Crude Oil: Uncertainty about Future Oil Supply Makes It Important to Develop a Strategy for Addressing a Peak and Decline in Oil Production
Published: 2007-02-28T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: 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.
section_title: What GAO Found
paragraphs: 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.

section_title: Letter
paragraphs: 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. EIA also projects that world oil  consumption will continue to grow and will reach 118 million barrels per  day in 2030. About 43 percent of this growth in oil consumption will come  from the non-Organization for Economic Co-operation and Development  Asian countries, including China and India, but the United States will  remain the world’s largest oil consumer. In 2005, the United States  accounted for just under 25 percent of world oil consumption. World oil  production has been running at near capacity in recent years to meet  rising consumption, putting upward pressure on oil prices. The potential  for disruptions in key oil-producing regions of the world, such as the  Middle East, and the yearly threat of hurricanes in the Gulf of Mexico have  also exerted upward pressure on oil prices. These conditions have  renewed interest in a long-standing question: Will oil supply continue to  expand to meet growing demand, or will we soon reach a maximum  possible level of production—a peak—beyond which oil supply can only  decline?
Historically, U.S. oil production peaked around 1970 at close to 10 million  barrels per day and has been generally declining ever since, to about 5  million barrels per day in 2005. While recent discoveries raise the prospect  of some increases in U.S. oil production, significant reductions in world oil  production could still have important consequences for the nation’s  welfare. The United States imported about 66 percent of its oil and  petroleum products in 2005, and the U.S. economy—particularly the  transportation sector—depends heavily on oil. Overall, transportation  accounts for approximately 65 percent of U.S. oil consumption. New  technologies have been introduced that displace some oil consumption  within the sector, but oil consumption for transportation has continued to  increase in recent years. According to a 2005 report prepared for DOE,  without timely preparation, a reduction in world oil production could  cause transportation fuel shortages that would translate into significant  economic hardship.
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.
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.
subsections: section_title: Background
paragraphs: 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. 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.
subsections: section_title: Oil Production Has Peaked in the United States and Most Other Countries Outside the Middle East
paragraphs: 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, U.S. oil production  peaked around 1970 and has been on a declining trend ever since. (See  fig. 1.)
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.)
section_title: Oil Is Critical in Satisfying the U.S. and World Demand for Energy
paragraphs: 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, 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.
section_title: Relationship of Supply and Demand of Oil to Oil Price
paragraphs: 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.
All else being equal, oil consumption is inversely correlated with oil price,  with higher oil prices inducing consumers to reduce their oil  consumption. Specifically, increases in crude oil prices are reflected in  the prices of products made from crude oil, including gasoline, diesel,  home heating oil, and petrochemicals. The extent to which consumers are  willing and able to reduce their consumption of oil in response to price  increases depends on the cost of switching to activities and lifestyles that  use less oil. Because there are more options available in the longer term,  consumers respond more to changes in oil prices in the longer term than  in the shorter term. For example, in the short term, consumers can reduce  oil consumption by driving less or more slowly, but in the longer term,  consumers can still take those actions, but can also buy more fuel-efficient  automobiles or even move closer to where they work and thereby further  reduce their oil consumption.
Supply and demand, in turn, affect the type of oil that is produced.  Conventional oil that is less expensive to extract using lower-cost drilling  techniques will be produced when oil prices are lower. Conversely, oil that  is expensive to produce because of the higher cost technologies involved  may not be economical to produce at low oil prices. Producers are  unlikely to turn to these more expensive oil sources unless oil prices are  sustained at a high enough level to make such an enterprise profitable.  Given the importance of oil in the world’s energy portfolio, as cheaper oil  reserves are exhausted in the future, nations will need to make the  transition to more and more expensive and difficult-to-access sources of  oil to meet energy demands. Recently, for example, a large discovery of oil  in the Gulf of Mexico made headlines; however, this potential wealth of oil  is located at a depth of over 5 miles below sea level, a fact that adds  significantly to the costs of extracting that oil.
section_title: Timing of Peak Oil Production Depends on Uncertain Factors
paragraphs: 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. 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.
subsections: section_title: Studies Predict Widely Different Dates for Peak Oil
paragraphs: 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.
section_title: Amount of Oil in the Ground Is Uncertain
paragraphs: Studies that predict the timing of a peak use different estimates of how  much oil remains in the ground, and these differences explain some of the  wide ranges of these predictions. Estimates of how much oil remains in  the ground are highly uncertain because much of these data are self- reported and unverified by independent auditors; many parts of the world  have yet to be fully explored for oil; and there is no comprehensive  assessment of oil reserves from nonconventional sources. This uncertainty  surrounding estimates of oil resources in the ground comprises the  uncertainty surrounding estimates of proven reserves 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, about 80 percent are  located in the OPEC countries, compared with about 2 percent in the  United States. Figure 6 shows this estimate in more detail.
