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Last Updated: April 10, 2019
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U.S. residential electricity price

Forecast Highlights

Global liquid fuels

  • For the 2019 summer driving season that runs from April through September, EIA forecasts that U.S. regular gasoline retail prices will average $2.76 per gallon (gal), down from an average of $2.85/gal last summer. EIA’s forecast is discussed in its Summer Fuels Outlook. The lower forecast gasoline prices primarily reflect EIA’s expectation of lower crude oil prices in 2019. For all of 2019, EIA expects U.S. regular gasoline retail prices to average $2.60/gal and gasoline retail prices for all grades to average $2.71/gal, which would result in the average U.S. household spending about $100 (4%) less on motor fuel in 2019 compared with 2018.
  • Brent crude oil spot prices averaged $66 per barrel (b) in March, up $2/b from February 2019. Brent prices for the first quarter of 2019 averaged $63/b, which is $4/b lower than the same period in 2018. Despite lower crude oil prices than last year, Brent prices in March were $9/b higher than in December 2018, marking the largest December-to-March price increase since December 2011 to March 2012. EIA forecasts Brent spot prices will average $65/b in 2019 and $62/b in 2020, compared with an average of $71/b in 2018. EIA expects that West Texas Intermediate (WTI) crude oil prices will average $8/b lower than Brent prices in the first half of 2019 before the discount gradually falls to $4/b in late-2019 and through 2020.
  • EIA estimates that U.S. crude oil production averaged 12.1 million barrels per day (b/d) in March, up 0.3 million b/d from the February average. EIA forecasts that U.S. crude oil production will average 12.4 million b/d in 2019 and 13.1 million b/d in 2020, with most of the growth coming from the Permian region of Texas and New MexicoWest Texas Intermediate (WTI) crude oil price


World liquid fuels production and consumption balance


Natural gas

  • The Henry Hub natural gas spot price averaged $2.95/million British thermal units (MMBtu) in March, up 26 cents/MMBtu from February. Prices increased as a result of colder-than-normal temperatures across much of the United States, which increased the use of natural gas for space heating. EIA expects strong growth in U.S. natural gas production to put downward pressure on prices in 2019 and in 2020. EIA expects Henry Hub natural gas spot prices will average $2.82/MMBtu in 2019, down 33 cents/MMBtu from 2018. The forecasted 2020 Henry Hub spot price is $2.77/MMBtu.
  • EIA forecasts that dry natural gas production will average 91.0 billion cubic feet per day (Bcf/d) in 2019, up 7.6 Bcf/d from 2018. EIA expects natural gas production will continue to grow in 2020 to an average of 92.5 Bcf/d.
  • EIA estimates that natural gas inventories ended March at 1.2 trillion cubic feet (Tcf), which would be 17% lower than levels from a year earlier and 30% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections will outpace the previous five-year average during the April-through-October injection season and that inventories will reach 3.7 Tcf at the end of October, which would be 13% higher than October 2018 levels but 1% lower than the five-year average.


