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Iraq’s latest attempt to corner Asian oil markets

Every new crisis is a formidable opportunity to try new things, oftentimes merely to have another go with methods that have failed in the past but should work better now.

Cognizant of the pricing developments in the Asian market, the Iraqi state oil marketing company SOMO has announced that from 2021 onwards it would introduce a new medium sour grade to its set of available grades – Basrah Medium. The concept of Basrah Medium is by no means a complete novelty, it has been mooted for more than 2 years already as a necessary step to mitigate the quality deterioration of Iraq’s flagship export blend, Basrah Light. Next year, however, might be the long-awaited year of breakthrough for Basrah Medium.

Taking a helicopter view of the Iraqi oil export, SOMO’s current grade allocation is quite new when compared to other Middle Eastern NOCs. In the beginning was the word, and the word was Basrah – short and straightforward.

Iraq also had a second export stream in Kirkuk that was predominantly shipped to the Turkish port of Ceyhan and from thereon taken to buyers in the Mediterranean and elsewhere. However, as the US-led military invasion has upended Iraq’s internal standing order, SOMO has found itself between the rock and a hard place in trying to keep its quality commitments. Basrah Light initially started out as a much lighter crude that it currently is – hence its peg to 34 degrees API.

The thing is that the crude production ramp-up from 2010 onwards has altered the quality parameters of Basrah crude, primarily due to the face that all new major fields to be commissioned were really heavy (West Qurna-2 at 23 API or Halfaya at 22-23 API).

The worsening of what is now Basrah Light has compelled Iraqi authorities to create a new crude stream in 2015, Basrah Heavy, easing the quality pressure on Basrah Light. From the start Basrah Heavy had its own resource base – the blend is predominantly composed of crude from 3 supergiant fields (West Qurna-2, Gharraf and Halfaya) – however it lacked a predictable outlet base as many Asian downstream firms were still yet to finalize their expensive refinery reconfigurations that would have allowed to refine challenging crudes, such as Basrah Heavy.

For much of the past 5 years Basrah Heavy was heavily discounted to regional benchmarks in Europe and Middle East. When Basrah Heavy was introduced for the first time in May 2015, its official selling price for Asian deliveries was set at $-6.85 per barrel to Oman/Dubai, whilst the European OSP stood at $-8.45 per barrel to Dated Brent.

Over the years both the better-quality Basrah Light and Basrah Heavy witnessed their market differentials appreciate and the OPEC+ production cuts were of special importance along the way.

Such a positive development was partially counteracted by the unbeseeming quality of Basrah Light and Basrah Heavy – the latter has slid down into the 28-29° API interval (i.e. roughly losing 2 per barrel on the quality mismatch between the contractual quality and the real one), whilst the former was sporadically worsened by a recurrent practice of dumping remaining fuel oil volumes into the general export stream.

Coming back to the concept of Basrah Medium, availability of crude, to use the words of Iraqi energy authorities, was never an issue, as opposed to the availability of storage and blending capacities. Then-Iraqi oil minister Thamir al-Ghadhban claimed last year that the launch of Basrah Medium is directly dependent on having enough storage capacities at the Fao export depot.

The Fao crude storage park plays a key role in Basrah Medium marketing as Fao would be the place where almost all of the pre-export blending would take place. The Fao storage upgrade should have been ready by 2016 already, consisting of 24 storage tanks totaling a bit more than 8 MMbbls – from FAO the crude would go to the single point moorings (SPM) of the Basrah Terminal, effectively the place where domestically-produced crude last touches Iraqi soil.

Hindered by the military operations against the Islamic State and everything that profound challenge entailed, today SOMO can only boast of 16 storage tanks being available in Fao. Having ample storage in Fao underpins SOMO’s quest to have dedicated berths for the three separate streams of Basrah crude – Light, Medium and Heavy.

SOMO has been talking about the “intended segregation” of Basrah Light into two streams – one that carries on with the current quality parameters and the other one which corresponds to the initial Basrah Light quality.