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. Estimates of reserves growth  and those resources that have the potential to be added to oil reserves are  important in determining when oil production may peak. However,  estimating these potential future reserves is complicated by the fact that  many regions of the world have not been fully explored and, as a result,  there is limited information. For example, in its 2000 assessment, USGS  provides a mean estimate of 732 billion barrels that have the potential to  be added as newly discovered conventional oil, with as much as 25 percent  from the Arctic—including Greenland, Northern Canada, and the Russian  portion of the Barents Sea. However, relatively little exploration has been  done in this region, and there are large portions of the world where the  potential for oil production exists, but where exploration has not been  done. According to USGS, there is less uncertainty in regions where wells  have been drilled, but even in the United States, one of the areas that has  seen the greatest exploration, some areas have not been fully explored, as  illustrated by the recent discovery of a potentially large oil field in the Gulf  of Mexico.
Limited information on oil-producing regions worldwide also leads USGS  to base its estimate of reserves growth on how reserves estimates have  grown in the United States. However, some experts criticize this  methodology; they believe such an estimate may be too high because the  U.S. experience overestimates increases in future worldwide reserves. In  contrast, EIA believes the USGS estimate may be too low. In 2005, USGS  released a study showing that its prediction of reserves growth has been in  line with the world’s experience from 1996 to 2003. 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.
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.
section_title: Uncertainty Remains about How Much Oil Can Be Produced from Proven Reserves, Hard-to-Reach Locations, and Nonconventional Sources
paragraphs: 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.
subsections: section_title: Oil Sands
paragraphs: 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.
section_title: Heavy and Extra-Heavy Oils
paragraphs: 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.
section_title: Oil Shale
paragraphs: 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.
section_title: Political and Investment Risk Factors Create Uncertainty about the Future Rate of Oil Exploration and Production
paragraphs: 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.
subsections: section_title: Political Conditions Create Uncertainties about Oil Exploration and Production
paragraphs: 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, 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.)
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.  Environmental restrictions may affect a peak in oil production by barring  oil exploration and production in environmentally sensitive areas.
section_title: Investment Climate Creates Uncertainty about Oil Exploration and Production
paragraphs: Foreign investment in the oil sector could be necessary to bring oil to the  world market, 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. 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. Industry officials  told us that lack of technical expertise could lead to less sophisticated  drilling techniques that actually reduce the ability to recover oil in more  complex reservoirs. For example, according to industry officials, some  Russian wells have difficulties with high water cut—that is, a high ratio of  water to oil—making oil difficult to get out of the ground at current prices.  This water cut problem stems from not using technically advanced  methods when the wells were initially drilled. We have previously reported  that the Venezuelan national oil company, PDVSA, lost technical expertise  when it fired thousands of employees following a strike in 2002 and 2003.  In contrast, other national oil companies, such as Saudi Aramco, are  widely perceived to possess considerable technical expertise.
According to our analysis, 85 percent of the world’s proven oil reserves are  in countries with medium-to-high investment risk or where foreign  investment is prohibited, on the basis of Oil and Gas Journal estimates of  oil reserves. (See fig. 8.) For example, over one-third of the world’s proven  oil reserves lie in only five countries—China, Iran, Iraq, Nigeria, and  Venezuela—all of which have a high likelihood of seeing a worsening  investment climate. Three countries with large oil reserves—Saudi Arabia,  Kuwait, and Mexico—prohibit foreign investment in the oil sector, and  most major oil-producing countries have some type of restrictions on  foreign investment. Furthermore, some countries that previously allowed  foreign investment, such as Russia and Venezuela, appear to be reasserting  state control over the oil sector, according to DOE.
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.
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.
section_title: Future World Demand for Oil Is Uncertain
paragraphs: 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, which includes the United States, and non-OECD Asia,  which includes China and India, are the major drivers of this growth.
Future world oil demand will depend on such uncertain factors as world  economic growth, future government policy, and consumer choices.  Specifically:    Economic growth drives demand for oil. For example, according to IEA, in  2003 the world experienced strong growth in oil consumption of 2.0  percent, with even stronger growth of 3.6 percent in 2004, from 79.8  million barrels per day to 82.6 million barrels per day and China accounted  for 30 percent of this increase, driven largely by China’s almost 10 percent  economic growth that year. EIA projects the Chinese economy will  continue to grow, but factors such as the speed of reform of ineffective  state-owned companies and the development of capital markets adds  uncertainty to such projections and, as a result, to the level of future oil  demand in China.
