Peter Nicholson is a former Deputy Chief of Staff for Policy in the Office of the Prime Minister of Canada and currently serves as Chair of the Board of the Canadian Climate Institute.
Prime Minister Carney has made clear from the outset of his time in office that without a commitment to implement the Pathways carbon capture and storage (CCS) project, there would be no new bitumen pipeline to the B.C. coast. The expectation was formalized in the Nov. 27 Alberta-Ottawa MOU and the May 15 Implementation Agreement. The oil sands industry has made it equally clear that CCS represents a major additional cost standing in the way of the new production needed to fill the proposed pipeline. In a June 9 speech, Jon McKenzie, CEO of Cenovus, spoke for the industry when he said:
“The reality is that this is a project with no revenue. It is simply another cost burden that will be borne by industry and the two levels of government.”
Then on July 2, the governments of Alberta and Canada and the Oil Sands Alliance (comprising the five principal oil sands producers1) entered into a further Memorandum of Understanding, to be confirmed in definitive agreements this Fall, that includes the following objective:
“The shared objective for the Oil Sands Alliance to reduce emissions by 16 million tonnes per annum (Mtpa) net:
• 6 Mtpa (net) through the Pathways CCS Project by January 1, 2035;
• 10 Mtpa (net) of additional reductions achieved through expansion of Pathways, deployment of other emissions-reduction technologies, or improved production practices, with 5 Mt online by 2040 and a further 5 Mt by 2045.”
Although the agreement doesn’t remove CCS from the picture, it substantially changes the practical significance of the Prime Minister’s “No Pathways, no pipeline” symmetry by stretching implementation over two decades, significantly broadening the means of compliance, and implicitly recognizing that governments will bear a substantial share of the cost. Most significantly, it virtually eliminates the risk that the CCS requirement ,by itself, will determine whether another pipeline proceeds. That’s because, as I explain below, the CCS provisions in the MOU will impose a much smaller burden on producers than many observers have assumed. Moreover, the new emissions objective is considerably less ambitious than earlier Pathways proposals which aimed to capture 22 Mt annually by 2030. And, unlike with earlier Trudeau-era limitations, investment tax credits will apply to the use of the carbon dioxide for enhanced oil recovery (injecting the carbon dioxide into older basins to extract additional oil). Turning CCS into CCUS (the ‘u’ for utilization) creates a potential revenue stream for producers.
All told, the commercial issue now shifts back, properly, to the underlying economics of expanding oil sands production to fill the proposed pipeline.
At the same time—again contrary to the impression governments may have created—the CCS agreement as currently constituted will not result in a particularly meaningful reduction in Canada’s greenhouse gas emissions. Oil sands operations emitted just under 92 million tonnes (Mt) of CO₂-equivalent in 2024—about 13% of Canada’s total emissions and an amount equal to total emissions in personal transportation (cars, SUVs, light trucks, planes, etc.). A reduction of 6 Mt by 2035 would mean that almost 94% of today’s oil sands emissions would remain untouched in ten years time. Even with the full 16 Mt reduction by 2045, 83% of today’s emissions would remain. And if oil sands production continues to grow over the next two decades—as both governments clearly hope—the reduction relative to emissions that would otherwise occur will be even smaller. Indeed, total oil sands emissions in 2045 could easily remain above today’s level depending on progress on other reduction measures.
None of this is to suggest that CCS is inexpensive. Quite the contrary. Capturing CO₂ at an oil sands facility is technically difficult and costly, with current estimates generally in the range of $80-150 per tonne, depending on the production process and facility. Transporting and permanently storing the captured CO₂—the purpose of the Pathways project itself—adds a further $20-40 per tonne. Total engineering costs are thus commonly estimated to average roughly C$100–200 per tonne of CO₂, with the wide range reflecting the substantial local variation and differences in modelling assumptions.
However, these engineering costs are not the same as the costs ultimately borne by producers. In practice, both the federal and Alberta governments have already pledged to provide substantial support through investment tax credits and other incentive programs for carbon capture, transportation and storage as well as for use of CO2 to enhance oil recovery. These could offset well over half the capital cost for producers, depending on the final financing arrangements.2
Perhaps most important, the obligations contained in the July 2nd MOU are considerably more flexible than is generally appreciated. Only 6 Mt of reductions by 2035 are specifically tied to the Pathways CCS project itself. The remaining 10 Mt may be achieved not only through expansion of Pathways, but also through "deployment of other emissions reduction technologies, or projects deploying improved production practices." This distinction is extremely significant.3
The oil sands industry has already demonstrated that substantial reductions in “emissions intensity” (CO2 per barrel produced) can be achieved through technological innovation motivated primarily by improved operating efficiency rather than by carbon capture itself. Between 2005 and 2023, emissions intensity fell by roughly 22%, from about 98 kg of CO₂ per barrel to 76 kg.4 Improvements in fuel efficiency, reduced venting, more efficient steam generation, and the increasing use of solvents in thermal production have all contributed to this decline. Such innovations can be expected to continue because they reduce production costs as well as emissions.
