Crude Oil: Uncertainty about Future Oil Supply Makes It Important
to Develop a Strategy for Addressing a Peak and Decline in Oil
Production (28-FEB-07, GAO-07-283).
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.
-------------------------Indexing Terms-------------------------
REPORTNUM: GAO-07-283
ACCNO: A66349
TITLE: Crude Oil: Uncertainty about Future Oil Supply Makes It
Important to Develop a Strategy for Addressing a Peak and Decline
in Oil Production
DATE: 02/28/2007
SUBJECT: Alternative energy sources
Crude oil
Energy consumption
Energy costs
Energy demand
Energy policy
Energy research
Fuel consumption
Fuel research
Gasoline
Oil importing
Petroleum exploration
Petroleum products
Prices and pricing
Projections
Transportation planning
Transportation policies
Supply and demand
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GAO-07-283
* [1]Results in Brief
* [2]Background
* [3]Oil Production Has Peaked in the United States and Most Othe
* [4]Oil Is Critical in Satisfying the U.S. and World Demand for
* [5]Relationship of Supply and Demand of Oil to Oil Price
* [6]Timing of Peak Oil Production Depends on Uncertain Factors
* [7]Studies Predict Widely Different Dates for Peak Oil
* [8]Amount of Oil in the Ground Is Uncertain
* [9]Uncertainty Remains about How Much Oil Can Be Produced from
* [10]Oil Sands
* [11]Heavy and Extra-Heavy Oils
* [12]Oil Shale
* [13]Political and Investment Risk Factors Create Uncertainty abo
* [14]Political Conditions Create Uncertainties about Oil
Explorat
* [15]Investment Climate Creates Uncertainty about Oil
Exploration
* [16]Future World Demand for Oil Is Uncertain
* [17]Factors That Create Uncertainty about the Timing of the Peak
* [18]Alternative Transportation Technologies Face Challenges in M
* [19]Development and Adoption of Technologies to Displace Oil Wil
* [20]Ethanol
* [21]Biodiesel
* [22]Biomass Gas-to-Liquid
* [23]Coal Gas-to-Liquid
* [24]Natural Gas and Natural Gas Vehicles
* [25]Advanced Vehicle Technologies
* [26]Hydrogen Fuel Cell Vehicles
* [27]Consequences Could Be Severe If Alternative Technologies Are
* [28]Federal Agencies Do Not Have a Coordinated Strategy to Addre
* [29]Federal Agencies Have Many Programs and Activities Related t
* [30]Agencies Have Options to Reduce Uncertainty and Mitigate Con
* [31]Conclusions
* [32]Recommendation for Executive Action
* [33]Agency Comments and Our Evaluation
* [34]Enhanced Oil Recovery
* [35]Key Costs
* [36]Potential Production
* [37]Readiness
* [38]Key Challenges
* [39]Current Federal Involvement
* [40]Deepwater and Ultra-Deepwater Drilling
* [41]Key Costs
* [42]Potential Production
* [43]Readiness
* [44]Key Challenges
* [45]Current Federal Involvement
* [46]Oil Sands
* [47]Key Costs
* [48]Potential Production
* [49]Readiness
* [50]Key Challenges
* [51]Current Federal Involvement
* [52]Heavy and Extra-Heavy Oils
* [53]Key Costs
* [54]Potential Production
* [55]Readiness
* [56]Key Challenges
* [57]Current Federal Involvement
* [58]Oil Shale
* [59]Key Costs
* [60]Potential Production
* [61]Readiness
* [62]Key Challenges
* [63]Current Federal Involvement
* [64]Ethanol
* [65]Key Costs
* [66]Potential Production
* [67]Readiness
* [68]Key Challenges
* [69]Current Federal Involvement
* [70]Biodiesel
* [71]Key Costs
* [72]Potential Production
* [73]Readiness
* [74]Key Challenges
* [75]Coal and Biomass Gas-to-Liquids
* [76]Key Costs
* [77]Potential Production
* [78]Readiness
* [79]Key Challenges
* [80]Current Federal Involvement
* [81]Natural Gas
* [82]Key Costs
* [83]Potential Production
* [84]Readiness
* [85]Key Challenges
* [86]Current Federal Involvement
* [87]Advanced Vehicle Technologies
* [88]Key Costs
* [89]Potential Displacement of Oil
* [90]Readiness
* [91]Key Challenges
* [92]Current Federal Involvement
* [93]Hydrogen Fuel Cell Vehicles
* [94]Key Costs
* [95]Potential Displacement of Oil
* [96]Readiness
* [97]Key Challenges
* [98]Current Federal Involvement
* [99]GAO Comments
* [100]GAO Comments
* [101]GAO Contact
* [102]Staff Acknowledgments
* [103]GAO's Mission
* [104]Obtaining Copies of GAO Reports and Testimony
* [105]Order by Mail or Phone
* [106]To Report Fraud, Waste, and Abuse in Federal Programs
* [107]Congressional Relations
* [108]Public Affairs
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
Contents
Letter 1
Results in Brief 4
Background 6
Timing of Peak Oil Production Depends on Uncertain Factors 12
Alternative Transportation Technologies Face Challenges in Mitigating the
Consequences of the Peak and Decline 29
Federal Agencies Do Not Have a Coordinated Strategy to Address Peak Oil
Issues 35
Conclusions 38
Recommendation for Executive Action 39
Agency Comments and Our Evaluation 40
Appendix I Scope and Methodology 43
Appendix II Key Peak Oil Studies 47
Appendix III Key Technologies to Enhance the Supply of Oil 49
Enhanced Oil Recovery 49
Deepwater and Ultra-Deepwater Drilling 50
Oil Sands 52
Heavy and Extra-Heavy Oils 53
Oil Shale 54
Appendix IV Key Technologies to Displace Oil Consumption in the
Transportation Sector 57
Ethanol 57
Biodiesel 58
Coal and Biomass Gas-to-Liquids 60
Natural Gas 61
Advanced Vehicle Technologies 63
Hydrogen Fuel Cell Vehicles 65
Appendix V Comments from the Department of Energy 67
GAO Comments 70
Appendix VI Comments from the Department of the Interior 72
GAO Comments 75
