Clean Electricity Regulations: SOR/2024-263

Canada Gazette, Part II, Volume 158, Number 26

Registration
SOR/2024-263 December 13, 2024

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

P.C. 2024-1317 December 13, 2024

Whereas, under subsection 332(1)^{footnote a} of the Canadian Environmental Protection Act, 1999 ^{footnote b}, the Minister of the Environment published in the Canada Gazette, Part I, on August 19, 2023, a copy of the proposed Clean Electricity Regulations, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection;

Whereas, under subsection 93(3) of that Act, the National Advisory Committee has been given an opportunity to provide its advice under section 6^{footnote c} of that Act;

And whereas, in the opinion of the Governor in Council, under subsection 93(4) of that Act, the proposed Regulations do not regulate an aspect of a substance that is regulated by or under any other Act of Parliament in a manner that provides, in the opinion of the Governor in Council, sufficient protection to the environment and human health;

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, makes the annexed Clean Electricity Regulations under subsection 93(1)^{footnote d}, sections 286.1^{footnote e} and 326^{footnote f} and subsection 330(3.2)^{footnote g} of the Canadian Environmental Protection Act, 1999 ^{footnote b}.

Clean Electricity Regulations

Purpose

Purpose

1 The purpose of these Regulations is to protect the environment and human health from the threat of climate change by establishing a regime that prohibits excessive carbon dioxide (CO₂) emissions from the use of fossil fuel to generate electricity.

Interpretation

Definitions

2 (1) The following definitions apply in these Regulations.

ASTM

means ASTM International. (ASTM)

auditor

means an individual who

(a) is independent of the responsible person that is to be audited; and
(b) has knowledge of and experience with respect to
- (i) the certification, operation and relative accuracy test audit of continuous emission monitoring systems, and
- (ii) quality assurance and quality control procedures in relation to those systems. (vérificateur)

authorized official

means

(a) in respect of a responsible person who is an individual, that individual or an individual who is authorized to act on that individual’s behalf;
(b) in respect of a responsible person that is a corporation, an officer of the corporation that is authorized to act on its behalf; and
(c) in respect of a responsible person that is another entity, an individual who is authorized to act on its behalf. (agent autorisé)

biogas

means a gaseous mixture — including landfill gas and sludge digestion gas — that consists primarily of methane and CO₂ that is recovered from the anaerobic decomposition of biomass and that contains other constituents that prevent it from meeting the standard for injection into the nearest natural gas pipeline. (biogaz)

biomass

means material that originates from plants or animals, including animal waste, or any product derived from any of these, and includes wood, wood products, agricultural residues, biologically derived organic matter in municipal or industrial wastes, biogas, renewable natural gas, bio-alcohols, pulping liquor and other fuels that consist only of non-fossilized, biodegradable organic material that originates from plants or animals but does not originate from a geological formation. (biomasse)

Canadian offset credit

means

(a) an offset credit issued under subsection 29(1) of the Canadian Greenhouse Gas Offset Credit System Regulations; or
(b) a unit or credit that is recognized under subsection 78(1) of the Output-Based Pricing System Regulations and meets the conditions set out in paragraphs 78(4)(a) to (d) of those Regulations. (crédit compensatoire canadien)

CEMS Protocol

means the document entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation and other sources, published by the Department of the Environment in 2023. (Protocole SMECE)

coal

includes petroleum coke and synthetic gas that is derived from coal or petroleum coke. (charbon)

combustion engine

means an engine, other than an engine that is self-propelled or designed to be propelled while performing its function, that

(a) operates according to the Brayton thermodynamic cycle and combusts fossil fuel to produce a net amount of motive power; or
(b) combusts fossil fuel and uses reciprocating motion to convert thermal energy into mechanical work. (moteur à combustion)

commissioning date

, in respect of a unit, means the day on which the oldest boiler or combustion engine in the unit starts operating. (date de mise en service)

continuous emission monitoring system or CEMS

means equipment for the sampling, conditioning and analyzing of emissions from a given source and the recording of data related to those emissions. (système de mesure et d’enregistrement en continu des émissions ou SMECE)

deduction period

means the period for which the beginning and end is determined in accordance with subsection 25(2). (période de déduction)

electricity generation capacity

means the capacity of a unit, expressed in MW and determined in accordance with section 6. (capacité de production d’électricité)

electricity system

means an electricity system that is subject to the standards of the North American Electric Reliability Corporation. (réseau électrique)

electricity system operator

, in respect of a unit, means the person that operates the electricity system within a province and to which the unit is required to report in order to transmit electricity to the electricity system. (exploitant de réseau électrique)

facility

means the units, buildings, other structures and stationary equipment — including equipment used for hydrogen or ammonia production and equipment used for fuel production from coal gasification — that have in common at least one owner or person who has the charge, management or control of each of them and that are located on a single site, or on contiguous or adjacent sites that function as a single integrated site, where an industrial activity is carried out. (installation)

fossil fuel

means a fuel, other than biomass, that releases CO₂ when combusted or that is produced using a process that results in CO₂ emissions. (combustible fossile)

GHGRP

means the document entitled Canada’s Greenhouse Gas Quantification Requirements, Greenhouse Gas Reporting Program, Version 5.0, published by the Department of the Environment in December 2021. (PDGES)

maximum continuous rating

means the maximum net power that a unit can continuously sustain, expressed in MW, as reported to the electricity system operator for the unit. (puissance maximale continue)

net supply

means the quantity of electricity supplied to an electricity system during a calendar year, expressed in GWh and determined in accordance with subsection 13(2). (solde de fourniture)

planned unit

means a unit referred to in section 3. (groupe prévu)

renewable natural gas

means natural gas that meets the standard for injection into the nearest natural gas pipeline and that is either gas derived from the processing of biogas or synthetic natural gas derived from biomass. (gaz naturel renouvelable)

responsible person

means an owner or a person that has the charge, management or control of a unit. (personne responsable)

standard conditions

means a temperature of 15°C and a pressure of 101.325 kPa. (conditions normales)

unit

means an assembly consisting of equipment that is physically connected and that operates together to generate electricity, including at least one boiler or combustion engine along with any other equipment, such as duct burners or other combustion devices, heat recovery systems, steam turbines, generators, emission control devices and carbon capture and storage systems. (groupe)

useful thermal energy

means 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. (énergie thermique utile)

Carbon capture and storage

(2) For the purposes of the definition unit in subsection (1), equipment that is connected only by a carbon capture and storage system is not considered to be physically connected. However, that carbon capture and storage system is considered to be part of each unit to which it is connected.

Planned unit

3 A unit is planned if its commissioning date is within the period that begins on January 1, 2025 and ends on December 31, 2034 and if the Minister is satisfied that the unit is substantially the same on its commissioning date as the unit in relation to which the following criteria were met:

(a) on or before December 31, 2025,
- (i) all information required to initiate any impact assessment or environmental assessment required in relation to the unit under a federal or provincial law has been submitted to the relevant authority,
- (ii) the proponent responsible for the development of the unit owns or has a lease for the land on which the unit is located,
- (iii) all information required to initiate the process to obtain any permit required to begin construction at the site where the unit is located has been submitted to the relevant authority, and
- (iv) contracts with a value of at least $10 million have been entered into for the purchase of any equipment referred to in the definition unit in subsection 2(1) for use in the unit; and
(b) on or before December 31, 2027, construction has begun at the site where the unit is located.

Incorporation by reference

4 (1) A reference to any document incorporated by reference into these Regulations, other than the GHGRP and the CEMS Protocol, is a reference to the most recently published version of the document.

Interpretation of documents incorporated by reference

(2) For the purposes of interpreting any document that is incorporated by reference into these Regulations, “should” is to be read as “must” and any recommendation or suggestion is to be read as an obligation.

Adaptation of GHGRP

(3) For the purposes of these Regulations, any reference in the GHGRP to the document entitled Reference Method for Source Testing: Quantification of Carbon Dioxide Releases by Continuous Emission Monitoring Systems from Thermal Power Generation is to be read as a reference to the CEMS Protocol.

Adaptation of CEMS Protocol

(4) For the purposes of these Regulations, the CEMS Protocol is to be read as follows:

(a) the references to “appropriate regulatory authority”, “applicable regulating authority”, “appropriate regulatory agency” and “corresponding regulating authority” are to be read as references to the Minister, except in section 5.3.1, where “the appropriate regulatory authority” is to be read as “subsection 46(1) of the Clean Electricity Regulations”; and
(b) the reference to “the most recent version of the ECCC Canada’s Greenhouse Gas Quantification Requirements” in section 7.1 is to be read as a reference to “section 16 of the Clean Electricity Regulations”.

Application

Criteria

5 (1) These Regulations begin to apply in respect of a unit on the day on which the unit meets the following criteria and, subject to subsection 43(2), continue to apply until the responsible person for the unit submits the notice of permanent cessation of electricity generation in accordance with subsection 43(1):

(a) the unit has an electricity generation capacity of at least 25 MW;
(b) the unit generates electricity using fossil fuel; and
(c) the unit is connected, directly or indirectly, to an electricity system.

Sum of electricity generation capacity

(2) Subject to subsection (3), a unit that has an electricity generation capacity of less than 25 MW is deemed to meet the criterion set out in paragraph (1)(a) if

(a) the unit’s commissioning date is on or after January 1, 2025; and
(b) the sum of the electricity generation capacity of all units, other than planned units, that are located at the facility where the unit is located and that have commissioning dates on or after January 1, 2025 is at least 25 MW.

Non-application — planned units

(3) These Regulations do not apply in respect of a planned unit that has an electricity generation capacity of less than 25 MW.

Electricity generation capacity

6 (1) Subject to subsection (6), a unit’s electricity generation capacity is

(a) the unit’s maximum gross power, measured at the electrical terminals of the unit’s generators and determined in accordance with subsections (2) to (4); or
(b) if the responsible person has not determined the unit’s maximum gross power, the unit’s most recent maximum continuous rating.

Performance test

(2) To determine a unit’s maximum gross power, the responsible person must conduct, in the presence of the performance test verifier referred to in subsection (3), a performance test that

(a) is conducted on or after January 1, 2025;
(b) is a continuous test that lasts at least two hours;
(c) does not compromise the continued operation of the unit by exceeding the operating specifications for temperature, pressure or electrical conductivity recommended by the manufacturer of the equipment that is part of the unit;
(d) does not require that the planned maintenance schedule of the unit be altered; and
(e) has results that are adjusted to standard conditions.

Performance test verifier

(3) The performance test verifier is an individual who

(a) is independent of the responsible person; and
(b) has demonstrated knowledge of the performance testing of units that generate electricity using fossil fuel and at least five years’ experience with respect to such testing.

Performance test report

(4) A responsible person that conducts a performance test must submit to the Minister a performance test report prepared by the performance test verifier that contains the information set out in Schedule 1.

Report submitted after registration

(5) A responsible person that submits a performance test report for a unit after the registration report for the unit is submitted under subsection 7(1), paragraph 7(2)(a) or subsection 8(2) must submit to the Minister, no later than 60 days after the day on which the test is conducted, the performance test report along with the updated registration report referred to in subsection 7(4).

Change of electricity generation capacity

(6) If, during a calendar year in which a unit is subject to an emission limit under subsection 9(1), the maximum gross power or maximum continuous rating of the unit changes, the unit’s electricity generation capacity for that calendar year is determined by the formula

$\sum_{i = 1}^{n} [\frac{C_{i} \times D_{i}}{N}]$: where
i: is the i^th period of the calendar year, where “i” goes from 1 to n and where n is the number of periods in the calendar year during which the unit’s electricity generation capacity differs from the preceding or subsequent period;
C_i: is the electricity generation capacity of the unit during the i^th period of the calendar year;
D_i: is the length of the i^th period of the calendar year, expressed in days; and
N: is the number of days during the calendar year that the unit’s electricity generation capacity is greater than zero.

Rounding

(7) The electricity generation capacity determined under subsection (2) or (6) is to be rounded to the nearest whole number or, if equidistant between two consecutive whole numbers, to the higher number.

Registration

Registration report

7 (1) Subject to section 8, the responsible person for a unit that meets the criteria set out in section 5 must submit to the Minister a registration report for the unit that contains the information set out in Schedule 2 by the later of

(a) December 31, 2025, and
(b) the 60th day after the day on which the unit meets the criteria set out in section 5.

Modification of a unit

(2) If a unit for which a registration report has been submitted under subsection (1) is modified, such as by adding or removing a piece of equipment or changing how equipment is physically connected, and that modification results in the creation of one or more units that meet the criteria set out in section 5, the responsible person must submit to the Minister

(a) a registration report for each unit that was created that contains the information set out in Schedule 2 within 60 days after the day on which the unit was created; and
(b) the notice of permanent cessation of electricity generation referred to in subsection 43(1) for the original unit or the updated registration report referred to in subsection (4) for that unit.

Registration number

(3) On receipt of the registration report referred to in subsection (1), paragraph (2)(a) or subsection 8(2), the Minister must assign a registration number to the unit and inform the responsible person of that registration number.

Updated registration report

(4) If there is a change to any information submitted under this section or subsection 8(2), the responsible person must submit to the Minister, no later than 60 days after the day on which the change occurs, an updated registration report for the unit that contains the information set out in Schedule 2.

Subunits

8 (1) A responsible person may register a unit as multiple subunits if

(a) each subunit would be a unit as defined in subsection 2(1) if it were not physically connected to any of the other subunits;
(b) each subunit has a maximum continuous rating;
(c) each subunit produces useful thermal energy;
(d) each boiler and combustion engine, as well as any other equipment that is part of the unit, is accounted for in one of the subunits; and
(e) either each boiler and combustion engine in the unit started operating on or before December 31, 2024 or each boiler and combustion engine was part of a planned unit on the unit’s commissioning date.

Registration report

(2) To register a unit as multiple subunits, the responsible person must

(a) in the case of a unit for which a registration report has not been submitted under section 7, submit to the Minister a registration report for each subunit that contains the information set out in Schedule 2 by the later of
- (i) December 31, 2025, and
- (ii) the 60th day after the day on which the unit meets the criteria set out in section 5; or
(b) in the case of a unit for which a registration report has been submitted under section 7, submit to the Minister the following reports no later than the day before the day on which any of the subunits would, if registered, be subject to an emission limit under subsection 9(1):
- (i) an updated registration report for the unit that contains the information set out in Schedule 2 in respect of one of the subunits, and
- (ii) a registration report for each of the other subunits that contains the information set out in Schedule 2.

Consequences of registration

(3) If a unit is registered as multiple subunits in accordance with subsection (2),

(a) each subunit is deemed to be a unit to which these Regulations apply; and
(b) these Regulations, other than this section, cease to apply in respect of the unit that is registered as multiple subunits.

Permanent cessation

(4) A registered subunit is no longer deemed to be a unit, other than for the purposes of subsection 43(2), beginning on the day on which the responsible person for the subunit submits the notice of permanent cessation of electricity generation referred to in subsection 43(1).

Notice — maximum continuous rating

(5) The responsible person for a unit that has been registered as multiple subunits must notify the Minister, no later than 60 days after the day on which the change occurs, if the sum of the maximum continuous rating for each of the subunits increases by 15% or more from the sum of the maximum continuous ratings reported in the registration reports submitted for the subunits under subsection (2).

Application of emission limit

(6) If, on the day on which the increase referred to in subsection (5) occurs, one or more of the subunits has not reached the end of its prescribed life, as determined in accordance with subsection 10(3) or section 11, subsection 9(1) begins to apply in respect of each of those subunits on the later of

(a) January 1, 2035, and
(b) January 1 of the calendar year following the year in which the increased maximum continuous rating was reported to the electricity system operator.

Prohibition

Emission limit

9 (1) The responsible person for a unit must not emit from the unit in a calendar year a quantity of CO₂, determined in accordance with section 12, that exceeds the limit, expressed in tonnes, determined by the formula

C × I_el × 8760 × 0.001

where

C

is the unit’s electricity generation capacity for the calendar year; and

I_el

is the emissions intensity applicable to the calendar year and is

(a) 65 tonnes of CO₂ emissions per GWh for the 2035 to 2049 calendar years, and
(b) 0 tonnes of CO₂ emissions per GWh for the 2050 and subsequent calendar years.

Rounding

(2) The emission limit determined under subsection (1) is to be rounded to the nearest whole number or, if equidistant between two consecutive whole numbers, to the higher number.

Non-application — end of prescribed life

10 (1) Subject to subsection (2), subsections 9(1), 12(1) and 13(1) do not apply in respect of a unit, other than one that combusts coal, until January 1 of the calendar year following the unit’s end of prescribed life if it

(a) has a commissioning date after December 31, 2009 but before January 1, 2025;
(b) is a planned unit; or
(c) is a boiler unit referred to in subsection 3(4) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity that has an end of prescribed life after December 31, 2034.

