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Opec cuts, shale mends

Is American tight oil going to ruin the price recovery?

When Opec's ministers emerged, deal in hand, from their November meeting in Vienna you could almost hear the champagne being uncorked half a world away in Texas. If it brings a lasting revival in prices, the deal will underpin new growth in US shale supply after two punishing years of austerity. Oil in the $50s will unleash a wave of new tight oil spending.

A rising oil price won't buoy all shale producers equally. The recovery in 2017 will look a lot like it did in the second half of 2016. That is, the Permian in west Texas will suck up most investment, yielding more oil. The Eagle Ford and Bakken will be slower to recover, needing prices north of $60 a barrel to grow. Basins outside the Permian tend to have less attractive economics and the downturn hit harder in those kinds of plays. Producers in the Bakken and Eagle Ford must climb out of deeper holes.

The rig count gives a good idea of the shape of the recovery. The number of oil-directed units in the US has marched steadily higher, from 316 in late May to 529 in early January - directly correlating with the price rise of the second half of 2016. The Permian accounted for about 60% of those gains, with smaller gains spread through other shale plays, and that should continue. At a WTI price in the low $50s, the Permian's lower drilling costs and more productive wells make the area a much better bet than the other major shale plays . Boardroom decisions have reflected this. More than $20bn in Permian deals were done in 2016, and Permian-focused drillers have been much quicker to lift their 2017 budgets than rivals in other areas.

In fact, the Permian-led shale recovery appears to have US tight oil production already nearing an inflection point. In the past two years, tight oil output fell more than 15%, from around 5.4m barrels a day to 4.5m b/d - but now the US Energy Information Administration expects this production to tick up slightly in January from its December levels. The bottom seems to have passed.

During shale's heyday, output rose by 1m b/d every year. If that happened now it would all but wipe out Opec's 1.166m b/d of cuts

The question isn't whether shale will come back but how big the bounce will be. A flood of new supply that quickly fills the gap left by Opec's cuts would be the worst outcome for the group, shredding its market share while killing the price recovery. During shale's 2012-14 heyday, the US added 1m b/d of new output every year. If that growth were repeated now, it would all but wipe out the 1.17m b/d Opec's members pledged to remove.

That's not in the cards at present. At $50-60/b, the range prices have settled in since the Opec-non-Opec deal, tight oil's supply response will be less dramatic - more a stream than a deluge. More likely is the addition of around 300,000-400,000 b/d over the course of 2017, driven almost entirely by the Permian. Bernstein Research, an investment bank, noted in a recent report that such growth would be in line both with late-2016 drilling trends and guidance of around 15-20% growth in 2017 from the Permian's most important producers. On the ground, this would mean Permian output rises from around 2m b/d at the end of 2016 to 2.3m-2.4m b/d in late 2017. Output in the Eagle Ford and Bakken would stay mostly flat, at around 1m b/d and 0.95m b/d, respectively. In those areas, a small uptick in activity and the activation of drilled-but-uncompleted wells would merely stave off decline.

Strong Permian growth in the first half of 2017 looks locked in already. The area saw a startling 30% jump in the rig count in the final quarter of 2016. Production from the wells those rigs are drilling will start to show up soon. The price updraft from Opec's deal also handed a gift to shale producers - many immediately hedged them in 2017 prices. The forward curve for early and mid-2017 contracts jumped to the mid-$50s on news of the Opec deal, a level that will support Permian growth. Companies haven't reported their post-Opec hedging yet, but a spike in trading volumes and a flattening of the futures curve suggest producers grasped what they could, quickly.

Time for a revival: Permian oil production and rig count Source: EIA, Baker Hughes, Petroleum Economist

As long as Opec's core members, like Saudi Arabia, keep signaling their commitment to support prices, the rig count will keep marching higher. Some of the Permian's biggest producers are already promising to bring new rigs into operation in 2017. Pioneer Natural Resources says it plans to have five new units, up to 17 from 12 in 2016. Concho Resources will add a rig to bring its total to 19, but is shifting focus to the less-developed Delaware area of the Permian, a new frontier. Devon Energy is also shifting its gaze to the Delaware, where it plans to move from three rigs to between seven and 10.

Equally important will be producers' ability to keep squeezing more oil from each well. In the Permian, there is still room to run on this front. Producers have adopted a go-bigger approach to drilling and completions - longer lateral wells, more frack stages and pumping more proppant into each well. This increases overall costs per well, but the higher output reduces costs per barrel produced, key to lowering break-even costs.

Data from Rystad, a consultancy, shows the average lateral length for wells in the Midland section of the Permian was around 8,000 feet (about 2,400 metres) in 2016, up from about 6,000 in 2014. But top Permian producers now show strong results from wells drilled laterally more than 10,000 feet, and deeper wells may be drilled in 2017. Companies are also pumping about twice as much sand and proppant into their wells as they did a couple of years ago. All this was crucial to shale drillers' maintaining output even as the rig count plunged. Now it will help propel growth as new rigs are brought back into the field.

Financing, the other key pillar of shale growth, will be more of a mixed bag during the recovery. Interest rates are rising after November's Federal Reserve decision, which will make high yield-chasing lending to higher-risk shale companies relatively less attractive. Many banks, stung by the raft of oil patch bankruptcies during the downturn, are also chary to jump back into energy lending. Still, higher prices will help repair balance sheets and bond markets will re-open to many companies, especially those in the Permian.

Strong Permian growth in the coming months is locked in. Its rig count jumped by 30% in the final quarter of 2016

Some bumps on this path to recovery are inevitable. After two years of steep declines, costs can also be expected to rise in 2017. Oilfield-service companies slashed rates to unsustainably low levels to get work in 2015 and 2016, but as activity picks up they will try to claw back those cuts. Some service contracts now include automatic cost increases in line with the oil price. Analysts at Raymond James, an investment bank, reckon shale producers might face a leap in costs of 20-30% in 2017. Other analysts see inflation more likely to come in around 10%. Either way, the bargains have ended.

One source of this cost inflation is the constraint on available kit and personnel, the outcome of years in which the service sector relentlessly shrank its fleets and workforces. For example, Raymond James says service companies will need 10-20% higher prices to redeploy idled pressure-pumping equipment - key to completing shale wells - and much higher prices to refurbish equipment or to build new kit. In total, it reckons pressure pumping prices could rise by around a third. Rates for high-end rigs, the sort that can "walk" themselves from drill site to drill site, are also likely to rise sharply -- their utilisation rate is already near 100%. Sand and proppant prices are also rising in the face of soaring demand.

Service companies have also started to hire again to meet rising demand. The low unemployment rate suggests many workers laid off during the downturn have found work elsewhere. The industry will have to pay higher wages to lure them back to the oil patch or find and train new workers.

Some evidence implies that cost re-inflation is already underway. The US' Bureau of Labor Statistics tracks a producer-price index for oil and gas extraction. According to its figures, costs bottomed out in February 2016 and have been creeping up ever since. They aren't at 2014 levels, yet, but have reached their score from mid-2015.

The biggest comfort Opec's ministers can take from all this is that a short-term return to the activity levels that fueled annual 1m-b/d growth in the boom years isn't possible - not soon, and not at prevailing prices. A huge amount of fracking equipment was scrapped during the downturn and it will take time to bring crews back. Raymond James reckons the industry could start to run into serious bottlenecks at around 800 oil rigs in 2017 and 1,100 in 2018. Considering that nearly 200 total oil rigs were added from May to December in 2016, this hypothesis might be tested as soon as the second half of 2017.

Rock bottom? US tight oil production (b/d). Source: EIA
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