Petroleum Refining: Industry's Outlook Depends on Market Changes and Key Environmental Regulations
Released: 2014-04-14T00:00:00

Letter

Background

This section describes the petroleum refining industry and the five key regulations that we reviewed.

Petroleum Refining Industry

According to data from EIA, there were 143 petroleum refineries in the United States as of January 2013, with a capacity to process 17.8 million barrels of crude oil per day. While there are refineries in most regions of the country, most refining capacity (almost 90 percent) is located in the Gulf Coast, West Coast, and Midwest regions (see fig. 1). These refineries employed over 70,000 people in 2013.

Refineries process crude oil into products primarily through a distillation process that separates crude oil into different fractions based on their boiling points, which can then be further processed into final products. One barrel of crude oil can be processed into varying amounts of gasoline, diesel, jet fuel, and other petroleum products depending on the configuration—or complexity—of the refinery and the type of crude oil that is being refined. Through the addition of specialized equipment, refineries can be optimized—or “upgraded”—to produce greater proportions of specific types of products or to use different types of crude oil. For example, a coker unit upgrades the low-value residual oil from the distillation process into higher value products such as diesel, increasing a refinery’s ability to process heavier crude oils. As shown in Figure 2, from a barrel of crude oil, U.S. refineries primarily produce gasoline, diesel, and jet fuel that are used in the transportation sector, along with heating oil and liquefied petroleum gases such as propane used in home heating.

The U.S. petroleum refining industry consists of firms of varying sizes that, in addition to operating refineries, may also have operations in other related industry segments: (1) the upstream segment, which consists of the exploration for and production of crude oil; (2) the midstream segment, which consists of pipelines and other infrastructure used to transport crude oil and refined products; (3) the downstream segment, which consists of the refining and marketing of petroleum products such as gasoline and heating oil; and (4) the renewable fuels segment, where biorefineries produce renewable fuels that are blended with petroleum products at wholesale terminals before being distributed to consumers. To varying degrees, refiners may primarily operate refineries—these are called merchant refiners—or may be integrated, participating in various other related industry segments. HollyFrontier Corporation is an example of a merchant refiner that purchases crude oil from unaffiliated producers and sells refined products to other companies operating retail fuel outlets, while Chevron is an example of a fully integrated company, a refiner that also produces crude oil and operates pipelines and retail fueling outlets across the United States.

Crude oil, petroleum products, and renewable fuels are transported between market participants through an extensive supply infrastructure including pipelines, tanker vessels, rail, trucks, wholesale terminals, and retail outlets. (See fig. 3.) In 2012, refineries received the majority of their crude oil by pipeline (over 50 percent) and by tanker vessel (37 percent), with trucks and rail generally playing a more limited role according to EIA data.

As we reported in 2007, according to industry officials and experts, the refining industry was a low-return industry for much of the prior two decades. Retail prices for regular gasoline averaged $3.63 per gallon in 2012, the highest annual average price when adjusted for inflation since 1976, the earliest comparable data available from EIA. Retail prices have declined in 2013—gasoline averaged $3.55 in the first half of 2013 and $3.18 in November 2013—but are still near historic highs. Market dynamics anywhere along the supply chain can influence consumer prices, beginning with upstream crude oil production, the production of renewable fuels, through downstream refining and retailing. According to EIA data, increases in crude oil costs have been the largest component of the recent increases in gasoline prices. The refining component of prices—including labor, materials, energy, and other costs of the refining process, as well as profits to refinery owners—has fluctuated over time but has not increased in a significant way since 2000, when EIA began reporting estimates of the components of retail prices (see fig.4).

Key Regulations Affecting the Domestic Refining Industry

The five key environmental regulations affecting the domestic refining industry that we reviewed are concerned with various health, environmental, and other issues.

Under the RFS, since 2006, transportation fuels sold in the United States have been required to contain increasing amounts of renewable fuels such as ethanol and biodiesel. EPA is responsible for administering the RFS and annually issues regulations that establish the percentage of gasoline and diesel fuels that refiners, importers, and other obligated parties must ensure are renewable fuels. Congress established the RFS in light of concerns such as climate change and the nation’s dependence on imported crude oil. As shown in figure 5, the law generally required that transportation fuels contain 9 billion gallons of renewable fuels in 2008, and that volumes increase 4-fold through 2022 to 36 billion gallons. The Administrator of EPA is authorized to waive the RFS levels established in the act if the Administrator determines—in consultation with the Secretaries of Agriculture and Energy—that implementing the requirement would severely harm the economy or environment, that there is an inadequate domestic supply, or in certain other situations. The major source of renewable fuels has traditionally been ethanol produced from corn; however, as we reported in 2009, the increased cultivation of corn for ethanol, its conversion into renewable fuels, and the storage and use of these fuels could affect water supplies, water quality, air quality, soil quality, and biodiversity. Under the RFS’ statutory provisions, the increasing amounts of renewable fuels are to primarily come from renewable fuels other than corn ethanol—called advanced biofuels—that meet certain criteria, including reducing GHG emissions by at least 50 percent compared with the gasoline or diesel fuel they displace. According to EPA, achieving the RFS’ statutory blending levels in 2022 could result in total benefits—including those related to overall fuel costs, energy security, health, and GHG effects—of between $13 and $26 billion and could reduce GHG emissions by 138 million metric tons of carbon dioxide equivalent emissions, equal to taking about 27 million vehicles off the road.

The federal government has regulated vehicle fuel economy through CAFE standards since 1978 and, more recently, aligned these standards with new GHG vehicle emission standards in a joint national program aimed at reducing oil consumption and GHG emissions from the transportation sector. CAFE standards are administered by the National Highway Traffic Safety Administration (NHTSA) and require that vehicle manufacturers meet fleet-wide average fuel economy standards for vehicles. The Energy Independence and Security Act of 2007 instituted several changes to the CAFE standards and, in 2009, the administration announced a new program to increase vehicle fuel economy and reduce vehicle GHG emissions, which was implemented by a joint rulemaking with NHTSA raising CAFE standards and EPA establishing the first GHG emissions standards for vehicles. Although the CAFE and GHG vehicle emission standards are distinct, their targets were aligned for compliance purposes. NHTSA and EPA put the national program into place by issuing coordinated regulations covering vehicle model years 2012 to 2025. As shown in figure 6, fuel economy standards for cars largely remained unchanged from 1990 through 2010, but vehicle manufacturers are now expected to meet increasingly stringent standards reaching the projected combined average fuel economy of about 50 miles per gallon by 2025— about 80 percent more efficient than required under the 2011 standards. EPA estimated that the 2011-2025 standards may save consumers and businesses $1.7 trillion, reduce oil consumption by 12 billion barrels, and reduce GHG emissions by 6 billion metric tons over the lifetime of the vehicles sold during model years 2011-2025.

