There is no single price of oil. There are hundreds of grades of crude, each with different chemistry and different transport costs, and the market prices almost all of them as a differential to one of three benchmarks: WTI, Brent, or Dubai.
Knowing which benchmark is being quoted, and why the gaps between them move, is the difference between following the oil price and understanding it.
The scale of the thing
Global production runs somewhere around 100 to 103 million barrels a day. At any ordinary price that is well over three trillion dollars a year, making crude the largest commodity market in the world by value.
Production is concentrated. The United States, Saudi Arabia and Russia each produce roughly ten million barrels a day or more, and together with Iraq, Iran, the UAE, Canada, China, Brazil and Kazakhstan account for over 80% of world output.
Consumption is concentrated too: the United States around 20 million barrels a day, China around 15 million and almost entirely imported, India around 5 million and growing fastest. Transport remains the dominant use, which is why oil demand tracks economic activity closely and why the energy transition affects it slowly.
Crude is not one substance
Two properties determine what a barrel is worth, and both benchmarks and differentials are built on them.
Density, measured in API gravity. Higher numbers mean lighter oil, which yields more gasoline and diesel per barrel.
Sulphur content. Low sulphur crude is called sweet, high sulphur sour. Sour crude needs more processing to meet fuel specifications, so it needs a more sophisticated refinery and sells at a discount.
Light sweet crude is the easiest and cheapest to refine, which is why the two most quoted benchmarks are both light and sweet, and why the Asian benchmark, which is neither, trades below them.
WTI: the American benchmark
West Texas Intermediate is light — around 39 degrees API — and sweet, at under 0.5% sulphur. It is produced in West Texas, New Mexico and Oklahoma, and the Permian Basin is the engine behind the American shale expansion.
The defining feature of the WTI futures contract is physical delivery at Cushing, Oklahoma, a pipeline junction with enormous storage capacity. That anchors the price to the physical balance of American crude, and it also creates a specific risk.
The contract trades on NYMEX, part of CME Group. Each contract is 1,000 barrels, so a one-dollar move in the price is $1,000 per contract. Margin is typically a single-digit percentage of contract value and is raised when volatility rises.
On 20 April 2020, the expiring WTI contract settled at −$37.63 a barrel. Traders holding long positions into expiry were obliged to take delivery at Cushing, storage was effectively full because the pandemic had destroyed demand, and there was nowhere to put the oil. They paid people to take it.
That was an extreme confluence, but the lesson is structural: a physically settled contract can price the cost of storage rather than the value of the commodity. Anyone holding oil futures into expiry needs to understand what happens on delivery day.
Brent: the international benchmark
Brent began as crude from a single North Sea field. It is now a blend, and the composition has changed as North Sea production declined. It has long included Forties, Oseberg, Ekofisk and Troll alongside Brent itself, and since 2023 the basket has also included WTI Midland — American shale delivered into Europe — added because North Sea volumes were no longer sufficient to make the benchmark robust.
That change is worth knowing. The world's leading international oil benchmark now includes American crude, which links the two markets more directly than at any point in their history.
Brent is light and sweet, marginally heavier and slightly higher in sulphur than WTI, and it prices roughly two-thirds of internationally traded crude — African, Middle Eastern and much Russian oil is sold at a differential to it. It is the reference for European and much Asian import pricing.
The futures contract trades on ICE in London and is cash-settled against a published index rather than physically delivered. That removes the delivery risk that produced the 2020 WTI episode, which is one reason institutions holding long-dated exposure often prefer Brent.
The WTI–Brent spread and what it says
Before 2011, WTI generally traded at a small premium to Brent — a dollar or two — reflecting its slightly better quality.
Then American shale production surged and the pipeline infrastructure to move it out of Cushing did not exist yet. Crude piled up in Oklahoma with nowhere to go, and WTI fell to a discount of ten to fifteen dollars. Export infrastructure and the lifting of the US crude export ban in 2015 narrowed it again.
The spread is a working indicator. It reflects American production and inventory conditions on one side, and international supply risk on the other. When geopolitical risk concentrates around Middle Eastern shipping, Brent responds more sharply than WTI, because Brent prices the barrels that have to move through the affected routes. A widening Brent premium is usually the market pricing supply risk outside the United States.
Dubai: the Asian benchmark
Dubai, often quoted as Dubai/Oman, is medium sour: heavier at around 31 degrees API and much higher in sulphur at roughly 2%. It is harder to refine and therefore trades at a discount.
It matters because it is the reference for crude sold into Asia — China, Japan, India, South Korea — which is where demand growth is. European and American consumption is flat or declining; Asian consumption is not.
The Brent–Dubai spread is the useful signal. When Dubai strengthens relative to Brent, Asian demand is firm or Middle Eastern supply is tight. When it weakens, Asian buying is soft. Refiners and traders watch it as a real-time read on the region that sets the marginal demand for oil.
