Understanding Canada’s Other Carbon Price

Credit Pricing Dynamics under Canada’s Federal Clean Fuel Regulations (CFR)

May 6, 2026

Canada’s federal Clean Fuel Regulations (CFR) require fuel suppliers to reduce the “lifecycle” carbon intensity of produced and imported gasoline and diesel through tradable credits created through the supply of low-carbon fuels (e.g., fuels produced from agricultural feedstocks), switching to alternatives (e.g., recharging of electric vehicles) or emission reductions across the fuel lifecycle (such as through carbon capture from upstream production, processing or refining).

In early April, quoted prices for credits under the CFR reached $430 per tonne of reduced carbon intensity, having climbed steeply over the last year from a nadir of $95/t in March 2025. Over the same period, the average monthly short-dated transfer price (i.e., for credit transfers within six months of an agreement) for credits under British Columbia’s Low Carbon Fuel Standards (BC LCFS) regime plunged to $110/t in March 2026 from $260/t in March 2025 and a peak of $500/t in October 2023.

The CFR and BC LCFS are “stackable” (with the same fuels earning credits in both regimes) and nearly mirror in overall design (and similarly parallel LCFS regimes in California, Oregon and Washington): These regimes are based on supplied fuels’ wells-to-wheels “carbon intensity” (including emissions from the steps along the production-to-pump supply chain as well as from the ultimate combustion). Obligations are incurred by fuel suppliers based on an annually ratcheting carbon intensity reduction on production or imported volumes of gasoline and diesel.

While the CFR came into effect for creating credits in July 2022 and fuel suppliers facing obligations since July 2023, its credit market had lagged in pricing in the long-term supply/demand dynamics. Of course, in the lead-up to the April 2025 federal election, statements suggesting potential cancellation of the CFR clouded credit pricing.

However, the past year’s CFR price surge – and corresponding BC LCFS tumble – follow from economic fundamentals:

• First, the credit price will reflect the cost of the marginal credit required to meet fuel supplier obligations.
• Second, the value of that credit must compensate for the cost difference of supplying the marginal volume of low-carbon fuel versus its gasoline or diesel alternative.
• Third, the regime that “binds” for the required supply of emission reductions will be where that required value is priced.

That is, the marginal low-carbon fuel supply will be reflected in the pricing of credits under the regime that requires more low-carbon fuels (or other reductions across the lifecycle).

As a regime that is national (rather than just provincial) in scope, if Canada’s CFR requires more emission reductions across the fuel lifecycle than the BC LCFS and other provinces’ renewable fuel requirements combined, CFR credits will be priced at the cost to compensate the marginal volume of low-carbon fuel. Correspondingly, credit prices in provincial regimes (like the BC LCFS) should decline – ultimately to relative logistics cost of delivering low-carbon fuel volumes to the given province rather than to a province with the lowest supply costs.

The price-setting role of the marginal low-carbon fuel

To better understand these pricing dynamics, first consider how obligations are incurred and credits earned under the CFR. The supply of gasoline or diesel faces an annually declining carbon intensity limit, with a 15% reduction by 2030 on its baseline carbon intensity. For each unit volume of diesel or gasoline produced or imported, the fuel supplier must retire credits earned from specified activities that reduce carbon intensity across the fuel lifecycle.

Therefore, demand for credits reflects the total volume of gasoline and diesel supplied across Canada (with exclusions for certain uses from the applicable pool) multiplied by the required carbon intensity reduction in the given year.

In turn, the supply of a low-carbon fuel – such as ethanol, biodiesel or hydrogenation-derived renewable diesel (HDRD) – earns credits based on its carbon intensity (assessed using a lifecycle assessment model with verified feedstock, energy and other process inputs) relative to the reference carbon intensity for the liquid class.

The CFR also provides for fuel suppliers to comply by contributing to an emission-reduction funding program at a $350/tonne price (inflation-adjusted from 2022 dollars), as well using “gaseous class” credits, each to a maximum of 10% of a suppliers’ obligations.

This translates to a picture of the CFR credit market as conceptually illustrated below. The costs of supplying low-carbon fuels (as well as emission reductions across the fuel lifecycle and through fuel-switching) can be considered as a supply curve for CFR credits, with the demand curve as the required carbon intensity reduction from supply of gasoline and diesel volumes.

