On August 10, 2023, the government of Canada released draft Clean Electricity Regulations [PDF] (CER) for public comment. The final CER are anticipated to be registered under the Canadian Environmental Protection Act, 1999 (CEPA) in 2024 and come into force on January 1, 2025.
The CER limit carbon emissions produced by electricity generated using fossil fuel in an effort to ultimately eliminate emitting sources of supply connected to public electricity grids in Canada. The CER implement measures proposed in the government of Canada’s 2030 Emission Reduction Plan, discussed in a previous post on our Canada Energy Transition Blog, and in furtherance of the federal government’s goal of economy-wide net-zero emissions by 2050. According to the government of Canada, carbon pricing regulations alone are insufficient to achieve the required emissions from the electricity sector, which accounted for 9.2% of total GHG emissions in Canada in 2020.
This blog describes the applicability of the CER to electricity generators in Canada, the emission limits imposed on CER-regulated generators, and the implications of CER limits for different provinces.
The CER apply to electricity generating units that, on or after January 1, 2025: (i) have a generating capacity of 25 megawatts (MW) or more; (ii) generate electricity using fossil fuel, which is defined to include hydrogen gas and exclude biomass (which includes biogas); and (iii) are connected to an electricity system subject to the North American Electric Reliability Corporation (NERC) standards, which includes systems in Alberta, British Columbia, Manitoba, New Brunswick, Nova Scotia, Ontario, Québec, and Saskatchewan. However, the CER Regulatory Impact Analysis Statement (RIAS) creates confusion regarding the CER’s applicability by referring to electricity generation in Newfoundland and Labrador, Prince Edward Island and the territories, which are not currently subject to NERC standards.
The responsible person for a CER-regulated generating unit must submit a registration report to the Minister (i) by December 31, 2025 for a unit commissioned prior to January 1, 2025 or (ii) within 60 days of the commissioning date for a unit commissioned on or after January 1, 2025. A similar registration requirement exists for any modifications to an existing unit that creates one or more new units. A similar registration requirement exists for any modification to an existing unit that creates one or more new units.
Prohibition on emissions by CER-regulated generators
Generating units subject to the CER must not emit more than 30 tonnes of CO2 per gigawatt hour (GWh) of electricity generated on average in a calendar year (Emission Prohibition). However, the CER do not impose the Emission Prohibition on any units until January 1, 2035 and provide extended timeframes for its application to certain existing units, as set out below.
Prohibition Start Date
Type of Unit
January 1, 2035.
The later of January 1, 2035 or January 1 of the calendar year the emissions limits under the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity apply.
January 1 of the year following the unit’s end of prescribed life (the later of December 31 of the calendar year 20 years after the commissioning date and December 31, 2034).
The Emission Prohibition start date for “all other units” sets a prescribed life for those units of 20 years. Generating assets can have varying expected useful lifespans with many thermal generating technologies expected to last 45 years. If investments in carbon capture and storage (CCS) are not economical for such units, the CER’s truncation of the lifespan of these generating units can be expected to result in significant stranded costs, limiting the ability of utility generators to optimize such sources of generation over the coming decades of energy transition planning horizons.
Exemptions from the CER prohibition on emissions
The Emission Prohibition does not apply to:
- Behind-the-Fence generating units with net exports of 0 GWh, provided the owner or operator submits an annual declaration to the Minister in the calendar year prior to which the Emission Prohibition would apply.
- Generating units that have not combusted coal in a calendar year and have operated for 450 hours or less during that calendar year. These units may emit up to 150 kilotonnes of CO2 emissions in the same calendar year.
- Generating units granted an exemption by the Minister due to an emergency circumstance where a provincial electricity authority ordered the unit to produce electricity. The CER defines an emergency circumstance to be a circumstance: (i) that arises due to an extraordinary, unforeseen and irresistible event; or (ii) under which one or more of the measures referred to in paragraph 1(a) of the Regulation Prescribing Circumstances for Granting Waivers Pursuant to Section 147 of the Act (e.g., a proclamation under the Emergencies Act, an order under the Energy Supplies Emergency Act or a declaration of an emergency in a province). An emergency circumstance exemption may continue for a maximum of 90 days and may be continued for a maximum of an additional 90 days.
