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entitled 'Department of Energy: Key Challenges Remain for developing 
and Deploying Advanced Energy Technologies to Meet Future Needs' which 
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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: 

GAO Highlights: 

Highlights of GAO-07-106, a report to congressional requesters 

Why GAO Did This Study: 

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. 

What GAO Found: 

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. 

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. 

[Hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-07-106]. 

To view the full product, including the scope and methodology, click on 
the link above. For more information, contact Jim Wells at 202-512-3841 
or wellsj@gao.gov. 

[End of Section] 

Contents: 

Letter: 

Results in Brief: 

Background: 

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: 

Advanced Renewable, Fossil, and Nuclear Energy Technologies Face Key 
Barriers to Market Deployment: 

The States and Countries We Reviewed Have Implemented a Variety of 
Initiatives to Encourage the Development and Deployment of Energy 
Technologies: 

Conclusions: 

Recommendation to the Congress: 

Agency Comments: 

Appendix I: Estimated Federal Tax Expenditures Targeted at Energy 
Suppliers and Users, Fiscal Year 2006: 

Appendix II: Scope and Methodology: 

Appendix III: The States' Use of Renewable Energy Incentives, 
Standards, and Mandates: 

Appendix IV: Three States' Initiatives to Stimulate the Use of 
Renewable Energy Technologies: 

Appendix V: Comments from the Department of Energy: 

Appendix VI: GAO Contact and Staff Acknowledgments: 

Tables: 

Table 1: Comparison of Conventional Pulverized Coal and IGCC 
Technologies: 

Table 2: Comparison of Electricity Generating Costs Using Nuclear, 
Coal, and Natural Gas Energy Sources: 

Table 3: Comparison of Electricity Generating Costs Assuming a Carbon 
Emissions Tax: 

Figures: 

Figure 1: Comparison of the U.S. Energy Portfolio in 1973 and 2004: 

Figure 2: Projected U.S. Electricity Generation by Energy Source, 2005- 
2030: 

Figure 3: DOE's Budget Authority for Renewable, Fossil, and Nuclear 
R&D, Fiscal Years 1978 through 2005: 

Figure 4: DOE's Budget Authority for Renewable, Fossil, and Nuclear 
R&D, Fiscal Year 2006: 

Figure 5: Distribution of State Incentives and Policies for Renewable 
Energy: 

Figure 6: Number of States Using Each of 12 Renewable Standards, 
Mandates, and Incentives: 

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: 

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. 

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.[Footnote 1] 
During the past 29 years, the Congress has provided DOE about $50 
billion for R&D in renewable, fossil, and nuclear energy 
technologies.[Footnote 2] Specifically: 

˛ 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. 

˛ 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. 

˛ 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.[Footnote 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.[Footnote 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.[Footnote 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;[Footnote 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);[Footnote 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. 

Figure 1: Comparison of the U.S. Energy Portfolio in 1973 and 2004: 

[See PDF for Image] 

Source: GAO analysis of EIA data. 

[End of Figure] 

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: 

[See PDF for image] 

Source: EIA. 

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. 

[End of figure] 

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.[Footnote 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.[Footnote 9] 

Figure 3: DOE's Budget Authority for Renewable, Fossil, and Nuclear 
R&D, Fiscal Years 1978 through 2005: 

[See PDF for Image] 

Source: GAO analysis of DOE data. 

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. 

[End of Figure] 

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. 

Figure 4: DOE's Budget Authority for Renewable, Fossil, and Nuclear 
R&D, Fiscal Year 2006: 

[See PDF for image] 

Source: GAO analysis of DOE data. 

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. 

[End of figure] 

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.[Footnote 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. 

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.[Footnote 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.[Footnote 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. 

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. 

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.[Footnote 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,[Footnote 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. 

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: 

Performance characteristic: Mercury emissions (pounds/year); 
New conventional pulverized coal plant: 45; 
IGCC: Current: 29; 
IGCC: Near future: 29; 
IGCC: 2020: 26. 

Performance characteristic: Sulfur dioxide emissions (tons/year); 
New conventional pulverized coal plant: 3,027; 
IGCC: Current: 566; 
IGCC: Near future: 276; 
IGCC: 2020: 250. 

Performance characteristic: Nitrogen oxide emissions (tons/year); 
New conventional pulverized coal plant: 1,412; 
IGCC: Current: 1,094; 
IGCC: Near future: 219; 
IGCC: 2020: 198. 