Future government policy can also affect oil demand. For example,  environmental concerns about gasoline’s emissions of carbon dioxide,  which is a greenhouse gas, may encourage future reductions in oil demand  if these concerns are translated into policies that promote biofuels.
Consumer choices about conservation also can affect oil demand and  thereby influence the timing of a peak. For example, if U.S. consumers  were to purchase more fuel-efficient vehicles in greater numbers, this  could reduce future oil demand in the United States, potentially delaying a  time at which oil supply is unable to keep pace with oil demand.
Such uncertainties that lead to changes in future oil demand ultimately  make estimates of the timing of a peak uncertain, as is illustrated in an EIA  study on peak oil. 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.
section_title: Factors That Create Uncertainty about the Timing of the Peak Also Create Uncertainty about the Rate of Decline
paragraphs: 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.
section_title: Alternative Transportation Technologies Face Challenges in Mitigating the Consequences of the Peak and Decline
paragraphs: 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.
subsections: section_title: Development and Adoption of Technologies to Displace Oil Will Take Time and Effort
paragraphs: 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.
subsections: section_title: Ethanol
paragraphs: 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.
section_title: Biodiesel
paragraphs: 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.
section_title: Biomass Gas-to-Liquid
paragraphs: 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.
section_title: Coal Gas-to-Liquid
paragraphs: 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.
section_title: Natural Gas and Natural Gas Vehicles
paragraphs: 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.
section_title: Advanced Vehicle Technologies
paragraphs: 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.
section_title: Hydrogen Fuel Cell Vehicles
paragraphs: 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.
section_title: Consequences Could Be Severe If Alternative Technologies Are Not Available
paragraphs: 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.
section_title: Federal Agencies Do Not Have a Coordinated Strategy to Address Peak Oil Issues
paragraphs: 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.
subsections: section_title: Federal Agencies Have Many Programs and Activities Related to Peak Oil Issues, but Peak Oil Generally Is Not the Main Focus of These Efforts
paragraphs: 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.
section_title: Agencies Have Options to Reduce Uncertainty and Mitigate Consequences but Lack a Coordinated Strategy
paragraphs: Several federally sponsored studies we reviewed reflect a growing concern  about peak oil and identify a need for action. For example:    DOE has sponsored two studies. A 2003 study highlighted the benefit of  reducing the uncertainty surrounding the timing of a peak to mitigate its  potentially severe global economic consequences. A 2005 study examined  mitigating the consequences of a peak and concluded the following:  “Timely, aggressive mitigation initiatives addressing both the supply and  the demand sides of the issue will be required.”
While EIA’s 2004 study of the timing of peak oil estimates that a peak  might occur closer to 2050, EIA recognized that early preparation was  important because of the long period required for widespread commercial  production and adoption of new energy technologies.
In its 2005 study of energy use in the military, the U.S. Army Corps of  Engineers emphasized the need to develop alternative technologies and  associated infrastructure before a peak and decline in oil production.
In addition, in response to growing peak oil concerns, DOE asked the  National Petroleum Council to study peak oil issues. The study is expected  to be completed by June 2007.
In light of these concerns, agency officials told us that it would be  worthwhile to take additional steps to reduce the uncertainty about the  timing of a peak in oil production. EIA believes it could reduce uncertainty  surrounding the timing of peak oil production if it were to robustly extend  the time horizon of its analysis and projection of global supply and  demand for crude oil presented in its domestic and international energy  outlooks. Currently, EIA’s projections extend only to 2030, and officials  believe that consideration of peak oil would require a longer horizon. Also,  the international outlook is fairly limited, in part because EIA no longer  conducts its detailed Foreign Energy Supply Assessment Program. EIA is  seeking to restart this effort in fiscal year 2007. In addition, USGS officials  told us that better and more complete information about global oil  resources could be used to improve estimates by EIA of the timing of a  peak. USGS officials said their estimates of global oil resources could be  improved or expanded in the following four ways:    Add information on certain regions—which USGS refers to as “frontier  regions”—where little is known about oil resources.
Add information on nonconventional resources outside the United States.
USGS believes these resources will play a large role in future oil supply,  and, therefore, accurate estimates of these resources should be included in  any attempts to determine the timing of a peak.
Calculate reserves growth by country. USGS considers this information  important because of the political and investment conditions that differ by  country and will affect future oil production and exploration.
Provide more complete information for all major oil-producing countries.
USGS noted that its assessment has some “holes” where resources in  major-producing countries have not yet been estimated completely.
