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As of January 1, 2018, U.S. operable atmospheric crude distillation capacity totaled 18.6 million barrels per calendar day (b/cd), a slight decrease of 0.1% since the beginning of 2017 according to EIA’s annual Refinery Capacity Report. Annual operable crude oil distillation unit (CDU) capacity had increased slightly in each of the five years before 2018. Refinery capacity is measured in two ways: barrels per calendar day and barrels per stream day. Barrels per calendar day reflect the input that a distillation unit can process in a 24-hour period under usual operating conditions, taking into account both planned and unplanned maintenance. Barrels per stream day reflect the maximum number of barrels of input that a distillation facility can process within a 24-hour period when running at full capacity under optimal crude oil and product slate conditions with no allowance for downtime. Stream day capacity is typically about 6% higher than calendar day capacity. The Refinery Capacity Report also includes information about secondary units—downstream refinery units that are used to process the products coming from the atmospheric crude distillation unit into ultra-low sulfur diesel and gasoline, as well as other products. Secondary refining capacity, including thermal cracking (coking), catalytic hydrocracking, and hydrotreating and desulfurization, increased slightly, up 1% from year-ago levels. These downstream capacity increases are primarily the result of changing processes that can increase refinery throughput rather than building new refining units. The number of operating refineries decreased from 141 on January 1, 2017, to 135 on January 1, 2018, largely reflecting classification changes in EIA’s survey: four refineries previously considered separate in survey data were merged into two, and two refineries were reclassified from idle to shut down. Consequently, the decrease in number of operating refineries does not necessarily represent a meaningful change in U.S. refinery operating capacity. Record refinery runs have helped accommodate increases in U.S. crude oil production, which averaged 9.4 million barrels per day (b/d) in 2017, an increase of 4.0 million b/d from the level in 2009. Gross crude oil inputs to refineries averaged 16.6 million b/d in 2017 compared with 14.3 million b/d in 2009. Over that period, operable refinery crude distillation capacity increased 945,000 b/cd, and utilization rose from 83% in 2009 to 91% in 2017, resulting in the 2.3 million b/d increase in gross crude oil inputs. Over the same period, U.S. crude oil imports decreased by 1.1 million b/d, and U.S. crude oil exports increased by 1.1 million b/d. EIA’s Refinery Capacity Report also includes information on capacity expansions planned for the balance of the year. Based on information reported to EIA in the most recent update, U.S. refining capacity will not expand significantly during 2018. Further investment in U.S. refinery expansion projects depends on expectations about crude oil price spreads, the characteristics of the crudes being produced, product specifications, and the relative economic advantage of the U.S. refining fleet compared with refineries in the rest of the world.

Fossil fuels—petroleum, natural gas, and coal—have accounted for at least 80% of energy consumption in the United States for well over a century. The fossil fuel share of total U.S. energy consumption in 2017 was the lowest share since 1902, at a little more than 80%, as U.S. fossil fuel consumption decreased for the third consecutive year. The decline in fossil fuel consumption in 2017 was driven by slight decreases in coal and natural gas consumption. Coal consumption fell by 2.5% in 2017, following larger annual declines of 13.6% and 8.5% in 2015 and 2016, respectively. U.S. consumption of coal peaked in 2005 and declined nearly 40% since then. Natural gas consumption fell by 1.4% in 2017, a change from recent trends. Unlike coal consumption, which has decreased in 8 of the past 10 years, natural gas consumption has increased in 8 of the past 10 years, and in 2017, was twice that of coal. Natural gas consumption growth has been driven by increased use in the electric power sector. Overall, U.S. consumption of natural gas increased by 24% from 2005 to 2017. Petroleum consumption increased in 2017, but remains 10% lower than its peak consumption level, also set in 2005. Mainly used in the transportation sector, several petroleum-based fuels are also used in homes, businesses, and industries. Petroleum has been the largest source of energy consumption in the United States since surpassing coal in 1950. The renewable share of energy consumption in 2017, which includes hydroelectricity, biomass, and other renewables such as wind and solar, was 11.3%, the highest since the late 1910s, when overall energy consumption was lower and biomass consumption—mainly wood—made up a larger share. The largest growth in renewables over the past decade has been in solar and wind electricity generation. Energy consumption in the United States has undergone many changes over the course of the nation’s history, from wood as the primary resource in the 18th and 19th centuries, to the onset of coal and petroleum use, to the more modern rise of nuclear power in the late 20th century, and to renewables in the early 21st century. Of course, EIA did not exist to collect data in 1776. The Monthly Energy Review's pre-1949 estimates of U.S. energy use are deeply indebted to two sources. Much of the data used in earlier energy estimates are from the book Energy in the American Economy 1850-1975, Its History and Prospects by Sam Schurr and Bruce Netschert. The U.S. Department of Agriculture’s Circular No. 641, Fuel Wood Used in the United States 1630–1930, published in 1942, provides some of the earliest biomass consumption estimates for the United States. Appendix D of EIA’s Monthly Energy Review compiles these estimates of U.S. energy consumption in ten-year increments from 1635 through 1845 and five-year increments from 1845 through 1945. Data for 1949 through the present day can be found in the latest Monthly Energy Review.

