Category: Nieuws

Saudi Arabia’s state-controlled oil giant pressed ahead with a plan to pay $75 billion in dividends this year despite sliding profit and a surge in debt, as the kingdom battles a widening budget deficit.

Saudi Aramco said net income for the three months ending in June fell to 24.6 billion riyals ($6.6 billion), down 73% from a year earlier, after crude prices collapsed. Aramco will pay a dividend of $18.75 billion for the quarter, most of it to the government, which owns around 98% of the company’s stock.

Aramco’s performance and demand for energy will probably improve over the rest of the year as nations ease coronavirus lockdowns, according to Chief Executive Officer Amin Nasser.

“We are seeing a partial recovery in the energy market as countries around the world take steps to ease restrictions and reboot their economies,” he said.

The results cap a turbulent period for the world’s biggest oil exporter. Prices briefly turned negative in the U.S. in April as the virus battered the global economy and Aramco slashed hundreds of jobs.

Saudi Arabia and Russia led a push by the Organization of the Petroleum Exporting Countries and its partners to reduce production and prop up crude prices. Although they’ve rallied, Brent is still down 33% this year.

Unlike Aramco, rivals such as BP Plc and Royal Dutch Shell Plc have cut their dividends.

“We are committed to delivering sustainable dividends through market cycles, as we have demonstrated this quarter,” Nasser said. “Our intention is to pay $75 billion, subject to board approval, of course, and market conditions.”

Saudi Arabia generates most of its revenue from crude, and its budget deficit is set to exceed 12% of gross domestic product in 2020, according to the International Monetary Fund. That would be the widest since 2016, adding pressure on Aramco to maintain dividend payments.

The shares of Aramco, which Apple Inc. dethroned last month as the world’s most valuable listed company, rose 0.3% to 33.05 riyals in Riyadh on Sunday. They’ve declined 6.2% this year, much less than the likes of Exxon Mobil Corp., which has fallen 38%, and Shell, down 50%.

Aramco’s shares have fallen far less than those of the oil majors
The outlook for Aramco will remain uncertain for “some time,” Nasser said. Still, he expressed confidence about the company’s business and strategy in the third quarter and said oil consumption in Asia, Aramco’s largest regional market, has almost returned to pre-coronavirus levels.

The Dhahran-based firm’s gearing ratio soared to 20.1% at the end of June from minus 5% in March. That was due largely to the debt Aramco took on when it bought chemicals company Saudi Basic Industries Corp. for $70 billion. The deal was funded by a loan from the Saudi Arabia’s sovereign wealth fund, which Aramco plans to finish repaying in 2028.

Aramco has yet to draw down a $10 billion revolving credit facility, according to Nasser. The company said in June that it might issue more bonds or loans to meet its dividend commitment.

Capital expenditure will be at the lower end of the $25 billion-to-$30 billion range set in March, it said. That’s already down from the company’s plan at the start of 2020 to spend between $35 billion and $40 billion.

Aramco is still working on a deal to buy a $15 billion stake in Reliance Industries Ltd.’s refining and chemicals business, Nasser said, without giving any detail on timing. The Indian firm’s Chairman Mukesh Ambani said in July that a transaction had been delayed.

A deal with Reliance would help Aramco join the ranks of the top oil refiners and chemical makers. It is already a major supplier of crude to India, while Reliance sells petroleum products, including gasoline, to the kingdom.

Aramco’s Fadhili natural-gas plant reached full production capacity of 2.5 billion standard cubic feet during the second quarter. The company is boosting gas output to feed local businesses and replace valuable crude that power plants burn to meet rising demand for air-conditioning during the summer. Aramco started the Fadhili gas plant last year and has gradually ramped up output.

By Matthew Martin, Bloomberg, August 9 2020

Despite a 33% rise since the March 23 lows of this year, at the current price of around $43 per share we believe Exxon Mobil (NYSE: XOM) has reached its near-term potential. XOM’s stock has rallied from $32 to $43 off the recent bottom compared to the S&P which moved 46%. The stock lagged broader markets because of the low demand for gasoline, diesel, and jet fuel.

