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The US supermajor and Global Clean Energy have an agreement to produce 4 million barrels of renewable diesel.

ExxonMobil is investing $125 million in Global Clean Energy to advance its renewable diesel production, with an option to acquire up to a 25% equity stake in the company.

Global Clean Energy is a leading producer of camelina, a non-food oilseed crop that doesn’t affect primary crops. The investment will help the company accelerate its expansion from the US into Europe and South America.

“We are investing in a number of technologies and initiatives that can reduce greenhouse gas emissions from vital sectors of the global economy, and are progressing lower-emission fuels to help industries like heavy transportation, marine and aviation,” said Ian Carr, president of ExxonMobil Fuels and Lubricants Company.

“Our agreement with GCE is an example of how we are leveraging our significant resources, technology and capabilities to deliver more renewable fuels to help customers reduce their emissions.”

Renewable diesel made from non-petroleum feedstocks can reduce lifecycle greenhouse gas emissions of diesel by 40% to 80%, according to the California Air Resources board.

ExxonMobil and Global Clean Energy had previously agreed to a produce more than 4 million barrels of drop-in renewable diesel from Global Clean Energy’s biorefinery in California. The companies expect to begin production later this year.

“This strategic investment by ExxonMobil is transformational for GCE and will enable the rapid expansion of our proprietary camelina business. It also demonstrates the long-term commitment of both organisations to develop ultra-low carbon, nonfood-based feedstocks and advanced biofuels,” said Richard Palmer, chief executive of Global Clean Energy.

“Throughout our four years working together, ExxonMobil has actively supported our feedstock deployment efforts in multiple US growth regions.”

Upstream by Naomi Klinge, February 15, 2022

The Russia-Ukraine crisis has put the energy market on high alert for possible disruptions of Russian energy supplies to Europe. While most of the talk and headlines focus on a potential disruption of Russian pipeline gas exports to Europe, a significant decline in Russian crude and oil product exports westwards to Europe would also have a devastating effect on the energy supply in Europe, which is already grappling with a gas and power crisis.

A plunge in Russian oil exports to Europe would also be a very bullish factor for oil prices, which could hit and exceed $100 in case of a conflict in Ukraine, analysts say.  

Still, a major disruption of oil flows from Russia to Europe is highly unlikely at this stage because such a probability would deal a devastating blow on both sides, according to experts. Any strict sanctions on Russian oil exports to Europe would deprive the continent of its single largest oil supplier at a time when governments are struggling with soaring energy prices that are also stoking high inflation and slow activities in energy-intensive industries.   

At this point, it’s unlikely that oil and gas supplies from Russia to Europe will be cut significantly since it would be mutually destructive for both Moscow and the European countries. Russia exports half of its crude to Europe and relies on those oil revenues, which make up a large share of its government revenues. Europe, for its part, imports from Russia more than one-third of the natural gas and more than one-quarter of the crude oil it consumes.

The West-Russia standoff over Ukraine showed once again Europe’s high dependence on Russian energy supplies. As it stands, there isn’t an immediate alternative to those supplies, despite the efforts of the United States and the EU, which are scouring the world for additional LNG supplies that could be sent to Europe in case the crisis escalates into a conflict. 

A look at the crude export reality for Russia and Europe shows how one needs the other in the oil trade in this corner of the world. 

Russia, the world’s second-largest oil exporter after Saudi Arabia, exports around 5 million barrels per day (bpd) of crude oil. Nearly half of it, or 48 percent, went to European countries in 2020, according to data from the U.S. Energy Information Administration (EIA). Europe, particularly refineries in Germany, the Netherlands, and Poland, take 48 percent of all Russian crude oil exports. 

So, Europe is Russia’s main market for its oil and natural gas exports, and by extension, Europe is its main source of revenue. 

Crude oil and natural gas revenue accounted for 43 percent, on average, of the Russian government’s total annual revenue between 2011 and 2020, according to data compiled by the EIA. 

On the other hand, Russia is the single largest external supplier of crude, natural gas, and solid fuel to the European Union. 

Russia accounted for 26.9 percent of European Union crude oil imports and 41.1 percent of the natural gas imports in 2019, the last pre-pandemic year, Eurostat data shows. Russia is the single largest supplier of oil, the fuel most used in the EU’s final energy consumption. Petroleum products, such as heating oil, gasoline, and diesel fuel, represent 41 percent of final energy consumption in the EU, according to Eurostat. 