Under the Clean Air Act, EPA is authorized to establish certain standards for new motor vehicles and fuels to address air pollution that may reasonably be anticipated to endanger public health or welfare. On May 21, 2013, EPA proposed the Tier 3 standards, and on March 3, 2014, EPA announced the final Tier 3 standards which establish more stringent vehicle emission standards and reduce the sulfur content of gasoline. (Because EPA finalized this rulemaking after the draft report was completed and provided to agencies, the views of stakeholders and other information on Tier 3 that we reviewed and summarize in the rest of this report relate primarily to the proposed standards. EPA stated that the final rulemaking is very similar to the proposal, and that EPA made some changes—including to the sulfur provisions—based on public input.) According to EPA, more than 149 million Americans experience unhealthy levels of air pollution that has been linked to respiratory and cardiovascular problems and other adverse health effects. Cars and light trucks are significant contributors to air pollution, and EPA estimated that the Tier 3 standards will reduce pollution from such sources. The standards set more stringent tailpipe emission standards for new vehicles and generally require refiners to lower the sulfur content of gasoline from 30 parts per million (ppm) to 10 ppm on an annual average basis by 2017, among other things. According to EPA, reducing the sulfur content of gasoline allows emissions control systems to work more effectively for existing and new vehicles and would therefore enable more stringent vehicle emissions standards. EPA estimated that the Tier 3 standards would reduce on-highway vehicle emissions of nitrogen oxides, a pollutant that has been liked to respiratory illnesses, by 10 percent in 2018, and 25 percent in 2030. According to EPA estimates, by 2030, annual emission reductions from the Tier 3 standards would generate annual benefits of between $6.7 and $19 billion and prevent up to 2,000 premature deaths annually. EPA estimated that the vehicle and fuel standards would cost approximately $1.5 billion in 2030, including costs for refiners to install and operate equipment to remove sulfur from gasoline, as well as costs for vehicle manufacturers to improve the emissions performance of vehicles.

Stationary Source GHG Requirements

Under the Clean Air Act, EPA is authorized to take certain steps to address emissions from stationary sources, including refineries. EPA has regulated certain emissions of air pollutants from stationary sources for several decades, and EPA recently issued rules concerning how GHGs are to be included in certain existing permitting processes. Specifically, permitting authorities are to include GHG emission control requirements in Prevention of Significant Deterioration (PSD) permits and certain other permits issued to refineries and other stationary sources that trigger GHG emissions thresholds. Since 2011, construction of any new refineries and certain refineries that are modified have generally been subject to the use of the “best available control technology” for GHG emissions. The best available control technology is determined for each facility based on an analysis of available technologies considering cost and other factors. According to EPA, in most cases, the best available control technology selected for GHGs are energy efficiency improvements. For example, for refineries, this could involve the installation of heat recovery units, which capture and use otherwise wasted heat in the refinery process. Such energy efficiency improvements can lower GHG emissions and other pollutants while reducing fuel consumption and saving money. Current regulations do not require existing facilities to take any steps to control GHG emissions unless they undertake a major modification. Examples of major modifications at a refinery include a significant expansion of crude oil processing units, or installing new secondary processing units that would increase GHG emissions above specified thresholds.

California’s LCFS aims to lower GHG emissions by reducing the level of carbon in transportation fuels. Established by the California Air Resources Board (CARB) following state legislation and an executive order, the LCFS has been fully in effect since January 2011. The LCFS would change the mix of fuels and vehicles in California to reduce emissions throughout the fuel “life cycle”—which includes emissions associated with producing, transporting, distributing, and using the fuel. To reduce emissions, carbon intensity (CI) scores are used, which are to reflect each fuel’s life cycle GHG emissions. Refiners generally are required to ensure that the overall CI score for their fuels—which can include gasoline, diesel, and their blendstocks and substitutes—meets the annual carbon intensity target for a given year. Unlike the RFS, which requires certain types of renewable fuels be used, under LCFS refiners can meet the CI reduction targets using a variety of low carbon fuel technologies. Low carbon fuel technologies include renewable fuels from waste and cellulosic materials, natural gas, electricity used in plug-in vehicles, and hydrogen used in fuel cell vehicles. The original LCFS statewide reduction targets for gasoline, diesel, and their substitutes started at 0.25 percent of 2010 values in 2011 and increased to 10 percent by 2020. However, in 2013 a state Court of Appeal found that CARB must correct certain aspects of the procedures by which the LCFS was originally adopted. CARB officials subsequently announced a regulatory package would be proposed in 2014, and that the 2013 standards—a 1 percent decrease in carbon intensity from 2010 values—will remain in effect through 2014.

To comply with LCFS, refiners can produce their own low carbon fuels, buy such fuels from other producers to blend into their products and sell on the market, or purchase credits generated by others. Refiners can also generate credits—which can be banked and traded—if their use of low carbon fuels results in greater-than-required carbon intensity reductions. CARB estimated that the 2020 targets would reduce GHG emissions associated with the transportation sector in California by 10 percent in 2020, or 23 million metric tons of carbon dioxide equivalent.

Market Changes and Key Environmental Regulations Likely Affected the Refining Industry

Stakeholders we interviewed identified three major changes that have likely recently affected the domestic petroleum refining industry. First, crude oil production in the United States and Canada has increased, which has lowered the cost of purchasing crude oil for some refiners but poses some challenges related to crude oil transportation infrastructure constraints and the types of crude oils produced. Second, after many years of generally increasing domestic consumption of petroleum products, consumption has fallen since 2005, resulting in a smaller domestic market for refiners. Third, two key environmental regulations— CAFE and GHG vehicle emission standards and the RFS—have likely recently contributed to declining consumption of petroleum fuels, and compliance with the RFS has increased costs for some refiners.

Increased Crude Oil Production Has Lowered Crude Oil Costs for Some Refiners

U.S. and Canadian crude oil production has increased in recent years, leading to lower crude oil costs for some refiners, according to several stakeholders we contacted. 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 companies that develop petroleum resources to extract 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 oil and natural gas to flow—have increased U.S. crude oil and natural gas production. As shown in figure 7, monthly domestic crude oil production has increased by over 55 percent through September 2013 compared with average production in 2008. According to EIA, increases in production in 2012 and 2013 were the largest annual increases since the beginning of U.S. commercial crude oil production in 1859. Much of the increase in crude oil production has been from shale and other formations, such as the Bakken in North Dakota and the Eagle Ford in Texas, according to EIA data. Similarly, crude oil production in Canada— the largest foreign supplier of crude oil to the United States—has also increased significantly in recent years. From 2005 through 2012, total Canadian crude oil production increased by 32 percent and U.S. imports from Canada increased almost 50 percent.

The rapid growth in U.S. and Canadian crude oil production has lowered the cost of crude oil for some domestic refiners that have the access and ability to process these crude oils. For example, West Texas Intermediate crude oil—a domestic crude oil used as a benchmark for pricing—was $17.60 per barrel less expensive in 2012 than Brent, an international benchmark crude oil from the European North Sea that was historically about the same price as West Texas Intermediate. Those refineries able to take advantage of these lower priced crude oils have benefited because crude oil costs are the largest cost for refiners. However, all refineries may not have been able to take advantage of these crude oils to the same extent for two key reasons:

Transportation infrastructure challenges. The development of domestic and Canadian crude oil production has created some challenges for U.S. crude oil transportation infrastructure because some of the growth in production has been in areas with limited transportation linkages to refining centers. 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 that time. According to DOE officials, this infrastructure was designed primarily to move crude oil from the South to the North, but emerging crude oil production centers in Western Canada, Texas, and North Dakota have strained the existing pipeline infrastructure. Though pipeline capacity has increased—investments increased pipeline capacity to deliver crude oil to a key Cushing, Oklahoma hub by about 815,000 barrels per day from 2010 through 2013—EIA reported that it has been inadequate. Because of these challenges, some refineries may not have been able to take full advantage of crude oil production increases or had to rely on other more expensive crude oil transportation options such as truck, rail, or barge. For example, two of the refineries we visited recently installed facilities to enable them to receive crude oil from North Dakota or Canada by rail. According to EIA data, while refinery receipts of crude oil by these methods of transportation is a small percentage of total receipts, they have increased 57 percent from 2011 to 2012. Infrastructure constraints have, according to EIA, contributed to discounted prices for some domestic crude oils.