XOM stock has partially reached the level it was at before the drop in February due to the coronavirus outbreak becoming a pandemic. The healthy rise since the March 23 lows has primarily been due to production curtailments, operational expense reduction, and capex cuts. While EIA expects global crude oil inventories to ease during the third quarter, the resurgence of Covid cases in the U.S. and other countries has led to the second round of restricted living. Per Exxon’s Q2 report, gasoline and diesel demand is likely to recover by the fourth quarter while the demand for jet fuel is expected to remain subdued. Thus, Exxon’s trailing P/E multiple has low near-term upside potential as the company tries to achieve operational efficiency amid falling revenues.

In the past two years, Exxon Mobil’s Revenues have observed an 8.4% growth mostly from rising benchmark prices and a slight uptick in production volumes. However, the net income margin declined by 3-percentage-points – dragging the net income down by 31% since 2017.

Consistent with the trajectory in benchmark crude oil prices, Exxon Mobil’s P/E multiple surged in 2019 due to pent up demand but, subsequently dropped as the coronavirus crisis was declared a pandemic by the WHO. We believe the stock is unlikely to see a significant upside after the recent rally due to potential weakness from a recession driven by the Covid outbreak. Our dashboard What Factors Drove -43% Change in Exxon Mobil’s Stock between 2017 and now? has the underlying numbers. XOM’s P/E multiple changed from 16 in 2017 to 20 in 2019. While the company’s P/E is now 12.5 – it is comparable to the lows observed in 2018.

So what’s the likely trigger and timing of an upside?

The global spread of coronavirus has led to a substantial drop in energy consumption across the world. Per Baker and Hughes, the international oil & gas rig count has fallen by 50% since the beginning of the year – triggering expectations that a prolonged slump in energy demand is likely to remain for the full year. With the U.S. being the largest supplier and consumer of crude oil, a sharp drop in commercial crude oil inventory levels is the key indicator to be observed for demand recovery. Though market sentiment can be fickle, and evidence of a surge in new Covid cases could further delay a recovery in XOM’s stock.

Trefis Team in Forbes, August 5 2020, Photo by hidde schalm on Unsplash

As Bernard Looney took to the stage in London in February to announce his plan to transform BP Plc for a low-carbon future, the U.K. capital confirmed its first case of Covid-19.

The oil giant’s chief executive officer couldn’t have known how the virus would shake the foundations of his industry: since the start of the pandemic, BP has said it will write off as much as $17.5 billion of fossil-fuel assets, slash 10,000 jobs and exit the petrochemicals business. And on Tuesday, it may announce the first dividend cut since the Macondo oil-spill disaster a decade ago.

But despite the pain for shareholders and employees, the crisis is giving Looney the opportunity to accelerate the big changes needed to fulfill his vision.

The global spread of coronavirus “only reaffirms the need to reinvent our company,” Looney now says. The pandemic has created a world that pumps less oil, gets more of its energy from renewable sources and emits less carbon dioxide — exactly what he says BP should do.

“This backdrop of battered demand presents a lot of challenges, but it also presents opportunity,” said Luke Parker, vice president of corporate research for Wood Mackenzie Ltd.

The measures BP has taken so far aren’t unique, either in the current slump or in the periodic downturns that have afflicted the industry over the decades. But there’s a symbolism that wasn’t there before.

Quitting a core business like chemicals is a good way to show that the future looks different. Taking an ax to billions of dollars of oil and gas asset values demonstrates that “you’re a company that believes this transition is going to happen and that the world will be on a 2-degree path,” Parker said.

Most importantly, the company is widely expected to follow Royal Dutch Shell Plc this week by cutting its dividend, potentially freeing up cash to invest in clean energy.

Difficult decisions like this have been made easier by the coronavirus crisis, according to JPMorgan Chase & Co.’s head of EMEA oil and gas, Christyan Malek.

“What you’re seeing BP do is getting its house in order” before announcing a detailed transformation plan in September, Malek said. “BP have been putting the building blocks in place — the impairments, the divestments. And we believe the dividend cut is the next building block.”

Reducing BP’s $8 billion annual shareholder payout would address the biggest unanswered question about Looney’s transition plan: Where is the money going to come from?

Even before the coronavirus lockdowns crashed energy prices, BP was saddled with more debt than any of its peers. Its gearing — the ratio of debt to equity — is poised to rise as high as 48%, according to RBC Capital Markets. That would be by far the highest in the industry, and could lead to questions about its credit rating.

