Crude Oil Markets: WTI vs Brent and What They Mean

Two Benchmarks, One Global Market

The world consumes roughly 100 million barrels of crude oil every day. That oil comes from dozens of countries, out of thousands of wells, in hundreds of slightly different chemical compositions. Yet the price of nearly all of it is set by reference to just two benchmark grades: West Texas Intermediate (WTI) and Brent. If you want to understand oil markets, or the price of gasoline, or the economic consequences of the Hormuz disruption, you need to understand these two numbers and why they sometimes disagree.

WTI is a grade of light, sweet crude oil produced in the Permian Basin and other fields across Texas, New Mexico, and Oklahoma. "Light" means it has a relatively low density (API gravity of about 39.6 degrees), which makes it easier to refine into gasoline and other high-value products. "Sweet" means it has low sulfur content (about 0.24%), which means less processing to remove sulfur compounds. WTI is, by the standards of the global oil market, an exceptionally high-quality crude.

Brent is a blend of crude oils originally produced from fields in the North Sea, between Norway and the United Kingdom. The name comes from the Brent oilfield, which Shell named after the Brent goose. Brent crude is also light and sweet, though slightly heavier and more sulfurous than WTI (API gravity around 38.3 degrees, sulfur content around 0.37%). In practice, the quality difference between WTI and Brent is modest, and refineries configured for one can generally process the other without difficulty.

The real differences between them are not chemical. They are geographic, logistical, and contractual. And those differences matter enormously for price.

Where They Trade

WTI futures trade on the New York Mercantile Exchange (NYMEX), which is part of the CME Group. The front-month WTI contract is the single most actively traded commodity futures contract in the world by volume, with open interest routinely exceeding 2 million contracts, each representing 1,000 barrels. The contract specifies physical delivery at Cushing, Oklahoma, a landlocked pipeline hub where roughly 80 million barrels of crude oil storage capacity sits at the intersection of several major pipeline systems. Cushing is not a port. It is not near a refinery cluster. It is a pipeline crossroads in the middle of the United States, and that geographic fact shapes everything about WTI pricing.

Brent futures trade on the Intercontinental Exchange (ICE), headquartered in London. The Brent contract is cash-settled, meaning that at expiration it does not require physical delivery of oil at a specific location. Instead, the contract settles against a price assessment of physical cargoes loading from five North Sea fields (Brent, Forties, Oseberg, Ekofisk, and Troll, collectively known as BFOET). The cash-settlement mechanism is important: it means Brent pricing reflects the broader seaborne crude oil market rather than conditions at any single delivery point.

This structural difference, physical delivery at a landlocked hub versus cash settlement against seaborne cargoes, is the single most important reason WTI and Brent prices diverge.

Why the Prices Diverge

If WTI and Brent were interchangeable commodities trading in a perfectly connected global market, their prices would be identical after adjusting for quality and transportation. In reality, they often trade at significantly different prices, and the gap between them (the WTI-Brent spread) tells a story about the state of the oil market that is more useful than either price alone.

1. The Cushing Bottleneck

Because WTI settles by physical delivery to Cushing, its price is acutely sensitive to conditions at Cushing. When storage tanks at Cushing fill up, traders holding expiring contracts face a problem: they must either take delivery of physical oil (which requires having storage space or pipeline capacity to move it) or sell the contract at whatever price the market offers. In extreme cases, this dynamic can push WTI prices far below Brent.

The most dramatic example occurred on April 20, 2020, when the May WTI contract settled at negative $37.63 per barrel. That was not a typo. Traders were paying other traders to take oil off their hands because Cushing storage was nearly full, demand had collapsed due to the COVID-19 pandemic, and there was nowhere to put the oil. Brent, which does not have a physical delivery mechanism tied to a single storage hub, fell to about $19 per barrel on the same day. The spread between them exceeded $50. The lesson was clear: WTI pricing can be distorted by logistics at a single inland facility in ways that have nothing to do with global oil supply and demand.

