Petroleum Refining: Industry's Outlook Depends on Market Changes and Key Environmental Regulations
Published: 2014-03-14T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: The U.S. petroleum refining industry—the largest refining industry in the world—experienced a period of high product prices and industry profits from the early 2000s through about 2007. Since the recession of 2007 to 2009, the industry has been in transition.
Federal and state agencies regulate petroleum refining and the use of petroleum products to protect human health and the environment, as well as for other purposes. EPA, DOT, and California recently proposed or strengthened five key regulations, including EPA and DOT's coordinated fuel economy and GHG vehicle emission standards, and EPA's RFS, which has required that refiners and others ensure transportation fuels include increasing amounts of renewable fuels such as ethanol produced from corn.
GAO was asked to provide information on the domestic petroleum refining industry. This report examines: (1) major changes that have recently affected the industry and (2) the future of the industry. GAO reviewed information including studies by agencies and consultants and company financial filings; interviewed stakeholders, including agency officials and representatives of refiners and environmental organizations; and reviewed forecasts by the Energy Information Administration and others.
section_title: What GAO Found
paragraphs: Stakeholders GAO contacted and information reviewed by GAO identified the following three major changes that have recently affected the domestic petroleum refining industry:
Increased production. U.S. and Canadian crude oil production have increased, leading to lower costs of crude oil for some refiners. After generally declining for decades, monthly U.S. crude oil production increased over 55 percent compared with average production in 2008.
Declining consumption. Domestic consumption of petroleum products declined by 11 percent from 2005 through 2012, resulting in a smaller domestic market for refiners.
Key regulations. Two key regulations—the Environmental Protection Agency's (EPA) and Department of Transportation's (DOT) coordinated fuel economy and greenhouse gas (GHG) vehicle emission standards, as well as EPA's Renewable Fuel Standard (RFS)—have contributed to declining petroleum-based fuel consumption. For some refiners, compliance with the RFS increased costs in the first half of 2013, though costs have since declined to some degree from their peak. According to some stakeholders GAO contacted, this 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. Moreover, EPA has missed the statutory deadline to issue regulations establishing annual RFS blending standards since 2009. EPA has not systematically identified the underlying causes of these delays or changed its approach in order to avoid them. A late RFS contributes to industry uncertainty, which can increase costs because industry cannot plan and budget effectively, according to some stakeholders.
Stakeholders GAO contacted and information reviewed generally suggested that the U.S. refining industry's outlook depends on the following factors:
Domestic consumption. Future consumption of petroleum products is uncertain, with projections ranging from stable to slightly increasing through 2020 but not returning to consumption levels of the past. Forecasts GAO reviewed suggest higher future refinery production in scenarios with higher domestic consumption.
Costs of key regulations . The extent to which requirements in the key regulations increase costs for refiners will affect the industry's outlook. For example, future costs to comply with RFS may depend on the annual renewable fuel volumes EPA sets and whether EPA issues annual RFS standards on time. In general, increasing costs may be absorbed by refiners (i.e., by reducing their profits), be passed on to consumers through higher prices, or both.
Foreign markets. The U.S. refining industry has increasingly relied on foreign markets. Exports grew from 7 percent of production in 2007 to 17 percent in 2012. The extent to which domestic refiners export their products will depend on the competitiveness of U.S. refiners. Factors that may affect competitiveness include domestic environmental regulations, levels of U.S. and Canadian crude oil production, and the balance between global refining capacity and demand for petroleum products.
section_title: What GAO Recommends
paragraphs: GAO recommends that EPA identify the underlying causes of delays in issuing RFS standards and implement a plan to issue RFS standards on time. EPA generally agreed with GAO's findings and recommendations.

section_title: Letter
paragraphs: The petroleum refining industry in the United States—the largest refining  industry in the world—experienced what some observers and industry  analysts have called a “golden age” from the early 2000s through about  2007. As we reported in 2007, this period was characterized by increased  petroleum product prices, as well as higher price volatility and industry  profits. Conditions changed with the recession of 2007 to 2009—the  most severe in this country since the 1930s—and the industry has since  been in transition. Amid declining refining profits, seven refineries have  closed since 2008, and the remaining refineries have not been run as  intensively. Conditions have improved more recently, with an Energy  Information Administration (EIA) official noting that the industry may be in  a second golden age. Petroleum refineries process crude oil into  transportation fuels and other products (e.g., gasoline, diesel, and  kerosene) that together comprise the largest source of energy in the  United States—36 percent of the energy consumed in 2012, according to  data from EIA. Domestic petroleum refineries produce the majority of the  fuels used in our transportation system, which also uses a small portion of  other fuels such as renewable fuels produced from corn, sugar cane, and  soybeans.
