The Canadian government released its long-anticipated draft Clean Electricity Regulations (Regulations) on August 10, 2023,1 setting out its approach to mandating a net-zero emissions power grid by 2035. In this note, we offer our insight on this federal regulatory initiative that will have implications on the electricity industry across Canada and is certain to be controversial in some regions of Canada, setting the stage for jurisdictional challenges and regulatory uncertainty, all of which must be addressed in order to establish a strong basis on which to invest.

While the Regulations include specific exemptions for small generating units under 25 MW or for emergency circumstances to preserve a reliable power supply, the Regulations are far-reaching in scope and will create a new federal regulatory regime that applies to the majority of existing and future natural gas, coal and hydrogen-fired electricity generating capacity. Historically, the electricity industry has been regulated primarily at the provincial level, due to section 92A(1)(c) of the Constitution Act, 1867.2 The federal government has invited public comment and feedback on the Regulations during a 75-day response period ending November 2, 2023.

The Regulations, once finalized, will come into force on January 1, 2025, but their primary implication—the emissions intensity limit—will not take effect until January 1, 2035. The Regulations set out a default emissions intensity limit of 30 tonnes of CO2 per gigawatt-hour (GWh) of electricity generated, with a number of exceptions, described below.

Background and Development of the Regulations

In the spring and summer of 2022, the federal government released a discussion paper and proposed framework for the Regulations. In the wake of the Supreme Court of Canada's decision in References re Greenhouse Gas Pollution Pricing Act,3 which found that setting minimum national standards for carbon price stringency was an area of valid federal jurisdiction, the federal government asserted that the Regulations would fall within its jurisdiction over emissions reduction. Both the discussion paper and proposed framework identified carbon capture, utilization, and storage (CCUS) as a possible emissions reduction solution for natural gas generation. However, they also acknowledged a limited ongoing role for unabated natural gas generation to: (1) mitigate emergency circumstances; (2) complement intermittent wind and solar generation; and (3) supply power during seasonal demand peaks.

In their present draft form, the Regulations do not appear to have addressed provincial concerns raised in response to the federal discussion paper and proposed framework last year, including concerns that a 2035 net-zero target for electricity generation was too ambitious and that the federal government was exceeding its jurisdiction. While the Regulations "phase in" the performance standard for existing natural gas units, they are more stringent than originally contemplated for emergency and peaking conditions.

Policymakers have been balancing three primary objectives: decarbonization, reliability and affordability. Many stakeholders have commented that simultaneously achieving these three objectives is challenging based on existing technologies and the costs associated with each. It remains to be seen how Canada will transition to a net-zero grid in a way that best preserves both reliability and affordability in a relatively short timeframe.

The 2023 Federal Budget provided financial support for investments in clean energy technology and infrastructure in the form of Investment Tax Credits (ITCs), which we previously commented on in our blog, Canada Using the Carrot Instead of the Stick to Decarbonize in Budget 2023. We also recently addressed the legislative proposals to implement the ITCs in our blog, Federal Government Releases Legislative Proposals for Clean Technology Investment Tax Credit. Recent statements made by Federal Minister of Energy and Natural Resources, Jonathan Wilkinson, suggest that the $40 billion in ITCs and other federal investments to assist with the transition to a net-zero electricity grid may be contingent on provincial commitments to move to a net-zero grid by 2035.

As provinces having the greatest opportunity for new investment in low carbon technologies are also jurisdictions with the largest potential cost impact from the proposed Regulations, these qualifications are setting the stage for federal-provincial jurisdictional challenges. The risk to developers that these ITCs may not be available in certain provinces may have a dampening effect on investment in clean energy technology and infrastructure in Canada.

Effect of the Regulations

The Regulations set emissions intensity limits for generating units that: (1) combust fossil fuels (any fuel, including hydrogen, other than biomass); (2) are connected to the grid; (3) are net exporters of electricity to the grid; and (4) have a capacity greater than 25 MW.

These emission intensity limits do not apply to non-coal-fired generating units that emit up to 150 kilotonnes of CO2 per annum that are operated for less than 450 hours in a calendar year (not including emergency exemption periods granted by the federal minister). Additionally, given the above qualifying requirements, it appears carbon-emitting electricity generation units that entirely or primarily serve load off the grid or behind the point of grid interconnection are not caught by the Regulations.

For affected units, the universal emissions intensity limit is 30 tonnes of CO2/GWh on average in a calendar year. A less stringent emissions intensity limit of 40 tonnes of CO2/GWh will be allowed until December 31, 2039, for generating units with a CCUS system that began operation within the previous seven calendar years. This less stringent limit is subject to a requirement to provide documentation demonstrating that the generating unit has operated below 30 tonnes of CO2/GWh for at least two continuous 12-hour periods separated by no less than four months during each calendar year.

The effective date for the application of the emissions intensity limits varies based on the generating unit:

  • The effective date is January 1, 2035, for: (1) generating units commissioned after January 1, 2025; (2) existing coal and petroleum coke-fired generating units; and (3) generating units that expand their capacity by more than 10% after registering under the Regulations (which must be done by the end of 2025).
  • The later of January 1, 2035, or January 1 of the calendar year when the prohibition applicable to natural gas boiler units as per section 4(2) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity begins to apply to that unit.
  • For other pre-existing generating units, January 1 of the calendar year following the unit's end of prescribed life, which is the later of either December 31 of the calendar year that is 20 years after the unit's commissioning date, or December 31, 2034.

