Last month, US President Joe Biden slammed ExxonMobil, complaining that the energy company made "more money than God".
"We're gonna make sure that everybody knows Exxon's profits," Biden commented in response to a question about inflation. "Exxon made more money than God this year and, by the way, nothing has changed."
In fact, it has. ExxonMobil reported its second-quarter results on Friday, July 29, and the oil major's net profit was US$17.9 billion, more than double the US$8.9 billion it reported in the first quarter (a number that excludes a US$3.4 billion charge for exiting the Sakhalin 1 project in Russia in March).
"More than God" in this context also means, "more than Google and Facebook, but less than Apple." Apple's profits for the second quarter were over US$19 billion.
However, the gangbuster results at ExxonMobil beat analysts' estimates of US$16.9 billion, and were a record for the company. The Financial Times reported that the previous highest quarterly net profit for the company was US$15.9 billion in 2012, when oil was also back above US$100 a barrel, as it is now.
"The strong second-quarter results reflect a tight global market environment, where demand has recovered to near pre-pandemic levels and supply has weakened," said chief executive Darren Woods in the results release here. "This situation was made worse by the events in Ukraine."
ExxonMobil's oil-equivalent production in the second quarter was 3.7 million barrels per day, more than most OPEC nations, and the company reported that its cash increased by US$7.8 billion in the second quarter, as strong cash flow from operating activities more than covered capital investments and shareholder distributions. Free cash flow in the quarter totalled US$16.9 billion, so almost all its profits were realised in cash. The company spent nearly US$4 billion buying back its own shares and paid out US$3.7 billion of dividends to shareholders.
ExxonMobil has not been alone. Chevron's second quarter profit was US$11.6 billion, also its highest quarterly profit ever, as the company smashed through analysts estimates that it would "only" achieve US$9.9 billion in profit. Chevron just pipped Shell at the post. Shell reported its second consecutive record-breaking quarter too last week, with adjusted earnings of US$11.5 billion. TotalEnergies meanwhile reported that its profits in the second quarter rose to US$9.8 billion, almost triple the profit from the same time a year ago. Italy's Eni also announced bumper second quarter results, with a quadrupling of its profits year on year to just under US$4 billion.
However, Norway's Equinor beat all its European rivals and Chevron as it reported adjusted pre-tax earnings of US$17.6 billion in the three months to the end of June, a tripling of income on the same period last year. The higher profits were driven by the same higher gas prices that drove up earnings at the other players.
Equinor also achieved increased production as Norway emerged to displace Russia as Europe's largest gas supplier. Equinor announced good news for the Norwegian taxpayers, who own two-thirds of the company – it said it would be stepping up distributions to shareholders by US$3 billion.
BP is the last major to report. BP's second quarter 2022 results will be published on Tuesday, August 2, at 7:00 UK time. The only question now is, "How high will they be?"
In 2020, observers were prophesying the end of the oil industry, as the majors reported massive losses, and Shell and BP slashed their dividends to zero. Now, there's a huge amount of "told you so" from their management, as technology company valuations fall and the world wakes up to the central role that oil and gas still play in supplying power and providing heat, light, and fuel. In its investor report (here), ExxonMobil was quick to highlight that in 2020, it invested around US$13 billion in its upstream exploration and production business, despite losing US$20 billion in that segment.
Oil and gas is a long-cycle business and the six years of low investment from 2015 to 2020 will take time to correct.
Expect the oil and gas companies to emphasise the uncertainty over oil prices, and the risk of a global recession pulling down demand. This enables them to sidestep demands from politicians for windfall taxes, and to highlight that their bumper profits may only be transient. Expect to see efforts to place special taxes on oil and gas companies to be rebuffed with arguments to the effect of, "Why not tax Apple extra, too?"
Given the brutal war of attrition in Ukraine, as the Russian invasion descends into the mutilation and murder of prisoners of war, it is unlikely that Western buyers will be rushing to buy Russian oil and gas, again unless there is a wholesale change of regime in Moscow, and unless there is accountability for the war crimes that seem to have occurred. This means that even with a global recession, oil and gas prices are likely to remain much higher than they did in the period 2015 to 2020. We can therefore expect oil majors' profits to remain high for the short term.
For contractors, day rates for rigs, supply boats, and other offshore services are rising, but much more slowly than the oil major's profits. After a sizzling June, North Sea spot rates slowed at the end of July, with platform supply vessels (PSVs) now fixing for US$15,000 a day last week (Stril Mermaid to TotalEnergies Denmark), and our bellwether spot anchor handler, Pacific Discovery, reported as fixed for "only" US$45,000 per day for the rig move of the jackup Maersk Innovator starting on August 3, according to Westshore brokers (here). That's half the rate the vessel achieved in June.
In the last boom, high oil prices in the 2012 to 2014 period were offset by massive cost increases, which saw deepwater rigs hit US$600,000 a day, and multi-billion budget overruns on projects like the Kashagan field in the Caspian Sea off Kazakhstan and the disastrous Gorgon LNG plant in Australia. Today, deepwater rigs are managing day rates of just under US$400,000 as additional laid-up units return to work. Valaris announced that it had reactivated four drillships in the last year and the overhang of surplus capacity acts as a brake on the day rate increases that contractors can achieve.
Expect the oil majors to use all their negotiating power to try to reign in costs in this stage of the cycle. It's okay for them to make record profits, but not their contractors. Indeed, on Friday last week, Boa Offshore announced that its creditors had taken over the shares in Boa OCV, a subsidiary that owns two offshore construction vessels, Boa Sub C (built in 2007) and Boa Deep C (built in 2003). The Bjørnevik family-controlled BOA Management will continue to act as manager of the vessels, but the creditors and not Boa OCV will formally own the ships.
