Department of Energy: Key Challenges Remain for Developing and
Deploying Advanced Energy Technologies to Meet Future Needs
(20-DEC-06, GAO-07-106).
Despite periodic price shocks and related energy crises, the
United States is even more dependent on crude oil and natural gas
than it was almost 30 years ago. And, without dramatic change,
the nation will become ever more reliant on imported oil and
natural gas with attendant threats to national security. The
nation has also become concerned about global warming, which has
been linked to carbon dioxide emissions from burning coal and
oil. To address these concerns, the Department of Energy (DOE)
has funded research and development (R&D) on advanced renewable,
fossil, and nuclear energy technologies. GAO examined the (1) R&D
funding trends and strategies for developing advanced energy
technologies, (2) key barriers to developing and deploying
advanced energy technologies, and (3) efforts of the states and
six selected countries to develop and deploy advanced energy
technologies. GAO reviewed DOE R&D budget data and strategic
plans and interviewed DOE officials and scientists, U.S. industry
executives, independent experts, and state and foreign government
officials.
-------------------------Indexing Terms-------------------------
REPORTNUM: GAO-07-106
ACCNO: A64346
TITLE: Department of Energy: Key Challenges Remain for
Developing and Deploying Advanced Energy Technologies to Meet
Future Needs
DATE: 12/20/2006
SUBJECT: Alternative energy sources
Budget authority
Cost analysis
Crude oil
Energy conservation
Energy consumption
Energy costs
Energy industry
Energy legislation
Natural gas
Nuclear energy
Renewable energy sources
Research and development
Tax expenditures
Policies and procedures
Supply and demand
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GAO-07-106
* [1]Results in Brief
* [2]Background
* [3]DOE's Budget Authority for Renewable, Fossil, and Nuclear En
* [4]DOE's Budget Authority for Renewable, Fossil, and Nuclear En
* [5]DOE's Renewable R&D Focuses on Innovations in Ethanol, Wind,
* [6]Ethanol
* [7]Wind
* [8]Solar
* [9]Hydrogen
* [10]Geothermal
* [11]Hydropower
* [12]DOE's Fossil R&D Program Has Focused on Reducing Harmful Emi
* [13]Coal
* [14]Oil and Natural Gas
* [15]DOE's Nuclear R&D Goals Recently Have Focused on Restarting
* [16]Advanced Renewable, Fossil, and Nuclear Energy Technologies
* [17]Renewable Energy Technologies Face a Variety of Technical an
* [18]Ethanol
* [19]Wind and Solar
* [20]Barriers to Advanced Fossil Technologies Include Harmful Emi
* [21]Advanced Nuclear Energy Technologies Face Uncertainty about
* [22]The States and Countries We Reviewed Have Implemented a Vari
* [23]States Are Stimulating Renewable Energy through Standards, M
* [24]Some States Are Offering Incentives to Encourage the Deploym
* [25]The Countries We Reviewed Have Stimulated the Development an
* [26]Brazil Has Displaced 40 Percent of Its Gasoline
Consumption
* [27]Denmark's Wind Energy Generates 19 Percent of Its
Electricit
* [28]Germany's Renewable Energy Technologies Generate 10
Percent
* [29]Japan Has Installed over 931 Megawatts of Residential
Solar
* [30]Spain Began Operating an IGCC Coal Gasification Plant in
199
* [31]France's Advanced Nuclear Reactor Is Scheduled to Begin
Oper
* [32]Conclusions
* [33]Recommendation to the Congress
* [34]Agency Comments
* [35]Appendix I: Estimated Federal Tax Expenditures Targeted at E
* [36]Appendix II: Scope and Methodology
* [37]Appendix III: The States' Use of Renewable Energy Incentives
* [38]Appendix IV: Three States' Initiatives to Stimulate the Use
* [39]Minnesota's Ethanol Program
* [40]Texas' Renewable Portfolio Standards
* [41]California's Solar Programs
* [42]Appendix V: Comments from the Department of Energy
* [43]Appendix VI: GAO Contact and Staff Acknowledgments
* [44]GAO Contact
* [45]Staff Acknowledgments
* [46]Order by Mail or Phone
Report to Congressional Requesters
United States Government Accountability Office
GAO
December 2006
DEPARTMENT OF ENERGY
Key Challenges Remain for Developing and Deploying Advanced Energy
Technologies to Meet Future Needs
GAO-07-106
Contents
Letter 1
Results in Brief 5
Background 8
DOE's Budget Authority for Renewable, Fossil, and Nuclear Energy R&D Has
Declined by over 85 Percent in Real Terms Since 1978; DOE Is Narrowing Its
R&D Focus 11
Advanced Renewable, Fossil, and Nuclear Energy Technologies Face Key
Barriers to Market Deployment 26
The States and Countries We Reviewed Have Implemented a Variety of
Initiatives to Encourage the Development and Deployment of Energy
Technologies 42
Conclusions 53
Recommendation to the Congress 54
Agency Comments 54
Appendix I Estimated Federal Tax Expenditures Targeted at Energy Suppliers
and Users, Fiscal Year 2006 56
Appendix II Scope and Methodology 58
Appendix III The States' Use of Renewable Energy Incentives, Standards,
and Mandates 61
Appendix IV Three States' Initiatives to Stimulate the Use of Renewable
Energy Technologies 63
Appendix V Comments from the Department of Energy 67
Appendix VI GAO Contact and Staff Acknowledgments 68
Tables
Table 1: Comparison of Conventional Pulverized Coal and IGCC Technologies
21
Table 2: Comparison of Electricity Generating Costs Using Nuclear, Coal,
and Natural Gas Energy Sources 38
Table 3: Comparison of Electricity Generating Costs Assuming a Carbon
Emissions Tax 39
Figures
Figure 1: Comparison of the U.S. Energy Portfolio in 1973 and 2004 9
Figure 2: Projected U.S. Electricity Generation by Energy Source,
2005-2030 10
Figure 3: DOE's Budget Authority for Renewable, Fossil, and Nuclear R&D,
Fiscal Years 1978 through 2005 13
Figure 4: DOE's Budget Authority for Renewable, Fossil, and Nuclear R&D,
Fiscal Year 2006 14
Figure 5: Distribution of State Incentives and Policies for Renewable
Energy 43
Figure 6: Number of States Using Each of 12 Renewable Standards, Mandates,
and Incentives 45
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Abbreviations
AFCI Advanced Fuel Cycle Initiative
DOE Department of Energy
EIA Energy Information Administration
EPA Environmental Protection Agency
GNEP Global Nuclear Energy Partnership
IGCC integrated gasification combined cycle
MIT Massachusetts Institute of Technology
NRC Nuclear Regulatory Commission
RPS renewable portfolio standards
R&D research and development
United States Government Accountability Office
Washington, DC 20548
December 20, 2006 December 20, 2006
The Honorable Bart Gordon
Ranking Member
Committee on Science
House of Representatives
The Honorable Michael M. Honda
Ranking Member
Subcommittee on Energy
Committee on Science
House of Representatives
Since 1974, the nation has been subjected to periodic disruptions of crude
oil imports resulting in price shocks and related energy crises. Oil
prices doubled in 1974 and doubled again between 1978 and 1980. These
price shocks alerted the nation to our growing dependence on imported oil
and the need to conserve energy and develop alternative energy sources.
Yet, when world crude oil prices plunged in the mid-1980s, the United
States continued to rely on oil, and U.S. energy companies reduced their
investments in developing alternative energy technologies. More recently,
crude oil prices more than doubled--gasoline prices exceeded $3 per gallon
in August 2006--as a result of increased world consumption, hurricanes in
the Gulf of Mexico, and instability in the Middle East and other oil
producing regions. However, by October 2006, crude oil prices had once
again declined, though at higher levels than previously. Despite these
periodic price shocks and related energy crises, the United States'
dependence on imported crude oil and natural gas continues to
increase--crude oil imports have grown from 40.5 percent of the U.S.
supply in 1980 to 65.5 percent of the U.S. supply in 2005, according to
the Energy Information Administration (EIA), within the Department of
Energy (DOE). Without dramatic change, the United States is likely to
become ever more reliant on imported oil and natural gas with all the
attendant threats to the U.S. economy and national security. Since 1974,
the nation has been subjected to periodic disruptions of crude oil imports
resulting in price shocks and related energy crises. Oil prices doubled in
1974 and doubled again between 1978 and 1980. These price shocks alerted
the nation to our growing dependence on imported oil and the need to
conserve energy and develop alternative energy sources. Yet, when world
crude oil prices plunged in the mid-1980s, the United States continued to
rely on oil, and U.S. energy companies reduced their investments in
developing alternative energy technologies. More recently, crude oil
prices more than doubled--gasoline prices exceeded $3 per gallon in August
2006--as a result of increased world consumption, hurricanes in the Gulf
of Mexico, and instability in the Middle East and other oil producing
regions. However, by October 2006, crude oil prices had once again
declined, though at higher levels than previously. Despite these periodic
price shocks and related energy crises, the United States' dependence on
imported crude oil and natural gas continues to increase--crude oil
imports have grown from 40.5 percent of the U.S. supply in 1980 to 65.5
percent of the U.S. supply in 2005, according to the Energy Information
Administration (EIA), within the Department of Energy (DOE). Without
dramatic change, the United States is likely to become ever more reliant
on imported oil and natural gas with all the attendant threats to the U.S.
economy and national security.
EIA projects that total U.S. energy demand will increase by about 28 to 35
percent between 2005 and 2030. Specific sectors reflect even more dramatic
growth in energy demand: (1) the transportation sector is expected to grow
by 43 percent, with annual crude oil consumption increasing from about 4.8
billion barrels in 2004 to about 6.8 billion barrels by 2030 (a barrel of
oil is equivalent to 42 gallons of gasoline), and (2) the EIA projects
that total U.S. energy demand will increase by about 28 to 35 percent
between 2005 and 2030. Specific sectors reflect even more dramatic growth
in energy demand: (1) the transportation sector is expected to grow by 43
percent, with annual crude oil consumption increasing from about 4.8
billion barrels in 2004 to about 6.8 billion barrels by 2030 (a barrel of
oil is equivalent to 42 gallons of gasoline), and (2) the electricity
sector is expected to grow by 50 percent, with electricity consumption
increasing from about 3.6 billion megawatt-hours in 2004 to about 5.3
billion megawatt-hours by 2030 (a megawatt-hour is sufficient to meet the
demand of 750 households for 1 hour). EIA projects that the proportions of
energy derived from renewable, fossil, and nuclear sources for both
transportation and electricity generation will remain about the same
through 2030.
Since its creation in 1977, DOE has had leadership responsibility for
energy research, development, and demonstration programs (R&D) to enable
the nation to deploy advanced energy technologies for meeting future
demands and diversifying its energy portfolio.^1 During the past 29 years,
the Congress has provided DOE about $50 billion for R&D in renewable,
fossil, and nuclear energy technologies.^2 Specifically:
o DOE's renewable energy R&D program has primarily focused on (1)
developing cost-effective technologies for producing ethanol from
biomass sources, such as agricultural residues and forest waste,
and (2) making wind and solar energy technologies more
cost-competitive sources of electricity. DOE has also funded R&D
for geothermal and hydropower energy technologies and, in 2003,
accelerated the R&D funding for developing hydrogen technologies.
o DOE's fossil energy R&D program has primarily focused on
reducing emissions of harmful pollutants from coal-fired power
plants, particularly sulfur dioxide and nitrogen oxide in the
1980s and early 1990s. More recently, DOE has concentrated on
developing (1) coal gasification technologies to improve
efficiency and reduce mercury and carbon dioxide emissions and (2)
sequestration technologies for the long-term storage of carbon
dioxide.
o DOE's nuclear energy R&D program has focused primarily on
improving nuclear power plant safety--in response to the March
1979 accident at the Three Mile Island plant near Harrisburg,
Pennsylvania--and efficiency.^3 More recently, the program has
focused on developing technologies and designs for new generations
of nuclear reactors --so-called Generation III and Generation IV.
Beginning in October 2007, electric power companies are expected
to apply for the first licenses to construct nuclear reactors
since 1979. These reactors will use Generation III technologies.
DOE's nuclear R&D program is developing Generation IV technologies
for deployment after 2020.
The market has been slow to embrace advanced energy technologies
because they typically are not economically competitive with
conventional energy sources such as oil, natural gas, and coal. In
part this is because the prices U.S. consumers pay for
conventional energy do not reflect their true costs, including the
costs of certain adverse environmental impacts; economists refer
to these hidden costs as negative externalities. For example, we
continue to rely on electricity generated from coal-fired plants
because coal is plentiful and inexpensive in the United States.
However, carbon dioxide emissions from coal-fired power plants--a
key concern for global warming--are not currently regulated, and
thus potential environmental costs associated with global warming
are not reflected in the electricity prices that consumers pay. In
contrast, renewable energy sources, such as wind farms, and
nuclear reactors do not produce carbon dioxide emissions in
generating electricity.
The American Jobs Creation Act of 2004 stimulated the deployment
of ethanol by providing a 51-cent tax credit through December 31,
2010, for every gallon of ethanol blended into gasoline.^4 The act
also provides tax credits that expire on December 31, 2006, for
every gallon of biodiesel and agri-biodiesel. Similarly, the
Energy Policy Act of 2005 promoted a diversified U.S. energy
portfolio by reauthorizing DOE's R&D funding and providing tax
incentives for stimulating investment in advanced renewable,
fossil, and nuclear energy technologies.^5 Specifically, the
Energy Policy Act of 2005 extended the production tax credit
established in the Energy Policy Act of 1992 for renewable
technologies for 2 years until January 1, 2008. The act also added
a new (1) investment tax credit of up to $1.3 billion for
constructing new clean-coal power plants and (2) production tax
credit of 1.8 cents per kilowatt-hour for up to 6,000 megawatts of
new nuclear power capacity lasting 8 years after each qualifying
nuclear reactor begins service. These tax credits and other tax
incentives are legally known as tax expenditures;^6 revenue losses
from these tax incentives can be viewed as spending channeled
through the tax system. Historically, the tax subsidies that the
U.S. government has provided to the energy sector have been
directed toward the conventional energy sector. More recently, tax
incentives available in fiscal year 2006, such as the new
technology tax credits, have also been directed toward stimulating
the development and deployment of advanced energy technologies
(see app. I).
You asked that we assess the nation's ability to meet its energy
needs through 2030 by examining DOE's efforts to diversify the
nation's energy portfolio and reduce its dependence on oil and
natural gas. Specifically, we examined (1) DOE's R&D funding
trends and strategies for developing advanced renewable, fossil,
and nuclear energy technologies; (2) the key barriers to
developing and deploying technologies that will address the
nation's future energy needs; and (3) the efforts of states and
selected countries to develop and deploy renewable, fossil, and
nuclear energy technologies that address future energy needs.
To ensure that we obtained a balanced view of future U.S. energy
challenges, we reviewed documents and interviewed DOE officials,
including program managers and laboratory scientists; senior
industry executives; independent experts; officials of several
state governments and states' associations; and representatives of
foreign governments and industry associations. More specifically,
to review DOE's R&D funding trends and strategy for developing
advanced energy technologies, we analyzed DOE's (1) budget
authority data for renewable, fossil, and nuclear energy R&D from
fiscal year 1978 through fiscal year 2006, adjusted for any
advanced appropriations and rescissions, and (2) strategic plans
for developing and deploying new energy technologies. For
perspective, we also reviewed revenue losses due to energy-related
tax expenditures for fiscal years 2000 through 2006. To assess the
key technological, economic, and other barriers, we analyzed
various energy studies and interviewed senior officials at DOE and
the Nuclear Regulatory Commission (NRC), which regulates the
construction and operations of nuclear power plants, industry
executives, and independent experts. To examine the efforts of
states and selected countries to develop and deploy advanced
energy technologies, we identified their use of mandates,
financial incentives, and other actions. We selected Brazil,
Denmark, France, Germany, Japan, and Spain because they have
initiated major nationwide programs to stimulate the deployment of
advanced energy technologies that have changed, or could change,
their energy portfolios. We found that the data we used to examine
trends and states' efforts to develop and deploy energy
technologies to be sufficiently reliable for our purposes. We
conducted our work from October 2005 through October 2006 in
accordance with generally accepted government auditing standards.
(See app. II for further information about our scope and
methodology.)
Results in Brief
Despite growing dependence on foreign energy sources, DOE's R&D
budget authority for renewable, fossil, and nuclear energy
technologies declined by over 85 percent (in real terms) between
fiscal years 1978 and 2005. Specifically, DOE's R&D budget
authority dropped from about $5.5 billion (in real terms) in
fiscal year 1978 to $793 million in fiscal year 2005. Budget
authority for renewable, fossil, and nuclear energy R&D peaked in
the late 1970s before falling sharply in the mid 1980s when crude
oil prices returned to lower levels. As funding has shrunk, DOE's
R&D focus has narrowed. For example, DOE's renewable R&D program
has focused on ethanol, wind, and solar technologies, making
steady incremental progress in reducing their costs over the past
29 years. DOE's fossil R&D program has focused primarily on
reducing harmful emissions of coal-fired power plants, working
with industry to make significant progress in reducing sulfur
dioxide and nitrogen oxide pollution during the 1980s and 1990s.
