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Last Updated: February 18, 2021
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Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.

EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.

Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.

U.S. quarterly crude oil production, net trade, and refinery runs

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021

EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.

EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.

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The Perfect Storm Pushes Crude Oil Prices

In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?

To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.

Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.

That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.

Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.

 

For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.

That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.

Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.

Market Outlook:

  • Crude price trading range: Brent – US$58-61/b, WTI – US$60-63/b
  • Better longer-term prospects for fuels demand over 2021 and a severe winter storm in the southern United States that idled many upstream and downstream facilities sent global crude oil prices to their highest levels since January 2021
  • Falling levels at key oil storage locations worldwide are also contributing to the crude rally, with crude inventories in Cushing falling to a six-month low and reports of drained storage tanks in the US Gulf Coast, the Caribbean and East Asia
February, 17 2021
The State of Industry: Q4 2020 Financials – A Fragile Recovery

Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.

That didn’t happen.

Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.

Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.

If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.

On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.

The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.

The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.

Market Outlook:

  • Crude price trading range: Brent – US$60-62/b, WTI – US$57-59/b
  • The Brent crude benchmark rose above US$60/b level for the first time in over a year, as the demand outlook for fuels improves with the accelerating rollout of Covid-19 vaccines and tight stockpiles brush off worries of oversupply
  • On the latter, the IEA estimated that global stockpiles of crude and fuels in onshore and floating storage has shrunk by 300 million barrels since OPEC+ first embarked on its deep production controls in May; in China, stockpiles are at their lowest level over a 12-month period, with US crude stockpiles also fell by 1 million barrels
  • Despite a tenuous alliance, OPEC+ has continuously reassured the market that it will work to clear the massive oil surplus created by the pandemic-induced demand slump, signalling that despite its internal differences, a repeat of last March’s surprise price war is not on the cards

