GAO-07-283, Crude Oil: Uncertainty about Future Oil Supply Makes It Important to Develop a Strategy for Addressing a Peak and Decline in Oil Production


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Important to Develop a Strategy for Addressing a Peak and Decline in 
Oil Production' which was released on March 29, 2007. 

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Report to Congressional Requesters: 

United States Government Accountability Office: 

GAO: 

February 2007: 

Crude Oil: 

Uncertainty about Future Oil Supply Makes It Important to Develop a 
Strategy for Addressing a Peak and Decline in Oil Production: 

GAO-07-283: 

GAO Highlights: 

Highlights of GAO-07-283, a report to congressional requesters 

Why GAO Did This Study: 

The U.S. economy depends heavily on oil, particularly in the 
transportation sector. World oil production has been running at near 
capacity to meet demand, pushing prices upward. Concerns about meeting 
increasing demand with finite resources have renewed interest in an old 
question: How long can the oil supply expand before reaching a maximum 
level of production—a peak—from which it can only decline? 

GAO (1) examined when oil production could peak, (2) assessed the 
potential for transportation technologies to mitigate the consequences 
of a peak in oil production, and (3) examined federal agency efforts 
that could reduce uncertainty about the timing of a peak or mitigate 
the consequences. To address these objectives, GAO reviewed studies, 
convened an expert panel, and consulted agency officials. 

What GAO Found: 

Most studies estimate that oil production will peak sometime between 
now and 2040. This range of estimates is wide because the timing of the 
peak depends on multiple, uncertain factors that will help determine 
how quickly the oil remaining in the ground is used, including the 
amount of oil still in the ground; how much of that oil can ultimately 
be produced given technological, cost, and environmental challenges as 
well as potentially unfavorable political and investment conditions in 
some countries where oil is located; and future global demand for oil. 
Demand for oil will, in turn, be influenced by global economic growth 
and may be affected by government policies on the environment and 
climate change and consumer choices about conservation. 

In the United States, alternative fuels and transportation technologies 
face challenges that could impede their ability to mitigate the 
consequences of a peak and decline in oil production, unless sufficient 
time and effort are brought to bear. For example, although corn ethanol 
production is technically feasible, it is more expensive to produce 
than gasoline and will require costly investments in infrastructure, 
such as pipelines and storage tanks, before it can become widely 
available as a primary fuel. Key alternative technologies currently 
supply the equivalent of only about 1 percent of U.S. consumption of 
petroleum products, and the Department of Energy (DOE) projects that 
even by 2015, they could displace only the equivalent of 4 percent of 
projected U.S. annual consumption. In such circumstances, an imminent 
peak and sharp decline in oil production could cause a worldwide 
recession. If the peak is delayed, however, these technologies have a 
greater potential to mitigate the consequences. DOE projects that the 
technologies could displace up to 34 percent of U.S. consumption in the 
2025 through 2030 time frame, if the challenges are met. The level of 
effort dedicated to overcoming challenges will depend in part on 
sustained high oil prices to encourage sufficient investment in and 
demand for alternatives. 

Federal agency efforts that could reduce uncertainty about the timing 
of peak oil production or mitigate its consequences are spread across 
multiple agencies and are generally not focused explicitly on peak oil. 
Federally sponsored studies have expressed concern over the potential 
for a peak, and agency officials have identified actions that could be 
taken to address this issue. For example, DOE and United States 
Geological Survey officials said uncertainty about the peak’s timing 
could be reduced through better information about worldwide demand and 
supply, and agency officials said they could step up efforts to promote 
alternative fuels and transportation technologies. However, there is no 
coordinated federal strategy for reducing uncertainty about the peak’s 
timing or mitigating its consequences. 

What GAO Recommends: 

To better prepare for a peak in oil production, GAO recommends that the 
Secretary of Energy work with other agencies to establish a strategy to 
coordinate and prioritize federal agency efforts to reduce uncertainty 
about the likely timing of a peak and to advise Congress on how best to 
mitigate consequences. In commenting on a draft of the report, the 
Departments of Energy and the Interior generally agreed with the report 
and recommendations. 

[Hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-07-283]. 

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: 

Timing of Peak Oil Production Depends on Uncertain Factors: 

Alternative Transportation Technologies Face Challenges in Mitigating 
the Consequences of the Peak and Decline: 

Federal Agencies Do Not Have a Coordinated Strategy to Address Peak Oil 
Issues: 

Conclusions: 

Recommendation for Executive Action: 

Agency Comments and Our Evaluation: 

Appendix I: Scope and Methodology: 

Appendix II: Key Peak Oil Studies: 

Appendix III: Key Technologies to Enhance the Supply of Oil: 

Enhanced Oil Recovery: 

Deepwater and Ultra-Deepwater Drilling: 

Oil Sands: 

Heavy and Extra-Heavy Oils: 

Oil Shale: 

Appendix IV: Key Technologies to Displace Oil Consumption in the 
Transportation Sector: 

Ethanol: 

Biodiesel: 

Coal and Biomass Gas-to-Liquids: 

Natural Gas: 

Advanced Vehicle Technologies: 

Hydrogen Fuel Cell Vehicles: 

Appendix V: Comments from the Department of Energy: 

GAO Comments: 

Appendix VI: Comments from the Department of the Interior: 

GAO Comments: 

Appendix VII: GAO Contact and Staff Acknowledgments: 

Figures: 

Figure 1: U.S. Oil Production, 1900-2005: 

Figure 2: World Crude Oil and Other Liquids Production, 1965-2005: 

Figure 3: Annual U.S. Oil Consumption, by Sector, 1974-2005: 

Figure 4: Real and Nominal Oil Prices, 1950-2006: 

Figure 5: Key Estimates of the Timing of Peak Oil: 

Figure 6: World Oil Reserves, OPEC and non-OPEC, 2006: 

Figure 7: Worldwide Proven Oil Reserves, by Political Risk: 

Figure 8: Worldwide Proven Oil Reserves, by Investment Risk: 

Figure 9: Top 10 Companies on the Basis of Oil Production and Reserves 
Holdings, 2004: 

Figure 10: World Oil Production, by OPEC and Non-OPEC Countries, 2004 
Projected to 2030: 

Figure 11: Daily World Oil Consumption, by Region for 2003 and 
Projected for 2030: 

Abbreviations: 

CO2: carbon dioxide: 

DOE: Department of Energy: 

DOT: Department of Transportation: 

EIA: Energy Information Administration: 

EOR: enhanced oil recovery: 

GDP: gross domestic product: 

GTL: gas to liquids: 

IEA: International Energy Agency: 

OECD: Organization for Economic Co-operation and Development: 

OPEC: Organization of the Petroleum Exporting Countries: 

USDA: United States Department of Agriculture: 

USGS: United States Geological Survey: 

United States Government Accountability Office: 
Washington, DC 20548: 

February 28, 2007: 

The Honorable Bart Gordon: 
Chairman: 
Committee on Science and Technology: 
House of Representatives: 

The Honorable Roscoe G. Bartlett: 
The Honorable Judy Biggert: 
The Honorable Wayne T. Gilchrest: 
The Honorable Vernon J. Ehlers: 
The Honorable Lynn C. Woolsey: 
House of Representatives: 

U.S. consumers paid $38 billion more for gasoline in the first 6 months 
of 2006 than they paid in the same period of 2005, and $57 billion more 
than they paid in the same period of 2004, in large part because of 
rising oil prices, which reached a 24-year high in 2006 when adjusted 
for inflation. Oil is a global commodity, and its price is determined 
mainly by the balance between world demand and supply. Since 1983, 
world consumption of petroleum products has grown fairly steadily. The 
Department of Energy's (DOE) Energy Information Administration (EIA) 
states in a 2006 report that world consumption of petroleum had reached 
84 million barrels per day in 2005.[Footnote 1] EIA also projects that 
world oil consumption will continue to grow and will reach 118 million 
barrels per day in 2030.[Footnote 2] About 43 percent of this growth in 
oil consumption will come from the non-Organization for Economic Co- 
operation and Development Asian countries, including China and India, 
but the United States will remain the world's largest oil consumer. In 
2005, the United States accounted for just under 25 percent of world 
oil consumption. World oil production has been running at near capacity 
in recent years to meet rising consumption, putting upward pressure on 
oil prices. The potential for disruptions in key oil-producing regions 
of the world, such as the Middle East, and the yearly threat of 
hurricanes in the Gulf of Mexico have also exerted upward pressure on 
oil prices. These conditions have renewed interest in a long-standing 
question: Will oil supply continue to expand to meet growing demand, or 
will we soon reach a maximum possible level of production--a peak-- 
beyond which oil supply can only decline? 

Historically, U.S. oil production peaked around 1970 at close to 10 
million barrels per day and has been generally declining ever since, to 
about 5 million barrels per day in 2005. While recent discoveries raise 
the prospect of some increases in U.S. oil production, significant 
reductions in world oil production could still have important 
consequences for the nation's welfare. The United States imported about 
66 percent of its oil and petroleum products in 2005, and the U.S. 
economy--particularly the transportation sector--depends heavily on 
oil. Overall, transportation accounts for approximately 65 percent of 
U.S. oil consumption. New technologies have been introduced that 
displace some oil consumption within the sector, but oil consumption 
for transportation has continued to increase in recent years. According 
to a 2005 report prepared for DOE, without timely preparation, a 
reduction in world oil production could cause transportation fuel 
shortages that would translate into significant economic 
hardship.[Footnote 3] 

The U.S. government addresses or examines world oil supply in several 
ways. For example, DOE is responsible for promoting the nation's energy 
security through reliable and affordable energy, including oil. DOE 
supports development of technologies for producing and using oil and 
for making alternative fuels, such as ethanol or hydrogen. The 
department also publishes statistics on energy production and 
consumption through EIA. In addition, the United States Geological 
Survey (USGS), within the Department of the Interior (Interior), 
assesses the amount of oil throughout the world. The United States also 
is a member of the International Energy Agency (IEA), an organization 
of 26 member countries whose objectives include coping with disruptions 
in the oil supply and providing information on the international oil 
market, among other things.[Footnote 4] 

In this context, we (1) examined when oil production could peak, (2) 
assessed the potential for transportation technologies to mitigate the 
consequences of a peak and decline in oil production, and (3) examined 
federal agency efforts that could reduce uncertainty about the timing 
of peak oil production or mitigate the consequences. 

In conducting our work, we identified and reviewed key studies on when 
oil production will peak. We reviewed estimates of the amount of oil 
throughout the world and the amount of oil held by national oil 
companies, and we analyzed forecasts of political and investment risks 
in oil-producing regions. To assess the potential for transportation 
technologies in the United States to mitigate the consequences of a 
peak and decline in oil production, we examined options to develop 
alternative fuels and technologies to reduce energy consumption in the 
transportation sector. In particular, we focused on technologies that 
would affect automobiles and light trucks. We consulted with experts to 
devise a list of key technologies in these areas and then reviewed DOE 
programs and activities related to developing these technologies. We 
did not attempt to comprehensively list all technologies or to conduct 
a governmentwide review of all programs, and we limited our scope to 
what federal government officials know about the status of these 
technologies in the United States. We did not conduct a global 
assessment of transportation technologies. We reviewed numerous studies 
on the relationship between oil and the global economy and, in 
particular, on the experiences of past oil price shocks. To identify 
federal government activities that could address peak oil production 
issues, we spoke with officials at DOE and USGS, and gathered 
information on federal programs and policies that could affect 
uncertainty about the timing of peak oil production and the development 
of alternative transportation technologies. To gain further insights 
into the federal role and other issues surrounding peak oil production, 
we convened an expert panel in conjunction with the National Academy of 
Sciences. These experts commented on the potential economic 
consequences of a transition away from conventional oil, factors that 
could affect the severity of the consequences, and what the federal 
role should be, among other things. A more detailed description of the 
scope and methodology of our review is presented in appendix I. We 
performed our work between July 2005 and December 2006, in accordance 
with generally accepted government auditing standards. 

Results in Brief: 

Most studies estimate that oil production will peak sometime between 
now and 2040, although many of these projections cover a wide range of 
time, including two studies for which the range extends into the next 
century. The timing of the peak depends on multiple, uncertain factors 
that will influence how quickly the remaining oil is used, including 
the amount of oil still in the ground, how much of the remaining oil 
can be ultimately produced, and future oil demand. The amount of oil 
remaining in the ground is highly uncertain, in part because the 
Organization of Petroleum Exporting Countries (OPEC) controls most of 
the estimated world oil reserves, but its estimates of reserves are not 
verified by independent auditors. In addition, many parts of the world 
have not yet been fully explored for oil. There is also great 
uncertainty about the amount of oil that will ultimately be produced, 
given the technological, cost, and environmental challenges. For 
example, some of the oil remaining in the ground can be accessed only 
by using complex and costly technologies that present greater 
environmental challenges than the technologies used for most of the oil 
produced to date. Other important sources of uncertainty about future 
oil production are potentially unfavorable political and investment 
conditions in countries where oil is located. For example, more than 60 
percent of world oil reserves, on the basis of Oil and Gas Journal 
estimates, are in countries where relatively unstable political 
conditions could constrain oil exploration and production. Finally, 
future world demand for oil also is uncertain because it depends on 
economic growth and government policies throughout the world. For 
example, continued rapid economic growth in China and India could 
significantly increase world demand for oil, while environmental 
concerns, including oil's contribution to global warming, may spur 
conservation or adoption of alternative fuels that would reduce future 
demand for oil. 

In the United States, alternative transportation technologies face 
challenges that could impede their ability to mitigate the consequences 
of a peak and decline in oil production, unless sufficient time and 
effort are brought to bear. For example: 

* Ethanol from corn is more costly to produce than gasoline, in part 
because of the high cost of the corn feedstock. Even if ethanol were to 
become more cost-competitive with gasoline, it could not become widely 
available without costly investments in infrastructure, including 
pipelines, storage tanks, and filling stations. 

* Advanced vehicle technologies that could increase mileage or use 
different fuels are generally more costly than conventional 
technologies and have not been widely adopted. For example, hybrid 
electric vehicles can cost from $2,000 to $3,500 more to purchase than 
comparable conventional vehicles and currently constitute about 1 
percent of new vehicle registrations in the United States. 

* Hydrogen fuel cell vehicles are significantly more costly than 
conventional vehicles to produce. Specifically, the hydrogen fuel cell 
stack needed to power a vehicle currently costs about $35,000 to 
produce, in comparison with a conventional gas engine, which costs 
$2,000 to $3,000. 

Given these challenges, development and widespread adoption of 
alternative transportation technologies will take time and effort. Key 
alternative technologies currently supply the equivalent of only about 
1 percent of U.S. consumption of petroleum products, and DOE projects 
that even under optimistic scenarios, by 2015 these technologies could 
displace only the equivalent of 4 percent of projected U.S. annual 
consumption. Under these circumstances, an imminent peak and sharp 
decline in oil production could have severe consequences, including a 
worldwide recession. If the peak comes later, however, these 
technologies have a greater potential to mitigate the consequences. DOE 
projects that these technologies could displace up to the equivalent of 
34 percent of projected U.S. annual consumption of petroleum products 
in the 2025 through 2030 time frame, assuming the challenges the 
technologies face are overcome. The level of effort dedicated to 
overcoming challenges to alternative technologies will depend in part 
on the price of oil; without sustained high oil prices, efforts to 
develop and adopt alternatives may fall by the wayside. 

Federal agency efforts that could reduce uncertainty about the timing 
of peak oil production or mitigate its consequences are spread across 
multiple agencies and generally are not focused explicitly on peak oil. 
For example, efforts that could be used to reduce uncertainty about the 
timing of a peak include USGS activities to estimate oil resources and 
DOE efforts to monitor current supply and demand conditions in global 
oil markets and to make future projections. Similarly, DOE, the 
Department of Transportation (DOT), and the U.S. Department of 
Agriculture (USDA) all have programs and activities that oversee or 
promote alternative transportation technologies that could mitigate the 
consequences of a peak. However, officials of key agencies we spoke 
with acknowledge that their efforts--with the exception of some 
studies--are not specifically designed to address peak oil. Federally 
sponsored studies we reviewed have expressed a growing concern over the 
potential for a peak and officials from key agencies have identified 
some options for addressing this issue. For example, DOE and USGS 
officials told us that developing better information about worldwide 
demand and supply and improving global estimates for nonconventional 
oil resources and oil in "frontier" regions that have yet to be fully 
explored could help prepare for a peak in oil production by reducing 
uncertainty about its timing. Agency officials also said that, in the 
event of an imminent peak, they could step up efforts to mitigate the 
consequences by, for example, further encouraging development and 
adoption of alternative fuels and advanced vehicle technologies. 
However, according to DOE, there is no formal strategy for coordinating 
and prioritizing federal efforts dealing with peak oil issues, either 
within DOE or between DOE and other key agencies. 