In 2021, Russia remained the largest supplier of natural gas and petroleum oils to the EU.

The mutual dependence of Europe and Russia on oil and gas suggests that any escalation of the Ukraine crisis and a subsequent significant drop in Russian energy supply would come at a very high cost for both the EU and Moscow. This makes analysts think that a major disruption of Russian oil and gas flows to Europe is unlikely, at least at this point.

OilPrice by Tsvetana Paraskova, February 15, 2022

Exxon Mobil (XOM.N) is injecting new cash into oil trading in Europe after a retreat on its ambitious expansion plans last year, three people with knowledge of the matter said.

Exxon slashed funding for its trading division in 2020 as part of wider cuts, leaving traders without the capital they needed to take full advantage of the volatile oil market during peak COVID-19 lockdowns.

The company’s cautious strategy during the pandemic sparked the exodus of some senior-level recruits from the previous couple of years, along with Exxon veterans, after they were restricted to routine hedging and deals.

Among the senior departures Reuters reported last year, Paul Butcher was due to leave in September but then stayed after Exxon decided to allocate more financing, the sources said, without providing further detail.

The sources said Exxon would keep its trading expansion going. Butcher is now expanding the paper market team in Exxon’s office outside London, which would see Exxon engage in speculative trade beyond hedging their own oil, they said.

Angela Cranmer moved internally to join his team in January this year, according to LinkedIn and two sources. She was previously a senior middle distillates trader, her LinkedIn profile showed. The sources added that Exxon was still looking to expand with internal and external hires.

The company also hired two refined products traders, Jon Hives and James Clements, who joined the team in Brussels in January as part of the expansion, two sources said. According to LinkedIn, Hives joined in January.

“Our active trading program continues to grow, and we’re pleased with the progress we are making,” Julie King, an Exxon spokesperson said, but declined to comment on the specific hires.

Last week, Exxon reported its biggest profit in seven years in the fourth quarter of 2021 on the back of soaring energy prices.

Reuters by Julia Payne, February 11, 2022

OPEC said on Thursday world oil demand might rise even more steeply this year as the global economy posts a strong recovery from the pandemic, a development that would underpin prices already at a seven-year high.

Tight oil supply has also given impetus to booming energy markets, and the report from the Organization of the Petroleum Exporting Countries also showed the group undershot a pledged oil-output rise in January under its pact with allies.

In the report, OPEC said it expected world oil demand to rise by 4.15 million barrels per day (bpd) this year, unchanged from its forecast last month, following a steep rise of 5.7 million bpd in 2021.

“Upside potential to the forecast prevails, based on an ongoing observed strong economic recovery with the GDP already reaching pre-pandemic levels,” the OPEC report said in a commentary on the 2022 demand outlook.

“As most world economies are expected to grow stronger, the near-term prospects for world oil demand are certainly on the bright side,” OPEC said in a separate comment on 2022 demand.

World consumption is expected to surpass the 100 million bpd mark in the third quarter, in line with last month’s forecast. On an annual basis according to OPEC, the world last used more than 100 million bpd of oil in 2019.

OPEC took an early view that the effect of the Omicron coronavirus variant would be mild, and the report said it has not had as negative an economic impact as previous COVID-19 waves.

Oil rose after the report was issued, trading above $92 a barrel. On Monday it hit $94, its highest level since October 2014.

OUTPUT UNDERSHOOTS

The report also showed higher output from OPEC as the group and allied non-members, known as OPEC+, gradually unwind record output cuts put in place in 2020.

OPEC+ has aimed to raise output by 400,000 bpd a month, with about 254,000 bpd of that due from 10 participating OPEC members, but production has increased by less than this as some producers struggle to pump more.

The report showed OPEC output in January rose by just 64,000 bpd to 27.98 million bpd.

Seven of the 13 OPEC members had a drop in output, among them Venezuela, Libya and Iraq.

Top exporter Saudi Arabia boosted output by 54,000 bpd according to the report, but Saudi Arabia told OPEC it made a larger increase of 123,000 bpd that brought its production to 10.145 million bpd.

The growth forecast for overall non-OPEC supply in 2022 was left unchanged, as was that for production of U.S. tight oil, another term for shale.

OPEC said it expects the world to need 28.9 million bpd from its members in 2022, up 100,000 bpd from last month and theoretically allowing further increases in output.