Appendix VII GAO Contact and Staff Acknowledgments 76
Figures
Figure 1: U.S. Oil Production, 1900-2005 8
Figure 2: World Crude Oil and Other Liquids Production, 1965-2005 9
Figure 3: Annual U.S. Oil Consumption, by Sector, 1974-2005 10
Figure 4: Real and Nominal Oil Prices, 1950-2006 11
Figure 5: Key Estimates of the Timing of Peak Oil 13
Figure 6: World Oil Reserves, OPEC and non-OPEC, 2006 16
Figure 7: Worldwide Proven Oil Reserves, by Political Risk 22
Figure 8: Worldwide Proven Oil Reserves, by Investment Risk 24
Figure 9: Top 10 Companies on the Basis of Oil Production and Reserves
Holdings, 2004 25
Figure 10: World Oil Production, by OPEC and Non-OPEC Countries, 2004
Projected to 2030 26
Figure 11: Daily World Oil Consumption, by Region for 2003 and Projected
for 2030 27
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
This is a work of the U.S. government and is not subject to copyright
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separately.
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
2005.1 EIA also projects that world oil consumption will continue to grow
and will reach 118 million barrels per day in 2030.2 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?
1This 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.
2This 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.
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.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.4
3Robert L. Hirsch, Roger Bezdek, and Robert Wendling, Peaking of World Oil
Production: Impacts, Mitigation, and Risk Management (February 2005).
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.
4The European Commission also participates in the work of IEA.
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:
o 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.
o 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.
o 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.
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.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,6 U.S. oil production peaked around 1970 and
has been on a declining trend ever since. (See fig. 1.)
5The 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.
6Saudi Arabia and Russia, respectively, lead in world oil production.
Figure 1: U.S. Oil Production, 1900-2005
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
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.
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,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
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.
7According to the Transportation Energy Data Book, light vehicles include
cars; light trucks (two-axle, four-tire trucks); and motorcycles.
Figure 4: Real and Nominal Oil Prices, 1950-2006
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.
All else being equal, oil consumption is inversely correlated with oil
price, with higher oil prices inducing consumers to reduce their oil
consumption.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.
8Oil 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.
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.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.
9One 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.
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
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."
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 reserves10 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,11 about 80 percent are
located in the OPEC countries,12 compared with about 2 percent in the
United States. Figure 6 shows this estimate in more detail.
10Proven 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.
11As 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.
12OPEC'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.
Figure 6: World Oil Reserves, OPEC and non-OPEC, 2006
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.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.
13USGS 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.
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 2003.14 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.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.
14T.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).
15Thomas 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).
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,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.)17
16The 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.
Figure 7: Worldwide Proven Oil Reserves, by Political Risk
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.
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.18
Environmental restrictions may affect a peak in oil production by barring
oil exploration and production in environmentally sensitive areas.
17Because 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.
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,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 2002.20 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.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.
18GAO, Oil and Gas Development: Increased Permitting Activity Has Lessened
BLM's Ability to Meet Its Environmental Protection Responsibilities,
[109]GAO-05-418 (Washington, D.C.: June 17, 2005).
