNG Compressed Natural Gas

CO2 Carbon Dioxide

CPV Concentrating Photovoltaics

c-Si Crystalline Silicon

CSP Concentrating Solar Power

CTL Coal-to-Liquids

Cu(In,Ga)Se2 Copper Indium Gallium Selenide

DAE India’s Department of Atomic Energy 

DC Direct Current

GLOSSARY
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DCL Direct Coal Liquefaction

DER Directed Energy Resources

DOE United States Department of Energy

EGS Enhanced Geothermal System

EOR Enhanced Oil Recovery

EPA United States Environmental Protection Agency

EPFL École Polytechnique Fédérale de Lausanne, one of the two Swiss Federal 

Institutes of Technology, located in Lausanne, Switzerland

EPRI Electric Power Research Institute

FACTS Flexible Alternate Current Transmission Systems

FCEV Fuel Cell Electric Vehicle

FhG-ISE Fraunhofer Institute for Solar Energy Systems

FSA Flat-Plate Solar Array Project

F-T Fischer-Tropsch

FTZrO Fluorine Doped Tin Oxide

GaAs Gallium Arsenide

GaN Gallium Nitride

GCR Gas Cooled Reactor

GDP Gross Domestic Product

gge Gallon of Gasoline Equivalent

GHG Greenhouse Gas 

GHP Ground-Source Heat Pump

GTL Gas-to-Liquids

GW Gigawatt

GWe Gigawatt of Electric Energy

GWh Gigawatt Hour

GWP Global Warming Potential

GWt Gigawatt Thermal

HCCI Homogenous-Charge Compression-Ignition

HEV Hybrid Electric Vehicle

HFO Hydrofluoroolefins

HHV Higher Heating Value

HTF Heat-Transfer Fluid

HTGCR High Temperature Gas-Cooled Reactor 

HTSC High-Temperature Superconducting Cable

HVAC Heating, Ventilation, and Cooling

HV-AC High-Voltage Alternating-Current

HV-DC High-Voltage Direct-Current

ICE Internal Combustion Engine
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IGCC Integrated Gasification Combined Cycle

INL Idaho National Laboratory 

IRIS International Reactor Innovative and Secure

kg Kilogram

KHNP Korea Hydro & Nuclear Power

KHz Kilohertz

kW Kilowatt

kWh Kilowatt Hour

LBNL Lawrence Berkeley National Laboratory

LCOE Levelized Cost of Electricity

LED Light-Emitting Diode

Lm Lumen

LNG Liquefied Natural Gas

LSIP Large-Scale Integrated Projects

LTC Low-Temperature Combustion

LWGR Light-Water-Cooled Graphite-Moderated Reactor

LWR Light Water Reactor

mAh/g Milliamp Hour per Gram

MCFC Molten Carbonate Fuel Cell

MHK Marine and Hydrokinetic

MMBtu Million British Thermal Units

Mt Million Tonnes

MTG Methanol-to-Gasoline

MW Megawatt

MWDC Megawatt Direct Current

MWe Megawatt of Electric Energy

MWh Megawatt Hour

NaS Sodium Sulfur

NETL National Energy Technology Laboratory

NGCC Natural Gas Combined Cycle

NGV Natural Gas Vehicle

NOx Nitrogen Oxide

NRC National Research Council

NRC Nuclear Regulatory Commission

NREL National Renewable Energy Laboratory 

O&M Operations and Maintenance

OEM Original Equipment Manufacturer

ORNL Oak Ridge National Laboratory

OTEC Ocean Thermal Energy Conversion
 284 | glossary

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PAFC Phosphoric Acid Fuel Cell

PC Pulverized Coal

PEMFC Polymer Electrolyte Membrane Fuel Cell

PFI Port-Fuel Injected

PHEV Plug-In Hybrid Electric Vehicle

PHWR Pressurized Heavy Water Reactors

PMU Phasor Measurement Unit

PNNL Pacific Northwest National Laboratory

PSH Pumped Storage Hydropower

PTO Power Take-Off

PV Photovoltaic

PVMaT Photovoltaic Manufacturing Technology

PWR Pressurized Water Reactor

QTR Quadrennial Technology Review

Quad Quadrillion British Thermal Units

RCA Radio Corporation of America

R&D Research and Development

RFB Redox Flow Battery

RBMK a Russian reactor, or Reaktor Bolshoy Moshchnosti Kanalniy

RFS Renewable Fuel Standard

RPS Renewable Portfolio Standard

SCADA Supervisory Control and Data Acquisition

SEGS Solar Energy Generating Systems

SFR Sodium Fast Reactor

SGIP Smart Grid Interoperability Panel

SI Spark Ignition

SiC Silicon Carbide

SMR Small Modular Reactor

SNL Sandia National Laboratories

SOFC Solid Oxide Fuel Cell

SSL Solid-State Lighting

TA Technology Assessment

TCO Transparent Conductive Oxides

T&D Transmission and Distribution

TES Thermal Energy Storage

TFP Thin-Film PV Partnership

TWh Terawatt Hour

UNSW University of New South Wales
glossary | 285

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V Volt

VAR Volt-Ampere Reactive

VCR Variable Compression Ratio

VVER a Russian reactor, or Vodo-Vodyanoi Energetichesky Reactor

W Watt

WACS Wide-Area Control System

Wp Watt Peak

This report was prepared as an account of work sponsored by an agency of the United States 

government. Neither the United States government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or responsibility 

for the accuracy, completeness, or usefulness of any information, apparatus, product, or process 

disclosed, or represents that its use would not infringe privately owned rights. Reference herein to 

any specific commercial product, process, or service by trade name, trademark, manufacturer, or 

otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by 

the United States government.
DOE/S-0002