Currently, DOE is using coal gasification technologies to reduce
mercury and carbon dioxide emissions and achieve the long-term
goal of a "near-zero emissions" power plant. From 1978 through
1998, DOE's nuclear R&D program focused on making incremental
improvements in nuclear power plant safety and efficiency. Since
1998, DOE's nuclear R&D program shifted its focus to developing
"next generation" nuclear facilities for reprocessing spent fuel,
developing advanced nuclear reactors that produce hydrogen and
reduce waste, and producing more efficient nuclear fuels. Faced
with competing R&D priorities and budget constraints, DOE's fiscal
year 2007 budget proposed eliminating R&D funding for its
geothermal, hydropower, oil, and natural gas programs.
Advanced renewable, fossil, and nuclear energy technologies all
face key barriers to their development and deployment. Among
renewable energy technologies, for ethanol to garner a significant
share of the U.S. gasoline market, ethanol producers need to
deploy cost-competitive technologies for processing agricultural
residues and other biomass materials; it is unclear whether
ethanol from corn alone can achieve this result. Widespread
deployment of ethanol also faces infrastructure challenges--in
particular, transporting and storing ethanol and retrofitting
gasoline station pumps. Barriers to electricity generation from
renewable sources--primarily wind and solar--include the
difficulty of efficiently converting renewable energy into
electricity, high up-front capital costs, including connection to
the electric power transmission grid; the intermittent nature of
wind and solar energy; and the higher financial risks associated
with gaps in the renewal of the production tax credit. In
addition, renewable energy technologies must compete with
traditional fossil energy sources whose greater environmental
costs are not reflected in the price paid by consumers, and
renewable energy R&D budgets have been subject to growing
congressional earmarks in recent years. For advanced fossil
technologies, the primary challenge continues to be controlling
emissions of mercury and carbon dioxide generated by conventional
coal-fired plants. However, reducing these emissions requires
plants to use new coal gasification technologies, which cost about
20 percent more to construct than conventional coal-fired plants
and carry higher perceived investment risk as new technologies.
Furthermore, DOE and industry have not demonstrated the
technological feasibility of the long-term storage of carbon
dioxide captured by a large-scale, coal-based power plant. For
advanced nuclear technologies, investors face uncertainties about
whether NRC's revised review process for new reactors will
effectively reduce regulatory delays and minimize added costs to
address safety concerns. While public opposition previously was a
primary barrier, the nuclear industry reports that public opinion,
particularly in the southeast United States, is more favorable
reflecting the increased demand for electricity, perceived
advances in safety, and growing concerns about global warming.
Investors also face higher financial risk because of nuclear
reactors' high capital costs and long construction time frames, as
well as environmental and nonproliferation concerns about spent
nuclear fuel.
While federal R&D has declined and the government has relied on
the market to determine whether to deploy advanced energy
technologies, many states have assumed higher profile roles by
enacting standards, mandates, and financial incentives primarily
to stimulate renewable energy technologies that address their
growing energy needs and environmental concerns. In particular, 22
states have established renewable portfolio standards requiring or
encouraging that a fixed percentage of the state's electricity be
generated from renewable sources; 39 states have established rules
for electric power companies to connect renewable energy sources
to the power transmission grid and credit producers for excess
generation; and 45 states offer tax credits, grants, or loans to
stimulate the deployment of renewable energy. Examples of state
initiatives include the following: Since 1980, Minnesota has
enacted various mandates and production incentives to stimulate
the use of ethanol. Minnesota had displaced nearly 10 percent of
all of its gasoline consumption with ethanol by June 2006 and had
nearly one-third of the nation's ethanol fueling stations in
September 2006. Texas' 2005 legislation extended the state's 1999
renewable portfolio standard to require the installation of 5,000
megawatts of new renewable capacity by 2015. As of September 2006,
electric power companies had installed over 1,900 megawatts of new
renewable capacity in Texas--approximately 3 percent of its total
electricity consumption. California's Solar Initiative called for
3,000 megawatts of new solar capacity by 2017. In response, 150
megawatts of new solar capacity have recently been installed. Some
states have also established mandates and financial incentives to
stimulate advanced fossil and nuclear technologies. For example,
2002 legislation in Indiana established investment tax credits for
advanced coal power plants to encourage cleaner coal technologies.
Similarly, Calvert County, Maryland, recently offered a
50-percent, 15-year property tax credit to the owner of the
Calvert Cliffs nuclear power plant if an additional nuclear
reactor is built.
Each of the six countries we reviewed--Brazil, Denmark, Germany,
Japan, Spain, and France--has sustained long-term efforts using
mandates and/or incentives to deploy advanced energy technologies
that are providing, or are expected in the future to provide,
significant amounts of energy. For example, by 2005, Brazil had
eliminated its need to import crude oil for gasoline by using
mandates and price subsidies to stimulate the development of an
ethanol industry that uses domestic sugarcane. Similarly,
Denmark's stimulation of renewable energy has resulted in wind
energy generating 19 percent of total electricity consumed in
2005. Denmark's support of wind energy has also created a thriving
domestic wind turbine industry, which grew from about 200
megawatts to more than 3,000 megawatts in annual global sales over
the past decade. To develop a sustainable energy supply and
protect the environment, Germany established a goal to increase
the share of renewable energy consumption to at least 4.2 percent
of its total energy requirements by 2010 and to 10 percent by
2020. The 2010 target was exceeded in 2005, when renewable
technologies accounted for 4.6 percent of consumption. To reduce
its reliance on imported energy, Japan initiated a 10-year program
subsidizing the cost of residential solar systems. As a result,
solar systems were installed on more than 253,000 homes and the
price of residential solar systems was cut by more than one-half.
Spain, supported in part by a European Union program to promote
cleaner energy technologies, is successfully operating a
320-megawatt coal gasification plant--the largest such plant in
the world--designed to run more efficiently with fewer emissions
than conventional coal-fired plants. France leads the United
States in deploying an advanced Generation III nuclear
reactor--the European Pressurized Reactor--which is designed to be
safer, more efficient, and less susceptible to terrorist attacks
than older reactors, and will also generate nearly 80 percent more
electricity.
To meet the nation's rising demand for energy, reduce its economic
and national security vulnerability to crude oil supply
disruptions, and minimize adverse environmental effects, we
suggest that the Congress consider further stimulating the
development and deployment of a diversified energy portfolio by
focusing R&D funding on advanced energy technologies.
Background
For the past several decades, the United States has enjoyed
relatively inexpensive and plentiful energy supplies, relying on
market forces to determine the energy mix that provides the most
reliable and least expensive sources of energy--primarily oil,
natural gas, and coal. In 1973, oil cost about $15 per barrel (in
real terms) and accounted for 96 percent of the energy used in the
transportation sector and 17 percent of the energy used to
generate electricity.
In 1973, the Organization of Arab Petroleum Exporting Countries
embargoed nations that it believed supported Israel during the Yom
Kippur War. The disruption of oil supplies caused oil prices in
the United States to double between 1973 and 1974, resulting in
long gasoline lines and rationing by the U.S. government. Natural
gas price spikes followed a pattern similar to that of oil. Since
oil and natural gas accounted for about 35 percent of electricity
generation in 1973, electricity prices soared, and consumers
experienced periodic brown outs. Oil disruptions reoccurred with
the 1979 Iranian Revolution and the 1979 to 1981 Iran-Iraq War,
which caused oil prices to double once again from the already
record-high prices, adversely affecting the U.S. economy. Oil and
natural gas prices fell in the mid-1980s, and U.S. reliance on
fossil fuels and, in particular on imported oil, continued as the
U.S. economy expanded and domestic sources of oil declined. By
2004, about 63 percent of U.S. oil was imported and cost $38 per
barrel (in real terms);^7 oil accounted for 98 percent of energy
consumed for transportation, and coal and natural gas accounted
for about 71 percent of the energy used to generate electricity.
As shown in figure 1, the current U.S. energy portfolio is similar
to the energy portfolio in 1973. The primary change is the growth
of the fledgling nuclear energy industry during the 1970s and
1980s, as new nuclear power plants came online and efficiency
improved. However, because nuclear power plants currently operate
at about 90 percent capacity, new growth will occur only when new
reactors are built. In addition, while hydropower makes up the
bulk of energy generated from renewable sources, its share of the
renewable energy has declined because new wind, geothermal, and
solar-generating capacity has been added while hydropower
generation has remained unchanged.
^1DOE is also responsible for energy efficiency programs, which are
integral to addressing future energy challenges by reducing demand.
^2All historical DOE R&D budget authority totals are presented in real
terms by adjusting them to fiscal year 2005 dollars to account for
inflation.
^3The Three Mile Island accident, which involved one of the plant's two
reactors, was the most serious incident at a U.S. commercial nuclear power
plant. While there were no deaths or injuries, the reactor's core began to
melt down, creating widespread concern about health and safety.
^4Pub. L. No. 108-357.
^5Pub. L. No. 109-58.
^6Tax expenditures result in forgone revenue for the federal government
due to preferential provisions in the tax code. See GAO, Government
Performance and Accountability: Tax Expenditures Represent a Substantial
Federal Commitment and Need to Be Reexamined, [47]GAO-05-690 (Washington,
D.C.: Sept. 23, 2005).
Figure 1: Comparison of the U.S. Energy Portfolio in 1973 and 2004
^7In 2006, crude oil prices peaked at nearly $70 per barrel in the United
States.
EIA's model of energy generation in 2030 projects that the United States
will continue to primarily rely on oil to provide most of the energy in
the transportation sector and coal to provide most of the energy for
generating electricity. EIA projects that U.S. electricity generation will
grow from 3,900 billion kilowatt-hours in 2005 to 5,500 billion
kilowatt-hours in 2030 (see fig. 2).
Figure 2: Projected U.S. Electricity Generation by Energy Source,
2005-2030
Note: EIA projects a greater reliance on coal to generate electricity if
oil prices exceed $90 per barrel by 2030 and less reliance on coal and a
slight reduction in renewable energy if oil prices are less than $30 per
barrel by 2030.
In addition to funding energy R&D to develop advanced energy technologies,
DOE has funded efforts to improve energy efficiency and reduce energy
demand. For example, DOE has encouraged energy efficiency by, for example,
establishing energy efficiency standards for home appliances and air
conditioners, and the federal government provides tax credits for
purchasing energy-efficient equipment.
The federal government also provides the energy industry and consumers
with 23 tax expenditures affecting energy supply, some of which are
incentives designed to stimulate the development and deployment of
advanced technologies. From a budgetary perspective, most tax expenditures
are comparable to mandatory spending for entitlement programs because they
require no further action. Tax expenditures do not compete directly in the
annual budget process and, in effect, receive a higher funding priority
than discretionary spending subject to the annual appropriations process.
Some tax expenditures are enacted on a temporary basis, providing an
opportunity for scrutiny before they can be extended.
Currently, the United States does not regulate carbon dioxide emissions,
which contribute to global warming. In 1992, the United States ratified
the United Nations Framework Convention on Climate Change, which was
intended to stabilize the build-up of greenhouse gases, but did not impose
binding limits on greenhouse gas emissions. In 1997, the United States
participated in drafting the Kyoto Protocol, which established some limits
on greenhouse gas emissions but did not ratify the protocol. Many DOE
officials and industry executives told us, however, that the federal
government might begin to regulate greenhouse gas emissions in the future
to address global warming concerns. The Energy Policy Act of 2005
authorized R&D funding for the capture and long-term storage--or
sequestration--of carbon dioxide.
DOE's Budget Authority for Renewable, Fossil, and Nuclear Energy R&D Has
Declined by over 85 Percent in Real Terms Since 1978; DOE Is Narrowing Its R&D
Focus
DOE's budget authority for renewable, fossil, and nuclear energy R&D
dropped from $5.5 billion (in real terms) in fiscal year 1978 to $793
million in fiscal year 2005--a decline of over 85 percent. Energy R&D
budget authority peaked in the late 1970s in response to the Organization
of Arab Petroleum Exporting Countries' oil embargo of 1973 and fell
sharply as crude oil prices plunged in the mid 1980s. However, since
fiscal year 2000, federal support for the energy industry--through DOE's
R&D budget authority and federal revenue losses from energy-related income
tax expenditures--has grown. Since 1978, DOE's renewable energy R&D
program has made incremental progress in making renewable technologies
more efficient and reducing their costs. DOE's fossil energy R&D program
has focused primarily on reducing harmful emissions by coal-fired power
plants. During the 1980s and 1990s, the program made significant progress
in demonstrating technologies that reduce sulfur dioxide and nitrogen
oxide pollutants, and DOE's current objective is to develop a "near-zero
emissions" power plant by targeting mercury and carbon dioxide emissions.
In response to the Three Mile Island accident in 1979, DOE's nuclear
energy R&D program focused on improving the safety and efficiency of
nuclear reactors. More recently, the nuclear energy R&D program has given
priority to (1) encouraging electric power companies to submit the first
applications to NRC in over 30 years for combined licenses to build and
operate a nuclear reactor to generate electricity, (2) developing
technologies for reprocessing spent nuclear fuel that minimize the threat
of spent fuel being used to make nuclear weapons and reduce highly
radioactive waste, and (3) developing advanced Generation IV reactor
technologies. Faced with competing R&D priorities and budget constraints,
DOE has proposed in recent years to concentrate its R&D funding on key
technologies for meeting the nation's growing energy demand while
eliminating funding for geothermal, hydropower, oil, and natural gas
technologies.
DOE's Budget Authority for Renewable, Fossil, and Nuclear Energy R&D Has
Substantially Fallen Since 1978
As shown in figure 3, renewable, fossil, and nuclear energy R&D budget
authority each peaked in the late 1970s before falling sharply in the
1980s. Similarly, energy R&D funding as a percentage of total nondefense
R&D expenditures fell from about 20 percent in the late 1970s to less than
5 percent in fiscal year 2006, according to the American Association for
the Advancement of Science. More recently, total budget authority for the
three energy R&D programs has risen after bottoming out in fiscal year
1998. Budget authority for renewable energy R&D peaked at $1.5 billion (in
real terms) in fiscal year 1979, with most of the funding directed toward
solar energy. Subsequently, renewable R&D budget authority fell, hitting
its lowest point of $144 million (in real terms) in 1990. Fossil energy
R&D budget authority peaked at $1.9 billion (in real terms) in fiscal year
1979 and then has fluctuated. In particular, the Clean Coal Technology
Program, a joint DOE-industry effort to demonstrate technologies that
reduce sulfur dioxide and nitrogen oxide emissions, began in 1985 with
high levels of DOE budget authority in the late 1980s and early 1990s.
Fossil energy R&D budget authority rose in fiscal year 2001, and the
administration introduced its "clear skies" initiative to further reduce
pollution in fiscal year 2002. DOE's nuclear energy R&D program peaked at
$2.4 billion (in real terms) in fiscal year 1978 and then fell through
fiscal year 1998, when the nuclear R&D program received no budget
authority. Since fiscal year 1998, budget authority for nuclear energy R&D
has gradually increased. Similar to DOE's budget authority for energy R&D,
estimated federal revenue losses from energy-related tax expenditures grew
from nearly $2.2 billion (in real terms) in fiscal year 2000 to nearly
$4.9 billion in fiscal year 2005.^8 While many of the new tax expenditures
are for developing and deploying advanced energy technologies, tax
expenditures for conventional energy remain among the largest in terms of
revenue loss. The alternative fuels production credit is the largest
energy-related tax expenditure, with estimated revenue losses of about
$2.4 billion in fiscal year 2006.^9
Figure 3: DOE's Budget Authority for Renewable, Fossil, and Nuclear R&D,
Fiscal Years 1978 through 2005
Note: Budget authority is in real terms, adjusted to fiscal year 2005
dollars to account for inflation. Excludes DOE program management costs
and indirect facilities costs of DOE laboratories.
In fiscal year 2006, the Congress provided about $982 million in budget
authority for energy R&D, including $324 million for renewable energy R&D,
about $434 million for fossil energy R&D, and about $224 million for
nuclear energy R&D (see fig. 4). The biomass, solar, and hydrogen energy
programs received about 80 percent of the renewable energy R&D budget
authority. Similarly, coal R&D programs received more than 80 percent of
the fossil energy R&D budget authority, particularly for developing and
demonstrating advanced gasification technologies--including integrated
gasification combined cycle (IGCC)--mercury capture, and sequestration
technologies. DOE's top nuclear energy R&D priority is to encourage
electric power companies to submit applications to NRC for licenses to
build and operate Generation III nuclear reactors by competitively
awarding funds for preparing early site permits and NRC combined license
applications. The nuclear R&D program also is developing Generation IV
nuclear reactor technologies, especially ones that can reprocess spent
nuclear fuel that reduce both proliferation risks and the amount of waste
generated.
^8Summing tax expenditure estimates is useful to gauge their general
magnitude but does not take into account interactions between individual
provisions.
^9The alternative fuels production credit is a tax credit of $3 per oil
equivalent barrel (in 1979 dollars) for gas produced from biomass or
synthetic fuels produced from coal.
Figure 4: DOE's Budget Authority for Renewable, Fossil, and Nuclear R&D,
Fiscal Year 2006
Note: Budget authority is in fiscal year 2006 dollars. Excludes DOE
program management costs, indirect facilities costs of DOE laboratories,
and funding for fuel cells--historically, an energy efficiency program.
