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Last Updated: August 7, 2019
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Forecast HighlightsGlobal liquid fuels

  • Brent crude oil spot prices averaged $64 per barrel (b) in July, almost unchanged from the average in June 2019 but $10/b lower than the price in July of last year. EIA forecasts Brent spot prices will average $64/b in the second half of 2019 and $65/b in 2020. The forecast of stable crude oil prices is the result of EIA’s expectations of a relatively balanced global oil market. EIA forecasts global oil inventories will increase by 0.1 million barrels per day (b/d) in 2019 and 0.3 million b/d in 2020.
  • EIA expects West Texas Intermediate (WTI) crude oil prices will average $5.50/b less than Brent prices during the fourth quarter of 2019 and in 2020, narrowing from the $6.60/b spread during July. The narrowing spread reflects EIA’s assumption that crude oil pipeline transportation constraints from the Permian Basin to refineries and export terminals on the U.S. Gulf Coast will ease in the coming months. In the July STEO, EIA forecast the Brent-WTI spread to average $4.00/b in 2020. The updated differential forecast reflects EIA’s revised assumptions about the marginal cost of moving crude oil via pipeline from Cushing, Oklahoma, to the Gulf Coast.
  • EIA estimates that U.S. crude oil production averaged 11.7 million b/d in July, down by 0.3 million b/d from the June level. The declines were mostly in the Federal Gulf of Mexico (GOM), where operators shut platforms for several days in mid-July because of Hurricane Barry. EIA estimates that GOM crude oil production fell by more than 0.3 million b/d in July. Those declines were partially offset by the Lower 48 States onshore region, which is mostly tight oil production, where supply rose by more than 0.1 million b/d. EIA expects monthly growth in Lower 48 onshore production to slow during the rest of the forecast period, averaging 50,000 b/d per month from the fourth quarter of 2019 through the end of 2020, down from an average of 110,000 b/d per month from August 2018 through July 2019. EIA forecasts U.S. crude oil production will average 12.3 million b/d in 2019 and 13.3 million b/d in 2020, both of which would be record levels.
  • U.S. regular gasoline retail prices averaged $2.74 gallon (gal) in July, up 2 cents/gal from June but 11 cents/gal lower than the average in July of last year. EIA expects that monthly average gasoline prices peaked for the year in May at an average of $2.86/gal and will fall to an average of $2.64/gal in September. EIA expects regular gasoline retail prices to average $2.62/gal in 2019 and $2.71/gal in 2020.

Natural gas

  • The Henry Hub natural gas spot price averaged $2.37/million British thermal units (MMBtu) in July, down 3 cents/MMBtu from June. However, by the end of the month, spot prices had fallen below $2.30/MMBtu. Based on this price movement and EIA’s forecast of continued strong growth in natural gas production, EIA lowered its Henry Hub spot price forecast for the second half of 2019 to an average of $2.36/MMBtu. In the July STEO, EIA expected prices to average $2.50/MMBtu during this period. EIA expects natural gas prices in 2020 will increase to an average of $2.75/MMBtu. EIA’s natural gas production models indicate that rising prices are required in the coming quarters to bring supply into balance with rising domestic and export demand in 2020.
  • EIA forecasts that U.S. 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 monthly average natural gas production to grow in late 2019 and then decline slightly during the first quarter of 2020 as the lagged effect of low prices in the second half of 2019 reduces natural gas-directed drilling. However, EIA forecasts that growth will resume in the second quarter of 2020, and natural gas production in 2020 will average 92.5 Bcf/d.
  • EIA estimates that natural gas inventories ended July at 2.7 trillion cubic feet (Tcf), 13% higher than levels from a year earlier and 4% lower than the five-year (2014–18) average. EIA forecasts that natural gas storage injections during the 2019 April-through-October injection season will outpace the previous five-year average and that inventories will rise to more than 3.7 Tcf at the end of October, which would be 16% higher than October 2018 levels and slightly above to the five-year average.