The Regulations establish the methodologies to quantify the emissions intensity of generating units. For units connected to CCUS systems, only CO2 injected into deep saline aquifers for the sole purpose of sequestration, or CO2 injected into depleted oil reservoirs for the purpose of enhanced oil recovery, may be used to reduce the total emissions quantity of the unit for the purposes of calculating the unit's emission intensity.

Additionally, any CO2 from the production of hydrogen fuel or steam used by a generating unit must be included in the calculation of emissions intensity. This approach requires the owner or operator of the generating unit to obtain information about the quantity of CO2 emitted during hydrogen or steam production from the supplier.4

Certain generating units may be exempted from the emissions intensity limits in emergency circumstances for up to 90 days where grid operators or provincial officials order a generating unit owner or operator to produce electricity to avoid a threat to supply or to restore supply. This exemption is subject to retroactive federal ministerial review and approval to determine whether the circumstances have been appropriately characterized as an emergency.

Compliance will be primarily assured through detailed reporting obligations set out in the Regulations. Additionally, the Regulations include amendments5 that designate any violation of the emissions intensity limits as offences under the Canadian Environmental Protection Act, 1999,6 and subject to financial penalties. Accordingly, owners or operators of generating units that do not meet the emissions intensity requirements may be directed by grid operators or provincial officials to operate their units, which may expose those private entities to liability if the federal minister disagrees with the province's characterization of the emergency.

Implications and Implementation Considerations

While the federal government has recognized that the Regulations will affect provincial jurisdictions differently, it has largely relied on Canadian average data in support of its policy. For example, Environment and Climate Change Canada estimates the national average household energy bill will increase by $35 to $61 per year if the regulations are adopted. However, the costs of the Regulation will largely be incurred in jurisdictions that rely more heavily on fossil fuels (Alberta, Saskatchewan, Nova Scotia) in comparison to those provinces with legacy hydro and nuclear assets (Ontario, Quebec, British Columbia., Manitoba, Newfoundland and Labrador).

In Alberta, the grid operator (AESO) has assessed the costs associated with achieving net-zero power by 2035 as ranging from $44-$52 billion, largely comprising investments in new generation.7 For Canada-wide costs associated with decarbonizing and increasing the supply of clean electricity to keep up with demand by 2050, the Public Policy Forum has analyzed cost estimates ranging from $1.1-$1.7 trillion.8

For renewable power proponents and those of complementary technologies (such as energy storage), the Regulations, paired with the myriad federal ITCs, signal strong federal support and a favourable regulatory environment for growth in the sector.

However, both Alberta's and Saskatchewan's premiers, Danielle Smith and Scott Moe, have raised concerns with respect to the very high costs and challenges to grid reliability associated with transition to a net-zero power grid by 2035, due in part to the absence of significant hydroelectricity supply (in contrast to British Columbia, Ontario and Quebec, for example). As a result, both provincial governments have expressed unwillingness to implement the Regulations, which may result in legal challenges. In the interim, Alberta implemented a pause on new renewable project approvals (discussed in our previous blog, Alberta's Pause on Renewable Projects: What We Know So Far) shortly before the Regulations were released, driving up investment risk in the province's renewable sector. Although various other drivers were cited by provincial regulators and spokespersons, the premier attributed the pause to the federal government's 2035 net-zero ambitions and associated (then forthcoming) Regulations.

It remains to be seen whether the Regulations would be upheld as within federal jurisdiction under the "doctrine of national concern" as applied in the Supreme Court of Canada's decision in References re Greenhouse Gas Pollution Pricing Act. As the Regulations will be promulgated under the Canadian Environmental Protection Act, 1999, a further question arises whether the Regulations are a valid exercise of the federal government's criminal law power.

The draft Regulations apply equally across Canadian jurisdictions and are mandatory. There are no exceptions for generating units within provinces that have openly "opted out" of the regime. Until the conflict with provincial regulatory jurisdiction is reconciled, the Regulations will create regulatory uncertainty that will affect investment decisions related to fossil fuel generators.

As a result, industry members and policymakers have expressed concerns that provinces relying primarily on natural gas for baseload supply and grid stability may face reliability challenges given the Regulations. The Business Council of British Columbia previously stated the Regulations will "[enact] barriers to the use of natural gas and thus [force] choices on the margin that are more expensive and will not necessarily deliver the reliable, low-cost energy (watt-hours) and peak reliability demanded by consumers."9

Additionally, de-regulated electricity markets will struggle to attract investment in fossil fuel-based technologies, even if those technologies would provide cost-effective grid stability services and reliable dispatchable supply through to 2035 and beyond. Independent power producers (as opposed to provincial government bodies) using unabated natural gas to supply power during emergencies may be confronted with compliance risks under the Regulations, which will affect investment and could result in the emergency exemption in the Regulations providing less practical value for jurisdictions without legacy hydro and nuclear assets that are seeking to avoid application of the Regulations.

As mentioned above, the federal government has invited public comment on the Regulations until November 2, 2023, which provides an opportunity for industry members and the public to share their concerns and provide input on the Regulations.




3. References re Greenhouse Gas Pollution Pricing Act, 2021 SCC 11

4. CO2 emissions to be quantified in accordance with Environment and Climate Change Canada's Greenhouse Gas Quantification Requirements, Greenhouse Gas Reporting Program.

5. The Regulations amend the schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999), SOR/2012-134.

6. SC 1999, c 33.




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