The thing is that Basrah Medium would be the one taking over the 28-29° API quality of today’s Basrah Light and, as it happens, concurrently taking over most of its volumes and Basrah Light would become a lighter stream, much smaller in volumes to be exported. The difficulty of maintaining high Basrah Light exports in the post-2021 horizon will be further exacerbated by the fact that Iraq’s own refineries run predominantly on lighter crudes due to their low sophistication.

The biggest foreseeable problem with introducing Basrah Medium is going to be the decline of Basrah Light. Let’s take the supergiant Rumaila field (current output around 1.4mbpd) as a case in point – heretofore the production has come from the Zubair formation (34-36° API) but future volumes would be heavier and sourer, coming from the field’s Mishrif reservoirs (26-28° API).

In addition, of the other giant fields only West Qurna-2 could provide a short-to-mid-term output boost, however that would also mean more Basrah Heavy production. Hence, it remains to be seen wherefrom does SOMO expect to garner future Basrah Light volumes. The lighter Yamama reservoirs (37-40° API) that should make up the backbone of Basrah Light are only represented by the Luhais and Tuba fields, both nowhere near the reserves and output numbers of Rumaila, West Qurna or Halfaya.

OilPrice.com, Editor: Viktor KatonA, November 30

In Shadow of pandemic, pipeline companies eye efficiency until market stabilises

Midstream companies see EBITDA, cash flow decreases. Contracts key to LNG export expansions. While gas pipeline volumes have been recovering recently, thanks in large part to a surge in activity among LNG exporters, operators plan to keep spending and growth plans in check heading into 2021.

Kinder Morgan, Enterprise Products Partners and Energy Transfer were among the midstream companies that expressed a desire to maintain cost efficiency, at least until the market further stabilizes. Record daily coronavirus cases in the US could cause demand to pull back again, something the operators are watching for carefully.

Sanford C. Bernstein and Co. said in a Nov. 10 note to clients that commodity prices pose the “greatest risks” to companies with natural gas infrastructure, with lower prices potentially leading to lower production and higher-than-expected prices benefiting pipeline volume throughput and processing plant utilization.

“Reduced production or demand for these products hurts the midstream master limited partnership companies that transport them, leaving pipelines empty and companies unable to earn back their investments,” the firm said. “Higher-than-expected production benefits existing assets while providing companies with more growth opportunities.”

Over half of the top 10 midstream companies in an S&P Global Market Intelligence analysis experienced percentage decreases in both adjusted EBITDA and distributable cash flow during the third quarter of 2020 compared with the prior-year period. Cheniere Energy recorded the biggest declines as customers canceled liquefied natural gas cargoes.

LNG exporters like Cheniere plan to focus on existing operations and sanction new expansion projects only once they have a sufficient number of commercial contracts in place. Some have lowered liquefaction fees they are offering new customers to remain competitive, while others have delayed final investment decisions until next year.

Cost cuts
The midstream firms that posted stronger results benefited from “aggressive” cost cuts and plans to return cash to shareholders as volumes strengthened in the Permian Basin and Marcellus and Bakken shales, according to analysts at Morgan Stanley and UBS.

“We were impressed how quickly [management] teams ‘got’ it,” UBS told clients Nov. 9. “Within two quarters since the onset of [COVID-19], capex came down, there was a real hard focus on costs and a slew of buyback authorizations. … Clearly [management] is listening to investors and attempting to deliver.”

Midstream observers have also been waiting for M&A activity in the upstream sector to trickle downstream, but executives acknowledged that such opportunities may be limited because of market uncertainty and depressed valuations, as well as regulatory hurdles.

“Trust me, we’ve looked at a lot of companies, and there are companies out there that I personally would love to have, but there’s no way we can do it because we’d sell damn near everything we bought,” Enterprise co-CEO James Teague said Oct. 28.

Magellan Midstream Partners Chairman, President and CEO Michael Mears said he anticipates “very few” pipeline mergers in 2021 given that the biggest players are laser-focused on maintaining sturdy balance sheets and implementing stock repurchase programs.

