HOUSTON—In the energy world where profitability is king, North American shale is oftentimes pitted against offshore developments, with each having its positives and negatives. However, chasing the rock that delivers returns is the route companies like Hess Corp. and Shell are taking, with a portfolio that includes both as cash and growth engines.

“What people don’t realize is shale is 8% of world oil supply. It’s going to grow to about 12% mid-decade and then it plateaus,” Hess Corp. CEO John Hess said earlier this week at the Argus Americas Crude Summit. “Our strategy has always been to invest in returns, go to where we can be low cost to supply. It’s really about the best rocks or the best returns, so there’s still good opportunities in the offshore.”

Some offshore players moved onshore when the U.S. shale revolution picked up pace, lured by quicker and cheaper drilling along with technological advances that lifted the U.S. to the world’s top crude producer. But deepwater developments, once notorious for large cost overruns, have become more cost-efficient as players continue to cut down time from discovery to first oil while utilizing existing infrastructure.

Hess opted to remain both offshore and onshore. “We thought that shale-only strategy was not sustainable,” he said.

Despite operating onshore and offshore, energy companies—including oilfield service companies—in general have faced pressure to improve free cash flow, reduce debt and cut budgets while being mindful of environmental, societal and governance issues that could impact their financial coffers.

Oil and gas executives speaking at the conference agreed that having shale and offshore assets in portfolios are necessary to meet short-term and long-term needs. Breakevens and costs appear to be falling for both.

Falling Breakevens, Costs

Matthew Fitzsimmons, vice president of Rystad Energy’s oilfield service team, pointed out that breakeven prices have fallen since 2013-2014 compared to 2017-2018. Shale breakevens dropped nearly 50% with a roughly one-year payback time for wells compared to six-plus years for their offshore counterpart, he said. About half of that, he added, was due to service price declines.

Efficiency, however, is also leading to “more tangible cost savings” including by use of zipper fracturing, which Fitzsimmons said is utilized by about 50% of the U.S. shale marketplace. “It helps to redirect the fluid flow as the well is completing from one well to another without actually having to disconnect.”

The pricing power of suppliers in the well services market is also a factor, according to Fitzsimmons.

“North American shale is significantly more saturated [compared to offshore] and so for proprietary technologies it’s hard to charge a premium for those services,” he said, noting Schlumberger, for example, used a different business model, licensing its technology to remove itself from the pricing game.

Looking offshore, he pointed out how the sector has shifted from newbuild projects, or greenfields, and exploration activity making up 48% of its overall offshore portfolio about 20 years ago to about 28%. Most of offshore spending today and over the next few years is on legacy assets. Offshore players are pursuing more phased developments to reduce risks.

Plateauing Shale

Shale players face another challenge: steep declines.

“It’s tight rock,” Hess said. “When you drill a shale well in the first year, it declines 70%; the second year it declines 35%, and the next year it declines 15%, and then it goes on a plateau.”

That’s problematic for a powerhouse on the global oil market, considering shale is a capital-intensive business that requires cash to flow back into the business to grow production and ultimately grow overall free cash flow. Yet, investment wanes, following a period that saw investors infuse dollars into shale.

“The [shale] business is recalibrating itself to a more sustainable rate where you can grow but also generate free cash. That keeps investors happy. But it also keeps shale producers disciplined,” Hess added. “But there’s a limit to that growth. You’re starting to see the Eagle Ford mature to where it’s plateauing. The Bakken in the next two years, I think, will plateau, and then the Permian probably by mid-decade will plateau as well.”

Hess has grown its Bakken production by about 20% per year. The company aims to produce about 180,000 barrels per day (bbl/d) in the Bakken this year and to 200,000 bbl/d in 2021, staying flat for the next year years, a level Hess sees as optimal for net present value and return to shareholders.

Looking Offshore

Cash flow from the Hess’ Bakken assets will go toward longer-term developments such as offshore Guyana, where the company is a partner in the Exxon Mobil Corp.-led consortium. It has made 16 discoveries—more than 8 billion barrels of oil equivalent of estimated recoverable resources—on the Stabroek Block.

“That’s world class. It’s got a very low cost of supply. The first ship has a breakeven of about $35 Brent. The second ship that should come on early 2022 has a $25 breakeven, so that’s a testament that offshore can compete with shale.”

Amir Gerges, vice president of Shell E&P’s Permian assets, said shale and offshore bring different values. The deepwater and integrated projects bring a “flat but continuous cash flow,” while shale brings “flexibility where you can ramp up and ramp down depending on the commodity price,” he said. “But you still need a certain level of fixed investment to maintain production.”

Shell, which grew its production in the Permian Basin to 250,000 bbl/d in December, plans to spend about $3 billion per year for the next five years on shale projects. He noted that Shell can bring a three-well or four-well pad online in less than 140 days to see cash flow.

“You need both,” Gerges said of shale and offshore assets. “They complement each other. ...The capital allocation process depends on the opportunity and the portfolio that you have at that point in time as well.”

Shell is also moving forward with several offshore projects, including the Powernap subsea tieback and Vito in the U.S. Gulf of Mexico.

Scheduled to startup in late 2021, Vito is expected to produce at peak up to 100,000 boe/d with a forward-looking breakeven price estimated at less than $35 per barrel. Vito, which has the same estimated breakeven, is also set to start producing oil in 2021. It is expected to reach peak production of 35,000 boe/d.

 

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