Energy Storage for Power Grids and Electric Transportation: A Technology Assessment

Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Energy Storage for Power Grids and Electric
Transportation: A Technology Assessment
Paul W. Parfomak
Specialist in Energy and Infrastructure Policy
March 27, 2012
Congressional Research Service
CRS Report for Congress
Prepared for Members and Committees of Congress
Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Energy storage technology has great potential to improve electric power grids, to enable growth
in renewable electricity generation, and to provide alternatives to oil-derived fuels in the nation’s
transportation sector. In the electric power system, the promise of this technology lies in its
potential to increase grid efficiency and reliability—optimizing power flows and supporting
variable power supplies from wind and solar generation. In transportation, vehicles powered by
batteries or other electric technologies have the potential to displace vehicles burning gasoline
and diesel fuel, reducing associated emissions and demand for oil.
Federal policy makers have become increasingly interested in promoting energy storage
technology as a key enabler of broad electric power and transportation sector objectives. The
Storage Technology for Renewable and Green Energy Act of 2011 (S. 1845), introduced on
November 10, 2011, and the Federal Energy Regulatory Commission’s Order 755, Frequency
Regulation Compensation in the Organized Wholesale Power Markets, are just two recent
initiatives intended to promote energy storage deployment in the United States. Numerous private
companies and national laboratories, many with federal support, are engaged in storage research
and development efforts across a very wide range of technologies and applications.
This report attempts to summarize the current state of knowledge regarding energy storage
technologies for both electric power grid and electric vehicle applications. It is intended to serve
as a reference for policymakers interested in understanding the range of technologies and
applications associated with energy storage, comparing them, when possible, in a structured way
to highlight key characteristics relevant to widespread use. While the emphasis is on technology
(including key performance metrics such as cost and efficiency), this report also addresses the
significant policy, market, and other non-technical factors that may impede storage adoption. It
considers eight major categories of storage technology: pumped hydro, compressed air, batteries,
capacitors, superconducting magnetic energy storage, flywheels, thermal storage, and hydrogen.
Energy storage technologies for electric applications have achieved various levels of technical
and economic maturity in the marketplace. For grid storage, challenges include roundtrip
efficiencies that range from under 30% to over 90%. Efficiency losses represent a tradeoff
between the increased cost of electricity cycled through storage, and the increased value of
greater dispatchability and other services to the grid. The capital cost of many grid storage
technologies is also very high relative to conventional alternatives, such as gas-fired power
plants, which can be constructed quickly and are perceived as a low risk investment by both
regulated utilities and independent power producers. The existing market structures in the electric
sector also may undervalue the many services that electricity storage can provide. For
transportation storage, the current primary challenges are the limited availability and high costs of
both battery-electric and hydrogen-fueled vehicles. Additional challenges are new infrastructure
requirements, particularly for hydrogen, which requires new distribution and fueling
infrastructure, while battery electric vehicles are limited by range and charging times, especially
when compared to conventional gasoline vehicles.
Substantial research and development activities are underway in the United States and elsewhere
to improve the economic and technical performance of electricity storage options. Changes to
market structures and policies may also be critical components of achieving competitiveness for
electricity storage devices. Removing non-technical barriers may be as important as technology
improvements in increasing adoption of energy storage to improve grid and vehicle performance.
Congressional Research Service
Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Introduction...................................................................................................................................... 1
Structure of the Report .............................................................................................................. 2
Other CRS Reports on Electricity Storage ................................................................................ 3
Technology Assessment Authorship.......................................................................................... 3
Acknowledgement ..................................................................................................................... 3
Chapter 1: Executive Summary ....................................................................................................... 4
Background................................................................................................................................ 4
Energy Storage for Electric Grid Applications .......................................................................... 5
High Power/Rapid Discharge Applications......................................................................... 5
Energy Management Applications ...................................................................................... 5
Energy Storage for Transportation Applications ....................................................................... 7
Chapter 2: Background and Scope................................................................................................... 9
Organization of This Report ...................................................................................................... 9
Chapter 3: Overview of Storage Technology Applications and Benefits....................................... 11
Energy Storage for Electric Power Grids ................................................................................ 11
Current Storage Deployment for the Grid......................................................................... 11
Applications of Energy Storage in the Grid ...................................................................... 12
Valuation of Storage for the Grid ...................................................................................... 14
Energy Storage and Renewable Energy ............................................................................ 17
Ongoing Barriers to Storage Deployment for the Grid ..................................................... 21
Current Grid Storage Policies............................................................................................ 23
Storage for Electric Transportation Applications .................................................................... 27
Transportation Storage Technologies and Pathways ......................................................... 27
Impacts and Benefits of Vehicle Electrification ................................................................ 28
Barriers to Deployment and Policies to Increase Vehicle Electrification.......................... 30
Chapter 4: Batteries for Grid Applications .................................................................................... 32
Overview ................................................................................................................................. 32
Technology .............................................................................................................................. 34
Description and Performance ............................................................................................ 34
Cost ................................................................................................................................... 37
Research and Development............................................................................................... 40
Deployment Challenges .................................................................................................... 43
Conclusions ............................................................................................................................. 44
Chapter 5: Batteries for Electric Transportation ............................................................................ 46
Overview ................................................................................................................................. 46
Technology .............................................................................................................................. 48
Description and Performance ............................................................................................ 48
Cost ................................................................................................................................... 52
Research and Development............................................................................................... 54
Deployment Challenges .................................................................................................... 59
Conclusions ............................................................................................................................. 60
Chapter 6: Hydrogen...................................................................................................................... 61
Overview ................................................................................................................................. 61
Technology .............................................................................................................................. 63
Description ........................................................................................................................ 63
Congressional Research Service
Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Performance ...................................................................................................................... 67
Cost ................................................................................................................................... 69
Research and Development............................................................................................... 71
Deployment Challenges .................................................................................................... 72
Conclusions ............................................................................................................................. 74
Chapter 7: Compressed Air Energy Storage .................................................................................. 75
Overview ................................................................................................................................. 75
Technology .............................................................................................................................. 76
Description ........................................................................................................................ 76
Performance ...................................................................................................................... 78
Cost ................................................................................................................................... 80
Research and Development............................................................................................... 82
Deployment Challenges .................................................................................................... 84
Conclusions ............................................................................................................................. 86
Chapter 8: Electrochemical Capacitors.......................................................................................... 87
Overview ................................................................................................................................. 87
Technology .............................................................................................................................. 87
Description ........................................................................................................................ 87
Performance ...................................................................................................................... 88
Cost ................................................................................................................................... 90
Research and Development............................................................................................... 91
Deployment Challenges .................................................................................................... 93
Conclusions ............................................................................................................................. 94
Chapter 9: Pumped Hydro Storage ................................................................................................ 95
Overview ................................................................................................................................. 95
Technology .............................................................................................................................. 97
Description ........................................................................................................................ 97
Performance ...................................................................................................................... 98
Cost ................................................................................................................................... 99
Research and Development............................................................................................. 101
Deployment Challenges .................................................................................................. 103
Conclusions ........................................................................................................................... 105
Chapter 10: Flywheel Storage...................................................................................................... 106
Overview ............................................................................................................................... 106
Technology ............................................................................................................................ 107
Description ...................................................................................................................... 107
Performance .................................................................................................................... 108
Cost ................................................................................................................................. 110
Research and Development............................................................................................. 111
Deployment Challenges .................................................................................................. 114
Conclusions ........................................................................................................................... 114
Chapter 11: Thermal Energy Storage in Buildings ...................................................................... 116
Overview ............................................................................................................................... 116
Technology ............................................................................................................................ 117
Description ...................................................................................................................... 117
Performance .................................................................................................................... 118
Cost ................................................................................................................................. 120
Research and Development............................................................................................. 121
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Deployment Challenges .................................................................................................. 121
Conclusions ........................................................................................................................... 122
Chapter 12: Thermal Energy Storage for Concentrating Solar Power......................................... 123
Overview ............................................................................................................................... 123
Technology ............................................................................................................................ 124
Description ...................................................................................................................... 124
Performance .................................................................................................................... 125
Cost ................................................................................................................................. 127
Research and Development............................................................................................. 128
Deployment Challenges .................................................................................................. 130
Conclusions ........................................................................................................................... 130
Chapter 13: Superconducting Magnetic Energy Storage ............................................................. 131
Overview ............................................................................................................................... 131
Technology ............................................................................................................................ 132
Description ...................................................................................................................... 132
Performance .................................................................................................................... 133
Cost ................................................................................................................................. 134
Research and Development............................................................................................. 135
Deployment Challenges .................................................................................................. 135
Conclusions ........................................................................................................................... 135
Figure 1. Estimated Life-Cycle Value of Several Electricity Grid Storage Applications .............. 15
Figure 2. Impact on Net Load from Using Wind Generation ........................................................ 18
Figure 3. Generation Dispatch in the WWSIS Study at 30% Wind Penetration............................ 21
Figure 4. Pathways to Vehicle Electrification................................................................................ 27
Figure 5. Cost Components for an Installed NaS System.............................................................. 38
Figure 6. Extraction Costs of Elements in Grid Battery Couples .................................................. 39
Figure 7. Energy Storage Potential (ESP) of Battery Material Reserves....................................... 44
Figure 8. United States Hybrid Electric Vehicle Sales................................................................... 47
Figure 9. Comparison of the Various Lithium-Ion Battery Chemistries........................................ 49
Figure 10. Battery Cost Requirements for a Five-Year Payback from Fuel Savings..................... 53
Figure 11. Extraction Costs of Elements in Vehicle Battery Couples............................................ 54
Figure 12. FreedomCAR PHEV Energy Storage Goals ................................................................ 56
Figure 13. Practical vs. Theoretical Specific Energy for 27 Battery Chemistries ......................... 59
Figure 14. Energy Storage Potential (ESP) of Battery Material Reserves..................................... 60
Figure 15. Electrolytic and Other Major Hydrogen Energy Pathways .......................................... 64
Figure 16. Schematic Representation of PEM Electrolysis ........................................................... 65
Figure 17. Location of Salt Deposits Across the United States ..................................................... 69
Figure 18. 110 MW CAES Plant in McIntosh, AL ........................................................................ 75
Figure 19. CAES System Diagram ................................................................................................ 77
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Figure 20. Comparison of CAES Dispatch Cost to Conventional Storage.................................... 80
Figure 21. Capital Cost Estimates for Conventional Diabatic CAES............................................ 81
Figure 22. Comparison of Various Capacitor and Battery Topologies .......................................... 88
Figure 23. Comparison of Energy Storage Technologies .............................................................. 90
Figure 24. Comparison of Cost per Energy Throughput for Li-Ion Batteries and ECs ................. 91
Figure 25. Capacity of PHS in United States, 1956–2003............................................................. 96
Figure 26. Existing and Proposed PHS Facilities in the United States.......................................... 97
Figure 27. Pumped-Storage Hydropower Plant Configuration...................................................... 97
Figure 28. Historical Efficiencies of PHS Plants in United States ................................................ 99
Figure 29. Installed Cost of PHS Plants in United States ............................................................ 100
Figure 30. Part of a 1 MW Flywheel System in the ISO-New England Grid.............................. 107
Figure 31. Electric Flywheel Components................................................................................... 108
Figure 32. Flywheel Cost Projections for a 20MW/5MWh Frequency Regulation Plant .......... 111
Figure 33. Illustration of a Chilled Water-Based TES System .................................................... 118
Figure 34. Electric Demand for Building Cooling With and Without TES ................................. 119
Figure 35. Two-Tank TES System at a 50 MW Solar Power Plant in Spain ............................... 124
Figure 36. Schematic of an Indirect Two-Tank TES System....................................................... 125
Figure 37. Potential SMES Cost Ranges Based on Component Costs ........................................ 134
Table 1. Energy Storage Applications and Technologies................................................................. 4
Table 2. Major Power Grid Applications of Electricity Storage .................................................... 13
Table 3. Example NaS Battery Installations in the United States .................................................. 33
Table 4. ARPA-E Supported Activities on Grid Battery Storage in FY2010-2011........................ 40
Table 5. ARRA Supported Grid Battery Demonstrations .............................................................. 41
Table 6. ARRA Supported Vehicular Battery Demonstrations ...................................................... 55
Table 7. Proposed CAES Plants in the United States .................................................................... 76
Table 8. Component Costs of a Conventional CAES System Deployed in a Salt Cavern............ 81
Table 9. Performance and Costs of Electrochemical Capacitors ................................................... 90
Table 10. Recently Completed or Proposed PHS Plants.............................................................. 101
Table 11. Flywheel Performance Characteristics......................................................................... 110
Table 12. Flywheel Materials Characteristics.............................................................................. 112
Table 13. Technical Characteristics of a CSP System.................................................................. 126
Table 14. U.S. Department of Energy FOA Projects ................................................................... 129
Table 15. Potential Cost Reductions for CSP/TES Systems........................................................ 129
Table 16. SMES Operating Parameters ....................................................................................... 133
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Appendix. Table of Acronyms ..................................................................................................... 137
Author Contact Information......................................................................................................... 139
Congressional Research Service
Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Energy storage technology has great potential to improve electric power grids, to enable growth
in renewable electricity generation, and to provide alternatives to oil-derived fuels in the nation’s
transportation sector. In the electric power system, the promise of this technology lies in its
potential to increase grid efficiency and reliability—optimizing power flows and supporting
variable power supplies from wind and solar generation. In transportation, vehicles powered by
batteries or other electric technologies have the potential to displace vehicles burning gasoline
and diesel fuel, reducing associated emissions and demand for oil.
In recent years, federal policy makers have become increasingly interested in promoting energy
storage technology as a key enabler of broad electric power and transportation sector objectives.
In remarks about the STORAGE Act of 2011 (S. 1845),1 which would provide investment tax
credits for storage systems connected to the electric grid, businesses and homes, Senate Energy
and Natural Resources Committee Chairman Jeff Bingaman remarked,
Deployment of storage technologies will make our nation’s electricity grid more reliable
while also enabling more efficient use of existing energy sources as well as new ones, such
as wind and solar.... These technologies have the potential to cut electricity bills, reduce peak
power demand and lower greenhouse gas emissions.2
Likewise, in a statement regarding new energy storage-related rules for wholesale electricity
markets, Federal Energy Regulatory Commissioner John Norris stated,
I believe today’s final rule is a positive first step by the Commission in recognizing the
unique characteristics and the value that storage resources offer.... As we move forward, I
strongly believe that storage will become ever more critical as we look to integrate
increasing amounts of variable energy resources.3
Referring to advanced batteries for electric transportation applications, Secretary of Energy
Steven Chu reportedly stated,
It’s now within grasp, that you can get a battery where the business plans are one-third of the
cost of today’s batteries, where you can get ranges now that would allow cars instead of 100
miles on a single charge, go 300 or more miles on the same charge…. It’s not a pipe dream
30 years from today or 20 years from today. It’s in the next decade.4
Statements such as those above highlight not only the technical opportunities for energy storage
in the grid and in electric transportation, but also the attention being paid to energy storage
technologies at the highest levels in the federal government. Nonetheless, many new energy
storage technologies continue to face significant technological and economic challenges to their
Storage Technology for Renewable and Green Energy Act of 2011 (S. 1845) introduced on November 10, 2011, by
Senator Ron Wyden and co-sponsored by Senators Jeff Bingaman, Susan Collins, and Robert Menendez.
Office of Senator Ron Wyden, “Wyden, Collins, Bingaman Legislation Will Increase Investments in the Storage of
Renewable Energy,” press release, November 10, 2011.
Commissioner John R. Norris, “Frequency Regulation Compensation in the Organized Wholesale Power Markets,”
Docket Nos. RM11-7-000 & AD10-11-000, Item No. E-28, Federal Energy Regulatory Commission, October 20, 2011.
Michael Warren, “Energy Secretary Steven Chu on Electric Cars,” The Weekly Standard Blog, April 3, 2011,
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
commercialization and widespread deployment. The recent bankruptcy of Beacon Power, one of
the leading developers of flywheel energy storage technologies for the grid, is a prominent
illustration of commercial barriers to grid storage technology. Public concerns about elevated fire
risks from Chevrolet Volt electric car batteries, although shown to be exaggerated, are another.5
By contrast, increasing investments by AES Corporation in utility-scale battery storage for power
grids show continuing successful efforts to overcome technical challenges and market barriers to
bring new storage technologies into the market.6
Understanding the potential of energy storage in electric applications is complicated by a number
of factors. The first is the wide range of storage technologies either commercially available, in
development, or being researched. Because they are technologically diverse, it is difficult to gain
a balanced understanding of the fundamental capabilities, costs, and comparative advantages of
these different energy storage options. Second, there are multiple applications of energy storage,
each with distinct operational requirements. Certain storage technologies may suit certain
applications better than others. Finally, there are many aspects of market structure and economic
regulation that affect energy storage deployment. Taken together, these factors make the
development of an energy storage research and development portfolio challenging. While there is
general consensus that storage technology improvements are needed, there are multiple potential
pathways to such improvements that cut across different disciplines.
This report attempts to summarize the current state of knowledge regarding energy storage
technologies for both electric power grid and electric vehicle applications. It is intended to serve
as a reference for policymakers interested in understanding the range of technologies and
applications associated with energy storage, comparing them, when possible, in a structured way
to highlight key characteristics relevant to widespread use. The report also discusses how aspects
of policy and market structure affect competition among both mature and emerging technologies.
Structure of the Report
The report contains 13 chapters, starting with an Executive Summary, which provides an
overview of the report’s main findings. Context and background are provided in “Chapter 2:
Background and Scope” and “Chapter 3: Overview of Storage Technology Applications and
Benefits.” In particular, Chapter 3 provides an overview of electricity storage applications and
value, including their use to enable renewable electricity; current barriers to deployment; and
current initiatives to address technical, economic and market barriers. Chapters 4-13 discuss the
individual storage technologies. Each chapter can be read independently, but Chapters 2 and 3
offer the reader a more complete understanding of some of the more technologically focused
discussions in the subsequent chapters.
Jim Henry, “Chevy Volt Battery Fires Threaten All Electric Vehicle Makers, Not Just GM,” Forbes, December 12,
2011; National Highway Traffic Safety Administration, “NHTSA Statement on Conclusion of Chevy Volt
Investigation,” press release, January 20, 2012.
“AES Peaker-Sized Battery Proposals Show Company’s Vision of Storage Potential for the Grid,” Electric Utility
Week, Platts, January 2, 2012.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Other CRS Reports on Electricity Storage
CRS has written two previous reports on electricity storage: CRS Report R40797, Electric Power
Storage, by Stan Mark Kaplan, and CRS Report R41709, Battery Manufacturing for Hybrid and
Electric Vehicles: Policy Issues, by Bill Canis.
Technology Assessment Authorship
This technology assessment and report was prepared by the National Renewable Energy
Laboratory (NREL), Strategic Energy Analysis Center, with contributions from Paul Denholm,
Anne Dillon, Easan Drury, Greg Glatzmaier, Jeffrey Logan, Marc Melaina, Jeremy Neubauer,
Doug Reindl (University of Wisconsin-Madison), Shriram Santhanagopalan, Kandler Smith,
Darlene Steward, and Samir Succar (Natural Resources Defense Council). The work was
performed under contract to CRS as part of a multiyear CRS project to examine different aspects
of U.S. energy policy. John L. Moore, Assistant Director, Resources, Science, and Industry
Division, served as the CRS project coordinator. Paul W. Parfomak, Specialist in Energy and
Infrastructure Policy, served as the CRS reviewer and editor of the final report.
This report was funded, in part, by a grant from the Joyce Foundation.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Chapter 1: Executive Summary
Energy storage in electric applications can provide two significant benefits to the nation’s energy
system. First, it can improve the technical and economic performance of the electric power grid,
increasing reliability and potentially decreasing costs while allowing greater penetration of
intermittent sources like solar and wind generation. Second, it enables a potential transition from
an oil-based transportation system to one based on an array of domestically sourced electricity
options, greatly reducing dependence on petroleum. In both cases, a reduction in the burning of
fossil fuels could result in lower overall U.S. carbon emissions and conventional pollutants.
For purposes of assessment and comparison, it is helpful to organize the various energy storage
technologies under two industry sectors (electric grid and transportation) and two general
categories of application based on the amount of time the storage device is required to provide
service (high power/rapid discharge and energy management), further explained below. Table 1
lists the storage technologies considered in this report according to these categories. The report
provides an overview of the current capabilities and costs of each storage technology, including
the potential for technical and cost improvement. It also discusses non-technical barriers
including environmental, material, market, and policy challenges to widespread deployment.
Table 1. Energy Storage Applications and Technologies
Electric Grid (Stationary)
Transportation (Vehicular)
High Power /
Rapid Discharge
• Lead-Acid
• Nickel
• Lithium-Ion
Superconducting Magnetic Energy
Storage (SMES)
• Nickel
• Advanced Lead-Acid
• Flow
• High Temperature
Compressed Air
Pumped Hydro
• Concentrating Solar Power
• End Use
• Lithium-Ion
• Lithium-Metal
• Metal Air
Source: P. Denholm, National Renewable Energy Laboratory, 2011.
Note: Electric power and transportation applications may elsewhere be referred to as “stationary” and
“vehicular,” respectively.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Energy Storage for Electric Grid Applications
It is possible to divide grid storage applications into two broad categories based on the length of
time a storage device needs to provide service: (1) high power applications where the device must
respond rapidly and be able to discharge for only short-term periods (up to about one hour), and
(2) energy management related applications where the device may respond more slowly but must
be able to discharge for several hours or more. Ideally, all storage devices would be able to
provide all services, but some technologies are technically restricted to provide only short-term
services. However, many of these services have very high value in the grid, so short-term storage
can still provide considerable benefits.
High Power/Rapid Discharge Applications
The rapid response category can be further divided into short-term discharge—less than one
minute—used to provide grid stability and power quality, and longer-term discharge—up to about
an hour. Though important, short-term discharge services can often be provided by non-storage
options such as power electronics. Furthermore, this class of grid services does not address the
primary challenge of renewables integration, which requires minutes to hours of discharge time.
Currently, capacitors and superconducting magnetic energy storage (SMES) are rapid response
technologies capable only of providing short-term discharge. Research efforts for both
technologies are focused on increasing energy density and decreasing cost, with capacitor efforts
being directed in part towards vehicle applications. While SMES research has been active
historically, current efforts are modest and there is no clearly defined pathway for SMES to be
competitive for applications requiring extended discharge.
Other grid applications require devices with up to about one hour of discharge to provide services
such as frequency regulation service (responding to random, rapid variations in demand) and
contingency reserves (rapidly responding to a generator or transmission failure). Longer-term
storage can also support renewables integration by providing the subhourly ramping requirements
which will increase as greater amounts of variable generation sources are added to the grid.
Flywheels have been deployed in significant demonstration projects providing frequency
regulation. Several battery types have been demonstrated for both frequency regulation and
operating reserves, including lithium-ion and various aqueous batteries (such as lead-acid, nickelcadmium, and nickel-metal hydride). Most aqueous chemistries are considered mature
technologies, but additional improvements are possible, even for 100+ year-old lead acid
batteries. Research and development efforts on lithium-ion batteries are focused on reducing cost
and weight for transportation applications, but these efforts should have spillover benefits to grid
applications. In addition, there are certain lithium-ion configurations that are probably unsuitable
for transportation applications but potentially suitable for the grid. A major effort by commercial
vendors of rapid response technologies such as flywheels and lithium-ion batteries has been
gaining access to markets for frequency regulation and full valuation of the response capabilities
of the technology.
Energy Management Applications
Grid storage devices for energy management applications can provide continuous discharge for
several hours or more. These devices would be potentially useful for shifting energy during
periods of low demand (or high renewable supply) to periods of high demand (or low renewable
supply). Many of them can also provide the same services as high power/rapid discharge devices.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Pumped hydro storage (PHS) is the dominant technology in this category with about 22
Gigawatts (GW), equivalent to about 22 large power plants, operating in the United States for
decades. PHS has high reliability, high efficiency, and long lifetime, but is dependent on the
availability of suitable geologic conditions and requires long development times (~10 years
including permitting). Based on siting challenges and environmental opposition, PHS suffers
from the perception that these issues will prevent large-scale deployment in the future. However,
the actual technical potential is large and the number of proposed plants exceeds the current
installed capacity, with many of these proposed plants using “closed-cycle” designs that will not
interact with existing water bodies and have the potential to reduce both opposition and licensing
times. They may also use variable speed equipment improving their ability to provide rapid
discharge services.
Compressed air energy storage (CAES) is technically mature, and often considered the lowestcost option for “bulk” electricity storage, although only one such facility is deployed in the
United States. CAES is a hybrid technology which uses natural gas, and typically requires a large
underground formation. Major development efforts for CAES currently underway include
demonstrating the technology in bedded salt and porous rock. Use of such geologic formations
would open up much more of the country to CAES development. Other research and
development activities include work on CAES cycles that do not require natural gas fuel.
Hydrogen and other electricity-derived fuels are possible storage options with the advantage of
long-term (even seasonal) storage. They currently are among the least efficient (well under 50%)
and more expensive storage technologies available and have yet to be deployed beyond small
demonstration projects. Fundamental research efforts are required to decrease the cost and
increase the durability of electrolyzers and fuel cells. Most of the historic research on hydrogen
has been as an alternative fuel for transportation.
Two classes of batteries are currently the primary candidates for electric grid applications—liquid
electrolyte flow batteries and high-temperature batteries. High-temperature sodium-sulfur
batteries are the most mature and commercially available, with over 270MW deployed
worldwide, including installations in the United States. They also have the advantage of relying
on low-cost and abundant materials, although manufacturing costs have limited larger-scale use.
Sodium sulfur is the only high-temperature battery deployed at large scale, currently
manufactured by a single company in Japan. There are several alternative high-temperature
chemistries under various stages of research, development, and commercialization. Flow batteries
are in the early stages of development and commercialization, with a few U.S. demonstration
projects of vanadium and zinc-bromine technologies, with several other technologies under
Thermal energy storage (TES) is often overlooked as an electricity storage technology option
because it does not store and discharge electricity directly. However, in some applications,
thermal storage can be functionally equivalent to electricity storage with efficiencies exceeding
90%, which is higher than most other storage technologies. There are two primary applications of
TES for electricity. The first is storing thermal energy from the sun which is later converted into
electricity. The currently deployed storage medium is a relatively low-cost molten salt. The
primary limitation is that TES is tied to a specific application, in this case concentrating solar
power (CSP), which has the challenges of high cost and limited deployment locations, mostly in
the desert southwest in the United States. The key research efforts include developing storage
materials with higher working temperature, which, when combined with higher temperature CSP
plants, will increase efficiency and decrease costs. CSP with thermal energy storage has been
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
deployed in Spain. Construction of a 250 MW CSP/TES facility in the United States is expected
to begin in 2012. The second application of TES is cold and hot storage in buildings. Cold
storage, used to reduce peak demand from air-conditioning, has been deployed on a relatively
large scale. This is a commercially mature technology that provides firm system capacity at very
high round-trip efficiency, with the capability of providing multiple grid services. The primary
barrier to deployment is capturing the benefits of this distributed technology in the current
regulatory and market environment.
Energy Storage for Transportation Applications
As with grid storage, energy storage for transportation applications can be loosely divided into
two primary categories: high power/rapid discharge and high energy/extended discharge. High
power devices provide short, rapid discharges for vehicle starting and acceleration. While they
cannot provide continuous discharge for electrified transport, they can dramatically improve fuel
efficiency, as demonstrated by the current generation of hybrid electric vehicles. Currently
deployed technologies for these applications include lithium-ion and nickel-based aqueous
batteries. Technologies being explored including capacitors, flywheels, and other battery types.
Some of these technologies, such as capacitors, may also be used as a fast-responding “buffer”
between the electric drive system and the battery or fuel cell in an electric vehicle (EV).
For high energy applications, where stored electricity is actually used to provide a significant
fraction of the driving energy, research and development efforts are currently focused on two
technologies—hydrogen and batteries. Conceptually, hydrogen is a simple storage technology,
produced by splitting water using electricity (among other options), storing hydrogen on board
the vehicle, and then converting it to electricity to drive an electric motor via a fuel cell. (Internal
combustion engines could also be used, but the low efficiency of that process is less attractive.)
The challenges of a hydrogen-based transportation system include the development of an entirely
new fueling infrastructure including hydrogen delivery systems and filling stations, with needed
safety standards and protocols. The low volumetric energy density of hydrogen makes storage
challenging without extremely high-pressure tanks, or advanced chemical storage still in the early
research phase. Finally, fuel cells for vehicles remain expensive, with limited lifetimes. There
have been demonstration fuel cell vehicle programs by several major auto manufacturers, with
announced plans for commercial deployment as soon as 2015. However, substantial research
efforts will be needed to reduce costs and improve performance for many of the technologies
needed for large-scale hydrogen based transportation. There are other electricity-to-fuel pathways
under consideration, but with limited research and development efforts in the United States. They
face similar challenges of requiring new fuel infrastructure and currently face much higher costs
than fossil fuel alternatives.
The primary alternative to electricity-based fuel production is battery electric storage in plug-in
hybrid electric vehicles (PHEVs) and EVs. Most commercially available and proposed EVs and
PHEVs (such as the Chevrolet Volt and Nissan Leaf) use lithium-ion batteries. Research and
development efforts are focused primarily on reducing cost and increasing energy density as well
as safety of lithium-ion technology. Earlier deployed technologies, such as lead-acid used in older
EVs and nickel metal hydride used in current HEVs, are not considered likely candidates in future
EVs due to fundamental limits of energy density. Concerns have been expressed about the largescale availability of several metals used in lithium-ion batteries, as well as its concentration in a
few geographic regions. In the longer term, lithium-metal and metal-air batteries are in the
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
research and development phase, with the potential of much higher energy density than currently
available battery types.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Chapter 2: Background and Scope
In the United States, there are two major motivations for deploying energy storage technologies.
The first is to improve the technical and economic performance of the electric power grid (“the
grid”).7 This includes enabling more efficient utilization of conventional power plants (e.g., coaland gas-fired) supplying the grid through load-leveling and providing fast response grid support
functions (“ancillary services”), among other services. It also includes enabling greater use of
renewable energy sources such as wind and solar generation, which have variable output due to
changing weather conditions. Electricity storage is a potential source of grid flexibility to ease
integration challenges and decrease integration costs for these renewables.
The second motivation for energy storage is to enable greater use of electrified transportation.
The United States is largely self-sufficient for its electricity needs, and has substantial potential to
increase production of low-carbon, domestically sourced electricity from renewable and nuclear
sources (or from coal using carbon capture). Yet many of these sources cannot directly produce
the liquid fuels generally used in conventional vehicles. Electricity storage in batteries or some
other technology (including electricity-derived fuels such as hydrogen) could provide a pathway
to more electrically powered vehicles, and thereby to reducing U.S. dependence on petroleum.
This report provides information and analysis about the current status and future opportunities for
energy storage technologies in electric grid and electric vehicle applications. It attempts to
identify technologies which may have a key role in achieving the objectives stated above. It
discusses key technical and market barriers, along with research and development (R&D) and
policy efforts to reduce those barriers. The report:
Describes and discusses briefly how existing storage technologies work, their
most likely applications, and their advantages for particular applications.
Describes current limitations of each technology and whether those limitations
might be addressed through R&D efforts.
Describes economic or materials barriers that might impede development or
deployment (e.g., requirements for imported precious metals).
Assesses the costs (fixed and operational), safety, and effectiveness of each
Assesses the time horizon for market readiness of each technology.
Provides a technical overview and status of R&D activities for new and emerging
storage technologies.
Organization of This Report
This report contains 12 chapters, starting with Chapter 1, “Executive Summary,” which provides
an overview of the report’s main findings. Context and background are provided in Chapter 2,
“Background and Scope.” Chapter 3, “Overview of Storage Technology Applications and
In this report, the electric power grid, or “the grid,” refers to the electric power transmission and distribution (T&D)
network operated by electric utilities to deliver electricity from generation facilities (including storage) to end users.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Benefits,” provides an overview of electricity storage applications and value, including their use
to enable renewable electricity; current barriers to deployment; and current initiatives to address
technical, economic, and market barriers. Chapters 4-13 discuss each individual storage
technology, including a general overview, status in the marketplace (including proposed projects),
estimates of current performance, service lifetime, and costs. They also discuss the status of
R&D, including key research needs to enable improvements in cost and performance, as well as
non-technical barriers including environmental challenges, availability of raw materials, and
safety. Each of Chapters 4-13 can be read independently, but Chapters 2 and 3 offer a more
complete understanding of some of the more technologically focused discussions that follow.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Chapter 3: Overview of Storage Technology
Applications and Benefits
Energy Storage for Electric Power Grids
Electric utilities have long been interested in energy storage technology because of its potential to
support the operation of electric power grids. Historically, one of the most important grid storage
functions has been “load-leveling,” or storing off-peak electricity during periods of low demand
and releasing it during periods of high demand, enabling the decreased use of high-cost peaking
generation. This function has been extended to include support for renewable electricity
generation, given the variable production output of wind and solar plants. More recently, utilities
have also been considering how energy storage can provide a partial alternative to the
development of the power grid itself by helping utilities optimize the use of grid infrastructure
already in place and thereby avoid or defer building new power lines. Other key storage functions
include technical services called “ancillary services” needed to provide electric power
transmission service to a customer. They include actions taken to effect a power transaction (e.g.,
scheduling), services needed to maintain the integrity of the power grid, and services needed to
correct the effects associated with undertaking a power transaction (e.g., supply-demand
balancing).8 As the electric power grid has evolved into a wholesale marketplace for competitive
bulk power purchases while at the same time becoming strained by growth in electricity demand,
the potential for energy storage has grown in importance, driving continued interest in storage
technology development and deployment.
Current Storage Deployment for the Grid
There are approximately 22 GW of utility-scale electric storage capacity in the United States
today, which equates to approximately 2% of the nation’s total existing generation capacity.9
Nearly all of this storage capacity is in the form of pumped hydro storage (PHS), which works by
pumping water from a lower reservoir to an upper reservoir, releasing that stored water through a
hydroelectric generator when electricity is needed (further discussed in Chapter 9). While there
was some development of PHS starting as early as the 1920s, much of the nation’s PHS capacity
was initiated in the mid- to late 1970s.10 This development was the result of a combination of
factors including dramatic price increases in oil and natural gas used for meeting peak electricity
demand, along with concerns about security of supply. These factors culminated in congressional
passage of the Powerplant and Industrial Fuel Use Act of 1978 (P.L. 95-620) restricting use of oil
and gas in new power plants.11 During this period utilities expected to bring online many new
Federal Energy Regulatory Commission, Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities, Order No. 888, April 24, 1996, p. 198.
U.S. Energy Information Administration, Electric Power Annual, Table 1.2, April 11, 2011,
American Society of Civil Engineers (ASCE),Task Committee on Pumped Storage of the Hydropower Committee of
the Energy Division of the American Society of Civil Engineers, “Compendium of Pumped Storage Plants in the
United States,” American Society of Civil Engineers, New York., 1993.
U.S. Energy Information Administration, “Repeal of the Powerplant and Industrial Fuel Use Act (1987),” web page,
October 18, 2011,
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coal-fired and nuclear power plants to meet relatively steady baseload demand, but were left with
limited options to provide generation capacity to meet daily and hourly load variations (“loadfollowing”) and peak demand.12 This limitation led utilities to actively develop PHS as an
alternative to fossil-fueled intermediate load and peaking generation.
During the 1970s, there was also significant research and development of other storage
technologies including several battery types, capacitors, flywheels, compressed-air, underground
pumped hydro, and superconducting magnetic storage.13 It was expected that deployment of
storage of all types would grow significantly during this period.14 However, most PHS
development, along with interest in and deployment of other emerging storage technologies,
ended in the 1980s after steep natural gas price reductions, improvements in natural gas turbines,
and repeal of the Industrial Fuel Use Act made deployment of flexible natural gas-fired
generation more economically attractive.
Other technical, market, and regulatory factors have also served to limit the deployment of
electricity storage historically. Many of these factors continue today. They are discussed in more
detail later in this chapter and in the individual technology chapters. Briefly, however, a primary
historical challenge of storage deployment has been the limited ability of utilities to estimate and
capture the full economic value of electricity storage, especially the many dynamic benefits to the
grid of fast responding storage technologies.15 Taken together, these factors have restricted
deployment of utility-scale electricity storage in the United States over recent decades. Besides 22
GW of PHS, deployment has been limited to a single 110 MW compressed-air energy storage
(CAES) facility, and a variety of smaller projects. Between 1990 and 2010, only 2 MW of new
PHS was constructed in the United States compared to over 300 GW of new generating
Applications of Energy Storage in the Grid
As noted above, energy storage can be used in many valuable applications for electric power
grids. A 2010 assessment by Sandia National Laboratories, for example, lists 17 distinct
applications and 26 associated benefits of electricity storage.17 Table 2 lists some of the most
commonly cited applications for electricity storage with a basic description of each. It does not
include other possible applications of electricity storage such as “black start” (providing power to
restart the grid after a blackout), power quality, voltage and transmission support, substation on-
Concern about the availability of oil and other peaking fuels in this period was so great that a 1979 international
conference on the subject, which included the U.S. National Academy of Sciences, described energy storage as “a vital
element in mankind’s quest for survival and progress.” J. Silverman,(ed). “Energy Storage: A Vital Element in
Mankind’s Quest for Survival and Progress,” Transactions of the First International Assembly held at Dubrovnik,
Yugoslavia, 27 May-1 June, 1979, Pergamon Press, 1980.
U.S. Department of Energy, “DOE Interagency Coordination Meeting on Energy Storage,” CONF 7709116, 1977.
D.W. Boyd, O.E. Buckley, and C.E. Clark, “Assessment of Market Potential of Compressed-Air Energy-Storage
Systems,” Journal of Energy, 1983, No. 7, pp. 549-556.
P. Denholm, E. Ela, B. Kirby, and M. Milligan, The Role of Energy Storage with Renewable Electricity Generation,
NREL/TP-6A2-47187, National Renewable Energy Laboratory, Golden, CO, 2010.
U.S. Energy Information Administration, Annual Energy Review, October 19, 2011, Table 8.11a,
J. Eyer and G. Corey, Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment Guide: A
Study for the DOE Energy Storage Systems Program, SAND2010-0815, Sandia National Laboratories, February 2010.
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site power, and supplemental reserves. Nor does it include the role of storage in supporting
variable generation, like wind and solar generation, which is discussed in the next section.
Table 2. Major Power Grid Applications of Electricity Storage
Timescale of Operation
Load Leveling/
Purchasing low-cost off-peak energy and
selling it during peak periods with high
Response in minutes to hours. Discharge time
of hours.
Firm Capacity
Provide reliable generation capacity to meet
peak system demand.
Must be able to discharge continuously for
several hours or more.
• Regulation
Fast responding increase or decrease in
generation (or load) to respond to random,
unpredictable variations in demand.
Unit must be able to respond in seconds to
minutes. Discharge time is typically minutes.
• Contingency
Fast responding increase in generation (or
decrease load) to respond to a contingency
such as a generator failure.
Unit must begin responding immediately and
be fully responsive within 10 minutes. Must be
able to hold output for 30 minutes to 2 hours
depending on the market.
Load Following
Follow longer-term (hourly) changes in
electricity demand.
Response time in minutes to hours. Discharge
time may be minutes to hours.
Transmission and
Replacement and
Reduce loading on electric power grid during
peak times. Provides an alternative to
expensive and often difficult to site power
lines and substations.
Response in minutes to hours. Discharge time
of hours.
• Time of Use
(TOU) Rates
Functionally the same as arbitrage, just at the
customer site.
Same as arbitrage.
• Demand Charge
Functionally the same as firm capacity, just at
the customer site.
Same as firm capacity.
• Backup Power/
Power Quality/
Power Supply
Functionally similar to contingency reserve,
just at the customer site.
Instantaneous response. Discharge time
depends on level of reliability needed by
Source: P. Denholm, et al., The Role of Energy Storage with Renewable Electricity Generation, NREL/TP-6A2-47187,
National Renewable Energy Laboratory, 2010.
Arbitrage, strictly defined, is the simultaneous purchase and sale of the same commodity to take advantage
of price differences in two different markets. Eyer and Corey (2010) consider the term arbitrage a
misnomer as applied to energy storage, however, its use is very common and it is used in this report as
Contingency reserves may be provided by both spinning and non-spinning units, depending on the market.
The requirements for non-spinning reserves are the same except the resource does not need to begin
responding immediately, but still requires full response within 10 minutes. These requirements depend upon
market and market reliability rules. For an example see PJM, PJM Manual 11: Scheduling Operations, Revision
43, September 24, 2009,
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
The applications in Table 2 can be divided any number of ways into a number of different groups.
However, for purposes of assessment in this report, it is helpful to classify these applications into
two general categories based on the amount of time the storage device is required to provide
service because discharge time is a fundamental characteristic distinguishing most energy storage
technologies. The first category is storage for high power or rapid discharge applications where
the device must be able to discharge for periods of up to about one hour. The second category is
energy management applications where the device must be able to discharge for several hours or
more. Some applications may overlap both categories, depending upon the type of installation in
question, but these categories offer a valid basis for comparison of storage technologies
performing, at least to the first degree, similar functions.
Valuation of Storage for the Grid
Each application of electricity storage for the power grid offers distinct benefits. One of the
challenges facing electricity storage technologies is appropriate valuation of these benefits,
especially in providing multiple services in combination. For example, some storage technologies
can provide load-leveling (and associated benefits such as lower cycling-induced maintenance),
regulation service, contingency reserves, and firm capacity. Historically, it has been difficult to
quantify these various value streams without sophisticated modeling and simulation methods. The
emergence of wholesale electricity markets now provides more transparent data for both utilities
and independent power producers to consider the opportunities for electricity storage.18
Depending on the market, these data allow evaluation of both the economic yield and optimum
location of electricity storage devices for arbitrage, capacity, operating reserves, and other
ancillary services.19
As of 2009, wholesale energy markets exist in parts of more than 30 states and cover about two-thirds of the U.S.
population. Independent System Operators and Regional Transmission Organizations Council, 2009 State of the
Markets Report, prepared by the ISO/RTO Council, 2009,
R. Sioshansi, P. Denholm, T. Jenkin, and J. Weiss, “Estimating the Value of Electricity Storage in PJM: Arbitrage
and Some Welfare Effects,” Energy Economics, No. 31, 2009, pp. 269-277.
