The Last Barrel

It is the best of times, it is the worst of times, it is the season of light, it is the season of darkness, it is the spring of hope, it is the winter of despair. Although I took a few liberties, the poignant opening of Charles Dickens’ “A Tale of Two Cities” seems to apply to the current state of our industry. The juxtaposition of yin/yang inverses is taking hold in the E&P’s new normal, with a harvest of plenty for some, but economic pain for others.  

First, the good news. A report by Westwood Global Energy predicts that the U.S. drilling and completion market will experience significant growth from 2018–2022 in six unconventional plays: DJ-Niobrara, Eagle Ford, Haynesville, SCOOP/STACK, Permian and Williston. The company forecasts that future expenditures for 17 key service and equipment lines in the U.S. onshore market will experience a 9% annual growth rate. Of a total, predicted expenditure of $554 billion, the report says 66% of it will be spent on completions and 34% on drilling. Another report, by NES Global Talent, shows “signs of returning confidence in the oil and gas market” and that “for the first time since 2014, the oil and gas industry expects more new jobs to be created than lost over the next 12 months.”

U.S. crude exports are setting new records, with outgoing shipments reaching 2.2 MMbpd in early November. The export rate is more than twice as high as it was in September, when exports were hampered by two hurricanes, according to a report by ESAI Energy. Up to that point, the most ever exported from the U.S. was 1.3 MMbpd, which was reached in May. The U.S. is still a crude importer (from Canada), but net inflow fell to a record low in mid-October. The primary reason for the rapid increase in U.S. crude exports is due to wide Brent/WTI spreads that have covered transportation costs to foreign markets in Europe and Asia. Although U.S. exports will continue to grow, “they will be competing with other sources who export to many of the same customers,” the report concluded.   

SPE ATCE. I have to give officials responsible for setting the keynote topic at SPE’s ATCE credit for concocting a session that focused on something other than the monumental bust or the increased efficiencies in the U.S. shale plays. The five-person panel provided insight on delivering economic and environmental sustainability. David Hager (Devon Energy) said “creativity is at the heart of everything we do. In the last five years, Devon has cut costs in the shale plays by 40%, while increasing production by 450% in the first 90 days, and improving ultimate recovery 45%.” Lorenzo Simonelli (Baker Hughes) said, “as an industry, we’ve got to embrace disruption,” the question is “how do we embrace that disruption and change much faster?” 

A more practical discussion of what the future holds took place during the SPE Technical Directors special session, when the panel suggested that the industry is going to suffer through a sustained period of deep cost reductions. However, Tom Blasingame said, “in reservoir engineering, the best years are ahead of us,” referring to an extensive list of challenges in unconventional formations. The opportunity to rewrite reservoir engineering text is an exciting prospect for those who remained in the industry, but Mr. Blasingame lamented the loss of many experienced people since the price crash. “There has been a loss of legacy knowledge,” he said, citing the mass departure of older engineers since the price crash.

Bleak outlook for deep water. Transocean was forced to scrap six floating deepwater rigs, costing the company $1.4 billion, according to Bloomberg. The company’s high-profile Pathfinder drillship was part of the downsizing, after spending two years in a Caribbean purgatory at a cost of $15,000/day. This drastic move by the world’s biggest offshore-rig operator signals just how bleak the future looks for deepwater drilling. Other deepwater rig contractors are going the same route, jettisoning more rigs in the third quarter than have ever been trashed in a 90-day stretch, according to Heikkinen Energy Advisors. Transocean has seven other offshore rigs staked in the Caribbean, and most will never drill again, because the longer a rig is parked, the more likely it will get passed up by customers for more capable competitors. That’s how bad it is — “deepwater is going to be playing a much-reduced role on the global oil-supply stage, relative to what the industry expected as recently as three years ago,” said Thomas Curran, FBR Capital Markets. In spite of promising predictions by major operators at OTC in May, the deepwater portion of our industry is going to be a casualty of the bust.

Death of oil sands mega projects. Canadian oil sands producers are facing stiff challenges associated with relatively high costs and low commodity prices. Large oil sands projects will tend to be leaner and smaller, according to a report by ESAI Energy. The firm projects that growth from the region will decelerate to 120,000 bopd in 2019. The 190,000-bopd Fort Hills mine, due by the end of the year, is forecast to be the last greenfield project for a number of years. Although operators are experimenting with new processes that could potentially reduce costs and emissions, new greenfield projects are unlikely to go forward until after 2020. 

Investors roll the dice. With OPEC and Russia planning to extend production cuts further into 2018, oil traders are betting that the supply/demand set-up has finally turned the corner. The cartel’s announcement drove Brent prices beyond $60/bbl for the first time since 2015. But the majors are still focusing on the break-even costs, which is a stark change from their traditional emphasis on increasing production rather than just generating capital. It appears the industry’s confidence is returning, but with shale’s hair trigger looming, is it worth betting that prices will go higher?   

About the Authors

Craig Fleming

World Oil

Craig Fleming Craig.Fleming@WorldOil.com