Configuration constraints at refineries. Increasingly, the crude oil being produced in the United States and Canada has different characteristics from the crude oils that some domestic refineries are configured to use. Production of new domestic crude oil has tended to be light and sweet, whereas a portion of new Canadian production has been heavy and sour crude oils. To a certain extent, some refineries can use these crude oils, but some have invested in new equipment in order to do so. For example, representatives of one refiner told us they had invested over $2.2 billion in a project including a new coking unit at a refinery to refine heavier and more sour crude oil from Canada.

Domestic Consumption of Petroleum Products Has Declined

After decades of generally increasing domestic consumption of petroleum products, consumption has declined since 2005, resulting in a smaller domestic market for refiners, according to several stakeholders we contacted. Overall, consumption of gasoline, diesel, and other petroleum products in the United States increased from 1983 through 2005. In 2007, EIA projected that U.S. consumption would increase by nearly 30 percent between 2005 and 2030. As we reported in late 2007, trends in domestic refining capacity had not kept pace with consumption growth, though it was unclear whether and for how long that market tightness would continue. However, as shown in figure 8, domestic consumption of petroleum products overall peaked in 2005 at 20.8 million barrels per day, and it declined by 11 percent through 2012. Consumption of gasoline, diesel, and jet fuel peaked in 2007 and declined by over 8 percent through 2012. More recent data indicate that these trends may now be starting to shift, as EIA estimated that petroleum product consumption increased in the first 11 months of 2013 compared with the first 11 months of 2012.

According to several stakeholders we contacted and information we reviewed, a number of factors can affect consumption of petroleum products, including economic activity and crude oil and petroleum prices. For example, the recession of 2007 to 2009 reduced economic activity and demand for gasoline, and historically high gasoline prices have discouraged the use of gasoline. Stakeholders and information we reviewed also cited the effect of more stringent fuel economy standards and the RFS, which are discussed in the next section.

Several stakeholders told us that this broad shift from growing to falling consumption of petroleum products has affected the domestic refining industry because it has resulted in a smaller domestic market. The U.S. market is important for domestic refineries because U.S. refiners have historically primarily sold their products domestically. On average, the United States exported almost 1 million barrels per day of domestic petroleum products from 2000 through 2005—less than 6 percent of U.S. refinery production. As discussed below, the refining industry has shifted sales to export markets amid a declining domestic market.

Two Key Regulations Have Likely Contributed to Declining Fuel Consumption and Compliance with One Has Increased Some Refiners’ Costs

According to stakeholders and the information we reviewed, two recently strengthened key environmental regulations—the coordinated CAFE and GHG vehicle emission standards, and the RFS—have likely affected the refining industry by reducing the consumption of petroleum fuels, and compliance with the RFS has recently increased costs for some refiners, as well as other challenges. The other three key environmental regulations we reviewed have had minimal effects to date because they have either not yet been implemented or have generally not affected the industry in a major way, according to several stakeholders and information we reviewed.

CAFE and GHG Vehicle Emission Standards

According to information we reviewed and two stakeholders we contacted, CAFE and GHG vehicle emission standards have contributed to reductions in the consumption of petroleum fuels, but the extent is unclear. These standards aim to reduce oil consumption, and although they do not require changes at the refinery level, they can affect refineries indirectly by contributing to improvements in the overall efficiency of the vehicle fleet and, therefore, reducing fuels consumption. However, the National Academy of Sciences reported that it is difficult to isolate the effect of CAFE and GHG vehicle emissions standards from other factors that also affect consumption, such as higher fuel prices and changing driving habits.

Stakeholders had different views on the extent to which CAFE and GHG vehicle emission standards have affected consumption of petroleum products. We reported, in 2007, that CAFE standards—along with higher fuel prices and other factors—contributed to a reduction in transportation fuel consumption of 2.8 million barrels per day in 2002. CAFE standards for cars largely did not change from 1990 through 2010, but they were strengthened beginning with model year 2011. According to EPA and DOE officials, since the standards did not change until recently, CAFE and GHG vehicle emissions standards did not cause the shift from growing consumption to declining consumption discussed previously. Regarding the strengthened standards, EPA estimated in 2010 that vehicles were expected to save 1.3 billion gallons of gasoline in 2013 compared with model year 2011 standards. This is equivalent to about 1 percent of EIA’s projection of gasoline consumption in 2013. A stakeholder told us that the CAFE and GHG vehicle emissions standards have likely had a relatively large impact on petroleum demand declines in the past few years, but it is unclear how much declining demand overall can be attributed to these standards versus other factors such as the recent economic recession and higher fuel prices. On the other hand, EPA and DOE officials, and a refinery representative told us that the most recent changes to CAFE and GHG vehicle emissions standards have had a marginal effect on petroleum demand so far. DOE officials also told us that the impact of the standards has been limited because they affect new car sales, and there are a relatively small number of new vehicles in the overall fleet.

Several stakeholders we contacted and information we reviewed cited three main effects that the RFS has had on the domestic petroleum refining industry or individual refiners—compliance has increased costs, declining domestic consumption, and investment uncertainty. In addition, EPA has been late in issuing annual RFS standards, and several factors contribute to the delays.

RFS Has Had Three Main Effects Stakeholders we contacted and information we reviewed identified three main ways the RFS has affected U.S. petroleum refiners: (1) compliance has recently increased costs for some refiners, (2) required blending of renewable fuels has contributed to declining domestic consumption of petroleum-based transportation fuels, and (3) EPA’s delays in issuing annual RFS standards may have contributed to investment uncertainty for some refiners. First, compliance with the RFS has recently increased costs for some refiners, according to information we reviewed and several stakeholders we contacted. Under the RFS regulations, refiners and other obligated parties are required to ensure U.S. transportation fuels include certain amounts of renewable fuels. To comply, refiners generally have two options—they can purchase and blend renewable fuels themselves, or they can pay others to blend or use renewable fuels by purchasing credits. These credits can be freely traded, and prices for credits are established based on the market and generally reflect the stringency of requirements and the costs of incorporating additional renewable fuels into the transportation fuel system to comply with the RFS—if costs increase, credits prices would tend to increase as well. According to EIA, corn-based ethanol credit prices were low—between $0.01 and $0.05 per gallon between 2006 and much of 2012—because it was generally economical to blend up to or above the level required by the RFS. However, in 2013, prices for these credits increased to over $1.40 per gallon in July before declining to about $0.20 per gallon as of mid- November 2013.

Several stakeholders told us this increase in credit prices was primarily due to RFS requirements exceeding the capability of the transportation fuel infrastructure to distribute and the fleet of vehicles to use renewable fuels, referred to as the “blend wall.” A refiner we spoke with also attributed the decline in credit prices in the second half of 2013 to EPA’s statements expressing its desire to address the blend wall. We have previously reported on the blend wall and other challenges to the increasing use of renewable fuels.

While the RFS applies to all refiners in the same way, the effect of the rise in credit prices may depend on each refiner’s situation. However, in comments to this report EPA stated that refiners experience the same compliance costs. As a result of higher costs, several stakeholders told us refiners could reduce production, produce more jet fuel, which is not subject to RFS requirements, or increase exports to nations where the RFS does not apply. (See app. III for more information about the blend wall, RFS credits, and views on how they have affected U.S. refiners.)

