Derek, Tom and Anjli have a big scoop today: In 2021 Shell considered ditching Europe and shifting its listing and headquarters to the US.
Elsewhere, in an intriguing new liquefied natural gas deal announced this morning, US exporter Venture Global has struck a sales and purchase agreement with Excelerate Energy, which operates the worlds biggest fleet of floating import terminals. The 700,000 tonne per annum deal will run for 20 years and potentially open up a host of new markets for US LNG.
Occidental tied off US earnings season yesterday as the last big name in oil to report. Record 2022 earnings of $12.5bn suggest Vicki Hollub’s bet on scale with the purchase of Anadarko — though initially disastrous — might be beginning to pay off. (The Due Diligence team has more on that today.)
But despite huge earnings across the sector, the US shale patch faces a bumpier 2023. That is the subject of today’s newsletter.
In Data Drill, Amanda charts how China is doubling down on coal, and digs into a new report that suggests the transatlantic rift over US green subsidies may be overblown.
In other news, the Energy Source team will be in Houston starting on Monday for CERAWeek. If any readers want to catch up, please get in touch: [email protected]
Thanks for reading — Myles
2023 will be less rosy for the shale patch
As earnings in the US oil and gas sector begin to wrap up, the verdict is in: America’s shale patch just had its best year ever on many metrics. Free cash flow and profits are at all time highs — in many cases double previous records — shareholder returns have never been better, and even stocks have surged.
Yet market reaction to full-year results over recent weeks has been mixed. Wall Street is beginning to fret about the mixed outlook some operators have offered. Questions loom over 2023.
Oil prices are lower. Gas prices have tanked. Inflation continues to bite, prompting misses on spending and output targets that knocked some big names (hello, Devon Energy). With last year’s cash haul firmly in the rear-view mirror, the focus now is on the year ahead.
Here are some takeaways:
1. Inflation is driving up costs
Costs are still spiralling, forcing producers to boost capital spending to maintain production.
As I wrote last week, the cost of practically every aspect or material used in drilling wells — from labour to piping to fracking sand and fluid — has jumped over the past year. Diamondback Energy, for example, reckons the cost of the casing used to line wells has tripled over the past 18 months to $110 a foot.
“Everybody is tired of talking about it — I certainly am as well,” Devon Energy’s finance boss Jeff Ritenour told analysts (before proceeding to talk about it). “We’ve seen anywhere between 30 and 50 per cent inflation.”
While many operators said there were signs this rampant oilfield services inflation was beginning to decelerate, it will remain all too sticky for some in the shale patch. Morgan Stanley reckons most management teams are still budgeting for a 10-20 per cent increase in capital spending this year just to offset the extra costs.
Analysts at TPH&Co reckon rig rates are starting to come off in some places. And the prices for piping and casing might hit a ceiling in the coming months. But it is likely to be 2024 at least before deflation kicks in, if at all.
2. Increased drilling is still off the cards
Thanks in part to this inflation problem, any significant production growth remains firmly off the table. Capital discipline remains the religion, at least among the big listed drillers.
“No one wants to lean into the price upcycle because they worry that inflation will eat up all the gains,” said Raoul Le Blanc, an analyst at S&P Global Commodity Insights.
Execs insisted they would stick to their guns on shareholder returns, which were massive this year. Pioneer returned more than 95 per cent of its $8.4bn free cash flow to shareholders.
“Most E&Ps are affirming previous messaging of maintenance programmes or low growth in 2023,” said Devin McDermott at Morgan Stanley. “Furthermore, some that had planned for more activity may now defer rig additions due to weaker commodity prices”.
On Friday, the number of onshore rigs fell again, according to Baker Hughes — marking the biggest monthly drop since June 2020, when oil prices were crashing and producers were forced to shut wells, slash capital spending, idle rigs, and sack workers.
Gas producers in particular, hit hard by a collapse in prices, are planning a sharp pullback in drilling as the year progresses. Chesapeake said it would stand down three rigs by the second half of the year. Comstock is cutting two.
3. Investors are fretting over inventory
What is most worrying investors now though is how much — or how little — decent drilling acreage operators still have on their books.
“The main thesis that investors have right now in oil and gas is about its yield plus duration,” said Andrew Gillick, a director at consultancy Enverus. “How much money can you give me back? And for how long can you do it?”
But that needs companies to be able to keep producing at the same clip. And because of shale’s endless hamster-wheel model — constant drilling just to keep production steady — that means companies must have a long “fairway”, as many Golf-obsessed execs like to describe it, of good drilling locations in store.
Executives were keen to impress on the market that they still held healthy amount of this “inventory”.
But analysts are less sure. Bankers reckon M&A activity will surge this year as companies jostle for control of dwindling prime drilling locations. Public and private groups have deals teams at the ready.
That does not mean every deal will be welcomed. Reports that Pioneer — the biggest oil producer in the Permian — was weighing a purchase of gas producer Range Resources sent the oil group’s shares swiftly lower.
How does all this roll up?
Shale oil output is still growing: total US output was up about 1mn b/d in January compared with a year earlier, according to the Energy Information Administration.
But at 12.4mn b/d it’s still well-below the pre-pandemic highs. And the administration does not think last year’s growth rate will be repeated, forecasting a rise of just 250,000 b/d by next January.
If costs keep rising and rigs numbers keep dropping, even that target might be missed. (Myles McCormick)
1. Coal permitting reaches seven-year high in China
The world’s largest clean energy investor is doubling down on coal. Last year Chinese permits for coal plants reached their highest levels since 2015, according to a new report from the Centre for Research on Energy and Clean Air and the Global Energy Monitor.
China began construction on 52GW of coal plants in 2022, up 50 per cent from 2021 and six times the capacity under construction in the rest of the world. Meanwhile, the pace for retirements has slowed. Only 4.1GW of coal plants were closed in China in 2022, down from 5.2GW in 2021.
China is the largest investor in renewable energy, according to BloombergNEF. The country invested $546bn in the transition in 2022, nearly half of the world’s combined investment. President Xi Jinping has pledged to reduce the country’s coal usage in the second half of the decade and reach carbon neutrality by 2060.
Last summer’s historic drought and heatwave curbed hydropower generation in China and pushed the country’s coal use to record levels. The report by CREA and GEM warns China’s resurgence of coal activity could slow its clean energy buildout and undermine global efforts on climate action.
“It’s a knee-jerk reaction to the crisis, not careful long-term planning,” said Flora Champenois, research analyst at GEM.
2. Taking another look at the EU-US green subsidies dispute
Trade tensions between the US and EU over the Inflation Reduction Act may be overblown.
For months, Brussels has accused the US of luring away business and undermining the bloc’s manufacturing base with its $369bn green subsidies package. Earlier this month, European Commission president Ursula von der Leyen outlined the EU’s own €250bn industrial plan to counter the IRA.
But a new analysis from Rhodium Group shows US incentives for domestic manufacturing are much smaller than the rift suggests. Only 7 to 11 per cent of the IRA’s climate funding directly subsidises domestic production.
The bill does not restrict imports and roughly 48 to 60 per cent of its climate funding does not have domestic content requirements. For the credits that do require domestic sourcing and assembly, European companies are free to participate in the US supply chain.
“The primary driver from the IRA shaping the clean energy manufacturing landscape is likely to be the overall accelerated pace of clean energy deployment in the US,” wrote the authors of the report. (Amanda Chu)