DOE's Renewable R&D Focuses on Innovations in Ethanol, Wind, Solar, and Hydrogen
Energy Technologies
Over the past 29 years, DOE has made steady incremental progress in making
each of the renewable energy technologies more cost-competitive; for
example, DOE and its industry partners have reduced wind energy costs by
more than 80 percent. DOE's renewable energy R&D efforts have focused on
developing ethanol, wind, and solar energy technologies. More recently, in
January 2003, the administration announced the Hydrogen Fuel Initiative
and proposed spending $1.2 billion over 5 years to support research in
hydrogen and fuel cell technologies. While DOE has conducted R&D in
geothermal and hydropower technologies since the late 1970s, the
administration's 2007 budget proposed to eliminate both programs.
Ethanol
DOE's ethanol R&D program, the primary component of its biomass R&D
efforts, is developing technologies to reduce the cost of producing
ethanol, which can be blended with gasoline to reduce harmful exhaust
emissions. In the early years of the biomass program, DOE focused on
developing biofuels and biomass energy systems that primarily relied on
corn as the energy source. As the biomass program evolved, it sought to
make biorefinery-related technologies cost- and performance-competitive.
As of October 2006, 106 biorefineries were operating throughout the United
States to supply (1) oil refineries with ethanol to oxygenate
gasoline--ethanol is a substitute for methyl tertiary-butyl ether (MTBE),
which some states have banned because of concerns about groundwater
contamination, and (2) fuel suppliers with ethanol to produce E85, a blend
of 85 percent ethanol and 15 percent gasoline that can be used in flex
fuel vehicles.^10
The long-term goal of DOE's biomass R&D program is to enable U.S. industry
to produce enough biofuels equivalent to 30 percent of current gasoline
demand--about 60 billion gallons of biofuels per year--by 2030. To meet
this goal, the biomass program is focused on developing additional sources
of ethanol from cellulosic biomass, such as agricultural residues, forest
wastes, and energy crops. According to DOE, producing cellulosic ethanol
is difficult because it requires a complex chemical process to convert the
plant material into a simple sugar to use for ethanol. The biomass program
is also working with industry to demonstrate biorefinery technologies and
assess infrastructure needs.
^10Flex fuel vehicles operate on any blend of ethanol and gasoline, from 0
percent ethanol and 100 percent gasoline, up to 85 percent ethanol and 15
percent gasoline.
Wind
DOE's wind R&D program primarily is focused on developing efficient wind
turbines that convert the wind's power into electrical power.
Historically, DOE's wind program focused on developing wind turbines for
high-wind sites because it was the easiest way to achieve significant
levels of electric power generation. High-wind sites--referred to as Class
6--typically are located in areas where the wind regularly blows from 18
to 20 miles per hour. During the past 29 years, DOE and its industry
partners have made technological improvements that reduced the cost of
wind energy by more than 80 percent, and industry has built wind farms on
many of the high-wind sites that are easily accessible.
DOE's wind R&D program primarily is seeking to develop new cost-effective
technology for deploying wind turbines for low-wind areas in the United
States and exploring the possibility of offshore wind development.
Low-wind sites--referred to as Class 4--generally are located in areas of
sustained winds of 16 to 17 miles per hour and primarily are located in
the Midwest from Texas to the Canadian border. The advantages of
developing low-wind resources are that low-wind sites are far more
plentiful than high-wind sites and are located closer to electricity load
centers, which can substantially reduce the cost of connecting to the
electricity transmission grid. DOE's R&D program is focused on developing
wind turbine technology for low-wind sites because easily accessible
high-wind sites are becoming scarce. Specifically, the turbine rotor
diameter must be much larger to harvest the low-energy winds without
increasing costs, and the tower must be taller to take advantage of the
increasing wind speed at greater heights. DOE is using public/private
partnerships to improve wind turbine designs and components and
demonstrate full-scale prototypes. DOE's goal is to reduce the cost of
low-wind generated electricity from about 4.5 to 5.5 cents per
kilowatt-hour in 2002 to 3.6 cents per kilowatt-hour by 2012.
DOE's wind R&D program is also exploring wind energy technology for the
distinct needs of offshore wind sites. While the United States currently
has no offshore wind farms, several projects have been proposed in the
waters off the Northeast and Gulf coasts. DOE estimates that there are
over 900,000 megawatts of potential wind energy off the coasts of the
United States, roughly between 6 and 58 miles offshore. Several European
countries, including Denmark, Ireland, and the United Kingdom, have
deployed wind farms in the shallow (less than 100 feet deep) waters off
their coastlines using wind turbine designs adapted from land-based
versions. However, the European offshore sites are different from
potential U.S. offshore wind sites, which are generally located in deeper
waters and expected to have more severe wind, wave, and ice conditions. As
a result, many U.S. sites will require new technologies. DOE's offshore
wind R&D activities include mapping coastal wind resources, organizing
workshops for knowledge sharing, and collaborating with industry in
developing offshore technologies to address design, offshore transmission,
and interconnection issues. DOE is also collaborating with European
nations on deep-water wind energy and with states to identify the
regulatory, environmental, and technical issues facing offshore wind
energy. DOE's goal is to reduce the cost of electricity generated by
offshore wind farms located in water 100 to 200 feet deep from an
estimated 12 cents per kilowatt-hour today to 5 cents per kilowatt-hour by
2016.
Solar
DOE's solar R&D program is working to make solar energy technologies a
more cost-competitive source of electricity. Specifically, DOE's extensive
work has advanced solar technologies, improved efficiency and reliability,
lowered costs, and resulted in more than 235 patents. While solar energy
technologies have evolved and costs have decreased, DOE is focused on
further reducing solar energy costs to compete in the residential,
commercial, and industrial energy markets and for solar technology to
penetrate the market sufficiently to create a sustainable solar industry.
Currently, DOE's solar R&D program focuses on developing advanced
photovoltaics, also called solar cells, that produce electricity directly
from absorbed photons from sunlight; solar heating and lighting systems;
and utility-size, solar-power plants.
DOE's photovoltaic R&D program is designed to increase performance, reduce
costs, and enhance the reliability of photovoltaic systems. DOE initially
focused on using crystalline-silicon, which continues to hold the majority
of the photovoltaic market today. DOE's second generation of photovoltaic
R&D focuses on thin-film technology, which is designed to use less
materials to reduce costs and can be made into a variety of forms. DOE's
goal is to lower the cost of photovoltaics so that they are an affordable
alternative to traditional electricity sources across all sectors. DOE is
working to reduce the costs of photovoltaics from about 18 to 23 cents per
kilowatt-hour in 2005 to about 5 to 10 cents per kilowatt-hour by 2015.
DOE's solar heating and lighting R&D program is developing technologies
that use sunlight for various thermal applications, particularly space
heating and cooling, water heating, and to illuminate building interiors.
DOE's R&D program is focused on advancing materials, design, and
manufacturability that will lower costs of solar water heaters, improve
their performance, and ease installation. DOE seeks to reduce the costs of
solar water-heating systems operating in cold climates from about 11 to 12
cents per kilowatt-hour today to about 5 to 6 cents per kilowatt-hour by
2011. DOE is also working with industry to fully commercialize solar
lighting systems. However, the administration's fiscal year 2007 budget
proposed eliminating funding for the solar heating and lighting R&D
program.
DOE is also working with industry and southwestern states to develop
utility-size solar power plants that use two types of concentrating solar
power technologies: trough systems and dish/engine systems. These
technologies use various mirror configurations to convert the sun's energy
into high-temperature heat that is used to generate electricity in a steam
generator. DOE's goal is to reduce the cost of utility-size solar power
plants in the Southwest from 12 to 14 cents per kilowatt-hour in 2005 to
10 to 12 cents per kilowatt-hour by 2010.
Hydrogen
In January 2003, the administration announced the Hydrogen Fuel Initiative
and proposed spending $1.2 billion over 5 years to support research in
hydrogen and fuel cell technologies. The initiative's objective is to
accelerate the development of technologies to produce and distribute
hydrogen to power fuel cells to replace the internal combustion engine in
vehicles. While hydrogen is used as a fuel for aerospace and rocket
propulsion applications, it is primarily used in the petroleum refining
and fertilizer industries. DOE's hydrogen R&D program is focused on
developing technologies for production and delivery, storage, conversion,
and end-use applications and on standards formulation and other research.
The program's goal is to develop the technology needed to allow industry
to make a technology readiness decision in 2015 and introduce new hydrogen
vehicles by 2020. However, these technologies are not expected to
penetrate the market or significantly displace oil before 2030.
Geothermal
DOE's geothermal R&D program is developing technologies to improve the
efficiency and cost competitiveness of geothermal technologies, which
currently provide about 0.3 percent of total U.S. electricity and heating
needs.^11 DOE's R&D program has changed over time from a
resource-oriented, long-term, high-risk program to a cost-shared,
competitively selected R&D program to meet immediate industry needs in
geosciences, drilling, resource engineering, and energy conversion
technologies. The program has developed drilling tools that oil and gas
companies have adapted for exploration and helped introduce geothermal
heat pumps into the market.^12 The current goals of the geothermal R&D
program are to (1) decrease the cost of geothermal electricity from about
8 to 9 cents per kilowatt-hour in 2004 to about 3 to 5 cents per
kilowatt-hour by 2010; (2) improve hydrothermal technologies by increasing
the productivity and lifetime of reservoirs, improve technology
performance, and reduce the costs associated with drilling geothermal
wells; (3) develop additional geothermal resources; and (4) explore the
technical feasibility of mining heat from hot dry rock and magma. However,
the administration's fiscal year 2007 budget proposed eliminating funding
for the geothermal R&D program.
^11See also GAO, Renewable Energy: Increased Geothermal Development Will
Depend on Overcoming Many Challenges, [48]GAO-06-629 (Washington, D.C.:
May 24, 2006).
Hydropower
Since 1991, annual budget authority for DOE's hydropower R&D program has
not exceeded $6 million (in real terms) for developing cost-effective
technologies to improve the operation of hydropower facilities and address
environmental concerns. Hydropower is currently the largest source of
renewable energy, generating as much as 10 percent of U.S. electricity.
The most common type of hydropower plant uses a dam on a river to store
water in a reservoir. Water released from the reservoir flows through a
turbine, spinning it, which, in turn, activates a generator to produce
electricity. Current hydropower technologies can have undesirable
environmental effects, such as fish injury and mortality from passage
through hydropower systems, and negative impacts on the quality of water
downstream. DOE has been working with industry to improve the
environmental and operational performance of hydropower systems. DOE's
goal is to demonstrate advanced turbine technologies that will enable a 10
percent growth in generation at existing hydropower plants and enhance
environmental performance by 2010. However, the administration's fiscal
year 2007 budget proposed eliminating funding for the hydropower R&D
program.
^12Geothermal heat pumps are used for space heating and cooling, as well
as water heating. The heat pump transfers heat stored in the earth or in
groundwater into a building during the winter and transfers it out of the
building and back into the ground during the summer.
DOE's Fossil R&D Program Has Focused on Reducing Harmful Emissions and Improving
the Efficiency of Burning Coal
DOE's fossil energy R&D has focused primarily on reducing emissions and
increasing the efficiency of coal-fired power plants. DOE also has
supported oil and natural gas R&D through cost-shared partnerships with
industry, with most funding focused on advanced drilling and piping
technologies for exploration and production.
Coal
In the 1980s and early 1990s, DOE's clean coal technology programs used
cost-shared cooperative agreements with power companies to demonstrate
technologies for reducing sulfur dioxide and nitrogen oxide emissions from
coal-fired power plants. In part as a result of concerns about acid rain
and transboundary pollution, the 1990 Clean Air Act amendments required
that the U.S. Environmental Protection Agency (EPA) regulate hazardous air
pollutants, including sulfur dioxide and nitrogen oxide emissions.^13
Technologies demonstrated by the clean coal technology program contributed
to a 98-percent reduction in sulfur dioxide and similar targets for
nitrogen oxide emissions from coal-fired power plants from 1986 to 2005.
While DOE's fossil R&D program seeks to further reduce sulfur dioxide and
nitrogen oxide emissions, its overall objective is to drive all coal-fired
power plant emissions to "near-zero" levels by 2020. To enable industry to
meet Clean Air Act standards, as well as new goals set out by the
administration's Clear Skies Initiative and EPA regulations,^14 DOE has
focused on reducing mercury and carbon dioxide emissions--significant
contributors to health hazards and global warming, respectively. DOE's
objective is to reduce mercury emissions by 95 percent and capture and
store--or "sequester"--up to 90 percent of carbon dioxide emissions by
2020. Carbon dioxide capture and storage technologies would separate
carbon dioxide from other gases produced during the combustion process and
would transport the captured carbon dioxide to a suitable long-term
storage site, such as geologic repositories or in the deep ocean.
^13Under the Clean Air Act, EPA sets limits on how much of a pollutant can
be in the air anywhere in the United States, which it can enforce by
fining companies that violate air pollution limits.
^14EPA has promulgated a Clean Air Mercury Rule for mercury and a Clean
Air Interstate Rule for sulfur dioxide and nitrogen oxide reductions
across the states.
DOE is also working to improve the efficiency of coal-fired plants by up
to 50 percent by 2010 and 60 percent by 2020. According to DOE, pulverized
coal-fired plants using currently available technology are only about
35-percent efficient--meaning about 65 percent of the energy generated by
the plant is lost during the conversion process, mostly as heat that is
not converted to electricity. Several of DOE's current fossil R&D projects
aim to develop coal-based plants that employ new, more efficient
gasification technologies. Rather than burning coal directly, gasification
breaks coal down into a synthesis gas, comprised primarily of carbon
monoxide and hydrogen, which is combusted to turn a gas turbine,
generating electricity. Heat from the combustion process is captured and
directed toward a steam turbine, which also generates electricity.
According to DOE, industry, and association officials, power plants using
an IGCC configuration for gasification increase the efficiency of
electricity generation and substantially reduce harmful emissions in
comparison with conventional pulverized coal technology (see table 1).
Table 1: Comparison of Conventional Pulverized Coal and IGCC Technologies
IGCC
Performance New conventional
characteristic pulverized coal
plant current near future 2020
Mercury emissions
(pounds/year) 45 29 29 26
Sulfur dioxide emissions
(tons/year) 3,027 566 276 250
Nitrogen oxide emissions
(tons/year) 1,412 1,094 219 198
Carbon dioxide emissions
(tons/year) 3,700,000 3,600,000 3,500,000 3,200,000
Potential for carbon
capture and sequestration Limited Yes Yes Yes
Plant efficiency
(percent) 38.6 39.7 45-50 50-60
Source: The Electric Power Research Institute and DOE.
Note: DOE is the source of plant efficiency data for the "near future" and
2020. The Electric Power Research Institute provided all other data.
Coal-based power plants that employ IGCC technologies break down coal into
its basic chemical elements, allowing for the capture of carbon dioxide as
a concentrated gas stream. In contrast, conventional pulverized coal
plants burn coal directly, creating a more diluted stream of carbon
dioxide that is much more costly to separate from the larger mass of gases
flowing from the combustor. As such, IGCC plants offer greater potential
for carbon capture and sequestration to reduce carbon dioxide emissions.
Moreover, according to international climate change experts at the United
Nations Environment Programme and the World Meteorological Organization,
carbon dioxide capture and sequestration technologies have the most
potential for significantly mitigating climate change when applied in IGCC
plants. Currently, only two coal-based IGCC plants in the United States
are fully operational and produce electricity, and an additional 28 coal
gasification plants are planned for operation by 2030.
To meet its emissions and efficiency goals, DOE recently proposed a $1
billion advanced coal-based power plant R&D project called
FutureGen--cost-shared between DOE (76 percent) and industry (24
percent)--which will demonstrate how IGCC technology can both reduce
emissions and improve efficiency by integrating IGCC with carbon capture
and sequestration technologies. According to DOE, FutureGen is designed to
be the first "zero-emissions" coal-based power plant and is expected to be
operational by 2015. In addition to producing electricity and capturing
and storing 1 million metric tons of carbon dioxide, the 275 megawatt
plant also will be capable of producing hydrogen.
Oil and Natural Gas
Since 1978, DOE has supported oil and natural gas R&D, mainly through
cost-shared partnerships with industry. Historically, DOE's R&D funding
for oil and natural gas was principally divided among specific resources,
such as gas shales and coal-bed methane. In the mid-1980s, however, DOE
switched its focus to developing energy technologies that cross multiple
resources. Recently, DOE's R&D has focused on improving oil exploration
technologies, extending the life of current oil reservoirs, and developing
drilling technology for tapping into deep deposits of natural gas. For
example, DOE is working with industry to develop (1) a composite drill
pipe that is lighter, stronger, and more flexible than steel to improve
oil and natural gas extraction and (2) technology for tapping into the
vast amount of natural gas available in naturally occurring methane
hydrate found on land in permafrost regions and beneath the ocean floor at
water depths greater than 1,600 feet. In fiscal year 2005, exploration and
production and methane hydrate R&D received almost two-thirds of DOE's
funding for oil and natural gas R&D. While DOE's fiscal year 2006 budget
proposed terminating the oil and natural gas R&D program, the Congress
provided $65 million. DOE's fiscal year 2007 budget again proposed
terminating the oil and natural gas R&D program. In addition to the
appropriated funds that oil and natural gas R&D program receives, section
999A-H of the Energy Policy Act of 2005 established a program for R&D and
commercialization of technologies for ultra-deepwater and unconventional
natural gas and other petroleum resource exploration and production
through September 2014 and authorized the use of $50 million per year from
federal oil and gas lease income for an 11-year period.