Second, the RFS has contributed to the declining domestic consumption of petroleum-based transportation fuels. Under the RFS regulation, refiners and other obligated parties are required to ensure U.S. transportation fuels include certain amounts of renewable fuels. As a result, refiners and other industry participants have blended increasing amounts of renewable fuels. For example, consumption of ethanol has increased almost 8-fold since 2000, from 1.7 billion gallons in 2000 to 12.9 billion gallons in 2012. According to EIA, increased ethanol use since 2007 displaced over 4 billion gallons of petroleum-based gasoline, or about 3 percent of gasoline consumption in 2012. As discussed previously, decreases in consumption affect refiners by decreasing the size of the domestic market. Since the RFS was established in light of concerns about the nation’s dependence on imported crude oil, decreased consumption of petroleum products may further some of the objectives of the RFS.

Third, the RFS has contributed to investment uncertainty for refiners according to several stakeholders because EPA has not issued annual RFS standards on time since 2009. Beginning in calendar year 2009 and through calendar year 2022, EPA is required to set annual blending percentages for total renewable fuels, advanced biofuels, cellulosic biofuels, and biomass-based diesel fuels by November 30 of the preceding calendar year. However, as shown in figure 9, EPA has missed the statutory deadline to set annual percentages since 2009. Most recently, EPA issued 2013 standards in August 2013—over 8 months late—and has not issued the 2014 standards. EPA proposed the 2014 standards on November 29, 2013, and EPA officials told us that they plan to finalize the standards in Spring 2014. The RFS compliance period—the time during which refiners and other parties incur obligations under RFS and can take steps to incorporate additional renewable fuels to create credits for compliance—is set by statute to be a full calendar year, and delays do not change this compliance period. As a result, when the RFS standards are issued late, the industry has less time to plan and budget effectively. Several representatives of refiners told us that delays in issuing annual RFS standards increase uncertainty for refiners and renewable fuel producers, making it more difficult to make long-term planning decisions. One refining company representative told us that the company has reduced capital investments due to uncertainty related to the RFS. In contrast, EPA officials told us that there is no indication that delays have caused significant problems for refiners. They also noted that delays could actually make annual standards more robust since EPA then has more data upon which to base decisions.

Regulatory Development Processes Contribute to EPA Delays in Issuing RFS Standards EPA officials told us that delays in issuing RFS standards have largely been due to the length of the regulatory development process, which includes interagency and public reviews. Under the interagency review process, EPA is to follow certain procedures before publishing proposed or final regulations that establish annual RFS standards, including submitting draft proposed and final regulations to the Office of Management and Budget (OMB), which coordinates review of the draft regulations by other agencies, as well as conducting its own review. The interagency review process is to ensure that regulations are consistent with the President’s priorities, among other things, and that decisions made by one agency do not conflict with the policies or actions taken or planned by another. Under the public review process, EPA must publish a proposed standard in the Federal Register, provide the public with the opportunity to review and comment on the proposal, and address comments received before finalizing the regulation. According to EPA officials, the interagency and public review processes can be time consuming because the RFS standards involve complex and controversial issues and balance competing agricultural, energy, and environmental policy interests.

In 2009, we recommended that EPA and other agencies track their performance for developing significant regulations against targeted milestones to identify opportunities for improvement. We found that monitoring actual versus estimated performance could help agency managers identify steps in the process that account for substantial time and provide information necessary to evaluate whether time was well spent. In this regard, EPA stated in comments to our 2009 report that it uses an agency-wide Action Development Process that tracks 14 milestones as it develops proposed rules and additional milestones in developing final regulations. For example, EPA tracks when its senior management approves of a document describing the scope of the regulation and the analytical work necessary to develop it, known as the detailed analytic blueprint. In comments to our 2009 report, EPA stated that it used an internal tracking system along with additional information to develop regulatory management reports to EPA managers and executives. EPA stated at the time that this process helps management identify regulations that are off-track so that corrective steps can be taken to expedite their completion. EPA officials told us that they develop RFS regulations using the same procedures used for developing all EPA regulations. However, even with these systems, EPA has not met its statutory deadlines under the RFS in the five annual standards since 2009. EPA has not conducted a systematic review of its experience issuing RFS regulations to identify the underlying causes of repeated delays and has not identified changes in its approach that may help to avoid these delays in the future. Without such analyses and a plan to address the underlying causes of the delays, EPA risks repeating them.

The other key regulations that we reviewed—Tier 3 standards, stationary source GHG requirements, and LCFS—have had minimal effects to date because these regulations either have not yet been implemented (Tier 3 standards) or, with respect to the other two, have not affected industry operations or costs in a major way, according to stakeholders and information we reviewed. Specifically:

Tier 3 standards. Tier 3 standards were proposed on May 21, 2013, and EPA announced final standards on March 3, 2014; therefore, they have had not had a direct effect on industry to date.

Stationary source GHG requirements. Representatives of two refiners told us that stationary source GHG requirements have been burdensome to refiners; however, several other stakeholders told us they have not had a major effect, and EPA officials told us they were aware of only three refineries that have received major source GHG permits since the GHG permitting program was implemented in 2011. A refining company representative expressed concerns to us about the lengthy permitting process to authorize GHG emission increases. However, stationary source GHG requirements do not apply unless an existing refining facility proposes a major modification or a new refinery is proposed for construction. An EPA official said that, in most cases, best available control technologies selected to comply with GHG requirements for refining facilities involve energy efficiency improvement measures that could help refiners reduce fuel consumption and save money. Further, EPA officials also explained that, in some cases, delays can occur when the refinery applicant has not provided EPA with the proper information to proceed with processing the permit. The Clean Air Act requires that EPA approve or deny such permits within 12 months of receiving a complete application.

LCFS. CARB, the entity responsible for implementing LCFS, said the regulation has had a modest effect to date—increasing fuel prices by about $0.01 per gallon. LCFS is the subject of several ongoing lawsuits, which resulted in a 4-month delay in some regulatory activities and uncertainty about the status of the regulation. According to a study conducted by a consultant on behalf of industry, the ongoing legal challenge to LCFS is creating uncertainty that discourages new investments by industry. A refining industry trade association representative told us many refiners that previously invested in new components for their California facilities to process heavy crude oils may not be able to make an adequate return on investment since the LCFS disincentivizes the use of carbon intensive heavy crude oils. However, a CARB official noted that LCFS does not specifically prohibit any crude oil from being processed in California refineries, but rather it ensures that the LCFS’ goal to reduce carbon intensity in transportation fuels is not affected by increased use of higher carbon intensity crude oils. Nevertheless, California refiners have thus far been able to comply with LCFS requirements by blending lower carbon intensive renewable fuels—such as Brazilian sugar-cane ethanol—or purchasing carbon credits as an alternative method of compliance.

Industry Outlook Depends on a Number of Factors

Stakeholders we contacted and information we reviewed generally suggest that the outlook of the U.S. refining industry depends on a number of factors, in particular: (1) future domestic consumption of petroleum products; (2) the extent to which key environmental regulations raise costs for domestic refiners; and (3) the extent to which domestic refiners will be able to export and compete in international markets.

