The 2020 oil price collapse placed a dagger in U.S. Lower 48 tight oil production and a myriad of constraints counters the idea of the sector returning to a growth trajectory. However, Wood Mackenzie analysts say ongoing developments like capital discipline, consolidation and well spacing will drive the U.S. tight oil sector toward growth again—eventually.

“We’re thinking about this in a real positive light because companies have the opportunity to get to a place where they're able to meaningfully de-lever and make good on those investments,” said Ryan Duman, Wood Mackenzie principal analyst of Lower 48 upstream. “While also evaluating complex operational decisions and the best sequencing and spacing choices for their individual assets.”

In a recent webinar held by the Petroleum Engineer’s Club of Dallas, Wood Mackenzie analysts agreed that tight oil will continue to decline by half a million barrels per day through 2021. However, the analysts said that as rigs continue to come online, tight oil will see modest growth in 2022.

And, if WTI price exceeds $50/bbl, the analysts predicted tight oil will hit 2019 levels by 2024.

“We’re entering a new and different era for tight oil and there are maturing and growing pains,” said Benjamin Shattuck, research director at Wood Mackenzie. “But, I think that we will emerge stronger.”

Currently, operators are under immense pressure from banks and shareholders to generate free cash flow. Many have chosen to limit their reinvestment rate under 100%, dedicating only 70% to 80% of operating cash flow to reinvestment and the rest towards paying down debt.

According to Shattuck, the change in business model isn’t a new concept. He noted that U.S. E&Ps have reduced capital intensity since 2015. What markets now expect is a new lower paradigm.

The Bottom Line

Diversifieds, led by ConocoPhillips Co., started to reduce capital intensity in first-quarter 2016 and multibasin E&Ps followed roughly two years later, the analyst said. However, Permian Basin pure-plays continued to outspend operating cash flow right up until the pandemic collapse.

“We saw a lot of Permian-focused companies traditionally favoring production growth over free cash flow, not necessarily any fault of their own, just given what investor demands were back in those previous years,” Shattuck said.

Collectively, he predicts U.S. E&Ps should be able to keep production flat and stay within an 80% reinvestment rate constraint even at $40 WTI.

“We can assume that all companies will target free cash flow going forward and as long as WTI remains flat above $40/bbl, helping most of the sector achieve a 70% to 80% reinvestment rate,” he said.

Shattuck said it will take multiple years of balance sheet repair and debt reduction before much of the sector can realistically target production growth.

“We think it’s going to be rare for companies to want to target much beyond their year-over-year growth rate,” he said. “Bottom line, we’re not looking for any major uptick in activity, even if prices were to materially appreciate.”

“If all of a sudden tomorrow we saw prices reach $60 a barrel, we’d hope to still see some restraint from the sector,” he added.

EOG Resources Inc. and Pioneer Natural Resources Co. stated they anticipate modest growth. However, Shattuck warned E&P companies struggling to deliver cash to shareholders to take the growth news with a grain of salt.

“Don’t mistake their announcements as being what’s going to happen across the sector because they’re not going to be able to carry the whole Lower 48 growth profile,” he said.

Consolidation

One of the most notable outcomes of the sector’s deteriorating financial health last year was the wave of M&A.

“We saw a slew of bankruptcies and consolidation last year,” he said. “That means it is likely that the cost structure will not be sustainable into the future.”

However, he said consolidation within the sector creates clear arbitrage of opportunities that work in both directions of a deal.

Shattuck highlighted Pioneer’s acquisition of fellow Permian Basin operator Parsley Energy in an all-stock merger in the second half of 2020. Pioneer did not have an enormous cost of capital advantage over Parsley. Though, according to Shattuck, Pioneer’s advantage was its ability to streamline the costs associated with developing offset assets and better target intervals, which Parsley was not able to explore prior to the deal.

“In the short term, it’s awkward and it's painful,” he said. “In the long term, those rocks are finding their way to a bigger and better balance sheet, which to some extent liberates those assets so that they can be developed more efficiently and that's a good thing for U.S. oil production particularly in the medium and long term.”

Similarly, the same opportunity appears in Permian rival Diamondback Energy Inc.’s all-stock acquisition deal for QEP Resources Inc. and private equity-backed Guidon Operating LLC. He said the U.S. shale producer will be able to operate the assets better and bring down QEP’s cost of capital, which sat 60% higher for the company before the deal.

“All of a sudden you’ve got a situation where the cost of bringing these assets into play is 15% lower than what it would have been under the existing company,” he added.

Shattuck expects a second wave of M&A this year, which will be “perfect” for smaller companies in the U.S. to find bigger balance sheets and good assets on a microscale.

As producers are split between distributing cash back to shareholders and/or putting it into the oil field, Shattuck said making the decision is different than any other period in history.

“For the next couple of years, the decisions that producers face with what to do with an extra dollar will be vastly different from what they were in the last decade,” he said. “But with a higher cost well and lower margins, I think during this period of making the sector investable again—which it absolutely it is—you're going to find the propensity head back to the shareholders.”

Sweet Spot

According to Duman, well spacing and sequencing—with the goal of limiting underperformance—are operational metrics that will grow production and cash flow, moving the tight oil curve forward.

The sweet spot sits at six wells per bed because that’s where operators will be able to maximize NPV, he said. Though upspacing further will result in an uptick in performance, he said it will not be enough to offset the benefit of more wells. “You’ll see more resource per section when you have the six wells.”

“Economically, your best single-well performance isn’t necessarily the best metric to chase when you’re trying to maximize NPV at bench section or project level,” he added. “So if you believe in higher prices, then you could arguably start to sacrifice even more of that single well performance and still get ahead from a return standpoint.”

However, he said operations should align their spacing and sequencing needs based on the company’s circumstances.

“I think the days of companies walking into plays and applying modern, high intensity completions is done,” he said. “The industry has a pretty good grasp of knowing what to do about spacing and one of the things that makes thinking about spacing and sequencing so interesting is the fact that there is no perfect answer.”

Shattuck continued: “It’s just a different environment, a different era and I think a pretty reasonable argument can be made that a healthier era for the oil industry is on the way.”

Onshore