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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.

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.

According to EIA’s Electric Power Monthly, total U.S. net electricity generation fell slightly (down 1.5%) in 2017, reflecting lower electricity demand. Natural gas and coal generation fell by 7.7% and 2.5% from 2016, respectively, as generation from several renewable fuels, particularly hydro, wind, and solar, increased from 2016 levels. Although natural gas continued to be most-used fuel for electricity generation for the third consecutive year, natural gas-fired electricity generation fell by 105 billion kilowatthours in 2017, the largest annual decline on record. Coal-fired electricity generation also fell, but to a lesser extent, marking the first year since 2008 that both natural gas- and coal-fired electricity generation fell in the same year. Coal-fired generation accounted for more than half of the electric capacity retired in 2017, with 6.3 gigawatts (GW) of the 11.2 GW total. For the first year in at least a decade, no new coal-fired generators were added. About 4.0 GW of natural gas-fired capacity was retired in 2017—most was steam turbine units. However, more natural gas capacity was added than retired, widening natural gas’s lead as the largest source of generating capacity in the United States. About 9.3 GW of new natural gas-fired generating capacity came online during 2017, 8.2 GW of which were combined-cycle units. Electricity from renewable sources, especially wind and solar, continued to increase in 2017. Wind made up 6.3% of total net generation, and utility-scale solar made up 1.3%—record shares for both fuels. In part as a result of record precipitation in California, hydroelectricity increased in 2017, accounting for 7.5% of total net generation. EIA’s latest Short-Term Energy Outlook expects hydro to continue to exceed wind in 2018, but wind is projected to become the predominant renewable electricity generation source in 2019. Nearly 6.3 GW of wind turbines and 4.7 GW of utility-scale solar photovoltaic systems were added in 2017. For each technology, about a third of the year’s capacity additions came online in the last month of the year; these December additions had little effect on 2017 annual generation values. Another 3.5 GW of small-scale solar capacity came online in 2017, increasing total small-scale solar capacity to 16.2 GW and surpassing biomass capacity, which ended 2017 at 14.2 GW.

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.

Working natural gas in storage in the Lower 48 states as of October 31, 2017, totaled 3,784 billion cubic feet (Bcf), as interpolated from EIA’s Weekly Natural Gas Storage Report data. Natural gas storage levels typically increase from April through October, although net injections sometimes occur in November. Inventories at the end of October 2017 were 2% lower than the previous five-year end-of-October average and 5% lower than the record-setting end-of-October level of 3,977 Bcf last year. Injection levels during refill season level can vary considerably, depending in part on inventory levels at the start of the refill season. This year, relatively high inventory levels at the beginning of the injection season (April) would naturally have resulted in a slower-than-average pace of injections. Nevertheless, injections were insufficient to return inventories to their recent historical average. From May 2015 through mid-September 2017, working gas levels were higher than the five-year average for 118 out of 122 weeks. However, since late September 2017, working natural gas levels have been lower than the previous five-year average for seven consecutive weeks, based on data through November 10. Natural gas storage is used to balance out seasonal fluctuations in demand. Natural gas demand is highest in the winter months, when residential and commercial demand for natural gas for space heating increases. Natural gas consumption in the power sector is highest in summer months, when overall electricity demand is relatively high for cooling. ased on data through August, year-over-year declines in electric power sector consumption have been partially offset by changes in natural gas trade, as exports have increased and imports have remained relatively flat. EIA’s latest Short-Term Energy Outlook expects the United States to be a net exporter of natural gas on an annual basis in 2017. Five new pipeline projects in the Northeast received approval from the Federal Energy Regulatory Commission (FERC) in October, some of the first projects to be approved since February. FERC regained its quorum in August after the Senate confirmed two new commissioners. These confirmations ended a six-month period when FERC was unable to issue certificates to allow construction of interstate energy transmission infrastructure, including natural gas pipeline projects. FERC did not have a quorum beginning in February 2017 when the number of commissioners fell below the required minimum of three. The final two commissioners await a floor vote by the Senate. The five projects approved in October, which are designed to increase the delivery capacity from the Northeast’s Utica and Marcellus natural gas-producing regions, are: Mountain Valley Pipeline: a 2 billion cubic feet per day (Bcf/d), 303-mile pipeline from West Virginia to Virginia Equitrans Expansion Project: about 8 miles in pipeline expansions, providing 0.6 Bcf/d from Pennsylvania to West Virginia Supply Header Pipeline: a 1.5 Bcf/d, 38-mile pipeline from West Virginia to Pennsylvania Atlantic Coast Pipeline: a 1.5 Bcf/d, 600-mile pipeline from West Virginia to North Carolina Eastern Shore 2017 Expansion Project: 40 miles in pipeline expansions, providing 0.061 Bcf/d from Pennsylvania to Delaware Before losing its quorum on February 3, 2017, FERC had certificated more than 7 Bcf/d of pipeline capacity. Since then, as of October 24, 2017, 12 pre-filing applications have been submitted to FERC for pipeline projects transmitting natural gas in the United States and 46 pipeline projects have FERC applications in process. The capacity of all these projects totals about 40 Bcf/d, covering slightly more than 2,500 miles of both new and upgraded pipeline construction. In comparison, the Lower 48 states have more than 300,000 miles of interstate and intrastate natural gas transmission pipeline in use. The eight largest projects by capacity with applications before FERC have a total capacity of slightly less than 20 Bcf/d, or more than 60% of the capacity for all pending natural gas pipeline applications. Six of these projects, located in Texas, Louisiana, and Oklahoma, are intended to support liquefied natural gas (LNG) export projects. The construction of five of these pipeline projects will likely be tied to the approval of the associated LNG export terminals. These projects include: Rio Bravo Pipeline: a 137-mile pipeline in Texas with a capacity of 4.5 Bcf/d, connecting the Rio Grande LNG facility to available interstate pipelines Driftwood Pipeline: a 96-mile pipeline in Louisiana with a capacity of 4 Bcf/d, connecting the Driftwood LNG facility to available interstate pipelines Port Arthur Pipeline–Louisiana Connector: a 135-mile pipeline with a capacity of 2 Bcf/d, mostly in Louisiana with a small segment of pipeline in Texas to connect to the Port Arthur LNG facility in Texas Port Arthur Pipeline–Texas Connector: a 34-mile pipeline with a capacity of 2 Bcf/d, mostly in Texas with a small segment of pipeline in Louisiana, terminating at the Port Arthur LNG facility in Texas Gator Express Pipeline: a 27-mile pipeline in Louisiana with a capacity of 1.9 Bcf/d, connecting the Plaquemines LNG facility to the Tennessee Gas pipeline and the Texas Eastern Transmission pipeline In addition, the proposed Cheniere Midship Pipeline in Oklahoma is a 199-mile pipeline, with a capacity of 1.4 Bcf/d, that would connect to pipelines that support Cheniere’s export facilities and provide natural gas to consumers along the Gulf Coast. Two other relatively large proposed pipeline projects would further increase the delivery capacity from natural gas-producing regions in the Northeast. These projects include: Mountaineer XPress Pipeline: a 2.7 Bcf/d, 165-mile pipeline in West Virginia PennEast Pipeline: a 1 Bcf/d, 120-mile pipeline from Pennsylvania to New Jersey