In addition to these actions reducing the uncertainty about the timing of a  peak, agency officials also told us that they could take additional steps to  mitigate the consequences of a peak. For example, DOE officials reported  that they could expand their efforts to encourage the development of  alternative fuels and advanced vehicle technologies. These efforts could  be expanded by conducting more demonstrations of new technologies,  facilitating greater information sharing among key industry players, and  increasing cost share opportunities with industry for research and  development. 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.
section_title: Conclusions
paragraphs: 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.
section_title: Recommendation for Executive Action
paragraphs: While uncertainty about the timing of peak oil production is inevitable,  reducing that uncertainty could help energy users and suppliers, as well as  government policymakers, to act in ways that would mitigate the  potentially adverse consequences. Therefore, we recommend that the  Secretary of Energy take the lead, in coordination with other relevant  agencies, to prioritize federal agency efforts and establish a strategy for  addressing peak oil issues. At a minimum, such a strategy should seek to  do the following:    Monitor global supply and demand of oil with the intent of reducing  uncertainty surrounding estimates of the timing of peak oil production.  This effort should include improving the information available to estimate  the amount of oil, conventional and nonconventional, remaining in the  world as well as the future production and consumption of this oil, while  extending the time horizon of the government’s projections and analysis.
Assess alternative technologies in light of predictions about the timing of  peak oil production and periodically advise Congress on likely cost- effective areas where the government could assist the private sector with  development and adoption of such technologies.
section_title: Agency Comments and Our Evaluation
paragraphs: We provided the Departments of Energy and the Interior with a draft of  this report for their review and comment.
DOE generally agreed with our message and recommendations and made  several clarifying and technical comments, which we addressed in the  body of the report as appropriate. Appendix V contains a reproduction of  DOE’s letter and our detailed response to their comments. Specifically,  DOE commented that the draft report did not make a distinction between  a peak in conventional versus a peak in total (conventional and  nonconventional) oil. We agree that we have not made this distinction, in  part because the numerous studies of peak oil that we reviewed did not  always make such a distinction. Furthermore, we do not believe a clear  distinction between these two peak concepts is possible, in part because  the definition of what is conventional oil versus nonconventional oil is not  universally agreed on. However, the information we have reported  regarding uncertainty about the timing of a peak applies to either peak oil  concept.
DOE also commented that our use of certain technical phrases, including  the distinction between heavy and extra-heavy oils and the distinction  between oil consumption and demand, may be confusing to some readers,  and we have made changes to the text to avoid such confusion. DOE  commented that the draft report wrongly attributed environmental  concerns to the use of enhanced oil recovery techniques, stating that the  environmental community prefers such techniques on existing oil fields to  exploration and development of new fields. We do not disagree that the  environmental costs of these techniques may be smaller than for other  activities and we have added text to express DOE’s views on this matter.  However, our point in listing the cost and environmental challenges of  enhanced oil recovery techniques is that increasing oil production in the  future could be more costly and more environmentally damaging than  production of conventional oil, using primary production methods. For  this reason we disagree with DOE’s comment that we should remove the  references to environmental challenges.
Finally, DOE pointed out that the draft report was primarily focused on  transportation technologies that are used to power autonomous vehicles,  and they stated that a broader set of technologies that could displace oil  should be considered. We agree with their characterization of the draft  report. We chose transportation technologies because transportation  accounts for such a large part of U.S. oil consumption and because DOE  and other agencies have numerous programs and activities dealing with  technologies to displace oil in the transportation sector. We also agree that  a broader set of technologies should be considered in the long run as  potential ways to mitigate the consequences of a peak in oil production.  We encourage DOE and other agencies to fully explore the options to  displace oil as they implement our recommendations to develop a strategy  to reduce the uncertainty surrounding the timing of a peak in oil  production and advise Congress on cost-effective ways to mitigate the  consequences.
Interior generally agreed with our message and recommendations in the  draft report and made clarifying and technical comments, which we  addressed in the body of the report as appropriate. Appendix VI contains a  reproduction of Interior’s letter and our detailed response to its  comments. Specifically, Interior emphasized that it has a major role to play  in estimating global oil resources, and that this effort should be made in  conjunction with the efforts of DOE. We agree and encourage DOE to  work in conjunction with Interior and other key agencies in establishing a  strategy to coordinate and prioritize federal agency efforts to reduce the  uncertainty surrounding the timing of a peak and to advise Congress on  how best to mitigate consequences. Interior also commented that  mitigating the consequences of a peak is outside their purview. We agree,  and, in this report, we focus on examples of work that Interior could  undertake to assist in reducing the uncertainty surrounding the estimates  of global oil resources.
As agreed with your offices, unless you publicly announce the contents of  this report earlier, we plan no further distribution of it until 30 days from  the report date. At that time, we will send copies of this report to  interested congressional committees, other Members of Congress, the  Secretaries of Energy and the Interior, and other interested parties. We  also will make copies available to others upon request. In addition, the  report will be available at no charge on the GAO Web site at  http://www.gao.gov.