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Figure 1. Estimated Life-Cycle Value of Several Electricity Grid Storage Applications
Source: Compiled from Eyer and Corey, 2010 and Denholm et al., 2010.20
While there is significant variation and uncertainty in costs, most electricity storage assessments
indicate that few commercially available bulk electricity storage technologies are deployable for
less than $1,000/kW. For comparison, Figure 1 summarizes the life-cycle value of several storage
applications estimated in several previous studies in a number of locations. (The life-cycle value
can serve as a proxy for the capital cost needed for storage to be economically viable for each of
these applications.) As Figure 2 shows, $1,000/kW falls within the range of estimated life-cycle
value for all but one of the applications shown, indicating that the storage value could exceed
storage costs in specific applications. For example, energy arbitrage revenues, independent of
other storage benefits, would require a capital cost of less than $1,000/kW over most of the
locations studied. The value of electricity storage increases, however, when taking advantage of
other individual sources of revenue or even combined services. A device with sufficient energy
capacity for energy arbitrage would likely be able to provide system capacity as well. The
combination of these two services could, therefore, likely support a device costing somewhat
more than $1,000/kW.
Figure 1 shows that regulation service and contingency reserves, which are shorter-duration
applications requiring less energy capacity, have potentially higher value than energy arbitrage.
The challenge for these applications is that a device providing contingency reserves must be able
to respond rapidly, which is technically harder to do. Frequency regulation is particularly
demanding, requiring continuous changes in output, frequent cycling, and fast response. It is also
the highest-value opportunity for an electricity storage device, however, and has been the focus of
Both studies provide detailed explanation of sources and methods. Regulation value may exceed $4000/kW.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
many potential electricity storage applications, especially given its fairly small energy
Defining the Cost of Electricity Storage
When discussing the costs of storage technologies, a critical issue is that storage devices in electric applications have
both a power component (kW of discharge capacity) and an energy component (kWh of discharge capacity, which may
also be expressed as hours of discharge at rated output). The total cost of a storage application must account for the
ratings of both components, and may be expressed differently depending on the application or audience. Utilities, for
example, universally define the cost of power plants only in terms of rated power ($/kW), so they would expect to
see costs in these terms, with the hours of storage (kWh capacity) expressed separately. A grid storage plant might,
therefore, be expressed as costing $2000/kW for a device with eight hours of discharge capacity. On the other hand,
the battery community typically expresses costs in terms of rated energy ($/kWh), and may or may not include the
power component in the cost. So the cost of a battery might be stated as $500/kWh with the power capacity of the
battery established separately. When evaluating the economics of storage technologies, care must, therefore, be taken
to ensure that the costs for meeting both kW and kWh specifications are included and that both components are
“sized” properly for any specific application.
It is difficult to estimate the total market size for electricity storage in the U.S. grid. The most
comprehensive assessment of market size identifies hundreds of gigawatts of total applications.22
However, some of these applications overlap. For example, end use time-of-use (TOU) rate
management effectively duplicates load-leveling on the wholesale side. Furthermore, several of
the highest-value services, such as regulation service, have the smallest market opportunities.23
Even with these considerations, the potential market for electricity storage is large, and that
market is expected to grow in value and size with the increasing deployment of renewable energy
Frequency regulation theoretically is a net zero energy service over relatively short time scales, meaning the energy
capacity of the device can be much smaller than that of devices providing operating reserves and energy arbitrage.
Several power markets in the United States have changed or have proposed to change their treatment of regulation to
accommodate energy-limited storage technologies. Furthermore, it has been suggested that fast-responding storage
devices could receive a greater value per unit of capacity actually bid, because they could actually reduce the amount of
reserves needed. For example, “faster responsive resources can help to reduce California ISO’s regulation procurement
by up to 40% (on average)” and “California ISO may consider creating better market opportunities and incentives for
fast responsive resources.” Y.V. Makarov, J. Ma, S. Lu, and T.B. Nguyen, “Assessing the Value of Regulation
Resources Based on Their Time Response Characteristics,” Pacific Northwest National Laboratory, PNNL – 17632,
June 2008.
Eyer and Corey, 2010.
Requirements for frequency regulation resources are typically set for each Independent Service Operator (ISO) or
utility. Regulation requirements frequently change by the month, day, and hour. However, regulation requirements are
about 1% of peak capacity, based on NYISO and ISO-NE regulation requirements for 2009. 1% of peak capacity in the
entire United States corresponds to about 10 GW.
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Energy Storage and Renewable Energy
Renewable energy sources, such as wind and solar generation, create additional opportunities for
energy storage deployment due to the variability and uncertainty of the electricity they produce.
As variable renewable generation (VG)24 from these sources is added to the grid, it can have a
number of operational impacts on the grid, many of which can be mitigated with electricity
storage (or other enabling technologies):
Frequency Regulation Requirements—VG adds to the short-term (seconds to
minutes) variability in electric power frequency, which must be maintained very
close to the 60 cycles per second (hertz) for proper and reliable grid operation.25
Load Following Requirements—VG adds to the hourly requirements for
generation supply (ramping) on the grid, increasing the cycling and associated
maintenance of conventional generators.
Uncertainty in Net Load—Wind availability is less predictable than either the
variation in electric load or the availability of conventional generators. This
uncertainty can increase the cost of power system operation because it can result
in too many or too few generators being available to respond to variation in “net
load,” which is the electric load remaining on the grid after wind power supplies
are added.26
Ramping Range and Curtailment—VG increases the difference between the
daily minimum and maximum electricity demand (including an effective
reduction in minimum load) which can force conventional generators to reduce
output. In some cases this difference may force generation units that ought to be
running continuously to cycle off during periods of high wind output, or it can
force wind generators to curtail output, “wasting” renewable generation potential.
Transmission Requirements—Some renewable resources, like wind and
concentrating solar power, are remotely located, requiring new transmission to
supply the grid. New transmission is difficult to construct for economic and
The variable generation (VG) nomenclature is used by the North American Electric Reliability Corporation (NERC).
See NERC, Accommodating High Levels of Variable Generation, April 2009,
The amount of additional regulation reserves required as a function of VG penetration has yet to be established
definitively, especially since the impact on minute-to-minute regulation requirements is mitigated by aggregating large
amounts of wind power with variability largely uncorrelated in the regulation time frame. However, a recent analysis
by the California Independent System Operator (CAISO) of a 33% renewable portfolio standard suggested that the use
of VG could increase regulation requirements by a factor of two to four. See CAISO, Integration of Renewable
Resources: Transmission and Operating Issues and Recommendations for Integrating Renewable Resources on the
California ISO Controlled Grid, November 2007.
This is actually the combination of the uncertainty in load and wind. As VG penetration increases, it begins to
dominate the net load uncertainty. This can also result in a shortage of available generation capacity. An example is the
ERCOT event of Feb. 26, 2008, where a combination of factors—including greater than predicted electricity demand,
forced outage of a conventional generation unit, wind forecast not being given to system operators, and lower than
expected wind production—resulted in too little generation capacity online to meet load. As a result, the ERCOT
system needed to deploy high-cost quick-start generation units and pay customers to curtail load. This issue has
important implications for the use of storage to mitigate uncertainty. Energy storage, like any other generation, must be
scheduled; a storage device used for load leveling may not be able to simultaneously provide hedging against underforecasted wind, because it may already be discharging. See E. Ela, and B. Kirby, ERCOT Event on February 26, 2008:
Lessons Learned, NREL/TP-500-43373. National Renewable Energy Laboratory, July 2008.
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policy reasons, however, and use of dedicated long-distance transmission for
wind or solar will be limited by the relatively low capacity factor of the resource.
Storage could increase line-loading and help reduce wind generation curtailment
due to transmission constraints.27
Figure 2 illustrates several of the above impacts on net load and corresponding operation of the
grid. In this figure, wind generation is subtracted from the load, showing the “residual” or net
load that the utility would need to meet with conventional sources. As the figure shows, the
change in generation the grid would need to provide for load-following purposes (ramp range)
can be much higher than overall load due to the variable contributions of wind power.
Figure 2. Impact on Net Load from Using Wind Generation
Source: P. Denholm, E. Ela, B. Kirby, and M. Milligan, The Role of Energy Storage with Renewable Electricity
Generation, NREL/TP-6A2-47187, National Renewable Energy Laboratory, 2010.
Note: This figure uses load data from the Electric Reliability Council of Texas (ERCOT) in 2005 along with 15
GW of spatially diverse simulated wind data from the same year.
Notwithstanding the potential contribution of storage technologies to grid operation, there is
considerable debate over the “need” for electricity storage with moderate penetration of
renewables. Many of the grid impacts listed above have been evaluated in various wind
integration studies attempting to evaluate the operational feasibility and associated costs of wind
integration. To date, most studies have found a relatively low cost of accommodating wind
Co-locating wind and storage has long been proposed to reduce the amount of transmission needed for new
development, coming at the tradeoff of less efficient use of energy storage. See P. Denholm, and R. Sioshansi, “The
Value of Compressed Air Energy Storage with Wind in Transmission-Constrained Electric Power Systems,” Energy
Policy, Vol. 37, pp. 3149-3158. This has been proposed to relieve congestion in the Texas grid, for example, where the
state’s best wind resources are located largely in the sparsely populated western part of the state, and transmission
capacity is limited. See N. Desai, et al., Study of Electric Transmission in Conjunction with Energy Storage
Technology, Lower Colorado River Authority, Texas State Energy Conservation Office, August 21, 2003.
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variability on the grid—typically less than $5/MWh (0.5 cents/kWh), adding less than 10% to the
cost of wind energy—when wind is providing up to 20% of a particular grid system’s demand.28
This low cost, mostly resulting from the large amount of flexible generation already available to
meet the variability in demand, has been used to argue that deployment of storage is not justified
based on variability impacts.29 However, many potentially significant costs, such as the
operations and maintenance costs of increased generator cycling, have yet to be quantified and
are not included in these studies.30 Furthermore, the studies do not consider the economic and
societal challenges associated with transmission expansion, or the option of storage as a method
to supplement new transmission.31 Consideration of these factors would almost certainly increase
the value of storage. A strong argument also can be made that VG will increase the value
proposition for storage, adding to the values that already exist in today’s grid. In general,
renewables are likely to increase the potential market size for electricity storage (for example, by
increasing the amount of certain types of generation reserves needed).
The operational value of combining a dedicated electricity storage device with a specific wind or
solar generation plant is also the subject of debate. Many storage applications dedicated to
individual renewable generators, such as renewables “firming,” which seeks to reduce variability
in renewable power output, are actually specific examples of the more general applications in
Table 2. For example, shifting wind power supply from periods of low demand to periods of high
demand is fundamentally the same as energy arbitrage. The economic benefits of this application
are greatest when the electricity storage operator can choose from all of the generators in a
system, storing electricity from any source instead of storing only wind generation, when demand
is lowest.32
J. DeCesaro, K. Porter, and M. Milligan., “Wind Energy and Power System Operations: A Review of Wind
Integration Studies to Date,” The Electricity Journal, Vol. 22, No. 10, December 2009, pp. 34-43.
Note that these studies have not necessarily focused on storage and generally do not attempt to determine the optimal
system (including the amount of storage if any) that provides the lowest cost of energy.
Wind integration studies typically use proprietary software and data sets, and do not always state which costs are
included or excluded. However, the Western Wind and Solar Integration Study (the highest penetration U.S. integration
study as of 2009) states: “‘Wear and tear’ costs due to increased or harder cycling of units were not taken into account
because these have not been adequately quantified.” See D. Lew et al., “How do Wind and Solar Power Affect Grid
Operations: The Western Wind and Solar Integration Study,” NREL/CP-550-46517, National Renewable Energy
Laboratory, September 2009.
The more recent U.S. studies of very high penetration (the Western Wind and Solar Integration Study and the Eastern
Wind Integration Study) require power and energy exchanges over larger areas than typically occur in the existing
system. See. M. Milligan, et al., Large-Scale Wind Integration Studies in the United States: Preliminary Results,
NREL/CP-550-46527, September 2009.
There are some exceptions when there are benefits of operationally combining VG and energy storage, typically
through co-location and sharing of certain high-cost components. The best example is integrating thermal storage into a
concentrating solar power (CSP) plant; another example is sharing power electronics in a distributed PV/battery
system. There are several other applications where co-location of VG and storage may make sense. Wind plants placed
in areas of weak transmission can potentially introduce power quality and stability issues, and storage can be a
mitigating technology; however, improved power electronics in modern wind turbines may be a lower-cost alternative.
Finally, combining wind and energy storage has been proposed as an alternative (or supplement) to developing new
transmission capacity. Despite these potential applications, the majority of storage deployed in the grid will likely be a
shared resource, which will benefit the entire system and not just a single generator or load. J.C. Smith et al., “Utility
Wind Integration and Operating Impact State of the Art,” IEEE Transactions On Power Systems, Vol. 22, No. 3,
August 2007. Just as loads are balanced in aggregate, the net load in the future grid—after all VG sources are
included—will be balanced by a mix of conventional generation, plus flexibility options that may include energy
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Grid Storage with High Renewables Penetration
Perhaps the strongest argument for energy storage in the grid occurs at relatively high penetration
of VG. The oft-cited limits of VG penetration in the range of 10%-20% and the associated “need”
for electricity storage appear to be moving targets as new grid integration techniques develop.
Recent studies have found that 30% penetration (on an energy basis) of renewables on the grid
appears to be feasible without an inherent need for storage to maintain system reliability.33
However, there appear to be some economic limits of VG at high penetration based on the limited
coincidence of VG supply and electricity demand patterns.34 At sufficiently high penetration of
wind or solar generation, VG supply can exceed demand for electricity, which results in curtailed
generation and decreased economic viability of VG. This problem is exacerbated by the cycling or
operational limits on conventional generators, many of which must remain on-line to provide
operating reserves or be available when wind and solar generation is insufficient to meet demand.
Such VG limits can be observed in the Western Wind and Solar Integration Study (WWSIS) with
30% wind penetration, at which wind power supply almost completely removes conventional
generation during high wind periods.35 Figure 3 shows the net load with wind in the study area,
along with the modeled operation (dispatch) of generation plants, which requires significant
ramping of coal generators. In one evening the net load (electricity demand minus wind supply)
drops to about 6 GW, meaning that wind is providing about 32 GW, even after much of the wind
generation is exported to surrounding areas. Doubling the amount of wind generation capacity
would produce a large amount of wind generation curtailment on this day, since the remaining 6
GW of load cannot absorb an additional 32 GW of wind generation, and the conventional
generation units are probably near or at their ability to ramp down or cycle off. Similarly, an
analysis of the Irish grid found limited wind generation curtailment at a wind penetration of 40%
on an energy basis.36 However, beyond this point, wind curtailment rates sharply increase and the
study found economic benefits of storage at the point where about 50% of the system’s energy is
provided by wind.
At higher penetration of renewable generation, the ability of conventional generators to reduce
output becomes an increasing concern. VG begins to displace units that are traditionally not
cycled, and the ability of conventional thermal generators to reduce output may become
constrained.37 Utilities in the United States have expressed concern about their systems
“bottoming out” due to the minimum generation requirements during overnight hours, and being
unable to accommodate more VG during these periods. Cycling operations, including
startup/shutdown, on-load cycling, and high frequency MW changes, can damage generation
equipment. However, the costs of such cycling can be very difficult to quantify.38 Minimum load
points would be less of a constraint if conventional power plants could be quickly shut down and
M. Milligan et al., Large-Scale Wind Integration Studies in the United States: Preliminary Results, NREL/CP-55046527, National Renewable Energy Laboratory, September 2009.
P. Denholm and M. Hand, “Grid Flexibility and Storage Required to Achieve Very High Penetration of Variable
Renewable Electricity,” Energy Policy, No. 39, 2011, pp. 1817-1830.
GE Energy, Western Wind and Solar Integration Study, prepared for National Renewable Energy Laboratory, NREL
Report No. SR-550-47434, May 2010.
A. Tuohy and M. O’Malley, “Impact of Pumped Storage on Power Systems with Increasing Wind Penetration,”
Energy Policy, Vol. 39, No. 4, 2011, pp.1965-1974.
For example, see M. Milligan, et al., The Impact of Electric Industry Structure on High Wind Penetration Potential,
NREL/TP-550-46273, National Renewable Energy Laboratory, July 2009.
S.A Lefton, and P. Besuner, “The Cost of Cycling Coal Fired Power Plants,” Coal Power, Winter 2006.
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started up at low cost. However, with the exception of certain peaking power plants such as
aeroderivative turbines and fast-starting reciprocating engines, most conventional plants have
minimum up-and-down times, and require several hours to restart—at considerable cost.
Figure 3. Generation Dispatch in the WWSIS Study at 30% Wind Penetration
Source: GE Energy (for NREL), 2010.
In some markets, electricity prices have dropped below the actual variable (fuel) cost of
producing electricity on a number of occasions. This indicates that power plant operators are
willing to sell energy at a loss to avoid further reducing output. At this point an increasing
fraction of wind generation will simply be unusable by the system and electricity storage becomes
an increasingly attractive method of shifting otherwise curtailed wind generation to times of
lower wind generation (and/or higher loads). Overall, the increase in energy storage value or
market size associated as a function of increasing VG penetration is not well quantified. In
addition, financial mechanisms for energy storage installations to recover their costs as VGenabling technologies are incomplete.
Ongoing Barriers to Storage Deployment for the Grid
Historically, the primary barriers to energy storage deployment for the grid have been establishing
a positive benefit/cost ratio for storage and actually capturing the economic value that storage
provides. While the emergence of restructured wholesale electricity markets has provided new
storage opportunities, electricity storage still faces significant non-technical barriers to
widespread market acceptance and adoption, further discussed below.
Unquantified and Uncaptured Benefits
Before wholesale electricity markets began to be restructured in the 1990s, the value of ancillary
services and other grid support functions was largely hidden in electric utilities’ cost of service.
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For example, the value of providing operating generation reserves, which affect the ability of a
power plant to respond to the electric grid’s dynamic operating needs, was rarely calculated.39 The
Federal Energy Regulatory Commission (FERC), which regulates wholesale transmission grid
tariffs, and grid operators are increasingly recognizing the value of these services, and the
advantages of electricity storage in providing them, especially because they generally require fast
response and limited energy delivery for which storage devices are well-suited. However, much
of the nation remains in a traditional regulated utility framework, where the benefits of storage in
providing grid support services remain undervalued. Furthermore, wholesale electricity markets
do not capture all the costs of generation plant operation, especially those related to cycling and
ramping. Quantifying the full value of energy storage remains challenging due in part to the
limited ability of utility models to simulate realistic power plant and storage system operation
over multiple time scales.
Wholesale electricity markets also do not capture all the potential benefits of storage to the
electric distribution system (which connects the high voltage grid to electricity end users),
including deferral of new equipment and reduced power line losses.40 Deploying storage in the
distribution system will likely be particularly challenging since distribution will almost certainly
remain a regulated monopoly utility service, with limited exposure to market conditions that
provide incentives for new technologies.
Finally, there are currently few mechanisms in place for potential energy storage operators to
capture economic benefits associated with enabling renewable energy sources. Some value may
be captured indirectly. For example, if VG increases regulation service requirements, then it also
increases market opportunities for storage. However, there are few comprehensive mechanisms to
capture any potential synergies between VG and storage.
Regulatory and Market Uncertainty and Risk
Utilities tend to be risk averse. To meet electricity supply requirements, they tend to rely on
mature generation technologies with which they have long-term experience rather than new
technologies. Conventional generation options, including flexible natural gas-fired turbines,
continue to be the primary option for load following, peak power generation, and ancillary
services. Market uncertainty, combined with a lack of incentives for risk taking in regulated
utilities, discourages the deployment of technologies that are new or have long lead times. Long
development times and risk are a particular challenge for the two leading options for bulk energy
storage—compressed air and pumped hydro. PHS, in particular, faces unique environmental and
other siting challenges (including new transmission requirements), and also faces long permitting
and construction times. The regulatory treatment of energy storage for the grid is often unclear,
and has complicated the financing of large storage projects.41 These issues are discussed in more
detail in the technology sections.
S.J. Jabbour, and W.M. Wells, “Optimal Dispatching of Storage Plants with Dynamics,” Proceedings of the Second
International Conference on Compressed Air Energy Storage, EPRI TR-101770, Electric Power Research Institute,
December 1992.
A. Nourai, V. I. Kogan, and C.M. Schafer, “Load Leveling Reduces T&D Line Losses,” IEEE Transactions on
Power Delivery, Vol. 23, No. 4, October 2008, pp. 2168-2173.
A recent example is the Lake Elsinore Advanced Pumped Storage Project, which applied to be considered a
transmission facility for purposes of utility rate recovery. FERC denied this request, forcing it to recover costs through
an alternative mechanism, such as the more risky (at least for the developer) generation market. Federal Energy
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Lack of Incentives for Customer-Sited Storage
As with deployment by utilities or independent power producers, customer-sited storage faces
challenges of valuation and capturing that value. The benefits of customer-sited storage can
exceed that of centrally deployed storage. In addition to providing load-leveling and ancillary
services, customer-sited storage can provide additional advantages of reduced distribution losses
and increased grid capacity. Some customers, particularly large commercial and industrial
consumers, can capture some of the benefits of load-leveling and peak capacity via time-of-use or
demand-based electricity rates. But many storage benefits, particularly the value of ancillary
services, cannot be captured through their rates. This makes electricity storage uncompetitive for
many electricity end users.
In summary, energy storage for the grid faces significant barriers to being evaluated on the same
economic terms as conventional grid options perceived to be less risky for utilities both in
restructured markets and in traditional integrated utilities. Storage also faces increasing
competition from a variety of technical and market options for providing grid flexibility. New
market mechanisms are being deployed to share generation, reserves, and net loads—all of which
can increase overall power system flexibility.42 Demand response also may compete against new
storage options as a significant source of operating reserves. In many locations in the United
States, demand is increasingly used as a source of grid services. In Texas demand response
typically provides half of the contingency reserve requirements. Other regions also use (or are
evaluating) load to provide regulation. Greater participation of load providing reserves and load
shifting will require regulatory and policy changes in addition to new technologies.
Current Grid Storage Policies
Recognition of the potential value of energy storage for grid applications has led to efforts by
federal and state agencies to engage in storage R&D efforts ranging from analysis of benefits to
providing direct incentives.
Analysis of Storage Benefits
Federal and state agencies have supported a number of studies to evaluate the potential role and
value of energy storage. These studies have demonstrated the potential benefits of traditional
storage applications discussed above.43 Other analyses have identified the unique benefits of fast
response electricity storage technologies (e.g., flywheels) in providing frequency regulation more
efficiently and with fewer emissions than conventional generation.44 Due in part to such analysis,
Regulatory Commission, “FERC Encourages Transmission Grid Investment,” Docket No. ER06-278-000, March 20,
Greater aggregation of loads and reserves has historically been one of the least-cost methods of dealing with demand
variability, especially because it often requires operational changes and relatively little new physical infrastructure.
This includes introducing sub-hourly markets that allow systems faster response to variability. See M. Milligan, et al.,
“The Impact of Electric Industry Structure on High Wind Penetration Potential,” NREL/TP-550-46273, National
Renewable Energy Laboratory, July 2009.
Many of these studies have been performed by the Department of Energy’s Energy Storage Systems Research
Program, managed by Sandia National Laboratories.
Makarov et al. 2008. As noted earlier the ramp requirement of 1 MW/min could easily be provided by a 1 MW
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there is a growing consensus, for example, that fast-response resources should be paid a premium
for regulation services in wholesale power markets to accurately reflect the value they add to the
electric system.45 As the Chairman of the Federal Energy Regulatory Commission has stated,
Regarding compensation, some storage technologies appear able to provide a nearly
instantaneous response to regulation signals, in a manner that is also more accurate than
conventional resources. These two characteristics can reduce the size, and hence overall
expense, of the regulation market. Most existing tariffs or markets do not compensate
resources for superior speed or accuracy of regulation response, but such payment may be
appropriate in the future....46
Other studies have demonstrated the potential benefit of electricity storage in supporting the
deployment of variable generation47 and reducing distribution losses.48 Analytic efforts like these
help guide policy and market reforms to appropriately capture the value of grid storage services.
Research, Development, and Demonstration Projects
Federal and local agencies have supported basic research, engineering, technology development,
and demonstration programs for many energy storage technologies in grid applications. Until
recently, Department of Energy (DOE) R&D efforts in grid electricity storage were relatively
modest. From 1992 through 2008 the annual budget for the Energy Storage Systems Program
within the DOE’s Office of Electricity Deliverability and Energy Reliability was typically less
than $10 million per year.49 (Programs supporting storage primarily for transportation
applications are discussed in the next section.) In 2010 the DOE budget was increased to $14
million. The American Recovery and Reinvestment Act of 2009 (ARRA) also greatly increased
funding for storage R&D through several programs. Applied research has been supported through
the Advanced Research Projects Agency–Energy (ARPA-E) program, with $30.6M awarded for
FY2010 and $37.7 awarded for FY2011.50
flywheel, but would require about 2 MW of hydroelectric capacity, 3 MW of gas-fired combustion turbine capacity, or
30 MW of gas-fired combined cycle or coal capacity. As a result, using fast responding energy storage to provide
regulation can reduce the amount of regulation required, potentially reducing system costs.
Federal Energy Regulatory Commission, Order Accepting Tariff Revisions, Docket ER09-836-000, May 15, 2009.
Jon Wellinghoff, Chairman, Federal Energy Regulatory Commission, Testimony before the Senate Committee on
Energy and Natural Resources Hearing on Energy Storage, Dec. 10, 2009.
KEMA, Inc., Research Evaluation of Wind Generation, Solar Generation, and Storage Impact on the California
Grid, prepared for the California Energy Commission, Public Interest Energy Research Program, CEC-500-2-1-010,
June 2010.
A. Nourai, V.I Kogan, and C.M. Schafer, “Load Leveling Reduces T&D Line Losses,” IEEE Transactions on Power
Delivery, Vol. 23, No. 4, October 2008, pp.2168-2173.
J. Boyes, “FY07 DOE Energy Storage Program Peer Review,” Sandia National Laboratories, slide presentation,
M. Johnson , “Gridscale Rampable Intermittent Dispatchable Storage (GRIDS) Program,” presentation to the DOE
Annual Storage R&D Review Meeting, November 2010.
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Electricity storage demonstrations have been funded directly through the ARRA with a total
funding of $185 million.51 Demonstration programs are particularly important in the electric
utility sector, since regulated utilities are typically not rewarded for risk taking, and have few
incentives to be the first to deploy new technologies. These funding activities are discussed in
more detail in the technology chapters. State agencies have also supported electricity storage
demonstrations, often with co-funding from federal agencies. Examples include New York State
Energy Research and Development Authority (NYSERDA) support of demonstration programs
for flywheels and several battery technologies.52 The California Energy Commission (CEC) also
has supported at least 20 storage research and demonstration projects since 1990.53
Market Rules
Securing the ability of energy storage to compete on common terms against traditional generation
assets is a critical challenge for grid storage developers. The creation of wholesale markets allows
increased participation of electricity storage devices, but the level of participation varies by
market. In 2007 FERC issued Order 890 requiring wholesale markets to consider non-generation
resources for grid services. The order required that non-generation resources (including energy
storage and demand response) be evaluated on a comparable basis to services provided by
generation resources in meeting mandatory reliability standards, providing ancillary services, and
planning the expansion of the transmission grid.54
Since that time Independent System Operators (ISOs) and Regional Transmission Organizations
(RTOs), the entities that operate regional power grids, have increased market access, including
creating new tariffs for electricity storage.55 56 In October 2011, FERC issued Order 755 requiring
a new compensation method for grid regulation service “to remedy undue discrimination” against
faster-ramping resources such as energy storage.57
Several large-scale grid storage projects have been proposed or constructed to take advantage of
high-value ancillary service markets. Examples of operating projects include a 20 MW flywheel
facility in New York and a 12 MW battery facility in Chile.58 However, market rules are still
E. Christy, “Energy Storage Systems Program: 2010 Update Conference” National Energy Technology Laboratory.
November 2, 2010.
G. Huff, “NYSERDA/DOE Joint Energy Storage Initiative,” Sandia National Laboratories, November 2, 2010.
P. Kulkarni, “California Energy Commission Support for Electricity Energy Storage,” California Energy
Commission, May 6, 2009.
Federal Energy Regulatory Commission, Preventing Undue Discrimination and Preference in Transmission Service,
Order No. 890, February 16, 2007.
For example, the New York ISO created a “limited energy storage resource”(LESR) tariff. In its approval of the
tariff, FERC stated “We find that the proposed tariff revisions to incorporate LESRs will benefit NYISO’s markets by
providing them with a new source of regulation service with unique operational characteristics that enable very fast
responses to needs for regulation.” Federal Energy Regulatory Commission, Order Accepting Tariff Revisions, Docket
ER09-836-000, May 15, 2009.
Federal Energy Regulatory Commission, Order Conditionally Accepting Stored Resources Compliance Filing,
Docket No. ER09-1126-001, May 10, 2009.
Federal Energy Regulatory Commission, Frequency Regulation Compensation in the Organized Wholesale Power
Markets, Order No. 755, October 20, 2011.
Sonal Patel, “Milestones for Flywheel, Lithium Battery Grid-Scale Projects,” Power, August 1, 2011.
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evolving in some regions and much of the United States has no access to restructured energy
markets to begin with.59 Uncertainty remains as to how storage assets should be able to capture
multiple value streams. Challenges remain in gaining access to distribution and customer-sited
storage. One storage company has developed a business model in which customer-sited storage is
owned by the utility as a peak generation and load shifting asset.60
Incentives for Deployment
There have been a number of financial incentive programs for grid storage technologies offered
by the federal government. In addition to the direct funding of demonstration programs, the
ARRA amended the DOE’s Loan Guarantee Program making certain electricity storage
technologies eligible.61 This program has been applied to a large solar plant in Arizona, discussed
in Chapter 12. The ARRA also established a manufacturing tax credit that could potentially be
applied to electricity storage manufacturing facilities. Several states have incentives supporting
deployment of renewable energy and energy efficiency devices which could be applicable to
storage-related equipment including fuel cells and cold thermal storage, but the impact of these
programs on actual adoption has been modest. Finally, certain renewable generators are eligible
for a 30% federal investment tax credit (ITC), currently scheduled to expire in 2016. This means
that thermal energy storage for concentrating solar power is eligible, since it is integrated into a
renewable generator. However, stand-alone storage technologies are not covered, since they are
typically not integrated into individual renewable generation installations.
A federal direct incentive program was proposed in 2010, which included a 20%-30% ITC for
new storage investments depending on size and application.62 Various other federal energy and
climate-change proposals have included language either providing financial incentives for or
otherwise encouraging energy storage deployment for the grid, but these proposals have yet to be
Storage Portfolio Standards
Recently there have been proposals for government-mandated energy storage portfolio standards,
similar to renewable portfolio standards (which require utilities to purchase a certain portion of
their energy supplies from renewable generators).63 One example that has been enacted in state
law is California’s AB 2514, which as originally proposed required certain utilities to install
See, for example: “Revised Draft Final Proposal for Participation of Non-Generator Resources in California ISO
Ancillary Services Markets.” California Independent System Operator, March2010.
Ice Energy, “SCPPA to Undertake Industry’s Largest Utility-Scale Distributed Energy Storage Project,” press
release, January 27, 2010.
The loan guarantee program was created to support the deployment of innovative clean energy technologies pursuant
to Section 1703 of Title XVII of the Energy Policy Act of 2005. Title XVII was amended by the American Recovery
and Reinvestment Act of 2009 to create Section 1705, a new program for deploying renewable energy and electric
power transmission projects.
“Storage Technology for Renewable and Green Energy Act of 2010,” S. 3617, 111th Cong., 2nd Sess, 2010.
Brian Nese, “Energy Storage Developers Call for National Storage Portfolio Standard,” Renewable + Law, Internet
blog, July 21, 2009.
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storage devices to meet 2.25% of peak demand. As passed, the bill requires the California Public
Utilities Commission to determine targets by March 1, 2012.64
Storage for Electric Transportation Applications
Transportation Storage Technologies and Pathways
The primary purposes of electrifying transportation are to reduce dependence on oil, which
currently provides most of the nation’s transportation fuel, and to reduce vehicle emissions. There
are two pathways to store electricity for use in electric vehicle (EV) fleets (Figure 4).65 The first
is switching from oil-derived fuels to one of several electricity-derived fuels, either gaseous or
liquid, with hydrogen receiving the most attention in recent years. These alternative fuels can be
produced using electricity (for example, by splitting hydrogen from oxygen atoms in water) either
centrally or near the point of use. They can then be burned in a vehicle using a modified internal
combustion (IC) engine and a conventional drive train. Such fuels can also be burned in an IC
engine-electric drive train (hybrid-electric) vehicle configuration (HEV), or in a similar fuel cell
electric vehicle (FCEV) configuration. The second pathway for electrified transport is to store
electricity on board the vehicle, primarily using batteries, and to use that stored electricity to
power an electric motor. The vehicle can be either a “pure” battery electric vehicle (BEV) or a
vehicle that uses both stored grid electricity and an IC or fuel cell engine, typically referred to as
a plug-in hybrid electric vehicle (PHEV).
Figure 4. Pathways to Vehicle Electrification
Source: P. Denholm, National Renewable Energy Laboratory.
Key: B = battery, EV = electric vehicle, FC = fuel cell, H = hybrid, IC = internal combustion, P = plug-in.
California Legislature, A.B. 2514 (introduced), February 19, 2010. ); and A.B. 2514 (approved), September 29, 2010.
This report does not consider alternative fuels, such as ethanol, that are not primarily derived from electricity.
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Impacts and Benefits of Vehicle Electrification
The most obvious benefit of vehicle electrification is reduced dependence on petroleum-derived
fuels. The amount of displaced petroleum depends on the degree of electrification of individual
vehicles and of the fleet as a whole. An FCEV running on hydrogen or a pure electric vehicle uses
no gasoline, while a PHEV could reduce a large fraction of gasoline use, depending on battery
size and driving patterns.
Shifting from gasoline to electricity may have a number of impacts on the electric power grid.
One possible outcome is a need for new generation capacity for battery charging. However, the
availability of off-peak generation is estimated to be sufficient for a large number of vehicles
assuming some level of “smart” charging. A 2007 study estimated that spare generating capacity
could have electrified 73% of light-duty gasoline vehicles in 2002.66 This level of vehicle
electrification would displace petroleum equivalent to more than 50% of the nation’s oil imports.
Another study used a somewhat more conservative methodology to estimate that the bulk power
system in 2002 could have supported electrification of approximately 37% of vehicle miles
traveled (VMTs).67 The Electric Power Research Institute (EPRI) analyzed a scenario with 20%
of VMTs in the United States powered by electricity in 2030; the modeled electric generating
capacity was just 1.7% higher in this scenario compared to the base case scenario that assumed no
EVs or PHEVs.68 Other, regional studies similar have concluded that, essentially, if vehicles
charge off-peak, a large number of vehicles can be accommodated, but if on-peak charging is
allowed, there could be increased generation requirements during peak periods of electricity
demand.69 On the electric distribution side, the impacts of vehicle electrification are more
complex. In some locations, a concentration of vehicle charging could exceed the capacity of
distribution systems, and increased loads could shorten the lifetimes of distribution transformers.
Distribution system impacts and the need for upgrades, as well as the ability to reduce the impacts
via smart charging schemes, will need to be further evaluated, typically on a local level.70
EVs and PHEVs generally produce lower greenhouse gas emissions per mile than conventional
vehicles. The amount of reduction depends on numerous assumptions about vehicle performance
and the mix of electricity supplies used for charging. One estimate is that a PHEV powered by an
average proportion of coal-generated electricity produces carbon emissions per mile similar to
those of an HEV.71 If the PHEV is charged using the current grid average emissions, carbon
M. Kintner-Meyer et al., Impacts Assessment of Plug-In Hybrid Vehicles on Electric Utilities and Regional U.S.
Power Grids. Part 1: Technical Analysis, Pacific Northwest National Laboratory, 2007.
The biggest difference between the methods is estimating which generating capacity is available and economical to
use to charge vehicles during the peak months. C.H. Stephan and J. Sullivan, “Environmental and energy implications
of plug-in hybrid-electric vehicles,” Environmental Science & Technology, Vol. 42 No. 4, 2008, pp. 1185-1190.
M. Duvall and E. Knipping, Environmental Assessment of Plug-In Hybrid Electric Vehicles. Volume 1: Nationwide
Greenhouse Gas Emissions, Electric Power Research Institute, 2007.
Examples include: P. Denholm and W. Short, An Evaluation of Utility System Impacts and Benefits of Optimally
Dispatched Plug-In Hybrid Electric Vehicles, NREL/TP-620-40293, National Renewable Energy Laboratory, 2006;
and K. Parks, P. Denholm, and T. Markel., Costs and Emissions Associated with Plug-In Hybrid Electric Vehicle
Charging in the Xcel Energy Colorado Service Territory, NREL/TP-640-41410, National Renewable Energy
Laboratory, 2007.
C. Farmer et al., “Modeling the Impact of Increasing PHEV Loads on the Distribution Infrastructure,” 43rd Hawaii
International Conference on System Sciences (HICSS), January 5-8, 2010.
In the worst case scenario for a PHEV, net CO2 emissions are about the same as those of a conventional vehicle. Any
electricity supply mix less than 100% coal-generated will be cleaner. See C.H. Stephan, and J. Sullivan,
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emissions per mile are reduced by almost 60% compared to a conventional vehicle.72 Air
pollutant emission changes due to EV and PHEV penetration are complicated because they
depend on the type of generators used for electricity production, the pollution control equipment,
and policies that limit emissions. A California study projects that PHEVs would reduce nitrogen
oxide (NOx) and volatile organic compound (VOC) emissions per mile by 87% and 97%,
respectively, due to limits on the emissions of these pollutants.73 Estimates from other regions
project changes over a large range, including some locations where net emissions could increase
if current power plants do not install new pollution control devices.74 For example, one study
found that life cycle NOx emissions changes could range from -70% (assuming charging with
renewable generation) to +38% (charging with uncontrolled coal-fired plants) assuming no
pollution control policies.75 The actual impact on air quality is even more complex because
PHEVs displace emissions from urban areas to rural areas where power plants are typically
located and fewer people live. Estimates using air quality models generally indicate improved air
quality in urban areas as a result of vehicle electrification.76
When parked, vehicles could potentially provide various grid services. Charging of EVs can
potentially be controlled and can provide a source of dispatchable demand and demand response.
Controlled charging can be timed to periods of greatest VG output, while charging rates can be
controlled to provide contingency reserves or frequency regulation reserves. Vehicle-to-grid
(V2G) (where EVs can partially discharge stored energy to the grid) may provide additional value
by acting as a distributed source of energy storage. Most proposals for V2G focus on short-term
response services such as frequency regulation and contingency. Their ability to provide energy
services is more limited by both the storage capacity of the battery and the high cost of battery
cycling. This could restrict their ability to provide time shifting (energy arbitrage) beyond their
ability to perform controlled charging.77 The role of V2G is an active area of research. Because
“Environmental and Energy Implications of Plug-in Hybrid-Electric Vehicles,” Environmental Science & Technology,
Vol. 42 No. 4, 2008, pp.1185-1190.
One study shows slightly less relative reductions in life cycle carbon emissions because the carbon emissions due to
vehicle production (excluding the batteries) are similar, and battery production represents 2-5% of life cycle carbon
emissions from a PHEV. See C. Samaras and K. Meisterling,“Life Cycle Assessment of Greenhouse Gas Emissions
from Plug-in Hybrid Vehicles: Implications for Policy,” Environmental Science & Technology, Vol. 42 No. 9, 2008,
pp. 3170-3176.
J. Pont, Full Fuel Cycle Assessment: Well-to-Wheels Energy Inputs, Emissions, and Water Impacts, California
Energy Commission, 2007.
The Electric Power Research Institute (EPRI) has projected that, although coal-fired power plants would provide
much of the charging for PHEVs in 2030, most charging would nonetheless be from sources with pollution control
equipment (new, existing, and retrofitted). Emissions of NOx, SO2, and VOCs were therefore projected to go down with
PHEV penetration. See M. Duvall and E. Knipping, Environmental Assessment of Plug-In Hybrid Electric Vehicles.
Volume 2: United States Air Quality Analysis Based on AEO-2006 Assumptions for 2030, Electric Power Research
Institute, 2007.
L. Gaines et al. (2007), “Sorting through the Many Total-Energy-Cycle Pathways Possible with Early Plug-In
Hybrids,” Electric Vehicle Symposium (EVS23), Anaheim, CA, December 2-5, 2007.
EPRI used an air quality model to project that the PHEVs would reduce population exposure to ozone and particulate
matter. Another study used a utility simulation model to project that PHEV charging in Colorado would come primarily
from natural gas-fired power plants if there were no change in the electric generating fleet. This would lead to
significant reductions in NOx and VOC emissions in the Denver metro area, leading to modest improvements in ozone
concentrations. See G.L. Brinkman et al. “Effects of Plug-In Hybrid Electric Vehicles on Ozone Concentrations in
Colorado,” Environmental Science & Technology, Vol. 44 No.16, 2010, pp. 6256-6262.
