LONDON (Reuters) - When U.S. firm ConocoPhillips COP.N spun off its refining assets in 2011 to focus on more profitable oil production, it seemed only a matter of time before one of the oil majors followed suit.
Three years on, the six vertically integrated global majors are still holding onto their often loss-making plants, seen as a drag by investors.
They cut oil processing rates, sell individual plants, shift exposure from region to region, but have yet to follow Conoco’s lead, hanging on instead to returns that are a shadow of the boom years of 2004-2007 but still worth having.
Conoco’s downstream spinoff was part of a trend in the U.S. industry where a handful of mid-level companies split their upstream and downstream operations, including Hess HES.N and Marathon MRO.N.
Europe’s oil refining guru, Marcel van Poecke, believes the move will be repeated one day.
“Investors say: ‘We don’t need you to be an integrated company’ ...They say: ‘We can buy BP BP.L for upstream and Valero VLO.N for downstream. And we will create our own oil company’,” Van Poecke, who runs a fund at private equity giant Carlyle CG.O, said this month.
The head of the world’s largest trading house Vitol, Ian Taylor also sees majors drastically reducing exposure to refining.
However, majors themselves say not many people realize how much scaling down has been already done in the past years.
BP, once considered to be a monster of refining, has sold 13 refineries in as many years, effectively halving the number of plants in which it participates or operates.
BP’s chairman Carl-Henric Svanberg says he believes majors will be actively shifting refining centers rather than selling off entire divisions.
“It is a different story if you look at developed and developing markets. We are decreasing our position in western markets... Whereas if you go to developing markets like Russia or China, then you still have the integrated chain,” Svanberg said this month.
Ivan Glasenberg, the head of commodities giant Glencore GLEN.L, which is currently leading a drive among miners to reduce costs and increase payouts, says oil majors embracing the same strategy should learn one lesson from mining.
“Don’t overproduce,” Glasenberg said this month.
His message is more applicable to downstream at oil majors rather than to upstream, where oil cartel the Organization of the Petroleum Exporting Countries can perform a balancing act to smooth out sharp production fluctuations.
In downstream, overproduction effectively happened over the past decade when a refining peak in the early 2000s saw too many refineries built around the world.
“If you look at the energy outlook you will see that fuel consumption in the developed market is flat or even coming down. With the increased share of biofuels you are actually seeing a slightly decreasing consumption of fossil fuels,” said Svanberg.
“Because of that the market is actually oversupplied. And very competitive... The only reason to be in refining in the Western world is actually if you have a distinct advantage as we have in Whiting,” he said referring to BP’s modern U.S. plant.
JBC Energy analysts estimate global crude distillation capacity will rise 9 percent to 92.6 million barrels per day in 2014, from 85.1 million bpd in 2004.
“Six years ago (in June 2008) we expected 2014 capacity to come in at 98.2 million bpd. This is a nice illustration of the post-crisis slowdown of demand as well as the reaction to overcapacity in terms of both shutdowns of existing plants and delays and cancellation of planned additions,” said David Wech from JBC.
Even as global refining capacity grew, albeit at a slower pace than expected, majors took a different approach.
Total refining capacity at six global majors - ExxonMobil XOM.N, BP, Royal Dutch Shell RDSa.L, Total TOTF.PA, Chevron CVX.N and Eni ENI.MI - fell by over 16 percent over the past decade to around 15 million bpd, according to Reuters calculations.
Except for Eni, all majors reduced their capacity, especially in Europe, where 1.5 million bpd of capacity has closed since 2008 amid weak demand and competition with new, modern plants in Asia, the Arab Gulf and the United States.
As Russian refineries upgrade too, another 2 million bpd are likely to close in Europe before 2018, according to JBC.
But as refining operations at majors become slimmer and more modern, the peak of the low returns pain might have passed.
According to BMO Financial, part of Bank of Montreal, majors such as Chevron, Exxon, BP and Total will probably see returns on average capital employed (ROACE) - a key metric for investors - in the area of 9-12 percent in downstream by 2017. Shell will see its ROACE at 7 percent and Eni at around 1 percent.
That is course a pale reflection of returns of 17-18 percent during the boom years of 2004-2007 but still not enough to fully divest downstream, especially as ROACE in upstream is also expected to fall to 11-15 percent from the peaks of 30 percent.
For BP free cash flows from downstream are expected to more than double to $9.6 billion by 2017, while free cash flow from upstream will only rise by 20 percent to $28.7 billion, according to BMO.
“The proportion of free cash flows that the downstream creates from its operating cash is much higher than the upstream,” Iain Conn, who runs BP’s downstream, told Reuters.
There are other reasons that will also help majors retain their downstream, including access to new regions.
“Quite often (emerging market) governments like a company that has got the downstream and helps them with their market evolution as well as developing their resources,” says Conn.
Finally, downstream can play an important role in bringing refining and extraction technologies together with research into how car engines interact with lubricants helping shed light on upstream fracking operations where oil is separated from rocks.
“It is exactly the same chemistry. We have put those teams together,” said Conn.
Additional reporting by Peg Mackey and Alex Lawler; editing by Keiron Henderson