The U.S. petroleum refining industry experienced what some have called a "golden age" during the years 2004-2007. During this period, the demand for petroleum products, especially gasoline, increased rapidly both in the United States and world markets. Refiners found favorable price-spreads between heavy and light crude oils as well as between crude oil and refined products. The industry operated plants at nearly maximum capacity and posted record profit levels. Unexpected events such as hurricanes that shut down Gulf Coast refineries, concerns over "peak oil" production, and crude oil price speculation likely contributed to spikes in gasoline prices. During the period, many policy makers expressed the concern that U.S. refining capacity was not increasing rapidly enough to keep up with the expected growth in demand for petroleum products. The concern now may be that excess refining capacity has affected bottom-line refining profitability and the ability to meet consumer demand. Current economic conditions have led to lower refinery utilization rates and recent closure of a few refineries. In a continuing trend, some vertically integrated oil companies (those engaged in all phases of production, refining and marketing) either have divested their refineries or spun them off as separate business units. The concentration of refining capacity in the U.S. Gulf Coast, an outcome of the region's significant petroleum resources and their history of development, influenced the current network of crude oil and product distribution pipelines. New sources of heavy crude oils from Canada and light crude oils from the mid-continent and mid-West are altering the logistics in supplying established refining centers. In the absence of pipeline capacity, existing rail lines are proving a viable alternative. Rail appears to offer an immediate solution to both crude supply and product delivery bottlenecks, as rail-delivered ethanol appears to demonstrate. No matter what the investment, refineries must adapt to changing crude streams to ensure lowest cost of operation, and the largest product/crude price spread. The greatest cost in refining is not capital investment, but crude costs. But, the growing availability of new unconventional oil resources in the mid-continent resources is changing refining economics and profitability on both the East and West Coasts, and perhaps challenging the Gulf Coast's refining center status. The U.S. refining industry faces a number of new policies that could force downward pressure on refinery numbers, capacity, or utilization: Tighter Corporate Average Fuel Economy (CAFE) and vehicle greenhouse gas standards; the federal Renewable Fuel Standard (RFS); natural gas as a transportation fuel; and EPA Mandatory Greenhouse Gas Reporting. Further, the potential binding greenhouse gas limits in the future, either through a federal cap-and-trade or carbon tax program, or through regulation under the Environmental Protection Agency's "tailoring rule," could provide further downward pressure on petroleum demand. This report reviews the current production capacity of the refineries operating in the United States, and the sources and changes in their crude oil supply. It also examines the changing characteristics of petroleum and petroleum product markets and identifies the effects of these changes on the refining industry, including tax considerations. It concludes with discussion of the policy and regulatory factors that are likely to affect the structure and performance of the industry during the next decade. Crude oil is a complex mix of hydrocarbon compounds, ranging from simple compounds with small molecules and low densities to very dense compounds with extremely large molecules. An average crude oil contains about 84% carbon, 14% hydrogen, 1% to 3% sulfur, and less than 1% each nitrogen, oxygen, metals, and salts. The American Petroleum Institute (API) compares the "lightness" or "heaviness" of crude oils on an inverted scale in terms of degrees (") API gravity. Figure 1 illustrates a range of crude oil gravities. Any crude above 10 °API will float on water. Light crude's API gravity is higher than 31.1 "API, medium crude between 22.3 °API and 31.1 °API, and heavy crude below 22.3 °API. The benchmark for comparing crudes has been West Texas Intermediate (WTI), or Texas light sweet. Light crude has a low wax-content, and sweet crude has less than 0.5% sulfur. (Refer to Appendix A for further information on crude oil properties.) A hypothetical refinery distills crude oil into various products, according to their boiling point range. The most common products—gasoline, diesel, and jet fuels—are complex mixtures of hydrocarbons that include paraffins, naphthenes, and aromatics (which give fuel its unique odor). Refineries vary in complexity, but have several basic processing steps in common: distillation , cracking , treating and reforming . Distillation