Electricity, coal, renewables, and emissions

  • EIA has expanded its forecasts for electricity supply in the United States and has introduced new forecasts for wholesale electricity prices. A STEO Supplement provides more information about the changes.
  • Lower costs for natural gas drive EIA’s forecast that annual average wholesale electricity prices will be lower in 2019 than last year in all areas of the United States. The forecast year-over-year declines range from -0.2% in the Southwest Power Pool (SPP) to -28% in the Electric Reliability Council of Texas (ERCOT) market.
  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and then decline slightly in 2020. EIA forecasts that the share of U.S. generation from coal will average 24% in 2019 and in 2020, down from 28% in 2018. The forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables together provided 10% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects electric power sector demand for coal to fall by 2% in 2020, compared with an expected decline of 15% in 2019. However, planned coal plant retirements will continue to put downward pressure on overall electricity demand for the fuel. Almost 13 gigawatts of coal-fired electricity generation capacity has retired this year or is scheduled to retire by the end of 2020, accounting for 5% of the capacity existing at the end of 2018.
  • EIA forecasts that renewable fuels, including wind, solar, and hydropower, will collectively produce 18% of U.S. electricity in 2019 and 19% in 2020. EIA expects that annual generation from wind will surpass hydropower generation for the first time in 2019 to become the leading source of renewable electricity generation and maintain that position in 2020.
  • EIA is improving its regional-level trend analysis by inserting a generator-level production cost model that simulates hourly generation at individual power plants. This improves our insight into generation, especially from fast-growing renewable sources like wind and solar.
  • This additional granularity and the assumption that wind will return to more normal levels in 2019, after a windy first half of 2018, results in an EIA forecast that electricity generation from wind power will average 295 billion kilowatthours (kWh) in 2019 and 335 billion kWh in 2020, estimates that are 4% and 7% lower, respectively, than forecast in the July STEO. In addition, the application of hourly dispatch that better models solar incidence lowers the solar electric production forecast by 1.1% in 2019 and by 2.8% in 2020.
  • EIA forecasts that, after rising by 2.7% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 2.3% in 2019 and by 0.5% in 2020. In 2019, EIA forecasts that space cooling demand (as measured in cooling degree days) will be lower than in 2018, when it was 13% higher than the previous 10-year (2008–17) average. In addition, in 2019, EIA expects U.S. CO2 emissions to decline because the forecast share of electricity generated from natural gas and renewables is increasing while the forecast share generated from coal, which is a more carbon-intensive energy source, is decreasing. EIA’s projected emissions decline is lower in 2020 than in 2019 because it forecasts that both heating and cooling requirements will be slightly lower than normal. At the same time, the forecast coal share of generation will remain about the same as in 2019 while the natural gas share declines. Although EIA forecasts that generation from renewables will continue to increase in 2020, a forecast decrease in nuclear power offsets 24% of the renewables’ gain.

Changes to the August STEO

Beginning with the August 6, 2019, publication of the STEO, EIA has expanded its forecasts for regional electricity supply in the United States and has introduced new forecasts for wholesale electricity prices. 

To better present the expanded forecast, EIA will no longer publish table 7e, and the data in tables 7a, 7b, 7d, and 8b will now be stated in billion kilowatthours.

EIA has posted a STEO Supplement that provides more information about the new electricity supply and wholesale price forecasts.

Price Summary
 2017201820192020
aWest Texas Intermediate.
bAverage regular pump price.
cOn-highway retail.
dU.S. Residential average.
WTI Crude Oila
(dollars per barrel)
50.7965.0657.8759.50
Brent Crude Oil
(dollars per barrel)
54.1571.1965.1565.00
Gasolineb
(dollars per gallon)
2.422.732.622.71
Dieselc
(dollars per gallon)
2.653.183.073.22
Heating Oild
(dollars per gallon)
2.513.012.993.07
Natural Gasd
(dollars per thousand cubic feet)
10.8610.4910.4910.61
Electricityd
(cents per kilowatthour)
12.8912.8913.0513.17

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EIA forecasts less power generation from natural gas as a result of rising fuel costs

In its latest Short-Term Energy Outlook (STEO), released on January 12, the U.S. Energy Information Administration (EIA) forecasts that generation from natural gas-fired power plants in the U.S. electric power sector will decline by about 8% in 2021. This decline would be the first annual decline in natural gas-fired generation since 2017. Forecast generation from coal-fired power plants will increase by 14% in 2021, after declining by 20% in 2020. EIA forecasts that generation from nonhydropower renewable energy sources, such as solar and wind, will grow by 18% in 2021—the fastest annual growth rate since 2010.

