Caution among US shale producers may give way to ramping up activity before service prices escalate, as the global energy crisis triggered by the disruption of transport in the Strait of Hormuz persists.

However, the two-week ceasefire announcement on 7 April between the US and Iran will likely delay many producers’ decisions, as geopolitical volatility once again injects extreme uncertainty into the market.

From ‘wait and see’ to drilling urgency

The response from the US shale sector to high prices driven by the war has shifted gradually over the past few weeks.

  • In the first days of the war, as front-month prices began to spike on the geopolitical risk premium, E&Ps emphasized unchanged plans given the volatility around the situation. Companies have highlighted deep capital discipline over price chasing.
  • As the disruption to volumes in the Strait of Hormuz became more evident, producers embraced a ‘wait and see’ attitude that prioritized hedging and cash harvesting over increased activity.
  • Steep backwardation – where the spot price is higher than the forward price – in the futures curve disincentivizes adding rigs, while depleted drilled-but-uncompleted (DUC) wells and cash on hand prohibits any immediate production spikes to realize $100 per barrel of WTI crude.
  • As it becomes clear that the forward curve does not reflect the magnitude of the supply disruption and prices may be ‘higher for longer,’ some producers have begun to discuss rig additions.
  • With the physical and financial markets disconnected, operators have begun to announce upward guidance revisions.
  • Further announcements are likely on hold as uncertainty caused by the temporary ceasefire announcement reinforces caution.
  • Even if the war ends and the Strait of Hormuz gradually reopens, geopolitical premiums, stockpiling demand and a new transit regime in the strait may keep prices higher for longer.
  • This will likely still create a supportive price environment for shale activity additions during this year.

Continental Resources became the first company to publicly announce plans to add activity.

Founder Harold Hamm said the US independent plans to increase its capital budget by between 15% and 20% this year. With other private E&Ps likely mulling similar moves, and some public players likely to follow during first quarter 2026 reporting in May, the market narrative could quickly change from caution to urgency.

Once some companies add rigs and hydraulic fracturing crews, others are likely to quickly follow in order to lock into contracts before service prices escalate more.

Some publics operators have still publicly singled their intent to keep plans in place even as prices remain volatile, while leaving the door open for activity increases next year, driven by expectations of a more supportive medium-term outlook for supply and demand balances.

These views could quickly change, however, as inevitable cost inflation once companies begin adding rigs could pick up quickly. This would reward early movers by locking in lower service costs and higher spot (or hedged to strip) prices over the first few months of a well’s production. Those that add rigs later could see the benefits of higher prices knocked out by higher D&C costs for the additional wells.

Service price escalation

The oilfield service sector faces the prospect of rapid growth, echoing 2021 when inflation was rampant and discussions centered on super-spec drilling rig availability and E-Fleet term commitments. The current strip pricing encourages the addition of about 30 to 40 rigs and between eight and 12 frac fleets by the end of this year.

Rystad Energy’s view is that this will go hand in hand with around 6% drilling and completion inflation in aggregate. We anticipate the back-end of the futures curve will raise 2027 and 2028 oil prices as Middle Eastern supply disruption drags on.

In a sustained $85 to $90-per-barrel of WTI world, the same basket of drilling and completion categories will see inflation of between 18% and 20%. The most acute categories are land rigs, which could see inflation in the order of 18% to 20%, oil-country tubular goods at 20%, frac services at 18% to 25%, and fuel at 20% to 25%.

Like in 2021, there is a segment of around 82 to 110 rigs that can be practically deployable with varying levels of capital requirements.

As more rigs are added, dayrates will rise to facilitate these additions. The first 15 to 25 rigs will likely require almost no capital, with the final 25 rigs requiring upgrade capital in the millions.

The frac service market is also tighter from a horsepower perspective, with demand in the order of 13 million to 14 million horsepower and supply between 16 million and 17 million horsepower.

Incremental fleet additions will draw from around 3 million warm-stacked horsepower (40 to 60 fleets) that will likely require pumpers to overhaul equipment versus retire it permanently, driving pumping hourly rates higher for operators.

With diesel fuel prices high, premiums for natural gas-capable equipment will rise.

Takeaway

To get a rough assessment of the potential impact of moving later rather than sooner, we have examined a median Permian well.

In Figure 1 below, we show that after 10% well cost escalation, the well’s breakeven is $3.57 per barrel higher. Moreover, the cost escalation is more apparent when comparing the IRRs of the two wells.

The lower cost well would have an IRR of 104% versus 63% for the higher cost well, a difference of 40%.

While both wells would remain commercial, especially in the current price environment, a lagged rig reactivation could limit an operator’s ability to use the higher oil prices to develop lower-tier acreage, one of the tools operators use to preserve tier 1 inventory.