Domestic natural gas-weighted production continued to be curtailed during the second quarter to wait out better pricing, but as Gulf Coast LNG projects near completion, could Lower 48 activity increase? Second quarter results may tell the tale.
Exploration and production (E&P) companies and their oilfield services (OFS) counterparts are gearing up to issue their financial and operational reports over the next few weeks. While the outlook for natural gas prices has been fuzzy, some liquefied natural gas export projects are nearing completion on the Gulf Coast – and in British Columbia.
Could the additional gas needed to propel LNG exports overseas and to Mexico move the needle during the last half of this year?
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“Natural gas prices are off their lows, but we don’t expect higher activity until mid-2025,” BMO Capital Markets analysts said. The natural gas price outlook was “slowly improving” during the second quarter. Less drilling and completion activity, combined with voluntary curtailments, “supported prices.”
BMO analyst Phillip Jungwirth noted that the 2024 Henry Hub strip “is down 13% since year-end 2023, but 2025 prices are 4% higher…We expect Henry Hub prices to average $2.57/MMBtu in 2024 and $3.38 in 2025, before reaching $4.00 in 2026.”
Flatter Upstream
A few of the big U.S.-focused operators already have signaled their quarterly expectations, including BP plc, ExxonMobil and Shell plc. Overall, flat to lower upstream profits were signaled.
London-based integrated major BP, with a substantial portfolio in the Haynesville Shale and the Gulf of Mexico, said upstream production “is now expected to be broadly flat compared to the prior quarter…” Oil output is forecast to be flat, “and slightly lower in Gas & Low Carbon Energy.”
In BP’s Gas & Low Carbon segment, price realizations “are expected to have an adverse impact of around $100,000, including declines in non-Henry Hub natural gas marker prices. The gas marketing and trading result is expected to be average following a strong result in the first quarter.”
Meanwhile, Texas-based supermajor ExxonMobil said the uplift in oil prices during the second quarter should increase upstream earnings by $300-700 million. Profits, though, are likely to be dinged on overall lower natural gas prices and refining margins.
ExxonMobil also is likely to update investors about the status of its mega-merger with Permian Basin heavyweight Pioneer Natural Resources Co. The merger has faced Federal Trade Commission scrutiny. A similar probe is underway concerning the combination of Chevron Corp. and Hess Corp.
Water Tower Research’s Jeff Robertson, managing director of Natural Resources, said the “themes” for the second half of 2024 “will continue to emphasize balancing growth with capital returns and maximizing cost efficiencies.”
The wave of merger and acquisition (M&A) activity also may continue.
“Since early 2023, we count more than $240 billion of announced M&A transactions among U.S. oil and gas producers, including more than $70 billion in 2024,” Robertson noted.
“A drive to add scale, wring out costs, and increase companies’ capacity to generate” free cash flow (FCF) “appears to be one of the primary drivers behind many of the transactions. Greater FCF capacity is expected to support many companies’ goals of returning cash to shareholders.”
Over time, though, “we expect portfolio rationalization in the newly combined asset bases could create further asset acquisition opportunities.”
The buyers of the new assets now “are continuing to work toward realizing the operational and cost synergies in their transactions,” he noted. “We expect companies will maintain development plans for the balance of 2024.” The planning cycle going into 2025 should gain momentum in the final three months, Robertson added.
Capex Plans? TBD
Still to be determined is the overall capital expenditure (capex) outlook for the energy operators. A better idea of how much E&Ps may be budgeting could come into view as the oilfield services (OFS) firms issue their second quarter results. OFS companies often have insight into how much capex is budgeted by their E&P customers.
“North America activity has grinded lower as E&P consolidation curbs private spending, which captured outsized share in recent years,” Jungwirth noted. “Privates are less able to respond to higher oil prices, and public E&Ps maintain capital discipline.”
The E&P executives have “expressed more optimism around price relief for North American services, which should put downward pressure on the second half of 2024 and 2025 OFS expectations.
