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The natural gas spot price spread between the Permian Basin, as priced at the Waha Hub in western Texas, and the U.S. national benchmark Henry Hub in Louisiana has grown considerably in the past year. Natural gas prices at Waha are nearly a dollar per million British thermal units (MMBtu) lower than Henry Hub prices. This spread widened as the ability to transport the increased natural gas production in the Permian Basin in western Texas and southeastern New Mexico was constrained by existing pipeline capacity. Based on estimates in EIA’s most recent Drilling Productivity Report, production of natural gas in the Permian Basin averaged 10.4 billion cubic feet per day (Bcf/d) in June 2018, which was 2.1 Bcf/d more than in June 2017. Much of this increase in production is associated natural gas, or natural gas produced as a byproduct of the increase in oil production from oil-directed rigs. As a result, the increase in natural gas production closely correlated with the increase in crude oil production in the Permian Basin, which averaged 3.3 million barrels per day (b/d) in June 2018, up 0.9 million b/d from the June 2017 level. As Permian Basin oil production grows, producers must find outlets for the associated natural gas. Once pipeline capacity is fully used, choices are limited. The widening price differential between Waha and Henry Hub indicates pipeline capacity is already somewhat constrained. Producers may flare or vent the natural gas, although these disposal methods are regulated in Texas and New Mexico. Both states allow flaring from wells during drilling and immediately after completion. However, after a certain amount of time, producers can only flare natural gas after receiving exemptions from a state agency. If natural gas production continues to grow, and natural gas prices continue to fall, some producers in the area may cease oil production to avoid producing associated natural gas. Two pipelines—Comanche Trail and Trans-Pecos—were completed in 2017 to export Permian natural gas to Mexico. Although these pipelines have a combined takeaway capacity of 2.6 Bcf/d, they are not expected to see significant flows until late 2018 or early 2019 when downstream pipeline infrastructure in Mexico enters service. The only other project expected to come online in 2018 is the combined expansion of the North Texas Pipeline and resumption of service on the Old Ocean Pipeline, which collectively will increase pipeline capacity out of the Permian by 0.15 Bcf/d. Several new pipelines are currently in development to carry natural gas from the Permian Basin to the Gulf Coast: the Gulf Coast Express Pipeline (2.0 Bcf/d capacity), the Permian to Katy Pipeline (1.7 to 2.3 Bcf/d capacity), and the Pecos Trail Pipeline (1.9 Bcf/d capacity). Of these three projects, only the Gulf Coast Express is under construction, with an expected in-service date of October 2019. The proposed pipelines from the Permian Basin are intended to meet Gulf Coast demand for natural gas, which includes new liquefied natural gas export facilities and regional industrial use. 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.

U.S. exports of methyl tert-butyl ether (MTBE), a motor gasoline additive, totaled 38,000 barrels per day (b/d) in 2017, primarily to Mexico, Chile, and Venezuela. MTBE was once commonly used in the United States but was phased out in the late 2000s as a result of water contamination concerns. Since then, fuel ethanol has replaced MTBE as a gasoline additive. MTBE is a fuel oxygenate that boosts octane ratings and helps achieve more complete combustion in gasoline engines. Since 2005, most U.S. exports of MTBE have gone to Mexico and Venezuela, with increasing exports to Chile. In 2017, Mexico accounted for two-thirds (66%) of U.S. MTBE exports. Economic instability in Venezuela may have contributed to the decrease in U.S. exports of MTBE to that country in recent years. Overall, MTBE accounts for a small portion of total U.S. petroleum product exports, averaging 0.7% of the total in 2017. MTBE is used as an oxygenate instead of fuel ethanol in those countries, in part, because it has lower evaporative emissions, can be shipped in pipelines alongside finished petroleum products, and does not require the kinds of infrastructure investments specific to ethanol. Virtually all U.S. MTBE exports originate from the Gulf Coast, where production is concentrated. MTBE can be blended with motor gasoline blendstock in the United States to produce a finished product that is subsequently transported to destinations in Mexico. MTBE was once a common fuel additive in the United States. U.S. blending of MTBE into motor gasoline peaked in 1999 at 260,000 b/d. In that year, the volume of fuel ethanol added to motor gasoline totaled 38,000 b/d. However, between 2000 and 2007, 23 states instituted a partial or complete ban on MTBE blended into motor gasoline because of groundwater contamination concerns. The result was an eventual phase out as a fuel oxygenate in the United States and a decline in domestic MTBE consumption that was replaced with ethanol. In contrast to MTBE, the use of fuel ethanol has been supported by tax subsidies such as the Volumetric Ethanol Excise Tax Credit and by the Renewable Fuel Standard, which mandates the use of biofuels in the nation’s transportation supply. As a result, almost all motor gasoline in the United States contains 10% fuel ethanol blends.

EIA’s July 2018 Short-Term Energy Outlook (STEO) expects natural gas-fired power plants to supply 37% of U.S. electricity generation this summer (June, July, and August), near the record-high natural gas-fired generation share in summer 2016. EIA forecasts the share of generation from coal-fired power plants will drop slightly to 30% in summer 2018, continuing a multi-year trend of lower coal-fired electricity generation. The share of electricity generation supplied by natural gas-fired power plants has increased over the past decade, while the share supplied by coal has fallen, primarily as a result of sustained low natural gas prices, increases in natural gas-fired capacity, and retirements of coal-fired generating capacity. Over the three-year period from 2015 to 2017, the cost of natural gas delivered to electric generators averaged $3.16 per million Btu (MMBtu), compared with $7.69/MMBtu between 2006 and 2008. The combination of relatively low natural gas prices, environmental regulations, and supportive renewable energy policies has led the industry to build new natural gas-fired and renewable capacity and to retire coal-fired power plants. As reported on EIA’s Preliminary Monthly Electric Generator Inventory, power plant operators added 5.4 gigawatts (GW) of new natural gas-fired generating capacity during the first four months of 2018 with an additional 15 GW scheduled to come online through the end of the year. This addition would be the largest increase in natural gas capacity since 2004. The electric industry also added 2.6 GW of new utility-scale solar and wind generating capacity during the first four months of the year, with an additional 9.6 GW scheduled to come online by the end of 2018. More than 10 GW of coal-fired capacity was retired over the 12-month period ending April 2018. EIA forecasts the delivered cost of natural gas will average $3.16/MMBtu this summer, 2% lower than the average cost during the summer of 2017. In contrast, the cost of coal delivered to electric generators is forecast to rise slightly this summer. The continued low cost of natural gas, along with the recent additions of natural gas-fired capacity and retirements of coal power plants, drive EIA’s expectation that natural gas will contribute a growing share of electricity generation this summer, while coal's share will fall. The largest changes in generation shares occur in the Midwest census region. During the summer of 2018, EIA expects natural gas will supply 20% of electricity in the Midwest, up from 15% last summer. The forecast share of generation from coal in the Midwest falls from 53% last summer to 49% this summer. Unlike the rest of the country, natural gas generation in the West census region is forecast to decline this summer as renewable energy generating capacity increases. Nearly 2 GW of utility-scale solar generating capacity came online in the West census region during the 12 months ending in April. EIA forecasts the share of generation in the West from renewable sources other than hydropower will increase to 16% in summer 2018, up from 14% last summer.

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