May 10, 2023
Ahead of the Canadian Clean Fuel Regulation’s implementation this summer, several members of Stillwater’s Carbon Crew chatted with Ian Thomson, President of Advanced Biofuels Canada about the current state of biofuels production and usage in Canada. We thought our readers might find this conversation enlightening, so we’re publishing it here. (We’ve edited Ian’s answers for clarity and brevity.)
Stillwater: Starting with the regulatory environment, what are the differences between the federal and provincial clean fuels regulations and incentives in Canada? What are the differences in the power structure between the federal and provincial governments?
Ian Thomson, Advanced Biofuels Canada: There’s a lot to cover here. The federal government and the provincial governments both play in the energy and climate space. The federal government has jurisdiction over pollutants, and CO2 was determined to be a pollutant under the Canadian Environmental Protection Act (CEPA) which is the main authorizing statute under which regulations can be promulgated. The Renewable Fuels Regulation (RFR), which came in in 2010 (and 2011 for the diesel pool), falls under CEPA. That regulation is being repealed, but its minimum blending requirements are carried forward in the Clean Fuel Regulations, which also fall under CEPA. Tailpipe emission standards also come under CEPA, with Canada traditionally adopting U.S. regulations, described as ‘incorporation by reference’, which points to a specific regulation in the U.S. Federal Register. At the federal level, we undertake rulemaking in a manner similar to the U.S. process. The ‘Canada Gazette Part One’ publishes draft regulations with accompanying ‘regulatory impact assessment statements’, which are posted for public comments – allotting a shorter comment period for regulations that don’t have a trade impact and a longer period of time for other countries and entities to weigh in if there are trade impacts. Following public comment, they move to a final regulation which would also come out in the Canada Gazette Part Two (which is a bit like the Federal Register in the U.S.) So that’s how it works on the federal level.
But the federal government and the provinces don’t always agree on who has jurisdiction. In the case of something like carbon pricing, the federal government wanted to impose on all provinces a federal carbon price – on both fuels, and on industrial facilities – but the federal government allowed the provinces to forgo the federal scheme if the provincial government implemented a scheme that was “substantially equivalent.” So provinces can have their regulations recognized by the federal government under a common equivalency arrangement, but the federal government will at times say “that’s not adequate and we’re going to impose our rules on you.” In the case of carbon pricing, several provinces took the federal government to the Supreme Court, which pronounced that the federal government does indeed have jurisdiction, and now all provinces either have the federal scheme imposed upon them or have an acknowledged ‘equivalent’ provincial scheme. In the case of fuel policy, provinces can, and largely have, implemented their own renewable and low carbon fuel standards.
Increasingly, provinces see a clear linkage between economic development and climate policy. Canada’s provinces have very different economic profiles. So, if you’re a fossil resource rich province, you are going to write and draft and create your climate policies to not undermine the engine of your provincial economy. If you’re a province with hydroelectricity, or agricultural and forestry sectors, you’re going to write a very different roadmap to a lower carbon economy. Advanced Biofuels Canada has developed a transportation fuels dashboard that details each province’s fuels policies, and an array of metrics on how those have played out in the market. So for more information about specific policies, I recommend checking that out. As you’ll see on the dashboard, all provinces west of and including Quebec have provincial mandates of some kind; these represent approximately 92% of national fuel consumption. Ontario and Quebec have over 60% of national gasoline consumption – smaller for diesel – so clearly their policies have quite an impact overall. Our dashboard data come from the Biofuels In Canada report which we commissioned through Navius Research to address the dearth of data available in Canada, which lacks the comprehensive approach of the U.S. Energy Information Administration. There are efforts underway to develop a Canadian energy center, but our ‘official’ data are currently sparse on detail, and not timely. So our response to that was to coordinate the publication of our own data set. On a side note, the Canadian International Merchandise Trade Database (CIMT) was upgraded in October 2021, with a much-improved user interface.
