Q1 2025 Research Theme: US Shale Activity Slowing – Cyclical Trough or Structural Twilight?
- PillarFour Capital Partners
- Apr 30
- 14 min read
Recent market commentary should make it abundantly clear to the White House that it cannot direct the independent US oil & gas industry by fiat.
Just a few examples of recent cautionary messages to industry investors:
Halliburton warns of the impact of US import tariffs and lower US oilfield activity as oil producers re-evaluate capital programs at weaker oil prices;
EOG Resources trims 2025 investment program by US$200 million;
Coterra Energy drops three of its ten Permian Basin drilling rigs; and
Diamondback Energy CEO states ‘… US oil production is at a tipping point at current commodity prices.’, cuts 2025 capital budget by US$400 million.
Predictably, President Trump’s ‘Drill, Baby, Drill’ slogan and Treasury Secretary Bessent’s related pledge to increase domestic US oil production by 3 million barrels per day (mmbopd) will gain little traction in the light of draconian US import tariffs that have prompted lower global oil prices on heightened fears of recession, all amid a backdrop of slowing oil production growth in the key Permian basin.
Perhaps the White House originally judged its 3 mmbopd growth target to be attainable once, as promised, Energy Secretary Wright eases all unnecessary regulatory burdens, thus lowering costs and accelerating permit approvals?
After all, on President Biden’s watch, US oil production grew by over 2 mmbopd to a record 13.5 mmbopd, despite a thicket of new regulations and restrictions on federal leases, and without a White House diktat!
However, it was an oil boom primarily on federal lands, in New Mexico’s Delaware Basin (a Permian sub-basin), that drove US oil production to record levels by year-end 2024. How so? Having already acquired their federal Delaware Basin leases, the operators ‘side-stepped’ the Biden administration’s tougher federal leasing regime. Furthermore, onshore and offshore federal acreage account for just 12% and 13% of current US oil production respectively - so any presumption by the new administration that a more relaxed federal regime will result in greater oil production growth is misplaced in our view.
The most important driver of upstream investment and thus incremental production is, as ever, the oil price: WTI averaged almost US$80 per barrel on Biden’s watch, well above ~US$60/bbl breakeven pricing in the key US oil basins.
To paraphrase James Carville: ’It’s the economics, ….’
But note that, despite high (> US$75/bbl) WTI oil pricing and this prodigious surge of Delaware Basin oil production, the annual growth rate of Permian oil production has halved since 2022 to 6.1% in 2024, , and is, according to the EIA, forecast to halve once more to just 2.6% by 2026E.
Annual oil production growth, overall US & Permian Basin, 2021 - 2026E
However, despite slowing growth, both historical and forecast, the Permian basin will likely remain the bellwether of the US oil industry:
The Permian basin delivers 6.3 mmbopd or 47% of current US oil & condensate production.
From 2020 to 2024, annual US oil production grew by 1.9 mmbopd, of which the Permian basin delivered 1.8 mmbopd or 96%.
By 2026E, the US EIA forecasts that Permian oil production will grow by 460,000 bopd, amply underpinning forecast US oil production growth of 350,000 bopd despite declining oil production elsewhere in other basins.
Other tight oil basins are also experiencing slowing production growth.
The future economic productivity of the Permian basin will therefore determine the foreseeable direction of overall US oil production and thus the fate of the White House ambition to add a further 3 mmbopd of oil production.
Survey says: Operators ‘breakeven’ at low-US$60s WTI
Published in late March, a recent Dallas Fed Energy Survey of E&P operators and oilfield service companies indicated the average WTI oil price required to profitably* drill a new well ranged from US$61 to US$70 per barrel by basin/sub-basin, with smaller operators (those with < 10,000 bopd production) requiring on average a US$5/bbl WTI premium over larger operators to profitably drill a new well, principally driven by scale economics.
Unsurprisingly, the ‘heartlands’ of the prolific Permian basin - the Midland and Delaware sub-basins - require the lowest average ‘breakeven’ WTI oil pricing (US$61 - US$62/bbl) to ensure a profit from an incremental oil well.
Note however the broad ‘breakeven’ range exhibited within each sub-basin - from as low as US$45/bbl to as much as US$75 - US$90/bbl on the high side.
All barrels (and operators) are clearly not equal - even within prolific basins, as we will discuss later.
WTI Oil Price Required To Profitably* Drill A New Well In 2025
2025 US Shale Activity Inevitably Curtailed by Lower Oil Prices & Volatility
Despite a 90-day ‘pause’ on all 10%-plus foreign import tariffs bar China, the overall US import tariff burden remains at 26% - the highest in over a century!