Starting with the May 2018 release of the Petroleum Supply Monthly, EIA now publishes U.S. petroleum export data by region, defined as Petroleum Administration for Defense District (PADD), of origin and by country of destination. Before this change, users could only see the total amount exported from each U.S. PADD, but not the actual destination associated with those PADD-level exports. U.S. petroleum exports have increased rapidly in recent years and have become an important factor in global oil markets. Increased access to U.S. oil exports data can provide valuable insight into global oil trade flows and allow new analysis of global oil markets. U.S. crude oil exports, in particular, have risen sharply since crude oil export restrictions were lifted in late 2015, reaching 1.1 million barrels per day (b/d) in 2017. Through June 15, 2018, U.S. crude oil exports have surpassed 2 million b/d seven times in EIA weekly data. Canada was the largest destination for U.S. crude oil exports in 2017, and with the addition of destination to PADD-level export data, EIA customers can now see that Canada receives U.S. crude oil primarily from the U.S. Midwest (PADD 2), the U.S. Gulf Coast (PADD 3), and the U.S. East Coast (PADD 1). In addition, changes in the relative amount of crude oil Canada received from each region over time can now be seen, notably the significant increase in exports from PADD 2 in 2017. U.S. petroleum product exports have also increased over the past several years, reaching 5.2 million b/d in 2017. With the addition of destination to PADD-level export data, EIA customers can better track the seasonality that may exist in the exports of certain petroleum products. For example, distillate, the most exported petroleum product, is exported in larger volumes in the summer months, when U.S. consumption is at its seasonal low. Distillate exports generally decline during the winter months, with exports from the East Coast, the main region that uses distillate (heating fuel) in the winter months, falling to nearly zero. However, during the winter in early 2017, warmer-than-normal weather and lower prices on the East Coast compared with those elsewhere in the Atlantic basin resulted in an unusually high amount of distillate exported from the East Coast for that time of year. By adding destination to PADD-level export data, it is now possible to see that the distillate was exported mainly to countries in Europe, along with some countries in Central and South America as well as Africa.

Fossil fuels—petroleum, natural gas, and coal—have accounted for at least 80% of energy consumption in the United States for well over a century. The fossil fuel share of total U.S. energy consumption in 2017 was the lowest share since 1902, at a little more than 80%, as U.S. fossil fuel consumption decreased for the third consecutive year. The decline in fossil fuel consumption in 2017 was driven by slight decreases in coal and natural gas consumption. Coal consumption fell by 2.5% in 2017, following larger annual declines of 13.6% and 8.5% in 2015 and 2016, respectively. U.S. consumption of coal peaked in 2005 and declined nearly 40% since then. Natural gas consumption fell by 1.4% in 2017, a change from recent trends. Unlike coal consumption, which has decreased in 8 of the past 10 years, natural gas consumption has increased in 8 of the past 10 years, and in 2017, was twice that of coal. Natural gas consumption growth has been driven by increased use in the electric power sector. Overall, U.S. consumption of natural gas increased by 24% from 2005 to 2017. Petroleum consumption increased in 2017, but remains 10% lower than its peak consumption level, also set in 2005. Mainly used in the transportation sector, several petroleum-based fuels are also used in homes, businesses, and industries. Petroleum has been the largest source of energy consumption in the United States since surpassing coal in 1950. The renewable share of energy consumption in 2017, which includes hydroelectricity, biomass, and other renewables such as wind and solar, was 11.3%, the highest since the late 1910s, when overall energy consumption was lower and biomass consumption—mainly wood—made up a larger share. The largest growth in renewables over the past decade has been in solar and wind electricity generation. Energy consumption in the United States has undergone many changes over the course of the nation’s history, from wood as the primary resource in the 18th and 19th centuries, to the onset of coal and petroleum use, to the more modern rise of nuclear power in the late 20th century, and to renewables in the early 21st century. Of course, EIA did not exist to collect data in 1776. The Monthly Energy Review's pre-1949 estimates of U.S. energy use are deeply indebted to two sources. Much of the data used in earlier energy estimates are from the book Energy in the American Economy 1850-1975, Its History and Prospects by Sam Schurr and Bruce Netschert. The U.S. Department of Agriculture’s Circular No. 641, Fuel Wood Used in the United States 1630–1930, published in 1942, provides some of the earliest biomass consumption estimates for the United States. Appendix D of EIA’s Monthly Energy Review compiles these estimates of U.S. energy consumption in ten-year increments from 1635 through 1845 and five-year increments from 1845 through 1945. Data for 1949 through the present day can be found in the latest Monthly Energy Review.