Increase in maximum continuous rating

(2) Subsections 9(1), 12(1) and 13(1) begin to apply in respect of a unit referred to in subsection (1) on the later of the following dates if the maximum continuous rating for the unit increases by 15% or more from the maximum continuous rating reported in the registration report submitted for the unit under subsection 7(1), paragraph 7(2)(a) or subsection 8(2):

(a) January 1, 2035, and
(b) January 1 of the calendar year following the year in which the increased maximum continuous rating was reported to the electricity system operator.

Date of end of prescribed life

(3) For the purposes of subsection (1) but subject to section 11, a unit’s end of prescribed life is on

(a) December 31 of the calendar year that is 25 years after the unit’s commissioning date, in the case of a unit referred to in paragraph (1)(a);
(b) December 31, 2049, in the case of a planned unit; and
(c) December 31 of the calendar year before the prohibition set out in subsection 4(2) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity would have applied to the unit, as determined under that subsection, in the case of a unit referred to in paragraph (1)(c).

Election

11 (1) For the purposes of subsection 10(1), the responsible person for a unit may elect to end the unit’s prescribed life on a date that is before the date set out for the unit in subsection 10(3) and that is no earlier than December 31, 2034.

Information

(2) The responsible person must, in order to make the election, submit the following information to the Minister on or before the date that is elected to be the unit’s end of prescribed life:

(a) the registration number assigned to the unit by the Minister under subsection 7(3); and
(b) the date that is elected as the unit’s end of prescribed life.

Election permanent

(3) An election made under this section may not be changed or revoked.

Obligations

CO₂ emissions from unit

12 (1) The responsible person for a unit must determine the quantity of CO₂, expressed in tonnes, emitted from the unit in each calendar year in accordance with the formula

E − C_off − C_c

where

E

is the quantity of CO₂ emissions attributed to the unit for the calendar year, expressed in tonnes and determined by the formula

E_u − E_th − E_int − E_ccs + E_ext − E_ec

where

E_u

is the quantity of CO₂ emissions from the combustion of fossil fuel in the unit during the calendar year, determined in accordance with subsection (3),

E_th

is the quantity of CO₂ emissions attributed to the production of useful thermal energy by the unit during the calendar year, determined in accordance with section 21,

E_int

is the quantity of CO₂ emissions attributed to electricity generated by the unit that is used internally, during the calendar year, at the facility where the unit is located and is

(a) equal to zero, in the case of
- (i) any calendar year in which the unit does not produce useful thermal energy,
- (ii) any unit, other than a planned unit, that has a commissioning date after December 31, 2024, and
- (iii) every calendar year after 2049, and
(b) determined in accordance with section 22, in any other case,

E_ccs

is the quantity of CO₂ captured from the unit during the calendar year and stored in a storage project, determined in accordance with section 23,

E_ext

is the quantity of CO₂ emissions from the production of the hydrogen, ammonia and purchased or transferred steam used by the unit to generate electricity during the calendar year, determined in accordance with section 24, and

E_ec

is the quantity of CO₂ emissions attributed to the unit for any deduction period during the calendar year, determined in accordance with section 27;

C_off

is the quantity of CO₂, expressed in tonnes, that corresponds to the number of Canadian offset credits remitted for the unit for the calendar year in accordance with section 28; and

C_c

is the quantity of CO₂, expressed in tonnes, that corresponds to the number of compliance credits remitted for the unit for the calendar year in accordance with section 33.

Rounding

(2) The quantity determined for E under subsection (1) is to be rounded to the nearest whole number or, if equidistant between two consecutive whole numbers, to the higher number.

Combustion of fossil fuel (E_u)

(3) The quantity referred to in the description of E_u in subsections (1) and 27(1) must be determined in accordance with

(a) section 15, in the case of a unit that combusted fossil fuel from a coal gasification system during the calendar year;
(b) section 16, in the case of a unit that combusted biomass and combusted fossil fuel from a coal gasification system during the calendar year;
(c) section 19, in the case of a unit that combusted biomass but did not combust fossil fuel from a coal gasification system during the calendar year; and
(d) section 15 or 19, in any other case.

Default value

(4) Despite subsection (1), the responsible person for a unit may elect to assign a value of zero to any of E_th, E_int, E_ccs and E_ec when determining, for the unit, the quantity referred to in the description of E in that subsection.

Definition of coal gasification system

(5) For the purposes of subsection (3), coal gasification system includes a coal gasification system that is in part located underground.

Net supply

13 (1) The responsible person for a unit must, for each calendar year, determine the net supply from the facility where the unit is located.

Determination

(2) The net supply from a facility is determined by the formula

Q_t − Q_r − Q_a − Q_na − Q_ec

where

Q_t

is the quantity of electricity transmitted from the facility to an electricity system during the calendar year;

Q_r

is the quantity of electricity transmitted to the facility from an electricity system during the calendar year;

Q_a

is the quantity of electricity allocated to the facility for the calendar year in accordance with subsection (4);

Q_na

is the sum of the quantities of electricity generated at the facility during the calendar year by

(a) any unit that has not reached the end of its prescribed life as determined in accordance with subsection 10(3) or section 11,
(b) any unit to which these Regulations do not apply, other than a unit that has been registered as multiple subunits in accordance with section 8, and
(c) any source of electricity generation at the facility that is not a unit; and

Q_ec

is the sum of the quantities of electricity generated by any unit located at the facility, other than a unit referred to in the description of Q_na, during any deduction period during the calendar year.

Measurement

(3) The quantities of electricity referred to in subsection (2) must be expressed in GWh and must be measured

(a) in the case of the quantities referred to in the descriptions of Q_t, Q_r and Q_a, using meters that measure the transfer of electricity; and
(b) in the case of the quantities referred to in the descriptions of Q_na and Q_ec, at the electrical terminals of the generators of the unit or, in the case of a source of electricity generation that is not a unit, at the electrical terminals of the source.

Electricity allocated to facility (Q_a)

(4) A quantity must not be assigned to Q_a in subsection (2) unless, during the calendar year for which the quantity is assigned, the facility transmits electricity to an electricity system and supplies useful thermal energy to a recipient facility and the following conditions are met:

(a) the recipient facility is not a facility where a unit to which these Regulations apply is located;
(b) the quantity assigned to Q_a does not exceed the quantity of electricity transmitted to the recipient facility from the electricity system during that calendar year; and
(c) the responsible person obtains from the recipient facility documentation that
- (i) indicates the quantity of electricity transmitted to the recipient facility from the electricity system during the calendar year, and
- (ii) demonstrates that the quantity of electricity was measured using an electricity meter that is installed, maintained and calibrated in accordance with subsections 36(1) and (2) and that enables measurements to be made in accordance with subsection 36(3).

Overlapping deduction periods

(5) A quantity of electricity generated by a unit must not be included in more than one deduction period for the purposes of determining the quantity for Q_ec in subsection (2).

Exemptions

Net supply ≤ 0

14 (1) The responsible person for a unit is exempt from the application of subsection 9(1) and sections 39 and 41 with respect to the unit for any calendar year in which the net supply from the facility where the unit is located is zero or less.

Declaration of net supply

(2) The responsible person for a unit is exempt from the application of sections 12 and 15 to 24 with respect to the unit if

(a) the net supply from the facility where the unit is located is zero or less for each calendar year in which subsection 13(1) applies in respect of the unit; and
(b) the responsible person submits to the Minister a declaration of net supply in accordance with subsections (3) and (4).

Contents

(3) The declaration must contain

(a) the registration number assigned to each unit located at the facility by the Minister under subsection 7(3);
(b) a statement that the facility operates in such a manner that it is reasonable to conclude that the net supply from the facility will be zero or less for each calendar year in which subsection 13(1) applies in respect of the unit; and
(c) an attestation, dated and signed by the responsible person or its authorized official, that the declaration is accurate and complete.

Submission date

(4) The declaration must be submitted within the 12 months before any unit at the facility would have been subject to an emission limit under subsection 9(1) had the unit not been subject to an exemption, under subsection (1), from the application of that subsection.

End of exemption

(5) The exemption referred to in subsection (2) ends on December 31 of the calendar year before any calendar year in which the net supply from the facility is greater than zero.

Quantification

Combustion of Fossil Fuel

Continuous Emission Monitoring Systems

Quantification with CEMS

15 (1) For the purposes of paragraphs 12(3)(a) and (d), the quantity of CO₂ emissions from the combustion of fossil fuel in a unit during a calendar year must be measured using a CEMS and is determined, subject to section 17, in accordance with sections 7.1 to 7.5 of the CEMS Protocol.

Multiple CEMS

(2) The quantity of CO₂ emissions from a unit equipped with multiple CEMS is determined by adding together the quantity of CO₂ emissions measured by each CEMS.

Combustion of biomass

16 (1) For the purposes of paragraph 12(3)(b), the quantity of CO₂ emissions from the combustion of fossil fuel in a unit during a calendar year must be measured using a CEMS and is determined by the formula

E_comb × (V_ff ÷ V_T) − E_s

where

E_comb

is the quantity of CO₂ emissions from the unit, expressed in tonnes, from the combustion of fossil fuel and biomass during the calendar year, determined in accordance with section 15 or 17, as applicable;

V_ff

is the volume of CO₂ emissions from the combustion of fossil fuel in the unit during the calendar year, expressed in m³ at standard conditions and determined by the formula

$\sum_{i = 1}^{n} Q_{i} \times F_{c, i} \times {HHV}_{i}$

where

i

is the i^th fossil fuel type combusted in the unit during the calendar year, where “i” goes from 1 to n and where n is the number of fossil fuel types combusted,

Q_i

is the quantity of fossil fuel type “i” combusted in the unit during the calendar year, determined

(a) for a gaseous fuel, in the same manner used in the determination of V_f in paragraph 20(1)(a) and expressed in m³ at standard conditions,
(b) for a liquid fuel, in the same manner used in the determination of V_f in paragraph 20(1)(b) and expressed in kL, and
(c) for a solid fuel, in the same manner used in the determination of M_f in paragraph 20(1)(c) and expressed in tonnes,

F_c,i

is the fuel-specific carbon-based F-factor for each fossil fuel type “i” — being either the F-factor set out in Appendix A of the CEMS Protocol or, for fuels not listed in that Appendix, the F-factor determined in accordance with that Appendix — corrected to be expressed in m³ of CO₂/GJ at standard conditions, and

HHV_i

is the higher heating value for each fossil fuel type “i” that is measured in accordance with subsection (2) or the default higher heating value set out in column 2 of Schedule 3 for the fuel type set out in column 1;

V_T

is the volume of CO₂ emissions resulting from combustion of fossil fuel and biomass in the unit during the calendar year, expressed in m³ at standard conditions and determined by the formula

$\sum_{t = 1}^{n} [0,01 \times {CO}_{2 h, t} \times Q_{h, t}]$

where

t

is the t^th hour, where “t” goes from 1 to n and where n is the total number of hours during which the unit generated electricity in the calendar year,

CO_2w,t

is the average concentration of CO₂ in relation to all gases in the stack emitted from the combustion of fuel in the unit during each hour “t” — or, if applicable, a calculation made in accordance with section 7.4 of the CEMS Protocol of that average concentration of CO₂ based on a measurement of the concentration of oxygen (O₂) in those gases in the stack — expressed as a percentage on a wet basis, and

Q_w,t

is the average volumetric flow during that hour, measured on a wet basis by a stack gas volumetric flow monitor and expressed in m³ at standard conditions; and

E_s

is the quantity of CO₂ emissions, expressed in tonnes, that is released from the use of sorbent to control the emission of sulphur dioxide from the unit during the calendar year, as determined by the formula

S × R × (44 ÷ MM_s): where
S: is the quantity of sorbent, such as calcium carbonate (CaCO₃), expressed in tonnes,
R: is the stoichiometric ratio, on a mole fraction basis, of CO₂ released on usage of one mole of sorbent, which is equal to 1 if the sorbent is CaCO₃, and
MM_s: is the molecular mass of the sorbent, which is equal to 100 if the sorbent is CaCO₃.

Higher heating value (HHV_i)

(2) The higher heating value of a fossil fuel must be measured

(a) in the case of a gaseous fuel,
- (i) in accordance with one of the following standards, as applicable:
  - (A) ASTM D1826, entitled Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter,
  - (B) ASTM D3588, entitled Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels,
  - (C) ASTM D4891, entitled Standard Test Method for Heating Value of Gases in Natural Gas and Flare Gases Range by Stoichiometric Combustion,
  - (D) Gas Processors Association Standard 2172, entitled Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, or
  - (E) Gas Processors Association Standard 2261, entitled Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, or
- (ii) by means of a direct measuring device, except that if the measuring device provides only lower heating values, those lower heating values must be converted to higher heating values;
(b) in the case of a liquid fuel that is
- (i) an oil or a liquid fuel derived from waste, in accordance with one of the following standards, as applicable:
  - (A) ASTM D240, entitled Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, or
  - (B) ASTM D4809, entitled Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), and
- (ii) any other liquid fuel type, in accordance with an applicable ASTM standard for the measurement of the higher heating value of the fuel type or, if there is no such ASTM standard, in accordance with an applicable internationally recognized method; and
(c) in the case of a solid fuel that is
- (i) coal, in accordance with ASTM D5865, entitled Standard Test Method for Gross Calorific Value of Coal and Coke, and
- (ii) any other solid fuel type, in accordance with an applicable ASTM standard for the measurement of the higher heating value of the fuel type or, if there is no such ASTM standard, in accordance with an applicable internationally recognized method.

Units sharing CEMS

17 If a unit is located at a facility where there are one or more other units and a CEMS measures emissions from that unit and at least one other unit at a common stack rather than at the exhaust duct of each unit that shares the common stack, the quantity of CO₂ emissions attributed to that unit is determined, based on the ratio of the heat input of that unit to the total heat input of all the units sharing the common stack, by the formula

$[\frac{\sum_{j = 1}^{y} Q_{u, j} \times {HHV}_{u, j}}{\sum_{i = 1}^{x} \sum_{j = 1}^{y} Q_{i, j} \times {HHV}_{i, j}}] \times E$

where

j

is the j^th fuel type combusted during the calendar year in a unit where “j” goes from 1 to y and where y is the number of fuel types combusted;

Q_u,j

is the quantity of fuel type “j” combusted in the unit “u” during the calendar year, determined

(a) for a gaseous fuel, in the same manner used in the determination of V_f in paragraph 20(1)(a) and expressed in m³ at standard conditions,
(b) for a liquid fuel, in the same manner used in the determination of V_f in paragraph 20(1)(b) and expressed in kL, and
(c) for a solid fuel, in the same manner used in the determination of M_f in paragraph 20(1)(c) and expressed in tonnes;

HHV_u,j

is the higher heating value for each fuel type “j” combusted in the unit “u” that is measured in accordance with subsection 16(2) or the default higher heating value set out in column 2 of Schedule 3 for the fuel type set out in column 1;

i

is the i^th unit, where “i” goes from 1 to x and where x is the number of units that share the common stack;

Q_i,j

the quantity of fuel type “j” combusted in each unit “i” during the calendar year, determined for a gaseous fuel, a liquid fuel and a solid fuel, respectively, in the manner set out in the description of Q_u,j;

HHV_i,j

is the higher heating value for each fuel type “j” combusted in each unit “i” that is measured in accordance with subsection 16(2) or the default higher heating value set out in column 2 of Schedule 3 for the fuel type set out in column 1; and

E

is the quantity of CO₂ emissions, expressed in tonnes, from the combustion of all fuels in all the units that share the common stack during the calendar year, measured using a CEMS at the common stack and determined in accordance with sections 7.1 to 7.5 of the CEMS Protocol.

Obligation — CEMS Protocol

18 (1) A responsible person that uses a CEMS to measure CO₂ emissions for the purposes of any of sections 15 to 17 must ensure that the requirements set out in sections 3, 4 and 6 of the CEMS Protocol are met.

Certification of CEMS

(2) The CEMS must be certified in accordance with section 5 of the CEMS Protocol before it is used for the purposes of these Regulations.

CEMS report

(3) For each calendar year during which a CEMS is used to measure CO₂ emissions from a unit, the responsible person must

(a) obtain a CEMS report, signed by an auditor, that contains the information set out in Schedule 4 in respect of the CEMS; and
(b) if the emissions report referred to in subsection 39(1) is required for the unit for that calendar year, submit the CEMS report along with the emissions report.