While the consequences of a peak would be felt globally, the United 
States, as the largest consumer of oil and one of the nations most 
heavily dependent on oil for transportation, may be particularly 
vulnerable. Therefore, to better prepare the United States for a peak 
and decline in oil production, we are recommending that the Secretary 
of Energy take the lead, in coordination with other relevant federal 
agencies, to establish a peak oil strategy. Such a strategy should 
include efforts to reduce uncertainty about the timing of a peak in oil 
production and provide timely advice to Congress about cost-effective 
measures to mitigate the potential consequences of a peak. In 
commenting on a draft of the report, the Departments of Energy and the 
Interior generally agreed with the report and recommendations. 

Background: 

Oil--the product of the burial and transformation of biomass over the 
last 200 million years--has historically had no equal as an energy 
source for its intrinsic qualities of extractability, transportability, 
versatility, and cost. But the total amount of oil underground is 
finite, and, therefore, production will one day reach a peak and then 
begin to decline. Such a peak may be involuntary if supply is unable to 
keep up with growing demand. Alternatively, a production peak could be 
brought about by voluntary reductions in oil consumption before 
physical limits to continued supply growth kick in. Not surprisingly, 
concerns have arisen in recent years about the relationship between (1) 
the growing consumption of oil and the availability of oil reserves and 
(2) the impact of potentially dwindling supplies and rising prices on 
the world's economy and social welfare. Following a peak in world oil 
production, the rate of production would eventually decrease and, 
necessarily, so would the rate of consumption of oil. 

Oil can be found and produced from a variety of sources. To date, world 
oil production has come almost exclusively from what are considered to 
be "conventional sources" of oil. While there is no universally agreed- 
upon definition of what is meant by conventional sources, IEA states 
that conventional sources can be produced using today's mainstream 
technologies, compared with "nonconventional sources" that require more 
complex or more expensive technologies to extract, such as oil sands 
and oil shale. Distinguishing between conventional and nonconventional 
oil sources is important because the additional cost and technological 
challenges surrounding production of nonconventional sources make these 
resources more uncertain. However, this distinction is further 
complicated because what is considered to be a mainstream technology 
can change over time. For example, offshore oil deposits were 
considered to be a nonconventional source 50 years ago; however, today 
they are considered conventional. For the purpose of this report, and 
consistent with IEA's classification, we define nonconventional sources 
as including oil sands, heavy oil deposits, and oil shale.[Footnote 5] 
Some oil is being produced from these nonconventional sources today. 
For example, in 2005 Canada produced about 1.6 million barrels per day 
of oil from oil sands, and Venezuelan production of extra-heavy oil for 
2005 was projected to be about 600,000 barrels per day. Currently, 
however, production from these sources is very small compared with 
total world oil production. 

Oil Production Has Peaked in the United States and Most Other Countries 
Outside the Middle East: 

According to IEA, most countries outside the Middle East have reached 
their peak in conventional oil production, or will do so in the near 
future. The United States is a case in point. Even though the United 
States is currently the third-largest, oil-producing nation,[Footnote 
6] U.S. oil production peaked around 1970 and has been on a declining 
trend ever since. (See fig. 1.) 

Figure 1: U.S. Oil Production, 1900-2005: 

[See PDF for image] 

Source: GAO analysis of Energy Information Administration data. 

[End of figure] 

Looking toward the future, EIA projects that U.S. deepwater oil 
production will slightly boost total U.S. production in the near term. 
However, this increase will end about 2016, and then U.S. production 
will continue to decline. Given these projections, it is clear that 
future increases in U.S. demand for oil will need to be fulfilled 
through increases in production in the rest of the world. Increasing 
production in other countries has to date been able to more than make 
up for declining U.S. production and has resulted in increasing world 
production. (See fig. 2.) 

Figure 2: World Crude Oil and Other Liquids Production, 1965-2005: 

[See PDF for image] 

Source: GAO analysis of British Petroleum data. 

Note: These data include crude oil, shale oil, oil sands, and natural 
gas liquids--the liquid content of natural gas. They exclude liquid 
fuels from other sources, such as coal derivatives. 

[End of figure] 

Oil Is Critical in Satisfying the U.S. and World Demand for Energy: 

Oil accounts for approximately one-third of all the energy used in the 
world. Following the record oil prices associated with the Iranian 
Revolution in 1979-80 and with the start of the Iran-Iraq war in 1980, 
there was a drop in total world oil consumption, from about 63 million 
barrels per day in 1980 to 59 million barrels per day in 1983. Since 
then, however, world consumption of petroleum products has increased, 
totaling about 84 million barrels per day in 2005. In the United 
States, consumption of petroleum products increased an average of 1.65 
percent annually from 1983 to 2004, and averaged 20.6 million barrels 
per day in 2005, representing about one-quarter of all world 
consumption. EIA projects that U.S. consumption will continue to 
increase and will reach 27.6 million barrels per day in 2030. 

As figure 3 shows, the transportation sector is by far the largest U.S. 
consumer of petroleum, accounting for two-thirds of all U.S. 
consumption and relying almost entirely on petroleum to operate. Within 
the transportation sector, light vehicles are the largest consumers of 
petroleum energy[Footnote 7], accounting for approximately 60 percent 
of the transportation sector's consumption of petroleum-based energy in 
the United States. Figure 3 also shows that while consumption of 
petroleum products in other sectors has remained relatively constant or 
increased slightly since the early 1980s, petroleum consumption in the 
transportation sector has grown at a significant rate. 

Figure 3: Annual U.S. Oil Consumption, by Sector, 1974-2005: 

[See PDF for image] 

Source: GAO analysis of Energy Information Administration data. 

[End of figure] 

Relationship of Supply and Demand of Oil to Oil Price: 

The price of oil is determined in the world market and depends mainly 
on the balance between world demand and supply. Recent world production 
of oil has been running at near capacity to meet rising demand, which 
has put upward pressure on oil prices. Figure 4 shows that world oil 
prices in nominal terms--unadjusted for inflation--are higher than at 
any time since 1950, although when adjusted for inflation, the high 
prices of 2006 are still lower than were reached in the 1979-80 price 
run-up following the Iranian Revolution and the beginning of the Iran- 
Iraq war. 

Figure 4: Real and Nominal Oil Prices, 1950-2006: 

[See PDF for image] 

Source: GAO analysis of British Petroleum, Energy Information 
Administration, and Bureau of Labor Statistics data. 

Note: Crude oil price data are annual averages of Arabian Light prices 
for 1945 through 1983 and Brent oil prices for 1984 through 2005. The 
2006 price is an average of daily Brent oil prices from January 3 to 
December 20, 2006. 

[End of figure] 

All else being equal, oil consumption is inversely correlated with oil 
price, with higher oil prices inducing consumers to reduce their oil 
consumption.[Footnote 8] Specifically, increases in crude oil prices 
are reflected in the prices of products made from crude oil, including 
gasoline, diesel, home heating oil, and petrochemicals. The extent to 
which consumers are willing and able to reduce their consumption of oil 
in response to price increases depends on the cost of switching to 
activities and lifestyles that use less oil. Because there are more 
options available in the longer term, consumers respond more to changes 
in oil prices in the longer term than in the shorter term. For example, 
in the short term, consumers can reduce oil consumption by driving less 
or more slowly, but in the longer term, consumers can still take those 
actions, but can also buy more fuel-efficient automobiles or even move 
closer to where they work and thereby further reduce their oil 
consumption. 

Supply and demand, in turn, affect the type of oil that is produced. 
Conventional oil that is less expensive to extract using lower-cost 
drilling techniques will be produced when oil prices are lower. 
Conversely, oil that is expensive to produce because of the higher cost 
technologies involved may not be economical to produce at low oil 
prices. Producers are unlikely to turn to these more expensive oil 
sources unless oil prices are sustained at a high enough level to make 
such an enterprise profitable. Given the importance of oil in the 
world's energy portfolio, as cheaper oil reserves are exhausted in the 
future, nations will need to make the transition to more and more 
expensive and difficult-to-access sources of oil to meet energy 
demands. Recently, for example, a large discovery of oil in the Gulf of 
Mexico made headlines; however, this potential wealth of oil is located 
at a depth of over 5 miles below sea level, a fact that adds 
significantly to the costs of extracting that oil. 

Timing of Peak Oil Production Depends on Uncertain Factors: 

Most studies estimate that oil production will peak sometime between 
now and 2040, although many of these projections cover a wide range of 
time, including two studies for which the range extends into the next 
century.[Footnote 9] Key uncertainties in trying to determine the 
timing of peak oil are the (1) amount of oil throughout the world; (2) 
technological, cost, and environmental challenges to produce that oil; 
(3) political and investment risk factors that may affect oil 
exploration and production; and (4) future world demand for oil. The 
uncertainties related to exploration and production also make it 
difficult to estimate the rate of decline after the peak. 

Studies Predict Widely Different Dates for Peak Oil: 

Most studies estimate that oil production will peak sometime between 
now and 2040, although many of these projections cover a wide range of 
time, including two studies for which the range extends into the next 
century. Figure 5 shows the estimates of studies we examined. 

Figure 5: Key Estimates of the Timing of Peak Oil: 

[See PDF for image] 

Source: GAO study. 

Note: These studies are listed in appendix II of this report. Estimates 
of 90 percent confidence intervals using two different reserves data 
sources are provided for study g. One additional study that is not 
represented in this figure, referenced as study v, states that the 
timing of the peak is "unknowable." 

[End of figure] 

Amount of Oil in the Ground Is Uncertain: 

Studies that predict the timing of a peak use different estimates of 
how much oil remains in the ground, and these differences explain some 
of the wide ranges of these predictions. Estimates of how much oil 
remains in the ground are highly uncertain because much of these data 
are self-reported and unverified by independent auditors; many parts of 
the world have yet to be fully explored for oil; and there is no 
comprehensive assessment of oil reserves from nonconventional sources. 
This uncertainty surrounding estimates of oil resources in the ground 
comprises the uncertainty surrounding estimates of proven 
reserves[Footnote 10] as well as uncertainty surrounding expected 
increases in these reserves and estimated future oil discoveries. 

Oil and Gas Journal and World Oil, two primary sources of proven 
reserves estimates, compile data on proven reserves from national and 
private company sources. Some of this information is publicly available 
from oil companies that are subject to public reporting requirements-- 
for example, information provided by companies that are publicly traded 
on U.S. stock exchanges that are subject to the filing requirements of 
U.S. federal securities laws. Information filed pursuant to these laws 
is subject to liability standards, and, therefore, there is a strong 
incentive for these companies to make sure their disclosures are 
complete and accurate. On the other hand, companies that are not 
subject to these federal securities laws, including companies wholly 
owned by various OPEC countries where the majority of reserves are 
located, are not subject to these filing requirements and their related 
liability standards. Some experts believe OPEC estimates of proven 
reserves to be inflated. For example, OPEC estimates increased sharply 
in the 1980s, corresponding to a change in OPEC's quota rules that 
linked a member country's production quota in part to its remaining 
proven reserves. In addition, many OPEC countries' reported reserves 
remained relatively unchanged during the 1990s, even as they continued 
high levels of oil production. For example, IEA reports that reserves 
estimates in Kuwait were unchanged from 1991 to 2002, even though the 
country produced more than 8 billion barrels of oil over that period 
and did not make any important new oil discoveries. At a 2005 National 
Academy of Sciences workshop on peak oil, OPEC defended its reserves 
estimates as accurate. The potential unreliability of OPEC's self- 
reported data is particularly problematic with respect to predicting 
the timing of a peak because OPEC holds most of the world's current 
estimated proven oil reserves. On the basis of Oil and Gas Journal 
estimates as of January 2006, we found that of the approximately 1.1 
trillion barrels of proven oil reserves worldwide,[Footnote 11] about 
80 percent are located in the OPEC countries,[Footnote 12] compared 
with about 2 percent in the United States. Figure 6 shows this estimate 
in more detail. 

Figure 6: World Oil Reserves, OPEC and non-OPEC, 2006: 

[See PDF for image] 

Source: GAO analysis of Oil and Gas Journal data. 

[End of figure] 

USGS, another primary source of reported estimates, provides oil 
resources estimates, which are different from proved reserves 
estimates. Oil resources estimates are significantly higher because 
they estimate the world's total oil resource base, rather than just 
what is now proven to be economically producible. USGS estimates of the 
resource base include past production and current reserves as well as 
the potential for future increases in current conventional oil 
reserves--often referred to as reserves growth--and the amount of 
estimated conventional oil that has the potential to be added to these 
reserves.[Footnote 13] Estimates of reserves growth and those resources 
that have the potential to be added to oil reserves are important in 
determining when oil production may peak. However, estimating these 
potential future reserves is complicated by the fact that many regions 
of the world have not been fully explored and, as a result, there is 
limited information. For example, in its 2000 assessment, USGS provides 
a mean estimate of 732 billion barrels that have the potential to be 
added as newly discovered conventional oil, with as much as 25 percent 
from the Arctic--including Greenland, Northern Canada, and the Russian 
portion of the Barents Sea. However, relatively little exploration has 
been done in this region, and there are large portions of the world 
where the potential for oil production exists, but where exploration 
has not been done. According to USGS, there is less uncertainty in 
regions where wells have been drilled, but even in the United States, 
one of the areas that has seen the greatest exploration, some areas 
have not been fully explored, as illustrated by the recent discovery of 
a potentially large oil field in the Gulf of Mexico. 

Limited information on oil-producing regions worldwide also leads USGS 
to base its estimate of reserves growth on how reserves estimates have 
grown in the United States. However, some experts criticize this 
methodology; they believe such an estimate may be too high because the 
U.S. experience overestimates increases in future worldwide reserves. 
In contrast, EIA believes the USGS estimate may be too low. In 2005, 
USGS released a study showing that its prediction of reserves growth 
has been in line with the world's experience from 1996 to 
2003.[Footnote 14] Given such controversy, uncertainty remains about 
this key element of estimating the amount of oil in the ground. In 
2000, USGS' most recent full assessment of the world's key oil regions, 
the agency provided a range of estimates of remaining world 
conventional oil resources. The mean of this range was at about 2.3 
trillion barrels comprising about 890 billion barrels in current 
reserves and 1.4 trillion barrels that have the potential to be added 
to oil reserves in the future.[Footnote 15] 

Further contributing to the uncertainty of the timing of a peak is the 
lack of a comprehensive assessment of oil from nonconventional sources. 
For example, the three key sources of oil estimates--Oil and Gas 
Journal, World Oil, and USGS--do not generally include oil from 
nonconventional sources. This is an important issue because oil from 
nonconventional sources is thought to exist in large quantities. For 
example, IEA believes that oil from nonconventional sources--composed 
primarily of Canadian oil sands, extra-heavy oil deposits in Venezuela, 
and oil shale in the United States--could account for as much as 7 
trillion barrels of oil, which could greatly delay the onset of a peak 
in production. However, IEA also points out that the amount of this 
nonconventional oil that will eventually be produced is highly 
uncertain, which is a result of the challenges facing this production. 
Despite this uncertainty, USGS experts noted that Canadian oil sands 
and Venezuelan extra-heavy oil production are under way now and also 
suggested that proven reserves from these sources will be growing 
considerably in the immediate future. 

Uncertainty Remains about How Much Oil Can Be Produced from Proven 
Reserves, Hard-to-Reach Locations, and Nonconventional Sources: 

It is also difficult to project the timing of a peak in oil production 
because technological, cost, and environmental challenges make it 
unclear how much oil can ultimately be recovered from (1) proven 
reserves, (2) hard-to-reach locations, and (3) nonconventional sources. 

To increase the recovery rate from oil reserves, companies turn to 
enhanced oil recovery (EOR) technologies, which DOE reports has the 
potential to increase recovery rates from 30 to 50 percent in many 
locations. These technologies include injecting steam or heated water; 
gases, such as carbon dioxide; or chemicals into the reservoir to 
stimulate oil flow and allow for increased recovery. Opportunities for 
EOR have been most aggressively pursued in the United States, EOR 
technologies currently contribute approximately 12 percent to U.S. 
production, and carbon dioxide EOR alone is projected to have the 
potential to provide at least 2 million barrels per day by 2020. 
However, technological advances, such as better seismic and fluid- 
monitoring techniques for reservoirs during an EOR injection, may be 
required to make these techniques more cost-effective. Furthermore, EOR 
technologies are much costlier than the conventional production methods 
used for the vast majority of oil produced. Costs are higher because of 
the capital cost of equipment and operating costs, including the 
production, transportation, and injection of agents into existing 
fields and the additional energy costs of performing these tasks. 
Finally, EOR technologies have the potential to create environmental 
concerns associated with the additional energy required to conduct an 
EOR injection and the greenhouse gas emissions associated with 
producing that energy, although EIA has stated that these environmental 
costs may be less than those imposed by producing oil in previously 
undeveloped areas. Even if sustained high oil prices make EOR 
technologies cost-effective for an oil company, these challenges and 
costs may deter their widespread use. 