involves heating crude oil in a furnace then condensing it in an atmospheric distillation tower (or Crude unit)—the tall, narrow columns that give a refinery its distinctive skyline. The Crude unit separates light hydrocarbon molecules from heavy hydrocarbons based on their boiling temperatures. The lightest materials, like propane and butane, vaporize and rise to the top of the atmospheric column. Medium weight materials, including gasoline, jet and diesel fuels, condense in the middle. Heavy materials, called gas oils, condense in the lower portion of the atmospheric column. Residuum (a heavy tar-like material) referred to as the "bottom of the barrel," has a high boiling temperature that keeps it in the lower portion of the column. In some cases, distillation columns operate at less than atmospheric pressure (vacuum) to lower the temperature at which a hydrocarbon mixture boils. Vacuum distillation reduces the chance of thermal decomposition (cracking) due to overheating. As the heavier oils move through the refinery, heat and catalysts "crack" them into lighter products through fluid-catalytic-cracking (FCC), hydrocracking, or thermal-cracking (coking). Fluid catalytic cracking uses high temperature and catalysts to convert heavy gas oil mostly into gasoline. Hydrocracking uses catalysts to react gas oil and hydrogen under high pressure and high temperature to make both jet fuel and gasoline. Coking converts low-value residuum (using thermal-cracking) to high-value light products, producing petroleum coke as a by-product. While the cracking breaks most of the gas oil into gasoline and jet fuel, it also breaks off some smaller hydrocarbons that are lighter than gasoline. These lighter hydrocarbons recombine in alkylation units, in the presence of sulfuric acid catalyst, to reform into high-octane gasoline. The products from the crude unit and the feeds to other units contain some natural impurities, such as sulfur and nitrogen that contribute to air pollution when fuels combust. Hydrotreating (a milder version of hydrocracking) removes these impurities by converting the sulfur to hydrogen sulfide and then to elemental sulfur; and converting nitrogen into ammonia and then removing it by water-washing for recovery as ammonia for fertilizer. The gasoline stream that comes out of the crude unit or cracking unit has a relatively low octane rating (a key measure of how gasoline performs in an automobile engine). To upgrade gasoline octane-rating, a reforming unit uses precious-metal catalysts (platinum and rhenium) to "reform" hydrocarbon molecules into high-octane gasoline components. The reforming process removes hydrogen from low-octane gasoline, which refinery reuses in various cracking (hydrocracking) and treating (hydrotreating) units. When refined, a 35 API crude might yield a product slate range of 27% gasoline and 25% middle distillate fuels in the range diesel and jet fuel. For further information on refining processes refer to Appendix A . After a volatile decade marked by record crude oil prices and profit margins, U.S. refiners now face the prospect of possibly long-term decreased demand for their products. Refiners are responding by cutting costs, reducing capacity utilization, and closing facilities. A decade ago, 158 refineries operated in the United States and its territories. By the Congressional Research Service's (CRS) most recent count, 115 refineries primarily process crude oil into fuels (of which four refineries are complexes made up of two or three formerly independent refineries joined by pipeline). Despite permanent closures, operable refining capacity has increased over the past decade from 16.5 million barrels/day to approximately 18 million barrels/day. By the Energy Information Administration's (EIA) definition, "operable capacity" includes both operating refineries and idle refineries which shut down temporarily for repair or "turn around" for seasonal adjustment in the product slate (for example, reformulating gasoline from winter to summer blends). EIA includes refineries that also produce lubricating oils, asphalts, and other products For this report, CRS reviewed petroleum refiners that primarily produce fuel and used the capacity that these refiners advertise on their corporate web pages to estimate an overall refinery capacity in excess of 18 million barrels/day. EIA had reported a U.S. operable crude oil distillation capacity of 17.73 million barrels/day and a gross crude oil input of 15.29 million barrels/day in 2011 yielding a refinery utilization capacity at slightly over 86%. As a refinery's year-to-year performance changes (for the reasons noted above) a better measure of capacity may be "barrels/stream day"—the barrels of crude oil input a refinery reports over the number of days it annually operates also termed "utilization." EIA also reported prime suppliers of refined products sold approximately 14.53 million barrels/day.