2. Transportation and Access to the Sea

Brent-referenced crude is seaborne oil. It loads onto tankers in the North Sea and can be shipped anywhere in the world. A cargo of Forties crude loading at Hound Point, Scotland, is equally available to a refiner in Rotterdam, a refiner in South Korea, or a refiner in India. The price of Brent therefore reflects the global competition for crude oil among refiners worldwide.

WTI crude, by contrast, was historically landlocked. Oil produced in the Permian Basin moved by pipeline to Cushing, and from Cushing by pipeline to refineries along the Gulf Coast. Until about 2015, there was no efficient way to export WTI crude by tanker because the United States maintained a ban on crude oil exports (a policy relic of the 1970s energy crisis, repealed in December 2015). Even after the export ban was lifted and new pipeline capacity from the Permian to Gulf Coast export terminals was built, the cost of moving WTI crude from Cushing to the waterfront added $2-5 per barrel to the effective price, keeping WTI persistently cheaper than Brent in international terms.

Today, with Gulf Coast export infrastructure substantially expanded, WTI has better access to the seaborne market than it did a decade ago. But the transportation cost has not disappeared, and during periods of pipeline congestion or storage buildup at Cushing, the landlocked premium re-emerges.

3. Quality Differentials

WTI is marginally lighter and sweeter than Brent. In theory, this should make WTI slightly more expensive, because lighter, sweeter crude yields more gasoline per barrel with less refining effort. In practice, the quality premium is small (roughly $1-2 per barrel under normal conditions) and is frequently overwhelmed by the logistical factors described above. When you see WTI trading $5 or $10 below Brent, the quality differential is not the explanation. Transportation and storage dynamics are.

4. Geopolitical Exposure

Brent is the benchmark for roughly 80% of internationally traded crude oil. Contracts for crude from Africa, the Middle East, and Europe are typically priced as a differential to Brent (for example, "Brent plus $2" or "Brent minus $1.50"). This means that any disruption to international supply, whether it originates in the Strait of Hormuz, the Red Sea, Nigeria, or Libya, feeds directly into Brent pricing. WTI, while influenced by the same global dynamics, is buffered by the fact that U.S. domestic production is not directly affected by most international supply disruptions. The United States produces roughly 13 million barrels per day, making it the world's largest producer, and that production is largely insulated from the geopolitical risks that move Brent.

The result: Brent is more volatile in response to international crises. WTI follows, but with a lag and often at a discount. The size of that discount is itself a measure of how much the crisis is an international problem versus a domestic one.

What the WTI-Brent Spread Tells You

The spread between WTI and Brent is one of the most watched indicators in commodity markets, not because the absolute number matters but because changes in the spread signal specific conditions.

As of April 2026, the Brent-WTI spread has widened to roughly $13 per barrel, driven almost entirely by the Hormuz crisis. International crude supplies are constrained; U.S. domestic production is not. The spread is telling you that the crisis is an international supply problem, not a domestic one, and that U.S. consumers are partially insulated by the sheer volume of American production. Partially, not fully. WTI has still risen from $68 to $105 because global oil markets are connected, and U.S. Gulf Coast refiners compete for crude with refiners worldwide.

How to Read Oil Futures Curves

Oil does not trade at a single price. At any moment, you can buy or sell contracts for delivery in every month stretching years into the future. The relationship between near-month and far-month prices, the shape of the futures curve, reveals what the market collectively expects about supply and demand conditions over time.

Contango: Costs More Later

When the futures curve slopes upward (the price for delivery six months from now is higher than the price for delivery today), the market is in contango. Contango is the normal state of most commodity markets because storing a physical commodity costs money. Storage fees, insurance, financing, and opportunity costs all add up. A futures curve in contango is pricing those carrying costs into forward delivery months.

But contango can also signal oversupply. When the market has more oil available today than refiners want to process, the spot price falls relative to futures. In extreme contango (the deep contango of April 2020, for instance), the market is telling you that oil is so abundant today that traders are willing to pay to store it for months, betting that prices will recover. An oil tanker sitting idle in a harbor, loaded with crude waiting for better prices, is the physical manifestation of contango.