The timing of peak oil is also difficult to estimate because new 
sources of oil could be increasingly more remote and costly to exploit, 
including offshore production of oil in deepwater and ultra-deepwater. 
Worldwide, industry analysts report that deepwater (depths of 1,000 to 
5,000 feet) and ultra-deepwater (5,000 to 10,000 feet) drilling efforts 
are concentrated offshore in Africa, Latin America, and North America, 
and capital expenditures for these efforts are expected to grow through 
at least 2011. In the United States, deepwater and ultra-deepwater 
drilling, primarily in the Gulf of Mexico, could reach 2.2 million 
barrels per day in 2016, according to EIA estimates. However, accessing 
and producing oil from these locations present several challenges. At 
deepwater depths, penetrating the earth and efficiently operating 
drilling equipment is difficult because of the extreme pressure and 
temperature. In addition, these conditions can compromise the endurance 
and reliability of operating equipment. Operating costs for deepwater 
rigs are 3.0 to 4.5 times more than operating costs for typical shallow 
water rigs. Capital costs, including platforms and underwater pipeline 
infrastructures, are also greater. Finally, deepwater and ultra- 
deepwater drilling efforts generally face similar environmental 
concerns as shallow water drilling efforts, although some deepwater 
operations may pose greater environmental concerns to sensitive 
deepwater ecosystems. 

It is unclear how much oil can be recovered from nonconventional 
sources. Recovery from these sources could delay a peak in oil 
production or slow the rate of decline in production after a peak. 
Expert sources disagree concerning the significance of the role these 
nonconventional sources will play in the future. DOE officials we spoke 
with emphasized the belief that nonconventional oil will play a 
significant role in the very near future as conventional oil production 
is unable to meet the increasing demand for oil. However, IEA estimates 
of oil production have conventional oil continuing to comprise almost 
all of production through 2030. Currently, production of oil from key 
nonconventional sources of oil--oil sands, heavy and extra-heavy oil 
deposits, and oil shale--is more costly and presents environmental 
challenges. 

Oil Sands: 

Oil sands are deposits of bitumen, a thick, sticky form of crude oil, 
that is so heavy and viscous it will not flow unless heated. While most 
conventional crude oil flows naturally or is pumped from the ground, 
oil sands must be mined or recovered "in-situ," before being converted 
into an upgraded crude oil that can be used by refineries to produce 
gasoline and diesel fuels. Alberta, Canada, contains at least 85 
percent of the world's proven oil sands reserves. In 2005, worldwide 
production of oil sands, largely from Alberta, contributed 
approximately 1.6 million barrels of oil per day, and production is 
projected to grow to as much as 3.5 million barrels per day by 2030. 
Oil sand deposits are also located domestically in Alabama, Alaska, 
California, Texas, and Utah. Production from oil sands, however, 
presents significant environmental challenges. The production process 
uses large amounts of natural gas, which generates greenhouse gases 
when burned. In addition, large-scale production of oil sands requires 
significant quantities of water, typically produce large quantities of 
contaminated wastewater, and alter the natural landscape. These 
challenges may ultimately limit production from this resource, even if 
sustained high oil prices make production profitable. 

Heavy and Extra-Heavy Oils: 

Heavy and extra-heavy oils are dense, viscous oils that generally 
require advanced production technologies, such as EOR, and substantial 
processing to be converted into petroleum products. Heavy and extra- 
heavy oils differ in their viscosities and other physical properties, 
but advanced recovery techniques like EOR are required for both types 
of oil. Known extra-heavy oil deposits are primarily in Venezuela-- 
almost 90 percent of the world's proven extra-heavy oil reserves. 
Venezuelan production of extra-heavy oil was projected to be 600,000 
barrels of oil per day in 2005 and is projected to be sustained at this 
rate through 2040. Heavy oil can be found in Alaska, California, and 
Wyoming and may exist in other countries besides the United States and 
Venezuela. Like production from oil sands, however, heavy oil 
production in the United States presents environmental challenges in 
its consumption of other energy sources, which contributes to 
greenhouse gases, and potential groundwater contamination from the 
injectants needed to thin the oil enough so that oil will flow through 
pipes. 

Oil Shale: 

Oil shale is sedimentary rock containing solid bituminous materials 
that release petroleum-like liquids when the rock is heated. The 
world's largest known oil shale deposit covers portions of Colorado, 
Utah, and Wyoming, but other countries, such as Australia and Morocco, 
also contain oil shale resources. Oil shale production is under 
consideration in the United States, but considerable doubts remain 
concerning its ultimate technical and commercial feasibility. 
Production from oil shale is energy-intensive, requiring other energy 
sources to heat the shale to about 900 to 1,000 degrees Fahrenheit to 
extract the oil. Furthermore, oil shale production is projected to 
contaminate local surface water with salts and toxics that leach from 
spent shale. These factors may limit the amount of oil from shale that 
can be produced, even if oil prices are sustained at high enough levels 
to offset the additional production costs. 

More detailed information on these technologies is provided in appendix 
III. 

Political and Investment Risk Factors Create Uncertainty about the 
Future Rate of Oil Exploration and Production: 

Political and investment risk factors also could affect future oil 
exploration and production and, ultimately, the timing of peak oil 
production. These factors include changing political conditions and 
investment climates in many countries that have large proven oil 
reserves. Experts we spoke with told us that they considered these 
factors important in affecting future oil exploration and production. 

Political Conditions Create Uncertainties about Oil Exploration and 
Production: 

In many countries with proven reserves, oil production could be shut 
down by wars, strikes, and other political events, thus reducing the 
flow of oil to the world market. If these events occurred repeatedly, 
or in many different locations, they could constrain exploration and 
production, resulting in a peak despite the existence of proven oil 
reserves. For example, according to a news account, crude oil output in 
Iraq dropped from 3.0 million barrels per day before the 1990 gulf war 
to about 2.0 million barrels per day in 2006, and a labor strike in the 
Venezuelan oil sector led to a drop in exports to the United States of 
1.2 million barrels. Although these were isolated and temporary oil 
supply disruptions, if enough similar events occurred with sufficient 
frequency, the overall impact could constrain production capacity, thus 
making it impossible for supply to expand along with demand for oil. 
Using a measure of political risk that assesses the likelihood that 
events such as civil wars, coups, and labor strikes will occur in a 
magnitude sufficient to reduce a country's gross domestic product (GDP) 
growth rate over the next 5 years,[Footnote 16] we found that four 
countries--Iran, Iraq, Nigeria, and Venezuela--that possess proven oil 
reserves greater than 10 billion barrels (high reserves) also face high 
levels of political risk. These four countries contain almost one-third 
of worldwide oil reserves. Countries with medium or high levels of 
political risk contained 63 percent of proven worldwide oil reserves, 
on the basis of Oil and Gas Journal estimates of oil reserves. (See 
fig. 7.)[Footnote 17] 

Figure 7: Worldwide Proven Oil Reserves, by Political Risk: 

[See PDF for image] 

Source: GAO analysis of Oil and Gas Journal and Global Insight data. 

Note: Oil and Gas Journal reserves estimates are based on surveys 
filled out by the countries. See appendix I of this report for 
limitations of these data and their effect on our use of these data. 

[End of figure] 

Even in the United States, political considerations may affect the rate 
of exploration and production. For example, restrictions imposed to 
protect environmental assets mean that some oil may not be produced. 
Interior's Minerals Management Service estimates that approximately 76 
billion barrels of oil lie in undiscovered fields offshore in the U.S. 
outer continental shelf. However, Congress has enacted moratoriums on 
drilling and exploration in this area to protect coastlines from 
unintended oil spills. In addition, policies on federal land use need 
to take into account multiple uses of the land, including environmental 
protection.[Footnote 18] Environmental restrictions may affect a peak 
in oil production by barring oil exploration and production in 
environmentally sensitive areas. 

Investment Climate Creates Uncertainty about Oil Exploration and 
Production: 

Foreign investment in the oil sector could be necessary to bring oil to 
the world market,[Footnote 19] according to studies we reviewed and 
experts we consulted, but many countries have restricted foreign 
investment. Lack of investment could hasten a peak in oil production 
because the proper infrastructure might not be available to find and 
produce oil when needed, and because technical expertise may be 
lacking. The important role foreign investment plays in oil production 
is illustrated in Kazakhstan, where the National Commission on Energy 
Policy found that opening the energy sector to foreign investment in 
the early 1990s led to a doubling in oil production between 1998 and 
2002.[Footnote 20] In addition, we found that direct foreign investment 
in Venezuela was strongly correlated with oil production in that 
country, and that when foreign investment declined between 2001 and 
2004, oil production also declined.[Footnote 21] Industry officials 
told us that lack of technical expertise could lead to less 
sophisticated drilling techniques that actually reduce the ability to 
recover oil in more complex reservoirs. For example, according to 
industry officials, some Russian wells have difficulties with high 
water cut--that is, a high ratio of water to oil--making oil difficult 
to get out of the ground at current prices. This water cut problem 
stems from not using technically advanced methods when the wells were 
initially drilled. We have previously reported that the Venezuelan 
national oil company, PDVSA, lost technical expertise when it fired 
thousands of employees following a strike in 2002 and 2003. In 
contrast, other national oil companies, such as Saudi Aramco, are 
widely perceived to possess considerable technical expertise. 

According to our analysis, 85 percent of the world's proven oil 
reserves are in countries with medium-to-high investment risk or where 
foreign investment is prohibited, on the basis of Oil and Gas Journal 
estimates of oil reserves. (See fig. 8.) For example, over one-third of 
the world's proven oil reserves lie in only five countries--China, 
Iran, Iraq, Nigeria, and Venezuela--all of which have a high likelihood 
of seeing a worsening investment climate. Three countries with large 
oil reserves--Saudi Arabia, Kuwait, and Mexico--prohibit foreign 
investment in the oil sector, and most major oil-producing countries 
have some type of restrictions on foreign investment. Furthermore, some 
countries that previously allowed foreign investment, such as Russia 
and Venezuela, appear to be reasserting state control over the oil 
sector, according to DOE. 

Figure 8: Worldwide Proven Oil Reserves, by Investment Risk: 

[See PDF for image] 

Source: GAO analysis of Oil and Gas Journal and Global Insight data. 

Note: Oil and Gas Journal reserves estimates are based on surveys 
filled out by the countries. See appendix I of this report for 
limitations of these data and their effect on our use of these data. 

[End of figure] 

Foreign investment in the oil sector also may be limited because 
national oil companies control the supply. Figure 9 indicates that 7 of 
the top 10 companies are national or state-sponsored oil and gas 
companies, ranked on the basis of oil production. The 3 international 
oil companies that are among the top 10 are BP, Exxon Mobil, and Royal 
Dutch Shell. 

Figure 9: Top 10 Companies on the Basis of Oil Production and Reserves 
Holdings, 2004: 

[See PDF for image] 

Source: GAO analysis of data from Petroleum Intelligence Weekly (dec. 
12, 2005). 

Note: The Petroleum Intelligence Weekly data relies on company reports, 
where possible, as well as other information sources provided by 
companies. See appendix I of this report for limitations of these data 
and their effect on our use of these data. 

[A] Lukoil is the only company in the top 10 based on reserves that is 
not 100 percent state-sponsored. 

[End of figure] 

National oil companies may have additional motivations for producing 
oil, other than meeting consumer demand. For instance, some countries 
use some profits from national companies to support domestic 
socioeconomic development, rather than focusing on continued 
development of oil exploration and production for worldwide 
consumption. Given the amount of oil controlled by national oil 
companies, these types of actions have the potential to result in oil 
production that is not optimized to respond to increases in the demand 
for oil. 

In addition, the top 8 oil companies ranked by proven oil reserves are 
national companies in OPEC-member countries, and OPEC decisions could 
affect future oil exploration and production. For example, in some 
cases, OPEC countries might decide to limit current production to 
increase prices or to preserve oil and its revenue for future 
generations. Figure 10 shows IEA's projections for total world oil 
production through 2030 and highlights the larger role that OPEC 
production will play after IEA's projected peak in non-OPEC oil 
production around 2010. 

Figure 10: World Oil Production, by OPEC and Non-OPEC Countries, 2004 
Projected to 2030: 

[See PDF for image] 

Source: International Energy Agency. 

Note: This projection excludes production from nonconventional oil 
sources, such as Canadian oil sands. 

[End of figure] 

Future World Demand for Oil Is Uncertain: 

Uncertainty about future demand for oil--which will influence how 
quickly the remaining oil is used--contributes to the uncertainty about 
the timing of peak oil production. EIA projects that oil will continue 
to be a major source of energy well into the future, with world 
consumption of petroleum products growing to 118 million barrels per 
day by 2030. Figure 11 shows world petroleum product consumption by 
region for 2003 and EIA's projections for 2030. As the figure shows, 
EIA projects that consumption will increase across all regions of the 
world, but members of the Organization for Economic Cooperation and 
Development (OECD) North America,[Footnote 22] which includes the 
United States, and non-OECD Asia, which includes China and India, are 
the major drivers of this growth. 

Figure 11: Daily World Oil Consumption, by Region for 2003 and 
Projected for 2030: 

[See PDF for image] 

Source: Energy Information Administration. 

[End of figure] 

Future world oil demand will depend on such uncertain factors as world 
economic growth, future government policy, and consumer choices. 
Specifically: 

* Economic growth drives demand for oil. For example, according to IEA, 
in 2003 the world experienced strong growth in oil consumption of 2.0 
percent, with even stronger growth of 3.6 percent in 2004, from 79.8 
million barrels per day to 82.6 million barrels per day and China 
accounted for 30 percent of this increase, driven largely by China's 
almost 10 percent economic growth that year. EIA projects the Chinese 
economy will continue to grow, but factors such as the speed of reform 
of ineffective state-owned companies and the development of capital 
markets adds uncertainty to such projections and, as a result, to the 
level of future oil demand in China. 

* Future government policy can also affect oil demand. For example, 
environmental concerns about gasoline's emissions of carbon dioxide, 
which is a greenhouse gas, may encourage future reductions in oil 
demand if these concerns are translated into policies that promote 
biofuels. 

* Consumer choices about conservation also can affect oil demand and 
thereby influence the timing of a peak. For example, if U.S. consumers 
were to purchase more fuel-efficient vehicles in greater numbers, this 
could reduce future oil demand in the United States, potentially 
delaying a time at which oil supply is unable to keep pace with oil 
demand. 

Such uncertainties that lead to changes in future oil demand ultimately 
make estimates of the timing of a peak uncertain, as is illustrated in 
an EIA study on peak oil.[Footnote 23] Specifically, using future 
annual increases in world oil consumption, ranging from 0 percent, to 
represent no increase, to 3 percent, to represent a large increase, and 
out of the various scenarios examined, EIA estimated a window of up to 
75 years for when the peak may occur. 

Factors That Create Uncertainty about the Timing of the Peak Also 
Create Uncertainty about the Rate of Decline: 

Factors that create uncertainty about the timing of the peak--in 
particular, factors that affect oil exploration and production--also 
create uncertainty about the rate of production decline after the peak. 
For example, IEA reported that technology played a key role in slowing 
the decline and extending the life of oil production in the North Sea. 
Uncertainty about the rate of decline is illustrated in studies that 
estimate the timing of a peak. IEA, for example, estimates that this 
decline will range somewhere between 5 percent and 11 percent annually. 
Other studies assume the rate of decline in production after a peak 
will be the same as the rise in production that occurred before the 
peak. Another methodology, employed by EIA, assumes that the resulting 
decline will actually be faster than the rise in production that 
occurred before the peak. The rate of decline after a peak is an 
important consideration because a decline that is more abrupt will 
likely have more adverse economic consequences than a decline that is 
less abrupt. 

Alternative Transportation Technologies Face Challenges in Mitigating 
the Consequences of the Peak and Decline: 

In the United States, alternative transportation technologies have 
limited potential to mitigate the consequences of a peak and decline in 
oil production, at least in the near term, because they face many 
challenges that will take time and effort to overcome. If the peak and 
decline in oil production occur before these technologies are advanced 
enough to substantially offset the decline, the consequences could be 
severe. If the peak occurs in the more distant future, however, 
alternative technologies have a greater potential to mitigate the 
consequences. 

Development and Adoption of Technologies to Displace Oil Will Take Time 
and Effort: 

Development and widespread adoption of the seven alternative fuels and 
advanced vehicle technologies we examined will take time, and 
significant challenges will have to be overcome, according to DOE. 
These technologies include ethanol, biodiesel, biomass gas-to-liquid, 
coal gas-to-liquid, natural gas and natural gas vehicles, advanced 
vehicle technologies, and hydrogen fuel cell vehicles. 