DOE's Nuclear R&D Goals Recently Have Focused on Restarting the U.S. Nuclear
Power Industry, Reprocessing Spent Nuclear Fuel, and Developing New Reactor
Designs
The commercial nuclear energy industry experienced substantial growth
during the 1960s and 1970s. By 1974, the federal government had approved
operating licenses for 52 nuclear reactors with plans for dozens more.
However, the energy crisis in the 1970s led to a significant reduction in
orders for new reactors and, coupled with concerns about reactor safety
and performance resulting from the 1979 accident at Three Mile Island, the
industry canceled the application process for 93 other reactors. DOE began
to focus on short-term R&D, working specifically to restore public trust
and regulator confidence by improving safety and efficiency of operations.
By the mid-1990s, the industry had dramatically improved its safety
record, and the performance of nuclear power exceeded that of any other
source of energy, reaching 90 percent of total potential capacity. Left
with only incremental improvements in operations and uncertain economics,
the Congress began to phase out funding DOE's nuclear energy R&D and
terminated nuclear R&D funding altogether in fiscal year 1998.
In fiscal year 1999, DOE crafted a long-term nuclear energy R&D agenda
that focused on developing more efficient systems and
proliferation-resistant fuel cycles, devising new technologies for
managing nuclear waste, and designing a fourth generation of nuclear
reactors that would not use conventional light water reactor technology.
In fiscal year 2001, DOE prioritized its R&D program to focus on (1) the
Nuclear Power 2010 program, (2) the Advanced Fuel Cycle Initiative (AFCI),
and (3) the Generation IV Nuclear Energy Systems Initiative.
DOE's Nuclear Power 2010 initiative has shared the costs that
participating power companies have incurred in preparing either an early
site permit or an application for an NRC license to construct and operate
an advanced Generation III nuclear power reactor. In the years after the
Three Mile Island accident, the nuclear power industry stated that NRC's
regulatory process had become too cumbersome, leading to costly delays in
construction and licensing and becoming a major stumbling block to
investing in a new nuclear reactor. In response, NRC promulgated
regulations in 1989 that established a single combined license to
construct and operate a new reactor, replacing its prior requirement that
companies obtain both a construction permit and an operating license.^15
More recently, in fiscal year 2002, to encourage power companies to apply
to NRC for a combined construction and operating license, DOE initiated a
demonstration program with three power companies seeking early site
permits for potential nuclear reactor sites in Illinois, Mississippi, and
Virginia. The permits, applications for which were submitted to NRC in
2003, would allow the sites to be used for nuclear power plants, but the
power companies still would have to apply to NRC for a combined license to
construct and operate any reactors later built on these sites. In fiscal
year 2004, DOE began a demonstration program with two industry consortia
to develop applications for NRC licenses to build and operate two
additional reactors at existing nuclear power plants. These applications
may be submitted to NRC next year. Even if NRC approves the licenses,
which NRC estimates will take 42 months, the industry consortia have not
committed to constructing the new reactors. The industry has, however,
received license extensions for 44 of the 103 operating nuclear reactors.
DOE allocated $65.3 million to the Nuclear Power 2010 program in fiscal
year 2006 and requested $54 million for fiscal year 2007.
^15See 54 Fed. Reg. 15383 (1989).
The AFCI program is designed to develop and demonstrate technologies for
reprocessing spent nuclear fuel that could recover the fuel for reuse,
minimize proliferation threats, and reduce the long-term hazard and
disposal requirements of spent nuclear fuel. In the 1970s, the United
States pioneered reprocessing technologies, but it abandoned the concept
because of concerns about nuclear proliferation--plutonium could be
separated to manufacture nuclear weapons.^16 Current R&D efforts focus on
reprocessing spent fuel without separating the plutonium, with the goal of
rendering it virtually useless to potential proliferators. Much of the
reprocessed fuel could be reused in commercial reactors to generate
electricity.
In February 2006, DOE announced the Global Nuclear Energy Partnership
(GNEP) program, characterizing it as an extension of the AFCI program.
GNEP furthers the R&D goals of the AFCI program, accelerating the R&D
efforts and introducing a global component. DOE's intent is to work with
other nations that reprocess spent fuel to supply fuel to countries for
the purpose of generating electricity. The countries then would return the
spent fuel to the supplier nations for reprocessing. Once reprocessed,
this fuel would be returned to the countries for reuse. The intent of the
program is to encourage these "reactor-only" countries not to develop
their own independent nuclear technologies, thereby reducing proliferation
risks. Details of the program are still being developed. DOE requested
$243 million for the combined AFCI and GNEP programs in fiscal year 2007.
According to DOE officials, the GNEP program would need about $5 billion
over the next 5 years.
^16In 1977, President Carter announced plans to indefinitely suspend U.S.
reprocessing efforts.
The Generation IV program focuses on developing new, fourth generation,
advanced reactor technologies intended to be commercially available by
about 2020 to 2030. The program, including the United States and 12
international partners, identified six advanced reactor designs from which
DOE has focused on two reactor designs: (1) a sodium-cooled fast reactor
and (2) a gas-cooled very high temperature reactor. A fast reactor manages
nuclear reactions somewhat differently than current commercial reactors,
in which neutrons interact with the low-enriched uranium fuel atoms to
induce fissions--or the splitting of the uranium atom--that emits more
neutrons and leads to a self-sustaining chain reaction. The fissioning of
uranium releases large amounts of energy that is captured as heat to drive
turbines and generate electricity. Because the fission neutrons are born
at high energy, they are not inherently efficient at causing more
fissions, so commercial nuclear reactors are filled with water that
functions both to slow the neutrons down and act as a coolant and heat
removal system. The lower energy neutrons in current commercial reactors
are much more effective at sustaining the uranium fission chain reaction.
In contrast, a fast reactor manages these nuclear reactions at a higher
energy level. Fast reactors use coolants such as liquid sodium metal that
do not slow down the neutron energy. Because fast reactors are more
effective than current commercial reactors at inducing fissions in a wider
variety of nuclear materials, including plutonium and other materials that
might otherwise become wastes from the current commercial reactor fuel
cycle, they can potentially reduce the total amount, temperature, and
radiotoxicity of the fuel that might otherwise have to be stored for many
thousands of years in a geologic repository. The lower temperature may
also allow more spent fuel to be stored at a deep geologic repository,
delaying the need for additional repository requirements. This continuous
recycle and burning of spent nuclear fuel materials is key to the GNEP
program.
The gas-cooled very high temperature reactor is also being developed
through DOE's Next Generation Nuclear Plant program because the high
temperature allows for the efficient production of hydrogen by splitting
water. U.S. industries annually produce over 9 million tons of hydrogen
to, for example, manufacture fertilizer and refine petroleum. Very high
temperature reactors may become an efficient and emissions free
alternative source of hydrogen, which is made primarily from natural gas.
The very high temperature reactor can be more efficient than current
reactors and is designed to be versatile, capable of generating small or
large amounts of electricity. DOE requested $31.4 million for fiscal year
2007 for the Generation IV R&D efforts.
Advanced Renewable, Fossil, and Nuclear Energy Technologies Face Key Barriers to
Market Deployment
Advanced renewable, fossil, and nuclear energy technologies all face key
challenges to their deployment into the market. Renewable technologies
face technological and market barriers--such as efficiency and high
up-front capital costs--to substituting for oil and for generating
electricity. Advanced fossil technologies also face key challenges--such
as controlling harmful emissions--to deploying advanced technologies for
generating electricity. Similarly, advanced nuclear technologies face key
challenges--such as public opposition and high capital costs--that must be
addressed as the industry considers constructing new nuclear power
reactors for the first time in nearly 30 years.
Renewable Energy Technologies Face a Variety of Technical and Deployment
Barriers
The primary renewable energy technologies with the potential to
substantially expand their existing production capacity during the next 25
years are biomass, a partial substitute for gasoline in transportation,
and wind and solar energy technologies for generating electricity.
Ethanol
In 2005, 95 ethanol refineries located in 19 states produced 3.9 billion
gallons of ethanol--an increase of 17 percent over 2004 and 126 percent
over 2001. The United States will consume about 5 billion gallons of
ethanol in 2006, according to the industry's September 2006 projections.
Ethanol is blended in 30 percent of the nation's gasoline and is primarily
produced in the Midwest because of the abundant supply of corn. Ethanol
demand is expected to continue to grow as a result of the national
renewable fuels standard,^17 enacted by the Energy Policy Act of 2005, and
the decision of many oil refineries to switch to using ethanol instead of
MTBE as a fuel additive in gasoline that improves its octane and
clean-burning properties.^18
17The national renewable fuels standard establishes a baseline for
renewable fuel use, beginning with 4 billion gallons per year in 2006 and
expanding to 7.5 billion gallons by 2012.
One of ethanol's biggest challenges is how to cost-effectively expand the
supply of biomass, in addition to corn, to enable the total ethanol market
to grow. DOE scientists are exploring technologies that can
cost-effectively use cellulosic biomass--low-value residues such as wheat
straw and corn stover or bio-energy crops such as fast-growing grasses and
trees. Some bio-energy crops, such as switchgrass, require less fertilizer
than corn and can be grown in many U.S. regions. While cellulosic ethanol
requires less fossil energy than corn ethanol on a total life-cycle basis,
capital costs are substantially higher for cellulosic ethanol plants than
for corn ethanol plants. In addition, cellulosic ethanol producers need to
reduce costs for (1) harvesting and handling cellulosic feedstock, (2)
enzymes for converting cellulose to fermentable sugars, and (3) novel
fermenting micro-organisms that can convert these biomass-derived sugars
to ethanol. Cellulosic ethanol currently costs at least twice as much to
produce as corn ethanol, according to DOE officials.
A related challenge is producing sufficient biomass levels without
disrupting current production of food and forest products. In 2005, 1.43
billion bushels of corn--nearly 13 percent of the U.S. corn crop--were
used for ethanol production. In a 2005 report, the U.S. Department of
Agriculture and DOE estimated that the nation is capable of producing
enough ethanol to replace 30 percent of the U.S. oil consumption by 2030
and still meet food, feed, and export demands.^19 However, some experts
have expressed concern that large-scale diversion of agricultural
resources to generate ethanol could result in higher food prices for
people and livestock. There are also questions about the amount of land
that will be needed to produce higher levels of ethanol, whether vast
preserved areas will be transformed into farmland, water quality issues,
and soil sustainability. In addition, scientists have debated whether
ethanol is an effective petroleum substitute because of the amount of
energy needed to produce it--a significant amount of energy is used
because (1) fertilizer made from fossil fuels is used to grow the corn,
(2) most U.S. biorefineries use natural gas to convert biomass into
ethanol, and (3) the corn and the ethanol need to be transported.
^18According to EIA, oil refineries decided to eliminate MTBE primarily
because (1) many states have banned MTBE because of water contamination
concerns, (2) industry's liability exposure by adding MTBE to gasoline,
and (3) industry's perception that liability exposure increased because
the Energy Policy Act of 2005 eliminated the oxygen content requirement
for reformulated gasoline.
^19DOE and USDA, Biomass as Feedstock for a Bioenergy and Bioproducts
Industry: The Technical Feasibility of a Billion-Ton Annual Supply, April
2005.
A third challenge is the distribution of ethanol from the biorefinery to
the consumer, according to DOE officials. Ethanol cannot use the same
infrastructure as gasoline because it has corrosive qualities and is water
soluble.^20 As a result, an independent infrastructure system for
transporting and storing ethanol would be needed throughout the United
States. In particular, no pipelines exist to distribute ethanol from the
Midwest, where it is mainly produced, to major markets on the East and
West coasts. In addition, infrastructure constrains the distribution of
E85--a blend of 85 percent ethanol and 15 percent gasoline--because
regular gas stations must have separate tanks for storing E85 and
specialized pumps for dispensing it. Currently, fewer than 1,000 fueling
stations provide E85 nationwide, compared with 176,000 gas stations. These
ethanol fueling stations are concentrated in the upper Midwest, and about
75 percent of ethanol is transported by rail and 25 percent is moved by
truck. U.S. consumers have bought more than 5 million flexible fuel
vehicles that can run on E85; however, without a ready supply of E85, many
of these vehicles will continue to operate using gasoline.
Ethanol also faces the challenge of becoming more price-competitive with
gasoline. Currently the market for ethanol relies on federal tax
incentives. One such incentive is the volumetric ethanol excise tax
credit, enacted in 2004, which provides a 51-cent tax credit for every
gallon of ethanol used to produce a fuel mixture through December 31,
2010. Even with tax incentives for ethanol producers, the fuel has been
more expensive than gasoline, in part because ethanol's energy content is
lower than gasoline's. According to DOE and EPA, flex fuel vehicles
require about one-third more ethanol to match gasoline's energy content.
Similarly, in October 2006, Consumer Reports, estimated that drivers
paying $2.91 per gallon for E85 in August 2006 actually paid about $3.99
for the energy equivalent of a gallon of gasoline because the distance
vehicles traveled per gallon declined by 27 percent.
^20It is a normal occurrence for water to accumulate in oil pipelines. In
most cases, water enters the system through terminal and refinery tank
roofs or can be dissolved in fuels during refinery processes. Introducing
ethanol into an oil pipeline risks rendering it unusable as a
transportation fuel.
Finally, congressional earmarks of DOE's biomass R&D funding rose from 14
percent of the fiscal year 2000 funds to 57 percent ($52 million) of the
fiscal year 2006 funds, according to a DOE program official.^21 DOE
program officials told us that the rising number of biomass earmarks
shifted funding away from DOE's R&D program, causing the biomass program
to change its program priorities and terminated some of its cost-shared
projects. Congressionally earmarked projects typically are not subject to
peer review, are not selected on either their technical merits or their
contribution to meeting program goals, and are only voluntarily
accountable for reporting results.
Wind and Solar
Both wind and solar technologies have experienced substantial growth in
recent years; they have benefited from federal and state financial
incentives, DOE's R&D programs that decreased costs and improved
efficiencies, and environmental and energy security concerns. For example,
U.S. wind electric generation capacity has grown from 2,000 megawatts in
1999 to 10,000 megawatts by August 2006, enough energy to power about 2.5
million homes^22 with electricity on a typical day. Similarly, the total
photovoltaic market has grown, on average, about 30 percent per year over
the past 10 years, according to a solar manufacturer. In 2005, the United
States had an estimated 475 megawatts of installed photovoltaic capacity,
enough to power about 240,000 homes. EIA data show that in 2005 domestic
shipments of solar photovoltaic solar technology increased by 72 percent
over 2004.
The wind energy industry faces technological challenges to improve turbine
design, performance, and reliability that will enable wind power to expand
into low wind and offshore locations. These locations use bigger wind
turbines with longer blades mounted on taller towers, requiring complex
design improvements in such areas as blade development, advanced drive
train and power electronics, and advanced controls to reduce system loads.
For example, while traditional blade materials have used fiberglass
technology, the next generation of turbines will need stiffer and stronger
materials, such as carbon fiber, to make longer, thinner, but equally
durable blades. Similarly, offshore wind development faces new technical
challenges, such as understanding the effects of wave and current loads on
the base of wind structures, connecting offshore wind farms to the
electric transmission grid, and designing support structures for turbines
located in deep water.
^21Similarly, earmarks accounted for about $43 million, or 27 percent, of
appropriated funds for DOE's hydrogen and fuel cell R&D program in fiscal
year 2006.
^22One megawatt of wind power generates about as much electricity as 240
to 300 households use each year.
Solar technologies also face challenges of improving the scientific
understanding of the electronic process of capturing and converting
sunlight at the molecular level and technical challenges of improving
performance and reliability. For example, DOE is pursuing thin-film
photovoltaic technologies, which are designed to reduce material costs by
using thin layers of semiconductor material. According to DOE, this
technology is not as efficient in converting sunlight to electricity as
conventional crystalline-silicon solar cells, but manufacturing costs are
anticipated to be lower. The challenge is to increase their efficiency,
while continuing to reduce the costs of manufacturing thin-film
technologies. DOE scientists are also seeking to reduce failure rates for
components in solar water-heating systems that are exposed to high
temperatures and improve the 12-year tank life of current solar heaters in
cold climates.
A second major challenge to deploying both wind and solar technologies is
overcoming investors' concern about their higher up-front capital costs.
In particular, wind investors pay substantial up-front capital costs to
build a facility and connect it to the power transmission grid.
Constructing a wind farm may cost less than connecting the facility to the
power transmission grid, according to DOE officials who noted that the
connection could cost $100,000 or more per mile, on average, depending on
such factors as the project's size, the terrain, and the transmission line
rating. In addition, in most areas, a wind farm's investors would pay for
upgrading the power transmission grid to carry the extra load, which can
be high because prime wind resources are often found far from large urban
areas that need the electricity. Similarly, the primary barrier to
deploying solar photovoltaic technologies is their up-front purchase
costs, which continue to make them more expensive than traditional energy
sources, according to DOE and industry executives.^23 More recently, the
rapidly growing solar energy industry has experienced an industrywide
shortage of solar-grade silicon--the principal material for making
crystalline-silicon photovoltaic cells--because of competition from other
industries, such as computer chip manufacturers. As a result, the price of
silicon wafers on the market has doubled in each of the past 2 years,
according to EIA. The tight silicon supply has also created back orders of
several months. Because photovoltaic manufacturing costs have risen
sharply, manufacturers have changed their business strategies to maintain
profits and continue to finance their plans to expand their production and
strengthen their distribution capabilities.
^23The Energy Policy Act of 2005 also established a new residential
investment tax credit for solar energy systems that provides a 2-year tax
credit through December 31, 2007.
