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EIA projects that the United States will become a net energy exporter in 2022 in the newly released Annual Energy Outlook 2018 (AEO2018) Reference case, primarily driven by changes in petroleum and natural gas markets. The transition from net energy importer to net energy exporter occurs even earlier in some sensitivity cases that modify assumptions about oil prices or resource extraction. Sensitivity cases with less energy production project that the United States will remain a net energy importer through 2050. The transition of the United States to a net energy exporter is fastest in the High Oil Price case, where higher crude oil prices lead to more oil and natural gas production and transition the United States into a net exporter by 2020. In that case, higher crude oil prices also result in higher petroleum product prices and lower consumption of petroleum products, driving decreases in net petroleum imports. In the High Oil and Gas Resource and Technology case, with more favorable assumptions for geology and technological developments, the United States becomes a net exporter in 2020, and net exports increase through the end of the projection period. In cases with relatively low oil prices or less favorable assumptions for geology and technological developments, U.S. net energy trade still decreases, but the United States remains a net energy importer through 2050. In energy equivalent terms, the United States imported about 27 quadrillion British thermal units (quads) of energy in 2017 and exported 18 quads, which resulted in 9 quads of net imports. In 2017, the United States imported about 11 quads of petroleum and other liquids and exported 2 quads of coal and coal coke. U.S. natural gas trade in 2017 was nearly balanced between imports and exports, and net electricity trade with Canada and Mexico was relatively small. Petroleum and natural gas account for most of the changes EIA projects in U.S. energy trade. U.S. net petroleum trade—crude oil, petroleum products, and natural gas plant liquids—has fallen in recent years, reaching 3.8 million barrels per day (b/d) in 2017 based on data through November. In the AEO2018 Reference case, petroleum net imports are projected to decrease through 2035, as increasing production and decreasing domestic demand result in lower petroleum imports and more exports. Net petroleum imports vary significantly across price and resource cases as domestic crude oil production shifts. By 2030, net petroleum trade ranges from exporting 5.3 million b/d in the High Oil Price case to importing 4.6 million b/d in the Low Oil Price case. Net petroleum exports in the High Oil and Gas Resource and Technology case grow throughout the projection period, ultimately reaching 8.5 million b/d by 2050. The United States transitioned to a net exporter of natural gas in 2017, and all cases in the AEO2018 project the United States remains a net exporter of natural gas. Most of the differences between cases can be attributed to differences in projections for liquefied natural gas (LNG) trade as opposed to pipeline shipments of natural gas. As LNG export facilities that are currently under construction are completed, LNG exports are projected to increase, especially to countries in Asia. After near-term increases in LNG exports, U.S. natural gas export growth is projected to slow as U.S.-sourced LNG becomes less competitive in world markets. In the Reference case, net natural gas exports reach a high of 23 billion cubic feet per day (Bcf/d) in 2050. In the High Oil Price case, net natural gas exports reach a high of 37.4 Bcf/d by 2050. In the Low Oil and Gas Resource and Technology case, net natural gas exports begin to decrease in the mid-2020s, reaching 6.7 Bcf/d by 2050.