In December 2017, the passage of Public Law 115-97 required the U.S. Secretary of the Interior to establish and administer a competitive oil and natural gas program for the leasing, development, production, and transportation of oil and natural gas in and from the coastal plain of the Arctic National Wildlife Refuge (ANWR). Previously, ANWR was effectively under a drilling moratorium. Three sensitivity cases in EIA’s Annual Energy Outlook 2018 explore the effect of this law on U.S. crude oil production. Much uncertainty surrounds any projection of production from ANWR. The only well drilled in the coastal plain was completed in 1986, and the results have remained confidential. Federal resource estimates are based largely on the oil productivity of geologic formations in neighboring state-owned lands in Alaska and two-dimensional seismic data that had been collected by a petroleum industry consortium in 1984 and 1985. ANWR is located on the northern coast of Alaska east of Prudhoe Bay and the National Petroleum Reserve-Alaska (NPRA). The coastal plain, also known as the 1002 Area, covers 1.5 million acres and is about 8% of the total area of ANWR. In the most recent resource assessment, conducted in 1998, the United States Geological Survey (USGS) estimated that the total technically recoverable crude oil resource for federal lands, state waters, and native lands in the coastal plain has a mean estimate of 10.4 billion barrels. USGS assigned a 5% chance of the resource being less than 5.7 billion barrels and a 5% chance of being as high as 16.0 billion barrels. These three resource estimate values—low, mean, and high—define the three sensitivity cases examined by EIA. In all three cases, production from ANWR does not start until 2031 because of the time needed to acquire leases, explore, and develop the required production infrastructure. Fields are assumed to take three to four years to reach peak oil production, to maintain peak production for three to four years, and then to decline until they are no longer profitable and are abandoned. In the Mean ANWR case, cumulative U.S. production from 2031 through 2050 is 3.4 billion barrels higher than in the AEO2018 Reference case. From 2031 through 2050, cumulative U.S. production is 5.1 billion higher in the High ANWR case and 2.0 billion barrels higher in the Low ANWR case than in the AEO2018 Reference case. Alaska relies on the Trans-Alaska Pipeline System (TAPS), which marked its 40th anniversary in 2017, to transport crude oil from the frozen North Slope to the warm-water port at Valdez on the state's southern coast. The 800-mile pipeline, built from 1974 to 1977, achieved peak flow in the late 1980s at 2 million barrels per day (b/d); current flow is nearly 500,000 b/d. Almost 80% of oil produced in Alaska in 2017 was refined in Washington and California. About 15% of Alaskan crude oil production was refined in Alaska. The remaining portion (about 5%) was shipped to Hawaii or exported to international destinations. Beyond resource uncertainty, market dynamics could limit the amount of increased Alaskan production processed domestically. In the AEO2018 Reference case, demand for gasoline in the United States is expected to decline through about 2040 because of improvements in fuel economy. For this reason, demand for additional Alaskan crude oil to be processed in its traditional market could be lower. Crude oil quality issues could also affect supply decisions: substituting Alaskan crude oil for the heavier crude oils historically processed in California would reduce the profitability of refinery coking and could lead to refinery closures. Transporting crude oil from Alaska to other domestic ports on the West Coast requires vessels that comply with the Merchant Marine Act of 1920 (also known as the Jones Act). This potential limitation, as well as constraints through high-traffic waterways on the West Coast, could limit the amount of Alaskan crude oil that is processed in domestic refineries. Given these factors, it is likely that some additional volumes of Alaskan oil production would be exported to Asia instead of consumed domestically. More information about ANWR crude oil production and the modeled effects on net petroleum trade and trade expenditures is available in the full Issues in Focus analysis.