While the measures Looney has taken so far may help him achieve BP’s long-term goals, in the short-term shareholders appear unimpressed. The company’s stock is down 42% this year, a steeper drop than the 37% decline in the Stoxx Europe 600 Oil & Gas index.

Low-Carbon Spending

Without a detailed plan of how BP is going to become a clean-energy giant, the cost of the transformation remains largely theoretical. What’s clear, is that at the very least the oil major will have to boost spending on low-carbon fuels significantly from the current $500 million a year to billions.

The other route would be acquisitions, following on from its 130 million-pound ($170 million) purchase of U.K. car-charging company Chargemaster in 2018. Such assets typically have positive cash flow and can be integrated easily into oil majors’ portfolios, said Bruce Duguid, head of stewardship, EOS at Federated Hermes.

As Looney, 49, reshapes BP, doubts linger about the strategy. Sitting in the audience of the great unveiling in February was former CEO John Browne, who tried to steer the company into renewables in the early 2000s with the ill-fated “Beyond Petroleum” campaign.

“We moved too soon,” Looney said in a recent Instagram post. “We lost money on much of what we had built up.”

Bob Dudley, Looney’s immediate predecessor, has repeatedly cautioned against moving too fast into low-carbon fuels, saying the potential failure of new technologies could lead to financial ruin.

The key to success will be keeping investors on board. There’s strong support for BP’s overall change in direction, with shareholders voting overwhelmingly in favor of climate resolutions in 2019, according to Hermes’ Duguid. But it could be a painful journey, and there’s a risk shareholders have a change of heart if Looney does cut the dividend.

“You can use the macroeconomic backdrop as a way to justify the means, but you still need the end result to work,” said JPMorgan’s Malek.

(Updates with share price information in 13th paragraph.)

By Laura Hurst, Bloomberg, 2 August 2020,
Photo by Morning Brew on Unsplash

When JP Morgan’s EMEA head of oil and gas research said last month that this crisis was fundamentally no different from previous crises, he was right – at least in a way. But in some ways, he was wrong, because it is not just out of a sense for the dramatic that most observers are calling the current crisis unprecedented.

This crisis will change the industry in ways no other crisis has done.

Oil sands on the path to diversification Canada’s oil sands have been among the worst affected segments of the industry, as Wood Mackenzie noted in a June report. One of the reasons for the extent of the damage was that Canada’s oil sands producers never got to recover fully from the previous crash before this one struck.

While elsewhere E&Ps picked up where they had left off while the price crisis of 2014 to 2016 unfolded, Canadian oil sands producers struggled amid regulations that made investors think twice about investing in oil sands and, most importantly, a shortage of offtake capacity complete with legal challenges from various groups who had taken it upon themselves to make sure no new pipelines would be built in Canada ever again.

This year alone, investment in the oil sands, according to Wood Mac, would be $8 billion lower than it was in 2019 and as much as 80 percent lower than it was in 2013. The industry has already seen an exodus of supermajors, and it seems new ones won’t be coming any time soon, if all the forecasts for a slow and prolonged recovery in oil prices and oil demand materialize.

Meanwhile, more than 20 oil sands projects have been approved, but they’ve been delayed because of the current price situation. And they may never see the light of day. So the heavyweights in Alberta are turning to clean energy.

The chief executive of Suncor and the CEO of Alberta Innovates last month co-authored a call to action focusing on a green recovery from the crisis, with oil and gas companies playing the lead role in that recovery as they were best positioned to drive the energy transformation forward.

“The oil and gas industry is one of the largest markets for, and potentially investors in, clean technology in Canada,” Mark Little and Laura Kilcrease wrote. “The challenges faced by the sector, combined with an entrepreneurial culture and the motivation to thrive in tomorrow’s low-carbon economy provides a wealth of opportunity for clean technology investment by the sector.”

Some would say that oil sands are dead. Others would note that they will be alive until there is no demand for heavy oil. As this demand falls, however, the companies producing the heavy oil are indeed wise to look for other ways to supply energy to their consumers.

Offshore oil remains resilient… for the most part

Offshore oil and gas projects may be costly and slow to come on stream, but they also have long lives and relatively low operating costs. And they appear to be among the most resilient segments of the oil industry in this unprecedented crisis that we are experiencing right now.

In the Gulf of Mexico, for instance, as much as 80 percent of producing projects have a marginal cost of just $10 per barrel, according to Wood Mac. But even outside the Gulf of Mexico, offshore oil production costs have been falling, helping the segment weather this storm like all the others before it. Some governments are helping, too.

