The basics of US renewable diesel

Low-carbon renewable fuels have a role to play in US energy supply mix, even as certain user groups for liquid fuels are able to electrify. With current technology, some user segments may find it difficult to make a near-term switch from conventional fuel or its renewable substitutes to alternatives like electrification or fuel cells. The viability of the switch to electric or fuel cell technology largely depends on the use case, including factors such as the intensity, duration, and location of use.

The US federal Renewable Fuel Standard (RFS), which mandates renewable fuel volumes, and various state-level clean fuels programs[1] support the use case for low-carbon fuels, including renewable diesel (RD). These programs are a major driver of the significant growth of the consumption and production of renewable diesel. In some instances this growth has also been supported by production economics linked to feedstock prices. In turn, the proliferation of renewable diesel has led to oversupply, weighing on the value of D4 RINs – the credit applicable to biomass-based diesel – and LCFS credit values. That has led to some rationalization across renewable fuel production – both renewable diesel and biofuels. Biofuels tend to be less advantaged for LCFS credit generation than renewable diesel is, due to their comparatively higher carbon intensity score and lower energy density.

[1] Such as the California Low Carbon Fuel Standard (LCFS), which awards credits that represent a reduction in the carbon intensity of transportation fuels. One LCFS edit is equivalent to one metric ton CO2-equivalent.

RD is considered a “drop-in” fuel, which can be used one-for-one in place of conventional diesel. That gives RD an advantage over biodiesel, which is subject to a so-called “blend wall,” as it is limited to blends of 5% to 20%, depending on its feedstock origin. Biodiesel requires blending due to the presence of oxygen in its molecules. Because RD is hydrogenated, it has oxygen-free molecules, avoiding the blend wall. RD’s cold flow properties – how the fuel operates in cold conditions – are similar to those of conventional diesel. Some other biofuels may encounter operational issues under cold conditions because they start to gel or the fuel does not move properly.

Used cooking oil, tallow, other waste oils, soy, corn, and canola oils can all serve as feedstocks for renewable diesel. Much of the feedstock slated for renewable diesel is considered a waste product, rather than cannibalization of potential foodstuffs. Soybean oil lost most of its edible end use market after scientific studies showed that hydrogenated fats contributed to LDL cholesterol (and the subsequent revocation of its “Generally Recognized as Safe” (GRAS) designation by the FDA). Once soybean oil lost the edible food market, biomass-based diesel became a critical end use market. Corn oil used in RD generally is an industrial byproduct of ethanol production and unfit for consumption. RD can use industrial tallow as a feedstock, a byproduct of meat processing and generally unfit for consumption. Some renewable diesel feedstocks may be fit for consumption, including some used cooking oil.

In the near term, demand for distillate fuel oils is not expected to slow down. The US Energy Information Administration (EIA) forecasts in its latest Short Term Energy Outlook that consumption of distillate fuel oil – a category that includes diesel fuels for on-highway and off-highway use (railroad, agricultural uses) and fuels oils – will actually increase marginally in 2025 versus 2024 (see Figure 2).

There is a limited selection of substitutes for conventional diesel, which currently accounts for just some 20% of energy used in the US transportation sector. For some vehicle classes, such as passenger vehicles, electrification may be an option. Return-to-base fleets that can use behind-the-gate fueling infrastructure on their route, and potentially charge overnight, are another example of such a use case.

Heavy-duty long-haul transport, a typical consumer of diesel, faces some barriers to electrification, particularly given weight and range considerations. In particular, long-haul transport in the US, which is dominated by Class 8 vehicles, will be difficult to transition in the near term to other alternative fuels or to electrify from two key perspectives (see Figure 3, Figure 4). Adoption in long-haul transport will require a significant build-out of infrastructure for alternative fueling. Any infrastructure would need to be robust enough to still allow intrastate truck drivers subject to the Federal Motor Carrier Safety Administration Hours of Service Regulations[2] to maintain similar scheduling, maximizing travel within their mandated safe driving hours.[3] Additionally, annual truck mileage in the long-haul segment is typically 80,000 to 100,000 miles per year (500 to 600 miles per day), so maximizing distance is critical for the segment use case and profitability.

[2] Generally applicable to trucks weighing 10,001 pounds or more, including load engaged in interstate commerce.

[3] Requiring a 30-minute break after eight hours of driving and stoppage of all work after the 14th consecutive hours of being on duty (inclusive of meal breaks, bathroom breaks, nap etc,) requiring 10 consecutive hours off-duty following this period. Within that 14-hour period, only 11 hours of driving time is permitted.

Even if there were sufficient infrastructure, in the case of battery electric vehicles (BEVs), there would still be a significant issue of loss of payload. A heavy-duty truck battery can weigh 5,000 to10,000 pounds. Given a federal regulation that prohibits more than 80,000 pounds on interstate highways, such a cannibalization of payload for an industry typically characterized by narrow profitability margins may not be feasible. While hydrogen fuel cells could potentially be an alternative fuel option, commercialization of clean hydrogen in the US has been slow. The availability of hydrogen and the scalability of related hydrogen infrastructure will act as a regulator of growth, as will the incremental cost of the vehicle. However, this does not rule out adoption for certain use cases where there is return-to-base fueling. This would negate a profound alternative fueling infrastructure concern, but still require access to hydrogen. Given the fuel availability and cost, we view the hydrogen fuel cell market as unlikely to evolve into a mainstream transportation market.