It’s therefore likely that a substantial fraction of the additional 10 Mt target can be achieved through ongoing technological and process improvements that occur in the normal course rather than through large new CCS installations.
Finally, Alberta’s industrial carbon pricing system (TIER) has also been the subject of agreement between the Province and Ottawa. Although often portrayed as a major obstacle to investment, its expected effect on the average cost of oil sands production is generally estimated to be only a few tens of cents per barrel. That’s because the headline carbon price applies only to emissions above performance benchmarks designed to preserve the international competitiveness of Canadian producers, while facilities performing better than the benchmark receive credits. So CCS initiatives have the potential to earn credits which, in a well-functioning credit market, can be sold for cash, thus further offsetting the cost of CCS. Unfortunately, quantitative modelling by the Canadian Climate Institute finds that design flaws in the TIER rules will dilute their effectiveness.5
The July 2nd agreement should not be interpreted either as a breakthrough in emissions reduction or as evidence that CCS has suddenly become inexpensive. It represents instead a political compromise that substantially reduces the likelihood that the CCS requirement itself will determine the future of Canada’s oil sands. The decisive questions have now returned to where they have belonged all along—Do producers see a sufficiently attractive long-term commercial return to justify major new investment in greenfield oil sands production and, if not, whether governments should ask taxpayers to bridge that gap?
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Members of the Oil Sands Alliance are: Canadian Natural Resources Limited, Cenovus, ConocoPhillips Canada, Imperial Oil Limited, and Suncor Energy.
A justification for public support for CCS is that the benefit accrues broadly, indeed globally, and not to the oil producer, apart from a return from the use to which the captured CO2 may be put—e.g., in enhanced oil recovery. Norway, for example, covers two-thirds of CCS project costs and all related operating costs for a decade.
The information released on July 2 left unclear the definition of the baseline against which the targeted reduction volumes would be measured. For directly captured CO2 the tonnage is easily measured; but how does one measure the CO2 that is not emitted because of new technologies and processes that have the effect of reducing emissions intensity? Conceptually, this can be determined by projecting what emissions would have been without the new technology and processes and comparing this modeled trajectory with actual emissions. How this measurement is to be carried out in practice will be an important detail.
Some of the reduced emissions intensity has been due to a reduction in the proportion of oil sands output coming from upgraders—which have much higher emissions intensity than raw bitumen production. But since most bitumen must eventually be upgraded, probably in an export jurisdiction, the emissions do eventually occur even if not counted in Canada’s numbers.
According to the Climate Institute’s modelling: “The MOU adds elements designed to strengthen Alberta’s carbon market while simultaneously weakening market fundamentals. Benchmark tightening rates are cut in half significantly reducing compliance demand, while the price floor’s design shifts the system away from market-driven price discovery toward fixed prices. The result is a floor asked to do too much and designed to deliver too little.”
Extremely helpful as always from Peter. Where is upgrading the current TMX in all this? My understanding is that the current TMX might be upgraded by 200-300,000 b/d for $2 to 5 billion, a fraction of the cost/b for a new pipeline. Are there estimates for a doubling of the existing line?
$100/ton for carbon capture and storage is not out of line with many carbon reduction prospects. The Government's communications should put treatment of the oil sands in context to its treatment of other industries. That said, could Alberta be pushed to do more on methane, which is getting increasing attention because of its potency in the here-and-now and methane reduction is relatively economical. The approach should include all GHGs.
And the federal deal with Alberta could be broadened further. There's a passing reference to an interlink in the original MOU which could provide new green electricity for BC at a much lower cost than BC wind and solar. Alberta's wind and solar potential is vast and highly competitive. The federal government should push back on the restrictions it has placed on what was a booming industry and stir to pot on the interlink.
Bringing in these other elements should be part of a comprehensive federal strategy for dealing with Alberta.
I can see no way that both levels of government will refuse to subsidize production. It's the wrong thing to do, mind you, but I don't see that stopping it.