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The Electric Reliability Council of Texas (ERCOT), grid operator for most of the state of Texas, estimates a reserve margin of 11% for this summer—lower than previous years and ERCOT’s 13.75% reference reserve margin—indicating a smaller cushion of resources to meet summer peak demand and an increased risk of grid stress conditions. The lower anticipated reserve margin is mainly a result of three large coal plants retiring in early 2018 and forecasts of record-breaking summer electricity demand. Although ERCOT is only expecting a slightly hotter-than-normal summer overall, abnormally hot stretches of weather in May and June have already set new monthly demand records. Hourly day-ahead prices at ERCOT’s North hub, which represents a region that includes the Dallas-Fort Worth area, reached $551 per megawatthour (MWh) on May 16 and 15-minute real-time prices reached $3,125/MWh on June 5, reflecting the dynamic needs of the grid during these unexpectedly high electricity demand periods. Reserve margins are projections of how much additional or reserve capacity is available beyond the amount needed to meet expected peak loads. These projections usually incorporate conservative estimates of factors such as the expected contribution of wind and solar resources during peak hours and demand reductions from load resources such as demand response programs. ERCOT’s final seasonal assessment of the anticipated reserve margin for the summer increased to 11% from earlier projections of 9.3% after a new generator moved up its online date, a mothballed generator became available, and a switchable generator that can choose to connect to either ERCOT or Southwest Power Pool became available to ERCOT. Reserve margin estimates from different sources can vary because of differences in the definitions of factors included in the calculations. Driven by continued growth of the Texas economy, ERCOT is again predicting record-breaking summer electricity demand, as it has for the past two summers, with a peak load forecast of 72,756 megawatts (MW) based on normal weather conditions. This forecast is more than 1,600 MW higher than the current all-time peak of 71,110 MW set in August 2016. While May 2018 was one of the hottest Mays on record for Texas, leading to a new May demand record that was more than 8,000 MW higher than the previous record, the June-August summer period is only expected to be slightly hotter than normal Unlike most regional transmission organizations, ERCOT does not have a capacity market. Capacity markets compensate generators and sometimes load resources for providing mainly capacity (and not energy) to the grid, although some capacity markets do have energy-related performance requirements. Consequently, ERCOT relies entirely on its energy market and energy prices to send accurate market signals about the grid’s need for additional capacity or generator capabilities and to provide adequate revenues to ERCOT generators because they are not receiving capacity payments. During the high temperatures in May, ERCOT issued several operating condition notices (OCNs) to signal the anticipation of possible emergency conditions; however, the grid operator maintained grid reliability without needing to take any further emergency procedure steps. The May and June price spikes in the day-ahead and real-time markets reflect the dynamically changing conditions of the grid. From day to day and on a real-time (hourly and sub-hourly) basis, the short-term needs of the grid can change quickly and depend on many factors, including the level of demand, the amount of generator outages, and the availability of resources to provide energy, ancillary services, and additional capacity to the grid. Three large coal plants retired in early 2018: the 1,865-MW Monticello plant; the 1,200-MW Sandow (4 & 5) plant; and the 1,208-MW Big Brown plant. These coal plants made up 4,273 MW of generation capacity, about 20% of coal capacity and 4% of total electricity generating capacity in ERCOT at the end of 2017. Before these coal plant retirements, most of the recent power plant retirements in ERCOT have been smaller and older natural gas steam plants that were built in the 1950s through 1970s, with some dating as early as the 1920s. The Monticello, Sandow, and Big Brown plants were all built in the 1970s or 1980s with some generating units added or upgraded as recently as 2010.

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.