This section describes crude oil export restrictions, the SPR, and recent trends in U.S. crude oil production and the petroleum refining industry. The export of domestically produced crude oil has generally been restricted since the 1970s. In particular, the Energy Policy and Conservation Act of 1975 (EPCA) led the Department of Commerce’s Bureau of Industry and Security (BIS) to promulgate regulations which require crude oil exporters to obtain a license. These regulations provide that BIS will issue licenses for the following crude oil exports: exports from Alaska’s Cook Inlet, exports to Canada for consumption or use therein, exports in connection with refining or exchange of SPR crude oil, exports of certain California crude oil up to 25,000 barrels per day, exports consistent with certain international energy supply exports consistent with findings made by the President under certain exports of foreign origin crude oil that has not been commingled with crude oil of U.S. origin. Other than for these exceptions, BIS considers export license applications for exchanges involving crude oil on a case-by-case basis, and BIS can approve them if it determines that the proposed export is consistent with the national interest and purposes of EPCA. In addition to BIS’s export controls, other statutes control the export of domestically produced crude oil depending on where it was produced and how it is transported. In these cases, BIS can approve exports only if the President makes the necessary findings under applicable laws. Some of the authorized exceptions, outlined above, are the result of such Presidential findings. According to NERA, no other major oil producing country currently restricts crude oil exports. BIS approved about 30 to 40 licenses to export domestic crude oil per year from fiscal years 2008 through 2010. The number of BIS approved licenses increased to 103 in fiscal year 2013. Meanwhile, crude oil exports increased from less than 30 thousand barrels per day in 2008 to 396 thousand barrels per day in June 2014—the highest level of exports since 1957. Nearly all domestic crude oil exports have gone to Canada. To help protect the U.S. economy from damage caused by crude oil supply disruptions, Congress authorized the SPR in 1975. The SPR is owned by the federal government and operated by DOE. The SPR is authorized to hold up to 1 billion barrels of crude oil and has the capacity to store 727 million barrels of crude oil in salt caverns located at sites in Texas and Louisiana. According to DOE, the SPR held crude oil valuded at almost $73 billion dollars as of May, 2014. From fiscal year 2000 through 2013, the federal government spent about $0.5 billion to purchase crude oil, and spent $2.5 billion for operations and maintenance of the reserve. The United States is a member of the IEA and has agreed, along with 28 other member nations, to maintain reserves of crude oil or petroleum products equaling 90 days of net imports and to release these reserves and reduce demand during oil supply disruptions. The 90-day reserve requirement can be made up of government reserves, such as the SPR, and inventory reserves held by private industry. Under conditions prescribed by the Energy Policy and Conservation Act, as amended, the President and the Secretary of Energy have discretion to authorize the release of crude oil from the SPR to minimize significant supply disruptions. In the event of a crude oil supply disruption, the SPR can supply the market by selling stored crude oil or trading crude oil in exchange for an equal quantity of crude oil plus an additional amount as a premium to be returned to the SPR in the future. When crude oil is released from the SPR, it flows through commercial pipelines or on waterborne vessels to refineries, where it is converted into gasoline and other petroleum products, and then transported to distribution centers for sale to the public. Reversing a decades-long decline, U.S. crude oil production has increased in recent years. According to EIA data, U.S. production of crude oil reached its highest level in 1970 and generally declined through 2008, reaching a level of almost one-half of its peak. During this time, the United States increasingly relied on imported crude oil to meet growing domestic energy needs. However, recent improvements in technologies have allowed producers to extract crude oil from shale formations that were previously considered to be inaccessible because traditional techniques did not yield sufficient amounts for economically viable production. In particular, the application of horizontal drilling techniques and hydraulic fracturing—a process that injects a combination of water, sand, and chemical additives under high pressure to create and maintain fractures in underground rock formations that allow crude oil and natural gas to flow—have increased U.S. crude oil and natural gas production. Monthly domestic crude oil production has increased from an average of about 5 million barrels per day in 2008 to about 8.4 million barrels per day in April 2014, an increase of almost 68 percent. As we previously found, the growth in U.S. crude oil production has lowered the cost of some domestic crude oils. For example, prices for West Texas Intermediate (WTI) crude oil—a domestic crude oil used as a benchmark for pricing—was historically about the same price as Brent, an international benchmark crude oil from the North Sea between Great Britain and the European continent. However, from 2011 through June 13, 2014, the price of WTI averaged $14 per barrel lower than Brent (see fig. 1). In 2014, prices for these benchmark crude oils narrowed somewhat, and WTI averaged $101 through June 13, 2014, while Brent averaged $109. The development of U.S. crude oil production has created some challenges for crude oil transportation infrastructure because some production has been in areas with limited linkages to refining centers. According to EIA, these infrastructure constraints have contributed to discounted prices for some domestic crude oils. Much of the crude oil currently produced in the United States has characteristics that differ from historic domestic production. Crude oil is generally classified according to two parameters: density and sulfur content. Less dense crude oils are known as “light,” while denser crude oils are known as “heavy.” Crude oils with relatively low sulfur content are known as “sweet,” while crude oils with higher sulfur content are known as “sour.” As shown in figure 1, according to EIA, production of new domestic crude oil has tended to be light oils. Specifically, according to EIA estimates about all of the 1.8 million barrels per day growth in production between 2011 and 2013 consisted of lighter sweet crude oils. EIA also forecasts that lighter crude oils will make up a significant portion of production growth in 2014 and 2015—about 60 percent. Light crude oil differs from the crude oil