  • U.S. natural gas prices


  • U.S. residential electricity price


  • West Texas Intermediate (WTI) crude oil price


Electricity, coal, renewables, and emissions

  • EIA expects the average U.S. residential customer will use an average of 1,026 kilowatt hours (kWh) of electricity per month during the summer cooling season that runs from June through August, 2019, about 5% less than the same period last year. EIA uses the National Oceanic and Atmospheric Administration’s weather forecast, which indicates that temperatures will be cooler than last summer in all regions of the United States. The cooler forecast temperatures contribute to the lower expected electricity use.
  • EIA forecasts that U.S. residential electricity prices will average 13.4 cents/kWh during the summer cooling season, about 2% higher than last summer. The higher forecast prices primarily reflect higher actual generation fuel costs from 2018 that affect retail rates with a time lag, as well as rising electric transmission and distribution costs.
  • EIA forecasts that all renewable fuels, including wind, solar, and hydroelectric generation, will produce 18% of U.S. electricity in 2019, and almost 20% in 2020. EIA expects that wind generation will surpass hydroelectric generation to become the leading source of renewable electricity in both years.
  • EIA estimates that U.S. coal production decreased by 19 million short tons (MMst) (2%) in 2018, totaling 756 MMst. EIA expects that coal production will continue to fall in the forecast as both domestic consumption and exports, which reached a five-year high in 2018, are forecast to decline. In the electric power sector, which accounts for more than 90% of U.S. coal consumption, more than 7 gigawatts of coal-fired generation is scheduled to retire by the end of 2020. EIA forecasts that coal production will total 684 MMst in 2019 (down by 9% from 2018) and 640 MMst in 2020 (down by 6% from 2019).
  • After rising by 2.7% in 2018, EIA forecasts that U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.6% in 2019 and by 1.0% in 2020. EIA expects emissions to fall in 2019 and in 2020 as forecasted temperatures return to near normal after a warm summer and cold winter in 2018, and because the share of electricity generated from natural gas and renewables is forecast to increase while the share generated from coal, which produces more CO2 emissions, is forecast to decrease. Energy-related CO2 emissions are sensitive to weather, economic growth, energy prices, and fuel mix.

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In 2018, the United States consumed more energy than ever before

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Primary energy consumption in the United States reached a record high of 101.3 quadrillion British thermal units (Btu) in 2018, up 4% from 2017 and 0.3% above the previous record set in 2007. The increase in 2018 was the largest increase in energy consumption, in both absolute and percentage terms, since 2010.

Consumption of fossil fuels—petroleum, natural gas, and coal—grew by 4% in 2018 and accounted for 80% of U.S. total energy consumption. Natural gas consumption reached a record high, rising by 10% from 2017. This increase in natural gas, along with relatively smaller increases in the consumption of petroleum fuels, renewable energy, and nuclear electric power, more than offset a 4% decline in coal consumption.

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum consumption in the United States increased to 20.5 million barrels per day (b/d), or 37 quadrillion Btu in 2018, up nearly 500,000 b/d from 2017 and the highest level since 2007. Growth was driven primarily by increased use in the industrial sector, which grew by about 200,000 b/d in 2018. The transportation sector grew by about 140,000 b/d in 2018 as a result of increased demand for fuels such as petroleum diesel and jet fuel.

Natural gas consumption in the United States reached a record high 83.1 billion cubic feet/day (Bcf/d), the equivalent of 31 quadrillion Btu, in 2018. Natural gas use rose across all sectors in 2018, primarily driven by weather-related factors that increased demand for space heating during the winter and for air conditioning during the summer. As more natural gas-fired power plants came online and existing natural gas-fired power plants were used more often, natural gas consumption in the electric power sector increased 15% from 2017 levels to 29.1 Bcf/d. Natural gas consumption also grew in the residential, commercial, and industrial sectors in 2018, increasing 13%, 10%, and 4% compared with 2017 levels, respectively.

Coal consumption in the United States fell to 688 million short tons (13 quadrillion Btu) in 2018, the fifth consecutive year of decline. Almost all of the reduction came from the electric power sector, which fell 4% from 2017 levels. Coal-fired power plants continued to be displaced by newer, more efficient natural gas and renewable power generation sources. In 2018, 12.9 gigawatts (GW) of coal-fired capacity were retired, while 14.6 GW of net natural gas-fired capacity were added.

U.S. fossil fuel energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Renewable energy consumption in the United States reached a record high 11.5 quadrillion Btu in 2018, rising 3% from 2017, largely driven by the addition of new wind and solar power plants. Wind electricity consumption increased by 8% while solar consumption rose 22%. Biomass consumption, primarily in the form of transportation fuels such as fuel ethanol and biodiesel, accounted for 45% of all renewable consumption in 2018, up 1% from 2017 levels. Increases in wind, solar, and biomass consumption were partially offset by a 3% decrease in hydroelectricity consumption.

