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.
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In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.
In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.
Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.
We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.
Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.
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The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.
How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.
The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.
The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.
On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.
But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.
For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.
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