that many U.S. refineries are designed to process. Refineries are configured to produce transportation fuels and other products (e.g., gasoline, diesel, jet fuel, and kerosene) from specific types of crude oil. Refineries use a distillation process that separates crude oil into different fractions, or interim products, based on their boiling points, which can then be further processed into final products. Many refineries in the United States are configured to refine heavier crude oils, and have therefore been able to take advantage of historically lower prices of heavier crude oils. For example, in 2013, the average density of crude oil used at domestic refineries was 30.8 while nearly all of the increase in production in recent years has been lighter crude oil with a density of 35 or above. According to EIA, additional production of light crude oil over the past several years has been absorbed into the market through several mechanisms, but the capacity of these mechanisms to absorb further increases in light crude oil production may be limited in the future as follows: Reduced imports of similar grade crude oils: According to EIA, additional production of light oil in the past several years has primarily been absorbed by reducing imports of similar grade crude oils. Light crude oil imports fell from 1.7 million barrels per day in 2011 to 1 million barrels per day in 2013. There may be dwindling amounts of light crude oil imports that can be reduced in the future, according to EIA. Increased crude oil exports: As discussed above, crude oil exports have increased recently, from less than 30 thousand barrels per day in 2008 to 396 thousand barrels per day in June 2014. Continued increases in crude oil exports will depend, in part, on the extent of any relaxation of current export restrictions, according to EIA. Increased use of light crude oils at domestic refineries: Domestic refineries have increased the average gravity of crude oils that they refine. The average API gravity of crude oil used in U.S. refineries increased from 30.2 degrees in 2008 to 30.8 degrees in 2013. Continued shifts to use additional lighter crude oils at domestic refineries can be enabled by investments to relieve constraints associated with refining lighter crude oils at refineries that were optimized to refine heavier crude oils. Increased use of domestic refineries: In recent years, domestic refineries have been run more intensively, allowing the use of more domestic crude oils. Utilization—a measure of how intensively refineries are used that is calculated by dividing total crude oil and other inputs used at refineries by the amount refineries can process under usual operating conditions—increased from 86 percent in 2011 to 88 percent in 2013. There may be limits to further increases in utilization of refineries that are already running at high rates. The studies we reviewed and stakeholders we interviewed generally suggest some domestic crude oil prices would increase if crude oil export restrictions were removed, while consumer fuel prices could decrease, although the extent of consumer fuel price changes are uncertain and may vary by region. Studies we reviewed and most of the stakeholders we interviewed suggest that some domestic crude oil prices would increase if crude oil export restrictions were removed. As discussed above, increasing domestic crude oil production has resulted in lower prices of some domestic crude oils compared with international benchmark crude oils. Three of the studies we reviewed also said that, absent changes in crude oil export restrictions, the expected growth in crude oil production may not be fully absorbed by domestic refineries or through exports (where allowed), contributing to even wider differences in prices between some domestic and international crude oils. By removing the export restrictions, these domestic crude oils could be sold at prices closer to international prices, reducing the price differential and aligning the price of domestic crude oil with international benchmarks. While the studies we reviewed and most of the stakeholders we interviewed agree that domestic crude oil prices would increase if crude oil export restrictions were removed, stakeholders highlighted several factors that could affect the extent of price increases. The studies we reviewed made assumptions about these factors, and actual price implications of removing crude oil export restrictions may differ from those estimated in the studies depending on how export restrictions and market conditions evolve. Specifically, stakeholders raised the following three key uncertainties: Extent of future increases in crude oil production. As we recently found, forecasts anticipate increases in domestic crude oil production in the future, but the projections are uncertain and vary widely. Two of the studies and two stakeholders told us that, in the absence of exports, higher production of domestic light sweet crude oil would tend to increase the mismatch between such crude oils and the refining industry. In turn, one study indicated that a greater increase in production would increase the price effects of removing crude oil export restrictions. On the other hand, lower than anticipated production of such crude oil would lower potential price effects as the additional crude oil could more easily be absorbed domestically. Extent to which crude oil production increases can be absorbed. The domestic refining industry and exports to Canada have absorbed the increases in domestic crude oil production thus far, and one stakeholder told us the domestic refining industry could provide sufficient capacity to absorb additional future crude oil production. This stakeholder said that refineries have the capacity to refine another 400,000 barrels a day of light crude oil, some of which is not being used because of infrastructure or logistics constraints. The industry is planning to develop or is in the process of developing the capacity to process an additional 500,000 barrels a day of light crude oil, according to this stakeholder. The current capacity that is not being utilized plus capacity that is planned or in development would constitute a total capacity to refine 900,000 barrels per day of light crude oil. To the extent that light crude oil production increases by less than this amount, the gap in prices between WTI and Brent could close in the future as increased crude oil supplies are absorbed. This would reduce the extent to which domestic crude oil prices increase if crude oil export restrictions are removed. On the other hand, some stakeholders suggested that the U.S. refining industry will not be able to keep pace with increasing U.S. light crude oil production. For example, IHS stated that refinery investments to process additional light crude oil face significant risks in the form of potentially stranded investments if export restrictions were to change, and this could result