The global energy transition away from fossil fuels also took center stage on third-quarter earnings calls. Investors who are focused on environmental, social and governance issues are pressuring pipeline management teams to address the sector’s future. Among other things, the investor movement has been prompted by a shift at gas utilities and European supermajors to a lower-carbon operating environment to fight climate change. While pipeline executives acknowledged that climate efforts require a significant reduction in emissions, they said such projects must make financial sense.

“The returns are lower and lower than what we would see in [oil and gas] midstream investment,” Kinder Morgan CEO Steven Kean noted. “I don’t see us gambling on an uplift in our overall equity value because we started to make some investments in solar panels or windmills.”

S&P Global Platts, Editor: Allison Good, November 30

Coronavirus accelerates oil refining shift to Asia

Slumping fuel consumption during the pandemic is accelerating the long-term shift of refining capacity from North America and Europe to Asia, and from older, smaller refineries to modern, higher-capacity mega-refineries.

The result is a wave of closures, often centring on refineries that only narrowly survived the previous closure wave in the years after the recession in 2008/09.

Fuel consumption has been stagnant or falling across most of North America, Western Europe and Japan since 2007 as a result of efficiency improvements.

North American, European and Japanese refineries have been left battling to protect their share of a declining market, creating downward pressure on profitability.

The problem of overcapacity has been masked during periods of strong economic growth but exposed every time the business cycle turns down.

Asia Fuel Growth

In contrast to Western Europe, North America and Japan, fuel consumption has grown rapidly across the rest of Asia over the last decade.

The region’s three sub-markets in West Asia (centred on the Gulf), South Asia (centred on India) and East Asia (China) have been responsible for more than two-thirds of worldwide oil consumption growth since 2009.

Asia has seen sustained growth in its refining capacity to match the growth in consumption; refineries are typically built near to consumption centres since it is operationally simpler to transport crude than products.

Asia and the Middle East account for 43% of worldwide refining capacity, almost exactly matching their 44% share in global oil consumption, with both shares up from 33% in 1999.

Asia’s refineries are more competitive because they are nearer growing markets; process large volumes with better economies of scale; and are equipped with more modern and sophisticated equipment.

Increasing Scale

In the 1960s and 1970s, new refineries were built at a minimum efficient scale of 100,000-250,000 barrels per day of crude capacity, but refineries commissioned in the 2000s and 2010s are generally 300,000-400,000 bpd or more.

New mega-refineries are often built with integrated petrochemicals units, enabling them to produce a higher share of higher value-added chemicals as well as lower-value fuels.

As a result, the new mega-refineries can squeeze a higher share of valuable products from the same crude at lower cost, outcompeting rivals in North America and Europe.

Facing a shrinking fuel market at home, North American and European refiners have found it increasingly difficult to compensate by growing fuel exports profitably.

And as the average size and complexity of new oil refineries has increased, the oldest, smallest and least complex refineries have become uneconomic.

The result is a wave of refinery closures, with jetties, tank farms and pipelines repurposed to become import terminals .

Most closures have been in North America and Europe, but smaller, older and fuel-only refineries in other parts of the world, including in Australia and the Philippines, have also been hit.

Reuters, Editor: Barbara Lewis, November 30

Oil refiners shut plants as demand losses may never return

Oil refiners are permanently closing processing plants in Asia and North America and facilities in Europe could be next because of the uncertain prospects for a recovery in fuel demand after the coronavirus pandemic cut consumption.

The pandemic initially cut global fuel demand by 30% and refiners temporarily idled plants. But consumption has not returned to pre-pandemic levels and less travel may be here to stay, leading to the possibility plants may shut permanently.

United States

Royal Dutch Shell RDSa.L said it was closing its refinery in Convent, Louisiana, the largest such U.S. facility. The shutdown will occur in November after Shell failed to find a buyer. Shell expects to sell all but six refineries and chemical plants globally and is considering closing facilities it cannot sell.

Marathon Petroleum MPC.N, the largest U.S. refiner by volume, plans to permanently halt processing at refineries in Martinez, California, and Gallup, New Mexico.

Singapore

Shell will halve crude processing capacity and cut jobs at its Pulau Bukom oil refinery in Singapore as part of an overhaul to reduce the company’s carbon dioxide (CO2) emissions to net zero by 2050.