Investing.Com by Alex Lawler, February 11, 2022

The geopolitically critical positioning of the UAE’s Fujairah as an alternative global crude oil storage facility and transit hub to the perennially troublesome Strait of Hormuz route continued last week, with the announcement that deliveries have now begun on the Fujairah Terminal expansion by Abu Dhabi (AD) Ports Group.

According to comments by the company’s commercial director-ports, Julian Skyrme, the AED1 billion (US$272 million) investment in the expansion has added container capacity of 720,000 twenty-foot equivalent units and general cargo capacity of 1.3 million metric tonnes. 

This push from Fujairah comes after the finalisation in July 2021 of Iran’s own game-changing crude oil storage, transport and delivery mechanism, the Jask Oil Terminal and the 42-inch Guriyeh-Jask pipeline.

As analysed in depth in my new book on the global oil markets, the significance of this new Iranian crude oil export terminal can barely be overstated, as it allows Iran to transport huge quantities of oil and petrochemicals from its major oil fields via Guriyeh in the Shoaybiyeh-ye Gharbi Rural District of Khuzestan Province, 1,100 kilometres to Jask port in Hormozgan province, which is perfectly strategically placed on the Gulf of Oman. 

At the same time, the Guriyeh-Jask pipeline allows Tehran the option of disrupting all other oil supplies that travel through the Strait of Hormuz – around 35 percent of the world’s total.

“Even before U.S. sanctions were re-introduced [in 2018], the Kharg terminal accounted for around 90 percent of all of Iranian oil export loadings, with the remaining loads going through terminals on Lavan and Sirri, which made obvious and easy targets for the U.S. and its proxies to cripple Iran’s oil sector and therefore its economy,” a senior oil and gas industry source who works closely with Iran’s Petroleum Ministry exclusively told OilPrice.com.

“In addition, the extreme narrowness of the Strait of Hormuz means that oil tankers have to travel very slowly through it, so pushing up the transit costs and delaying revenue streams,” he said.

“Conversely, Iran wants to be able to use the threat – or reality – of closing the Strait of Hormuz for political reasons without also completing destroying its own oil exports revenue stream,” he added.

It was precisely such an incident – the 2011/12 Strait of Hormuz Dispute – that the once fanciful notion of Fujairah (one of the UAE’s smallest and lesser known emirates) becoming one of the world’s great oil storage and trading hubs alongside the Far East’s Singapore hub, Europe’s ARA (Amsterdam-Rotterdam-Antwerp), and the U.S.’s Cushing gained real momentum.

This Dispute began in December 2011 when Iran threatened to cut off oil supply through the Strait should economic sanctions limit, or halt, Iranian oil exports, and it included a 10-day military exercise in international waters near the chokepoint. 

Fujairah at that point was recognised as having an extremely strategically advantageous position to deal with such potential supply disruptions, being located both outside the Persian Gulf and a healthy 160 kilometres away from the Strait of Hormuz.

It was also seen as not aligned to any possibly pro-Iranian country, such as Oman, which at that time was considering plans with Iran to co-operate in Tehran’s build-out of a world-class liquefied natural gas (LNG) sector.

An additional advantage that Fujairah offered in that 2011/2012 analysis was that it affords international oil companies the facility to do business in the same generally transparent and non-corrupt legal framework found across the UAE. 

Various stages of Fujairah’s expansion plans were subject to delays prior to the onset of the major downturn in global oil prices in 2020, due to lower forward oil prices making hydrocarbons storage a less attractive option.

However, each element of the project to make Fujairah the pre-eminent Middle Eastern storage hub – termed ‘Black Pearl’ – gradually came into line. The pace of this picked up after the 380 kilometre Abu Dhabi Crude Oil Pipeline from the Habshan onshore field in Abu Dhabi to Fujairah city became operational in June 2012, capable of transporting 1.8 million bpd and allowing for the smooth movement of UAE crude to the global market. 

At that time, Fujairah also expedited the rolling out of a wide range of the corollary services required in a global storage hub. These included facilities for the loading and discharge of partially laden very large crude carriers (VLCCs) for crude oil and refined products, the blending of crude oil, fuel oil and clean products, the storage and supply of bunker fuel, and inter- and intra-tank cargo transfer.

Within a relatively short time, the Fujairah port’s jetties had the capacity to accommodate both small barge vessels – 3000 deadweight tonnage (DWT) – and the larger VLCCs (up to 300,000 DWT).