Backwardation: Costs More Now

When the curve inverts, with near-month prices higher than deferred months, the market is in backwardation. This is the signal to pay attention to. Backwardation means the market needs oil right now more than it expects to need oil later. Refiners are bidding up spot prices because current supply is tight. Traders have no incentive to store oil because today's price already exceeds tomorrow's price.

Sustained backwardation typically indicates genuine supply tightness, either because production has been cut, inventories are low, or demand is running ahead of supply. The current oil market, shaped by the Hormuz disruption, is in steep backwardation. The front-month Brent contract trades at roughly $118. The contract for delivery 12 months from now trades at about $90. That $28 gap is the market saying: we need oil now, and we expect this crisis to ease eventually, but we are not willing to bet on when.

For consumers, backwardation is the worse of the two states. It means the pain at the pump is real and immediate, not a speculative artifact. When the curve is in contango, high prices may reflect storage plays and financial positioning. When the curve is in backwardation, high prices reflect physical scarcity.

OPEC+ and Production Decisions

No discussion of oil prices is complete without OPEC+, the cartel-plus-allies group that collectively controls roughly 40% of global crude oil production and an even larger share of spare capacity. OPEC+ comprises the 13 members of the Organization of the Petroleum Exporting Countries (led by Saudi Arabia) plus 10 allied non-OPEC producers (most notably Russia). The group's production decisions are, alongside supply disruptions, the most powerful short-term driver of oil prices.

OPEC+ manages supply through a quota system. Each member agrees to produce no more than a specified volume per day, and the group adjusts total quotas based on market conditions. In practice, Saudi Arabia functions as the swing producer: it holds the world's largest spare production capacity (estimated at 2-3 million barrels per day) and can raise or lower output faster than any other producer. When Saudi Arabia increases production, prices fall. When Saudi Arabia cuts production, prices rise. The kingdom's production decisions are arguably the single most consequential economic policy actions on Earth.

The 2026 Hormuz crisis has complicated OPEC+ dynamics considerably. Saudi Arabia is the world's largest exporter through Hormuz. The kingdom's ability to increase production is constrained by the fact that much of its export infrastructure terminates at Ras Tanura and other Gulf terminals that depend on Hormuz transit. Saudi Arabia can redirect some volume through the East-West Pipeline to Yanbu on the Red Sea, but that route's capacity (roughly 2 million barrels per day operational, versus theoretical 5 million) limits the option, and Yanbu itself faces Red Sea shipping risks from Houthi attacks.

Other OPEC+ members outside the Gulf, notably the UAE (via its Fujairah bypass pipeline), Iraq (if the Turkey pipeline reopens), and African producers like Nigeria and Angola, could theoretically increase supply. But most OPEC+ members are already producing near their capacity limits, and the spare capacity that exists is concentrated in Saudi Arabia and the UAE, precisely the countries most affected by Hormuz.

The Crack Spread: From Crude to Gasoline

Crude oil is not gasoline. A barrel of crude must be refined, a process that involves heating, distillation, catalytic cracking, and blending, before it becomes the gasoline, diesel, jet fuel, and other products consumers actually use. The price difference between crude oil and refined products is called the crack spread, and it is the refining industry's profit margin.

The most commonly cited crack spread is the 3-2-1 crack: for every three barrels of crude oil input, a refinery produces approximately two barrels of gasoline and one barrel of distillate (diesel/heating oil). The 3-2-1 crack spread is calculated as:

(2 x gasoline price + 1 x distillate price - 3 x crude oil price) / 3

A "normal" 3-2-1 crack spread ranges from $10 to $20 per barrel. When crack spreads widen above $20, it typically signals that refined product demand is outpacing refining capacity, either because crude supply is abundant but refining capacity is constrained, or because seasonal demand (driving season, winter heating) is surging. When crack spreads narrow below $10, refineries begin cutting runs because the margin no longer justifies the cost of operation.