Ethanol: 

Ethanol is an alcohol-based fuel produced by fermenting plant sugars. 
Currently, most ethanol in the United States is made from corn, but 
ethanol also can be made from cellulosic matter from a variety of 
agricultural products, including trees, grasses, and forestry residues. 
Corn ethanol has been used as an additive to gasoline for many years, 
but it is also available as a primary fuel, most commonly as a blended 
mix of 85 percent ethanol and 15 percent gasoline. As a primary fuel, 
corn ethanol is not currently available on a large national scale and 
federal agencies do not consider it to be cost-competitive with 
gasoline or diesel. The cost of corn feedstock, which accounts for 
approximately 75 percent of the production cost, is not projected to 
fall dramatically in the future, in part, because of competing demands 
for agricultural land use and competing uses for corn, primarily as 
livestock feed, according to DOE and USDA. 

DOE and USDA project that more cellulosic ethanol could ultimately be 
produced than corn ethanol because cellulosic ethanol can be produced 
from a variety of feedstocks, but more fundamental reductions in 
production costs will be needed to make cellulosic ethanol commercially 
viable. Production of ethanol from cellulosic feedstocks is currently 
more costly than production of corn ethanol because the cellulosic 
material must first be broken down into fermentable sugars that can be 
converted into ethanol. The production costs associated with this 
additional processing would have to be reduced in order for cellulosic 
ethanol to be cost-competitive with gasoline at today's prices. 

In addition, corn and cellulosic ethanol are more corrosive than 
gasoline, and the widespread commercialization of these fuels would 
require substantial retrofitting of the refueling infrastructure-- 
pipelines, storage tanks, and filling stations. To store ethanol, 
gasoline stations may have to retrofit or replace their storage tanks, 
at an estimated cost of $100,000 per tank. DOE officials also reported 
that some private firms consider capital investment in ethanol 
refineries to be risky for significant investment, unless the future of 
alternative fuels becomes more certain. Finally, widespread use of 
ethanol would require a turnover in the vehicle fleet because most 
current vehicle engines cannot effectively burn ethanol in high 
concentrations. 

Biodiesel: 

Biodiesel is a renewable fuel that has similar properties to petroleum 
diesel but can be produced from vegetable oils or animal fats. It is 
currently used in small quantities in the United States, but it is not 
cost-competitive with gasoline or diesel. The cost of biodiesel 
feedstocks--which in the United States largely consist of soybean oil-
-are the largest component of production costs. The price of soybean 
oil is not expected to decrease significantly in the future owing to 
competing demands from the food industry and from soap and detergent 
manufacturers. These competing demands, as well as the limited land 
available for the production of feedstocks, also are projected to limit 
biodiesel's capacity for large-volume production, according to DOE and 
USDA. As a result, experts believe that the total production capacity 
of biodiesel is ultimately limited compared with other alternative 
fuels. 

Biomass Gas-to-Liquid: 

Biomass gas-to-liquid (biomass GTL) is a fuel produced from biomass 
feedstocks by gasifying the feedstocks into an intermediary product, 
referred to as syngas, before converting it into a diesel-like fuel. 
This fuel is not commercially produced, and a number of technological 
and economic challenges would need to be overcome for commercial 
viability. These challenges include identifying biomass feedstocks that 
are suitable for efficient conversion to a syngas and developing 
effective methods for preparing the biomass for conversion into a 
syngas. Furthermore, DOE researchers report that significant work 
remains to successfully gasify biomass feedstocks on a large enough 
scale to demonstrate commercial viability. In the absence of these 
developments, DOE reported that the costs of producing biomass GTL will 
be very high and significant uncertainty surrounding its ultimate 
commercial feasibility will exist. 

Coal Gas-to-Liquid: 

Coal gas-to-liquid (coal GTL) is a fuel produced by gasifying coal into 
a syngas before being converted into a diesel-like fuel. This fuel is 
commercially produced outside the United States, but none of the 
production facilities are considered profitable. DOE reported that high 
capital investments--both in money and time--deter the commercial 
development of coal GTL in the United States. Specifically, DOE 
estimates that construction of a coal GTL conversion plant could cost 
up to $3.5 billion and would require at least 5 to 6 years to 
construct. Furthermore, potential investors are deterred from this 
investment because of the risks associated with the lengthy, uncertain, 
and costly regulatory process required to build such a facility. An 
expert at DOE also expressed concern that the infrastructure required 
to produce or transport coal may be insufficient. For example, the rail 
network for transporting western coal is already operating at full 
capacity and, owing to safety and environmental concerns, there is 
significant uncertainty about the feasibility of expanding the 
production capabilities of eastern coal mines. Coal GTL production also 
faces serious environmental concerns because of the carbon dioxide 
emitted during production. To mitigate the effect of coal GTL 
production, researchers are considering options for combining coal GTL 
production with underground injection of sequestered carbon dioxide to 
enhance oil recovery in aging oil fields. 

Natural Gas and Natural Gas Vehicles: 

Natural gas is an alternative fuel that can be used as either a 
compressed natural gas or a liquefied natural gas. Natural gas vehicles 
are currently available in the United States, but their use is limited, 
and production has declined in the past few years. According to DOE, 
large-scale commercialization of natural gas vehicles is complicated by 
the widespread availability and lower cost of gasoline and diesel 
fuels. Furthermore, demand for natural gas in other markets, such as 
home heating and energy generation, presents substantial competitive 
risks to the natural gas vehicle industry. Production costs for natural 
gas vehicles are also higher than for conventional vehicles because of 
the incremental cost associated with a high-pressure natural gas tank. 
For example, light-duty natural gas vehicles can cost $1,500 to $6,000 
more than comparable conventional vehicles, while heavy-duty natural 
gas vehicles cost $30,000 to $50,000 more than comparable conventional 
vehicles. Regarding infrastructure, retrofitting refueling stations so 
that they can accommodate natural gas could cost from $100,000 to $1 
million per station, depending on the size, according to DOE. Although 
refueling at home can be an option for some natural gas vehicles, home 
refueling appliances are estimated to cost approximately $2,000 each. 

Advanced Vehicle Technologies: 

Advanced vehicle technologies that we considered included lightweight 
materials and improvements to conventional engines that increase fuel 
economy, as well as hybrid vehicles and plug-in hybrid electric 
vehicles that use an electric motor/generator and a battery pack in 
conjunction with an internal combustion engine. Hybrid electric 
vehicles are commercially available in the United States, but these are 
not yet considered competitive with comparable conventional vehicles. 
DOE experts report that demand for such vehicles is predicated on their 
cost-competitiveness with comparable conventional vehicles. Hybrid 
electric vehicles, for example, cost $2,000 to $3,500 more to buy than 
comparable conventional vehicles and currently constitute around 1 
percent of new vehicle registrations in the United States. In addition, 
electric batteries in hybrid electric vehicles face technical 
challenges associated with their performance and reliability when 
exposed to extreme temperatures or harsh automotive environments. Other 
advanced vehicle technologies, including advanced diesel engines and 
plug-in hybrids, are (1) in the very early stages of commercial release 
or are not yet commercially available and (2) face obstacles to large- 
scale commercialization. For example, advanced diesel engines present 
an environmental challenge because, despite their high fuel efficiency, 
they are not expected to meet future emission standards. Federal 
researchers are working to enable the engine to burn more cleanly, but 
these efforts are costly and face technical barriers. Plug-in hybrid 
electric vehicles are not yet commercially feasible because of cost, 
technical, and infrastructure challenges facing their development. For 
example, plug-in electric hybrids cost much more to produce than 
conventional vehicles, they require significant upgrades to home 
electrical systems to support their recharging, and researchers have 
yet to develop a plug-in electric with a range of more than 40 miles on 
battery power alone. 

Hydrogen Fuel Cell Vehicles: 

A hydrogen fuel cell vehicle is powered by the electricity produced 
from an electrochemical reaction between hydrogen from a hydrogen- 
containing fuel and oxygen from the air. In the United States, these 
vehicles are still in the development stage, and making these vehicles 
commercially feasible presents a number of challenges. While a 
conventional gas engine costs $2,000 to $3,000 to produce, the stack of 
hydrogen fuel cells needed to power a vehicle costs $35,000 to produce. 
Furthermore, DOE researchers have yet to develop a method for feasibly 
storing hydrogen in a vehicle that allows a range of at least 300 miles 
before refueling. Fuel cell vehicles also are not yet able to last for 
120,000 miles, which DOE believes to be the target for commercial 
viability. In addition, developing an infrastructure for distributing 
hydrogen--either through pipelines or through trucking--is expected to 
be complicated, costly, and time-consuming. Delivering hydrogen from a 
central source requires a large amount of energy and is considered 
costly and technically challenging. DOE has determined that 
decentralized production of hydrogen directly at filling stations could 
be a more viable approach than centralized production in some cases, 
but a cost-effective mechanism for converting energy sources into 
hydrogen at a filling station has yet to be developed. 

More detailed information on these technologies is provided in appendix 
IV. 

Consequences Could Be Severe If Alternative Technologies Are Not 
Available: 

Because development and widespread adoption of technologies to displace 
oil will take time and effort, an imminent peak and sharp decline in 
oil production could have severe consequences. The technologies we 
examined currently supply the equivalent of only about 1 percent of 
U.S. annual consumption of petroleum products, and DOE projects that 
even under optimistic scenarios, these technologies could displace only 
the equivalent of about 4 percent of annual projected U.S. consumption 
by around 2015. If the decline in oil production exceeded the ability 
of alternative technologies to displace oil, energy consumption would 
be constricted, and as consumers competed for increasingly scarce oil 
resources, oil prices would sharply increase. In this respect, the 
consequences could initially resemble those of past oil supply shocks, 
which have been associated with significant economic damage. For 
example, disruptions in oil supply associated with the Arab oil embargo 
of 1973-74 and the Iranian Revolution of 1978-79 caused unprecedented 
increases in oil prices and were associated with worldwide recessions. 
In addition, a number of studies we reviewed indicate that most of the 
U.S. recessions in the post-World War II era were preceded by oil 
supply shocks and the associated sudden rise in oil prices. 

Ultimately, however, the consequences of a peak and permanent decline 
in oil production could be even more prolonged and severe than those of 
past oil supply shocks. Because the decline would be neither temporary 
nor reversible, the effects would continue until alternative 
transportation technologies to displace oil became available in 
sufficient quantities at comparable costs. Furthermore, because oil 
production could decline even more each year following a peak, the 
amount that would have to be replaced by alternatives could also 
increase year by year. 

Consumer actions could help mitigate the consequences of a near-term 
peak and decline in oil production through demand-reducing behaviors 
such as carpooling; teleworking; and "eco-driving" measures, such as 
proper tire inflation and slower driving speeds. Clearly these energy 
savings come at some cost of convenience and productivity, and limited 
research has been done to estimate potential fuel savings associated 
with such efforts. However, DOE estimates that drivers could improve 
fuel economy between 7 and 23 percent by not exceeding speeds of 60 
miles per hour, and IEA estimates that teleworking could reduce total 
fuel consumption in the U.S. and Canadian transportation sectors 
combined by between 1 and 4 percent, depending on whether teleworking 
is undertaken for 2 days per week or the full 5-day week, respectively. 

If the peak occurs in the more distant future or the decline following 
a peak is less severe, alternative technologies have a greater 
potential to mitigate the consequences. DOE projects that the 
alternative technologies we examined have the potential to displace up 
to the equivalent of 34 percent of annual U.S. consumption of petroleum 
products in the 2025 through 2030 time frame. However, DOE also 
considers these projections optimistic--it assumes that sufficient time 
and effort are dedicated to the development of these technologies to 
overcome the challenges they face. More specifically, DOE assumes 
sustained high oil prices above $50 per barrel as a driving force. The 
level of effort dedicated to overcoming challenges to alternative 
technologies will depend in part on the price of oil, with higher oil 
prices creating incentives to develop alternatives. High oil prices 
also can spark consumer interest in alternatives that consume less oil. 
For example, new purchases of light trucks, SUVs, and minivans declined 
in 2005 and 2006, corresponding to a period of increasing gasoline 
prices. Gasoline demand has also grown slower in 2005 and 2006--0.95 
and 1.43 percent, respectively--compared with the preceding decade, 
during which gasoline demand grew at an average rate of 1.81 percent. 
In the past, high oil prices have significantly affected oil 
consumption: U.S. consumption of oil fell by about 18 percent from 1979 
to 1983, in part because U.S. consumers purchased more fuel-efficient 
vehicles in response to high oil prices. 

While current high oil prices may encourage development and adoption of 
alternatives to oil, if high oil prices are not sustained, efforts to 
develop and adopt alternatives may fall by the wayside. The high oil 
prices and fears of running out of oil in the 1970s and early 1980s 
encouraged investments in alternative energy sources, including 
synthetic fuels made from coal, but when oil prices fell, investments 
in these alternatives became uneconomic. More recently, private sector 
interest in alternative fuels has increased, corresponding to the 
increase in oil prices, but uncertainty about future oil prices can be 
a barrier to investment in risky alternative fuels projects. Recent 
polling data also indicate that consumers' interest in fuel efficiency 
tends to increase as gasoline prices rise and decrease when gasoline 
prices fall. 

Federal Agencies Do Not Have a Coordinated Strategy to Address Peak Oil 
Issues: 

Federal agency efforts that could contribute to reducing uncertainty 
about the timing of a peak in oil production or mitigating its 
consequences are spread across multiple agencies and are generally not 
focused explicitly on peak oil issues. Federal agency-sponsored studies 
have expressed a growing concern over the potential for a peak, and 
officials from key agencies have identified options for reducing the 
uncertainty about the timing of a peak in oil production and mitigating 
its consequences. However, there is no strategy for coordinating or 
prioritizing such efforts. 

Federal Agencies Have Many Programs and Activities Related to Peak Oil 
Issues, but Peak Oil Generally Is Not the Main Focus of These Efforts: 

Federal agencies have programs and activities that could be directed to 
reduce uncertainty about the timing of a peak in oil production or to 
mitigate the consequences of such a peak. For example, with regard to 
reducing uncertainty, DOE provides information and analysis about 
global supply and demand for oil and develops projections about future 
trends. Specifically, DOE's EIA regularly surveys U.S. operators to 
gather data about U.S. oil reserves and compiles reserves data for 
foreign countries from other sources. In addition, EIA prepares both a 
domestic and international energy outlook, which includes projections 
for future oil supply and demand. As previously discussed, USGS 
provides estimates of oil resources that have the potential to add to 
reserves in the United States. Interior's Minerals Management Service 
also assesses oil resources in the offshore regions of the United 
States. 

In addition, several agencies conduct activities to encourage 
development of alternative technologies that could help mitigate the 
consequences of a decline in oil production. For example, DOE promotes 
development of alternative fuels and advanced vehicle technologies that 
could reduce oil consumption in the transportation sector by funding 
research and development of new technologies. In addition, USDA 
encourages development of biomass-based alternative fuels, by 
collaborating with industry to identify and test the performance of 
potential biomass feedstocks and conducting research to evaluate the 
cost of producing biomass fuels. DOT provides funding to encourage 
development of bus fleets that run on alternative fuels, promote 
carpooling among consumers, and conduct outreach and education 
concerning telecommuting. In addition, DOT is responsible for setting 
fuel economy standards for automobiles and light trucks sold in the 
United States. 

While these and other programs and activities could be used to reduce 
uncertainty about the timing of a peak in oil production and mitigate 
its consequences, agency officials we spoke with acknowledged that most 
of these efforts are not explicitly designed to do so. For example, 
DOE's activities related explicitly to peak oil issues have been 
limited to conducting, commissioning, or participating in studies and 
workshops. 

Agencies Have Options to Reduce Uncertainty and Mitigate Consequences 
but Lack a Coordinated Strategy: 

Several federally sponsored studies we reviewed reflect a growing 
concern about peak oil and identify a need for action. For example: 

* DOE has sponsored two studies.[Footnote 24] A 2003 study highlighted 
the benefit of reducing the uncertainty surrounding the timing of a 
peak to mitigate its potentially severe global economic consequences. A 
2005 study examined mitigating the consequences of a peak and concluded 
the following: "Timely, aggressive mitigation initiatives addressing 
both the supply and the demand sides of the issue will be required." 

* While EIA's 2004 study of the timing of peak oil estimates that a 
peak might occur closer to 2050, EIA recognized that early preparation 
was important because of the long period required for widespread 
commercial production and adoption of new energy technologies.[Footnote 
25] 

* In its 2005 study of energy use in the military,[Footnote 26] the 
U.S. Army Corps of Engineers emphasized the need to develop alternative 
technologies and associated infrastructure before a peak and decline in 
oil production. 

In addition, in response to growing peak oil concerns, DOE asked the 
National Petroleum Council to study peak oil issues. The study is 
expected to be completed by June 2007. 

In light of these concerns, agency officials told us that it would be 
worthwhile to take additional steps to reduce the uncertainty about the 
timing of a peak in oil production. EIA believes it could reduce 
uncertainty surrounding the timing of peak oil production if it were to 
robustly extend the time horizon of its analysis and projection of 
global supply and demand for crude oil presented in its domestic and 
international energy outlooks. Currently, EIA's projections extend only 
to 2030, and officials believe that consideration of peak oil would 
require a longer horizon. Also, the international outlook is fairly 
limited, in part because EIA no longer conducts its detailed Foreign 
Energy Supply Assessment Program. EIA is seeking to restart this effort 
in fiscal year 2007. In addition, USGS officials told us that better 
and more complete information about global oil resources could be used 
to improve estimates by EIA of the timing of a peak. USGS officials 
said their estimates of global oil resources could be improved or 
expanded in the following four ways: 

* Add information on certain regions--which USGS refers to as "frontier 
regions"--where little is known about oil resources. 

* Add information on nonconventional resources outside the United 
States. USGS believes these resources will play a large role in future 
oil supply, and, therefore, accurate estimates of these resources 
should be included in any attempts to determine the timing of a peak. 

* Calculate reserves growth by country. USGS considers this information 
important because of the political and investment conditions that 
differ by country and will affect future oil production and 
exploration. 

* Provide more complete information for all major oil-producing 
countries. USGS noted that its assessment has some "holes" where 
resources in major-producing countries have not yet been estimated 
completely. 

In addition to these actions reducing the uncertainty about the timing 
of a peak, agency officials also told us that they could take 
additional steps to mitigate the consequences of a peak. For example, 
DOE officials reported that they could expand their efforts to 
encourage the development of alternative fuels and advanced vehicle 
technologies. These efforts could be expanded by conducting more 
demonstrations of new technologies, facilitating greater information 
sharing among key industry players, and increasing cost share 
opportunities with industry for research and development.[Footnote 27] 
Agency officials told us such efforts can be essential to developing 
and encouraging the technologies. 

Although there are many options to reduce the uncertainty about the 
timing of a peak or to mitigate its potential consequences, according 
to DOE, there is no formal strategy to coordinate and prioritize 
federal programs and activities dealing with peak oil issues--either 
within DOE or between DOE and other key agencies. 

Conclusions: 

The prospect of a peak in oil production presents problems of global 
proportion whose consequences will depend critically on our 
preparedness. The consequences would be most dire if a peak occurred 
soon, without warning, and were followed by a sharp decline in oil 
production because alternative energy sources, particularly for 
transportation, are not yet available in large quantities. Such a peak 
would require sharp reductions in oil consumption, and the competition 
for increasingly scarce energy would drive up prices, possibly to 
unprecedented levels, causing severe economic damage. While these 
consequences would be felt globally, the United States, as the largest 
consumer of oil and one of the nations most heavily dependent on oil 
for transportation, may be especially vulnerable among the 
industrialized nations of the world. 

In the longer term, there are many possible alternatives to using oil, 
including using biofuels and improving automotive fuel efficiency, but 
these alternatives will require large investments, and in some cases, 
major changes in infrastructure or break-through technological 
advances. In the past, the private sector has responded to higher oil 
prices by investing in alternatives, and it is doing so now. 
Investment, however, is determined largely by price expectations, so 
unless high oil prices are sustained, we cannot expect private 
investment in alternatives to continue at current levels. If a peak 
were anticipated, oil prices would rise, signaling industry to increase 
efforts to develop alternatives and consumers of energy to conserve and 
look for more energy-efficient products. 

Federal agencies have programs and activities that could be directed 
toward reducing uncertainty about the timing of a peak in oil 
production, and agency officials have stated the value in doing so. In 
addition, agency efforts to stimulate the development and adoption of 
alternatives to oil use could be increased if a peak in oil production 
were deemed imminent. 

While public and private responses to an anticipated peak could 
mitigate the consequences significantly, federal agencies currently 
have no coordinated or well-defined strategy either to reduce 
uncertainty about the timing of a peak or to mitigate its consequences. 
This lack of a strategy makes it difficult to gauge the appropriate 
level of effort or resources to commit to alternatives to oil and puts 
the nation unnecessarily at risk. 

Recommendation for Executive Action: 

While uncertainty about the timing of peak oil production is 
inevitable, reducing that uncertainty could help energy users and 
suppliers, as well as government policymakers, to act in ways that 
would mitigate the potentially adverse consequences. Therefore, we 
recommend that the Secretary of Energy take the lead, in coordination 
with other relevant agencies, to prioritize federal agency efforts and 
establish a strategy for addressing peak oil issues. At a minimum, such 
a strategy should seek to do the following: 

* Monitor global supply and demand of oil with the intent of reducing 
uncertainty surrounding estimates of the timing of peak oil production. 
This effort should include improving the information available to 
estimate the amount of oil, conventional and nonconventional, remaining 
in the world as well as the future production and consumption of this 
oil, while extending the time horizon of the government's projections 
and analysis. 

* Assess alternative technologies in light of predictions about the 
timing of peak oil production and periodically advise Congress on 
likely cost-effective areas where the government could assist the 
private sector with development and adoption of such technologies. 

Agency Comments and Our Evaluation: 

We provided the Departments of Energy and the Interior with a draft of 
this report for their review and comment. 

DOE generally agreed with our message and recommendations and made 
several clarifying and technical comments, which we addressed in the 
body of the report as appropriate. Appendix V contains a reproduction 
of DOE's letter and our detailed response to their comments. 
Specifically, DOE commented that the draft report did not make a 
distinction between a peak in conventional versus a peak in total 
(conventional and nonconventional) oil. We agree that we have not made 
this distinction, in part because the numerous studies of peak oil that 
we reviewed did not always make such a distinction. Furthermore, we do 
not believe a clear distinction between these two peak concepts is 
possible, in part because the definition of what is conventional oil 
versus nonconventional oil is not universally agreed on. However, the 
information we have reported regarding uncertainty about the timing of 
a peak applies to either peak oil concept. 

DOE also commented that our use of certain technical phrases, including 
the distinction between heavy and extra-heavy oils and the distinction 
between oil consumption and demand, may be confusing to some readers, 
and we have made changes to the text to avoid such confusion. DOE 
commented that the draft report wrongly attributed environmental 
concerns to the use of enhanced oil recovery techniques, stating that 
the environmental community prefers such techniques on existing oil 
fields to exploration and development of new fields. We do not disagree 
that the environmental costs of these techniques may be smaller than 
for other activities and we have added text to express DOE's views on 
this matter. However, our point in listing the cost and environmental 
challenges of enhanced oil recovery techniques is that increasing oil 
production in the future could be more costly and more environmentally 
damaging than production of conventional oil, using primary production 
methods. For this reason we disagree with DOE's comment that we should 
remove the references to environmental challenges. 

Finally, DOE pointed out that the draft report was primarily focused on 
transportation technologies that are used to power autonomous vehicles, 
and they stated that a broader set of technologies that could displace 
oil should be considered. We agree with their characterization of the 
draft report. We chose transportation technologies because 
transportation accounts for such a large part of U.S. oil consumption 
and because DOE and other agencies have numerous programs and 
activities dealing with technologies to displace oil in the 
transportation sector. We also agree that a broader set of technologies 
should be considered in the long run as potential ways to mitigate the 
consequences of a peak in oil production. We encourage DOE and other 
agencies to fully explore the options to displace oil as they implement 
our recommendations to develop a strategy to reduce the uncertainty 
surrounding the timing of a peak in oil production and advise Congress 
on cost-effective ways to mitigate the consequences. 

Interior generally agreed with our message and recommendations in the 
draft report and made clarifying and technical comments, which we 
addressed in the body of the report as appropriate. Appendix VI 
contains a reproduction of Interior's letter and our detailed response 
to its comments. Specifically, Interior emphasized that it has a major 
role to play in estimating global oil resources, and that this effort 
should be made in conjunction with the efforts of DOE. We agree and 
encourage DOE to work in conjunction with Interior and other key 
agencies in establishing a strategy to coordinate and prioritize 
federal agency efforts to reduce the uncertainty surrounding the timing 
of a peak and to advise Congress on how best to mitigate consequences. 
Interior also commented that mitigating the consequences of a peak is 
outside their purview. We agree, and, in this report, we focus on 
examples of work that Interior could undertake to assist in reducing 
the uncertainty surrounding the estimates of global oil resources. 

As agreed with your offices, unless you publicly announce the contents 
of this report earlier, we plan no further distribution of it until 30 
days from the report date. At that time, we will send copies of this 
report to interested congressional committees, other Members of 
Congress, the Secretaries of Energy and the Interior, and other 
interested parties. We also will make copies available to others upon 
request. In addition, the report will be available at no charge on the 
GAO Web site at http://www.gao.gov. 

Should you or your staffs need further information, 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 contributions to this report 
are listed in appendix VII. 

Signed by: 

Jim Wells: 
Director, Natural Resources and Environment: 

[End of section] 

Appendix I: Scope and Methodology: 

To examine estimates of when oil production could peak, we reviewed key 
peak oil studies conducted by government agencies and oil industry 
experts. We limited our review to those studies that were published and 
excluded white papers or unpublished research. For studies that we 
cited in this report, we reviewed their estimate of the timing, 
methodology, and assumptions about the resource base to ensure that we 
properly represented the validity and reliability of their results and 
conclusions. We also consulted with federal government agencies and oil 
companies, as well as academic and research organizations, to identify 
the uncertainties associated with the timing of a peak. 

As part of our examination of the timing of peak oil production, we 
assessed other factors that could affect oil exploration and 
production. Specifically, we examined the challenges facing future 
technologies that could enhance the global production of oil, including 
technologies for increasing recovery from conventional reserves as well 
as technologies for producing nonconventional oil. To examine these 
technologies, we met with experts at the Department of Energy's (DOE) 
National Energy Technology Laboratory, and synthesized information 
provided by these experts. 

In addition, we examined political and investment risks associated with 
global oil exploration and production using Global Insight's Global 
Risk Service. For each country, Global Insight's country risk analyst 
estimates the subjective probability of 15 discrete events for 
political risk, and 22 discrete events for investment risk in the 
upstream oil and gas sectors. The probability is estimated for the next 
5 years. Senior analysts then meet to review the scores to ensure cross-
country consistency. The summary score is derived by weighting 
different groups of factors and then summing across the groups. For 
political risk, external and internal political risks are the two 
groups of factors. For investment risk in the oil and gas sectors, the 
factors are: investment/maintenance risk, input risk, production risk, 
sales risk, and revenue/repatriation risk. We compared political and 
investment risk with Oil and Gas Journal oil reserves estimates. Oil 
and Gas Journal reserves estimates are limited by the fact that they 
are not independently verified by the publishers and are based on 
surveys filled out by the countries. Because most countries do not 
reassess annually, some estimates in this survey do not change each 
year. We divided the countries into risk categories of low, medium, and 
high on the basis of quartiles and natural break points in the data. To 
obtain the percentage of reserves held by public companies and by 
national oil companies, we used the Petroleum Intelligence Weekly list 
of top 50 companies worldwide. The Petroleum Intelligence Weekly data 
are limited by reliance on company reports and other information 
sources provided by companies and the generation of estimates for those 
companies that do not release regular or complete reports. Estimates 
were created for most of the state-owned oil companies in figure 9 of 
this report. The limitations of these data reflect the uncertainty in 
estimates of the amount of oil in the ground, and our report does not 
rely on precise estimates of oil reserves but rather on the uncertainty 
about the amount of oil throughout the world and the challenges to 
exploration and production of oil. Therefore, we found these data to be 
sufficiently reliable for the purposes of our report. We also spoke 
with officials at the Securities and Exchange Commission and with DOE 
as well as experts in academia and industry. In addition, we reviewed 
documents from the Department of the Interior and the International 
Energy Agency (IEA). 

To assess the potential for transportation technologies to mitigate the 
consequences of a peak and decline in oil production, we examined 
options to develop alternative fuels and technologies to reduce energy 
consumption in the transportation sector. In particular, we focused on 
technologies that would affect automobiles and light trucks. We 
consulted with experts to devise a list of key technologies in these 
areas and then reviewed DOE programs and activities related to 
developing these technologies. To assess alternative fuels and advanced 
vehicle technologies, we met with various experts at DOE, including 
representatives from the National Energy Technology Laboratory and the 
National Renewable Energy Laboratory, and reviewed information provided 
by officials from various offices at DOE. In addition, we spoke with 
officials from the U.S. Department of Agriculture (USDA) and the 
Department of Transportation regarding the development of these 
technologies in the United States. We did not attempt to 
comprehensively list all technologies or to conduct a governmentwide 
review of all programs, and we limited our scope to what government 
officials at key federal agencies know about the status of these 
technologies in the United States. In addition, we did not conduct a 
global assessment of transportation technologies. We reviewed numerous 
studies on the relationship between oil and the global economy and, in 
particular, on the experiences of past oil price shocks. 

To identify federal government activities that could address peak oil 
production issues, we spoke with officials at DOE and the United States 
Geological Survey (USGS), and gathered information on federal programs 
and policies that could affect uncertainty about the timing of peak oil 
production and the development of alternative transportation 
technologies. To gain further insights into the federal role and other 
issues surrounding peak oil production, we convened an expert panel in 
Washington, D.C., in conjunction with the National Research Council of 
the National Academy of Sciences. On May 5, 2006, these experts 
commented on the potential economic consequences of a transition away 
from conventional oil; factors that could affect the severity of the 
consequences; and what the federal role should be in preparing for or 
mitigating the consequences, among other things. We recorded and 
transcribed the meeting to ensure that we accurately captured the panel 
members' statements. 

The following 13 experts served on the panel: 

* Stephen Brown, Director of Energy Economics and Microeconomic Policy 
Analysis, Federal Reserve Bank of Dallas: 

* David Greene, Corporate Fellow, Oak Ridge National Laboratory: 

* Howard Gruenspecht, Deputy Administrator, Energy Information 
Administration: 

* James Hamilton, Professor of Economics, University of California, San 
Diego: 

* Robert Hirsch, Senior Energy Program Advisor, SAIC: 

* Hillard G. Huntington, Executive Director Energy Modeling Forum, 
Stanford University: 

* James Katzer, Visiting Scholar, Massachusetts Institute of Technology 
(MIT), and Manager (retired), Strategic Planning and Performance 
Analysis, ExxonMobil Research and Engineering Company: 

* Robert Kaufmann, Professor, Center for Energy & Environmental 
Studies, Boston University: 

* Paul Leiby, Oak Ridge National Laboratory: 

* Nicola Pochettino, Senior Energy Analyst, Economic Analysis Division, 
International Energy Agency: 

* Edward Porter, Research Manager, American Petroleum Institute: 

* James Smith, Maguire Chair of Oil and Gas Management, Edwin L. Cox 
School of Business, Southern Methodist University: 

* James Sweeney, Professor, Management Science and Engineering, 
Stanford University: 

[End of section] 

Appendix II: Key Peak Oil Studies: 

This appendix lists the studies cited in figure 5 of this report. 

(a) L.F. Ivanhoe. " Updated Hubbert Curves Analyze World Oil Supply." 
World Oil. Vol. 217 (November 1996): 91-94. 

(b) Albert A. Bartlett. " An Analysis of U.S. and World Oil Production 
Patterns Using Hubbert-Style Curves." Mathematical Geology. Vol. 32, 
no.1 (2000). 

(c) Kenneth S. Deffeyes. " World's Oil Production Peak Reckoned in Near 
Future." Oil and Gas Journal. November 11, 2002. 

(d) Volvo. Future Fuels for Commercial Vehicles. 2005. 

(e) A.M. Samsam Bakhtiari. " World Oil Production Capacity Model 
Suggests Output Peak by 2006-2007." Oil and Gas Journal. April 26, 
2004. 

(f) Richard C. Duncan. " Peak Oil Production and the Road to the 
Olduvai Gorge." Pardee Keynote Symposia. Geological Society of America, 
Summit 2000. 

(g) David L. Greene, Janet L. Hopson, and Jai Li. Running Out Of and 
Into Oil: Analyzing Global Oil Depletion and Transition Through 2050. 
Oak Ridge National Laboratory, Department of Energy, October 2003. 

(h) C.J. Campbell. " Industry Urged to Watch for Regular Oil Production 
Peaks, Depletion Signals." Oil and Gas Journal. July 14, 2003. 

(i) Merril Lynch. Oil Supply Analysis. October 2005. 

(j) Ministére de l'Economie Des Finances et de l'Industrie. L'industrie 
pétrolière en 2004. 2005. 

(k) International Energy Agency. World Energy Outlook 2004. Paris 
France: 101-103. 

(l) Jean Laherrère. Future Oil Supplies. Seminar Center of Energy 
Conversion, Zurich: 2003. 

(m) Peter Gerling, Hilmar Remple, Ulrich Schwartz-Schampera, and Thomas 
Thielemann. Reserves, Resources and Availability of Energy Resources. 
Federal Institute for Geosciences and Natural Resources, Hanover, 
Germany: 2004. 

(n) John D. Edwards. " Crude Oil and Alternative Energy Production 
Forecasts for the Twenty-First Century: The End of the Hydrocarbon 
Era." American Association of Petroleum Geologists Bulletin. Vol. 81, 
no. 8 (August 1997). 

