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Higher 2022 capex foreseen during Q3 calls, but operators to remain disciplined

Third-quarter 2021 upstream calls were dominated by operator assurances that high oil prices won’t sway them from continued capital and production discipline, while they also detailed progress in low-carbon initiatives and a desire to return more of their torrential cash flows to investors.

In the face of $80-plus WTI crude prices, upstream operators largely left 2021 capital budgets unchanged but said capex for next year was shaping up to be about 10%-20% higher year on year – much of which stems from inflation, analysts and observers said.

“The majority of operators are sticking to their prior capex for this year,” S&P Global Platts Analytics senior energy analyst Sami Yahya said. “For next year, while many operators plan to disclose budgets in the next quarter, [the overall] plans are to stick to maintenance capital which entails an increase in budgets between 10%-15% given expected price inflation and the need to bring online more wells to sustain their Q4 2021 volumes into next year.”

Production growth remains an “afterthought,” Yahya said, which is evidenced by the fact that Q3 was a “blowout quarter” in terms of free cash flow generation that was funneled toward debt reduction and rewarding investors.

Free cash flows in Q3 were 40% higher sequentially, compared to 18% in Q2 in Platts Analytics’ sample of 20 E&Ps, he said.

KeyBanc analyst Leo Mariani thinks 2022 budgets will be higher by as much as 20% year on year although he said nearly half of that will be attributable to inflation.

Capex growth ‘far less’ than in past

“[But even 20%] is far less than what we would have seen in previous commodity cycles of at least a 50% increase at current oil and gas prices, as relative discipline appears to be holding,” Mariani said in a Nov. 9 investor note.

According to Evercore ISI’s James West, oil and gas capex for his investment bank’s independent and integrated E&P coverage universe — which includes most of the large public names – has increased 15% in 2021 year over year to $19.5 billion, outpacing the 8% yearly increase in production on a boe/d basis.

“Independent E&P spending has ramped 76% year over year [in 2021] while production is up only 16%,” West added in a Nov. 8 investor note. “Efficiency gains are continuing as every 1,000 boe/d of production costs $1.01 million versus $1.08 million in Q3 2020.”

A few larger E&P companies such as ConocoPhillips and EOG Resources indicated they could grow oil production some in 2022, said Mariani.

ConocoPhillips said it plans to continue growing its Eagle Ford Shale production in South Texas in the next few years. There may be some incremental capital spending in the US, Norway, Alaska and Canada next year, but specifics won’t be known until the company unveils its capital plan for next year in December 2021.

EOG expects no more than 5% oil production growth in 2022 compared to 2021, as the the company may return to pre-coronavirus pandemic oil production levels if it sees spare oil production capacity lower and also global inventories that are below five-year averages.

Upstream operators’ Q3 calls also had more news about searching not only for improvements in emissions that have been a feature of E&P quarterly calls for the past couple of years, but also chat about some actual projects.

Progressing low-carbon projects

Small US Gulf of Mexico operator Talos Energy, for instance, forged a carbon capture/storage project offshore with TechnipFMC in October, outlined on its Q3 call. And ConocoPhillips’ new low-carbon group is eyeing development of CCS and also hydrogen projects, which company CEO Ryan Lance said both “have a strong adjacency” to its core businesses and competencies.

A recent study by consultants Deloitte noted upstream merger and acquisition activity may increasingly be influenced by the carbon profile of assets on the market. Properties with “limited visibility” on emissions might find fewer potential buyers, it said.

“Companies pursuing their net-zero goals are either looking to acquire low-carbon-intensity barrels or divest the high-intensity ones, implying that there might be an acreage consolidation or portfolio restructuring on the horizon,” Deloitte said. “A large resource size and an attractive offering price may not be enough to elicit a response from a buyer focused on meeting net-zero targets.”

While a few smaller E&P operators are in the market looking for deals, larger operators – many of whom are still digesting major acquisitions during the last year – said during Q3 calls they have a full plate for now and are more interested in bolt-on or smaller acreage additions.

In November 2021, three M&A transactions with a combined value of $3.1 billion have brought the deal total this year to the highest level since 2014, Platts Analytics analyst Nathan Hasbrook said in a recent report.

“This year has had an unprecedented level of M&A activity, which now stands at $53.9 billion year to date,” Hasbrook said. “While it is no surprise that the Permian Basin accounts for the bulk of all transactions at 60%, the Haynesville has had an unusually active year.”

The gas-weighted Haynesville Shale, sited in East Texas/Northwest Louisiana, has had $6.75 billion in activity, making up 13% of all deals year to date, he said. “That makes it the second most active basin for M&A.”
Source: Platts

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