Stillwater: What are the consumption rates for these renewable fuels, any kind of new renewable fuels that are coming on the market and where are those trends going?
Ian: First off, I’ll refer you back to the map on our data dashboard which will tell you what the minimum blending is; those are the requirements. And then, in the workbook associated with the Biofuels in Canada report you can actually set on the dashboard tab which province you’d like data for by using the drop-down in cell B3 and it repopulates the entire dashboard to that province. Navius publishes these data roughly 10 months after the end of the calendar year; two years ago, they added estimates for the most current full year. So based on this dashboard, you can see where the blending levels are and what the trend lines have been. Another great resource is our Clean Fuels Report Card which came out last year and uses the same Biofuels in Canada dataset but in a user-friendly format; it also provides a number of metrics that are ‘derivatives’ of the Navius work and provide a really novel look into costs and carbon tax impacts, etc. On that Report Card page, if you click on the “Top 3” tab, a map comes up and you can select the car icon for gasoline or the truck icon for diesel; each province’s annual blending levels are shown back to 2010. Again, there are a range of data interpreted there. I should note that the Biofuels in Canada dataset has just started to reflect the impact in BC from electric vehicle charging, but not yet RNG.
Stillwater: That was going to be my next question. What do you think is the limiting factor on RNG? Is it accessibility to the natural gas vehicles?
Ian: Largely it’s accessibility to heavy-duty vehicles that can run gaseous fuels. The LCFS in California is what’s driving RNG blending for vehicles. In Canada, there are also some initiatives underway to support on-road RNG use, but we are seeing a push – some of it regulatory – to use RNG in industrial facilities. British Columbia has a huge natural gas play in the northeast part of the province, and the big utility doing a lot of natgas and RNG work is Fortis BC. Fortis is making RNG available to its natural gas customers, residential mostly. And so that’s where much of the focus to-date has been for RNG. They’re also delivering LNG for marine applications; utilities may have a decision point on where best to place what had been so far a limited supply, but RNG production capacity is expanding. The BC Utility Commission regulates the sector and has considerations such as impact on their ratepayer base, so that’s a factor. There are rules about how they can price the RNG, and alongside industrial obligations, it may be a more complex situation than it would be if it were in California where the real focus appears to be on-road utilization. Provincial objectives for industrial decarbonization – which includes a renewable gas policy in BC – and transportation uses will drive new RNG projects.
Stillwater: That’s very helpful insight. Let’s discus where supply (of renewable fuels) in Canada is coming from.
Ian: The answer is quite different for the gasoline pool than the diesel pool. For the gasoline pool, the renewable fuel is all ethanol. In 2022, we had about 1.9 billion liters of import and less than that in domestic production. The bulk of ethanol production is located in southern Ontario and Quebec, mostly in Southern Ontario where much of our corn is grown (as well as soybeans). We have a handful of ethanol plants across the western provinces; those tend to process corn, most of which is imported, and wheat which is not quite as good a feedstock as corn. The diesel pool tends to be quite different. We’ve traditionally been more balanced in the diesel pool. We have until recent years produced about as much biomass-based diesel as we consume, but when there’s an arbitrage it has been sent south of the border for the blender’s tax credit (BTC) in the U.S. and we reimport to backfill our obligations. That has worked well for producers on both sides of the border. With blending rates increasing particularly in BC, we’ve been more reliant on renewable diesel imports; we have no production as of date in Canada. We do have some co-processing out of the Parkland Burnaby refinery, and more co-processing capacity and renewable diesel capacity is in the works in western Canada.
Stillwater: Where is most of the BD produced in Canada?
Ian: It is distributed. There’s a Consolidated Biofuels plant in Delta (British Columbia) which produces about 11 million liters per year, there’s Archer Daniels Midland (ADM) plant in Lloydminster (Alberta) which can produce 320 million liter, Verbio’s 170 million liter plant in Welland (Ontario), a 60 million liter World Energy plant in Hamilton (Ontario), and a 12 million liter Innoltek plant near Montreal (Quebec) that will be expanding. You can go on our data dashboard for more detail about feedstocks (and the Members Map to for a lot more detail about an array of biofuel assets in Canada.)