Uncertain Future Domestic Consumption

The outlook of the U.S. refining industry depends on future domestic consumption of petroleum products, which is uncertain, according to stakeholders we contacted and information we reviewed. As discussed above, domestic petroleum product consumption declined by 11 percent from 2005 through 2012, and forecasts we reviewed project consumption of three major petroleum products—gasoline, diesel, and jet fuel—will be stable to slightly increasing through 2020, but not returning to high levels of the past. Most of the scenarios in forecasts we reviewed from IHS and EIA project total consumption of gasoline, diesel, and jet fuel to increase slightly by 2020, with projections ranging from a decline of 2 percent to an increase of 7 percent compared with 2012 consumption. Expectations differ somewhat by fuel, with all EIA scenarios projecting gasoline consumption to decline or remain stable and diesel and jet fuel consumption to increase from 2012 to 2020 (see fig. 10). IHS projects an increase in the consumption of both gasoline and diesel, with more robust growth projected for diesel. Scenarios in the forecasts we reviewed generally project consumption to decline after 2020.

Forecasts indicate that the level of future domestic consumption—the size of the domestic market for petroleum products—may affect future U.S. refinery production. In higher consumption scenarios, EIA’s projections suggest higher refinery production than in scenarios with lower domestic consumption. Specifically, EIA projects that inputs to refineries—which track trends in refinery production—in 2020 would be about 1 million barrels per day higher in scenarios with higher domestic consumption—a difference of about 7 percent of 2012 inputs. This difference is equivalent to about eight average-size U.S. refineries.

Several stakeholders we contacted and information we reviewed highlighted various factors that can affect future domestic consumption levels and thereby the size of the largest market for the production of U.S. refineries, including the following:

Economic growth. Faster economic growth tends to increase consumption, and EIA’s forecast scenario with higher economic growth assumptions projects greater future consumption of petroleum products than a scenario with low economic growth.

Crude oil and petroleum product prices. Higher prices for crude oil and petroleum products tend to decrease consumption. For example, of the forecast scenarios we reviewed, the scenario that assumes high future oil prices projects lower domestic consumption of petroleum products.

Shifts in consumer behavior and demographic trends. Changes in consumer behavior, such as reduced driving, along with demographic trends, such as an aging population and fewer young people with driving licenses, may reduce future consumption, according to EIA.

Key regulations. Three of the key regulations we reviewed—CAFE and GHG vehicle emission standards, RFS, and LCFS—are expected to reduce domestic consumption of petroleum products in the future according to information we reviewed, though it is uncertain by how much. CAFE and GHG vehicle emission standards will require more efficient vehicles in the future, which may reduce future consumption of fuels. EPA estimated that the model year 2012-2025 standards are projected to reduce U.S. consumption of crude oil by 2.2 million barrels per day by 2025, equivalent to almost 15 percent of crude oil used by refineries in 2012. Similarly, under the RFS statute, unless waived by EPA, renewable fuels blending is required to double by 2022, which EPA estimated would reduce gasoline and diesel demand by 13.6 billion gallons, equivalent to about 10 percent of consumption in 2012. Furthermore, CARB projected that the LCFS would help decrease future gasoline consumption in California. However, the extent to which these regulations will reduce future consumption depends on actions by regulators and market and other developments. For example, as discussed above, EPA has proposed to reduce renewable fuel requirements for 2014 due to an inadequate supply in light of the blend wall and other issues. EPA stated that the framework it applied to determine the proposed percentage standards could be appropriate for later years. Therefore, the potential for RFS to reduce petroleum-based fuel consumption will depend on the percentages finalized by EPA, which, in turn will depend on the development of advanced renewable fuel sources and market infrastructure and could be affected by legal challenges, as well as any legislative action to modify the RFS.

Costs of Key Regulations

Stakeholders we contacted and information we reviewed generally suggest that the outlook of the U.S. refining industry will also depend on the extent to which some key regulations—RFS, Tier 3, stationary source GHG requirements, and LCFS—increase costs for refiners. In general, increasing costs for refiners may be absorbed by refiners themselves (i.e., by reducing their profits), be passed on to consumers through higher product prices, or both. The requirements on domestic refiners from the key regulations we reviewed generally are expected to collectively have a greater effect in the future, for example, by affecting more refiners (such as the stationary source GHG requirements to the extent that more refineries make modifications over time), or becoming more stringent in the future (such as the RFS), potentially increasing costs for refiners. In addition, several stakeholders told us that the uncertainty surrounding these regulations—and what costs they will impose—can affect the market climate within which refiners and other market participants make investment decisions such as whether to expand a refinery’s ability to process different crude oils, or to build new advanced biofuel processing facilities. Such uncertainty can discourage investments in the industry overall.

RFS. RFS may increase costs for some refiners depending on the percentages of renewable fuels required by EPA and on other factors. As discussed previously, costs for some refiners to comply with RFS rose in 2013, which some of the stakeholders we contacted attributed to concerns about the blend wall. The blend wall may remain a concern into the future because statutory renewable fuel blending requirements continue to increase—they more than double from 2012 to 2022—while the consumption of petroleum products is expected to increase only slightly. Several stakeholders told us that the effect of the RFS depends in particular on how EPA addresses the blend wall in the annual standards it issues in the future. Furthermore, EPA’s timeliness in issuing the standards could also affect costs to the extent that delays affect the supply of renewable fuels, RIN prices, and refiners’ ability to plan and budget effectively for compliance. Several representatives of refiners told us that future delays would contribute to investment uncertainty and higher costs for refiners. EPA officials said that they did not believe delays have affected market participants, and that the market for RFS credits has provided flexibility to refiners and other obligated parties. The extent to which the RFS increases costs in the future could also be affected by the outcome of any relevant litigation and of legislative proposals to change the RFS or how EPA implements it.

Tier 3. According to EPA, to meet the Tier 3 fuel sulfur standards, refiners would need to install or upgrade hydrotreating capacity or take other steps to reduce the sulfur content in fuels, which will likely increase industry-wide costs. EPA projected that 67 out of 108 refineries would modify or purchase some equipment, and the capital costs of installing this equipment and operating costs to run it would average about $0.0065 per gallon, and total $804 million in 2017. An industry study of the Tier 3 proposal estimated that the regulation would increase costs by up to $0.09 per gallon for the highest-cost refinery, and several refinery representatives told us that Tier 3 would increase their costs. The extent to which the refining industry will be affected by Tier 3 standards would have been greater had EPA decreased the per-gallon maximum allowable sulfur levels in gasoline—known as caps. In the final standards, EPA maintained the current 80 ppm cap, but had sought comment on whether it should decrease the cap to as low as 20 ppm. A stakeholder told us that Tier 3 would be manageable if EPA maintained the current caps, but far more difficult if the caps were lowered. One study we reviewed estimated that industry could incur additional capital expenses to achieve lower sulfur caps, ranging from $2 billion to over $6 billion dollars depending on the sulfur cap level in the final standards.

Stationary source GHG requirements. Several of the refining industry representatives we contacted expressed concerns that stationary source GHG requirements could become more stringent in the future. The current permitting framework is a case-by-case determination that takes into account costs, among other factors, and places no requirement on existing refineries unless they undertake a major modification. However, EPA entered a settlement in which the agency agreed to develop national performance standards—called New Source Performance Standards—for GHG emissions from new and modified refineries, and GHG emissions guidelines for certain facilities at existing refineries. Although EPA has no current schedule to issue these standards, EPA committed in its settlement to issue them, and several stakeholders expressed concern that future standards could impose more strict controls involving higher costs at refineries. A stakeholder told us that until EPA clarifies its approach for NSPS, many refiners will be reluctant to make certain investments in their refineries out of concerns that their investments may be unprofitable given future requirements. In addition, some companies may preemptively factor in the cost of emissions control technologies in their investment analyses.

