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Short-Term Energy Outlook

Release Date: January 9, 2018  |  Next Release Date: February 6, 2018  |  Full Report    |   Text Only   |   All Tables   |   All Figures

Natural Gas

Natural Gas Consumption. Total U.S. natural gas consumption averaged 74.0 billion cubic feet per day (Bcf/d) in 2017, a 1% decrease from 2016. Natural gas consumption is forecast to increase by 3.5 Bcf/d in 2018 and by 2.2 Bcf/d in 2019. The 2017 decrease in total natural gas consumption mainly reflects warm winter temperatures and lower electric power sector use. In 2017, U.S. heating degree days (HDD) were 2% lower than in 2016, and U.S. cooling degree days (CDD) in 2017 were 8% lower than in 2016. Electric power sector use of natural gas decreased by 1.6 Bcf/d (6%) in 2017. The decline reflects competition from increasing renewable energy use (particularly hydropower), competitive coal prices, and overall lower electricity generation levels.

Based on forecasts by the National Oceanic and Atmospheric Administration (NOAA), EIA projects 2018 HDD will be 11% higher than 2017 levels. The difference is driven temperatures during first quarters of 2017 and 2018. The first quarter of 2017 was unseasonably warm, and the first quarter of 2018 is projected to be relatively close to the 10-year average. On an annual basis, EIA expects combined residential and commercial natural gas consumption to increase by 1.3 Bcf/d in 2018 compared with 2017 levels and remain mostly unchanged in 2019.

Industrial sector consumption of natural gas increased by 1.6% from 2016 to 2017. In 2018, industrial consumption is expected to rise by 1.2%, averaging 21.7 Bcf/d in 2018. Industrial consumption is expected to increase by 2.6% in 2019. Most of the increase in the 2019 forecast is attributable to new chemical plants expected to come online. A low natural gas price environment in recent years has made it economical to increase the use of natural gas as feedstock in ammonia for nitrogenous fertilizer and methanol.

Natural Gas Production and Trade. Dry natural gas production averaged 73.6 Bcf/d in 2017, up 1.0% from the 2016 level and reversing the 2016 production decline. The strongest growth in dry natural gas production occurred late in the year, as improved economics related to expanded pipeline capacity contributed to a 3.8% increase in production between the third and fourth quarters of 2017. The rate of production growth is expected to moderate in 2018. <

EIA expects dry natural gas production to rise by 6.9 Bcf/d (9.3%) in 2018 and by 2.6 Bcf/d (3.2%) in 2019. If achieved, the forecast 6.9 Bcf/d increase in 2018 would be the highest on record. Growth is expected to be concentrated in Appalachia’s Marcellus and Utica regions, along with the Permian Basin region. Much of the expected increase in natural gas production is the result of increasing pipeline takeaway capacity out of the Appalachia producing region to end-use markets. The greater pipeline connectivity contributes to higher wellhead natural gas prices for producers and is expected to encourage production growth.

EIA projects liquefied natural gas (LNG) gross exports will average 3.0 Bcf/d in 2018, up from 1.9 Bcf/d in 2017. In 2018, U.S. liquefaction capacity will continue to expand. EIA expects the Cove Point terminal in Maryland to ramp up to full capacity. At the Elba Island facility in Georgia, 6 of the 10 small modular trains, each with a capacity of 0.03 Bcf/d, are expected to enter service. The first liquefaction train (capacity 0.7 Bcf/d) at Freeport LNG in Texas is also expected to come online by the end of 2018. EIA projects gross LNG exports to average 4.8 Bcf/d in 2019, when the four remaining modular trains at Elba Island come online and the remaining two trains at Freeport LNG enter service. Two trains in Corpus Christi, Texas, and three trains at Cameron LNG in Louisiana are also expected to enter service in 2019. EIA forecasts exports will ramp up in the second half of 2019 to an average of 5.5 Bcf/d, up from 4.1 Bcf/d in the first half of 2019. In both 2018 and 2019 the new liquefaction facilities will require a ramp up period, and they are forecast to operate below nameplate capacity for a period of time, lowering the overall LNG export capacity utilization rate.