The U.S. federal government has approved 12 requests for royalty reductions from offshore drillers to help them survive the worst. The Norwegian government is also helping its offshore oil industry: it recently approved a package of relief measures that could reduce breakeven levels for some projects by as much as 40 percent, if only temporarily.

And yet not everyone in the offshore business is as resilient as the companies that pump the oil. Offshore drillers are facing much tougher times as producers curb exploration investment. As many as six of the seven largest drilling companies have already applied for bankruptcy protection, begun to restructure, or engaged in talks with creditors, according to a recent Reuters report. Some of them might go under. Those that survive will likely operate in an environment that is very different from the one before the crisis, with a lot fewer rigs—as many as 200 floating rigs may need to be scrapped—and much closer ties to the large E&Ps players who will still be standing once the worst of the crisis passes.

A mixed picture for the rest of the world

U.S. shale has been the focus of a lot of recent forecasts and analyses. The reluctant consensus seems to point to a slower than hoped for recovery and an even leaner and meaner landscape after the crisis. Elsewhere in the world, what all oil companies have in common is the investment cuts and project delays that, according to some like JP Morgan’s Chrystian Malek, will swing the oil market into a deficit and prices will soar to three-digit territory.

It is a definite possibility. Everyone is cutting capital expenditure, from the North Sea to the Caspian, and from Latin America to the Middle East. Perhaps a good example of just how bad the industry has been hurt is this snapshot of the upstream situation in Africa, as presented by Wood Mac: there were 22 projects to be granted a final investment decision over the next 18 months before the crisis; now there are just three. And, as Wood Mac’s analysts note, “upstream value in Africa is down one-third (US$200 billion).”

Why is Africa a good case in point? Simple. Because it was, before the crisis, the hottest new spot for oil and gas investments with a particular focus on liquefied natural gas. It was the new frontier. Now, this frontier may never be passed as it was planned to be passed. If nothing else, diversification into alternative revenue streams may get in the way if the recovery takes too long.

By Irina Slav for Oilprice.com,
Photo by Zbynek Burival on Unsplash

There may, as discussed in part two of this series, have been little gender and racial diversity among the participants in London’s 1980s oil trading. But there was plenty in the product set and, ever increasingly, among the firms dealing in them.

Oil streams of differing qualities flowed to Sullom Voe, Flotta, Nigg Bay, Hound Point and Teesside, and there was a plethora of offshore loading locations at Statfjord, Beryl, Montrose and others. It represented a wide and interesting canvas on which the industry could play.

A varied cast

And there were many different types of companies involved from the early days. The big integrated companies such as BP, Shell, Conoco, Chevron, Mobil, Texaco and Gulf were active participants—although Esso, notably, was not. There was also a fair representation from out-of-town North Sea producers such as Texas Eastern, Marathon, Philips and Kerr McGee—all regularly preyed on over lunch by the independent traders.

The US refiners had their men in London: Crown Central, Coastal States and Sun Oil among them. By 1984, according to research by the Oxford Institute for Energy Studies’ Robert Mabro, a full 60pc of North Sea oil headed to the US to be refined. This is not, though, to understate the diversity of refining players in Europe. The likes of OK Petroleum, Cepsa, Saras, Wintershall, CFP and a host of others were regular refiners of North Sea grades.

The independent traders—Phibro, Transworld, Tradax (Cargill), Avant, Bomar, Gotco and countless others—were active on a daily basis. As were the Japanese sogo shoshas, which were seeking turnover rather than profitability, to the delight of other players. This group preferred a long, late evening to a fine lunch. The trading community was only too willing to provide company for them, and ingratiate themselves over a whiskey or five in the process!

The early brokers Fearnoil and PVM, under Anders Johansen and David Hufton respectively, played a central role in London in shining a light on the opacity. The price reporting and specialist newsletter services of Platts and Argus expanded with the growth of the business, as did the longer-established publications PIW and MEES.

Argus had been reporting prices from 1970, when the redoubtable Jan Nasmyth founded that entity, and his Weekly Petroleum Argus front-page opinion pieces were devoured by the whole industry in the same way as the insights of Wanda Jablonski and Amy Jaffe in PIW.

