Which crude refiners make the most money when oil prices move?

A refinery buys crude and sells a basket of fuels. Its fortunes depend less on the oil price than on the gap between the cost of crude and the prices of gasoline, diesel, jet fuel and other products. This theme links oil-producing states and companies, refinery operators, regulators, transport networks and the motorists, airlines, shippers and factories that buy finished fuels. It matters in 2026 because the war around the Strait of Hormuz has made finished fuels scarcer than crude, lifting Atlantic Basin refining margins to records. When product prices rise faster than crude, the clearest beneficiaries are reliable, complex, well-supplied independent refiners such as Marathon Petroleum $MPC and Valero Energy $VLO. Integrated producers such as Exxon Mobil $XOM and أرامكو السعودية Saudi Aramco $2222.SR can earn more overall when oil rises, but refining represents a smaller share of their businesses. A crude-price jump alone can squeeze refiners before wholesale and retail fuel prices adjust; inventory gains can temporarily make that squeeze appear more profitable.

A barrel, a drill and a problem nobody had solved

On Saturday, August 27, 1859, a steam-driven drill on the banks of Oil Creek near Titusville, Pennsylvania, reached sixty-nine and a half feet. The following Sunday, the driller William Smith, known locally as “Uncle Billy,” looked down the iron pipe lining the hole and saw oil standing five inches from the top. He sent word to Edwin Drake, the man in charge, who waited until Monday to inspect it.¹

Drake was an unlikely industrial founder. Born in New York in 1819, he had worked as a hotel clerk in Michigan and as a conductor on the New York and New Haven Railroad from 1850 to 1857, when poor health forced him to retire. He invested about $200 of savings in the Pennsylvania Rock Oil Company, which sent him to inspect land near Titusville in December 1857. His report led to a new venture, with Drake appointed chief engineer for production.¹

His problem was mechanical: groundwater repeatedly collapsed the walls of the hole. Drake drove fifty feet of cast-iron pipe into the bore to support its sides, an approach that made oil drilling repeatable. After spending $2,500 without finding oil, the company’s officers ordered him to stop. Drake had borrowed $500 from a bank in Meadville and continued.¹

The National Park Service’s nomination calls the site the world’s first oil well. Because petroleum had long been collected from natural seeps, a more precise description is that it helped launch the commercial American oil industry. Titusville became the centre of US oil production for roughly a quarter-century, but Drake captured little of that value. The company removed him as president in March 1860; he lost his savings in New York by 1866 and spent his final years on a pension from the Commonwealth of Pennsylvania before his death in 1880.¹

The lesson is central to refining: the person who makes the barrel abundant does not necessarily capture the value created after it leaves the ground.

The first refinery was a sorting house

Crude oil from the ground is a mix of molecules, from small and volatile compounds to long, waxy ones. Early refiners boiled it. Distillation separates the mixture by temperature: lighter components vaporise first, heavier ones later, and the resulting fractions can be sold separately. In the 1860s, kerosene for lamps was the prize.

But distillation only sorts molecules; it does not change them. If a crude contains little of the fuel customers want, a simple still can produce only a limited amount. Modern refineries go further, breaking and rebuilding molecules with heat, hydrogen and catalysts. They consume substantial energy in the process and must meet fuel specifications measured in parts per million.

Early refiners occupied an awkward middle ground. Thousands of wildcat producers created swings between glut and scarcity, while customers wanted dependable lamp oil at a stable price. Refiners had to absorb that volatility and still earn a margin.

Rockefeller's lesson: control the flows

John D. Rockefeller recognised the value of controlling those flows. Standard Oil was founded in Ohio in 1870 with $1 million in capital, and by 1880 controlled roughly 90% of American refining capacity.² Its advantage was often outside the refinery gate. In 1868, Rockefeller’s business negotiated sharply lower freight rates with the Lake Shore Railroad in exchange for guaranteed daily shipments; Standard later expanded into pipelines and gathering systems. In 1882, it reorganised as a trust, pooling the securities of 40 companies under nine trustees.²

The model combined gathering, refining, transport and branded distribution, allowing Standard to earn across the supply chain while competitors paid third parties at each stage. The Supreme Court ruled it an unreasonable monopoly in 1911 and ordered its break-up; Exxon Mobil is among its descendants.²

That break-up still shapes how the industry should be read. Antitrust law, national oil companies and deep global commodity markets have limited the model in which one company controlled the full margin. Most refiners discussed here buy crude at market prices, sell products at market prices and retain what remains after costs.

The first myth

The common assumption is that higher oil prices benefit oil companies. For a well owner, that is broadly true. For a refinery, crude is a cost. A higher crude price helps only when gasoline, diesel and jet-fuel prices rise by more, or when the crude a refinery buys becomes cheaper relative to the benchmark. Otherwise, the plant is paying more for its main input.

Revenue can obscure this distinction. A refiner’s sales rise with the prices of its products, so reported revenue can increase sharply when oil rises even as profit per barrel falls. Empor’s research dossier makes the distinction directly: revenue largely tracks oil prices, while profit depends on product prices less crude, energy, compliance, freight, maintenance and financing costs.³

By the early twentieth century, the automobile would give that gap new importance. It needed gasoline, while a simple still could produce only as much as the crude naturally contained.

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The French engineer who taught oil to become gasoline

In April 1936, engineers at Socony-Vacuum’s Paulsboro, New Jersey, refinery converted an old thermal-cracking unit to run a process invented by a French engineer. It worked. In March 1937, Sun Oil began operating a commercial unit at Marcus Hook, Pennsylvania, capable of processing 15,000 barrels a day.⁴ Its inventor, Eugène Houdry, had spent more than a decade and much of his family’s money developing it.

