Ethanol, biodiesel and renewable diesel are three different products made three different ways. Ethanol comes from fermenting starch or sugar. Biodiesel comes from a chemical swap called transesterification, and renewable diesel comes from a refinery process called hydrotreating that produces a fuel nearly identical to petroleum diesel. That’s why renewable diesel can go straight into a diesel engine or a pipeline at full strength, while biodiesel usually tops out well below that.
How each fuel gets made
Ethanol is grain alcohol. Producers use yeast to ferment the starch or sugar in corn or sugarcane, then distill the result up to fuel grade and add a denaturant so it can’t be sold as a beverage before it’s blended into gasoline, as the Energy Information Administration explains. It’s the same basic biology as a distillery, aimed at a gas tank instead of a bottle.
Biodiesel takes a different chemical path. A producer reacts vegetable oil or animal fat with a short-chain alcohol, almost always methanol, using a catalyst such as sodium or potassium hydroxide. Roughly 100 pounds of oil combined with about 10 pounds of methanol yields 100 pounds of biodiesel and 10 pounds of glycerin, according to the Department of Energy’s Alternative Fuels Data Center. That glycerin isn’t waste. It’s sold into pharmaceutical and cosmetics manufacturing, feeding a plant’s bottom line.
Renewable diesel skips transesterification. Refiners run the same fats and oils through hydrotreating, adding hydrogen under heat and pressure to strip out oxygen and produce what the industry calls hydroprocessed esters and fatty acids, or HEFA. The output is a hydrocarbon chain almost indistinguishable from petroleum diesel, so it meets ASTM D975, the petroleum diesel spec, instead of the separate ASTM D6751 standard written for biodiesel, per EIA.
What feeds the vats and reactors
Corn is the dominant US ethanol feedstock, and it’s likely to stay that way. Cellulosic ethanol made from non-food plant material such as corn stover or switchgrass is technically feasible, but as of the end of 2022 the country had no commercial cellulosic ethanol production running at all, per EIA.
Biodiesel and renewable diesel draw on a more overlapping feedstock pool, led in the US by soybean oil, with animal fats and used cooking oil or yellow grease from restaurants filling out most of the rest, and rapeseed and palm oil more common abroad, according to EIA.
From the operations side, feedstock cost is the line that decides whether a renewable diesel plant turns a profit in a given quarter, since soybean oil and used cooking oil trade in commodity and export markets that move for reasons that have nothing to do with fuel policy.
How much of each you can put in a tank
| Fuel | Common blends | Blending limit |
|---|---|---|
| Ethanol | E10, E15, E85 | Roughly a 10% average blend wall across the gasoline pool |
| Biodiesel | B2, B5, B20, B100 | Many vehicle warranties cap it around B20 |
| Renewable diesel | R20 through R100 | None. It’s a true drop-in fuel |
Nearly all US gasoline is sold as E10, 10% ethanol and 90% gasoline. E15, approved for cars from model year 2001 onward, runs up to 15% ethanol, and E85, at 51% to 83% ethanol, needs a flex-fuel vehicle and is sold at roughly 4,300 stations concentrated in the Midwest, per EIA.
The “blend wall” describes the point where the national gasoline supply can’t absorb more ethanol without pushing the average blend rate above 10%. Ethanol’s share of gasoline consumption first cleared 10% in 2017, according to EIA, and hit 10.38% in 2022, per the Renewable Fuels Association. The same group counted about 634 million gallons of 2023 ethanol consumption above that ceiling, credited mostly to E15 growth and exports.
Biodiesel usually shows up as B2 or B5 at the pump. B20 is common in fleet contracts, and B100 is for equipment built to run on it, per EIA. Renewable diesel faces no such ceiling. Chemically identical to petroleum diesel, it runs as R100, straight and undiluted, or blended at any ratio, without the warranty concerns that limit biodiesel.
The federal program that created this market
Almost none of this scale would exist without the Renewable Fuel Standard. Refiners and importers, the program’s “obligated parties,” must retire enough Renewable Identification Numbers, or RINs, to meet an annual quota, with one RIN standing in for one ethanol-equivalent gallon, per EPA. RINs carry a D-code by feedstock and required emissions cut: D6 for conventional biofuel like corn ethanol (20%), D5 for advanced biofuel (50%), D4 for biomass-based diesel (50%), and D3 for cellulosic biofuel (60%).