In the current environment, crack spreads have widened to roughly $30-35 per barrel for the Gulf Coast 3-2-1 crack. This is partly because crude supply disruptions from Hormuz have tightened refinery input availability, and partly because U.S. refinery utilization is already running at 90%+ of capacity. Refineries cannot simply process more crude to bring product prices down; they are already running near their physical limits. The widened crack spread adds another $5-8 per barrel on top of the crude price increase, meaning consumers are paying a premium for both the crude oil shortage and the refining bottleneck.

The 2026 Hormuz Effect on Both Benchmarks

The ongoing Hormuz crisis provides a real-time illustration of everything discussed above. Before the disruption began in March 2026, Brent traded at roughly $75 per barrel and WTI at roughly $68, a spread of about $7. As of mid-April 2026, Brent is at approximately $118 and WTI at approximately $105, a spread of about $13.

The asymmetry is telling. Brent has risen about $43 per barrel (57%). WTI has risen about $37 per barrel (54%). Both moved substantially because global oil markets are interconnected, but Brent moved more because international seaborne crude supply is more directly affected by the loss of Hormuz transit capacity. The widened spread is the market pricing in the fact that European, Asian, and African refiners who depend on Gulf crude are facing more severe supply constraints than American refiners who can source domestically.

The futures curve tells the rest of the story. Both WTI and Brent are in steep backwardation, with near-month contracts trading well above contracts 6-12 months forward. The market expects the crisis to eventually resolve, or at least for alternative supply routes to partially compensate, but it is not willing to bet on a timeline. That backwardation is the reason gasoline prices have risen so sharply: the market is paying a premium for oil right now, and refineries are passing that premium through to the pump.

For American consumers, the arithmetic works out roughly like this: the $37 increase in WTI translates to approximately $0.90 per gallon in higher gasoline costs, transmitted with a lag of two to four weeks. The widened crack spread adds another $0.15-0.20 per gallon. Add in higher transportation and distribution costs (diesel is also more expensive, raising the cost of trucking gasoline to stations), and the total Hormuz-attributable increase at the pump is approximately $1.10-1.30 per gallon above pre-crisis levels.

Why Retail Investors Watch Crude Oil

Crude oil is the most actively traded commodity in the world and the third most actively traded asset class behind U.S. Treasuries and the S&P 500. Individual investors watch it for several reasons, some sound and some questionable.

As a macro indicator. Oil prices correlate with economic activity. Rising prices can signal strong demand (growth) or supply disruption (risk). Falling prices can signal weakening demand (recession) or supply glut (overproduction). The direction of oil prices, and especially the shape of the futures curve, provides information about the market's collective expectation for the global economy that is available nowhere else.

As an inflation input. Energy is a direct component of the Consumer Price Index, and oil prices feed into transportation costs that affect the price of virtually everything else. Investors watching for inflation signals pay close attention to oil because it leads consumer price changes by weeks to months. The Federal Reserve watches it for the same reason.

As a portfolio hedge. Oil prices tend to spike during geopolitical crises, which are often the same events that cause equity markets to decline. An allocation to crude oil futures or oil-linked ETFs can provide a portfolio hedge against geopolitical risk, though the correlation is imperfect and the costs of maintaining a long futures position (due to contango and roll costs) can erode returns over time.

As a tradeable asset. The liquidity of WTI and Brent futures is exceptional. The bid-ask spread on front-month WTI is typically one cent per barrel, and daily volume routinely exceeds one million contracts. For traders who have a view on supply, demand, or geopolitics, crude oil markets offer the deepest, most liquid venue to express that view.

The risks are equally clear. Crude oil is volatile. WTI's annualized historical volatility runs 30-40% in normal markets and can spike above 80% during crises. The April 2020 negative price episode demonstrated that even sophisticated participants can be caught off guard. Oil-linked ETFs, particularly those that hold front-month futures and roll forward each month, are subject to contango drag that can reduce returns substantially below the underlying commodity's performance. The popular USO fund lost roughly 80% of its value in 2020 even as WTI recovered to $40 per barrel within months of its negative print, because the fund's rolling mechanism locked in losses as it sold cheap expiring contracts and bought more expensive forward contracts each month.

Key Takeaways