Second, the ownership model within long-haul trucking represents the next impediment to a change in fuel use. The long-haul trucking industry is dominated by small independent owner-operators. 95.8% of fleets operate ten of fewer trucks in the heavy-duty segment. The large-scale price differential between an internal combustion engine (ICE) Class 8 vehicle (typically heavy-duty long-haul) and a battery electric (BEV) Class 8 vehicle of upwards of USD 300,000[4] presently, is a very large incremental cost for an operator. There are several state-level incentives for commercial zero emissions vehicles, but not all actually cover the full incremental cost. The Class 8 BEV total vehicle population is estimated in the low thousands versus more than 300,000 total Class 8 sales in 2023 alone. Such a gap underscores the significant uptake required for Class 8 alternative vehicle penetration, and the substitution of diesels.

Outside of long-haul trucking, there will also be certain applications for which current substitutes including batteries may not be well suited due to the weight, intensity, and duration of use in the near term. This includes Class I rail, which accounts for some two-thirds of freight rail miles in the US, generally in long-haul use, and some off-road equipment including construction and other heavy-duty equipment. Such uses would require frequent recharging or battery switching.

[4] The average cost of a BEV in USD ~460,000 per the US Department of Energy versus $160,000 for a conventional vehicle.

US federal Renewable Fuel Standard (RFS) and state clean fuels programs have driven demand for RD.

The federal RFS was implemented with the Energy Policy Act of 2005. It was then expanded under the Energy Independence and Security Act of 2007. The Clean Air Act, and the Energy Policy Act of 1992 all provide the legal foundation of the RFS. While the Environmental Protection Agency (EPA), the agency which oversees the RFS, has some discretion in how the program is administered, there are statutory requirements it must follow in setting volumes from 2023 forward. The RFS, in effect, requires fuel consumed in the US transportation sector to contain a minimum volume of renewable fuel.

Those requirements on the EPA for volume-setting include consideration of several key factors, including the impact on renewable fuel volumes to the “price and supply of agricultural commodity prices, rural economic development, and food prices.” In order to comply with the federal RFS, advanced biofuels must show at least a 50% lifecycle greenhouse gas (GHG) reduction as compared to a 2005 petroleum baseline, and biomass-based diesel must show a 60% reduction.

The next RFS update for 2026 obligations was delayed from 2024 with the EPA targeting March 2025 for its noticed on proposed rulemaking.

The LCFS program is the oldest such state-level program in the US, having been established in 2009 and implemented in 2011. The fuel-agnostic California LCFS was designed to decrease GHG emissions, lower carbon intensity (CI) in the transportation sector, and encourage the use of lower CI fuels in the state of California. As of 2023 (the most recently available year), there was a 15.3% reduction for a composite of gasoline and diesel fuels in CI versus a 2010 baseline, according to the California Air Resources Board (CARB) versus the target requirement of 11.3%.

The latest rulemaking was concluded on November 8, 2024, and the LCFS program is currently mandated through 2045, a 15-year extension versus the previous rule. The stringency of required CI reduction has also increased to 30% from the 20% of the 2010 baseline in 2030. Given that more ambitious target, credits generated by biofuels may decline over time because the stringency in CI reduction increases with the passage of time.

The amendment included provisions to reduce the volumes of soy- and canola-based renewable diesel by imposing a 20% credit cap, reflecting the volumes sold in 2023 in the bio-based diesel category. This cap does not limit the total volume. However, as was the case prior to the imposition of that cap, producers with the optionality to sell low-veg feedstocks into the market are likely already maximizing sales into the market and will continue do so given the comparatively better monetization opportunities for non-vegetable feedstock-based RD based on their respective CI scores.

The California LCFS has served as a model for other clean state fuels programs. Currently, three other states have their own clean fuels programs – Oregon, Washington, and New Mexico. As of April 2024, eight other states had pending clean fuels programs. Per the law firm Pillsbury, those eight states would represent 14% of diesel sold in the US being under the jurisdiction of low carbon standards and 25% of diesel sold in the US when accounting for the four states with active clean fuels programs.

In addition to these programs, the Inflation Reduction Act (IRA) includes provisions to support clean fuel production, specifically the 45Z Clean Fuel Production Tax Credit (PTC). Clean fuel producers, including refiners, are eligible for the credit. That credit is worth up to USD 1/gallon based on the CI of the produced fuel. As of this writing, guidance on the 45Z credit was issued in January 2025, but further clarifications are necessary in a future rulemaking. That timing lends some uncertainty to what the provision will look like upon those further clarifications (and now that Trump has taken office). The lack of clarity on the credit and the timeline for additional guidance together with its duration – the 45Z credit is applicable to transportation fuels sold through December 31, 2027 though that does not preclude any potential extension – leads to some uncertainty around clean fuels incentives to start the year.