There were plenty of characters, ranging from spies—whose names must, of course, remain secret—to alleged ex-mercenaries. Yet it was a business and a market which, on the whole, was run free of illicit activity, surprisingly so in such a big money arena.

The Americans are coming

The so-called ‘Wall Street refiners’ entered the fray from 1985, led firstly by Morgan Stanley, whose head of metals, Bob Feduniak, sensed an opportunity in oil. He sensibly mixed the experiences of ex-oil company traders Nancy Kropp and John Shapiro with the in-house cerebral contribution of Marc Crandall—who, with the late Claude Dauphin, Eric de Turckheim and Graham Sharp, would go on to found Trafigura in1987.

Morgan Stanley was immediately followed by J Aron, the commodity trading arm of Goldman Sachs, led at the time by Gary Cohn and featuring ‘the Steves’—Hendel and Semlitz—who would go on to found Hetco and Hartree. The opportunity they saw arose from the success, from 1983 onwards, of oil futures trading on the Nymex. The Nymex WTI crude oil futures contract changed everything and was the first critical driver in the development of the ‘financialisation’ of markets which was to characterise the 1990s.

Back in London, the IPE had been trading gasoil futures since 1983 but had found it difficult to sustain a crude oil contract. Only after Morgan Stanley blazed a trail with its OTC partials market in Brent in 1987-88—supported at its inception by Conoco, Petronor and ICI amongst others—did the IPE finally manage to ride on the back of that OTC market and create a successful futures contract. In time, of course, it became the world’s primary benchmark crude oil contract.

It was a time of invention and, hot on the heels of crude oil futures and OTC partials, came the Brent CFD market. It was designed to finetune the hedging of the Dated Brent market but became also a significant instrument for speculative activity. Mobil and Chevron were leaders in this field and found willing counterparties in the two original Wall Street refiners and other newbies from the same stable— most notably Drexel and Bear Stearns.

By Colin Bryce, Petroleum Economist, 27 July 2020, Photo by Ed Robertson on Unsplash

The billionaire CEO of Gunvor Group told staff the firm thrived during the oil market meltdown caused by the Covid-19 pandemic as trading and shipping operations boomed, offsetting potential refinery writedowns.

Torbjorn Tornqvist, the co-founder and chief executive officer of Gunvor, one of the biggest independent energy traders, told employees in an internal email that earnings from trading oil and ship chartering excelled during the second quarter, according to people familiar with the email’s contents.

“Gunvor managed to navigate very well through the downs and ups and got it basically right,” Tornqvist wrote, according to the people who asked not to be named because the email is private.

Gunvor’s strong performance is the latest example of energy traders racking-up profits during the market crash, which saw oil prices in New York briefly trade below zero in April.

The Geneva-based trading house took full advantage of a market structure called contango to fill tanks with cheap oil and sell forward futures contracts for delivery later at higher prices.

The closely-held company, which owns or manages more than 100 ships, also profited from soaring chartering rates during the crisis as traders and producers rushed to secure tankers to store and transport oil and products.

“Given our sizeable fleet of ships under management, this allowed for substantial earnings for the quarter,” Tornqvist wrote.

A Gunvor spokesman said the company doesn’t comment on internal communications.

Refinery Woes

The memo wasn’t all good news. Tornqvist said he expected brutal refining margins, which have devastated the industry, to persist for “many years.”

Gunvor has previously said it is considering mothballing its refinery in Antwerp, Belgium because the facility continues to lose money.

Tornqvist, who has a personal connection with the plant having worked there more than three decades ago, said if the company does shutter the plant, trading and chartering profits during the first half would more than offset any impairment charges.

The company’s strong second quarter represents a dramatic rebound from a tough first quarter where it earned only about $20 million in net income, according to people familiar with the trader’s results.

Rival energy traders Trafigura Group and Mercuria Energy Group have also thrived amid the market sell-off. Mercuria told bankers on a recent loan call it made a record $425 million in net income in the first half of the year while Trafigura reported record results from trading in the first six months of 2020.

Oil traders in Geneva, one of the world’s biggest hubs for commodities trading, have largely returned to their offices after conducting business from home amid the early stages of the pandemic.

“I am impressed how you all have managed your work under the rules of social distancing and got on with business in such a formidable manner,” Tornqvist said in the email.