In addition, the CER provides for a transition period for regulated units that include a CCS system. Until December 31, 2029, these units may emit a calendar year average of 40 tonnes of CO2 emissions per GWh of electricity generated, provided that:
- The unit’s CCS system began operating within the last seven calendar years; and
- The unit has operated at or below 30 tonnes of CO2 emissions per GWh for two periods of at least 12 continuous hours, with at least four months between those two periods, in a calendar year.
The government of Canada has stated that the timeframe for this exemption aligns with a 95% capture rate that should be attainable by 2035. At present, CCS technologies and projects within Canada generally remain at a pilot or demonstration status for purposes of deployment at scale. For example, Alberta has two operational commercial scale CCS projects, with 25 additional projects proposed. However, the government of Canada has acknowledged that CCS projects require large investments and take a long time to build, and which projects eventually get built, and when, will depend upon availability of labour, material, financing, and government policies.
Quantification of emissions
For the purposes of demonstrating compliance with the Emissions Prohibition, the CER require the emissions intensity of a unit, for a calendar year, to be determined by dividing the quantity of CO2 emissions attributed to a unit (in tonnes), during such calendar year, by the quantity of electricity generated by the unit (in GWh), during such calendar year.
The quantity of electricity generated by a unit is the gross quantity of electricity generated by a unit, as measured by a meter, over a calendar year, less the gross quantity of electricity generated by a unit, as measured by a meter, during any period in such calendar year for which the Minister has granted an emergency circumstance exemption to the unit.
The CER require a unit’s total CO2 emissions for a calendar year to be determined using the following formula:
Eu – Eth – Eccs + Eext – Eec
Eu = a unit’s CO2 emissions from the combustion of fossil fuels Eth = a unit’s CO2 emissions from the production of useful thermal energy Ecss = the quantity of CO2 emissions captured and stored from a unit by a CCS system Eext = the quantity of CO2 emissions emitted from the production of hydrogen fuel or purchased or transferred steam used to by the unit to generate electricity Eec = a unit’s CO2 emissions during any period for which the Minister has issued an emergency circumstance exemption.
The CER provide a detailed description regarding the quantification method for each of the above variables.
For Eu, the quantification method varies based on the type(s) of fuel combusted and may either be based on a continuous emissions monitoring system (CEMS) or a fuel-based calculation, and where a unit combusts biomass (e.g., a multi-fuel unit) emissions from the biomass combustion are excluded.
From Eu certain emissions are subtracted (e.g., Eth, Eccs and Eec):
- Eccs are emissions captured by a CCS system and are excluded from a generating unit’s total emissions for the purposes of the Emission Prohibition. However, the CER only recognize CO2 permanently stored in a prescribed geological sites – either a deep saline aquifer used exclusively for CO2 storage or a depleted oil reservoir for the purpose of enhanced oil recovery. The CER do not address how a leak or accidental release of stored CO2 may impact compliance with the Emission Prohibition for any previous calendar year. Additionally, only recognizing CO2 stored in a prescribed geological site may unduly restrict potential emission reductions from CCS if other geological sites are identified as more feasible locations to store CO2.
- Eth are emissions attributed to the production of useful thermal energy are excluded from a generating unit’s total emissions for the purposes of the Emissions Prohibition. The CER define useful thermal energy as “energy in the form of steam or hot water that is destined for a use, other than the generation of electricity, that would have required the consumption of energy in the form of fuel or electricity had that steam or hot water not been used.”
- Eec are emissions generated while the unit is operating pursuant to an exemption by the Minister due to an emergency circumstance, as discussed above.
With respect to Eext, since the combustion of fossil fuels for the production of hydrogen and purchased or transferred steam that are used in a unit to generate electricity do not result in CO2 emissions from that unit in its generation of electricity, the CER’s emissions formula requires the addition of Eext to ensure that all emissions associated with electricity generated by a unit are included in the calculation of the unit’s emissions intensity, regardless of the location of the supplier of the hydrogen fuel or thermal energy used in that unit for electricity generation.
The CER would make non-compliance with the Emission Prohibition an offence under the CEPA punishable by fines from $100,000 to $12 million.