Dubai is also the benchmark most exposed to the Strait of Hormuz, because the physical crude behind it transits the strait. War risk insurance premiums on Hormuz transits feed directly into the delivered cost of Asian crude — one of the clearer illustrations of how a regional conflict reaches markets that are nowhere near it.
OPEC, OPEC+ and the limits of coordination
OPEC was founded in 1960 to coordinate production among major exporters. The mechanism is production quotas: cut output to raise prices, raise output to lower them. Saudi Arabia is the de facto leader, because it is the largest producer in the group and holds most of the world's spare capacity — the ability to increase production quickly, which is what gives a producer influence rather than merely volume.
OPEC+ is the wider arrangement, formed in 2016, that added Russia and other non-OPEC producers. At its peak the extended group covered roughly half of world production.
Its influence has been eroding, for reasons that are structural rather than cyclical.
American shale is a competing swing producer. Shale wells can be drilled and completed in months rather than years, and production responds to price within a couple of quarters. When OPEC+ cuts to raise prices, it hands market share to producers it does not control — the central strategic problem the cartel has faced for a decade.
Quota compliance is imperfect. Members regularly produce above their allocations, and enforcement depends on Saudi willingness to absorb the adjustment alone.
Membership is not permanent. Several countries have left over the years, and departures weaken the coordination that gives the group its remaining pricing power.
The practical point for a trader: OPEC+ announcements move prices immediately, but announced quotas are permissions, not deliveries. What is authorised and what actually reaches refineries are different numbers, and the gap between them is where the real supply balance sits.
What moves the price
Supply side. OPEC+ decisions; American shale activity, which responds to price with a lag of a few months; geopolitical disruption to production or transit; storage levels; and weather, particularly Gulf of Mexico hurricanes that close refineries and offshore output.
Demand side. Global growth, above all Chinese industrial activity; natural gas prices, which substitute in some industrial uses; the slow drag of electrification; and seasonality — heating demand in winter, driving and cooling demand in summer.
The dollar. Crude is quoted in dollars everywhere, so a stronger dollar mechanically raises the price of oil for every buyer using another currency, and demand softens. That convention is not an accident of history — it is the petrodollar arrangement, and it is slowly thinning at the edges.
The scheduled data. American inventory figures are released weekly and reliably move the price. Monthly reports from the IEA, OPEC and the US Energy Information Administration set the medium-term demand narrative.
The futures curve, which most retail traders ignore
This is the part that separates an oil position that works from one that quietly bleeds.
Oil futures trade with a curve of prices across delivery months, and the curve has two shapes.
Contango means later months cost more than nearer ones. It reflects storage costs and comfortable supply. A long position rolled forward each month sells the cheap expiring contract and buys the more expensive next one, losing money on every roll even if the spot price never moves.
Backwardation means later months are cheaper. It signals tight physical supply — buyers paying up for immediate delivery — and it pays the holder of a rolled long position.
This is why oil exchange-traded funds can badly underperform the oil price over long periods. A fund holding front-month futures in persistent contango loses on every roll, and the tracking error compounds. Several oil ETFs demonstrated this at scale during 2020, when severe contango turned a correct view on the oil price into a substantial loss.
The curve is also information in its own right: steep backwardation is the physical market saying it is short of barrels now, which is often more reliable than any headline about future supply.
How to take a position
Futures are the direct route, with real leverage, defined contract sizes and the roll and delivery mechanics described above. Not suitable for small accounts, and WTI in particular requires attention to expiry.
CFDs are the common retail route, usually referencing the front-month future. They carry the same roll effect, applied as an adjustment to the position rather than visibly, plus overnight financing.
ETFs are simplest but carry the contango drag unless they hold longer-dated contracts or a spread across maturities. Read what the fund actually holds before assuming it tracks the oil price.
Energy equities give oil exposure with company risk attached — a producer's shares can fall while oil rises, and refiners are exposed to the crack spread rather than to crude.
Currencies are an indirect but liquid route. The Canadian dollar and Norwegian krone carry positive oil exposure; the yen and most emerging market currencies carry negative exposure through the import bill. For anyone already trading foreign exchange, this expresses the macro view without touching the roll mechanics at all.
Three benchmarks, one market
WTI prices American crude at a pipeline hub in Oklahoma and settles physically. Brent prices internationally traded crude, settles in cash, and now includes American barrels in its own basket. Dubai prices the sour crude that Asia actually buys, and carries the most direct exposure to Gulf transit risk.
The spreads between them are not noise. They are the market telling you where the constraint sits — American infrastructure, international supply risk, or Asian demand — and reading them is more informative than watching any single number.
