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Short-Term Energy Outlook

Release Date: December 12, 2017  |  Next Release Date: January 9, 2018  |  Full Report    |   Text Only   |   All Tables   |   All Figures

Natural Gas

The front-month natural gas futures contract for delivery at Henry Hub settled at $2.76/million British thermal units (MMBtu) on December 7, 2017, a decrease of 13 cents/MMBtu from November 1 (Figure 8). Several factors affected price movements in November. Natural gas inventories fell further below the five-year average in recent weeks until a rare injection into storage for the week ending December 1 brought inventories up to 36 billion cubic feet below the five-year average. Increased takeaway capacity from Appalachia is expected to result in increased natural gas production in the coming months and could limit significant upward price pressure, although colder-than-normal temperatures throughout the rest of 2017 could contribute to price increases. The Henry Hub natural gas spot price averaged $3.01/MMBtu in November, almost 14 cents/MMBtu higher than in October. EIA expects that price to average $3.13/MMBtu in December and average $3.12/MMBtu in 2018.

Figure 8: U.S. natural gas front-month futures prices and storage

Natural gas futures prices in November traded within a 43 cents/MMBtu range, wider than in recent months, but they stayed close to $3.00/MMBtu. In comparison, natural gas futures prices in October traded within a 31 cents/MMBtu range, the narrowest range for October since 1995. Natural gas front-month implied volatility increased 2.3 percentage points since November 1, settling at 39% on December 7 (Figure 9). After reaching a three-year low in August 2017, volatility has been steadily increasing, as is typical heading into winter, but it remains below the volatility levels seen in November 2015 and 2016. In November 2016, liquefied natural gas gross exports were more than 1 billion cubic feet per day (Bcf/d) for the first time in U.S. history, as Sabine Pass entered service, and storage reached an all-time high of more than 4 trillion cubic feet, factors that may have contributed to higher volatility. Natural gas production has shown year-on-year growth since June 2017, and inventories are within 1% of the five-year average level, which may moderate implied volatility.

Figure 9: Natural gas implied volatility

U.S. Natural Gas Summary
  2015 2016 2017 2018
Prices (dollars per thousand cubic feet)
Henry Hub Spot 2.73 2.61 3.12 3.24
Residential Sector 10.36 10.04 11.13 10.92
Commercial Sector 7.90 7.29 7.97 8.02
Industrial Sector 3.93 3.52 4.20 4.31
Supply (billion cubic feet per day)
Marketed Production 78.83 77.81 78.82 85.53
Dry Gas Production 74.15 72.85 73.55 79.70
Pipeline Imports 7.20 7.97 7.94 7.63
LNG Imports 0.25 0.24 0.21 0.21
Consumption (billion cubic feet per day)
Residential Sector 12.64 11.87 11.93 12.87
Commercial Sector 8.77 8.48 8.56 9.04
Industrial Sector 20.61 21.10 21.33 21.60
Electric Power Sector 26.34 27.28 25.49 26.40
Total Consumption 74.64 75.10 73.71 76.85
Primary Assumptions (percent change from previous year)
Heating Degree Days -10.2 -5.1 -1.7 11.1
Cooling Degree Days 14.6 4.7 -8.6 -4.3
Commercial Employment 2.4 2.2 1.7 1.2
Natural-gas-weighted Industrial Production -2.0 1.1 2.7 3.4