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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.

U.S. natural gas plant liquids (NGPL) production has nearly doubled since 2010, outpacing the rate of natural gas production growth and setting an annual record of 3.7 million barrels per day (b/d) in 2017. NGPLs are produced at natural gas processing plants, which separate liquids from raw natural gas to produce pipeline-quality dry natural gas. Marketed natural gas includes both NGPLs and dry natural gas. Growth in U.S. natural gas production has been driven by shale gas, particularly from the Appalachian region, and to a lesser extent by associated natural gas, a byproduct of crude oil production. The high liquids content of many shale plays means that growth in marketed natural gas production has led to increased production of NGPLs. NGPLs accounted for a growing share of marketed natural gas production between 2010 and 2017, making up 15% of total marketed production in 2017 in energy content terms, up from 11% in 2010. The increased share of NGPL production can be attributed to expanded capacity to produce, transport, and consume NGPL products. Increases in NGPL production pushed two measures of total natural gas production—gross withdrawals and marketed production—to record highs in 2017. NGPLs that come out of natural gas plants are a mix of ethane, propane, isobutane and normal butane, and natural gasoline that requires further processing to convert into separate marketable products. The yield of these liquid products, especially ethane, varies significantly depending on product prices, the ability to process and distribute them to market, and the makeup of the raw natural gas. With the exception of ethane, natural gas plant operators may leave only trace amounts of NGPLs in dry—pipeline-quality—natural gas. Natural gas specifications set by pipeline operators allow for significant amounts of ethane to be left in dry gas at the discretion of natural gas plant operators. If ethane prices are low relative to the price of natural gas on a heating-value equivalent basis, more ethane is likely to be left in the dry natural gas stream, provided that the mix can still meet specifications required by natural gas pipeline operators. U.S. ethane prices began declining relative to natural gas prices in late 2011 and remained consistently lower than the price of natural gas between 2013 and 2015 when ethane production began to outpace consumption. As a result, the ethane share of total U.S. NGPLs declined between 2012 and 2015, when natural gas producers had the incentive to leave as much ethane in pipeline natural gas as possible to capture its value as a heating fuel instead of recovering and selling it as a separate product. U.S. ethane prices began to increase in 2016 when ethane demand increased, and ethane prices surpassed natural gas prices in the United States on a heat-content equivalent basis in 2016 and 2017, causing the ethane share of U.S. NGPL production to increase as well. Two U.S. ethane export terminals opened in 2016, and two U.S. ethane-consuming petrochemical plants opened in 2017, providing additional sources of demand. Annual average U.S. NGPL production increased nearly 400,000 b/d between 2015 and 2017, and about 175,000 b/d of this increase resulted from growth in ethane production. Several more petrochemical plants are expected to come online in the United States in 2018 and 2019, further driving increases in ethane demand and prices. First-quarter 2018 U.S. ethane production was 260,000 b/d higher than the first-quarter 2017 level. Ethane production will increase by another 440,000 b/d between the first quarter of 2018 and the fourth quarter of 2019, according to EIA’s Short-Term Energy Outlook, accounting for 52% of the growth in NGPL production.

Global trade in liquefied natural gas (LNG) reached 38.2 billion cubic feet per day (Bcf/d) in 2017, a 10% (3.5 Bcf/d) increase from 2016 and the largest annual volume increase since 2010, according to the Annual Report on LNG trade by the International Association of Liquefied Natural Gas Importers (GIIGNL). In 2017, there were 19 LNG exporting countries and 40 LNG importing countries. Australia and the United States were among the countries with the largest increases (2.7 Bcf/d combined) in 2017 LNG exports. Besides Australia and the United States, several other countries also increased LNG exports in 2017. The return to service of Angola LNG and increases from several countries including Nigeria, Malaysia, Algeria, Russia, and Brunei added another 1.4 Bcf/d of LNG exports, more than offsetting a combined decline of 0.6 Bcf/d in exports from Qatar, Indonesia, Norway, Peru, the United Arab Emirates, and Trinidad. Asian countries led the growth in global LNG imports, accounting for 74% (2.6 Bcf/d) of the increase in 2017. Japan remains the largest LNG importer, importing 11.0 Bcf/d in 2017. China had the largest growth in LNG imports globally (1.5 Bcf/d) and became the world’s second-largest LNG importer in 2017, surpassing South Korea. LNG imports also increased in South Korea, Pakistan, Taiwan, and Thailand, which collectively added 1.0 Bcf/d. Europe increased its LNG imports by 1.4 Bcf/d, primarily in Spain, Italy, Portugal, France, and Turkey. LNG imports in the United Kingdom declined by 0.34 Bcf/d (35%), one of only two countries in Europe to experience declines in LNG imports, as lower winter heating demand from the residential sector and increased electricity generation from wind reduced the demand for natural gas. LNG imports in South America (Brazil, Argentina, Chile, and Colombia) remained essentially unchanged from 2016. In North America, Mexico’s LNG imports increased by 17% as the country continued to rely on LNG supplies amid declining domestic production and construction delays in infrastructure connecting the Mexican domestic grid to natural gas pipeline exports from the United States. LNG imports into the Middle East declined by 9%, primarily to Egypt and the United Arab Emirates (Dubai). Growth in LNG trade was driven in part by new liquefaction capacity commissioned in Australia, the United States, and Russia, collectively adding 3.4 Bcf/d of liquefaction capacity. The world’s first floating liquefaction plant, Malaysia’s PFLNG Satu (0.2 Bcf/d capacity), was also commissioned in 2017. Since 2013, the United States and Australia have added a combined 9.67 Bcf/d of new liquefaction capacity, with another 8.3 Bcf/d expected to be completed by 2020. Including additions in the United States and Australia, liquefaction projects currently under construction are projected to increase global liquefaction capacity by 13.5 Bcf/d by 2022. The United States is expected to add 6.05 Bcf/d of new liquefaction capacity by 2021, in addition to 3.5 Bcf/d already in operation at Sabine Pass and Cove Point. This year the Elba Island liquefaction project in Georgia is expected to commission the first 6 of 10 small modular liquefaction units, or trains, with a combined capacity of 0.2 Bcf/d. New trains at Cameron, Freeport, and Corpus Christi—all along the U.S. Gulf Coast—are expected to be commissioned in the next three years.