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Promising future for US shale

The tide is turning, slowly, for America’s beleaguered shale industry

The modest oil-price recovery has brought a shift in perspective in America's tight oil industry. The doom and gloom from early 2016 has given way to a cautious optimism that, for shale drillers, the worst is over.

Rigs that were laid up for months due to a lack of work are slowly being fired up again. Output from the major shale plays is down a whopping 0.7m barrels a day, or 15%, from the peak in March 2015, to 3.93m b/d. But it is likely at or near the bottom, barring another steep drop in crude prices. As recently as May, every day brought news of a new bankruptcy. And yet the sector has backed away from the brink after five straight months of $40-plus crude prices. After cutting budgets to the bone executives are starting to look for places to spend again.

Today's singular focus on the supply glut obscures the fact that global demand for oil is chugging along and the world does not have enough new production in the pipeline to meet it. Conventional output is falling nearly everywhere outside the Middle East and hardly any new projects have been given the go ahead over the past two years.

Therein lies the opportunity for US shale. Its drillers' ability to ramp up production far more quickly than a deep-water megaproject in Brazil or heavy oilfield in Canada or Venezuela puts the sector in a position to fill the supply gap. It could be a substantial gap. Analysts at Barclays, an investment bank, reckon the world will need close to 7m b/d in new supply by 2021 and nearly half of that-3.4m b/d-must come from American light tight oil. It's why many of the supermajors, most vocally Chevron, are trying to move away from the large-scale projects that have been their raison d'etre in recent years, and are trying to master shale.

Still, questions remain about how quickly and on what scale the shale industry would be able to return to growth.

The economics of shale drilling are constantly shifting, making the answer tricky to pin down. When the downturn began, drillers needed an oil price of around $80 a barrel to break even. Thanks to a combination of cost cutting, moving operations to their most productive properties and improving technology, that figure is between $45-50/b today, with the Permian emerging as the most attractive play to drill followed by the more established Bakken and Eagle Ford shales.

How much of that cost reduction is sustainable? Technology and drilling improvements have clearly helped. Companies are now getting much more oil output for each dollar spent. Drillers are now able to sink multiple wells from a single location, which helps cut costs and time. The wells themselves are also better engineered now than they were a couple of years ago. They're drilled longer, which helps tap into more of the shale seam with each well. Companies are also pumping more and more sand and proppant into the wells, which unleashes more of oil and gas when the well starts producing, meaning operators recover their costs quicker and, they hope, ultimately recover more from each well. These sorts of engineering and technical advances will continue to deliver benefits no matter what the oil price.

But companies have also leaned heavily on discounted rates from their service providers to cut costs. Service charges for drilling and completing wells have fallen around 30% since the downturn started, helping to push breakeven prices lower. These cuts are unsustainable for service companies, so as activity picks up they will look to claw back these discounts. Some contracts already include automatic price increases, in case oil prices rise.

Continental Resources has estimated that somewhere between 25% and 50% of the cost reductions in the relatively mature Bakken play are sustainable, indicating a post-recovery breakeven of somewhere between $60 and $70/b. The figure is similar in the Eagle Ford shale, although in the Permian it is closer to $60/b.

If prices do recover to those levels, growth could return relatively quickly. Companies will start with their drilled-but-uncompleted wells (DUCs) which can be brought online quickly and cheaply because the drilling costs have already been sunk. The Energy Information Administration estimates there are around 5,000 DUCs across the major shale plays, mostly in the big three-Bakken, Eagle Ford and Permian. Assuming each of those wells initially produces around 350 b/d, a rough average across the industry, the DUCs alone represent close to 2m b/d of production that could return relatively quickly and cheaply.

How quickly this could happen still involves some guesswork. But analysts at Raymond James, an investment bank, reckon growth in the first year of a recovery would be slowed by the loss of a huge chunk of the industry's workforce and equipment during the downturn. The bank forecasts oil production rising by around 220,000 b/d in 2017, though that assumes a bullish price rise to $75/b early in the year and an annual average of $80/b. As soon as 2018, though, the bank says the industry could get back to the sort of breakneck speed seen in the boom years. Total US output would grow by 1.1m b/d, driven largely by new shale output. It would be a remarkable turnaround.

Where it came from: tight oil production by play (m b/d). Source: Energy Information Administration

This article is part of a report on US energy. Next article: Loosening the purse strings in the Permian

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