Should you or your staffs need further information, please contact me at  202-512-3841 or wellsj@gao.gov. Contact points for our Offices of  Congressional Relations and Public Affairs may be found on the last page  of this report. GAO staff who made contributions to this report are listed  in appendix VII.
section_title: Appendix I: Scope and Methodology
paragraphs: 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.
section_title: Appendix II: Key Peak Oil Studies
paragraphs: This appendix lists the studies cited in figure 5 of this report.  (a) L.F. Ivanhoe. “ Updated Hubbert Curves Analyze World Oil Supply.”  World Oil. Vol. 217 (November 1996): 91-94.  (b) Albert A. Bartlett. “ An Analysis of U.S. and World Oil Production  Patterns Using Hubbert-Style Curves.” Mathematical Geology. Vol. 32, no.1  (2000).  (c) Kenneth S. Deffeyes. “ World’s Oil Production Peak Reckoned in Near  Future.” Oil and Gas Journal. November 11, 2002.  (d) Volvo. Future Fuels for Commercial Vehicles. 2005.  (e) A.M. Samsam Bakhtiari. “ World Oil Production Capacity Model  Suggests Output Peak by 2006-2007.” Oil and Gas Journal. April 26, 2004.  (f) Richard C. Duncan. “ Peak Oil Production and the Road to the Olduvai  Gorge.” Pardee Keynote Symposia. Geological Society of America,  Summit 2000.  (g) David L. Greene, Janet L. Hopson, and Jai Li. Running Out Of and  Into Oil: Analyzing Global Oil Depletion and Transition Through 2050.  Oak Ridge National Laboratory, Department of Energy, October 2003.  (h) C.J. Campbell. “ Industry Urged to Watch for Regular Oil Production  Peaks, Depletion Signals.” Oil and Gas Journal. July 14, 2003.  (i) Merril Lynch. Oil Supply Analysis. October 2005.  (j) Ministére de l’Economie Des Finances et de l’Industrie. L’industrie  pétrolière en 2004. 2005.  (k) International Energy Agency. World Energy Outlook 2004. Paris  France: 101-103.  (l) Jean Laherrère. Future Oil Supplies. Seminar Center of Energy  Conversion, Zurich: 2003.  (m) Peter Gerling, Hilmar Remple, Ulrich Schwartz-Schampera, and  Thomas Thielemann. Reserves, Resources and Availability of Energy  Resources. Federal Institute for Geosciences and Natural Resources,  Hanover, Germany: 2004.  (n) John D. Edwards. “ Crude Oil and Alternative Energy Production  Forecasts for the Twenty-First Century: The End of the Hydrocarbon Era.”  American Association of Petroleum Geologists Bulletin. Vol. 81, no. 8  (August 1997).  (o) Cambridge Energy Research Associates, Inc. Worldwide Liquids  Capacity Outlook to 2010, Tight Supply or Excess of Riches. May 2005.  (p) John H. Wood, Gary R. Long and David F. Morehouse. Long Term  World Oil Supply Scenarios. Energy Information Administration: 2004.  (q) Total. Sharing Our Energies: Corporate Social Responsibility Report  2004.  (r) Shell International. Energy Needs, Choices and Possibilities:  Scenarios to 2050. Global Business Environment: 2001.  (s) Directorate-General for Research Energy. World Energy, Technology  and Climate Policy Outlook: WETO 2030. European Commission, EUR  20366: 2003.  (t) Exxon Mobil. The Outlook for Energy: A View to 2030. Corporate  Planning. Washington, D.C.: November 2005.  (u) Harry W. Parker. “ Demand, Supply Will Determine When World Oil  Output Peaks.” Oil and Gas Journal. February 25, 2002.  (v) M.A. Adelman and Michael C. Lynch. “ Fixed View of Resource Limits  Creates Undue Pessimism.” Oil and Gas Journal. April 7, 1997.
section_title: Appendix III: Key Technologies to Enhance the Supply of Oil
paragraphs: 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.
subsections: section_title: Enhanced Oil Recovery
paragraphs: 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 (CO)), 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 CO 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.
Costs associated with EOR production vary by reservoir, but reported  marginal costs for oil recovery using EOR can range from $1.42 per barrel  to $30 per barrel.
Key capital costs include new drills, reworking of existing drills,  reconfiguring gathering systems, and modification of the injection plant  and other surface facilities.
EOR currently contributes approximately 12 percent to the U.S.  production of oil.
EOR is projected to increase average recovery rates in reservoirs from 30  percent to 50 percent.
Upper-end estimates of EOR’s future recovery potential in the United  States include the following: 1.0 million barrels per day by 2015 and 2.5  million barrels per day by 2025.
Thermal, gas, and chemical injection technologies are currently  commercially available.
