Gulf of Mexico Seen Springing Back to Life
Mergers and acquisitions have been brisk and operators are drilling more, and have sanctioned a number of stand-alone facilities for the first time in years. As a further signal of the Gulf of Mexico’s promise, Chevron—in a much-anticipated December move—gave the green light to development of its Anchor discovery, potentially opening up a new play in the region. But despite the Gulf’s promise and quickening pace of activity, analysts caution that it is unlikely to see comparable activity levels to those of early in the last decade—at least not yet.
“We are still in a period of recovery” from an industry downturn that began in early 2015, said Sami Yahya, an analyst with S&P Global Platts Analytics. “Operators are not putting their feet on the gas pedal all the way.” One big uncertainty is cost, which blew through the roof during the last regional activity peak six or seven years ago, but was tamped down by low demand when oil prices fell about 50% from above $100/bbl between the middle of 2014 to the end of that year.
Costs may not rise that much this year, said William Turner, vice president, Gulf of Mexico, at Welligence Energy Analytics. “The year 2019 will probably mark the bottom of costs for third-party contractors, rig rates, and oilfield services. So those moving forward are betting that now is the best time to be lining up the work because prices will only go up from here.”
The relatively low oilfield costs seen at present stem from concessions made to exploration and production companies to help them stay afloat during the 2015-2017 industry downturn. Turner and others believe costs will rise this year as demand picks up from more U.S. Gulf activity. In part as a result of lower oilfield prices, and also from efficiencies, Gulf oil break-evens average about $45/bbl, with a lower average for tiebacks. Tiebacks are quick field hookups to existing infrastructure that do not require massive and long lead-time construction.
Gulf crudes currently priced around $60/bbl leave a comfortable margin for operators that survived the downturn. They are now beefing up their Gulf operations. Talos Energy, for example, in December made what it called a “transformative” purchase of Gulf of Mexico prospects, finds, and production from several small operators. Also in December, W&T Offshore, a U.S. Gulf-focused producer, bought ConocoPhillips’ last operated producing asset in the region after ConocoPhillips exited Gulf exploration in 2015. Hess recently drilled its first Gulf exploratory well in years at Esox, unveiling a discovery in October 2019. It will be online late in the first quarter of this year.
And Murphy Oil acquired more than two dozen production blocks in the Gulf from LLOG Exploration in April 2019. Murphy is also developing its Samurai and Khaleesi/Montmort fields, with production from the King’s Quay floating production system. While Occidental Petroleum was not a Gulf of Mexico producer at the time of its $57-billion acquisition of Anadarko Petroleum last August, the purchase marked its return to the Gulf after an absence of a dozen years. Occidental plans to spend $100 million on “near-field exploration” in 2020 that includes tiebacks and development wells drilled from platforms, Ken Dillon, Oxy senior vice president, said during a November earnings call.
During that call, Oxy CEO Vicki Hollub said she believed the U.S. Gulf could “compete for capital…[and] can beat the Permian Basin,” which analysts say has a breakeven cost of about $40/bbl. Chevron’s Anchor field, located about 140 miles off the coast of Louisiana in 5183 feet of water, is the first ultrahigh-pressure, 20,000-psi find to be sanctioned. Currently, 15,000-psi wells are producing in deep, remote Gulf areas, but 20,000-psi development requires subsea equipment rated to withstand more punishing pressures. Until recently the technology was not available.
Once Anchor is online in 2024, it could spur not only further exploration of extreme wells, but also development of discoveries made years ago but kept on ice for lack of production technology. These include BP’s Tiber and Kaskida discoveries, which were announced in 2009 and 2006, respectively. LLOG Exploration Co. recently ordered subsea trees for Shenandoah, also a 20,000-psi project 200 miles south of New Orleans containing 100 MMbbl to 400 MMbbl of oil, while Total is in the early stages of advancing another 20,000-psi project, North Platte.
In addition, the cost of new-build facilities has dropped dramatically. Better supply-chain logistics, reusing hub designs in lieu of designing uniquely for each field, and sizing hubs for nearer-term output rather than the long term, are greatly slashing construction costs in an era of corporate austerity.
The payoff has been that in the last couple years new production facilities have been given the go-ahead by Shell in the form of the Vito project in the Gulf, which has a breakeven cost of under $35/bbl, and the Mad Dog Phase 2 initiative by BP. “The industry will be watching the performance of the upcoming standalone projects that could have an impact on how other projects trend forward,” Yahya said.
(SOURCE: The Weekly Propane Newsletter, Feburary 24, 2020. Available by subscription.)
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