U.S. energy consumption of selected fuels

Source: U.S. Energy Information Administration, Monthly Energy Review

Nuclear consumption in the United States increased less than 1% compared with 2017 levels but still set a record for electricity generation in 2018. The number of total operable nuclear generating units decreased to 98 in September 2018 when the Oyster Creek Nuclear Generating Station in New Jersey was retired. Annual average nuclear capacity factors, which reflect the use of power plants, were slightly higher at 92.6% in 2018 compared with 92.2% in 2017.

More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

April, 17 2019
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April, 17 2019
A New Frontier for LNG Pricing and Contracts

How’s this for a first? As the world’s demand for LNG continues to grow, the world’s largest LNG supplier (Shell) has inked an innovative new deal with one of the world’s largest LNG buyers (Tokyo Gas), including a coal pricing formula link for the first time in a large-scale LNG contract. It’s a notable change in an industry that has long depended on pricing gas off crude, but could this be a sign of new things to come?

Both parties have named the deal an ‘innovative solution’, with Tokyo Gas hailing it as a ‘further diversification of price indexation’ and Shell calling it a ‘tailored solutions including flexible contract terms under a variety of pricing indices.’ Beneath the rhetoric, the actual nuts and bolts is slightly more mundane. The pricing formula link to coal indexation will only be used for part of the supply, with the remainder priced off the conventional oil & gas-linked indexation ie. Brent and Henry Hub pricing. This makes sense, since Tokyo Gas will be sourcing LNG from Shell’s global portfolio – which includes upcoming projects in Canada and the US Gulf Coast. Neither party provided the split of volumes under each pricing method, meaning that the coal-linked portion could be small, acting as a hedge.

However, it is likely that the push for this came from Tokyo Gas. As one of the world’s largest LNG buyers, Tokyo Gas has been at the forefront of redefining the strict traditions of LNG contracts. Reading between the lines, this deal most likely does not include any destination restriction clauses, a change that Tokyo Gas has been particularly pushing for. With the trajectory for Brent crude prices uncertain – owing to a difficult-to-predict balance between OPEC+ and US shale – creating a third link in the pricing formula might be a good move. Particularly since in Japan, LNG faces off directly with coal in power generation. With the general retreat from nuclear power in the country, the coal-LNG battle will intensify.

What does this mean for the rest of the industry? Could coal-linked contracts become the norm? The industry has been discussing new innovations in LNG contracts at the recent LNG2019 conference in Shanghai, while the influx of new American LNG players hungry to seal deals has unleashed a new sense of flexibility. But will there be takers?

I am not a pricing expert but the answer is maybe. While Tokyo Gas predominantly uses natural gas as its power generation fuel (hence the name), it is competing with other players using cheaper coal-based generation. So in Japan, LNG and coal are direct competitors. This is also true in South Korea and much of Southeast Asia. In the two rising Asian LNG powerhouses, however, the situation is different. In China – on track to become the world’s largest LNG buyer in the next two decades – LNG is rarely used in power generation, consumed instead by residential heating. In India – where LNG imports are also rising sharply – LNG is primarily aimed at petrochemicals and fertiliser. LNG based power generation in China and India could see a surge, of course, but that will take plenty of infrastructure, and time, to build. It is far more likely that their contracts will be based off existing LNG or natural gas benchmarks, several of which are being developed in Asia alone.

If it takes off  the coal-link LNG formula is likely to remain a Asian-based development. But with the huge volumes demanded by countries in this region, that’s still a very big niche. Enough perhaps for the innovation to slowly gain traction elsewhere, next stop -  Europe?

The Shell-Tokyo Gas Deal:

Contract – April 2020-March 2030 (10 Years)

Volume – 500,000 metric tons per year

Source – Shell global portfolio

Pricing – Formula based on coal and oil & gas-linked indexes

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April, 15 2019