Crude Oil
Uncertainty about Future Oil Supply Makes It Important to Develop a Strategy for Addressing a Peak and Decline in Oil Production Gao ID: GAO-07-283 February 28, 2007The 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.
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.
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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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