Fuel-based Method

Quantification

19 For the purposes of paragraphs 12(3)(c) and (d), the quantity of CO₂ emissions from the combustion of fossil fuel in a unit during a calendar year is determined by the formula

$\sum_{i = 1}^{n} E_{i} \times E_{s}$

where

i

is the i^th fossil fuel type combusted in the unit during the calendar year, where “i” goes from 1 to n and where n is the number of fossil fuel types combusted;

E_i

is the quantity of CO₂ emissions from the combustion of each fossil fuel type “i” in the unit during the calendar year, expressed in tonnes, as determined for that fossil fuel type in accordance with section 20; and

E_s

is the quantity of CO₂ emissions that is released from the sorbent used to control the emission of sulphur dioxide from the unit during the calendar year, expressed in tonnes and determined by the formula

S × R × (44 ÷ MM_s): where
S: is the quantity of sorbent, such as CaCO₃, expressed in tonnes,
R: is the stoichiometric ratio, on a mole fraction basis, of CO₂ released on usage of one mole of sorbent, which is equal to 1 if the sorbent is CaCO₃, and
MM_s: is the molecular mass of the sorbent, which is equal to 100 if the sorbent is CaCO₃.

Measured carbon content

20 (1) The quantity assigned to E_i in section 19 is, for each type of fossil fuel combusted in the unit during a calendar year, determined by one of the following formulas, as applicable:

(a) in the case of a gaseous fuel,

V_f × CC_A × (MM_A ÷ MV_cf) × 3.664 × 0.001

where

V_f

is the volume of the fossil fuel combusted during the calendar year, determined using flow meters and expressed in m³ at standard conditions,

CC_A

is the weighted average of the carbon content of the fossil fuel, determined in accordance with subsection (4) and expressed in kg of carbon per kg of the fossil fuel,

MM_A

is the average molecular mass of the fossil fuel, determined based on fuel samples taken in accordance with section 34 and expressed in kg per kg-mole of the fossil fuel, and

MV_cf

is the molar volume conversion factor of 23.645 m³ at standard conditions, per kg-mole of the fossil fuel at standard conditions;
(b) in the case of a liquid fuel,

V_f × CC_A × 3.664

where

V_f

is the volume of the fossil fuel combusted during the calendar year, determined using flow meters and expressed in kL, and

CC_A

is the weighted average of the carbon content of the fossil fuel, determined in accordance with subsection (4) at the same temperature as that used in the determination of V_f and expressed in tonnes of carbon per kL of the fossil fuel; and
(c) in the case of a solid fuel,

M_f × CC_A × 3.664

where

M_f

is the mass of the fossil fuel combusted during the calendar year, determined, as the case may be, on a wet or dry basis using a measuring device and expressed in tonnes, and

CC_A

is the weighted average of the carbon content of the fossil fuel, determined in accordance with subsection (4) on the same wet or dry basis as that used in the determination of M_f and expressed in kg of carbon per kg of the fossil fuel.

Renewable natural gas

(2) If a unit that combusts natural gas is supplied by a pipeline network into which renewable natural gas is injected, the volume of natural gas to be used in determining the value for V_f in paragraph (1)(a) is determined by the formula

V_total − V_RNG: where
V_total: is the total volume of natural gas and renewable natural gas supplied to the unit that is combusted during the calendar year, determined using flow meters and expressed in m³ at standard conditions; and
V_RNG: is the volume of renewable natural gas that may be claimed by the unit during the calendar year, determined in accordance with subsection (3) and expressed in m³ at standard conditions.

V_RNG — conditions

(3) For the purposes of determining the value for V_RNG in subsection (2), a volume of renewable natural gas may be claimed for a calendar year only if

(a) a contractual agreement specifies that the volume is supplied to the unit for the calendar year;
(b) the volume is kept physically separated from any other substance and is clearly identifiable as renewable natural gas from the time it is produced until the time it is injected into a pipeline network to which the unit is connected;
(c) the responsible person for the unit is able to identify each producer of the renewable natural gas supplied to the unit under the contractual agreement referred to in paragraph (a) and the volume supplied by each producer;
(d) the volume supplied by each producer does not exceed the volume of renewable natural gas produced by that producer that is injected during the calendar year into a pipeline network to which the unit is connected;
(e) the volume is not being used to create credits in a jurisdiction outside Canada or to comply with a requirement relating to greenhouse gas emissions that is set by a jurisdiction outside Canada;
(f) the volume is not being used by an end user, other than the responsible person, to create credits in Canada or to comply with a requirement relating to greenhouse gas emissions set out in a federal or provincial law; and
(g) the responsible person for the unit submits to the Minister, in the emissions report submitted under section 39 for the calendar year, the information set out in section 8 of Schedule 5 in respect of the volume.

Weighted average (CC_A)

(4) The weighted average CC_A referred to in paragraphs (1)(a) to (c) is determined by the formula

$\frac{\sum_{i = 1}^{n} {C C}_{i} \times Q_{i}}{\sum_{i = 1}^{n} Q_{i}}$

where

i

is the i^th sampling period that is set out for the fuel type in subsection 34(2), where “i” goes from 1 to n and where n is the number of sampling periods;

CC_i

is the carbon content of each sample or composite sample, as the case may be, of the fossil fuel for the i^th sampling period — expressed for gaseous fuels, liquid fuels and solid fuels, respectively, in the same unit of measure as that set out in the description of CC_A in paragraph (1)(a), (b) or (c), as applicable — as provided by the supplier of the fossil fuel to the responsible person or, if not so provided, as determined in the following manner:

(a) in the case of a gaseous fuel,
- (i) in accordance with one of the following standards, as applicable:
  - (A) ASTM D1945, entitled Standard Test Method for Analysis of Natural Gas by Gas Chromatography,
  - (B) ASTM UOP539, entitled Refinery Gas Analysis by Gas Chromatography,
  - (C) ASTM D7833, entitled Standard Test Method for Determination of Hydrocarbons and Non-Hydrocarbon Gases in Gaseous Mixtures by Gas Chromatography, or
  - (D) API Technical Report 2572, entitled Carbon Content, Sampling, and Calculation, published by the American Petroleum Institute, or
- (ii) by means of a direct measuring device,
(b) in the case of a liquid fuel, in accordance with one of the following standards or methods, as applicable:
- (i) API Technical Report 2572, entitled Carbon Content, Sampling, and Calculation, published by the American Petroleum Institute,
- (ii) ASTM D5291, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, or
- (iii) the ASTM standard that applies to the fossil fuel type, or if there is no such ASTM standard, an applicable internationally recognized method, and
(c) in the case of a solid fuel, on the same wet or dry basis as that used in the determination of CC_A, in accordance with
- (i) for a solid fuel derived from waste, ASTM E777, entitled Standard Test Method for Carbon and Hydrogen in the Analysis Sample of Refuse-Derived Fuel, and
- (ii) for any other solid fuel type, in accordance with an ASTM standard for the measurement of the carbon content of the fuel type or, if there is no such ASTM standard, in accordance with an applicable internationally recognized method; and

Q_i

is the volume or mass, as the case may be, of the fossil fuel combusted during the i^th sampling period, determined

(a) using flow meters and expressed in m³ at standard conditions, in the case of a gaseous fuel,
(b) using flow meters and expressed in kL, in the case of a liquid fuel, and
(c) using a measuring device and expressed in tonnes, on the same wet or dry basis as that used in the determination of CC_A, in the case of a solid fuel.

Useful Thermal Energy

Attributed emissions (E_th)

21 The quantity of CO₂ emissions attributed to the production of useful thermal energy by a unit during a calendar year is determined by the formula

H_pnet × b_EI

where

H_pnet

is the net quantity of useful thermal energy, expressed in GJ, determined by the formula

$\sum_{t = 1}^{x} [\sum_{i = 1}^{n} {h_{out i} \times M_{out i}} - \sum_{j = 1}^{m} {h_{in j} \times M_{in j}}]_{t}$: where
t: is the t^th period, where “t” goes from 1 to x and where x is the total number of periods during which the unit produced useful thermal energy during the calendar year,
i: is the i^th heat stream exiting the unit, where “i” goes from 1 to n and where n is the total number of heat streams exiting the unit,
h_outi: is the average specific enthalpy of the i^th heat stream exiting the unit during period “t”, expressed in GJ/tonne and determined based on the measurement, using a continuous measuring device, of the temperature and pressure of that heat stream,
M_outi: is the mass flow of the i^th heat stream exiting the unit during period “t”, expressed in tonnes and determined using a continuous measuring device,
j: is the j^th heat stream, other than condensate return, entering the unit, where “j” goes from 1 to m and where m is the total number of heat streams entering the unit,
h_inj: is the average specific enthalpy of the j^th heat stream, other than condensate return, entering the unit during period “t”, expressed in GJ/tonne and determined based on the measurement, using a continuous measuring device, of the temperature and pressure of that heat stream, and
M_inj: is the mass flow of the j^th heat stream, other than condensate return, entering the unit during period “t”, expressed in tonnes and determined using a continuous measuring device; and
b_EI: is the emission intensity of a reference boiler, set to 0.0556 tonnes of CO₂ emissions per GJ.

Electricity Used at Facility

Attributed emissions (E_int)

22 The quantity of CO₂ emissions attributed to electricity generated by a unit that is used internally, during a calendar year, at the facility where the unit is located is determined by the formula

G_int × C_EI

where

G_int

is the quantity of electricity generated by the unit that is used internally, during the calendar year, at the facility where the unit is located, expressed in GWh and determined by the formula

(G_F − Q_ns) × (G_U ÷ G_F): where
G_F: is the sum of the total gross electricity generated by each unit at the facility that is subject to an emission limit under subsection 9(1) during the calendar year, expressed in GWh and measured for each unit at the electrical terminals of the unit’s generators,
Q_ns: is the net supply from the facility for the calendar year, and
G_U: is the total gross electricity generated by the unit during the calendar year, expressed in GWh and measured at the electrical terminals of the unit’s generators; and
C_EI: is the emission intensity of a reference unit that produces useful thermal energy, set to 250 tonnes of CO₂ emissions per GWh.

Carbon Capture and Storage

CO₂ captured and stored (E_ccs)

23 (1) The quantity of CO₂ from a unit that is captured during a calendar year and stored in a storage project is determined by the formula

E_u × (E_cap ÷ E_in): where
E_u: is the value determined for E_u in subsection 12(1) or, if applicable, subsection 27(1);
E_cap: is the quantity of CO₂ that is the portion of E_in that has been captured and subsequently stored, during the calendar year, in a storage project that meets the conditions set out in subsection (2), expressed in tonnes and determined by means of a direct measuring device that measures the flow and concentration of CO₂; and
E_in: is the quantity of CO₂, expressed in tonnes, entering the carbon capture and storage system during the calendar year, determined, in accordance with sections 7.1 to 7.5 of the CEMS Protocol, using a CEMS that is located upstream of the carbon capture and storage system and that measures all CO₂ entering the carbon capture and storage system.

Conditions

(2) For the purposes of determining the value for E_ccs in subsections 12(1) and 27(1), a quantity of CO₂ may only be claimed if it has been permanently stored in a storage project that meets the following conditions:

(a) the geological site into which the CO₂ is injected is
- (i) a deep saline aquifer into which the CO₂ is injected for the sole purpose of storing it, or
- (ii) a depleted oil reservoir into which the CO₂ is injected for the purpose of enhanced oil recovery; and
(b) the CO₂ stored for the purposes of the project is captured, transported and stored in accordance with the laws of Canada or a province or the laws of the United States or one of its states.

Energy carriers

Emissions — hydrogen, ammonia or steam (E_ext)

24 (1) The quantity of CO₂ emissions from the production of the hydrogen, ammonia or steam used by a unit to generate electricity during a calendar year is determined by the formula

$\sum_{k = 1}^{n} ((\frac{E_{k}}{P_{k}}) \times Q_{k})$

where

k

is the k^th stream of hydrogen, ammonia or steam, where “k” goes from 1 to n and where n is the number of streams of hydrogen, ammonia or steam that are used by the unit during the calendar year;

E_k

is the total annual CO₂ emissions, expressed in tonnes, from the total annual production of the k^th stream of hydrogen, ammonia or steam used by the unit during the calendar year;

P_k

is the total annual production of the k^th stream of hydrogen, ammonia or steam during the calendar year, determined using a continuous measuring device and expressed

(a) in m³ at standard conditions, in the case of hydrogen and ammonia, and
(b) in GJ, in the case of steam; and

Q_k

is the quantity of hydrogen or ammonia, expressed in m³ at standard conditions, or the quantity of purchased or transferred steam, expressed in GJ, in the k^th stream used by the unit to generate electricity during the calendar year, determined using a continuous measuring device.

Quantification of E_k and P_k

(2) Subject to subsection (4), the responsible person must obtain the values of E_k and P_k from the supplier of the hydrogen, ammonia or steam, if any, used by the unit, determined in accordance with

(a) section 10 of the GHGRP, in the case of hydrogen production;
(b) section 8 of the GHGRP, in the case of ammonia production; and
(c) section 7 of the GHGRP, in the case of steam production.

Adaptation of GHGRP

(3) For the purposes of paragraph (2)(a), the description of R_CO2 in Equation 10-2 of the GHGRP is to be read as “CO₂ captured and permanently stored in a storage project that meets the conditions set out in subsection 23(2) of the Clean Electricity Regulations”.

Default values

(4) If the hydrogen or ammonia used by a unit is not produced at the facility at which the unit is located or the steam used by a unit is purchased or transferred to that facility and the responsible person for the unit is not able to obtain from the supplier the information required under subsection (2), the responsible person must replace the ratio E_k ÷ P_k in subsection (1) with the following values:

(a) 9.8312 × 10^-4 tonnes of CO₂/m³, in the case of hydrogen;
(b) 1.4635 × 10^-3 tonnes of CO₂/m³, in the case of ammonia; and
(c) 0.08 tonnes of CO₂/GJ, in the case of steam.

Emergency Circumstances

Deduction

25 (1) The responsible person for a unit may, for the purposes of subsection 12(1), deduct the quantity of CO₂ emissions attributed to the unit during a deduction period and may, for the purposes of subsection 13(2), deduct the quantity of electricity generated by the unit during a deduction period if the following conditions are met:

(a) the electricity system operator has determined that there is an irresistible emergency event, whether natural or arising from human action, or the Minister has determined that there is a risk to human health and safety;
(b) in the case of an irresistible emergency event, the event is outside the control of the electricity system operator and the responsible person;
(c) the electricity system operator has determined that the event or risk referred to in paragraph (a) has triggered a disruption or significant risk of disruption to the electricity supply in the province in which the unit is located or in a contiguous province or state;
(d) the electricity system operator directs the unit to generate electricity due to the event or risk referred to in paragraph (a) in order to alleviate or materially help alleviate a disruption or significant risk of disruption to the electricity supply in the province in which the unit is located or in a contiguous province or state;
(e) the generation of electricity by the unit will alleviate or materially help alleviate a disruption or significant risk of disruption to the electricity supply in the province in which the unit is located or in a contiguous province or state; and
(f) within seven days after the day on which the direction to generate electricity referred to in paragraph (d) is received, the responsible person notifies the Minister of that direction.

Deduction period

(2) The period for which the quantities of CO₂ emissions and electricity generated may be deducted begins in the hour in which a unit operates in response to the direction to generate electricity referred to in paragraph (1)(d) and ends as follows:

(a) if an application for an extension of the deduction period is not submitted to the Minister in accordance with subsection 26(1), the period ends on the earlier of
- (i) the day that is the 30th day after the day on which the direction to generate electricity was given, and
- (ii) the hour that is 24 hours after the electricity system operator notifies the responsible person for the unit that the direction to generate electricity no longer applies; or
(b) if an application for an extension of the deduction period is submitted to the Minister in accordance with subsection 26(1), the period ends
- (i) in the case of an application that is not granted, on the earlier of
  - (A) the hour that is 24 hours after the electricity system operator notifies the responsible person for the unit that the direction to generate electricity no longer applies, and
  - (B) the day that is the 45th day after the day on which the direction to generate electricity was given, and
- (ii) in any other case, on the earlier of
  - (A) the hour that is 24 hours after the electricity system operator notifies the responsible person for the unit that the direction to generate electricity no longer applies, and
  - (B) the hour that is 24 hours after the Minister notifies the responsible person for the unit that the deduction period has ended.

Notice to Minister

(3) The responsible person must, within seven days after the day on which the electricity system operator notifies the responsible person that the direction to generate electricity referred to in paragraph (1)(d) no longer applies, notify the Minister that the direction no longer applies.

Application for extension of deduction period

26 (1) If the conditions set out in subsection 25(1) will continue to be met for more than 30 days after the day on which the unit receives the direction to generate electricity referred to in paragraph 25(1)(d), the responsible person may, within 30 days after the day on which the direction is received, apply to the Minister for an extension of the deduction period.

Contents of application

(2) The application must include

(a) the registration number assigned to the unit by the Minister under subsection 7(3), if any;
(b) the date on which and hour at which the deduction period began;
(c) a description of the irresistible emergency event or risk to human health and safety that caused the electricity system operator to direct the unit to generate electricity, including
- (i) the date on which and hour at which the event or risk began and, if applicable, the date on which and hour at which it ended,
- (ii) the province or state in which the event or risk occurred,
- (iii) the province or state in which the disruption or significant risk of disruption to the electricity supply occurred, and
- (iv) information demonstrating that the unit received the direction to generate electricity to alleviate or materially help alleviate a disruption or significant risk of disruption to the electricity supply; and
(d) if the direction to generate electricity is due to the electricity system operator determining that there is an irresistible emergency event, information, along with supporting documents, demonstrating that
- (i) the electricity system operator determined that an irresistible emergency event occurred,
- (ii) the event was outside the control of the electricity system operator and the responsible person for the unit,
- (iii) the irresistible emergency event caused the disruption or significant risk of disruption to the electricity supply that the direction to generate electricity is intended to alleviate or materially help alleviate, and
- (iv) the disruption or significant risk of disruption to the electricity supply arising from the event will continue for more than 30 days after the day on which the deduction period began.

Minister’s decision

(3) If the Minister is satisfied that the conditions set out in subsection 25(1) will continue to be met, the Minister must, within 10 days after the day on which the application is received, grant an extension of the deduction period.

Irresistible emergency event

(4) Before granting an extension of a deduction period based on an irresistible emergency event, the Minister must be satisfied that

(a) the event occurred;
(b) the event is outside the control of the electricity system operator and the responsible person for the unit;
(c) the disruption or significant risk of disruption to the electricity supply arising from the event will continue; and
(d) the generation of electricity by the unit will alleviate or materially help alleviate the disruption or significant risk of disruption to the electricity supply in the province in which the unit is located or in a contiguous province or state.

Emissions during deduction period (E_ec)

27 (1) The quantity referred to in the description of E_ec in subsection 12(1) is determined by the formula

$\sum_{i = 1}^{n} {(E_{u} - E_{th} - E_{int} - E_{ccs} + E_{ext})}_{i}$

where

i

is the i^th deduction period, where “i” goes from 1 to n and where n is the number of deduction periods in the calendar year;

E_u

is the quantity of CO₂ emissions, expressed in tonnes, from the combustion of fossil fuel in the unit during the i^th deduction period during the calendar year, determined in accordance with subsection 12(3);

E_th

is the quantity of CO₂ emissions, expressed in tonnes, attributed to the production of useful thermal energy by the unit during the i^th deduction period during the calendar year, determined in accordance with section 21;

E_int

is the quantity of CO₂ emissions, expressed in tonnes, attributed to electricity generated by the unit, during the i^th deduction period during the calendar year, that is used internally at the facility where the unit is located and is

(a) equal to zero, in the case of
- (i) any deduction period in which the unit did not produce useful thermal energy,
- (ii) any unit, other than a planned unit, that has a commissioning date after December 31, 2024, and
- (iii) every deduction period after 2049, and
(b) determined in accordance with section 22 in any other case;

E_ccs

is the quantity of CO₂, expressed in tonnes, captured from the unit during the i^th deduction period during the calendar year and stored in a storage project, determined in accordance with section 23; and

E_ext

is the quantity of CO₂ emissions, expressed in tonnes, from the production of the hydrogen, ammonia and the purchased or transferred steam used by the unit to generate electricity during the i^th deduction period during the calendar year, determined in accordance with section 24.

Adaptation

(2) For the purposes of subsection (1), any reference to a calendar year in a calculation required under section 15 or 16 or any of sections 19 to 24 is to be read as a reference to the applicable deduction period.

Multiple calendar years

(3) If a deduction period begins in one calendar year and ends in another calendar year, the deduction period for the purposes of subsection (1) is the portion of that deduction period that occurred during the calendar year for which CO₂ emissions are being determined.

Overlapping deduction periods

(4) A quantity of CO₂ emissions must not be included in more than one deduction period for the purposes of subsection (1).

Canadian Offset Credits

Remittance — December 15

28 (1) The quantity of CO₂ assigned to C_off in subsection 12(1) corresponds to the number of Canadian offset credits that the responsible person remits to the Minister for the unit on or before the December 15 that follows the calendar year for which the remittance is made.

Maximum

(2) The maximum number of Canadian offset credits that may be remitted for a unit for a calendar year corresponds to the quantity of CO₂, expressed in tonnes, determined by the formula

C × I_off × 8760 × 0.001

where

C

is the unit’s electricity generation capacity for the calendar year; and

I_off

is the emission intensity applicable to the calendar year and is

(a) 35 tonnes of CO₂ emissions per GWh for the 2035 to 2049 calendar years, and
(b) 42 tonnes of CO₂ emissions per GWh for the 2050 and subsequent calendar years.

Rounding

(3) The quantity determined under subsection (2) is to be rounded to the nearest whole number or, if equidistant between two consecutive whole numbers, to the higher number.

Condition

(4) Any Canadian offset credit remitted for a calendar year must have been issued for greenhouse gas reductions or removals that occurred no more than eight calendar years before the calendar year in which the Canadian offset credit is remitted.

Cross-recognition

(5) A responsible person may remit the same Canadian offset credit for the purposes of both subsection 12(1) and an eligible system referred to in subsection (6) if, under that eligible system, the Canadian offset credit is remitted

(a) for the same calendar year as the year for which the Canadian offset credit is remitted under this section;
(b) in relation to the same unit for which the Canadian offset credit is remitted under this section; and
(c) in fulfillment of a remittance requirement other than a requirement that relates to an extraordinary situation, such as to replace a cancelled credit or as compensation for non-compliance with a requirement.

Eligible systems

(6) The eligible systems are

(a) a system for pricing greenhouse gas emissions established under Division 1 of Part 2 of the Greenhouse Gas Pollution Pricing Act; and
(b) a provincial carbon pricing system that is subject to an agreement between the Minister and a province regarding the cross-recognition of Canadian offset credits and that is on the list published on the Department of the Environment’s website for the purposes of this section.

Timing of remittance

(7) A Canadian offset credit is considered to be remitted on the day on which a reconciliation report that contains all of the information set out in sections 1 and 2 of Schedule 6 in respect of the Canadian offset credit is submitted to the Minister in accordance with section 41.

Cancelled Canadian offset credit

29 (1) If, within five years after the day on which a responsible person remits to the Minister one or more Canadian offset credits referred to in paragraph (b) of the definition Canadian offset credit in subsection 2(1), the issuing province cancels and does not provide a mechanism to replace the credits, the Minister must notify the responsible person of the number of Canadian offset credits that were cancelled by the province and the number of Canadian offset credits that the responsible person must remit to the Minister.

Cross-recognition conditions not met

(2) If the Minister determines that one or more Canadian offset credits referred to in subsection 28(5) were remitted that did not meet the conditions set out in that subsection, the Minister must notify the responsible person of the number of Canadian offset credits remitted that did not meet those conditions and the number of Canadian offset credits that the responsible person must remit to the Minister.

Request by Minister

(3) The responsible person must provide to the Minister, within the time limit specified by the Minister, any information requested by the Minister to determine whether a Canadian offset credit meets the conditions set out in subsection 28(5).

Remittance obligation

(4) The responsible person must remit the number of Canadian offset credits set out in a notice referred to in subsection (1) or (2) by submitting to the Minister, no later than December 15 of the calendar year that follows the calendar year in which the Minister provides the notice, a reconciliation report that contains the information set out in sections 1 and 4 of Schedule 6 in respect of the credits.

Eligible Canadian offset credits

(5) The Canadian offset credits that are remitted under subsection (4) must have been issued for greenhouse gas reductions or removals that occurred no more than eight calendar years before the time limit set out in that subsection.

Compliance Credits

Issuance

Number of compliance credits issued

30 (1) If the Minister is satisfied that, for any of the 2035 to 2049 calendar years, the quantity of CO₂ emissions attributed to a unit, as determined in accordance with the formula set out in the description of E in subsection 12(1), is below the emission limit determined for the unit in accordance with subsection 9(1), the Minister must issue to the responsible person for the unit, for that calendar year and for that unit, a number of compliance credits, each with a corresponding value of one tonne of CO₂, that is equal to the difference between that quantity and that limit.

Exceptions

(2) Despite subsection (1), no compliance credits are issued for a unit for a calendar year if

(a) the unit is not subject to an emission limit under subsection 9(1) before July 1 of that calendar year; or
(b) the unit is subject to an exemption, under subsection 14(1), from the application of subsection 9(1) for that calendar year.

Request by Minister

(3) The responsible person for a unit must provide to the Minister, within the time limit specified by the Minister, any information requested by the Minister that is necessary to determine whether

(a) the quantity of CO₂ emissions assigned to E in subsection 12(1) that is reported in the emissions report submitted under section 39 for the unit for a calendar year was determined in accordance with that subsection; and
(b) the emission limit that is reported in the emissions report submitted under section 39 for the unit for a calendar year was determined in accordance with subsection 9(1).

Notice

(4) If, after receiving the information requested under subsection (3), the Minister is not satisfied that the quantity of CO₂ emissions attributed to a unit, as determined in accordance with the formula set out in the description of E in subsection 12(1), is below the emission limit determined for the unit in accordance with subsection 9(1), the Minister must notify the responsible person that no compliance credits will be issued for the unit for the calendar year.

Transferable compliance credits

31 (1) Subject to section 32, the compliance credits issued under subsection 30(1) for a unit for a calendar year are transferable if the unit does not combust coal during the calendar year and is

(a) a unit that has a commissioning date before January 1, 2025 and that does not produce useful thermal energy during the calendar year;
(b) a unit, other than a planned unit, that has a commissioning date after December 31, 2024 but before January 1, 2030; or
(c) a planned unit that does not produce useful thermal energy during the calendar year.

Non-transferable compliance credits

(2) Subject to section 32, the compliance credits issued under subsection 30(1) for a unit for a calendar year are non-transferable if the unit is not a unit referred to in subsection (1).

Transfer between responsible persons

(3) A transferable compliance credit may only be transferred between responsible persons for units to which these Regulations apply.

Designation of substitute unit

32 (1) The responsible person for a unit described in any of paragraphs 31(1)(a) to (c) or a unit that has been designated as a substitute unit under this section may, with the agreement of the responsible person for another unit, designate that other unit as a substitute unit if

(a) the electricity generation capacity of the unit being designated as a substitute unit does not exceed the electricity generation capacity of the unit being substituted; and
(b) both units report to the same electricity system operator.

Required information

(2) To designate a substitute unit, the responsible person that makes the designation and the responsible person for the unit that will be designated as a substitute unit must each submit the following information to the Minister before January 1 of the calendar year in which the substitution will take effect, along with an attestation, dated and signed by the responsible person or its authorized official, that it agrees to the substitution:

(a) the registration number assigned to each unit by the Minister under subsection 7(3);
(b) the electricity generation capacity of each unit; and
(c) the electricity system operator for each unit.

Consequences of substitution

(3) Beginning with the calendar year in which the designation of a substitute unit takes effect,

(a) any compliance credits issued for the substitute unit for that calendar year — and for any subsequent calendar year in which the unit is a substitute unit — are transferable, unless the substitute unit
- (i) combusts coal during that calendar year,
- (ii) has a commissioning date before January 1, 2025 and produces useful thermal energy during that calendar year, or
- (iii) is a planned unit that produces useful thermal energy during that calendar year; and
(b) any compliance credits issued for the unit that is not the substitute unit for that calendar year — and for any subsequent calendar year in which that unit is not a substitute unit — are non-transferable.

Ceasing to be a substitute unit

(4) A substitute unit ceases to be a substitute unit on January 1 of the calendar year that follows the year in which the responsible person for that unit designates another substitute unit in accordance with this section.

Remittance

Remittance — December 15

33 (1) The quantity of CO₂ assigned to C_c in subsection 12(1) corresponds to the number of compliance credits that the responsible person remits to the Minister for the unit on or before the December 15 that follows the calendar year for which the remittance is made.

Conditions

(2) A responsible person may only remit a compliance credit for the purposes of subsection 12(1) if the following conditions are met:

(a) the remittance is for a calendar year before 2050;
(b) the compliance credit was issued for a calendar year that is no more than five calendar years before the calendar year in which it is remitted;
(c) in the case of a non-transferable compliance credit, the credit is remitted for the unit for which it was issued; and
(d) in the case of a transferable compliance credit, the credit is remitted
- (i) for a unit that
  - (A) met, during the calendar year for which the remittance is made, the conditions to be issued transferable compliance credits that are set out in subsections 31(1) and 32(3), and
  - (B) reports to the same electricity system operator as the unit for which the transferable compliance credit was issued, or
- (ii) for the unit for which it was issued.

Timing of remittance

(3) A compliance credit is considered to be remitted on the day on which a reconciliation report that contains all of the information set out in sections 1 to 3 of Schedule 6 in respect of the compliance credit is submitted to the Minister in accordance with section 41.

Retirement

(4) A compliance credit remitted under these Regulations may only be remitted once and, once remitted to the Minister, is retired and must not be used again.

Sampling and Missing Data

Sampling

34 (1) The value of the variables referred to in the formulas set out in subsection 20(1) and (4) must be determined based on fuel samples taken in accordance with this section.

Frequency

(2) Each fuel sample must be taken at a time and location in the fuel-handling system of the facility that provides the following representative samples of the fuel combusted at the applicable minimum frequency:

(a) for natural gas, during each sampling period consisting of each calendar year that the unit generates electricity or produces useful thermal energy, two samples taken that year, with each of those samples being taken at least four months after any previous sample has been taken, in accordance with one of the following standards:
- (i) ASTM D4057, entitled Standard Practice for Manual Sampling of Petroleum and Petroleum Products,
- (ii) ASTM D4177, entitled Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, or
- (iii) ASTM F307, entitled Standard Practice for Sampling Pressurized Gas for Gas Analysis;
(b) for refinery gas, during each sampling period consisting of each day that the unit generates electricity or produces useful thermal energy, one sample per day that is taken at least six hours after any previous sample has been taken, in accordance with any of the standards referred to in paragraph (a);
(c) for a type of liquid fuel or of a gaseous fuel other than refinery gas and natural gas, during each sampling period consisting of each month that the unit generates electricity or produces useful thermal energy, one sample per month that is taken at least two weeks after any previous sample has been taken, in accordance with any of the standards referred to in paragraph (a); and
(d) for a solid fuel, one composite sample per month that consists of sub-samples, each having the same mass, that are taken
- (i) from the fuel that is fed for combustion during each week that begins in that month and during which the unit generates electricity or produces useful thermal energy,
- (ii) after all fuel treatment operations have been carried out but before any mixing of the fuel with other fuels, and
- (iii) at intervals of at least 72 hours.

Additional samples

(3) If the responsible person takes more samples or composite samples, as the case may be, than the number required under subsection (2) and a determination is made on the carbon content of any of those samples or composite samples in the manner set out in the description of CC_i in subsection 20(4) for the fuel type, the results of that determination must be included in the determination of CC_A under subsection 20(4).

Carbon content provided by the supplier

(4) A responsible person may use the carbon content of a fuel provided by the supplier of the fuel rather than taking fuel samples in accordance with this section if the supplier

(a) determined the carbon content in the manner set out in the description of CC_i in subsection 20(4); and
(b) took the samples during the applicable sampling period and at the applicable minimum sampling frequency set out in subsection (2).

Missing data

35 (1) If, for any reason beyond the responsible person’s control, the data required to determine the value of any variable in any formula in these Regulations is missing for a period of a calendar year, replacement data for that period must be used to determine that value.

Replacement data — CEMS

(2) If a CEMS is used to determine the value of a variable in a formula set out in section 16 or 17 or any of sections 7.1 to 7.5 of the CEMS Protocol, but data is missing for a given period, the replacement data must be obtained in accordance with section 3.4.1 of the CEMS Protocol.

Replacement data — non-CEMS

(3) If data, other than data referred to in subsection (2), that is required to determine the value of any variable in a formula in these Regulations is missing for a given period, the replacement data is to be the average of the available data for that variable during the equivalent period prior to and, if the data is available, subsequent to that given period. However, if no data is available for that variable for the equivalent period prior to that given period, the replacement data to be used is the value determined for that variable during the equivalent period subsequent to the given period.

Maximum number of hours

(4) Replacement data may be used for more than one period during a calendar year but must not be used for more than 672 hours during the calendar year.

Accuracy of Data

Measuring devices — installation, maintenance and calibration

36 (1) A responsible person must install, maintain and calibrate all measuring devices, other than a CEMS, that are used for the purposes of these Regulations in accordance with the manufacturer’s instructions or any applicable generally recognized national or international industry standard.

Frequency of calibration

(2) The responsible person must calibrate each measuring device

(a) at least once in every calendar year and at least five months after a previous calibration; or
(b) at the minimum frequency recommended by the manufacturer.

Accuracy of measurements

(3) The responsible person must use measuring devices that enable measurements to be made with an accuracy of

(a) ± 3% in the case of any device used to measure a quantity of electricity; and
(b) ± 5% in the case of any other device.