This conclusion depends on the anticipated cycle life and cost of EV batteries. However, controlled charging
(without V2G) is still a potentially significant source of flexibility, with the ability to raise the minimum load and avoid
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electric vehicles in any form have yet to achieve significant market penetration, assessing their
potential as a source of grid flexibility is difficult. However, analysis has demonstrated potential
system benefits of both controlled charging and V2G.78
Barriers to Deployment and Policies to Increase Vehicle Electrification
A primary barrier to deployment of electric vehicles is their cost and availability. After the
discontinuation of commercially produced electric passenger vehicles in the early 1990s, and
before the introduction of the Nissan Leaf and Chevrolet Volt in late 2010, there were no massproduced electric passenger vehicles available in the United States.79 The costs of the current
generation of EVs and PHEVs are high—with recent prices for the Leaf and Volt about $35,000
and $39,000, respectively.80 The earliest projected deployment of fuel cell vehicles is 2015. While
the performance of battery technologies continues to improve, it is unclear when costs will reach
the point needed for large scale adoption.81
There are a number of federal and state policies targeted towards increasing the use of battery
electric and fuel cell vehicles. These include R&D efforts through the American Recovery and
Reinvestment Act of 2009 (ARRA, discussed in detail in the corresponding technology chapter).
ARRA also provides $2 billion toward grants for the manufacturing of advanced battery systems
and electric vehicle components. These funds are intended to support domestic manufacturing of
advanced lithium-ion batteries and hybrid electric systems and components. To incentivize
adoption, ARRA supports tax credits for the purchase of PHEVs. A comprehensive summary of
current federal and state incentives is provided at the Alternative Fuels & Advanced Vehicles Data
Other critical barriers include a lack of existing infrastructure for vehicle fueling and charging.
For hydrogen fueled FCEVs or HEVs, entirely new infrastructure is needed for fuel production,
transport and refueling. (These issues are discussed in more detail in the hydrogen chapter.) For
EVs, lack of charging infrastructure, combined with limited range of pure electric vehicles
curtailment. For additional discussion of the impact of battery life and cycling on the value of V2G, see S.B. Peterson,
J.F. Whitacre, and J. Apt, “The Economics of Using PHEV Battery Packs for Grid Storage,” Journal of Power Sources,
No. 195, 2010, pp. 2377-2384; and R. Sioshansi, R. and P. Denholm, “The Value of Plug-In Hybrid Electric Vehicles
as Grid Resources,” The Energy Journal, Vol. 31 No. 3, 2010, pp. 1-23.
Short, W., and P. Denholm. (2006) “A Preliminary Assessment of Plug-In Hybrid Electric Vehicles on Wind Energy
Markets” NREL/TP-620-39729.
Some non-highway, low speed vehicles (neighborhood electric vehicles, or NEVs) were available over this time.
Prices are manufacturer’s suggested retail price (MSRP) before federal tax incentives. Nissan USA, “Nissan LEAF,”
Web page, 2011.; General Motors, “2011
Volt,” 2011.
General Motors, in its recent IPO stated “In some cases, the technologies that we plan to employ, such as hydrogen
fuel cells and advanced battery technology, are not yet commercially practical and depend on significant future
technological advances by us and by suppliers. For example, we have announced that we intend to produce by
November 2010 the Chevrolet Volt, an electric car, which requires battery technology that has not yet proven to be
commercially viable. There can be no assurance that these advances will occur in a timely or feasible way.” Securities
and Exchange Commission (2010) Amendment to No. 9 to Form S-1 Registration Statement under the Securities Act of
1933 General Motors Company
U.S. Department of Energy, Alternative Fuels and Advanced Data Center, “Federal & State Incentives and Laws,”
website, 2011.
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presents a barrier to large-scale adoption, especially for those who do not have access to secure
charging at home.83 Current electric rate structures also create a barrier, preventing both
maximum benefit of controlled charging to the grid, and lowest-cost charging for the consumer.
For more discussion of charging infrastructure issues see T. Markel, Plug-in Electric Vehicle Infrastructure: A
Foundation for Electrified Transportation, Report No. CP-540-47951, National Renewable Energy Laboratory, 2010.
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Chapter 4: Batteries for Grid Applications
Batteries are devices that store energy chemically. This report focuses on “secondary” batteries,
which must be charged before use and which can be discharged and recharged (cycled) many
times before the end of their useful life. For electric power grid applications, there are four main
battery types of interest:
High temperature “sodium-beta”
Liquid electrolyte “flow” batteries
Other emerging chemistries84
Lead-acid batteries have been used for more than a century in grid applications and in
conventional vehicles for starting, lighting, and ignition (SLI). They continue to be the
technology of choice for vehicle SLI applications due to their low cost. Consequently, they are
manufactured on a mass scale. In 2010, approximately 120 million lead-acid batteries were
shipped in North America alone.85 Lead-acid batteries are commonly used by utilities to serve as
uninterruptible power supplies in substations, and have been used at utility scale in several
demonstration projects to provide grid support.86 Use of lead acid batteries for grid applications is
limited by relatively short cycle life. R&D efforts are focused on improved cycle-life, which
could result in greater use in utility-scale applications.
Sodium-beta batteries include sodium-sulfur (NaS) units, first developed in the 1960s,87 and
commercially available from a single vendor (NGK Insulators, Ltd.) in Japan with over 270 MW
deployed worldwide.88 A NaS battery was first deployed in the United States in 2002.89 There are
now a number of U.S. demonstration projects, including several listed in Table 3. The focus of
NaS deployments in the United States has been in electric distribution deferral projects, acting to
reduce peak demand on distribution systems, but they also can serve multiple grid support
Several of the battery types discussed in this chapter have been demonstrated or proposed for transportation
applications as well. However, they also have challenges in achieving the energy density or other characteristics needed
for storing large amounts of energy in mobile applications. Batteries for electric vehicles are discussed in Chapter 5.
Battery Council International, “Breakdown of North American Battery Shipments (2001-2010),” Chicago, November
4, 2011.
Electric Power Research Institute and U.S. Department of Energy (EPRI/DOE), EPRI-DOE Handbook of Energy
Storage for Transmission and Distribution Applications, Palo Alto, CA, No. 1001834, December, 2003. A 10 MW, 40
MWh lead-acid battery was built in Southern California in 1988. It operated for about nine years. A 21 MW, 14 MWh
lead-acid plant was built in Puerto Rico in 1994 to provide spinning reserves. It operated for about five years.
X. Lu et. al., “Advanced materials for sodium-beta alumina batteries: status, challenges, and perspectives,” Journal
of Power Sources, No. 195, 2010, pp. 2431-2442.
D. Rastler, “New Demand for Energy Storage,” Electric Perspectives, Edison Electric Institute, September 2008.
Nourai, A., “Installation of the First Distributed Energy Storage System (DESS) at American Electric Power (AEP):
A Study for the DOE Energy Storage Systems Program.” SAND2007-3580. Albuquerque, NM: Sandia National
Laboratories, June 2007.
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services. An alternative high-temperature battery, sodium-nickel-chloride, is in the early stages of
Table 3. Example NaS Battery Installations in the United States
Gahanna, OH (First U.S. demonstration)
North Charleston, WV
Bluffton, OH; Balls Gap, WV; East Busco, IN
New York Power Authorityd
Long Island, NY
Presidio, TX
Luverne, MN
Source: National Renewable Energy Laboratory compilation.
Continuous rating.
A. Nourai, Installation of the First Distributed Energy Storage System (DESS) at American Electric Power (AEP): A
Study for the DOE Energy Storage Systems Program, SAND2007-3580, Sandia National Laboratories,
Albuquerque, NM, June, 2007.
AEP, Energy Storage in T&D Applications, slide presentation, May 2009.
G. Sliker, “Long Island Bus: NaS Battery Energy Storage Project,” slide presentation, New York Power
Authority, September 29, 2009.
Xcel Energy, “Wind-To-Battery Project,” fact sheet, November 2008.
“Flow” batteries, in which a liquid electrolyte flows through a chemical cell to produce
electricity, are in the early stages of commercialization. In grid applications there has been some
deployment of two types of flow battery: vanadium redox and zinc-bromide. There are a number
of international installations of vanadium redox units, including a 250 kW installation in the
United States to relieve a congested transmission line.91 There are also a number of zinc-bromine
demonstration projects.92 Several other flow battery chemistries have been pursued or are under
development, but are less mature.
In addition to the three battery types discussed above, there are several emerging technologies
based on new battery chemistries which may also have potential in grid applications. Several of
these emerging technologies are being supported by DOE efforts such as ARPA-E and are
discussed briefly in the R&D section of this chapter.
J. Baker, “New Technology and Possible Advances in Energy Storage,” Energy Policy, Vol. 36, 2008, pp. 4368–
EPRI/DOE, 2003. The U.S. unit was installed by Pacificorp in 2004 in Moab, UT.
EPRI/DOE, 2003.
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Description and Performance
The lead-acid battery consists of a lead dioxide positive electrode (cathode), a lead negative
electrode (anode), and an aqueous sulfuric acid electrolyte which carries the charge between the
two. During discharge, each electrode is converted to lead sulfate, consuming sulfuric acid from
the electrolyte. When recharging, the lead sulfate is converted back to sulfuric acid, leaving a
layer of lead dioxide on the cathode and pure lead on the anode. In such conventional “wet”
(flooded) cells, water in the electrolyte is broken down to hydrogen and oxygen during the
charging process. In a vented wet cell design, these gases escape into the atmosphere, requiring
the occasional addition of water to the system. In sealed wet cell designs, the loss of these gases is
prevented and their conversion back to water is possible, reducing maintenance requirements.
However, if the battery is overcharged or charged too quickly, the rate of gas generation can
surpass that of water recombination, which can cause an explosion.
In “valve regulated gel” designs, silica is added to the electrolyte to cause it to gel. In “absorbed
glass mat” designs, the electrolyte is suspended in a fiberglass mat. The latter are sometimes
referred to as “dry” because the fiberglass mat is not completely saturated with acid and there is
no excess liquid. Both designs operate under slight constant pressure. Both also eliminate the risk
of electrolyte leakage and offer improved safety by using valves to regulate internal pressure due
to gas build up, but at significantly higher cost than wet cells described above.93
Lead-acid is currently the lowest-cost battery chemistry on a dollar-per-kWh basis. However, it
also has relatively low specific energy (energy per unit mass) on the order of 35 Wh/kg and
relatively poor “cycle life,” which is the number of charge-discharge cycles it can provide before
its capacity falls too far below a certain percentage (e.g., 80%) of its initial capacity. While the
low energy density of lead-acid will likely limit its use in transportation applications, increase in
cycle life could make lead-acid cost-effective in grid applications.
The cycle life of lead-acid batteries is highly dependent on both the rate and depth of discharge
due to corrosion and material shedding off of electrode plates inside the battery. High depth of
discharge (DoD) operation intensifies both issues. At 100% DoD (discharging the battery
completely) cycle life can be less than 100 full cycles for some lead-acid technologies. During
high rate, partial state-of-charge operation, lead sulfate accumulation on the anode can be the
primary cause of degradation. These processes are also sensitive to high temperature, where the
rule of thumb is to reduce battery life by half for every 8°C (14°F) increase in temperature above
ambient.94 Manufacturers’ warrantees provide some indication of minimum performance
expectations, with service life of three to five years for deep cycle batteries, designed to be mostly
discharged time after time. SLI batteries in cars have expected service lives of five to seven years,
with up to 30 discharges per year depending on the rate of discharge. Temperature also affects
D. Linden and T. Reddy, Handbook of Batteries, 3rd ed., McGraw Hill, New York, 2002.
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capacity, with a battery at -4°C (25°F) having between roughly 70% and 80% of the capacity of a
battery at 24°C (75°F).95
For many applications of lead-acid batteries, including SLI and uninterruptible power supply
(UPS), efficiency of the batteries is relatively unimportant. One estimate for the DC-DC (direct
current) efficiency of utility-scale lead acid battery is 81%, and AC-AC (alternating current)
efficiency of 70%-72%.96
High Temperature Sodium-Beta
Sodium-beta batteries use molten (liquid) sodium for the anode, with sodium ions transporting the
electric charge. The two main types of sodium-beta batteries are distinguished by the type of
cathode they use. The sodium-sulfur (Na-S) type employs a liquid sulfur cathode, while the
sodium-nickel chloride (Na-NiCl2) type employs a solid metal chloride cathode. Both types
include a beta-alumina solid electrolyte material separating the cathode and anode. This ceramic
material offers ionic conductivity similar to that of typical aqueous electrolytes, but only at high
temperature. Consequently, sodium-beta batteries ordinarily must operate at temperatures around
300°C (572°F).97 The impermeability of the solid electrolyte to liquid electrodes and its minimal
electrical conductivity eliminates self discharge and allows high efficiency.98
Technical challenges associated with sodium-beta battery chemistry generally stem from the high
temperature requirements. To maintain a 300°C operating point the battery must have insulation
and active heating. If it is not maintained at such a temperature, the resulting freeze-thaw cycles
and thermal expansion can lead to mechanical stresses, damaging seals and other cell
components, including the electrolyte.99 The fragile nature of the electrolyte is also a concern,
particularly for Na-S cells. In the event of damage to the solid electrolyte, a breach could allow
the two liquid electrodes to mix, possibly causing an explosion and fire.100
Na-S batteries are manufactured commercially for a variety of grid services ranging from shortterm rapid discharge services to long-term energy management services.101 The DC-DC efficiency
is about 85%. Calculation of the AC-AC efficiency is complicated by the need for additional
heating. The standby heat loss for each 50 kW module is between 2.2 and 3.4 kW. As a result of
this heat loss, plus losses in the power conversion equipment, the AC-AC efficiency for loadleveling services is estimated in the range of 75%-80%.102 Expected service life is 15 years at
90% DoD and 4500 cycles.103
EPRI/DOE, 2003.
This estimate is of the Chino 10 MW battery with 96% inverter efficiency. EPRI/DOE, 2003.
X. Lu et al., “Advanced Materials for Sodium-Beta Alumina Batteries: Status, Challenges, and Perspectives,”
Journal of Power Sources, No. 195, 2010, pp. 2431-2442.
D. Linden and T. Reddy, 2002.
X. Lu et. al, 2010.
B. Norris, J. Newmiller, and G. Peek, NAS Battery Demonstration at American Electric Power, SAND2006-6740,
Sandia National Laboratories, 2007. NGK sells a “PS” module rated for continuous discharge for load-leveling
applications and a “PQ” module rated for short discharge applications such as frequency and contingency reserves.
75% from Nourai, 2007 and 80% from A. Nourai, V.I. Kogan, and C.M. Schafer,“Load Leveling Reduces T&D
Line Losses,” IEEE Transactions on Power Delivery, Vol. 23, No. 4, 2008, pp. 2168–2173.
EPRI/DOE, 2003.
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The primary sodium-beta alternative to the Na-S chemistry, the Na-NiCl2 cell (typically called
the ZEBRA cell).104 Although ZEBRA batteries have been under development for over 20 years,
they are only in the early stages of commercialization.105 Nickel chloride cathodes offer several
potential advantages including higher operating voltage, increased operational temperature range
(due in part to the lower melting point of the secondary electrolyte), a slightly less corrosive
cathode, and somewhat safer cell construction, since handling of metallic sodium—which is
potentially explosive—can be avoided.106 They are likely to offer a slightly reduced energy
Liquid Electrolyte Flow Batteries
Flow batteries use liquid electrolytes that are pumped through a “stack” which contains either an
ion-exchange membrane or an electrode array. Energy is stored primarily in active materials
dissolved into electrolytes, which are stored externally and passed through the electrodes during
charge and discharge. The electrodes are separated by an ion exchange membrane to keep the
cathode-side and anode-side electrolytes separate. The advantage of flow battery technology is
that the power component (MW) and the energy component (MWh) can be sized independently,
with the electrolyte materials held in large external storage tanks for multi-MW applications. The
power rating of a flow battery is determined by the size of the battery stack, and the energy rating
by the size of the electrolyte storage tanks.
As stated earlier in this section, the two main types of flow battery in early commercialization are
vanadium redox and zinc-bromine. Vanadium redox batteries are part of a large class of flow
batteries using an ion-exchange membrane similar to that used in fuel cells. (Hence, they are
sometimes called regenerative fuel cells.) In a redox flow battery, the active materials are always
dissolved in the electrolyte. While a number of electrolyte materials have been proposed or are
under development, vanadium has the greatest degree of commercialization, with a number of
installations and active vendors. Other redox flow battery chemistries have yet to be
commercialized but have the potential to provide cost-effective alternatives and are discussed in
the R&D section of this chapter.
The redox flow battery offers several benefits over conventional batteries. First, the amount of
energy storage available is limited only by the size of the tanks and the amount of electrolyte
available. An additional benefit is avoiding the need to correct for differences among individual
battery cells (cell balancing) typical in multi-cell storage configurations using other battery
technologies, which allows for relatively simple construction of higher voltage redox batteries.
Redox flow batteries can also be recharged mechanically by replacing the electrolyte. The
disadvantages generally stem from the complexity of electrolyte pumping and storage; control
system complexity; and relatively low specific energy and energy density (typically less than that
of lead acid cells). The use of an ion-exchange membrane introduces other challenges and
benefits. Leakage across the membrane is possible, causing mixing of the cathode-side and
anode-side electrolytes. In a vanadium redox battery, the impact of leakage is mitigated by the
The name derives from the Zeolite Battery Research Africa Project which invented the technology in 1985.
See, for example, Daimler AG, “The New Mercedes-Benz A-Class E-CELL,” web page, September 15, 2010,; J.L.
Sudworth, “The Sodium/Nickel Chloride (ZEBRA) Battery,” Journal of Power Sources, Vol. 100, 2001, pp. 149-163.
C. Dustmann, “Advances in ZEBRA Batteries,” Journal of Power Sources, Vol. 127, 2004, pp. 85-92.
D. Linden and T. Reddy, 2002.
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fact that both electrolyte materials are identical. However, using alternative chemistries, mixing
can seriously degrade performance. The challenge of cost-effectively manufacturing reliable ionexchange membranes is cited as a primary reason for the limited development of some of the
earliest flow battery chemistries. The claimed calendar lifetime for a vanadium battery stack is at
least 10 years with more than 10,000 cycles.108
The primary alternative to redox flow batteries is a flow battery where at least one of the active
materials is plated onto an electrode. Several chemistries have been investigated, with zinc
bromine being the most well developed. During charging, zinc is plated onto the negative
electrode. When discharging zinc is dissolved into the electrolyte. This configuration benefits
from a low-cost electrolyte and a slightly improved energy density, but problems can arise with
formation of sharp particulates during zinc plating. A 2003 estimate of cycle life is about 2000
cycles or 6000 hours of continuous operations.109 Commercial units have cycle life ratings from
1500 to over 2000 cycles.110
The DC-DC round-trip efficiency for flow batteries is in the range of 70%-80%.111 However, as
with all batteries, DC-AC losses reduce this efficiency further, and flow batteries have additional
parasitic loads of electrolyte pumps. As a result, estimates of AC-AC roundtrip efficiency is in the
range of 65%-72%.
The ability to estimate the capital cost of batteries varies by commercial maturity and application.
Lead acid batteries are the most mature and lowest-cost technology with one 2008 estimate in the
range of $150-$200/kWh.112 To this must be added the costs of a storage installation equipment in
addition to the battery cell itself (balance of plant), which were estimated at $265/kW in 2003;
however, more recent estimates are considerably higher.113 On a cost basis alone, this makes leadacid batteries appear competitive for a wide variety of applications. However, this total cost must
be placed in context of the relatively short cycle life of current lead-acid technology, restricting its
use to applications which require few actual cycles per year.
One 2009 estimate for the cost of NaS battery is about $350-$400/kWh and about $450-$550/kW
for the balance of plant.114 This corresponds to about $2970-$3450/kW for a 7.2 hour device. It is
EPRI/DOE, 2003.
EPRI/DOE, 2003. Data from current vendors indicate longer lives are possible with periodic maintenance. Since
zinc-bromine, like all flow battery technologies are in the early stages of commercialization, additional field trials will
be necessary to establish calendar and cycle life estimates.
P. de Boer, and J. Raadschelders, “Flow Batteries,” white paper prepared for Leanardo ENERGY, June 2007,; G. P. Corey, “An Assessment of the State of the Zinc-Bromine
Battery Development Effort,” RedFlow Limited, Brisbane, Australia, October 2010,
EPRI/DOE, 2003; D. Rastler,“New Demand for Energy Storage,” Electric Perspectives, September/October 2008 Electric Perspectives Article Listing/2008-09-01-EnergyStorage.pdf.
D. Ton, et al. “Solar Energy Grid Integration Systems – Energy Storage (SEGIS-ES),” U.S. Department of Energy
and Sandia National Laboratories, May 2008,
EPRI/DOE, 2003.
D. Rastler, “Overview of Electric Energy Storage Options for the Electric Enterprise,” slide presentation, Electric
Power Research Institute, Palo Alto, CA, 2009,
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unclear whether or not this estimate considers potential deployment at scale. Another estimate
from the first large NaS project in the United States claims that when initial project costs are
removed, NaS would cost about $2500/kW for a 7.2 hour device (Figure 5).115
Figure 5. Cost Components for an Installed NaS System
Source: A. Nourai, 2007.
Notes: PCS=Power Control Station. The factory-to-site shipping costs are considerable: “The total
transportation costs from factory to site, including customs and handling charges plus a few other items shipped
by air, translated to approximately $140/kW.”
Limited cost estimates are available for both vanadium and zinc-bromine batteries. Lack of recent
large-scale installations also makes cost estimates highly uncertain. A 2004 estimate for the cost
of a vanadium flow battery is $236/kWh and $566 for the balance of plant, or about $2450/kW
for an 8-hour device.116 While total costs are not provided, a 2010 estimate for a proposed
vanadium plant provides a cost breakdown of 35% electrolyte, 9% membrane, 17% other stack,
and 5% power control station, with the remaining 34% for engineering, management, and balance
of plant.117
A 2003 estimate118 for Zinc-Bromine is $353/kWh and $576 for the balance of plant, or about
$3400/kW for an eight hour device, while a 2011 manufacturer’s estimate is about $780/kWh for
the entire system, with projected costs of about $400/kWh for a next generation system at “full
production levels.”119 More recent, unpublished estimates place flow battery costs in excess of
$4000/kW for multi-hour devices, while a 2009 EPRI estimate places the projected costs of a
generic flow battery at $1545-$3100/kW for a 4 hour device.120 Manufacturing and deployment at
A. Nourai, 2007.
Electric Power Research Institute and U.S. Department of Energy (EPRI/DOE), EPRI-DOE Handbook Supplement
of Energy Storage for Grid Connected Wind Generation Applications, No. 1008703, December 2004.
. J.F Startari, “Painesville Municipal Power Vanadium Redox Battery Demonstration Project,” slide presentation,
Ashlawn Energy, Painesville, OH, 2010.
EPRI/DOE, 2003.
The manufacturer also projects future costs at “grid scale production” of close to $100/kWh. ZBB 2011 “Investor
D. Rastler, 2009.
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scale will be necessary to establish better estimates of flow battery costs. Deployment at scale
will also be needed to determine longevity as well as operation and maintenance requirements.
Some perspective on the overall cost reduction potential for certain battery types is provided in
one recent analysis of different battery chemistries.121 Figure 7 shows the cost of various
chemical pairs (couple elements) for battery types considered in this chapter. For many types,
such as the NaS battery the cost of raw materials is, theoretically, a trivial component. Most
others have couple element costs of about $10/kWh or less (assuming costs in the study year).
One chemistry that stands out as a potential cost challenge is vanadium, with the couple element
costs close to $100/kWh, primarily due to the high cost of vanadium. Figure 6 also shows goals
for the Department of Energy’s ARPA-E grid storage and electric vehicle (EV) programs. The
ARPA-E goal of $100/kWh appears to include both the power and energy component, including
power conditioning equipment, installation, and other balance of system components. This would
correspond to $800/kW for a device with eight hours of storage capacity, which would require
battery costs of well below $100/kWh considering balance of system is currently a considerable
fraction of $800/kW. The goal for the EV battery pack is discussed in the next chapter.122
Figure 6. Extraction Costs of Elements in Grid Battery Couples
Source: C. Wadia, P. Albertus, and V. Srinivasan, 2011.
Notes: Calculated from U.S. Geological Survey element prices. The EV battery pack goal of $100/kWh includes
only the cost of the battery itself.
C. Wadia, P. Albertus, and V. Srinivasan, “Resource Constraints on the Battery Energy Storage Potential for Grid
and Transportation Applications,” Journal of Power Sources, Vol. 196, 2011, pp. 1593-1598.
U.S. Department of Energy, Grid-Scale Rampable Intermittent Dispatchable Storage (GRIDS), DE-FOA-0000290,
CFDA Number 81.135, poncept paper, April 23, 2010.
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Research and Development
The federal government, industry consortiums, and other groups support R&D efforts across a
range of battery technologies, including a number of emerging battery chemistries that do not fall
under the categories summarized above. The latter include alkaline, sodium ion, and liquid metal
batteries. To illustrate these efforts, Tables 4 and 5 list federal battery R&D activities supported
by ARPA-E and ARRA, according to general battery type and chemistry. Activities associated
with specific battery types are discussed below. Note that these tables include several lithium-ion
and metal-air batteries, both of which are thought of as prime candidates for transportation
applications. (These two battery types are discussed in greater detail in the following chapter.)
However, some forms may be more suitable for grid applications and supported through gridoriented R&D efforts.
In addition to federally supported efforts, there are grid battery technology R&D activities funded
by other groups and among private companies (whose details may be proprietary). For example,
the Stanford University’s Global Climate and Energy Project has awarded grants to outside
researchers for new grid-oriented battery technologies including enhanced electrolyte and solid
oxide flow battery systems.123
Table 4. ARPA-E Supported Activities on Grid Battery Storage in FY2010-2011
Lead Research Organization
Battery Type /Chemistry
Funding ($Millions)
CUNY Energy Institute
Other (Zinc-Manganese Oxide)
Fluidic Energy, Inc.
Metal Air (Zinc Air)
General Atomics
Lawrence Berkeley National Lab
Flow (Hydrogen-Bromine)
Primus Power
Flow (Zinc Chloride-Zinc Chloride)
United Technologies Research Center
Flow (To Be Determined)
Univ. of Southern California
Metal Air (Iron-Air)
Arizona State University
Metal Air (Zinc-Air)
EaglePicher Technologies
Sodium-Beta (Sodium Sulfur)
Envia Systems
Inorganic Specialists, Inc.
Massachusetts Institute of Technology
Other (Liquid Metal)
Source: Sandia National Laboratories, “ARPA-E Awarded Projects in Energy Storage,” web page, 2010,
Mark Shwartz, “GCEP Awards $3.5 million for Energy Storage Research,” Stanford Report, Stanford University,
September 23, 2011.
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Table 5. ARRA Supported Grid Battery Demonstrations
Battery Type /Chemistry
Size (Power/Energy)
Funding ($Millions)
Duke Energy Business Services
24 MW
Primus Power
Flow (Zinc-Chloride)
25 MW (75 MWh)
Southern California Edison Co.
8 MW (4 hrs)
City of Painesville
Flow (Vanadium Redox)
1 MW (6-8 MWh)
Detroit Edison
25 kW (20 units, 50 kWh
East Penn Manufacturing Co.
Lead-Acid (with ultracapacitor)
3 MW (1-4 MWh)
Premium Power Corp.
Flow (Zinc-Bromine)
5-500 kW (6 hrs)
Public Service Company of NM
500kW (2.5MWhr)
Aquion Energy, Inc.
Other (Sodium-Ion)
10-100 kWh
Ktech Corp.
Flow (Iron-Chromium)
250kW (1MWhr)
Seeo, Inc.
25 kWh
Source: Sandia National Laboratories, “ARRA Energy Storage Demonstrations,” October 13, 2010,
The primary disadvantages of lead-acid batteries are their poor energy density and short cycle
life. Marginal gains to specific energy can be achieved by improving the active material and
design of the electrodes, but will always be limited by the chemistry’s relatively low theoretical
boundaries. Cycle life potentially can be increased by adding carbon in various forms to either the
anode or cathode,124 or by replacing the traditional lead acid anode with a carbon anode similar to
that of an asymmetrical electrochemical capacitor.125 Another approach to improve cycle life is
the so called lead acid flow battery, in which lead is dissolved in an aqueous methanesulfonic acid
electrolyte. This system differs from traditional flow batteries by using of just one electrolyte and
the subsequent lack of troublesome electrolyte separators.126 If long deep discharge cycle life is
proven and costs can be kept low, these technologies may be promising for grid-based bulk
electricity storage applications.
There are several R&D efforts associated with sodium-beta batteries. One is to develop a stacked
planar cell design that could cut cell costs in half.127 This departure from the traditional tubular
P.T. Moseley et al., “The Role of Carbon in Valve-Regulated Lead-Acid Battery Technology,” Journal of Power
Sources, Vol. 157, 2006, pp. 3-10; Enos, D., Hund, T., Shane, R. (2010) “Carbon-Enhanced VRLA Batteries.” DOE
Energy Storage Systems Research Program Annual Peer Review.
L.T. Lam and R. Louey, “Development of ultra-battery for hybrid-electric vehicle applications,” J. Power Sources
158: 1140-1148 (2006); P.T. Moseley et al (2006).
Hazza, et. al., “A Novel Flow Battery: A Lead Acid Battery Based on an Electrolyte with Soluble Lead(II). Part I:
Preliminary Studies,” Phys. Chem. Chem. Phys., 2004 (6) 1773-1778.
Pacific Northwest National Laboratory, “EaglePicher Teams with PNNL to Transform Large-Scale Energy
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design has the ability to increase specific energy and power (the latter a limiting factor for the use
of these batteries in many applications), improve packing efficiency, and improve modularity. It
also presents the opportunity to address long term corrosion problems. However, planar designs
face sealing and material selection challenges.128 Other R&D efforts focus on low temperature
sodium based chemistries using new cathodes and/or sodium ion conductors.129 While cost is a
major R&D focus, longevity and reliability still have room for some marginal improvement using
improved cell configurations and designs.
Liquid Electrolyte
Flow battery R&D efforts include improving the performance of commercially available products
and developing new chemistries. For vanadium redox cells, research seeks to decrease the
vanadium required and increase energy density, for example, by up to 70%.130 New redox couples
that increase efficiency, improve specific energy, or utilize more cost effective or less toxic
materials are also the subject of investigation. These chemistries include iron-chromium, zincchloride, hydrogen-halogen, hydrogen-bromine, lead, and others.131 An earlier flow battery type
(sodium-bromide/sodium-polysulfide) reached the initial stages of commercialization, but was
discontinued. It is unclear if development of this chemistry is being pursued.132 Another key
requirement for large-scale deployment will be achieving demonstrated reliability and longevity.
These requirements are complicated by the toxic and corrosive electrolytes, which pose
significant materials challenges for the hydraulic subsystems and ion exchange membrane,
particularly for chemistries other than vanadium in which electrolyte mixing is unacceptable.
Other Emerging Technologies
Slight modifications to the ubiquitous alkaline battery (e.g., Duracell batteries) utilizing a
powdered zinc anode, manganese dioxide cathode, and potassium hydroxide electrolyte, make the
system rechargeable. These batteries are currently plagued by very short and highly DoD
dependent cycle lives (on the order of 10 or fewer cycles at high DoD) with excessive capacity
loss between cycles (approaching 50% between the first and second cycle in some cases).133 Due
Storage,” web page, PNNL-SA-72347.
X. Lu et. al., “Advanced Materials for Sodium-Beta Alumina Batteries: Status, Challenges, and Perspectives,”
Journal of Power Sources, Vol. 195, 2010, pp. 2431-2442.
C-W Park et. al., “Room-Temperature Solid-State Sodium/Sulfur Batteries,” Electrochemical and Solid State
Letters, Vol. 9, No. 3., 2006, pp. A123-A125.
Liyu Li et al., “A New Vanadium Redox Flow Battery Using Mixed Acid Electrolytes,” Presentation to the U.S.
DOE Energy Storage Systems (ESS) Program Review, November 2, 2010.
T.M Anderson and ID. ngersoll, “MetILs: New Ionic Liquids for Flow Batteries,” Presentation to the U.S. DOE
Energy Storage Systems (ESS) Program Review, November 2, 2010,
2010/anderson_snl.pdf. Iron chromium was the first flow battery chemistries explored, but development was limited by
the state of ion exchange membranes.
“Company Pulls Plug on Power Storage Plant in Lowndes County,” Associated Press, December 9, 2003;
EPRI/DOE, 2004; This chemistry, originally trademarked as Regenesys was nearly commercialized with two partially
constructed facilities, including one in the United States They were cancelled when the parent company discontinued
development for “business reasons.”
D. Linden and T. Reddy, 2002.
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to this massive life cycle performance differential between this chemistry and others,
rechargeable alkaline batteries have only a small and declining market share. However,
modifications have been proposed to overcome cycling challenges, with one ARPA-E supported
“high-risk” project.134
Sodium ion batteries function in principle like lithium-ion batteries do—by shuttling positively
charged ions between electrodes. Sodium ion batteries differ from the sodium beta batteries by
the use of non-reactive electrode materials allowing the elimination of the ceramic separator and
enabling room temperature operation.135 The combination of highly available materials with
aqueous electrolyte and low voltage cells has the potential to provide the low cost and high safety
necessary for grid applications, with cost claims competitive with lead-acid, but with cycle life
exceeding 5000 cycles and 100% DoD.136 There are a number of other emerging chemistries in
the early stages of research, including nitrogen-air137 and a liquid metal battery.138
Deployment Challenges
Batteries for utility applications have yet to be deployed at scale, so potential challenges, notably
land use, are not well quantified. One estimate for land use of a lead-acid facility is 77 m2/MW
for a device with 15 minutes of capacity.139 For NaS, an estimate is about 211 m2/MW (with a 7.2
hour storage capacity).140 An estimate for a proposed (and subsequently cancelled) 12 MW, 100120 MWh flow battery is about 850 m2/MW141 with additional land surrounding the facility.142
Availability of raw materials is another major concern for some battery types, especially those
also being considered for large-scale transportation applications. However, this factor appears to
be less critical for most of the battery types being considered for grid applications discussed in
this chapter.143 Figure 7 provides an estimate of the 2010 production and reserves of battery
materials, measured in Terawatt-hours (TWh) of energy storage potential (ESP). For additional
context, the installation of 100 GW of storage, with 10 hours of capacity (equivalent to about
10% of the total installed generation capacity in the United States) would require about 1 TWh of
S. Banerjee et al., “Flow-Assisted Rechargeable Zn-MnO2 Battery,” Poster, U.S. DOE Energy Storage Systems
(ESS) Program Review, November 2, 2010.
Liu, J., “Emerging Technologies for Large-scale Energy Storage: Towards Low Temperature Sodium Batteries,”
Pacific Northwest National Laboratory, 2006. Presentation to the U.S. DOE Energy Storage Systems (ESS) Program
Review, November 2, 2010.
T. Wiley, “Demonstration of a Sodium Ion Battery for Grid Level Applications,” Aquion Energy, Presentation to the
U.S. DOE Energy Storage Systems (ESS) Program Review, November 2, 2010.
F. Delnick, D. Ingersoll, and K. Waldrip, “Nitrogen-Air Battery,” Sandia National Laboratories Presentation to the
U.S. DOE Energy Storage Systems (ESS) Program Review, November 2, 2010.
M. LaMonica, “Liquid Metal Battery Snags Funding from Gates Firm,” CNET News, May 20, 2011.
EPRI/DOE, 2003.
NGK Insulators, Ltd., “Principle of the NAS Battery,” web page, October 10, 2011.
EPR/DOE 2003.
Tennessee Valley Authority, Environmental Assessment: The Regenesys Energy Storage System, August 2001.
C. Wadia, P. Albertus, and V. Srinivasan, 2011.
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storage capacity. While production rates might need to be increased if deployed at large scale, few
of the materials appear to be a major limiting factor, with the exception of vanadium, where
resource limits could present challenges at extremely large scale. Antimony (Sb) is even more
constrained but a high-temperature Mg/Sb battery has not been demonstrated.
Figure 7. Energy Storage Potential (ESP) of Battery Material Reserves
Source: C. Wadia, P. Albertus, and V. Srinivasan, 2011.
Notes: The elements in brackets at the right side of the labels are the limiting elements in each couple. The
asterisk (*) indicates ESP well beyond the limit of the figure. Production is raw material for all uses.
Batteries under consideration use materials with a range of toxicity. Lead, for example, can be
harmful to human health, and, thus, requires appropriate collection and recycling efforts to
minimize potential health impact. For flow batteries, proper containment and mitigation is needed
to address the potential release of materials from large tanks used for multi-MW applications.144
There are a large number of diverse battery chemistries in various stages of development and
commercialization. Several projects have demonstrated competitive or near competitive
economics for power grid applications. The rapid response of batteries makes them well suited
for ancillary service applications such as frequency regulation, although they must demonstrate
long calendar and cycle life, which is a challenge for many available battery technologies.
Batteries will compete with other newly commercialized technologies such as flywheels for shortduration ancillary services. For longer-duration application, reduced capital cost is the primary
requirement. A single battery technology has yet to emerge as a likely market leader for the many
potential applications for grid storage. R&D will likely further improve battery technical
performance and reduce costs for multiple technologies. Engineering and improved
Tennessee Valley Authority, August 2001.
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manufacturing techniques will also reduce costs and increase reliability for many of the battery
types under development.
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Chapter 5: Batteries for Electric Transportation
This chapter discusses battery technologies with the greatest potential for use in electric
transportation. Compared to more grid-oriented storage technologies, batteries for electric
vehicles need to have higher energy density, storing more energy for a given weight or volume,
and therefore can be lighter, offering longer drive ranges. Because some vehicle battery
technologies may also be suited for grid applications, the distinction may not be a rigid one, but it
highlights significant differences in specifications and development that ease the discussion. For
electric vehicle applications, there are four main battery types of interest:
Nickel-based aqueous
Lithium metal
Nickel-cadmium and nickel-metal hydride are the two main nickel-based aqueous (liquid
electrolyte) battery types. Nickel-cadmium batteries have been challenged by the cost and toxicity
of cadmium (they have largely been banned in the European Union), and are not considered a
viable technology for large-scale deployment in vehicles. Nickel-metal hydride (NiMH) batteries
are deployed extensively in current hybrid electric vehicles, such as the Ford Escape and
Chevrolet Malibu hybrid models, and are, therefore, included in this chapter. In these
applications, the battery serves primarily as a power resource for vehicle starting and
acceleration. However, due to low energy density compared to lithium-ion or emerging battery
technologies, current NiMH technology is unlikely to see large-scale deployment for plug-in
hybrid electric vehicles (PHEVs ) or battery electric vehicles (EVs).
Figure 8 shows the growth of hybrid electric (HEV) passenger vehicle sales over the last decade.
Altogether, 1.7 million HEVs were sold in the United States between 2003 and 2010.145 Most of
these vehicles used NiMH batteries; only recently have HEVs and EVs begun to use lithium-ion
Thomas B. Reddy, Editor, Linden’s Handbook of Batteries, Fourth Edition, McGraw-Hill, 2011, p. 29.26; For
classification by manufacturer and other details see Electric Drive Transportation Association, “Hybrid Vehicle Sales
Information,” web page, June 2010.
The first hybrid to transition to lithium-ion was the Mercedes-Benz S-Class sedan using a Johnson Controls-SAFT
(JCS) battery. K. Snyder, X.G. Yanand T.J. Miller, “Hybrid Vehicle Battery Technology—The Transition from NiMH
to Li-Ion,” SAE Technical Paper No. 2009-01-1385, Society of Automotive Engineers, Warrendale, PA (2009).
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Figure 8. United States Hybrid Electric Vehicle Sales
Source: Reddy, 2011.
Lithium-ion (Li-ion) batteries are by far the most popular battery type for portable consumer
electronics, due primarily to their durability, high specific energy, correspondingly light weight,
and reasonably fast-charge/discharge capability.147 Recently, lithium-ion batteries have begun to
enter the automotive market in hybrid and full electric vehicles. Several manufacturers including
SAFT, LG Chem, SK Energy, Hitachi, AESC, A123, Enerdel, and Panasonic have developed
high-power lithium-ion HEV batteries now under various stages of testing and
commercialization. In addition to the ability to store more energy per unit weight, the automotive
market also benefits from this chemistry’s high power, efficiency, and long cycle life capability.148
However, lower costs and enhanced safety are required before Li-ion batteries significantly
impact the transportation sector.149 While the focus of lithium-ion battery development has been
for mobile and transportation applications, they are also being deployed in grid applications.
Examples include an 8 MW Li-ion battery system installed by AES to provide frequency
regulation in New York, and a 2 MW installation in Southern California, with a number of
projects proposed or under development.150
Two other battery technologies (lithium metal and metal-air) currently under development
promise up to a tenfold increase in specific energy. Although these chemistries have demonstrated
basic performance and energy density potential in niche applications, they are still in the R&D
stage for deployment in the transportation sector.
M. Armand and J.M., Tarascon, “Building Better Batteries,” Nature, No. 451, February 7, 2008, pp. 652-657; M.S.
Whittingham, “Lithium Batteries and Cathode Materials,” Chemical Reviews, Vol. 104, No. 10, 2004, pp. 4271-4302.
F. Wagner, B. Lakshmanan, and M. Mathias, “Electrochemistry and the Future of the Automobile,” Journal of
Physical Chemistry Letters, Vol. 1., No. 14, 2010, pp. 2204-2219.
U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, FreedomCAR and Fuel
Partnership: 2009 Highlights of Technical Accomplishments, 2009.
AES Energy Storage, “AES Energy Storage Projects,” web page, 2011.
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Description and Performance
All nickel-based aqueous batteries use a nickel oxyhydroxide cathode and a potassium hydroxide
(KOH) electrolyte. Differentiation among nickel battery chemistries is in the anode. The original
anode material in commercial nickel batteries, cadmium, resulted in a battery with significantly
improved energy density and cycle life over lead acid batteries. However, because cadmium is
toxic, further deployment of nickel-cadmium technology will be limited.