No wonder that WTI hit a 4-year low of US$57/bbl on fears of global recession.
As we go to press, WTI is hovering around US$60/bbl – modestly below average ‘breakeven’ pricing for US onshore oil wells, offering little to no margin for all but the more advantaged operators.
Of course, tariffs are not the only culprit currently weighing on global oil prices: Kazakhstan’s continued defiance of OPEC+ quotas has long rankled more compliant OPEC+ members. Led by Saudi Arabia, OPEC+ tripled its planned May production increase and, unless Kazakhstan agrees to get in line, may well do the same in June. While this Saudi-driven ‘price war’ is directed toward Kazakhstan, the impact clearly drives global oil prices lower.
Continued market volatility and low commodity prices have already prompted oil & gas operators and oilfield service companies alike to speak of lower 2025 global upstream oil & gas investment.
As presaged earlier, with WTI trading at or below average US shale ‘breakeven’ levels, some operators have already announced modest curtailments of their 2025 US shale investment plans.
DUCs Offer Little Relief With Inventory Down 75%, At Record Low
Since late 2020, the inventory of drilled but uncompleted (DUC) wells in the prime oil producing Permian, Eagleford and Bakken basins has shrunk by over 75% to the lowest level since the US EIA started keeping records in 2013!
This ‘blowdown’ of DUC inventory no doubt enabled nimble operators to capture pricing opportunities to swiftly add production. However, with future production growth more reliant on the drill bit, longer lead times and higher costs to first oil will weigh on such investment decisions at current WTI levels.
However, this record DUC ‘blowdown’ will also ensure greater ‘direct-drive’ demand for drilling rigs as and when WTI pricing firms and market risks diminish.
DUC* Wells - Permian, Eagleford & Bakken Basins: 2019 - 2024
Steel Tariffs Inevitably Raise Near-Term Drilling & Completion (D&C) Costs
A lower, more volatile revenue stream is more than enough to contend with, but steel and other tariffs will raise equipment, consumable and service costs - the result being higher D&C costs, thus higher ‘breakeven’ oil pricing.
Although subject to the specifics of a well (e.g. total depth, profile, completion design etc), oil country tubular goods (OCTG), better known as casing & tubing, typically rank Top 3 at ca. 20% of the total D&C cost of a US onshore shale well.
Diamondback Energy recently spoke of their largest drilling input cost, casing, increasing by 10% in the last quarter due to steel tariffs. Should the passthrough, direct or indirect, of such import tariffs to US steel consumers rise toward the full 25%, OCTG alone could add 5% to overall well costs.
Other vital steel oil & gas equipment such as wellheads, BOPs, drillpipe, drillbits and pipeline will also rise in cost, whether sourced locally or from overseas, once inventories are exhausted. Furthermore, until the dust settles on US tariffs - whatever the outcome, service providers will be unwilling or unable to commit to new supply chains, foreign or domestic.
Geologic Issues Present Growing Structural Economic Challenges
So far, we have discussed market issues - lower, more volatile oil pricing and higher tariff-driven well costs - that will inevitably thwart the White House’s targeted 3.0 mmbopd growth of US oil production.
But pricing and costs ultimately prove cyclical in global commodity businesses.
Long flagged by operators and analysts, several geologic issues now present growing structural cost threats to the future economics of US shale oil.
Caveat: I’m not a reservoir engineer but will endeavour to describe the issues!
Diminishing Inventory of Tier 1 Acreage Driving Up Production Costs
Despite the many advances in drilling and completion technologies, reservoir rock quality remains a key determinant of unconventional well performance. Operators have inevitably sought to acquire and exploit Tier 1 acreage first - that being the best in terms of both resource and productivity once fractured.
With approximately two-thirds of and half of the prime Tier 1 acreage in the Midland and Delaware sub-basins respectively already developed (according to analytics firm Novi Labs), competition for residual prime acreage, as well as scale efficiencies, has no doubt played a large part in the US$136 billion of M&A deals in the Permian Basin since 2023.
Peripheral Tier 2/Tier 3 acreage typically suffers from less favourable geology in terms of oil content and maturity, resulting in wells with higher water and gas cut, greater investment in treatment facilities and higher production costs.
As illustrated by the high-low range of ‘breakeven’ pricing by basin/sub-basin within the Fed survey described earlier, average ‘breakeven’ pricing ranges from US$60/bbl and lower for Tier 1 acreage to as much as US$96/bbl for Tier 4 (according to Novi Labs), reflecting the scale of geologic variance and associated production costs across the basin.
Vast, Growing Volumes Of Produced Water Demand Lower-Cost Solutions
The average 2024 water cut for the Permian basin of 77%, or 3.3 barrels of produced water per crude barrel is the highest across all major US shale basins.
