Tight oil set to make money in 2018
Chairman, Chief Analyst and author of The Edge
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A teenage growth spurt – US onshore liquids production is on a tear again. Already rebounding from the downturn for a year, right now it’s turbo-charged.
We expect tight oil to grow by 2 million b/d over the next two years (1.1 million b/d in 2018, 0.9 million b/d in 2019) – double the rate we forecast a few months ago. And that excludes another 1 million b/d of new NGL volumes, associated with rising gas production.
There are two main factors behind the big upgrade: First, an extraordinary leap in production of 0.6 million b/d in September and October 2017. We had expected growth, but spread over several months rather than a flood. Second, operators this year are focusing on a backlog of 3,000 DUCs (drilled uncompleted wells) from the jump in rig activity in 2017. Completions will be up by 30%, bringing on producing wells which feed the 2019 volume growth.
Tight oil operators might even confound expectations and make money this year. Production will be higher – 30% up on average for tight oil focused players.
Oil prices will be higher by around US$10/bbl, with WTI averaging US$61/bbl (above most companies’ cash-flow breakeven). And investment will be relatively subdued with the focus on DUCs, part of a conscious shift in the last year to demonstrate capital discipline. All the stars seem aligned for Tight Oil Inc. to generate positive cash flow in 2018, two years earlier than we predicted.
What’s not clear is how companies will respond to this serendipitous turn of events. Will higher prices undermine resolve and the focus shift back to volume? We may find out in the coming weeks. Anadarko and Pioneer have chosen to increase dividends and buy-backs in this week’s Q4 results.
Generally, we expect capex budgets for 2018 to be still ‘set for value’ with modest rises in spend. But rising activity in recent weeks might indicate an unfolding ramp-up.
The rig count, up 270 in 2017, already shows 27 rigs put to work in January, one-quarter of the 90 we assumed for 2018.
These next two years will lift tight oil production to 7 million b/d, well on the way, seemingly, to maturity and the plateau we forecast of 10 million b/d by 2025. Despite this growth spurt, there are still doubts as to whether tight oil can reach and sustain these lofty levels.
Might parent child/wells limit drilling intensity and recovery factors? How extensive will Permian sweet spots prove to be? We’ve already reined back our longer-term forecasts for the Eagle Ford and Bakken, and expect both to enter decline early in the 2020s.
Downgrading these plays leaves tight oil forecasts dependant on the Permian to deliver.
The economics support the positive outlook – the Permian continues to look more attractive than most other options for new investment in the global upstream hopper.
As the play has become better understood, expected returns have risen and are typically much higher than those for most green field conventional projects, based on our modelling. This, in turn, has led to divergence in the prospective weighted returns from new investment between companies, largely depending on their exposure to tight oil. Pure players Pioneer and EOG stand out from the rest (see chart).
It's no surprise then that ExxonMobil and Chevron have reiterated bold investment programmes and growth targets for tight oil. The tight oil ‘haves’, a group that also includes Shell and ConocoPhillips, Occidental, and Anadarko among many US independents, mostly have weighted IRRs of 20%-30% on future investment, assuming Brent at US$65/bbl long term (see chart). IRRs for those with more conventional-oriented portfolios are nearer 15%-20% and they have fewer discretionary options for investment (x-axis).
So are the ‘have nots’ disadvantaged? Up to a point. But tight oil doesn’t fulfil all portfolio needs. It’s marginal cost production: operators may make money in 2018, but many won’t if prices drop back below US$50/bbl.
It’s also perpetually consuming capital to maintain production. Returns for the have nots may be more modest, but 15-20% is not to be sniffed at. Nor do conventional projects need ongoing investment once onstream, so cash margins are higher and much more resilient to low prices.