There is a simple assumption shared by almost everyone who follows oil prices: when a barrel becomes more expensive, an exporting country should benefit twice over – from the higher price and from the incentive to pump more. A new study by researchers at the Federal Reserve Bank of Dallas tested that assumption against real-world evidence, using the 2026 war with Iran as a clean natural experiment. The result challenges this intuition far more forcefully than it may appear at first glance.
On February 28, 2026, the Strait of Hormuz, through which roughly one-fifth of the world’s oil passes, was closed following a strike on Iran. About 15% of global supply vanished from the market almost overnight – more than twice the peak disruption during the 1973 crisis, previously regarded as the largest geopolitical shock in the history of the oil market. The price of WTI surged from an average of $61 to a peak of $115 a barrel. The authors asked an obvious question: how strongly did US producers, which had spent a decade describing themselves as the flexible “swing valve” of the global market, respond by increasing production?
The answer was uncomfortable for the notion that expensive oil means more oil. The monthly and quarterly supply elasticity of US shale oil was effectively zero – 0.02 both in March and over the March-May quarter. In other words, a price increase of almost 42% produced an output gain of less than 1%. This diverges sharply from some of the academic literature published in recent years, which put the elasticity at 0.6 or even within a range of 0.3-0.9. Those estimates implied that a price surge of this scale should have lifted monthly production by 26-37%, equivalent to an additional 2.4-3.5 million barrels a day. Nothing of the kind occurred in any major shale basin. In the Permian and Bakken, which together account for almost 80% of US shale output, elasticity was a meagre 0.01. The only notable exception was the tiny Woodford basin, with elasticity of 0.20. Even there, however, the absolute production increase was just 6,000 barrels a day – statistical noise against the broader picture.
It is worth explaining where the much higher estimates of 0.6-0.9 came from, since they sustained the myth of shale flexibility for several years. The explanation proved to be purely methodological. The authors of those studies included not only the current price in their elasticity formula but also the three-month spread between spot and futures prices, treating it as a signal of expected future price growth. The problem is that when the futures price moves one-for-one with the spot price, as it usually does during a persistent shock, that premium disappears and the elasticity estimate collapses to almost zero. Once recalculated to reflect the actual behaviour of futures in March 2026, the inflated estimate of 0.62 falls to a far more modest 0.12 – and even that remains noticeably higher than the response shown by the production data.
The first reason for this rigidity is purely physical. A regular survey of oil-company executives conducted by the Dallas Fed shows that the typical interval between a decision to drill and first oil is four to six months, while more than half of companies budget more than six months. Satellite data covering more than 21,000 actual wells confirm this: the median time from the arrival of a drilling rig to the start of production is 5.7 months, and only 0.8% of wells begin producing within a month. The speed of the response also depends on company size. Smaller private producers generally move considerably faster than large listed companies, which are more likely to drill entire multi-well pads at once, extending the process.
The industry does have a theoretical reserve for a rapid response: drilled but uncompleted wells, known as DUCs, which can be brought into production relatively quickly. But the numbers are sobering even here. The median interval between a crew arriving at such a well and the start of production is 1.4 months. Allowing for measurement error, only about 6% of wells in this inventory are completed in under three weeks. Across the whole of the United States, there were just 2,357 such wells in February 2026. Achieving the headline elasticity of 0.62 would have required more than 12,000 wells to be completed at once – five times the entire inventory then available. Even the more modest adjusted estimate of 0.12 would have required 2,400 wells to be completed within two weeks, whereas historically only 150-230 wells at most have been completed that quickly. It is also telling that the inventory of uncompleted wells did not shrink in March. It edged up from 2,357 to 2,381, directly contradicting the idea that producers rushed to tap it on a mass scale.
The second reason is expectations. Producers respond not to today’s price but to the price likely to prevail when a new well actually reaches peak output – eight months or more into the future once site preparation, drilling and completion are taken into account. At the end of March 2026, the futures curve showed the price for late 2027 having returned almost to its pre-war level of $67 a barrel, even though the spot price at the time was twice as high. Since the market viewed the shock as temporary, drilling new wells in response made no economic sense. A producer starting a well today would reach peak output just as the price, in the market’s own view, returned to its pre-war level.
This is where the Kazakhstan part of the story begins. The paper does not examine it directly, but its logic points squarely in that direction. The authors emphasise that the supply elasticity of conventional, non-shale oil is widely accepted to be zero. This is not a hypothesis but the consensus across the academic literature, supported, among other evidence, by data on conventional production in Texas itself. Kazakhstan’s oil production is almost entirely conventional. If a shale well that can be drilled and completed in a matter of months, and that has been celebrated as the most flexible asset in the global market, proved so inelastic that even a rapid-response inventory of thousands of ready wells was insufficient to generate a meaningful reaction, then supergiant fields such as Tengiz, Kashagan and Karachaganak are inelastic by an order of magnitude more – and they have no equivalent reserve at all.
The difference lies not in scale but in the nature of decision-making. For a shale company, the response cycle is measured in months and consists of calling a drilling crew, leasing a rig and drilling a well. For a consortium operating Kashagan or Tengiz, the equivalent cycle is measured in years and involves securing agreement among several international partners, revising the budget of a multibillion-dollar project and repeating the engineering work. The Tengiz expansion took almost a decade to prepare and cost tens of billions of dollars, committed long before anyone could have anticipated a specific price shock. This type of production has no equivalent of an “uncompleted well” that can be finished within a couple of weeks in response to news from the Middle East. Nor is there even a theoretical possibility of assembling the required crews and equipment within weeks, as US shale companies can in principle do, albeit on an insufficient scale.
The logic of expectations works even more strongly against a rapid response. If a US producer looks eight months ahead and sees no reason to drill even over that horizon, the operator of a supergiant field looks years ahead because that is the timeframe over which capital invested in such a project must pay back. According to the futures curve, the market regarded the geopolitical shock as temporary barely a month after it began. Such a shock simply cannot alter an investment decision made for decades ahead, no matter how dramatic the immediate price surge may appear.
In Kazakhstan’s case, this physical and investment rigidity is compounded by another constraint that US producers do not face at all: OPEC+ quotas, which limit production volumes regardless of what happens to the price. The result is a double lock on the same door. Even if the physical capacity to raise production sharply existed, the collective agreement would separately prevent the country from using it.
The practical conclusion is simple and worth remembering whenever oil prices jump. A surge in the global price does not translate into additional barrels for Kazakhstan. It merely allows the country to sell already planned barrels at a higher price. The entire increase in revenue for the budget and the National Fund generated by a price shock is a pure price effect, not a volume effect. The limit of that gain is determined not by a desire to pump more, but by the physics of the well, a consortium agreement signed years ago and a quota negotiated at cartel level.
Sultan Valikhanov, EconomyKZ Research Group, exclusively for EconomyKZ.org