Both wind and solar power also have unique intermittency characteristics
that can constrain their use because the existing power transmission grid
was built to accommodate large central-station power plants located near
population centers that operate full time. This system relies on precisely
predicting and controlling power plant output to avoid blackouts and other
disruptions. However, wind and solar energy are intermittent energy
sources because wind speed and sunlight vary, depending, for example, on
the time of day and the weather--on average, wind turbines operate the
equivalent of less than 40 percent of the hours in a year due to the
intermittency of wind. Alternatively, the electricity generated must be
immediately used or transmitted to the power transmission grid because no
cost-effective means exists for storing electricity. DOE is conducting R&D
in this area.
A recent challenge facing the wind industry is mitigating environmental
and community concerns about its adverse effects. While wind energy does
not create the pollution or greenhouse gas emissions associated with
fossil fuel power generation, some wind farms have resulted in the death
of birds and bats because they are located amidst migratory pathways or
important habitats.^24 Our 2005 report found that impacts of wind farms on
birds and other wildlife varied by region and by species, and the lack of
comprehensive data on bird and bat fatalities from wind turbines make it
difficult to make national assessments of the impact of wind turbines on
wildlife.^25 In addition, wind energy may face community opposition
because it affects visual aesthetics and landscapes. For example, the
first proposed U.S. offshore wind project, consisting of 130 wind turbines
off the coast of Massachusetts, ran into opposition from local residents
and organizations who oppose the appearance of wind turbines in Nantucket
Sound.
^24The Fish and Wildlife Service estimates that some of the leading
sources of bird mortality per year are attacks by domestic and feral cats,
hundreds of millions of bird deaths; collisions with building windows, 97
million to 976 million bird deaths; poisoning from pesticides, at least 72
million bird deaths; and collisions with communication towers, 4 million
to 50 million bird deaths.
^25See GAO, Wind Power: Impacts on Wildlife and Government
Responsibilities for Regulating Development and Protecting Wildlife,
[49]GAO-05-906 (Washington, D.C.: Sept. 16, 2005).
Another challenge for wind energy is that the federal production tax
credit--the primary federal financial incentive to stimulate the
deployment of renewable energy systems--periodically must be legislatively
extended, creating uncertainty among investors whether the tax credit will
be extended. The federal production tax credit, initially established by
the Energy Policy Act of 1992 for a limited duration, had expired before
being renewed by subsequent legislation in 1999, 2001, and 2003. The
Energy Policy Act of 2005 extended it an additional 2 years, until January
1, 2008. According to DOE officials and industry representatives, the
production tax credit has helped to offset the significant higher capital
costs per unit of generating capacity needed to start up wind power
projects, compared with projects for fossil fuel power generation.
However, the uncertainty about the production tax credit's availability
has created a boom-and-bust cycle for installing new wind power
capacity--installation of new capacity fell dramatically in years when the
authorization for the tax credit expired and its renewal was delayed, as
compared with years when it was available without interruption. Potential
developers are reluctant to commit resources to the planning and
construction of new capacity without the certainty that the tax credit
will be reauthorized. Furthermore, according to the American Wind Energy
Association, 4 to 6 months before the tax credit expires, financial
lenders hesitate to provide capital for wind projects because of the
uncertainty of whether the tax credit will be extended.
DOE officials and industry representatives believe the continued
availability of the production tax credit, or other subsidy support, is
vital to the potential future growth of the wind industry. According to an
industry representative, a long-term production tax credit would
facilitate steady market development for wind power and other renewable
sources by encouraging companies to enter the market, allowing the
industry to conduct long-term planning, and eventually help the industry
stand on its own. According to some stakeholders, renewable energy sources
require subsidies, such as the production tax credit, to level the playing
field because various subsidies for fossil fuel and nuclear technologies
have made it difficult for renewable energy sources to compete.
Both DOE's wind and solar R&D programs have experienced a large increase
in the amount of congressional earmarks in recent years. Wind energy
earmarks grew from 6 percent of funding in fiscal year 2004 to about 33
percent ($13 million) of funding in fiscal year 2006, according to a DOE
program official. Similarly, solar energy earmarks grew from 1 percent of
funding in fiscal year 2004 to about 17 percent ($14 million) of funding
in fiscal year 2006, according to a DOE program official. An industry
association executive noted that congressional earmarks reduce DOE's
ability to adequately fund its solar R&D programs and meet targets.
Barriers to Advanced Fossil Technologies Include Harmful Emissions and High
Capital Costs of New Coal Gasification Plants
While coal-fired power plants have substantially reduced their sulfur
dioxide and nitrogen oxide emissions, electric power companies face
important challenges to deploying a new generation of advanced IGCC coal
gasification power plants. These challenges are to further reduce mercury
and carbon dioxide emissions and manage the risk associated with high
construction and operating costs of new advanced coal technologies. The
administration's Clear Skies Initiative set goals for coal-fired plants to
cut their 2003 emissions--49 tons of mercury, 10.2 million tons of sulfur
dioxide, and 3.9 million tons of nitrogen oxide--by an average of 70
percent by 2018. However, coal-fired plants also annually emit 2.1 billion
tons of carbon dioxide--the most significant contributor to greenhouse
gases and global warming--or 36 percent of the nation's total carbon
dioxide emissions. EPA currently does not regulate carbon dioxide
emissions but might do so in the future to address the growing concern
about the harmful effects of greenhouse gases.
IGCC coal-gasification technology enables power plants to separate sulfur
dioxide, nitrogen oxide, mercury, and carbon dioxide before the synthesis
gas is burned, thus reducing their emission into the air. DOE and industry
are conducting R&D to develop sequestration technologies for the long-term
storage of carbon dioxide gas without the gas gradually leaking back into
the atmosphere. DOE has funded 25 carbon-dioxide sequestration projects as
of September 2006, but has not yet demonstrated the storage of carbon
dioxide captured by a large-scale, coal-based power plant. Specifically,
when carbon dioxide is compressed and stored in geologic formations, such
as oil and gas reservoirs, its density is close to that of some crude
oils, resulting in buoyant forces that tend to drive carbon dioxide
upwards. It is unknown whether carbon dioxide will remain safely
sequestered if pressure, temperature, or other conditions change.
According to international climate change experts, leakages could
significantly affect climate change or contaminate groundwater. Moreover,
given the long-term nature of carbon dioxide capture and sequestration,
storage sites may require monitoring for very long periods of
time--possibly for "eternity," according to one DOE official.
New coal gasification plants also face the high costs associated with
employing advanced energy technologies, such as IGCC and carbon dioxide
capture and sequestration systems. In particular, IGCC plants are 20
percent more expensive--about $100 million more--than pulverized coal
plants that use currently available technology, according to International
Energy Agency, DOE, and industry officials. Moreover, carbon dioxide
capture and sequestration technologies will further increase an IGCC
plant's costs because capturing and sequestering carbon dioxide increases
fuel consumption by as much as 25 percent. According to international
climate change experts, an IGCC plant that employs carbon dioxide capture
and sequestration technologies could increase the cost of electricity per
kilowatt hour from 21 to 78 percent, depending on plant design, the cost
of fuel, and the storage site characteristics.^26
In addition to technological and cost barriers, the uncertainties
surrounding new coal-gasification technologies create substantial
investment risks that threaten to hinder development. Despite the greater
efficiency, reduced emissions, and the ability to capture carbon dioxide,
only four coal-based IGCC power plants currently operate worldwide. The
unproven nature of IGCC technology creates uncertainty and reluctance
among industry to invest in building a new coal-based IGCC power plant,
particularly given the additional cost, according to DOE and industry
officials. Furthermore, international climate change forecasting models
predict that carbon dioxide capture and sequestration systems are unlikely
to be deployed on a large scale without explicit government regulations
that substantially limit greenhouse gas emissions to the atmosphere. In
light of such technological uncertainties, industry officials noted that
cost-sharing initiatives with DOE will continue to be an important factor
in encouraging the demonstration and deployment of IGCC plants.
^26The higher cost of electricity generated using IGCC technology in
comparison with conventional coal-fired technologies more fully reflects
the total cost of burning coal by including the cost of controlling the
release of harmful emissions. Alternatively, several countries have
enacted a carbon tax that puts a value on the carbon emissions that
conventional coal-fired technologies generate.
Advanced Nuclear Energy Technologies Face Uncertainty about NRC's Regulatory
Process, Public Opposition, High Capital Costs, and the Storage of Nuclear Waste
The nuclear energy industry, DOE, and NRC face important challenges in
reinvigorating the nuclear power industry include an untried regulatory
process, the public's concern about safe operations, investor concerns
about high capital costs, and uncertainty about the long-term storage of
nuclear waste. During the 1960s and 1970s, several nuclear power plants
experienced construction costs that doubled and time frames that extended
several years longer than anticipated--in one case, a project took nearly
20 years to build and begin operations, according to the Nuclear Energy
Institute, an industry association. Since 1974, power companies have
cancelled applications for 93 proposed reactors and have shut down 22 of
126 operating reactors before their 40-year license expired. NRC issued
its last permit to construct a nuclear reactor in 1978, the year before
the Three Mile Island nuclear reactor accident, which heightened public
opposition to nuclear power and tightened NRC's oversight of nuclear power
plant operations. More recently, however, NRC has approved a 20-year
license extension for 44 of the 103 operating nuclear reactors in the
United States and is reviewing applications to extend the licenses for 10
additional reactors.
Because NRC has not issued a construction permit in almost 30 years,
investors worry that the problems that contributed to the schedule delays,
cost overruns, and abandonment of many planned reactors may not be
resolved. Among the reasons for these problems were that electric power
companies custom-built many of the nuclear power plants, rather than using
a standard design, and sometimes began construction with preliminary
design information, only to resort to mid-construction retrofits as final
design plans changed. In addition, NRC's regulatory process at that time
required the applicant to obtain a construction permit first and apply for
an operating license in the midst of construction. Final approval of the
operating license sometimes hinged on time-consuming and costly retrofits,
particularly if operational procedures conflicted with design features.
To reduce these high costs and long time frames, NRC streamlined its
licensing process in 1989 by combining its construction and operating
licenses into a single license that requires applicants to submit final
design information, safety analyses, and environmental data in advance of
or with the license application. While industry representatives generally
agree that the revised licensing process reduces risk of costly retrofits,
they are concerned that the new process has not been tested and could
still lead to extensive delays. For example, some representatives noted
that NRC has already fallen behind schedule in reviewing the early site
permits that three electric power companies submitted as part of a DOE
demonstration program to stimulate power companies to apply to NRC for a
combined construction and operating license. The early site permits
address site suitability matters such as safety and environmental issues
and, once obtained, can be used as a reference in a combined license
application to streamline the site suitability portion of the
application.^27 NRC acknowledged the delays, attributing them to a
learning process under new procedures and regulations; an unexpectedly
large number of public comments received electronically; and, in one case,
the applicant's decision to change the design. Electric power companies
have notified NRC that they plan to submit license applications to build
and operate at least 29 new reactors. To prepare, NRC has implemented a
design-centered approach that encourages applicants to use a standardized
design for each reactor manufacturer with variations only to address the
site's local characteristics, such as environmental conditions. NRC also
has created a separate Office of New Reactors to oversee the licensing
process, plans to hire 400 additional staff by fiscal year 2008, and is
developing a more robust system to handle electronic comments. NRC expects
to review license applications and issue a decision within 42 months.
However, while it has issued its draft regulatory guidance for submitting
and reviewing the combined license applications, NRC does not expect to
finalize the guidance until March 2007.
A second challenge that investors face is public opposition to nuclear
power. According to the nuclear energy industry, public support for
nuclear power has increased in recent years, primarily as a result of the
industry's improved safety record and a growing awareness that nuclear
power production releases few greenhouse gases.^28 Electric power
companies plan to construct most of the announced new reactors at existing
nuclear power plants in the southeast United States, where public opinion
is more favorable toward nuclear power. Reactor projects at existing
nuclear power plants also benefit from existing power transmission lines
and historical environmental data for the required environmental impact
assessment. However, industry officials acknowledge that public support is
fragile and note that a nuclear accident anywhere in the world could
undermine this support.
^27See 10 C.F.R. pt. 52.
^28Mining and processing of uranium and transporting of nuclear fuel
result in some greenhouse gas emissions. In addition, greenhouse gas
emissions result from site construction and worker transportation for both
nuclear and renewable energy facilities.
A third challenge facing nuclear energy is the high capital costs to build
new nuclear reactors and a potential shortage of skilled workers. Nuclear
energy representatives expect a new nuclear power plant to cost between
$1.5 billion and $4 billion--more than double the cost of a comparably
sized conventional coal-fired plant. These costs may increase if (1)
transmission lines need to be installed or upgraded, (2) significant
delays occur during construction or start-up operations, and (3) lawsuits
are filed resulting in higher legal costs and delays. Although nuclear
power plants have relatively low operating costs and can operate at
90-percent capacity, the overall cost of construction makes nuclear energy
a high-cost option. In addition, nuclear energy industry officials noted
that a potential shortage of skilled workers creates additional
uncertainties over construction schedules that could increase the cost of
a new plant. With the hiatus in nuclear power plant construction, industry
officials have expressed concerns that there may be a shortage of workers
with the skills critical to the construction of new nuclear power plants,
particularly if several utilities plan construction simultaneously.
The Energy Policy Act of 2005 has facilitated the construction of new
nuclear power reactors by providing a 1.8 cents/kilowatt-hour tax credit
for up to 6,000 megawatts of new nuclear energy capacity for the first 8
years of operation (up to $125 million per reactor). The Department of the
Treasury is to prescribe the process for allocating the tax credit in
consultation with the Secretary of Energy. In addition, the act authorizes
the Secretary of Energy to enter into six contracts with sponsors of
advanced nuclear facilities to ensure against certain delays in attaining
full-power operation and provide indemnification of (1) 100 percent of
covered costs, up to $500 million each for the first two reactors and (2)
50 percent of covered costs, up to $250 million each for the next four
reactors after an initial 180-day delay.
Recently, the Massachusetts Institute of Technology (MIT) and the
University of Chicago issued studies comparing nuclear power's costs with
other forms of generating electricity. ^29 Both studies concluded that,
assuming no unexpected costs or delays in licensing and construction,
nuclear power is only marginally competitive with conventional coal and
natural gas and, even then, only if the nuclear power industry
significantly reduces anticipated construction costs. The nuclear power
industry has proposed constructing modular plants based on a set of
reference designs in the hopes of reducing construction costs. New
technologies that use more reliable and less expensive passive safety
systems also can reduce costs considerably compared with active safety
systems currently used. For example, several of the proposed nuclear
reactors utilize less piping. Despite the projected cost reductions, the
MIT authors suggested that investors would most likely prefer conventional
coal or natural gas over nuclear energy for generating electricity. Table
2 shows that without substantial cost reductions, nuclear energy cannot
compete with either conventional coal or natural gas.
^29MIT. The Future of Nuclear Power (Cambridge, MA: July 2003); University
of Chicago, The Economic Future of Nuclear Power (Chicago, IL: August
2004).
Table 2: Comparison of Electricity Generating Costs Using Nuclear, Coal,
and Natural Gas Energy Sources
Cents per kilowatt-hour
Energy source 25-year period 40-year period
Nuclear (base case) 7.0 6.7
Nuclear (best case) 4.7 4.4
Coal 4.4 4.2
Natural gas 4.9 5.1
Source: MIT.
Note: Costs were calculated using 2002 dollars and an 85 percent capacity
factor using merchant plant financing, reflecting a risk premium for
nuclear energy. The best case for nuclear energy assumes a 25-percent
reduction in construction costs and a 12-month reduction in construction
time. The natural gas case assumes combined cycle turbine technology and a
price that starts at $4.50/million Btu and rises at a 2.5 percent rate
over 40 years. Although natural gas prices were lower in 2002 than today,
construction and other costs have risen, resulting in a good measure of
relative costs, according to one of the MIT authors.
However, the MIT study found that if a tax on carbon emissions were
introduced, nuclear energy could become much more competitive because
conventional coal and natural gas power plants would be subject to the tax
while nuclear reactors would not because they do not emit carbon dioxide
during the generation of electricity (see table 3). Coal-based IGCC plants
could perform better than the conventional coal-fired power plants in
capturing and sequestering carbon dioxide emissions, but these plants are
considerably more expensive to build and operate than conventional
coal-fired plants. Part of DOE's R&D efforts include reducing the cost of
construction of coal-based IGCC plants.
Table 3: Comparison of Electricity Generating Costs Assuming a Carbon
Emissions Tax
Cents per kilowatt-hour
Energy source 25-year period 40-year period
Nuclear (base case) 7.0 6.7
Nuclear (best case) 4.7 4.4
Coal ($50/ton carbon tax) 5.6 5.4
Coal ($100/ton carbon tax) 6.8 6.6
Natural gas ($50/ton carbon tax) 5.3 5.6
Natural gas ($100/ton carbon tax) 5.8 6.0
Source: MIT.
Note: Costs were calculated using 2002 dollars and an 85 percent capacity
factor using merchant plant financing, reflecting a risk premium for
nuclear energy. The best case for nuclear energy assumes a 25-percent
reduction in construction costs and a 12-month reduction in construction
time. The natural gas case assumes combined cycle turbine technology and a
price that starts at $4.50/million Btu and rises at a 2.5 percent rate
over 40 years. Although natural gas prices were lower in 2002 than today,
construction and other costs have risen, resulting in a good measure of
relative costs, according to one of the MIT authors.
