The war in Ukraine has reshaped the world’s fuel markets

In 2017 Qatar lifted a 12-year ban on developing the world’s biggest natural-gas field, most of which lies under the waters of the Persian Gulf. Soon afterwards it announced plans to exploit its share of the field (Iran, too, has an interest) through a $30bn project called the North Field Expansion (nfe). The nfe is designed to increase the country’s liquefied natural gas (lng) production from its current rate of 77m tonnes per annum (mtpa) to 110 mtpa in 2026, an amount which, expanded, would be 152bn cubic metres of gas. Critics saw it as an unfeasibly risky punt. Qatar responded by announcing that a second phase would take it to 126 mtpa by 2027—one-third the size of today’s lng market.

In 2019 a global LNG glut pushed the spot price in Asia, where Qatar sells most of its gas, to $5.49 per million British thermal units (mBTU—the natural-gas business is stalked by unhelpful units), its lowest point in a decade. A year later, as lockdowns enacted in the face of the covid-19 pandemic smothered demand, it fell 20% further to $4.39—its all-time low. The NFE’s critics smelled blood. But Saad al-Kaabi, the energy minister, stuck to his plan. His calculations showed that, by 2025, “plus or minus two years”, the world would be craving gas again.

Mr al-Kaabi was off on timing—but not much else. In 2021 a rebound in energy demand saw consumers scrambling for LNG, in part because it is seen as more climate-friendly than coal. In 2022 the war in Ukraine, which has seen European gas prices soar sixfold in a year, has sent delegation after delegation to Doha, the capital of Qatar, in search of supplies. On the day The Economist met with Mr al-Kaabi, Charles Michel, the head of the European Council, was also in town, braving the ferocious heat and fabricated football fever—Qatar hosts the World Cup this winter—to ask for more gas. Two weeks before it had been the prime minister of Greece; two weeks after it was the German chancellor.

They are not coming away with much by way of wins. In August Qatar sent Europe 2m tonnes of LNG. It was only a fifth of the total it shipped that month but, Mr al-Kaabi says, as much as could be managed, because the rest is tied into long-term contracts, mostly with Asia. Nor will things necessarily get easier in the future. Mr al-Kaabi has signed partnerships with five of the largest Western oil and gas companies; but he is also discussing potential partnerships with Chinese, Indian, Japan­ese and South Korean firms. And he is willing to make straightforward supply deals “with everybody”.

Qatar’s dealfest points to a fundamental reordering of the global energy-trading system. In recent years the main organising principles of the sophisticated web of buyers and sellers of fuel around the world have been price and climate concerns. Now the war in Ukraine has reinserted energy security into the mix at a time when supply cannot rapidly grow. The market which will emerge will be structurally tight. It will also be split along a meridian running from the Urals to Saudi Arabia—allowing Gulf states to arbitrage opportunities as never before.

Turning to face the dawn

Of the three fuel flows which matter most—crude oil, oil products (refined oil) and natural gas—start with the one where the ructions are least apparent: the 100m barrel-per-day (b/d) crude-oil market. From December, European countries will be banning seaborne imports from Russia. Those imports accounted for 1.9m b/d last January. Russian crude exports run at about 5m b/d, which makes this a significant loss. European sanctions do not apply to the smaller flow of oil, around 800,000 b/d, that arrives by pipeline, a loophole designed to keep landlocked Hungary happy. Seeing an opportunity to punish Europe and sow discord, Russia may cut the flow through pipelines anyway.

It can afford to consider this because Russian crude not sold to Europe can be sold elsewhere. Rystad Energy, a consultancy, reckons Russia will be able to redirect 75% of the oil Europe shuns. This redirection is already in full swing. Although European and American imports of Russian crude are down by 760,000 b/d since February, tallies of ships leaving Russian ports show that it is currently shipping half a million more barrels a day than it did a year ago—implying that 1.3m b/d are already finding a new home (see chart).

Last month India, which bought little Russian crude before February, imported 765,000 b/d; China guzzled 900,000 b/d, 230,000 more than a year ago. Adi Imsirovic, a former oil-trading boss for Gazprom, Russia’s state-run gas giant, who is now at the Oxford Institute of Energy Studies, reckons China’s storage and refinery capacity will be able to mop up many of Russia’s excess barrels after the crackdown.

Europe would like to stop this redirection. When the embargo starts European insurance firms, which dominate the global shipping market, will be barred from offering cover to vessels carrying Russian oil. This may not matter much to big players like India and China, which can afford to self-insure; it could be a problem for smaller buyers who lack such means, such as the African countries which in August imported 200,000 b/d from Russia when they had previously bought next to nothing. Europe may exempt those who agree to buy the stuff at a price set by the G7 in order to make such deals more or less profitless for Russia. Russia has said it will not sell at the price the G7 sets.