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February, 10 2021
SHORT-TERM ENERGY OUTLOOK
Forecast Highlights
  • The February Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because responses to COVID-19 continue to evolve. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy demand and supply over the past year and will continue to affect these patterns in the future. U.S. gross domestic product (GDP) declined by 3.6% in 2020 from 2019 levels. This STEO assumes U.S. GDP will grow by 3.8% in 2021 and by 4.2% in 2022. The U.S. macroeconomic assumptions in this outlook are based on forecasts by IHS Markit.
  • Brent crude oil spot prices averaged $55 per barrel (b) in January, up $5/b from the December average but $9/b lower than the average in January of last year. Higher Brent prices in January largely reflected the January 5 announcement by Saudi Arabia that it would unilaterally cut 1.0 million barrels per day (b/d) of crude oil production in February and March, in addition to the reduced production levels on which the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) previously agreed. The U.S. Energy Information Administration (EIA) expects Brent crude oil prices will average $56/b in the first quarter of 2021 and $52/b over the remainder of the year. EIA expects lower oil prices later in 2021 as a result of rising oil supply that will slow the pace of global oil inventory withdrawals. EIA also expects that high global oil inventory levels and spare production capacity will limit upward price pressures. EIA expects Brent prices will average $55/b in 2022.
  • EIA estimates that the world consumed 93.9 million b/d of petroleum and liquid fuels in January, which is down 2.8 million b/d from January 2020. EIA forecasts that global consumption of petroleum and liquid fuels will average 97.7 million b/d for all of 2021, which is up by 5.4 million b/d from 2020. EIA forecasts that consumption of petroleum and liquid fuel will increase by 3.5 million b/d in 2022 to average 101.2 million b/d.
  • EIA estimates that U.S. crude oil production averaged 11.0 million b/d in January, which is down slightly from 11.1 million b/d in November (the most recent month for which historical data are available). EIA expects production will continue to decline slightly in the coming months, reaching 10.9 million b/d in June. Although oil-directed drilling has increased in the United States in recent months, the number of active drilling rigs remains lower than year-ago levels. EIA expects production from newly drilled wells will be more than offset by declining production rates at existing wells in the first half of 2021. However, based on EIA’s forecast that West Texas Intermediate crude oil prices will remain near or higher than $50/b during the forecast period, EIA expects drilling will continue to increase. As a result, production from new wells will exceed the declines from legacy wells, and overall crude oil production will increase in the second half of 2021 and in 2022. EIA estimates that U.S. crude oil production will average 11.0 million b/d in 2021—down from 11.3 million b/d in 2020 and 12.2 million b/d in 2019—and will rise to 11.5 million b/d in 2022.
  • U.S. regular gasoline retail prices averaged $2.33 per gallon (gal) in January, compared with an average of $2.20/gal in December and $2.55/gal in January 2020. EIA forecasts gasoline prices to average $2.44/gal in 2021 and $2.46/gal in 2022. U.S. diesel fuel prices averaged $2.68/gal in January compared with $2.58/gal in December and $3.05/gal in January 2020, and EIA forecasts it will average $2.70/gal in 2021 and $2.77/gal in 2022.
  • On a volume basis, U.S. consumption of gasoline declined by more than other petroleum products in 2020. EIA forecasts that U.S. gasoline consumption will rise in the forecast but remain lower than 2019 levels. U.S. gasoline consumption is forecast to average 8.6 million b/d in 2021 and 8.9 million b/d in 2022, up from 8.0 million b/d in 2020 but lower than the 9.3 million b/d consumed in 2019.
  • EIA expects that total U.S. consumption of natural gas will average 81.7 billion cubic feet per day (Bcf/d) in 2021, down 1.9% from 2020. The decline in total U.S. consumption reflects less natural gas consumed for electric power as a result of higher natural gas prices compared with last year. In 2021, EIA expects residential natural gas demand to average 12.9 Bcf/d (up 0.2 Bcf/d from 2020) and commercial demand to average 9.1 Bcf/d (up 0.6 Bcf/d from 2020). EIA forecasts industrial consumption will average 23.0 Bcf/d in 2021 (up 0.4 Bcf/d from 2020) as a result of increased manufacturing activity amid a recovering economy. Industrial consumption of 23.0 Bcf/d would be 0.1 Bcf/d below the 2019 level. EIA expects total U.S. natural gas consumption will average 81.0 Bcf/d in 2022.
  • In January, the Henry Hub natural gas spot price averaged $2.71 per million British thermal units (MMBtu), up from the December average of $2.59/MMBtu. EIA expects Henry Hub spot prices to reach a monthly average of $2.98/MMBtu in February 2021. Higher expected prices in February reflect expectations of continued strong liquefied natural gas (LNG) exports and a shrinking surplus of natural gas in storage compared with the five-year (2016–20) average. EIA uses weather forecasts from the National Oceanic and Atmospheric Administration (NOAA) as an input into the STEO, and the NOAA forecast in this STEO is from late January. More recent forecasts for mid-February weather show cold temperatures could extend across much of the United States, which creates an upside risk to near-term prices in this outlook. EIA expects that Henry Hub spot prices will average $2.95/MMBtu in 2021, which is up from the 2020 average of $2.03/MMBtu. EIA expects that continued growth in LNG exports and in domestic natural gas consumption outside of the electric power sector, as production remains relatively flat, will contribute to Henry Hub spot prices rising to an average of $3.27/MMBtu in 2022.