The revival of the nuclear power industry is also challenged by
uncertainty about long-term disposal of commercial reactors' spent nuclear
fuel. DOE reports that about 55,000 tons of commercial spent nuclear
fuel--enough to fill the area of a football field about 10 feet
deep--currently sits in interim storage at 72 sites in 33 states, mostly
at operating reactor sites. This spent fuel must be safely disposed of to
protect the public and the environment from harm because it will remain
highly radioactive for hundreds of thousands of years. The Atomic Energy
Commission, DOE's predecessor, initially planned to recycle spent nuclear
fuel to reduce the amount of waste for disposal, but the 1970s recycling
technology did not address concerns that plutonium might be separated and
diverted for use in manufacturing nuclear weapons. The Nuclear Waste
Policy Act of 1982 determined that the spent fuel should be disposed of in
a deep geologic repository; and, in 1987, an amendment to the act
identified Yucca Mountain, about 100 miles northwest of Las Vegas, Nevada,
as the one site that DOE should study further. However, DOE has extended
the repository's commissioning date from the original 1998 target to
2017.^30 In addition, once the repository is completed, decades may be
needed to transport the spent fuel from various locations across the
country to Yucca Mountain. In the meantime, utilities continue interim
storage of spent nuclear fuel at operating reactor sites.^31
30The Nuclear Waste Policy Act of 1982 originally set 1998 as the date for
DOE to begin accepting spent nuclear fuel for disposal. DOE has revised
its estimate of the repository's opening first to 2010 and currently to
2017, characterized by DOE as a "best-achievable schedule."
Many states have expressed alarm at the delays in opening Yucca Mountain,
fearing that the repository will suffer continual delays or might never
open, forcing the nuclear power plants to store the spent fuel
indefinitely. While the states are concerned about the public health and
environmental risks, especially with about 2,200 tons of spent nuclear
fuel being added to the national inventory annually, DOE and NRC cite a
long list of studies that indicate that the risks of radiation release
from spent fuel in interim storage in pools or in dry storage casks is
low.^32 The states are also concerned that Yucca Mountain project delays
are resulting in ongoing costs for the consumer because, under the Nuclear
Waste Policy Act, users of nuclear power generated electricity pay $0.001
per kilowatt-hour into a Nuclear Waste Fund, which is designed to pay for
the permanent disposal of all commercial spent nuclear fuel and high-level
waste, including the siting, licensing, and construction of a nuclear
waste repository. In fiscal year 2006, DOE reported $19.4 billion in the
fund. DOE reported that from project inception in fiscal year 1983 through
fiscal year 2005 that it had spent approximately $11.7 billion (in real
terms).^33 Recently, DOE revised the start date from 2010 to 2017 and
estimated that the project would incur an additional $10.9 billion (in
real terms) from fiscal year 2006 to fiscal year 2017. According to the
National Council of State Legislatures, seven states have prohibited the
construction of new nuclear plants, citing the need to resolve the spent
nuclear fuel issue.
^31NRC requires that utilities store spent nuclear fuel immersed in deep
pools of water or in dry storage casks consisting of all steel or steel
and concrete. Currently, 37 commercial dry storage facilities exist in 27
states. However, Private Fuel Storage in Utah, a facility licensed to take
waste from a consortium of commercial reactors, is not yet operational.
Two sites in Colorado and Idaho that are managed by DOE and store
commercial spent nuclear fuel from the Fort St. Vrain and Three Mile
Island reactors, respectively, are not included in this count.
^32NRC has determined that there is reasonable assurance that a geologic
repository will be open by 2025, giving it confidence that the nuclear
waste issue will be resolved. In the meantime, NRC testified that
continued interim storage is considered safe. In February 2006, NRC
licensed a centralized interim storage facility in Utah that the electric
power industry is pursuing to relieve congested spent fuel pools. However,
there is no timetable for construction.
^33Funding includes $8.3 billion from the Nuclear Waste Fund, $3 billion
from defense waste, and the remainder from various reprogramming actions.
Both commercial spent nuclear fuel and high-level defense waste are
planned for disposal at Yucca Mountain.
Nuclear energy representatives also told us that another barrier facing
nuclear power is states' opposition to transporting spent nuclear fuel.
Specifically, once Yucca Mountain opens, DOE expects to make about 175
shipments of spent nuclear fuel each year to Yucca Mountain, by both rail
and truck, over at least 24 years. Some states and public interest groups
have cited safety concerns if an incident occurred while the spent fuel
was near populated or environmentally sensitive areas. DOE and NRC
officials report that transportation casks have been certified to
withstand severe accidents and, according to numerous studies, have also
been found to withstand certain acts of sabotage and are considered safe
for transporting spent nuclear fuel.
In fiscal year 1999, DOE began R&D to develop proliferation-resistant
technology for reprocessing spent nuclear fuel. The new technology--called
uranium extraction or UREX--strives to keep plutonium mixed with other
highly radioactive elements. The resulting product can be used as fuel in
a fast reactor, but it would be very unattractive to proliferators because
the desired plutonium is mixed with thermally hot and highly radioactive
elements. The technology still needs to be demonstrated to show that it
can be cost competitive. In addition, while supporting the idea of
reprocessing spent fuel, industry representatives noted that reprocessing
technologies are technically challenging and very expensive and would make
nuclear energy less economic. DOE and industry representatives have
suggested that the reprocessing program, including development of a fast
reactor, could cost about $5 billion by 2012 and could exceed $35 billion
by 2050. DOE and NRC officials noted, however, that the reprocessing
program could delay the need for a second repository, potentially saving
money over the long term.
The States and Countries We Reviewed Have Implemented a Variety of Initiatives
to Encourage the Development and Deployment of Energy Technologies
While federal R&D funding has declined and the government has relied on
the market to determine whether to deploy advanced energy technologies,
the states and countries we reviewed have enacted various standards,
mandates, and financial incentives in an effort to deploy energy
technologies that address their energy needs and environmental concerns.
The states have focused their efforts on stimulating the deployment of
renewable energy technologies; some states have also provided incentives
for stimulating the deployment of advanced fossil and nuclear energy
technologies. Each of the six countries we reviewed has sustained
long-term efforts resulting in the deployment of one or more advanced
renewable, fossil, and/or nuclear energy technologies. While the
countries' initiatives have not been without difficulties, they have
sustained long-term efforts using mandates and/or incentives to deploy
advanced technologies that are providing, or are expected to provide,
significant amounts of energy.
States Are Stimulating Renewable Energy through Standards, Mandates, and
Financial Incentives
Forty-five states have enacted legislation or developed initiatives to
stimulate the deployment of renewable energy technologies, primarily to
address their growing energy demand, reduce adverse impacts on the
environment, encourage local economic development, and/or provide a
reliable, diversified supply of electricity for residents. (See app. III
for states' use of five types of standards, mandates, and financial
incentives for stimulating renewable energy.) As of 2006, (1) 39 states
have established interconnection and net metering rules that require
electric power companies to connect renewable energy sources to the power
transmission grid and credit, for example, the monthly electricity bill of
residents with solar-electric systems when they generate more power than
they use;^34 (2) 22 states have established renewable portfolio standards
(RPS) requiring or encouraging that a fixed percentage of the state's
electricity be generated from renewable sources; and (3) 45 states offer
various tax credits, grants, or loans including, for example, exemptions
from the state sales tax for purchases of renewable energy equipment and
low- or no-interest loans for the purchase of renewable energy equipment.
As shown in figure 5, states in the West, Northeast, and Midwest are
leading many of these efforts.
^34The Public Utility Regulatory Policies Act of 1978, (Pub. L. No.
95-617, (1978)) requires that utilities buy excess energy generated by
small energy producers. The states determine its minimum purchase price.
Figure 5: Distribution of State Incentives and Policies for Renewable
Energy
Note: The map does not show the magnitude of state incentives. For
example, while Minnesota has more types of financial incentives for
renewable energy than California, California's rebate programs have a
collective budget over 500 times greater than the budget for the single
rebate program administered by Minnesota.
Many states have adopted various standards, mandates, and financial
incentives to stimulate the deployment of renewable energy technologies by
offsetting their high startup costs. The following are two examples of
states' initiatives:
o In 2002, New Mexico enacted a production tax credit of 1 cent
per kilowatt-hour for companies that generate electricity from
wind, solar, or biomass. In February 2006, New Mexico enacted a
30-percent personal income tax credit (up to $9,000) for residents
who purchase and install photovoltaic or solar thermal systems.
New Mexico also has net-metering and interconnection rules, which
address connecting renewable energy sources to the power
transmission grid and crediting producers for excess power
generation.
o Since 2004, Massachusetts has provided $2.5 million annually in
grants to consumers who install qualified clean-energy
technologies under the state's RPS. These technologies include
solar thermal electric power, photovoltaics, and wind generation.
Massachusetts also has net-metering and interconnection rules.
Figure 6 shows the number of states that provide each of 12
incentives we reviewed to stimulate renewable energy
Figure 6: Number of States Using Each of 12 Renewable Standards,
Mandates, and Incentives
Note: Net metering and interconnection refer to eligibility and
pricing rules for connecting renewable energy sources to the power
transmission grid and for crediting producers for excess
generation. A public benefit fund is a general fund to support
renewable energy resources, energy efficiency initiatives, and
renewable energy projects for low-income residents, supported by a
small surcharge on each consumer's electricity bill.
In addition to specific incentives and policies, some states have
implemented statewide programs to stimulate the deployment of
advanced renewable energy technologies. Three examples of states'
efforts are described as follows (see app. IV for further
details):
o Since 1980, Minnesota has provided mandates and production
incentives to stimulate ethanol production. In particular,
Minnesota (1) established an incentive in 1986 that paid ethanol
producers 20 cents per gallon over 10 years and (2) mandated in
2003 that all gasoline sold in the state contain at least
10-percent ethanol. In 2004, Minnesota's governor proposed raising
this mandate to 20 percent. As a result, the state is now home to
one-third of the nation's E85 (85 percent ethanol and 15 percent
gasoline) stations and has replaced nearly 10 percent of all its
gasoline consumption with ethanol.
o In 2005, Texas enacted legislation that extended its 1999 RPS to
require the installation of 5,000 megawatts of new renewable
capacity--in addition to 880 megawatts of existing renewable
capacity--by 2015. The Texas RPS represents 5 percent of the
state's electricity demand. Electric power retailers that do not
comply with RPS requirements are subject to penalties of up to $50
per megawatt-hour, or 5 cents per kilowatt-hour. Moreover, to
ensure a wide variety of renewable projects, the Texas RPS
requires that 500 megawatts of new capacity come from renewable
sources other than wind. According to the Electric Reliability
Council of Texas, Inc., as of September 2006, Texas had installed
over 1,900 megawatts of new renewable energy, representing about 3
percent of its total electricity consumption.
o In 2006, California enacted a $2.2 billion solar initiative to
support the governor's goal to install 3,000 megawatts of new
solar energy by 2017. In particular, the initiative provides
rebates for new photovoltaic and solar thermal systems, and
pay-for-performance incentives that reward high-performing solar
systems (greater than 100 kilowatts). The initiative also sets
aside 10 percent of its funding to subsidize solar energy for
low-income and affordable housing projects. According to a state
official, California has already installed more than 150 megawatts
of new solar energy capacity.
Some States Are Offering Incentives to Encourage the Deployment of
New Fossil and Nuclear Energy Technologies
In addition to the investment tax credits and loan guarantees that
the Energy Policy Act of 2005 authorizes for the deployment of
fossil and nuclear technologies, some states have enacted
financial incentives and requirements to further stimulate the
deployment of advanced fossil and nuclear technologies that
support state needs and goals. For example, Indiana enacted
legislation in 2002 to provide financial incentives for clean coal
projects using Illinois Basin coal or gas and extended these
incentives in 2005 by establishing investment tax credits for
state investments in IGCC power plants. Similarly, Pennsylvania's
Energy Deployment for a Growing Economy program provides
low-interest loans for IGCC plants in an effort to build advanced
coal plants that use coals abundant to the state.
However, states provide far fewer incentives for fossil and
nuclear technologies--both in variety and number--than for
renewable energy technologies. As of 2006, only seven states had
incentives for coal gasification and IGCC technologies, according
to the National Conference of State Legislatures. We found no
national database on states' nuclear incentives, although industry
officials said that states or localities may offer a variety of
economic incentives to attract large businesses, such as a nuclear
power plant.
An industry association official noted that states may have an
important influence over regulatory incentives for fossil plants,
such as requiring new coal-fired plants to employ mercury removal
technologies. For example, Idaho has stopped construction on all
conventional pulverized coal-fired power plants until the state
finishes researching the possibility of building new gasification
plants that significantly reduce mercury emissions. Similarly,
while industry officials say state and local incentives for new
nuclear plants--the most common of which are property tax
breaks--do not significantly impact the high costs of plants,
states may have an indirect impact on encouraging or discouraging
the construction of new nuclear plants. For example, seven states
specifically discourage or prohibit the construction of new
nuclear plants until methods of waste disposal are determined. In
contrast, some states and localities may send more positive signs
about nuclear energy by offering economic enticements. For
instance, Calvert County, Maryland, recently offered a 50-percent,
15-year property tax credit to the Calvert Cliffs nuclear power
plant's owner if another nuclear reactor is built.
The Countries We Reviewed Have Stimulated the Development and
Deployment of Advanced Renewable, Fossil, and Nuclear Energy
Technologies
We identified six countries--Brazil, Denmark, Germany, Japan,
Spain, and France--that illustrate a range of financial
initiatives and mandates to stimulate the development and
deployment of advanced renewable, fossil, and nuclear energy
technologies. For example, successful use of financial incentives
and/or mandates has enabled Germany to generate 10.2 percent of
its electricity from renewable sources and Denmark to generate 19
percent of its electricity from wind technologies, surpassing the
United States in the percentage of electricity derived from
renewable sources.
Brazil Has Displaced 40 Percent of Its Gasoline Consumption with
Ethanol
In 1975, in response to oil price shocks, Brazil initiated a
program to replace imported oil with ethanol produced from
domestic sugarcane to power vehicles. To stimulate its ethanol
industry, Brazil (1) required its major oil company, Petrobras, to
purchase a guaranteed amount of ethanol; (2) provided $4.9 billion
in low-interest loans to the agricultural and industrial sectors
to stimulate ethanol production for transportation use; (3)
provided subsidies so ethanol's price at the pump was 59 percent
of the price of gasoline; and (4) required that all fuels be
blended with a minimum of 22 percent ethanol (called E22 fuel).
Brazil removed its price supports for ethanol in 2000, when it
deregulated the ethanol market, but still requires that all fuels
be blended with 20 to 25 percent ethanol, depending on market
conditions. Moreover, to receive an operating license, all fueling
stations must provide an ethanol or ethanol-blend pump. In 2003,
the Brazilian government introduced flex-fuel cars--which can run
on ethanol, gasoline, or a blend of the two, thus allowing
consumers to choose which fuel to use based on the current oil and
ethanol prices--further encouraging the consumption of ethanol.
As of 2005, Brazil was the world's ethanol leader, producing 4.2
billion gallons of ethanol per year, or 47 percent of the world's
supply. Brazil no longer needs to import crude oil for
transportation, saving an estimated $1.8 billion per year by
displacing 40 percent of its gasoline consumption--200,000 barrels
of oil per day--with ethanol, according to Brazilian experts. In
comparison, the United States produced 3.9 billion gallons of
ethanol in 2005, displacing about 3 percent of gasoline
consumption. By 2011, Brazil's ethanol production is expected to
increase to 27 billion gallons per year--a more than 600 percent
increase--from efficiency improvements and land expansion. With
the introduction of flex-fuel cars, consumer confidence in ethanol
consumption has grown significantly, according to Brazilian
embassy officials. As a result, more than 70 percent of cars sold
in Brazil today run on ethanol or ethanol blends, and according to
Brazil's former Secretary of Environment, ethanol is now fully
competitive with international gas prices--sold for 60 to 70
percent of the price of gasoline at the pump.
Brazil has also significantly improved its environmental profile
by replacing oil with ethanol in the transportation sector. From
1975 to 2000, for instance, the use of ethanol in cars saved 100
million tons of carbon emissions, according to Brazilian
authorities. In addition, ethanol production has helped Brazil
become more self-sufficient in electricity. In particular, by
burning sugarcane waste, mills have been able to generate energy
surpluses of around 600 megawatts per crop season, allowing them
to be completely self-sufficient in electricity, and in some
cases, to export electricity abroad.
Denmark�s Wind Energy Generates 19 Percent of Its Electricity
Successive Danish governments have committed to a series of
national energy plans aimed at reducing dependency on imported
fuels, improving the environment, and moving toward greater
sustainability. As a result, since 1980 there has been general
consensus in Denmark that renewable technologies--and especially
wind energy--require special support to gain an advantage in the
market. Specifically, the Danish government has (1) conducted R&D
in wind turbine technologies since the 1970's; (2) provided
investment subsidies for 30 percent of the installation cost of
wind turbines until 1990; and (3) required that electric power
companies purchase wind energy from private producers at a fixed
price until 1999, when the obligation moved to electricity
consumers paying for all increased costs associated with wind
power. In addition, the government exempts wind generators from a
carbon dioxide tax,^35 gives wind power priority access to the
electric power grid, and has established regulations for building
wind turbines.