Credit prices compensate for the cost of supplying the marginal low-carbon fuel

In turn, to compensate for the cost of this marginal (and price-setting) low-carbon fuel, the credit value must be equivalent (1) to the difference in supply cost between the low-carbon fuel’s supply cost and the fossil fuel for which it substitutes (2) at the carbon intensity of the low-carbon fuel relative to that fossil fuel.

Consider the supply of HDRD as a drop-in substitute for diesel: Each litre of HDRD will have a higher supply cost than a litre of diesel, reflecting its higher production cost. However, at the pump, drivers will only pay a common retail price. Therefore, to supply HDRD instead of diesel, the supplier must be compensated by the credit value for the difference with the cost of supplying diesel (including the diesel wholesale price and the additional cost of CFR obligations at the required reduction in carbon intensity).

Since that $/L HDRD-Diesel supply cost difference must be compensated by the corresponding credit value, the carbon intensity of the low-carbon fuel determines the required credit price.

For example, if HDRD can be supplied at a carbon intensity of 33 g CO2e/MJ versus the diesel baseline of 93 g CO2e/MJ, the number of credits from supplying HDRD plus those that would be otherwise required for supplying diesel will approximately reflect the carbon intensity difference of 60 g CO2e/MJ – roughly equivalent 2.1 kg CO2e/L at the specified energy densities.

Therefore, for a difference in supply cost of $1.00/L between HDRD and diesel, a supplier of that HDRD must be compensated by the 2.1 kg CO2e/L carbon intensity difference for the higher supply cost of supplying HDRD instead of diesel. That is, at such a carbon intensity difference and supply cost difference, a roughly $475/t credit price (i.e., $1.00/L divided by 2.1 kg CO2e/L) is required for supplying HDRD rather than diesel.

The corollary is that a lower carbon intensity of the low-carbon fuel that is supplied at the margin to meet compliance obligations (increasing credit supply with the larger difference in carbon intensity with its gasoline or diesel substitute) would push credit prices lower. Conversely, a larger difference between the supply cost of the marginal low-carbon fuel and its gasoline/diesel substitute (e.g., from higher costs of producing HDRD or relatively falling diesel wholesale prices) would push credit prices higher.

Practically, for anticipating credit prices in the CFR and other LCFS regimes, HDRD is the key low-carbon fuel to watch for its differential with diesel and relative carbon intensity. Notably, since HDRD can substitute for diesel in engines, its supply is distinct from the blending limits faced by biodiesel or ethanol with diesel and gasoline, respectively.

That is, the supply of HDRD is not constrained by the need for delivery to a particular location to be directly blended with gasoline or diesel up to a maximum share. HDRD can be comparatively oversupplied in one location but the resulting credits available to another fuel supplier in a harder-to-access location. Indeed, as a drop-in substitute for diesel, HDRD supply has surged over past years within LCFS markets, with increasing share of the overall credit creation in BC and California.

As well, the HDRD vs. diesel wholesale price difference has broadly tracked estimated values for supplying HDRD under the relevant regulatory regimes at market credit prices and reported average HDRD carbon intensity. For example, the combined estimated value of California LCFS credits and D4 RINs (for biomass-based diesel under the U.S. Environmental Protection Agency’s Renewable Fuel Standards) has broadly tracked this evolving differential over the past decade.

Credit price is set by the “binding” clean fuels regime

A final point relates to how credits will price between “stackable” regimes such as Canada’s federal CFR and the BC LCFS, as well as various provincial renewables fuel requirements.

If the supply of a low-carbon fuel creates credits in two different regimes, in which regime are the credits actually valued?

For example, HDRD supplied in British Columbia will create both credits for compliance with the CFR and the BC LCFS. If the combined value of credits for HDRD in each of the regimes is greater than the HDRD vs. diesel price differential, a supplier of HDRD will continue to profit from delivering more HDRD volumes to British Columbia.

In 2023 and 2024, this appears to have been the case at the then prevailing credit prices in the BC LCFS and in the federal CFR. As shown below, based on the imported average unit prices of diesel and HDRD to British Columbia, the supply of HDRD (at an illustrative carbon intensity of 33 g CO2e/MJ) would have been overcompensated by the combined value of CFR and BC LCFS credits relative to the cost of supplying diesel.

But in a competitive market, this incentive means that suppliers should increase HDRD supplies until the combined credit value – through the increasing creation of credits – is pushed down to the difference between HDRD and diesel wholesale prices in the given geographic market.

Indeed, by 2025 (as exhibited above), the estimated value from the credits under the CFR and BC LCFS from supplying HDRD had converged to the difference in the average unit price difference between HDRD and diesel. Again, from 2024 to 2025, the price of BC LCFS credits plummeted while the quoted CFR credit price climbed steeply.