Stillwater: Excellent! Let’s shift to talking about how the downstream works in Canada.
Ian: We have very limited midstream in Canada relative to the US. We don’t have the Magellans or other such entities operating either finished product pipelines or racks. I’ll say more in a bit about transloading facilities. Pipelines are more diversified, but the downstream on the liquid side is much more concentrated than in the U.S. If you look at wholesale, a much smaller group of fuel suppliers operate the majority of distribution assets. And it’s quite nuanced geographically. An obligated party with a national footprint will have a different set of compliance options – for both its federal and provincial requirements – than a party with a smaller, regional footprint. For instance, British Columbia has a Low Carbon Fuel Standard that is much more stringent than other provinces’ regulations, so an obligated party that has fuel operations in British Columbia is going to have an outsized obligation there vis a vis the rest in Canada. As another “for instance,” until Ontario adopted a mandate for the diesel pool in 2014, British Columbia saw a lot of over compliance in the diesel pool because if you were a nationwide fuel supplier with operations in Ontario, you had no renewables obligations there, but you did in BC, so you could achieve much of your federal compliance in BC rather than spreading it out across multiple provinces. That was a pretty efficient solution for those obligated parties. Now that Quebec has its own regulation (and a much more sizeable fuel pool), and Ontario is turning up the dial on their fuel regulations (again, with a bigger fuel pool than BC), the balance of blending is shifting from BC toward Central Canada. Another thing about the downstream in Canada is that most of the large refiners and especially the integrated ones that have upstream crude production have divested their retail assets. Despite moving away from direct ownership, their fuel supply agreements for branded products are fairly prescriptive on products offered, which has definitely muted the offering of mid- and high-blend biofuels. So, there is less room for discretionary biofuel blending at a branded station. But increasingly you’re seeing companies stepping into the midstream with high-volume transload assets, and in a few cases, acquiring or building their own retail networks which can pull from any rack. So we’ve got some interesting dynamics coming up, and these new wholesaling assets are welcome news for fuel users as well as the biofuels sector. I think we’ll see emerging opportunities such as E15 that may go into branded and unbranded sites. B20 has a small footprint in Canada, but that may change also.
Stillwater: That’s very insightful! When looking forward to the dynamics that are coming, how is the forthcoming Clean Fuel Regulation going to impact market presence and the behavior of the players in the market?
Ian: The CFR is already having a significant impact. Whereas the RFR had very restricted opportunities for voluntary parties to participate via the credit market, the CFR credit market has a very open and accessible architecture. Its credit tracking platform – CATS, which Environment and Climate Change Canada will maintain – and the lifecycle analysis (LCA) model, are having understandable startup issues but are expected to provide much more timely information in late 2024. The CFR’s debits start to accrue effective July 1, 2023. There are already credit market exchanges happening, but they’re not visible. All provinces except Manitoba will allow the exchange of credits to reach compliance. For most provincial low carbon fuel markets – the BC-LCFS market excepted – parties who are long or short have to communicate directly for price discovery. It’s much more opaque, Illiquid, infrequent than what is observed in the U.S. or in BC under the provincial LCFS. The CFR will vastly improve the efficiency, and the values, in the credit market. I should note that provincial and federal credits can stack; in other words, for the same liter put into the market, you can create – for instance – a BC LCFS credit and a CFR credit, and both will have separate values in separate markets.
Stillwater: As far as key players go, biofuels producers and technology developers, who do you see as the key companies in Canada?