Documents incorporated by reference

(4) However, if a document incorporated by reference into these Regulations requires measurements that are more accurate than what is required by subsection (3), the responsible person must use a measuring device that enables measurements to be made with the degree of accuracy required by that document.

Errors and Omissions

Correcting errors and omissions

37 A responsible person must, as soon as feasible, notify the Minister of any error or omission in any information submitted in accordance with these Regulations and must submit to the Minister the corrected information no later than 120 days after the day on which the responsible person becomes aware of the error or omission.

Corrected emissions report

38 (1) A responsible person must submit to the Minister a corrected emissions report for a unit no later than 120 days after the day on which

(a) the responsible person submits a notice under section 37 that indicates that the responsible person has become aware of an error or omission that resulted in the issuance of an incorrect number of compliance credits for the unit; or
(b) the Minister notifies the responsible person of an error or omission that resulted in the issuance of an incorrect number of compliance credits for the unit.

Contents of report

(2) The corrected emissions report must contain the information set out in Schedule 5 for the same calendar year as the calendar year to which the error or omission relates, along with

(a) the information that required correction and a description of the corrections made;
(b) a description of the circumstances that led to the error or omission and an indication of the reasons why the error or omission was not previously detected; and
(c) a description of the measures that have been and will be implemented to avoid errors or omissions of the same type.

Remittance obligation

(3) If, as a result of the error or omission, the number of compliance credits issued for a unit is greater than the number of compliance credits that would have been issued had the correct quantities been used to calculate that number at the time of issuance, the responsible person must remit to the Minister, no later than the December 15 that follows the time limit referred to in subsection (1), a number of compliance credits and, if applicable, Canadian offset credits that is equal to the difference between the number of compliance credits issued and the number that should have been issued.

Order of precedence

(4) The credits remitted for a unit for the purposes of subsection (3) must be, in the following order of precedence,

(a) compliance credits issued for the unit for the same calendar year as the calendar year to which the error or omission relates;
(b) if an insufficient number of compliance credits referred to in paragraph (a) are held by the responsible person to fulfill the remittance obligation, any other compliance credits that are held in respect of that unit on the day that the notice referred to in paragraph (1)(a) or (b) is provided; or
(c) if an insufficient number of compliance credits referred to in paragraphs (a) and (b) are held by the responsible person to fulfill the remittance obligation, any combination of transferable compliance credits and Canadian offset credits.

Conditions

(5) The responsible person may only remit compliance credits and Canadian offset credits for a unit for the purposes of this section if

(a) in the case of compliance credits, the credits were issued
- (i) for a calendar year that is no more than five calendar years before the calendar year in which they are remitted, and
- (ii) for a unit that reports to the same electricity system operator as the unit for which they are remitted; and
(b) in the case of Canadian offset credits,
- (i) the credits were issued for greenhouse gas reductions or removals that occurred no more than eight calendar years before the calendar year in which they are remitted, and
- (ii) the number remitted does not exceed the number that is equal to the difference between
  - (A) the sum of the maximum number of Canadian offset credits that may be remitted for the unit under section 28 for each calendar year beginning with the calendar year to which the error or omission relates and ending with the calendar year in which the credits are remitted, and
  - (B) the sum of the number of Canadian offset credits that have already been remitted for the unit for each of those calendar years.

Partial remittance

(6) Despite subsection (3), if a responsible person does not hold and is unable to obtain a sufficient number of compliance credits or Canadian offset credits that meet the conditions set out in subsections (4) and (5) to fulfill the remittance obligation by the time limit set out in subsection (3), the responsible person must remit the number of credits that it was able to obtain by that time limit and remit to the Minister the outstanding number of compliance credits or Canadian offset credits in the following calendar year — or, if it still does not hold and is unable to obtain a sufficient number of credits in that following calendar year, in a subsequent calendar year — in accordance with subsection (7).

Remittance in following year

(7) Credits remitted for a unit after the time limit set out in subsection (3) must be

(a) compliance credits issued for the unit; or
(b) if an insufficient number of compliance credits referred to in paragraph (a) are held by the responsible person to fulfill the remittance obligation, any combination of transferable compliance credits or Canadian offset credits that the responsible person is able to obtain in that calendar year that meet the conditions set out in subsection (5).

Timing of remittance

(8) Compliance credits and Canadian offset credits remitted under this section are considered to be remitted on the day on which a reconciliation report that contains all of the information set out in sections 1, 3 and 5 of Schedule 6 in respect of the credits is submitted to the Minister in accordance with section 41.

Reports

Emissions report

39 (1) Beginning with the calendar year in which a unit becomes subject to an emission limit under subsection 9(1), the responsible person must submit to the Minister an annual emissions report for the unit that contains the information set out in Schedule 5.

June 1

(2) The emissions report must be submitted on or before June 1 of the calendar year that follows the calendar year that is the subject of the report.

Short emissions report

40 (1) A responsible person must submit to the Minister — for each calendar year that the unit is subject to an exemption, under subsection 14(1), from the application of section 39 — a short emissions report for the unit that contains the information set out in sections 1, 2, 4 and 9 of Schedule 5.

June 1

(2) The short emissions report must be submitted on or before June 1 of the calendar year that follows the calendar year that is the subject of the report.

Reconciliation report

41 (1) Beginning with the calendar year in which a unit becomes subject to an emission limit under subsection 9(1), the responsible person must submit to the Minister an annual reconciliation report for the unit that contains the information set out in Schedule 6.

December 15

(2) The reconciliation report must be submitted on or before December 15 of the calendar year that follows the calendar year that is the subject of the report.

Short reconciliation report

42 (1) If a compliance credit is held in respect of a unit for any portion of a calendar year and a reconciliation report is not required under subsection 41(1) in respect of the unit for that calendar year, the responsible person must submit to the Minister a short reconciliation report for the unit for that calendar year that contains the information set out in sections 1 and 3 of Schedule 6.

December 15

(2) The short reconciliation report must be submitted on or before December 15 of the calendar year that follows the calendar year that is the subject of the report.

Permanent cessation

43 (1) If a unit permanently ceases to generate electricity, the responsible person for the unit must, no later than 60 days after the day on which the unit permanently ceases generating electricity, submit to the Minister a notice of permanent cessation of electricity generation that contains the information set out in Schedule 7.

Continuing responsibility

(2) A responsible person that submits the notice referred to in subsection (1) must

(a) submit any report required under any of sections 39 to 42 in respect of the unit for the calendar year in which the unit permanently ceases to generate electricity; and
(b) continue to comply with the requirements set out in sections 29, 37, 38 and 44 to 48 in respect of the unit.

Signature and submission — electronic

44 (1) Any information that is required to be submitted under these Regulations, including any notice provided under subsection 8(5), paragraph 25(1)(f), subsection 25(3), section 37 or subsection 46(3), and any application that is made under these Regulations, must be submitted electronically in the form specified by the Minister and must bear the electronic signature of the responsible person or its authorized official.

Provision on paper

(2) If the Minister has not specified an electronic form or if the responsible person is unable to submit the information electronically in accordance with subsection (1) because of circumstances beyond the responsible person’s control, the information must be submitted on paper, signed by the responsible person or its authorized official, in the form specified by the Minister or, if no form has been specified, in any form.

Records

Contents

45 (1) A responsible person must make records containing the following documents and information with respect to the unit:

(a) any notice, attestation, declaration, application, report or information submitted to the Minister under these Regulations;
(b) if the responsible person is required to make a determination or perform a calculation under these Regulations,
- (i) the determination or calculation required,
- (ii) the measurements on which the determination or calculation was based,
- (iii) an indication of the standard or method that was used to determine the value of any variable of a formula required to complete the calculations, as well as any information, including the methodology, that is used to determine that value, and
- (iv) any supporting documents for the information referred to in subparagraphs (i) to (iii);
(c) if a quantity is assigned to Q_a in subsection 13(2), the documentation referred to in paragraph 13(4)(c) and information demonstrating that useful thermal energy was supplied to a recipient facility;
(d) an indication of the standard or method used to determine the value of CC_i in subsection 20(4) for a sample of gaseous fuel, including an indication of whether a direct measuring device was used to determine that value;
(e) the manufacturer’s instructions for any measuring device used to determine any value or quantity under these Regulations;
(f) information demonstrating that the requirements set out in section 36 have been met;
(g) for each calendar year during which the responsible person uses a CEMS,
- (i) information demonstrating that the requirements set out in the CEMS Protocol for the design, certification, operation and performance evaluation of the CEMS have been met,
- (ii) documents confirming that the CEMS certification requirement set out in subsection 18(2) has been met, and
- (iii) a copy of each quality assurance plan developed for the CEMS and information demonstrating that the requirements set out in section 6 of the CEMS Protocol for the quality assurance plan have been met;
(h) the results of the analysis of every sample taken for the purposes of subsections 20(1) or (4), as well as the date on which each sample was taken and an indication of the standards that were used to take representative samples of the fuel;
(i) if a supplier of hydrogen, ammonia or steam has provided the values of E_k and P_k under subsection 24(2), the information provided by the supplier;
(j) if a supplier of fuel has provided the carbon content of that fuel under subsection 34(4), the information provided by the supplier;
(k) information demonstrating the manner in which the electricity generation capacity set out in any registration report submitted under section 7 or subsection 8(2) and each emissions report submitted under section 39 was determined; and
(l) if replacement data was used under section 35, information demonstrating the reason replacement data was required, along with the replacement data that was used.

Time limit

(2) A record must be made no later than 30 days after the day on which the information and documents to be included in it become available.

Retention of information

46 (1) A responsible person must keep the records that are required to be made under these Regulations with respect to the unit, along with the supporting documents, for the following periods:

(a) in the case of a registration report submitted under subsection 7(1), paragraph 7(2)(a) or subsection 8(2) and any supporting documents related to that registration report, the period that begins on the day on which the registration report is submitted to the Minister and ends on the day that is seven years after the day on which the notice referred to in subsection 43(1) is submitted in respect of the unit; and
(b) in any other case, a period of seven years after the later of the day on which the record is made and the day on which the information is submitted to the Minister.

Location of records

(2) The records and supporting documents must be kept at the responsible person’s principal place of business in Canada or at any other place in Canada where they can be inspected. If the records and documents are not kept at the responsible person’s principal place of business, the responsible person must provide the Minister with the civic address of the place where they are kept.

Relocation of records

(3) If the records and supporting documents are moved, the responsible person must notify the Minister of the civic address of the new location within 30 days after the day of the move.

Minister’s request

47 A responsible person must provide to the Minister a copy of any record that is required to be kept no later than 30 days after the Minister requests it.

Language of Documents

English or French

48 All documents required by these Regulations must be in English or French or be accompanied by a translation in English or French and an affidavit of the translator attesting to the accuracy of the translation.

Consequential Amendments

Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999)

49 The schedule to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999) ^{footnote 1} is amended by adding the following in numerical order:
Item	Column 1 Regulations	Column 2 Provisions
42	Clean Electricity Regulations	(a) subsection 9(1) (b) subsection 29(4) (c) subsections 38(3) and (6)

Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity

50 Section 3 of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity ^{footnote 2} is amended by adding the following after subsection (6):

Non-application — Clean Electricity Regulations

(7) These Regulations do not apply to a unit if it is subject to

(a) an emission limit under subsection 9(1) of the Clean Electricity Regulations; or
(b) an exemption, under subsection 14(1) of those Regulations, from the application of that subsection.

Repeals

51 The Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations ^{footnote 3} are repealed.

52 The Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity ^{footnote 2} are repealed.

Coming into Force

January 1, 2025

53 (1) Subject to subsections (2) and (3), these Regulations come into force on January 1, 2025, but if they are registered after that day, they come into force on the day on which they are registered.

January 1, 2035

(2) Sections 9 and 12, subsection 13(1), sections 15 to 24, 27 to 30, 33 to 36, 38 to 42 and 49 to 51 and Schedules 3 to 6 come into force on January 1, 2035.

January 1, 2050

(3) Section 52 comes into force on January 1, 2050.

SCHEDULE 1

(Subsection 6(4) and paragraph 3(h) of Schedule 2)

Performance Test Verifier Report — Information Required

1 The registration number, if any, assigned to the unit by the Minister under subsection 7(3) of these Regulations.

2 The following information about a unit that has not been assigned a registration number:

(a) the unit’s name and, if any, civic address; and
(b) the unit’s geographic coordinates (latitude and longitude), expressed in decimal degrees to five decimal places.

3 The name, civic address, telephone number, email address and, if any, fax number of the performance test verifier.

4 Information demonstrating that the performance test verifier meets the requirements set out in subsection 6(3) of these Regulations.

5 The procedures followed by the performance test verifier to assess whether

(a) the maximum gross power was measured at the electrical terminals of the unit’s generators; and
(b) the performance test was conducted in accordance with subsection 6(2) of these Regulations.

6 A statement by the performance test verifier that affirms that

(a) the maximum gross power was measured at the electrical terminals of the unit’s generators; and
(b) the performance test was conducted in accordance with subsection 6(2) of these Regulations.

7 The unit’s maximum gross power, expressed in MW, as determined by the performance test.

8 The unit’s most recent maximum continuous rating.

9 The date of the performance test.

SCHEDULE 2

(Subsection 7(1), paragraph 7(2)(a) and subsections 7(4) and 8(2))

Registration Report — Information Required

1 The following information about the responsible person that is submitting the report:

(a) its name and civic address;
(b) an indication of whether it is the owner and whether it has the charge, management or control of the unit;
(c) the federal Business Number assigned to it by the Canada Revenue Agency, if any;
(d) its percentage of ownership interest in the unit, if any;
(e) the name, title, civic and postal addresses, telephone number, email address and, if any, fax number of its authorized official; and
(f) the name, title, civic and postal addresses, telephone number, email address and, if any, fax number of a contact person, if different from the authorized official.

2 The following information about the facility where the unit is located:

(a) its name and, if any, civic address;
(b) its geographic coordinates (latitude and longitude), expressed in decimal degrees to five decimal places;
(c) the name of each owner or person that has the charge, management or control of the facility and the federal Business Number, if any, assigned to each of those persons by the Canada Revenue Agency; and
(d) in respect of a facility that transmits electricity to an electricity system and supplies useful thermal energy to a recipient facility,
- (i) the name and, if any, civic address of the recipient facility,
- (ii) the geographic coordinates (latitude and longitude) of the recipient facility, expressed in decimal degrees to five decimal places, and
- (iii) the name of each owner or person that has the charge, management or control of the recipient facility and the federal Business Number, if any, assigned to each of those persons by the Canada Revenue Agency.