(o) Cambridge Energy Research Associates, Inc. Worldwide Liquids 
Capacity Outlook to 2010, Tight Supply or Excess of Riches. May 2005. 

(p) John H. Wood, Gary R. Long and David F. Morehouse. Long Term World 
Oil Supply Scenarios. Energy Information Administration: 2004. 

(q) Total. Sharing Our Energies: Corporate Social Responsibility Report 
2004. 

(r) Shell International. Energy Needs, Choices and Possibilities: 
Scenarios to 2050. Global Business Environment: 2001. 

(s) Directorate-General for Research Energy. World Energy, Technology 
and Climate Policy Outlook: WETO 2030. European Commission, EUR 20366: 
2003. 

(t) Exxon Mobil. The Outlook for Energy: A View to 2030. Corporate 
Planning. Washington, D.C.: November 2005. 

(u) Harry W. Parker. " Demand, Supply Will Determine When World Oil 
Output Peaks." Oil and Gas Journal. February 25, 2002. 

(v) M.A. Adelman and Michael C. Lynch. " Fixed View of Resource Limits 
Creates Undue Pessimism." Oil and Gas Journal. April 7, 1997. 

[End of section] 

Appendix III: Key Technologies to Enhance the Supply of Oil: 

This appendix contains brief profiles of technologies that could 
enhance the future supply of oil. This includes technologies for (1) 
increasing the rate of recovery from proven oil reserves using enhanced 
oil recovery; (2) producing oil from deepwater and ultra-deepwater 
reservoirs; and (3) producing nonconventional oil, such as oil sands 
and oil shale. For each technology, we provide a short description, 
followed by selected information on the key costs, potential 
production, readiness, key challenges, and current federal involvement. 
Although some of these technologies are in production or development 
throughout the world, the following profiles primarily focus on the 
development of these technologies in the United States. 

Enhanced Oil Recovery: 

Enhanced oil recovery (EOR) refers to the third stage of oil 
production, whereby sophisticated techniques are used to recover 
remaining oil from reservoirs that have otherwise been exhausted 
through primary and secondary recovery methods. During EOR, heat (such 
as steam), gases (such as carbon dioxide (CO2)), or chemicals are 
injected into the reservoir to improve fluid flow. Thermal and gas 
injection techniques account for almost all EOR activity in the United 
States, with CO2 injection being the technique that is currently 
attracting the most commercial interest. In the United States, EOR 
methods are currently being applied in a variety of regions, although 
most CO2 EOR occurs in the Permian Basin in Texas. Most EOR efforts in 
the United States are currently managed by small, independent 
operators. Globally, EOR has been introduced in a number of countries, 
but North America is estimated to represent over half of all global EOR 
production. 

Key Costs: 

* Costs associated with EOR production vary by reservoir, but reported 
marginal costs for oil recovery using EOR can range from $1.42 per 
barrel to $30 per barrel. 

* Key capital costs include new drills, reworking of existing drills, 
reconfiguring gathering systems, and modification of the injection 
plant and other surface facilities. 

Potential Production: 

* EOR currently contributes approximately 12 percent to the U.S. 
production of oil. 

* EOR is projected to increase average recovery rates in reservoirs 
from 30 percent to 50 percent. 

* Upper-end estimates of EOR's future recovery potential in the United 
States include the following: 1.0 million barrels per day by 2015 and 
2.5 million barrels per day by 2025. 

Readiness: 

* Thermal, gas, and chemical injection technologies are currently 
commercially available. 

* Key areas for further development exist, including sweep efficiency 
and water shut-off methods. 

Key Challenges: 

* Key challenges facing the development of EOR include the following: 
(1) a lack of industry-accepted, economical fluid injection systems; 
(2) a reliance on out-of-date practices and limited data due to lack of 
familiarity with state-of-the-art imaging and reluctance to risk 
investment in technologies; and (3) unwillingness on the part of some 
operators to assume the risks associated with EOR. 

Current Federal Involvement: 

* DOE is involved in several industry consortia and individual 
programs, designed to develop EOR, including conducting research and 
development and educating small producers about EOR. 

Deepwater and Ultra-Deepwater Drilling: 

Deepwater drilling refers to offshore drilling for oil in depths of 
water between 1,000 and 5,000 feet, while ultra-deepwater drilling 
refers to offshore drilling in depths of water between 5,000 and 10,000 
feet, according to DOE. The department reported that oil production at 
these depths involves a number of differences over shallow water 
drilling, such as drills that operate in extreme conditions, pipes that 
withstand deepwater ocean currents over long distances, and floating 
rigs as opposed to fixed rigs. The primary region for domestic 
deepwater drilling is the Gulf of Mexico, where deepwater drilling has 
become a major focus in recent years, particularly as near-shore oil 
production in shallow water has been declining. Globally, deepwater 
drilling occurs offshore in many locations, including Africa, Asia, and 
Latin America. 

Key Costs: 

* Costs vary by rig type, but the three key components of cost for 
deepwater and ultra-deepwater drilling include the following: (1) the 
daily vessel rental rate, (2) materials, and (3) drilling services. 

* The average market rate for Gulf of Mexico rigs can range from 
$210,000 per day to $300,000 per day. 

* Overall, the projected marginal costs of deepwater drilling range 
from 3.0 to 4.5 times the cost of shallow water drilling. 

Potential Production: 

* Current deepwater production in the Gulf of Mexico is estimated at 
1.3 million barrels per day. 

* Deepwater production in the Gulf of Mexico is projected to exceed 2 
million barrels per day in the next 10 years. 

Readiness: 

* Commercial deepwater drilling at depths of more than 1,000 feet in 
the Gulf of Mexico has been under way since the mid-1970s. 

* Companies are currently exploring prospects for drilling in depths of 
more than 5,000 feet, and since 2001, 11 discoveries of ultra-deepwater 
wells at depths of more than 7,000 feet have been announced. 

Key Challenges: 

* Examples of some of the key challenges facing the development of 
deepwater and ultra-deepwater drilling include the following: (1) rig 
issues, such as finding ways to adapt and use lower-cost rigs and 
improving the ability to moor vessels in deepwater; (2) drilling 
equipment reliability at high pressures and temperatures; and (3) 
reducing the costs of drilling and producing at deepwater and ultra- 
deepwater depths. 

Current Federal Involvement: 

* DOE is not directly involved in deepwater and ultra-deepwater 
drilling, but it does fund projects that could impact such drilling. 

* The Energy Policy Act of 2005 authorized some funding for research 
and development of alternative oil and gas activities, including 
deepwater drilling. 

Oil Sands: 

Oil sands are deposits of bitumen, a thick, sticky form of crude oil, 
which is so heavy and viscous that it will not flow unless heated or 
diluted with lighter hydrocarbons. It must be rigorously treated to 
convert it into an upgraded crude oil before it can be used by 
refineries to produce gasoline and diesel fuels. While conventional 
crude flows naturally or is pumped from the ground, oil sands must be 
mined or recovered "in-situ," or in place. During oil sands mining, 
approximately 2 tons of oil sands must be dug up, moved, and processed 
to produce 1 barrel of oil. During in-situ recovery, heat, solvents, or 
gases are used to produce the oil from oil sands buried too deeply to 
mine. The largest deposit of oil sands globally is found in Alberta, 
Canada--accounting for at least 85 percent of the world's oil sands 
reserves--although DOE reported that deposits of oil sands can also be 
found in the United States in Alabama, Alaska, California, Texas, and 
Utah. 

Key Costs: 

* Commercial Canadian oil sands are being produced at $18 to $22 per 
barrel. 

* Key infrastructure costs to support oil sands production in the 
United States would include construction of roads, pipelines, water, 
and energy production facilities. 

Potential Production: 

* The 2005 production of Canadian oil sands yielded 1.6 million barrels 
of oil per day and production is projected to grow to as much as 3.5 
million barrels per day by 2030. 

* Current U.S. production of oil sands currently yields less than 
175,000 barrels per year, and future production of U.S. oil sands will 
depend on the industry's investment decisions. 

Readiness: 

* Production of Canadian oil sands is currently in the commercial 
phase. 

* U.S. oil sands production is only in the demonstration phase, and 
adapting Canadian technologies to the characteristics of U.S. oil sands 
will require time. 

Key Challenges: 

* Examples of key challenges facing the development of oil sands 
include the following: (1) evaluating and alleviating environmental 
impacts, particularly concerning water consumption; (2) accessing the 
federal lands on which most of the U.S. oil sands are located; (3) 
addressing the increased demand on roads, schools, and other 
infrastructure that would result from the need to construct production 
facilities in some remote areas of the west; and (4) addressing the 
increased need for natural gas, electricity, and water for production. 

Current Federal Involvement: 

* There are currently no federal programs to develop the U.S. oil sands 
resource, although the Energy Policy Act of 2005 called for the 
establishment of a number of policies and actions to encourage the 
development of unconventional oils in the United States, including oil 
sands. 

* The Bureau of Land Management, which manages most of the federal 
lands where oil sands occur, maintains an oil sands leasing program. 

Heavy and Extra-Heavy Oils: 

Heavy and extra-heavy oils are dense, viscous oils that generally 
require advanced production technologies, such as EOR, and substantial 
processing to be converted into petroleum products. Heavy and extra- 
heavy oils differ in their viscosities and other physical properties, 
but advanced recovery techniques like EOR are required for both types 
of oil. Heavy and extra-heavy oil reserves occur in many regions around 
the world, with the Orinoco Oil Belt in Eastern Venezuela comprising 
almost 90 percent of the total extra-heavy oil in the world. In the 
United States, heavy oil reserves are primarily found in Alaska, 
California, and Wyoming, and some commercial heavy oil production is 
occurring domestically. 

Key Costs: 

* The cost of producing heavy and extra-heavy oil is greater than the 
cost of producing conventional oil, due to, among other things, higher 
drilling, refining, and transporting costs. 

Potential Production: 

* The 2005 Venezuelan extra-heavy oil production was estimated to be 
600,000 barrels of oil per day and is projected to at least sustain 
this production rate through 2030. 

* In 2004, production of heavy oil in California was 474,000 barrels 
per day. In December 2005, heavy oil production in Alaska was 42,500 
barrels per day, but some project Alaskan production to increase to 
100,000 barrels per day in 5 years. 

Readiness: 

* Extra-heavy oil production is in the commercial phase in Venezuela. 

* Heavy oil production technologies are currently commercially 
available and employed in the United States. 

Key Challenges: 

* Development of the heavy oil resource in the United States faces 
environmental, economic, technical, permitting, and access-to-skilled- 
labor challenges. 

Current Federal Involvement: 

* There has not been a specific DOE program focused on heavy oil, as 
most of the research and developments have been handled under the 
general research umbrella for EOR. 

* The Energy Policy Act of 2005 called for an update of the 1987 
technical and economic assessment of heavy oil resources in the United 
States. 

Oil Shale: 

Oil shale refers to sedimentary rock that contains solid bituminous 
materials that are released as petroleum-like liquids when the rock is 
heated. To obtain oil from oil shale, the shale must be heated and the 
resultant liquid must be captured, in a process referred to as 
"retorting." Oil shale can be produced by mining followed by surface 
retorting or by in-situ retorting. The largest known oil shale deposits 
in the world are in the Green River Formation, which covers portions of 
Colorado, Utah, and Wyoming. Estimates of the oil resource in place 
range from 1.5 trillion to 1.8 trillion barrels, but not all of the 
resource is recoverable. In addition to the Green River Formation, 
Australia and Morocco are believed to have oil shale resources. At the 
present time, a RAND study reported there are economic and technical 
concerns associated with the development of oil shale in the United 
States, such that there is uncertainty regarding whether industry will 
ultimately invest in commercial development of the resource. 

Key Costs: 

* On the basis of currently available information, oil shale cannot 
compete with conventional oil production. 

* At the present time, and given current technologies and information, 
Shell Oil reports that it may be able to produce oil shale for $25 to 
$30 per barrel. 

* Infrastructure costs for oil shale production include the following: 
additional electricity, water, and transportation needs. A RAND study 
expects a dedicated power plant for the production of oil shale to 
exceed $1 billion. 

Potential Production: 

* The Green River Basin is believed to have the potential to produce 3 
million to 5 million barrels per day for hundreds of years. 

* Given the current state of the technology and associated challenges, 
however, it is possible that 10 years from now, the oil shale resource 
could be producing 0.5 million to 1.0 million barrels per day. 

Readiness: 

* Oil shale is not presently in the research and development stage. 

* Shell Oil has the most advanced concept for oil shale, and it does 
not anticipate making a decision regarding whether to attempt 
commercialization until 2010. 

Key Challenges: 

* Examples of key challenges facing the development of oil shale 
include the following: (1) controlling and monitoring groundwater, (2) 
permitting and emissions concerns associated with new power generation 
facilities, (3) reducing overall operating costs, (4) water 
consumption, and (5) land disturbance and reclamation. 

Current Federal Involvement: 

* The Energy Policy Act of 2005 called for the establishment of a 
number of policies and actions to encourage the development of 
unconventional oils in the United States, including oil shale. 

[End of section] 

Appendix IV: Key Technologies to Displace Oil Consumption in the 
Transportation Sector: 

This appendix contains brief profiles of key technologies that could 
displace U.S. oil consumption in the transportation sector. These 
technologies include alternative fuels to supplement or substitute for 
gasoline as well as advanced vehicle technologies to increase fuel 
efficiency. For each technology, on the basis of information provided 
by federal experts, we provide a short description, followed by 
selected information on the costs, potential production or displacement 
of oil, readiness, key challenges, and current federal involvement. 
Although some of these technologies are in production or development 
throughout the world, the following profiles primarily focus on the 
development of these technologies in the United States. 

Ethanol: 

Ethanol is a grain alcohol-based, alternative fuel made by fermenting 
plant sugars. It can be made from many agricultural products and food 
wastes if they contain sugar, starch, or cellulose, which can then be 
fermented and distilled into ethanol. Pure ethanol is rarely used for 
transportation; instead, it is usually mixed with gasoline. The most 
popular blend for light-duty vehicles is E85, which is 85 percent 
ethanol and 15 percent gasoline. The technology for producing ethanol, 
at least from certain feedstocks, is generally well established, and 
ethanol is currently produced in many countries around the world. In 
Brazil, the world's largest producer, ethanol is produced from sugar 
cane. In the United States, more than 90 percent of ethanol is produced 
from corn, but efforts are under way to develop methods for producing 
ethanol from other biomass materials, including forest trimmings and 
agricultural residues (cellulosic ethanol). Currently, corn ethanol is 
primarily produced and used across the Midwest. 

Key Costs: 

* The current cost of producing ethanol from corn is between $0.90 to 
$1.25 per gallon, depending on the plant size, transportation cost for 
the corn, and the type of fuel used to provide steam and other energy 
needs for the plant. 

* The projected cost of producing ethanol from biomass is expected to 
drop significantly to about $1.07 per gallon by 2012. 

* The current cost of producing of ethanol from biomass is not cost 
competitive, but by 2012 it is projected to be about $1.07 per gallon. 

* Key infrastructure costs associated with ethanol include retrofitting 
refueling stations to accommodate E85 (estimated at between $30,000 and 
$100,000) and constructing or modifying pipelines to transport ethanol. 

Potential Production: 

* The 2005 production of ethanol in the United States was approximately 
4 billion gallons. By 2014-15, corn ethanol production is expected to 
peak at approximately 9 billion to 18 billion gallons annually. 

* Assuming success with cellulosic ethanol technologies, experts 
project cellulosic ethanol production levels of over 60 billion gallons 
by 2025-30. 

Readiness: 

* Corn ethanol is commercially produced today and continues to expand 
rapidly. 

* Cellulosic ethanol is in the demonstration phase, but it is projected 
to be demonstrated by 2010. 

Key Challenges: 

* For corn ethanol, key challenges include the necessary infrastructure 
changes to support ethanol distribution and the ability and willingness 
of consumers to adapt to ethanol. 

* For cellulosic ethanol, several technical challenges still remain, 
including improving the enzymatic pretreatment, fermentation, and 
process integration. 

* For cellulosic ethanol, economic challenges are high feedstock and 
production costs and the initial capital investment. 

Current Federal Involvement: 

* The federal government is currently involved in numerous efforts to 
develop ethanol. Several federal agencies collaborate with industry to 
accelerate the technologies, reduce the cost of the technologies, and 
assist in developing the infrastructure. 

Biodiesel: 

Biodiesel is a renewable fuel that has similar properties to petroleum 
diesel, but it can be produced from vegetable oils or animal fats. Like 
petroleum diesel, biodiesel operates in compression-ignition engines. 
Blends of up to 20 percent biodiesel (B20) can be used in nearly all 
diesel equipment and are compatible with most storage and distribution 
equipment. These low-level blends generally do not require any engine 
modifications. Higher blends and 100 percent biodiesel (B100) may be 
used in some engines with little or no modification, although 
transportation and storage of B100 requires special management. 
Biodiesel is currently produced and used as a transportation fuel 
around the world. In the United States, the biodiesel industry is small 
but growing rapidly, and refueling stations with biodiesel can be found 
across the country. 