The key biofuel producers on the diesel side would be ADM, Verbio, World Energy, Consolidated Biofuels, Parkland Fuels, and Canary Biofuels (which is on the cusp of commissioning). For ethanol, the key players are Greenfield Global, BIOX/World Energy, Kawartha, Suncor, Permolex, IGPC, Husky, and Federated Coop. The developing project we’re watching most closely is the Come-By-Chance refinery conversion in Newfoundland that will produce 18,000 barrels per day of renewable diesel, with SAF potential. We don’t have many idle refineries in Canada which could be converted to biofuels production, and it’s exciting to see that conversion. The only other players in that space are Parkland and Tidewater Renewables. Parkland is expanding to a co-processing capacity of 5,500 barrels per day while adding the ability to process things like tallow and various lipids. Unfortunately, Parkland has announced that it is pulling back from their RD plant in part due to the uncertainty around the IRA incentives/disincentives in the U.S. Similar to Parkland, Tidewater Renewables is starting with co-processing, and they’ve got a RD train that they’re proposing to bring on. Imperial Oil has gone to FID on a 20,000 barrel renewable diesel in Edmonton, and Federated Co-op also has a large project advancing in Saskatchewan where they are going to co-locate a greenfield canola crush plant. There aren’t that many players yet, but it’s important to keep in mind the fact that the refiners in Canada were not broadly embracing renewables until a few years ago.
On the trade level, our association, Advanced Biofuels Canada, and the business coalition Renewable Industries Canada, have traditionally represented renewable fuels. The Canadian Fuels Association represents Canada’s petroleum refining, distribution, and marketing sector. It’s closer to an AFPM than an API, and in the last couple of years, its members, and the association, have become much more involved in the low carbon fuels sector, investing in RD, hydrogen, RNG, CCS, etc. And then there are national associations for biogas and RNG, such as the Canadian Biogas Association and the RNG Coalition, and for electric vehicles and supply chain, Electric Mobility Canada, and in hydrogen, the Canadian Hydrogen and Fuel Cell Association. In 2020, the Canadian Transportation Alliance (CTA) was formed, in collaboration with the Fuels Institute, to bring a research-based, non-partisan perspective to Canada’s low carbon transition. CTA publishes objective data and reports for policymakers; it does not advocate.
Finally, we have a very engaged agriculture sector. In Canada, canola is the current elephant in the room, with the central Canada corn sector playing a key role in supporting biofuel growth regionally. It’s a $30 billion economic driver, and Canada is regularly the largest canola exporter in the world. So, the canola sector has a lot of engagement to increase domestic utilization for biofuels. The grain and forestry sectors have also contributed meaningfully to biofuel policy.
Stillwater: Are there any closing thoughts you’d like to convey about biofuels in Canada?
Ian: The CFR appears to be having a robust start. Technically, the CFR demand signal will exceed the cumulative provincial signal somewhere in 2025-2026 timeline. But credit banking is underway, so we’re actually seeing a more engaged response than we had anticipated.
Canada has ambitious net-zero targets; the CFR paired with ZEV mandates for LDV are key policies in transportation. Canada’s vast size, climate, biomass resources, and other factors all point to a large role for low-carbon, energy dense fuels out to 2050 and beyond. This is broadly recognized to be the case especially for harder to decarbonize sectors such as aviation, rail, marine, and long-haul transport. Electrification, and hydrogen are certainly going to grow in use exponentially, but we’ll see ongoing reliance on liquid fuels so we have work to do to shift to very low carbon alternatives, and biofuels (and gradually more renewable synthetics) will be indispensable.
Regarding policy durability, the billions of dollars being invested by the private sector, paired with comparable investments by the federal government, are making the CFR somewhat of a ‘too big to fail’ or ‘too big to pull apart’ regulation. This provides some assurance that a change in government may not jeopardize the regulation. So I think we have fairly good stability on the policy side for the CFR. ZEV mandates and carbon pricing may face stiffer headwinds in the future, but in the case of the former, huge automotive sector and battery supply chain investments are changing the economic landscape and at some point, you can’t simply can’t go backwards. Interesting times ahead.