Recent legislation has directed the sale of more than 100 million barrels of oil from the U.S. Strategic Petroleum Reserve (SPR) in U.S. government fiscal years (FY) 2022 through 2027. Based on legislated sales established in multiple acts of Congress, the SPR could decline by about 40% in the coming decade while still meeting requirements for petroleum import coverage. Assuming no other legislation over this period, the SPR could decline from 695 million barrels at the start of 2017 to about 410 million barrels at the start of 2028. The largest stockpile of government-owned emergency crude oil in the world, the SPR was established to help alleviate the effects of unexpected oil supply reductions. Located in four storage sites along the Gulf of Mexico, the SPR held more than 695 million barrels of crude oil at the beginning of 2017, or about 97% of its 713.5 million barrel design capacity. Prior to FY 2017 sales, the SPR inventory level had remained nearly constant for several years. A previous Today in Energy article described the three bills enacted in 2015 and 2016 that collectively call for the sale of 149 million barrels in FY 2017 through FY 2025. Most of these sales set volumetric requirements, and revenues from those sales go to the U.S. Department of Treasury. A section of one of those bills—Section 404 of the Bipartisan Budget Act of 2015—included authorization for funding an SPR modernization program by selling up to $2 billion worth of SPR crude oil in FY 2017 through FY 2020. In that act, the sales are based on revenue targets that must be authorized by Congress. Two recent congressional acts collectively call for the sale of 107 million barrels of crude oil in FY 2022 through FY 2027: The Bipartisan Budget Act of 2018, enacted in February 2018, calls for the sale of 30 million barrels over the four-year period of FY 2022 through FY 2025, 35 million barrels in FY 2026, and 35 million barrels in FY 2027. The Tax Cuts and Jobs Act of 2017, enacted in December 2017, calls for the sale of 7 million barrels over the two-year period of FY 2026 through FY 2027. One of the SPR's core missions is to hold enough oil stocks to carry out U.S. obligations under the International Energy Program (IEP), the 1974 treaty that established the International Energy Agency (IEA). Under the IEP, the United States must be able to contribute to an IEA collective action based on its share of IEA oil consumption. Based on the most recent shares, the United States must be prepared to contribute about 43% of the barrels released in an IEA coordinated response. The United States government relies on the SPR to meet this requirement. As a member of the IEA, the United States is obligated to maintain stocks of crude oil and petroleum products, both public and private, to provide at least 90 days of U.S. net import protection. As net imports of crude oil and petroleum products into the United States continue to decline, this requirement can be met with lower SPR inventory levels. The Reference case of EIA’s latest Annual Energy Outlook projects that the United States will be a net exporter of petroleum by 2029. Other cases with more domestic petroleum production show the United States reaching net petroleum exporter status even sooner. Based on November 2017 levels of net crude oil and petroleum product imports, the SPR alone holds crude oil stocks equivalent to 252 days of import protection. Private (commercial) stocks of crude oil provide an additional 452 million barrels, equivalent to another 172 days of import protection. EIA expects a 40% increase in natural gas consumed in the U.S. industrial sector, from 9.8 quadrillion British thermal units (Btu) in 2017 to 13.7 quadrillion Btu in 2050, according to the Annual Energy Outlook 2018 (AEO2018) Reference case. By 2020, total industrial natural gas consumption will surpass the previous record set in the early 1970s, according to the AEO2018 Reference case. The U.S. industrial sector consumes more natural gas than any other sector, surpassing electric power in 2017 and the combined residential and commercial sectors in 2010. The industrial sector, as discussed here, includes natural gas used in production operations (lease and plant fuel) and natural gas used for liquefaction of natural gas for export. About 40% of the increase in industrial natural gas consumption from 2017 through 2030 is lease and plant fuel and liquefaction fuel, which, by 2030, represent 22% of total industrial natural gas consumption. In 2017, about two-thirds of total industrial natural gas consumption was consumed for heat or power applications—either for industrial processes, such as in furnaces, or for onsite electricity generation. Several industries including bulk chemicals, food, glass, and metal-based durables used natural gas for 40% or more of their heat or power applications in 2017. EIA expects that these industries will continue to use about the same proportion of natural gas for heat or power applications through 2050 because of the cost associated with fuel switching. Industrial fuel switching often involves changing manufacturing processes, which requires substantial capital investment in new equipment. As the largest natural gas consumer in the industrial sector, the bulk chemicals industry consumed 3.1 quadrillion Btu of natural gas in 2017, or the equivalent of about 3.0 trillion cubic feet. The bulk chemicals industry includes production of organic chemicals (including petrochemicals), inorganic chemicals, resins, and agricultural chemicals. In the AEO2018 Reference case, increases in the bulk chemicals industry’s consumption of natural gas outpaces overall growth in the industrial sector through 2050, with 51% growth compared with the sector average of 40%. Most natural gas in the bulk chemicals industry is used for heat or power applications, but about 25% of bulk chemical natural gas consumption is used for feedstocks in agricultural chemicals (i.e., fertilizer) and methanol production. Natural gas feedstock is only used for agricultural chemicals and methanol, but hydrocarbon gas liquids (HGL) can be used as feedstock for many basic organic chemicals such as ethylene and propylene, which are used in the production of plastics. Most HGL production is recovered at natural gas processing plants from raw natural gas streams with high proportions of hydrocarbons other than methane. EIA projects that natural gas produced in the Appalachian and Permian basins will account for most of the growth in HGL production through 2050.