  • U.S. working natural gas in storage ended October at more than 3.9 trillion cubic feet (Tcf), 5% more than the 2015–19 average and the fourth-highest end-of-October level on record. EIA estimates that inventory withdrawals were 703 billion cubic feet (Bcf) in January, compared with a five-year (2016–20) average January withdrawal of 716 Bcf. The January withdrawals occurred at a lower rate than EIA forecast in last month’s STEO. The lower-than-expected withdrawal is the result of warmer-than-average January temperatures that reduced natural gas use for space heating. However, EIA forecasts that declines in U.S. natural gas production this winter compared with last winter will more than offset the declines in natural gas consumption, which will contribute to natural gas storage returning to levels near the five-year average by the end of winter. Forecast natural gas inventories end March 2021 at 1.8 Tcf, which is about the same as the five-year average.
  • EIA forecasts that U.S. production of dry natural gas will average 90.5 Bcf/d in 2021 and 91.0 Bcf/d in 2022, which are down from an average of 91.3 Bcf/d in 2020 and 93.1 Bcf/d in 2019. In the forecast, dry natural gas production remains relatively flat, averaging between 89.8 Bcf/d and 91.0 Bcf/d in every month from February 2021 through July 2022. Flat natural gas production is the result of falling production in several of the smaller natural gas producing regions being offset by growth in other regions, most notably in the Appalachia and Haynesville regions.
  • EIA estimates that the United States exported 9.8 Bcf/d of LNG in January amid high spot natural gas prices in Asia. However, foggy conditions and high winds affected export operations at Sabine Pass LNG, Corpus Christi LNG, and Cameron LNG, leading to several weather-related closures and sporadic suspension of piloting services on several days in January. EIA forecasts that U.S. LNG exports will average 8.5 Bcf/d in 2021. In 2022, EIA forecasts LNG exports will average 9.2 Bcf/d, surpassing the amount of natural gas exported via pipeline for the first time.
  • EIA forecasts that consumption of electricity in the United States will increase by 1.6% in 2021 after falling 3.8% in 2020. EIA forecasts residential sector retail sales will grow by 2.2% in 2021. The increase is primarily a result of colder forecast temperatures in the first quarter of 2021 compared with the same period in 2020, which EIA expects will raise demand for space heating, along with EIA’s assumption that more people will be working from home than in the first quarter of 2020. EIA expects retail sales of electricity in the commercial and industrial sectors will increase by 1.2% and 2.3%, respectively. For 2022, EIA forecasts total electricity consumption will grow by another 1.7%.
  • EIA expects the share of U.S. electric power generated with natural gas to fall from 39% in 2020 to 37% in 2021 and to 35% in 2022. The forecast natural gas share declines in response to a forecast increase in the price of natural gas delivered to electricity generators from an average of $2.38/MMBtu in 2020 to $3.27/MMBtu in 2021 (a 37% increase). Coal’s forecast share of electricity generation rises from 20% in 2020 to 21% in 2021 and to 22% in 2022. Electricity generation from renewable energy sources rises from 20% in 2020 to 21% in 2021 and to 23% in 2022. The nuclear share of U.S. generation declines from 21% in 2020 to 20% in 2021 and to 19% in 2022.
  • EIA forecasts that planned additions to U.S. wind and solar generating capacity in 2021 and 2022 will contribute to increasing electricity generation from those sources. EIA estimates that the U.S. electric power sector added 17.5 gigawatts (GW) of new wind capacity in 2020. EIA expects 15.3 GW of wind capacity will be added in 2021 and 3.6 GW in 2022. Utility-scale solar capacity rose by an estimated 11.1 GW in 2020. The forecast for added utility-scale solar capacity is 16.2 GW for 2021 and 12.3 GW for 2022.
  • EIA expects U.S. coal production to total 589 MMst in 2021, 50 MMst (9%) more than in 2020. In 2022, EIA expects coal production to rise by a further 5 MMst (1%). These increases reflect higher forecast demand for coal in the electric power sector because of rising natural gas prices, which increases coal’s competitiveness relative to natural gas for power generation dispatch. Although EIA expects coal production to rise in 2022, expected production increases will be limited by strong inventory draws. EIA expects significant coal supply to the power sector will come from a reduction in inventory levels in 2022, as the power sector brings inventory levels back in line with historical averages. Coal production in the forecast will also be limited by declining production capacity, as high mine reclamation costs have contributed to mine divestments and closings that may counter the effects of higher coal demand.
  • EIA expects rising global economic activity will contribute to rising steel production and power demand, which will lead to increased U.S. exports of both metallurgical and steam coal. EIA forecasts coal exports will total 85 MMst in 2021, up by 24% from 2020, which was the lowest level since 2016. EIA forecasts exports will rise by 6 MMst in 2022 to 91 MMst.
  • EIA estimates that U.S. energy-related carbon dioxide (CO2) emissions decreased by 11% in 2020. This decline in emissions is the result of less energy consumption related to economic contraction in response to the COVID-19 pandemic. In 2021, EIA forecasts that energy-related CO2 emissions will increase by about 4% from the 2020 level as economic activity increases leading to rising energy use. Energy-related CO2 emissions are also expected to rise by 3% in 2022 as economic growth continues. 
February, 10 2021