in investments not being made as quickly as anticipated. Extent to which export restrictions change. Aspects of the export restrictions could be further defined or interpreted in ways that could change the pricing dynamics of domestic crude oil markets. Recently, two companies received clarification from the Department of Commerce that condensate—a type of light crude oil—that has been processed through a distillation tower is not considered crude oil and so not subject to export restrictions. One stakeholder stated that this may lead to more condensate exports than expected. Within the context of these uncertainties, estimates of potential price effects vary in the four studies we reviewed, as shown in table 1. Specifically, estimates in these studies of the increase in domestic crude oil prices due to removing crude oil export restrictions range from about $2 to $8 per barrel. For comparison, at the beginning of June 2014, WTI was $103 per barrel, and these estimates represent 2 to 8 percent of that price. In addition, NERA found that removing export restrictions would have no measurable effect in a case that assumes a low future international oil price of $70 per barrel in 2015 rising to less than $75 by 2035. According to NERA, current production costs are close to these values, so that removing export restrictions would provide little incentive to produce more light crude oil. The studies we reviewed and most of the stakeholders we interviewed suggest that consumer fuel prices, such as gasoline, diesel, and jet fuel, could decrease as a result of removing crude oil export restrictions. A decrease in consumer fuel prices could occur because they tend to follow international crude oil prices rather than domestic crude oil prices, according to the studies and most of the stakeholders. If domestic crude oil exports caused international crude oil prices to decrease, consumer fuel prices could decrease as well. Table 2 shows that the estimates of the price effects on consumer fuels vary in the four studies we reviewed. Price estimates range from a decrease of 1.5 to 13 cents per gallon. These estimates represent 0.4 to 3.4 percent of the average U.S. retail gasoline price at the beginning of June 2014. In addition, NERA found that removing export restrictions has no measurable effect on consumer fuel prices in a case that assumes a low future world crude oil price. The effect of removing crude oil export restrictions on domestic consumer fuel prices depends on several uncertain factors. First, it depends on the extent to which domestic versus international crude oil prices determine the domestic price of consumer fuels. Recent research examining the relationship between domestic crude oil and gasoline prices concluded that low domestic crude oil prices in the Midwest during 2011 did not result in lower gasoline prices in that region. This research supports the assumption made in all of the studies we reviewed that to some extent higher prices of some domestic crude oils as a result of removing crude oil export restrictions would not be passed on to consumer fuel prices. However, some stakeholders told us that this may not always be the case and that more recent or detailed data could show that lower prices for some domestic crude oils have influenced consumer fuel prices. Second, the extent to which domestic consumer fuel prices could decline also depends on how the global crude oil market responds to the domestic crude oil entering the market. In this regard, stakeholders highlighted several uncertainties. In particular, the response of the Organization of the Petroleum Exporting Countries (OPEC) could have a large influence on any international crude oil price changes. The projections in the RFF, IHS, and ICF International studies assumed that OPEC would not respond by attempting to counterbalance the effect of increased U.S. exports by reducing its countries’ exports. However, OPEC could seek to maintain international crude oil prices by pulling crude oil from the global market. In this case, the international crude oil price would not be affected by removing export restrictions, and consumer fuel prices would not decline. On the other hand, OPEC could increase production to maintain its large market share, which would push international crude oil prices and consumer fuel prices downward. NERA examined two alternative OPEC response cases, and found that gasoline prices would not generally be affected if OPEC reduces production, and that consumer fuel prices would decrease further if OPEC maintains its production in the face of lower global crude oil prices. In addition, one stakeholder questioned whether international crude oil prices would be affected by U.S. crude oil exports. Given the size of the global crude oil market, this stakeholder suggested that U.S. exports would have little to no effect on international crude oil prices. Third, two of the stakeholders we interviewed suggested that there could be important regional differences in consumer fuel price implications, and that prices could increase in some regions—particularly the Midwest and the Northeast—due to changing transportation costs and potential refinery closures. For example, two stakeholders told us that because of requirements to use more expensive U.S.-built, -owned, and -operated ships to move crude oil between U.S. ports, allowing exports could enable some domestic crude oil producers to ship U.S. crude oil for less cost to refineries in foreign countries. Specifically, representatives of one refiner told us that, if exports restrictions were removed, they could ship oil to their refineries in Europe at a lower cost than delivering the same oil to a refinery on the U.S. East Coast. According to another stakeholder, this could negatively affect the ability of some domestic refineries to compete with foreign refineries. Additionally, because refineries are currently benefiting from low domestic crude oil prices, some studies and stakeholders noted that refinery margins could be reduced if removing export restrictions increased domestic crude oil prices. As a result, some refineries could face an increased risk of closure, especially those located in the Northeast. As EIA reported in 2012, refinery closures in the Northeast could be associated with higher consumer fuel prices and possibly higher price volatility. However, according to one stakeholder, domestic refiners still have a significant cost advantage in the form of less expensive natural gas, which is an important energy source for many refineries. For this and other reasons, one stakeholder told us they did not anticipate refinery closures as a result of removing export restrictions. The studies we reviewed and stakeholders we interviewed generally suggest that removing crude oil export restrictions would increase domestic crude oil production and may affect the environment and the economy. Studies we reviewed and stakeholders