LCFS. Two stakeholders and a refining industry trade association told us that California refiners could face higher costs or compliance challenges unless CARB adjusts future low carbon fuel requirements. CARB has estimated that the cost of LCFS on gasoline and gasoline- substitute fuels is likely to range between an increase of $0.09 per gallon, and a decrease of $0.13 per gallon by 2020. However, an industry study estimated that the LCFS could cost the refining industry an average of $0.70 per gallon by 2020. The study also projected that 5 to 7 of 14 California refineries could cease production by 2020, and the LCFS could raise other compliance challenges because of insufficient supplies or consumer uptake of cellulosic, Brazilian sugar- cane ethanol, and other low carbon intensity fuels or vehicle technologies. CARB officials told us that if it proves more difficult than expected to meet LCFS requirements, CARB could introduce cost containment provisions to increase the availability of credits, such as through a “safety valve” to release additional credits at a set price, or by providing extra credits to certain compliance approaches. Stakeholder told us that the decisions CARB makes with respect to the LCFS may affect California refiners’ ability to stay in business and compete with refiners in other states and countries.

Extent to Which Refiners Can Export and Compete in Foreign Markets

While the domestic refining industry has increasingly relied on export markets, stakeholders and forecasts we reviewed indicate that the industry’s future competitiveness is uncertain and that foreign markets present both challenges and opportunities for U.S. refiners.

Refiners Projected to Continue to Rely on Foreign Markets

Forecasts and data we reviewed from EIA and IEA suggest that future domestic refinery production levels may depend on exports of petroleum products. Petroleum products are increasingly global commodities, and EIA data indicate that as domestic consumption has declined, refiners have looked to foreign markets to sell products. Since 1949, the United States had been a net importer of petroleum products, but this long-term trend reversed in 2011 when the United States became a net exporter of total petroleum products. According to EIA data, the United States recently exported more petroleum products than other leading exporters, including Russia, India, and Singapore, and petroleum product exports have represented an increasing share of U.S. refinery production. Exports of petroleum products represented 7 percent of refinery production in 2007 but increased to 17 percent in 2012. Major markets for U.S. exports include Central and South America, Mexico, and Europe, to which U.S. refiners sent nearly all diesel exports in 2012. The United States exports more diesel than gasoline, though U.S. refiners have been increasing exports of gasoline to Central and South America and Africa.

Forecasts that we reviewed generally project that exports will remain strong. According to most of the EIA and IHS forecasts we reviewed, exports of petroleum products are expected to increase until 2015, but the extent of the increase is unclear. As shown in figure 11, EIA scenarios project export levels from 2.6 to 3.4 million barrels per day by 2020, a relatively wide range. Even the lowest projection for petroleum product exports in 2020 is above 2010 levels, indicating a general expectation that exports will remain strong.

The extent to which domestic refiners are able to export their products will depend on the competitiveness of domestic refiners compared with foreign refiners, and stakeholders we contacted and information we reviewed highlighted both challenges that may inhibit competitiveness and opportunities that may increase it in the future. To sell products abroad, refiners need to be competitive—that is, they must be able to supply fuels that foreign purchasers want to buy at prices that are attractive. Stakeholders and information we reviewed suggest that various factors may affect the U.S. refining industry’s future competitiveness, including: (1) the balance between global refining capacity and global demand for petroleum products, (2) costs associated with environmental regulations, (3) exports to nations with stringent fuel standards, and (4) increasing domestic and Canadian crude oil production. More specifically:

Balance between global refining capacity and demand. IEA data indicate that competition from foreign refiners may increase as global refining capacity is projected to exceed global consumption, creating an imbalance between global supply and demand that may affect U.S. refiners. According to IEA, global consumption of petroleum products was about 78.9 million barrels per day in 2012 and is projected to grow an additional 6 million barrels per day by 2020—with growth concentrated in Asia and the Middle East and consumption declining in Europe. But IEA projects refining capacity may grow even faster, resulting in excess capacity (refining capacity beyond that needed to meet consumption) of nearly 15.5 million barrels per day by 2020, in contrast to an estimated 4.8 million barrels per day of excess capacity in 2012. Excess refining capacity is likely to result in greater competition in foreign markets overall, and some regions may present particular challenges. A large share of the new capacity is expected in China, India, and the Middle East, and representatives of two refiners indicated concern that capacity additions in some of those regions may present competition for U.S. refiners. Several other stakeholders were optimistic about domestic refiners’ ability to compete in the future. According to IEA, capacity additions in China and India are intended to keep pace with growing consumption in those regions, but new Middle Eastern refineries are intended to be export facilities and may present increased competition to U.S. refiners.

Costs associated with environmental regulations. As discussed above, the key environmental regulations we reviewed could collectively impose additional costs on the domestic refining industry. These costs could affect the industry’s ability to compete internationally to the extent that foreign refiners do not face similar costs. In addition, regulatory uncertainty can affect refiners’ competitiveness if it inhibits the industry from making investments that would otherwise lower costs. Not all of the key regulations we reviewed would be expected to affect the industry’s competitiveness. In particular, CAFE and GHG vehicle standards do not impose requirements on refiners. In addition, although RFS and Tier 3 standards could impose requirements with potential associated costs on some refiners, they would not apply to exported fuels—they apply only to fuels sold in the United States regardless of where they are produced.

Potential for increased exports to nations with stringent fuel standards. In general, U.S. refineries are among the most sophisticated in the world and have generally been optimized to produce large proportions of cleaner-burning gasoline. IEA has pointed out that refiners in many parts of the world face challenges producing fuels that meet high product quality and environmental performance standards. Therefore, some U.S. refiners may benefit from any trend toward higher quality and more stringent environmental performance standards. In this regard, actions refiners may take to reduce gasoline sulfur to comply with proposed Tier 3 standards could enable them to export to markets—such as Japan and much of Europe—that already require low sulfur gasoline. On the other hand, representatives of a refiner pointed out that refiners could undertake such investments on their own—without Tier 3—if such exports were sufficiently economically attractive.

Increasing domestic and Canadian crude oil production. As discussed above, increasing U.S. and Canadian crude oil production has led to lower cost crude oil for some refiners, providing a competitive advantage. All of the forecast scenarios we reviewed from EIA, IEA, and IHS anticipate increases in U.S. crude oil production, but the projections are uncertain and vary widely—from 6.8 to 9.8 million barrels per day in 2020 as shown in figure 12. Projections are revised each year, and expectations for U.S. crude oil production in 2020 have increased in more recent forecasts. For example, the reference scenario in EIA’s most recent forecast projects domestic crude oil production to approach a historical high of 9.6 million barrels per day in 2020, higher than the reference scenario from the prior year. Canadian crude oil production—which accounted for about 16 percent of the crude oil used by U.S. refineries in 2012—is expected to increase as well: the reference scenario in EIA’s international forecast projects that Canadian petroleum liquids production will increase more than 30 percent from 2012 levels, reaching approximately 5 million barrels per day in 2020. The extent of the increase in future crude oil production can have implications for future petroleum product exports. For example, EIA’s scenario that assumes more domestic crude oil and natural gas resources projects higher export levels than a scenario that assumes low crude oil and natural gas resources. Several stakeholders told us that various issues could mitigate U.S. refiners’ ability to take advantage of growing crude oil supplies. In particular, it is unclear whether planned expansions in pipelines and rail transportation will keep pace with growing production, and these infrastructure expansions could be affected by regulatory actions to address pipeline and rail safety. Similarly, several stakeholders told us that potential future increases in crude oil exports, which are currently minimal, could put pressure on regional crude oil prices, reducing the price advantage of U.S. refiners.