In NiMH cells, a complex metal alloy (comprised of some rare-earth metals, nickel, zirconium,
and aluminum) is used to store hydrogen on the negative electrode. This chemistry has higher
specific energy, cycle life, and high discharge rate capability than nickel-cadmium cells, but
suffers from poor low temperature performance (below 0°C/32°F) and limited shelf-life—as low
as three months.
The use of metallic zinc as an anode increases cell voltage, capacity, and improves high rate
performance. Furthermore, the relative abundance of zinc151 keeps the cost lower than both
nickel-cadmium and NiMH batteries. However, the nickel-zinc battery suffers the same
drawbacks as other systems with a metallic anode. In such a system, metal is deposited back on
the anode during charge, as a highly non-uniform layer, leading to the formation of sharp
particulates (known as dendrites) and swelling of the battery. Large volume changes cause
mechanical stress on other cell elements, leading to degraded performance. Notably, the dendrites
can create internal short circuits and loss of active material, causing irreversible capacity loss.
Iron has also been employed as an anode for nickel-based batteries, but currently, is in limited use
due to problems with the formation of hydrogen gas, leading to pressure build-up within the
Other nickel-based batteries, such as nickel-hydrogen have been demonstrated. A nickel-hydrogen
cell is essentially a hybrid battery-fuel cell, with gaseous, pressurized hydrogen used as the anode
active material. Designed and employed exclusively for aerospace applications, these cells can
provide exceptionally long life along with other benefits, but their extremely high cost essentially
prevents their use in all other applications.153
Lithium-ion (Li-ion) batteries operate by shuttling lithium ions to the anode structure when
charging, then by migrating the same ions across a porous separator via the electrolyte to the
U.S. Geological Survey, Mineral Commodity Summaries 2011, January 2011, p. 189.
D. Linden T. Reddy, 2002.
L. H. Thaller and A.H. Zimmerman, Nickel-Hydrogen Life Cycle Testing: Review and Analysis, Aerospace Press
Series, Aerospace Press, CA, 2003.
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cathode structure during discharge. There are multiple combinations of cathodes, anodes, and
electrolytes commercially classified under the lithium-ion umbrella as discussed below.154
Most Li-ion battery development efforts over the past decade have been focused on cathode
technology. The anodes have generally been composed of common carbon-based materials (e.g.,
graphite, hard carbon, etc.). The anodes also are relatively less expensive components in the cell,
and are not the limiting factor in terms of battery energy. However, improvements in anode
performance may still yield gains, and may affect safety risks from the plating out of metallic
lithium at the anode, especially when a battery is fast-charged at low temperatures.155
Three classes of cathode material prevail today: layered transition-metal oxides (e.g., cobalt oxide
and various mixed oxides such as nickel-cobalt-aluminum oxide, etc.), spinels (e.g., manganese
oxide), and olivines (e.g., iron phosphate).156 The main difference among these classes of
cathodes is in their crystal structures. Each offers various advantages and disadvantages as shown
in Figure 9. The largest drawbacks of the layered oxide cathodes are cost and safety. Cost is
driven up by cobalt and nickel content. Safety concerns are driven by the production of oxygen
under abusive conditions (typically high temperature, high voltage and state of charge, where
reaction with the electrolyte or dissolution may occur). Since the electrolyte is comprised of
flammable organic solvents, when combined with oxygen, such reactions lead to the risk of fire
and explosion. The principal challenges in spinel-based cathodes are lower energy content
compared to layered oxides and a tendency for manganese to dissolve at higher temperatures (>55
C/131 oF), thereby limiting longevity.157 Olivines offer significant improvements in the safety
threshold and stability. However, the maximum voltage that olivine materials can offer is lower
than the other two categories, and the energy content is roughly half of that in layered oxides.
Figure 9. Comparison of the Various Lithium-Ion Battery Chemistries
Source: S. Santhanagopalan, National Renewable Energy Laboratory, 2011.
Note: Scale is based on typical industry targets.
G.-A. Nazri, G. Pistoia, Editors, Lithium Batteries: Science and Technology; Kluwer Academic Publishers, New
York, 2004.
N.A. Chernova, et al., “Layered Vanadium and Molybdenum Oxides: Batteries and Electrochromics,” Journal of
Materials Chemistry. No. 19, 2009, pp. 2526-2552; A.N. Jansen et. al., “Low-temperature Study of Lithium-ion Cells
Using a LiySn Micro-Reference Electrode,” Journal of Power Sources, No. 174, 2007, pp. 373-379.
B.L. Ellis, K.T. Lee, and L.F. Nazar, “Positive Electrode Materials for Li-Ion and Li-Batteries,” Chemistry of
Materials, Vol. 22, 2010, pp. 691-714.
G.-A. Nazri and G. Pistoia, 2004.
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The electrolyte commonly consists of a mixture of organic solvents, such as an ethylene
carbonate/dimethyl carbonate, or propylene carbonate mixtures that contain a dissolved fluoride
based lithium salt. Due to the wide voltage window for lithium-ion batteries (4 volts compared to
2 volts or less for other batteries), the electrolyte is often exposed to working conditions beyond
its stability limits. One way to overcome these stability issues—particularly on the carbon
anodes—is to build a protective layer known as the solid electrolyte interface (SEI) layer. The
SEI layer is typically formed during the first few charge cycles. Tuning the electrolyte
formulation to optimize the SEI layer is an actively pursued means to improve the longevity of
these batteries.
The cycle life of current Li-ion batteries is highly dependent on how deeply the battery is
discharged each cycle. Using data from one published study, a graphite/nickelate Li-ion battery
might last for 3000 cycles at 80% DoD, and 500,000 cycles at 4% DoD.158
Lithium Metal
The operational potential of using lithium metal as the anode could be significant since it offers a
ten-fold increase in energy stored per unit weight. This idea has been successfully implemented in
the non-rechargeable batteries (e.g., Energizer Ultimate Lithium AAA Cells). Extension of these
efforts into rechargeable cells has been met with some success, limited primarily due to the highly
reactive nature of lithium metal. The lithium-sulfur chemistry is among the most successful so far.
The basic lithium-sulfur cell is comprised of a liquid sulfur cathode, generally supported with a
porous carbon framework, a liquid electrolyte, and a lithium metal anode. The working principle
of the lithium sulfur cell closely resembles that of the sodium-sulfur cells (see Chapter 4).159
Lithium sulfur cells offer the potential for extremely high energy density (theoretical energy
content is ~2500 Wh/kg compared to 200 Wh/kg for the lithium-ion cells), due in part to the low
molecular weight of sulfur. The low cost and high availability of sulfur also aid the cost
effectiveness and sustainability of manufacturing these batteries.160 However, because the
electrical conductivity of sulfur is low, it is generally necessary to employ porous carbon
supports, the additional weight of which lowers the energy content per unit weight or volume of
the cell.161 The chemistry also includes a natural mechanism to protect the cell from overcharge
by diverting the current to a shuttle reaction in which sulfur is cycled back-and-forth between two
valence states. However, tuning the shuttle for optimal performance is complex, and limits the life
of the cell to 10 months or less, in some cases. In addition, the multiple intermediate compounds
that are formed during the charge and discharge of the battery make stabilizing the cathode a
difficult task. Often these intermediates are insoluble and block the porous network within the
sulfur cathode.162
J.C. Hall, et al., “Decay Processes and Life Predictions for Lithium Ion Satellite Cells,” Paper AIAA 2006-4078, 4th
International Energy Conversion Engineering Conference and Exhibit, San Diego, CA, Jun. 26-29, 2006.
X. Ji, K. T. Lee, and L.F. Nazar, “A Highly Ordered Nanostructured Carbon-Sulphur Cathode for Lithium-Sulphur
Batteries,” Nature Materials, Vol. 8, No. 6, 2009, pp. 500-506.
Wang et. al., “Sulfur Composite Cathode Materials for Rechargeable Lithium Batteries,” Advanced Functional
Materials, Vol. 13, 2003, pp. 487-492.
X. Ji et. al., 2009.
V.S. Kolosnitsyn and E.V. Karaseva, “Lithium-Sulfur Batteries: Problems and Solutions,” Russian Journal of
Electrochemistry, Vol. 44, No. 5, 2008, 506-509.
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The use of lithium metal as an anode provides extremely high energy, but comes with many
challenges to safety and long-term operation. Lithium metal is deposited (plated) during charge
and dissolved when the battery is used. This plating process results in a significant volume
change, with cycling, on the order of 300% (compared to approximately 10% for graphitic
anodes), inducing mechanical stress on all components of the cell and exacerbating other failure
mechanisms. Furthermore, this process can be highly non-uniform, leading to possible dendrite
formation. As in lithium-ion batteries, the electrolyte employed in lithium-sulfur batteries is also
flammable, leading to potential safety concerns. However, when combined with the sulfur
cathode, the anode surface and newly formed dendrites are coated by protective layers of soluble
polysulfide chains. Finally, metallic lithium is extremely reactive when exposed to water,
presenting safety concerns if the cell container is breached.163
Metal-air batteries have the potential to simultaneously be the highest energy density and lowestcost energy storage solution for many applications. In a metal-air battery, oxygen available from
the atmosphere serves as the cathode, in conjunction with a metallic anode. When the battery is
discharging, oxygen is combined with the metallic anode to create metal oxides; when charging,
these metal oxides are reduced to plate the metal back at the anode. Although several metals have
been considered for such systems—including magnesium, iron, aluminum, zinc, and lithium—
only the latter two have shown any affinity for electrical recharging.164 There is also a variant of
metal-air systems, “metal-water” batteries, in which the air cathode is replaced with water. Many
of the issues are the same as those of metal-air systems, but the voltage is significantly reduced
and applications are generally limited, thus they are omitted from this discussion.
Zinc-air systems have a theoretical specific energy greater than 3 kWh/kg, and thus present an
opportunity to greatly surpass the energy carrying capability of lithium-ion cells. Furthermore,
their use of zinc, a highly abundant and low-cost material, offers improved sustainability and cost
effectiveness. The deployment challenges of zinc-air batteries include poor reversibility and
resultant cycling problems due to metal plating, as well as evaporation of the aqueous electrolyte
(when used in an open system).
Lithium-air (Li-air) batteries, with a theoretical specific energy exceeding 11 kWh/kg (excluding
oxygen), are perhaps the most likely candidate battery to approach the energy density of fossil
fuels. Hence , Li-air technology is of considerable interest to automotive and other mobile
applications. However, after including accessory components, such as the porous carbon support
layers, the realized specific energy is only about 30% of the theoretical value. Even at these
levels, however, Li-air specific energy still surpasses today’s state of the art Li-ion technology
(0.25 kWh/kg) by an order of magnitude. As in the case of Li-ion batteries, the use of metallic
lithium (and organic electrolytes) raises safety concerns for Li-air cells. The large thermodynamic
loss between charge and discharge reactions also raises issues of reversibility.165
Ibid.; G.-A. Nazri and G. Pistoia, 2004.
D. Linden and T. Reddy, 2002.
J. Zhang et. al., “Air Dehydration Membranes for Nonaqueous Lithium-Air Batteries,” Journal of the
Electrochemical Society, Vol. 157, No. 8, 2010, pp. A940-A946.
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DOE estimates for the current generation of Li-ion battery packs for electric vehicles are between
$800 and $1200/kWh, including the battery cell, integration, thermal management, and other
system costs.166 The battery cells alone are believed to account for only 65% of these costs,
leaving a large share of costs in the other pack level systems.167 The cost of the pack relative to
typical vehicle costs is a significant issue, however. For example, the necessary pack size for a
small- to mid-size electric sedan is on the order of 30 kWh, implying a battery cost on the order
of $20,000, which exceeds the total cost of many vehicles in this class. A more detailed
discussion of the per-cycle cost of Li-ion batteries is provided in Chapter 7.
Figure 10 shows the cost levels that batteries would need to achieve for the fuel cost savings over
five years to offset the initial incremental cost according to one study.168 The chart assumes a
baseline grid electricity cost of 9 cents/kWh and fuel costs of $2.15/gallon (low case) and
$4.30/gallon (high case). Energy requirements for various kinds of vehicles are represented by the
power-to energy ratio: plug-in hybrids (PHEVs) with long ranges typically have large energy
requirements, whereas hybrid electric vehicles (HEVs) have more demanding power
requirements. If the fuel prices were at $2.15/gallon, the cost of batteries should follow the curve
labeled “Projected battery costs” relatively closely (at least for shorter ranges) in order to be costneutral; however, for the case of future costs of fuel, the energy storage systems only need to
reach the $500-$700/kWh range, according to this study.
This is the pack, not the cells alone, and includes integration, thermal management and other costs. US DOE (2010)
Batteries for Electric Energy Storage in Transportation (BEEST) DE_FOA-0000207 DFDA Number: 81.135 3/1/2010.
More recent estimates are less than $800/kWh. Kanellos (2011) “Is Sodium the Future Formula for Energy Storage?
Greentech Media.
Boston Consulting Group, “Batteries for Electric Cars: Challenges, Opportunities and the Outlook to 2020,” January
T. Markel and A. Simpson, “Plug-in Hybrid Electric Vehicle Storage System Design,” presentation at the Advanced
Automotive Battery Conference, Baltimore, MD, May 17-19, 2006.
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Figure 10. Battery Cost Requirements for a Five-Year Payback from Fuel Savings
Source: T. Markel and A. Simpson, 2006.
Notes: This figure is for the entire battery pack, including the cells, integration, thermal management, etc. The
number following “PHEV” in the figure indicates the miles that can be traveled solely using electricity ranging
from 3.5 to 40.
The maturity of lithium-sulfur and metal-air battery systems is not yet sufficient to project
expected battery pack costs. Cost challenges associated with raw materials (couple elements) for
the battery technologies discussed in this chapter are illustrated in Figure 11. For several battery
types, including nickel-based batteries and many Li-ion batteries, the couple element costs alone
are a large fraction of $100/kWh, the ARPA-E and DOE cost goals for complete grid and vehicle
storage battery packs, respectively.169
Near-term goals are $500/kWh (2012) and $270-$300/kWh (2014) Longer-term goals EERE and ARPA-E goals are
$100-$150/kWh. D. Howell, “Vehicle Technologies Program,” presentation at the 2011 Annual Merit Review and Peer
Evaluation Meeting, Energy Storage R&D, May 913, 2011,
merit_review_2011/electrochemical_storage/es000_howell_2011_o.pdf; see also U.S. Department of Energy,
“Batteries for Electric Energy Storage in Transportation (BEEST),” DE_FOA-0000207, March 1, 2010.
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Figure 11. Extraction Costs of Elements in Vehicle Battery Couples
Source: C. Wadia, P. Albertus, and V. Srinivasan, 2011.
Notes: Calculated from U.S. Geological Survey element prices. The EV battery pack goal of $100/kWh includes
only the cost of the battery itself.
Research and Development
At present, DOE R&D efforts on vehicle batteries are in two main programs: Batteries for
Advanced Transportation Technologies, which is a fundamental research program focused on new
materials, and Advanced Battery Research, which focuses on scale-up and commercialization of
technologies. For incentivizing deployment at scale, ARRA has provided funding to a number of
manufacturers, detailed in Table 6. The Department of Energy has also awarded grants for
advanced battery R&D under the ARPA-E Batteries for Electrical Energy Storage in
Transportation (BEEST) program, some of which are discussed below. In all, the BEEST program
invested $40 million in non-conventional battery technologies in 2010.170
Private sector R&D efforts in the United States are conducted by the United States Advanced
Battery Consortium (USABC), led by the “big three” U.S. auto makers—Chrysler, Ford, and
General Motors—in cooperation with the DOE. USABC has funded a number of advanced
battery development and technology assessment contracts, in some cases with DOE cofunding.171
Advanced Research Projects Agency-Energy, “Batteries for Electrical Energy Storage in Transportation (BEEST),”
web page, 2011.
United States Council for Automotive Research LLC, “USABC Awards $15.6 Million in Advanced Battery
Technology Contracts to Three Firms,” press release, March 2, 2011.
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Table 6. ARRA Supported Vehicular Battery Demonstrations
Johnson Controls, Inc.
Holland, MI
Lebanon, OR
Production of nickel-cobalt-metal battery cells and
packs, as well as production of battery separators (by
partner Entek) for hybrid and electric vehicles.
A123 Systems, Inc.
Romulus, MI
Brownstown, MI
Manufacturing nano-iron phosphate cathode powder
and electrode coatings; fabrication of battery cells and
modules; and assembly of complete battery pack
systems for hybrid and electric vehicles.
Midland, MI
Production of manganese oxide cathode / graphite
lithium-ion batteries for hybrid and electric vehicles.
Compact Power, Inc.
St. Clair, MI
Pontiac, MI
Holland, MI
Production of lithium-ion polymer battery cells for the
GM Volt using a manganese-based cathode material
and a proprietary separator.
EnerDel, Inc.
Indianapolis, IN
Production of lithium-ion cells and packs for hybrid
and electric vehicles. Primary chemistries include
manganese spinel/lithium titanate for high power
applications; and manganese spinel/amorphous carbon
for high energy applications.
General Motors Corp.
Brownstown, MI
Production of high-volume battery packs for the GM
Volt. Cells will be from LG Chem, Ltd. and other cell
providers to be named
Saft America, Inc.
Jacksonville, FL
Production of lithium-ion cells, modules, and battery
packs for industrial and agricultural vehicles and
defense applications. Primary lithium chemistries
include nickel-cobalt-metal and iron phosphate
Exide Technologies
with Axion Power
Bristol, TN
Columbus, GA
Production of advanced lead-acid batteries, using leadcarbon electrodes for micro and mild hybrid
East Penn
Manufacturing Co.
Lyon Station, PA
Production of the UltraBattery (lead-acid battery with
a carbon supercapacitor combination) for micro and
mild hybrid applications.
Source: Sandia National Laboratories, “Recovery Act Awards for Electric Drive Vehicle Battery and
Component Manufacturing Initiative,” 2010,
Longer-term targets for PHEV energy storage, as envisioned by the Department of Energy’s
FreedomCAR program, are shown in Figure 12. The figure highlights key barriers to achieving
these long-term targets; all current battery chemistries face some or all of these barriers.
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Figure 12. FreedomCAR PHEV Energy Storage Goals
Source: G. Henriksen, “Overview of Applied Battery Research,” presentation to the Department of Energy
Annual Merit Review, Washington, D.C., June 9, 2010,
Further development of nickel-cadmium and nickel-hydrogen batteries is unlikely due to the use
of toxic cadmium and high cost, respectively. R&D topics for NiMH batteries include improving
cold temperature performance, reducing self-discharge rates, increasing power, and extending
cycle life.172 Cost is also an issue, but is difficult to address through R&D since economies of
scale in production have already been achieved, and a large fraction of the cost of NiMH batteries
is due to the cost of nickel. Nickel-zinc batteries offer improvements relative to NiMH, but they
are currently limited by poor cycle life. Overcoming this obstacle requires a solution to the zinc
dissolution and plating problems.
A significant number of research efforts in industry, national laboratories, and academia are
presently devoted to improving cost, safety, energy density, cold temperature performance, and
longevity of Li-ion batteries—a key focus of DOE vehicle technology R&D. Especially for large
format automotive cells, increasing the scale of manufacturing is often cited as a likely pathway
to reduce cost. To this end, $2.4 billion in ARRA funds were awarded in late 2009 to create a U.S.
manufacturing base capable of supporting the annual production of 500,000 electric vehicles by
M.A. Fetcenko, et al., “Recent advances in NiMH battery technology,” Journal of Power Sources, No. 165, 2007,
pp. 544-551.
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2015, resulting in a projected 70% decrease in battery cost.173 A large portion of such scaleinduced cost reductions is based on the commoditization of materials, reported to make up 60%
of current cell costs.174 The active materials alone (anode, cathode, and electrolyte) have been
shown to make up approximately 20% of costs.175 Thus, development of anodes and cathodes
incorporating lower-cost materials (such as iron rather than cobalt) is another route actively being
Safety is the foremost concern for many current and potential Li-ion battery markets, especially
in light of well publicized laptop computer fires and fires following Chevrolet Volt crash tests
involving Li-ion battery technology. Although such events are isolated, they merit concern,
particularly in automotive applications. Electrode coatings currently under investigation can
stabilize the electrode-electrolyte interface, benefiting not only safety but also cell longevity.176
Non-flammable electrolyte systems, still in need of further development, hold similar promise.177
Finally, system level approaches have introduced better thermal management and protective
Low-temperature response, long-term degradation, specific energy, and other aspects of battery
performance also show room for improvement, although in many cases they are already superior
to competing technologies. It should be noted that long-term improvements in cell degradation
and specific energy, achievable with advanced cathodes and anodes, electrode coatings, and other
technical enhancements, also have the potential to reduce the cost of Li-ion cells on a dollars per
kWh basis. Noteworthy are efforts funded by ARPA-E, including three-dimensional electrodes
developed by Applied Materials and all solid-state batteries developed by Planar Energy.178
Lithium titanate has been offered as an alternative to graphite as an anode material. Lithium
titanate anodes may provide high stability by operating at a much higher voltage versus lithium
than carbon anodes do, by greatly reducing the chance of lithium plating, and by eliminating
electrolyte reduction and the need for the SEI layer. This chemistry improves safety, longevity,
and efficiency, but has a significantly lower cell voltage. Combined with a specific capacity
(capacity per unit mass) about half that of graphite, a lithium titanate cell’s energy storage
capability is reduced by as much as 50% compared to the conventional lithium-ion cells.179
Similar concerns arise for other metal-oxide anodes currently under evaluation.180 Using a silicon
anode also is under extensive study, as it offers an extremely high theoretical specific capacity.
U.S. Department of Energy, Fiscal Year 2010 Annual Progress Report for Energy Storage R & D, January 2011.
B. Barnett, et al., “PHEV Battery Cost Assessment,” presentation to the Department of Energy Annual Merit
Review, Washington, D.C., TIAX LLC, 2009.
U.S. Department of Energy, January 2011.
Y.S. Jung, et al., “Enhanced Stability of LiCoO2 Cathodes in Lithium-Ion Batteries Using Surface Modification by
Atomic Layer Deposition,” Journal of the Electrochemical Society 2010, No. 157, pp. A75-A81; Y.S. Jung, et al.,
“Ultrathin Direct Atomic Layer Deposition on Composite Electrodes is Critical for Highly Durable and Safe Li-Ion
Batteries,” Advanced Materials, No. 22, 2010, pp. 2172-2176.
L. Zinck et al., “Purification Process for an Inorganic Rechargeable Lithium Battery and New Safety Concepts,”
Journal of Applied Electrochemistry, Vol. 36, 2006, pp. 1291-1295.
Advanced Research Projects Agency-Energy, 2011.
G.-A. Nazri and G. Pistoia, 2004.
S.-H. Lee, et al., “Reversible Lithium-Ion Insertion in Molybdenum Oxide Nanoparticles,” Advanced Materials, No.
20, 2008, pp. 3627-3632; C. Ban, “Nanostructured Fe3O4/SWNT Electrode: Binder-Free and High-Rate Li-Ion
Anode,” Advanced Energy Materials, No. 22, 2010, pp. E145-E149.
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Volume change in the cell during charge/discharge is the major concern. Such extreme volume
expansion can cause particle fracturing and loss of electronic conductivity, leading to high
irreversible capacity loss and vastly reduced cycle life.181
The promise of practical specific energy that is at least twice that of Li-ion is enticing to longterm PHEV goals. However, much work remains to be done to improve Li-ion specific energy
while addressing capacity decline, self discharge, and safety. There are many ongoing efforts to
address these challenges, such as new cathode structures reliant on different porous carbons,182
and possibly doped or functionalized porous carbons to stabilize the polysulfide products. Surface
coatings for increased sulfur utilization, stability, and conductivity, as well as new electrolytes
formulated for increased conductivity and shuttle control, etc. are also under investigation.183 The
ARPA-E BEEST program awarded $5 million last year to a consortium including Sion Power,
LLC, BASF, Lawrence Berkeley National Laboratory, and Pacific Northwest National Laboratory
to develop lithium-sulfur batteries with a 300 mile range between charges (about three times that
of conventional lithium batteries).
With some minor differences among the different design variants, the core challenges for metalair batteries lie with the obstruction of the active electrode surface, along with other challenges
typical of metallic anodes, such as volume change and loss of uniformity during cycling.
Protecting and stabilizing the anode is of particular importance where lithium is used, as it not
only represents a barrier to long-term performance, but also to safety. Most current R&D efforts
focus on overcoming the energy loss between charge and discharge at the air cathode by
employing suitable catalysts.184 Additional challenges include evaporation of the electrolyte and
contamination when using ambient air. The use of ionic and solid electrolytes has the potential to
address evaporation, but typically degrades efficiency and increases cost. Alternatively,
evaporation and air contamination can be approached at the system level by using closed or
filtered air systems, but such systems bring added cost, complexity, and mass.
Noteworthy funding for metal-air battery R&D includes a $5 million grant under the ARPA-E
program and support from the Oregon Department of Energy’s Small Scale Energy Loan Program
(SELP), to ReVolt Technology, LLC in 2010, that published datasheets demonstrating a few
hundred cycles of charge-and-discharge on their Zinc-air batteries.185
C. K. Chan, et al., “High-performance Lithium Battery Anodes Using Silicon Nanowires,” Nature Nanotechnology,
VCol. 3, 2008, pp. 31-35.
B. L. Ellis, K.T Lee, and L.F Nazar, “Positive Electrode Materials for Li-Ion and Li-Batteries,” Chemistry of
Materials, Vol. 22, 2010, ,pp. 691–714.
Y.-J. Choi, et al., “Effects of Carbon Coating on the Electrochemical Properties of Sulfur Cathode for
Lithium/Sulfur Cell,” Journal of Power Sources, Vol. 184, No. 2, 2008, pp. 548-552; D. Aurbach, et al., “On the
Surface Chemical Aspects of Very High Energy Density, Rechargeable Li–Sulfur Batteries,” Journal of the
Electrochemical Society, Vol. 156. No. 8, 2009, pp. A694-A702.
Y.-C. Lu et. al., “Platinum-Gold Nanoparticles: A Highly Active Bifunctional Electrocatalyst for Rechargeable
Lithium-Air Batteries,” Journal of the American Chemical Society, Vol. 132, No. 35, 2010, pp. 12170-12171.
ReVolt Technology, “ReVolt Technology LLC Selected for $5 Million ARPA-E BEEST Grant Award,” press
release, May 5, 2010.
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Deployment Challenges
The primary deployment challenges of electric vehicle batteries are high initial cost and limited
performance. Achieving large-scale deployment will require batteries with higher energy density
and battery chemistries that use abundant materials. Figure 13 provides the specific energy of a
range of battery types compared to the DOE target for electric vehicle battery packs (200 Wh/kg).
Currently, only three chemical couples can practically meet that goal: one variant of lithium-ion,
one variant of lithium-metal, and one variant of metal-air (the upper right quadrant in Figure 13).
Figure 13. Practical vs. Theoretical Specific Energy for 27 Battery Chemistries
Source: C. Wadia, P. Albertus, and V. Srinivasan, 2011.
Key: 1= Lead-Acid, 2=Ni-Cd, 3-5=Nickel Metal Hydride, 7-16=Li-Ion and Li-Metal, 17=Sodium Nickel Chloride,
18=Sodium Sulfur, 20=Vanadium Redox, 21=Zinc Bromine, 22-25=Other Flow Batteries, 26-27=Metal-air.
Notes: Specific energy is based on the weight of active materials alone. The DOE pack goal for an EV with a 40
kWh battery pack is shown, as well as the approximate theoretical energy required for a couple to have a
chance of meeting the pack goal. Chemistries that have demonstrated very good reversibility (i.e., a long cycle
life) are underlined.
Another potential deployment challenge is the potential scarcity of raw materials. Figure 14
provides an estimate of the 2010 production and reserves of materials for the batteries discussed
in this chapter. The material requirements are measured in TWh, with total annual production (fro
all uses) compared to the potential worldwide needs of 1 million and 100 million 40 kWh battery
packs, and total estimate reserves compared to the need for 1 billion battery packs. This
demonstrates that large-scale deployment of lithium-based batteries will require greatly increased
production rates. Total material availability may also be a challenge for batteries using cobalt.
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Figure 14. Energy Storage Potential (ESP) of Battery Material Reserves
Source: C. Wadia, P. Albertus, and V. Srinivasan, 2011.
Notes: The elements in brackets at the right side of the labels are the limiting elements in each couple.
Production is raw material for all uses
Batteries show potential as an option for electrifying the transportation sector. Reduced battery
cost could produce PHEVs and EVs with life-cycle costs at or below those of conventional fossilfueled vehicles, depending on the future price of gasoline. However, achieving this potential will
require addressing the cost of a few key raw materials, engineering large format batteries to
adequate safety standards, and improving long-term performance. A number of research efforts
currently exist to address the shortcomings of current Li-ion technology, as well as to pursue
advanced battery types that could provide even greater performance.
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Chapter 6: Hydrogen
Hydrogen is a high quality “energy carrier” that can be used to store energy for use in vehicle or
grid applications.186 A hydrogen energy storage system would be composed of several
components, with the specific configuration depending upon the application; it generally consists
of hydrogen production (electrolysis), hydrogen transmission and storage, and hydrogen
conversion to electricity (via fuel cell or combustion process). Hydrogen is typically discussed as
being used in fuel cell systems, which have higher efficiency than conventional combustion
engines, partly compensating for the upstream energy intensity of most hydrogen energy
pathways. Fuel cells convert hydrogen and oxygen into electricity through an electrochemical
process, resulting in water and heat as potentially useful byproducts. Fuel cells have been
described as “open” or “flow” batteries, in which the chemical reactants, typically hydrogen and
oxygen, are fed into the fuel cell continuously rather than being stored within the system like a
battery.187 Though the concept has been understood since 1838, the first significant use of fuel
cells was in the Apollo space program in the 1960s.188
Hydrogen produced from natural gas is used extensively today to refine crude oil and produce
fertilizer, but most of the R&D interest in hydrogen is for use as a sustainable fuel for
transportation applications, such as buses, ground equipment (e.g., forklifts or airport tugs) and
light duty vehicles. Hydrogen fueled vehicles would produce zero emissions at the point of use (if
using fuel cells), with hydrogen being potentially produced from a variety of energy sources,
illustrated in Figure 15. Hydrogen fuel cell electric vehicles (FCEVs) can potentially provide a
cost effective, clean and low-carbon alternative to gasoline in light duty vehicle applications
depending upon the original energy source for the fuel.189 A 2010 study by McKinsey evaluating
the current status of FCEVs concluded that the technology has moved from the demonstration
phase to the commercial deployment phase.190 Most major automotive companies have some
demonstration-scale production FCEVs in operation. Hydrogen fuel cell systems are
commercially viable today in forklifts for warehouses. Demonstration FCEV projects are ongoing
in the United States and elsewhere, with commercial deployment in select areas expected in 2015
Hydrogen is one of a number of gaseous or liquid fuels that can be produced by electricity for later use in a vehicle
or stationary generator. Other chemical fuel pathways (such as ammonia) are possible, but most of the R&D on
electricity based fuels is targeted towards hydrogen, which is the focus of this chapter. Hydrogen may also be produced
from other primary fuels (e.g., natural gas) . Currently, the vast majority of hydrogen is produced by non-electric
sources and processes.
For additional information on fuel cell technology, see EG&G Technical Services, Inc., Fuel Cell Handbook, 7th
Edition, prepared for the U.S. Department of Energy, November 2004.
P. Hoffman, The Forever Fuel: The Story of Hydrogen, Boulder, CO, Westview Press, 1981.
D.L. Greene, et al., Hydrogen Scenario Analysis Summary Report: Analysis of the Transition to Hydrogen Fuel Cell
Vehicles and the Potential Hydrogen Energy Infrastructure Requirements, Oak Ridge National Laboratory,
ORNL/TM-2008/030, March, 2008,; National Academy of
Science, Transitions to Alternative Transportation Technologies—A Focus on Hydrogen, The National Academies
Press 2008.
McKinsey and Company, Inc., A Portfolio of Power-Trains for Europe: A Fact-Based Analysis, 2010.
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for ordinary consumers.191 Projected costs for automotive fuel cell systems, once perceived to be
a major cost barrier, have come down significantly due to R&D activities, with estimates
approaching $50/kW when deployed at scale.192 Significant industry and government stakeholder
support for FCEVs has been realized internationally and in several states including California and
Hawaii.193 There are currently 56 hydrogen refueling stations in the United States, most being test
or demonstration projects, and approximately 300 FCEVs are in use by select household
consumers in California, refueling at some 22 hydrogen stations within the state.194 Major barriers
to large-scale deployment of FCEVs include the durability of fuel cells, sufficient onboard fuel
storage, and the need for new refueling infrastructure.
For grid applications, challenges to hydrogen storage include capital costs and low round-trip
efficiency (well under 50%) compared to other commercially available energy storage
technologies. Fuel cell systems have become commercial in a number of niche markets, and
electrolysis-based storage systems have been demonstrated in multiple countries. Current fuel cell
applications include backup power, remote power, and combined heat and power for buildings, as
well as space and military applications.195 These various markets received approximately 24,000
fuel cell unit shipments in 2009, mostly for small portable applications, including over 1000 fuel
cell forklifts and more than 600 backup power units at telecom sites. Of these shipments, 58 large
grid fuel cell systems represented a total of about 15 MW of electricity production capacity.196
Recent demonstrations storing and testing electrolytic hydrogen include a project at the National
Renewable Energy Laboratory, in partnership with Xcel Energy, testing hydrogen production,
storage, and conversion to grid electricity.197 There are a number of other test projects of various
scales internationally.198 Japan has installed over 3000 small (1 kW) residential systems for
combined heat and power as of 2008.199
For international developments, see International Partnership for Hydrogen and Fuel Cells in the Economy (IPHE),
website, 2011.
S. Satyapal, “Hydrogen and Fuel Cells Technology Update,” presented at the Fuel Cell Seminar & Exposition, San
Antonio, TX, October 19, 2010.
International Partnership for Hydrogen and Fuel Cells in the Economy (IPHE), “2010 Hydrogen and Fuel Cell
Global Commercialization & Development Update,” prepared with support from the U.S. Department of Energy, 2010,; State of California,
“California Hydrogen Highway,” web page, 2011,; Honolulu Clean Cities,
“Hawaii Hydrogen Initiative,” web page, 2011,
California Fuel Cell Partnership, “Progress,” web page, March 2011, A current and
interactive map of alternative fuel stations is maintained by the National Renewable Energy Laboratory (NREL)
through TransAtlas, available online at
Most of these fuel cells are powered by fossil fuels (e.g., natural gas), as opposed to hydrogen. See “Fuel Cell
Today: Industry Review 2010,” Fuel Cell Today, 2010.
S. Curtin and J. Gangi, “The Business Case for Fuel Cells,” Fuel Cells 2000, Washington, DC, September 2010.
The project includes 250 kg of storage, approximately 90 kW of electrolysis capacity, a 60 kW hydrogen-fueled
internal combustion generator, a 5 kW PEM fuel cell and a hydrogen refueling station for vehicles. NREL, “Wind-toHydrogen Project,” web page, 2011.
K. Harrison, et al., “Hydrogen Production: Fundamentals and Case Study Summaries,” National Renewable Energy
Laboratory, NREL/CP-550-47302, presented at the 18th World Hydrogen Energy Conference, Essen, Germany, May
16-21, 2010.
These are fossil-fuel powered polymer electrolyte membrane (PEM) units. I. Staffell, and R.J. Green, “Estimating
Future Prices for Stationary Fuel Cells with Empirically Derived Experience Curves,” International Journal of
Hydrogen Energy, No. 34, 2009, pp. 5617-5628.
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In the longer term, the cost reductions anticipated in producing, storing and delivering hydrogen
on a large scale for automotive and other markets will also reduce the costs of hydrogen for grid
applications. While potentially limited by round-trip efficiency, the economic viability of
hydrogen for grid applications will therefore improve as niche fuel cell markets continue to
expand in the near term, bringing down costs by achieving economies of scale, mass production
and learning-by-doing across the hydrogen infrastructure supply chain.200
Hydrogen can be derived from a variety of sources, using a variety of techniques. Figure 15
illustrates major hydrogen energy pathways in a simplified schematic. Hydrogen production from
electricity by way of electrolysis, is technically feasible. However, lifecycle costs for electrolytic
hydrogen tend to be high compared to most of the other hydrogen pathways shown. These
pathways have been described in detail elsewhere, with the most common and inexpensive
method of producing hydrogen today being steam methane reforming of natural gas, performed at
large scale in petroleum refining and fertilizer production industries.201 Similarly, most grid fuel
cell applications today are fueled with natural gas or biogas directly, or with hydrogen derived
from natural gas or biogas. Electrolysis units are a commercial technology for numerous niche
markets, typically where high purity hydrogen is needed on site and on demand, such as in
metallurgy, electronics and generator cooling in large electricity generating power plants. The
three main components of an electrolytic hydrogen system, electrolysis, storage, and fuel cells,
are discussed in turn below.
D. Greene and S. Das, Bootstrapping a Sustainable North American PEM Fuel Cell Industry: Could a Federal
Acquisition Program Make a Difference? Oak Ridge National Laboratory, ORNL/TM-2008/183, October, 2008.
N. Brinkman et al., Well-to-Wheels Analysis of Advanced Fuel/Vehicle Systems: A North American Study of Energy
Use, Greenhouse Gas Emissions, and Criteria Pollutant Emissions, Argonne National Laboratory, May 2005; M. Ruth,
M. Laffen and T. Timbario, Hydrogen Pathways: Cost, Well-to-Wheels Energy Use, and Emissions for the Current
Technology Status of Seven Hydrogen Production, Delivery, and Distribution Scenarios, National Renewable Energy
Laboratory, NREL/TP-6A1-46612, September, 2009.
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Figure 15. Electrolytic and Other Major Hydrogen Energy Pathways
Source: M. Melaina, National Renewable Energy Laboratory, 2011.
There are two main types of low temperature electrolyzers—alkaline and polymer electrolyte
membrane (PEM)—both of which generally operate in the range of 60-80o C.202 PEM
electrolyzers are a fundamentally similar technology to the PEM fuel cells used in automotive
applications, but are run in reverse by splitting water molecules with electricity to produce
hydrogen and oxygen, rather than combining hydrogen with oxygen to produce electricity and
water. Low temperature alkaline and PEM systems are able to meet varying load or demand, and
ramp up and down in power levels very quickly (providing multiple grid services).
In a PEM electrolyzer, the hydrogen side (cathode) and the oxygen side (anode) are separated by
a solid membrane electrolyte, selectively permeable to hydrogen ions which are transported
across the membrane accompanied by water molecules. Figure 16 illustrates a PEM process.
Water reacts at the catalytic surface of the anode to form oxygen, positively charged hydrogen
ions (protons), and electrons. Oxygen is collected or released to the atmosphere, the electrons
flow through an external circuit, and the hydrogen ions selectively move across the membrane to
the cathode. At the cathode, the positively charged hydrogen ions combine with electrons from
the external circuit to form hydrogen gas.
Polymer electrolyte membrane fuel cells are also called proton exchange membrane fuel cells.
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Figure 16. Schematic Representation of PEM Electrolysis
Source: F. Barbir, “PEM Electrolysis for Production of Hydrogen from Renewable Energy Sources,” Solar Energy,
No. 78, 2005, pp. 661-669.
Alkaline electrolyzer systems are the most established electrolysis technology, with several largescale installations, including one with a reported capacity of 74,000 kg H2/day.203 Alkaline
electrolyzers use an alkaline solution (potassium hydroxide) as the electrolyte. However, whereas
PEM electrolytes transfer hydrogen ions (H+) through a semi-solid polymer membrane, alkaline
electrolysis transfers hydroxide ions (OH-) through a hot liquid electrolyte. The PEM or alkaline
cell stacks are the core technology of an electrolysis system. Other components include a water
supply and circulation system, water-gas separators for hydrogen and oxygen, power supply and
voltage regulator, heat exchangers, hydrogen gas drying, and controls.
Hydrogen Storage
There are three general types of hydrogen storage technology: (1) physical storage, including high
pressure gas tanks and liquid tanks; (2) geologic storage; and (3) material-based storage,
including various types of hydrogen carrier materials.204 The low volumetric energy density of
hydrogen requires very high pressures to store hydrogen in sufficient quantities to provide vehicle
ranges comparable to a conventional vehicles.205 All advanced FCEV designs include physical
National Renewable Energy Laboratory, “Current (2009) State-of-the-Art Hydrogen Production Cost Estimate
Using Water Electrolysis: Independent Review,” NREL/BK-6A1-46676, September 2009.
U.S. Department of Energy, “Hydrogen Storage,” fact sheet, October 2006.