A tank officer who liked fast cars

Houdry was born in 1892 in Domont, near Paris, the son of a successful structural-steel manufacturer. He trained as a mechanical engineer and graduated first in his class in 1911. During the First World War, he served in the artillery and later in the new tank corps. On April 16, 1917, during the Nivelle Offensive, he was seriously wounded while trying to repair damaged tanks under fire. He received the Croix de Guerre and the Legion of Honour.⁵

After the war, he returned to the family business and raced a Bugatti. Racing brought him into contact with engine designers seeking better fuel. In 1922, he toured the United States, visiting the Indianapolis 500 and a Ford plant in Detroit. That year, he established a fuel laboratory with the chemist E. A. Prudhomme. By 1927, they had developed a three-step catalytic process to make fuel from lignite, a soft brown coal. A pilot plant operated from 1929 to 1930 but was uneconomic.⁵

France did not provide further funding. In 1930, Houdry moved to the United States, settled in Paulsboro and formed the Houdry Process Corporation in 1931. He worked with Vacuum Oil, later Socony-Vacuum, and Sun Oil.⁵⁴ He had brought a coal-based technique to a market increasingly focused on turning oil into gasoline.

Cracking: rebuilding the pieces

If distillation sorts a mixture into its components, cracking breaks large, low-value hydrocarbon molecules into smaller ones that can yield more valuable products. Heat alone can do this, as older thermal crackers did. Houdry’s contribution was to use a catalyst: a solid material that speeds and directs the reaction, allowing more heavy oil to become high-octane gasoline.

The analogy has limits. Catalysts do not remain effective indefinitely. In cracking, carbon deposits coat them and reduce their activity, so they must be burned clean and returned to service. That cycle makes the units mechanically demanding, and their yields depend on both the feedstock and plant operation.

War made octane a weapon

Houdry’s process arrived at a consequential moment. By 1942, fourteen Houdry units were producing high-octane aviation fuel for the war effort.⁵ The industry and the U.S. government then pushed further. Wartime demand accelerated the deployment of fluid catalytic cracking, alkylation and isomerization, which enabled refiners to produce aviation fuel at scale.⁶ Houdry, stripped of his French citizenship by the Vichy regime in 1941, became an American citizen in January 1942.⁵

The equipment built during those years became part of the modern refinery. Over subsequent decades, refiners added cokers, which extract lighter products from the heaviest residue, and hydrocrackers and hydrotreaters, which use hydrogen to split molecules and remove sulfur. Together, these units create what the industry calls complexity: the ability to process difficult, cheaper crude into compliant gasoline, diesel, jet fuel and petrochemical feedstocks.

Why complexity pays, and when it doesn't

Crude is priced by quality. Heavy, sulfur-rich grades—known as heavy sour crude—usually trade at a discount to light, low-sulfur benchmarks because simple refineries cannot process them as effectively. A complex refinery can buy that discounted crude and still produce higher-value fuels. That capability underpins much of the U.S. Gulf Coast refining model inherited in different forms by Valero, Marathon Petroleum, PBF Energy $PBF, HF Sinclair $DINO and Phillips 66 $PSX.³

The usual shortcut is that the most complex refinery earns the most. The economics are more conditional. Conversion units cost billions of dollars, consume energy and hydrogen, require periodic maintenance shutdowns known as turnarounds, and justify themselves only when the heavy-crude discount exceeds those costs. If heavy crude is scarce and its discount narrows, the additional hardware may add little. Local crude access, product outlets, carbon costs and operational reliability can matter more in a given quarter.³

Capacity creates a second potential misunderstanding. Measured in barrels per day, it indicates how much a refinery could process, not how much it did process, the products it yielded or the margin it earned. A refinery shut for repairs retains its nominal capacity but generates no earnings.³

Houdry spent his final years working on another catalytic problem: reducing vehicle exhaust emissions. He received a patent for a catalytic converter in 1956.⁵ By his death in 1962, however, a larger shift in the industry’s economics was under way. The countries that owned the oil were beginning to organise.

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When the countries that owned the oil changed the factory's world

From September 10 to 14, 1960, five men met in Al-Shaab Hall in Baghdad: Fuad Rouhani of Iran, Tala'at al-Shaibani of Iraq, Ahmed Sayed Omar of Kuwait, Abdullah al-Tariki of Saudi Arabia and Juan Pablo Pérez Alfonzo of Venezuela. They founded the Organization of the Petroleum Exporting Countries, OPEC, to stabilise the oil market and protect member states’ permanent sovereignty over their natural resources.⁷⁸

For refiners, OPEC changed who could influence the price of their most important input. Until then, a small group of international oil companies had largely controlled concessions, production and crude flows to their own plants. Governments that owned the reserves were now coordinating.

The embargo

That power was felt at the pump thirteen years later. During the Arab-Israeli war in October 1973, Arab OPEC members cut production and embargoed shipments to the United States in response to its military resupply of Israel.⁹ Oil prices first doubled, then quadrupled, and Americans queued for gasoline. On November 7, 1973, President Richard Nixon launched Project Independence, promising energy self-sufficiency. Secretary of State Henry Kissinger began talks with Arab leaders that month. The embargo ended in March 1974.⁹

Its effects outlasted the embargo. The United States created the Strategic Petroleum Reserve, introduced a 55-mile-per-hour speed limit and fuel-economy standards, and joined other importers in founding the International Energy Agency.⁹ Governments had learned that fuel security was a national concern—and that demand could be managed as well as supply.

A second warning followed five years later. The Iranian Revolution had cut Iranian production by 4.8 million barrels a day by January 1979, roughly 7% of global output. Oil prices more than doubled between April 1979 and April 1980 as hoarding and fear compounded the lost supply. By May 9, 1979, drivers were queuing at California filling stations, with rationing in nine counties.¹⁰

What the shocks taught refiners

For a refinery that buys crude, such a supply shock is initially a threat, not an opportunity. Crude prices rise before product prices can fully adjust. Governments facing angry motorists may impose price controls, rationing or taxes. The owner of the barrel captures the immediate windfall; the refinery can be squeezed between a rising input cost and a capped selling price.

The shocks encouraged three defences: securing crude through term contracts or ownership, building plants able to process different grades, and carrying inventories as a buffer. They also strengthened a model that still shapes the industry: state companies that own both oil production and refineries, using plants as outlets for national crude and tools of domestic fuel security.