Conclusions

The domestic petroleum refining industry has been and is expected to continue to be affected by several profound changes. Some of these changes, such as the growth in crude oil production in the United States and Canada, are reshaping the industry and creating new business opportunities. To take advantage of some of these opportunities, refiners and other market participants will need to invest—to upgrade refineries to be able to process different crude oils or to build pipelines or rail connections to move more crude oil from production to refining centers. Uncertainty can affect the market climate within which these investment decisions will be made. In this context, EPA’s timeliness in issuing annual percentage standards under the RFS is important to help inform the investment decisions of the refining industry. In issuing annual percentage standards, EPA may waive the statutory volumes in whole or in part according to statutory criteria, which EPA has identified as potentially factoring in the blend wall, market developments, and other issues. However, EPA has missed the annual deadline for issuing annual standards under the RFS in most years. EPA has some systems in place to monitor and evaluate progress in developing regulations, which could provide useful information for understanding delays in RFS. But EPA has not identified the underlying causes of delays, and it has not developed a plan to address delays and, therefore, risks repeating delays. EPA delays in issuing RFS standards are important because delays do not change refiners’ compliance periods accordingly and they therefore create uncertainty in the marketplace, potentially harming investment. Uncertainty among refiners, renewable fuel producers, and other market participants about how EPA will address the blend wall, which can be exacerbated by the prospect of litigation, can affect investment decisions and ultimately the availability and prices of the fuels they produce.

Recommendations for Executive Action

To improve EPA’s ability to meet the annual statutory deadline for issuing annual RFS standards, we recommend that the Administrator of the EPA take the following two actions:

Assess past experience to identify the underlying causes of delays in issuing annual RFS standards.

Develop and implement a plan to address the causes of delays and help ensure RFS annual standards are issued on time.

Agency Comments and Our Evaluation

We provided drafts of this report to DOE, DOT, and EPA for review and comment. The three agencies provided technical comments on early or final drafts, which we incorporated as appropriate.

EPA also provided a letter in which it generally agreed with our findings and recommendations and clarified three topics discussed in the report.

First, regarding the effects of compliance with RFS, EPA asserted that refiners experience the same compliance costs regardless of whether they are fully integrated, with blending capabilities, or merchant refiners that purchase credits for compliance. Based on our work, we found the views of several stakeholders differed from EPA's. For example, in a 2011 study, DOE identified the degree to which a small refiner can actively blend production with renewable fuels is a large component that could contribute to economic hardship from compliance with the RFS. In theory, market-based compliance systems—such as the RFS credit system—provide incentives for market participants to make decisions that would tend to equalize additional compliance costs over time. However, there can be physical infrastructure or contractual constraints, among various other factors, that could result in different outcomes in the short run. We added additional language to explain EPA's views in the report and in Appendix III.

Second, regarding the time-frame for RFS compliance, EPA stated that the RFS compliance deadline—the date by which refiners and other obligated parties must demonstrate compliance to EPA—is established through implementing regulations, not statute. EPA stated that it adjusted the 2013 deadline to provide additional time to demonstrate compliance. We acknowledge that EPA can extend the compliance deadline. However, the compliance period refers to the time during which refiners and other parties incur obligations under RFS and can take steps to incorporate additional renewable fuels to generate credits for compliance. This period is set by statute to be a full calendar year. We clarified language in the report to acknowledge EPA's ability to adjust the compliance deadline, essentially providing additional time for obligated parties to purchase credits, and its inability to adjust the compliance period.

Third, regarding Tier 3 standards, EPA announced the final standards while our draft was with the agency for comment. EPA stated that the final Tier 3 program is very similar to what it proposed, though EPA made some changes based on public input and updated its analyses. EPA provided technical comments to incorporate information from the final rule which we incorporated into the report, as appropriate. However, we were not able to obtain stakeholder and other views on the final Tier 3 rule for this report. See appendix IV for EPA’s letter.

As agreed with your offices, 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 and to the Secretaries of Energy and Transportation and the Administrator of the EPA. 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 V.

Appendix I: Scope and Methodology

This report provides information on the domestic petroleum refining industry and its market and regulatory environment. Specifically, it addresses what is known about (1) major changes—including key environmental regulations—that have recently affected the domestic petroleum refining industry and (2) major factors that may affect the future of the domestic petroleum refining industry—including its production, profitability, and competitiveness in foreign markets.

To provide information on major changes that have affected the domestic petroleum refining industry and the future of the industry, we reviewed information including the following: studies by federal agencies and consultants, company financial regulatory filings, and proposed and final regulations and regulatory impact analyses.

To identify studies and other literature, we conducted searches of various databases, such as ProQuest and PolicyFile, for studies since published 2009. We also asked agency officials and other stakeholders we contacted to recommend studies.

Based on our research and information from stakeholders, we identified five key regulations that were recently strengthened or proposed: (1) the Environmental Protection Agency’s (EPA) Renewable Fuels Standard regulations, (2) the Department of Transportation’s Corporate Average Fuel Economy and EPA’s greenhouse gas vehicle emission standards; (3) EPA’s Tier 3 Motor Vehicle Emission and Fuel Standards; (4) EPA’s stationary source greenhouse gas requirements; and (5) the state of California’s Low Carbon Fuel Standard. We reviewed agency regulatory impact assessments and industry and other studies on the effect of these regulations on industry. Other regulations may also affect the industry.

We also summarized the results of semistructured interviews with a nonprobability sample of 32 stakeholders. (See app. II for a list of these stakeholders.) Stakeholders included representatives from refining companies, environmental organizations, consultants, and officials from federal and state agencies. We also visited several refineries of selected refining companies. We selected these stakeholders to represent broad and differing perspectives on these issues based on recommendations from agencies and industry associations, along with other information. For example, to select refiners, we considered, among other factors, the size and location of their refineries, and whether they were vertically integrated or merchant refiners. When possible, we used a standard set of questions in interviewing stakeholders, including questions about the effect of the key regulations we reviewed. However, as needed, we also sought perspectives on additional questions tailored to these stakeholders’ expertise and sought opinions from stakeholders on key issues, such as their views on the potential effects of exports on industry. Because we used a nonprobability sample, the views of these stakeholders are not generalizable to all potential stakeholders, but they provide illustrative examples of the range of views. Similarly, the conditions at the refineries we visited are not generalizable to all refineries. The stakeholder views we summarize were not necessarily supported by all types of stakeholders, though we identify differing views where appropriate. Stakeholders and information we reviewed identified a number of changes that have affected the industry and a number of factors that may affect its future, and we report on those that were most often cited.

To illustrate major changes over time and to describe the domestic petroleum refining industry, we summarized historical data from the Energy Information Administration (EIA) regarding such issues as capacity and location of refineries, crude oil production, and consumption of petroleum products. To assess the reliability of EIA data, we took several steps including reviewing documentation, interviewing EIA staff, and consulting with stakeholders. We determined the EIA data to be sufficiently reliable for the purposes of this report.

