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A month ago, the world witnessed something never thought possible – negative oil prices. A perfect storm of events – the Covid-19 lockdowns, the resulting effect on demand, an ongoing oil supply glut, a worrying shortage of storage space and (crucially) the expiry of the NYMEX WTI benchmark contract for May, resulted in US crude oil prices falling as low as -US$37/b. Dragging other North American crude markers like Louisiana Light and Western Canadian Select along with it, the unique situation meant that crude sellers were paying buyers to take the crude off their hands before the May contract expired, or risk being stuck with crude and nowhere to store it. This was seen as an emblem of the dire circumstances the oil industry was in, and although prices did recover to a more normal US$10-15/b level after the benchmark contract switched over to June, there was immense worry that the situation would repeat itself.
Thankfully, it has not.
On May 19, trade in the NYMEX WTI contract for June delivery was retired and ticked over into a new benchmark for July delivery. Instead of a repeat of the meltdown, the WTI contract rose by US$1.53 to reach US$33.49/b, closing the gap with Brent that traded at US$35.75b. In the space of a month, US crude prices essentially swung up by US$70/b. What happened?
The first reason is that the market has learnt its lesson. The meltdown in April came because of an overleveraged market tempted by low crude oil prices in hope of selling those cargoes on later at a profit. That sort of strategic trading works fine in a normal situation, but against an abnormal situation of rapidly-shrinking storage space saw contract holders hold out until the last minute then frantically dumping their contracts to avoid having to take physical delivery. Bruised by this – and probably embarrassed as well – it seems the market has taken precautions to avoid a recurrence. Settling contracts early was one mechanism. Funds and institutions have also reduced their positions, diminishing the amount of contracts that need to be settled. The structural bottleneck that precipitated the crash was largely eliminated.
The second is that the US oil complex has adjusted itself quickly. Some 2 mmb/d of crude production has been (temporarily) idled, reducing supply. The gradual removal of lockdowns in some US states, despite medical advisories, has also recovered some demand. This week, crude draws in Cushing, Oklahoma rose for the second consecutive week, reaching a record figure of 5.6 million barrels. That increase in demand and the parallel easing of constrained storage space meant that last month’s panic was not repeated. The situation is also similar worldwide. With China now almost at full capacity again and lockdowns gradually removed in other parts of the world, the global crude marker Brent also rose to a 2-month high. The new OPEC+ supply deal seems to be working, especially with Saudi Arabia making an additional voluntary cut of 1 mmb/d. The oil world is now moving rapidly towards a new normal.
How long will this last? Assuming that the Covid-19 pandemic is contained by Q3 2020, then oil prices could conceivably return to their previous support level of US$50/b. That is a big assumption, however. The Covid-19 situation is still fragile, with major risks of additional waves. In China and South Korea, where the pandemic had largely been contained, recent detection of isolated new clusters prompted strict localised lockdowns. There is also worry that the US is jumping the gun in easing restrictions. In Russia and Brazil – countries where the advice to enforce strict lockdowns was ignored as early warning signs crept in – the number of cases and deaths is still rising rapidly. Brazil is a particular worry, as President Jair Bolosnaro is a Covid-19 skeptic and is still encouraging normal behaviour in spite of the accelerating health crisis there. On the flip side, crude output may not respond to the increase in demand as easily, as many clusters of Covid-19 outbreaks have been detected in key crude producing facilities worldwide. Despite this, some US shale producers have already restarted their rigs, spurred on by a need to service their high levels of debt. US pipeline giant Energy Transfer LP has already reported that many drillers in the Permian have resumed production, citing prices in the high-US$20/b level as sufficient to cover its costs.
The recovery is ongoing. But what is likely to happen is an erratic recovery, with intermittent bouts of mini-booms and mini-busts. Consultancy IHS Markit Energy Advisory envisions a choppy recovery with ‘stop-and-go rallies’ over 2020 – particularly in the winter flu season – heading towards a normalisation only in 2021. It predicts that the market will only recover to pre-Covid 19 levels in the second half of 2021, and a smooth path towards that only after a vaccine is developed and made available, which will be late 2020 at the earliest. The oil market has moved from certain doom to cautious optimism in the space of a month. But it will take far longer for the entire industry to regain its verve without any caveats.
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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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