The state-owned refiners

That model now operates at substantial scale. Saudi Aramco, Kuwait Petroleum Corporation, Роснефть Rosneft, Pemex, Petrobras and 中国石化 Sinopec $600028.SS are among the largest refinery-capacity owners. Empor’s data puts Sinopec’s capacity at about 6.2 million barrels a day, Aramco’s at about 4.4 million and Exxon’s at about 4.3 million.³

Their roles differ. Aramco’s downstream operations provide outlets for its crude and access to overseas fuel markets. Sinopec operates within Chinese state objectives on prices, supply security and industrial policy. Pemex and Petrobras carry domestic fuel-security and pricing responsibilities that a private refiner would be unlikely to accept. A pure refiner, by contrast, buys most of its feedstock and must earn a margin on it.³

The producer-versus-refiner distinction is therefore incomplete. An integrated group can lose money in refining when crude rises yet still earn more overall because its oil fields benefit. A state company may be required to supply fuel below cost, effectively transferring value to households. Neither outcome is visible in the benchmark oil price.

OPEC did not gain permanent control over refinery economics. Demand destruction, non-OPEC supply, emergency stock releases, new refinery capacity, wars, sanctions and subsidies have repeatedly altered the outcome. The same forces were at work in 2026: Brent crude averaged about $94 a barrel in the quarter to September, 36% more than a year earlier,³ yet refiners around the world responded in opposite ways, as later chapters show.

Governments had one more lever. In 1970, the United States began regulating what could legally leave the refinery gate.

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Clean fuel became a second refinery industry

In 1970, amid the visible smog over American cities and industrial centres, Congress established the basic structure of the Clean Air Act.¹¹ The law did not change crude oil’s chemistry. It changed the fuels refiners could legally sell.

Fifty years of tightening

The Act was substantially revised in 1977 and again in 1990.¹¹ On November 15 that year, President George H. W. Bush signed amendments that pushed fuel-quality and emissions requirements further into refinery economics.¹² With each round, equipment once considered optional became necessary to remain in the market.

Sulfur illustrates the change. In 2000, the Environmental Protection Agency finalised its Tier 2 standards, which from model year 2004 reduced gasoline sulfur by up to 90%. Modern catalytic converters—the descendants of devices such as Houdry’s—are damaged by sulfur, so cleaner vehicle emissions required cleaner fuel. Tier 3, introduced in 2017, set a maximum sulfur content of 10 parts per million.¹³

Refineries remove sulfur in hydrotreaters. The process protects engines’ emissions-control systems, but it is not a simple filter: it consumes hydrogen, often made from natural gas in energy-intensive units, and requires capital and capacity that might otherwise be used to process additional crude.

A market in credits

The Energy Policy Act of 2005 created the Renewable Fuel Standard, and the Energy Independence and Security Act expanded it in 2007. The programme requires renewable fuel to replace a rising volume of fossil transport fuel and places the compliance obligation on refiners and importers of gasoline and diesel. They demonstrate compliance through tradable Renewable Identification Numbers, or RINs, generated when renewable fuel is produced and available for purchase on the open market.¹⁴

For refiners with limited blending operations, RINs can be a volatile cost. For those producing renewable fuel, they can be income. The credits redistribute money within the policy system; they do not by themselves show that one refinery operates better than another.

The effect can be material. Valero, which operates renewable-diesel and ethanol plants, reported $717 million of renewable-diesel operating income in the second quarter of 2026, compared with a $79 million loss a year earlier.¹⁵ The reversal shows that some earnings attributed to refiners arise from policy-created markets and can change quickly. Companies including Neste $NESTE.HE and Eni $ENI.MI have converted parts of their conventional refining systems to renewable fuels, altering—but not eliminating—their exposure to crude margins.³

The ship that changed its fuel

Fuel rules also crossed borders. In October 2016, the International Maritime Organization confirmed that the sulfur limit for ships’ fuel would fall from 3.50% to 0.50% on January 1, 2020.¹⁶¹⁷ Shipowners could buy compliant low-sulfur fuel, switch to alternatives such as liquefied natural gas, or install exhaust scrubbers and continue using heavy fuel oil.¹⁷

The rule appeared to favour complex refiners able to turn high-sulfur residue into compliant marine fuel and diesel. It took effect as planned. Within months, however, the pandemic emptied roads, grounded aircraft and slowed trade, causing demand for oil products to collapse.¹⁸ The regulatory shift was real, but the expected profit effect was overwhelmed by falling demand.

The episode qualifies the argument that tighter fuel rules reliably produce a margin boom for incumbents. Plants with the required equipment can gain a relative advantage, but compliance also raises costs, can hasten weaker plants’ closure, permits competition from overseas plants built to the same standard and encourages customers to use substitutes. The profitability of surviving plants still depends on demand.

By the 2010s, another force was reshaping the American refinery map from below: the United States was again producing oil in large volumes and from unexpected places.

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Shale turned geography into a trading advantage

On June 30, 2011, Marathon Oil completed the spin-off of its refining, marketing and transportation business, giving shareholders one share of the new Marathon Petroleum for every two Marathon Oil shares they owned.¹⁹ Ten months later, on May 1, 2012, ConocoPhillips separated Phillips 66, a downstream company with fifteen refineries and 2.2 million barrels a day of capacity, as well as half of DCP Midstream and half of Chevron Phillips Chemical.²⁰

Phillips 66's first chief executive, Greg Garland, described the new company as “one of the world's most competitive refining and marketing operations”, alongside growing midstream and chemicals businesses tied to liquids-rich shale development.²⁰ The separations gave investors a clearer way to own refining-margin exposure without an upstream oil business offsetting—or obscuring—the result.

A new map of crude

The spin-offs coincided with the shale revolution. Horizontal drilling and hydraulic fracturing unlocked light, tight oil in basins often far from refineries designed for heavier imported crude. U.S. crude production rose by 2.6 million barrels a day between January 2016 and July 2019 alone.²¹ For several years, federal law restricted most crude exports, leaving new domestic barrels dependent on U.S. buyers. Pipelines, storage and rail therefore determined which refiners could access them.

That created crude differentials: price gaps between grades or delivery points. A refiner able to transport an appropriate crude cheaply from a discounted region could retain part of that gap. But the grades were not interchangeable. They varied in density, sulfur content and product yield, while refineries built for heavy crude could not process unlimited volumes of light shale oil without sacrificing efficiency.

