The Edge

Tight oil's second great growth phase gains momentum - Permian and emerging plays show still more promise

1 minute read

Tight oil operators set out their stall early this year. Independents, with a nose for the turn, sniffed the opportunity.

After two years of desperate retrenchment, 2017 would be a year of growth, the start of a new upcycle. With equity capital shoring up many a balance sheet, investment budgets were cranked up, and rigs deployed.

Dizzying, decade-long growth targets from Pioneer, ExxonMobil and Chevron drove home the point - the second phase of the tight oil boom was different from just any old oil and gas fad.

Momentum is building

US independents re-iterated commitment to 2017 budgets in Q1 results over the last fortnight, in spite of an unfortunately timed wobble in crude prices. The push into tight oil is being reinforced as companies rationalise and reposition portfolios.

Marathon raised US$2.5bn from its Canadian oil sands exit and invested US$1.8bn in two Permian acquisitions. The allure of tight oil to Marathon is clear - it intends to increase the US share of production from 60% to 90% in the next 5-10% years, deprioritising conventional international assets. ConocoPhillips is treading a similar path.

The Permian, like any new play, is going through the de-risking phase and it’s all happening.

EOG scored a record-setting well in the Delaware (30-day IP of 6,230 boe/d) and increased its premium-well inventory by 20%. Apache drilled more than 40 test wells to confirm the promising economics of the Alpine High, a wet gas play with oil potential and a minimum of 3,000 drilling locations. Pioneer had encouraging results from four wells in the Jo Mill formation.

Potential beyond the Permian

These three examples serve to show that the potential in the Permian basin is huge and still unquantified, but that the risks for commercial volumes are seemingly on the upside.

There are also other emerging tight oil plays where operators are proving up resources well beyond the Permian’s boundaries in Texas and New Mexico. Continental in the Sycamore (Mid-Continent) and Chesapeake in the southern Powder River (Wyoming) both made progress in the early months of the year.

Rig count is a good barometer of the intensifying activity in the L48. The count is up 129% to 708 rigs from the low of 309 a year ago; and the rate of deployment has been quicker and steeper than we anticipated. The number of active rigs averaged 394 in 2016. We now forecast 716 for 2017 (up from 553 in our November view) and 803 in 2018 (up from 730).

The uptick in drilling will feed through to volume growth, weighted towards the second half of 2017.

2016 marks the cyclical low of production at 4.1 million b/d (annualised) down from the monthly all-time high of 4.6 million b/d in May 2015. A new wave of growth begins in 2017, materially higher than we predicted last November and a function of the faster ramp up in drilling. We now forecast 4.4 million b/d in 2017 (up 0.4 million b/d from November) and 5.0 million b/d in 2018 (up 0.7 million b/d).

Availability of capital has been key

Equity capital has continued to pour into the sector. Providers, reassured by the stabilisation of oil prices, want in on the growth story.

Most operators are aiming to grow tight oil organically, out of cash flow – each well must pay its way.

Our modelling suggests US$50/bbl WTI is a critical threshold, including assumptions for cost inflation which is largely segment-specific (proppant and high pressure pumping) and play-specific (Permian hot spots). Below US$50/bbl many operators are FCF negative; above US$55/bbl most will generate FCF. WTI averaged US$51/bbl in Q1.

A giant resource and its individual plays are being de-risked, promising still more and more production. And an increasing number of these plays work at an oil price we’d argue is below what OPEC will likely seek to sustain in the coming years. Tight oil’s second great growth phase is just beginning.

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