How deep water projects can compete with tight oil - more progress on costs and tight oil may get a run for its money
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Reports of the death of green field deep water projects may have been exaggerated. Tight oil has garnered all the plaudits in the last few months, rightly given the resurgent growth underway. But there are stirrings in the conventional space too, even in the challenging deep water sector. Costs are coming down and we can foresee in the not too distant future green field deep water projects giving tight oil a run for its money in competing for capital.
This year may be the brightest for upstream investment since 2014. That’s not saying much after the precipitous 40% drop in spend the industry has suffered. Tight oil is leading us out of the trough, driving a modest 4% increase in global spend to US$413bn in 2017 on our forecasts. There is a huge, commercial opportunity seemingly there for the taking for tight oil operators. This stems from a serendipitous combination of the dramatic improvement in drilling efficiencies, the Permian Basin’s emergence, and firmer oil prices.
There are 15bn barrels of tight oil resource in undrilled wells with break evens of US$50/bbl or lower at a 15% hurdle rate in our dataset – equivalent to ten years of current tight oil production. At US$60/bbl there’s 26bn barrels, or eighteen years worth. Drilling up these resources is what drives our forecast growth in tight oil from the current 4.0 million b/d to 8.5 million b/d by 2025.
In stark contrast, the perception is that conventional investment is stuck in the mud.
To a degree that’s fair. Spend on conventional projects will be flat in 2017 at just under US$340bn, still scraping along at the lows of the cycle. A new wave of FIDs is needed to sustain investment into 2018 and beyond, as spend winds down on projects already under development.
The challenge to commercialise is particularly acute for deep water projects. A meagre 5bn boe of green field projects achieve a 15% hurdle rate at US$50/bbl. The volumes almost triple to 14 bn boe at US$60/bbl, such is the sensitivity of the economics to price.
But deep water is heading in the right direction.
Pre FID project break evens have fallen from US$79/boe on average in mid-2014 to US$62/boe today. The two main drivers have been costs and portfolio high grading. On costs, cheaper rig rates are cyclical, but all important structural change is starting to show through. Operators are re-working project designs, and using more subsea tiebacks and hub facilities.
Portfolio high grading is changing the type and quality of project. Higher-cost projects in traditional investment hot spots like Angola have been pushed out of the hopper. In their place have come lower breakeven fields in new provinces such as Senegal, Guyana, Equatorial Guinea, Mexico and Azerbaijan. There’s also an increase in high-return incremental projects tied-back to existing infrastructure, reflecting the industry’s focus on value over volume.
We think costs can come down further still, to the point where deep water is competitive with tight oil.
Our Upstream Research Director, Angus Rodger, reckons that another 20% of cost cuts would lift the volumes for deep water projects in-the-money at US$60/bbl to 18 bn boe. The big opportunities lie in four main areas: reduction of facility size and processing capacity; changing the facility concept, say using a semi-sub rather than a spar; reducing well count; and improving well design.
At the same time, cost inflation is resurfacing for tight oil players. A 20% rise in tight oil costs would mean that the two resource themes effectively have the same opportunity set measured by volumes in-the-money at US$60/bbl.
Tight oil will be the dominant investment theme in 2017 and likely remain so for some time.
The wobble in oil markets this month is a timely reminder that any recovery in upstream spend is sensitive to price, tight oil included. And our analysis shows that the commerciality of deep water projects are more leveraged than most - something that won’t be lost on OPEC as it weighs up its tactics.
Progress is being made. But operators need to be unrelenting in their quest for structural cost reduction if deep water is ever to compete with tight oil and provide investment optionality should oil prices stay ‘lower-for-longer’.