Performance characteristic: Carbon dioxide emissions (tons/year); 
New conventional pulverized coal plant: 3,700,000; 
IGCC: Current: 3,600,000; 
IGCC: Near future: 3,500,000; 
IGCC: 2020: 3,200,000. 

Performance characteristic: Potential for carbon capture and 
sequestration; 
New conventional pulverized coal plant: Limited; 
IGCC: Current: Yes; 
IGCC: Near future: Yes; 
IGCC: 2020: Yes. 

Performance characteristic: Plant efficiency (percent); 
New conventional pulverized coal plant: 38.6; 
IGCC: Current: 39.7; 
IGCC: Near future: 45-50; 
IGCC: 2020: 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. 

[End of table] 

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.[Footnote 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. 

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.[Footnote 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. 

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,[Footnote 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.[Footnote 18] 

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.[Footnote 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. 

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.[Footnote 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. 

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.[Footnote 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[Footnote 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. 

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.[Footnote 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. 

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.[Footnote 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.[Footnote 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. 

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.[Footnote 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. 

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.[Footnote 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.[Footnote 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. 

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. [Footnote 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. 

Table 2: Comparison of Electricity Generating Costs Using Nuclear, 
Coal, and Natural Gas Energy Sources: 

Cents per kilowatt-hour. 

Energy Source: Nuclear (base case); 
25-year period: 7.0; 
40-year period: 6.7. 

Energy Source: Nuclear (best case); 
25-year period: 4.7; 
40-year period: 4.4. 

Energy Source: Coal; 
25-year period: 4.4; 
40-year period: 4.2. 

Energy Source: Natural gas; 
25-year period: 4.9; 
40-year period: 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. 

[End of table] 

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: Nuclear (base case); 
25-year period: 7.0; 
40-year period: 6.7. 

Energy source: Nuclear (best case); 
25-year period: 4.7; 
40-year period: 4.4. 

Energy source: Coal ($50/ton carbon tax); 
25-year period: 5.6; 
40-year period: 5.4. 

Energy source: Coal ($100/ton carbon tax); 
25-year period: 6.8; 
40-year period: 6.6. 

Energy source: Natural gas ($50/ton carbon tax); 
25-year period: 5.3; 
40-year period: 5.6. 

Energy source: Natural gas ($100/ton carbon tax); 
25-year period: 5.8; 
40-year period: 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. 

[End of table] 

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.[Footnote 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.[Footnote 31] 

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.[Footnote 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).[Footnote 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. 

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;[Footnote 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. 

Figure 5: Distribution of State Incentives and Policies for Renewable 
Energy: 

[See PDF for Image] 

Source: GAO analysis of Database of State Incentives for Renewable 
Energy maintained by the Interstate Energy Council and Map Resources 
(map). 

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. 

[End of Figure] 

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: 

* 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. 

* 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: 

[See PDF for image] 

Source: Database of State Incentives for Renewable Energy maintained by 
the Interstate Energy council. 

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. 

[End of figure] 

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): 

* 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. 

* 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. 

* 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,[Footnote 
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.[Footnote 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.[Footnote 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.[Footnote 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 [Hyperlink, http://www.gao.gov]. 

If you or your staffs have any questions about this report, please 
contact me at (202) 512-3841 or wellsj@gao.gov. 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. 

Signed by: 

Jim Wells: 
Director, Natural Resources and Environment: 

[End of section] 

Appendix I: Estimated Federal Tax Expenditures Targeted at Energy 
Suppliers and Users, Fiscal Year 2006: 

Dollars in millions. 

1; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Capital gains treatment of royalties on coal; 
Budget function: Energy; 
First year[B]: 1974; 
Estimated FY 2006 revenue loss: $90. 

2; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Excess of percentage over cost depletion, fuels; 
Budget function: Energy; 
First year[B]: 1974; 
Estimated FY 2006 revenue loss: 670. 

3; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Expensing of exploration and development costs, fuels; 
Budget function: Energy; 
First year[B]: 1974; 
Estimated FY 2006 revenue loss: 680. 

4; 
Federal tax expenditures targeted at energy suppliers and users[A]: New 
technology credits (addresses energy production from several 
technologies, including wind and solar energy); 
Budget function: Energy; 
First year[B]: 1978; 
Estimated FY 2006 revenue loss: 510. 

5; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Alcohol fuel credits[C]; 
Budget function: Energy; 
First year[B]: 1980; 
Estimated FY 2006 revenue loss: 40. 

6; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Alternative fuel production credit; 
Budget function: Energy; 
First year[B]: 1980; 
Estimated FY 2006 revenue loss: 2,390. 

7; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Exclusion of interest on energy facility bonds; 
Budget function: Energy; 
First year[B]: 1980; 
Estimated FY 2006 revenue loss: 90. 

8; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Exception from passive loss limitation for working interests in oil and 
gas properties; 
Budget function: Energy; 
First year[B]: 1988; 
Estimated FY 2006 revenue loss: 40. 

9; 
Federal tax expenditures targeted at energy suppliers and users[A]: Tax 
credit and deduction for clean-fuel burning vehicles; 
Budget function: Energy; 
First year[B]: 1992; 
Estimated FY 2006 revenue loss: 90. 

10; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Enhanced oil recovery credit; 
Budget function: Energy; 
First year[B]: 1994; 
Estimated FY 2006 revenue loss: 0. 

11; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Credit for holding clean renewable energy bonds; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 0. 

12; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Deferral of gain from dispositions of transmission property to 
implement the Federal Energy Regulatory Commission's restructuring 
policy[D]; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 620. 

13; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Credit for production from advanced nuclear power facilities; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 0. 

14; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Credit for investment in clean coal facilities; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 50. 

15; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Temporary 50 percent expensing for equipment used in the refining of 
liquid fuels; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 10. 

16; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Pass through low sulfur diesel expensing to cooperative owners; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 0. 

17; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Natural gas distribution pipelines treated as 15-year property; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 20. 

18; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Amortize all geological and geophysical expenditures over 2 years; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 40. 

19; 
Federal tax expenditures targeted at energy suppliers and users[A]: 30 
percent credit for residential purchases/ installations of solar and 
fuel cells; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 10. 

20; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Credit for business installation of qualified fuel cells and stationary 
microturbine power plants; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 80. 

21; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Alternative Fuel and Fuel Mixture tax credit; 
Budget function: Energy; 
First year[B]: 2005; 
Estimated FY 2006 revenue loss: 170. 

22; 
Federal tax expenditures targeted at energy suppliers and users[A]: Bio-
Diesel and small agri-biodiesel producer tax credits; 
Budget function: Agriculture; 
First year[B]: 2004; 
Estimated FY 2006 revenue loss: 90. 

23; 
Federal tax expenditures targeted at energy suppliers and users[A]: 
Expensing of small refiner capital costs with respect to complying with 
EPA sulfur regulations; 
Budget function: Natural resources and environment; 
First year[B]: 2004; 
Estimated FY 2006 revenue loss: 10. 

Total estimated tax expenditures[E]; 
Budget function: [Empty]; 
First year[B]: [Empty]; 
Estimated FY 2006 revenue loss: $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). 

[A] This 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. 

[B] First year the Department of the Treasury reported expenditures. 

[C] The 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. 

[D] This tax expenditure was listed under the community and regional 
development budget function in 2004. 

[E] Summing tax expenditure estimates does not take into account 
interactions between individual provisions. 

[End of table] 

[End of section] 

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.[Footnote 39] 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. 

[End of section] 

Appendix III: The States' Use of Renewable Energy Incentives, 
Standards, and Mandates: 

State: Alabama; 
Tax credits[A]: Yes; 
Rebates[B]: No; 
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Alaska; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Arizona; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: No.  

State: Arkansas; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: California; 
Tax credits[A]: Yes; 
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Colorado; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Connecticut; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Delaware; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Florida; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Georgia; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Hawaii; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Idaho; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Illinois; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: No.  

State: Indiana; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Iowa; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Kansas; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Kentucky; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Louisiana; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Maine; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Maryland; 
Tax credits[A]: Yes; 
Rebates[B]: Yes; 
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Massachusetts; 
Tax credits[A]: Yes; 
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Michigan; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Minnesota; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Mississippi; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Missouri; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Montana; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Nebraska; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Nevada; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: New Hampshire; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: New Jersey; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: New Mexico; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: New York; 
Tax credits[A]: Yes; 
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: North Carolina; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: North Dakota; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Ohio; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Oklahoma; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Oregon; 
Tax credits[A]: Yes; 
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Pennsylvania; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Rhode Island; 
Tax credits[A]: Yes; 
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: South Carolina; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: South Dakota; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Tennessee; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Texas; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Utah; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Vermont; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Virginia; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Washington; 
Tax credits[A]: No;  
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: West Virginia; 
Tax credits[A]: Yes; 
Rebates[B]: No;  
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: No.  

State: Wisconsin; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: Yes; 
Renewable portfolio standards[D]: Yes; 
Net metering & inter connection rules[E]: Yes. 

