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Just after the calendar officially turned over to 2020, reports from China suggested that a ‘new strain of viral pneumonia of an unknown cause’ had been detected in the city of Wuhan. As investigations began, normal life continued, which included the mass movement of several million people in Wuhan and the surrounding Hubei province in preparation for the Lunar New Year festivities. As the extent of pandemic became apparent, Wuhan was placed on virtual lockdown on 23 January; several other cities in Hubei – totalling almost 60 million people – followed suit. The World Health Organisation declare the Wuhan Coronavirus Outbreak a ‘global emergency’, as the first death outside of China was declared in the Philippines.
Traced to the Huanan Seafood Wholesale Market in Wuhan, a mutating melting pot for infections with the cramped presence of all forms of live animals, domesticated and wild – the Wuhan pandemic has now exceeded the 2003 SARS crisis in terms of infections, nearing 20,000 in over a month vs just over 8,000 over five months. Infections and deaths have been mainly localised to China, with over 26 countries have reported cases (vs 29 for SARS). The University of Hong Kong predicts that the cases in Wuhan alone could peak at 75,000. In response, China has curtailed outbound travel, other countries have closed their borders to visitors with recent travel to China and airlines have cancelled thousands of flights. Economic activity in Hubei – as well as other Chinese provinces – has slowed down, with orders to work from home and public/private transportation banned. Given that the Wuhan Coronavirus is only in its second months, it is very likely that its broader impact will be far greater than SARS.
But let’s focus on its impact on oil. Crude oil prices plunged as the impact of the Wuhan pandemic deepened. Much of this is sentiment-based, pricing in a long-lasting economic disruption on pessimistic expectations of the outbreak. How true is this prognosis? In 2003, a similar fall in crude prices accompanied the SARS crisis. However, this cannot be a true parallel as coordinated OPEC efforts reduced crude prices that had risen as the US invaded Iraq at the same time. In China, the SARS effects on oil demand was broadly localised to one quarter – Q2 – and then also localised to one product – jet fuel. LPG, naphtha, gasoline and gasoil demand were relatively unaffected, with annual growth of 8-12% for the year vs 1% for jet fuel (which had grown by 28% the previous year). Will the Wuhan pandemic follow this pattern?
There is reason to believe it won’t. Take jet fuel. In 2003, Chinese jet fuel demand was 160,000 b/d; in 2019, it has grown six-fold to 860,000 b/d. In 17 years, China has become increasingly more connected to the world by air. The SARS crisis affected an estimated 21% of jet fuel demand in 2003. Apply that to 2019 and over 180,000 b/d of jet fuel demand could be eliminated. With the government placing restrictions on domestic and international air travel in China – something that was only implemented partially during SARS – the effect could be even higher. There is also global jet fuel demand to consider. As major airlines scale back or even cancel all flights to China, it will be tough times depending on how long the pandemic lasts. Refining margins for jet fuel in Asia are now at their lowest level in 4 years.
Other fuel products could be affected. Unlike SARS, China been praised for its speedy response to the pandemic – including extended civil lockdowns, activity shutdowns and extending official holiday periods – but that has curtailed tourist activity, transport movements and manufacturing operations. Gasoline and gasoil, in particular, will be impacted by this. Against a backdrop of already-decelerating oil and gas demand, Standard Chartered estimates that the Wuhan pandemic could reduce oil demand growth in 2020 from 1 mmb/d to 900,000 b/d – a 10% fall. A lot will depend on how soon and how well the pandemic can be contained. This new pandemic might not be as fatal as SARS thus far, but its effect on oil demand could be graver.
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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.
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.
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%.
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