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It’s been a wild and bumpy ride for OPEC+ this year. The consortium, consisting of the traditional members of the Organization of the Petroleum Exporting Countries plus oil and gas superpower Russia, was largely responsible for the huge collapse in oil prices toward the end of April. After a huge drop in oil demand corresponding with the devastating spread of the novel coronavirus around the world, an OPEC+ strategy meeting turned into a spat between Russia and Saudi Arabia which then turned into an all-out oil price war and massive global oil glut. The oil storage shortage created by this glut would go on to push the West Texas Intermediate crude benchmark into previously-unthinkable negative territory, closing out the day on April 30th at nearly $40 below zero per barrel.

OPEC+ has since reconciled and once again banded together to address the oil market crisis, making myriad pledges and severe production cuts to bolster crude oil prices. But many of the countries that made those pledges have fallen far short of their promises. “OPEC reached a historic deal to cut output by 9.7 million barrels per day in April, but a number of countries fell significantly short in meeting their production targets,” reports Markets Insider.

But, just this week Iraq, OPEC’s second-biggest member just made a huge commitment to cut its oil production in the coming months. After a Thursday night conversation between Iraqi and Saudi leadership, Baghdad “made a commitment to cut oil production by 400,000 barrels per day in August and September,” a massive uptick from the nation’s relatively paltry July production cut of 11,000 barrels per day.

But while the oil market is now recovering and countries like Iraq are starting to fall in line, this may not indicate smooth sailing for the international oil consortium. “Rebounding oil prices have the potential to show the cracks that already exist in the delicate cooperation between the powerful oil-producing nations,” the Wall Street Journal reported this week in an article entitled “How a Tenuous Saudi-Russia Oil Alliance Could Melt Down.”

The article recounts OPEC’s rough, tough year(s), remarking that “Saudi Arabia, the dominant force of OPEC, might as well have been herding cats in recent years trying to bring order to the unruly cartel.” At first, the addition of Russia to bring the “+” to OPEC+ was a godsend for the group and a boon to oil markets, but now Riyadh and Moscow’s extremely different ambitions could spell doom for the cartel.

In light of the fact that many OPEC+ members have been complying with production cuts and that these cuts seem to be working, in mid-July, the cartel actually agreed to let OPEC members’ overall production to increase by a considerable 1.6 million barrels a day. “The latest adjustment was a reflection of a demand picture that seems to be improving,” reports the Wall Street Journal. “Yet that very development could hobble cooperation between Saudi Arabia and Russia going forward.”

As history has taught us over and over, alliances more often than not require a common enemy–in this case a floundering oil market. “Under $40 [a barrel], they were able to come together. The higher the price, the harder it will be to get Russia to go along with continued production cuts—especially once you get to $50 a barrel for Brent Crude,” Gary Ross, Chief Executive Officer of Black Gold Investors told the Wall Street Journal.

And now, there’s not enough to keep Saudi Arabia and Russia’s diverging visions from, well, diverging. The two nations at the helm of OPEC+ publicly claim vastly different break-even prices and the recent easing of austere production measures could be the harbinger of doom for the already delicately-balanced cartel. And a dramatic failure for OPEC and its consortium of precarious oil autocracies could spell serious geopolitical turmoil for the Middle East, and by extension, for all of us in this global village.

By Haley Zaremba for Oilprice.com
Photo by Mohammed Hassan on Unsplash

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