A New (and Better) Way to Read the Tea Leaves on Future Oil Prices
Ever since the price of oil tumbled off a cliff in June 2014, bottoming out at $27 a barrel by the beginning of 2016, and bouncing between $45 and $50 a barrel in the summer of 2016 (still far, far below the 2011 peak of about $127 a barrel), investors and industry players have been trying to read the tea leaves to forecast the future of oil prices. Many prognosticators have suggested that prices will remain low for quite some time; “lower for longer” is the term of art. But in recent weeks, U.S. rig counts have registered modest gains, and that has stirred up the tea leaves, with some analysts and investors seeing one thing, and some another, like people looking at a Rorschach blot.
For some, the redeployment of rigs is a signal that the best capitalized E&Ps are newly confident, convinced that the market has finally stabilized and poised for recovery. Tracking rig counts is a traditional way for analysts to forecast future oil prices. The more rigs, the more optimistic the industry is that the worst is over, and the overall market is poised for improvement.
For others, the rising rig count is an ominous indication that the industry hasn’t learned its lessons from the downturn. If operators are willing to jump back into drilling with the U.S. benchmark price still below $50 per barrel, the pause in U.S. light tight oil production growth that of late has helped rebalance the market may prove fleeting, with more supply reinforcing the “lower for longer” scenario.
Of course, the modest aggregate increase in U.S. land drilling activity in recent weeks is not especially meaningful in the context of the cyclical collapse that began in late 2014. The most recent Baker Hughes U.S. onshore rig count of 412, although up 20 rigs from the nadir, is still down more than 1,400 rigs from its Sept. 2014 peak.
But while rig count is a useful barometer of activity and general operator sentiment, it’s become something of a lagging indicator of future supply. These days, analysts aren’t just following rigs. They’re asking about drilled but uncompleted (DUCs) wells, too – a potential source of additional supply that can be brought online quickly, and cost effectively, even in the current price environment.
Before the advent of pad drilling (drilling multiple wellbores at a single location), the practice of drilling a well without completing it was not a strategy found in most operators’ playbooks. But in recent years, producers discovered that drilling multiple wells on one pad, at one location, and then moving onto the next site, had the benefit of reducing disruption, increasing efficiency, and allowing them to be more strategic in their development plans by holding acreage with production. Critically, the efficiency gains associated with pad drilling also kept service-side costs manageable.
The Importance of DUC Wells
As commodity prices declined over the past two years, more operators sought to get their DUCs in a row, expanding inventories, and applying the strategy to new regions across their portfolios. Current estimates suggest there are nearly 4,300 DUCs scattered throughout the United States today, with nearly 75 percent of them found in the Bakken, Eagle Ford, Marcellus, Niobrara, and Permian plays. According to one analyst, the activation of DUCs in just a handful of Permian counties alone could translate into 300,000 additional barrels of oil coming online almost immediately without the addition of a single rig.
If prices creep up past the $50 mark – and stay there – there’s no doubt these DUCs will be converted into active wells. The only question is the pace at which that will occur. Early indications so far suggest that DUC backlogs are being activated, with independent E&Ps first out of the gate. "We're just going to be continuously completing the wells [in the Permian] with our fleets and so you will not see any DUCs in Midland basin," Pioneer Natural Resource’s chief operating officer said on a recent earnings call.
Nevertheless, more DUCs have been added to the U.S. tally this year than have been converted into active wells, according to data from Bloomberg. Is that ratio about to change? If it does, we could very well see significant short-term movements in price in both the oil and natural gas markets, in a way that correlates more strongly than with rig counts.
Of course, savvy investors and analysts aren’t just limiting their analysis to DUC counts. The performance of horizontal re-fracs is another factor which may accelerate the decoupling of production from the active rig count. Based on recent reports, some unconventional re-fracs are allowing producers to re-stimulate wells at as little as 20 percent of initial costs, while producing at levels as high as 80 percent of initial production rates. That’s good math, even at today’s prices.
Not all wells are particularly well-suited for refracturing treatments. But the adoption of new risk-sharing models on the part of oilfield services providers, coupled with the application of new technologies that ensure toe-to-heel lateral stimulation, offer another cost-effective means for the industry to enhance production without standing up more rigs in the field.
Advances in technology continue to allow producers to deliver incremental increases in production at lower costs per unit. But improving current ultimate recovery factors is the real prize. Actual yield data tend to vary from field to field, but one major services company we talked to recently said that the current working average across all basins is still only around 7 percent.
If that’s true, producers are leaving behind more than 90 percent of the in-place resource. Consequently, mere percentage-point gains in recovery factors could have outsize impacts on the global supply and demand picture.
Amidst all the news about how advanced technologies are being leveraged to help producers deliver greater supplies more efficiently, the great paradox here is that the industry once again risks becoming a victim of its own success, with new supplies begetting lower prices and perpetuating a “lower-for-longer” price slump.
On the other hand, efficiency metrics are reaching their practical limits in many unconventional plays. Outside of the U.S. onshore arena, budgetary constraints, chronic dysfunction within OPEC, and unforeseen supply disruptions will continue to impact production absent a meaningful recovery in E&P capital spending. Weighing those factors, a “medium-for-longer” thesis recently has begun to gain traction within the industry and investment communities.
As projections for future world energy demand continue to climb, producers that find a way to emerge intact from the current price slump will find themselves with a world of opportunity in front of them. And based on the recent uptick in DUCs, producers may find themselves profiting from those opportunities sooner than most people think.
Jeffrey Spittel, a former oilfield services analyst based in Houston, is a managing director with FTI’s Energy, Power & Products group. Chris Tucker, based in Washington, D.C., is a senior managing director with FTI’s Strategic Communications segment.
© Copyright 2016. The views expressed herein are those of the author(s) and not necessarily the views of FTI Consulting, Inc., its management, its subsidiaries, its affiliates, or its other professionals.
Senior Managing Director, Global Leader of Energy & Natural Resources