Iran War Escalates, Hormuz in Crisis: Where Are the Real Opportunities in US Oil Stocks as Crude Spikes?

On February 28, the United States and Israel launched joint military strikes on Iran. Within two trading days, Brent crude jumped from 72 dollars to over 85 dollars, a gain of more than 15%. The Dow plunged 1,100 points, the S&P 500 fell 2%, and nearly every sector was bleeding.

Oil stocks were rising.

ExxonMobil briefly hit a record high of 159 dollars. Occidental Petroleum climbed on the very day the Dow crashed. A war taking place 8,000 kilometers away has quickly turned into a very real question for US equity investors: how much further can oil stocks run? Is this just a short‑term sentiment spike, or the opening chapter of a much bigger story?

To answer that question, you can’t just stare at the Strait of Hormuz. The strait is obviously critical, around 15 million barrels of crude and 5.5 million barrels of refined products pass through it every day, roughly 20% of global seaborne oil trade—but if you build an entire investment thesis on whether the strait is closed or not, you’re reducing a structural story to an event‑driven gamble.

What really matters is this: the Iran–US conflict has merely lit a fuse that was laid long ago. Even before the war, the fundamentals of the oil market were shifting in profound ways—global upstream spending has fallen for two consecutive years, natural decline rates are accelerating, US shale’s cost curve is moving higher, and the Strategic Petroleum Reserve is sitting near historic lows. These forces were already pushing oil stocks higher long before the first missile hit. The war simply forced everyone to see them at the same time.

The Insurance Blockade of Hormuz: Not About Missiles

Let’s start with the strait, because it is the immediate trigger for the latest spike in oil prices.

A counter‑intuitive fact: the Strait of Hormuz has not been physically blockaded by the Iranian navy in a strict military sense. The Islamic Revolutionary Guard Corps declared the strait effectively closed and threatened to sink passing vessels. But what really paralyzed Hormuz was the insurance market. Global marine insurers rushed to cancel war‑risk cover or raise premiums to prohibitive levels. Over 100 tankers ended up at anchor in and around the Strait of Hormuz, and shipping was brought almost to a standstill. It’s not that ships can’t sail; it’s that no one dares to insure them. In practice, that amounts to a commercial blockade.

What’s less appreciated is that Ras Laffan in Qatar—the world’s largest LNG export hub—also lies inside the strait. After Iranian drone strikes, Qatar’s national oil company, QatarEnergy, not only shut down LNG production at Ras Laffan, it also announced a halt to domestic production of several downstream products, including urea, polymers, methanol, and aluminum. This means the impact radius of Hormuz goes far beyond crude oil, already spilling over into global natural gas, chemicals, and metals supply chains. At one point, European gas futures spiked roughly 40–50% in a single session, one of the largest one‑day moves in recent years.

The odds of a prolonged physical closure of the strait are low—Iran itself depends on Hormuz to import refined fuels, and two US carrier strike groups are already on station. But the insurance blockade alone is deadly enough: as long as underwriters don’t restore war‑risk cover, most tankers won’t transit, and the effect on supply is almost indistinguishable from a naval blockade. And the time it takes for insurance markets to regain confidence is often longer than the time it takes to reach a ceasefire on the ground.

Against this backdrop, OPEC+ announced a 206,000 barrels‑per‑day production increase starting in April, in an attempt to signal supply is under control. The irony is obvious: Saudi Arabia and the UAE together hold roughly 2–2.5 million barrels per day of spare capacity, but those barrels also need to exit via Hormuz. When the strait itself is the bottleneck, spare capacity on paper is of limited help in the short run.

These are short‑term variables. The bigger problem is that they are piling on top of fundamentals that were already tight.

Five Fuses: Fundamentals That Were Lit Long Before the War

By the time the strikes began on February 28, the energy sector was already leading the US market in 2026 with a gain of roughly 20% year‑to‑date. Brent had climbed from under 60 dollars in early January to 72 dollars before the first missile. If you attribute the entire move in oil stocks to the war, you’re making a serious attribution error.

The war is a catalyst. The fuel was in place long before. At least five fuses had been lit well before the shooting started.

Fuse 1: Global Upstream Investment Has Fallen for Two Straight Years

After the last cycle of 100‑dollar oil plus frantic capacity expansion ended in massive value destruction—and with the added pressure of energy transition narratives and ESG—global oil and gas companies have shifted from growth at all costs to returns first. The result: upstream capex has persistently run below what future demand would require.

This may be the single most important and yet most overlooked element in the entire oil fundamental picture.

Global upstream oil and gas investment in 2025 was about 420 billion dollars, down 2.5% year‑on‑year. Wood Mackenzie expects another 2–3% decline in 2026, leaving spending more than 5% below 2024 levels. Combined with IEA decline‑rate analysis, the industry would need around 600 billion dollars of upstream investment annually just to maintain current global supply. In other words, actual spending is only about 70% of what’s needed.

Even BP—long held up as a poster child of aggressive transition away from oil and gas—has admitted in its latest strategy update that it has underinvested in its core oil and gas business in recent years, and is now re‑allocating more capital back to upstream.

IEA executive director Fatih Birol is blunter: “Close to 90% of upstream investment today is just to offset declines from existing fields, and less than 10% goes to meeting new demand. The industry has to run faster just to stand still.”

The consequences of underinvestment don’t show up overnight. They behave more like a chronic disease that manifests three to five years down the line. When it does surface, the amount of new capacity you can quickly bring online is severely limited. This is the core of the oil bull case: regardless of short‑term price gyrations, the supply side is accumulating an ever larger deficit.

Fuse 2: Global Field Decline Rates Are Accelerating

The IEA’s latest study, based on production data from 15,000 fields, finds that conventional oil fields decline at an average of 5.6% per year after peak; deepwater fields decline at over 10%. If all investment into existing fields stopped, global oil production would shrink by roughly 5.5 million barrels per day every year—equivalent to losing Brazil and Norway combined. In 2010, that number was closer to 4 million barrels per day.

US shale is even more brutal. If you stop drilling new wells, production at shale fields can fall by more than 35% in the first year and another double‑digit percentage in the following year. Shale is a machine that must be constantly fed capital; when capex slows, volumes fall off a cliff.

By contrast, super‑giant conventional fields in the Middle East decline at less than 2% per year. That points to a dangerous trend: global supply is becoming ever more concentrated in OPEC countries and Russia. The IEA estimates that, on current investment and project‑approval trends, their share of global oil production could rise from around 43% today to over 65% by 2050. Against that backdrop, the political slogan of energy independence looks increasingly fragile.

Fuse 3: The Permian’s Evolution and Limits

On the US shale map, the Permian Basin is the undisputed center of gravity. Straddling West Texas and eastern New Mexico, it is the country’s largest oil field and accounts for roughly half of US crude output growth. In 2025, Permian production reached around 6.76 million barrels per day—close to half of total US crude production. Over the past decade, a large share of the world’s swing supply has come out of this basin.

Production has hit record highs, but month‑over‑month growth has clearly flattened. The narrative that Permian is peaking is gaining traction. Research by Gorozen estimates that, defining Tier 1 sweet spots as locations that are profitable at WTI 50 dollars or lower, around 60% of this top‑tier inventory has already been developed. Eagle Ford and the Bakken saw growth stall and never recover once they hit similar development levels around 2018.

There are subtler signals as well. Single‑well productivity gains are slowing; operators are drilling three‑mile laterals to achieve what two‑mile wells could deliver just a few years ago. Basin‑wide gas‑oil ratios have moved noticeably higher over the past decade, suggesting that reservoirs are becoming gassier and less oil‑rich. At the same time, the volume of produced water per barrel of oil and the cost of handling that water have both risen. Water is quietly becoming one of the fastest‑growing line items in the Permian cost structure.

But peaking does not mean collapsing. ExxonMobil’s cube‑development approach—drilling multiple stacked horizons from a single surface pad, optimizing spacing and minimizing interference—allows it to produce the same reserves with roughly 20% fewer wells. Combined with new lightweight proppants that increase recovery, management expects project values to rise by over 20% and per‑well development costs to fall materially. Exxon now targets doubling Permian output to around 2.5 million barrels of oil equivalent per day by 2030, without increasing overall capex. Occidental, for its part, is betting on CO₂‑EOR to give shale wells a second life. Its unconventional pilots have delivered 5–10% incremental recovery, and the company plans to launch three commercial CO₂‑EOR projects in 2026, with about 30 more in the pipeline.

Net‑net, the Permian is unlikely to repeat the days of adding 1–1.5 million barrels per day of new supply each year. But with technology and consolidation by large operators, it is entering an industrialized stability phase. The EIA still expects Permian output to hold around 6.5 million barrels per day in 2026 at current price assumptions. For the global market, shrinking marginal growth itself is a structural support for long‑term prices.

Fuse 4: Shale Breakevens Are Moving Up the Cost Curve

Enverus forecasts that the marginal breakeven for US shale today is around 70 dollars per barrel WTI. As core sweet spots are exhausted and producers are forced into lower‑quality Tier 2 and Tier 3 acreage, that marginal cost could rise to around 95 dollars by 2035—an increase of more than 30% over a decade. Steel tariffs and inflation are adding fuel to the fire. On tubular goods alone, tariffs add roughly 64,000 dollars per well, almost 10% of a typical drilled‑and‑completed cost, while the much‑touted regulatory relief translates to less than 1 dollar per barrel in savings.

A recent survey of over twenty listed producers shows a combined 2‑billion‑dollar cut in capex plans after mid‑2025. That’s a self‑reinforcing loop: costs rise → companies cut spending → future volumes shrink → supply tightens → price support builds.

At the same time, the cost curve is highly differentiated. Low‑cost producers enjoy breakevens far below the industry marginal cost: Diamondback Energy’s corporate breakeven is around 37 dollars per barrel; Chevron’s overall cash‑flow breakeven sits in the 30–40 dollar range; Devon Energy’s is roughly 45 dollars. That means in a high‑price environment, low‑cost producers have enormous profit leverage, while high‑cost producers tread water at the breakeven line. Rising industry concentration is channeling more and more economic rent toward the top of the cost curve.

Fuse 5: The Strategic Petroleum Reserve Is Still Low

The US Strategic Petroleum Reserve currently holds about 415 million barrels of crude—58% of its 714‑million‑barrel authorized capacity. In 2022, to blunt the post‑Ukraine oil price spike, the Biden administration drew the SPR down from around 600 million barrels to roughly 360 million, the lowest level since the 1980s. The Trump administration has been slowly refilling for the past year, but the gap to historical highs remains large.

In the face of the latest price surge driven by the Iran conflict, the Trump administration has explicitly said it is not planning any immediate SPR release. Officials have floated ideas for a phased price stabilization framework, but SPR sales are not on the table.

At 58% full, the SPR’s buffer capacity is limited. At the maximum designed drawdown rate of about 4.4 million barrels per day, it could sustain that level of release for roughly 90 days, after which the sustainable draw rate begins to fall as caverns empty. If you deploy the SPR now, you may have no cards left to play if the conflict escalates. But if you refuse to use it, the market never gets the comfort of visible government intervention, and the geopolitical risk premium embedded in prices becomes harder to erase. That dilemma is itself part of how the market is pricing oil right now.

Buffett’s Occidental Bet: Why He May Be Right Again

String all of these fuses together and then look at Warren Buffett’s Occidental Petroleum (OXY) position, and it stops being mysterious.

Berkshire Hathaway owns over 28% of OXY, making it the company’s largest shareholder, and in late 2025 agreed to buy OxyChem—Occidental’s chemical unit—for 9.7 billion dollars in cash, further turning OXY into a pure‑play oil and gas company.

When Buffett first backed OXY in 2019 with preferred stock and warrants, the market didn’t understand it. When oil prices briefly went negative in 2020, the investment looked like a joke. In 2025, when OXY fell more than 30% from its highs, Berkshire didn’t trim; it bought more. Seven years on, it’s clear he’s not betting on where oil trades next quarter. He’s betting on all of the structural forces we just walked through.

OXY’s corporate breakeven is around 38 dollars per barrel, with roughly 84% of its resource base economic below 50 dollars. Even in a severe downturn, it can still generate positive cash flow. After selling OxyChem, the company plans to use the bulk of the 9.7‑billion‑dollar proceeds to pay down debt, saving hundreds of millions per year in interest and further amplifying its leverage to oil prices. Based on management’s own sensitivity, at current production levels each 1‑dollar move in WTI translates into roughly 200–300 million dollars of incremental annual cash flow. A 10‑dollar move is worth 2–3 billion dollars of earnings swing. Layer on its leading CO₂‑EOR capabilities and the STRATOS direct air capture project, and OXY effectively owns both the cash flows of old energy and an option on new energy.

What’s interesting is that OXY’s current share price—around 50‑plus dollars—is broadly below many estimates of Buffett’s blended entry cost. The world’s most famous capital allocator has been buying and holding at higher prices without selling a share, while the market is offering the same asset to new investors at a discount. Whether he ends up making another huge profit here is something only time can answer.

In a sentence, what Buffett sees is this: in a world of accelerating field decline, chronic underinvestment, rising shale costs, and ever‑present risks to seaborne supply, US onshore oil assets with low costs and no chokepoint exposure deserve a geopolitical premium.

The Landscape: Same War, Different Winners

Once you understand the fundamentals, you can look at individual names. This isn’t a stock‑picking list; it’s a map of how different companies are positioned where geopolitics and fundamentals intersect. Under the same oil stocks benefit from war headline, each company’s win condition is very different.

ExxonMobil (XOM) is steadily morphing into an oil‑tech company. After acquiring Pioneer, it controls over 1.4 million net acres and about 16 billion barrels of oil equivalent of resources in the Permian, with expected annual synergies raised to over 3 billion dollars, driven by cube development, extra‑long four‑mile laterals, proprietary proppants, and other technologies competitors can’t easily copy. In Guyana’s Stabroek block, daily production has reached 900,000 barrels and is targeted to hit roughly 1.7 million barrels per day by 2030 across eight FPSOs. Exxon is buying back around 20 billion dollars of stock per year, with a dividend yield near 2.7%. Its core value lies in being one of the very few companies that can double production in a super‑basin without significantly raising total capex. Geopolitical premia are just icing on that cake.

Chevron (CVX) is playing a different game. It leans less on tech sizzle and more on portfolio breadth and dividend certainty. Its 53‑billion‑dollar all‑stock acquisition of Hess delivers 30% of Guyana’s Stabroek block—a once‑in‑a‑generation asset by most accounts. In Q4 2025, Chevron generated 10.8 billion dollars of operating cash flow, up from 8.7 billion a year earlier, and about 33.9 billion dollars for the full year. Adjusted free cash flow in the quarter was up roughly one‑third despite oil prices being lower than in 2024. In the Permian, Chevron’s breakeven sits around 30–40 dollars per barrel, and it has committed to maintaining about 1 million barrels of oil equivalent per day of Permian output through 2040. The company has raised its dividend for 39 consecutive years; after the latest hike to 1.78 dollars per quarter, the yield sits around 3.7–3.8%. If XOM is the offensive play in the energy sector, CVX is the defensive cornerstone.

Diamondback Energy (FANG) is a pure‑blood Permian racehorse, with far more torque to oil prices than the integrated majors. In Q4 2025 it reported 3.38 billion dollars of revenue and around 1 billion of free cash flow (1.2 billion on an adjusted basis), returning more than half of that to shareholders via dividends and buybacks. But the most interesting angle isn’t just its price leverage; it’s a structural improvement few talk about. Diamondback currently has about 350,000 MMBtu per day of firm long‑haul gas transportation commitments, and management expects that to rise to roughly 800,000 MMBtu per day as new pipelines come online. The long‑standing headache in the Permian has been WAHA basis discounts—pipeline bottlenecks have forced operators to sell associated gas at steep discounts or even negative prices locally. More pipe capacity means more gas can reach higher‑priced markets, lifting realized revenue per barrel of oil equivalent without relying on higher oil prices.

Devon Energy (DVN) has a core catalyst in its all‑stock merger with Coterra. The combined company will have an enterprise value of about 58 billion dollars, with closing targeted in Q2 2026. Post‑merger, Devon will operate across Delaware (Permian), Williston, Eagle Ford, Anadarko, Marcellus, and other basins, and plans to authorize over 5 billion dollars in share repurchases once the deal closes. Its corporate breakeven is in the low‑ to mid‑40s per barrel WTI. At 80‑dollar Brent, the profit pool is nearly as large as the breakeven itself, providing substantial upside and a comfortable cushion. The appeal is the combination of low valuation, M&A synergies, and basin diversification—a rare offense and defense in one profile in a highly volatile market.

ConocoPhillips (COP) is the world’s largest independent E&P, and the purest upstream flagship without refining and marketing baggage. Its 22.5‑billion‑dollar takeover of Marathon Oil brings in more than 2 billion barrels of additional low‑cost resource (under 30 dollars per barrel) and at least 500 million dollars per year in synergies, further deepening its low‑cost inventory in the US and Africa. COP’s internal plan is to push its dividend plus sustaining capex breakeven down to just above 30 dollars per barrel before 2030. Even if Hormuz fully reopens and oil slides back to the 60–65‑dollar range, its ability to generate free cash flow and fund dividends and buybacks is largely intact. Unlike many peers, COP’s assets are spread across the Permian, Eagle Ford, Montney, the North Sea, Alaska, and Qatari LNG. It’s not betting on any single price scenario or geopolitical story; its underlying logic is simple: as long as global demand stays above 100 million barrels a day, someone will buy the lowest‑cost barrels.

Finally, there are the oilfield service companies—often overlooked. Halliburton (HAL) and Schlumberger (SLB) don’t sell oil; they provide drilling, completion, logging, and stimulation services. The more drilling and completion activity there is, the more money they make. Historically, in post‑war rebuilds and capex up‑cycles, it’s often the service names, not the producers, that feel the spring breeze first. If one tail‑risk outcome of the current Iran–US conflict is that Iranian fields partially reopen to Western capital and technology, a country with the world’s second‑largest gas reserves and fourth‑largest oil reserves—yet decades behind on maintenance—would be a dream client for HAL and SLB. Even if that never happens, accelerating global decline rates alone imply structurally rising demand for maintenance, workovers, and enhanced recovery. As long as fields keep declining, the service order books have a structural reason to grow thicker.

After the Risk Premium Fades

All price spikes driven by geopolitics eventually face the same question: what happens when the war ends?

A conservative base case puts medium‑term Brent somewhere around 65 dollars. That assumes a relatively quick resolution, OPEC+ adding barrels, and demand growing modestly. But even if that entire assumption set proves correct, none of the five fuses we discussed goes away. Upstream spending is still drifting lower, decline rates are still accelerating, the Permian’s Tier 1 inventory is still being chewed through, shale costs are still rising, and the SPR is still half‑full.

The more likely scenario is that even after the current war premium washes out, the floor for oil prices ends up higher than most expect—because the floor itself is rising.

And if the conflict doesn’t resolve quickly? Even with a ceasefire, insurance markets will need time to regain confidence, tankers will need time to be rerouted, and damaged infrastructure will need time to be repaired. This high‑friction period could last for months—long enough for elevated prices to show up in corporate earnings as real, not just notional, excess profits.

The world consumes more than 100 million barrels of oil every day. Roughly one‑fifth of that flow passes through a narrow and fragile strait that can be cut by the threat of a drone and the cancellation of an insurance policy. Beneath Texas and New Mexico, each barrel from the Permian faces no straits, no war‑risk riders, no chokepoints—only its own geology and cost curve. For the leading operators, those cost curves still sit well below today’s prices. That’s why they can keep capex and shareholder returns steady even as headlines scream war.

What’s truly driving the repricing of these assets are structural forces that have been in place for years. The Iran–US war is not the beginning of this story. It’s merely the moment when everyone was forced to look up and pay attention.

Disclaimer: This article is for informational and industry‑analysis purposes only and does not constitute investment advice. Oil prices and equity markets are highly uncertain. Investors should make independent decisions based on their own circumstances and, where necessary, consult licensed professional advisers.