· This edition of the Short-Term Energy Outlook is the first to include forecasts for 2019.
· Benchmark North Sea Brent crude oil spot prices averaged $64 per barrel (b) in December, an almost $2/b increase from the November average and the highest monthly average since November 2014.
· Brent crude oil prices averaged $54/b in 2017 and are forecast to average $60/b in 2018 and $61/b in 2019. West Texas Intermediate (WTI) crude oil spot prices are forecast to average $4/b less than Brent prices in both 2018 and 2019. EIA’s forecast for the average WTI price for December 2018 of $58/b should be considered in the context of NYMEX contract values for December 2018 delivery. NYMEX contract values traded during the five-day period ending January 4 suggest that a range of $40/b to $85/b encompasses the market expectation for WTI prices in December 2018 at the 95% confidence level.
· U.S. regular gasoline retail prices averaged $2.48 per gallon (gal) in December, down almost 9 cents/gal from the average in November but 22 cents/gal higher than at the same time last year. U.S. regular gasoline retail prices averaged $2.42/gal in 2017 and are forecast to average $2.57/gal in 2018 and $2.58/gal in 2019.
· U.S. crude oil production averaged an estimated 9.3 million barrels per day (b/d) in 2017 and is estimated to have averaged 9.9 million b/d in December. U.S. crude oil production is forecast to average 10.3 million b/d in 2018, which would mark the highest annual average production in U.S. history, surpassing the previous record of 9.6 million b/d set in 1970. EIA forecasts production to increase to an average of 10.8 million b/d in 2019 and to surpass 11 million b/d in November 2019.
· Dry natural gas production is forecast to average 80.4 billion cubic feet per day (Bcf/d) in 2018, a 6.9 Bcf/d increase from the 2017 level, which would be the highest year-over-year increase on record. Forecast dry natural gas production increases by an average of 2.6 Bcf/d in 2019.
· Henry Hub natural gas spot prices are forecast to average $2.88 per million British thermal units (MMBtu) in 2018 and $2.92/MMBtu in 2019, compared with the 2017 average of $2.99/MMBtu. EIA’s forecast for the average Henry Hub price for December 2018 of $3.04/MMBtu should be considered in the context of NYMEX contract values for December 2018 delivery. NYMEX contract values traded during the five-day period ending January 4 suggest that a range of $1.83/MMBtu to $4.89/MMBtu encompasses the market expectation for Henry Hub prices in December 2018 at the 95% confidence level.
· Coal production increased by 45 million short tons (MMst) (6%) in 2017 in response to high demand for U.S. coal exports. Coal production is forecast to decline by 14 MMst (2%) in 2018 and by 18 MMst (2%) in 2019, as export demand is expected to slow and natural gas prices are expected to stay below $3/MMBtu during much of the forecast period, which contributes to less coal use for electricity generation.
· EIA expects the share of U.S. total utility-scale electricity generation from natural gas to rise from 32% in 2017 to 33% in 2018 and to 34% in 2019, as a result of low natural gas prices. Coal's forecast generation share falls from 30% in 2017 to slightly lower than 30% in 2018 and 28% in 2019. The nuclear share of generation was 20% in 2017 and is forecast to average 20% in 2018 and 19% in 2019. Nonhydropower renewables provided almost 10% of electricity generation in 2017, and its 2018 share is expected be similar before increasing to almost 11% in 2019. The generation share of hydropower was more than 7% in 2017 and is forecast to be slightly lower than 7% in both 2018 and 2019.
· After declining by 1.0% in 2017, energy-related carbon dioxide (CO2) emissions are forecast to increase by 1.7% in 2018 and by 0.2% in 2019. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, and energy prices.
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In its latest Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that natural gas-fired electricity generation in the United States will increase by 6% in 2019 and by 2% in 2020. EIA also forecasts that generation from wind power will increase by 6% in 2019 and by 14% in 2020. These trends vary widely among the regions of the country; growth in natural gas generation is highest in the mid-Atlantic region and growth in wind generation is highest in Texas. EIA expects coal-fired electricity generation to decline nationwide, falling by 15% in 2019 and by 9% in 2020.
