Fuel Oil Desulfurization Margins Dictate the Spread Between Light and Heavy Crude Benchmarks

When the price gap between a barrel of light Texas crude and a barrel of heavy Canadian crude widens, oil traders point to supply gluts. They argue that OPEC production cuts or new pipeline capacities are flooding the market with one grade while starving it of another, driving the benchmarks apart.

Refinery engineers look at the exact same price spread and point to the natural gas market. To a plant operator, the discount on heavy crude is not a reflection of global oil supply, but a strict mathematical function of what it costs to buy the hydrogen required to strip the sulfur out of it.

Both camps are pricing the same physical commodity, but they are trading entirely different mechanisms. The trader trades the geopolitical flow of liquid volume, while the refiner trades the chemical cost of molecular conversion.

The reality of the modern energy market is that the chemical cost usually wins. The spread between light-sweet and heavy-sour crude is fundamentally dictated by the desulfurization margin—the operating expense of turning dirty residual fuel into legally compliant products.

The API and Sulfur Grid

There is no such thing as a generic barrel of oil. A cargo of West Texas Intermediate (WTI) and a cargo of Mexican Maya or Western Canadian Select (WCS) are fundamentally different industrial inputs that require entirely different processing hardware.

The difference is measured on two axes: density and sulfur. Density is tracked by API gravity, an inverse scale where higher numbers mean lighter liquid. Light crude, sitting above 35 degrees API, flows easily and naturally boils off into high-value gasoline and diesel.

Heavy crude, falling below 25 degrees API, is dense, viscous, and yields a massive proportion of residual fuel oil. "Light and sweet is easy money for a simple plant and commands a premium," notes industry analysis from The Oil Slick. "Heavy and sour is a discount that only a deep-conversion refinery can turn into profit."

The second axis is sulfur, a corrosive contaminant that poisons refinery catalysts and produces toxic sulfur dioxide when burned. Crude with less than 1 percent sulfur is "sweet," while anything above that threshold is "sour" and requires intensive chemical scrubbing before it can be sold.

The Hydrogen Toll

Stripping sulfur from heavy crude is not a passive filtration process. It requires hydrodesulfurization, a high-pressure, high-temperature catalytic reaction that forces hydrogen gas into the hydrocarbon molecules to bind with the sulfur, creating hydrogen sulfide that can be safely extracted.

Hydrodesulfurization demands a massive and constant supply of pure hydrogen. Because hydrogen does not exist freely in nature in usable volumes, refineries must manufacture it on-site, overwhelmingly through an industrial process called steam methane reforming.

Steam methane reforming uses natural gas as its primary feedstock. Therefore, the cost of removing sulfur from heavy crude is directly tethered to the price of natural gas. When natural gas prices spike, the cost of producing hydrogen spikes in tandem.

The U.S. Energy Information Administration explicitly links these markets, noting that higher natural gas prices directly increase refinery feedstock costs for treating sour crude. "Higher costs have led to lower demand for sour crude oils that incur more of these costs, at the same time increasing demand for sweeter crude oils," the agency reports.[1]

The IMO 2020 Shock

The cost of sulfur removal became an existential market force on January 1, 2020. On that date, the International Maritime Organization implemented a global regulation capping the sulfur content of marine bunker fuel at 0.5 percent, down from the previous 3.5 percent limit.

Before the IMO 2020 regulation took effect, refineries could take the high-sulfur residual fuel oil left over from refining heavy crude and sell it directly to the global shipping fleet. The ocean served as the ultimate, unregulated sink for the bottom of the crude barrel.

The new regulation split the bunker market in two. Ships had to either burn compliant very low sulfur fuel oil (VLSFO) or install expensive exhaust gas cleaning systems, known as scrubbers, to continue burning high-sulfur fuel oil (HSFO) legally.

This regulatory shift forced refineries to either heavily discount their HSFO to the fraction of ships equipped with scrubbers, or spend the capital and operating expenses to hydrotreat the residual fuel down to VLSFO standards. The price spread between VLSFO and HSFO became a critical metric for refinery survival.

Calculating the Spread

The VLSFO-HSFO spread is highly volatile and dictates the economics of the entire barrel. In late 2019, ahead of the IMO deadline, the spot spread in Northwest Europe traded as high as $290 per tonne, before collapsing to below $45 per tonne during the demand shocks of 2020.[3]

That spread dictates the heavy crude discount. If a refinery buys heavy sour crude, it knows a large percentage of that barrel will end up as HSFO. If the penalty for selling HSFO is steep, the refinery must demand a steeper discount on the raw crude to break even.

The Federal Reserve Bank of Kansas City tracked this dynamic in the North American market. Between January 2024 and March 2025, the price spread between light-sweet WTI and heavy-sour Western Canadian Select narrowed from $19 per barrel down to $11 per barrel.[2]

That $11 to $19 window is not arbitrary. It represents the exact capital and operating margin required to run the complex hydrocracking and desulfurization units that a light-sweet barrel allows a refinery to bypass entirely. If the spread drops below that margin, processing heavy crude destroys capital.

Complexity and Capital

Processing heavy sour crude requires a facility with a high Nelson Complexity Index, a metric that quantifies a refinery's sophistication. While a plant processing light sweet crude might operate with an index of 5 to 7, handling heavy sour grades requires an index exceeding 10.[4]

These complex refineries command premium processing margins, typically $12 to $18 per barrel compared to the $8 to $12 per barrel earned by simpler plants. They earn this premium precisely because they possess the rare hardware capable of breaking down the heavy molecules.[4]

However, that hardware is immensely expensive to build and operate. High-pressure hydrodesulfurization equipment requires specialized metallurgy, explosion-proof zone designs, and massive compressors to handle the flammable hydrogen gas at pressures up to 10.0 megapascals.

If the discount on heavy crude shrinks below the operating cost of those units, complex refineries will simply refuse to buy it. They will pivot to lighter grades, leaving heavy crude producers without buyers until the price drops back below the desulfurization threshold.

The Coking Alternative

Desulfurization is not the only way to handle the bottom of the barrel. Some deep-conversion refineries utilize coking units, which use extreme heat to thermally crack residual fuel oil into lighter distillates and solid petroleum coke.

Cokers bypass the hydrogen cost entirely by destroying the residual fuel rather than cleaning it. For a refinery equipped with a coker, the economics of heavy crude are dictated by the price of petroleum coke and the energy cost of running the furnace, rather than the natural gas market.

Yet coking capacity is strictly limited globally, and building new units requires billions of dollars in capital expenditure. The marginal barrel of heavy crude must still be processed through hydrotreating, leaving hydrogen costs as the ultimate price setter for the broader market.

As environmental regulations tighten and the push for green hydrogen—produced via renewable electrolysis rather than fossil fuels—gains traction, the cost of desulfurization will evolve. Until then, the gap between light and heavy oil will remain tethered to the price of the natural gas required to clean it.[6]

The transition to green hydrogen introduces a new variable into the spread calculation. Because green hydrogen is currently more expensive than fossil-derived gray hydrogen, refineries piloting electrolysis units face higher immediate operating costs, which could temporarily widen the required discount for heavy crude.[6]

Ultimately, the crude oil market is a market of margins, not just volumes. As long as sulfur remains a regulated contaminant, the price of heavy oil will never be independent of the industrial cost required to remove it.