The 45Z PTC replaces the expiring Blender’s Tax Credit (BTC), which is available to blenders rather than producers of biofuels and expired at the end of 2024. The BTC provided a USD 1/gallon credit to both imported and domestically produced biofuels (including both biodiesel and RD). While a one-year extension of the BTC was raised in the Senate, it stalled in the lame duck session. Unlike the BTC, the PTC is only applicable to domestically produced clean fuels, irrespective of whether they are consumed in the US. Limiting qualification to domestic biofuels only could result in a decrease in biofuels imports as they will be comparatively less competitive in the absence of the BTC. That potential reduction in aggregate supply could support RD fundamentals.

Most RD is produced through hydrotreating feedstock. Hydrogenation is key to renewable diesel’s drop-in fuel status, as it results in oxygen-free RD molecules. The hydrogenation process is similar to that used to desulphurize diesel and gasoline. This is why co-refining with conventional petroleum products is also possible, though this accounts for a smaller relative portion of RD production. Globally, there is hydrogenation capacity of ~60,000 Mbpd. Of this, the US has the largest capacity, with some 17,000 Mbpd.

Due to the critical role hydrogenation/hydrotreating plays in the production of RD, there are significant synergies with existing refining assets, and with traditional energy companies. Such synergies also include access to hydrogen. The current hydrogen pipeline network in the United States is almost entirely used to service large industrial users.

The ownership of an existing hydrotreating unit gives the asset owners an advantage in speed to market, through conversion. It also gives the owner of that asset the option to participate in the market while also reducing outright initial capital outlay if a conversion decision is taken. Such market participants may also have existing ancillary assets such as tanks and towers for that production and may already have logistical connections in place. Conversion of a typical asset may take two years, versus roughly double for construction of a greenfield facility.

Export market optionality, whether this be by having access to pipe, rail, or deepwater assets for waterborne exports is a significant advantage to a facility. It allows the facility to sell into generally premium-priced domestic markets like California, or access export markets in order to seek the highest netback and diversify its potential customer base. Shipping optionality allows a producer to realize shipping efficiencies, elect the mode of transport yielding the most positive netback, and potentially to continue sales activity in the event of a market or logistical disruption.

Lower carbon fuel mandates such as SAF mandates could underpin fundamental market tightening in the US by incentivizing finished product export. While these mandates are for SAF, they may result in those markets diverting existing feedstock supply and resources to SAF, opening up market share for imports of US RD. Beginning in 2025, 2% of UK jet fuel must be SAF. Similarly, the EU’s ReFuelEU Aviation regulation requires a 2% blend of SAF for its airports beginning in 2025.

There has been some rationalization in US biodiesel and renewable diesel capacity. Larger industry players that have sales and shipping/logistics optionality, operational flexibility as well as operational expertise for understanding how to operate and maintain such a complex asset, may be those best-positioned to withstand the cyclicality of the industry. The advantaged facilities are also likely to have sufficient on-site storage for feedstocks and finished product to withstand any weather event or other disruption. They are likely to also have offsite tank farm storage for both feedstock and finished product flexibility, which could also extend to the ability to make arbitrage decisions involving market timing and time spreads.

Some RD producers may choose to co-produce SAF or convert their assets to maximize SAF production given limited substitutes for jet fuels. Commercial airlines have shown a significant public commitment to SAF use. More than 30 airlines have SAF targets and, according to the Air Transport Action Group, more than 45 airlines have signed forward-purchase agreements for the fuel totaling some USD 40 billion.

The timeline for SAF production and cost for conversion will depend on if the operator intends to maximize SAF production. Because of the overlap in the chemical and physical properties of jet and diesel fuel, some RD producers can produce both RD and SAF at the same facility. This may only require an upgrade to a facility’s hydrocracking unit, though this may vary per facility.

Generally, a decision to pursue maximized SAF conversion will be based on the perceived value of the relative RD to SAF value stacks. Outside of the value stack, the lack of any viable substitutes for SAF with increasing government and company-level SAF mandates/targets are a consideration, especially for companies that could undergo conversion to SAF at limited capital outlay and with time-to-market advantage due to existing infrastructure.

Currently, there is no viable substitute for RD across certain key distillate markets. Its chemical properties give it unique functionality versus biodiesel, with no blend wall, high cetane value, and cold flow properties equivalent to conventional diesel. Given the hydrogenation process is central to these chemical advantages, traditional energy companies have been key players in the market segment. This is because of their ownership of existing hydrogenation and ancillary assets, access to industrial hydrogen supply and logistics, and expedited time to market (at lower capital expenditure) due to the ability to convert existing assets. Clean state fuel programs have supported domestic demand. However, the lack of additional guidance on the 45Z and the delay to the 2026 RFS obligations do pose near-term headwinds as the industry awaits greater clarity. The expansion of clean fuels programs to additional states could support additional demand. Renewable fuel mandates in international markets could be potentially supportive of RD market fundamentals, as well as advantaging facilities with strong export optionality.