Importantly, unlike BC LCFS credits, CFR credits are valuable across Canada to also satisfy obligations of fuel suppliers resulting from supplying gasoline or diesel in other provinces. Most other provinces also have requirements for blending minimum volumes of renewable fuels with gasoline or diesel.

Economically, credits in the “binding” regulatory regime must provide the value to compensate the supply of the marginal low-carbon fuel. That is, if the CFR requires the supply of more low-carbon fuels to meet the obligations of gasoline and diesel suppliers than are required under provincial regimes, then the cost of supplying the marginal low-carbon fuel should be compensated by CFR credit prices.

In contrast, if the CFR is binding, credit prices under provincial regimes like the BC LCFS should in turn fall since, with the greater low-carbon fuel volumes required by CFR, these provincial regimes can be satisfied at zero marginal cost (excepting the relative logistics costs of delivering sufficient low-carbon fuels within the given province to meet the provincial requirements).

In the Regulatory Impact Analysis Statement (RIAS) that accompanied the finalized Clean Fuel Regulations in 2022, Environment and Climate Change Canada (ECCC) provided projected gasoline and diesel volumes from 2022 to 2030 across Canada and the corresponding obligations that fuel suppliers would face.

The plot below contrasts these projected CFR obligations from the ECCC RIAS with the total required carbon intensity reductions estimated for the BC LCFS and other provinces’ renewable fuel requirements in future years (presenting provincial biofuel blending requirements – typically imposed as a percentage share of gasoline and diesel volumes – in terms of the equivalent carbon intensity reduction under the CFR).

Of course, actual diesel and gasoline volumes will differ (and have already) from ECCC’s forecast. Nonetheless, the aim of the above comparison is to exhibit that, even at the 2022 implementation of the CFR, the regime would quickly require the supply of significantly more low-carbon fuels (or emission reductions across the fuel lifecycle) than all of the provincial regimes combined.

Indeed, since credits created under the CFR are fungible across provinces, low-carbon fuels to satisfy nationwide CFR obligations should be supplied wherever is the lowest-cost delivered location for creating the necessary credits to satisfy fuel suppliers’ CFR obligations.

These economics (particularly the CFR as the nationally binding regime) mean that the compensation for low-carbon fuels in Canada will overwhelming be from CFR credit prices. In turn, prices in the BC LCFS credits (and “shadow prices” for meeting renewable fuel requirements in other provinces) should fall to reflect only the relative costs of delivering low-carbon fuels to the province rather than supplying elsewhere at lower cost.

The road ahead for the CFR credit market…

In the past years, BC LCFS credit prices have indeed plunged just as CFR credit prices have surged. As explained above, this follows from economic fundamentals of supply and demand for credits under the respective regulatory regimes. Specifically, the value of credits must be sufficient to compensate the supply of low-carbon fuels to meet fuel suppliers’ obligations (i.e., credits must compensate the cost difference of a low-carbon fuel with gasoline or diesel alternative), and the regime that “binds” for the required supply of emission reductions will be where that required credit value is priced (i.e., because the total reductions in carbon intensity under the CFR exceed the requirements under provincial regimes, CFR credits will be where the supply cost is compensated).

Looking ahead, this overview also highlights the key determinants for future credit prices. In particular, in formulating our outlook for credit prices, we are tracking:

• Imported price and production cost differences between blended or substituted low-carbon fuels for gasoline or diesel – whether from current and future pricing of biofuel feedstocks, crude oil, other refining inputs or the impact of subsidies (e.g., production tax credits)
• Improvements or deterioration of carbon intensity in the available low-carbon fuel supply – whether from innovation around pathways to reduce fuels’ carbon intensity or stretched biofuel production resorting to higher carbon intensity feedstocks
• Evolution of Canada-wide gasoline and diesel consumption and consequent total demand for CFR credits to satisfy suppliers’ obligations
• Policy changes to the CFR – such as the domestic content requirements or credit multiplier for domestic low-carbon fuel production proposed by the federal government in September 2025
• Competition for low-carbon fuels from regulatory regimes in other jurisdictions (particularly the United States) with tightening carbon intensity requirements
• Electric vehicle penetration by province and implications for extent of CFR credits for EV recharging
• Roll-out of “big mover” emission reduction projects (such as carbon capture at refineries or upstream petroleum production) eligible for credit creation