The export restrictions were lifted late in 2015. Before then, U.S. crude exports had gone almost exclusively to Canada. By the first seven months of 2019, they averaged 2.8 million barrels a day across as many as 31 monthly destinations, supported by new, expanded and reversed pipelines and larger export terminals.²¹ Domestic crude could then seek global prices. That narrowed some inland discounts enjoyed by refiners while creating new trading opportunities for coastal operators.

The companies that move the oil

Pipeline and storage companies sit between the well and refinery. Plains All American Pipeline $PAA gathers, transports and stores crude across North America; ONEOK $OKE moves natural-gas liquids, refined products and crude; Vopak $VPK.AS operates tank terminals worldwide for oil, chemicals and gas storage and blending.³

Their economics differ from those of refiners. Vopak reported an EBITDA margin of about 54% in 2025, ONEOK about 23% and Plains less than 7%, reflecting the differing weight of fee-based storage and lower-margin marketing.³ Over recent years, their margins generally moved inversely with Brent in the same quarter—clearly for Plains and ONEOK, and less consistently for Vopak. Higher oil prices can inflate commodity-linked revenue without lifting fixed fees.³ These businesses benefit from volumes and regional dislocation, not directly from the crack spread.

The same idea abroad

The shale lesson—that logistics and location can matter as much as refinery hardware—also applies elsewhere. Reliance Industries $RELIANCE.NS built its Jamnagar complex on India’s west coast as two refineries with a broad crude slate, petrochemical integration and an owned port.³ S-Oil $010950.KS in South Korea, backed by Saudi Aramco, is positioned to buy Middle Eastern crude and export products to Asian markets.³ In both cases, flexible crude sourcing and port access matter alongside local demand.

Shale did not give American refiners a permanent feedstock advantage. The end of export restrictions, pipeline expansion and global arbitrage narrowed many of the widest local discounts, while plant configurations constrained light-crude use. Its more durable legacy was a group of listed companies with relatively direct exposure to refining margins—an exposure that could prove volatile.

The distinction remains useful: an independent refiner is relatively close to a crack-spread business, while an integrated major is a portfolio in which upstream and downstream earnings can offset each other.

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The year the world stopped driving, then discovered it had closed too much

In the spring of 2020, only months after the world’s ships had switched to cleaner fuel, aircraft were grounded, roads emptied and factories fell quiet. The International Energy Agency said demand for oil products had collapsed and “the bottom has dropped out of the market.”¹⁸

The IEA explained why this was so damaging. Lower crude prices can help refiners by reducing their input costs, but the pandemic cut margins and volumes simultaneously. It also arrived after more than 2 million barrels a day of refining capacity had started in 2019 alone. The agency warned that excess capacity endangered older and more exposed plants, and expected refining to shift toward regions with cheap crude, including the Middle East, or faster demand growth, including developing Asia.¹⁸

Closures, then scarcity

The prediction proved broadly correct, then went too far. Refineries closed, were converted to biofuels or had projects delayed, in what the IEA later described as a third wave of retrenchment since the pandemic began.²² Global refining capacity fell in 2021 for the first time in more than 30 years.²³

Demand then returned to a system with less spare capacity. Russia invaded Ukraine in February 2022. By May, the IEA said global refinery margins had reached unusually high levels: diesel and gasoline cracks hit records in April, while reduced Russian exports of fuel oil, diesel and naphtha worsened the shortage. Middle-distillate stocks had fallen to their lowest level since April 2008 after seven consecutive quarters of draws.²⁴

Middle distillates—mainly diesel, jet fuel and heating oil—were the constraint. Crude was expensive, but finished fuel was scarcer in the places where it was needed. By July, the IEA said cracks had retreated from late-May records, though they remained elevated on a monthly basis.²⁵

What the windfall did to the companies

For U.S. independents, 2022 was exceptionally profitable. Marathon Petroleum’s operating margin rose from 3.6% in 2021 to 10.7%; Valero’s increased from 1.9% to 8.9%; PBF’s from 2.2% to 8.9%; and HF Sinclair’s from 4.1% to 10.6%. Valero’s return on capital employed reached 36.5%, while PBF’s reached 45.8%.³

The gains did not persist. By 2025, Marathon’s operating margin was 4.3%, Valero’s 3.5% and PBF’s slightly negative. Valero’s return on capital had fallen to 8.1%, while PBF’s was minus 9.8%. The median operating margin among refiners in Empor’s data fell from 8.0% in 2022 to 3.5% in 2025.³ The boom illustrated the sector’s operating leverage; it did not create a durable margin floor.

Some refiners lost money during the same shock. Hindustan Petroleum, one of India’s state-controlled fuel marketers, reported a net loss in the fiscal year ended March 2023, despite record cracks elsewhere. State-controlled marketers in India can face government fuel-pricing decisions that delay the pass-through of higher crude costs to customers.³ The contrast shows that global cracks matter less when a company cannot set its own pump price.

Two myths that 2020 and 2022 dispose of

The first myth is that refining scarcity guarantees profit. In 2020, capacity had little value when demand for its products disappeared.

The opposite myth—that 2022 was an unrepeated anomaly—is also too simple. In 2023, the IEA forecast net capacity additions through 2028 that would exceed product-demand growth, yet warned that another period of middle-distillate tightness “cannot be ruled out.”²² That was a risk assessment, not a forecast.

The episode also highlighted the system’s unlisted and inaccessible participants. Russian refiners—Rosneft, Лукойл Lukoil, Газпром нефть Gazprom Neft, Татнефть Tatneft and Башнефть Bashneft—own capacity material to global product balances, though sanctions, domestic pricing rules and market-access limits make their securities unavailable or difficult for many investors to compare.³ In the United States, Aramco-owned Motiva and Citgo operate large Gulf Coast plants without separately listed shares.³

The inventory illusion

Inventory accounting added another complication. Refiners hold millions of barrels of crude and products in storage. When prices rise sharply, the value of that stock rises, and accounting methods may record part of the increase as profit. The gain resembles that of a grocer selling flour bought cheaply after shelf prices rise: it is real once, but the next bag is bought at the higher price. When prices fall, the effect reverses into a loss.³

The effect worked in both directions, and it mattered again in 2026. This time, the shock began neither with a pandemic nor with Russia’s invasion of Ukraine, but in the narrow waters between Iran and the Arabian Peninsula.