Hydrogen has one of the highest energy contents by weight (more than twice that of natural gas), but one of the
lowest by volume 10.8 MJ/nm3 compared to 35.9 MJ/nm3 for natural gas. U.S. Department of Energy, “Permitting
Hydrogen Motor Fuel Dispensing Facilities,” PNNL-14518, January 12, 2004,
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storage, with either compressed hydrogen tanks (at 5,000 or 10,000 pounds per square inch) or
liquid hydrogen storage. Automakers have demonstrated onboard hydrogen storage in vehicles
with ranges that have approached or exceeded the ~300 mile range typically quoted as desirable
by consumers. For example, a Toyota Highlander FCEV demonstrated a 431 mile range under
real-world driving conditions, with an average fuel economy of 68.3 miles per gallon gasoline
equivalent (mpgge).206 Other FCEVs have had trouble reaching a 300 mile range. In addition to
improving the commercial viability of FCEVs, sufficient onboard storage (and therefore range)
enhances the vehicle-to-grid capability of future FCEVs. As an example, a future FCEV with a
100 kW fuel cell system (most likely hybridized with a small battery), and a range of 350 miles,
could provide 3 kW of electricity—enough for a large home—for more than 30 hours when
starting with a full tank.207
Above-ground tanks with lower pressure gas or liquid can be used to store hydrogen for grid
applications. Geologic hydrogen storage is technically feasible, as demonstrated by the
commercial system maintained to support a 310 mile hydrogen pipeline serving refineries along
the Gulf Coast.208 The three geologic hydrogen storage systems operating today are all in
solution-mined salt caverns.209 Current research activities are attempting to identify additional
opportunities in depleted natural gas reservoirs and aquifers.210 Some of the same formations
considered for compressed air energy storage are also being investigated for bulk hydrogen
Material-based storage methods under development include metal hydrides, chemical hydrides,
high surface area sorbent materials (including carbon structures), and various types of chemical
storage. Laboratory and cost analyses are ongoing to identify the technical and cost potential of
numerous types of material-based hydrogen storage.211
Fuel Cells
Stored hydrogen can be converted into electricity by means of a combustion engine or fuel cell.
The primary focus of government and industry R&D is fuel cells rather than hydrogen
combustion engines. Fuel cells combine hydrogen and oxygen to produce electricity, heat, and
water through a chemical reaction. Hydrogen is today generally derived from hydrocarbon fuels,
such as methane, through a “reforming” process. The grid-oriented fuel cells being actively
H. Lammer, “Eco-Friendly SUV Gets a Hydrogen Mileage Boost,” news feature, National Renewable Energy
Laboratory, November 13, 2009.
Assumes a fuel economy of 65 mpgge, an electrical conversion efficiency of 45%, and a tank capacity of 5.5 kg
Praxair Technology, Inc. “Increase Hydrogen Supply Availability with Cavern Storage,” fact sheet, 2006.
A.S. Lord, “Overview of Geologic Storage of Natural Gas with an Emphasis on Assessing the Feasibility of Storing
Hydrogen,” SAND2009-5878, Sandia National Laboratory, 2009a.
A.S. Lord, “Investigating the Potential for Hydrogen Geostorage within Igneous and Metamorphic Rocks: A Status
Report,” Sandia National Laboratory, 2010; A.S. Lord, P. H. Kobos, et al., “A Life Cycle Cost Analysis Framework for
Geologic Storage of Hydrogen: A Scenario Analysis,” SAND2010-6938, Sandia National Laboratory, October 2010.
U.S. Department of Energy, October 2006.
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developed employ proton exchange membraness (PEMFC), phosphoric acid (PAFC), molten
carbonate (MCFC), solid oxides (SOFC), direct methanol (DMFC), and alkaline (AFC).212 Some
systems run on natural gas or biogas directly (SOFC and MCFC with internal reforming, and
PAFC with external, integrated reforming),213 on hydrogen derived from natural gas or another
source (PEMFC, PAFC or AFC), or directly on methanol (DMFC). The main focus for
automotive fuel cells is the PEMFC. A primary advantage of PEM fuel cells is their ability to run
under variable conditions, including fast-start, on/off cycling, and part-load operation, as well as
the ability to operate at low temperatures.214 Because the focus of PEMFC development is on
mobile applications, demonstrated sizes (about 5-100 kW) are much smaller than for non-PEM
fuel cells designed for grid applications (about 100-1000 kW).215
The performance of each component within a hydrogen storage system must be evaluated
separately. Each component can vary considerably in size and performance depending on the
systems configuration and application. Overall, the expected round trip efficiency of hydrogen
storage systems is estimated in the range of 28%-41% depending upon technology advances in
the near term and the combination of electrolysis, storage, and fuel cell or combustion
Electrolyzer size can range from a few watts to greater than 1 GW depending on design and
application. Stacks can be combined in parallel to increase hydrogen production capacity.
Alkaline systems are traditionally larger, but PEM manufacturers are trying to scale up design to
reach sizes of 1,000 kg H2/day. Low temperature alkaline and PEM electrolysis systems have
conversion efficiencies between 61% and 81% or 65-48 kWh/kg.217 In the longer term,
efficiencies closer to 50-45 kWh/kg could be typical.218 Compression energy for storage might
add about 4 kWh/kg to these values. High temperature electrolyzers, currently under development
and based on solid oxide technology, hold the promise of achieving better that 90% electrical
efficiency.219 PEM electrolyzers have the capability of responding rapidly and operating at part
Fuel Cell Today, The Fuel Cell Today Industry Review 2011, Hertfordshire, UK, September 14, 2011.
For an example of an integrated biogas stationary fuel cell and hydrogen fueling station project, see E. Heydorn,,
“Validation of an Integrated Hydrogen Energy Station,” Air Products and Chemical, Inc., report to the DOE Fuel Cell
Technologies Annual Merit Review, 2010.
L. Venturelli, P. Santangelo, and P. Tartarini, “Fuel Cell Systems and Traditional Technologies. Part II:
Experimental Study on Dynamic Behavior of PEMFC in Stationary Power Generation,” Applied Thermal Engineering,
Vol. 29, No. 17-18, 2009, pp. 3469-3475.
F. Barbir, and S. Yazici, “Status and Development of PEM Fuel Cell Technology, International Journal of Energy
Research, Vol. 32, No. 5, 2008, pp. 369-378; Ballard Power Systems, “CLEARgen,” specification sheet, April 2011,
D. Steward et al., Lifecycle Cost Analysis of Hydrogen Versus Other Technologies for Electrical Energy Storage,
NREL/TP-560-46719, National Renewable Energy Laboratory, November 2009.
Ibid. These values assume the higher heating value (HHV) of hydrogen fuel, a measure of heat released during
combustion. For an example of an electrolyzer see Hydrogenics Corp., “HySTAT-60,” specification sheet, 2011.
D. Steward, et al., 2009.
Based on the higher heating value (HHV) of hydrogen fuel.
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load, so they could potentially act as a variable load for grid services, including operating
reserves.220 However, some units may not be optimized for part load operation, and there are
other issues associated with variable operation that include greater chance for hydrogen crossover
in low load situations and suboptimal temperature operation which may decrease efficiency.221
Durability over the stack lifetime is a performance metric that still needs to be demonstrated more
thoroughly, especially under variable operation.222
Hydrogen Storage
State-of-the-art high pressure automotive hydrogen tank systems have exceeded the 2010 DOE
automotive storage goal for gravimetric density (1.5 kWh/kg) and have approached the 2010 goal
for volumetric density (0.9 kWh/l).223 Ongoing R&D efforts are focused on additional cost
reductions for onboard storage systems. The ability to rely upon geologic storage for hydrogen, as
is done with natural gas today, depends upon a variety of factors, including chemical reactions,
contamination, mobility of hydrogen through the formation, and embrittlement and weakening of
metals (more of an issue for high pressure systems).224 Mined salt caverns appear to have the
most favorable physical and chemical properties for hydrogen storage, as well as relatively low
costs; however, these formations are not ubiquitous across the Unites States as illustrated in
Figure 17. By using underground formations, hydrogen provides the opportunity for extremely
long duration storage that is able to shift energy seasonally, which could be valuable in high
penetration renewable generation scenarios.225
For example, the Proton Onsite HOGEN C30 system has an operating range of 0-100% power. Proton Onsite,
“HOGEN C Series Hydrogen Generation Systems,” specification sheet, 2011.
NREL, “Wind-to-Hydrogen Project,” web page, December 5, 2011,
proj_wind_hydrogen.html; K.W. Harrison et al., The Wind-To-Hydrogen Project: Operational Experience,
Performance Testing, and Systems Integration, NREL/TP-550-44082, National Renewable Energy Laboratory, March
2009; F. Barbir, “PEM Electrolysis for Production of Hydrogen from Renewable Energy Sources,” Solar Energy, Vol.
78, No. 5, 2005, pp. 661-669.
NREL is conducting long-term testing of PEM and alkaline stacks to understand stack performance under both
varying and constant operation. See, for example, NREL, “Wind- to-Hydrogen Project,” December 5, 2011.
U.S. Department of Energy, Hydrogen, Fuel Cells & Infrastructure Technologies Program Multi-Year Research,
Development and Demonstration Plan, April, 2009,
A.S. Lord, 2009a.
D. Steward et al., 2009.
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Figure 17. Location of Salt Deposits Across the United States
Source: A.S. Lord, 2009a.
Fuel Cells
Fuel cell projects run from a few watts to greater than 1 MW. Recent efforts have improved fuel
cell start-reliability, durability, and cost.226 Current electrical efficiency of a PEM fuel cell system
is approximately 47% with the target efficiency of about 58% based upon the lower heating value
(33.3 kWh/kg) of hydrogen.227 The conversion efficiencies of PEM fuel cells are therefore much
higher (2 to 2.5 times) than typical combustion engines. The lifetime for PEM fuel cells in grid
applications is about 20,000 hrs, with a DOE target of 60,000 hours by 2020, and the target for
vehicles is 5,000 hrs with a peak efficiency of 60%.228
Electrolysis is an established process, but increased future demand for electrolyzer units will
result in capital and operating cost reductions due to higher volumes of production and improved
M. Inaba, “Durability of Electrocatalysts in Polymer Electrolyte Fuel Cells,” ECS Transactions, Vol. 25, No. 1,
2009, pp. 573-581; N.E. Takeuchi, et al., “Investigation and Modeling of Carbon Oxidation of Pt/C under Dynamic
Potential Condition,” ECS Transactions, Vol. 25, No. 1, 2009, pp. 1045-1054; G.S. Tasic, et al. “Non-Noble Metal
Catalyst for a Future Pt Free PEMFC,” Electrochemistry Communications, Vol. 11, No. 11, pp. 2097-2100.
D. Steward, et al., 2009.
U.S. Department of Energy, “Distributed/Stationary Fuel Cell Systems,” web page, March 8, 2011,; U.S. Department of Energy, April 2009; D.
Steward et al., 2009.
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designs. One recent estimate places electrolyzer costs at about $830/kW.229 Estimates of costs
when deployed at scale are in the range of $340/kW-$384/kW for low temperature (PEM and
alkaline) electrolyzers. The balance of plant, which includes control systems, power electronics,
and auxiliary systems, might be anywhere from 34% to 86% of the capital cost, depending on
size, application, and design.230 Stack replacement costs (at seven year intervals) are estimated at
about 35% of total purchased costs.231 Maintenance costs for low temperature electrolyzers are
expected to be relatively low—between 1% and 3% of the total installed capital cost per year for
the units.232
Hydrogen Storage
Estimates of future costs of high volume manufactured carbon fiber tanks for onboard vehicular
storage are $13 and $20/kWh for 5,000 and 10,000 psi tanks, respectively. Similar analyses for
future liquid automotive tanks suggest that $8/kWh of storage is achievable.233 Cost estimates for
2500 psi storage for above ground hydrogen tanks for retail fueling stations are near $900 per kg
of usable hydrogen based upon U.S. DOE hydrogen analysis delivery component cost models.234
Costs for storage of hydrogen in salt caverns has been estimated at $5-$24 per kg of usable
hydrogen storage.235 Use of depleted gas reservoirs, if suitable physically and chemically, would
tend to have lower costs.
Fuel Cells
As with other components, hydrogen fuel cells systems are currently not deployed at scale, and
there is significant uncertainty as to the cost reduction potential. Current costs for stationary fuel
cells are estimated at about $3,000/kW for equipment costs (not including installation).236 A large
fraction of this cost is associated with the platinum catalyst, discussed later in this chapter.
Estimates of potential costs after additional R&D and higher deployment volumes are in the range
of $400-$800/kW. As with electrolyzers, the small number of moving parts for fuel cells reduces
ongoing maintenance requirements. The current O&M costs for fuel cells are estimated at about
$50/kW-yr, potentially dropping to $20/kW-yr as the technology becomes more established.237
One of the largest expenses for stationary fuel cells is the cell stack replacement cost, which is
estimated to be about 30% of the initial capital cost after 20,000 hrs of use.238
D. Steward et al., 2009.
National Renewable Energy Laboratory, September 2009.
S. Lasher, “Analyses of Hydrogen Storage Materials and On-Board Systems,” presentation to the Department of
Energy Annual Merit Review, Washington, DC, TIAX LLC, June 7-11, 2010.
U.S Department of Energy, “DOE H2A Delivery Analysis,” web page, Dec 12, 2011,
A.S. Lord, P. Kobos, and D. Borns, A Life Cycle Cost Analysis Framework for Geologic Storage of Hydrogen,
SAND2009-6310, Sandia National Laboratories, 2009b.
D. Steward et al., 2009.
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Research and Development
Research and development activities in the United States are being funded and actively pursued,
in part, by the U.S. Department of Energy’s Fuel Cell Technologies Program. Some of the
technology limitations and research directions can be seen in the program’s Roadmap on
Manufacturing R&D for the Hydrogen Economy,239 in a study by the National Academy of
Engineering,240 and in an independent panel review of low temperature electrolysis sponsored by
the DOE.241
For electrolysis, areas of interest can be characterized into four broad categories: materials,
design improvements, manufacturing, and systems integration/testing.
Materials. Catalyst materials are currently a significant expense for both PEM
and alkaline electrolyzers. New catalyst coatings that would reduce the
requirement for precious metals could reduce costs, while improved membranes
with higher ionic flow and lower resistance would improve efficiency.
Design Improvements. Power conditioning systems that are tuned for specific
applications and operation at higher pressure would reduce costs.
Manufacturing. Advances needed include simplified designs adapted for mass
production, improved stack forming and assembly, low-temperature metal joining
methods, improved in-line quality testing, and improved coating and thin film
deposition methods. Research is also needed to develop low-cost sensors and
other safety equipment and procedures. Some advances in manufacturing for
automotive PEM fuel cell systems may translate to savings for PEM electrolysis
System integration. Improved integration of auxiliary equipment, including
power conditioning, impurity removal, water management, and drying, would
improve the system energy balance and reduce component costs.
Hydrogen Storage
For storage, research is needed to improve the cost and manufacturability of storage for
transportation applications.242 R&D efforts are needed to develop low-cost, high-pressure tanks
whether using conventional materials (where better methods for heat-treating containment vessel
junctions and walls adapted to high volume manufacture are needed) or using advanced
composites where research and engineering is required to develop lightweight tanks
manufacturable at scale. These technologies would be useful for grid applications as well.
U.S. Department of Energy, “Roadmap on Manufacturing R&D for the Hydrogen Economy,” December 2005.
National Academy of Engineering, The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs,
National Academies Press, 2004.
National Renewable Energy Laboratory, September 2009.
U.S. Department of Energy, December 2005.
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Investigation of geologic storage may reveal opportunities for lower-cost and larger-scale
hydrogen storage systems for utility applications.243
Fuel Cells
For fuel cells, many of the R&D needs are similar to those for electrolyzers. Key issues for fuel
cells fall into the categories of materials, design, and manufacturing.244
Materials. R&D needs include membrane research for operation at low relative
humidity and high temperatures with greater durability and lower cost, electrode
catalyst loading with either reduced precious metal requirements or alternative
materials with lower cost and similar performance, bi-polar plates with improved
weight and size, and corrosion resistant coatings for supports, which would
lengthen stack life.
Design. Better power electronics subsystems, as well as air, thermal, and water
management systems can help reduce cost and increase performance.
Manufacturing. Improved manufacturing provides the greatest opportunity for
cost reduction and is key to the deployment of large numbers of fuel cell systems.
High speed and automated manufacturing R&D needs include sealing and
coating methods for electrodes, membranes, and bi-polar plates as well as high
speed component production. Manufacturing issues are especially important to
successful introduction of FCEVs, which would require much greater volumes
than most grid-oriented fuel cell applications. Tied to manufacturing are testing
needs which reduce the time, footprint, and equipment required for testing,
break-in, and acceptance of a system. This includes high speed quality control
and defect detection. Low-cost sensors and safety equipment are needed for all
stages of production and operation.
Deployment Challenges
Hydrogen faces a number of deployment challenges beyond those associated with cost and
efficiency. The most significant is the development of a new fueling infrastructure for hydrogen
vehicles. Hydrogen is currently stored and delivered as a process gas for some industrial uses via
pipelines and steel tank tubes, but the necessary infrastructure for widespread use, especially in
transportation, would require a many-fold expansion of this infrastructure. Small quantities of
hydrogen can be transported by truck, but this method quickly becomes cost-prohibitive at high
volumes. Although hydrogen pipelines exist, they are not widely distributed. Development costs
for an extensive pipeline infrastructure would be high, especially during early market introduction
when demand for hydrogen is low.245 Hydrogen can be blended with natural gas at low volumes
(less than 10%-20%) with little concern for safety or appliance compatibility, and some newer
A.S. Lord, 2009a.
U.S. Department of Energy, April 2009; J. Nie, and Y. Chen, “Numerical Modeling of Three-Dimensional TwoPhase Gas-Liquid Flow in the Flow Field Plate of a PEM Electrolysis Cell,” International Journal of Hydrogen
Energy, Vol. 35, No. 8, 2010, pp. 3183-3197; Tasic et al., 2009.
Hydrogen pipelines differ from natural gas pipelines since hydrogen can cause steel embrittlement and may require
different seals and fittings. J.L. Gillette and R.L Kolpa, Overview of Interstate Hydrogen Pipeline Systems,
ANL/EVS/TM/08-2, Argonne National Laboratory, 2007.
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natural gas pipelines could be converted to hydrogen pipelines if made of the right steels or
plastics.246 Near term developments that do not require extensive hydrogen infrastructure, such as
production onsite at distributed refueling stations, can facilitate the adoption of hydrogen as a
vehicle fuel and energy carrier. Early market applications are particularly important to achieve
manufacturing scale-up and reduce costs.
Safety is a concern, primarily with hydrogen being used as a transportation fuel. Hydrogen’s
physical and chemical characteristics have both safety benefits and drawbacks in its production,
transportation, and use as a fuel.247 Hydrogen’s safety advantages compared to other fuels include
extremely fast dispersal after a leak compared to gasoline, higher flammability limit than gasoline
(4% compared to 1%), lower risk that secondary materials will ignite, and no toxic gases
produced from burning. The primary drawbacks of hydrogen in comparison to other fuels are its
relatively high probability of ignition and the combination of low ignition energy and wide
flammability range, resulting in a higher risk of ignition from leak points in equipment.248
Hydrogen burns with a flame not visible in daylight and has no odor, increasing the concern of
undetected leaks leading to hazardous fire conditions. High pressure hydrogen systems are prone
to leakage due to the physical properties of hydrogen, such as small molecular size, but these
same properties ensure a rapid rate of dispersal noted above—although special precautions must
be taken for indoor, contained systems. Explosive conditions can occur in contained systems at
concentrations in air of approximately 18%, but these concentrations are nearly impossible to
achieve in outdoor systems. Common odorants and flame enhancers poison fuel cells, so
specialized sensors are required for detection; research into alternative odorants is ongoing. As is
the case with natural gas vehicles and tank trucks, hydrogen storage tanks have a low probability
of release in collisions during transportation because of the high impact strength of compressed
gas tubes. Overall, different precautions must be taken to ensure hydrogen achieves the same
level of safety as other fuels.249
Both electrolyzers and fuel cells depend on expensive materials with varying degrees of
availability. The electrolyzer cell stack often includes expensive noble metals for the cathode and
anode where the hydrogen and oxygen are formed. Typically, these include platinum, iridium, and
ruthenium based catalysts, which are needed to work within an acidic, corrosive environment.
The catalyst loading for PEM electrolyzers might be anywhere from 0.4 mg/cm2 to a few mg per
square centimeter with the cell active area for a 1,000 kg/day unit being greater than 2,000 cm2.250
NaturalHy Project, “About NaturalHy,” web page, 2011.
S.E. Plotkin, “Assessment of PNGV Fuels Infrastructure: Infrastructure Concerns Related to the Safety of
Alternative Fuels,” ANL/ESD-TM-160, Argonne National Laboratory, June 2000.
U.S. Department of Energy, “Hydrogen Data,” DOE/GO12008-2597, October 2008.
For additional safety information, see C. Grant, Reaching the U.S. Fire Service with Hydrogen Safety Information: A
Roadmap, Prepared by the Fire Protection Research Foundation for the National Renewable Energy Laboratory, 2009.
L. Ma, et al., “Investigations on High Performance Proton Exchange Membrane Water Electrolyzer.” International
Journal of Hydrogen Energy, Vol. 34, No. 2, 2009, pp. 678-684; P. Millet, et al., “GenHyPEM: A Research Program
on PEM Water Electrolysis Supported by the European Commission, “ International Journal of Hydrogen Energy,
Vol.34 No. 11, 2009, pp. 4974-4982; J. Cheng, et al., “Study of Carbon-Supported IrO2 and RuO2 for Use in the
Hydrogen Evolution Reaction in a Solid Polymer Electrolyte Electrolyzer,” Electrochimica Acta, Vol. 55, No. 5, 2010,
pp. 1855-1861; J.D. Holladay, et al., “An Overview of Hydrogen Production Technologies,” Catalysis Today, Vol. 139,
No. 4, 2009, pp. 244-260; P. Millet, et al., “PEM Water Electrolyzers: From Electrocatalysis to Stack Development,”
International Journal of Hydrogen Energy, Vol. 35, No. 10, May 2010, pp. 5043-5052.
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Alkaline electrolyzers often operate at lower current density which requires even larger cell active
areas, 15,000 cm2 or greater, for 1,000 kg/day hydrogen production. PEM fuel cells typically
require platinum based catalysts and can contribute to more than 50% of the cell stack cost.251
The platinum loading for the PEM fuel cells might be 0.15 mg/cm2 or greater, or 170-214
mg/kW.252 The hydrogen production process requires approximately 3 gallons of water per kg H2
while cooling might require anywhere from 0.1-300 gallons of water per kg H2 depending on the
size of the production plant and the type of cooling system implemented.253
Other potential impacts (such as land use) have yet to be quantified in detail, although are
unlikely to be significantly larger than other storage technologies.
Hydrogen systems are distinct from other storage systems in the ability to serve both grid and
transportation energy markets. However, hydrogen storage and fuel cell technologies face a
number of technical and economic challenges before becoming competitive. Electrolytic
hydrogen systems are currently both more expensive and have lower round-trip efficiencies than
a number of commercially available technologies for grid applications. For transportation, FCEVs
face the challenge of cost, durability and lack of a refueling infrastructure, though infrastructure
developments are proceeding in California, Hawaii, and internationally. Many key hydrogen
technologies, particularly fuel cells, are still in the early stages of commercialization, and will
require substantial cost reductions to achieve large-scale and economical deployment. Progress in
niche markets, such as forklifts for warehouses and small-scale backup power for telecom sites, is
pushing the technology forward and resulting in reduced costs as the volume of units purchased
G.S. Tasic, et al., 2009; S. Zhang, et al., “A Review of Platinum-Based Catalyst Layer Degradation in Proton
Exchange Membrane Fuel Cells,” Journal of Power Sources , Vol. 194, No. 2, 2009, pp. 588-600; S. Lasher, “Direct
Hydrogen PEMFC Manufacturing Cost Estimation for Automotive Applications,” presentation to the Department of
Energy Annual Merit Review, Washington, DC, TIAX LLC, May 17, 2007,
S. Harmin, et al., “Synthesis of Novel Electro-catalysts for Proton Exchange Membrane Fuel Cells,” Separation
Science & Technology, No. 38. p. 2963, 2003; S.A. Grigoriev, et al., “On the Possibility of Replacement of Pt by Pd in
a Hydrogen Electrode of PEM Fuel Cells,” International Journal of Hydrogen Energy, Vol. 32, No. 17, 2007, pp.
4438-4442; B. James, et al., “Mass-Production Cost Estimation for Automotive Fuel Cell Systems,” DOE Hydrogen
and Fuel Cells Program, FY2011 Annual Progress Report, 2010, pp. 609- 613.
For instance, the Hogen C30 would consume 7.1 gal/hr of de-ionized water and require liquid cooling of both fluids
(up to 35 gal/min) and the hydrogen dryer sub system (up to 20 gal/min); Barbir, 2005; National Renewable Energy
Laboratory, September 2009.
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Chapter 7: Compressed Air Energy Storage
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 “diabatic” CAES, stored compressed air is released through a modified
gas turbine, requiring the use of natural gas, making CAES a hybrid storage/generation
technology. CAES is typically considered to have the lowest capital cost of any bulk electricity
storage technology. The first CAES plant was completed in 1978 in Huntorf, Germany. It was
designed primarily to provide “black start” capability (provide a source of power to start
conventional generators after a system-wide power failure), and it was rated at 290 MW with two
hours of capacity.254 A second plant (Figure 18) was built in 1991 in McIntosh, AL, and has a
rating of 110 MW for 26 hours.255
Figure 18. 110 MW CAES Plant in McIntosh, AL
Source: Courtesy of PowerSouth Energy Cooperative, 2006.
CAES can be scaled to several-hundred megawatts or even gigawatts. CAES can provide long
duration storage with independently scalable energy storage capacity and can provide efficient
operation over a broad range of operating conditions. These characteristics make CAES beneficial
on multiple time scales and able to provide many services, including operating reserves and load
F. Crotogino, et al., “Huntorf CAES: More Than 20 Years of Successful Operation,” Solution Mining Research
Institute Spring 2001 Meeting. Orlando, FL, March 22, 2001.
R. Schalge, and B. Mehta, “The Alabama Electric Compressed Air Storage Cavern from Planning to Completion,”
Proceedings of the American Power Conference, Chicago, IL, 1993.
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following, generally mitigating the impact of large-scale ramp events from variable generation
Conventional diabatic CAES is subject to a set of detailed siting criteria associated with its use of
underground geological formations. Without a comprehensive study of the availability of geology
suitable for CAES it would be difficult to assess the extent to which project siting could limit
CAES deployment. Several specific CAES projects are in various stages of development and
developers have indicated interest in exploring the possibility of developing additional ones. The
success of future projects depends on the ability of utilities, developers, and regulators to address
existing deployment barriers. Table 7 provides a list of several proposed CAES plants in the
United States This list is not comprehensive, as there have been at least preliminary analysis and
proposals for other CAES facilities in Texas, Montana, Utah, North Dakota, and Arizona.
Table 7. Proposed CAES Plants in the United States
Cavern Type
Capacity (MW)
McIntosh, Alabama
Salt dome
Dallas Center, Iowa
Norton Energy Storageb
Norton, Ohio
Abandoned hard rock mine
Kern County, California
Porous rock
Seneca (NYSEG/Iberdrola)d
Schuyler County, NY
Bedded salt
McIntosh Power Plant (existing)
Iowa Stored Energy
Source: NREL compilation from:
K. Holst and M .King, “Iowa Stored Energy Park,” presentation to the U.S. Department of Energy, Energy
Storage Systems Program Update Conference 2010, Washington, DC, November 2, 2010; Iowa Stored
Energy Park, “Frequently Asked Questions,” web page, Dec. 14, 2011,
Norton Energy Storage L.L.C., “Application to the Ohio Power Siting Board for a Certificate of
Environmental Compatibility and Public Need,” Summit County, OH, 2000.
H. LaFlash “Compressed Air Energy Storage” slide presentation, Pacific Gas and Electric Company, Nov 3,
J. Rettberg, “Seneca Advanced Compressed Air Energy Storage (CAES) 150MW Plant Using an Existing Salt
Cavern,” slide presentation, November 3, 2010,
The operation of a CAES system mirrors that of a combustion turbine except that compression
and expansion are decoupled in time. Conventional CAES technology (illustrated in Figure 19)
uses grid electricity to run a compressor “train” that raises air to high pressure through several
stages and injects the air into storage, typically an underground geologic formation. The two
existing CAES facilities use salt domes, where the underground cavity was formed by solution
mining—pumping fresh water into the formation to dissolve the salt, and pumping out the
resulting brine for disposal or other use.256 Other formations have been proposed, discussed later
R.L. Thoms, and R.M. Gehle, “A Brief History of Salt Cavern Use,” AGM, Inc., 2000.
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in this chapter. Intercooling is typically used at the compression stage to bring the high-pressure
air back to near-ambient temperatures prior to injection to reduce storage volume requirements
and minimize thermal stress on the geologic formation. Electric power can be regenerated by
withdrawing air from storage, combusting fuel (typically natural gas) and expanding the
combustion products through a turbine (often in two stages).
While conventional diabatic CAES has been the only technology deployed thus far, several other
variants have been proposed. These are often focused on alternative methods for managing the
heat of compression and schemes for reducing the fuel consumption. By storing the heat
generated during compression to reheat the air at a later time or by compressing the air
isothermally, the need to intercool the compressor train and to combust fuel to heat air withdrawn
from storage can be reduced or eliminated.257 In addition, better heat integration and novel
turboexpander design can help eliminate the need for a specialized combustor on the highpressure turboexpansion stage.258 Additionally, storage of air in aboveground vessels for smallscale applications has been investigated as a way to circumvent the subsurface engineering
requirements of siting a CAES facility (especially for small-scale applications).259
Figure 19. CAES System Diagram
Source: S. Succar and R.H. Williams, Compressed Air Energy Storage: Theory, Operation and Applications, Princeton
Environmental Institute, Princeton University, 2008.
C. Bullough, et al., “Advanced Adiabatic Compressed Air Energy Storage for the Integration of Wind Energy,”
Proceedings of the European Wind Energy Conference, EWEC 2004, European Wind Energy Association, London,
UK, November 22-25, 2004.
I. Tuschy, et al., “Evolution of Gas Turbines for Compressed Air Energy Storage,” VGB Powertech, Vol. 85, No. 4,
2004, pp. 84-7.
EPRI/DOE, 2003.
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CAES is a utility-scale technology, with its size determined by the availability of turbo-machinery
equipment and reservoir availability. CAES plants consist of one or more “blocks” of expander
capacity, each in the range of 100-300 MW. Having multiple blocks increases the flexibility of the
plant since each can be run independently. Because diabatic CAES output is managed by
regulating air flow rather than inlet temperature, as in a conventional combustion turbine, CAES
has comparatively high part load efficiencies and ramp rates, potentially enabling a wide range of
grid services such as voltage support, ramping, and frequency regulation. The existing U.S. plant
has a single turbomachinery drive train using a common motor-generator set connected to the
compressor and expander via clutches. This results in turnaround times from compression to
expansion of approximately 30 minutes, limiting its use in providing operating reserves and other
services requiring fast response.
Proposed CAES plants include a dedicated motor drive compressor and expander-generator that
would eliminate the single turbomachinery train.260 This would allow for faster switchover from
compression to generation, thus increasing its usefulness for providing ancillary services and
responding to increased variability of net load. Once operating, CAES plants can provide rapid
ramp rates; the McIntosh plant is capable of ramping at about 18 MW (16% of full output) per
minute, or rates that are more than 50% greater than a typical gas turbine.261 While CAES can
provide a variety of services, including those needed to aid in renewables integration, it is also
well suited to help address transmission constraints in locations with good wind resources. CAES
has been proposed to reduce curtailment due to transmission constraints by co-locating it with
wind generation, allowing for greater utilization of transmission lines.262 As stated earlier in this
report, this application could decrease the amount of new transmission needed to access remote
wind resources, but represents a trade-off between the most cost-effective use of storage, and the
cost of new transmission. In general, it is not optimal to co-locate wind turbines and storage
because doing so decreases the usefulness of the storage device. However, in cases where
transmission is difficult (or impossible) to site, or is very expensive, the loss of opportunities for
storage may be exceeded by its use as an alternative to transmission.263
Norton Energy Storage L.L.C., 2000.
S. Succar and R.H. Williams, 2008.
N. Desai et al., “Study Of Electric Transmission In Conjunction With Energy Storage Technology,” Lower
Colorado River Authority, Texas State Energy Conservation Office, August 21, 2003.
P. Denholm and R. Sioshansi, “The Value of Compressed Air Energy Storage with Wind in TransmissionConstrained Electric Power Systems,” Energy Policy, No. 37, pp. 3149-3158.
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Since CAES is a hybrid system, its efficiency cannot be simply stated as a single number.264 The
performance of CAES is based on two separate quantities: the heat rate and the charging
electricity ratio. The heat rate is the fuel consumption per unit electrical output similar to heat
rates quoted for conventional thermal generation. A typical value for the diabatic CAES heat rate
is approximately 3900-4400 Btu/kWh, although improved turboexpansion cycles and heat
recovery can reduce fuel consumption further.265 The charging electricity ratio (CER) is the ratio
of output electricity to input electricity of the plant, typically in the range of 1.2-1.8, with higher
values for increased pressure ratios across the turboexpander train and greater numbers of
compression stages. The fact that the charging ratio is greater than one means that CAES
produces more electricity than it consumes, with the balance made up by the consumption of
natural gas. As a result, the production of 1 kWh from a CAES plant requires the input of about
0.6 to 0.8 kWh of electricity and 3900-4400 Btu of natural gas fuel. The CER also takes into
account piping and throttling losses (a function the reservoir pressure range) as well as
compressor and expander efficiencies. Turbine efficiency is especially important in the lowpressure expansion stage where approximately three quarters of the power is generated.266
Increased turbine inlet temperatures (e.g., by using expander blade cooling technologies) would
enhance the turbine and CAES electrical efficiencies.267 Unlike almost all other storage
technologies, there is virtually no decay or self-discharge of stored energy, at least when deployed
in salt domes, since these formations are self-healing, meaning pores on the cavity walls seal
themselves with available air moisture, virtually eliminating the possibility of air leakage.
Figure 20 provides a method to compare the impact of the heat rate and CER of CAES with
conventional storage plant efficiency (such as in a battery or pumped hydro plant). It provides the
dispatch price, or fuel related costs (both natural gas and electricity) for generation of electricity
from both a CAES plant and a conventional storage plant with different natural gas prices and
efficiencies. Ignoring O&M costs, the dispatch price of CAES is the sum of the cost of electricity
for compression, plus natural gas, while for a conventional storage plant it is just the cost of
charging electricity, considering storage losses. At very low off-peak electricity prices,
conventional storage has an advantage over CAES due to the fixed natural gas cost, while at
higher off-peak prices, CAES has an advantage due to the need for less electricity purchases. It
should be noted that this chart does not consider the capital cost of the device, where CAES has
additional advantages over many other storage technologies.
Expressing the efficiency of CAES as a single number is more of an academic exercise than useful for estimating its
economic performance. There are many ways of calculating a single efficiency number with a large range of values.
Since a single value for efficiency is often “insisted on,” the CAES community typically expresses the round trip
efficiency of CAES in the range of 70%-85%. This value is based on assigning an electrical equivalency to the natural
gas input, assuming it would have otherwise be used in a natural gas turbine with an efficiency in the range of 30%40%. Lower net efficiency values, often below 50% are cited by those who combine the input energy of natural gas and
electricity equally, ignoring the relative quality of energy inputs. Because the thermal energy in the fuel input is subject
to some conversion efficiency that is independent of the roundtrip storage efficiency of CAES, it is not appropriate to
sum the electricity and fuel inputs in the denominator when calculating the plant efficiency. This issue is discussed at
length in S. Succar and R.H. Williams, Compressed Air Energy Storage: Theory, Operation and Applications,
Princeton Environmental Institute, 2008. Detailed thermodynamic analysis of CAES plants is provided by P. Zaugg,
“Energy Flow Diagrams For Diabatic Air-Storage Plants,” Brown Boveri Review, Vol. 72, No. 4, 1985, pp. 179-183.
Btu=British thermal units.
D.R. Hounslow, et al., “The Development of a Ccombustion System for a 110 MW CAES Plant,” Journal of
Engineering for Gas Turbines and Power-Transactions of the ASME, Vol. 120, No. 4, 1998, pp. 875-883.
I. Tuschy, et al., “Compressed Air Energy Storage with High Efficiency and Power Output,” VDI Berichte, No.
1734, 2002, pp. 57-66.
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Figure 20. Comparison of CAES Dispatch Cost to Conventional Storage
Storage Dispatch Price ($/MWh)
Conventional Storage (65% eff.)
Conventional Storage (80% eff.)
Electricity Purchase Price ($/MWh)
Source: P. Denholm, National Renewable Energy Laboratory.268
The lifetime of CAES is similar to that of a combustion turbine. While operation and maintenance
is required to replace turbine blades, well materials, and other components, the existing systems
at Huntorf and McIntosh continue to operate after 20 to 30 years with very high running and
starting availabilities (over 95%).269 The impact of rapid ramping and multiple daily starts might
increase operation and maintenance costs, but the conventional CAES is a proven technology
with a well-established operational record.
Given that no CAES facilities have been constructed since 1991, it is difficult to accurately
estimate the current capital cost of the technology. Recent estimates for the capital cost of
conventional diabatic CAES (Figure 21) range from $600 to $1200/kW with a mean range of
$880 to $1020/kW.270
The dispatch cost of conventional storage (pumped hydro, batteries etc.) is the electricity purchase price divided by
the efficiency. The dispatch cost of CAES is the electricity purchase price multiplied by the energy ratio plus the cost
of natural gas multiplied by the heat rate. In this figure the energy ratio of CAES is assumed to be 0.7 and a heat rate of
4000 BTU/kWh.
G. Lucas and H. Miller, “Dresser-Rand SmartCAES Technology,” Integrating Wind-Solar-CAES, 2nd Compressed
Air Energy Storage (CAES) Conference & Workshop, Columbia University, New York, NY, October 20, 2010.
The cost estimates provided are for large-scale CAES systems (100-300 MW). Smaller, distributed CAES systems
(10-20 MW) using aboveground storage vessels will be a factor of 2 to 3 higher in total overnight capital cost and
roughly two orders of magnitude higher in terms of the capital cost for incremental storage capacity.
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Figure 21. Capital Cost Estimates for Conventional Diabatic CAES
Overnight Construction Cost ($/kW)
EPRI, 2008 Iowa, 2007 PG&E 2009
Consulting Consulting
Firm 1,
Firm 2,
Source: S. Succar, Natural Resources Defense Council. Compiled from references in Table 7 and other
published and unpublished sources.
Total capital cost for CAES can be disaggregated into surface turbomachinery costs and
subsurface costs with the latter projected to account for approximately 5%-10% of total project
capital cost depending on the type of geology chosen.
Table 8. Component Costs of a Conventional CAES System
Deployed in a Salt Cavern
Fraction of Total
Heat exchanger
High pressure expander
Low pressure expander
Construction, labor, indirect costs
Cavern development
Source: R.B. Schainker, and A. Rao, Compressed Air Energy Storage (CAES) Scoping Study for California, CEC-5002008-069, Electric Power Research Institute for California Energy Commission, 2008.
To gauge the potential for future cost reduction associated with CAES turbomachinery, it is
common to use the natural gas combustion turbine (CT) as a reference or lower bound. CT capital
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costs of $650-$690/kW imply a CAES-equivalent cost lower bound of $220-$230/kW.271 While it
is unlikely that CAES surface turbomachinery will reach these costs in the near term, it does
suggest high levels of deployment could drive substantial capital costs reductions.
Typical numbers for variable and fixed O&M for CAES are $60/kW-year and $13/kW-year
respectively.272 Low duty cycle operation with high frequency switching between compression
and expansion modes of operation could considerably increase the variable O&M and the
levelized replacement costs for critical components of the turboexpander train.
Research and Development
Conventional CAES is considered a fairly mature technology, based on well proven gas-turbine
technology and with two plants operating for over two decades. There are four general areas of
RD&D activities, listed below, with the first two being near-term activities, and the second two
being more research oriented.
More Optimized CAES Equipment
Previous CAES plants used components that were not optimized for the unique characteristics of
the CAES expansion cycle. This is partially due to the small market for which developing
dedicated equipment would not be worthwhile. A large CAES market could drive development of
custom turbo-machinery, improving the efficiency of CAES components. While the existing
plants in Huntorf and McIntosh are based largely on legacy steam and gas turbine technology, it is
likely that future system designs will benefit from improved heat integration, more specialized
surface turbomachinery, better systems integration and newer cycles that take advantage of the
technology’s unique operating characteristics. CAES output is changed by adjusting the air flow
(taking advantage of the compressed air from storage) rather than by adjusting the inlet
temperature as in a conventional gas turbine. This contributes to the overall low heat rate and
high part load efficiency of CAES, but also allows for more specialized cycles to be employed to
take advantage of these characteristics.273 One such example of a new design could provide
improved heat recovery and elimination of specialized combustors.274
Near-term cost reductions can be realized by using CAES designs that rely to a greater extent on
off-the-shelf technology.275 Several variations of this approach have been explored recently as
CT costs are from U.S. Energy Information Administration, Annual Energy Outlook 2010, DOE/EIA-0383(2010),
2010. Because CTs divert 2/3 of their turboexpander output to power the compressor, construction cost expressed as
dollars per net output capacity reflects only one third of the CT turbine’s capacity. By comparison, because power from
the grid powers the CAES compressor, the full output of the turboexpander is reflected in its construction cost. This
means that a factor of 1/3 should be applied to the cost of the CT in order to make an equivalent comparison with
CAES capital costs
EPRI/DOE, 2003.
It should be noted that the heat rate of a CAES plant is much lower than a simple-cycle CT combustion turbines
(8,600-10,700 Btu/kWh), and has better part load efficiency. It is more appropriate to compare a CAES plant to a CT,
since it is more likely to provide load-following, peaking, and ancillary services. While combined cycle systems have
much lower heat rates (6,300-7,200 Btu/kWh), they are somewhat less suited to perform these services.
Tuschy, I., et al., Compressed air energy storage with high efficiency and power output. VDI Berichte, 2002(1734):
p. 57-66.
Nakhamkin, M., “Second Generation of the CAES Technology,” Center for Life Cycle Analysis Compressed Air
Energy Storage Scoping Workshop, Columbia University, October 21, 2008.
