New Investment Crucial to Keep Deepwater US GOM Production Afloat
Efficiency and historic investment in legacy U.S. Gulf of Mexico (GOM) deepwater fields are flooding inventories this year, but along with the rig count, deepwater investment there continues to plunge.
“The CAPEX number for 2017 is going to be pretty flat,” said Imran Khan, senior research manager for GOM deepwater at Wood MacKenzie (WoodMac). “There was a big drop in previous years, so we’re already looking at a pretty low number for 2016. We’re going from about $12.2 billion to about $10 billion for 2017.”
But less capital expenditures (CAPEX) isn’t reflected by current deepwater production. In January, U.S. production in the GOM grew for the fourth consecutive month, reaching 1.7 million barrels per day (MMbpd) and obliterating the annual record high set in 2016 of 1.6 MMbpd, which had knocked 2009 out of the top spot, according to the U.S. Energy Information Administration.
Prior to the downturn, significant capital was deployed in the Gulf, which has allowed large fields, such as BP plc’s Mad Dog and Thunderhorse, to crank out hydrocarbons without additional significant capital. As the rigs that are in action ramp up, their forward breakevens are between $25 and $35 per barrel, Khan said.
“You do have to keep in mind that prices have come down, and operators are getting better at drilling wells so it’s costing them less to do the same,” Khan said.
In the not-too-distant future, though, investment in the Gulf must rebound, said Dan Pickering, president and head of TPH Asset Management at Tudor, Pickering, Holt & Co., during a May 2 presentation at the Offshore Technology Conference in Houston.
Global crude oil demand has increased by at least 2 percent for most year-to-year averages. But even the most prolific majors in the GOM have drilled dry holes, Pickering said. During the last three years, TPH has modeled production on a 50 “wells to watch.” That research has found that 69 percent of the new wells are dry; 16 percent are unclear; and 16 percent are commercially viable. That makes replacing reserves to meet future demand a serious challenge.
TPH’s findings are sobering, Pickering said. On a five-year average replacement basis, none of the major oil companies have been able to replace their deepwater reserves at 100 percent. In fact, the average replacement rate of the biggest players – ExxonMobil Corp., TOTAL SA, Chevron Corp., BP and Royal Dutch Shell plc – is 42 percent.
Between 2010 and 2014 – when global oil prices were generally close to $100 per barrel – the biggest deepwater producers lost 2 MMbpd in oil equivalent, he said.
“Even when prices were great, these companies were having trouble growing on the oil side,” Pickering said.
And so, deepwater is an answer to how to boost volume, but it’s one that’s challenged by $50 oil. The contraction in cash flow – along with the economics of drilling in the vast, deepest parts of the ocean – are tricky, he said.
“Volatility of price makes it tough to commit to projects that take six, eight, 10 years to go from concept to first production to cash flow,” he said.
Private equity is one way to address the cash flow issue, but price volatility historically has unnerved that market. A new approach to attracting private equity is key to finding the intersection between that cash, Pickering said.
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