EPA finalized the 2026 and 2027 volume requirements on March 27, 2026, setting total renewable fuel obligations at 26.81 billion RINs for 2026 and 27.02 billion for 2027, with biomass-based diesel alone set at 9.07 billion for 2026, per the agency’s final rule. Part of that jump reflects reallocated small refinery exemptions from 2023 through 2025.
The market noticed. By June 4, 2026, D4 biomass-based diesel RINs traded around $2.41 and D6 ethanol RINs around $2.37, both near 2021’s all-time highs and roughly double where they started the year, per EIA. EIA expects 2026 ethanol production up about 2% from 2025. Renewable diesel is expected to climb about 24%, biodiesel about 41%.
California’s carbon math, and the credit that replaced it
California runs its own system on top of the federal one. Its Low Carbon Fuel Standard, or LCFS, sets a declining carbon-intensity benchmark for transportation fuel sold in the state, and fuel scoring below the benchmark earns credits sold to fuel scoring above it, per CARB. Tighter benchmarks took effect July 1, 2025, splitting the year into two compliance periods, per CARB’s FAQ. Biodiesel and renewable diesel both earn LCFS credits when they beat the benchmark, and that value stacked on federal RIN value often makes a West Coast renewable diesel plant pencil out.
A newer federal tax credit reshaped the incentive further. The Clean Fuel Production Credit, known as 45Z, replaced older, separate blender credits for biodiesel and sustainable aviation fuel with one production-side credit, effective for fuel produced starting January 1, 2025, per the American Farm Bureau Federation. It pays 20 cents a gallon at the base rate, scaling up to $1 a gallon for fuel with the largest calculated emissions cut under the Department of Energy’s GREET lifecycle model.
Congress’s 2025 reconciliation law, the One Big Beautiful Bill Act, extended 45Z through 2029 and excluded indirect land-use-change emissions (ILUC) from the carbon-intensity math, lowering the scored emissions for corn ethanol and soy biodiesel by 20 to 25 grams of CO2-equivalent per megajoule, per the Clean Air Task Force. The same law cut the SAF credit from $1.75 a gallon to the same $1 cap as other biofuels, a 43% reduction, and now limits qualifying feedstock to North America. The nonpartisan cost estimate for the credit through 2029 grew to $25.7 billion, up from roughly $2.9 billion projected for the original four-year version in 2022.
Sustainable aviation fuel is next
Sustainable aviation fuel, or SAF, mostly runs through the same HEFA hydrotreating process as renewable diesel, finished to jet fuel specifications instead of diesel. US SAF production capacity sat at around 2,000 barrels a day at the start of 2024, spread across two plants, per EIA.
Capacity built fast. Phillips 66 finished a 10,000-barrel-a-day project at its Rodeo, California refinery in the third quarter of 2024, and Diamond Green Diesel completed a 15,000-barrel-a-day plant in Port Arthur, Texas that same year, per EIA. By 2025, total capacity had grown to roughly 30,000 barrels a day.
Even at that growth rate, SAF is expected to stay under 2% of the roughly 1.7 million barrels a day of jet fuel the US consumes through 2025 and 2026, per EIA. What caps SAF’s growth is feedstock. It draws on the same finite pool of waste fats and vegetable oil as ethanol, biodiesel and renewable diesel, and competes with them for the same 45Z credit.
The food-versus-fuel argument isn’t settled
Rising mandates mean rising demand for feedstock that also feeds people and livestock. The 2026-27 biomass-based diesel quota represents roughly a 50% jump over 2024 levels, and EPA estimated biodiesel producers would need about 250 million additional gallons a year to comply, equal to about 4% of current US soybean production, according to the Federal Reserve Bank of Kansas City. US corn and soybean yields have climbed about 20% since 2010, but export growth to competitors like Brazil has stalled, leaving biofuel demand as one of the few growth outlets for US crop production.
That’s the case producers and farm groups make for expanding the mandates. Critics look at the same numbers and see cropland, and its carbon footprint, getting redirected toward fuel instead of food. The 45Z exclusion of ILUC sharpens that fight. Leaving it out lowers the official score for corn ethanol and soy biodiesel, but it doesn’t change what happens on the ground if US farmland devoted to fuel pushes crop production onto land that would otherwise stay in pasture or forest. Producers counter that the old ILUC penalty rested on modeling assumptions rather than a measured outcome, and neither side has new data that changes the other’s mind.
The volume mandates and the production tax credit both reward more biofuel output, and the RIN and LCFS markets are pricing that in. Whether the extra gallons come from waste fats and marginal acreage, or from prime farmland shifting out of food and feed use, is a distinction the incentives don’t make.