Key areas for further development exist, including sweep efficiency and  water shut-off methods.
Key challenges 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.
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.
section_title: Deepwater and Ultra- Deepwater Drilling
paragraphs: 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.
Costs vary by rig type, but the three key components of cost for deepwater  and ultra-deepwater drilling include the following: (1) the daily vessel  rental rate, (2) materials, and (3) drilling services.
The average market rate for Gulf of Mexico rigs can range from $210,000  per day to $300,000 per day.
Overall, the projected marginal costs of deepwater drilling range from 3.0  to 4.5 times the cost of shallow water drilling.
Current deepwater production in the Gulf of Mexico is estimated at 1.3  million barrels per day.
Deepwater production in the Gulf of Mexico is projected to exceed 2  million barrels per day in the next 10 years.
Commercial deepwater drilling at depths of more than 1,000 feet in the  Gulf of Mexico has been under way since the mid-1970s.
Companies are currently exploring prospects for drilling in depths of more  than 5,000 feet, and since 2001, 11 discoveries of ultra-deepwater wells at  depths of more than 7,000 feet have been announced.
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.
DOE is not directly involved in deepwater and ultra-deepwater drilling, but  it does fund projects that could impact such drilling.
The Energy Policy Act of 2005 authorized some funding for research and  development of alternative oil and gas activities, including deepwater  drilling.
section_title: Oil Sands
paragraphs: 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.
Commercial Canadian oil sands are being produced at $18 to $22 per  barrel.
Key infrastructure costs to support oil sands production in the United  States would include construction of roads, pipelines, water, and energy  production facilities.
The 2005 production of Canadian oil sands yielded 1.6 million barrels of oil  per day and production is projected to grow to as much as 3.5 million  barrels per day by 2030.
Current U.S. production of oil sands currently yields less than 175,000  barrels per year, and future production of U.S. oil sands will depend on the  industry’s investment decisions.
Production of Canadian oil sands is currently in the commercial phase.
U.S. oil sands production is only in the demonstration phase, and adapting  Canadian technologies to the characteristics of U.S. oil sands will require  time.
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.
There are currently no federal programs to develop the U.S. oil sands  resource, although the Energy Policy Act of 2005 called for the  establishment of a number of policies and actions to encourage the  development of unconventional oils in the United States, including oil  sands.
The Bureau of Land Management, which manages most of the federal  lands where oil sands occur, maintains an oil sands leasing program.
section_title: Heavy and Extra- Heavy Oils
paragraphs: 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.
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.
The 2005 Venezuelan extra-heavy oil production was estimated to be  600,000 barrels of oil per day and is projected to at least sustain this  production rate through 2030.
In 2004, production of heavy oil in California was 474,000 barrels per day.  In December 2005, heavy oil production in Alaska was 42,500 barrels per  day, but some project Alaskan production to increase to 100,000 barrels  per day in 5 years.
Extra-heavy oil production is in the commercial phase in Venezuela.
Heavy oil production technologies are currently commercially available  and employed in the United States.
Development of the heavy oil resource in the United States faces  environmental, economic, technical, permitting, and access-to-skilled- labor challenges.
There has not been a specific DOE program focused on heavy oil, as most  of the research and developments have been handled under the general  research umbrella for EOR.
The Energy Policy Act of 2005 called for an update of the 1987 technical  and economic assessment of heavy oil resources in the United States.
section_title: Oil Shale
paragraphs: 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.
On the basis of currently available information, oil shale cannot compete  with conventional oil production.
At the present time, and given current technologies and information, Shell  Oil reports that it may be able to produce oil shale for $25 to $30 per  barrel.
Infrastructure costs for oil shale production include the following:  additional electricity, water, and transportation needs. A RAND study  expects a dedicated power plant for the production of oil shale to exceed  $1 billion.
The Green River Basin is believed to have the potential to produce 3  million to 5 million barrels per day for hundreds of years.
Given the current state of the technology and associated challenges,  however, it is possible that 10 years from now, the oil shale resource could  be producing 0.5 million to 1.0 million barrels per day.
Oil shale is not presently in the research and development stage.
Shell Oil has the most advanced concept for oil shale, and it does not  anticipate making a decision regarding whether to attempt  commercialization until 2010.
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.
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.
section_title: Appendix IV: Key Technologies to Displace Oil Consumption in the Transportation Sector
paragraphs: 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.
subsections: section_title: Ethanol
paragraphs: 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.
The current cost of producing ethanol from corn is between $0.90 to $1.25  per gallon, depending on the plant size, transportation cost for the corn,  and the type of fuel used to provide steam and other energy needs for the  plant.
The projected cost of producing ethanol from biomass is expected to drop  significantly to about $1.07 per gallon by 2012.