In 2005, renewable energy accounted for approximately 28 percent
of the Danish electricity supply, including 19 percent from wind
power--the highest percentage in the world. Since 1980, more than
6,000 wind turbines have been established in Denmark. From 2001 to
2003, a repowering program led to approximately 1,500 smaller wind
turbines being replaced by approximately 300 new and larger wind
turbines, which together have tripled the capacity. At the end of
2005, Denmark had 3,122 megawatts of installed wind power
capacity--more than the 2,631 megawatts of the installed capacity
in Texas, the nation's leader in wind power.
Denmark's long-term support of wind energy has fostered a thriving
wind turbine industry, with global sales increasing over the last
decade from about 200 megawatts of capacity per year to more than
3,000 megawatts per year. Danish wind turbine manufacturers
accounted for about 40 percent of global sales in 2004, providing
about 20,000 jobs domestically, or 4 percent of Danish industrial
production. In particular, Denmark is a world leader in offshore
wind power development. Denmark built the first offshore wind farm
in 1991 and had eight operating offshore wind farms by the end of
2005. Two additional offshore wind farms are planned to supply
electricity to 350,000 to 400,000 households, or about 4 percent
of the total Danish electricity consumption.^36 As a result of its
experience, Denmark has gained extensive technical knowledge in
how to integrate wind power into the overall electricity system,
how to combine wind power with other sources of energy to maintain
the electrical system's stability, and how to develop offshore
wind farms--including the logistics of transporting, installing,
and maintaining wind turbines at sea.
Germany�s Renewable Energy Technologies Generate 10 Percent of Its
Electricity
In 2000, the German government enacted the Renewable Energy
Sources Act to accelerate the growth of renewable energy
technologies in the German electricity market. It amended the act
in 2004 to increase country targets for renewable technologies and
further develop the framework conditions for renewable
technologies.^37 The Renewable Energy Sources Act requires
electricity grid operators to purchase electricity generated from
renewable energy technologies and establishes minimum rates for
it. Germany's goal is to increase the share of renewable energy
consumption to at least 4.2 percent of its total energy
requirements by 2010, 10 percent by 2020, and at least 50 percent
by 2050. The target for 2010 was exceeded in 2005, when renewable
technologies accounted for 4.6 percent of consumption. The German
government is also offering tax relief for biofuels and financial
support for constructing plants that generate heat and/or
electricity from renewable energy sources. In response, Germany
has more than doubled its electricity consumption from renewable
energy sources--from 4.8 percent in 1998 to 10.2 percent in 2005.
In particular, Germany generated about 1 billion kilowatt-hours of
solar electricity in 2005, tripling the generation of electricity
from solar cells in 2 years. Germany has also become the world
leader in wind energy with 18,428 megawatts of installed wind
capacity that produced 26.5 terawatt-hours of electricity in 2005.
Under the Kyoto Protocol and as a member of the European Union,
Germany has committed to a 21-percent reduction in the 1990
baseline year's greenhouse gas emissions from 2008 to 2012. The
German government believes the Renewable Energy Sources Act is one
of Germany's most effective and efficient instruments for climate
protection, stating that using renewable energy technologies
prevented the emission of approximately 84 million tons of carbon
dioxide in 2005. The government also states that renewable energy
technologies have created jobs in Germany--the renewables sector
had 157,000 jobs in 2004, including 64,000 jobs in wind power,
57,000 jobs in biomass, and 25,000 in the solar industry. The
government estimates that renewable energy jobs increased to
170,000 in 2005, and German industry estimates that this number
will grow to more than 255,000 by 2010.
Japan Has Installed over 931 Megawatts of Residential Solar
Systems
In 1994, Japan launched a 10-year residential solar project as
part of its efforts to deploy domestic energy technologies that
would diversify its energy portfolio and reduce its dependence on
energy imports.^38 The goal of the residential solar project was
to reduce the cost of photovoltaics and promote installation of
solar systems in residential communities. Initially, the Japanese
government provided a subsidy covering 50 percent of the cost of
installing a residential solar system. This percentage
subsequently dropped to 33 percent and eventually became a fixed
amount as the 10-year project matured. As a result of the project,
over 253,000 homes installed solar systems that collectively
generate over 931 megawatts of power. Even though the government
subsidy decreased, the number of systems installed increased
considerably year by year, as the installation price decreased.
According to a solar manufacturer, the cost of installing a solar
system dropped from about $16,000 per kilowatt in 1994 to about
$6,000 per kilowatt when the project ended. Due to the successful
transformation of the photovoltaic market, Japanese homeowners
continue to buy and install solar systems without the government
subsidy.
The 10-year residential solar project has also helped create a
Japanese solar industry that has become a world leader in the
photovoltaic market. According to the European Commission,
Japanese manufacturers' share of the world photovoltaic market is
now greater than 40 percent. The residential solar project also
enables the Japanese government to fulfill its commitment to
increase its share of renewables in its energy portfolio to about
3 percent by 2010 and reduce its greenhouse gas emissions under
the Kyoto Protocol.
Spain Began Operating an IGCC Coal Gasification Plant in 1997
In the early 1990s, the European Union and the Spanish government
collaborated to construct the world's largest coal-based IGCC
plant in Puertollano, Spain, to improve the efficiency, cost, and
environmental profile of coal-based power plants. The 320-megawatt
IGCC plant, which began generating electricity from coal in 1998,
is operated by a consortium of eight utilities from France,
Germany, Italy, Portugal, Spain, and the United Kingdom as part of
a European Union program to demonstrate energy technologies that
promote clean coal and reduce the European Union's dependency on
natural gas.
The European Union and the Spanish government supported the
construction of the Puertollano plant by subsidizing about 8.5
percent of its nearly $900 million cost. European consortium
members noted that, in comparison, DOE can fund up to 50 percent
of the cost of commercial IGCC demonstration projects. In 2000,
the Puertollano plant produced nearly 1 million megawatts of
electricity using synthetic gas. The Puertollano plant is expected
to operate at over 45 percent efficiency and eliminate 99.9
percent of sulfur dioxide emissions. DOE plans to achieve
efficiencies and emissions levels comparable to the Puertollano
plant by 2010--currently, U.S. IGCC plants are about 40-percent
efficient and eliminate 98 percent of sulfur dioxide emissions.
France�s Advanced Nuclear Reactor Is Scheduled to Begin
Operations in 2012
In response to the oil price shocks in 1973, France decided to
reduce its reliance on oil-fired power plants to generate
electricity by launching a nuclear initiative designed to make
nuclear power a primary source of electricity. France built 56
nuclear reactors during the 1970s and 1980s and, according to the
International Energy Agency, spent about 90 percent of its energy
R&D funding on nuclear energy from 1985 through 2001. The French
government reported that its R&D efforts during this time focused
on technological improvements and safety, as well as development
of a fast reactor. Today, France has 58 nuclear reactors
generating 75 to 80 percent of its electricity.
France does not license reactors for a specific amount of time,
but conducts reviews every 10 years to grant continued operational
authority. Reactors are expected to operate for about 40 years.
Some interest groups in France have called for an end to nuclear
energy, citing radioactive waste and safety issues and noting that
Germany has decided to phase out of nuclear energy and close down
its reactors. However, the French government has maintained its
support for nuclear energy, deciding in a 2005 law to keep the
nuclear option open for the future and planning to potentially
replace its current reactors with a new generation of reactors
designed to be more efficient, safer, and less susceptible to
external threats. As part of this effort, France has developed the
European Pressurized Reactor, which uses Generation III technology
and will be capable of generating 1,600 megawatts of electricity,
a significant increase over the capacity of existing reactors,
which range from 900 megawatts to 1,450 megawatts. Two European
Pressurized Reactors are under construction--one in Flammanville,
France, scheduled to be operational in 2012 and a second in
Finland scheduled to be operational in 2009.
France is one of 13 partners in the Generation IV International
Forum that collaborates on R&D to develop next generation nuclear
reactor technologies. France is conducting R&D on several nuclear
reactors, including the sodium-cooled fast reactor that is a
critical element of the U.S. GNEP program. In addition, France has
provided U.S. researchers with access to the French Phenix fast
reactor to study how highly radioactive nuclear fuel might be
converted to less radiotoxic material.
Conclusions
It is unlikely that DOE's current level of R&D funding or the
nation's current energy policies will be sufficient to deploy
alternative energy sources in the next 25 years that will reverse
our growing dependence on imported oil or the adverse
environmental effects of using conventional fossil energy. The
United States has generally relied on market forces to determine
the nation's energy portfolio, primarily conventional supplies of
oil, natural gas, coal, and nuclear energy. In contrast, advanced
energy technologies have higher up-front capital costs that make
them less cost competitive than conventional technologies. As a
result, despite periodic energy price spikes caused by disruptive
world events and about $50 billion (in real terms) in energy R&D
funding since 1978, the United States has made only steady
incremental progress in developing and deploying advanced
renewable, coal, and nuclear technologies that can compete with
conventional energy technologies. However, continued reliance on
conventional technologies leaves the United States vulnerable to
crude oil supply disruptions, with economic, energy security, and
national security consequences.
The nation is once again assessing how best to stimulate the
deployment of advanced energy technologies in response to recent
high energy prices--caused by the growing world demand for energy,
wars in the Middle East, and last year's hurricanes--and concerns
about the adverse environmental effects, particularly greenhouse
gas emissions, of using conventional fossil energy. Reducing the
nation's dependence on oil and carbon dioxide emissions in the
next 25 years is not unlike the 1960s challenge to put a man on
the moon. Without sustained high energy prices or concerted,
high-profile federal government leadership, U.S. consumers are
unlikely to change their energy-use patterns, and the United
States will continue to rely upon its current energy portfolio.
Specifically, government leadership is needed to overcome
technological and market barriers to deploying advanced energy
technologies that would reduce the nation's vulnerability to oil
supply disruptions and the adverse environmental effects of
burning fossil fuels.
The nation's current energy portfolio has raised concerns about
the adverse environmental effects of energy
generation--particularly greenhouse gas emissions from coal-fired
and oil-fired power plants and the long-term storage of spent
nuclear fuel. In addition, the duration of certain federal tax
incentives has been insufficient to stimulate investment decisions
to deploy advanced energy technologies. For example, renewable
energy industry representatives have stated that the 2-year
extension of the production tax credit in the Energy Policy Act of
2005 does not provide sufficient certainty to stimulate
investment. In providing a production tax credit to stimulate the
construction of projects using advanced technologies, the credit's
duration is key to encouraging companies and their lenders to
undertake the substantial investments and build an industry over
time.
Several states have taken the lead in encouraging the deployment
of advanced energy technologies, particularly in renewable energy.
For example, in the past 7 years, Texas tripled its renewable
energy use as a result of its renewable portfolio standard.
Similarly, Minnesota's ethanol program has displaced 10 percent of
gasoline consumption with ethanol. Many other states have
initiatives to stimulate renewable energy generation as well.
States' initiatives that diversify our energy portfolio and reduce
harmful emissions are positive steps. Similarly, foreign
countries, including Brazil, Denmark, and Germany, have sustained
long-term efforts using mandates and/or financial incentives to
deploy advanced energy technologies that are providing, or are
expected in the future to provide, significant amounts of energy.
Approaches taken by these countries may provide useful insights
and opportunities for fostering the deployment of advanced energy
technologies.
Recommendation to the Congress
To meet the nation's rising demand for energy, reduce its economic
and national security vulnerability to crude oil supply
disruptions, and minimize adverse environmental effects, the
Congress should consider further stimulating the development and
deployment of a diversified energy portfolio by focusing R&D
funding on advanced energy technologies.
Agency Comments
We provided DOE with a draft of this report for its review and
comment. In its written response, DOE did not comment on our
recommendation to the Congress. (See app. V.) DOE provided
technical comments, which we have incorporated as appropriate.
As arranged with your offices, unless you publicly announce its
contents earlier, we plan no further distribution of this report
until 30 days from the report date. At that time, we will send
copies to interested congressional committees, the Secretary of
Energy, the Director of the Office of Management and Budget, and
other interested parties. We will also make copies available to
others upon request. In addition, the report will be available at
no charge on the GAO Web site at http://www.gao.gov .
If you or your staffs have any questions about this report, please
contact me at (202) 512-3841 or [email protected]. Contact points for
our Offices of Congressional Relations and Public Affairs may be
found on the last page of this report. GAO staff who made major
contributions to this report are listed in appendix VI.
Jim Wells
Director, Natural Resources and Environment
^35Renewable technology plants are exempt from taxes placed on power
plants that emit carbon dioxide.
^36One of the new offshore developments, Horns Rev II, is expected to be
operational by 2009.
^37The German government also amended the Atomic Energy Act in 2002, which
will systematically decommission the nation's existing nuclear power
plants once the volume of electricity specified for each plant is
generated--the last nuclear power plant in Germany is estimated to shut
down about 2020.
^38About half of Japan's total energy demand is for oil, which is
primarily imported from the Middle East.
Appendix I: Estimated Federal Tax Expenditures Targeted at Energy
Suppliers and Users, Fiscal Year 2006
Dollars in millions
Estimated
Federal tax expenditures targeted First FY 2006
at energy suppliers and users^a Budget function year^b revenue loss
1 Capital gains treatment of Energy 1974 $90
royalties on coal
2 Excess of percentage over cost Energy 1974 670
depletion, fuels
3 Expensing of exploration and Energy 1974 680
development costs, fuels
4 New technology credits (addresses Energy 1978 510
energy production from several
technologies, including wind and
solar energy)
5 Alcohol fuel credits^c Energy 1980 40
6 Alternative fuel production credit Energy 1980 2,390
7 Exclusion of interest on energy Energy 1980 90
facility bonds
8 Exception from passive loss Energy 1988 40
limitation for working interests in
oil and gas properties
9 Tax credit and deduction for Energy 1992 90
clean-fuel burning vehicles
10 Enhanced oil recovery credit Energy 1994 0
11 Credit for holding clean renewable Energy 2005 0
energy bonds
12 Deferral of gain from dispositions Energy 2005 620
of transmission property to
implement the Federal Energy
Regulatory Commission's
restructuring policy^d
13 Credit for production from advanced Energy 2005 0
nuclear power facilities
14 Credit for investment in clean coal Energy 2005 50
facilities
15 Temporary 50 percent expensing for Energy 2005 10
equipment used in the refining of
liquid fuels
16 Pass through low sulfur diesel Energy 2005 0
expensing to cooperative owners
17 Natural gas distribution pipelines Energy 2005 20
treated as 15-year property
18 Amortize all geological and Energy 2005 40
geophysical expenditures over 2
years
19 30 percent credit for residential Energy 2005 10
purchases/installations of solar
and fuel cells
20 Credit for business installation of Energy 2005 80
qualified fuel cells and stationary
microturbine power plants
21 Alternative Fuel and Fuel Mixture Energy 2005 170
tax credit
22 Bio-Diesel and small agri-biodiesel Agriculture 2004 90
producer tax credits
23 Expensing of small refiner capital Natural 2004 10
costs with respect to complying resources and
with EPA sulfur regulations environment
Total estimated tax expenditures^e $5,700
Source: GAO analysis of tax expenditures reported by the
Department of the Treasury.
Note: For descriptions of tax expenditures, see Office of
Management and Budget. Analytical Perspectives, Budget of the
United States Government, Fiscal Year 2007, (Washington, D.C.:
2005).
aThis list does not include five tax expenditures whose primary
focus is energy conservation--exclusion of utility conservation
subsidies, deduction for certain energy efficient commercial
building property as well as tax credits for construction of new
energy efficient homes, energy efficiency improvements to existing
homes, and energy efficient appliances--with revenue loss
estimates summing to $510 million for fiscal year 2006. This list
also does not include tax incentives for general research and
development available for all businesses. Also, the Department of
Treasury does not report tax expenditures with revenue losses
below $5 million.
bFirst year the Department of the Treasury reported expenditures.
cThe alcohol fuel credit includes, among other things, the
volumetric tax credit for ethanol, which was enacted in 2004.
Treasury estimates a $2.1 billion reduction in excise tax receipts
in fiscal year 2006 as a result of income tax revenue losses and
reduced excise tax receipts.
dThis tax expenditure was listed under the community and regional
development budget function in 2004.
eSumming tax expenditure estimates does not take into account
interactions between individual provisions.
Appendix II: Scope and Methodology
To review the Department of Energy's (DOE) research and
development (R&D) funding trends, we analyzed DOE budget authority
data for renewable, fossil, and nuclear energy R&D from fiscal
year 1978 through fiscal year 2006. The data consist of DOE's
annual appropriations, adjusted for any advanced appropriations
and rescissions. To assess the reliability of these data, we
interviewed DOE program managers and budget officials with
oversight of each of the technologies. We asked DOE officials a
series of data reliability questions, including questions covering
data classification, particularly over time; program changes that
could impact data classification or budget accounts; custody and
maintenance of the data, including updates; quality control
procedures; and accuracy and completeness of the data. Where
appropriate, we adjusted the data to ensure consistency in
reporting over time. We obtained historical documents, program
plans, and assessments from other entities to corroborate the
data. We determined that the data were sufficiently reliable for
the purposes of this report. In addition to DOE's R&D funding, we
reviewed revenue losses from energy-related tax expenditures for
fiscal years 2000 through 2006 by reviewing tax expenditure
revenue loss estimates prepared by the Department of the Treasury
and published in the President's annual budget. While the
aggregate value for energy-related tax expenditures is useful for
gauging their general magnitude, summing does not take into
account interactions between individual provisions. We excluded
annual tax expenditures below $5 million because Treasury does not
report them. To review DOE's strategy for developing advanced
energy technologies, we reviewed DOE documents, including
strategic plans, program plans, and studies on each of the
technologies. We also collected and analyzed documents from
industry and industry associations. In addition, we interviewed
senior DOE managers, program managers and scientists at DOE
laboratories, senior power company and industry association
executives, and independent experts.