The whole sick crude

That said, Russia is already getting less than top dollar; Urals crude is selling at 20% to 30% less than Brent crude, the global benchmark. As volumes grow the rebate may steepen. If Russia negotiates long-term deals with Asian countries, as it seems minded to do, they will demand a better price in return for offering a guaranteed market. As this prospect drives down the price in Asia, second-tier producers such as Angola, Brazil, Norway and Venezuela are redirecting their output towards Europe. But so far the job of quenching Europe’s thirst is mostly falling to the Gulf states, whose shipments to the bloc have risen to 1.2m b/d, up from 500,000 b/d in February, and America, which last month sent it a record 1.6m b/d.

Next year, with little or no Russian oil, Europe may need even more from America, because the Gulf is running flat out. Weaker members of the Organisation of Petroleum Exporting Countries (OPEC), such as Iraq and Kuwait, are already producing less than the cartel has agreed they can. Only Saudi Arabia and the UAE have room to increase production, perhaps by 1.8m b/d between them. But they fear slowing growth may hinder oil demand; and they are reluctant to undermine Russia. Russia’s decision to join OPEC+, as the cartel’s extended version is known, in 2016 was the result of decades of effort on the part of the Arab producers.

Getting Iran back into the global market would help Europe a lot. It could rapidly increase its production capacity to nearly 4m b/d. But a deal that would suspend the heavy sanctions America has imposed on the Islamic Republic—the key to unlocking Iran’s supplies—looks increasingly unlikely. So next year it will be down to America to pump to the rescue. Which it might, if prices stay high long enough to tempt its shale oilmen to further open their taps.

Crude oil, though, is not the whole story. It must be refined, and though the world’s refineries have, in aggregate, enough capacity to deal with its crude, the refineries are not evenly distributed. There is a growing shortage of refinery capacity in the West; there is spare capacity in China. This means the effect of Europe’s ban on oil products from Russia will be more complex, and perhaps more far-reaching.

A pick-up truck and the devil’s eyes

Because of the pollution and emissions involved, and expecting a drop in demand as road traffic becomes electrified, the West’s oil majors have invested little in refinery capacity. A lack of maintenance during the various lockdowns further reduced capacity. And because the crude it is now importing is not the same grade as that of the Russian oil many of its refineries are designed for, some of its capacity is not suited to the needs of the day, says Reid l’Anson of Kpler, a data firm. This means Europe cannot simply replace the 1.5m b/d of oil products it bought from Russia last year with crude it can refine itself.

In China, by contrast, concerns about emissions have just led to refineries being underutilised; this year officials in Beijing nearly halved the export quotas allowed to big refiners. About 4m b/d of refinery capacity is not being used.

Because neither China nor India, which has refineries aplenty, have any thirst for oil products, Russia will find it much harder to redirect the refined oil it is no longer selling to Europe (and the lesser amount, 400,000 b/d, that it used to sell to America). That is bad for Russia. But it also means that, unlike the crude-oil sanctions, the oil-product sanctions will cut into the amount of product on the market.

America is doing a lot to plug the gap. Last month it exported a record 6.4m b/d of refined products, a 1m b/d increase in a year. But its refineries cannot respond to demand quickly in the way its oil producers can. And they are currently operating at an average 93% capacity, well above the 85% level deemed sustainable. Sooner or later, traders reckon that the appeal of profit will see China ease its export limits; there are signs this may already be in the works. If so, the global oil-product trade may be turned into a giant “petroleum-laundering operation”, says an Emirati oil boss, with Russian crude flowing to China and India being processed into products which end up in Europe.

Europe may decide to turn a blind eye to this. Its need for refined products may be severe. And it can tell itself that such sales do not really enrich Russia, as its crude would have flowed south and east anyway. If instead it seeks to ban such imports it will have a hard time of it. Refiners can always blend various grades so the share of Urals crude falls below any legal, or even detectable, threshold.

Either way, refined oil from the Gulf, where Saudi Arabia and the UAE have both increased capacity in past years, will find willing buyers. History shows that if they should choose to expand their refinery capacity further they will be able to do so faster than their competitors, and at little political cost. The countries are happy to buy Russian refined oil to arbitrage against their own pricier exports.

The big chill

If dealing with constrained supplies of oil products proves a problem, natural-gas shortages will be a far worse one—and a greater opportunity for the Gulf. Russian gas accounted for 45% of Europe’s imports last year, with most of it coming via pipeline (see chart). In June Russia started to reduce and interrupt deliveries via Nord Stream, its main conduit; it stopped them indefinitely early this month. If it does not restart but other pipelines keep running, Europe will have received 90 billion cubic metres (bcm) of gas from Russia during the whole of 2022, leaving a 60-70 bcm shortfall, estimates McKinsey, a consultancy.