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The new bottleneck is not oil; it is fuel in the right place

War broke out in the Middle East on February 28, 2026, disrupting traffic through the Strait of Hormuz, which carries roughly a fifth of the world’s seaborne oil and gas, and damaging nearby infrastructure. Crude briefly surged to just under $150 a barrel before falling to about $70 by mid-June, close to its pre-war level.²⁶

Fuel prices did not fall with crude. By mid-May, diesel and gasoline remained about 30% above pre-war levels. The IEA said diesel and jet fuel were hit hardest because the lost regional heavy crudes yield relatively large volumes of those products.²⁶ The Hormuz closure resumed in early July, cutting Gulf oil production that month by 8.3 million barrels a day from pre-war levels.²⁷

What scarcity looks like in numbers

The IEA’s August report described a system short of both fuel and the means to move it. Global refinery throughput in July was 80.9 million barrels a day, nearly 5 million below a year earlier. Observed oil inventories fell by 69 million barrels in a month, dropping below 7.9 billion barrels for the first time since April 2025. Diesel exports from major regions were 1.3 million barrels a day lower than a year earlier—about a fifth of global seaborne diesel trade. Atlantic Basin refining margins reached record highs.²⁷

The burden varied by country. Without emergency intervention, U.S. pump prices were about 50% above pre-war levels by mid-May. Japan subsidised fuel, leaving motorists paying roughly what they had paid in 2022. European governments cut fuel taxes, offsetting around 3% of pre-war retail prices.²⁶ The IMF’s July update still projected global growth of 3.0%, but identified war-related energy costs as a drag, especially for importers.²⁸

Walking the chain

A barrel’s economics begin with its owner: a national oil company such as Saudi Aramco or Kuwait Petroleum; an integrated major such as Exxon, Chevron $CVX, Shell, BP or TotalEnergies $TTE.PA; or a producer or trader selling a particular grade. Integrated companies including Petrobras, Suncor, Cenovus, Imperial Oil, Ecopetrol and YPF own wells and refineries in differing proportions. A crude-price jump can therefore help their upstream businesses while pressuring their downstream operations.³

Pipelines, tankers and terminals move and store the crude, generally for fees. Refineries process it. Independent refiners—Marathon, Valero, Phillips 66, PBF, HF Sinclair, Delek US $DK, Par Pacific $PARR, CVR Energy and Calumet $CLMT in the U.S.—buy crude at market prices and retain the difference between the value of their product slate and their costs.³ Wholesalers and retailers such as Sunoco $SUN, Global Partners, World Kinect and Brazil’s Ultrapar then distribute fuel to filling stations, airports, ports and fleets. Airlines, truckers, shippers, factories, petrochemical plants and motorists ultimately decide whether to pay more or consume less.

The refinery’s share is commonly represented by the crack spread: the market value of a basket of products less the cost of the crude used to make them. Like the difference between a bakery’s bread sales and its flour cost, it approximates the gross value added before labour, energy, maintenance, financing and other expenses. But a crack spread is a market indicator, calculated for a standardised product mix at a particular location. No refinery produces precisely that mix or pays precisely that crude price.

The closely watched U.S. Gulf Coast 3-2-1 crack assumes that three barrels of crude yield two barrels of gasoline and one of diesel. It stood at about $65 a barrel in August 2026, roughly twice its level a year earlier, while Brent averaged around $94 in the third quarter.³ These are different measures in different markets, but the crack spread, rather than Brent alone, is more directly tied to a refiner’s earnings.

Crude grades also matter. In August, Dubai crude, the benchmark for Middle Eastern supplies into Asia, averaged about $11 a barrel below Brent.³ A refinery able to shift toward that cheaper grade may capture part of the discount; one tied to a more expensive grade cannot.

What the data says about oil prices and refiners

Empor’s data compares changes in each company’s gross margin with changes in Brent over several years of quarterly results. It offers no universal rule: only 9 of 23 refiners behaved as simple theory would suggest, with margins falling as oil prices rose.³

Those companies are revealing. Sinopec, Indian Oil $IOC, Hindustan Petroleum $HINDPETRO, Bharat Petroleum $BPCL, 台塑石化 Formosa Petrochemical $6505.TW and Petron Malaysia saw margins squeezed as crude rose, usually in the same quarter or the following one. Most are import-dependent Asian refiners, and several operate under regulated or politically sensitive fuel prices.³

The large U.S. independents showed the opposite tendency. Marathon, Valero and PBF generally saw gross margins rise with Brent, though the relationship was loose and often lagged by one or two quarters.³ That pattern suggests that product prices, crude differentials and inventory gains often rose alongside oil prices in the open U.S. market. It does not establish that higher oil prices caused higher margins; in 2026, product scarcity was plainly the principal driver. HF Sinclair, Calumet, Hellenic Energy and Motor Oil showed no consistent relationship.

Several years of data can indicate a pattern, not prove causation. Still, the divide reflects a meaningful institutional difference. In India, China, Brazil, Mexico, Indonesia, Iran and parts of Southeast Asia, refiners cannot always pass higher costs through freely; government policy often determines the outcome.

That leaves the market’s more practical question: among refiners able to capture the margin, which are doing so most effectively?

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The contest: scale, uptime and the price of the wrong barrel

Valero’s second quarter of 2026 showed how a large, reliable system can benefit when product markets tighten. Its refineries processed about 3.0 million barrels a day, broadly unchanged from a year earlier. Refining operating income, however, rose to $4.5 billion from $1.3 billion as margin per barrel nearly doubled to $23.62 from $12.35. Net income reached $3.7 billion, compared with $714 million, and the company returned $2.6 billion to shareholders. Chief executive Lane Riggs credited “excellent operations and commercial execution”.¹⁵

The comparison is straightforward: similar throughput produced more than three times as much refining operating income because each barrel was more profitable. That gain still depended on plants being available to run.

Contest one: the American independents

The United States has the largest group of listed independent refiners. Their relative performance depends on scale, plant configuration, commercial reach and uptime.