To provide information about the future of the domestic petroleum refining industry and major factors that could affect it, we also reviewed forecasts from EIA, the International Energy Agency (IEA), and IHS, and summarized projections through 2020 under different scenarios. We selected these forecasts because they made projections through 2020, contained information broadly relevant to our report, covered multiple scenarios or offered a counterpoint scenario, and contained well- documented discussions of methodologies used and assumptions made.

While forecasts are subject to inherent uncertainties, we found these forecasts to be reasonable for describing a range of views about potential conditions of the domestic refining industry and major factors that will help determine these conditions. We reviewed and compiled data from relevant scenarios and compared them where appropriate. Specifically, we reviewed all 27 scenarios in EIA’s 2013 forecast, the reference scenario in EIA’s 2014 initial forecast, and IHS’s forecast, and, in particular, highlight the scenarios representing the highest and lowest projection of gasoline, diesel, and jet fuel consumption; petroleum product exports; and crude oil production. We identified some differences in the metrics reported in the four forecasts and did not make direct comparisons in these instances.

We conducted this performance audit from November 2012 to March 2014 in accordance with generally accepted government auditing standards. Those standards require that we plan and perform the audit to obtain sufficient, appropriate evidence to provide a reasonable basis for our findings and conclusions based on our audit objectives. We believe that the evidence obtained provides a reasonable basis for our findings and conclusions based on our audit objectives.

Appendix II: List of Stakeholders

Federal Agencies

Refiners

Other

Appendix III: Further Information Regarding the Renewable Fuel Standard, Compliance Credits, and the Blend Wall

To demonstrate compliance with the Environmental Protection Agency’s (EPA) annual blending requirements under the Renewable Fuel Standard (RFS), refiners use renewable identification numbers (RIN), which we refer to in this report as credits. A RIN is a unique 38-character code that renewable fuel producers and importers assign to each gallon of renewable fuel produced or imported. To demonstrate compliance with the RFS, refiners and importers must provide sufficient RINs for the volume of gasoline and diesel they produce for use in the contiguous United States and Hawaii. For example, to comply with the 2013 total renewable fuels standard requiring that renewable fuels compose at least 9.74 percent of gasoline and diesel, a refiner selling 100 million gallons of gasoline would have to provide 9.74 million total RINs to EPA. Refiners can obtain RINs by purchasing and blending renewable fuels themselves, or they can purchase RINs from renewable fuel producers, importers, blenders, other refiners, or other RIN-holding entities. RINs are valid for the calendar year in which they were generated, and up to 20 percent of a year’s standard can be met with RINs from the previous year. Refiners and other obligated parties with more RINs than needed to meet the year’s blending standard can hold them for use in the following year or sell them to another party that needs additional RINs to comply with the blending standard.

Prices for RINs reflect the cost of renewable fuels compared with the petroleum fuels they displace, the stringency of annual blending percentage standards, and other factors, and have varied over time. According to the Energy Information Administration (EIA), between 2006 and much of 2012, corn-based ethanol RIN prices were low—between $0.01 and $0.05 per gallon—because it was generally economical to blend up to or above the level required by the RFS. However, RIN prices for corn-based ethanol increased to over $1.40 per gallon in July 2013. Several stakeholders told us this increase in RIN prices was primarily due to RFS requirements exceeding the capability of the transportation fuel infrastructure to distribute and the fleet of vehicles to use renewable fuels, referred to as the “blend wall.” EPA officials told us that high corn prices, which made ethanol more expensive relative to gasoline, also contributed to higher RIN prices during this period. These RIN prices have since come down to about $0.20 per gallon as of mid-November 2013. A refiner attributed this decline to EPA’s statements expressing its desire to address the blend wall.

The blend wall exists because blending more than 10 percent ethanol with gasoline (called E10) is affected by constraints such as the limited availability of vehicles that can use higher ethanol blends. In addition, higher ethanol blends are less widely available than E10 and must be priced at a discount to encourage greater consumption, according to EIA. EPA officials recently said the blend wall would be reached in 2014 when about 13.2 billion gallons of E10 could be consumed. Blending additional renewable fuels can be difficult and costly once the blend wall is reached because significant volumes of non-ethanol renewable fuels must be available, consumers must be encouraged to purchase additional higher blends of ethanol, and other market participants must develop the infrastructure to deliver those fuels.

Compliance with the RFS has recently increased costs for some refiners, according to information we reviewed and several stakeholders we contacted. While the RFS applies to all refiners in the same way, effects of rising or falling RIN prices may vary depending on each refiner’s situation. For example, those refiners that have incorporated renewable fuel blending into their operations may have benefited from the rising prices relative to those refiners that are less well positioned. According to several stakeholders, RFS compliance has been most difficult for refiners with less of a retail presence, known as merchant refiners, because they do not blend their own fuel and must purchase RINs from others, increasing their cost of compliance. On the other hand, some industry participants may be relatively advantaged when the price of RINs rises. For example, an ExxonMobil official said that RIN costs did not have a significant impact on the company’s financial performance during the second quarter of 2013 because ExxonMobil meets the majority of its obligation by blending its renewable fuels itself.

EPA officials told us, however, that the RFS program affects all refiners equally because obligations are the same regardless of whether refiners blend renewable fuels themselves or purchase RINs. In particular, EPA stated that refiners experience the same costs. If a company generates its own RINs, there is a cost associated with doing so, namely the cost for the renewable fuel compared to the petroleum fuel it displaces.

Appendix IV: Comments from the Environmental Protection Agency

Appendix V: GAO Contact and Staff Acknowledgments

GAO Contact

Staff Acknowledgments

In addition to the individual named above, Christine Kehr (Assistant Director), Elizabeth Beardsley, Catherine Bombico, Keya Chateauneuf, Nirmal Chaudhary, Quindi Franco, Cindy Gilbert, Katharine Kairys, Michael Kendix, Armetha Liles, and Alison O’Neill made key contributions to this report.

Related GAO Products

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Biofuels: Challenges to the Transportation, Sale, and Use of Intermediate Ethanol Blends. GAO-11-513. Washington, D.C.: June 3, 2011.

Vehicle Fuel Economy: NHTSA and EPA’s Partnership for Setting Fuel Economy and Greenhouse Gas Emissions Standards Improved Analysis and Should Be Maintained. GAO-10-336. Washington, D.C.: February 25, 2010.

Energy-Water Nexus: Many Uncertainties Remain about National and Regional Effects of Increased Biofuel Production on Water Resources. GAO-10-116. Washington, D.C.: November 30, 2009.

Energy Markets: Estimates of the Effects of Mergers and Market Concentration on Wholesale Gasoline Prices. GAO-09-659. Washington, D.C.: June 12, 2009.

Biofuels: Potential Effects and Challenges of Required Increases in Production and Use. GAO-09-446. Washington, D.C.: August 25, 2009.

Federal Rulemaking: Improvements Needed to Monitoring and Evaluation of Rules Development as Well as to the Transparency of OMB Regulatory Reviews. GAO-09-205. Washington, D.C.: April 20, 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.

Vehicle Fuel Economy: Reforming Fuel Economy Standards Could Help Reduce Oil Consumption by Cars and Light Trucks, and Other Options Could Complement These Standards. GAO-07-921. Washington, D.C.: August 2, 2007.

Motor Fuels: Understanding the Factors That Influence the Retail Price of Gasoline. GAO-05-525SP. Washington, D.C.: May 2, 2005.