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exemplified by plans for the 150 MW CAES plant proposed by the New York State Electric &
Gas Corporation.276 By integrating a stand-alone CT into the CAES configuration, capital costs
can be significantly reduced (estimated by the company to be roughly half the cost of a
conventional diabatic CAES system). However, these near-term cost improvements might be
offset somewhat by a higher heat rate and/or reduced CER, diminished operational flexibility or
reduced potential for further cost reduction as discussed above.
Demonstrate CAES in New Underground Formations
The only deployment of CAES to date has been in salt domes, which are only available in a small
fraction of the United States.277 A frequently cited barrier to CAES deployment is the perceived
difficulty of finding geology suitable, but available data is insufficient to accurately determine
whether this is the case. Although CAES can theoretically use a wide variety of geologic
formations, current utility-scale experience is limited. Demonstration of CAES at commercial
scale over a broad range of geologies could significantly accelerate deployment in the near term.
The development of commercial CAES projects in saline aquifers, depleted gas wells, abandoned
mines, compensated hard rock caverns and salt beds would reduce perceived project development
risk of CAES and aid its adoption in the marketplace. Utilities to date have been unwilling to
develop CAES under this uncertainty. Projects now being supported by ARRA and state agencies
will demonstrate CAES in the major geology types, including bedded salt in New York, an
aquifer in Iowa, and a depleted gas field in California (Table 7).
Reduce or Eliminate Fuel Use
There are two pathways being pursued to reduce use of fuel in CAES systems. The first is
adiabatic CAES, where the heat of compression is stored for later use in the expansion cycle.278
Relatively little work has been performed on adiabatic CAES in the United States beyond
engineering studies. This approach is currently being pursued primarily in Europe, with at least
one proposed plant,279 driven in part by concerns about CO2 emissions and natural gas supply
security concerns, especially since adiabatic cycles are unlikely to be cost effective without high
natural gas prices.280 A CAES plant that does not burn natural gas can use efficiency as the
primary performance metric (similar to other bulk energy storage technologies), with estimates of
New York State Energy Research and Development Authority, “Compressed Air Energy Storage Engineering and
Economic Study,” Final Report 10-09, prepared by New York State Electric and Gas, December 2009; J. Rettberg,
Domal salt is limited to a few gulf coast states. Bedded salt is available in a few more states, but the dominant
source of underground caverns for future deployment would need to be porous rock. See S. Succar and R.H. Williams
2008 for a map of the United States showing the areas of suitability for potential CAES development.
G. Grazzini and A. Milazzo, “Thermodynamic Analysis of CAES/TES Systems for Renewable Energy Plants,”
Renewable Energy, No. 33, 2008, pp. 1998–2006; E. Macchi and G. Lozza, “A Study of Thermodynamic Performance
of CAES Plants, Including Unsteady Effects,” TP 87-GT-23, International Gas Turbine Conference and Exhibition.,
Anaheim, CA, May 31, American Society of Mechanical Engineers, 1987.
RWE Power AG, “ADELE—Adiabatic Compressed-Air Energy Storage for Electricity Supply,” January 2010.
R.W. Reilly and D.R. Brown, “Comparative Economic Analysis of Several CAES Design Studies,” Proceedings of
the Intersociety Energy Conversion Engineering Conference, Atlanta, GA, American Society of Mechanical Engineers,
January 1, 1981, pp. 989-994.
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round-trip efficiency in the range of 65%-75%.281 An alternative fuel-free approach is isothermal
CAES, which requires maintaining a constant temperature. Two R&D proposals are being
supported by DOE efforts, however, few details are available on this technology.282 283 In general,
isothermal CAES requires maintaining highly efficient, responsive isothermal cycles with rapid
heat transfer over a broad temperature range and it is still too early to gauge the merits of this
approach. It is also unclear how this approach will affect part load efficiency or ramp rate
capabilities, and the ability to serve multiple grid support functions.
Other Novel Approaches
There are several novel approaches to CAES cycles with limited active R&D efforts. One
proposed configuration is aboveground CAES with air storage in high pressure piping.284
Aboveground CAES has been proposed as an alternative air storage option for distributed
(<10MW) short duration (< 3 hour) storage applications. While the capital cost of incremental
storage capacity additions are significantly larger for such systems (~$200/kWh for aboveground
CAES versus $2/kWh for salt dome storage), small, modular CAES systems without geologic
siting constraints could be attractive for distributed, high-value applications.
Another approach for expanding the siting availability for CAES is to expand air storage into
subsea environments. Underwater CAES concepts typically employ an anchored containment bag
and exploit the buoyancy of air and the subsea pressure gradient to store high pressure air
Deployment Challenges
CAES offers many potential advantages: low capital cost, high efficiency, fast ramping capability,
adaptability to many types of geologic storage, low fuel consumption, and a well-established
operational record. Nevertheless, the deployment of CAES has been extremely slow and the past
three decades have resulted in only a handful of utility-scale projects and test facilities. While in
part this can be attributed to market conditions and regulatory barriers that have impacted the
energy storage industry as a whole, there are technology-specific barriers as well.
A major barrier is the need to prove CAES operation in geologic formations other than domal
salt. However, even after the demonstrations in individual locations mentioned previously, this
does not demonstrate the universal applicability of CAES in porous rock.
The Electric Power Research Institute and others have shown that large fractions of the
continental US have geology suitable for CAES, but these estimates only reflect the existence of
salt, sandstone, and hard rock.285 They do not take into account detailed geologic characteristics
EPRI/DOE 2003, S. Succar & R.H. Williams 2008.
General Compression, Inc “Fuel-Free, Ubiquitous, Compressed Air Energy Storage and Power Conditioning,” fact
sheet, 2010, .
D. Kepshire, “Isothermal Compressed Air Energy Storage,” U.S. Department of Energy 2010 Energy Storage
Systems Research Program Update Conference, Washington D.C., 2010,
EPRI/DOE, 2003.
K. Allen, “CAES: The Underground Portion,” IEEE Transactions on Power Apparatus and Systems, PAS-104, No.
4, 1985, pp. 809-12.
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necessary to deem a site suitable for air storage and therefore do not provide a comprehensive
analysis of deployment potential. While there is ample geology available for near-term
deployment, an accurate determination of the total availability of geologic air storage will require
extensive additional data. Site testing and characterization is certainly not a trivial matter;
numerous screening criteria and extensive testing are required to determine a formation’s
adequacy for air storage. An extensive survey of CAES geologies including aquifer permeability,
porosity, and cap rock characteristics is needed to accurately make the assessment on the
deployment limits of CAES.
There are a number of other challenges associated with the underground formation and use. The
development of solution mined caverns in domal or bedded salt requires water, and subsequent
disposal of brine. Water use for solution mining is likely to be about 8 cubic meters of water for
each cubic meter of salt excavated286 or about 4.8 million cubic meters of fresh water withdrawals
and brine management per 220-MW plant. Disposal of brine has been raised as a concern for
some locations. Additional challenges related to the introduction of air into an underground
geologic formation (e.g., oxidation and additional corrosion mechanisms) have been identified287
and likewise cyclic loading of formations could result in greater material degradation than
conventional natural gas storage operation288 but it is not yet clear the extent to which these could
limit CAES deployment potential. With regard to permitting the subsurface component, although
it will depend on the type of geology and formation characteristics, air storage is similar in most
respects to a conventional natural gas storage facility that have been routinely sited for many
Other deployment challenges associated with CAES are similar to other gas-fired power plants in
terms of land,290 water,291 or other environmental impacts.292 CAES requires little in the way of
unique materials or labor requirements, and the above ground portion can be developed rapidly—
the equipment required for CAES is very similar to conventional gas turbines, and the historical
installation of gas turbines has often exceeded 8 GW per year.293
American Gas Association, Survey of Underground Gas Storage Facilities in the United States and Canada,
Washington, DC, 2004.
T. Smith, “Opportunities for Subsurface Compressed Air Energy Storage in New York State,” Compressed Air
Energy Storage (CAES) Scoping Workshop, Columbia University, October 21–22, 2008.
Electric Power Research. Institute, Compressed-Air Energy Storage: Pittsfield Aquifer Field Test, Palo Alto, CA,
1990, p. 336.
S.J Bauer and T.W. Pfeifle, “Potential Risks Associated with Underground CAES,” Integrating Wind-Solar-CAES,
2nd Compressed Air Energy Storage (CAES) Conference & Workshop, Columbia University, 2010.
Federal Energy Regulatory Commission, Current State of and Issues Concerning Underground Natural Gas
Storage, Federal Energy Regulatory Commission, 2004.
The land area estimate for one proposed CAES facility is about 140 m2/MW. Norton Energy Storage L.L.C., 2000.
Cooling water is required during operation of the compressors, with one estimate of 2.5 million-3.0 million gallons
per day for a 2700 MW facility. Assuming a 25% capacity factor (5913 GWh annual generation), this corresponds to
about 0.2 gallons/kWh. See Ohio Power Siting Board, In the Matter of the Application of Norton Energy Storage, LLC
for a Certificate of Environmental Compatibility and Public Need for an Electric Power Generating Facility in Norton,
Ohio, Case No. 99-1626-EL-BGN, 2001.
B.R Mehta, “Siting Compressed-Air Energy Storage Plants,” Proceedings of the American Power Conference,
Chicago, IL, Illinois Institute of Technology, 1990.
U.S. Department of Energy, Electricity Generating Capacity: Existing Electric Generating Units in the United
States, 2008, online table, 2011.
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CAES is a commercially available electricity storage technology with arguably the lowest cost for
large-scale deployment. Its deployment is not limited by raw materials, calendar or cycle life, and
can provide multiple services to the grid. The operational characteristics and benefits of CAES
suggest that it could be a valuable addition to the generation mix and an important source of
flexibility as the penetration of variable generation increases. The primary barrier to deployment
is demonstration in widely available underground formations, including bedded salt, aquifers, and
depleted gas wells. Perhaps the most important near-term R&D effort for CAES, in addition to
demonstration in different formations, is a national screening to assess the regional and total
potential for new development. While the available data suggests that CAES deployment could
reach or exceed tens of gigawatts, additional analysis must be done to refine understanding of the
geologic limits to CAES deployment. Additional R&D will be useful to identify alternative
CAES configurations that reduce fuel use, improve performance, and use more standardized
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Chapter 8: Electrochemical Capacitors
Electrochemical capacitors (ECs), including “supercapacitors” and “ultracapacitors,” are devices
that store energy in an electric field at the surface of an electrode.294 Unlike traditional
electrostatic capacitors, ECs use an electrolyte to shuttle ions between two working electrodes in
a manner similar to batteries. Capacitors have among the fastest response time of any electricity
storage device, and they are typically used in power-quality applications such as providing
transient voltage stability. However, their low energy capacity has restricted their use to short
time-duration applications with pulses lasting less than 40 seconds.
ECs are most commonly used in computer memory backup systems to bridge brief power
interruptions. However, a target application of ECs is to act as an energy storage system for
hybrid electric vehicles (HEVs) with low to moderate electric power requirements.295 Compared
to batteries, ECs have excellent cycle life and are well suited for cycling-intense applications such
as use in transit buses and trains. A major research goal is to increase their energy density and
thereby increase their usefulness in the grid and potentially in vehicle applications.296 Capacitors
have yet to see significant deployment in utility-scale or transportation applications, but there
have been demonstration programs for both activities.297
Traditional electrostatic capacitors store energy in an electric field between two electrodes. These
devices are used extensively in consumer electronics, but their low energy density makes them
unsuitable in utility or transportation applications. ECs differ from traditional capacitors in that
they store energy in an “electric double-layer” that builds up at the surface of an electrode where
it is wetted by an electrolyte. Similar to batteries, the electrolyte shuttles charged ions back and
forth between two electrodes. Unlike batteries, capacitance at the electric double-layer serves as
the primary energy storage mechanism of ECs. In contrast, batteries rely on a “faradaic” process
for energy storage, meaning that the physical state of the electrode changes during
charge/discharge, often limiting battery cycle life. Figure 22 compares the various types of
capacitors with batteries.
There is some ambiguity within the industry regarding the name for capacitors with massive storage capability due
to the many product names among manufacturers and the relative newness of the technology. “Electrochemical
capacitors” is used herein as a generic term for this group of technologies See EPRI/DOE, 2003.
J. Furukawa, T. Mangahara,, and L.T. Lam, “Development of the UltraBattery for Micro- and Medium-HEV
Applications,” Proceedings of the 214th Electrochemical Society Meeting, Honolulu, HI, October 12-17, 2008; J.
Gonder, “Recent Analysis of UCAPs in Mild Hybrids,” Presentation to the 6th Advanced Automotive Battery
Conference, Baltimore, MD, May 17-19, 2006,
I. Hadjipaschalis, A Poullikkas, and V. Efthimiou, “Overview of Current and Future Energy Storage Technologies
for Electric Power Applications,” Renewable and Sustainable Energy Reviews, No. 13, 2009, pp. 1513–1522.
Examples include a 450 kW capacitor demonstration project for wind power smoothing at a water treatment plant in
Palmdale CA, and a demonstration of the “UltraBattery”
demonstration supported by ARRA.
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Figure 22. Comparison of Various Capacitor and Battery Topologies
Source: K. Smith, National Renewable Energy Laboratory, 2011.
There are two general classes of ECs. The first is the electric double-layer capacitor which stores
energy in the double-layer formed near the electrode surface. This type of capacitor includes the
“supercapacitor” first introduced by NEC in 1978 and initially used to provide backup power for
computer and appliance memory devices.298 Although the energy is stored as charge like in a
capacitor, special electrodes separated by an electrolyte are employed, similar to a battery. There
are three types of electrode materials suitable for ECs—activated carbons with high surface area,
conducting metal oxides, and conducting polymers. The high-surface-area carbon electrode
material is the most common and least costly to manufacture. The electrolyte may be aqueous or
The second type of EC more closely resembles a hybrid between a capacitor and battery. The
capacitor-like electrode stores charge in the electric double-layer, while the battery-like electrode
uses a faradaic mechanism. By employing some of the characteristics of batteries, they can
greatly increase the energy density. These devices are referred to as “asymmetric” or “pseudo”
capacitors and are currently under development.
ECs are capable of responding within a fraction of a second and are able to charge and discharge
at high rates. As a result, they have a power density of ~5-10 kW/kg, much higher than most
battery technologies which are typically less than 0.5 kW/kg.299 However, EC energy density of
1-10 Wh/kg is at least 10 times lower than most battery types being considered for transportation
applications.300 As a result of these characteristics, a proposed application of capacitors is to place
EPRI/DOE, 2003.
J. Miller, and A. Burke, “Electrochemical Capacitors: Challenges and Opportunities for Real-world Applications,”
ECS Interface, Spring 2008.
EPRI/DOE, 2003.
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them in parallel with battery terminals and provide a current boost during periods of high
demand, such as during vehicle acceleration. It is unclear though, whether the benefits of a
parallel battery/EC system outweigh the additional cost of ECs; EV storage costs are
predominantly driven by the useable energy requirement which dictates the size of the battery.
Capacitors are designed to provide tens of thousands of charge/discharge cycles with limited or
no performance degradation, with long lifetimes (on the order of 10 years) under continuous
operation.301 Accepted levels of performance degradation for ECs are 100% resistance growth and
20% to 30% capacity loss over 10 years and 500k cycles.
Unlike batteries, where voltage in the usable range is fairly constant, the voltage of an EC ranges
from full voltage to zero volts. This can require additional electronics to boost EC power to the
working voltage required, which makes control challenging. Provisions must be made to limit the
current when charging a depleted EC. While a rapid discharge rate does not decrease the lifetime
of an EC, research efforts are underway to extend EC discharge time. At present, EC rapid
discharge rates are ideal for pulse power applications.
ECs perform well in cold environments, maintaining functionality down to -40oC. By
comparison, lithium-ion batteries do not operate well below -10oC. ECs can charge and discharge
with high turnaround efficiency—in excess of 95%.302 Compared to batteries, this means that
minimal thermal management is required, resulting in a simpler system overall. ECs are well
suited to high-reliability applications in extreme environments which require frequent
charge/discharge cycles with short bursts on the order of 10 seconds.
Commercial ECs have specific energies around 5 Wh/kg. Li-ion batteries, by comparison, have
some 20 times more energy at 70-200 Wh/kg,303 with perhaps one-fifth the power. Even in power
applications, energy requirements commonly determine the size of the energy storage device. An
example is a 50 kW uninterruptable power supply that must supply power for 2 minutes. The 50
kW power requirement would seem to indicate that just 10 kg of ECs are necessary. The 2 minute
energy requirement, however, means that some 1700 Wh of energy storage is needed, or 340 kg
of ECs. A Li-ion battery system is more likely to be power-constrained in this application,
requiring 100-200 kg of batteries.
Figure 23 compares the energy and power density of ECs with various battery technologies. As
demonstrated by the previous example, the inherent power-to-energy ratio of ECs dictates that
they are best suited for short bursts of power from 0.1 to 40 second duration. By comparison, Liion batteries are best suited for charge/discharge operation ranging from 5 seconds to tens of
EPRI/DOE, 2003.
DC-DC rating.
J. Miller and A. Burke, 2008.
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Figure 23. Comparison of Energy Storage Technologies
Source: V. Srinivasan “Batteries for Vehicular Applications—Present Status and Challenges,” slide presentation,
Lawrence Berkeley National Laboratory, April 22, 2009.
Since 2000, the energy density of ECs has increased 250% and cost has fallen by 50%.304 Costs of
traditional symmetric ultracapacitors are as low as $10/kW and $17/Wh according to one
manufacturer.305 Allowing for 50% power degradation and 30% energy degradation over a 10
year, 500k cycle life, this manufacturer’s usable power and energy costs are $20/kW and $24/Wh.
These costs compare well with values listed in Table 9.
Table 9. Performance and Costs of Electrochemical Capacitors
Charge time
1 second
Discharge time
1 second
Cycle life
Specific Energy (Wh/kg)
Specific Power (kW/kg)
Cycle efficiency (%)
<75% to >95%
Cost per unit energy ($/Wh)
Cost per unit power ($/kW)
Source: J. Miller and A. Burke, 2008.
M. Bolton, “Energy Storage Systems for Severe Duty Truck Applications,” Presentation to the 5th International
Symposium, Large EC Capacitor Technology and Application, Long Beach, CA, June 8-10, 2009.
M. Leiber (Ioxus, Inc). “Falling Costs Heighten Appeal of Ultracapacitors,” Automotive Engineering International,
Jan. 11, 2011.
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On a power basis, Table 9 indicates that ECs are cheaper than Li-ion batteries. But as mentioned
in the previous example, ECs often must be sized on an energy-basis. On an energy-basis, today’s
ECs initially do not appear to be cost competitive with Li-ion batteries, although this changes
when considering applications requiring frequent cycling. Commercial ECs can tolerate 500,000
full depth-of-discharge (DoD) cycles. The cycle life of Li-ion batteries is highly dependent on
how deeply the battery is discharged each cycle. For example, a graphite/nickelate Li-ion battery
might last for 3,000 cycles at 80% DoD, and 500,000 cycles at 4% DoD.306
As a general rule, for applications with frequent cycling, ECs are cheaper than Li-ion batteries.
Figure 24 compares the cost of ECs and Li-ion batteries per unit energy throughput (calculated as
device energy-specific cost divided by expected cycle-life times DoD). For Li-ion batteries, the
expected cycle-life is dependent on DoD. For ECs, the cycle-life is assumed to be 500,000 cycles,
independent of DoD. EC life is assumed to be 10 years. As the figure shows, ECs are the cheaper
alternative to Li-ion batteries only for cycling-intense applications requiring 100 or more cycles
per day. This conclusion is, of course, highly dependent on cost and life assumptions for the two
Figure 24. Comparison of Cost per Energy Throughput for Li-Ion Batteries and ECs
Source: K. Smith, National Renewable Energy Laboratory, 2011.
Note: The figure uses two different logarithmic relationships from J.C. Hall et al. fit to data over a range of
cycling duties.
Research and Development
Current EC research primarily targets reducing material and device cost and increasing energy
density without sacrificing power and life. Specific areas of research and development include:
J.C. Hall, et al., “Decay Processes and Life Predictions for Lithium Ion Satellite Cells,” Paper No. AIAA 20064078, 4th International Energy Conversion Engineering Conference and Exhibit, San Diego, CA, June 26-29, 2006.
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Reducing component and finished electrode material manufacturing costs,
Increasing the capacitance of electrodes by increasing surface area and tailoring
the pore size and shape,
Finding electrolytes capable of voltages beyond 2.7V, preferably with less
toxicity, and
Optimizing asymmetric ECs, with potential to increase energy density to 8 times
that of standard ECs.307
Advanced Carbons
Carbon remains the preferred material for EC electrodes as it is non-reactive in most electrolytes.
Carbon can be derived from a variety of materials and its structure is tunable during
manufacturing, allowing the designer to control surface area, pore size and pore volume.308 While
the cost of raw carbon may be low, highly purified finished carbon is generally expensive.
However, carbon electrodes have the potential to cost less in the future. Nanotube and graphene
structures are also under investigation as possible EC electrode materials.
Increasing Capacitance
The capacitive effect, responsible for storing energy, occurs at the electrode/electrolyte interface.
Finished carbons have tailored pore shapes and sizes, creating high specific surface area with a
large working capacitance. Typical surface areas are 1000-2000 square meters per gram of
material. For a fixed amount of surface area, two effects contribute to EC double layer
capacitance, (1) the space charge layer and (2) the Helmholtz layer.309 A suitable space charge
layer requires electrode wall structures with a thickness greater than about 1 nm. In order for
charged ions to build up at the Helmholtz layer, electrode pores must be large enough for the ion
to fit. Until recently, it was thought that pore sizes needed to be greater than 2 nm to
accommodate the charged ion as well as its accompanying electrolyte solvent sheath. However, it
was recently discovered that smaller pores might also be accessible, with greatly increased
The impact is that far greater capacitance may be available from tailored electrodes than
previously thought possible. Better physical understanding of capacitive behavior is expected to
lead to new materials with greater energy density.311
An overview of EC research is provided in: Interface, Electrochemical Society, Vol 17, No. 1, Spring 2008.
R. Brodd, “Overview of Electrochemical Capacitors,” Presentation to the 27th International Battery Seminar and
Exhibit. Mar. 16-18, 2010.
H.J. Gerischer, “An Interpretation of the Double Layer Capacity of Graphite Electrodes in Relation to the Density of
States at the Fermi Level,” Journal of Physical Chemistry, No. 89, 1985, p. 4249.
J. Chmiola, et al., “Anomalous Increase in Carbon Capacitance at Pore Sizes Less Than 1 Nanometer,” Science, No.
313, 2006, p. 1760.
J.S. Huang, B.G. Sumpter, and V. Meunier, “Theoretical Model for Nanoporous Carbon
Supercapacitors,”Angewandte Chemie, International Edition, Vol. 47, No. 3, 2008, pp. 520-524.
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High Voltage/Alternative Electrolytes
Greater energy density is possible by raising the working voltage of the EC; however,
conventional electrolytes break down at voltage which is too high. Common electrolytes include
acetonitrile and propylene carbonate—each permit high operating voltages up to 2.7V. Electrodes
may also be a limiting factor at high voltages as electrode shrinking and swelling occurs with
cycling, inducing stress that limits cycle life,312 similar to battery electrodes. The calendar life of
EC devices is presently limited by electrolyte degradation which gradually builds up pressure
inside the EC case. EC life beyond 10 years is uncertain, though possible, as long as the device
does not accumulate too much time at high voltages and/or temperatures.
Asymmetric Designs for Increased Energy
Asymmetric designs replace the positive electrode in carbon-carbon ECs with a faradaic, batterytype electrode such as NiOOH, MnOOH, PbO2, and Li4Ti5O12. Introducing a high-capacity
electrode reduces mass and volume and allows for a flatter operating voltage. Energy density may
increase by eight times.313 Replacing a capacitive electrode with a faradaic one, however,
introduces material volume expansion and contraction issues, accompanied by mechanical stress
and electrode fracture that can limit cycle life. Nonetheless, there is sufficient middle ground
between traditional battery performance with power-to-energy ratio of ~5 hr-1 and EC
performance with power-to-energy ratio of ~1000 hr-1 to warrant further research and
optimization of these hybrid devices. A number of promising configurations and electrochemical
couples are under investigation.314
Deployment Challenges
ECs have deployment challenges similar to several battery types. As with batteries, capacitors
present potentially lethal voltage levels. For utility (grid) applications, this presents very little
incremental risk, but presents challenges for transportation applications. Aqueous electrolytes
may contain hazardous materials including potassium hydroxide and methyl cyanide.
Furthermore, certain electrolytes are flammable, such as acetonitrile, which releases hydrogen
cyanide when burned.315 316 This may provide limited risk in grid applications, where there is
lower risk of release, and the expectation is that installation and maintenance would be performed
by trained personnel only. As with batteries, ECs must be properly disposed or recycled at end-oflife.
The majority of materials in current ECs include common materials such as carbon, nickel, steel,
aluminum, and a variety of plastics. Advanced asymmetric ECs would use several materials used
R. Kötz, et al., “In-situ Monitoring of EDLCs Operation by Physio-Chemical Techniques,” Presentation to the 5th
International Symposium, Large EC Capacitor Technology and Application, Long Beach, CA, June 8-10, 2009.
R. Brodd, “An Overview of Electrochemical Capacitors,” Presentation to the 27th International Battery Seminar and
Exhibition, Ft Lauderdale, Fl, March 16-18, 2010.
K. Naoi and P. Simon, “New Materials and New Configurations for Advanced Electrochemical Capacitors,”
Interface, Electrochemical Society, Vol 17, No. 1, Spring 2008.
EPRI/DOE, 2003.
K. Rechenberg and M. Meinert, “Requirements on DLC Energy Storage Units for Rolling Stock,” Presentation to
the 5th International Symposium, Large EC Capacitor Technology and Application, Long Beach, CA, June 8-10, 2009.
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in advanced batteries, such as lithium and vanadium. It is difficult to estimate the total material
requirements, but they would unlikely be greater than those for batteries, and this requirement
must be placed in the context that the target applications for capacitors are those with limited
actual energy capacity.
In the near term, EC systems are likely limited to power-related (rapid discharge) applications for
both grid and transportation applications. Currently, ECs have high power density, and are costcompetitive for certain applications where discharge time is measured in seconds. The low energy
density and high cost per unit of energy stored makes ECs currently uncompetitive for energy
applications where discharge times of minutes or more are required. Energy density will need to
increase by at least an order of magnitude for capacitors to compete against batteries for
electricity storage applications in transportation. ECs are already well suited for niche
applications such as trains and buses, requiring high power, low temperatures, and/or high cyclelife. These early markets continue to decrease EC manufacturing costs.
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Chapter 9: Pumped Hydro Storage
Pumped hydro storage (PHS) stores energy by pumping water from a lower-level reservoir (e.g., a
lake or river) to a higher-elevation reservoir via an underground tunnel.317 During periods of high
electricity demand, the water is released to the lower reservoir to turn turbines to generate
electricity, similar to the way in which conventional hydropower plants generate electricity. Many
existing PHS plants store eight hours or more of energy, making them useful for load leveling,
and providing firm capacity. PHS can also ramp rapidly, making it useful for load following and
providing ancillary services including contingency spinning reserves and frequency regulation.318
Pumped hydro is the only electricity storage technology deployed on a gigawatt scale worldwide.
In the United States, about 22 GW is deployed at 39 sites,319 while global capacity is over 127
GW.320 U.S. capacity was largely built during the 1970s and 1980s largely in response to market
conditions in the 1970s as discussed in Chapter 2. Figure 25 illustrates the capacity of PHS in the
United States There has been no large-scale PHS development in the United States since 1995,321
although development has continued in Europe and Asia.322 Lack of continued development of
PHS projects domestically has been attributed to a number of factors, including the availability of
low-cost natural gas along with increasing regulatory, environmental, and siting challenges.323
There are several names and acronyms for pumped storage. They include pumped-storage hydro (PSH) pumped
hydro storage (PHS), hydro-pumped storage (HPS) and pumped hydro energy storage (PHES).
J. Phillips, “Pumped Storage in a Deregulated Environment,” International Journal on Hydropower & Dams, Vol.
7, No. 1, 2000, pp. 32-35.
Estimates for the total PHS installed capacity in the United States ranges from 20-22 GW, partially due to different
plant ratings. For example, the EIA lists the total nameplate capacity of PHS as of 2010 at 20.5 GW, while the summer
capacity is listed at 22.2 GW. U.S. Department of Energy, “Existing Generating Unit in the United States by State and
Energy Source, 2010,” online database, 2011.
E.A. Ingram, “Worldwide Pumped Storage Activity,” Hydro Review Worldwide, Vol. 18, No. 4, September 2010.
There is one small (40 MW) PHS facility which began operating in 2011. San Diego County Water Authority,
“Lake Hodges Project Begins Pumped Storage and Power Generation Operations,” press release, September 14, 2011.
J.P. Deane, B.P. Ó Gallachóir, and E.J McKeogh, “Techno-Economic Review of Existing and New Pumped Hydro
Energy Storage Plant,” Renewable and Sustainable Energy Reviews, Vol. 14, No. 4, May 2010, pp. 1293-1302.
P. Denholm, E. Ela, B. Kirby, and M. Milligan, The Role of Energy Storage with Renewable Electricity Generation,
NREL/TP-6A2-47187, National Renewable Energy Laboratory, Golden, CO, 2010.
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Figure 25. Capacity of PHS in United States, 1956–2003
Source: Derived from U.S. Department of Energy, “Existing Generating Units in the United States by State and
Energy Source, 2010,” online database, 2011.
Although domestic PHS capacity has been relatively static for the last 15 years, developers are
showing a renewed interest in building PHS projects in the United States. As of December 2011,
the Federal Energy Regulatory Commission (FERC), which regulates PHS projects, issued
preliminary permits for 45 new plants, representing about 35 GW of capacity.324 The capacity of
proposed plants (including those with issued and pending preliminary permits) exceeds 40 GW.
Figure 26 is a map of existing PHS sites as well as those with a FERC preliminary permit.
Federal Energy Regulatory Commission (FERC), “All Issued Preliminary Permits,” internet database, December
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Figure 26. Existing and Proposed PHS Facilities in the United States
Source: D. Heimiller, National Renewable Energy Laboratory.
PHS consists of two reservoirs connected by an underground shaft and a powerhouse containing
turbines and electrical equipment. PHS relies on either reversible pump-turbine motor-generator
units or on separate motor/pumps and turbine/generators. Reversible units operate as a motor and
pump in the “pumping” mode, and as a turbine and generator in the “generating” mode. The great
majority of U.S. plants have multiple reversible pump-turbines. Figure 27 shows a representative
configuration of a PHS plant.
Figure 27. Pumped-Storage Hydropower Plant Configuration
Source: Tennessee Valley Authority, “The Mountaintop Marvel,” web page, 2011.
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The total amount of energy stored in a PHS facility is the product of the volume of the upper
reservoir and the “head” or difference in height between the upper and lower reservoir. Siting
PHS requires suitable topographical relief. PHS facilities are typically large and located in fairly
remote locations. PHS plants often make use of an existing river or lake, avoiding the need for—
and cost of—construction of a separate (usually lower) reservoir. This is called an “open cycle”
PHS plant. In instances where a suitable natural water body is not available for use as one of the
reservoirs, both the upper reservoir and the lower reservoir must be constructed. This type of
construction is known as a “closed-cycle” plant, because it has minimal interaction with natural
water bodies. A water source is needed for a closed-cycle plant to provide water to initially fill the
reservoir and to compensate for losses during operation due to leakage and evaporation. Nearby
rivers or streams are typical sources; treated municipality grey water or groundwater (wells) can
also be used. Of the 40 plants with preliminary permits at least 9 have proposed closed-cycle PHS
plants, exceeding 9 GW of capacity.325
Existing PHS installations in the United States range in capacity from less than 50 MW to 2,800
MW with typical energy capacities in the range of 8-15 hours of full discharge.326 Most PHS
plants can ramp rapidly while generating and are often used for ancillary services. Some modern
PHS plants can also rapidly change the rate of pumping. The greatest limitation in older PHS
plants is the time required to switch between pumping and generation which can be up to 30
The round-trip efficiency of a PHS plant depends largely on the type of pump/turbine system and
the head. PHS plants use and generate AC electricity, avoiding the conversion losses (and costly
power electronics) associated with technologies that store or generate DC electricity—such as
batteries. Typical AC-AC efficiencies for U.S. plants are in the range of 65%-80%.327 There has
been a trend toward increased efficiencies. Proposed PHS plants have expected efficiencies
exceeding 80%. Figure 28 illustrates the efficiency tend for U.S. facilities. Transmission
requirements and associated losses may slightly reduce the effective efficiency of PHS.328 There
is little loss of performance due to age or throughput. Plants are upgraded through efficiency
improvements and life extension on a project-by-project basis, and most U.S. projects have been
modernized through runner (turbine) replacements, generator rewinds, control system upgrades,
and other improvements.329 For example, the New York Power Authority upgraded its BelenheimGilboa plant to increase its operating range from 203-260 MW to 140-290 MW.330 Lifetimes of
FERC, 2011.
U.S. Department of Energy, “Existing Generating Units in the United States by State and Energy Source, 2010,”
online database, 2011.
Task Committee on Pumped Storage of the Hydropower Committee of the Energy Division of the American Society
of Civil Engineers (ASCE), Compendium of Pumped Storage Plants in the United States, American Society of Civil
Engineers, New York, NY, 1993.
P. Denholm, and G.L. Kulcinski, ”Life-Cycle Energy Requirements and Greenhouse Gas Emissions from LargeScale Energy Storage Systems,” Energy Conversion and Management, No. 45, 2004, pp. 2153-2172.
A. Ferreira “Sixteen Years Operating and Maintenance Experience of the 1080 MW Northfield Mountain Pumped
Storage Plant” and B.E. Sadden “Maintenance of Pumped Storage Plants,” Pumped Storage, Institution of Civil
Engineers, London, England, 1990.
K Tani and H. Okimura, “Performance Improvement of Pump-Turbine for Large Capacity Pumped Storage Power
Plant in US,” Hitachi Review, Vol. 58 No. 5, October 2009.
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PHS plants can exceed 60 years; the Rocky River Plant in Connecticut has operated since
Pumped Storage Efficiency (AC-AC Roundtrip)
Figure 28. Historical Efficiencies of PHS Plants in United States
Source: National Renewable Energy Laboratory, 2011. Compiled from several sources including ASCE 1993,
FERC “Form 1” filings and Department of Energy databases.
Having multiple units per plant allows for scheduling maintenance on one unit while keeping the
other units available, typically minimizing effects on overall plant availability. Existing PHS
facilities in the United States have high availability and few forced outages.332 New PHS
deployments in the United States would likely include variable speed (also referred to as
“adjustable speed”) operation. This technology has not yet been applied in a major U.S.
installation, but has been used in several international plants.333 Among the benefits of variable
speed operation are faster response to grid requirements, higher efficiencies, ability to
accommodate greater ranges of “head,” and wider unit and plant operating ranges (i.e., an ability
to operate with a lower minimum load in megawatts).
The cost of new PHS plants will vary. Since large-scale PHS has not been built in the United
States in some time, the cost of the next plant is somewhat uncertain. The geotechnical and
geological characteristics and complexity of a site are major factors in PHS development costs.
Typically, the largest costs are for development of a project’s upper and lower reservoirs and for
underground components. Figure 29 provides historical cost data for U.S. PHS plants. There is a
general trend toward increasing costs, with the last three plants constructed costing over
EIA, “Existing Electric Generating Units in the United States.”
Detailed availability and outage statistics are available via the Generating Availability Data System (GADS) from
the North American Electric Reliability Corporation,|43.
M. Yasuda, “Enhancing Ancillary Services to Make Pumped Storage More Competitive,” International Journal on
Hydropower & Dams, Vol. 7, No. 1, 2000, pp. 36-42.
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$1000/kW. The cost for PHS is typically reported only in terms of cost per unit of capacity
($/kW) and includes both the energy component and power component.
Figure 29. Installed Cost of PHS Plants in United States
(current dollars)
Installed Cost ($/kW) - $2009)
Source: National Renewable Energy Laboratory, 2011. Compiled from several sources including ASCE 1993,
FERC “Form 1” filings and Department of Energy databases.
A number of projects have been completed worldwide in the last decade. There are also a
significant number of proposed plants both in the United States and internationally. Table 10 lists
several recently completed plants in Europe and proposed plants in the United States, along with
capital costs ($/kW) adjusted to $2009. There are many proposed plants in Europe, with costs
estimated in the range of $700/kW to over $3000/kW.
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Table 10. Recently Completed or Proposed PHS Plants
Plant Name
Capacity (MW)
$/kW (2009)
Date of Completion
Eagle Mountain
Iowa Hills PS
Lake Elsinore
Red Mountain
North Eden PS
Parker Knoll PS
Sources: National Renewable Energy Laboratory compilation, 2010. Europe costs from J.P. Deane et al., 2010.
United States costs are from various public sources including Northwest Wind Integration Forum, Pumped
Hydro Storage Workshop, Portland, OR, October 17, 2008.
Many of the lower-cost projects listed in the table require only the construction of one reservoir
(typically the upper reservoir) and use an existing body of water, abandoned mine, or other
existing formation for the lower reservoir. New construction requiring an upper reservoir will
raise costs significantly.334 Engineering estimates of more “generic” PHS plants are often higher
than the costs cited in Table 10. Examples include estimates from the Electric Power Research
Institute ($2100-$4000/kW)335 and R.W. Beck ($5595/kW).336 The cost impact of using variable
speed equipment in new plants is expected in the range of $50/kW (assuming a base cost of
$1000/kW) to $200/kW (over a base cost of $1900/kW).337
Research and Development
PHS is considered a mature technology, so there is little active R&D dedicated to it. However,
incremental improvements in efficiency are possible, and the flexibility of existing and future
plants may be improved using variable speed drive technologies.338
A more comprehensive discussion of recent and projected future costs is provided by J.P. Deane et al., 2010.
$2,100 in D. Rastler, Overview of Electric Energy Storage Options for the Electric Enterprises, Electric Power
Research Institute, 2009; $2,500-$4,000 in D. Rastler, “New Demand for Energy Storage,” Electric Perspectives,
Edison Electric Institute, September/October 2008.
This cost is based on a 250 MW plant, with a basic breakdown of cost components provided. Further details of the
type of PSH plant are unclear, but it is presumably a “greenfield” site requiring extensive development of both
reservoirs. See Energy Information Administration, Updated Capital Cost Estimates for Electricity Generation Plants,
November 2010.
The lower estimate is from S.M. Schoenung and W.V. Hassenzahl, “Long- vs. Short-term Energy Storage
Technologies Analysis—A Life-Cycle Cost Study,” Sandia National Laboratories, 2003. The Higher estimate is from
A. Petersen, “Red Mountain Bar Pumped Storage Project,” Presentation to the Northwest Wind Integration Forum,
Pumped Hydro Storage Workshop, Portland, OR, October 17 2008. Both estimates are in uninflated dollars.
A meeting of PHS stakeholders held in 2010 identified 10 key issues associated with deployment. Only one item on
the list was technology related (demonstration of variable speed equipment). Oak Ridge National Laboratory, Pumped
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Although not technical, one potential research effort considered important by some would be a
national screening of potential PHS sites. PHS suffers from the perception that there are no
available sites for new development, notwithstanding that the capacity of proposed plants exceeds
the installed capacity of PHS in the United States.339 Although there is no single comprehensive
estimate of PHS potential, older studies indicate the availability of hundreds of conventional PHS
sites and over 1000 GW of potential capacity in just 6 western states.340 Over 100 GW of
potential has been identified in the eastern states.341 These older assessments include some areas
that would be very difficult (or impossible) to develop based on current environmental or other
restrictions. Efforts are underway at DOE national labs to perform resource assessment for new
PHS development.342
Additional R&D could evaluate unconventional PHS development. PHS requires suitable
topographical relief, but there is a noticeable lack of existing or proposed sites in much of the
country, particularly in the Midwest and Texas (both areas with excellent wind resources). There
are several proposals to extend PHS deployment in areas without traditional PHS geography.
There are also proposals to decrease the footprint of PHS, which would have the added benefit of
reducing its environmental impact and corresponding opposition. The most common proposal is
to use an underground formation such as a natural aquifer or mined cavern for the lower reservoir.
There was extensive discussion of this type of configuration, including a large number of design
studies and proposals for underground pumped hydro, during the build-out period of conventional
PHS during the 1970s and 1980s.343 Of the proposed plants with preliminary permits, several use
an underground formation, but the majority use an above ground reservoir. This is likely due to
cost, but updated cost estimates would be valuable to assess the feasibility of underground PHS.
Other approaches to PHS include saltwater PHS facilities in coastal regions, where the ocean is
the lower body.344
Storage Hydropower, 2010,
C-J. Yang and R.B. Jackson., “Opportunities and Barriers to Pumped-hydro Energy Storage in the United States,”
Renewable and Sustainable Energy Reviews, No. 15, 2011, pp. 839–844.
This represents 155 potential sites with 341 GW of capacity in Arizona, California, Nevada, and Utah, as well as
670 GW. Harza Engineering Co. and U.S. Department of Energy, Underground Pumped Hydro Storage and
Compressed Air Energy Storage: An Analysis of Regional Markets and Development Potential, Argonne National
Laoboratory, 1977. This report is also summarized in A. E. Allen, “Potential for Conventional and Underground
Pumped-Storage,” IEE Transactions on Power Apparatus and Systems, Vol. PAS-96, No. 3, May/June 1977.
Dames and Moore, An Assessment of Hydroelectric Pumped Storage, IWR 82-H-10, prepared for the U.S. Army
Engineer Institute for Water Resources, 1981.
L. Rogers, T. Key, and P. March, “Quantifying the Value of Hydropower in the Electric Grid,” presentation to the
4th International Conference on Integration of Renewable and Distributed Energy Resources, Albuquerque, NM,
December 6-10, 2010.