State: Wyoming; 
Tax credits[A]: No;  
Rebates[B]: Yes; 
Public benefit funds[C]: No;  
Renewable portfolio standards[D]: No;  
Net metering & inter connection rules[E]: Yes. 

State: Total; 
Tax credits[A]: 21; 
Rebates[B]: 17; 
Public benefit funds[C]: 15; 
Renewable portfolio standards[D]: 22; 
Net metering & inter connection rules[E]: 39. 

Source: GAO analysis of the Database of State Incentives for Renewable 
Energy, maintained by the Interstate Renewable Energy Council. 

[A] Provided 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. 

[B] Typically 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. 

[C] A 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. 

[D] Require 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. 

[E] Eligibility 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. 

[End of table] 

[End of section] 

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.[Footnote 40] 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. 

[End of section] 

Appendix V: Comments from the Department of Energy: 

Department of Energy: 
Washington, DC 20585: 

December 11, 2006: 

Mr. Jim Wells: 
Director, Natural Resources and Environment: 
Government Accountability Office: 
441 G Street, NW: 
Washington, DC 20548: 

Dear Mr. Wells: 

Thank you for the opportunity to comment on the draft report GAO-07- 
106, Department of Energy: Key Challenges Remain for Developing and 
Deploying Advanced Energy Technologies to Meet Future Needs. The 
Department of Energy's official technical corrections and comments are 
enclosed for your consideration. If you have any questions, please 
contact Mr. Thomas Shoemaker at: 202-586-7022. 

Sincerely, 

Signed by: 

Rita L. Wells: 

Deputy Assistant Secretary: 
Business Administration: 

Enclosure: 

[End of section] 

Appendix VI: GAO Contact and Staff Acknowledgments: 

GAO Contact: 

Jim Wells (202) 512-3841 or wellsj@gao.gov: 

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. 

(360625) 

[End of section] 

FOOTNOTES 

[1] DOE is also responsible for energy efficiency programs, which are 
integral to addressing future energy challenges by reducing demand. 

[2] All historical DOE R&D budget authority totals are presented in 
real terms by adjusting them to fiscal year 2005 dollars to account for 
inflation. 

[3] The 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. 

[4] Pub. L. No. 108-357. 

[5] Pub. L. No. 109-58. 

[6] Tax 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, GAO-05-690 
(Washington, D.C.: Sept. 23, 2005). 

[7] In 2006, crude oil prices peaked at nearly $70 per barrel in the 
United States. 

[8] Summing tax expenditure estimates is useful to gauge their general 
magnitude but does not take into account interactions between 
individual provisions. 

[9] The 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. 

[10] Flex 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. 

[11] See also GAO, Renewable Energy: Increased Geothermal Development 
Will Depend on Overcoming Many Challenges, GAO-06-629 (Washington, 
D.C.: May 24, 2006). 

[12] Geothermal 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. 

[13] Under 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. 

[14] EPA 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. 

[15] See 54 Fed. Reg. 15383 (1989). 

[16] In 1977, President Carter announced plans to indefinitely suspend 
U.S. reprocessing efforts. 

[17] The 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. 

[18] According 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. 

[19] DOE and USDA, Biomass as Feedstock for a Bioenergy and Bioproducts 
Industry: The Technical Feasibility of a Billion-Ton Annual Supply, 
April 2005. 

[20] It 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. 

[21] Similarly, 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. 

[22] One megawatt of wind power generates about as much electricity as 
240 to 300 households use each year. 

[23] The 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. 

[24] The 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. 

[25] See GAO, Wind Power: Impacts on Wildlife and Government 
Responsibilities for Regulating Development and Protecting Wildlife, 
GAO-05-906 (Washington, D.C.: Sept. 16, 2005). 

[26] The 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. 

[27] See 10 C.F.R. pt. 52. 

[28] Mining 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. 

[29] MIT. The Future of Nuclear Power (Cambridge, MA: July 2003); 
University of Chicago, The Economic Future of Nuclear Power (Chicago, 
IL: August 2004). 

[30] The 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." 

[31] NRC 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. 

[32] NRC 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. 

[33] Funding 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. 

[34] The 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. 

[35] Renewable technology plants are exempt from taxes placed on power 
plants that emit carbon dioxide. 

[36] One of the new offshore developments, Horns Rev II, is expected to 
be operational by 2009. 

[37] The 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. 

[38] About half of Japan's total energy demand is for oil, which is 
primarily imported from the Middle East. 

[39] Results 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. 

[40] Some 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. 

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