The current cost of producing of ethanol from biomass is not cost  competitive, but by 2012 it is projected to be about $1.07 per gallon.
Key infrastructure costs associated with ethanol include retrofitting  refueling stations to accommodate E85 (estimated at between $30,000 and  $100,000) and constructing or modifying pipelines to transport ethanol.
The 2005 production of ethanol in the United States was approximately 4  billion gallons. By 2014-15, corn ethanol production is expected to peak at  approximately 9 billion to 18 billion gallons annually.
Assuming success with cellulosic ethanol technologies, experts project  cellulosic ethanol production levels of over 60 billion gallons by 2025-30.
Corn ethanol is commercially produced today and continues to expand  rapidly.
Cellulosic ethanol is in the demonstration phase, but it is projected to be  demonstrated by 2010.
For corn ethanol, key challenges include the necessary infrastructure  changes to support ethanol distribution and the ability and willingness of  consumers to adapt to ethanol.
For cellulosic ethanol, several technical challenges still remain, including  improving the enzymatic pretreatment, fermentation, and process  integration.
For cellulosic ethanol, economic challenges are high feedstock and  production costs and the initial capital investment.
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.
section_title: Biodiesel
paragraphs: 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.
The current wholesale cost of pure biodiesel (B100) ranges from about  $2.90 to $3.20 per gallon, although recent sales have been reported at $2.75  per gallon.
To date, there has been limited evaluation of the projected infrastructure  costs required for biodiesel. However, it is acknowledged that there are  infrastructure costs associated with installation of manufacturing capacity,  distribution, and blending of the biodiesel.
In 2005, U.S. production of biodiesel was 75 million gallons, and DOE  projects about 3.6 billion gallons per year by 2015.
Under a more speculative scenario requiring major changes in land use  and price supports, experts project it would be possible to produce 10  billion gallons of biodiesel per year.
While biodiesel is commercially available, in many ways it is still in  development and demonstration. Key areas of focus for development and  demonstration include quality, warranty coverage, and impact of air  pollutant emissions and compatibility with advanced control systems.
Experts project that, with adequate resources, key remaining  developments could be resolved in the next 5 years.
Initial capital costs are significant and the technical learning curve is  steep, which deters many potential investors.
Economic challenges are significant for biodiesel. In the absence of the $1  per gallon excise tax, biodiesel would not likely be cost-competitive.
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.
section_title: Coal and Biomass Gas-to-Liquids
paragraphs: 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.
Coal. Construction of a precommercial coal GTL plant is estimated at $1.7  billion, while construction of a commercial coal GTL is estimated at $3.5  billion.
Biomass. Potential costs associated with biomass GTL are uncertain,  given the early stage of the technology.
Infrastructure costs associated with both biomass and coal GTLs are  expected to be substantial, given the necessary modifications to pipelines,  refueling centers, and storage facilities.
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.
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.
Coal. Coal GTL is commercially available in South Africa, but the  technology has not yet been commercially adopted in the United States.
Biomass. Biomass GTL is currently in research and development, nearing  the demonstration stage. Experts project that biomass GTL production  could be demonstrated at the pilot scale by 2012.
Coal. Key challenges facing coal GTL include technology integration, for  example integrating various processes with combined cycle turbine and  CO  Light-duty natural gas vehicles are estimated to cost an additional $1,000  per vehicle.
Heavy-duty natural gas vehicles are estimated to cost an additional $10,000  to $30,000 per vehicle.
Natural gas refueling stations are estimated to cost $100,000 to $1 million  to build, while home fueling appliances cost approximately $2,000 per  year.
Currently, natural gas vehicles displace approximately 65 million gallons  of diesel fuel per year.
There is a potential niche market in heavy-duty vehicles for natural gas,  which could displace 1,500 million gallons of gasoline per year.
Natural gas vehicles are commercially available now, but their overall use  is limited on a national scale and production has been declining in recent  years.
Heavy-duty natural gas vehicles are in the final stages of research and  development.
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.
There is currently no federal funding or research focusing on natural gas  vehicles.
section_title: Advanced Vehicle Technologies
paragraphs: 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.
Advanced diesel engines. DOE does not have information on the potential  cost of this technology. Officials told us that this information is  proprietary.
Hybrid electric and plug-in hybrid vehicles. DOE officials told us that  these vehicles can cost several thousand dollars more than conventional  vehicles, although some of the incremental cost in hybrid vehicles  currently on the market may be related to additional amenities, rather than  the hybrid technology.
Lightweight materials. DOE officials told us that lightweight carbon fiber  materials currently cost approximately $12 to $15 per pound, and that  their goal is to reduce this cost to $3 to $5 per pound. Information was not  available on costs associated with other technologies to improve  conventional vehicle efficiency.
