New modelling shows that different versions of the MOU policy package could vary by more than 80 million tonnes of emissions in 2050, depending on how the industrial carbon market is designed.
New analysis in partnership with Navius Research tests different possible outcomes of the Canada–Alberta MOU with scenarios combining choices on industrial carbon pricing, electricity regulation, methane, and oil production to fill new pipeline capacity. And while all of these policy choices matter, our modelling shows that one element drives the outcome more than any other: how the industrial carbon market inside that package is designed.
The table at the end of this Insight provides more technical detail on the scenarios assessed and the policy outcomes in 2050, which are based on publicly available information in the MOU text.
Industrial carbon pricing details will be crucial for emissions from MOU agreement
There is a wide range of outcomes across MOU policy choices. The same MOU, implemented with a weak or strong carbon market, produces national results that differ by roughly 55 megatonnes of carbon dioxide-equivalent (Mt) annually by 2040, widening to more than 80 Mt by 2050 (Figure 1). That makes a significant difference because Canada is not currently on track to meet any of its climate goals, including net zero by 2050, as we’ve previously shown.
Both implementations in our modelling reach $130 per tonne for minimum carbon credit prices, but at different times and on very different trajectories, with very different levels of emissions. In the weak market scenario, the minimum $130 price is reached by 2035 and holds steady over time, whereas the strong version reaches this level by 2030 and continues a gradual annual increase.
Over time, the gap widens as emission-limit tightening increases scarcity and prices rise. A flat price in a surplus market does not.
In a weak market with high emissions limits, surplus credits and low compliance pressure result in little to no emissions reductions in heavy industry. The price of credits remains elevated but compliance comes largely from companies relying on banked credits and flexible mechanisms to meet their compliance obligations rather than real abatement.
Figure 1
In a stronger carbon market, tighter credit limits ensure demand exceeds supply with enough of a buffer to create genuine scarcity. With tighter emissions limits, there are fewer performance credits and offsets available for compliance, and firms face real investment decisions that push them to consider either paying into the TIER technology fund (fund credits) or reducing emissions.
The clearest signal is in heavy industry: current policies are set to deliver an 8 per cent reduction from today’s levels by 2040. A weak $130 per tonne carbon market adds almost no emissions reductions on top of that, reaching just 9 per cent. A strong market, by contrast, delivers a 37 per cent reduction in the sector’s emissions, according to our modelling.
Methane regulation outcomes are secondary. While the federal and Alberta regulations may not immediately deliver equivalent emissions outcomes under the Canadian Environmental Protection Act, both will need to deliver similar reductions by 2040 and would not materially change the longer term MOU emissions trajectories.
An expansion of the existing Trans Mountain pipeline project and a new tidewater pipeline are different. With 1.4 million barrels per day of new supply needed to fill those projects, roughly 20 Mt of new emissions are added. In a strong market there are enough reductions to compensate for the pipeline increase, with a weak market there are not.
In electricity, the divergence is more severe because the absence of the CER and weak carbon markets lead to compounding effects. Without a strong carbon market, dropping CER worsens the emissions intensity of Alberta’s electricity grid and locks in higher-cost gas power, raising affordability concerns as gas sets the marginal price in our scenarios. Emissions in the sector rebound, more than doubling from 14 Mt in 2035 to 29 Mt in 2050, nearly erasing 15 years of grid decarbonization. A strong carbon market with CER in place nationally instead holds electricity emissions at 9 Mt by 2040 and 6 Mt by 2050. That reinforces the Climate Institute’s position that the CER is a critical policy for the power sector, both in Alberta and across the country.
Overall, the numbers are stark. A weak $130 per tonne market with pipeline expansion actually increases Canada’s national emissions 22 Mt above today’s policy trajectory by 2040 and over 40 Mt above it by 2050. It reverses progress already embedded in current policy—which is itself weakened by gaps in industrial pricing, including no effective price in Saskatchewan and a chronically oversupplied, underperforming TIER system in Alberta.
Industrial carbon pricing is the load-bearing element of the MOU
The carbon market is the load-bearing element of the system. But experience in Canada shows these markets can underperform—either by design or over time, as pressures emerge to ease compliance.
A carbon price floor is insurance against that outcome. In a strong market it is irrelevant. In a weak market, it helps sustain demand and reduces the risk that policy adjustments weaken the system.
The MOU is a foundation, not a destination. Whether it is a credible foundation depends entirely on whether the carbon market it establishes is built to last.
Figure 2
- Today’s policies: Clean Electricity Regulations are in place (CER) in all provinces, 75 per cent methane regulations in 2035, federal output based pricing system reaches a headline prices of $170 by 2030 non-binding—Alberta’s TIER prices frozen at $95 per tonne; Saskatchewan at zero; direct investment credits.
- Weak MOU: $130 minimum carbon credit price by 2035; the carbon price is flat thereafter. The system sees weak demand for credits and includes Alberta’s direct investments credit program. The scenario does not include CER nationally, and methane emissions reductions are delayed to 2040.
- Strong MOU: $130 minimum carbon credit price by 2030, escalating at $5 per tonne each year ($188 by 2040, $229 by 2050). This scenario includes a demand buffer of 20 per cent and no direct investments credits. The CER applies nationally, and the federal methane regulations are maintained.
- Pipeline: Both scenarios include additional pipeline throughput of 1.4 million barrels per day with $5 billion CCUS subsidy and the associated federal Investment Tax Credits.
Alison Bailie is Senior Research Associate at 440 Megatonnes. Dale Beugin is Executive Vice President at the Canadian Climate Institute