19According 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.
20National Commission on Energy Policy, Ending the Energy Stalemate: A
Bipartisan Strategy to Meet America's Energy Challenges (December 2004),
available at www.energycommission.org.
21GAO, Energy Security: Issues Related to Potential Reductions in
Venezuelan Oil Production, [110]GAO-06-668 (Washington, D.C.: June 27,
2006).
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
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.
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
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.
aLukoil is the only company in the top 10 based on reserves that is not
100 percent state-sponsored.
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
Note: This projection excludes production from nonconventional oil
sources, such as Canadian oil sands.
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,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
Future world oil demand will depend on such uncertain factors as world
economic growth, future government policy, and consumer choices.
Specifically:
o 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.
o 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.
o 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.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:
o DOE has sponsored two studies.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."
o 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.25
o In its 2005 study of energy use in the military,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:
o Add information on certain regions--which USGS refers to as
"frontier regions"--where little is known about oil resources.
o 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.
o 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.
o 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.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:
o 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.
o 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.
22OECD is a group of 30 member countries sharing a commitment to
democratic government and a market economy.
23John 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).
24David 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).
25John 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).
26Donald 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).
27Experts we spoke with noted that it is important that the government not
choose one viable alternative technology to the exclusion of another
technology.
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 [email protected]. Contact points for our
Offices of Congressional Relations and Public Affairs may be found
on the last page of this report. GAO staff who made contributions
to this report are listed in appendix VII.
Jim Wells
Director, Natural Resources and Environment
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:
o Stephen Brown, Director of Energy Economics and Microeconomic
Policy Analysis, Federal Reserve Bank of Dallas
o David Greene, Corporate Fellow, Oak Ridge National Laboratory
o Howard Gruenspecht, Deputy Administrator, Energy Information
Administration
o James Hamilton, Professor of Economics, University of
California, San Diego
o Robert Hirsch, Senior Energy Program Advisor, SAIC
o Hillard G. Huntington, Executive Director Energy Modeling Forum,
Stanford University
o James Katzer, Visiting Scholar, Massachusetts Institute of
Technology (MIT), and Manager (retired), Strategic Planning and
Performance Analysis, ExxonMobil Research and Engineering Company
o Robert Kaufmann, Professor, Center for Energy & Environmental
Studies, Boston University
o Paul Leiby, Oak Ridge National Laboratory
o Nicola Pochettino, Senior Energy Analyst, Economic Analysis
Division, International Energy Agency
o Edward Porter, Research Manager, American Petroleum Institute
o James Smith, Maguire Chair of Oil and Gas Management, Edwin L.
Cox School of Business, Southern Methodist University
o James Sweeney, Professor, Management Science and Engineering,
Stanford University
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) Ministere de l'Economie Des Finances et de l'Industrie.
L'industrie petroliere en 2004. 2005.
(k) International Energy Agency. World Energy Outlook 2004. Paris
France: 101-103.
(l) Jean Laherrere. 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.
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
o 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.
o 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
o EOR currently contributes approximately 12 percent to the U.S.
production of oil.
o EOR is projected to increase average recovery rates in
reservoirs from 30 percent to 50 percent.
o 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
o Thermal, gas, and chemical injection technologies are currently
commercially available.
o Key areas for further development exist, including sweep
efficiency and water shut-off methods.
Key Challenges
o 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
o 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
o 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.
o The average market rate for Gulf of Mexico rigs can range from
$210,000 per day to $300,000 per day.
o Overall, the projected marginal costs of deepwater drilling
range from 3.0 to 4.5 times the cost of shallow water drilling.
Potential Production
o Current deepwater production in the Gulf of Mexico is estimated
at 1.3 million barrels per day.
o Deepwater production in the Gulf of Mexico is projected to
exceed 2 million barrels per day in the next 10 years.
Readiness
o Commercial deepwater drilling at depths of more than 1,000 feet
in the Gulf of Mexico has been under way since the mid-1970s.
o 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
o 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
o DOE is not directly involved in deepwater and ultra-deepwater
drilling, but it does fund projects that could impact such
drilling.
o 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
o Commercial Canadian oil sands are being produced at $18 to $22
per barrel.
o 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
o 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.
o 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
o Production of Canadian oil sands is currently in the commercial
phase.
o 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
o 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
o 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.
o 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
o 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
o 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.
o 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
o Extra-heavy oil production is in the commercial phase in
Venezuela.
o Heavy oil production technologies are currently commercially
available and employed in the United States.