If, as is likely, Russia supplies nothing at all in 2023, Europe will have to find an extra 140 bcm next year—a hole equivalent to 14% of globally traded gas volumes, and to 27% of the LNG market.

And it is to the LNG market that Europe will mostly have to turn. This year it should be possible to replace some 30 bcm of the lost Russian volumes by greater production from the North Sea. But next year Norway, which has been postponing rig maintenance to avoid stoppages, may find itself producing less. There are pipelines from Azerbaijan and Algeria, and the one from Azerbaijan might be able to take some more. But imports from Algeria have been reduced by the closure of one of the two pipelines across the Mediterranean. When it reopens exports are not likely to increase by all that much. Algeria’s gasfields are declining and its own consumption is rising.

Pearl Petroleum, a gas producer in Iraq, is developing a field in Kurdistan that could, once scaled up and connected to the Turkish pipeline network, deliver 20 bcm a year to Europe, starting perhaps in as little as a year. But discussions have been stuck for months because Europe won’t commit to a long-term contract, says Badr Jafar, Pearl’s chair. Similar bemused complaints are heard elsewhere. One gas producer who recently spoke with Germany’s energy minister describes the position as “schizophrenic”: it desperately wants gas, but is unable to commit to buying beyond next winter. Mr al-Kaabi says Europe’s insistence on paying the spot price makes it difficult for him to agree to long-term deals with security of supply.

The absence of pipelines means most of the deficit will need to be made up through LNG or done without. When Russian gas was available on tap, Europe deemed LNG an unnecessarily fussy pair of braces which, having a perfectly serviceable belt, it did not need. It did nothing to encourage natural-gas producers in America and elsewhere to get liquefaction facilities off the ground. Its purchases from Gazprom were indexed to the price of gas at a Dutch hub, which was low throughout the decade, and it did not enter into long-term deals. So scant was the EU’s interest that much of the LNG that came its way was immediately dispatched elsewhere: last year the EU was the biggest LNG re-exporter on the planet.

Now that it wants more it faces two problems. One is the paucity of its regasification infrastructure. In principle the continent has the capacity to turn LNG imports into 209 bcm of gas a year, which on the face of it looks ample. But Germany, Europe’s biggest gas consumer, has no import terminals at all, and one-third of the capacity is in Britain and Spain, from which there is only enough pipeline capacity to provide the core of the continent with a paltry 35 bcm a year.

To remedy this, European countries are paying handsomely to attract movable plants on giant barges. By the end of 2023 ten of them—one-fifth of the global fleet—will be docked at European ports. The EU is also building five onshore import terminals, at the cost of $500m-1bn apiece, but they will take longer to come online.

New currents

Where will the LNG for these new terminals come from? Only 37% of global LNG volumes are traded on spot or on short-term contracts. The rest is locked for the long term, usually a decade or more. For now, Europe is getting as much as it can, largely by sucking in cargo that would otherwise have gone to Asia. The best proxy for the amount of LNG being rerouted while at sea is where the tankers in the Atlantic end up. Last month 70% went to Europe, says Zongqiang Luo of Rystad, up from just 38% a year before. Asian countries are also reselling part of their stock. But soon the bidding war could grow fiercer, as Asian buyers stock up for the winter and China’s gas demand rebounds from the low caused by its zero-covid policy.

This all looks likely to be very frustrating for Russia. Europe accounted for 76% of the 240 bcm of gas it exported last year. Cutting it off thus leaves it with a huge unsold surplus. There is a pipeline linking its gasfields (almost all in the west of the country) to China, but it is barely bigger than the connections from Britain and Spain to the heart of Europe. China, Mongolia and Russia recently met to discuss a pipeline that might be able to supply another 50 bcm to China by 2030, more than doubling capacity. But it is hard to imagine that China, unwilling to tie itself to one (unreliable) supplier, would endorse the idea unless it can extract a huge discount, making the project unprofitable. This must all make increasing LNG production immensely attractive to the Russian government. But Western sanctions are depriving Russia of the technology and skills it needs to make that happen.

Over time new supply will come online. Some of it will come from Africa, where hopes have been high, though an Islamist insurgency near a giant gasfield in Mozambique is making investors skittish. In America there are new projects planned which should produce 44 mtpa (60 bcm a year), and existing facilities will be ramped up both there and in Australia. And there will be the huge North Field increases in Qatar. All told there could be enough new LNG infrastructure in the world to handle 260 mtpa more than the industry deals with today, a 74% increase (see chart).

That is enough to lead some to worry about a glut. Mr al-Kaabi is not one of them—not because they are necessarily wrong, but because he feels that the emirate can tough a glut out. It has a cost advantage in gas like that which the UAE and Saudi Arabia have in oil. Even if prices are pushed down, much of Qatar’s reserves will remain profitable to exploit. “[We] have the downside covered,” says Mr al-Kaabi. “Others will go offline before [us]”