Japan

Japan’s biggest refiner, Eneos Corp, permanently shut the 115,000 barrels-per-day (bpd) crude distillation unit at its Osaka refinery on Sept. 30 as planned.

Australia & New Zealand

Exxon Mobil Corp XOM.N is urging the Australian government to start releasing aid to the country’s oil refineries by January after a decision by BP early in November to shut the nation’s biggest refinery.

BP plc BP.L plans to stop producing fuel in Australia and will convert its loss-making Kwinana oil refinery, the biggest of the country’s four, into a fuel import terminal because of tough competition in Asia.

Australia has proposed offering incentives worth A$2.3 billion ($1.68 billion) over 10 years to keep the country’s four remaining oil refineries open and said it would invest in building fuel storage as part of a long-term fuel security plan.

Viva Energy has said a full shutdown of its refinery in Victoria was on the cards given the dire long-term outlook for the industry.

Refining NZ NZR.NZ said in late June it was considering shutting New Zealand’s only oil refinery and turning it into a fuel import terminal, but first would reduce its operations to cut costs and break even into 2021.

Philippines

Royal Dutch Shell RDSa.L will permanently shut its 110,000-barrel-per-day Tabangao facility in the Philippines’ Batangas province, one of only two oil refineries in the country.

Europe

Gunvor Group said in June it was considering mothballing its 110,000 bpd refinery in Antwerp as COVID-19 hurt the plant’s economic viability.

Petroineos said on Nov. 10 it plans to mothball nearly half of its 200,000 barrel-per-day refinery at Grangemouth in Scotland.

French oil major Total TOTF.PA said in September it was investing more than 500 million euros ($583 million) to convert its Grandpuits, France, refinery into a zero-crude platform for biofuels and bioplastics.

Energy consultancy Wood Mackenzie put plants in Netherlands, France, and Scotland on a list of potential closures.

Reuters, Editor: Florence Tan, Ahmad Ghaddar, Bozorgmehr Sharafedin, Enrico Dela Cruz, Seng Li Peng, Erwin Seba, Sonali Paul and Koustav Samanta, November 30

Asian crude demand gives oil markets hope

While oil demand in Europe and the United States continues to disappoint, refiners in Asia are racing to procure crude from around the world, giving the oil market some hope that at least in one region, demand is strengthening in the fourth quarter.

Lower term supplies from major OPEC producers due to the OPEC+ cuts, new import quotas for independent refiners in China, and strengthening fuel demand in India have all combined to create a bidding war for crude grades from all around the world going to Asia at the beginning of 2021, traders have told Bloomberg.

The increased demand for crude has pushed the price of Russia’s ESPO blend for January loading to the highest premium over the Dubai benchmark in five months. ESPO is very popular with refiners in China and Japan, but Chinese refiners are also snapping up cargoes from Angola and Brazil, according to the traders who spoke to Bloomberg. Japan and South Korea are also buying more cargoes from Qatar and the United States.

Some of the increased purchases are due to the fact that the top Middle Eastern producers and exporters, Saudi Arabia and Iraq, have recently reduced term supplies to their customers.

Demand in Asia is also supported by India, which sees a recovery in fuel demand that rose year-on-year in October for the first time since February.

Shipbrokers told Reuters that the oil trading units of major oil firms, including Shell and China’s Sinopec, have been on the lookout to book supertankers to send U.S. crude oil from the Gulf Coast to Asia next month. This has pushed the price of the West Texas Intermediate at Magellan East Houston WTI-MEH to the highest in two months, according to Reuters data.

Demand in China and the wider Asia region is currently the only bright spot on the oil market as demand remains depressed in major developed economies in Europe and in the United States, which are grappling with a surge in COVID-19 infections.

OilPrice.com, Editor: Josh Owens, November 30

Oil trades at highest level since March on wider market confidence

Oil is trading at its highest level since March as the commodity is swept up in wider market enthusiasm about the US presidential transition process getting underway and positive progress on the vaccine front.

Brent (BZ=F) was up as much as 1% on Tuesday, sitting at $46.47 (£34.26) a barrel at around 10:40am in London.