The trends in projected generation reflect changes in the mix of generating capacity. In the mid-Atlantic region, which is mostly in the PJM Interconnection transmission area, the electricity industry has added more than 12 gigawatts (GW) of new natural gas-fired generating capacity since the beginning of 2018, an increase of 17%.
This new natural gas capacity in PJM has replaced some coal-fired generating capacity—6 GW of coal-fired generation capacity has been retired in that region since the beginning of 2018. The Oyster Creek nuclear power plant in New Jersey was also retired in 2018, and the Three Mile Island plant in Pennsylvania plans to shut down its last remaining reactor this month.
These changes in capacity contribute to EIA’s forecast that natural gas will fuel 39% of electricity generation in the PJM region in 2020, up from a share of 31% in 2018. In contrast, coal is expected to generate 20% of PJM electricity next year, down from 28% in 2018. In 2010, coal fueled 54% of the region’s electricity generation, and natural gas generated 11%.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Wind power has been the fastest-growing source of electricity in recent years in the Electric Reliability Council of Texas (ERCOT) region that serves most of Texas. Since the beginning of 2018, the industry has added 3 GW of wind generating capacity and plans to add another 7 GW before the end of 2020. These additions would result in an increase of nearly 50% from the 2017 wind capacity level in ERCOT. EIA expects wind to supply 20% of ERCOT total generation in 2019 and 24% in 2020. If realized, wind would match coal’s share of ERCOT's electricity generation this year and exceed it in 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Natural gas-fired generation in ERCOT has fluctuated in recent years in response to changes in the cost of the fuel. EIA forecasts the Henry Hub natural gas price will fall by 21% in 2019, which contributes to EIA’s expectation that ERCOT’s natural gas generation share will rise from 45% in 2018 to 47% this year. Although EIA forecasts next year’s natural gas prices to remain relatively flat in 2020, the large increase in renewable generating capacity is expected to reduce the region’s 2020 natural gas generation share to 41%.
Headline crude prices for the week beginning 9 September 2019 – Brent: US$61/b; WTI: US$56/b
Headlines of the week
Detailed market research and continuous tracking of market developments—as well as deep, on-the-ground expertise across the globe—informs our outlook on global gas and liquefied natural gas (LNG). We forecast gas demand and then use our infrastructure and contract models to forecast supply-and-demand balances, corresponding gas flows, and pricing implications to 2035.Executive summary
The past year saw the natural-gas market grow at its fastest rate in almost a decade, supported by booming domestic markets in China and the United States and an expanding global gas trade to serve Asian markets. While the pace of growth is set to slow, gas remains the fastest-growing fossil fuel and the only fossil fuel expected to grow beyond 2035.Global gas: Demand expected to grow 0.9 percent per annum to 2035
While we expect coal demand to peak before 2025 and oil demand to peak around 2033, gas demand will continue to grow until 2035, albeit at a slower rate than seen previously. The power-generation and industrial sectors in Asia and North America and the residential and commercial sectors in Southeast Asia, including China, will drive the expected gas-demand growth. Strong growth from these regions will more than offset the demand declines from the mature gas markets of Europe and Northeast Asia.
Gas supply to meet this demand will come mainly from Africa, China, Russia, and the shale-gas-rich United States. China will double its conventional gas production from 2018 to 2035. Gas production in Europe will decline rapidly.LNG: Demand expected to grow 3.6 percent per annum to 2035, with market rebalancing expected in 2027–28
We expect LNG demand to outpace overall gas demand as Asian markets rely on more distant supplies, Europe increases its gas-import dependence, and US producers seek overseas markets for their gas (both pipe and LNG). China will be a major driver of LNG-demand growth, as its domestic supply and pipeline flows will be insufficient to meet rising demand. Similarly, Bangladesh, Pakistan, and South Asia will rely on LNG to meet the growing demand to replace declining domestic supplies. We also expect Europe to increase LNG imports to help offset declining domestic supply.
Demand growth by the middle of next decade should balance the excess LNG capacity in the current market and planned capacity additions. We expect that further capacity growth of around 250 billion cubic meters will be necessary to meet demand to 2035.
With growing shale-gas production in the United States, the country is in a position to join Australia and Qatar as a top global LNG exporter. A number of competing US projects represent the long-run marginal LNG-supply capacity.Key themes uncovered
Over the course of our analysis, we uncovered five key themes to watch for in the global gas market: