On May 1, 2026, the United Arab Emirates ended its 59-year membership in OPEC. The announcement had come three days earlier, on April 28, with Brent crude well above $100 per barrel after spiking to nearly $120 in early March. What had pushed it there was the war: the United States and Israel had attacked Iran on February 28, and Iran’s retaliation had all but shut the Strait of Hormuz.
Before the war, about 20 million barrels of oil passed through the Strait of Hormuz every day. When Iran began attacking ships and declared the Strait closed in early March, tanker traffic collapsed: by late April, on some days fewer than ten commercial vessels crossed, against roughly 130 a day before the war. Ships anchored offshore and waited. The IEA called it the largest supply disruption in the history of the global oil market, and Goldman Sachs estimated that world inventories were draining at a record 11 to 12 million barrels per day in April.
OPEC+’s response to a 20-million-barrel-per-day chokepoint crisis was to announce, on May 3, an extra 188,000 barrels per day for June. That is roughly a hundred-to-one ratio. Al Jazeera called the move largely symbolic: the Strait’s closure had throttled the Gulf members’ exports, so extra quota could barely reach the market whatever was announced. The seven countries behind the decision kept nudging their targets up month by month through September, then froze them for October and November. Set against the scale of the disruption, the gesture shows where the institution now stands in the oil market: it can adjust at the margins of a price determined elsewhere, by events it neither controls nor influences.
The UAE announced its departure in the same fortnight, and the timing was hardly coincidental: the crisis was showing how little the cartel could do.
The game the cartel is playing
A cartel works like this. A group of producers agrees to restrict output collectively so the price stays above what it would be if they competed freely. Every member benefits from the higher price. But every member also benefits, individually, from selling a few extra barrels at that elevated cartel price — capturing the full revenue from cheating while the cost of price support is spread across all members. If everyone reasons this way simultaneously, everyone cheats, the price collapses, and everyone ends up worse off than if they’d kept the agreement.
This is the prisoner’s dilemma. Cooperation is rational for the group; defection is rational for each individual member. Repeated dealings and the threat of retaliation can hold a cartel together, and the most direct form of that threat is one member large enough to enforce. It needs to be able to cut its own production when others cheat, absorbing the revenue loss itself while threatening that if cheating continues, it will abandon the floor entirely and flood the market, collapsing prices for everyone. The threat has to be credible, and credibility requires an enforcer large enough that its production decisions move the global price and willing to accept significant short-term losses.
OPEC has had exactly one such enforcer across its history: Saudi Arabia. The record on compliance shows how much that role matters.
Between January 2024 and February 2025, seven OPEC+ members together pumped about 300,000 barrels a day above their production targets on average. In April 2025 they pledged compensation cuts spread over the fifteen months to June 2026. Iraq and Kazakhstan, which owed most of them, had already failed to deliver on earlier pledges, and they were the group’s persistent structural violators.
What OPEC+ is, and how it differs from OPEC
OPEC is a formal international institution headquartered in Vienna, with a legal charter and eleven current member states following the UAE's departure. Its members have formal quota obligations, though Iran, Libya and Venezuela are exempt from the current cuts, and submit to the institution's governance structure. OPEC+ is something different: a looser alliance formed in December 2016 that joins OPEC's members with ten non-OPEC producers, most importantly Russia and Kazakhstan, for 21 countries in all after the UAE's exit. OPEC+ has no formal treaty obligations. Enforcement is entirely reputational. A member that violates its OPEC+ quota faces peer pressure and diplomatic friction; it faces no legal remedy, no formal penalty. The UAE was an OPEC member, but the production constraints that limited its output in practice came through OPEC+. When it left both simultaneously, it ended obligations under two frameworks with very different weights.Three hundred thousand barrels a day of persistent cheating was enough to eat into the cuts Saudi Arabia announced, and it told members that targets were optional. For much of this period the cartel worked mostly as a framework for announcing targets that its biggest violators ignored while Saudi Arabia absorbed the consequences.
The enforcer and what it cost
To understand OPEC, start with the years between 1980 and 1986.
Saudi Arabia entered the 1980s producing close to 10 million barrels per day. As non-OPEC producers including Norway, the UK North Sea fields, Mexico, and the Soviet Union kept pumping at capacity regardless of price signals, Saudi Arabia cut, and kept cutting. Every OPEC member trimmed output between 1979 and 1985, but none as deeply as the kingdom, which gave up more than 60 percent of its 1979 production. By August 1985, Saudi output had fallen to about 2.3 million barrels per day. The kingdom had absorbed five years of revenue destruction to hold the price floor, while others collected most of the benefits.
By late 1985, Saudi Arabia had had enough. It reversed course, ramped production, and within months prices collapsed — falling from around $28 per barrel in 1985 to about $14 in 1986. The cartel’s enforcement mechanism had worked in the sense that it prevented an earlier crash; it failed in the sense that it couldn’t be sustained indefinitely, and when it ended, the price collapse was severe because so much supply had been held back.
Zaki Yamani, Saudi oil minister through this entire period, spent 1985 pleading with fellow producers to share the burden. In December 1985 he announced that Saudi Arabia would no longer act as the swing producer.
The mechanism had been rational for the cartel and punishing for the enforcer, so why did Saudi Arabia play this role at all?
Reserve logic gives the first answer. A country with hundreds of billions of barrels in the ground can rationally accept lower revenue today in exchange for higher prices across a long planning horizon. The mathematics work only if the reserve base is large enough and the horizon long enough, and Saudi Arabia meets both conditions.
The fiscal architecture gave the second answer. The Saudi state, from its political settlement and subsidy system to its royal transfers and development spending, was built around sustained oil revenue at managed prices; that was the premise of the national economy. Bloomberg Economics estimated Saudi Arabia’s fiscal breakeven at $94 per barrel; the IMF’s projection for 2025 was about $91 per barrel. Those numbers are what oil needs to cost for the budget to balance, and they reflect decades of state expenditure calibrated to managed prices.
Geopolitical alignment supplied the third. From the 1945 meeting between Franklin Roosevelt and King Abdulaziz aboard the USS Quincy onward, the relationship between Saudi Arabia and the United States was partly structured around Saudi Arabia maintaining stable, accessible oil markets — a commitment with strategic value that translated into US security guarantees. Enforcing OPEC’s price floor served Saudi Arabia’s economic interests and also the broader logic of a geopolitical relationship that American foreign policy had underwritten.
The arithmetic now works against all three. Brent averaged about $69 in 2025 and ended the year near $61 per barrel, $30 to $33 below Saudi Arabia’s fiscal breakeven of $91 to $94. The kingdom ran a budget deficit of 5.8 percent of GDP that year. It can borrow: debt of about 32 percent of GDP leaves some headroom. But borrowing to fund a fiscal gap created by supporting prices that competitors then undercut is not a sustainable strategy.
Saudi Arabia was never a continuous price manager. The mechanism collapsed in 1985-86, ran poorly in the late 1990s, and broke down badly in 2014-2016. What Saudi Arabia provided was the expectation of a floor. Petrostate fiscal architects could plan around a managed-price assumption because Saudi Arabia had periodically demonstrated willingness to enforce it. The planning horizon made sense because the enforcement mechanism had been shown to exist. Both of those things are now in question.
Zaki Yamani and the logic of the 1985-86 production surge
Sheikh Ahmed Zaki Yamani served as Saudi Arabia's oil minister from 1962 to 1986, through the 1973 embargo, the price shocks of the late 1970s and the punishing years of unilateral production cuts in the early 1980s. His predicament captured the paradox: the country best positioned to enforce the cartel floor was also the country that bore the most cost when enforcement required unilateral sacrifice. By mid-1985, Saudi Arabia was producing less than a quarter of what it had pumped in 1980–81 to maintain a price that other producers, OPEC members and outsiders alike, then undercut by refusing to adjust their own output. Yamani was dismissed by King Fahd in October 1986, shortly after the price collapsed. The failure his dismissal marked was built into the cartel: the mechanism that made OPEC work demanded that one country absorb costs the system distributed across all members.The revolution that changed the rules
US shale added a different kind of supply, one that behaves like an involuntary swing producer, responding to price signals individually and collectively without any coordination or cartel loyalty.
Between 2014 and 2019, US crude oil production rose by more than 3.5 million barrels per day. In October 2014, Goldman Sachs spelled out what this meant: US shale’s effective spare capacity had exceeded Saudi Arabia’s. With about 5 million barrels per day of shale spare capacity against Saudi Arabia’s roughly 1.5 million, OPEC had lost first-mover pricing power. The cartel could no longer credibly threaten to flood the market in a way that would break high-cost producers, because American producers were already in the market and responding to prices independently.
Shale’s economic character makes this structural rather than cyclical. A shale well can be drilled, completed, and brought online in months, and suspended as quickly. Producers respond to price without coordinating, and their collective response acts as a ceiling. When oil prices rise toward petrostate fiscal breakeven levels, shale producers ramp up and add supply, and that addition dampens the price rise. The ceiling has no formal agreement behind it, only the aggregate of thousands of individual production decisions in Texas and North Dakota responding to a commodity price signal.
Saudi Arabia’s 2014-2016 response was to try to break it. In November 2014, with Saudi Arabia in the lead, OPEC refused to cut output, leaving its 30-million-barrel ceiling in place and letting prices fall to squeeze high-cost producers — shale included. Brent fell from about $115 per barrel in June 2014 to roughly $26 in January 2016. The strategy had a surface logic: if prices stay low enough long enough, shale producers go bankrupt and exit the market.
The squeeze backfired: shale’s breakeven costs fell steeply through efficiency gains — horizontal drilling techniques improved, completion costs fell, water management got cheaper, and producers learned to extract more from each well. By the time OPEC reversed course and formed OPEC+ in December 2016, US production was already recovering, and the price war had left shale more competitive than before.
The 2016 OPEC+ formation was supposed to fix the underlying problem by enlarging the coalition, bringing in Russia, Kazakhstan, and other major producers so that the combined group could move markets. In practice, adding large producers without enforcement mechanisms widened the circle of members who could ignore their quotas.
Why shale is structurally different from other supply
Conventional deepwater oil fields require years of capital investment before a drop of oil is produced. Once built, they run at capacity because the marginal cost of stopping is higher than the marginal cost of continuing. Shale is the opposite. The upfront cost per well is relatively modest, the time from decision to first production is measured in months, and wells can be idled when prices fall below operating costs. This means shale supply is price-elastic in a way conventional supply is not: it expands when prices rise and contracts when they fall, with a lag measured in quarters rather than years. For OPEC, this creates a lasting problem. Any time the cartel successfully raises prices, it signals shale producers to expand, and that expansion pushes against the rise, though capital discipline and geology keep the response well short of unlimited.The coalition that can’t hold
OPEC+ made the enforcement problem structurally worse, because the new members brought fiscal and strategic logics incompatible with Saudi Arabia’s.
Russia’s cash costs for pumping existing fields and moving the oil to an export terminal run about $13 to $14 per barrel — low by international standards. Saudi Arabia’s are lower still: Aramco puts its all-in cost, lifting plus capital spending, at about $11.50 per barrel of oil equivalent. On production costs alone, both countries could ride out a price war. Fiscal architecture is what separates them.
On 2025 estimates, Saudi Arabia needs oil at about $91 to $94 per barrel to balance its budget. Russia is running a war. Its 2026 budget was drawn up around Urals crude at $59 a barrel, yet the head of Sweden’s military intelligence service argued in April 2026 that Russia would need Urals above $100 for at least a year just to close its budget gap. Either way, Russia’s wartime fiscal logic pulls it toward volume.
Running a war economy means maximizing revenue now. Revenue is price times volume, and Russia did sign up to an extra voluntary cut of 471,000 barrels a day in 2024, but a war budget makes Moscow wary of trading barrels today for a higher price that may not come, which leaves Saudi Arabia and Russia with requirements that are hard to reconcile.
Russia’s oil and gas revenues fell about a quarter in 2025 versus 2024, to around 8.5 trillion rubles. Urals crude fell below $40 per barrel in December. Russia was producing under heavy pressure, from sanctions on its tanker fleet and Ukrainian attacks on oil infrastructure. It tracked its OPEC+ target fairly closely, and from August 2025 its output began slipping below it, a gap that later widened to as much as 400,000 barrels a day as Ukrainian drone strikes shut down offshore fields. What Russia has no reason to do is volunteer deeper cuts: with revenues collapsing, every barrel withheld to prop up the price is revenue a war budget cannot spare.
Nor can Saudi Arabia credibly threaten Russia with a price war. Russian oil keeps flowing at prices that would wreck Saudi Arabia’s budget, and a government at war has little room to cut volumes for long. If Saudi Arabia abandons its own quota and floods the market to discipline Russia, as it disciplined OPEC cheaters in 1985-86, its fiscal breakeven problem becomes catastrophic while Russia’s wells keep pumping. The threat that underpins cartel enforcement doesn’t work when the target of the threat has no room to give way and the enforcer has more to lose.
This is the 1985 problem rebuilt on worse architecture. In 1985, when the swing-producer role became unsustainable, Saudi Arabia abandoned it and crashed the price. In time the market found a new equilibrium, one in which Saudi Arabia maintained a less punishing enforcement posture. The difference now is that no new equilibrium is available through a managed transition. Shale as a standing brake on prices, Russia as a reluctant cutter and an energy transition that is reducing long-run demand growth together mean the floor that enforcement used to create cannot be rebuilt through the same mechanism.
By May 2026, Saudi Arabia had effectively been stripped of its most capable enforcement ally within OPEC. When the UAE left, Saudi Arabia was left carrying the enforcement burden, with only smaller partners such as Kuwait, against a coalition structurally incentivized to produce at maximum.
Why the UAE left, and what its exit says
The UAE’s arithmetic is very different. S&P Global puts its fiscal breakeven at about $42 per barrel, less than half Saudi Arabia’s.
The gap is the product of two decades in which the UAE deliberately built an economy that isn’t dependent on high oil prices. In the first quarter of 2025 the non-oil sector reached a record of more than three-quarters of GDP, and over the full year non-oil output grew almost 7 percent. Dubai’s tourism, financial services, logistics, and real estate sectors have become the economy, with oil as a legacy income stream.
From that position, OPEC’s quota system looked different than it does from Riyadh. The Abu Dhabi National Oil Company, ADNOC, approved a $150 billion five-year capital plan for 2023 to 2027 and brought its 5-million-barrel-per-day capacity target forward to 2027; UAE production capacity had already reached roughly 4.85 million barrels per day. The UAE’s OPEC+ quota was about 3.5 million barrels per day. At $60 a barrel, the 1.35 million barrels a day of unused capacity add up, as an order-of-magnitude figure, to roughly $30 billion a year in forgone income. The UAE built production capacity it couldn’t use while paying the price-support costs of a system whose floor Saudi Arabia needed far more.
UAE officials and ADNOC leadership had for years referenced a more direct argument: the need to monetize reserves before the energy transition makes them worth progressively less. This is the stranded asset logic applied to sovereign oil policy. If demand does decline over the long run, delaying production to sustain a cartel price imposes a permanent opportunity cost on reserves that will be worth less in the future, and the rational response is to produce more now. It is a bet Abu Dhabi is entitled to make, even though OPEC itself still sees consumption climbing to about 124 million barrels a day by 2050.
Qatar left OPEC effective January 1, 2019, saying it wanted to concentrate on its natural gas strategy and expand LNG output. Qatar’s departure attracted attention but limited alarm: its oil production was a small fraction of OPEC’s total output, and its contribution to enforcement was negligible.
The UAE’s departure matters far more. The UAE had its own lapses: it, too, had overshot its target and still owed compensation cuts in 2025. But it carried real cuts alongside Saudi Arabia for years and stayed inside the system as Riyadh’s most capable partner. Officially, Abu Dhabi said only that a review of its production policy and capacity had concluded it needed the freedom to pump toward 5 million barrels a day. Its exit removes the second pillar of the enforcement structure OPEC had.
What the floor was holding up
The numbers that matter most here are the fiscal breakevens, the oil price at which each petrostate’s government budget balances.
In 2025 S&P Global put Nigeria’s fiscal breakeven at about $86 per barrel and Iraq’s nearer $99, while the IMF projected Iraq’s at about $92 for 2025. For Saudi Arabia, the IMF puts it at about $91 and Bloomberg Economics at $94.
In April 2026, Goldman Sachs raised its fourth-quarter 2026 Brent forecast to $90 per barrel, citing the prolonged Hormuz disruption. At $90, Nigeria clears its breakeven, Iraq comes up about $2 short and Saudi Arabia $1 to $4 short. Prices have since run even higher, but a high price is little help to a producer that cannot ship. For much of 2026 most of the barrels of Iraq, Kuwait and the Gulf’s other exporters were trapped behind the Strait. Saudi Arabia, which rerouted crude through its East-West pipeline to the Red Sea, came out with a windfall. Even a geopolitical shock that threatened 20 million barrels per day of supply did not hand OPEC’s most important members a durable fiscal cushion.
The pre-Hormuz structural baseline is more telling. Brent closed 2025 at about $61 per barrel, a price set by underlying supply and demand before Iranian forces threatened the Strait. At that price Nigeria is $25 short of its breakeven, Iraq $31 and Saudi Arabia $30 to $33.
Shale helps explain why that baseline is what it is. Whenever oil prices approach petrostate fiscal breakeven levels in the $86 to $99 range, US shale producers respond to the price signal, expand output, and push prices back down. This has already happened: the mechanism played out in 2014 and again in 2018, when American output jumped by well over a million barrels a day in a single year. OPEC struggles to punch through it by restricting production, because the restriction itself raises the price that triggers shale expansion.
Previous price crashes, in 2014 to 2016 and in 2020, were cyclical. Demand fell, or supply surged, and eventually the equilibrium corrected. Petrostates survived through borrowing, reserve drawdowns, and waiting for the cycle to turn. This time several structural features are operating at once. Shale keeps pressing on the upside in every cycle, not just one. The energy transition is reducing long-run demand growth: even OPEC, the most bullish of the major forecasters, has demand adding only about 0.8 million barrels a day per year on average between 2025 and 2050. And the enforcement mechanism that used to create the floor is absent.
Venezuela: the demonstrated endpoint
Venezuela was pumping roughly 3.4 million barrels per day in the late 1990s. By 2020, output had fallen to around half a million barrels per day, a collapse of more than 80 percent. Even after a partial recovery, it averaged just under a million barrels a day in 2025. The trajectory illustrates the political economy of petrostate fiscal failure at its most extreme. The damage started early: nearly 20,000 skilled oil workers were fired in the early 2000s, and years of mismanagement and underinvestment followed. When oil revenues collapsed after 2014, Venezuela's government faced a choice between cutting the expenditures that maintained political compliance or borrowing against collapsing assets. It did neither effectively. It printed money, and US sanctions from 2019 deepened the slide in production. Hyperinflation erased savings; the political settlement collapsed along with the economy. Venezuela's story is often treated as exceptional, the product of specific political pathologies under Chávez and Maduro, and it is exceptional in its severity. But part of the mechanism is generic, and Venezuela met it early: a petrostate whose fiscal system was calibrated to managed prices meets a structural price decline without the fiscal flexibility to adjust.The political dimension of petrostate fiscal stress is not separable from the economic one. Beyond export income, oil revenues are the material substrate of political order. Subsidies, public sector employment, infrastructure spending, and in many cases direct transfers to citizens are funded by oil rents. When those rents fall and stay low, governments have three options: cut the spending that maintains political compliance, borrow against depleting assets, or attempt the economic diversification that takes decades to execute and requires exactly the stable revenue stream that is disappearing.
Saudi Arabia is attempting all three at once: the Vision 2030 program is real, the borrowing capacity exists at 32 percent debt-to-GDP, and the spending cuts are being made. Iraq and Nigeria lack both the fiscal headroom and the institutional capacity for equivalent adjustment. When the IMF concluded its 2026 review of Saudi Arabia in July, it found that the war had handed the kingdom an oil-revenue windfall, yet still called for medium-term fiscal consolidation alongside the Vision 2030 reforms.
When the shooting stops
The Strait has already reopened once. A US–Iran interim deal in June sent tankers streaming out of the Gulf and pushed prices below their pre-war level by early July — until the ceasefire broke down on 7–8 July and the waterway effectively closed again. By September, Gulf crude exports had climbed back above three-quarters of pre-war levels, but renewed attacks, including the 11 September bombing of Saudi Arabia’s East-West Pipeline, had Brent futures back around $107 by mid-October 2026. When the shooting finally stops, the Hormuz premium is likely to drain away, though more slowly than in June: drained inventories and damaged refining will keep parts of the market tight well into 2027. US shale and the other fast-growing producers of the Americas, which kept adding barrels throughout the crisis, will cap the upside. The equilibrium that reasserts is likely to look something like the pre-crisis baseline: Brent somewhere in the $60s, petrostate budgets in deficit, and OPEC announcing production decisions that the market acknowledges and then mostly ignores.
What the Strait crisis revealed, and what the UAE’s departure confirmed, is the permanent absence of the mechanism that used to operate between the extremes. There has always been volatility: $30 oil in 2016 and $130 oil in 2022. Within that volatility OPEC used to provide something short of a fixed price: the expectation that Saudi Arabia would periodically defend a minimum. Petrostate fiscal architects built their systems around that expectation. It was never guaranteed, but it had been demonstrated enough times to be plannable.
The enforcer has changed its own arithmetic. The war has handed Riyadh a temporary windfall, but a kingdom that needs $91 to $94 a barrel to balance its budget cannot go back to absorbing the revenue cost of unilateral production cuts at the $61 the market paid at the end of 2025, while Russia pumps at volume and shale caps the upside. It can still announce cuts, publish targets, convene OPEC meetings and issue communiqués. What it can no longer do credibly is threaten a price war that would cost it more than it costs the members it’s trying to discipline.
The market has acquired two swing producers that don’t follow cartel logic: US shale, which responds to price signals without coordination, and Russia, which responds to wartime revenue imperatives without diplomatic constraint. And the UAE, the Gulf partner with the most fiscal room and spare capacity to share enforcement costs, has now left.
Don’t expect a formal OPEC dissolution. OPEC will continue meeting, issuing statements, publishing forecasts, maintaining its Vienna headquarters. What is ending is the political guarantee that managed pricing would make petrostate development models viable across the planning horizons governments need to build states around. That guarantee was conditional on Saudi Arabia’s periodic willingness to enforce it.
What follows is price discovery in a market that petrostate fiscal systems were never designed to handle — a market that ranges from $30 to $130 depending on whether a military conflict is threatening a single strait, where the upside is geopolitically driven and temporary, and the structural pressure runs consistently downward.
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