we interviewed generally agree that removing crude oil export restrictions would increase domestic crude oil production. Monthly domestic crude oil production has increased by almost 68 percent since 2008—from an average of about 5 million barrels per day in 2008 to 8.3 million barrels per day in April 2014. Even with current crude oil export restrictions, given various scenarios, EIA projects that domestic production will continue to increase and could reach 9.6 million barrels per day by 2019. If export restrictions were removed, according to the four studies we reviewed, the increased prices of domestic crude oil are projected to lead to further increases in crude oil production. Projections of this increase varied in the studies we reviewed—from a low of an additional 130,000 barrels per day on average between 2015 and 2035, according to the ICF International study, to a high of an additional 3.3 million barrels per day on average between 2015 and 2035 in NERA’s study. This is equivalent to 1.5 percent to almost 40 percent of production in April 2014. One stakeholder we spoke with told us that, although domestic demand for crude oil is not expected to change, production will rise as a result of increased international demand, primarily from Asia. For example, according to EIA, India was the fourth-largest consumer of crude oil and petroleum products in the world in 2013, and the country’s dependence on imported crude oil continues to grow. Another stakeholder stated that removing export restrictions could lead to increased local and regional opposition to crude oil production if the crude oil was primarily for export, which could affect domestic production. Two of the studies we reviewed and most stakeholders we spoke with stated that the increased crude oil production that would result from removing the restrictions on crude oil exports may affect the environment. In September 2012, we found that crude oil development may pose certain inherent environmental and public health risks; however, the extent of the risk is unknown, in part, because the severity of adverse effects depend on various location- and process-specific factors, including the location of future shale oil and gas development and the rate at which it occurs, as well as geology, climate, business practices, and regulatory and enforcement activities. The stakeholders who raised concerns identified the following risks related to crude oil production, about which GAO has reported in the past: Water quality and quantity: Increased crude oil production, particularly from shale, could affect the quality and quantity of surface and groundwater sources, but the magnitude of such effects is unknown. In October 2010, we found that water is needed for a number of oil shale development activities, including constructing facilities, drilling wells, generating electricity for operations, and reclamation of drill sites. In 2012, we found that shale oil and gas development may pose a risk to surface water and groundwater because withdrawing water from streams, lakes, and aquifers for drilling and hydraulic fracturing could adversely affect water resources. For example, we found that groundwater withdrawal could affect the amount of water available for other uses, including public and private water supplies. One of the stakeholders we interviewed suggested that water withdrawal is already an important consideration, particularly for areas experiencing drought. For example, the stakeholder noted that crude oil production and associated water usage already has implications for the Edwards Aquifer, a groundwater system serving the agricultural, industrial, recreational, and domestic needs of almost two million users in south central Texas. In addition, removing export restrictions may affect water quality. Another stakeholder told us that allowing crude oil exports would lead to more water pollution as a result of increased production through horizontal drilling. Air quality: Increased crude oil production may increase greenhouse gases and other air emissions because the use of consumer fuels would increase, and also because the crude oil production process often involves the direct release of pollutants into the atmosphere (venting) or burning fuels (flaring). Two stakeholders told us that venting and flaring has escalated in North Dakota, in part because regulatory oversight and infrastructure have not kept pace with the recent surge in crude oil production in the state. In January 2014, the North Dakota Industrial Commission reported that nearly 30 percent of all natural gas produced in the state is flared. According to a 2013 report from Ceres, flaring in North Dakota in 2012 resulted in greenhouse gas emissions equivalent to adding 1 million cars to the road. Another stakeholder told us that allowing crude oil exports would lead to more air pollution as a result of increased production through horizontal drilling and hydraulic fracturing. RFF estimated the potential environmental effect of removing export restrictions, estimating that increases in crude oil production and consumption would increase carbon dioxide emissions worldwide by almost 22 million metric tons per year. By comparison, U.S. emissions from energy consumption totaled 5,393 million metric tons in 2013 according to EIA. NERA estimated that increased crude oil production and use of fossil fuels would increase greenhouse gas emissions by about 12 million metric tons of carbon dioxide equivalents per year on average from 2015 through 2035. Transportation challenges: Increased crude oil production could exacerbate transportation challenges. In March 2014, we found that domestic and Canadian crude oil production has created some challenges for U.S. crude oil transportation infrastructure. Some of the growth in crude oil production has been in areas with limited transportation to refining centers. To address this challenge, refiners have relied on rail to transport crude oil. According to data from the Surface Transportation Board, rail moved about 236,000 carloads of crude oil in 2012, which is 24 times more than the roughly 9,700 carloads moved in 2008. As we recently found, as the movement of crude oil by rail has increased incidents such as spills and fires involving crude oil trains have also increased—from 8 incidents in 2008 to 119 incidents in 2013 according to Department of Transportation data. Some stakeholders told us that removing export restrictions would increase the risk for crude oil spills by rail and other modes of transportation such as tankers. On the other hand, one stakeholder suggested that removing export restrictions could reduce the amount of crude oil transported by rail, in some instances, since the most economic way to export crude oil is by pipeline to a tanker. As a result, the number of rail accidents involving crude oil spills could decrease. The studies we reviewed suggest that removing crude oil export