By Andy Hoffman and Laura Hurst, Bloomberg, July 15, 2020,
Photo by M. B. M. on Unsplash

Oil traders make investment decisions based on various inputs. Some use charts to predict future price moves, others look at supply and demand data, and in the 1920s some traders actually thought that the dialogue bubbles in comic strips revealed the future price move of stocks and commodities. New technologies brought more complex methods including the use of thermal cameras to track pipelines and storage tanks. And according to Reuters, many oil traders thought that thanks to Apple, they had discovered the “holy grail” of forecasting gasoline prices.

Oil traders find lack of a solid correlation between Apple’s mobility data and the demand for gasoline

In the middle of April, Apple announced that it was releasing data from its Maps app based on the number of requests for directions made by iPhone users. This so-called mobility data was created to track the spread of COVID-19. But oil traders decided that by studying the data from Apple, they could come to some conclusions about how fast demand for gasoline and crude oil was recovering after drying up from the global pandemic.

Traders who used the mobility data in their trading systems were hopeful that it would provide them with useful and accurate information. But the report notes that this backfired; using the mobility data as an additional tool, traders purchased gasoline futures heading into the Memorial Day weekend back in May. The U.S. Energy Information Administration (EIA) announced that its data indicated a 6% decline in demand for gas, and futures prices declined creating red ink for many traders. Considering that 70% of the demand for oil is for vehicles, traders were upset not only because they took a hit to their accounts, but also because this exciting new tool that traders thought would tell them the future was not working.

What caused the disconnect? Some say that the problem lies with the fact that Apple’s mobility data is based on search requests and not on actual miles traveled. Apple explained on its website how it calculates the data: “Using aggregated data collected from Apple Maps, the new website indicates mobility trends for major cities and 63 countries or regions. The information is generated by counting the number of requests made to Apple Maps for directions. The data sets are then compared to reflect a change in volume of people driving, walking or taking public transit around the world. Data availability in a particular city, country, or region is subject to a number of factors, including minimum thresholds for direction requests made per day.” So the information used by traders only reveals how often an iPhone user looked up directions to a location. Instead of discovering a tool that provided them with real-time demand data for oil, the traders simply saw hypothetical demand for fuel.`

Matt Sallee, managing director of investment firm Tortoise Capital Advisors, says that the data generated by Apple does not correlate to oil demand as well as other indexes do. Sallee says that he still uses Apple’s mobility data but adds other data including real-time traffic congestion information from mapping firm TomTom. He also uses the Dallas Federal Reserve Bank’s mobility and engagement index which tracks how far user devices travel in a day and how long they remain away from home.

TomTom’s data is preferred over Apple’s data by RNC analyst Michael Tran. The latter says that most people do not use apps to map out their outings. RNC uses TomTom’s data along with its own in-house geolocation data. While Apple declined to comment on the Reuters report, the company claims that its data captures everyone who owns an iPhone. That works out to about 100 million people in the United States alone.

With millions of dollars at stake, traders are always searching for a tool that will give them an edge.

by Alan Friedman, phonearena.com, July 4, 2020,
Photo by Medhat Dawoud on Unsplash

LONDON (Bloomberg) –Royal Dutch Shell said it will write down between $15 billion and $22 billion in the second quarter, as the company gave investors a wider glimpse of just how severely the coronavirus crisis has hit Big Oil.

The impairment is the firm’s largest since Royal Dutch Petroleum Co. and Shell Transport & Trading Co. merged in 2005, and shows how the pandemic has left no part of the energy giant’s sprawling business unscathed. Shell lost money from pumping oil, fuel sales fell and shipments of everything from liquefied natural gas to petrochemicals suffered.

The lockdown-induced slump has permeated through the entire industry, which is reassessing both the value of its assets and longer-term business models. Shell’s large LNG business, which is central to its vision of the future of energy, is seen taking the biggest hit.

Big Charges

“We see material downside for second-quarter earnings,” Banco Santander SA analyst Jason Kenney said. Despite a possible weaker performance relative to its peers, the Spanish bank still sees potential upside in the stock, as the bad news was largely anticipated.

The drop in demand comes as little surprise. Oil majors’ earnings took a beating in the first quarter, and the companies warned that things would only get worse as the full impact of the pandemic started to be felt in March. Despite a recent rebound in consumption in some of the worst-hit countries, resurgent waves of the virus show the recovery remains fragile.