In some parts of the Permian basin, the produced-water-to-crude oil ratio can be as high as 12 to 1!
Average Water Cut By US Shale Basin, 2024
On both an absolute and relative scale, the scale of Permian produced water is extraordinary: some 20 million barrels per day for 2024; an order of magnitude greater than that of the other major US shale oil basins combined; equivalent to the daily oil consumption for the entire US!
Produced Water by Shale Basin, 2017 - 2030E
Currently, ca. 85% of Permian produced water is disposed of via thousands of injection wells across the Midland and Delaware sub-basins, primarily into shallow disposal zones that lie above the primary shale production horizons. Rising volumes and seismic-related regulatory restrictions are driving up in-basin disposal costs. According to Coterra Energy, at a 4-to-1 produced water-to-oil ratio, in-basin water disposal costs about $2 per barrel of oil. At 12-to-1, similar water disposal would cost nearly $8 per barrel of oil.
Growing issues with in-basin disposal of produced water has seen midstream investment in dedicated out-of-basin evacuation pipelines and disposal wells. In tandem, the growing demand for fresh water for multi-stage fracs is now threatening the longevity of local natural aquifers. Some Permian operators, particularly in the Delaware basin, are therefore investing in large-scale strategic water treatment hubs to recycle produced water for fracking operations – an operational ‘win-win’ : lower freshwater supply costs, lower produced water disposal costs, andt potential third-party access revenues.
Rising Gas-to-Oil Ratio Across Key Shale Oil Basins – Should We Be Worried?
Most shale oil wells produce a proportion of associated gas that was originally ‘in solution’ under reservoir conditions. As with conventional reservoirs, shale oil wells also tend to produce comparatively more associated gas with age.
Average Gas-to-Oil Ratio for Single Wells by US Shale Basin
Individual Permian wells exhibit, on average, lower GOR growth over time and thus a lower GOR at the ‘3-year mark’ than other US shale basins bar the Williston.
In aggregate, the overall gas-to-oil ratio (GOR) of a basin will necessarily rise over time as the average well population ages.
In recent years, there has been a growing industry debate regarding the increasing GOR ratio observed across the Permian and other shale basins.
The debate essentially centres on whether the rising GOR observed across Permian wells anticipates an irreversible threat – colloquially referred to as ‘Bubble-Point Death’ – to the future of oil production in this vital US basin.
However, the average Permian Basin GOR has been comparatively stable, rising by less than 30% over the last decade, while Eagleford and Bakken GORs have risen by 56% and 141% respectively.
Average Gas-Oil Ratios for Key US Oil Shale Plays: 2014 - 2024 (mcf/bbl)
So, what to make of this debate regarding the ‘bubble-point death’ threat?
Are Rising GORs the ‘Canary in the Coalmine’ …
Several articles cite public-domain production data from the Permian and other shale basins that, in their authors’ opinion, indicates oil wells are irreversibly ‘gassing out’ due to the onset of ‘bubble-point’ issues, resulting in materially lower ultimate oil recovery (EUR) and thus lower asset valuations.
Shale is arguably as likely to fall foul of ‘bubble point death’ as conventional reservoirs: once reservoir pressure is drawn down below a critical level (the bubble point), gas is liberated from its prior solution in oil. Albeit raising near-term drive, associated gas ultimately ‘crowds out’ oil production due to its greater relative mobility, ‘choking off’ oil production via narrow matrix pores.
The simple remedy, in a conventional reservoir, is to reinject water, foam, CO2 or indeed gas to maintain reservoir pressure well above the ‘bubble-point’. But such reinjection does not work in shale due to its low permeability (hence the immense amount of energy, water and proppant required to frac shale).
This inability to re-pressure the shale matrix via reinjection amid evidence of growing GOR across US shale basins gives rise to the ‘bubble-point death’ argument for the inevitable, premature decline of US shale oil production.
… Or Does the Impermeability of Shale Limit the Bubble-Point Threat?
Novi Labs, having recently completed a detailed analysis of operator activity and oil & gas production across all major US shale oil basins, presents an interesting, data-led counter-argument – namely that periods of increasing GOR within a particular shale oil basin generally coincide with slowing drilling & completion (D&C) activity, particularly following a rapid increase in activity.
In summary, to quote Ted Cross, latterly of Novi Labs, rising GOR is primarily an effect of, and not a cause of declining activity levels.
Intuitively, this conclusion makes sense: as activity slows, so fewer new wells come online, the overall well population ages, and the overall GOR increases in tandem, as described earlier.