European markets rallied on Tuesday in the wake of US General Services Administration chief Emily Murphy writing a letter on Monday that confirmed President-elect Joe Biden could formally begin the hand-over process.

Market enthusiasm was also buoyed by the latest news on the vaccine front. AstraZeneca (AZN) said on Monday that its COVID-19 vaccine could be as much as 90% effective, be cheaper to make, easier to distribute and faster to scale-up than its rivals.

“The oil market has for a long time been shrouded with fog, with predictability extremely difficult with respect to both the timing and magnitude of an oil demand rebound,” said Bjarne Schieldrop, chief commodities analyst at SEB.

“This fog has now been lifted and blown away.”

Still, Schieldrop contends that a “Biden administration is bad news for oil” as he is expected to accelerate the green energy transition as well as the electrification of transportation, which will lower oil demand over the long-term.

While the Organization of the Petroleum Exporting Countries and its allies (OPEC+) are expected to extend current output cuts into next year, some members of the group are facing major obstacles. For instance, Iraq is seeking upfront payments of about $2bn for a long-term crude-supply contract, as the country continues to suffer an economic crisis due to low oil prices and wider OPEC+ cuts.

“Once financial markets know the oil market will tighten up, that inventories will decline and the oil market will move from a surplus situation to a tightening situation, then the forward crude oil price curve flattens almost overnight, well before the physical tightening actually begins,” said Schieldrop.

Yahoo! Finance, Editor: Kumutha Ramanathan, November 30

Study: New Mexico’s oil and gas collapse could last years

Economic analysts are warning that New Mexico could be unable to rely on its oil and gas industry as the market continues to struggle amid the COVID-19 pandemic.

Lease fees, royalty payment and taxes from oil and gas operations accounted for about 30% of the state’s budget in recent years, according to a study from the Institute for Energy Economics and Financial Analysis. The research also found that the industry provided about a quarter of the state’s operations budget last year.

But with the price per barrel of oil declining, the study suggests the financial support the industry offers New Mexico could be weakening.

Earlier this year, lawmakers faced a $400 million shortfall in the state’s budget which many attributed to declines in the oil and gas markets.

As of Tuesday, domestic crude oil was trading at about $41 per barrel, after a historic plummet in April — when the pandemic took hold in the U.S. — pushed the price to less than $0 per barrel for the first time in history.

Before the pandemic, oil was priced at about $55 to $60 per barrel, with the study reporting an average of about $48 per barrel between 2015 and 2019. Between 2010 and 2014, the average price of oil was about $86 per barrel.

That has meant shrinking operations in New Mexico where oil and gas development is centered around the Permian Basin. Baker Hughes reported an average of 45 active rigs so far in October, marking a 60% decrease since October 2019.

Most of those rigs were lost in recent months as the health crisis grew, the Carlsbad Current-Argus reported. The year had started strong at an average of 106 rigs in January and steadily declined through the spring and summer.

Tom Sanzillo, co-author of the report, said estimates show the average price of oil will remain as low as $43 per barrel through 2022.

“It’s an improvement over the historic lows hit in April 2020, but still far below what’s needed to return New Mexico to robust fiscal health,” he said. “The situation is unlikely to improve anytime soon.”

While prices have recovered some, they would need to stay at an average of $80 per barrels for several years, the study read.

Oil and gas reserves would need to rise quickly, while companies must be able to pay off debt. At the same time, fuel demand would have to increase significantly after plummeting due to the pandemic and travel restrictions.

“These features need to be in alignment, a scenario that is highly unlikely,” read the study.

Also blocking the industry’s path to recovery are high infrastructure costs, oversupply and increasing competition from the renewable sector.

“Consequently, the industry’s future is likely to be one of long-term decline,” the study read.

Sanzillo said New Mexico should diversify its economy to survive the inevitable busts of oil and gas.

“New Mexico can no longer expect oil and gas revenues to bounce back. But the negative outlook for the oil and gas industry does not have to be a negative outlook for New Mexico,” he said.

A Sept. 30 presentation from the Legislative Finance Committee warned that the reduction in drilling activity led to less revenue through gross receipts tax, especially in Eddy and Lea counties, from April to July.