Key Costs: 

* The current wholesale cost of pure biodiesel (B100) ranges from about 
$2.90 to $3.20 per gallon, although recent sales have been reported at 
$2.75 per gallon. 

* To date, there has been limited evaluation of the projected 
infrastructure costs required for biodiesel. However, it is 
acknowledged that there are infrastructure costs associated with 
installation of manufacturing capacity, distribution, and blending of 
the biodiesel. 

Potential Production: 

* In 2005, U.S. production of biodiesel was 75 million gallons, and DOE 
projects about 3.6 billion gallons per year by 2015. 

* Under a more speculative scenario requiring major changes in land use 
and price supports, experts project it would be possible to produce 10 
billion gallons of biodiesel per year. 

Readiness: 

* While biodiesel is commercially available, in many ways it is still 
in development and demonstration. Key areas of focus for development 
and demonstration include quality, warranty coverage, and impact of air 
pollutant emissions and compatibility with advanced control systems. 

* Experts project that, with adequate resources, key remaining 
developments could be resolved in the next 5 years. 

Key Challenges: 

* Initial capital costs are significant and the technical learning 
curve is steep, which deters many potential investors. 

* Economic challenges are significant for biodiesel. In the absence of 
the $1 per gallon excise tax, biodiesel would not likely be cost- 
competitive. 

Current Federal Involvement: 

* DOE is currently collaborating with the biodiesel and automobile 
industries in funding research and development efforts on biodiesel 
use, and USDA is conducting research on feedstocks. 

Coal and Biomass Gas-to-Liquids: 

Gas-to-liquid (GTL) alternatives include the production of liquid fuels 
from a variety of feedstocks, via the Fisher-Tropsch process. In the 
Fischer-Tropsch process, feedstocks such as coal and biomass are 
converted into a syngas, before the gas is converted into a diesel-like 
fuel. The diesel-like fuel is low in toxicity and is virtually 
interchangeable with conventional diesel fuels. Although these 
technologies have been available in some form since the 1920s, and coal 
GTL was used heavily by the German military during World War II, GTL 
technologies are not widely used today. Currently, there is no 
commercial production of biomass GTL and the only commercial production 
of coal GTL occurs in South Africa, where the Sasol Corporation 
currently produces 150,000 barrels of fuel from coal per day. Extensive 
research and development, however, is currently under way to further 
develop this technology because automakers consider GTL fuels viable 
alternatives to oil without compromising fuel efficiency or requiring 
major infrastructure changes. 

Key Costs: 

* Coal. Construction of a precommercial coal GTL plant is estimated at 
$1.7 billion, while construction of a commercial coal GTL is estimated 
at $3.5 billion. 

* Biomass. Potential costs associated with biomass GTL are uncertain, 
given the early stage of the technology. 

* Infrastructure costs associated with both biomass and coal GTLs are 
expected to be substantial, given the necessary modifications to 
pipelines, refueling centers, and storage facilities. 

Potential Production: 

* Coal. Experts project that, at most, 80,000 billion barrels per day 
could be produced by 2015 and 1.7 million barrels per day by 2030. 

* Biomass. Some experts project biomass GTL to have the potential to 
produce up to approximately 1.4 million barrels-of-oil-equivalent per 
day by 2030. 

Readiness: 

* Coal. Coal GTL is commercially available in South Africa, but the 
technology has not yet been commercially adopted in the United States. 

* Biomass. Biomass GTL is currently in research and development, 
nearing the demonstration stage. Experts project that biomass GTL 
production could be demonstrated at the pilot scale by 2012. 

Key Challenges: 

* Coal. Key challenges facing coal GTL include technology integration, 
for example integrating various processes with combined cycle turbine 
and CO2 capture operations, and market risk. 

* Biomass. The challenges are mostly technical in nature, for example, 
pretreatment of biomass feedstocks, identification of high-efficiency 
feedstocks, improving cleanliness of the syngas, and process 
integration. 

Current Federal Involvement: 

* Coal. DOE does not receive any direct funding for coal GTL, but 
funding for other programs indirectly supports and benefits some coal 
GTL research. 

* Biomass. DOE funds some biomass conversion research. 

Natural Gas: 

Natural gas is an alternative fuel that can be used as either heavy- 
duty compressed natural gas or liquefied natural gas to power natural 
gas vehicles. These vehicles require pressurized tanks, which have been 
designed to withstand severe impact, high external temperatures, and 
environmental exposure. Natural gas can be used by either retrofitting 
an existing gasoline or diesel engine or purchasing a natural gas 
vehicle. Natural gas vehicles are in use in many countries, totaling 
more than 5 million natural gas vehicles and over 9,000 refueling 
stations. The United States has about 130,000 natural gas vehicles and 
1,340 refueling stations. 

Key Costs: 

* Light-duty natural gas vehicles are estimated to cost an additional 
$1,000 per vehicle. 

* Heavy-duty natural gas vehicles are estimated to cost an additional 
$10,000 to $30,000 per vehicle. 

* Natural gas refueling stations are estimated to cost $100,000 to $1 
million to build, while home fueling appliances cost approximately 
$2,000 per year. 

Potential Production: 

* Currently, natural gas vehicles displace approximately 65 million 
gallons of diesel fuel per year. 

* There is a potential niche market in heavy-duty vehicles for natural 
gas, which could displace 1,500 million gallons of gasoline per year. 

Readiness: 

* Natural gas vehicles are commercially available now, but their 
overall use is limited on a national scale and production has been 
declining in recent years. 

* Heavy-duty natural gas vehicles are in the final stages of research 
and development. 

Key Challenges: 

* Examples of some key challenges facing the adoption of natural gas 
vehicles include the following: (1) the higher cost of high-pressure 
fuel tanks for consumers, (2) the costly upgrades to the existing 
refueling infrastructure, and (3) the availability and cost of natural 
gas. 

Current Federal Involvement: 

* There is currently no federal funding or research focusing on natural 
gas vehicles. 

Advanced Vehicle Technologies: 

Vehicle technologies encompass several different efforts to reduce 
vehicles' oil consumption. Increasing the efficiency of the internal 
combustion engine, specifically advanced diesel engines, is considered 
a first step toward other engine technologies. For example, researchers 
are working to improve the emissions profile of advanced diesel engines 
through techniques such as low-temperature combustion, which would 
enable the engine to burn more cleanly so that emissions control at the 
tailpipe is less burdensome. Another set of technologies are hybrid 
electric and plug-in hybrid electric vehicles. Hybrid vehicles use a 
battery alongside the internal combustion engine to facilitate the 
capture of braking energy as well as to provide propulsion, while plug- 
in hybrids use a different battery and can be powered by battery alone 
for an extended period. Researchers are examining how to build longer- 
lasting and less-expensive batteries for hybrid and plug-in hybrid 
vehicles. Finally, a range of ongoing work is attempting to improve the 
efficiency of conventional vehicles. For example, lightweight materials 
have the potential to improve efficiency by reducing vehicle weight. 
Oil consumption can also be cut by reducing the rolling resistance of 
tires, increasing the efficiency of transmission technologies that move 
the energy from the engine to the tires, and improving how power is 
managed within the vehicle. 

Key Costs: 

* Advanced diesel engines. DOE does not have information on the 
potential cost of this technology. Officials told us that this 
information is proprietary. 

* Hybrid electric and plug-in hybrid vehicles. DOE officials told us 
that these vehicles can cost several thousand dollars more than 
conventional vehicles, although some of the incremental cost in hybrid 
vehicles currently on the market may be related to additional 
amenities, rather than the hybrid technology. 

* Lightweight materials. DOE officials told us that lightweight carbon 
fiber materials currently cost approximately $12 to $15 per pound, and 
that their goal is to reduce this cost to $3 to $5 per pound. 
Information was not available on costs associated with other 
technologies to improve conventional vehicle efficiency. 

Potential Displacement of Oil: 

* DOE estimates that the oil savings that would result from its vehicle 
technology efforts, including research on internal combustion engines, 
hybrids, and other vehicle efficiency measures, is 20,000 barrels per 
day by 2010, up to 1.07 million barrels per day by 2025. 

* DOE was not able to estimate oil savings for plug-in hybrids for 
fiscal year 2007. 

Readiness: 

* Advanced diesel engines. Low-temperature combustion that would reduce 
the emissions burden of diesel engines is under research and 
development. 

* Hybrid electric and plug-in hybrid electric vehicles. Hybrid electric 
vehicles are currently on the market, although research continues on 
longer-lasting, less expensive batteries for both hybrid and plug-in 
hybrid electric vehicles. DOE's goal is to have plug-in hybrids 
commercially available by 2014, although officials considered this an 
aggressive goal. 

* Lightweight vehicle materials. Lightweight materials, such as 
aluminum, magnesium, and polymer composites, have made inroads into 
vehicle manufacturing. However, research and development are still 
under way on reducing the costs of these materials. By 2012, DOE aims 
to make the life-cycle costs of glass-and carbon-fiber-reinforced 
composites, along with several other lightweight materials, comparable 
to the costs for conventional steel. 

Key Challenges: 

* Advanced diesel engines. Reducing the emissions of nitrogen oxides 
and particulate matter to meet government requirements is a key 
challenge for the diesel engine combustion process. Emissions reduction 
will help make more efficient advanced diesel engines cost-competitive 
with gasoline engines because it will reduce the cost and energy 
consumption of tailpipe emissions treatment. 

* Hybrid electric and plug-in hybrid electric vehicles. Battery cost is 
one of the central challenges for hybrid electric and plug-in hybrid 
electric vehicles. DOE officials told us that their goal is to reduce 
the cost of a battery pack for a hybrid electric vehicle from 
approximately $920 today to $500 by 2010. Technological challenges 
include extending the life of the battery pack to last the life of the 
car, and improving power electronics in the vehicle. Researchers are 
using lithium-ion and lithium polymer chemistries in the next 
generation of batteries, instead of the current nickel metal hydride. 
Officials told us that plug-in hybrids face infrastructure challenges, 
such as the capacity of household electric wiring systems to recharge a 
plug-in, and the capacity of the electricity grid if plug-in hybrids 
are widely adopted. Battery lifetime and cost are also challenges for 
plug-in hybrids. 

* Lightweight vehicles. The cost of lightweight materials is the 
largest barrier to their widespread adoption. In addition, 
manufacturing capacity for lightweight materials occurs primarily in 
the aerospace industry and is not available for producing automotive 
components for lightweight materials. 

Current Federal Involvement: 

* Advanced diesel engines. DOE currently conducts research into 
combustion technology. For example, federal funds are supporting 
fundamental research to understand low-temperature combustion 
technology, and the industry is attempting to establish the operating 
parameters of an engine that facilitate low-temperature combustion. 

* Hybrid electric and plug-in hybrid electric vehicles. DOE's 
FreedomCAR program sponsors research that supports the development of 
hybrid vehicles, specifically with respect to improving the 
performance, and reducing the cost, of electric batteries. 

* Lightweight vehicles. DOE currently funds research and development on 
lightweight materials. 

Hydrogen Fuel Cell Vehicles: 

A hydrogen fuel cell vehicle is powered by the electricity produced 
from an electrochemical reaction between hydrogen from a hydrogen- 
containing fuel and oxygen from the air. A fuel cell power system has 
many components, the key one being the fuel cell "stack," which is many 
thin, flat cells layered together. Each cell produces energy and the 
output of all of the cells is used to power a vehicle. Currently, 
hydrogen fuel cell vehicles are still under development in the United 
States, and a number of challenges remain for them to become 
commercially viable. In the United States, government and industry are 
working on research and demonstration efforts, to facilitate the 
development and commercialization of hydrogen fuel cell vehicles. 

Key Costs: 

* Because hydrogen fuel cells are still in an early stage of 
development, the ultimate cost of hydrogen fuel cells is uncertain, but 
the goal is to make them competitive with gasoline-powered vehicles. 

* A fuel cell stack currently costs about $35,000, and a hydrogen fuel 
cell vehicle about $100,000. 

* An ongoing cost-share effort between the federal government and the 
industry is working toward price targets of $2 to $3 per gallon of 
gasoline equivalent for hydrogen at the refueling station. 

Potential Displacement of Oil: 

* Federal experts project that hydrogen fuel cell vehicles could have 
the potential to displace 0.28 million barrels per day by 2025. 

Readiness: 

* Hydrogen fuel cell vehicle technologies are still in research, 
development, and demonstration. 

* Federal experts project that the technology is not likely to be 
commercially viable before 2015. 

Key Challenges: 

* Key challenges facing the commercialization of hydrogen fuel cell 
vehicles include the following: (1) hydrogen storage; (2) cost and 
durability of the fuel cell; and (3) infrastructure costs for 
producing, distributing, and delivering hydrogen. 

Current Federal Involvement: 

* The federal government conducts research with industry to improve the 
feasibility of the technology and reduce the costs. 

* The government facilitates information-sharing among industry leaders 
by analyzing sensitive information on hydrogen fuel cell performance 
from leading automotive and oil companies. 

[End of section] 

Appendix V: Comments from the Department of Energy: 

Note: GAO comments supplementing those in the report text appear at the 
end of this appendix. 

Department of Energy: 
Washington, DC 20585: 

February 7, 2007: 

Mr. Mark Metcalfe: 
U.S. Government Accountability Office: 
301 Howard Street: 
Suite 1200: 
San Francisco, CA 94105: 

Dear Mr. Metcalfe: 

Attached are the Department of Energy's comments for GAO Draft (Job 
Code GAO-07-283) entitled Crude Oil: Uncertainty About Future Oil 
Supply Makes It Important To Develop a Strategy for Addressing a 
Potential Peak in Oil Production. 

If you have any questions, you may direct them to David Morehouse, at 
202-586-4853. 

Sincerely, 

Signed by: 

Guy F. Caraso: 
Administrator: 
Energy Information Administration: 

DOE Comments - GAO Draft Report (GAO-07-283) Crude Oil. Uncertainty 
About Future Oil Supply Makes It Important To Develop a Strategy for 
Addressing a Potential Peak in Oil Production: 

Substantive Comments: 

The Department of Energy (DOE) believes that the Government 
Accountability Office (GAO) has done a reasonable job of describing the 
present wide range of estimates of the time when world oil production 
might peak, as well as in identifying and generally describing many of 
the significant uncertainties that underlie these estimates' variance. 
DOE also believes GAO's recommendation that the Federal Government 
establish a coordinated strategy to deal with a potential peak in oil 
production is a reasonable one. 

In conjunction with other measures, DOE believes it would be useful if 
the Federal Government, in partnership with allied consuming countries 
or at least the members of the International Energy Agency, invested 
substantially more resources in estimating exactly what oil is likely 
to be produced and what depletion rates are likely to be over a future 
period of perhaps 5 to 7 years. While not foolproof, a strategy that 
combines more complete and higher quality geologic, technological, and 
oil field performance information with more robust supply and demand 
modeling offers the best opportunity to reduce uncertainties. 

This report is focused on "a potential peak in oil production." It does 
not, however, definitively state whether the potential peak being 
addressed involves only the peaking of conventional crude oil 
production or instead involves the peaking of conventional plus 
unconventional crude oil production. While the latter seems to be the 
case given the discussion of extra-heavy oils, tar sands, and oil shale 
in the report, this should be clearly stated at the outset. 

There are at least two ways in which the report's use of technical 
terminology may confuse many readers. First, on page 7 the report 
defines extra-heavy oil as unconventional oil, and defines heavy oil as 
conventional oil (albeit implicitly, by omission), but thereafter 
repeatedly confuses the two. Numerous specific corrections for this 
problem are suggested in the technical comments below. 

Second, the report interchanges the terms "world demand for petroleum 
products," "world oil consumption," and "oil demand" as though they 
were equivalents, which they are not. For example, on page 1 beginning 
at line 5 this is done within the space of three consecutive sentences. 
In the first of these, the cited 84 million barrels of petroleum 
products includes ethanol which is not "oil," but a substitute 
therefore. The clearest way to refer to consumption of petroleum 
products and their liquid substitutes is as "liquids consumption." A 
further explanation could indicate that liquids consumption includes 
products derived from conventional oils, biofuels, coal-to-liquids, 
natural gas-to-liquids.refinery volumetric gains, upgraded bitumen, and 
extra-heavy oils. 

The report would also benefit from a clearer distinction between the 
related but distinct concepts of demand and consumption. Demand is 
defined either as the willingness and ability to purchase a commodity 
or service, or as the quantity of a commodity or service wanted at a 
specified price and time. Consumption, on the other hand, is the 
utilization of economic goods in the satisfaction of wants or in the 
process of production resulting chiefly in their destruction, 
deterioration, or transformation. It can easily be argued that crude 
oil is demanded and consumed at the refinery, whereas petroleum 
products and their substitutes are demanded and consumed downstream 
from the refinery or plant. For purely physical reasons, the total 
quantities of crude oil demanded, supplied, and consumed are less than 
the total quantities of petroleum liquids demanded, supplied, and 
consumed, and the latter are, for reasons of substitution or 
augmentation, less than the total quantities of hydrocarbon liquids 
demanded, supplied, and consumed. Wherever "demand" or "consumption" 
appears in the text it should be checked to ensure that the correct 
term (and concept) has been used. 

