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European refiners try to optimize amid gas crisis, North Sea decline

Europe’s oil refiners are grappling with the combined impact of North Sea decline and rocketing prices for natural gas used in their operations, even as they enjoy higher margins on the back of the pandemic recovery.

Refiners have said they are doing their best to reduce use of natural gas as the market is squeezed by Russian supply shutoffs stemming from the conflict in Ukraine.
It comes as European refineries are expected to remain stretched going into winter when it comes to supplying diesel, partly due to sanctions on Russian diesel supply, even as recession fears have helped ease gasoline market tightness.

BP’s indicative marker margins for Northwest Europe and the Mediterranean were roughly five times year-earlier levels in Q2 2022.

Ultra-low sulfur diesel was assessed at $987/mt on Aug. 5 in the Amsterdam-Rotterdam-Antwerp hub, still more than double from year-ago levels despite a recent pull-back, according to Platts assessments from S&P Global Commodity Insights.

However, at its latest quarterly results, TotalEnergies said energy costs in its refining division had at least quadrupled to $20-$25/mt. And US downstream company ConocoPhillips estimated the advantage for US refiners over European counterparts due to gas prices at $10-$12 per barrel of throughput; it said its own 221,000 b/d Humber refinery in the UK was a “very low” consumer of purchased natural gas, however.

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Shell CEO Ben van Beurden said his company’s refining segment was taking “self-help” measures to reduce gas consumption, making gas where needed from oil refining processes rather than taking it from national grids.

This would typically involve using refinery fuel gases, LPG and naphtha to provide heat and power, likely reducing commercial sales of LPG and naphtha, the latter a petrochemical feedstock.

Van Beurden said Shell had reduced gas intake by 40% at its Rotterdam refinery and by 50% at its Moerdijk chemicals plant, with a 70% cut in gas use at its Rheinland energy and chemicals park in Germany. BP said it had reduced gas intake at its continental European refineries by 50%, with Italy’s Eni also talking of similar measures.

“We are able to reduce gas intake for processing without actually changing much on the output,” van Beurden said. “The way we effectively do it is to run our refineries, which are complex refineries in both Germany and the Netherlands, in such a way that we produce more off-gases in say cracking processes and everything else and then we use basically gas that has been produced out of the oil intake to fire some of these furnaces.”

“These are very material reductions of a material stream and very welcome therefore as we prepare for winter,” he added.

The effort to reduce gas consumption is part of a trend toward gas-to-oil switching among industrial facilities generally and partially reverses earlier trends to use more natural gas in refining as a way of limiting emissions. Natural gas use by UK refineries jumped from 5.3 Bcf to 9 Bcf annually between 2009 and 2019 against a backdrop of UK refining capacity dropping around 30%, according to government figures.

Analysts at S&P Global estimate the total impact of European industrial users switching from gas to oil at 198,000 b/d in the third quarter 2022 and 195,000 b/d in Q4 2022.

“High natural gas prices continue to pressure refining margins for refiners reliant on gas as input. Those that are able to substitute natural gas with cheaper fuels, such as Low Sulfur Fuel Oil, are seeing wider margins, around $6.9/b higher,” Rebeka Foley, Europe oil market analyst at S&P Global said.

Crude flows
On the input side, curbing natural gas use may also incentivize processing light sweet crudes such as those from the North Sea as these entail less desulfurization in the refining process, which uses hydrogen often produced from natural gas.

Such pressures, along with sanctions on Russian crude, have helped keep North Sea crude at a premium at a time of muted regional production; UK North Sea output, while up from 2021 lows, remains affected by field depletion and maintenance, while Norwegian production, though more prolific, is now dominated by the more sulfurous Johan Sverdrup oil field.

“Right now there is a preference for low sulfur [crude] and I think this trend will accentuate as we move into winter,” assuming continued Russian gas shortages, one crude trader told S&P Global.

Weak North Sea production is in turn incentivizing light sweet crude imports, notably from the US, which shipped around 1 million b/d of crude to Europe in 2021, according to the BP Statistical Review. Libya’s recent recovery is also said to be providing relief. For the UK, the share of US crude processed by its refineries rose from 21% in 2019 to 26% in 2020, while increasing volumes are also being imported from Turkey, according to the UK Petroleum Industry Association; the Turkish volumes likely originating in part from Azerbaijan, source of the Azeri Light grade.

However, the issue of gas input costs is likely to be particularly acute on the European continent, with its reliance on pipeline inflows from Russia.

Texas-based Valero, which operates the UK’s Pembroke refinery, said the facility had done particularly well of late, with chief operating office Lane Riggs saying the UK is “a little bit better positioned than Europe is in terms of the value that they’re paying for gas.”
Source: Platts

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