3 The following information and documents about the unit:

(a) for each responsible person for the unit, other than the responsible person referred to in section 1, if any,
- (i) its name and, if any, civic address,
- (ii) an indication of whether it is an owner and whether it has the charge, management or control of the unit,
- (iii) its percentage of ownership interest in the unit, if any, and
- (iv) the federal Business Number assigned to it by the Canada Revenue Agency, if any;
(b) the unit’s name and, if any, civic address;
(c) the unit’s geographic coordinates (latitude and longitude), expressed in decimal degrees to five decimal places;
(d) if applicable, any National Pollutant Release Inventory identification number assigned by the Minister to the unit or the facility where it is located for the purposes of section 48 of the Canadian Environmental Protection Act, 1999;
(e) if applicable, any identifiers assigned by the Minister to the unit or the facility where it is located for the purposes of the Greenhouse Gas Reporting Program;
(f) the electricity system operator;
(g) the unit’s electricity generation capacity;
(h) if the electricity generation capacity was determined under paragraph 6(1)(a) of these Regulations, the unit’s maximum gross power and the performance test report prepared by the performance test verifier that contains the information set out in Schedule 1;
(i) the unit’s most recent maximum continuous rating and the date on which it was reported to the electricity system operator;
(j) the year in which subsection 9(1) and section 12 of these Regulations begin to apply in respect of the unit;
(k) if the responsible person has made an election under section 11 of these Regulations with respect to the unit, the date on which the information referred to in subsection 11(2) of these Regulations was submitted and the date elected as the unit’s end of prescribed life;
(l) the unit’s commissioning date;
(m) the name of each boiler and combustion engine in the unit and the date on which each boiler and combustion engine started operating;
(n) an indication of whether the unit combusted coal during the previous calendar year;
(o) an indication of whether the maximum continuous rating for the unit has increased by 15% or more from the maximum continuous rating reported for the unit in the registration report that was submitted in respect of the unit under subsection 7(1), paragraph 7(2)(a) or subsection 8(2) of these Regulations;
(p) an indication of whether the unit is a boiler unit referred to in subsection 3(4) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity that has an end of prescribed life after December 31, 2034, and, if so, the year of its end of prescribed life;
(q) an indication of whether the unit produces useful thermal energy;
(r) the registration number, if any, assigned to the unit by the Minister under subsection 4(2) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations;
(s) the registration number, if any, assigned to the unit by the Minister under subsection 21(4) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity;
(t) if the unit is a subunit referred to in section 8 of these Regulations,
- (i) the registration number, assigned by the Minister under subsection 7(3) of these Regulations, of each other subunit that was registered as one of the multiple subunits referred to in subsection 8(1) of these Regulations,
- (ii) an indication of whether all of the conditions set out in subsection 8(1) of these Regulations are met,
- (iii) the sum of the maximum continuous rating of the subunit and each other subunit that was registered as one of the multiple subunits referred to in subsection 8(1) of these Regulations, and
- (iv) an indication of whether the sum of the maximum continuous rating for each of the subunits has increased by 15% or more from the sum of the maximum continuous ratings reported in the registration reports submitted for the subunits under subsection 8(2) of these Regulations;
(u) a process diagram of the facility where the unit is located that clearly identifies the assembly of equipment that constitutes the unit as well as
- (i) major equipment, including boilers, combustion engines, duct burners and other combustion devices, heat recovery systems, steam turbines, generators, emission control devices, carbon capture and storage system equipment and continuous emission monitoring systems,
- (ii) the manner in which the equipment referred to in subparagraph (i) is physically connected and operates together,
- (iii) the boundaries used to identify each unit,
- (iv) if applicable, the boundaries used to identify the unit that was registered as multiple subunits in accordance with subsection 8(1) of these Regulations,
- (v) the electric flows that cross the boundary of a unit and those that cross the boundary of the facility,
- (vi) the location of any electricity-measuring device,
- (vii) if applicable, the heat streams that cross the boundary of a unit and those that cross the boundary of the facility,
- (viii) if a carbon capture and storage system is shared between multiple units or other sources, information that identifies those units and sources, and
- (ix) if applicable, any major equipment that is physically connected with another facility and the name of that facility;
(v) if the unit includes major equipment that is physically connected with another facility, the name of that facility and the name of the owner or person that has the charge, management or control of that facility;
(w) an indication of whether the unit is deemed, under subsection 5(2) of these Regulations, to meet the criterion set out in paragraph 5(1)(a) of these Regulations and, if so, the names and registration numbers, assigned by the Minister under subsection 7(3) of these Regulations, of the units for which the sum of the electricity generation capacity is at least 25 MW;
(x) if the unit contains a combustion engine, boiler or steam turbine that was contained in another unit previously registered under these Regulations,
- (i) the registration number assigned to the previously registered unit by the Minister under subsection 7(3) of these Regulations,
- (ii) in the case of a combustion engine or steam turbine, the electricity generation capacity associated with the combustion engine or steam turbine, and
- (iii) the date on which the combustion engine, boiler or steam turbine started operating in the unit that is the subject of the report;
(y) if the unit is a planned unit, information demonstrating that the unit is a planned unit and an explanation, along with supporting documents, of how each of the criteria set out in section 3 of these Regulations was met in relation to the unit, including the following:
- (i) if the unit’s commissioning date is after December 31, 2025, a description of the plans for the unit as they existed on December 31, 2025,
- (ii) if no impact assessment or environmental assessment was required in relation to the unit, a declaration to that effect and an explanation of why it was not required,
- (iii) if an impact assessment or environmental assessment was required, an explanation of how the information submitted to the relevant authority on or before December 31, 2025 was all of the information required to initiate the relevant assessment and the date on which the information was submitted,
- (iv) information respecting the ownership or control, on or before December 31, 2025, of the land on which the unit is located,
- (v) information respecting any permit required to begin construction of the unit,
- (vi) an explanation of how the information submitted on or before December 31, 2025 in relation to any permit required to begin construction at the site where the unit is located was all the information required to obtain that permit and the date on which the information was submitted,
- (vii) the value of the contracts referred to in subparagraph 3(a)(iv) of these Regulations and the date on which those contracts were entered into,
- (viii) details of the value of the equipment that is the subject of the contracts and an explanation of how that equipment is used in the unit,
- (ix) information respecting the construction of the unit, including the date on which construction began at the site where the unit is located, and
- (x) an explanation of how the unit is substantially the same on its commissioning date as the unit in relation to which the criteria set out in section 3 of these Regulations were met, including an indication of the electricity generation capacity that was planned for the unit on the date on which the unit met the criteria set out in that section; and
(z) if the unit has been modified in a way that resulted in the creation of one or more units for which a registration report is required under paragraph 7(2)(a) of these Regulations, the registration number assigned to each of those units by the Minister under subsection 7(3) of these Regulations.

4 If the report is submitted in accordance with subsection 7(4) of these Regulations, the following information:

(a) an indication of the provisions of this Schedule to which the updated information relates;
(b) a description of the updated information; and
(c) the effective date of the change.

SCHEDULE 3

(Subsection 16(1) and section 17)

List of Fuels and Default Higher Heating Value
Item	Column 1 Fuel type	Column 2 Default higher heating value	Column 3 Units
1	Distillate fuel oil No. 1	38.78	GJ/kL
2	Distillate fuel oil No. 2	38.50	GJ/kL
3	Distillate fuel oil No. 4	40.73	GJ/kL
4	Kerosene	37.68	GJ/kL
5	Liquefied petroleum gases (LPG)	25.66	GJ/kL
6	Propane ^{table 1 note 1}	25.31	GJ/kL
7	Propylene	25.39	GJ/kL
8	Ethane	17.22	GJ/kL
9	Ethylene	27.90	GJ/kL
10	Isobutane	27.06	GJ/kL
11	Isobutylene	28.73	GJ/kL
12	Butane	28.44	GJ/kL
13	Butylene	28.73	GJ/kL
14	Natural gasoline	30.69	GJ/kL
15	Motor gasoline	34.87	GJ/kL
16	Aviation gasoline	33.52	GJ/kL
17	Kerosene-type aviation	37.66	GJ/kL
18	Pipeline quality natural gas	0.03793	GJ/m³ at standard conditions
19	Bituminous Canadian coal — Western	25.6	GJ/tonne
20	Bituminous Canadian coal — Eastern	27.9	GJ/tonne
21	Bituminous non-Canadian coal — U.S.	25.7	GJ/tonne
22	Bituminous non-Canadian coal — other countries	29.9	GJ/tonne
23	Sub-bituminous Canadian coal — Western	19.2	GJ/tonne
24	Sub-bituminous non-Canadian coal — U.S.	19.2	GJ/tonne
25	Coal — lignite	15.0	GJ/tonne
26	Coal — anthracite	27.7	GJ/tonne
27	Coal coke and metallurgical coke	28.8	GJ/tonne
28	Petroleum coke from refineries	46.4	GJ/tonne
29	Petroleum coke from upgraders	40.6	GJ/tonne
30	Municipal solid waste	11.5	GJ/tonne
31	Tires	31.2	GJ/tonne
32	Diesel	38.3	GJ/kL
33	Light fuel oil	38.8	GJ/kL
34	Heavy fuel oil	42.5	GJ/kL
35	Ethanol	21	GJ/kL
36	Hydrogen	0.012289	GJ/m³ at standard conditions
Table 1 Notes Table 1 Note 1 The default higher heating value for propane is only for pure gas propane. The product commercially sold as propane is to be considered LPG for the purpose of these Regulations. Return to table 1 note 1 referrer

SCHEDULE 4

(Paragraph 18(3)(a))

CEMS Report — Information Required

1 The registration number assigned to the unit by the Minister under subsection 7(3) of these Regulations.

2 The name, civic address and telephone number of the responsible person.

3 The auditor’s name, qualifications, civic address, telephone number, email address and, if any, fax number.

4 The procedures followed by the auditor to assess whether

(a) the responsible person’s use of the CEMS complied with the quality assurance plan referred to in section 6.1 of the CEMS Protocol; and
(b) the responsible person complied with the CEMS Protocol and the CEMS met the specifications set out in the CEMS Protocol, in particular those set out in sections 3 and 4 of the CEMS Protocol.

5 A statement of the auditor’s opinion as to whether

(a) the responsible person’s use of the CEMS complied with the quality assurance plan referred to in section 6.1 of the CEMS Protocol;
(b) the responsible person complied with the CEMS Protocol and the CEMS met the specifications set out in the CEMS Protocol, in particular those set out in sections 3 and 4 of the CEMS Protocol; and
(c) the responsible person complied with subsection 18(2) of these Regulations.

6 A statement of the auditor’s opinion as to whether the responsible person has ensured that the quality assurance plan has been updated in accordance with sections 6.1 and 6.5.2 of the CEMS Protocol.

SCHEDULE 5

(Paragraph 20(3)(g) and subsections 38(2), 39(1) and 40(1))

Emissions Report — Information Required

1 The registration number assigned to the unit by the Minister under subsection 7(3) of these Regulations.

2 The following information about the unit:

(a) an indication of whether the unit is subject to an exemption, under subsection 14(1) of these Regulations, from the application of subsection 9(1) of these Regulations for the calendar year that is the subject of the report;
(b) an indication of whether a declaration of net supply has been submitted in accordance with subsections 14(2) to (4) of these Regulations with respect to the facility where the unit is located;
(c) an indication of whether the unit generated electricity during a deduction period during the calendar year that is the subject of the report;
(d) an indication of whether the unit was designated as a substitute unit under section 32 of these Regulations for the calendar year that is the subject of the report and, if so, the following information:
- (i) with respect to the unit for which it is being substituted,
  - (A) the registration number assigned to that unit by the Minister under subsection 7(3) of these Regulations,
  - (B) electricity generation capacity of that unit,
  - (C) the electricity system operator for that unit, and
  - (D) an attestation, dated and signed by the responsible person for that unit or its authorized official, that the responsible person agrees to the substitution,
- (ii) an explanation of how the conditions set out in subsection 32(1) of these Regulations were met,
- (iii) the information referred to in subsection 32(2) of these Regulations, and
- (iv) the date on which the unit became a substitute unit and, if applicable, the date it ceased to be one.

3 The unit’s emission limit for the calendar year that is the subject of the report, determined in accordance with section 9 of these Regulations.

4 The net supply, for the calendar year that is the subject of the report, from the facility where the unit is located and the values determined for Q_t, Q_r, Q_a, Q_na and Q_ec in subsection 13(2) of these Regulations, expressed in GWh, that were used to calculate that net supply.

5 The following information about the quantity of CO₂ emissions attributed to the unit for the calendar year that is the subject of the report:

(a) the value determined for E in accordance with subsection 12(1) of these Regulations, expressed in tonnes;
(b) with respect to the quantity of CO₂ emissions from the combustion of fossil fuel in the unit (E_u),
- (i) if the quantity is determined in accordance with section 15 of these Regulations, that quantity, expressed in tonnes, and, if section 17 of these Regulations applies to the unit, the values determined for Q_u,j, HHV_u,j, Q_i,j, HHV_i,j and E in that section, expressed in the applicable units of measurement, used to determine the quantity of CO₂ emissions attributed to the unit,
- (ii) if the quantity is determined in accordance with section 16 of these Regulations, that quantity, expressed in tonnes, as well as
  - (A) the values determined for E_comb, V_ff, Q_i, F_c,i, HHV_i, V_T and E_S in subsection 16(1) of these Regulations, expressed in the applicable units of measurement, and
  - (B) if section 17 of these Regulations applies to the unit, the values determined for Q_u,j, HHV_u,j, Q_i,j, HHV_i,j and E in that section, expressed in the applicable units of measurement, used to determine the quantity of CO₂ emissions attributed to the unit,
- (iii) if the quantity is determined in accordance with section 19 of these Regulations, that quantity, expressed in tonnes, as well as
  - (A) the values determined for E_i and E_s in that section, expressed in tonnes,
  - (B) the values determined for V_f, CC_A, MM_A, MV_cf, M_f, CC_i and Q_i in subsections 20(1) and (4) of these Regulations, expressed in the applicable units of measurement,
  - (C) the values determined for V_total and V_RNG in subsection 20(2) of these Regulations, expressed in m³ at standard conditions, and
  - (D) with respect to the data used to determine the value of CC_A in subsection 20(4) of these Regulations, an indication of the standard or method, including use of a direct measuring device, used to measure the carbon content of fuel samples or composite samples, as the case may be, or if the carbon content of a fuel was provided by the supplier of the fuel, an indication of the methods used to measure the carbon content of the fuel samples or composite samples, as the case may be;
(c) if applicable, the following information about the quantity of CO₂ emissions attributed to the production of useful thermal energy by the unit (E_th):
- (i) the quantity determined in accordance with section 21 of these Regulations, expressed in tonnes, and
- (ii) the values determined for H_pnet, h_outi, M_outi, h_inj and M_inj in section 21 of these Regulations, expressed in the applicable units of measurement;
(d) if applicable, the following information about the quantity of CO₂ emissions attributed to electricity generated by the unit that is used internally at the facility (E_int):
- (i) the quantity determined in accordance with section 22 of these Regulations, expressed in tonnes, and
- (ii) the values determined for G_int, G_F and G_U in section 22 of these Regulations, expressed in GWh;
(e) if applicable, the following information about the quantity of CO₂ that is captured from the unit and stored in a storage project (E_ccs):
- (i) the quantity determined in accordance with subsection 23(1) of these Regulations, expressed in tonnes,
- (ii) the values determined for E_cap and E_in in subsection 23(1) of these Regulations, expressed in tonnes, and
- (iii) information demonstrating that the CO₂ was captured, transported and permanently stored in accordance with subsection 23(2) of these Regulations;
(f) if applicable, the following information about the quantity of CO₂ emissions from the production of the hydrogen, ammonia or steam used by the unit to generate electricity (E_ext):
- (i) the quantity determined in accordance with section 24 of these Regulations, expressed in tonnes, and
- (ii) the values determined for E_k, P_k and Q_k in section 24 of these Regulations, expressed in tonnes, m³ or GJ, as applicable; and
(g) if applicable, the following information about the quantity of CO₂ emissions attributed to the unit for each deduction period (E_ec):
- (i) the quantity determined in accordance with section 27 of these Regulations, expressed in tonnes, and
- (ii) the values determined for E_u, E_th, E_int, E_ccs and E_ext in subsection 27(1) of these Regulations, expressed in tonnes.

6 If biomass was combusted in the unit during the calendar year that is the subject of the report,

(a) an explanation of how the combusted material is biomass as defined in subsection 2(1) of these Regulations; and
(b) the quantity of biomass combusted, expressed in m³, kL or tonnes, as applicable, during that year.

7 If a CEMS was used to measure CO₂ emissions from the unit during the calendar year that is the subject of the report, a copy of the CEMS report referred to in subsection 18(3) of these Regulations.

8 If, in order to determine the value of V_f in paragraph 20(1)(a) of these Regulations, a volume was claimed for V_RNG in subsection 20(2) of these Regulations, the following information in relation to each producer of renewable natural gas supplied to the unit during the calendar year that is the subject of the report:

(a) the name of each person from which the natural gas containing renewable natural gas that was produced by the producer was purchased;
(b) the producer’s name, civic address, telephone number and email address;
(c) the name, civic address and geographic coordinates (latitude and longitude), expressed in decimal degrees to five decimal places, of the facility where the renewable natural gas was produced;
(d) information demonstrating that the renewable natural gas was kept physically separated from any other substance and was clearly identifiable as renewable natural gas from the time it was produced until the time it was injected into a North American pipeline network;
(e) a map that indicates
- (i) the location where the producer injected the renewable natural gas into a North American pipeline network or, if the producer is not directly injecting the renewable natural gas into a North American pipeline network, a description of the location where the renewable natural gas is no longer kept physically separated and is no longer clearly identifiable as originating from the producer and the location where the renewable natural gas is injected into a North American pipeline network,
- (ii) the location of the unit, and
- (iii) the pipeline network into which the renewable natural gas was injected and from which it was supplied to the unit;
(f) the volume of renewable natural gas produced by the producer that was injected into a North American pipeline network during the calendar year; and
(g) information demonstrating that the conditions referred to in paragraphs 20(3)(e) and (f) of these Regulations are met.

9 The following information about each deduction period during the calendar year that is the subject of the report:

(a) a description of the irresistible emergency event or risk to human health and safety referred to in paragraph 25(1)(a) of these Regulations, including
- (i) an indication of whether the electricity system operator determined that there was an irresistible emergency event or whether the Minister determined that there was a risk to human health and safety,
- (ii) the date on which and hour at which the event or risk began and, if applicable, the date on which and hour at which it ended,
- (iii) a description of how the event or risk led to a disruption or significant risk of disruption to the electricity supply in the province in which the unit is located or in a contiguous province or state,
- (iv) in the case of an irresistible emergency event,
  - (A) an indication of whether the event was natural and, if so, details of the event,
  - (B) an indication of whether the event arose from human action and, if so, the identity of the person whose actions resulted in the event and an explanation of how the event was outside the control of both the electricity system operator and the responsible person for the unit, and
  - (C) an indication of whether the event led to a disruption or a significant risk of disruption to the electricity supply and an explanation of the disruption or risk,
- (v) the province or state in which the event or risk occurred, and
- (vi) the province or state in which the disruption or significant risk of disruption to the electricity supply occurred;
(b) the date on which and hour at which the deduction period began and ended or, if the deduction period has not ended, an indication to that effect;
(c) information demonstrating that the unit was directed by the electricity system operator to generate electricity due to an event or risk referred to in paragraph 25(1)(a) of these Regulations;
(d) the date on which the Minister was notified that a direction referred to in paragraph 25(1)(d) of these Regulations was given; and
(e) if an application for an extension of the deduction period was submitted to the Minister under section 26 of these Regulations,
- (i) the date on which the application was submitted to the Minister,
- (ii) an indication of whether the extension was granted, and
- (iii) if the extension was granted and the deduction period has ended, an indication of the reason that the deduction period ended.