In 2015, Vopak Horizon Fujairah also announced that it was building five crude oil storage tanks with total capacity of 478,000 cubic metres at the port and intended to expand that number. 

Part of the positive backdrop for the continued expansion of the Fujairah hub was always expected to be the trade flows coming out of the Dubai Multi-Commodities Centre, with more storage capacity allowing traders greater flexibility in their deals, and a very supportive financial infrastructure created by the Fujairah authorities.

This proved to be the case and Fujairah further stands to benefit from the ongoing rise in volumes traded over the recently established Abu Dhabi-based ICE Futures Abu Dhabi (IFAD), with its focus on the trading of futures contracts for the light, sweet Murban crude oil that constituted around half of the UAE’s total near-4 million bpd crude oil production before the outbreak of the COVID-19 pandemic in 2020.

OilPrice by Simon Watkins, February 9, 2022

Investments in renewables-based electricity networks and technologies like carbon capture, utilisation and storage (CCUS) are needed this decade to accelerate China’s energy transition and put the country on course to reach carbon neutrality by 2060, Shell said.

A new report by the company, Achieving a carbon-neutral energy system in China by 2060, lays out a pathway to achieve net-zero emissions from energy production and use. In this scenario, Shell sees the share of electricity in China’s total energy consumption rising to almost 60pc in 2060 from 23pc today, with sectors such as buildings and passenger road transport largely electrified.

China is the world’s largest consumer of coal, which currently accounts for 60pc of its power use. A power crisis late in 2021 has prompted Beijing to plan a steadier energy transition and avoid abrupt coal plant closures that could threaten its energy security.

Shell recommends investing in flexible low-carbon sources of power generation, large-scale energy storage, and transmission network reinforcement and interconnections to manage demand fluctuations and ensure stable supply. Electricity market structures must also be improved to manage intermittency in a high-renewables power system, the report said.

Electricity demand is likely to be driven by the need for green hydrogen produced by electrolysis using renewable power. Hydrogen scales up from negligible levels today to more than 17 exajoule/yr by 2060, equivalent to 580mn t of coal equivalent, or 16pc of final energy consumption.

Hydrogen will mainly be used in sectors such as heavy industry, road transport, short-haul aviation and shipping, and more than 85pc of it will be green hydrogen produced from electrolysis. Hydrogen alone will add 25pc to electricity demand by 2060, so China’s electricity system needs to be scaled up to almost four times its current size, Shell said.

China is the world’s largest hydrogen producer. But most of it is brown hydrogen produced from fossil fuels, with coal accounting for 62pc of feedstock compared with 18pc globally. Only 4pc of China’s hydrogen uses renewable-based electricity. China produced over 21mn t of hydrogen in 2019, out of 70mn t produced globally.

Shell also sees electricity generated from biomass, combined with CCUS, providing a source of negative emissions for the energy system from 2053 onwards.

Carbon capture

Scaling up CCUS is key to carbon neutrality, with Shell seeing it as a way of keeping Chinese coal-fired power plants in operation.

Integrating a CCUS system into the coal-fired power and industrial sector can reduce emissions without the need to retire these facilities, Shell said. China has great geological potential for CCUS, with an estimated storage capacity of 2.4 trillion t. The country currently has more than 40 CCUS pilot projects with a total capacity of 3mn t. Under Shell’s net zero scenario, CCUS capacity needs to increase by more than 400 times in the next 40 years.

A carbon pricing mechanism is also needed for China to achieve net-zero emissions by 2060, Shell said. China already has an emissions trading scheme (ETS), covering 4.5bn t/yr of CO2 across around 2,200 coal- and gas-fired power plants. China expects all eight key emissions-intensive sectors such as steel, petrochemicals, non-ferrous metal and aviation to be included in the national ETS by 2025.

Shell estimates these steps will require investments of around $12.5 trillion in the next 40 years, with more than half of this required in the next two decades. But an enhanced energy system with the required flexibility could bring about net savings of up to $132bn/yr by 2050, with electricity prices reduced by up to 18pc on lower capital costs and declining solar and wind capacity installation costs.

Argus Media by Prethika Nair, January 31, 2022

We are halfway through the first month of the new year, and oil’s bull run is showing no signs of slowing. Oil futures have vaulted 12% in the first two trading weeks of the new year, boosted by several catalysts, including supply constraints, worries of a Russian attack on neighboring Ukraine, and growing signs the Omicron variant won’t be as disruptive as feared.