The shift from coal to natural gas marked a significant change in the energy sources used to generate electricity in the United States in the past decade. This shift was driven primarily by the sustained low natural gas price. In 2020, natural gas prices were the lowest in decades: the nominal price of natural gas delivered to electric generators averaged $2.37 per million British thermal units (Btu). For 2021, EIA forecasts the average nominal price of natural gas for power generation will rise by 41% to an average of $3.35 per million Btu, about where it was in 2017. In contrast, EIA expects nominal coal prices will rise just 6% in 2021.

The large expected rise in natural gas prices is the primary driver in EIA’s forecast that less electricity will be generated from natural gas and more electricity will come from coal-fired power plants in 2021 than in recent years. EIA expects about 36% of total U.S. electricity generation in 2021 will be fueled by natural gas, down from 39% in 2020. The forecast coal-fired generation share in 2021 rises to 22% from 20% last year. However, these forecast generation shares are still different from 2017, when natural gas and coal each fueled 31% of total U.S. electricity generation.

Significant growth in electricity-generating capacity from renewable energy sources in 2021 is also likely to affect the mix of fuels used for power generation. Power developers are scheduled to add 15.4 gigawatts (GW) of new utility-scale solar capacity this year, which would be a record high. An additional 12.2 GW of wind capacity is scheduled to come online in 2021, following 21 GW of wind capacity that was added last year. Much of this new renewable generating capacity will be located in areas that have relied on natural gas as a primary fuel for power generation in recent years, such as in Texas.

January, 20 2021
U.S. oil and natural gas production to fall in 2021, then rise in 2022

U.S. monthly crude oil and natural gas production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)

In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that annual U.S. crude oil production will average 11.1 million b/d in 2021, down 0.2 million b/d from 2020 as result of a decline in drilling activity related to low oil prices. A production decline in 2021 would mark the second consecutive year of production declines. Responses to the COVID-19 pandemic led to supply and demand disruptions. EIA expects crude oil production to increase in 2022 by 0.4 million b/d because of increased drilling as prices remain at or near $50 per barrel (b).

The United States set annual natural gas production records in 2018 and 2019, largely because of increased drilling in shale and tight oil formations. The increase in production led to higher volumes of natural gas in storage and a decrease in natural gas prices. In 2020, marketed natural gas production fell by 2% from 2019 levels amid responses to COVID-19. EIA estimates that annual U.S. marketed natural gas production will decline another 2% to average 95.9 billion cubic feet per day (Bcf/d) in 2021. The fall in production will reverse in 2022, when EIA estimates that natural gas production will rise by 2% to 97.6 Bcf/d.

U.S. monthly crude oil production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)

EIA’s forecast for crude oil production is separated into three regions: the Lower 48 states excluding the Federal Gulf of Mexico (GOM) (81% of 2019 crude oil production), the GOM (15%), and Alaska (4%). EIA expects crude oil production in the U.S. Lower 48 states to decline through the first quarter of 2021 and then increase through the rest of the forecast period. As more new wells come online later in 2021, new well production will exceed the decline in legacy wells, driving the increase in overall crude oil production after the first quarter of 2021.

Associated natural gas production from oil-directed wells in the Permian Basin will fall because of lower West Texas Intermediate crude oil prices and reduced drilling activity in the first quarter of 2021. Natural gas production from dry regions such as Appalachia depends on the Henry Hub price. EIA forecasts the Henry Hub price will increase from $2.00 per million British thermal units (MMBtu) in 2020 to $3.01/MMBtu in 2021 and to $3.27/MMBtu in 2022, which will likely prompt an increase in Appalachia's natural gas production. However, natural gas production in Appalachia may be limited by pipeline constraints in 2021 if the Mountain Valley Pipeline (MVP) is delayed. The MVP is scheduled to enter service in late 2021, delivering natural gas from producing regions in northwestern West Virginia to southern Virginia. Natural gas takeaway capacity in the region is quickly filling up since the Atlantic Coast Pipeline was canceled in mid-2020.

January, 15 2021
So, Why Is Saudi Arabia Doing This?

Just when it seems that the drama of early December, when the nations of the OPEC+ club squabbled over how to implement and ease their collective supply quotas in 2021, would be repeated, a concession came from the most unlikely quarter of all. Saudi Arabia. OPEC’s swing producer and, especially in recent times, vocal judge, announced that it would voluntarily slash 1 million barrels per day of supply. The move took the oil markets by surprise, sending crude prices soaring but was also very unusual in that it was not even necessary at all.

