Sub-$70 oil is further differentiating the E&P “haves and have nots”—the latter consisting of those that haven’t made the investments or done the work, EOG Resources Chairman and CEO Ezra Yacob said in an investor call Aug. 8.
Yacob’s remarks were in response to an analyst’s question about whether U.S. shale will “reach peak production or may have already reached peak production.”
“From EOG’s standpoint, if you’re looking at the U.S. shale oil industry at a $65 to $70 WTI price, do you think we are running out of inventories?” the analyst, Paul Cheng with Scotiabank, asked.
Yacob said, “You can’t really refute the fact that at current pricing at $65 or $70, the rig count has fallen off pretty hard.”
Shale-directed rigs at work currently total 480, down from 511 rigs in mid-February, according to a new J.P. Morgan Securities analysis of Enverus data.
Since February, OPEC+ has been adding barrels into the global market, while market watchers anticipate a global economic slowdown due to Trump administration-imposed tariffs nearly worldwide.
Some of the rig count decline is due to better drilling efficiency, Yacob said, “but I think the data is showing that the U.S. doesn’t seem to have a lot of incentive to grow at this pricing,” he said.
“What you’re left with is, if you filter down from the U.S. into the industry or individual companies, I think you’re finding companies—and we’ve talked about it before—turning into groups of haves and have nots.”
The “haves” are those that have invested in scale, data collection and infrastructure to lower their breakevens.
“There are a handful of companies out there that can continue to grow and be very, very profitable at pricing well below $65,” he said.
“And then you have a series of other companies that, for whatever reason—maybe don’t have the scale, don’t have the track record or the access to the data to continue to make that happen—clearly have a higher break-even.”
But “the U.S. has a vast amount of resources,” Yacob said.
Sub-$70 WTI is “a call on pricing, but it’s also on technology.”
New tech
Jeff Leitzell, EOG COO, said the company has developed two new proprietary technology programs.
One is using high-frequency subsurface sensors while drilling to calculate geo-mechanical rock properties, identify faulting local stresses and monitor downhole equipment performance to minimize downtime.
Sensors have been deployed in more than 50 wells to date, Leitzell said.
The other new tech is a generative AI system for easier collaboration and to automate data capture.
Yacob noted that, in the more than two decades of U.S. shale development, EOG’s tech investments have included simul-frac, longer laterals, faster drilling and improved motor performance.
And employees, he added. That expertise applied to generative AI is the next step, he said.
“It’s really capturing … the human intelligence. … You can capture the knowledge, the experiential learning … into a searchable database that you can really start to unlock trends that were maybe not as apparent without that data,” he said.
“So I’d never count our employees out.”
Yacob’s 2023 forecast
ConocoPhillips CEO Ryan Lance described industry haves and have-nots in an investor call in May, putting ConocoPhillips in the “haves” category.
“We have a deep, durable and diverse portfolio,” Lance said. “We have decades of inventory below our $40/bbl WTI cost-of-supply threshold, both in the U.S. and internationally.
“We believe we are the clear leader of the ‘haves.’”
Yacob said in a 2023 investment conference hosted by Barclays, “In the next few years, what you’ll see is a segregation of the operators. You’ll see the ‘haves and the have-nots’ really start to come apparent to everybody.”
In the early 2010s, the “haves” were those who grabbed the best parts of the best basins.
“The have-nots were either on the fringes of the basins or had scattered acreage or were in the wrong basin altogether,” he said.
The “haves” today will be E&Ps that can make less productive rock economic. “There’s no reason that a less productive rock cannot deliver high return,” Yacob said.
It just requires a lot of work—”learning about the reservoir, understanding how to make wells better, … driving down costs, grabbing different pieces of the value chain, … drilling faster, completing wells faster.”
In EOG’s Eagle Ford play, for example, it was already drilling in 2023 what would have been considered Tier 2 rock at the time of the play’s 2008 discovery.
Beating costs back, though, EOG is now “developing lower-cost reserves than we were 10 years ago in higher-productive rock.”
The have and have-not differentiator is “really going to come down to what companies have taken the time, the effort, the expertise to collect the data and apply the data, understand how to make Tier 2 … rock still be highly economic.”
“I think that’s what you’ll see in the next few years,” he forecasted.
Utica, UAE, Bahrain
EOG has added two new plays to its portfolio this year.
It closed a $5.6 billion bolt-on acquisition Aug. 1 of Utica Shale oil neighbor Encino Energy, picking up 1.1 million net acres potentially holding 2 Bboe or more.
There, it is running five rigs and three completion crews, adding what Encino had at work to its own iron and pressure-pumping count.
Yacob said the play has a more than 55% average direct after-tax rate of return at $45 oil and $2.50 gas and a more than 200% after-tax rate of return at $65 oil and $3.50 gas.
EOG’s average drilling and completion (D&C) cost in the Utica is less than $650/ft, while Encino’s was $750/ft, Leitzell said.
Wells EOG drilled, which total 50, are paying off in 9.3 months, which is similar to EOG’s Permian wells payout rate.
EOG also signed deals earlier this year to explore and produce from offshore Bahrain and in 900,000 acres onshore the United Arab Emirates.
In the latter, “this is actually a reservoir that we’ve been working on for a number of years,” Yacob said in the Aug. 9 call.
The target formation is a carbonate shale geologically similar to the Eagle Ford by some measures.
“It has been drilled and delineated both vertically and horizontally … throughout a portion of the basin where our concession is and so we have good geological data on it,” Yacob said.
“I would say the challenge that we have in front of us is not necessarily on the geologic side; it’s going to be more on bringing an international unconventional play up to scale.”
The plays join its existing portfolio, which includes the Permian and Powder River basins, the Bakken and the Eagle Ford Shale.
In the Eagle Ford, it recently landed a 24,128-ft lateral (4.6 miles), which Leitzell said is the longest lateral in Texas history.
$1 billion FCF
EOG’s free cash flow from the second quarter was $1 billion or $1.78 per share, after earning $2.5 billion on $1.5 billion spent.
It paid $528 million in regular dividends ($0.975 per share) and bought back 5.4 million shares. The third-quarter dividend will be $1.02 per share.
It paid for Encino with cash on hand and a $3.5 billion debt offering.
Second-quarter oil production was 504,200 bbl/d.