Production in the 2021 fiscal year was expected to continue its decline between 13 and 30%, the LFC reported.

New Mexico produced about 368 million barrels of oil in the last fiscal year, and the LFC predicted production would drop to 260 million to 320 million barrels this fiscal year.

Production of natural gas was also expected to decline by 7 to 10%.

James Jimenez, executive director of child advocacy group New Mexico Voices for Children, said the state’s reliance on the industry led to drops in funding for education and other social services.

“For too long, New Mexico has been whipsawed by volatile oil and natural gas markets that our policymakers have no power to control,” Jimenez said in a statement. “… We need bold and innovative solutions from our policymakers to accelerate the diversification of our state’s economy, create a more equitable and transparent tax system, and strategically invest in proven programs that deliver better outcomes for our children.”

The San Francisco Chronicle, Editor: Adrian Hedden, October 30

5 Reasons you should invest in a tank terminal

Is investing in a tank terminal something you should consider? While in most cases the answer will be a sounding ‘yes,’ it will pay dividends to first learn more about the exciting world of tank terminals. Let’s take a look at the top 5 reasons why you should invest in a tank terminal.

We often see investors flocking to lower-risk investments during economic uncertainty, such as government bonds, real estate, and infrastructure. Therefore, it’s hardly surprising that we are seeing a significant uptick in interest for tank terminals investments.

Is investing in a tank terminal also something you should consider? While in most cases the answer will be a sounding ‘yes,’ it will pay dividends to first learn more about the exciting world of tank terminals. Let’s take a look at the top 5 reasons why you should invest in a tank terminal.

1. Tank terminals have typically always been a very profitable industry, with high return of investments and a low-risk profile

When we take a look at the profitability of tank storage companies over the past decades, they show in general very positive numbers. For example, Vopak, the worldwide market leader in tank terminals, has consistently demonstrated high EBITDA and EBIT percentages over the last 15 years; an excellent track record that most companies from other sectors can only dream of.

2. Tank terminals benefit from gross trade and product imbalances

As our national economies become more intertwined, gross trade keeps growing consistently. For some sectors, this increased gross trade and consequent product imbalances cause challenges. Because tank terminals are key in facilitating gross trade and correcting product imbalances, an increase in gross trade actually presents new business opportunities.

3. By using tank terminals as ‘forward stocking’ locations, products owners can save a considerable amount of supply chains costs

Tank terminals are not just about storage; smart product owners know that they can also leverage them as forward stocking locations.

Let’s say there is a South African refinery that has contracts in place with 20 European customers, selling them 10 tons of product per year each. The refinery could choose to ship 20 times 10t of product from South Africa to its individual customers in Europe. However, a smart product owner will ship the 200t of products to Europe in a single load, rent a tank in the region, and distribute the product when the customers need it. The cost advantage of the second option is huge; keep in mind that vessel costs are much higher than storage costs.

As pressure on supply chains to become more efficient is constantly rising, this forward stocking function of terminals will only become more important in the future.

4. As GDP is expected to keep on growing, it is also likely that gross trade keeps on growing

Historically speaking, there has always been a strong correlation between GDP and gross trade. If we take chemicals as an example, we have seen that historical chemical consumption growth percentages routinely exceed the GDP growth percentages. The main reason is that chemicals are heavily integrated into our daily lives and that chemicals have replaced other materials like wood, steel, paper, and glass.

5. Tank terminals are part of the supply chain of different value chains, like oil, gas, chemicals, and vegetable oils.

The location of a terminal is a very critical factor in determining the attractiveness of a terminal; if a terminal is located close to the sea is on average more attractive compared to more inland located terminals, as it saves time from marine vessels’ perspective and larger vessels can access the terminal.

What’s next?

These top 5 reasons are just the start. To become a successful investor in the tank terminal industry, there is still much more to learn. 

Download our whitepaper “What you must know before investing in tank terminals.”

Download here

The oil market outlook: Lasting scars from the pandemic

After plummeting in April, oil prices have partially rebounded in response to a steep drop in production, particularly among OPEC and its partners. While consumption has risen from its lows in 2020Q2, it remains well below its pre-pandemic level.