Oil-product sales volumes will be 3.5 million to 4.5 million barrels a day in the second quarter, down from 6.6 million a year earlier, driven by a “significant drop” in demand because of the pandemic, Shell said Tuesday in a statement ahead of quarterly results on July 30.

Shell also flagged that its upstream unit, traditionally the company’s core business, will suffer a loss in the second quarter. The division, which is responsible for pumping oil across the world, will take an impairment charge of $4 billion to $6 billion, mostly from North American shale and Brazilian assets.

Shell said it has revised its mid- and long-term pricing and refining margin outlook, and expects gearing — a measure of debt — to increase by as much as 3% due to the impairment charges.

The company’s B shares fell as much as 2.6% and traded down 2.3% at 1,241.40 pence as of 1:26 p.m. in London.

Drastic Changes

The coronavirus has exposed the vulnerability of some of the world’s biggest oil and gas companies, but also given them an opportunity to make investors swallow some unpleasant remedies. Since the pandemic started, Shell and BP Plc have made drastic changes to their businesses, from multibillion-dollar writedowns to big cuts to dividends and jobs.

They explained these moves as responses to the dual threats of the lockdown-induced oil slump and the growing pressure to cut carbon emissions. BP has said oil and gas prices will be lower than expected in the coming decades as the virus hurts long-term demand and accelerates the shift to cleaner energy.

Second-quarter performance at Shell’s in-house trading unit, which can be a boon when other parts of the business are hurting, is expected to be “below average,” the company said. Still, trading and optimization will offset “significantly lower” refining margins.

When Shell reports its results next month, the market will be focused on the company’s outlook and any green-shoot developments, said Jefferies analyst Jason Gammel. The market is getting closer to balancing, he said, and while this isn’t necessarily bullish, “it’s better…it’s bad but it’s better.”

The company indicated there was more pain to come from LNG sales, which have a price lag of three to six months compared with oil. The impact of crude prices on LNG margins became “more prominent” from June.

Longer term, Shell is optimistic about the LNG market, with Chief Executive Officer Ben van Beurden telling Bloomberg in an interview in May that he expects the market to recover to pre-virus levels.

In April, Van Beurden cut the company’s dividend for the first time since the Second World War. Last month, the Anglo-Dutch major said it would be well-placed to boost shareholder payouts again once the oil market recovers.

“This morning’s announcement will cement the view that dividends will take longer to get back to their pre-crisis level than originally thought,” said The Share Centre analyst Helal Miah.

Worldoil.com, Laura Hurst, June 30, 2020,
Photo by Marc Rentschler on Unsplash

MOSCOW (Reuters) – Russian oil exports to Europe are set to hit their lowest levels in two decades in July, with an output cut deal prompting other suppliers to fill the gap left by Moscow, data from traders and Refinitiv Eikon shows.

Russia is set to slash seaborne Urals supplies to Europe to 3.8 million tonnes (900,000 barrels per day) next month, its lowest since 1999, when President Vladimir Putin first came to power as prime minister.

“This is a shock for everyone … Even the American oil is currently more profitable to refine … Requests for oil supplies from the United States have increased,” a trading source said.

Light oil flows from the United States to Europe were close to 3 million tonnes in both May and June, just 1 million tonnes lower than a record high in March, Refinitiv Eikon data shows.

Supplies from the United States to Europe remain ample despite oil production decrease in the U.S. by 2.1 million bpd from March, as oil prices have plummeted due to overproduction and the fallout from the coronavirus crisis.

Through May to July, Russia produced 2 million bpd less due to the global oil output cut deal, which Washington is not part of. With less Urals available, its prices have spiked, hurting the demand further.

Urals have traded at a hefty premium of more than $2 per barrel to dated Brent, global benchmark, since April, up from a discount of around $4 per barrel.

Russian crude sales have also been hit by recovering oil production in Europe, where output had been stagnant for decades until Norway launched the huge Johan Sverdrup oilfield last year.

The new grade, JS Blend, has lower sulphur content than Urals, making it more attractive to some refineries. Norway is not part of the global cuts either and production at Johan Sverdrup is seen rising to 440,000 bpd this summer.

“There is a high risk of not finding a (Urals) cargo at all, so we are looking for alternatives from the start,” a trader at a European refinery said.

Reuters, Gleb Gorodyankin, Olga Yagova, June 30, 2020,
Photo by Irina Grotkjaer on Unsplash