Fracking shale to stimulate oil & gas production requires vast amounts of energy, fluid and proppant. But the shale volume that lies beyond the ‘frac-zone’ remains in virgin or near-virgin condition – tight, virtually undepleted and ripe for delivering further low-GOR oil once fractured.
Indeed, the relatively modest growth of GOR in the Permian basin, despite aggressive D&C activity, suggests continued access to near-virgin shale resource rather than depleted shale resource on the cusp of irreversible ‘bubble-point’ death.
Only time and further irrefutable production data will reveal the truth.
Technology & Innovation Will Remain Key In Maturing US Shale Basins
Diamondback Energy, in its most recent letter to shareholders, stated that ‘Today, geologic headwinds outweigh the tailwinds provided by improvements in technology and operational efficiency.’
Taken alone and, in our view, out of context, such a statement argues that the demise of US shale oil is now inevitable; technological innovation and efficiency improvements are no longer a match for the subsurface.
However, Diamondback Energy’s statement goes on: ‘… Therefore, we believe we are at a tipping point for US oil production at current commodity prices.’
This reference to the oil price is critical – as with all oil basins worldwide, global oil pricing clearly remains the key economic arbiter for US shale.
Necessity being the mother of invention, we are confident that technical innovation will continue to mitigate inevitable cost pressures as US shale basins mature.
A few examples of recent technical and related innovations, all of which should serve to lower D&C costs within maturing US shale basins and elsewhere:
To improve return on investment, Chevron plans to ‘triple-frac’ (ie frac three wells simultaneously) more than half of its new wells in the Permian Basin. While this technique clearly requires greater upfront capital as well as substantial logistics planning for water and proppant, well completion times and costs have to date been cut by 25% and 12% respectively.
nanoActiv®: Patented some 5 years ago, Nissan Chemicals America markets a range of downhole additives that employ inorganic nanoparticles to penetrate and persist within hydrocarbon-bearing reservoirs well beyond alternate products – the result being more effective fracking, higher production levels and improved oil & gas recovery.
Exxon just announced a new proprietary, lightweight proppant engineered from refinery coke that increases Permian Basin well EURs by up to 15%.
The provision of fresh water for fracking and the disposal of brackish produced water are critical issues for operators within the Permian Basin. Both Chevron and Coterra Energy have invested in major water recycling initiatives, repurposing produced water for fracking operations – mitigating disposal costs and reducing the demands on local natural aquifers.
Completion chemicals have been reformulated to be compatible with brackish water and even recycled produced water. As a result, operators can now minimally treat produced water on site at low cost to just remove suspended solids, oil and other contaminants, and then directly reuse the water in subsequent completions – effectively transforming the environmental and logistic challenges of Permian Basin’s high water cut into a distinct environmental advantage.
In mid-March, the US Environmental Protection Agency (EPA) said it would explore alternate markets for recycled produced water to ease future pressure on local aquifers: data center cooling, irrigation, fire control etc.
Also, as we have previously written of, we firmly expect that the continued integration of AI across both drilling and production processes will deliver further efficiency gains – optimization of drilling parameters, early prediction of equipment failure, streamlined production processes – potentially mitigating the growing economic pressure of geological constraints.
Summary
US oil & gas operators’ investment decisions will continue to be determined by price signals, market volatility, incremental returns and shareholder priorities rather than populist ‘Drill, Baby, Drill’ slogans or political growth mandates.
Despite just six oil & gas operators already controlling over 60% of the Permian Basin’s commercial oil resource, industry consolidation will continue, particularly as diminished margins threaten the viability of smaller E&P players within this and other US shale basins. Only the largest, most efficient oil & gas operators will survive over the long term.
The current pressure on US oil & gas operators’ margins is already resulting in lower D&C activity; the resulting lower utilisation of drilling rigs, frac spreads and allied oilfield services will inevitably cascade down to lower OFS margins.
The days of US shale being the global ‘swing producer may be long gone. Furthermore, the continued development of maturing US shale basins will clearly require further migration toward lower-quality Tier 2/Tier 3 acreage, despite greater incumbent risks for both production growth and returns.
We believe that ingenuity, strategy and innovation offer a significant prize to operators with such acreage. Improved subsurface data, bespoke well placement and completion techniques, as well as enhanced oil recovery – all have the potential to enhance returns and well productivity.
It is worth noting that development of Tier 2 acreage within the mature Bakken basin is now growing at 20% year-on-year, twice the rate of its Tier 1 acreage,
Our continued belief in the pivotal role of technical innovation within the oil & gas industry underpins PillarFour Capital’s investment strategy, centred on commercial technology-led companies that require low capital intensity, deliver high returns on invested capital while enhancing the sustainability of oilfield operations – from upstream to midstream and downstream.
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