After a day’s extension to the negotiations, the OPEC+ club had actually already agreed on the path forward for their supply deal through the remainder of Q1 2021. The nations of OPEC+ agreed to ease their overall supply quotas by 75,000 b/d in February and 120,000 b/d in March, bringing the total easing over three months to 695,000 b/d after the UAE spearheaded a revised increase of 500,000 b/d for January. The increases are actually very narrow ones; there were no adjustments for quotas for all OPEC+ members with the exception of Russia and Kazakshtan, who will be able to pump 195,000 additional barrels per day between them. That the increases for February and March were not higher or wider is a reflection of reality: despite Covid-19 vaccinations being rolled out globally, a new and more infectious variant of the coronavirus has started spreading across the world. In fact, there may even be at least of these mutations currently spreading, throwing into question the efficacy of vaccines and triggering new lockdowns. The original schedule of the April 2020 supply deal would have seen OPEC+ adding 2 million b/d of production from January 2021 onwards; the new tranches are far more measured and cognisant of the challenging market.

Then Saudi Arabia decides to shock the market by declaring that the Kingdom would slash an additional million barrels of crude supply above its current quota over February and March post-OPEC+ announcement. Which means that while countries such as Russia, the UAE and Nigeria are working to incrementally increase output, Saudi Arabia is actually subsidising those planned increases by making a massive additional voluntary cut. For a member that threw its weight around last year by unleashing taps to trigger a crude price war with Russia and has been emphasising the need for strict compliant by all members before allowing any collective increases to take place, this is uncharacteristic. Saudi Arabia may be OPEC’s swing producer, but it is certainly not that benevolent. Not least because it is expected to record a massive US$79 billion budget deficit for 2020 as low crude prices eat into the Kingdom’s finances.

So, why is Saudi Arabia doing this?

The last time the Saudis did this was in July 2020, when the severity of the Covid-19 pandemic was at devastating levels and crude prices needed some additional propping up. It succeeded. In January 2021, however, global crude prices are already at the US$50/b level and the market had already cheered the resolution of OPEC+’s positions for the next two months. There was no real urgent need to make voluntary cuts, especially since no other OPEC member would suit especially not the UAE with whom there has been a falling out.

The likeliest reason is leadership. Having failed to convince the rest of the OPEC+ gang to avoid any easing of quotas, Saudi Arabia could be wanting to prove its position by providing a measure of supply security at a time of major price sensitivity due to the Covid-19 resurgence. It will also provide some political ammunition for future negotiations when the group meets in March to decide plans for Q2 2021, turning this magnanimous move into an implicit threat. It could also be the case that Saudi Arabia is planning to pair its voluntary cut with field maintenance works, which would be a nice parallel to the usual refinery maintenance season in Asia where crude demand typically falls by 10-20% as units shut for routine inspections.

It could also be a projection of soft power. After isolating Qatar physically and economically since 2017 over accusations of terrorism support and proximity to Iran, four Middle Eastern states – Saudi Arabia, Bahrain, the UAE and Egypt – have agreed to restore and normalise ties with the peninsula. While acknowledging that a ‘trust deficit’ still remained, the accord avoids the awkward workarounds put in place to deal with the boycott and provides for road for cooperation ahead of a change on guard in the White House. Perhaps Qatar is even thinking of re-joining OPEC? As Saudi Arabia flexes its geopolitical muscle, it does need to pick its battles and re-assert its position. Showcasing political leadership as the world’s crude swing producer is as good a way of demonstrating that as any, even if it is planning to claim dues in the future.

It worked. It has successfully changed the market narrative from inter-OPEC+ squabbling to a more stabilised crude market. Saudi Arabia’s patience in prolonging this benevolent role is unknown, but for now, it has achieved what it wanted to achieve: return visibility to the Kingdom as the global oil leader, and having crude oil prices rise by nearly 10%.

Market Outlook:

  • Crude price trading range: Brent – US$55-57/b, WTI – US$51-53/b
  • Global crude oil benchmarks jumped several levels to a new higher range, as Saudi Arabia supplemented OPEC+’s decision to allow a minor increase in supply quotas for February and March with a massive 1 mmb/d voluntary cut over the same period
  • There are signs that the elevated level of crude pricing is tempting American drillers back to work, with Baker Hughes reporting a massive 67-site gain in active rigs over the first week of 2021; this will present another headache for OPEC+ when it comes time to debate the supply deal path forward for April and beyond
January, 14 2021