Natural gas pipeline exports to Mexico through October increased by 0.4 Bcf/d in 2017 compared with the same period in 2016, and EIA expects growth to continue over the forecast period with ongoing Mexican energy market reform. A relatively low natural gas export price, rising demand from Mexico’s power sector, and increased pipeline capacity in both in the United States and Mexico have led to increased exports. U.S. gross pipeline exports are expected to increase by 0.6 Bcf/d in 2018 and by 0.8 Bcf/d in 2019 to an average of 8.0 Bcf/d

Total U.S. natural gas imports averaged 8.2 Bcf/d in 2017, and they are expected to average 7.9 Bcf/d in 2018 and 8.2 Bcf/d in 2019. A low natural gas price environment in Western Canada could contribute to increased seasonal imports for some regional U.S. markets.

In 2017, the United States was a net exporter of natural gas for the first time on an annual basis since 1957[1], with net exports averaging 0.4 Bcf/d. Overall, net natural gas exports are forecast to average 2.3 Bcf/d in 2018 and 4.6 Bcf/d in 2019.

Natural Gas Inventories. As of December 29, 2017, working natural gas inventories were 3,126 Bcf, 6% lower than both the five-year average and year-ago levels. Inventory draws in recent weeks have been larger than normal for this time of year, despite a rare winter injection of 2 Bcf during the week ending December 2, the first December injection since 2012. Based on an assumption of relatively normal temperatures in the first quarter of 2018, along with a forecast of growing natural production, EIA forecasts inventories to be 1,623 Bcf at the end of March, which would be 6% lower than the five-year average for that time of year. Inventories are expected to build slightly above the five-year average pace from the end of March through October, bringing inventories to a projected 3,861 Bcf at the end of October 2018, which is slightly higher than the previous five-year average for the end of October. In 2019, inventories are expected to be about 6% lower on average than 2018 levels.

Natural Gas Prices. Henry Hub spot prices averaged $2.99 per million British thermal units (MMBtu) in 2017, up 47 cents/MMBtu from a 17-year low in 2016. Henry Hub natural gas spot prices are forecast to average $2.88/MMBtu in 2018 and $2.92/MMBtu in 2019. Prices are expected to decline slightly from 2017 levels based on strong expected production growth, which EIA forecasts will meet growing domestic consumption and exports.

Natural gas futures contracts for April 2018 delivery that were traded during the five-day period ending January 4 averaged $2.75/MMBtu. Current options and futures prices indicate that market participants place the lower and upper bounds for the 95% confidence interval for April 2018 contracts at $2.01/MMBtu and $3.75/MMBtu, respectively. Last year at this time, the natural gas futures contracts for April 2017 delivery averaged $3.38/MMBtu, and the corresponding lower and upper limits of the 95% confidence interval were $2.39/MMBtu and $4.77/MMBtu, respectively.

Footnotes

[1] This sentence was updated on January 11, 2018, to add "since 1957." It was originally published on January 9, 2018, as: "In 2017, the United States was a net exporter of natural gas for the first time on an annual basis, with net exports averaging 0.4 Bcf/d."

U.S. Natural Gas Summary
  2016201720182019
Prices (dollars per thousand cubic feet)
Henry Hub Spot 2.613.102.993.03
Residential Sector 10.0411.1210.7010.77
Commercial Sector 7.297.947.847.87
Industrial Sector 3.524.174.084.13
Supply (billion cubic feet per day)
Marketed Production 77.8178.8886.4489.46
Dry Gas Production 72.8573.5780.4283.02
Pipeline Imports 7.977.977.708.02
LNG Imports 0.240.200.210.22
Consumption (billion cubic feet per day)
Residential Sector 11.8711.9612.8512.80
Commercial Sector 8.488.619.049.00
Industrial Sector 21.1021.4421.6922.25
Electric Power Sector 27.2825.6427.0128.34
Total Consumption 75.1074.0477.5379.72
Primary Assumptions (percent change from previous year)
Heating Degree Days -5.1-1.711.2-0.6
Cooling Degree Days 4.6-8.5-4.10.2
Commercial Employment 2.21.71.41.2
Natural-gas-weighted Industrial Production 1.13.03.43.7

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