Federal and state agencies regulate aspects of petroleum refining and the  use of refined petroleum products for several purposes, including to  protect human health and the environment, and to respond to concerns  regarding the nation’s dependence on imported crude oil. Petroleum  refining and the combustion of gasoline and diesel emit carbon dioxide, a  greenhouse gas (GHG) linked to climate change. To address climate  change and other concerns, the Environmental Protection Agency (EPA),  the primary federal agency responsible for implementing many of the  nation’s environmental laws, along with the Department of Transportation  (DOT) and the state of California recently proposed or strengthened five  key environmental regulations as follows:
Renewable Fuel Standard (RFS). Established in light of concerns  such as climate change and the nation’s dependence on imported  crude oil, the RFS provides that U.S. transportation fuels must contain  certain percentages of renewable fuels. Under the law establishing  the program, volumes of renewable fuels were to increase over time,  though EPA determines requirements annually and may reduce  percentages under certain circumstances.
Corporate Average Fuel Economy (CAFE) and GHG vehicle emission  standards. A coordinated program in which DOT establishes fleet- wide gas mileage or fuel economy standards and EPA establishes  GHG emission standards for vehicle manufacturers.
Tier 3 Motor Vehicle Emission and Fuel Standards. EPA’s standards  for vehicles and transportation fuels to reduce emissions of certain air  pollutants.
Stationary source GHG requirements. EPA’s new requirements to  address GHG emissions at new refineries and refineries that  undertake major modifications.
Low Carbon Fuel Standard (LCFS). California’s recently implemented  LCFS requires reductions to the amount of carbon in California’s  transportation fuels. California is important for the domestic refining  industry because it is the nation’s largest consumer of petroleum- based transportation fuels. It also has the nation’s third largest refining  capacity, after Texas and Louisiana.
You asked us to provide information about the domestic petroleum  refining industry and its market environment. This report examines 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 conduct this work, we reviewed information, including studies by  federal agencies and consultants, and company financial regulatory  filings; and summarized the results of interviews with a nonprobability  sample of 32 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, industry associations, and others. We  took into account such factors as the location and size of companies’  refineries. Because we used a nonprobability sample, the views of  stakeholders are not generalizable to all potential stakeholders but  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. The stakeholders we contacted and information we  reviewed identified a number of changes that have affected industry and  factors that may affect its future, and we report on those that were most  often cited. Based on our research and information from stakeholders, we  identified five key regulations that were recently strengthened or  proposed, though other regulations may also affect the industry. To  illustrate major changes affecting industry over time, we summarized  historical data from EIA. We took several steps to assess the reliability of  EIA data, 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 major factors that could affect the industry, we also reviewed  forecasts from EIA, the International Energy Agency (IEA), and IHS, and  summarized projections through 2020 under different scenarios. 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. Appendix I provides additional information  on our scope and methodology, and appendix II lists the stakeholders we  interviewed.
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.
subsections: section_title: Background
paragraphs: This section describes the petroleum refining industry and the five key  regulations that we reviewed.
subsections: section_title: Petroleum Refining Industry
paragraphs: 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).
section_title: Key Regulations Affecting the Domestic Refining Industry
paragraphs: 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.
subsections: section_title: Stationary Source GHG Requirements
paragraphs: 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.
section_title: Market Changes and Key Environmental Regulations Likely Affected the Refining Industry
paragraphs: 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.
subsections: section_title: Increased Crude Oil Production Has Lowered Crude Oil Costs for Some Refiners
paragraphs: 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.
section_title: Domestic Consumption of Petroleum Products Has Declined
paragraphs: 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.
section_title: Two Key Regulations Have Likely Contributed to Declining Fuel Consumption and Compliance with One Has Increased Some Refiners’ Costs
paragraphs: 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.
subsections: section_title: CAFE and GHG Vehicle Emission Standards
paragraphs: 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.
section_title: Industry Outlook Depends on a Number of Factors
paragraphs: 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.
subsections: section_title: Uncertain Future Domestic Consumption
paragraphs: 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.
section_title: Costs of Key Regulations
paragraphs: 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.
section_title: Extent to Which Refiners Can Export and Compete in Foreign Markets
paragraphs: 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.
subsections: section_title: Refiners Projected to Continue to Rely on Foreign Markets
paragraphs: 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.
section_title: Conclusions
paragraphs: 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.
section_title: Recommendations for Executive Action
paragraphs: 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.
section_title: Agency Comments and Our Evaluation
paragraphs: 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.
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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.
section_title: Appendix I: Scope and Methodology
paragraphs: 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.
section_title: Appendix II: List of Stakeholders
subsections: section_title: Federal Agencies
section_title: Refiners
section_title: Other
section_title: Appendix III: Further Information Regarding the Renewable Fuel Standard, Compliance Credits, and the Blend Wall
paragraphs: 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.
section_title: Appendix IV: Comments from the Environmental Protection Agency
section_title: Appendix V: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
section_title: Staff Acknowledgments
paragraphs: 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.
section_title: Related GAO Products
paragraphs: Oil and Gas: Information on Shale Resources, Development, and  Environmental and Public Health Risks. GAO-12-732. Washington, D.C.:  September 5, 2012.
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.