In addition to resurgent growth in shale plays such as the Permian, BTU Analytics is forecasting continued growth in the Deepwater Gulf through 2020. The region currently supplies 15% of daily U.S. oil production, more than the Eagle Ford or Bakken, and is expected to remain just as relevant by 2020. Considering the region’s significant role in the U.S. supply and demand balance, do Deepwater project economics support the investment levels needed to achieve growth despite long-term pricing uncertainties?
As shown below, Deepwater production has been on the upswing since 2013, increasing from 948 to 1,296 Mb/d and accounting for a larger share of total Gulf production due to declines in shallow water production. BTU defines Deepwater as the Gulf’s eight OPDs, or Official Protraction Diagrams: Alaminos Canyon, De Soto Canyon, East Breaks, Garden Banks, Green Canyon, Keathley Canyon, Mississippi Canyon, and Walker Ridge.
In a previous post, BTU described how large projects continued to receive FIDs and come online through the downturn due to the Deepwater industry’s longer lead times and massive fixed investments. This production momentum proved more immune to short-term prices than faster turnaround shale projects, with 2016 seeing 467 Mb/d of Deepwater capacity added. As shown in the map below, BP, Shell, Anadarko, and privately held LLOG Exploration drilled most Deepwater wells in 2016, with activity focused in Mississippi Canyon.
With uncertainty still prevalent in the oil price outlook, Deepwater operators have recently broadcasted competitive economics for new projects. Shell recently put new project breakevens below $45, including sub-$40 for the Kaikias project, while Anadarko is predicting 75%+ before tax RORs at $55.
To keep fixed costs down, companies are leveraging existing infrastructure by tying wells in new fields back to existing facilities over long distances and shifting from customized to standardized equipment and technologies. Aiding in cost reduction, low drilling activity and overbuilds have depressed contract rates for drilling ships and semi-subs, easing variable costs.
Improving type curves offer additional support to improving producer economics. The charts below show annual oil type curves for selected operators Shell and Anadarko, averaged across their Deepwater assets. Recent wells show higher rates than those in 2012 and 2013, resulting in higher EURs and shorter payback periods.
It should be noted that both Shell and Anadarko have recently increased drilling at Walker Ridge and Keathley Canyon, which have historically had higher production profiles than Mississippi Canyon and Green Canyon.
Current trends in U.S Deepwater indicate that project economics are improving as companies cut costs, push efficiencies, and funnel investments into their prospects most likely to offer favorable returns. The question is, will it be enough to support increasing Gulf production after investments made during the boom years come online and start to decline? For more information on BTU’s Gulf of Mexico production forecasts, request a copy of our Upstream Outlook Report.
