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Downstream depression

Even the International Energy Agency (IEA) admits there are other influences at work: executive director Nobuo Tanaka now says it is "obvious that there are many elements" affecting oil prices – including financial markets (see p4).

The downstream industry's weakness is a compelling piece of evidence that oil – at press-time, crude futures in London and New York were trading at around $80 a barrel – is overpriced.

Refining and selling oil products has become unprofitable in the world's biggest energy market – the US. Crack spreads have narrowed to about half of their long-term norm and US oil companies are making big losses. ExxonMobil's downstream division lost $189m in the fourth quarter; oil prices are now about $10/b higher than they were then, suggesting the first three months of this year may turn out to have been even worse.

Cold winter weather bolstered products demand to an extent, but not enough to cure the industry's underlying problems. US refinery utilisation has been cut to about 80% in an effort to limit the damage, but high fixed costs mean that, sooner or later, further capacity reductions are probably inevitable.

In the US, oil products have simply become too expensive; economic recovery has been anaemic and unemployment remains high. With the retail price of gasoline pushing above the sensitive $3/USG level, more demand destruction could be on the way.

It's not just a US problem. Assets are being put up for sale or closing down in Europe, as companies grapple with weak demand, excess supply of products and too much processing capacity. Utilisation rates in Europe, also at around 80%, are at their lowest level for more than two decades.

Refinery shut-downs in western Europe now involve the majors: Total said last month it will permanently close its unit at Dunkirk, France. There are forecasts that, with few prospective buyers emerging, other major companies will also be forced to close facilities already carrying for-sale signs.

Total's focus for disposals will now be on its European refineries outside France, because the company gave French labour unions – which had called a strike in February – an undertaking not to close or sell any other refinery in the country for five years.

The firm is considering the sale of its 220,000 barrels a day (b/d) Lindsey refinery, on Humberside in the UK, to make progress towards its target of cutting 0.5m b/d of capacity by the end of next year. Total's other European refineries are at Antwerp, Leuna (Germany), Rome and Vlissingen (the Netherlands), and it has five in France besides Dunkirk. The 137,000 b/d Dunkirk refinery stopped operating in September and, Total says, it lost more than €130m ($176m) in the year. It will be dismantled over the years to 2013.

Chevron, meanwhile, is looking for buyers for its Pembroke refinery in Wales, UK, and other European downstream assets may also be considered for disposal (see p27).

Until recently, refineries put up for sale by the majors – which generally do not skimp on maintenance – have been snapped up by the smaller specialist refiners, usually at prices that do not reflect past investments. But now the firms that had been buyers are closing capacity themselves – Petroplus, for example, which built-up its European network through acquisitions from Shell, BP, ExxonMobil and ConocoPhillips, has closed its Teesside, UK, refinery, after failing to find a buyer.

Refining in Europe has always been costly and refining margins are rarely large, but logistics favoured transporting crude to the market instead of refined products. This trend may now be reversing, with operators of new, large refineries in Asia proving able to deliver products to Europe – and the US – at prices competitive with home production. (Equally, however, a counter-argument exists: that the gradual shift of refining capacity to the Middle East and Asia will eventually result in higher end-user prices. Production costs in those regions might be lower, but freight and logistics costs will be higher.)

India's Essar, for example, is rapidly expanding its home refinery at Vadinar with the aim of gaining a foothold in the European market. The firm has been negotiating with Shell since November over the acquisition of three refineries – the flagship 240,000 b/d facility at Stanlow, UK, and Hamburg-Harburg and Heide in Germany, with a combined capacity of 100,000 b/d – and would like to close them and use the sites as import terminals.

Similarly, PetroChina has plans to build up its international sales and has been talking with the UK's Ineos over an investment in the 200,000 b/d Grangemouth refinery in Scotland. PetroChina confirmed last month that "preliminary work" for a bid is under way. Also for sale are Shell's 78,000 b/d refinery at Gothenburg, Sweden, and Eni's 85,000 b/d facility at Livorno, Italy.

If Asia's new refiners succeed in their sales drive, more closures seem inevitable. Europe's refining capacity is in surplus – according to BP, capacity in the EU in 2008 amounted to 15.8m b/d, while products consumption totalled 14.8m b/d (see Figure 1). Refinery throughputs in that year amounted to 13.5m b/d, giving a utilisation rate of only 85%. Consumption and throughputs both declined sharply last year, and motor-fuels demand has probably peaked – biofuels are reducing the demand for petroleum streams, and hybrid and electric cars are becoming more capable. Total describes the decline in products demand as "structural and permanent". BP chief Tony Hayward says margins are likely to be depressed "for the foreseeable future".

The downstream sector's troubles make attempts by Opec to defend $80/b as a reasonable price for crude oil hard to justify. It evidently does not seem reasonable to a European or North American refinery manager – or to Western consumers. And, as the IEA's Tanaka argues, such a level implies a large profit margin for much of Opec's production: while $70-80/b might be necessary for deep-water oil or Arctic projects, Opec's production costs are much lower, he says – perhaps $10-20/b. Some frontier operators might even look on $70-80/b as an attractive price: Brazil's Petrobras, which has to cope with some of the industry's highest upstream costs, claims it can make money on its pricey pre-salt projects when oil is at $45-65/b.

Nonetheless, while there might be few compelling fundamental reasons to expect further oil-price inflation, that doesn't mean prices won't rise. Wall Street bankers have been at it again, forecasting further gains – perhaps to $100/b or above. They may be right, but, as last year showed, the longer oil prices trade above their natural level, the worse the subsequent crash is likely to be.

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