restrictions would increase the size of the economy. Three of the studies project that removing export restrictions would lead to additional investment in crude oil production and increases in employment. This growth in the oil sector would—in turn—have additional positive effects in the rest of the economy. For example, NERA projects an average of 230,000 to 380,000 workers would be removed from unemployment through 2020 if export restrictions were eliminated in 2015. These employment benefits largely disappear if export restrictions are not removed until 2020 because by then the economy will have returned to full employment. Potential implications for investment, public revenue, and trade are as follows: Investments: According to one of the studies we reviewed, removing export restrictions may lead to more investment in crude oil exploration and production, but this investment could be somewhat offset by less investment in the refining industry. As discussed previously, removing export restrictions is expected to increase domestic crude oil production. Private investment in drilling rigs, engineering services, and transportation and logistics facilities, for example, is needed to increase domestic crude oil production. According to IHS, this will directly benefit industries such as machinery, fabricated metals, steel, chemicals, and engineering services. At the same time, removing export restrictions may decrease investment in the refining industry because the industry would not need extensive additional investment to accommodate lighter crude oils. For example, one stakeholder told us that, under current export restrictions, refining additional light crude oils may require capital investment to remove processing constraints at refineries that are designed to process heavier crude oils. Officials from one refining company told us that they had invested a significant amount of capital to refine lighter oils. For example, the refinery installed two new distillation towers to process lighter crude oils at a cost of $800 million. Such investments may not be necessary if export restrictions were removed. Public revenue: Two of the studies we reviewed suggest that removing export restrictions would increase government revenues, although the estimates of the increase vary. One study estimated that total government revenue would increase by a combined $1.4 trillion in additional revenue from 2016 through 2030 while another study estimated that U.S. federal, state, and local tax receipts combined with royalties from drilling on federal lands could increase by an annual average of $3.9 to $5.7 billion from 2015 through 2035. Trade: According to the studies we reviewed, removing export restrictions would contribute to further declines in net petroleum (i.e., crude oil, consumer fuels, and other petroleum products) imports and reduce the U.S. trade deficit. Three of the studies we reviewed estimated the effect of removing export restrictions on net petroleum imports, with ICF projecting a decline in net imports of about 100,000 to 300,000 barrels per day; IHS projecting a decline, but not providing a specific estimate; and NERA projecting a decline of about 0.6 to 3.2 million barrels per day. Further, according to one study, removing export restrictions could also improve the U.S. trade balance because the light sweet crude oils are usually priced higher than heavy, sour crude oils. One study estimated that removing export restrictions could improve the trade balance (narrow the U.S. trade deficit) by $8 to $15 billion per year on average from 2015 through 2035. Another study estimated that removing crude oil export restrictions would improve the trade balance by $72 to $101 billion per year from 2016 through 2030. Changing market conditions—most importantly the significant increase in domestic production of crude oil from shale—have implications for the role of the SPR, including its appropriate size, location, and composition. DOE has taken some steps to reexamine the location and composition of the SPR in light of these changes, but has not recently reexamined its size. Recent and expected changes in crude oil markets have important implications for the role of the SPR, including its size, location, and composition. DOE has recognized that recent increases in domestic crude oil production and correlating reductions in crude oil imports have changed how crude oil is transported around the United States, and that these changes carry potential implications for the operation and maintenance of the SPR. As discussed above, removing crude oil export restrictions would be expected to increase domestic crude oil production and contribute to further declines in net imports. Our review of DOE documents, prior GAO work, and discussions with stakeholders highlight three primary implications for the SPR. Size: Increased domestic crude oil production and falling net petroleum imports may affect the ideal size of the SPR—how much the SPR should hold to optimize the benefits of protecting the economy from damage with the costs of holding the reserves. One measure of the economy’s vulnerability to oil supply disruptions is to assess net petroleum imports— imports minus exports. Net petroleum imports have declined from a peak of 60 percent of consumption in 2005 to about 30 percent in the first half of 2014. In 2006, net imports were expected to increase in the future, increasing the country’s reliance on foreign crude oil. However, imports have declined and, according to EIA’s most recent forecast, are expected to remain well below 2005 import levels into the future. (See fig. 3.) As discussed above, removing crude oil export restrictions would be expected to contribute to additional decreases in net petroleum imports in the future. To the extent that changes in net imports reflect changes in vulnerability, these and other changes in the economy may have reduced the nation’s vulnerability to supply disruptions. For example, a recent report by the President’s Council of Economic Advisers suggests that decreased domestic petroleum demand, increased domestic crude oil production, more fuel efficient vehicles, and increased use of biofuels, have each contributed to reducing the vulnerability of the nation’s economy to international crude oil supply disruptions. Although international crude oil supply and price volatility remains a risk, the report suggests that additional reductions in net petroleum imports could reduce those risks in the future. In addition, the SPR currently holds oil in excess of international obligations. As a member of the IEA, the United States is required to maintain reserves of crude oil or petroleum products equaling at least 90 days of net imports, which it does with a combination of public and private reserves. According to IEA, as of May 2014, the SPR held 106 days of net imports, and private reserves held an additional 141 days of imports for a total of 