A fairly large body of literature exists, mostly published between 1975 and 1985. For example, see Electric Power
Research Institute, Preliminary Design Study of Underground Pumped Hydro and Compressed-Air Energy Storage in
Hard Rock, EPRI-EM-1589, 1981. A brief literature review of this topic is provided by G. Martin, “Aquifer
Underground Pumped Hydro,” Colorado Energy Research Institute, June 30, 2007 and W.F. Pickard, A.Q. Shen, and
N.J. Hansing, “Parking the Power: Strategies and Physical Limitations for Bulk Energy Storage in Supply-Demand
Matching on a Grid Whose Input Power is Provided by Intermittent Sources,” Renewable and Sustainable Energy
Reviews, Vol. 13, No. 8, October 2009, pp. 1934-1945.
This approach has been demonstrated in Japan. H. Tanaka, H., “The Role of Pumped-storage in the 21st Century,”
International Journal on Hydropower & Dams, Vol. 7, No. 1, 2000.
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Another pumped hydro storage method has recently been proposed that works by hydraulically
moving a large cylindrical weight inside a vertical underground pipe.345 A cylindrical weight
sitting on a column of water is raised like a piston to store electricity and lowered during
discharge. The total amount of energy that can be stored is proportional to the mass of the piston
and the length of the vertical column. Since these are excavated systems, they could theoretically
be sited anywhere with suitable geology and could have a relatively small footprint (about 0.3
GW/acre).346 The proposed roundtrip efficiency of this device is likely to be comparable to
conventional PHS systems, about 75%-80%.
Deployment Challenges
There are a number of barriers to further development of PHS. While a major barrier appears to
be capital cost, an element of this cost is the long construction time, and associated risks and
uncertainty, especially under changing market conditions and structures. Federal Energy
Regulatory Commission permitting alone requires about five years.347 State and local application
and permitting can add to this time. Construction times vary, with one recent estimate of 4-5
years. This results in a 10-12 year construction time for new PHS based on current schedules.
Permitting and construction times, and associated costs, can increase due to siting opposition and
environmental regulations. PHS development on existing streams can affect water quality and
ecosystems as with any other hydro project.348 Environmental concerns have prevented or greatly
delayed construction of many proposed projects, and even delayed or prevented operation of
completed projects. For example, one project in Georgia was completed in 1988, but did not
operate until 2002 due to environmental concerns.349 Another project in Missouri was completed
in 1982, but has never been used due to fish kills.350 Finally, there is significant opposition to new
PHS development based simply on the amount of land area flooded for the upper and lower
reservoirs. The total flooded area of three of the more recently constructed large PHS plants in the
United States (the Bad Creek Hydroelectric Station in South Carolina, the Balsam Meadow
Pumped Storage Project in California, and the Bath County Pumped Storage Station in Virginia)
is in the range of 1,200 m2/MW-1,500 m2/MW.351 Older PHS facilities with constructed upper and
lower reservoirs can have flooded areas that exceed 4,000 m2/MW. New plants are more likely to
have land use requirements towards the lower range, such as the proposed Eagle Mountain and
P. Reynolds, “A Weighting Game,” Water Power and Dam Construction, March 2010,
E. Wesoff, “Gravity Power’s New Take on Pumped-Hydro Energy Storage,” GreentechMedia, November 9, 2010.
D. M. Adamson, “Realizing New Pumped-Storage Potential through Effective Policies,” Hydro Review, April 2009,
pp. 28–30.
For examples, see J.P. Clugston (editor), Proceedings of the Clemson Workshop on Environmental Impacts of
Pumped Storage Hydroelectric Operations, U.S. Fish and Wildlife Service, 1980; P.L. Strauss, “Pumped Storage, the
Environment and Mitigation,” proceedings of Waterpower ’91: A new View of Hydro Resources, New York, NY,
1991; G.M. Simmons, Jr. and S.E. Neff, “The Effect of Pumped-Storage Reservoir Operation on Biological
Productivity and Water Quality,” Water Resources Research Center, Virginia Polytechnic Institute, 1969.
C.-J. Yang and R.B. Jackson, “Opportunities and Barriers to Pumped-Hydro Energy Storage in the United States,”
Renewable and Sustainable Energy Reviews, Vol. 15, 2011, pp. 839-844.
General Accounting Office, Power Marketing Administrations: Cost Recovery, Financing, and Comparison to
Nonfederal Utilities, GAO/AIMD-96-145, September 1996, p. 34.
ASCE 1993.
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Iowa Hill plants, with flooded area requirements of about 1,100 m2/MW.352 Since PHS facilities
are generally large and in remote, they typically require new high-voltage transmission, which
adds additional siting challenges.353
An approach to minimizing the environmental impact (and potential opposition) to new PHS
construction is to reduce or eliminate its impact on existing bodies of water. Most existing U.S.
PHS plants are “open-cycle” plants; that is, they use an existing water body, usually the lower
reservoir, for one of their reservoirs. However, “closed-cycle” plants—plants where both lower
and upper reservoirs are constructed—will likely become more prevalent in the future because
they minimize environmental effects as they do not interact with natural water bodies and they
have little or no impact to aquatic life. Closed cycle plants can use existing features including
abandoned mines to minimize development costs. A water source is needed for a closed-cycle
plant to provide water to initially fill the reservoir and to compensate for losses during operation
due to leakage and evaporation. Some proposed plants will use groundwater and at least one
facility has proposed to use recycled wastewater, which could be a significant opportunity for
other new PHS facilities as well.354 Closed-cycle PHS plants could be candidates for a
streamlined FERC permitting process given their lack of interaction with any active body of
water.355 This could reduce licensing and construction times to eight years, reducing investor
Safety risks associated with PHS are similar to those of other hydro projects. The biggest risk is
dam failure and flooding. There is one example of failure (resulting in property damage and
injuries) at a U.S. PHS facility, which occurred at the Taum Sauk plant in 2005.356 The failure was
due to the upper reservoir being overfilled and subsequently being breached. The resulting flood
destroyed one house and caused damage to a local park. PHS requires little if any toxic, rare, or
foreign-sourced materials. There are no operational emissions. “Life-cycle” greenhouse gas
emissions due to construction and operation are relatively low.357 This includes emissions from
decomposition of vegetation on land flooded by new PHS reservoirs, which are relatively small,
especially for U.S. sites.358
G. Tam, “Eagle Mountain Hydro Electric Pumped Storage Project,” presentation to the Northwest Wind Integration
Forum, Portland, OR, October 17, 2008,; D.
Hanson, “Iowa Hill Pumped Storage Development Project Description,” presentation to the Northwest Public Power
Association Conference, April 6, 2011.
The proposed Lake Elsinore Advance Pumped Storage project requires about 32 miles of new 500 kV transmission
routed around the San Mateo Canyon Wilderness. Federal Energy Regulatory Commission, Final Environmental
Impact Statement Lake Elsinore Advanced Pumped Storage Project, FERC/FEIS – 0191F, January 2007.
C.-J. Yang and R.B. Jackson, 2011.
D.M. Adamson, April 2009.
Federal Energy Regulatory Commission, Report of Findings on the Overtopping and Embankment Breach of the
Upper Dam - Taum Sauk Pumped Storage Project, FERC No. 2277, April 28 2006.
P. Denholm and G.L. Kulcinski, 2004.
L.P. Rosa and M.A. dos Santos, “Certainty & Uncertainty in the Science of Greenhouse Gas Emissions from
Hydroelectric Reservoirs (Part 2): Thematic Review,” World Commission on Dams, 2000; L. Gagnon, L. and J. Van de
Vate, “Greenhouse Gas Emissions from Hydropower,” Energy Policy, Vol. 25, No. 1, 1997, pp. 7-13.
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Pumped hydro is the only electricity storage technology currently deployed on the GW scale
worldwide. It has deployment opportunities in the United States measured at least in the tens of
gigawatts without limitations of raw materials, limited calendar or cycle life, and with
demonstrated AC-AC round-trip efficiencies that routinely exceed 75%. The use of variable speed
technology will improve the efficiency and ramping characteristics of new facilities. Closed-cycle
plants will reduce environmental impact, and could reduce the permitting time needed. Perhaps
the most important R&D effort for PHS is a national screening to assess the total potential for
new conventional and unconventional PHS development, especially considering environmental
and land use constraints.
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Chapter 10: Flywheel Storage
Flywheels are one of the oldest energy storage technologies, historically used to smooth the
power delivery in applications ranging from potter’s wheels to reciprocating engines. Flywheel
technology has advanced tremendously over the last century, however, bringing the technology
from large rotating steel wheels that spin at tens to hundreds of revolutions per minute (RPM) to
composite (carbon fiber or fiberglass in resin) rotors that spin up to 100,000 RPM, achieving
supersonic speeds in a low pressure vacuum.359 These advancements allow flywheels to achieve
high power and energy densities, high roundtrip efficiency (>80%), low frictional drag losses
(<3%/hour), and long operational lifetimes (~20 years) with low operation and maintenance costs.
Flywheels can respond rapidly, both as a source and sink for electricity, making them a valuable
resource for frequency regulation in electric power grids. Flywheels are one of the most costeffective storage technologies for high power (rapid discharge) applications, where they compete
directly with batteries. But flywheels are typically more expensive than other storage
technologies as an energy resource and are unlikely to compete in the near term for applications
requiring several hours of energy storage. Flywheels have also been applied in niche
transportation applications, in automobiles, buses, and trains.360 Flywheels will compete with
batteries and capacitors in these markets. Their future market share will depend upon the relative
technological advancement in each field.361
The rapid charging and discharging characteristics of flywheels, and their ability to cycle
hundreds of thousands of times with minimal performance degradation, make them ideally suited
to provide power quality and frequency regulation to electric grids. Recent deployment trends
have centered around this application. Other applications include distributed uninterruptible
power supply (UPS) devices for telecommunication and computing resources, and mobile
applications like recycling regenerative braking energy, and using the flywheel to reduce peak
power requirements from the motor.362 Current flywheel research and development are focused on
increasing the energy density of flywheels to enable one to several hours of energy discharge,
which would enable flywheels to be used in several additional electric utility applications like
peak shaving, ramping, and load following.
Beacon Power is the main company developing and deploying flywheels for frequency
regulation. Figure 30 shows Beacon Power’s 1MW/250kWh flywheel demonstration project
deployed in 2008 to provide frequency regulation to the Independent System Operator (ISO) New
Modern flywheel technology is based in part on high-speed gas centrifuge technology developed for uranium
enrichment. M.B. Richardson, “Flywheel Energy Storage Systems for Traction Applications,” Paper No. 487,
International Conference on Power Electronics, Machines and Drives, Bath, UK, April 16-18, 2002.
M.B. Richardson 2002; EPRI/DOE, 2003; M.Lafoz, C. Vazquez, and J. Iglesias, “DC Railway Catenary Regulation
Based on KESS,” presentation to the Electrical Energy Storage Applications and Technologies Conference, Seattle,
WA, October 4-7, 2009.
R. Doucette and M. McCulloch, “A Comparison of High-Speed Flywheels, Batteries, and Ultra-Capacitors on the
Bases of Cost and Fuel Economy as the Energy Storage System in a Fuel Cell Based Hybrid Electric Vehicle,” Journal
of Power Sources, No. 196, 2011, pp. 1163-1170.
U.S. Department of Energy, Flywheel Energy Storage: An Alternative to Batteries for Uninterruptible Power Supply
Systems, DOE/EE-0286, September 2003; M.B. Richardson, 2002; R. Doucette and M. McCulloch 2010.
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England electric grid.363 Beacon expanded this 1MW project to 3 MW in 2009, and also
constructed a 20MW/5MWh plant in the New York ISO grid in 2011.364 Beacon secured an
ARRA stimulus grant to develop a second 20 MW plant in the Mid-Atlantic/Midwest grid and
proposed additional installations, but filed for bankruptcy protection in October 2011, casting
doubt on any of its future projects.365
Figure 30. Part of a 1 MW Flywheel System in the ISO-New England Grid
Source: Courtesy of Beacon Power Corp., 2011.
Flywheels store rotational kinetic energy in the form of a spinning cylinder or disc, then use this
stored kinetic energy to regenerate electricity at a later time. The amount of energy stored in a
flywheel depends on the dimensions of the flywheel, its mass, and the rate at which it spins.
Increasing a flywheel’s rotational speed is the most important factor for increasing stored
energy—doubling a flywheel’s speed quadruples the amount of energy stored.
Flywheels typically use an electric motor to spin a cylindrical rotor at very high speed. Flywheel
systems, therefore, consist of the spinning rotor(s), bearings, a motor/generator, power
electronics, and a containment enclosure (Figure 31). The bearings connecting the rotor to the
non-rotating platform are of two types: mechanical bearings, which physically connect the rotor
to the housing, or magnetic bearings, which levitate the rotor inside the housing to reduce friction
losses. The motor/generator converts electrical energy to rotational kinetic energy to “spin up” the
Beacon Power Corp., Smart Energy Matrix 20 MW Frequency Regulation Plant, fact sheet, 2010a,; and Beacon Power Corp., “Beacon Power Corporation,”
presentation to the Rodman & Renshaw Global Investment Conference, New York, NY, 2010b,
The 20MW/5MWh system is composed of two hundred 100kW/25kWh units. Beacon Power Corp., 2010a.
E. Ailworth, “As Federal Funds Dry Up, Beacon Power Still Has Reason for Hope,” Boston Globe, November 27,
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flywheel, and then regenerates electrical energy at a later time from the spinning rotor. The
containment enclosure is the non-rotating platform in which the rotor spins, designed to contain
rotor debris in the case of catastrophic rotor failure. The enclosure may also hold a vacuum to
reduce air drag on the rotor and standby energy losses.
Figure 31. Electric Flywheel Components
Source: Courtesy of Active Power Corp., 2012.
Flywheels can be designed for a broad range of applications with different power and energy
requirements. These applications can be roughly categorized by their design discharge times.
Historically, flywheels were designed for applications with discharge times of about 1 minute,
including uninterruptible power supply and transportation applications.366 More recent
applications require discharge times of up to 15-30 minutes for frequency regulation. These
applications use composite rotors to achieve high energy densities, along with vacuum housings
and magnetic bearings. Long duration flywheels with discharge times of several hours for load
shifting have also been considered but have not reached commercial deployment.367
Flywheel energy density scales with rotor mass and the square of rotor velocity, based on the
physical characteristics of the device. Flywheel power density is largely based on how quickly the
rotor can be slowed down. Flywheel roundtrip efficiency is determined by the combination of two
factors: instantaneous roundtrip efficiency and standby losses. Instantaneous roundtrip efficiency
M.B. Richardson 2002 ; M. Lafoz et al., 2009 ; R. Doucette and M. McCulloch, 2010.
M. Ricci and J. Fiske, Third Generation Flywheels for Electricity Storage, DOE award number: DE-FG3605GO15163, . LaunchPoint Technologies, Inc., Goleta, CA, June 20, 2008; J. Arseneaux, “Development of a 100
kWh/100kW Flywheel Energy Storage Module,” presentation to the 2010 Energy Storage Systems Program
Conference, U.S. Department of Energy, Washington DC, Nov. 2-4, 2010.
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represents the efficiency of turning electricity into rotational kinetic energy, and then returning
the kinetic energy back to electricity. Most of the energy losses occur in the power electronics,
converting AC electricity to DC electricity, and then the reverse. Typical instantaneous roundtrip
efficiencies range from 80% to 90%.368
Standby losses refer to frictional losses on the spinning rotor, which increase with the amount of
time the rotational energy is stored. Frictional losses are primarily from the bearings and air drag.
Typical standby losses range of 2%-3%/hr are primarily managed by using the motor to maintain
a constant rotor velocity. For example, to maintain 1 kWh of rotational kinetic energy, a constant
electrical load of 25 W may be used to maintain rotor velocity.369 Employing superconductive
magnetic bearings can reduce bearing losses to less than 0.5% per hour, but at higher cost.370
Because frictional losses transform kinetic energy into heat, and the constant electrical load
required to maintain a constant rotor speed transforms to heat, device temperature must be
managed to keep the rotor within sustainable limits.
Since standby losses are dependent on the amount of time energy is stored, they vary significantly
depending on application. For example, a flywheel dispatched in frequency regulation markets
can have approximately 6,000 full charge/discharge cycles in one year with a mean stored energy
time on the order of 1.5 hours.371 In this application, roundtrip efficiency would likely be in the
range of 80% (85% instantaneous minus 5% standby losses) and very competitive with other
technologies, namely batteries, operating in this market. If flywheels were used to shift off-peak
generation to meet on-peak load, flywheel roundtrip efficiencies could decrease to 50%-70%
(85% instantaneous minus 15% for five hours of storage or minus 36% for twelve hours of energy
storage), reducing their economic feasibility.
Flywheels can have very rapid response times; those designed for frequency regulation can ramp
to full nameplate power capacity in less than four seconds.372 Because flywheels can ramp more
rapidly than conventional generators, a smaller amount of flywheel power capacity can provide
the same ramping characteristics for regulation as a larger amount of conventional generation
Flywheels have minimal operations and maintenance costs, design lifetimes on the order of 20 to
25 years, and are designed to be cycled hundreds of thousands of times with little or no
performance degradation.374 Flywheels also have high operational reliability. In a recent
demonstration project, frequency regulation flywheels were available for more than 98% of the
EPRI/DOE, 2003; C. Lyons, “Flywheel Energy Storage—A Smart Grid Approach to Supporting Wind Integration,”
presentation to the Electrical Energy Storage Applications and Technologies Conference, Seattle, WA, October 4-7,
KEMA, Inc., Emissions Comparison for a 20 MW Flywheel-based Frequency Regulation Power Plant, 2007a.
M. Strasik, et al., “Design, Fabrication, and Test of a 5 kWh/100 kW Flywheel Energy Storage Utilizing a HighTemperature Superconducting Bearing,” IEEE Transactions on Applied Superconductivity, Vol. 17, No. 2, 2007, pp.
Beacon Power, Inc., 2010b.
J. Eyer, Benefits from Flywheel Energy Storage for Area Regulation in California-Demonstration Results,
SAND2009-6457, Sandia National Laboratories, 2009.
Y.V Makarov, et al., “Assessing the Value of Regulation Resources Based on Their Time Response
Characteristics,” PNNL – 17632, Pacific Northwest National Laboratory, June 2008.
Beacon Power Corp., 2010b; J. Eyer, 2009.
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time.375 The most common flywheel failure mode is the propagation of cracks through the rotor
over time. The presence of cracks can frequently be diagnosed by reduced performance in
composite rotors before hazardous failure occurs.
Table 11 summarizes flywheel performance characteristics. Flywheel sizes, shown by flywheel
energy and power footprints, vary significantly depending on the energy and power
characteristics of each application. Roundtrip efficiencies also vary significantly across
applications because flywheels for applications like load shifting would typically designed to
reduce standby losses (at the additional cost of high speed composite rotors, and magnetic
bearings) whereas frequency regulation flywheels are designed with higher standby losses. Loadshifting and frequency regulation flywheels also are dispatched differently. Flywheels generally
have similar design lifetimes and operations and maintenance (O&M) costs across a range of
sizes and applications.
Table 11. Flywheel Performance Characteristics
Power footprint
1.4 – 490
Lower value for frequency regulation with 15 minute discharge.
Upper value for a power application with 1 second discharge.
Energy footprint
0.35 – 0.54
Lower value for frequency regulation with 15 minute discharge.
Upper value for a power application with 1 second discharge.
Instantaneous roundtrip efficiency for frequency regulation
flywheels. Roundtrip efficiencies vary by application because of
the different standby losses associated with different charge and
discharge characteristics.
Standby energy
1%- 3%/hour
Standby losses represent frictional losses in an extended
discharge flywheel, where it frequently takes 10-30W of
continuous power to maintain 1 kWh of stored energy. Hourly
standby losses are typically higher in rapid discharge flywheels.
Ramp rate
>25% / sec
Frequency regulation application.
>100,000 cycles,
>20 years
Rapid discharge and extended discharge flywheels have similar
design lifetimes.
Sources: Beacon Power Corp., 2010a; J. Eyer, 2009; EPRI/DOE, 2003; NREL analysis.
Flywheel costs can vary significantly depending on the power and energy requirements of each
application. While flywheels are an old technology, they have only recently been applied to
electricity storage. Current costs are largely based on experience building demonstration projects.
Significant near-term cost reductions are projected due to organizational learning and economies
of scale in future deployments. An example of current costs is the 20MW/5MWh demonstration
project in the New York ISO, with a cost of $69 million (2009 dollars). Beacon Power has set a
cost target of $25 million-$30 million for an “nth system” frequency regulation plant, as shown in
Figure 32. The plant is designed with 15 minutes of discharge capacity, corresponding to cost
projections, on an energy basis, of $14,000/kWh for the first demonstration plant to $5,000-
Beacon Power Corp., 2010b.
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$6,000/kWh for the nth plant. Long-term O&M costs have yet to be determined. Estimates include
$10-$12/kW-yr for fixed O&M and about $3/MWh of output for variable O&M.376
Figure 32. Flywheel Cost Projections for a 20MW/5MWh
Frequency Regulation Plant
Source: National Renewable Energy Laboratory analysis, 2011; Beacon Power Corp., 2010b.
Research and Development
Recent flywheel research and development (R&D) have focused on improving flywheel energy
density, reducing standby losses, increasing the efficiency of associated power electronics, and
decreasing cost.
To improve flywheel energy density, R&D has focused on developing and using new rotor
materials capable of sustaining higher speeds. Energy density has improved significantly by
transitioning from metallic rotors, with maximum rim velocities of 300-500 m/s, to composite
rotors which can achieve rim velocities well above 1,000 m/s. Table 12 summarizes flywheel
rotor material characteristics, including maximum theoretical energy densities, and the actual or
proposed energy densities for real flywheel systems. Operating flywheels have lower energy
densities than the maximum theoretical limits because flywheels are operated below their
maximum stress threshold for safety reasons (typically a reduction of 25%-50% in flywheel
performance).377 Furthermore, realistic rotor designs are not fully able to utilize a material at its
stress potential at each position within the rotor (typically an additional 20%-50% performance
reduction).378 This leads to current flywheels performing at 25% to 60% of the maximum
theoretical limits. The difference between real world performance and the maximum theoretical
EPRI/DOE, 2003, Eyer 2009
P. Johnson, et al., “Design, Fabrication, and Test of a 5 kWh Flywheel Energy Storage System Utilizing a High
Temperature Superconductive Magnetic Bearing,” proceedings of the Electric Energy Storage Applications and
Technologies Conference, Sandia National Laboratories, San Francisco, CA, October 17-19, 2005.
F. Werfel, et al., “Towards High-Capacity HTS Flywheel Systems,” IEEE Transactions on Applied
Superconductivity, No. 20, 2010b, pp. 2272-2275.
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performance roughly represents the R&D potential for improved design, although flywheels will
always be operated below their maximum stress thresholds for safety considerations, and there
are other fundamental limits to design improvements.
Table 12. Flywheel Materials Characteristics
Maximum Theoretical
Energy Densities (Wh/kg)
Achieved or Proposed
Energy Densities (Wh/kg)
Carbon Nanotube
Fused Silica
373-532, 547-780
Spectra 1000
Kevlar 49
Steel (4340)
Sources: M. Strasik et al. 2007; J. Bitterly, “Flywheel Technology: Past, Present, and 21st Century Projections,”
IEEE Aerospace and Electronic Systems Magazine, August, 1998; H. Liu and J. Jiang, “Flywheel Energy Storage – An
Upswing Technology for Energy Stability,” Energy and Buildings, No. 39, 2007, pp. 599-604; F. Werfel et al., “HTS
Flywheel from R&D to Pilot Energy Storage System,” Journal of Physics, Conference Series, Vol. 234, 2010a.
Note: Energy density is shown here in Watt-hours (Wh) per kilogram (kg) of rotor material. Flywheels designed
for vehicle applications often measure energy density in Wh/kg, while larger flywheel plants for frequency
regulation may measure energy density in units of Wh/m2. Wh/kg provides the more useful metric to compare
the energy density of rotor materials
Another area of active R&D, not limited to the flywheel community, is developing high tensile
strength materials. For example, carbon nanotubes can reach theoretical tensile strengths that are
an order of magnitude higher than graphite.379 While these materials would have to be
demonstrated, and cost-effectively manufactured at scale, they could considerably increase
flywheel energy density.
In addition to improving rotor materials, new rotor designs are being developed to increase
energy density. Design trends include the use of larger diameter rotors to increase rim tip speeds,
and eliminating the central shaft and hub, levitating the rotor on magnetic bearings located at or
near the rim to better utilize the tensile strength of rotor materials.380 This approach could provide
additional controllability for large diameter energy flywheels and could reduce several
engineering challenges, including rotor rigidity and exciting frequency oscillation modes.381
While such flywheels have not been demonstrated, it is projected that new designs could
significantly improve energy density and flywheel costs. Flywheel rotor R&D is being conducted
in the United States by universities (e.g., the University of Texas and Pennsylvania State
University), Sandia National Laboratories, and the U.S. Army, as well as several commercial
companies including Boeing, Beacon Power, and LaunchPoint, Inc.382
J.P. Salvetat, et al., “Mechanical Properties of Carbon Nanotubes,” Applied Physics A., No. 69, 1999, pp. 255-260.
M. Ricci and J. Fiske, 2008; J. Arseneaux, 2010.
M. Ricci and J. Fiske, 2008.
EPRI/DOE, 2003; T. Boyle et al., “Improved Properties of Nanocomposites for Flywheel Applications,”
presentation to the Energy Storage Systems Program Conference, U.S. Department of Energy, Washington DC, Nov. 2(continued...)
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To reduce standby energy losses, flywheel R&D has focused on reducing frictional drag in the
bearings and air drag on the spinning rotor. Air drag can be effectively reduced by pulling a
vacuum in the rotor housing—the approach used in current designs. Bearing friction can be
reduced by replacing mechanical bearings with magnetic bearings that levitate the rotor inside its
housing.383 Magnetic bearings typically consist of a fixed magnet on the rotor, and a fixed and/or
electromagnet on the rotor housing. Magnetic bearings are either static (passive system with a
fixed magnetic field that holds the rotor in place, with additional control components), active
(variable magnetic field that dynamically controls flywheel position and motion), and/or
superconducting (passive or active electromagnet designed using high temperature
superconductive components).384 These bearings either draw constant current (active magnetic
bearings) to offset resistive losses, or can be designed using high-temperature superconductive
materials which draw current to power cryogenic coolers.385 Magnetic bearings can reduce
standby losses to a few percent per hour where losses represent the combination of the remaining
frictional losses and the system load required to operate magnetic bearings.386 Superconducting
bearings can reduce standby losses down to 0.1%/hour.387 Flywheel bearing R&D continues at the
Lawrence Livermore National Laboratory as well as international universities and several
commercial companies.388
Flywheel power electronics have become more efficient over time. Recent power electronics
R&D has been driven by other, larger industries, and flywheels benefit from the resulting
incremental efficiency and durability improvements. These improvements will be shared with
other storage technologies that do not use conventional generators.
Future flywheel R&D will likely focus on further improving flywheel energy density, magnetic
bearing technology and control circuits, and reducing materials and manufacturing costs. It is
likely that flywheels will see incremental efficiency improvements, driven by efficiency gains in
the power electronics and bearings. Flywheel energy density could see larger improvements,
particularly by using new materials capable of higher energy densities and by modifying flywheel
design for extended discharge applications.389 In addition to fundamental R&D improvements,
there is a large potential for reducing costs based on organizational learning.
4, 2010; J. Tzeng,, R. Emerson, and P. Moy, “Composite Flywheels for Energy Storage,” Composites Science and
Technology, No. 66, 2006, pp. 2520-2527; M. Strasik, et al., 2007b; J. Hull et al., “High Rotational-Rate Rotor with
High-Temperature Superconducting Bearings,” IEEE Transactions on Applied Superconductivity, No. 19, 2009, pp.
2078-2082; M. Ricci and J. Fiske, 2008.
Use of magnetic bearings also eliminates lubrication challenges. As flywheel spin rates exceeds about 40,000 RPM,
the lubrication in mechanical bearings (mostly ball bearings) begins to heat and fail. H. Liu and J. Jiang, 2007.
Electric Power Research Institute (EPRI), Flywheels for Electric Utility Energy Storage, TR-108889, Palo Alto, CA,
J. Hull et al., 2009.
Beacon Power Corp., 2010b.
P. Johnson et al., 2005.
Lawrence Livermore National Laboratory, “LLNL and Arnold Magnetic Technologies Collaborate on Passive
Magnetic Bearing System,” press release, May 26, 2010; N. Koshizuka, “R&D of Superconducting Bearing
Technologies for Flywheel Energy Storage Systems,” Physica C, No. 445, 2006, pp. 1103-1108.
J.P.Salvetat et al., 1999; T. Boyle, et al., 2010; M. Ricci and J. Fiske, 2008; J. Arseneaux, 2010.
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Deployment Challenges
Flywheel permitting should be relatively easy compared to several other technologies since
flywheels do not use fuel or contain hazardous chemicals, do not use water, are emissions free,
and have a relatively small footprint.390 Flywheel units up to 10 kWh can be assembled in a
factory and delivered using standard shipping trucks.391 Both the modular nature of flywheels,
and low operations and maintenance requirements, allow flywheels to be sited virtually
anywhere. One estimate of complete siting, permitting, and construction time is about 18
The physical footprint of frequency regulation flywheels is about 50 kW/m2 and or about 10
kWh/m2. The footprint of the entire regulation plant (including power conditioning equipment
and a security perimeter) is about 6 MW/acre (for example, a recent 20 MW/5MWh regulation
flywheel plant is sited on about three acres).393 The relatively small land area requirement (and
their modular nature) allows flywheels to be located at substations, or near urban load centers. In
act, flywheels are frequently sited underground encased in thick concrete walls to contain debris
should a catastrophic failure occur.394 While steel flywheels are subject to hazardous failure
modes, composite flywheels have a diagnosable deterioration in performance before failure
occurs.395 With these precautions, flywheels can be operated safely and reliably through their 20+
year calendar life. Flywheels do not contain any toxic materials, and there is no risk for explosion
or environmental contamination.
Flywheels are primarily constructed from metal, carbon, or glass fiber and resin, and support
materials like concrete and structural steel. While these materials will be subject to commodity
prices, their supply is virtually unlimited. High temperature superconductive materials like
yttrium barium copper oxide (YBCO) use common earth elements, and material shortages are not
a concern. Neodymium magnets are used in some motors and magnetic bearings, and may have a
limited supply. However, different magnetic materials or electromagnets can also be used.
Flywheel systems are being deployed now using a basic utility engineering and construction labor
force. While flywheel deployment will lead to new jobs, it will not require unique new
infrastructures or labor forces.
Several demonstration projects are currently showing that flywheels are a competitive source of
frequency regulation. The rapid response of flywheels, and their ability to cycle extensively with
KEMA, Inc. 2007a.
J. Hull, Flywheels, Encyclopedia of Energy, Volume 2, Elsevier, Inc., ISBN:978-0-12-176480-7, 2004.
C. Lyons, “A Smart Grid Approach to Regulation and Ramping,” Renewgrid, August 2009.
Beacon Power Corp., 2010b.
Flywheels store a very large amount of energy, which could be destructive in a catastrophic failure. For example, a
100 kW Smart Energy 25 flywheel from Beacon Power stores 25 kWh of rotational kinetic energy when fully charged
C. Lyons, 2009. This amount of energy is approximately equal to 20 kg of trinitrotoluene (TNT). Flywheel housing and
encapsulation material must, therefore, be designed to contain debris should catastrophic failure occur.
Composite rotors are designed so that stress fractures propagate longitudinally through the material, leading to the
delimitation of outer rotor layers prior to failure, causing the system to wobble and slow down through frictional losses
before catastrophic failure occurs.
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little or no performance degradation, makes them ideally suited to provide regulation. However,
they will compete with batteries and supercapacitors in these markets, and flywheel economics
will have to be (and remain) dominant over these technologies to capture and maintain market
share. Other potential markets for flywheel energy storage include transportation (capturing
regenerative braking energy), and additional ancillary services that bridge regulation and reserves
markets and require a longer-duration discharge.
Flywheel R&D will likely further improve energy density, reduce standby energy losses, and
reduce costs. Energy density improvements will be driven by the development and use of new
composite rotor materials, and larger diameter rotors. Standby losses will likely be reduced using
superconducting magnetic bearings. Flywheel costs will likely be reduced by implementing new
rotor materials and designs, and from organizational learning as more flywheels are deployed and
the industry benefits from economies of scale.
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Chapter 11: Thermal Energy Storage in Buildings
Thermal energy storage (TES) in buildings is an alternative to most electricity storage
technologies which is often overlooked because it does not store and discharge electricity directly.
However, in some applications, TES can be functionally equivalent to electricity storage, with
efficiencies that exceed 90%. One key application is to use cold storage to shape end-use
electrical demands in the same manner as customer-sited electricity storage, with corresponding
benefits of reduced distribution capacity and losses, and with higher efficiency and potentially
lower cost.
Air conditioning for buildings represents a significant component of end-use of energy in the
United Sates, comprising approximately 10% of total electricity sales.396 More importantly, the
peak demand for most U.S. utilities is strongly driven by the aggregated cooling demands of
individual buildings. “Cool” thermal storage relies on a simple concept: operate a building’s
energy-intensive refrigeration equipment for space conditioning at night to create and store
energy in the form of ice or chilled water. That chilled water is then used as a reservoir of “cold”
during the day to meet building cooling loads, reducing the operation of the building’s cooling
equipment during daytime on-peak periods. In effect, the TES shifts electricity demand from day
to night, when electric energy cost and utility demand is low, in a highly predictable way. The
concept of cool storage as a “thermal battery” translates into operating cost savings for the
building owner. It also yields broader benefits for utilities when widely applied through its ability
to decrease the aggregate electric demand during on-peak periods. By decoupling the production
of cooling with the demand for cooling, TES offers the opportunity to considerably alter the
electrical demand profile associated with building space conditioning systems. Heat storage
technology similarly offers potential benefit for load shaping of buildings that derive heating
energy from electricity (either by resistance heating or heat pumps). This application of thermal
energy storage is not mature or widely applied but does offer potential—particularly for winterpeaking electric utilities.
In the United States, there are approximately a dozen manufacturers or providers of thermal
energy storage systems (ice storage and chilled water storage). The industry trade association
currently has five U.S. thermal energy storage manufacturers as members of their “Thermal
Storage Equipment” product section.397 Most of the TES technologies being sold into the U.S.
market today are mature, having undergone refinements over the past three decades. One notable
exception are unitary ice thermal storage systems, which integrate the required refrigeration
system along with a thermal energy storage module. Unitary systems have been commercialized
only relatively recently.
Although detailed statistics about the cool thermal energy storage market in the United States are
not available, an estimated 4,500 thermal energy storage systems are operating across the country.
There are also a number of demonstrated facilities in federal and public buildings.398 The primary
Energy Information Administration, Annual Energy Outlook 2011, DOE/EIA-0383(2011), 2011.
The Air-Conditioning, Heating, and Refrigeration Institute (AHRI) is a trade association representing more than 300
manufacturers of air conditioning, heating and commercial refrigeration equipment.
W. D. Chvala, Technology Potential of Thermal Energy Storage (TES) Systems in Federal Facilities, PNNL-13489,
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challenge of TES is due to its distributed nature—deployment is dependent on individual
customers being aware of its existence and current electricity rate structures typically do not
capture its benefits to the grid. Partly in recognition of this challenge, in 2010 a consortium of
municipal utilities in southern California began installing 53 MW of distributed ice storage
systems as a system resource for load shifting and firm capacity.399 This consortium represents a
potential shift in approaches to distributed storage, as it may be easier to develop business models
that deploy utility-owned but customer-sited storage.
Broadly speaking, TES technologies are classified into two categories based on the nature of how
they store energy: “sensible” energy change and “latent” energy change. Sensible energy change
systems store thermal energy by using the heat capacity of a working fluid (e.g., water) and
causing it to undergo a temperature change. During charging, warm water from the top of a
storage tank is cooled using a mechanical refrigeration plant (chiller) prior to being returned back
to the bottom of the tank. The cool water within the water storage tank is then made available to
meet instantaneous building cooling loads at a later time. As the water absorbs heat when meeting
the building’s space cooling load, its temperature rises and the warm water is returned back to the
top of the storage device for re-cooling during the off-peak period. Figure 33 shows a simple
schematic of a chilled water storage system operating to meet building cooling loads.
Latent energy change technologies extract and absorb heat into a storage medium that undergoes
a liquid-solid phase change (e.g., melting and freezing). The most widely used latent energy
change storage medium is ice but other substances, like salt solutions or ethylene glycol-water
mixes, have been employed as well. During charging, the chiller cools the fluid—say, an ethylene
glycol-water solution—to a temperature below the freezing point of water. The cold glycol
circulates through a heat exchanger immersed in a water tank causing it to freeze. During a melt
period, warm glycol returning from the load can either be pre-chilled by the mechanical chiller or
cooled directly by circulation through the ice storage tank(s). The warm glycol is cooled as it
gives up its heat to the ice causing it to melt back to a liquid.
Pacific Northwest National Laboratory, July 2001; U.S. Department of Energy, “Thermal Energy Storage at a Federal
Facility,” DOE/GO-102000-1099, fact sheet., July 2000; Stanford University, “Ice Plant,” web page, 2011.
Ice Energy, “SCPPA to Undertake Industry’s Largest Utility-Scale Distributed Energy Storage Project,” press
release, January 27, 2010.
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Figure 33. Illustration of a Chilled Water-Based TES System
Source: Courtesy of Cypress, Ltd., “Stratified Chilled Water Storage,” web page, Coto de Cazxa, CA, 2011,
Heat storage is an even simpler form of TES. It stores heat in a high-heat capacity material, such
as bricks, and discharges that stored heat later.400 While much simpler than ice storage, it has
several disadvantages. First, while virtually all air-conditioning is driven by electricity, a large
fraction of space heating is accomplished by burning natural gas or other fuels, reducing the
potential opportunities. Second, hot storage has fewer utility benefits, especially in terms of
providing system capacity. Nearly all of the United States is summer peaking, meaning there is
generally large capacity reserves to meet winter demand. However, hot storage can still provide
valuable load-leveling applications. Controllable water heating is another form of TES, which
somewhat blurs the line between energy storage and demand response.
Historically, thermal storage has been used to reduce demand and peak energy charges, making it
functionally equivalent to an electricity storage device providing load-leveling and firm capacity.
However, while charging, TES has the potential to provide operating reserves as well. The
compressor for cold storage, for example, could respond to a signal for frequency regulation or
spinning reserves while charging and reduce load or turn off. Given the flexibility of when the
device charges during the overnight period, this should have limited effect on the customer.
Figure 34 shows how two alternative cool storage system operating strategies can alter the
electrical demand for a facility compared to a building without thermal energy storage. Without
TES, the peak demand associated with its cooling system operation is 500 kW with the peak
occurring mid-afternoon. If TES was added to the building, it would allow the refrigeration plant
to idle during the on-peak period yielding a 500 kW demand reduction (full-storage). A somewhat
smaller TES system could be installed that would necessitate some chiller operation during the
on-peak period but still yield a 50% reduction in electrical demand during the time of the day
For an example in residential applications see Steffes Corp., “How IT Works: ETS Heating System,” web page,
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when utilities experience their peak demand (partial storage). The size of a TES influences the
extent to which it can alter a building’s demand profile. This gives designers flexibility to achieve
end-use objectives that may vary from building to building or utility region to utility region.401
Figure 34. Electric Demand for Building Cooling With and Without TES
Source: D. Reindl, University of Wisconsin-Madison, 2011.
In all performance metrics, TES must be compared to the system it is replacing. The concept of
“round trip efficiency” is not easily defined in TES systems in part because it must be compared
to the conventional alternative. However, by many measures the efficiency of TES is commonly
cited as well above 90%. The overall energy “effectiveness” can sometimes even be higher than
100% because a cold-storage based cooling system can use less electricity than its conventional
alternative. Unlike most technologies, TES does not have to convert electricity into an
intermediate energy carrier and back to electricity. TES converts electricity into “cold” in
essentially the same manner it would in a system without TES, only at a different time. As a
result, the primary losses (again compared to its conventional alternative) are heat losses in the
storage tank (which are generally well insulated). One estimate of heat losses in a commercial ice
storage tank was about 0.7% per day.402 Another report claims 1%-5% per day.403 However, TES
systems can improve the operating efficiency of equipment used for air conditioning compared to
non-storage systems. A building with TES system will run its refrigeration equipment at nighttime
when the system efficiency is higher due to cooler ambient conditions.404 In addition TES system
A. Wilson, “Buildings on Ice,” Environmental Building News, Vol. 18, No. 7, July 2009,
T.K. Stovall, Calmac Ice Storage Test Report, ORNL/TM-11582, Oak Ridge National Laboratory, 1991.
K. Roth, R. Zogg, and J. Brodrick, “Cool Thermal Energy Storage,” ASHRAE Journal, September 2006.
This is due to the fact that “cold” is actually made by removing heat from the cooling medium and discharging that
heat into the outside environment. It is easier and more efficient to discharge the removed heat into cooler air, and as a
result a device making cold in the cooler evening is more efficient than making cold in the heat of the day. See R.
Willis and B. Parsonnet, “Energy Efficient TES Designs for Commercial DX Systems,” ASHRAE Transactions, OR10-016, June 8, 2010; M. MacCracken, “Thermal Energy Storage Myths,” ASHRAE Journal, September 2003.