The pandemic is expected to have a lasting impact on oil consumption, with demand only likely to fully recover by 2023. Oil prices are forecast to rise to $44/bbl in 2021 from a projected $41/bbl in 2020, as the gradual rise in demand coincides with an easing of supply restraint among OPEC+.

The main risk to the oil price forecast is the duration of the pandemic, including the risk of an intensifying second wave in the Northern Hemisphere, and the speed at which a vaccine is developed and distributed.

After rebounding from April lows, oil prices stabilized in 2020Q3

After plunging in March and April, crude oil prices saw a robust recovery in May and June, and averaged $42/bbl in 2020Q3. However, they remain almost one-third lower than their 2019 average.

The recovery in prices was helped by a sharp fall in global production

Especially by OPEC and its partners, known as OPEC+. The group agreed to cut production by 9.7mb/d, almost 10% of global oil supply. Supply also fell sharply in the United States and Canada. The rise in oil prices was also helped by a recovery in consumption as lockdown measures were eased and travel and transport began to pick up.

Unprecedented oil production cuts by OPEC+, strong compliance

Global oil production plummeted by 12% in May, falling from 100mb/d to 88mb/d, and has remained well below its pre-pandemic level. The fall was driven by OPEC+, which collectively agreed to production cuts of 9.7mb/d. Compliance with the cuts has been high, particularly compared with previous agreements. The group agreed to ease the restraints over two years, and this began in August with increased production of 2mb/d.

A further increase of 2mb/d is planned for January 2021, although this increase could be delayed if oil prices do not see a further recovery. One additional factor is production in Libya, which is a member of OPEC but is not subject to the OPEC+ agreement. Libya had seen production fall close to zero in mid-2020 as a result of internal geopolitical conflict, from an average of 1.1mb/d in 2019.

However, a nationwide ceasefire was announced in October and a robust recovery in oil production is possible in coming months.

Plunging output and weak activity in the United States

Oil production in the United States dropped by one-fifth in May amid plummeting demand and prices. While output has since recovered, it remains around 10% below its 2019 level. Investment in new oil production in the U.S is also very weak.

The oil rig count, a measure of new drilling activity, fell by 75% to reach an all-time low in August, although it has since seen a modest recovery. Survey results from the Federal Reserve Bank of Dallas suggest most U.S. shale companies do not expect a major increase in new drilling until the price of WTI increases above $50/bbl—$10/bbl above its current level.

As a result of low levels of new investment, oil production is expected to average nearly 3% lower in 2021 relative to 2020.

Weakness in oil consumption driven by collapse in air travel

Two-thirds of oil consumption is accounted for by transport. Of the three main transport fuels, jet fuel has been the most affected by the COVID-19 pandemic, given the collapse in air travel. Diesel, in contrast, has been the least affected , as it is used for shipping and road transport of freight, which have been boosted by e-commerce.

After reaching a trough in April, gasoline and diesel consumption in OECD countries have seen a recovery in demand and are expected to almost reach pre-pandemic levels by the end of 2020. However, the weakness in jet fuel consumption is expected to be significantly more persistent.

Oil consumption expected to be permanently affected by COVID-19

The pandemic is expected to have a lasting impact on oil consumption. Over the next few years, consumption is forecast to remain well below its pre-pandemic trend. In the longer-term, the pandemic is likely to affect oil consumption via a shift in people’s behaviors.

Air travel could see a permanent reduction as business travel is curtailed in favor of remote meetings, reducing demand for jet fuel. A shift to working from home may reduce demand for gasoline, but this could be somewhat offset by increased use of private vehicles if people remain averse to using public transport.

While the overall impact is difficult to quantify, concerns about future oil demand are already impacting corporate investment decisions. Some industry scenarios indicate that oil demand may have peaked in 2019, and several major oil producing companies have announced changes in long-term strategy, including a significant reduction in investment in new hydrocarbon projects, albeit with long horizons.