247 days—well above the 90 days required by the IEA. In light of these factors, some of the stakeholders we interviewed raised questions about whether such a large SPR is needed in the future. For example, one stakeholder indicated that SPR crude oil is surplus and no longer needed to protect the economy. However, other stakeholders highlighted the importance of maintaining the SPR. For example, one stakeholder said that the SPR should be maintained at the current level, and another said that the SPR serves an important “energy insurance” service. DOE officials and one other stakeholder highlighted that, in addition to net imports, there are other factors that may affect the appropriate size of the SPR. Location: According to DOE, changes in how crude oil is transported throughout the United States and in the existing infrastructure surrounding SPR facilities have implications for the location of the SPR. Crude oil in the SPR is stored along the Gulf Coast, where it can take advantage of being in close proximity to a major refining center, as well as distribution points for tankers, barges, and pipelines that can carry crude oil from the SPR to refineries in other regions of the country. Most of the system of crude oil pipelines in the United States was constructed in the 1950s, 1960s, and 1970s to accommodate the needs of the refining sector and demand centers at the time. According to DOE officials, the existing infrastructure was designed primarily to move crude oil from the southern United States to the North. The SPR has historically been able to rely on this distribution system to reach a large portion of the nation’s refining capacity. But, with increases in crude oil production in the Northern U.S. and imports of crude oil from Canada, the distribution system has changed to increase crude oil flows south to the Gulf Coast. Such changes include new pipeline construction and expansions, flow reversals in existing pipelines, and increased utilization of terminals and marine facilities. Such changes may make it more difficult to move crude oil from the SPR to refineries in certain regions of the United States, such as the Midwest, where almost 20 percent of the nation’s refining capacity is located, according to EIA data. Some stakeholders raised questions about the location of the SPR. One stakeholder also suggested that holding SPR crude oil in the western United States may better ensure access to crude oil in the case of a disruption, since the West has no pipeline connectivity to the Gulf Coast. According to DOE, recent changes to crude oil distribution in the United States could have significant implications for the operation and maintenance of the SPR. Composition: In 2006, we reported that the type of crude oil in the SPR was not compatible with all U.S. refineries. We reported that some U.S. refineries processed crude oils heavier than those stored in the SPR. We found that in the event of a disruption in the supply of heavy crude oil, refineries configured to use heavy crude oil would not be able to efficiently refine crude oil from the SPR and would likely reduce production of some petroleum products. As we reported, in such instances, prices for heavy crude oil products could increase, reducing the SPR’s effectiveness to limit economic damage. Refinery officials we spoke with noted that the SPR should contain heavier crude oils that domestic refineries could refine in the event of a supply disruption. Since our 2006 report, domestic production of light sweet crude oil has increased. According to EIA, roughly 96 percent of the 1.8 million-barrel per day growth in production from 2011 to 2013 consisted of light sweet grades with API gravity of 40 or above. As a result, imports of light crude oils have declined, and U.S. reliance on imported heavy crude oil has increased from 37 percent of total imports in 2008 to 50 percent of total imports in 2013, as shown in figure 4. However, DOE officials raised concerns about the prospect of storing additional heavy crude oil in the SPR. According to DOE officials and a 2010 report by DOE, storing heavy crude oil in the SPR would limit the SPR’s ability to respond to nonheavy crude oil disruptions, such as a loss of Middle East medium sour crude oils. In addition, storing more heavy crude would require infrastructure improvements. At the same time, DOE officials also stated that, based on recent conversations with refinery officials, no U.S. refineries would have difficulty using SPR crude oils. Another issue raised by some stakeholders we interviewed is that the SPR holds primarily crude oil, and some stakeholders told us that holding additional consumer fuels could be beneficial. Many recent economic risks associated with supply disruptions have originated from the refining and distribution sectors rather than crude oil supplies. DOE has taken some steps to assess the appropriate location and composition of the SPR in view of changing market conditions, but has not recently re-examined its size. We previously found that federal programs should be re-examined if there have been significant changes in the country or the world that relate to the reason for initiating the program. In that report, we identified a set of reexamination criteria that, when taken together, illustrate the issues that can be addressed through a systematic reexamination process. We found that many federal programs and policies were designed decades ago to respond to trends and challenges that existed at the time of their creation. Given fiscal constraints that we are likely to face for years to come, reexamination may be essential to addressing newly emergent needs without unduly burdening future generations of taxpayers. DOE has taken some steps to reexamine how recent changing market conditions could affect the location and composition of the SPR as follows: In March 2014, DOE conducted a test sale of SPR crude oil to evaluate the SPR’s ability to draw down and distribute SPR crude oil through multiple pipeline and terminal delivery points within one of its distribution systems. DOE officials told us they were reviewing the results of the test sale including data on the movement of crude oil through the system. DOE officials also told us they are working to establish a Northeast Regional Refined Petroleum Product Reserve in New York Harbor and New England to store refined consumer fuels. Although the northeast reserve will not store crude oil, it will be considered part of the SPR and hold 1 million barrels of gasoline at a cost of $200 million. DOE officials told us that they are conducting a regional fuel resiliency study that will provide insights into whether there is a need for additional regional product reserves and, if so, where these reserves should be located and the capacity. We did not assess this effort because the study was ongoing at the time of our review. DOE finalized an assessment in 2010 of the compatibility