Brent crude futures settled $1.59, or 1.9%, higher in Friday’s session at a 2-1/2-month high of $86.06 a barrel, gaining 5.4% in the week, while U.S. West Texas Intermediate crude gained $1.70, or 2.1%, to $83.82 per barrel, rising 6.3% in the week. Both Brent and WTI futures have now entered overbought territory for the first time since late October.

“People looking at the big picture realize that the global supply versus demand situation is very tight and that’s giving the market a solid boost,” Phil Flynn, senior analyst at Price Futures Group, has told Reuters.

“When you consider that OPEC+ is still nowhere near pumping to its overall quota, this narrowing cushion could turn out to be the most bullish factor for oil prices over the coming months,” PVM analyst Stephen Brennock has said.

Indeed, several banks have forecast oil prices of $100 a barrel this year, with demand expected to outstrip supply, thanks in large part to OPEC’s limited capacity.

Morgan Stanley predicts that Brent crude will hit $90 a barrel in the third quarter of this year, while JPMorgan has forecast oil to hit $125 a barrel this year and $150 in 2023. Meanwhile, Rystad Energy’s senior vice-president of analysis, Claudio Galimberti, says if OPEC was disciplined and wanted to keep the market tight, it could boost prices to $100.

OPEC+ has lately come under pressure to ramp up production at a faster clip from several quarters, including the Biden administration so as to ease supply shortages and rein in spiraling oil prices. But the organization is scared of spoiling the oil price party by making any sudden or big moves with last year’s oil price collapse still fresh on its mind.

But maybe we have been overestimating how much power the cartel has to jack up production on the fly.

According to a recent report, at the moment, just a handful of OPEC members are capable of meeting higher production quotas compared to their current clips.

Amrita Sen of Energy Aspects has told Reuters that only Saudi Arabia, the United Arab Emirates, Kuwait, Iraq, and Azerbaijan are in a position to boost their production to meet set OPEC quotas, while the other eight members are likely to struggle due to sharp declines in production and years of underinvestment.

Underinvestments stalling recovery

According to the report, Africa’s oil giants Nigeria and Angola are the hardest hit, with the pair having pumped an average of 276kbpd below their quotas for more than a year now.

The two nations have a combined OPEC quota of 2.83 million bpd according to Refinitiv data, but Nigeria has failed to meet its quota since July last year and Angola since September 2020.

In Nigeria, five onshore export terminals run by oil majors with an average production clip of 900,000 bpd handled 20% less oil in July than the same time last year despite relaxed quotas. The declines are due to lower production from all the onshore fields that feed the five terminals.

In fact, only French oil major TotalEnergies‘(NYSE:TTE) new deep offshore oilfield and export terminal Egina has been able to quickly ramp up production. Turning the taps back on has been proving to be a bigger challenge than earlier thought due to a shortage of workers, huge maintenance backlogs, and tight cash flows.

Indeed, it could take at least two quarters before most companies can work through their maintenance backlogs which cover everything from servicing wells to replacing valves, pumps, and pipeline sections. Many companies have also fallen behind on plans to do supplementary drilling to keep production stable. 

Angola has not been faring any better.

In June, Angola’s oil minister, Diamantino Azevedo, lowered its targeted oil output for 2021 to 1.19 million bpd, citing production declines at mature fields, drilling delays due to COVID-19 and “technical and financial challenges” in deepwater oil exploration. That’s nearly 11% below its 1.33 million bpd OPEC quota and a far cry from its record peak above 1.8 million bpd in 2008.

The southern African nation has struggled for years as its oil fields steadily declined while exploration and drilling budgets failed to keep up. Angola’s largest fields began production about two decades ago, and many are now past their peaks. Two years ago, the country adopted a string of reforms aimed at boosting exploration, including allowing companies to produce from marginal fields adjacent to those they already operate. Unfortunately, the pandemic has stunted the impact of those reforms, and not a single drilling rig was operational in the country by May, the first time this has happened in 40 years.

So far, just three offshore rigs have resumed work.

Shale decline

But it’s not just OPEC producers that are struggling to boost oil production.

In an excellent op/ed, vice chairman of IHS Markit Dan Yergin observes that it’s almost inevitable that shale output will go in reverse and decline thanks to drastic cutbacks in investment and only later recover at a slow pace. Shale oil wells decline at an exceptionally fast clip and therefore require constant drilling to replenish lost supply. 