U.S. crude oil production in the Federal Gulf of Mexico (GOM) increased slightly in 2017, reaching 1.65 million b/d, the highest annual level on record. Although briefly hindered by platform outages and pipeline issues in December 2017, oil production in the GOM is expected to continue increasing in 2018 and 2019, based on forecasts in the EIA’s latest Short-Term Energy Outlook (STEO). EIA expects the GOM to account for 16% of total U.S. crude oil production in each year. Based on STEO’s expected production levels at new fields and existing fields, annual crude oil production in the GOM will increase to an average of 1.7 million b/d in 2018 and 1.8 million b/d in 2019. However, uncertainties in oil markets may still affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly. In 2016, producers brought seven new projects and expansions online and ramped up production in 2017, collectively contributing to an average of 126,000 b/d of production in 2017. Another two projects came online in 2017, contributing 10,000 b/d of new production last year. EIA expects these nine projects to ramp up over the next two years. Producers expect four new projects to come online in 2018 and six more in 2019. Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to pull back on future deepwater exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2017. Recent crude oil price increases have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discovery in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead affect the discovery of future projects and fields. In March 2018, the Bureau of Ocean Energy Management held a lease sale for more than 14,000 Federal Gulf of Mexico blocks, most of which did not receive any bids. Although the results of this auction will not affect GOM production within the Short-Term Energy Outlook forecast horizon (through 2019), the level of interest for leases may have longer-term implications for GOM crude oil production. Recent growth in U.S. crude oil production has been primarily light, sweet crude oil, defined as having an API gravity of 35 or higher and sulfur content of 0.3% or less. These light, sweet crudes, which are produced from tight resource formations, accounted for up nearly 90% of the 3.1 million barrel per day (b/d) growth in production from 2010 to 2017. Light, sweet crude oil accounted for more than half (56%) of total domestic crude oil production in 2017, and in EIA’s Annual Energy Outlook 2018 (AEO2018) Reference case, this share grows to 60% by 2020 and to 70% by 2050. U.S. supply of lighter crude oil from tight formations, such as the Bakken in North Dakota and the Wolfcamp and Eagle Ford in Texas, is projected in the Reference Case to continue to outpace that of medium and heavier crudes. Medium-gravity (API between 27 and 35) sour crudes, primarily Alaskan and Lower 48 states offshore production, accounted for about 30% of 2017 U.S. crude oil production and are projected to account for 18% of 2050 production in the AEO2018 Reference case. In the Reference Case, EIA projects that more than 80% of U.S. crude oil production from 2017 through 2050 will occur in the Gulf Coast and Midwest regions (as defined by Petroleum Administration for Defense Districts 3 and 2, respectively). Most of the growth in light, sweet crude oil production is projected in the Gulf Coast, increasing from 3.1 million b/d in 2017 to 5.3 million b/d in 2050. The Permian Basin has developed into one of the more active drilling regions in the United States because of its large geographic size, spanning 53 million acres across western Texas and southeastern New Mexico, and favorable geology, with many prolific tight oil formations such as the Wolfcamp, Spraberry, and Bonespring. The Midwest region is home to the Bakken formation in North Dakota, another significant source of light, sweet crude oil production. The pace and duration of projected crude oil production increases are dependent on crude oil prices and the quality and amount of technically recoverable resources. Two AEO2018 sensitivity cases explore this uncertainty. In the High Oil and Gas Resource and Technology case, tight oil production is higher than in the Reference case, so light, sweet crudes account for a greater share of domestic crude oil production, eventually reaching 76% of the total in 2050. In the AEO2018 Low Oil and Gas Resource and Technology case, the growth in tight oil production is lower than in the Reference case, but light, sweet crudes still account for most (56%) of the domestic crude oil production in 2050.