10 The following information for the calendar year that is the subject of the report:

(a) the difference between the emission limit for the unit determined in accordance with subsection 9(1) of these Regulations and the value determined for E in accordance with subsection 12(1) of these Regulations;
(b) an indication of whether the unit became subject to an emission limit under subsection 9(1) of these Regulations on or after July 1 of that calendar year; and
(c) an indication of whether the unit meets the conditions for the issuance of transferable compliance credits set out in subsection 31(1) and 32(3) of these Regulations and, if so, an explanation of how the conditions are met.

11 If replacement data referred to in section 35 of these Regulations was used during the calendar year that is the subject of the report, the total number of hours for which replacement data was used during the calendar year and the following information about the replacement data that was used for each given period during the calendar year:

(a) the reason why the data required to determine the value of a variable in a formula referred to in these Regulations was missing for a period of the calendar year and an explanation of how that reason was beyond the responsible person’s control;
(b) the variable for which data was missing and the date on which and hour at which the period during which replacement data was used began and ended; and
(c) the value determined for the variable referred to in paragraph (b), along with details of that determination, including
- (i) the replacement data used to make that determination,
- (ii) the method used to obtain that replacement data, and
- (iii) in the case of a determination referred to in subsection 35(3) of these Regulations, an explanation of why a particular equivalent period was used as the basis for determining the value of the variable.

SCHEDULE 6

(Subsections 28(7), 29(4), 33(3), 38(8), 41(1) and 42(1))

Reconciliation Report — Information Required

1 The registration number assigned to the unit by the Minister under subsection 7(3) of these Regulations.

2 The following information for the calendar year that is the subject of the report:

(a) the values determined for E, C_off and C_c in accordance with subsection 12(1) of these Regulations, expressed in tonnes;
(b) for each collection of compliance credits that have the same characteristics and that are being remitted for the purposes of subsection 12(1) of these Regulations,
- (i) the total number of tonnes of CO₂ that the credits represent,
- (ii) the calendar year for which the credits were issued,
- (iii) an indication of whether the credits are non-transferable or transferable,
- (iv) the registration number, assigned by the Minister under subsection 7(3) of these Regulations, of the unit for which the credits were issued, if it is a unit other than the unit that is the subject of the report, and
- (v) an indication that the credits meet the conditions for remittance set out in subsection 33(2) of these Regulations;
(c) the maximum number of Canadian offset credits that may be remitted, determined in accordance with section 28 of these Regulations;
(d) for each collection of Canadian offset credits issued under subsection 29(1) of the Canadian Greenhouse Gas Offset Credit System Regulations that have the same characteristics and sequential serial numbers and that are being remitted for the purposes of subsection 12(1) of these Regulations,
- (i) the total number of tonnes of CO₂ that the credits represent,
- (ii) the first and last serial number of the credits,
- (iii) the year in which the greenhouse gas reduction or removal for which the credits were issued occurred,
- (iv) the date on which the credits were issued, and
- (v) an indication of whether the credits are being remitted in accordance with subsection 28(5) of these Regulations and, if so, an indication that the conditions set out in that subsection are met; and
(e) for each collection of Canadian offset credits recognized under subsection 78(1) of the Output-Based Pricing System Regulations that have the same characteristics and sequential serial numbers and that are being remitted for the purposes of subsection 12(1) of these Regulations,
- (i) the total number of tonnes of CO₂ the credits represent,
- (ii) the province or program authority referred to in subsection 78(1) of those Regulations that issued the credits,
- (iii) the date of retirement of the credits or the date on which the credits were designated by the province or program authority for the purposes of remittance under these Regulations,
- (iv) the first and last serial number of the credits,
- (v) the start date of the project for which the credits were issued,
- (vi) the year in which the greenhouse gas reduction or removal for which the credits were issued occurred,
- (vii) the offset protocol applicable to the project for which the credits were issued, including the version number and publication date,
- (viii) the name of the verification body that verified the credits, and
- (ix) an indication of whether the credits are being remitted in accordance with subsection 28(5) of these Regulations and, if so, an indication that the conditions set out in that subsection are met.

3 The following information about compliance credits:

(a) for compliance credits issued for the unit,
- (i) the number of non-transferable compliance credits issued for each calendar year,
- (ii) the number of non-transferable compliance credits that have been remitted under these Regulations and the calendar year for which they were remitted,
- (iii) the number of non-transferable compliance credits that have not been remitted,
- (iv) the number of transferable compliance credits issued for each calendar year,
- (v) the number of transferable compliance credits that have been remitted for the unit under these Regulations and the calendar year for which they were remitted, and
- (vi) the number of transferable compliance credits that have not been remitted for the unit and have not been transferred to another unit;
(b) for each collection of transferable compliance credits that have the same characteristics and that have been transferred to the unit,
- (i) the calendar year for which the credits were issued,
- (ii) the total number of tonnes of CO₂ that the credits represent,
- (iii) the registration number, assigned by the Minister under subsection 7(3) of these Regulations, of the unit from which the credits were transferred,
- (iv) a document, dated and signed by the responsible person for the unit from which the credits were transferred, or its authorized official, and the responsible person for the unit to which the credits were transferred, or its authorized official, confirming that both responsible persons agree to the transfer,
- (v) the registration number, assigned by the Minister under subsection 7(3) of these Regulations, of the unit for which the credits were issued and the electricity system operator for that unit, and
- (vi) the calendar year for which the credits were remitted or an indication that they have not been remitted; and
(c) for each collection of transferable compliance credits that have the same characteristics and that have been transferred from the unit,
- (i) the calendar year for which the credits were issued,
- (ii) the total number of tonnes of CO₂ that the credits represent,
- (iii) the registration number, assigned by the Minister under subsection 7(3) of these Regulations, of the unit to which the credits were transferred,
- (iv) a document, dated and signed by the responsible person for the unit from which the credits were transferred, or its authorized official, and the responsible person for the unit to which the credits were transferred, or its authorized official, confirming that both responsible persons agree to the transfer, and
- (v) the registration number, assigned by the Minister under subsection 7(3) of these Regulations, of the unit for which the credits were issued and the electricity system operator for that unit.

4 The following information about Canadian offset credits that are being remitted for the purposes of subsection 29(4) of these Regulations:

(a) for each collection of Canadian offset credits issued under subsection 29(1) of the Canadian Greenhouse Gas Offset Credit System Regulations that have the same characteristics and sequential serial numbers,
- (i) the total number of tonnes of CO₂ that the credits represent,
- (ii) the first and last serial number of the credits,
- (iii) the year in which the greenhouse gas reduction or removal for which the credits were issued occurred, and
- (iv) the date on which the credits were issued; and
(b) for each collection of Canadian offset credits recognized under subsection 78(1) of the Output-Based Pricing System Regulations that have the same characteristics and sequential serial numbers,
- (i) the total number of tonnes of CO₂ that the credits represent,
- (ii) the province or program authority referred to in subsection 78(1) of those Regulations that issued the credits,
- (iii) the date of retirement of the credits or the date on which the credits were designated by the province or program authority for the purposes of remittance under these Regulations,
- (iv) the first and last serial number of the credits,
- (v) the start date of the project for which the credits were issued,
- (vi) the year in which the greenhouse gas reduction or removal for which the credits were issued occurred,
- (vii) the offset protocol applicable to the project for which the credits were issued, including the version number and publication date, and
- (viii) the name of the verification body that verified the credits.

5 The following information about compliance credits or Canadian offset credits that are being remitted for the purposes of section 38 of these Regulations:

(a) for each collection of compliance credits that have the same characteristics,
- (i) the total number of tonnes of CO₂ that the credits represent,
- (ii) the calendar year for which the credits were issued,
- (iii) an indication of whether the credits are non-transferable or transferable,
- (iv) the registration number, assigned by the Minister under subsection 7(3) of these Regulations, of the unit for which the credits were issued, if it is a unit other than the unit that is the subject of the report, and
- (v) an explanation of how the credits meet the conditions for remittance set out in paragraph 38(5)(a) of these Regulations;
(b) for each collection of Canadian offset credits issued under subsection 29(1) of the Canadian Greenhouse Gas Offset Credit System Regulations that have the same characteristics and sequential serial numbers,
- (i) the total number of tonnes of CO₂ that the credits represent,
- (ii) the first and last serial number of the credits,
- (iii) the year in which the greenhouse gas reduction or removal for which the credits were issued occurred,
- (iv) the date on which the credits were issued, and
- (v) an explanation of how the credits meet the conditions for remittance set out in paragraph 38(5)(b) of these Regulations; and
(c) for each collection of Canadian offset credits recognized under subsection 78(1) of the Output-Based Pricing System Regulations that have the same characteristics and sequential serial numbers,
- (i) the total number of tonnes of CO₂ that the credits represent,
- (ii) the province or program authority referred to in subsection 78(1) of those Regulations that issued the credits,
- (iii) the date of retirement of the credits or the date on which the credits were designated by the province or program authority for the purposes of remittance under these Regulations,
- (iv) the first and last serial number of the credits,
- (v) the start date of the project for which the credits were issued,
- (vi) the year in which the greenhouse gas reduction or removal for which the credits were issued occurred,
- (vii) the offset protocol applicable to the project for which the credits were issued, including the version number and publication date,
- (viii) the name of the verification body that verified the credits, and
- (ix) an explanation of how the credits meet the conditions for remittance set out in paragraph 38(5)(b) of these Regulations.

SCHEDULE 7

(Subsection 43(1))

Notice of Permanent Cessation of Electricity Generation — Information Required

1 The registration number assigned to the unit by the Minister under subsection 7(3) of these Regulations.

2 An attestation, dated and signed by the responsible person or its authorized official, that the unit has permanently ceased generating electricity.

3 The date on which the unit permanently ceased generating electricity.

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues: Climate change is a growing threat to Canada and the world. We are already seeing the costs and risks of climate change through extreme weather events like wildfires, floods, and more severe storms. For example, insured losses as a result of catastrophic weather events in Canada totalled over $18 billion (2019 Can$) between 2010 and 2019, while the number of catastrophic weather events in this period was over three times higher than it had been between 1980 and 1989.

Reducing greenhouse gas (GHG) emissions in all sectors, including electricity, is necessary to address the threat of climate change to the environment. To help avoid the worst impacts of climate change, and based on the conclusions of climate science, over 100 of the world’s governments – including the Government of Canada, along with those of many Canadian provinces and territories – have committed to reaching net-zero emissions by 2050.

A prosperous net-zero economy will require far more electricity than we use today: to cut greenhouse gas emissions, households and businesses will increasingly switch from fossil fuels to using energy in the form of electricity. For example, electric vehicles displace vehicles with internal combustion engines; buildings are heated with heat pumps rather than natural gas or oil; and electricity provides energy for a growing number of heavy industry applications.

Background: The International Energy Agency’s World Energy Outlook 2024 finds that global electricity demand more than doubles by 2050 in all scenarios. This means that access to abundant electricity, especially that which is clean, is an increasingly important competitive advantage for Canada. In addition to addressing the threat to the environment and human health caused by climate change, these Regulations will also, as a secondary benefit, help make Canada an attractive place to invest. Accelerating the uptake of clean electricity in Canada could strengthen Canada’s ability to provide clean technology to the world’s growing markets.

Moreover, electricity prices tend to be more stable than natural gas, diesel, and gasoline prices. Clean electricity can protect against price volatility and price shocks, e.g. those brought about by international conflicts. An abundant and readily available supply of clean electricity supports economic competitiveness.

Electrification delivers a much greater climate benefit if it is powered by clean electricity. (In this document, “clean electricity generation” can be understood to include generation sources that are non-emitting (e.g. wind, solar, etc.), low-emitting (e.g. nuclear) or firing fossil fuels in a manner that meets the requirements of these Regulations.) Prohibiting excessive emissions from fossil fuel electricity generation has the secondary benefit of encouraging clean electricity. Electricity from wind, solar, and other renewable sources is now often the cheapest source of electricity available, so it is being deployed at record pace around the globe. The International Energy Agency’s Renewables 2023 report notes that renewable energy sources like wind and solar have grown from 2% of electricity generation in 2010 to 13% in 2023, and are projected to account for a quarter of all global electricity generation in 2028. The clean energy sector is also seeing significant job growth, according to the International Energy Agency, which found in 2024 that clean energy employment rose by 1.5 million jobs in 2023 and contributed as much as 10% of economy-wide job growth in the leading markets for clean energy technologies. The solar photovoltaic (PV) industry alone added over half a million new jobs, spurred by record new installations. In Canada, the nuclear industry has seen much recent activity with small modular nuclear reactors buildout planned for Ontario and similar nuclear projects being anticipated in Saskatchewan, New Brunswick and Alberta.

A number of recent analyses have looked at what using more electricity means for Canadians’ overall energy costs. An October 2024 report from Clean Energy Canada quantifies the monthly energy savings from switching to heat pumps and to electric vehicles. The report concluded that almost all households in Canada save money from electrification. Global trends in renewable energy prices, non-emitting electricity generation and storage, in comparison to fossil fuels, provide opportunities to enable further energy cost savings for Canadians.

Rationale: The electricity sector in Canada has taken very significant steps to reduce its emissions in recent years. Since 2005, the sector’s emissions have dropped by 55%, mainly from the phaseout of unabated coal power in Ontario and Alberta. Today, electricity emissions account for just under 8% of Canada’s total, with most of those emissions originating from Alberta, Saskatchewan, Nova Scotia, Ontario, and New Brunswick. Despite the sector’s progress, electricity emissions will need to fall further for Canada to reach net-zero. In this context the Government of Canada is introducing the Clean Electricity Regulations (the Regulations) in order to avoid excessive emissions from electricity generation that would otherwise occur in their absence.

In addition to addressing the threat to the environment and human health caused by climate change, the Regulations will also, as a secondary benefit, help make Canada an attractive place to invest in. By 2024, all G7 countries had pledged to achieve a net-zero electricity grid and over 140 countries had committed to net-zero economy-wide goals by 2050. Clean electricity is increasingly recognized as a competitive advantage for major economies such as Canada. In Canada, clean electricity is an increasingly important factor in attracting investment in areas like the electric vehicle supply chain, critical minerals, and other natural resource projects.

Together with the effects of population growth, electrification means that Canada’s electricity sector will see very significant growth in demand in the years ahead. Provinces and territories — the jurisdictions responsible for electricity systems in Canada — are already working to meet growing demand by expanding their electricity systems and making choices about which electricity sources to build and operate in the years ahead.

In the absence of the Regulations, many electricity systems will still invest in renewable electricity and will also use backup power to manage its intermittency. However, unabated natural gas is less costly than options like abated natural gas and nuclear power. Electricity operators are also familiar with natural gas technology and value its ability to be easily integrated into the grid. Despite having favourable conditions for renewable electricity deployment, Canada has also deployed comparatively lower levels of lower-cost wind and solar than many other western countries, including all other G7 countries (e.g. 7% of Canada’s electricity mix is wind and solar compared to 39% in Germany, 34% in the UK, 15% in the U.S.). For these reasons, without the Regulations, more unabated natural gas would continue to be built and deployed to meet growing electricity demand. Without additional action, some modelling shows that in a scenario with higher demand growth, electricity emissions could more than double by 2050 (relative to 2025 levels) [see Figure 3].

Cost-benefit statement: The costs and benefits of the Regulations are measured against a Baseline Scenario (i.e. without the Regulations in place) where electricity is supplied by emitting sources beyond 2050. In both the baseline and regulatory scenarios, electricity demand grows by approximately 50% by 2050 based on policies and measures in effect today and expected population growth.

This Baseline Scenario comes from a modified version of the Department’s 2023 Current Reference Case (Ref23), which is a projection for GHG emissions in Canada that includes all federal, provincial and territorial policies and measures that are funded, legislated and implemented up to August 2023 (including the suite of announcements from Budget 2023). In order to make the projection as up-to-date as possible when analyzing the impacts of the Regulations, Ref23 was modified for this analysis to include the federal Electric Vehicle Availability Standard, alongside the suite of Budget 2024 announcements and federal investment tax credits (ITCs) that pertain to the electricity sector.