In 2017, a group of the world’s largest publicly traded oil and natural gas producers added more hydrocarbons to their resource base than in any year since 2013, according to the annual reports of 83 exploration and production companies. Collectively, these companies added a net 8.2 billion barrels of oil equivalent (BOE) to their proved reserves during 2017, which totaled 277 billion BOE at the end of the year. Exploration and development (E&D) spending in 2017 increased 11% from 2016 levels but remained 47% lower than 2013 levels. Of the 83 companies, 18 held more than 80% of the 277 billion BOE in proved reserves at the end of 2017. Although many of these companies have global operations, some are national oil companies with reserves concentrated in their home countries, including Russia, China, and Brazil. Proved reserves change from year to year because of revisions to existing reserves, extensions and discoveries of new resources, purchases and sales of proved reserves, and production. Organic additions to proved reserves, or reserves added through improved recovery and extensions and discoveries, are linked directly with capital expenditures in E&D. Proved reserves acquired through purchases do not represent E&D capital investment but rather reflect transfers of assets between companies. Revisions to proved reserves are usually more significantly influenced by changes in crude oil and natural gas prices than by E&D investment. Of the 17.7 billion BOE in organic proved reserves added in 2017, slightly less than half (8.5 billion BOE) were in the United States, while Russia, Central Asia, and the Asia-Pacific region accounted for 24% (4.3 billion BOE). Canada (which includes oil sands and synthetic crude oil), Latin America, and the Middle East and Africa regions each added more than 1.1 billion BOE. Regionally, Europe accounted for the fewest organically added proved reserves for the sixth consecutive year, adding 0.3 billion BOE (2% of world total) of proved reserves in 2017. Global E&D spending by region was similarly distributed. Of the $285 billion companies spent on E&D in 2017, 33% ($95 billion) was in the United States, with the Russia, Central Asia, and Asia-Pacific region accounting for 30% ($85 billion) and all other regions each accounting for 10% or less. Changes in nominal year-over-year E&D spending varied across regions, increasing by 36% in the United States and by 15% each in Canada and the Russia, Central Asia, and Asia-Pacific region. Spending declined by 24% in Europe, 16% in the Middle East and Africa, and 15% in Latin America. Because of a disparity between the timing of companies’ capital expenditures and the formal reporting of changes to their proved reserves, standard practice is to average the results over several years. Analyzed this way, E&D costs declined significantly on a per BOE basis from the 2012–2014 average to the 2015–2017 average. Three-year average E&D capital expenditures per BOE of organic proved reserves additions decreased in all regions except Latin America. On an annual basis, 2017 represented the lowest E&D capital expenditures per additional BOE to proved reserves during the 2012–2017 period at $16.12/BOE. First-quarter 2018 capital expenditures for this set of companies were 16% higher than in first-quarter 2017, suggesting that many of these companies have increased their E&D budgets, which will likely contribute to further organic proved reserves additions in 2018.

Fossil fuel consumption in the electric power sector declined to 22.5 quadrillion British thermal units (quads) in 2017, the lowest level since 1994. The declining trend in fossil fuel consumption by the power sector has been driven by a decrease in the use of coal and petroleum with a slightly offsetting increase in the use of natural gas. Changes in the fuel mix and improvements in electricity generating technology have also led the power sector to produce electricity while consuming fewer fossil fuels. In 2017, coal consumption by the electric power sector reached its lowest level since 1982, and petroleum consumption in the power sector was the lowest on record, based on data since 1949. Recent natural gas consumption in the power sector has generally been increasing, but 2017 consumption was slightly lower than the record-high 2016 level. In energy-equivalent terms, more coal was consumed in the power sector than natural gas in 2017, at 12.7 quads and 9.5 quads, respectively. However, in terms of electricity generation, natural gas-fired power plants in the electric power sector produced more electricity than coal-fired plants, at 31% and 30% of the U.S. total, respectively, in 2017. Natural gas-fired units tend to be more energy efficient, requiring less energy content to produce a unit of electricity. As recently as 2000, natural gas-fired power plants were on average about as efficient as coal-fired plants. Since then, new natural gas-fired power plants have tended to use combined-cycle generators, which are more efficient because the waste heat from the gas turbine is routed to a nearby steam turbine that generates additional power. Combined-cycle units now make up most of the natural gas-fired electricity generation capacity. By the end of 2018, natural gas combined-cycle units may surpass conventional coal-fired power plants to become the most prevalent technology for generating electricity in the United States. As the natural gas-fired generation fleet has grown and become more efficient, the generation-weighted average efficiency of fossil fuel-fired electricity generation has improved. In 1994, fossil fuel power plants required 10,400 British thermal units (Btu) of primary energy to produce each kilowatthour (kWh); by 2017 that rate had fallen to 9,400 Btu/kWh. These changes in energy consumption and efficiency have also affected carbon dioxide (CO2) emissions from the electric power sector, which in 2017 were the lowest since 1987. Because coal combustion is much more carbon intensive than natural gas combustion, CO2 emissions from coal were more than double those from natural gas in 2017, even though natural gas provided more electricity generation. More information on U.S. energy consumption and CO2 emissions across sectors is available in EIA’s Monthly Energy Review.