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allows operation of refrigeration equipment at or near peak efficiency during all operating hours
compared to non-storage systems which have to operate at less efficient part-load conditions for
the majority of its hours of operation annually.405 The net effect is the potential to decrease total
energy consumption associated with cooling, in addition to the load-shifting and capacity
There are examples of comparable buildings where the TES equipped building uses less cooling
energy than the non-TES building, implying an efficiency of greater than 100%. One case
involves the installation of an ice storage TES system at one of the Kraft Foods Headquarters
buildings in Northfield, IL. Two comparably constructed buildings were operated—one with ice
TES and one without. In 1997, the building equipped with ice storage consumed 10,114,460 kWh
with a peak demand of 2,368 kW while the non-storage building required 11,695,468 kWh
(+15%) with a peak electrical demand of 3,307 kW (+40%). The TES equipped building operated
during that year with a 19% ($193,000) lower electric bill.406 In addition, TES has the added
benefit of reduced transmission and distribution losses similar to other distributed energy storage
For most TES technologies, the device lifetime is equal to or longer than the refrigeration system
it is displacing. Detailed O&M cost figures (which again must be compared to the O&M
requirements to that alternative system) are not widely published, however, the ongoing
maintenance of a TES system is minimal—often only requiring occasional checks of water levels
and water quality to assure adequate treatment is being sustained. Furthermore, buildings
equipped with TES often have fewer chillers or smaller chillers. This means that there is less
“rotating mechanical equipment” to maintain, so O&M for a TES equipped system can be less
than a non-TES system.
As with other performance metrics, the cost of a cooling system with TES must be compared to
the system without one. The cost associated with addition of a TES is partially offset by
reductions in the size (or number) of active refrigeration or chilling equipment that would
otherwise be required to meet an application’s peak load directly. In fact, a number of building
thermal storage systems have been installed at a lower capital cost when compared to their nonstorage system counterparts.408 The actual costs of storage systems will be variable depending on
the sizing strategy. One estimate for the installed cost for ice storage systems ranges from $500 to
$1,000 per kW of electricity shifted from on-peak to off-peak periods kW.409 This cost range does
not include the emerging unitary ice storage systems with recent estimates in the range of $2000$3000/kW.410 Chilled water storage system costs range from $330-$1,350 per kW.411
“ASHRAE GreenGuide,” American Society of Heating, Refrigerating, and Air-Conditioning Engineers, Atlanta,
GA, 2003, pp. 84-85.
İ. Dinçer and M. Rosen, Thermal Energy Storage: Systems and Applications, John Wiley & Sons, 2002.
Gansler, R. A., Reindl, D. T., and Jekel, T. B., “Simulation of Source Energy Utilization and Emissions for HVAC
Systems”, ASHRAE Transactions, V. 107, Pt. 1, 2001.
J.S. Andrepont, “Stratified Low-Temperature Fluid Thermal Energy Storage (TES) in a Major Convention
District—Aging Gracefully, as Fine Wine,” ASHRAE Transactions Vol. 112, No. 1, 2006.
Electric Power Research Institute (EPRI), “Thermal Energy Storage Technology Brief,” No. 1016084, Palo Alto,
CA, November 2008.
M. Wald “Storing Energy as Ice?,” Green (internet blog), New York Times, January 27, 2010; Ice Energy, “Glendale
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Research and Development
The state of cool storage technologies today can be described as “semi-mature.” A considerable
amount of technology development occurred in the 1980s with subsequent refinements that have
continued to date. The technologies currently available are highly functional and further
development efforts are not critical to the future success of the technology. However, there are
several R&D efforts that could provide incremental improvement in TES performance including:
Advanced heat transfer fluids. Ice storage systems principally rely on the use of
ethylene glycol or propylene glycol heat transfer fluids. Thermal storage systems
and the broader industry could benefit appreciably by the development of high
heat carrying capacity secondary fluids that are non-toxic with low viscosity.
This includes exploring the potential for using nanoparticles or microencapsulated phase change materials to increase the fluid’s heat capacity.
Efficient low temperature refrigeration. By their nature, ice storage systems
require lower operating temperatures to charge the storage system. Advances
aimed at increasing the operating efficiency of refrigeration technologies at lower
operating temperatures can further improve the energy advantage of ice storage
TES technologies compared to non-storage system counterparts. This area has
not received attention in the industry because of the focus on higher operating
temperature systems used for direct space conditioning.
Communication and Control. Like other distributed storage technologies, TES
will provide maximum benefit when responding to the needs of the grid as a
whole, as well as the building cooling demand. There are opportunities to
optimize the aggregated charging and discharging of thermal energy storage
systems to maximize grid stability and generation dispatch via intelligent
communication (i.e., smart grid).
Deployment Challenges
The primary barrier to TES deployment is associated with the fact that it is customer sited and
deployed. There is currently a lack of technology awareness among end users, as well as policy
makers and utilities that might encourage TES adoption. For example in several of the major
surveys of energy storage, TES is not even listed as an option.412
In the late 1980s and early 1990s, EPRI and its member utilities conducted a significant amount
of outreach and education through the Thermal Storage Applications Research Center (TSARC)
to a wide range of stakeholders. These outreach efforts drove a significant number and variety of
applications. By the mid 1990s, outreach support for thermal storage ended and visibility of
Water & Power to Launch Thermal Energy Storage Project,” press release, March 16, 2010.
EPRI, 2008.
Several of the common storage resources including the EPRI-DOE Handbook, the Electricity Storage Association
website, and recent storage reports by the Electricity Advisory Council, and the American Physical Society do not even
mention thermal storage. The historical lack of awareness of TES as an option is noted in: C. E. Dorgan, R.T. Linton,
and S.L Mattix, Market Assessment of Thermal Energy Storage Report, No: TSARC 96-01, Thermal Storage
Applications Research Center, University of Wisconsin-Madison, May 1996.
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thermal storage technology, its benefits, and sustained application declined significantly. This
history underscores the need to develop and support effective outreach efforts to encourage
application of the technology.
For TES to be incorporated effectively, building designers must be aware of and willing to
consider the technology. Currently, building design tools are not widely available to support quick
and accurate systems analysis. Many of the most widely used software tools for building
mechanical systems do not include TES technologies. Designers must also be willing to address
design complexity. Although the added complexity of TES to a building is small to moderate,
many designers perceive this added complexity as increased risk. Overall, greater awareness and
suitable design tools are needed to increase consideration of TES as a design option. The addition
of a cool storage system necessitates a greater footprint within or outside of a building compared
to a non-storage system alternative. This reality can be overcome with proper planning and
coordination with architects and building designers—even in cases where space is constrained.
Another major challenge of TES is the limited quantification and recovery of benefits. Thermal
storage systems become cost-justified in cases where demand costs are high and time-of-use rates
exhibit high energy cost differentials between on-peak and off-peak periods. When rate structures
do not completely capture the capacity and time-shifting value of TES, then the technology will
be undervalued and adoption minimized.413 For building types that would utilize small TES
technologies, time-of-use rate structures are not uniformly available; therefore, this technology is
particularly challenged to achieve market penetration. As a result, one manufacturer has
developed a business model in which customer-sited storage is owned by the utility as a peak
generation and load shifting asset.414
There are few other non-technical barriers to large-scale deployment. TES requires little in the
way of exotic materials, and the only potentially hazardous materials are certain refrigerants,
which are common to the industry. There are no discharges of any material into the environment
for a well maintained system, as with other cooling technologies. There is also the associated
(small) risk of tank failure and discharge of the chilled water.
As a technology, TES has several advantages over conventional electricity storage devices. Most
importantly, it effectively stores energy at much higher round trip efficiencies and can also be
deployed at the point of use, decreasing need for transmission and lowering transmission and
distribution losses. The primarily disadvantage of thermal storage is that it is tied to an end use
(air-conditioning), which means it is less flexible than other electricity storage technologies
which can provide storage services that are unrelated to the demand for cooling or heating. The
primary barriers to deployment are not technical or economic—given appropriate valuation,
benefits of TES can outweigh the costs with existing technology. However, limited awareness,
technology perception, and limited access to recovery of benefits currently restrict adoption and
suggest market and policy changes are needed to allow equitable competition for TES.
For a more comprehensive discussion of the benefits of customer-sited TES see J. Swisher, W. Clift, and E. Lokey,
System Benefits of Mass Deployment of Distributed Thermal Energy Storage: An Evaluation of the Physical and
Environmental Impacts of the Ice Power Plant, Camco International, June, 2009; and R.W. Beck, Ice Bear Energy
Storage System Electric Utility Modeling Guide, October 8, 2010.
Ice Energy, January 27, 2010.
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Chapter 12: Thermal Energy Storage for
Concentrating Solar Power
Another application of thermal energy storage for electric grid applications is storing thermal
energy from the sun that is later converted into electricity. Incorporating thermal energy storage
(TES) into concentrating solar power (CSP) plants enables these plants to dispatch power beyond
their normal operational hours of daytime sun. Such a system can be functionally equivalent to
other energy storage technologies for the grid. TES allows full-load generation hours to be added
or shifted, providing increased utilization (capacity factor) of the power block, providing firm
capacity, generating higher-value electricity, and potentially reducing the levelized cost of
CSP with TES has been commercially deployed in three Andasol parabolic trough solar plants in
Spain (Figure 35).416 Each of the three Andasol plants is rated at a nominal power output of 50
megawatts (MW) of electricity with storage that provides an additional generating capacity of 7.5
hours.417 The Gemasolar plant, completed in Spain in 2011, is a 17 MW power tower with 15
hours of TES; it is the first commercial power tower with molten-salt heat-transfer fluid (HTF)
and storage.418
R. Sioshansi and P. Denholm, “The Value of Concentrating Solar Power and Thermal Energy Storage,” IEEE
Transactions on Sustainable Energy, Vol. 1, No. 3, pp. 173-183, 2010.
M. Medrano, et al., “State of the Art on High Temperature Thermal Energy Storage for Power Generation. Part 2—
Case Studies,” Renewable and Sustainable Energy Review, No. 14, pp. 56-72, 2010.
As a result of this single plant, the capacity of CSP TES now exceeds most battery technologies.
NREL 2011, “Concentrating Solar Power Projects.”
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Figure 35. Two-Tank TES System at a 50 MW Solar Power Plant in Spain
Source: D. Biello, “How to Use Solar Energy at Night,” Scientific American, February 18, 2009.
There are a number of proposed and planned CSP plants incorporating TES. In 2011, construction
began in Arizona on a 250-MW parabolic trough plant with six hours of storage.419 CSP plants are
currently incentivized by a 30% federal investment tax credit (ITC), currently scheduled to expire
in 2016, and the Department of Energy’s Loan Guarantee Program amended by the American
Recovery and Reinvestment Act of 2009. The first loan guarantee of $1.45 billion was used to
finance construction and start-up of the Arizona project.420
With thermal storage, the heat from the solar field is stored prior to reaching the power generation
turbine. Storage media being used or considered include molten salt, steam accumulators (for
short-term storage only), solid ceramic particles, high-temperature phase-change materials,
graphite, and high-temperature concrete.421 Molten salt is the most commonly used storage
medium and is used in the two-tank storage system shown in Figure 36. In this approach, hot
heat-transfer fluid (HTF), typically a synthetic oil, from the solar field flows through heat
exchangers to charge molten salt in the “hot” storage tank. This salt starts out as lowertemperature material in the “cold” storage tank, having come from the power block after being
used to generate steam for the steam turbine/generator. When the energy in the hot storage tank is
Excluding pumped hydro plants, this is larger than any other single storage facility in the United States.
U.S. Department of Energy, “DOE Finalizes $1.45 Billion Loan Guarantee for One of the World’s Largest Solar
Generation Plants,” press release, December 21, 2010.
A. Gil, et al., “State of the Art on High Temperature Thermal Energy Storage for Power Generation. Part 1—
Concepts, Materials and Modellization,” Renewable and Sustainable Energy Review, No. 14, pp. 31-55, 2010; D.
Kearney et al., “Engineering Aspects of a Molten Salt Heat Transfer Fluid in a Trough Solar Field,” Energy, No. 29,
pp. 861-870, 2004; U. Herrman and D. Kearney, “Survey of Thermal Energy Storage for Parabolic Trough Power
Plants,” Journal of Solar Energy Engineering, No. 124, pp. 145-152, 2002.
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needed, the system simply operates in reverse to reheat the solar HTF. The hot HTF then releases
its thermal energy through a set of heat exchangers to generate steam to spin the turbine and
generator in the power plant. It is an “indirect” system because it uses a storage medium (salt)
that is different from the HTF (oil) circulated in the solar field.
Other options include direct storage. This includes use of molten salt as the HTF, such as is used
in the Gemasolar plant. Another option is the direct storage of steam, which is being used
commercially in Spain.422 Steam storage is typically limited to less than 1 hour of generation due
to the high cost of pressurized vessels for larger steam volumes and storage capacities.
Figure 36. Schematic of an Indirect Two-Tank TES System
Source: A. Gil, et al., 2010.
TES can greatly improve the performance of CSP plants. Low levels of storage—30 minutes to 1
hour of full-load storage—can ease the impact of transients such as clouds. However, the most
significant attribute of thermal storage is that it can significantly increase the energy and capacity
value of CSP compared to equivalent systems without storage. In addition, CSP systems with
storage can provide load following and ancillary services acting as an enabling technology for
variable generation sources.423
Trough plants such as Andasol 1 have been designed for 7.5 hours of full-load storage, which
allows operation well into the evening when peak demand can occur and energy costs are high.
Abengoa Solar, Power Tower Technology Plants, marketing brochure, 2011.
R. Sioshansi and P. Denholm, 2010.
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Power towers, with their higher operating temperatures, can charge and store molten salt more
efficiently and less expensively.424 The 17-MW Gemasolar power tower being developed in Spain
is designed for an operation of 6500 hours per year—or a 74% capacity factor. In Arizona, a
power purchase agreement has been signed for the Solana project, a 250-MW net trough plant
with 6 hours of molten-salt thermal storage, which yields a 40% capacity factor.
CSP trough and tower plants generate electricity at utility-scale levels, currently ranging from 10
MW to 50 MW or more. The single power block—the portion of the plant where power is
generated—for each of these plants is one reason that TES can readily be incorporated. For
dish/engine CSP systems, in contrast, the potential for TES is currently much less because of their
more modular design and much lower (25 kW or less) generating capacities.
A key advantage of TES over electricity storage technologies is very high round-trip efficiency,
because it is much easier to store thermal energy than electricity energy. Electricity is a high
“quality” source of energy, so transforming electricity into a stored medium and back to
electricity incurs considerable losses. In a CSP plant, thermal energy is stored before conversion
to electricity. As a result, the round-trip efficiency of CSP thermal storage typically exceeds
90%.425 However, CSP thermal storage can only store thermal energy produced from the solar
field, as opposed to other storage technologies that can store electricity produced from any
source. Table 13 summarizes the storage efficiency and other basic technical characteristics of a
typical two-tank indirect TES system.
Table 13. Technical Characteristics of a CSP System
Energy density
~ 155 kJ/kg of molten salta
Power density
Determined by heat-exchanger design
Size of typical installations
Power: 50 MW, Energy: 350 MWh
Thermal storage efficiency
Response time (to bring thermal energy from storage to
the steam generator)
~ 10 minutes
Decay (of stored energy)
30 years (same as lifetime of power plant)
Source: U. Herrman and D. Kearney, “Survey of Thermal Energy Storage for Parabolic Trough Power Plants,”
Journal of Solar Energy Engineering, No. 124, 2002, pp.145-152.
This value (for a trough) is roughly one-third of that for current power towers.
A. Gil, et al. 2010.
Performance measurements from the Solar Two plant estimated a daily loss of about 3.4% of thermal energy,
representing a >96% storage efficiency for a plant cycled daily. The report estimates that that a commercial plant would
experience annual storage losses of less than 1% due to the higher volume to surface area ratio of the storage tanks and
the fact that most stored energy is used the same day. J. E. Pacheco, Editor, Final Test and Evaluation Results from the
Solar Two Project, SAND2002-0120, Sandia National Laboratories, January 2002.
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One recent estimate for the cost of two-tank indirect molten salt TES in a trough system is
approximately $240/kWh of electricity output.426 For a two-tank direct molten salt power tower,
the cost estimate is $72/kWh. The higher temperature and other aspects of towers result in the use
of about one-third the amount of molten salt compared to troughs. While these costs are lower
than those for most other storage technologies, a direct comparison is of limited value since TES
must be tied to a single solar plant. The cost of CSP plants is typically compared to a
conventional alternative, such as a combined-cycle natural gas plant, while potentially
considering the added benefits of zero-emissions and fuel security. One estimate for the levelized
cost of electricity for a trough plant is about 19 ¢/kWh (2009 dollars).
In 2009, the DOE set a goal to establish CSP technology as competitive with conventional
intermediate-load generation technologies by 2020.427 The targeted cost of energy was
approximately 8-12 ¢/kWh, depending on market conditions.428 In 2011, the DOE officially
unveiled the SunShot Initiative, an aggressive R&D plan to make large-scale solar energy
systems cost competitive without subsidies by 2020. The SunShot Initiative takes a systems-level
approach to revolutionary, disruptive (as opposed to incremental) technological advancements in
the field of solar energy. The goal of the SunShot Initiative is reaching cost parity with baseload
energy rates, which would pave the way for rapid and large-scale adoption of solar electricity
across the United States.
Cost reduction of current CSP technologies will result, in part, from economies of scale and from
learning due to increased production and deployment of CSP systems. But a significant fraction
of cost reduction will also need to come from improvements in performance and costs of the solar
field, as well as TES. Once of the key drivers in the cost of TES is the relatively small
temperature difference between the cold and hot fluid in the storage system which increases the
volume of storage medium required.429 A variety of options for cost reduction and technology
improvements exist as discussed in the following section.
In general, very little operations and maintenance (O&M) should be required for the TES
systems. However, reliability of certain components such as the molten salt pumps may affect the
long-term O&M for TES. The Andasol plants in Spain started operating in 2009. O&M costs for
TES are currently being determined at these plants; it will require several years of operation
before they can be accurately assessed.
C. Turchi, M. Mehos, C.K. Ho, and G. J. Kolb, “Current and Future Costs for Parabolic Trough and Power Tower
Systems in the U.S. Market,” Conference Paper, NREL/CP-5500-49303, National Renewable Energy Laboratory,
October 2010.
Ibid.; For additional information about cost improvement potential, see Sargent & Lundy LLC, “Assessment of
Parabolic Trough and Power Tower Solar Technology Cost and Performance Forecasts,” subcontractor report,
NREL/SR-550-34440, National Renewable Energy Laboratory, October 2003.
C. Kutscher, et al., Line-Focus Solar Power Plant Cost Reduction Plan (Milestone Report, No. TP-5500-48175,
National Renewable Energy Laboratory, 2010.
C. Turchi, “Parabolic Trough Reference Plant for Cost Modeling with the Solar Advisor Model (SAM),” NREL/TP550-47605, National Renewable Energy Laboratory, July 2010.
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Research and Development
A major focus on TES research and development is developing new TES materials and storage
methods. As noted above, the DOE has prepared roadmaps for line-focus and power tower
technologies, identifying and prioritizing Technology Improvement Opportunities (TIOs) to help
meet program cost goals.430 The TIOs with greatest importance are the following:
High-temperature heat transfer fluids (HTFs) with freeze protection,
Low-cost storage fluids and media,
High-energy-density phase-change materials (PCMs) and storage fluid, and
High-energy-density thermochemical TES.
Alternative TES materials, including phase-change materials, graphite, and concrete each offer
some combination of greater stored energy density and lower cost. These materials are currently
not in use but are being developed as advanced storage materials. Ceramic particles, graphite, and
concrete are typically used in a thermocline system because these materials store thermal energy
as solids and cannot be transferred easily like a molten salt or other fluid. A thermocline is a
storage system in which the storage medium (solid) is stationary in a packed bed or monolithic
structure.431 A heat transfer fluid flows through the bed or structure and transfers thermal energy
to and from the solid storage material as the system is charged and discharged. These materials
are generally low cost, but control of this type of storage system is difficult and can lead to losses
in plant efficiency.
Research efforts in the United States on advanced CSP thermal storage materials include
activities at NREL, Sandia, and through the Funding Opportunity Announcement (FOA) awards
granted to 18 recipients by the DOE in 2007 and 2008.432 Table 14 shows a list of the FOAs,
being performed by a combination of universities and companies, categorized by TIO. This list
indicates that there are a large number of pathways that may improve the performance of TES
J.A. Gary, et al., “Development of a Power Tower Technology Roadmap For DOE,” SAND2010-5279C, Sandia
National Laboratories, 2010.
G. J. Kolb, “Evaluation of Annual Performance of 2-Tank and Thermocline Thermal Storage for Trough Plants,”
Journal of Solar Energy Engineering, Vol. 133, No. 3, August 2011.
J. Stekli, “DOE CSP R&D: Storage Award Overview,” slide presentation, U.S. Department of Energy, April 28,
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Table 14. U.S. Department of Energy FOA Projects
Technology Improvement Opportunities
Institution (Research Area)
Increased Temperature Differential (∆T)
Abengoa Solar (Molten-salt HTF)
Skyfuel (High-temperature linear Fresnel)
Solar Millennium (High-temperature collector)
Halotechnics (Eutectic salt formulations)
Low-cost media
Acciona (Sensible, direct TES)
University of Arkansas (High-temperature concrete)
U.S. Solar Holdings (Thermocline demonstration)
U.S. Solar Holdings (Sand-shifter demonstration)
High-energy-density PCMs
Lehigh University (Encapsulated PCMs)
Terrafore (Off-eutectic formulations)
University of Connecticut (PCM thermosyphons)
Abengoa Solar (Cascading PCMs)
Infinia (PCMs for dish/Stirling)
Acciona (PCMs with agitation)
Low-cost storage fluids/media
University of Alabama (Low-melting-point, low-cost salts)
High-energy-density storage fluid
Texas A&M University (Storage nanofluids)
High-energy-density thermochemical TES
General Atomics (High-temperature thermochemical TES)
Source: J. Stekli, 2010.
Deployment of advanced TES could contribute significantly to cost reduction for CSP/TES
systems. Table 15 shows the results of an analysis of potential reduction in levelized cost of
energy (LCOE) related to technology improvement opportunities in thermal energy storage.
Table 15. Potential Cost Reductions for CSP/TES Systems
LCOE Reduction
LCOE Reduction
Increased ∆T: 500°C w/o freeze protection
Increased ∆T: 500°C with freeze protection
Low-cost media: thermocline
Low-cost media: sand
High-energy-density phase-change materials
Low-cost storage fluids/media
High-energy-density storage fluid
High-energy-density thermochemical TES
Technology Improvement Opportunity
Source: J. Stekli, 2010.
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Deployment Challenges
The primary barrier to deployment of TES with CSP is more associated with the solar plant than
the thermal storage component. TES is only an option where CSP is deployable—areas with high
direct normal radiation—such as the southwestern United States. Although this region is close to
some major load centers, especially Southern California, it would require large-scale
development of new transmission to provide significant electricity supply to eastern states.
The use of molten salts adds little additional environmental impact or risk beyond a standard CSP
plant. The footprint of the tanks is small compared to the footprint of the solar field. A failure of
the tank would result in a spill that would be contained by a wall or berm. The salt is a solid at
ambient temperatures, so the liquid salt would quickly freeze into a non-hazardous solid.
Material requirements for TES are not expected to be a significant constraint, although large-scale
deployment both in the United States and internationally, combined with usage at the rate
associated with current two-tank systems, could require development of new sources. The molten
salt requirement for a 100 MW trough plant with six hours of storage using a two-tank system is
about 57,000 metric tons, while a tower system would require about a third of this amount.433
Deployment of thermoclines would also substantially reduce this requirement. Much of the
world’s nitrate salts are derived from deposits in the Atacama region of Chile. Proven reserves are
29.4 million metric tons, although this figure is based on exploration of only 16% of total
reserves.434 An alternative source of nitrite salts could include synthetic production via the HaberBosch process, used worldwide for fertilizer production, while entirely new TES materials could
also provide alternatives to molten salts.
Thermal energy storage is a commercially available option for large-scale deployment, featuring
higher efficiency than most other electricity storage technology, although tied to a single
application with significant geographical constraints. Deployment of TES is dependent on costcompetitiveness of CSP, and significant cost barriers remain to achieving large-scale deployment
of TES with CSP. However, there are multiple pathways to improve CSP plant efficiency and
reduce the delivered cost of energy via higher-temperature parabolic troughs and power tower
technologies. Higher-temperatures also increase the storage capacity of the TES system. The
currently operating plants are expected to demonstrate good reliability and performance.
Assuming this positive outcome, and success in efforts to increase technical performance,
CSP/TES will continue be a viable option to decrease the variability and increase the
dispatchability of the solar resource in areas where CSP is economically viable.
J.J. Burkhardt III, G. A. Heath, and C.S. Turchi, “Life Cycle Assessment Of A Parabolic Trough Concentrating
Solar Power Plant And The Impacts Of Key Design Alternatives,” Environmental Science & Technology, Vol. 45, No.
6., 2011, pp. 2457-2464.
Sociedad Quimica y Minera de Chile S.A. (SQM)., Form 20-F for U.S. Securities & Exchange Commission, June
30, 2010.
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Chapter 13: Superconducting Magnetic Energy
Superconducting magnetic energy storage (SMES) devices store energy in the form of a magnetic
field. Using superconducting wires allows SMES units to achieve very high efficiencies.
Superconducting materials are characterized by the temperature required to achieve
superconductivity: low-temperature or high-temperature. Low-temperature superconductors,
which require expensive liquid helium, have been used in most SMES demonstrations. Recent
SMES research and development have focused on developing high-temperature SMES devices,
which could use less costly liquid nitrogen and therefore, could have lower overall system costs
that the low-temperature SMES devices demonstrated to date.435 While low-temperature SMES
devices have been demonstrated, their costs have been greater than those of proposed hightemperature systems.436
There have been several SMES demonstration projects for quick-response and very short-term
capacity applications, primarily for electric grid power quality.437 Commercial SMES units
typically have relatively large power capacities (on the order of several MW), but short discharge
times on the order of 1 second, because the high cost of superconducting coils and cryocoolers
limits amount of energy stored. One example is a set of 3 MW/0.8 kWh distributed SMES units
built in 2000 by the American Semiconductor company for Wisconsin Public Service Corporation
to enhance voltage stability in northern Wisconsin.438 Other utilities have purchased similar units
to provide voltage stability and power quality, and to defer the construction of new transmission
lines. Since the distributed SMES units are trailer-mounted, they can be optimally sited at
locations on the grid where they are most needed. Distributed SMES systems have also been
installed in industrial applications, primarily to eliminate voltage sags in manufacturing power
supplies.439 The cost of SMES is currently very high, however; significant reductions are needed
to show an economic advantage over alternatives including batteries, capacitors, and power
electronics alternatives.
A.M.Wolsky, “The Status and Prospects for Flywheels and SMES that Incorporate HTS,” Physica C, Vol. 372,
2002, pp.1495-1499; J.-F. Fagnard, et al., “Use of a High-Temperature Superconducting Coil for Magnetic Energy
Storage,” Journal of Physics, Conference Series 43, 2006, pp. 829-832; J.H. Choi et al., “Basic Insulating Design of a
Magnet Coil and a Bobbin for a Conduction Cooled HTS SMES System,” Physica C, Vol. 463, 2007, pp. 1252-1256;
K.C. Seong, “Development of a 600 kJ HTS SMES,” Physica C, Vol. 468, 2008, pp. 2091-2095.
H.C. Freyhardt, “YBaCuO and REBaCuO HTS for Applications,” International Journal of Applied Ceramic
Technology, Vol. 4, No. 3, 2007, pp. 203-216; EPRI/DOE, 2003.
D. Sutanto and K. Cheng, “Superconducting Magnetic Energy Storage Systems for Power System Applications,”
proceedings of the International Conference on Applied Superconductivity and Electromagnetic Devices, Institute of
Electrical and Electronics Engineers, 2009, pp. 377-380; EPRI/DOE, 2003.
J.B. Howe, Distributed SMES: A New Technology Supporting Active Grid Management, Modern Power Systems,
January 22, 2001.
Chubu Electric Power Company, Inc., “Field Testing of Superconducting Magnetic Energy Storage System
(SMES),” press release, February 21, 2003, This is
a 10MW unit at the Sharp Corp. Kameyama Plant.
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SMES devices are large superconducting electromagnets that store energy in a magnetic field
generated by electric current flowing through superconducting magnetic wire. The wire is
typically coiled in loops to form a solenoid. Because superconducting material has no electrical
resistance, very large amounts of current can be sent through these wires, up to a factor or 100500 greater than equivalently sized copper wire.440 This enables very strong magnetic fields
(measured in tens to hundreds of Teslas), and much stronger energy densities than conventional
electromagnets.441 The amount of energy that can be stored in the resulting magnetic field
quadruples for each doubling of current, but also depends on the coil geometry and the magnetic
permeability of the material inside and surrounding the coil.
SMES systems typically consist of four main components: the superconducting coil, the
cryogenic cooling system, the power conditioning system, and the control unit. Superconducting
materials are characterized by the temperature required to achieve superconducting
characteristics. Low temperature superconductors (LTS), like niobium-titanium (NbTi), have been
used in most commercial SMES applications.442 The electromagnetic coils must be cooled to
4.5ºK (-269ºC) to become superconducting, which is typically done with a cryocooler system that
uses liquid helium as the working fluid.443 Liquid helium, with a boiling point of 4.2ºK, is the
only element that is not solid at this low temperature. High temperature semiconductors (HTS),
such as (Bi,Pb)2Sr2Ca2Cu3Ox (BSCCO) and YBa2Cu3Ox (YBCO), are superconductive at the
boiling point of liquid nitrogen (77 ºK).444 The SMES coil is typically made out of LTS materials,
typically NbTi.445 HTS prototypes have been demonstrated using BSCCO, and there is ongoing
work to demonstrate less expensive YBCO coils.446 LTS SMES devices require the coil to be
cooled to about 4.5ºK, whereas HTS SMES devices require cooling to only about 77ºK.447 For
this reason, LTS cryocoolers use liquid helium as the working fluid and HTS cryocoolers use
liquid nitrogen which is far less expensive. In both systems, the cryocooler must be located
outside the area with a strong magnetic field, with a thermally conductive link between the
cryocooler and coil.448 The power electronics unit converts alternating current (AC) electricity
The current carrying capacity of a superconductor is about 300,000 Amps/cm2, whereas the current carrying
capacity of an uncooled copper wire is about 600 Amps/cm2, and the capacity of an actively cooled copper wire is
about 3,000 Amps/cm2; EPRI, 2003.
Tesla is a unit used to characterize the strength of a magnetic field. The Earth’s magnetic field is about 10-5 Teslas
near the surface. A common refrigerator magnet is about 10-3 Teslas.
EPRI/DOE, 2003.
Temperature units are in degrees Kelvin (ºK). The temperature difference measured by one degree K is equal to one
degree C, but the Kelvin scale is zeroed at absolute zero (0 ºK equals about -273 ºC) whereas the Celsius scale is zeroed
at the freezing point of water (0 ºC equals about 273 ºK).
D. Larbalestier et al., “High-Tc Superconducting Materials for Electric Power Applications,” Nature, No. 414, 2001,
pp. 368-377; H.C. Freyhardt, “YBaCuO and REBaCuO HTS for Applications,” International Journal of Applied
Ceramic Technology, No. 4, 2007, pp. 203-216.
EPRI/DOE, 2003.
J.-F. Fagnard, et al. 2006; K.C. Seong et al., 2008; D. Larbalestier et al., 2001; H.C. Freyhardt, 2007.
K.C. Seong et al., 2008.
Y.S. Choi et al., “Cryocooled Cooling System for Superconducting Magnet,” Cryocoolers 15, edited by S.D. Miller
and R.G. Ross, Jr., International Cryocooler Conference, Inc., Boulder, CO, 2009.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
from the electric grid to direct current (DC) electricity to be stored when charging, reversing this
process during discharge.
Typical SMES performance is characterized by short bursts (about 1 second) of power that are
capable of responding very rapidly (less than 0.5 milliseconds) from fault detection, well within
one cycle of power grid frequency.449 SMES devices are designed to provide tens of thousands of
charge/discharge cycles with little or no performance degradation and have long design lifetimes
on the order of 20 years operating continuously.450 Table 16 summarizes key SMES operating
Table 16. SMES Operating Parameters
Operating parameter
SMES capacity density
160 kW/m2
SMES energy density
0.04 kWh/m2
Response rate
< 1 cycle (0.017 seconds)
Instantaneous system efficiency
Round trip efficiency
Up to 95%;
Highly dependent on operating characteristics
Standby energy losses
Design lifetime
20 years
Source: E. Drury, National Renewable Energy Laboratory, 2009. Compiled from EPRI/DOE, 2003; A.M. Wolsky,
2002; H.C. Freyhardt, 2007.
The roundtrip efficiency of an SMES device is based on the instantaneous system efficiency
(including energy conversion losses and standby energy losses) as well as the energy required to
maintain cool temperatures. Instantaneous efficiency has been estimated to range from 96% to
98%, before parasitic and power conversion losses.451 Cryocooler power loads are typically about
1% of nameplate capacity for LTS SMES units.452 Cryocooler loads could decrease by an order of
magnitude or more for HTS SMES units.453 SMES roundtrip efficiencies are also dependent on
how frequently they are charged and discharged. For example, if SMES systems are charged and
discharged every hour, roundtrip efficiency is greater than 95%. If SMES systems discharge once
per day, roundtrip efficiency drops to 73%. However, since commercial SMES applications
provide a capacity resource, and not an energy resource, roundtrip efficiency is far less important
than other factors like capital and operating costs.
J.B. Howe, 2001.
EPRI/DOE, 2003.
EPRI/DOE, 2003.
A.M. Wolsky, 2002.
The power required to remove heat from the superconducting coil increases with decreasing temperature. At 4.5 ºK
(LTS system), about 200 to 1,000 watts of electric power are required to remove one watt of heat seep into the coil
whereas at 77 ºK (HTS system), about 20 watts are required. EPRI/DOE, 2003; K.B. Wilson and D.R. Gedeon, “Status
of Pulse Tube Cryocooler Development at Sunpower, Inc.,” proceedings of the International Cryocooler Conference,
Cambridge, MA, March 29-April 1, 2004, Kluwer Academic/Plenum Press, NY, 2004.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
SMES costs are driven primarily by the cost of the superconductive coil and cryocooler, limiting
the amount of energy that can be stored economically. Power electronics costs are based on the
capacity of the device and range from $195-$325/kW (2009 dollars).454 The superconductive coil
and cryocooler costs scale with the amount of energy to be stored by the SMES device, and range
from $395,000-$740,000/kWh. Figure 37 integrates the capacity-based and energy-based costs
into device cost estimates for a design range of 1 to 30 seconds of energy storage. The cost of a
commercially produced SMES unit (10MW/2.8kWh, 1 second discharge) is estimated at
$215/kW455-$285/kW,456 and is within the lower range of projected costs. Since very few SMES
devices have been built commercially, these costs represent demonstration project costs. It is
likely that future costs could benefit from organizational learning-based cost reductions and by
achieving economies of scale.
Figure 37. Potential SMES Cost Ranges Based on Component Costs
Source: E. Drury, National Renewable Energy Laboratory, 2009. Costs are 2009 dollars, excluding O&M.
SMES costs increase significantly with increasing energy storage. A $1,000/kW SMES device is
likely to have the stored energy capacity to discharge for 3.5-7.5 seconds, and a $2,000/kW
device has a stored energy range of about 8-16 seconds. Unless energy-based costs for SMES
devices achieve significant cost improvements, SMES will likely only compete in power quality
markets. Both the superconductor and cryocooler costs would have to achieve about an order of
magnitude of cost reductions to compete with flywheels and batteries in regulation and reserves
markets, and they would have to achieve several orders of magnitude cost reductions to compete
with compressed air energy storage and pumped storage hydro in diurnal storage applications.
V. Karasik, et al., “SMES for Power Utility Applications: A Review of Technical and Cost Considerations,” IEEE
Transactions on Applied Superconductivity, Vol. 9, 1999, pp. 541-546.
L. Borgard, “Grid Voltage Support at Your Fingertips,” Transmission and Distribution World, October 1, 1999.
EPRI/DOE, 2003.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
O&M costs are not included in Figure 37. Fixed O&M costs have been estimated at $16-$26/kWyr.457 Variable O&M costs have been estimated at about $11-$14/kW-yr,458 of which about
$5/kW-yr is based on the cost of electricity for cooling an LTS system.459 A large fraction of
variable O&M costs are dependent on the electricity costs associated with running cryocoolers.
Research and Development
SMES research and development is focused primarily on developing and demonstrating HTS coil
materials, as well as improving cryocooler design and performance. Several BSCCO HTS storage
devices have been built and demonstrated in laboratories.460 However, no YBCO devices have
been demonstrated, although YBCO has the potential to significantly reduce HTS costs if
fabrication challenges can be overcome.461 Currently, HTS systems remain more expensive than
LTS systems, which remain the commercial standard. Cryocoolers are also an active area of
research, much of which has focused on improving designs to reduce initial capital costs, and
improving performance to reduce cryocooler power loads, and operating costs.462
Deployment Challenges
SMES systems do not use fuel or water, do not contain hazardous chemicals, are emissions free,
and have a relatively small footprint. Additionally, SMES units are frequently designed to be
mobile.463 One challenge in siting a SMES resource is limiting human exposure to strong
magnetic fields.464 Magnetic field exposure can be managed through magnetic shielding (using
passive material shielding, or active shielding with a compensating magnetic coil) or by siting the
SMES resource on enough land to limit human exposure.
It is not likely that material constraints will limit SMES deployment. LTS superconductors
require niobium and titanium. Niobium is rare, but annual niobium production is tens of
thousands of tons, which is more than sufficient for potential SMES applications. Titanium is a
fairly common earth element mined at a rate of millions of tons annually. The elements required
for the HTS material YBCO are not rare, and will not limit deployment.
SMES systems are likely to be limited to power quality applications in utility and industrial
markets. SMES costs are primarily driven by the cost of superconducting coils and cryocoolers.
These costs would have to decrease by at least an order of magnitude for SMES to compete in
EPRI/DOE, 2003.
EPRI/DOE, 2003.
A.M. Wolsky, 2002. Cost estimate based on wholesale electricity rates for Wisconsin Public Service Corporation.
A.M. Wolsky, 2002; J.-F. Fagnard et al., 2006; Y.S. Choi et al., 2007; H.C. Freyhardt, 2007; K.C. Seong et al.,
D. Larbalestier et al., 2001; H.C. Freyhardt, 2007.
K.B. Wilson and D.R. Gedeon; 2004; K.C. Seong et al., 2008; Y.S. Choi et al., 2009.
EPRI/DOE, 2003.
C. Polk, R.W. Boom, and Y.M. Eyssa, “Superconductive Magnetic Energy Storage (SMES) External Fields and
Safety Considerations,” IEEE Transactions on Magnetics, No. 28, 1992, pp. 478-481.
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frequency regulation and reserve markets, and by several orders of magnitude to compete in
diurnal storage markets.
SMES research and development are currently focused on developing and demonstrating high
temperature superconductor materials for the electromagnetic coil, as well as improving
cryocooler design and performance. HTS units have historically used BSCCO materials, and
there is also the potential to demonstrate the use of less costly HTS materials like YBCO.
Currently, HTS magnetic energy storage systems are more expensive than low temperature
superconducting LTS systems, which remain the commercial standard. There is considerable
effort on developing and demonstrating new HTS materials across several fields. SMES costs will
benefit from future advancements driven by developments in related fields. However, HTS costs
will have to decrease substantially for SMES to compete in energy-intensive storage markets.
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Appendix. Table of Acronyms
AC - alternating current
AFC - alkaline fuel cell
ARPA-E - Advanced Research Projects Agency – Energy
ARRA - American Recovery and Reinvestment Act
BSCCO - bismuth strontium calcium copper oxide (type of superconductor)
CAES - compressed air energy storage
CAISO - California Independent System Operator
CEC - California Energy Commission
CER - charging electricity ratio
CSP - concentrating solar power
CT - combustion turbine
DC - direct current
DMFC- direct methanol fuel cell
DoD - depth of discharge
DOE - Department of Energy
EC - electrochemical capacitors
EPRI - Electric Power Research Institute
ERCOT - Electric Reliability Council of Texas
EV - electric vehicle
FCEV - fuel cell electric vehicle
FERC - Federal Energy Regulatory Commission
FOA - funding opportunity announcement
GW - gigawatts
HEV - hybrid electric vehicle
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HHV - higher heating value
HTF - heat-transfer fluid
ISO - Independent System Operator
ITC - investment tax credit
KOH - potassium hydroxide
kW - kilowatt
kWh - kilowatt hour
Li-Ion - lithium-ion
LTS - low temperature superconductor
MCFC - molten carbonate fuel cell
MWh - megawatt hour
NaS - sodium sulfur
NERC - North American Electric Reliability Corporation
NiMH - nickel metal hydride
NOx - nitrogen oxides
NREL - National Renewable Energy Laboratory
NYSERDA - New York State Energy Research and Development Authority
O&M - operations and maintenance
OCC - overnight construction cost
PAFC - phosphoric acid
PEM - polymer electrolyte membrane
PEMFC - proton exchange membrane fuel cells
PHEV - plug-in hybrid electric vehicles
PHS - pumped hydro storage
PSI - pounds per square inch
R&D - research and development
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RD&D - research, development, and deployment
RTO - regional transmission organization
SLI - starting, lighting, and ignition
SMES - superconducting magnetic energy storage
SOFC - solid oxide fuel cell
T&D - transmission and distribution
TES - Thermal energy storage
TIO - technology improvement opportunities
TOU - time of use
TWh - terrawatt hour
UPS - uninterruptible power supply
V2G - hehicle-to-grid
VG - variable generation
VMT - vehicle mile traveled
VOC - volatile organic compound
WWSIS - Western Wind and Solar Integration Study
YBCO - yttrium barium copper oxide (type of superconductor)
Author Contact Information
Paul W. Parfomak
Specialist in Energy and Infrastructure Policy
[email protected], 7-0030
Congressional Research Service
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