Enhanced oil recovery (EOR) technologies do not necessarily raise 
environmental concerns irrespective of whether their objective is the 
production of heavy oil, extra-heavy oil, or bitumen (from a tar sand 
deposit.) 'For example, the environmental community typically prefers 
use of FOR in existing fields to exploration in frontier areas. To the 
extent that carbon dioxide injection FOR operations (CO2 EOR) can be 
expanded using man-made C02, some analyses have shown that more C02 can 
be sequestered in the producing reservoirs than results from use of the 
produced oil --a net environmental improvement. Also, if the process 
heat for a thermal FOR project is derived from nuclear fission rather 
than combustion of a fossil fuel, there are no greenhouse gas 
emissions. On page 18, in the top paragraph, DOE recommends deletion of 
the last 2 sentences. Similarly on page 20, in the top paragraph, DOE 
recommends deletion of the last sentence. 

GAO's discussion of alternative fuel and transportation technologies is 
mostly limited to those used to power autonomous vehicles. Other 
alternatives ranging from vehicles that draw power from guideways to 
the substitution of remote sensing and telecommuting for the 
requirement to travel are not mentioned. While there is some 
information along these lines in the Appendices, a broader list of 
alternatives must ultimately be considered. 

The following are GAO's comments on the Department of Energy's letter 
dated February 7, 2007. 

GAO Comments: 

1. We agree that we have not defined a peak as either a peak in 
conventional or total oil--conventional plus nonconventional. In the 
course of our study, we found that experts conducting the timing of 
peak oil studies also do not agree on a single peak concept. Different 
studies by these experts use different estimates for oil remaining and, 
as a result, implicitly have different concepts of a peak--a 
conventional versus a total oil peak. We have added language to the 
report to clarify this point. The lack of agreement on a peak concept 
mirrors the disagreement about the very definition of conventional oil 
versus nonconventional oil. The distinction regarding what portion of 
heavy oil is conventional is debated by experts. For example, USGS 
would consider the heavy oil produced in California as conventional 
oil, while IEA would not--the latter considers all heavy (and extra- 
heavy) oil to be nonconventional. For the purposes of this report, we 
have adopted IEA's definition of nonconventional oil, which includes 
all heavy oil. 

2. We agree that the use of heavy and extra-heavy oil may be confusing 
in sections of this report, and we have implemented some of the 
suggestions that DOE provided in their technical comments. 

3. With regard to the inclusion of some ethanol in petroleum 
consumption as reported on page 1 of the report, we asked EIA staff to 
identify how much of such nonpetroleum liquids are in the figure. They 
told us that just under one-third of 1 percent of the world petroleum 
consumption data they report is comprised of ethanol, and we noted this 
in a footnote on page 1 of the report. We decided to continue to call 
it petroleum consumption, rather than "liquids consumption" as 
suggested by DOE because the former is what EIA calls it and because 
the nonpetroleum component is so small. 

4. We agree that our language regarding the use of oil consumption and 
oil demand is confusing in some sections of the report. Overall, the 
report makes the point that, all other things equal, the faster the 
world consumes oil, the sooner we will use up the oil and reach a peak. 
The report also makes the point that future demand for oil, which 
depends on many factors, including world economic growth, will 
determine just how fast we consume oil. We have made some changes to 
the text to clarify when we are talking about consumption of oil and 
when we are talking about the demand for oil. 

5. We do not disagree that the environmental costs of EOR are lower 
than for some of the other technologies examined, and we did not try to 
rank the environmental costs of all the alternatives we examined. 
However, we believe that these costs are relevant for assessing the 
potential impacts of producing more of our oil using such technologies. 
Therefore, we left that discussion in the report but added language 
attributing DOE's views on this. 

6. We agree with DOE's assessment that there is a broader range of 
transportation technologies besides those used to power autonomous 
vehicles. We chose to focus on the technologies that experts currently 
believe have the most potential for reducing oil consumption in the 
light-duty vehicle sector, which accounts for 60 percent of the 
transportation sector's consumption of petroleum-based energy. We 
encourage DOE and other agencies to consider the full range of oil- 
displacing technologies as they implement our recommendations to 
develop a strategy to reduce uncertainty about the timing of a peak in 
oil production and advise Congress on cost-effective ways to mitigate 
the consequences of such a peak. 

[End of section] 

Appendix VI: Comments from the Department of the Interior: 

Note: GAO comments supplementing those in the report text appear at the 
end of this appendix. 

United States Department Of The Interior: 
Office Of The Assistant Secretary: 
Policy, Management And Budget: 
Washington, D.C. 20240: 

Mr. James E. Wells Jr. 
Director, Natural Resources and Environment: 
U.S. Government Accountability Office: 
441 G St., N.W. 
Washington, D.C. 20548: 

Dear Mr. Wells: 

Thank you for the opportunity to comment on the draft report GAO 07-28 
"Crude Oil, Uncertainty About Future Oil Supply Makes It Important to 
Develop a Strategy for Addressing a Potential Peak in Oil Production." 

Please find enclosed technical comments prepared by Bureaus within the 
U.S. Department of the Interior. We hope you find these comments useful 
as you finalize the report. 

Sincerely, 

Signed by: 

R. Thomas Weimer: 
Assistant Secretary: 

Enclosure: 

United States Department of the Interior: 
US. Geological Survey: 
Reston, Virginia 20192: 

In Reply Refer To: Mail Stop 105 #2007146-DO: 

Feb 14 2007: 

Memorandum: 

To: Assistant Secretary - Policy, Management, and Budget: 

Through: Mark Limbaugh: 
Assistant Secretary - Water and Science

From: Mark Myers: 
Director, US. Geological Survey: 

Subject: Comments on the Government Accountability Office (GAO) draft 
report entitled, "Crude Oil: Uncertainty About Future Oil Supply Makes 
It Important to Develop a Strategy for Addressing a Potential Peak in 
Oil Production" (Report Number GAO-07-283). . 

Thank you for providing the U. S. Geological Survey (USGS) the 
opportunity to review the US. Government Accountability Office (GAO) 
draft report entitled, "Crude Oil: Uncertainty About Future Oil Supply 
Makes It Important to Develop a Strategy for Addressing a Potential 
Peak in Oil Production" (Report Number GAO-07-283). 

The report recognizes the importance of increased coordination among 
agencies, but we express concern over the recommendation the "DOE ... 
establish a strategy to coordinate and prioritize federal agency 
efforts to reduce uncertainty..." We would like to emphasize, as the 
report does, that the U.S. Geological Survey (USGS)/DOI has a major 
role in global oil resource estimates and a different mission than DOE. 
The two agencies are complementary and therefore any prioritization of 
Federal agency efforts should be made jointly, not just by DOE, as the 
recommendation reads on the cover of the draft report. 

The document fairly portrays the USGS and its role in providing 
unbiased science for others to make policy, decisions, forecasts, etc. 
However, there are a few instances in the document where it is implied 
that the USGS said it could take additional steps to mitigate the 
consequences of a peak (for example, last paragraph on page 40). This 
sentence directly follows a list of what the USGS has proposed it could 
do to improve or expand our global resource estimates, which will 
reduce the uncertainty surrounding estimates of global oil resources. 
It needs to be made clear that the USGS cannot take steps to "mitigate 
the consequences of a peak." That is neither the purview nor 
responsibility of the USGS. The USGS provides information about 
undiscovered resources, research into continuous, unconventional, 
nonconventional resources, etc. to better characterize the global 
petroleum endowment, in order that others can make policy and perhaps 
take steps to mitigate the peak. 

We hope our comments will assist the GAO in preparing the final report. 

The following are GAO's comments on the Department of the Interior's 
letter dated February 14, 2007. 

GAO Comments: 

1. We agree that DOE and Interior will both play a vital role in 
implementing our recommendation. We have made the appropriate wording 
change to the Highlights page of the report to clarify that our 
recommendation is that DOE work in conjunction with other key agencies 
to establish a strategy to coordinate and prioritize federal agency 
efforts to reduce the uncertainty surrounding the timing of a peak and 
to advise Congress on how best to mitigate consequences. 

2. We agree that mitigating the consequences of a peak is outside the 
purview of Interior. The examples cited highlight the areas where 
Interior can help reduce the uncertainty surrounding the estimates of 
global resources. We have changed the wording accordingly to make this 
distinction clear. 

[End of section] 

Appendix VII: GAO Contact and Staff Acknowledgments: 

GAO Contact: 

Jim Wells, (202) 512-3841: 

Staff Acknowledgments: 

In addition to the contact person named above, Mark Gaffigan, Acting 
Director; Frank Rusco, Assistant Director; Godwin Agbara; Vipin Arora; 
Virginia Chanley; Mark Metcalfe; Cynthia Norris; Diahanna Post; Rebecca 
Sandulli; Carol H. Shulman; Barbara Timmerman; and Margit Willems- 
Whitaker made key contributions to this report. 

(360601): 

FOOTNOTES 

[1] This number comes from EIA's Monthly Energy Review (December 2006), 
table 11.2. EIA labels this table as petroleum consumption, but DOE 
pointed out in its comments that the consumption data include some 
ethanol, which is not a petroleum product. EIA staff told us that the 
ethanol in the 2005 figure amounts to 265,000 barrels per day, 
amounting to just under one-third of 1 percent of world consumption. 

[2] This projection comes from EIA's International Energy Outlook 2006 
and reflects assumptions used in EIA's reference case scenario. To 
assess uncertainties in the reference case projections, EIA also runs 
low and high oil price scenarios, in which the projected world oil 
consumption in 2030 is 102 million and 128 million barrels per day, 
respectively. 

[3] Robert L. Hirsch, Roger Bezdek, and Robert Wendling, Peaking of 
World Oil Production: Impacts, Mitigation, and Risk Management 
(February 2005). 

[4] The European Commission also participates in the work of IEA. 

[5] The distinction as to what portion of heavy oil is conventional is 
debated by experts. For example, contrary to the IEA definition, USGS 
considers the heavy oil produced in California as conventional oil. 

[6] Saudi Arabia and Russia, respectively, lead in world oil 
production. 

[7] According to the Transportation Energy Data Book, light vehicles 
include cars; light trucks (two-axle, four-tire trucks); and 
motorcycles. 

[8] Oil consumption also depends on other factors; therefore, it is 
sometimes difficult to isolate the changes in consumption caused by 
changes in oil prices. For example, gasoline consumption generally 
increases as incomes rise and people choose to drive more. In addition, 
higher incomes mean that oil plays a smaller role in a consumer's 
budget, and, therefore, higher-income consumers may be less sensitive 
to changes in oil prices than lower-income consumers. 

[9] One key difference between the studies is in how much oil they 
assume is still in the ground. Some studies consider a peak in 
conventional oil, while other studies consider a peak in total oil, 
including conventional and nonconventional oils. Because of these 
differences in the peak concept used in the various studies, we have 
not attempted to define a peak as either a peak in conventional oil or 
conventional plus nonconventional oils. Instead, we have focused on 
identifying key factors that cause uncertainty in the timing of the 
peak. These factors would cause such uncertainty regardless of whether 
the peak concept focused on conventional or total oil. 

[10] Proven reserves are classified as oil in the ground that is likely 
to be economically producible at expected oil prices and given expected 
technologies. Conventional reserves are often classified according to 
the degree of certainty that they exist and can be extracted 
profitably. Even this classification is fraught with uncertainty 
because there are no harmonized rules about the assumptions to be used 
when determining this profitability. 

[11] As previously discussed in this report, there is no universally 
agreed-upon definition of conventional oil. The Oil and Gas Journal 
includes Canadian oil sands in its estimates. IEA classifies oil sands 
as nonconventional, and, therefore, since we are using the IEA 
classification throughout this report, we have removed the Oil and Gas 
Journal estimate of 174 billion barrels of oil from the Canadian oil 
sands data. USGS experts emphasized the importance of these oil sands 
in future oil production and stated that in their view, these resources 
are now considered to be conventional. 

[12] OPEC's members are Algeria, Indonesia, Iran, Iraq, Kuwait, Libya, 
Nigeria, Qatar, Saudi Arabia, the United Arab Emirates, and Venezuela. 
Beginning with January 2007 data, new OPEC member Angola would also be 
included in OPEC reserves estimates. 

[13] USGS defines conventional oil accumulation based primarily on 
geology. The time horizon for these data is 30 years. This definition 
does not incorporate economic or political factors, such as deepwater, 
remoteness, harsh climate, regulatory status, or engineering 
techniques. Not included in this USGS definition are oil sands and oil 
shale. Interior's Minerals Management Service oversees oil production 
on federal lands offshore. Officials from the Minerals Management 
Service stated in comments on a draft of this report that, with regard 
to some offshore areas, resource estimates are based on data that are 
20 to 25 years old. They also pointed out that resource estimates can 
change dramatically with improvements to technology and information. 

[14] T.R. Klett, Donald L. Gautier, and Thomas S. Ahlbrandt, "An 
Evaluation of the U.S. Geological Survey World Petroleum Assessment 
2000," American Association of Petroleum Geologists Bulletin. Vol. 89, 
no.8 (August 2005). 

[15] Thomas S. Ahlbrandt, Ronald R. Charpentier, T.R. Klett, James W. 
Schmoker, Christopher J. Schenk, and Gregory F. Ulmishek, Global 
Resource Estimates from Total Petroleum Systems (The American 
Association of Petroleum Geologists: Tulsa, Oklahoma, 2005). 

[16] The political risk measure comes from Global Insight's Global Risk 
Service. Global Insight is a worldwide consulting firm headquartered in 
Massachusetts. The Global Risk Service political risk score is a 
summary of probabilities that different political events, such as civil 
war, will reduce GDP growth rates. The subjective probabilities are 
assessed by country analysts at Global Insight, on the basis of a wide 
range of information, and are reviewed by a team to ensure consistency 
across countries. The measures are revised quarterly; the measure we 
used comes from the second quarter of 2006. 

[17] Because we examined a forecast of risk factors, it would have been 
ideal to have a forecast of what oil reserves are likely to be in each 
country for the next 5 years, including reserve growth and potential 
future discoveries. However, such reserve predictions are not publicly 
available, and, therefore, we used published country-level data on 
proven reserves from the Oil and Gas Journal. Consistent with our 
previous presentation of proven reserves, the information we present 
here does not include Canadian oil sands data. 

[18] GAO, Oil and Gas Development: Increased Permitting Activity Has 
Lessened BLM's Ability to Meet Its Environmental Protection 
Responsibilities, GAO-05-418 (Washington, D.C.: June 17, 2005). 

[19] According to IEA, infrastructure investment in exploration and 
production would need to total about $2.25 trillion from 2004 through 
2030. This investment will be needed to expand supply capacity and to 
replace existing and future supply facilities that will be closed 
during the projection period. 

[20] National Commission on Energy Policy, Ending the Energy Stalemate: 
A Bipartisan Strategy to Meet America's Energy Challenges (December 
2004), available at www.energycommission.org. 

[21] GAO, Energy Security: Issues Related to Potential Reductions in 
Venezuelan Oil Production, GAO-06-668 (Washington, D.C.: June 27, 
2006). 

[22] OECD is a group of 30 member countries sharing a commitment to 
democratic government and a market economy. 

[23] John H. Wood, Gary R. Long, and David F. Morehouse, Long Term 
World Oil Supply Scenarios: The Future Is Neither as Bleak or Rosy as 
Some Assert, Energy Information Administration, U.S. Department of 
Energy (2004). 

[24] David L. Greene, Janet L. Hopson, and Jai Li, Running Out Of and 
Into Oil: Analyzing Global Oil Depletion and Transition Through 2050, 
Oak Ridge National Laboratory, Department of Energy (2003); and Robert 
L. Hirsch, Roger Bezdek, and Robert Wendling, Peaking of World Oil 
Production: Impacts, Mitigation, and Risk Management, Science 
Applications International Corporation and Management Information 
Services Inc. (February 2005). 

[25] John H. Wood, Gary R. Long, and David F. Morehouse, Long Term 
World Oil Supply Scenarios: The Future Is Neither as Bleak or Rosy as 
Some Assert, Energy Information Administration, U.S. Department of 
Energy (2004). 

[26] Donald F. Fournier and Eileen T. Westervelt, Energy Trends and 
Their Implications for U.S. Army Installations, U.S. Army Corps of 
Engineers, Engineer Research and Development Center, ERDC/CERL TR-05-21 
(September 2005). 

[27] Experts we spoke with noted that it is important that the 
government not choose one viable alternative technology to the 
exclusion of another technology. 

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