Indeed, Norway-based energy consultancy Rystad Energy recently warned that Big Oil could see its proven reserves run out in less than 15 years, thanks to produced volumes not being fully replaced with new discoveries.

According to Rystad, proven oil and gas reserves by the so-called Big Oil companies, namely ExxonMobil, BP Plc. (NYSE:BP), Shell (NYSE:RDS.A), Chevron (NYSE:CVX), TotalEnergies SE (NYSE:TTE), and Eni S.p.A (NYSE:E) are all falling, as produced volumes are not being fully replaced with new discoveries.

Granted, this is more of a long-term problem whose effects might not be felt soon. However, with the rising sentiment against oil and gas investments, it’s going to be hard to change this trend.

Experts are warning that the fossil fuel sector could remain depressed thanks to a big nemesis: the trillion-dollar ESG megatrend. There’s growing evidence that companies with low ESG scores are paying the price and are increasingly being shunned by the investing community.

According to Morningstar research, ESG investments hit a record $1.65 trillion in 2020, with the world’s largest fund manager, BlackRock Inc. (NYSE:BLK), with  $9 trillion in assets under management (AUM), throwing its weight behind ESG and oil and gas divestitures.

Michael Shaoul, Chairman and Chief Executive Officer of Marketfield Asset Management, has told Bloomberg TV that ESG is largely responsible for lagging oil and gas investments:

“Energy equities are nowhere close to where they were in 2014 when crude oil prices were at current levels. There are a couple very good reasons for that. One is it’s been a terrible place to be for a decade. And the other reason is the ESG pressures that a lot of institutional managers are on lead them to want to underplay investment in a lot of these areas.”

In fact, U.S. shale companies are now facing a real dilemma after disavowing new drilling and prioritizing dividends and debt paydowns, yet their inventories of productive wells continue falling off a cliff.

According to the U.S. Energy Information Administration, the United States had 5,957 drilled but uncompleted wells (DUCs) in July 2021, the lowest for any month since November 2017 from nearly 8,900 at its 2019 peak. At this rate, shale producers will have to sharply ramp up the drilling of new wells just to maintain the current production clip.

If we need any more proof that shale drillers are sticking to their newfound psychology of discipline, there is recent data from the EIA. That data shows a sharp decline in DUCs in most major U.S. onshore oil-producing regions. This, in turn, points to more well completions but less new well drilling activity. It’s true that higher completion rates have been leading to an uptick in oil production, particularly in the Permian; however, those completions have sharply lowered DUC inventories, which could limit oil production growth in the United States in the coming months.

That also means that spending will have to increase if we are to see shale keep pace with production declines. More will have to come online, and that means more money.

Crude oil has already gained 10 percent since the start of the year and has further to go, Vitol’s head of Asia told Bloomberg in an interview.

“These prices are justified,” said Mike Muller. “Strong backwardation is very much justified.”

The executive added that unlike natural gas, whose high price has already prompted lower consumption for some industrial users, oil has yet to reach that price level.

The latest in the gas sector “serves to remind us that people will abstain from buying expensive energy at some point,” Muller said at an industry webinar, adding, “The question is at what point that affects the oil market.”

Crude oil prices have posted four consecutive weeks of gains, which is the longest winning streak since October, in evidence that the demand recovery remains robust as fears about the effect of Omicron die down.

News that China will release oil from its strategic reserve next month had the potential to disrupt the rally but did not, with Brent crude reaching a two-month high last week and trading at over $86 per barrel at the time of writing. WTI was trading at over $84 per barrel.

“People looking at the big picture realize that global supply versus demand situation is very tight and that’s giving the market a solid boost,” Phil Flynn, Price Futures Group senior analyst, told Reuters last week.

Meanwhile, according to Vitol’s Muller, the White House may decide to release more crude oil from the strategic petroleum reserve, on top of the 50 million barrels announced in November last year.

“The market’s saying: ‘More, please,'” Muller said, as quoted by Bloomberg.

According to traders that Reuters interviewed, there is a strong appetite for future oil supply ahead of spring and summer, otherwise known as driving season in the northern hemisphere. There is also an element of anticipation of even tighter supply.

“With spring and summer on the horizon … people are getting prepared to enjoy a strong market,” one trader said.

“I think it’s more trying to get ahead of tightness they think is coming … back to a ‘herd of lemmings’ market dynamic,” said another.

OilPrice by Irina Slav, January 25, 2022