DOE estimates that the oil savings that would result from its vehicle  technology efforts, including research on internal combustion engines,  hybrids, and other vehicle efficiency measures, is 20,000 barrels per day by  2010, up to 1.07 million barrels per day by 2025.
DOE was not able to estimate oil savings for plug-in hybrids for fiscal year  2007.
Advanced diesel engines. Low-temperature combustion that would reduce  the emissions burden of diesel engines is under research and development.
Hybrid electric and plug-in hybrid electric vehicles. Hybrid electric  vehicles are currently on the market, although research continues on  longer-lasting, less expensive batteries for both hybrid and plug-in hybrid  electric vehicles. DOE’s goal is to have plug-in hybrids commercially  available by 2014, although officials considered this an aggressive goal.
Lightweight vehicle materials. Lightweight materials, such as aluminum,  magnesium, and polymer composites, have made inroads into vehicle  manufacturing. However, research and development are still under way on  reducing the costs of these materials. By 2012, DOE aims to make the life- cycle costs of glass- and carbon-fiber-reinforced composites, along with  several other lightweight materials, comparable to the costs for  conventional steel.
Advanced diesel engines. Reducing the emissions of nitrogen oxides and  particulate matter to meet government requirements is a key challenge for  the diesel engine combustion process. Emissions reduction will help make  more efficient advanced diesel engines cost-competitive with gasoline  engines because it will reduce the cost and energy consumption of tailpipe  emissions treatment.
Hybrid electric and plug-in hybrid electric vehicles. Battery cost is one of  the central challenges for hybrid electric and plug-in hybrid electric  vehicles. DOE officials told us that their goal is to reduce the cost of a  battery pack for a hybrid electric vehicle from approximately $920 today  to $500 by 2010. Technological challenges include extending the life of the  battery pack to last the life of the car, and improving power electronics in  the vehicle. Researchers are using lithium-ion and lithium polymer  chemistries in the next generation of batteries, instead of the current  nickel metal hydride. Officials told us that plug-in hybrids face  infrastructure challenges, such as the capacity of household electric  wiring systems to recharge a plug-in, and the capacity of the electricity  grid if plug-in hybrids are widely adopted. Battery lifetime and cost are  also challenges for plug-in hybrids.
Lightweight vehicles. The cost of lightweight materials is the largest  barrier to their widespread adoption. In addition, manufacturing capacity  for lightweight materials occurs primarily in the aerospace industry and is  not available for producing automotive components for lightweight  materials.
Advanced diesel engines. DOE currently conducts research into  combustion technology. For example, federal funds are supporting  fundamental research to understand low-temperature combustion  technology, and the industry is attempting to establish the operating  parameters of an engine that facilitate low-temperature combustion.
Hybrid electric and plug-in hybrid electric vehicles. DOE’s FreedomCAR  program sponsors research that supports the development of hybrid  vehicles, specifically with respect to improving the performance, and  reducing the cost, of electric batteries.
Lightweight vehicles. DOE currently funds research and development on  lightweight materials.
section_title: Hydrogen Fuel Cell Vehicles
paragraphs: 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.
Because hydrogen fuel cells are still in an early stage of development, the  ultimate cost of hydrogen fuel cells is uncertain, but the goal is to make  them competitive with gasoline-powered vehicles.
A fuel cell stack currently costs about $35,000, and a hydrogen fuel cell  vehicle about $100,000.
An ongoing cost-share effort between the federal government and the  industry is working toward price targets of $2 to $3 per gallon of gasoline  equivalent for hydrogen at the refueling station.
Federal experts project that hydrogen fuel cell vehicles could have the  potential to displace 0.28 million barrels per day by 2025.
Hydrogen fuel cell vehicle technologies are still in research, development,  and demonstration.
Federal experts project that the technology is not likely to be  commercially viable before 2015.
Key challenges 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.
The federal government conducts research with industry to improve the  feasibility of the technology and reduce the costs.
The government facilitates information-sharing among industry leaders by  analyzing sensitive information on hydrogen fuel cell performance from  leading automotive and oil companies.
section_title: Appendix V: Comments from the Department of Energy
paragraphs: The following are GAO’s comments on the Department of Energy’s letter  dated February 7, 2007.
subsections: section_title: GAO Comments
paragraphs: 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.
section_title: Appendix VI: Comments from the Department of the Interior
paragraphs: The following are GAO’s comments on the Department of the Interior’s  letter dated February 14, 2007.
subsections: section_title: GAO Comments
paragraphs: 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.
section_title: Appendix VII: GAO Contact and Staff Acknowledgments
subsections: section_title: Staff Acknowledgments
paragraphs: 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.