Weekly Overview: Damage Limitation Time

The financial results reporting season got off to as bad a start as predicted, with even ExxonMobil seeing its profits halve on the year. A common theme running through the announcements has been capex reductions upstream, in response to the low oil price.

Prompt Brent crude continued to chart a volatile course over the course of the week that Statoil, BP and Shell/BG also announced their results. It rose on the news that the Saudis and the Russians could be about to do the unthinkable and agree to cut production by a small percentage. Between January 25 and 29 it rose from $29.82/b to $33.14/b, although most observers had always doubted if Saudi Arabia and Russia would make common cause. But they fell 4.4% on February 2 as that dream melted away.

Prices rose almost 8% the next day, though, perhaps because of growing belief that US production would shrink over the course of the year, pushing crude up to the high $40s/b. But US shale production has proved very responsive to price movements in the past, with rigs being idled or put back to work as prices move down and up again, and different plays have different break-even prices as technology improves, complicating the forecasting of where price will balance supply.

While it is likely that many individual companies there will struggle to stay afloat for much longer as interest repayments mount and cash flow dries up, the underlying geology remains as good as ever. One company’s failure to meet obligations might enable another company that is in better financial shape to acquire relatively cheap assets and work them hard.

So with Brent seemingly for now stuck around the $30/b mark, a term LNG supply contract, which is typically priced against Brent but with a discount to be negotiated, could work out at around $4.20/mn Btu plus shipping, which is very similar to the price of gas at European hubs.

Natural gas for day-ahead delivery at the Dutch Title Transfer Facility – which by some measures at least has overtaken the much older UK NBP in the liquidity stakes – has drifted downwards, on average, since January 4, according to data from spot market operator EEX. It started at €14.378/MWh ($4.72/mn Btu) but was at €12.775/MWh ($4.20/mn Btu) on February 2 – 11% lower. It recorded a high of €15.186/MWh and a low of €12.633/MWh over the course of January, again not showing much volatility.

These would be the kinds of prices that US LNG would have to beat if Cheniere Energy's Sabine Pass LNG export terminal had come on stream as planned in January; as it is, its first cargoes are unlikely to arrive here before late March at the earliest, by which time the Dutch price, being seasonally driven, is likely to be even lower. Not every cargo of course has to be profitable in the course of a 20-year contract but those free on board deals with Cheniere – train 1 is the cheapest to use, with later trains having higher charges – were struck in very different market conditions from today. China had yet to “rebalance” its economy, for example, and was seen as a natural buyer even above $12/mn Btu.

European prices could go lower still, depending on the extent to which Norway and Russia's Gazprom defend market share if the US LNG does head towards Europe. Gazprom in particular has gas that it cannot use at home as producers there, such as Rosneft and Novatek, have undercut it with sales to large industrials and the power generation sector. But Gazprom needs revenues to fund its share of pipeline projects, for example, not to mention replenish the state budget. So leaving the gas in the ground is not an appealing option.

There are a lot of implications arising from this, ranging from further contract renegotiations – only this week Turkey won money back from Iran after an arbitration court agreed that the long-term supply contract was overpriced – to the fate of major projects such as Shah Deniz, whose gas has to cross the Caucasus and Turkey through brand new pipelines before reaching what are now depressed European markets. And the European utility model, which E.On for one has tried to escape from, has long been doomed.

Given limited gas demand growth in the short term, most companies on the sale side will be counting on the worst of the trough being over by the end of this decade at the latest, and taking advice now from their lawyers on the impregnability of their pricing clauses. Operators of projects off Africa will face tough decisions regarding markets, if they have cheaper options; Qatar on the other hand cannot really lose as its condensates sales allow plenty of downward flexibility with its LNG contract prices. It has also worked hard to develop LNG markets in Asia.

Buyers on the other hand will be continuing to look for the weak points in their own positions and trying to mitigate them, whether through arbitration, friendly renegotiation, or corporate restructuring. The latter two approaches worked for British Gas in the UK in the mid-1990s, weighed down as it was with expensive gas purchase contracts, and it broke up ultimately into three value-creating companies: BG, Transco and Centrica. And of those, with Transco owned by the electricity grid operator and the Shell-BG deal all but done, only Centrica – the old British Gas brand – has retained its name.

William Powell