[NGW Magazine] Editorial: A False Dawn for Producers?

This article is featured in NGW Magazine Volume 2, Issue 21

This year has been a better one than the last few for the upstream industry, with the quarter just ended providing further grounds for confidence that a corner of sorts has been turned. But this might be about as good as it gets.

The explanation for the rise is not a cheering one: war in Iraq. Crude exports were down 7% in October and the price has risen 15% since September. This cut, coincidentally, takes output below the cap imposed on Iraq by the Opec/Russia agreement to curtail production, according to Bloomberg. That reduction in Iraq is not necessarily sustainable and exports could rise again, even if the Opec agreement, with Russian support, is rolled over this month. But still oil and gas prices were both higher year on year; and many producers have also reported overall an increase in output. Demand is on the up – including their refined products and petrochemicals. These commodities are still safe, for now, from substitution by renewable energy.

Companies have had time to grow used to $50/barrel of Dated Brent crude and to incorporate that in their plans. Now, after much belt-tightening and pain, they are prepared for that in the short and medium term at least. So they will be enjoying the continuing ramp-up to, and even over, the almost mythical $60/barrel mark – outside the US at least, where the benchmark is heavily discounted. Enjoying the jingle of cash in its pocket, Shell is mulling the end of its scrip dividend, which helped its transformative acquisition of BG, in favour of returning cash to shareholders. BP is buying shares back, which has the same effect.

Of course, profits are a lot lower than they were in the bad old days, before the crash of 2014 worked its way through to the bottom line – but so too are some of their costs. The industry has been streamlined: capital expenditure has been cut; mergers and acquisitions are happening as the floor price has been tested; oil field companies have merged; upstream investment has been focused on the lowest-cost barrels; and companies have found new, cheaper ways of doing the same things in the new era of austerity. These improvements ought to be futureproof, keeping down cost inflation.

In the case of Russia, the added problems of US and EU sanctions and the fall in the value of the ruble have forced it to innovate: its third LNG export plant, Novatek’s Arctic LNG 2, is to be built entirely with Russian technology, if it is built at all. To the east of Yamal, Gazprom is already starting to build all of the 38bn m./yr Power of Siberia using Russian-built linepipe, which will have to function in one of the world’s harshest environments.

This Kremlin-mandated switch to domestic goods will improve the economics of both projects, although it will perhaps place a heavy strain on Russian industry initially. But outside Russia, much more has to come in the way of cost-cutting, such as the standardisation of mechanical and subsea equipment. And competition must give way to co-operation, especially in the mature provinces such as the UK North Sea, or more barrels will be permanently locked in underground for the wrong reasons.

Opportunities like this to implement drastic change should not be wasted. But if this new environment is working for producers, it is also working for consumers. Many of the unconventional oil fields in the US have the capacity to turn up their output when the price is right, and assuming further technology gains, that means that the price needed to perform that task can be lower than before.

Where gas is concerned, the market may be balancing here and there, earlier than it was expected to. Prices in Asia have been going up partly because of innovation and the rise of LNG trucking, notably in China, creating demand that was not there even a few years ago. Nevertheless, there is still more LNG to come to market in the next few months from the US and from Russia, and there may simply not be enough capacity to absorb it in Asia, forcing it into an already well-supplied Europe.

There are pockets of vulnerability to supply-side shocks in Europe, such as the UK which is losing output from its Rough seasonal storage field. And the continuing low level of gas output from the Dutch Groningen field, a key swing producer, is another bullish factor. Militating against them though is Gazprom’s ability to use more export capacity this year than last thanks to the raising of the bar on its capacity in Opal. But there may still be short periods of price volatility. Much depends on the length of the northwest European winter and how fast the storage is used up.

But in the longer term, the role of natural gas in Europe is already being reduced, its gradual replacement with synthesized methane in the grid underway in small pockets of enterprise on the continent and the UK. Local distribution networks are studying the injection of other combustible gases that meet the grid quality standards and so enable homes to be heated without the endless construction of pylons that electrification implies, or the same carbon emissions that natural gas produces.

The claims made for the ease of electrification have been overdone in the UK, given its small role now and the strides forward it will have to make: at peak times, 61% of power, and over 80% of heat and power, is delivered by gas through the network. Last year, electricity accounted for just 17.5% of the final energy UK consumers used, compared with 29.4% for gas.

The pipelines on both sides of the Channel will still be used, but less and less of that gas will be ‘natural’.

NGW