of crude oil stored in the SPR with the U.S. petroleum refining industry. DOE decided against storing heavy crude oil in the SPR at the time, but committed to revisiting the option of storing heavy crude oil in the future. However, DOE has not recently reexamined the appropriate size of the SPR. DOE last issued a strategic plan for the SPR in May 2004. The plan outlined the mission, goals, and near-term and long-term objectives for the SPR. In 2006, we recommended that the Secretary of Energy reexamine the appropriate size of the SPR. In 2007, while DOE was planning to expand the SPR to its authorized size of 1 billion barrels, the Administration reevaluated the need for an SPR expansion and decided that the current level was adequate. In responding to our recommendation, DOE stated that its reexamination had taken the form of more “actionable items,” including not requesting expansion-funding in its 2011 budget and canceling and redirecting prior year’s expansion funding to general operations of the SPR. Officials from DOE’s Office of Petroleum Reserves told us that the last time they conducted a comprehensive re-examination of the size of the SPR was in 2005. At that time, DOE’s comprehensive study examined the costs and benefits of alternative SPR sizes. Officials told us that they have not conducted a comprehensive reexamination since 2005 because the SPR only recently met the IEA requirement to maintain 90 days of imports. However, the IEA requirement is for total reserves, including those held by the government and private reserves. As shown in figure 5, such reserves in the United States are currently in excess of the nation’s international obligations and, in some scenarios, are expected to be in excess in the future. In July 2014, DOE’s Office of Inspector General recommended that the Office of Fossil Energy perform a long-range strategic review of the SPR to ensure it is best configured to respond to the current and future needs of the United States. DOE concurred with the recommendation. DOE stated that it expected to determine the appropriate course of action by August 2014, and according to DOE, it has initiated a process to conduct such a review. The SPR currently holds oil valued at over $73 billion, and without a current reexamination of the SPR’s size, DOE cannot be assured that the SPR is sized appropriately. The SPR may therefore be at risk of holding excess crude oil. In addition, DOE officials told us that SPR infrastructure is aging and will need to be replaced soon. Conducting a reexamination of the size of the SPR could also help inform DOE’s decisions about how or whether to replace existing infrastructure. If DOE were to assess the appropriate size of the SPR and find that it held excess crude oil, the excess oil could be sold to fund other national priorities. For example, in 1996, SPR crude oil was sold to reduce the federal budget deficit and offset other appropriations. If, for example, DOE found that 90 days of imports was an appropriate size for the SPR, it could sell crude oil worth about $10 billion. Increasing domestic crude oil production, and declines in consumption and crude oil imports have profoundly affected U.S. crude oil markets over the last decade. These changes can have important implications for national energy policies and programs. The SPR is a significant national asset, and it is important for federal agencies tasked with overseeing such assets to examine how, if at all, changing conditions affect their programs. DOE has recently taken several steps to reexamine various aspects of the SPR in light of these changes, including its location and composition; however, DOE’s most recent comprehensive examination of the appropriate size of the SPR was conducted in 2005 when the general expectation was that the country would increasingly rely on foreign crude oil. At about that time, however, it began to become clear that this was not to be the case. Removing export restrictions would be expected to lead to further decreases in net imports that would further affect the role of the SPR. Without a reexamination of the SPR that considers whether a smaller or larger SPR is in the national interest in light of current and expected future changes in market conditions, DOE cannot be assured that the SPR is holding an appropriate amount of crude oil in the SPR, and its ability to make appropriate decisions regarding maintenance of the SPR could be compromised. In view of recent changes in market conditions and in tandem with DOE’s ongoing activities to assess the content, connectivity, and other aspects of the SPR, we recommend that the Secretary of Energy undertake a comprehensive reexamination of the appropriate size of the SPR in light of current and expected future market conditions. We provided a draft of this report to DOE and Commerce for their review and comment. The agencies provided technical comments, which we incorporated as appropriate. In its written comments, reproduced in appendix III, DOE concurred in principle with our recommendation. However, DOE stated that conducting a study of only the size of the SPR would be too narrow in scope and would not address other issues relevant to the SPR carrying out its mission of providing energy security to the United States. DOE stated that a broader, long-range review of the SPR is needed. We agree that such a review would be beneficial. We do not recommend that DOE undertake an isolated reexamination of the size of the SPR, but that such a reexamination be conducted in tandem with DOE’s other activities to assess the SPR and we clarified our recommendation accordingly. As agreed with your office, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date. At that time, we will send copies to the appropriate congressional committees, the Secretaries of Energy and Commerce, and other interested parties. In addition, the report will be available at no charge on the GAO website at http://www.gao.gov. If you or your staff members have any questions about this report, please contact me at (202) 512-3841 or ruscof@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 key contributions to this report are listed in appendix IV. We identified four studies that examined the price and other implications of removing crude oil export restrictions. These four studies are as follows: Resources for the Future (RFF). Crude Behavior: How Lifting the Export Ban Reduces Gasoline Prices in the United States. Washington, D.C.: Resources for the Future, February 2014, revised March 2014. ICF International and EnSys Energy (ICF International). The Impacts of U.S. Crude Oil Exports on Domestic Crude Production, GDP, Employment, Trade, and Consumer Costs. Washington, D.C.: ICF Resources, March 31, 2014. IHS. US Crude Oil Export Decision: Assessing the impact of the export ban and free trade on the US economy. Englewood, Colorado: IHS, 2014. NERA Economic Consulting (NERA). Economic Benefits of