Key Challenges
o Development of the heavy oil resource in the United States faces
environmental, economic, technical, permitting, and
access-to-skilled-labor challenges.
Current Federal Involvement
o 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.
o 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
o On the basis of currently available information, oil shale
cannot compete with conventional oil production.
o 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.
o 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
o The Green River Basin is believed to have the potential to
produce 3 million to 5 million barrels per day for hundreds of
years.
o 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
o Oil shale is not presently in the research and development
stage.
o 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
o 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
o 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.
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
o 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.
o The projected cost of producing ethanol from biomass is expected
to drop significantly to about $1.07 per gallon by 2012.
o 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.
o 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
o 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.
o Assuming success with cellulosic ethanol technologies, experts
project cellulosic ethanol production levels of over 60 billion
gallons by 2025-30.
Readiness
o Corn ethanol is commercially produced today and continues to
expand rapidly.
o Cellulosic ethanol is in the demonstration phase, but it is
projected to be demonstrated by 2010.
Key Challenges
o 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.
o For cellulosic ethanol, several technical challenges still
remain, including improving the enzymatic pretreatment,
fermentation, and process integration.
o For cellulosic ethanol, economic challenges are high feedstock
and production costs and the initial capital investment.
Current Federal Involvement
o 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
o 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.
o 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
o In 2005, U.S. production of biodiesel was 75 million gallons,
and DOE projects about 3.6 billion gallons per year by 2015.
o 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
o 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.
o Experts project that, with adequate resources, key remaining
developments could be resolved in the next 5 years.
Key Challenges
o Initial capital costs are significant and the technical learning
curve is steep, which deters many potential investors.
o 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
o 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
o 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.
o Biomass. Potential costs associated with biomass GTL are
uncertain, given the early stage of the technology.
o 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
o Coal. Experts project that, at most, 80,000 barrels per day
could be produced by 2015 and 1.7 million barrels per day by 2030.
o 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
o Coal. Coal GTL is commercially available in South Africa, but
the technology has not yet been commercially adopted in the United
States.
o 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
o 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.
o 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
o Coal. DOE does not receive any direct funding for coal GTL, but
funding for other programs indirectly supports and benefits some
coal GTL research.
o 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
o Light-duty natural gas vehicles are estimated to cost an
additional $1,000 per vehicle.
o Heavy-duty natural gas vehicles are estimated to cost an
additional $10,000 to $30,000 per vehicle.
o 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
o Currently, natural gas vehicles displace approximately 65
million gallons of diesel fuel per year.
o 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
o 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.
o Heavy-duty natural gas vehicles are in the final stages of
research and development.
Key Challenges
o 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
o 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
o Advanced diesel engines. DOE does not have information on the
potential cost of this technology. Officials told us that this
information is proprietary.
o 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.
o 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
o 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.
o DOE was not able to estimate oil savings for plug-in hybrids for
fiscal year 2007.
Readiness
o Advanced diesel engines. Low-temperature combustion that would
reduce the emissions burden of diesel engines is under research
and development.
o 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.
o 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
o 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.
o 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.
o 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
o 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.
o 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.
o 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
o 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.
o A fuel cell stack currently costs about $35,000, and a hydrogen
fuel cell vehicle about $100,000.
o 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
o Federal experts project that hydrogen fuel cell vehicles could
have the potential to displace 0.28 million barrels per day by
2025.
Readiness
o Hydrogen fuel cell vehicle technologies are still in research,
development, and demonstration.
o Federal experts project that the technology is not likely to be
commercially viable before 2015.
Key Challenges
o 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
o The federal government conducts research with industry to
improve the feasibility of the technology and reduce the costs.
o The government facilitates information-sharing among industry
leaders by analyzing sensitive information on hydrogen fuel cell
performance from leading automotive and oil companies.
Appendix V: Comments from the Department of Energy
Note: GAO comments supplementing those in the report text appear at the
end of this appendix.
See comment 3.
See comment 2.
See comment 1.
See comment 6.
See comment 5.
See comment 4.
GAO Comments
The following are GAO's comments on the Department of Energy's
letter dated February 7, 2007.
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.
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.
See comment 2.
See comment 1.
GAO Comments
The following are GAO's comments on the Department of the
Interior's letter dated February 14, 2007.
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.
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.
GAO�s Mission
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Highlights of [119]GAO-07-283 , a report to congressional requesters
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
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.
[120]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.
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.
References
Visible links
109. http://www.gao.gov/cgi-bin/getrpt?GAO-05-418
110. http://www.gao.gov/cgi-bin/getrpt?GAO-06-668
119. http://www.gao.gov/cgi-bin/getrpt?GAO-07-283
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