To assess the key technological, economic, and other barriers to
developing and deploying new energy technologies, we analyzed
various documents from DOE, including program plans, energy
studies and assessments, and key budget documents, including
supporting documentation justifying budget requests. We also
analyzed documents from other federal agencies; utilities;
industry associations; state utility commissions and associations;
and independent experts, including studies from the Electric Power
Research Institute, the Massachusetts Institute of Technology, and
the University of Chicago. We interviewed DOE and NRC officials;
program managers and scientists at DOE laboratories; executives of
utilities, manufacturers, and industry associations; public
utility commissions from various states; and selected state
governments and government associations.
To examine the efforts of states to develop and deploy advanced
energy technologies, we analyzed reports and assessments from DOE,
various state governments and associations, industry and industry
associations, and independent experts. We also used the Database
of State Incentives for Renewable Energy, maintained by the
Interstate Renewable Energy Council, to analyze state initiatives
and select three states with successful initiatives--Texas'
renewable portfolio standards, Minnesota's ethanol program, and
California's solar programs. To assess the reliability of this
database, we reviewed relevant documentation and obtained
responses from the database administrator to a series of data
reliability questions covering issues such as data entry, access,
quality control procedures, and the accuracy and completeness of
the data. We determined that the data were sufficiently reliable
for the purposes of this report. In addition to the database, we
collected documents and interviewed officials from DOE; industry
and industry associations; and various state organizations,
including the National Conference of State Legislatures and the
Western Governor's Association; and selected public utility
commissions.
To develop a nonprobability sample of countries that have
developed and deployed advanced renewable, fossil, and nuclear
technologies, we (1) reviewed the Energy Information
Administration's (EIA) international data to identify significant
changes in consumption patterns among renewable, fossil, and
nuclear energy technologies; (2) examined other related
information; and (3) interviewed cognizant DOE officials and
independent industry experts.^1 We selected Brazil, Denmark,
France, Germany, Japan, and Spain because they have initiated
major efforts to deploy advanced energy technologies that could
change their energy portfolios. To obtain information on each
country's initiatives, we analyzed documents from EIA, the
International Energy Agency, each of the countries, and
independent experts. We also interviewed DOE officials; officials
from each country, either at their U.S. embassy or by telephone or
e-mail; and independent experts.
We conducted our work from October 2005 through October 2006 in
accordance with generally accepted government auditing standards.
^1Results from a nonprobability sample cannot be used to make inferences
about a population because in a nonprobability sample some elements of the
population being studied have no chance or an unknown chance of being
selected as part of the sample.
Appendix III: The States� Use of Renewable Energy Incentives,
Standards, and Mandates
Public Renewable Net metering &
Tax benefit portfolio interconnection
State credits^a Rebates^b funds^c standards^d rules^e
Alabama o
Alaska
Arizona o o
Arkansas o
California o o o o o
Colorado o o
Connecticut o o o o
Delaware o o o o
Florida o
Georgia o
Hawaii o o o
Idaho o
Illinois o o o
Indiana o
Iowa o o o
Kansas o
Kentucky o
Louisiana o
Maine o o o o
Maryland o o o o
Massachusetts o o o o o
Michigan o
Minnesota o o o o
Mississippi
Missouri o o
Montana o o o o
Nebraska
Nevada o o o
New Hampshire o
New Jersey o o o o
New Mexico o o o
New York o o o o o
North Carolina o o
North Dakota o o
Ohio o o o
Public Renewable Net metering &
Tax benefit portfolio interconnection
State credits^a Rebates^b funds^c standards^d rules^e
Oklahoma o o
Oregon o o o o
Pennsylvania o o o
Rhode Island o o o o o
South Carolina o
South Dakota
Tennessee
Texas o o o
Utah o o
Vermont o o o
Virginia o
Washington o
West Virginia o
Wisconsin o o o o
Wyoming o o
Total 21 17 15 22 39
Source: GAO analysis of the Database of State Incentives for
Renewable Energy, maintained by the Interstate Renewable Energy
Council.
aProvided to corporations or individuals that purchase or install
renewable energy equipment. For example, New Mexico offers a
30-percent personal income tax credit (up to $9,000) for residents
who install photovoltaic or solar thermal systems. Tax credits are
one of the most frequently used state-level financial incentives.
bTypically provided in the form of cash rebates to residents and
businesses for the purchase and installation of renewable energy
equipment. For example, New York provides $4 to $4.50 per watt to
eligible installers for the installation of approved,
grid-connected photovoltaic systems.
cA surcharge on each consumer's electricity bill that goes into a
general fund to support renewable energy resources, energy
efficiency initiatives, and renewable energy projects for
low-income residents. For example, Connecticut residents are
charged up to 0.1 cents per kilowatt-hour on their utility bills,
which provides funding for Connecticut's Energy Efficiency Fund
for energy efficiency and Clean Energy Fund for renewable energy.
dRequire that a fixed percentage of the state's electricity be
generated from renewable sources. For example, Texas enacted
legislation in 2005 requiring the installation of 5,000 megawatts
of new renewable capacity by 2015. According to the National
Conference of State Legislatures, renewable portfolio standards
have been particularly successful in encouraging wind power
development.
eEligibility and pricing rules for connecting renewable energy
sources to the power transmission grid and crediting producers for
excess generation. For example, the value of energy generated in
excess of what is used is subtracted from the monthly utility bill
of residents in Arizona with solar-electric systems.
Appendix IV: Three States� Initiatives to Stimulate the Use of
Renewable Energy Technologies
Minnesota, Texas, and California have implemented programs to
stimulate the use of renewable energy technologies. In response to
various incentives and mandates, Minnesota now has one-third of
the nation's ethanol fueling stations and had displaced nearly 10
percent of its gasoline consumption with ethanol by June 2006.
Since Texas enacted renewable portfolio standards (RPS) in 1999,
its electric power companies have installed over 1,900 megawatts
of new renewable energy capacity--approximately 3 percent of the
state's total electricity generation. Since California began its
Solar Initiative in January 2006, over 150 megawatts of new solar
capacity have been installed.
Minnesota�s Ethanol Program
Minnesota's Ethanol Program began in 1980 as an effort to expand
the state's farm economy by building a new market for corn, its
largest crop; meet EPA standards for air quality in the Twin
Cities area by reducing carbon monoxide emissions from cars; and
reduce dependence on imported oil. To reach these goals, Minnesota
established financial incentives and mandates to encourage the
development of a state ethanol industry over a 17-year period. As
of June 2006, ethanol had displaced nearly 10 percent of
Minnesota's gasoline consumption.
The Minnesota Ethanol Program encouraged growth in the state's
ethanol industry, primarily through the use of producer incentives
and mandated ethanol blends. In particular, state legislation
passed in 1980 provided a tax credit for gasoline that was blended
with 10-percent ethanol, and in 1986, the state set up a producer
payment incentive that paid ethanol producers 20 cents per gallon
for a 10-year period. Legislation enacted in 1992 required that
all gasoline offered for sale in the state be blended with 7.7
percent ethanol beginning in 1997. This provision was amended in
2003 to require blends to contain at least 10 percent ethanol. In
1995, Minnesota also established a statutory goal to develop over
200 million gallons of ethanol production. The tax credits were
eliminated in 1997, and the producer incentive payments were
phased out beginning in the late 1990s.^1 In 2004, Minnesota
enacted legislation doubling the requirement to 20 percent by
2013.
Currently, nearly all gasoline in Minnesota is blended with
10-percent ethanol, representing over $100 million in annual
savings on oil imports. Ethanol production has expanded from 1.5
million gallons in 1987 to a current capacity of over 500 million
gallons. Corn prices have also doubled to 30 cents a bushel, and
the Twin Cities area is in compliance with EPA air quality
standards, according to Minnesota officials. Minnesota is the
nation's leader in the use of renewable fuels, with the highest
renewable fuel use per capita in the nation. It is home to 32
percent of the nation's E85 stations.
Texas� Renewable Portfolio Standards
To reduce a growing dependency on imported fossil fuels, make
better use of the region's natural renewable resources, and
improve air quality profiles, Texas enacted legislation in 2005
that extended its 1999 RPS to require the installation of 5,000
megawatts of new renewable capacity, or about 5 percent of the
state's electricity demand, by 2015. Texas has already tripled its
use of renewable energy in the 7 years since its RPS was initially
enacted.
Texas uses more total energy--including electricity, petroleum,
natural gas, and coal--than any other state. In the early 1990s,
Texas' use of renewable energy was less than 1 percent, the lowest
in the United States. In 1992, Texas became a net importer of
energy. Moreover, if Texas was a country, it would have ranked 7th
in the world for greenhouse gas emissions in the early 1990s,
according to climate change experts at the Pew Center on Global
Climate Change. Despite these conditions, however, Texas also
ranks first in abundance of U.S. solar and biomass resources, and
second for wind resources. To encourage the use of the state's
abundant renewable resources and improve its environmental
profile, Texas' 1999 legislation established an RPS mandating that
state utilities derive 2,000 megawatts of new generating capacity
from renewable sources by 2009. When Texas had nearly reached this
capacity by 2005, new legislation increased the mandate to 5,000
new megawatts by 2015. Electric power retailers that do not comply
with RPS requirements are subject to penalties of up to $50 per
megawatt-hour, or 5 cents per kilowatt-hour, as tracked by a
renewable energy credit system. To encourage a wide variety of
renewable developments, the Texas RPS also requires that 500
megawatts of total mandated new capacity come from renewable
sources other than wind, because wind power is the most
competitive renewable energy technology in Texas--98 percent of
new installed capacity in Texas prior to 1999 was wind power. In
addition, Texas' RPS set a nonbinding target of 10,000 megawatts
of installed renewable capacity by January 1, 2025.
According to the Electric Reliability Council of Texas, Inc., as
of September 2006, Texas had tripled its renewable energy
capacity, installing over 1,900 megawatts of new capacity,
representing about 3 percent of its total electricity consumption.
During 2001 alone, Texas installed 912 megawatts of wind
power--more than the entire country had installed in any previous
year--and created 2,500 wind-power related jobs. Texas' 2025 goal
would result in an estimated $5 billion in consumer electric bill
savings and the creation of nearly 20,000 jobs, according to the
Union of Concerned Scientists.
California�s Solar Programs
Since 1998, California has supported the installation of solar
systems--including photovoltaic systems and solar thermal
systems--by establishing production incentives and rebates for
solar energy generators and consumers. These programs are designed
to reduce electricity demand and improve the reliability of the
state's electricity system. In January 2006, California enacted a
$2.2 billion Solar Initiative to install 3,000 megawatts of new
solar energy by 2017, supporting the governor's 2006 "Million
Solar Roofs Plan" to power 50 percent of all California homes--or
1 million roofs--with solar energy by 2019. As of January 2006,
California had installed over 150 megawatts of new solar systems
on over 20,000 homes, businesses, schools, and government
buildings, according to California state officials and a
California environmental group.
California established the Emerging Renewables Program in 1998.
Implemented by the California Energy Commission, the program has
encouraged the use of naturally abundant solar resources by
allocating $118 million in rebates from 2002 through 2006 for the
installation of new, primarily residential, renewable energy
generating systems. In particular, for systems less than 30
kilowatts, the program offered $2.60 per watt for the installation
of solar-cell systems and $3.00 per watt for the installation of
solar-thermal systems. The Emerging Renewables Program also
allocated $10 million toward a performance-based incentive option
for photovoltaic installations, giving electricity generators
$0.50 per kilowatt-hour over a 3-year period. In 2001, the
California Public Utilities Commission initiated the
Self-Generation Incentive Program, which offers rebates through
2007 for nonresidential distributed renewable generation for 30
kilowatt or larger systems. Since its inception, the rebate
program has spent about $50 million per year, achieving 50
megawatts of installed solar capacity, with another 62 additional
megawatts in progress. In 2006, the Public Utilities Commission
introduced the California Solar Initiative, which will provide
$2.9 billion in solar energy incentives over 11 years and support
the governor's Million Solar Roofs Plan to install 3,000 megawatts
of new solar energy capacity by 2017. By integrating California's
existing Emerging Renewables Program and rebate solar programs,
the initiative will continue to encourage new solar installations
through rebate incentives for new photovoltaic and solar thermal
systems, and pay-for-performance incentives that reward
high-performing solar systems (greater than 100 kilowatts). To
help sustain the solar industry, rebates for new solar systems
will begin at $2.50 per watt, but will decline by about 10 percent
annually over the next 10 years. In addition, the initiative sets
aside 10 percent of program funding for low-income and affordable
housing projects.
^1Some payments are still being made to producers that qualified for the
program prior to 1999. However, these payments are now less than 20
percent and are being continuously phased out.
Appendix V: Comments from the Department of Energy
Appendix VI: GAO Contact and Staff Acknowledgments
GAO Contact
Jim Wells (202) 512-3841 or [email protected]
Staff Acknowledgments
In addition to the individual named above, Richard Cheston,
Assistant Director; Robert Sanchez, Kerry Lipsitz, Christina
Connelly, Chuck Bausell, MaryLynn Sergent, Anne Stevens, and
Alison O'Neill made key contributions to this report. Also
contributing to this report were Doreen Feldman, Barbara
Timmerman, and Jenny Chanley.
GAO�s Mission
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Highlights of [58]GAO-07-106 , a report to congressional requesters
December 2006
DEPARTMENT OF ENERGY
Key Challenges Remain for Developing and Deploying Advanced Energy
Technologies to Meet Future Needs
Despite periodic price shocks and related energy crises, the United States
is even more dependent on crude oil and natural gas than it was almost 30
years ago. And, without dramatic change, the nation will become ever more
reliant on imported oil and natural gas with attendant threats to national
security. The nation has also become concerned about global warming, which
has been linked to carbon dioxide emissions from burning coal and oil. To
address these concerns, the Department of Energy (DOE) has funded research
and development (R&D) on advanced renewable, fossil, and nuclear energy
technologies. GAO examined the (1) R&D funding trends and strategies for
developing advanced energy technologies, (2) key barriers to developing
and deploying advanced energy technologies, and (3) efforts of the states
and six selected countries to develop and deploy advanced energy
technologies. GAO reviewed DOE R&D budget data and strategic plans and
interviewed DOE officials and scientists, U.S. industry executives,
independent experts, and state and foreign government officials.
[59]What GAO Recommends
GAO suggests that the Congress consider further stimulating the
development and deployment of a diversified energy portfolio by focusing
R&D funding on advanced energy technologies. DOE had no comment on this
recommendation.
DOE's total budget authority for energy R&D dropped by over 85 percent (in
real terms) from 1978 to 2005, peaking in the late 1970s but falling
sharply when oil prices returned to lower levels in the mid-1980s (see
table). DOE's R&D efforts have resulted in steady incremental progress in
reducing costs for renewable energy technologies, reducing harmful
emissions of coal-fired power plants, and improving safety and efficiency
for nuclear power plants.
Further development and deployment of advanced renewable, fossil, and
nuclear energy technologies face several key challenges. Challenges for
renewable technologies include developing (1) cost-effective technologies
to produce ethanol using agricultural residues and other biomass materials
as well as the infrastructure for distributing ethanol, (2) new wind
technologies to expand into low wind and offshore locations, and (3)
improved solar technologies that can better compete with conventional
technologies. Challenges for fossil technologies are primarily associated
with developing advanced coal gasification technologies to further reduce
harmful emissions and reducing their high capital costs. Challenges for
advanced nuclear technologies include uncertainty about the Nuclear
Regulatory Commission's revised licensing process, investor concerns about
high capital costs, and the disposal of a legacy of spent nuclear fuel.
Many states have successfully stimulated the deployment of renewable
energy technologies by using standards, mandates, and financial incentives
that require, for example, power companies to provide small producers with
access to the power transmission grid and purchase their excess energy.
Each of the six countries GAO reviewed has used mandates and/or financial
incentives to deploy advanced energy technologies that are providing, or
are expected in the future to provide, significant amounts of energy.
Budget Authority for Renewable, Fossil, and Nuclear R&D, Fiscal Years
1978-2005
Note: Budget authority is in real terms, adjusted to fiscal year 2005
dollars to account for inflation.
References
Visible links
47. http://www.gao.gov/cgi-bin/getrpt?GAO-05-690
48. http://www.gao.gov/cgi-bin/getrpt?GAO-06-629
49. http://www.gao.gov/cgi-bin/getrpt?GAO-05-906
50. http://www.gao.gov/
51. http://www.gao.gov/
52. http://www.gao.gov/
53. http://www.gao.gov/fraudnet/fraudnet.htm
54. file:///home/webmaster/infomgt/d07106.htm#mailto:[email protected]
55. file:///home/webmaster/infomgt/d07106.htm#mailto:[email protected]
56. file:///home/webmaster/infomgt/d07106.htm#mailto:[email protected]
57. http://www.gao.gov/cgi-bin/getrpt?GAO-07-106
58. http://www.gao.gov/cgi-bin/getrpt?GAO-07-106
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