Lifting the Crude Oil Export Ban. Washington, D.C.: NERA Economic Consulting, September 9, 2014. Table 3 describes these studies and several key assumptions, Table 4 summarizes their findings regarding prices, and Table 5 summarizes their findings regarding other implications of removing crude oil export restrictions. In addition to the individual named above, Christine Kehr (Assistant Director), Philip Farah, Quindi Franco, Cindy Gilbert, Taylor Kauffman, Celia Rosario Mendive, Alison O’Neill, and Barbara Timmerman made key contributions to this report. Petroleum Refining: Industry’s Outlook Depends on Market Changes and Key Environmental Regulations. GAO-14-249. Washington, D.C.: March 14, 2014. Oil and Gas: Information on Shale Resources, Development, and Environmental and Public Health Risks. GAO-12-732. Washington, D.C.: September 5, 2012. Energy Markets: Estimates of the Effects of Mergers and Market Concentration on Wholesale Gasoline Prices. GAO-09-659. Washington, D.C.: June 12, 2009. Strategic Petroleum Reserve: Issues Regarding the Inclusion of Refined Petroleum Products as Part of the Strategic Petroleum Reserve. GAO-09-695T. Washington, D.C.: May 12, 2009. Energy Markets: Refinery Outages Can Impact Petroleum Product Prices, but No Federal Requirements to Report Outages Exist. GAO-09-87. Washington, D.C.: October 7, 2008. Energy Markets: Increasing Globalization of Petroleum Products Markets, Tightening Refining Demand and Supply Balance, and Other Trends Have Implications for U.S. Energy Supply, Prices, and Price Volatility. GAO-08-14. Washington, D.C.: December 20, 2007. Strategic Petroleum Reserve: Available Oil Can Provide Significant Benefits, but Many Factors Should Influence Future Decisions about Fill, Use, and Expansion. GAO-06-872. Washington, D.C.: August 24, 2006. Motor Fuels: Understanding the Factors That Influence the Retail Price of Gasoline. GAO-05-525SP. Washington, D.C.: May 2, 2005. Alaskan North Slope Oil: Limited Effects of Lifting Export Ban on Oil and Shipping Industries and Consumers. GAO/RCED-99-191. Washington, D.C.: July 1, 1999.

Summary: Almost 4 decades ago, in response to the Arab oil embargo and recession it triggered, Congress passed legislation restricting crude oil exports and establishing the SPR to release oil to the market during supply disruptions and protect the U.S. economy from damage. After decades of generally falling U.S. crude oil production, technological advances have contributed to increasing U.S. production. Meanwhile, net crude oil imports—imports minus exports—have declined from a peak of about 60 percent of consumption in 2005 to 30 percent in the first 5 months of 2014. According to Energy Information Administration forecasts, net imports are expected to remain well below 2005 levels into the future. GAO was asked to provide information on the implications of removing crude oil export restrictions. This report examines what is known about (1) price implications of removing crude oil export restrictions; (2) other key potential implications; and (3) implications of recent changes in market conditions on the SPR. GAO reviewed four studies on crude oil exports, including two sponsored by industry, and summarized the literature and views of a nonprobability sample of stakeholders including academic, industry, and other experts. The studies GAO reviewed and stakeholders interviewed suggest that removing crude oil export restrictions is likely to increase domestic crude oil prices but decrease consumer fuel prices. Prices for some U.S. crude oils are lower than international prices—for example, one benchmark U.S. crude oil averaged $101 per barrel in 2014, while a comparable international crude oil averaged $109. Studies estimate that U.S. crude oil prices would increase by about $2 to $8 per barrel—bringing them closer to international prices. At the same time, studies and some stakeholders suggest that U.S. prices for gasoline, diesel, and other consumer fuels follow international prices, so allowing crude oil exports would increase world supplies of crude oil, which is expected to reduce international prices and, subsequently, lower consumer fuel prices. Some stakeholders told GAO that there could be important regional differences in the price implications of removing crude oil export restrictions. Some stakeholders cautioned that estimates of the implications of removing export restrictions are uncertain due to several factors such as the extent of U.S. crude oil production increases, how readily U.S. refiners are able to absorb such increases, and how the global crude oil market responds to increasing U.S. production. The studies GAO reviewed and stakeholders interviewed generally suggest that removing crude oil export restrictions may also have the following implications: Crude oil production. Removing export restrictions would increase domestic production—8 million barrels per day in April 2014—because of increasing domestic crude oil prices. Estimates range from an additional 130,000 to 3.3 million barrels per day on average from 2015 through 2035. Environment. Additional crude oil production may pose risks to the quality and quantity of surface groundwater sources; increase greenhouse gas and other emissions; and increase the risk of spills from crude oil transportation. The economy. Removing export restrictions is expected to increase the size of the economy, with implications for employment, investment, public revenue, and trade. For example, removing restrictions is expected to contribute to further declines in net crude oil imports, reducing the U.S. trade deficit. Changing market conditions have implications for the size, location, and composition of Department of Energy's (DOE) Strategic Petroleum Reserve (SPR). In particular, increased domestic crude oil production and falling net imports may affect the ideal size of the SPR. Removing export restrictions is expected to contribute to additional decreases in net imports in the future. As a member of the International Energy Agency, the United States is required to maintain public and private reserves of at least 90 days of net imports but, as of May 2014, the SPR held reserves of 106 days—worth about $73 billion—and private industry held reserves of 141 days. DOE has taken some steps to assess the implications of changing market conditions on the location and composition of the SPR but has not recently reexamined its size. GAO has found that agencies should reexamine their programs if conditions change. Without such a reexamination, DOE cannot be assured that the SPR is sized appropriately and risks holding excess crude oil that could be sold to fund other national priorities. In view of changing market conditions and in tandem with activities to assess other aspects of the SPR, GAO recommends that the Secretary of Energy reexamine the size of the SPR. In commenting on a draft of this report, DOE concurred with GAO's recommendation.