BP plc’s U.S. natural gas and oil portfolio, both onshore and offshore, have the potential to sharply increase reserves in the coming years, according to CEO Murray Auchincloss.
The London-based supermajor issued its second quarter results on Tuesday. The global natural gas and oil markets were a big focus of the conference call.
However, Lower 48 performance was a significant part of the discussion, particularly drilling advancements in the Eagle Ford Shale and the newly sanctioned deepwater Gulf of Mexico (GOM) project, Kaskida.
The field is about 250 miles southwest of New Orleans in the prolific Lower Tertiary trend. It is in Keathley Canyon Block 292 in 5,860 feet of water. Of note, said Auchincloss, is that BP is estimating the project could hold “10 billion boe of discovered resource in a basin that’s now been highly developed by other companies.
“It’s time for us to catch up with that.”
The Kaskida hub, with planned capacity of 80,000 boe/d, could ramp up in 2029. Using an “industry standard solution,” the first phase of development would produce around 275 million boe, Auchincloss said.
“We might do quite a bit better than that,” he said of the estimated output. “The reason we might do quite a bit better than that is we have 1,000 feet of pay, and the average across the rest of the Paleogene is 500 feet of pay. So it's an enormous column of oil.”
If Kaskida performs as expected, BP could sanction its Keathley neighbor Tiber as soon as mid-2025. The Tiber development would “be a photocopy of Kaskida,” Auchincloss said.
BP holds all the stakes in Kaskida and Tiber. Other Keathley discoveries include Gibson, Gila and Guadalupe fields.
“It’s a very, very, very strong resource base,” the CEO said of the Keathley treasure. “We've got some derisking to do with appraisal wells and exploration wells that are very sensible to do, given the high quality seismic which we bought…Do we bring in a partner or not?...It will be an interesting choice to ask me in 12 or 18 months.”
‘Unbelievable’ Eagle Ford Returns
Meanwhile, updated hydraulic fracturing (fracking) being used in wells already drilled in the Eagle Ford has resulted in increased recovery rates and higher output, Auchincloss said. To that end, BPX Energy, the Lower 48 arm, is “rethinking the Eagle Ford.”
The company has 500 wells in the play “that have been producing for about a decade,” he explained. “Obviously, fracking techniques have moved on materially since then…”
BPX initially trialed some wells that already had been completed to test whether refracking would be worthwhile. Since then, the team has performed about 50 refracks in a mature portion of the South Texas formation.
“The returns on these are unbelievable,” Auchincloss said of the Eagle Ford refracks.
The Eagle Ford team also has begun downspacing some wells, which the CEO noted is “very counter to what you think of in some of these plays.” The usual practice is to improve output through laterals.
However, the wells that were downspaced “have delivered 3,700 boe/d…” That is “way above…even what we're seeing in some of the Permian acreage.
“So the Eagle Ford is opening back up to us,” the CEO said. “It is this mantra that we always have to think about with resources…
“Once you think you're done on the recovery factor, have another go at technology and see what happens. And that's what we're proving in the Eagle Ford.”
Drilling experts used to tout oil and gas recovery factors of 7-10% in the Permian Basin, Auchincloss said.
“They're now talking 30% recovery factors in the Eagle Ford from these refrack and from the downspacing. And of course, that's a question that will constantly challenge ourselves in the Permian as well.”
Liquids Over Gas
For now, the BPX business will continue to focus on liquids recovery. The Haynesville Shale, a dry gas play, will draw fewer resources.
“With liquids growth, gas production will decline with only one rig running in the Haynesville,” the CEO said. “But given where our prices are right now, that's fine. We'll take our hedges through profit, and we'll see what happens with gas prices as we move through ‘25 and ‘26.
“Our sense is, it'll be more resilient. And if it's more resilient, we can lean in and we can produce an awful lot more natural gas. But we have tremendous flexibility in the portfolio, given all the resource we have there.”
Acknowledging the current low natural gas prices, Auchincloss said BPX plans to keep its powder dry in the Haynesville.
Natural gas trades for NGI’s Haynesville - E. TX shale price index averaged about 23.0 cents lower at $1.655/MMBtu in 2Q2024 versus the year-ago period, NGI’s Shale Historical Data show.
[Forward Look: Quickly understand where the price of natural gas is headed with these graphic day-on-day comparisons of NGI's forward curves at 70 locations. View Now.]
“We've got tons of resource, 22 Tcf,” the CEO said. “We've just moved down to minimal drilling…to one rig in the Haynesville…
“So we'll continue to drill out the Permian and gradually fill that system up entirely. We’ll probably hit peak production for liquids in the Permian around 2030 first.”
BPX’s third central gas processing facility in the Permian, which ramped in the first quarter, has begun to fill up, the CEO said. “That's why we should see the strong growth in liquids…”
A compressor station is being built to lower line pressure and draw “more resource out of the ground,” he said. “That should come online sometime in the middle of next year.”
The “difficulty,” he explained, is that BPX is able to drill “the same number of wells with half the rigs” in the Permian. “So they've just done incredible work on arranging well drilling and some top drive system technology as well.
“It's hard to believe that they've been able to do that step change yet again. So when you look at the rig count numbers that we provide, it's as if it's two times the rate that existed two years ago…”