Marathon Petroleum is the largest. Its thirteen-refinery system has about 3.1 million barrels a day of capacity and processed about 2.9 million in the second quarter, a 94% utilisation rate.³ Its logistics and marketing businesses also provide additional ways to optimise crude and product flows. Valero has about 2.8 million barrels a day of capacity and offers more direct exposure to refining margins, alongside renewable-fuel and ethanol operations.³

Their advantages are not identical. In 2025, a weaker margin year, Marathon reported a 4.3% operating margin and 12.8% return on capital employed, compared with Valero’s 3.5% and 8.1%.³ Valero had lower leverage, with net debt of about one times EBITDA, versus Marathon’s 2.6 times.³ Which company captures more of a particular crack spread varies by quarter, crude slate and plant availability.

Phillips 66 processed about 2.1 million barrels a day in the second quarter, though its chemicals, midstream and marketing operations make it less direct refining exposure.³ HF Sinclair combines inland refineries with lubricants and renewable fuels. Delek US and Par Pacific are smaller, more regional operators.

PBF Energy illustrates the risk of operational disruption. Its latest filing confirms six refineries.³ A major fire struck its Martinez refinery in California on February 1, 2025. The plant did not return to full operations until May 2026, while PBF collected $1.25 billion in insurance proceeds.²⁹ The outage helps explain why PBF lost money in 2025 while its larger peers remained profitable. With Martinez back in service and cracks elevated, second-quarter 2026 revenue rose 56% to $11.68 billion and net income reached $906 million, compared with a small loss a year earlier. Long-term debt fell to $1.75 billion.²⁹ The reversal demonstrates both the benefit of high margins and the cost of losing a major plant.

Par Pacific qualifies the idea that the largest system necessarily wins. Its refineries serve island and other isolated markets, and in 2025 it reported an 18.9% return on capital employed, above Marathon’s and Valero’s.³ Local supply constraints can outweigh scale. But a smaller system is also more exposed to a single outage, so one year of strong returns does not establish a lasting advantage.

Contest two: the export and regional refiners

Outside the United States, the comparison is between export-oriented complexes and refiners serving regional markets. Reliance’s oil-to-chemicals segment reported an EBITDA margin of about 9% in the fiscal year to March 2026.³ Its petrochemical integration makes that result not directly comparable with a U.S. refiner focused primarily on transport fuels.

S-Oil illustrates the risks of export exposure. It operated at 76% utilisation in the second quarter of 2026, reported a 0.7% operating margin in 2025 and carried net debt of about 5.8 times EBITDA, compared with roughly one times for Valero.³ Saudi Aramco’s backing provides crude access, but does not insulate S-Oil from Asian refining margins or its own leverage.

Around the Mediterranean, Turkey’s Tüpraş, Greece’s Hellenic Energy and Motor Oil (Hellas) Corinth Refineries $MOH.AT serve markets reshaped by reduced Russian product flows. Their free-cash-flow yields of 15% to 20% at current prices reflect both strong cash generation and investor uncertainty over its durability; they are not, by themselves, a valuation verdict.³ In Asia, Thai Oil, PTT $PTT.BK, Thailand’s state-backed energy group, 出光興産 Idemitsu Kosan $5019.T, Cosmo Energy, ENEOS $5020.T and SK Innovation $096770.KS buy imported crude, largely in dollars, and sell into mature or regulated local markets. Exchange rates and inventory timing can therefore materially affect reported earnings.³

Contest three: the state systems

Sinopec, 中国石油 PetroChina $601857.SS, Indian Oil, Hindustan Petroleum and Bharat Petroleum are large by volume, but policy determines how much of the refining margin they retain. India’s three state marketers reported returns on capital employed of roughly 21% to 26% in the fiscal year to March 2026.³ Smaller peers, Mangalore Refinery and Petrochemicals $MRPL and Chennai Petroleum, showed a similar pattern.

The September quarter underscored how quickly conditions can change. Before results due in October and November, analysts expected Hindustan Petroleum to report a loss per share, while Valero was expected to earn close to $19 a share.³ Scarce diesel can enrich an exporter that can pass through prices while hurting a domestic marketer required to limit them.

What the market already knows

The apparent lead of the large U.S. independents is already reflected in their market values. At the end of 2025, Marathon and Valero were each valued at about $50 billion. By September 24, 2026, their values had risen to about $113 billion and $108 billion, respectively.³ Both had exceeded analysts’ revenue forecasts in each of their previous four quarters, as had PBF, HF Sinclair and Par Pacific.³ But revenue beats during an oil-price upswing can largely reflect higher prices rather than improved profitability.

Low valuation multiples do not resolve the comparison either. Price-to-sales ratios and free-cash-flow yields incorporate expectations for margin normalisation, working-capital needs and future capital spending. A high benchmark crack spread creates an opportunity; realised margins depend on reliability, crude flexibility and access to product customers.

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What the boom believers and the skeptics both miss

September produced two apparently conflicting narratives. Refiners reported some of their strongest profits on record, while long-term outlooks continued to point to electric vehicles, more efficient engines, low-carbon-fuel mandates, new capacity and declining road-fuel consumption in rich countries. Both can be true. The more useful question is which forces will shape margins over the next few years.

The case for durable scarcity

The bullish argument is straightforward. Refineries closed after 2020 and are difficult to replace because permits, environmental requirements, ports and pipeline connections take years to develop. The disruption of 2026 also showed how vulnerable product-export routes can be. Diesel, jet fuel and petrochemical feedstocks will remain necessary for decades, so complex and reliable surviving plants could continue to run at attractive margins.

There is evidence for that view. U.S. refining capacity fell by more than 250,000 barrels a day in 2025, according to the Energy Information Administration.³ The IEA’s 2023 medium-term outlook expected jet-fuel demand to grow by 2 million barrels a day through 2028, with petrochemical feedstocks accounting for more than half of demand growth.²²

The case for normalization

The opposing argument is equally plausible. Middle Eastern and Russian flows could recover, new export capacity could arrive and inventories could rebuild. High fuel prices could curb consumption. Cracks would then narrow, inventory gains would reverse and earnings would normalise, even as lower working-capital needs released cash.

The evidence also supports this case. The same IEA outlook expected 4.4 million barrels a day of net capacity additions by 2028, exceeding growth in refined-product demand.²² Its August 2026 report forecast that global oil demand would fall by 1.6 million barrels a day this year and that refinery throughput would rebound by 3.5 million barrels a day in 2027 as flows recovered.²⁷ Margin history shows how quickly windfalls can fade: within two years of the 2022 boom, U.S. independents’ margins had fallen by more than half.

The case for transition

The longer view complicates both arguments. The IEA expected gasoline demand to peak after 2023 and transport fuels collectively after 2026, driven by electric vehicles and efficiency.²² Aviation and petrochemical demand, however, continued to grow. In such a market, the more resilient operators may be those with an appropriate mix of conventional fuels, biofuel conversion capacity, logistics and compliance assets.

Europe’s refiners—ORLEN, Repsol $REP.MC, OMV $OMV.VI, Galp $GALP.LS, Hellenic Energy and Motor Oil—face product-trade exposure, the loss of Russian crude and carbon policy simultaneously.³ In Australia, Ampol and Viva Energy combine refining with large fuel-import and retail networks and play a domestic fuel-security role. Viva illustrates the pressure on that model: it reported a net loss in 2025.³ Calumet, with specialty products and renewable fuels, only partly fits the conventional-refining comparison.

Three myths, tested

“No new refining capacity has been built, so margins must remain high.” The IEA’s forecast of net capacity additions challenges the first premise. Its warning that middle-distillate markets could still tighten leaves the conclusion possible, but unproven.²²

“Electric vehicles make refineries obsolete now.” The outlook is more selective. Gasoline faces the greatest pressure, while jet fuel and petrochemical feedstocks are expected to grow for years. The outcome depends on each plant’s configuration, geography and the pace of closures, rather than on a single oil-demand headline.

“Watch the oil price.” Empor’s data shows no universal relationship between Brent and refining margins. What matters is a sustained advantage in product prices and availability after crude, energy, compliance and financing costs.

Where the money could move

The profit pool can also shift between layers of the supply chain. If crude becomes scarce, producers and national oil companies capture more of the gain. If shipping and terminals become the constraint, tanker owners and storage operators benefit. If wholesale scarcity eases while retail prices adjust slowly, retailers and distributors can retain more margin; distributors in Empor’s data have tended to see revenue rise with industrial activity, and Sunoco’s margin moved inversely with oil prices, suggesting delayed pass-through.³ World Kinect, which sells aviation, marine and land fuel, illustrates how thin that business can be: its return on capital employed was about minus 25% in 2025.³ If demand destruction accelerates, value leaves the chain altogether.

These shifts are unlikely to be visible first in annual revenue. They should appear earlier in a small set of operating and margin measures.

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Four signals that decide who keeps the money

The next results calls will show whether the 2026 shortage translated into durable earnings. But the evidence will appear first in four measures that follow the chain from physical constraint to the customer.

First: the product crack

The Gulf Coast 3-2-1 crack, along with diesel and jet-fuel equivalents, measures the gross value of turning crude into fuel in a large, transparent market. It moves daily with physical supply and demand, well before companies report earnings. The latest reading was about $65 a barrel in August 2026.³

The scarcity thesis holds if cracks remain elevated for weeks while stocks stay tight. It weakens if they steadily compress as inventories build. A one-day spike caused by a crude-price shock is less informative.

Second: global throughput, product trade and stocks

The IEA’s monthly Oil Market Report tracks refinery throughput, cross-border fuel trade and inventories. Together, those measures show whether scarcity is persisting or being repaired. Its August report put July throughput at 80.9 million barrels a day, nearly 5 million below a year earlier, with observed stocks below 7.9 billion barrels.²⁷

Continued constraints on refinery runs and further inventory draws would support the scarcity case. Restored trade and sustained stock builds would challenge it.

Third: utilization and uptime

In the United States, the EIA reports refinery utilisation weekly and monthly, indicating how much operable conversion capacity remains unused. In June 2026, U.S. refineries ran at 96.5% of operable capacity, which stood at about 18 million barrels a day at the start of the year.³⁰

At company level, the relevant measures are quarterly throughput and realised margin. Marathon’s 94% utilisation rate and Valero’s refining margin of about $24 a barrel in the second quarter are the latest disclosed readings.³ High uptime and realised margins that broadly track benchmark cracks indicate that operators are capturing favourable market conditions. Outages, or a widening gap between benchmark and realised margins, would indicate otherwise. Valero is due to report on October 22 and Marathon on November 3.³

Fourth: what customers are buying

The EIA’s weekly estimate of gasoline supplied to the U.S. market is a timely measure of demand in the largest open fuel market. It was 8.8 million barrels a day in the week ended September 18, 2026.³¹

Resilient demand amid tight supply would support high margins. Demand that remained weak after fuel prices eased would point to more lasting damage.

How to read them together

No measure is decisive alone. High utilisation can precede maintenance; a high crack can reflect a brief panic; and inventory changes can be driven by crude rather than finished products. Cash flow can also be distorted by inventory gains and working-capital movements. Read in sequence—physical constraint, product value, plant reliability and customer willingness to pay—the four signals provide a clearer view of who retains the margin.

Empor’s data offers a related clue. Revenue growth at pipeline operators and fuel distributors has moved clearly with U.S. industrial production in the same quarter, a stronger relationship than the one between oil prices and refining margins.³ Industrial activity appears to support volumes in adjacent parts of the supply chain, though it does not establish the cause of any individual company’s results.

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The refiner is not a bet on oil

From Titusville’s sixty-nine-foot well to a complex refinery on the Gulf Coast, in Jamnagar or on the Aegean, the underlying chemistry remains recognisable: separate molecules, then transform them. The surrounding business has become a contest among governments, chemistry, infrastructure, financial discipline and customer demand.

Drake helped make the barrel abundant but captured little of its value. Houdry helped make it more valuable and advanced the factory model that still defines the industry. OPEC shifted control of the input toward the states that owned it. Regulators made compliance integral to refining. Shale and corporate spin-offs created listed companies with relatively direct exposure to margins. The pandemic, Russia’s invasion of Ukraine and the 2026 Hormuz disruption showed how sharply those margins can move—and that the constraint can be finished fuel in the right place at the right time.

So who makes the most money when oil prices move?

When product prices rise faster than crude, as they did in 2026, the most direct beneficiaries are independent refiners with complex, reliable plants, access to advantageous crude and resilient product markets. Among large listed companies, Marathon Petroleum and Valero offered the clearest exposure. Phillips 66, PBF, HF Sinclair, Par Pacific and selected export refiners provided less direct variations. Their advantage depended on uptime and market access, and would last only while product scarcity persisted.

When crude rose faster than products, the barrel’s owner benefited first and refiners could be squeezed. Integrated groups such as Saudi Aramco, Exxon, Chevron, Shell, TotalEnergies and Suncor could offset downstream pressure with upstream income. Pipelines and terminals such as Plains, ONEOK and Vopak generally collected fees across price cycles. Distributors such as Sunoco and Global Partners depended on the speed of pass-through. State refiners in India, China and elsewhere could instead be required to protect consumers, helping explain why several saw margins decline as crude rose.

Three distinctions clarify the analysis: a crack-spread boom differs from an oil-price boom; an inventory gain differs from an underlying margin gain; and nominal capacity differs from uptime.

The conclusion would change if product routes recovered, new capacity arrived, inventories rebuilt and cracks narrowed. The advantage would then drain from pure refiners. Persistent crude scarcity without product-price pass-through would shift value upstream, while government intervention could transfer it to consumers. Shares could still disappoint even if the operating case held, because markets had already more than doubled the value of the two largest U.S. independents during the year.

In future cycles, the useful question remains the same: what is scarce—the crude barrel, conversion capacity, shipping and terminals, or customers’ willingness to buy fuel? The owner of that constraint is most likely to retain the profit.

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Glossary

Barrel per day: A measure of refinery capacity or throughput; capacity is not the same as actual runs.

Brent: A global crude-oil benchmark. It is a useful reference for feedstock costs, but not the exact price every refinery pays.

Crack spread: The value of selected refined products less the cost of the crude used to make them; a gross market indicator before company-specific costs.

3-2-1 crack: A standardised calculation in which three barrels of crude produce two barrels of gasoline and one barrel of diesel.

Complex refinery: A plant with conversion equipment—including cokers, hydrocrackers and hydrotreaters—that can process more difficult crude and produce more valuable, compliant fuels.

Crude differential: The price gap between crude grades or delivery locations.

Hydrotreater: Equipment that uses hydrogen to remove sulfur and other impurities from refinery streams.

Inventory gain or loss: The accounting effect of changes in the value of crude and products held in storage.

Middle distillates: Mainly diesel, jet fuel and heating oil.

Refinery utilization: Actual crude throughput as a share of usable refining capacity.

RIN: A U.S. Renewable Identification Number, a tradable compliance credit under the Renewable Fuel Standard.

Turnaround: A planned maintenance shutdown that supports long-term reliability but interrupts production.

Upstream integration: Ownership of oil production, which can offset a refiner’s exposure to higher crude costs.

Working capital: Cash tied up in inventories and receivables; it can rise sharply with oil prices.

References

1. Drake Oil Well, National Register of Historic Places Inventory–Nomination Form — U.S. National Park Service ↩↩↩↩

2. Standard Oil — Wikipedia ↩↩↩

3. Crude Refiners: research dossier and data tables — Empor, 24 September 2026 ↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩↩

4. Houdry Process for Catalytic Cracking, National Historic Chemical Landmark — American Chemical Society ↩↩

5. Eugene Houdry — Wikipedia ↩↩↩↩↩↩

6. Assuring the Adequacy and Affordability of Cleaner Fuels — U.S. Department of Energy ↩

7. OPEC celebrates 63rd anniversary — OPEC, 14 September 2023 ↩

8. Agreement establishing OPEC, Baghdad, 14 September 1960 — United Nations Treaty Collection ↩

9. Oil Embargo, 1973–1974 — U.S. Department of State, Office of the Historian ↩↩↩

10. Oil Shock of 1978–79 — Federal Reserve History ↩

11. Clean Air Act Requirements and History — U.S. Environmental Protection Agency ↩↩

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13. Gasoline Sulfur — U.S. Environmental Protection Agency ↩

14. Overview of the Renewable Fuel Standard Program — U.S. Environmental Protection Agency ↩

15. Valero Energy Reports Second Quarter 2026 Results — Valero Energy, July 2026 ↩↩

16. IMO sets 2020 date for ships to comply with low sulphur fuel oil requirement — International Maritime Organization, October 2016 ↩

17. IMO 2020: cutting sulphur oxide emissions — International Maritime Organization ↩↩

18. The global oil industry is experiencing a shock like no other in its history — International Energy Agency, 2020 ↩↩↩

19. Marathon Oil unaudited pro forma financial statements following the spin-off of Marathon Petroleum — Marathon Oil, SEC filing, 2011 ↩

20. Phillips 66 launches as independent downstream company — Phillips 66, SEC filing, May 2012 ↩↩

21. U.S. crude oil exports go to more destinations — U.S. Energy Information Administration, 2019 ↩↩

22. Oil 2023: Executive summary — International Energy Agency ↩↩↩↩↩↩

23. World Energy Outlook 2022: Outlook for liquid fuels — International Energy Agency ↩

24. Oil Market Report, May 2022 — International Energy Agency ↩

25. Oil Market Report, July 2022 — International Energy Agency ↩

26. From Hormuz to the pump: why oil price shocks hit consumers differently — International Energy Agency, 2026 ↩↩↩

27. Oil Market Report, August 2026 — International Energy Agency ↩↩↩↩

28. World Economic Outlook Update, July 2026 — International Monetary Fund ↩

29. PBF Energy Form 10-Q for the quarter ended 30 June 2026 — PBF Energy, SEC filing ↩↩

30. Refinery Utilization and Capacity — U.S. Energy Information Administration ↩

31. Petroleum and Other Liquids data — U.S. Energy Information Administration ↩