Many vessel owners and rig companies remain fragile after the pain of the market collapse in 2020 and the preceding industry-wide recession from 2015 onwards.
In the Middle East, the "do it yourself" trend we identified last year (here) has continued with the state oil companies continue to binge their excess profits on oilfield services businesses. The latest acquisition was the news (here) that Adnoc Logistics and Services was buying Zakher Marine International and its fleet of 24 jackup barges and 38 offshore support vessels (OSVs). The acquisition of Zakher came with an undisclosed price tag but leaves precious few marine and drilling businesses in the region in private hands.
The majors are unlikely to follow suit with such boated, vertically integrated models. Where have state run marine monopolies prospered? Answers on a postcard please.
However, ExxonMobil, in particular, is boosting its spending. It reported second-quarter capex of US$4.6 billion or year-to-date US$9.5 billion. However, the company told investors that it expects to spend US$21 billion to US$24 billion this year, implying that there could be significant extra spending in the next six months, and it advised that it expected even higher investment in 2023.
Any oil or gas reserves with large reserves outside Russia and central Asia (which is dependent on Russian transit routes) thus appear very attractive to the majors as the payback is potentially very fast and creates the opportunity of locking out Russian production for years to come, even if Russia can be rehabilitated into the international community. We see ExxonMobil really ramping up production and exploration in Guyana, where production now accounts for over 340,000 barrels per day and where the company announced it would be piping associated gas ashore to reduce the cost of electricity in the newly rich South American producer.
With two more FPSOs in the pipeline for Guyana, ExxonMobil also announced that it was planning to drill an additional 35 new exploration wells off Guyana in the 2023 to 2028 period. ExxonMobil already has six drillships currently operating offshore Guyana — Stena Carron, Stena DrillMax, Noble Bob Douglas, Noble Tom Madden, Noble Don Taylor and Noble Sam Croft.
ENI has announced that it is now looking at a second floating liquified natural gas (FLNG) system to develop the deepwater gas fields it owns in conjunction with ExxonMobil off Mozambique, and that it continued to fast track its expanding discoveries off Ivory Coast, as well as launching an exploration campaign off Morocco. Total would desperately like to recommence the construction of its own LNG plant onshore in Mozambique, but the security situation seems unlikely to permit a restart until 2023 at the earliest, and Saipem has now announced that when the project does restart, it will be seeking better contract terms from Total, a sign that the low costs of the pre-war period are no longer sustainable.
Expect to see BP make rapid moves to develop its gas fields on the Senegal/Mauritania border, as the Chairman of the African Energy Chamber wrote for us last week (here).
Total has also announced a US$850 million investment in tie-backs to its Angolan deepwater FPSOs. Tie-backs provide quick and cheap incremental production. Chevron is even looking at the Aphrodite deepwater gas development off Cyprus with a tie-back to its Leviathon production facilities in Israel. Discovered in 2011 by Noble Energy (which Chevron acquired), the Aphrodite gas reservoir holds about 3.5 trillion cubic feet (99.1 billion cubic metres) of contingent gas resource in Cypriot waters, plus a further one trillion cubic feet (2.83 billion cubic metres) of potential additional resources.
One area where we can expect to see a lot of fanfare from the majors is carbon capture and storage. They have every incentive to be promising massive investment in this technology, which, in theory, will let them continue producing hydrocarbons even in a "net zero" world of 2050. By sequestering the carbon deep underground – which is an incredibly expensive, and so far not especially successful strategy – they can claim that they are reducing emissions and making the planet safer, even as they continue to pump millions of barrels of oil. And at the same time, they can try and get government subsidies for their efforts.
And so it is at ExxonMobil. The company announced that together with Neptune Energy, Rosewood, and EBN, it had signed an agreement to advance the L10 carbon capture and storage project in the Dutch North Sea. ExxonMobil claims that this stage of the project has the potential to store four to five million tonnes of CO2 annually for industrial customers, and represents the first stage in the potential development of the greater L10 area as a large-volume CO2 storage reservoir.
ExxonMobil has also announced the start of early front-end engineering design studies for a South East Australia carbon capture and storage hub in Gippsland, Victoria. The project would initially use existing infrastructure to store up to two million tonnes of CO2 per year from multiple local industries in the depleted Bream field off the coast of Gippsland. Operations could begin as early as 2025, the company claims.
Chevron's latest presentation highlighted how disappointing its carbon capture and storage project at the Gorgon LNG plant has been, but with pressure on the oil majors rising, we can expect carbon capture and storage to be emphasised in investor communications and in response to rising global temperatures. Whether it works and can be applied at scale matters little to oil majors looking for reasons to continue the status quo.
The wind producers in Europe seem stuck, however. Their share prices have fallen sharply, as they find themselves squeezed by higher costs and bidding against the oil majors, who have much deeper pockets, for new projects. The French government has nationalised EDF. Other wind players are finding it hard to pass higher prices onto their European residential customers.
On August 11, Ørsted will release its interim report for the first half-year of 2022, which will give us a better picture. BP has been busy signing a strategic hydrogen alliance for Iberia with Spain's renewable energy leader Iberdrola, which also owns Scottish Power, and is a major wind farm operator. Iberdrola is currently worth just under US$70 billion and makes a mere US$1 billion in net profit a quarter. Ørsted is worth just US$44 billion, but its Danish government shareholders are unlikely to sell. Shell, on the other hand is worth close to US$200 billion, so temptation in Europe must be rising in the oil majors to use the bumper profits from oil and gas to buy wind and renewables through a "transformative" acquisition.
Nothing cures high prices like high prices, and the history of the oil and gas industry shows that some of the worst acquisitions and most value-destructive investments are made when oil and gas prices are highest. This time is unlikely to be different.