World Bank Blogs, Editor: Peter Nagle, October 30

Big profits are no longer the top priority for oil investors

For years, the oil industry drew in investors with sizable—and regular—returns. Even when oil prices fell, Big Oil found ways to keep paying dividends, even if it had to cut them, which happened only in extreme cases. Now, it is becoming increasingly clear that dividends—and profits—are no longer king. Today’s investors want other things from their oil investments.

Returns are not what they used to be

To be perfectly fair, returns are still important. They are just not the only reason for an investor to buy into or stay with an oil company. The sustainability of an oil company is garnering growing attention, too. But more on that later. Even if returns were the one and only priority of investors today, they would be unhappy.

Back in 2006, the average return on capital employed in upstream activities among Big Oil majors stood at more than 27 percent, a recent study by Boston Consulting Group revealed. In 2019, that average was no more than 3.5 percent. That’s before the pandemic pummeled oil prices and forced severe spending cuts. The oil industry’s returns, the study showed, had become much less resilient to price movements.

The difference is too stark to be brushed off as coincidental. Indeed, the authors of the study note that one marked change in the industry during the period between 2006 and 2019 was a shift in companies’ upstream asset portfolios.

The myths about shale and deepwater

Until about 2006, BCG noted in its report, up to 80 percent of Big Oil’s portfolio was made up of conventional oil and gas assets. Since then, they have gone into things such as deepwater and shale. And while investors have been hearing for years how production costs in both deepwater and shale are going down, this has not been the case for all deepwater fields or all shale plays.

Unconventional and deepwater exploration and production continue, overall, to be a lot costlier than shallow water and conventional oil wells. For deepwater, this is because of purely physical challenges such as, as the name suggests, depth. For shale, it is because of the capital intensity of fracking.

A focus has been put on the quick turnaround time of fracked wells: they take a lot less than conventional wells to start bringing in returns on the investment employed. But unlike conventional wells, they have much shorter life spans. In short, the promise of unconventional and deepwater oil has, based on the rates of investment return, fallen well short of promises.

The ESG path

Oil investors have been growing unhappy with Big Oil for a while now, ever since the environmental, sustainable, and social governance trend gathered speed. A growing number of people looking for a company to buy into now want to know that this company’s business is environmentally responsible. That’s not just out of altruistic motives. Investors are being told that climate change constitutes an existential threat for many companies, and the more environmentally responsible a company is, the greater chance of survival it has.

Obviously, oil companies are in a delicate place, to put it mildly, when it comes to environmental responsibility. But it is not as delicate a spot as many may imagine. Global demand for energy is growing, and it will continue growing for the observable future despite the pandemic. And this means that oil and gas will continue to be needed.

“On one hand, the energy transition is real and here to stay,” Bob Maguire, managing director of Carlyle Group, told the Energy Intelligence Forum as quoted by Argus Media. “On the other hand, there are 280mn cars on the road in the US today, 279mn of them running on oil, and the average lifespan of a vehicle is 12 years.”

Oil and gas will continue to be needed, but they would need to be produced differently to satisfy investors’ changing sentiment towards the industry. According to Boston Capital Group’s study, 65 percent of oil investors want companies to prioritize ESG factors over profits, even if this has a negative on said profits.

As much as 83 percent say Big Oil should invest in low-carbon alternatives to their core business. An even greater majority of 86 percent believe investments by oil companies in clean energy technology would make them more attractive for investors. That should provide a pretty clear picture of where Big Oil needs to go.

The way forward is not all green

Some would argue that Big Oil is already going in that direction, with the European supermajors leading the way with renewable energy investment commitments worth tens of billions. Others would counter that they are still only making promises but little actual work on changing their business.

Indeed, whatever Big Oil’s green ambitions, they would need to stick with their core business of extracting fossil fuels, too. They need the revenues from this core business to fund their renewable energy ambitions. But they could do this differently, too. The BCG study suggests reinforcing their focus on lower-cost production, taking steps to reduce the capital intensity, and pay more attention to risk mitigation. All that in addition to the clearly unavoidable diversification into alternative energy that should make them more resilient to oil price shocks in the future.

OilPrice.com, Editor: Irina Slav, October 30