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Shale and Demand Uncertainty Put Big Oil on its Back Foot

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Shale and Demand Uncertainty Put Big Oil on its Back Foot

U nder pressure from low oil prices and their rising debt levels, top oil executives at the ONS 2016 conference this week might well have found the blunt message of shale driller Scott Douglas Sheffield unsettling.

The chief executive of Pioneer Natural Resources seemed to enjoy the role of spoiler-in-chief, harrying Big Oil with some uncomfortable assertions.

The bad news, for those in the industry who missed out on shale and expected it to fade in the face of low prices, is that the Permian basin should be able to increase its output from 2 million b/d to 5 million b/d in the next 10 years, assuming prices reach $56/b in 2025, Sheffield said. Pioneer itself is growing its output by 27-30% annually.

“It’s in that [price] strip that I see the Permian adding 300,000 b/d per year in US supply,” he told the Offshore Norwegian Seas conference, held Aug. 29 through Sept. 1 in Stavanger. Ramming home his contrarian stance, he said he was skeptical of some of the higher forecasts of long-term oil demand growth due to global warming, alternative energy and electric vehicles, while boasting of the company’s use of renewables in its own operations and the solar panels on his home.

In Sheffield’s view, the dip in US production has been misconstrued, with some in the industry underestimating the Permian basin as output falters in the Eagle Ford and the Bakken. Some have failed to appreciate that rig reductions in the Permian have happened partly because of reduced drilling at conventional, non-shale sites, rather than in the shale plays, he said. The Spraberry-Wolfcamp shale, where Pioneer operates, remains resilient and Pioneer’s own breakeven price is below $25/b. Prices paid for shale acreage have been rising, in some cases, to levels higher than in 2013-2014, he said.

“In the Permian we still have about 600,000 b/d of conventional production that’s declining — it’s arresting the growth. [However] there’s one field in the Midland basin, six fields in the Delaware basin that make up most of the growth in production. The Permian is still growing,” he said. With the Permian accounting for over half of US oil rigs, he forecast another 50-75 would be added.

But while the world’s oil majors were largely caught off guard by shale and have of late struggled to maintain a foothold in many parts of the world, Shell chief executive Ben van Beurden insisted on their relevance, reiterating the International Energy Agency’s central scenario for a 25% increase in energy demand by 2035 and predictions of oil demand growth of 1-1.5 million b/d for the next five years.

That, together with decline from existing fields of 5% per year, means the notion of stranded assets, by which oil and gas becomes redundant, is a “red herring,” he said. The industry is now filling the gap between demand growth and natural decline “quite comfortably, with all the investment decisions that we took four-five years ago. [But] that time will dry up,” he said. “We will see the tightness come back into the market. I’m more worried about supply shrinkage.”

But van Beurden made clear he was worried by the international push for renewables and electric vehicles and their effect on demand. Financial authorities are looking to “weaponize the banking system against oil and gas,” he said. If they succeed, “those parts of the hydrocarbon system that are most capital intensive will be penalized first. The most capital intensive development of the hydrocarbon system is gas — you will have yet another unintended consequence — promoting coal.”

If Shell is sticking with its big-project mentality, one man hedging his bets at ONS was ConocoPhillips chief executive Ryan Lance, whose company has made the leap into US shale, although like Shell it failed in its efforts to develop shale outside the US.

More recently ConocoPhillips’ strategy has been to grow its US shale operations, while holding on to core conventional production. Of its 1.5 million boe/d of production, it says one third is from unusually low-decline fields such as Norway’s Ekofisk, while it has increased its US production by 80% since 2008.

“We can see short-term swings between over- and under-supply: if $80-90/b comes, we’d better be prepared for $30-40 on the back end of it,” Lance said. While the US shale industry will need time to recover, not least having lain off 200,000 workers, “we’ll see gaps between supply and demand and, if so, more US shale is going to be called on to meet that growing demand,” he said. In the meantime, ConocoPhillips remains committed to the North Sea, he said, implying however that Norway, which prides itself on its stable tax regime, may have to show flexibility.

Like van Beurden, Lance also acknowledged worries about energy demand. “I do worry about demand security, with the electrification, with some of the things that are going on,” he said.

But this, he said, was another argument in favor of shale, due to the flexibility it offers. “When we think about going forward in a more volatile world with cyclic prices and shorter cycles between peaks and troughs you start to ask yourself what wins in that kind of environment. What we’ve convinced ourselves wins is a large stable base of production which provides the cash flow to fund dividends and stabilize your production, and then a lot of low-cost investments in the portfolio that have a range of cycle times.”

Fighting back

Among those seemingly confident of big oil’s future, the prize exhibit of Norway’s state-controlled Statoil is the Johan Sverdrup project, due on stream at the end of the decade, with production eventually to reach 660,000 b/d. Under pressure from investors worried about its debt — a problem also for Shell — Statoil announced it had reduced the breakeven price for the first phase of Johan Sverdrup to just $25/b.

Skeptics are inclined to see such big North Sea projects as a thing of the past and Johan Sverdrup as a last gasp (ex-BP chief John Browne described the North Sea as “inexorably declining”).

Recent large discoveries in the Barents Sea are proving hard to commercialize because of high infrastructure costs. But others argue that technological transformation will help the North Sea to stand its ground in the competition for investment. Those looking to develop North Sea projects “take a second, third, fourth look at the same project — the trend today is to look at projects and look at them again because it is a question of rearranging components and taking things out of the stream and removing inefficiencies and things that are in a sense useless,” said Michele Stangarone, European chief executive for GE Oil and Gas, which provides continuous monitoring of some 750 offshore turbines and compressors worldwide from centers in Florence, Houston and Kuala Lumpur, using technology borrowed from the aviation industry.

Nonetheless, big oil companies may continue to struggle to define their role, whether it be in shale or the Middle East. The Johan Sverdrup project has eased the pressure on Statoil and like Shell it is banking on growth in turbulent Brazil. However chief executive Eldar Saetre admitted it had struggled in the Middle East, having withdrawn from Iraq and suffered a terrorist onslaught in Algeria in 2013.

“Statoil hasn’t been very successful in establishing a foothold in the Middle East,” he told S&P Global Platts. “There could be opportunities. But so far, when it comes to Iran, for instance, we have a very cautious approach: we need to see the terms firming up and a stable environment.”

In the meantime in a low-price environment even Brazil could present problems, Citigroup head of energy for Europe, the Middle East and Africa Douglas Mackenzie warned.

“Brazil has clearly got to work its way through some issues. I’m more concerned about the demands, the social pressures, the fiscal demands that are placed on energy companies in these regions, the national oil companies, to support the social sector. It’s going draw away from the capital expenditure,” he said.