Houston — Oil and gas upstream activity in the US Gulf of Mexico could pick up in 2021, even as production is expected to dip slightly because of reduced drilling in 2020 stemming from the coronavirus pandemic, analysts said this week.
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"We expect 2021 to recover somewhat, so we should see well activity rise," said Justin Rostant, a Gulf of Mexico analyst for consultants Wood Mackenzie.
Rostant expects as many as 60 new deepwater wells drilled this year in the region, excluding sidetracks and bypass wells, against 52 in 2020 and 60 in 2019.
US Gulf operators applied for 75 drilling permits for US Gulf wells in 2019 (52 for wells deeper than 3,000 feet), but this fell to 61 last year (46 for wells deeper than 3,000 feet), Sami Yahya, an S&P Global Platts Analytics analyst, said.
Following the crude price decline in 2020, and several US Gulf project delays, offshore operators should largely focus this year on development drilling rather than exploration, Yahya said.
"There will be some potential exploration baked in if there are already contracts in place," he said. "But operators are trying to figure out their footing, at least for the first half of 2021. [They] have plenty of development work available to keep them busy for the rest of the decade."
Activity may pick up in the second-half 2021, Yahya added.
Average breakevens for the deepwater US Gulf have dropped substantially in recent years to about $47/b in 2020 from $68/b in 2014, and are not much above US shale's $43/b, according to Platts Analytics. Both have full-cycle project breakeven costs of $50/b. That compares to $40/b in for deepwater Brazil last year and $49/b for the North Sea.
Production to edge up in H2
Oil production in the US Gulf of Mexico, which according to the US Energy Information Administration hovers near or around 1.8 million b/d currently, will likely drop a bit by year-end to 1.75 million b/d.
EIA estimates H1 2022 production to rise to 1.8 million b/d and fall again to 1.7 million b/d in the second half of the year.
Platts Analytics sees output ending 2021 at 1.85 million b/d.
The coronavirus has interrupted and slowed offshore work schedules in 2020, caused upstream operators to slash budgets from low oil prices and impacted supply chains.
"Companies drilling development wells, conducting workovers and other interventions to stimulate production will help [offset production impacts], but may not be enough to drive growth" in 2021, Rostant said.
Shell and BP were slated to each bring on a large and medium-sized projects, respectively, this year, but the status of some are uncertain.
First oil from Shell's Vito field, with peak output estimated at 100,000 boe/d, was slated to come online this year but has been postponed to 2022 after a three-month scale-back to prevent spread of the coronavirus, Shell spokeswoman Cindy Babski, said.
The company's PowerNap field startup, with a projected 35,000 boe/d of peak output, was similarly postponed to 2022 on pandemic concerns, she said.
Shell's Perdido Phase 2 tieback well to its operated Perdido hub in the remote southern US Gulf, achieved first oil Jan. 2. It is the first of four wells expected to come online this year at that project, Babski said.
BP's 140,000 b/d Mad Dog 2 project, as well as its 50,000 boe/d Thunder Horse South Phase 2, were scheduled to come online in 2021, although some sources believe these could be pushed back to 2022 for similar reasons.
BP could not be reached for comment.
Delays to have limited impact
Yahya said the delays of the larger fields may not matter much to 2021 production in any case.
"Mad Dog 2 and Vito were coming online in late 2021, so their true impact to production [wouldn't] be felt until well into 2022 anyway, given a required ramp-up period that could take many months," he said.
In addition, an assortment of smaller fields are expected online this year, such as Murphy Oil's Calliope, at around 7,000 boe/d, and Ourse at around 6,500 boe/d, analysts said.
The ramp-up of fields that came online in 2020 but whose start-ups were interrupted by the most brutal hurricane season in at least 15 years will provide a boost to 2021 output.
For example, Talos' Bulleit field, estimated around 15,000 b/d, started up late last year, and the company's Kaleidoscope field was also due to come online in November, but a series of storm-related shut-ins delayed startup or resumption.
This year, Shell expects to sanction its deepwater Whale project and Total is expected to green light its North Platte field (75,000 b/d at peak), although Rostant believes North Platte won't be approved until 2022.
Equinor is likely to drill an appraisal well this year at its 2020 Monument discovery from earlier in 2020. And LLOG Exploration, a large but privately held producer, plans more development drilling on its existing fields this year.
And Hess, which returned in 2019 to US Gulf drilling after an absence of several years, took another pause in 2020 from lowered capex and activity. But analysts see it returning to exploration near term. As recently as November its CEO, John Hess, called the region a "core focus area" for the company, which is partnered with ExxonMobil in giant discoveries in Guyana.
"Operators will need to continue to drill to maintain their volumes; it's the nature of the beast," Yahya said.