“Also, faster cycle times could curb spending late in the year,” as E&P budgets often are weighted to the first six months.
“Admittedly, valuations reflect these headwinds, with pumpers/drillers significantly underperforming the rest of energy over the past 18 months,” Jungwirth said. “We think a more visible recovery in activity is needed for North American-levered OFS, which is difficult to see.”
Tudor, Pickering, Holt & Co. analyst Jeff LeBlanc also offered his initial take on expected quarterly results.
“We continue to believe softer North American activity trends will weigh on Street estimates,” LeBlanc said. “For North America-levered names, we expect management teams to moderate their views on activity as rig churn remains high for both private and public operators, with efficiency gains and commodity prices remaining headwinds for both pumpers and drillers alike.
“We view the softer public activity trends as well telegraphed, as upstream has been forthright about the shape of their annual operating plans…We get the sense from investors that they are already underwriting a more subdued outlook.”
Natural gas fundamentals should support “higher activity in 2025,” but 3Q2024 should be the trough for estimates,” LeBlanc said.
Awaiting ‘Tidbits’
Siebert Williams Shank & Co. analyst Gabriele Sorbara’s team is not expecting to hear any of the operators cut their capex materially for the second half of this year.
“However, we would not be surprised by potential decisions to accelerate some 2025 activity into 4Q2024, which would likely be absorbed within prior budgets due to savings throughout the year.”
The reduced gas-directed activity earlier this year is likely to lead to some E&P production declines. However, FCF would “inflect higher off the 2Q2024 lows at current strip prices, which also benefits from reduced spending levels,” Sorbara noted.
“Investors will keenly await any tidbits that help to shape up next year, especially following the recent surge in consolidation.”
The “knee-jerk reaction to acquisitions is typically negative,” according to Sorbara. Still, “recent deals have helped replenish/extend inventory and durability of FCF and capital returns.”
Siebert has adjusted its commodity price deck for oil and for gas.
For Henry Hub, the full-year average was cut by 10 cents to $2.35/Mcf. Analysts also reduced the 2025 gas price assumption to $3.35 from $3.75 “due to bearish pressure from oversupply and uncertain demand. We maintain our 2026-plus assumption at $4.00, as we remain constructive on LNG and power generation demand over the next several years.”
‘Harsh’ Month For Permitting
Of note is the rapid decline on onshore oil and gas permitting.
There was a “harsh decline” during June compared to May, according to Evercore ISI. The analyst firm compiles a monthly report on U.S. oil and gas permitting using state and federal data.
“A total of 2,744 permits was granted over June, a 19% decrease from May’s 3,375,” Evercore analyst James West wrote in the recent report.
The monthly loss primarily was in the Permian, where 1,238 permits were granted. That was down by 201, or off 14% from May.
The Permian’s impact is notable, as it represented 45% of the total permits issued in June, West noted.
The Eagle Ford Shale in Texas also reported a sharp fall off in permits. It had 211 permits granted in June, down by 102 from May or by 33%. The Eagle Ford represents “8% of the total count.”
Evercore also tracked permit losses in the Powder River Basin, down 32%. Permitting in the Denver-Julesburg Niobrara formation of Colorado also saw a 32% decline in permitting, while the Barnett Shale’s numbers fell by 52% from May. In the Haynesville Shale, permits dipped by 27%.
There were positive signs for E&P and OFS employment during June, which “is recovering,” West noted.
“While total U.S. unemployment increased to 4.1%, the energy industry remained strong in June,” the Evercore analyst said. The Energy Workforce & Technology Council “noted a potential rebound in energy-specific job markets, as OFS employment shows signs of improvement. OFS employment grew 40 basis points (bps) over June, yet remains 2.6% down versus June 2023 numbers.
“The U.S. Bureau of Labor Statistics reported another increase in E&P employment following May’s 90 bps adjusted growth,” West noted. “Over June, E&P employment increased another 1.1% and is currently 3.8% up versus June 2023 numbers.”