Implications for provincial electricity systems
The CER were published with an extensive regulatory impact analysis statement detailing the government of Canada’s expected impacts of implementing the CER. The RIAS highlights that the CER would disproportionately impact certain provincial electricity systems, creating cost savings for some, while imposing substantial costs on others.
Under the CER, an estimated 98% of incremental electricity system air pollutant emission reductions from 2024 to 2050 would be made by electricity systems in the five provinces with electricity systems most reliant on electricity generated using fossil fuel (Alberta, Saskatchewan, Ontario, Nova Scotia and New Brunswick). These provinces will need to make significant investments in non-emitting sources of electricity generation to comply with the CER, while other provinces are not expected, based on the CER, to be required to undertake any significant buildout of non-emitting generation.
According to the government of Canada, the majority of capital cost incurred would be attributable to the buildout of biomass in Nova Scotia, nuclear in New Brunswick, peaking-capable hydroelectric facilities in Ontario, nuclear in Saskatchewan and natural gas with CCS in Alberta. However, the CER do not account for the regulatory and construction timelines needed to phase in these new sources of generation as the Emission Prohibition takes effect and phases out existing sources of generation.
The government of Canada also expects the CER to spur the development of new inter-provincial transmission lines and significantly increase domestic trade activity, amounting to $43 billion in economic value from 2024 to 2050. However, the incremental capital cost of new inter-provincial transmission lines from 2024 to 2050 is expected to total $6.7 billion. Alberta will bear the brunt of these costs, with an estimated cost of $1.1 billion in 2031-2035 alone. The cost of new inter provincial transmission lines may become increasingly prohibitive if provinces with cleaner sources of electricity are unwilling to contribute to capital costs, compelling provinces with supply shortages to do so alone.
The economic value of increased domestic electricity trade to each province is expected to vary significantly as well. For example, Alberta is projected to see an estimated cost impact of $16.3 billion over that time period, whereas British Columbia is projected to see estimated cost savings of $21.7 billion, while other provinces can expect to see cost impacts or savings falling somewhere in between. The government of Canada’s expectation of increased inter-provincial electricity trade also assumes provinces with cleaner sources of electricity generation will have excess power to trade, and be willing to trade it. The RIAS does not address whether provinces will have excess electricity supply to sell and deliver to neighboring jurisdictions. The government of British Columbia recently announced its intention to procure new electricity supply to support an increase in demand of 30% between now and 2030. Similarly, Hydro-Québec announced its intention to procure additional generation needed to support Québec’s growing demand for electricity.
The government of Canada has acknowledged that the CER do not prescribe any particular compliance pathway. Therefore, it may be incumbent on provincial governments to identify available sources of funding. Utilities and independent power producers that invest in cleaner sources of electricity generation can be expected to seek a return on their investment through customer rates, long-term contracted rates with government, or private off-takers or market prices (as applicable). The government of Canada has already indicated it expects higher incremental increases to residential, commercial and industrial electricity rates in provinces more reliant on electricity generated using fossil fuel.
It may also be incumbent upon provincial governments to develop regulations governing the approval processes for new generation projects, as well as procurement and contracting strategies for new electricity resources in line with the CER, and reclamation obligations associated with the decommissioning (or conversion) of emitting sources of generation.
The public comment period for the CER ends on November 2, 2023. The CER have already faced significant backlash from provincial governments with electricity systems reliant on emitting sources of generation. Alberta Premier Danielle Smith issued a statement on August 10, 2023, challenging the constitutionality of the CER (as an intrusion on provincial jurisdiction over electricity generally) and linking concerns over the CER with the recently announced pause on approvals for new renewable energy facilities in Alberta (discussed here). Coupled with a federal election looming in the next two years, and the planned role out of the potentially transformational federal investment tax credit regime (discussed here), the future of electricity generation in Canada faces increased uncertainty. This is at a time when Canadian jurisdictions from coast-to-coast-to-coast are planning for aggressive growth of their electricity supply to meet increased electrification demands in support of economy-wide carbon reduction targets.
The CER appear poised to impose significant restrictions on investments in emitting sources of electricity generation and prompt investment in cleaner sources of electricity generation and the entrance of new market participants. Companies, electricity system and market operators and electricity market participants and other stakeholders across Canada will need to carefully manage their obligations, expectations and opportunities arising from implementation of the CER.