The Regulations will reduce the electricity sector’s greenhouse gas emissions by an estimated 181 million tonnes from 2024 to 2050 relative to a Baseline Scenario that does not include these Regulations; those reductions help limit excessive CO₂ emissions that lead to global damage caused by climate change. By accelerating the uptake of renewable electricity, the Regulations also cut air pollution, reducing Canadians’ exposure to pollutants like nitrogen oxides, sulfur oxides, particulate matter, and mercury. This results in benefits to local air quality and to Canadians’ health. Finally, the Regulations will deliver cost savings to the electricity sector through avoided fuel and maintenance costs from the increased use of renewable electricity. In total, these benefits are valued at $54.9 billion, or a $2.7 billion annualized average benefit.

Under Baseline (i.e. without the Regulations), the required costs to build and maintain Canada’s electricity system to meet expected growth in demand is estimated to be approximately $690 billion between 2024 and 2050 in present-value terms. The Regulations will result in $40.3 billion in costs over the 2024–2050 time period, or a $1.9 billion annualized average cost. This includes capital costs to build more clean electricity capacity, refurbishment and maintenance costs, the purchase of offsets, and administrative costs. Some of these costs will be passed on to consumers in the form of electricity rates. However, clean electricity can generate new revenue in the electricity system that offsets other costs (e.g. renewable electricity generators can generate valuable credits in Alberta’s carbon market and electricity generators can realize profits from exporting electricity). Federal analysis, corroborated by third-party studies, finds that the impacts of the Regulations on electricity rates prior to 2050 are expected to be minor, or even neutral, relative to the costs of a growing electricity sector that will occur with or without the Regulations. In 2050, the full range of modelling suggests that electricity rate impacts are expected to be modest. It should be noted that rates are expected to increase over time with or without the Regulations. This analysis looks only at the incremental difference between how much rates increase in a Baseline Scenario, without the Regulations, and a policy case where the Regulations are in place.

Overall, relative to the Baseline Scenario, the Regulations are estimated to deliver a net benefit of $14.6 billion.

To consider a scenario of higher electricity demand growth, this analysis also includes a higher electrification scenario where electricity demand approximately doubles. Under this scenario, the benefits of (GHG reductions from the Regulations will be even greater, and, despite increased electricity system costs, overall energy cost savings to households and business due to electrification would also be expected to increase.

Description: The Regulations will prohibit excessive emissions from fossil fuel-fired electricity generation, while providing flexibility to enable provinces and territories to continue providing reliable and affordable electricity to Canadians. Prohibiting excessive emissions in Canada’s electricity sector is fundamental to achieving the economy-wide goal of reaching net-zero by 2050.

Requirements to reduce emissions under the Regulations start in 2035 and reach net-zero in 2050. They achieve emission reductions by prohibiting emissions above an annual emissions limit for all covered electricity generating units, based on each unit’s electricity generation capacity.

The Regulations are technology-neutral and also include limited compliance flexibility mechanisms that adjust the scope of the prohibition to limit negative impacts on grid stability or disproportionately increasing compliance costs and therefore electricity prices. Operators can select the best path to meet their obligations. This flexibility includes providing access to prescribed offset credits, adopting more limited coverage of emissions from cogeneration relative to the approach taken in the draft Regulations, allowing operators within a jurisdiction to be issued, bank, and transfer (transferring was discussed as “pooling” during engagement) compliance credits until 2050. Also as a flexibility, natural gas units that are commissioned before 2025 or planned before 2025 and commissioned before 2028 have a maximum of 25 years from their date of commissioning before they are subject to the prohibition.

Issues

There is an urgent global need to address climate change and move towards a low-carbon economy. Greenhouse gases (GHGs) are primary contributors to climate change, and decreasing GHG emissions in all sectors, including electricity, is necessary to address the threat of climate change to the environment (e.g. extreme weather events, ocean acidification, sea-level rise, floods, wildfires) and to reach the Government of Canada’s GHG emissions reduction target of 40–45% below 2005 levels by 2030 and net-zero emissions economy-wide by 2050.

As reported in Part 3 of the National Inventory Report 1990-2022: Greenhouse Gas Sources and Sinks in Canada (2022 NIR), “public electricity and heat production”^{footnote 4} accounted for 56 megatonnes (Mt) ^{footnote 5} of GHG emissions in terms of carbon dioxide equivalent (CO₂e) in 2022, nearly 8% of Canada’s total, with the majority of those emissions originating from Alberta, Saskatchewan, Nova Scotia, Ontario, and New Brunswick. Excessive GHG emissions from national electrical generation will contribute to the environmental risks associated with climate change as other key economic sectors such as transportation and buildings electrify over the coming decades, and as populations grow. To prevent GHG emissions from increasing in the electricity sector as other sectors electrify, it is increasingly important that Canada’s electricity be generated from low or non-emitting sources while remaining affordable and reliable for Canadian households and the economy. Regulations are needed to prohibit excessive emissions and ensure that by 2035, Canada’s electricity system is on track to contribute to the goal of economy-wide net-zero emissions by 2050.

In addition, a significant portion of existing capital infrastructure throughout Canada’s electricity system is nearing the end of its useful technical life and will require replacement or refurbishment in the coming years. Therefore, as routine investments and upgrades are made in the coming years, there is an opportunity to ensure that Canada’s electricity system accelerates its movement away from sources of electricity generation that involve excessive emissions, to contribute to the fight against climate change and advance Canada’s climate goals and commitments.

Background

Harms of climate change and global push to achieve net-zero GHG emission economies

As detailed in the Synthesis Report for the Intergovernmental Panel on Climate Change’s Sixth Assessment Report (AR6 Report), human activities (primarily through emissions of GHGs) have unequivocally contributed to global warming, with global surface temperatures reaching 1.1 degrees Celsius (°C) above 1850–1900 levels in 2011–2022 and such temperatures increasing faster since 1970 than in any other 50-year period over the last two millennia. Due to shortfalls in implemented policies and finance flows worldwide, the AR6 Report concludes that warming is likely to exceed 1.5 °C before the end of the century and will be hard to limit to below 2 °C based on participating countries’ 2021 projections of their “nationally determined contributions” to global GHG emissions in 2030. According to the AR6 Report, in the absence of additional abatement, projected carbon dioxide (CO₂) emissions from existing global fossil fuel infrastructure alone would exceed the remaining leeway to limit warming to 1.5 °C. The AR6 Report posits that modelled pathways that do limit warming to 1.5 °C, as well as those that limit warming to 2 °C, all involve deep, rapid, and, in most cases, immediate GHG reductions across all sectors this decade, including the need to reach global net-zero CO₂ emissions by the early 2050s for 1.5 °C pathways and by the early 2070s for 2 °C pathways.

As of 2023, over 140 countries that make up the United Nations Net-Zero Coalition (including Canada) have communicated net-zero targets, covering an estimated 88% of global emissions. ^{footnote 6}

The AR6 Report also provides a summary of the state of knowledge on climate change and its widespread impacts and risks. For example, the report outlines how human-caused climate change has and continues to lead to widespread adverse impacts to nature and people, such as water availability and food production (fisheries yields, crop yields, animal livestock health), health and well-being (displacement, infectious diseases, mental health), biodiversity and ecosystems (changes in structure, species ranges and seasonal timing in terrestrial, freshwater and ocean ecosystems), and damage to key economic sectors and physical infrastructure from extreme weather events and storm surge. According to the AR6 Report, vulnerable communities (who have historically contributed the least to climate change) are disproportionately negatively impacted, with approximately 3.3 to 3.6 billion people living in contexts that are highly vulnerable to climate change. This impact is felt regionally for Africa, Asia, Central and South America, LDCs (least developed countries), small Islands and the Arctic. Globally, this impact is felt by Indigenous Peoples, small-scale food producers and low-income households. The AR6 report finds that human mortality from floods, droughts and storms has been 15 times higher between 2010 and 2020 in regions with very high vulnerability than regions with very low vulnerability.

There are also direct impacts of climate change on Canadians. The Department of Public Safety maintains the Canadian Disaster Database (CDD), which tracks significant disaster events meeting one or more specified criteria (e.g. 10 or more people killed, 100 or more people injured or evacuated, need for outside assistance, historical significance) and provides normalized cost estimates, where available, in 2016 Canadian dollars for events that occurred between 1900 and 2016. ^{footnote 7} A summary of the frequency and costs of a subset of these natural disasters are presented in Table 1.

Table 1: Summary of “Meteorological – Hydrological” natural disasters in Canada as reported in the CDD, 1970 to 2016
	Total count (in brackets: count of events with known costs)	Total count (in brackets: count of events with known costs)	Total count (in brackets: count of events with known costs)	Total cost of events with known costs in millions of 2016 dollars	Total cost of events with known costs in millions of 2016 dollars	Total cost of events with known costs in millions of 2016 dollars
Time Period	1970–1985	1986–2000	2001–2016	1970–1985	1986–2000	2001–2016
Storms^{table c1 note a}	55 (17)	65 (45)	111 (94)	$391	$9,380^{table c1 note c}	$2,646
Floods	74 (30)	79 (59)	93 (87)	$841	$2,800	$7,545
Wildfires	2 (0)	26 (8)	63 (61)	-	$206	$5,793
Phenomena^{table c1 note b}	31 (9)	27 (18)	20 (16)	$172	$2,577	$889
Total	162 (56)	197 (130)	287 (258)	$1,404	$14,964	$16,874
Table c1 note(s) Table c1 note a For the purpose of this summary table, "Storms" encompasses the following categories from the CDD: Geomagnetic Storm, Hurricane / Typhoon / Tropical Storm, Storm — Unspecified / Other, Storm Surge, Storms and Severe Thunderstorms, Winter Storm. Return to table c1 note a referrer Table c1 note b For the purpose of this summary table, "Phenomena" encompasses the following categories from the CDD: Avalanche, Cold Event, Drought, Heat Event, Tornado. Return to table c1 note b referrer Table c1 note c Of this value, 74% ($6,921 million) is attributable to the subcategory "Winter Storm" in the years 1998 and 1999. Return to table c1 note c referrer

As calculated from the information in Table 1, amongst reported events, the total frequency of storms, floods, and wildfires in Canada has increased over time, with a rate of growth of 71%, 18%, and 142%, respectively, between the 1986–2000 time period and the 2001–2016 time period. Between those same time periods, the total reported cost (for events with known costs) increased nearly threefold for floods, and more than 28-fold for wildfires. Over the 2001–2016 time period, the total reported cost associated with 258 discrete events was nearly $17 billion, or an average cost of $65 million per event.

The rate at which climate change-related costs are climbing in Canada is expected to continue to increase over time. In 2020, the Canadian Climate Institute published The Costs of Climate Change: A Series of Five Reports (CCI Climate Change Reports) to better understand potential cost impacts to Canada and individual households. According to the CCI Climate Change Reports, the cost of weather-related disasters and catastrophic events between 2010 and 2020 amounted to 5–6% of the growth in Canada’s annual Gross Domestic Product (GDP), compared to around 1% in previous decades, with climate-induced damages projected to stifle GDP growth by 50% of modelled 2025 levels, or $25 billion annually. By the end of the century, the CCI Climate Change Reports indicate that flood damages to homes and buildings could cost nearly $14 billion annually, and that ground-level ozone levels could increase hospitalizations and premature deaths at an annual cost of around $250 billion. The CCI Climate Change Reports conclude that proactive climate change adaptation actions can dramatically reduce the projected costs of climate change to Canada and individual households, especially when combined with global emissions reductions.

Canada’s performance and commitments to reducing GHG emissions

As reported in Part 1 of the 2022 NIR, Canada’s GHG emissions totaled 708 Mt of CO₂e in 2022, representing an increase of 9.3 Mt (1.3%) above 2021 levels but a decrease of 54 Mt (7.1%) below 2005 levels. By some accounts, Canada’s CO₂e emissions in 2022 represented the 11th highest amount worldwide (after China, the US, India, Russia, Brazil, Indonesia, Japan, Mexico, Iran, and Saudi Arabia) and the 11th highest amount on a per-capita basis (after Qatar, Bahrain, Brunei, Kuwait, Trinidad and Tobago, United Arab Emirates, Oman, Mongolia, Saudi Arabia, and Australia). ^{footnote 8}

Canada is party to several international accords and commitments with respect to GHG emissions reductions, the most significant of which is the Paris Agreement, a legally binding international treaty on climate change adopted by 196 parties at the 2015 United Nations (UN) Climate Change Conference. This landmark multilateral agreement set the shared goal of limiting the increase in global average temperatures to below 2 °C above pre-industrial levels and to pursue efforts to limit this increase to 1.5 °C. Pursuant to the Paris Agreement, Canada has implemented the following initiatives in collaboration with provinces, territories, Indigenous communities, advisory bodies, and other interested parties:

The Pan-Canadian Framework on Clean Growth and Climate Change in 2016, which set an emissions reduction target across all provinces and territories of 30% below 2005 levels by 2030 and included more than 50 measures to reduce GHG emissions, build resilience and support climate innovation for clean economic growth.
Healthy Environment and a Healthy Economy in 2020, which set out a strengthened climate plan to meet or exceed the 30% target and included 64 enhanced or new policies, programs and investments to reduce emissions.
The Canadian Net-Zero Emissions Accountability Act (Net-Zero Act) in 2021, which enshrined Canada’s enhanced emissions reductions targets of 40–45% below 2005 levels by 2030 and net-zero GHG emissions economy-wide by 2050, and introduced new requirements to ensure transparency, accountability, and certainty of achieving these goals.
The 2030 Emissions Reduction Plan: Canada’s Next Steps to Clean Air and a Strong Economy (ERP) in 2022, which included over $9 billion in new investments and provided a sector-by-sector roadmap to reach Canada’s enhanced emissions reductions targets. The ERP is considered an evergreen plan that will adapt as new information, technologies, and partnerships emerge via progress reports as legislated under the Net-Zero Act.

Initiatives to reduce GHG emissions in Canada’s electricity generation sector

Of the 708 Mt of CO₂e emissions reported in the 2022 NIR, 8% (56 Mt) were attributable to “public electricity and heat production” ^{footnote 4}. Among the economic sectors depicted in the 2022 NIR, public electricity and heat production is one of the few to have exhibited a significant decrease in GHG emissions since 2005 (down 55% from 124 Mt in 2005). Such a significant decrease can be widely attributable to technological development (e.g. proliferation of cheaper renewable electricity) and a vast array of regulatory and non-regulatory initiatives that impact the electricity generation sector including federal ones.

Federal regulatory initiatives include:

The Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations in 2012, which impose an emissions limit of 420 tonnes of carbon dioxide per gigawatt-hour (t CO₂/GWh) of electricity produced for electricity generating units fuelled by coal, coal derivatives or petroleum coke. New units, whose commissioning date is on or after July 1, 2015, became subject to the emissions standard immediately, while existing units were required to comply with the emissions standard after a period that ranges from 45 to 50 years of operation, depending on the unit’s commissioning date.
The Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations in 2018, which increase the stringency of the emission intensity limit for conventional coal-fired electricity generation by December 31, 2029.
The Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity in 2018, which impose an emission intensity limit of 420 t CO₂/GWh for new or significantly modified electricity generating units fuelled by natural gas. New units of certain size, whose commissioning date is on or after January 1, 2021, became subject to the emission intensity limit immediately, while existing units are not required to comply with the emissions standard.
The Output-Based Pricing System Regulations (OBPSR) establish a carbon pollution pricing system for industrial sectors including the electricity sector. The OBPSR includes emissions-intensity output-based standards for a wide range of industrial activities. Facilities subject to the system calculate an emissions limit using the applicable output-based standards and their level of production. Emissions limits for the electricity sector are determined using fuel-specific output-based standards (t CO₂e/GWh) and the facility’s production. If a facility’s actual emissions exceed the limit, the regulatee must provide compensation for the difference by paying the excess emissions charge ($80/tonne of CO₂e in 2024, increasing by $15 per year to $170/tonne of CO₂e in 2030) and/or by remitting compliance units including surplus credits and recognized offset credits. A facility earns surplus credits when its actual emissions are below its limit. Surplus credits can be sold or banked to meet future compliance obligations. For the electricity sector, the applicable output-based standards are 538 t CO₂e/GWh for solid fuel (e.g. coal) in 2024 (decreasing linearly to 370 t CO₂/GWh by 2030), 550 t CO₂/GWh for liquid fuel (e.g. light or heavy fuel oil), and 370 t CO₂e/GWh for gaseous fuel (e.g. natural gas). For electricity production from gaseous fuel meeting certain criteria, with a commissioning date on or after January 1, 2021, the standard is 247 t CO₂e/GWh in 2024, decreasing linearly to 0 t CO₂e/GWh in 2030. In general, in jurisdictions where the OBPSR is in effect, the OBPSR applies to all fossil fuel-based electricity generating facilities with annual emissions at or above 50 kt CO₂e per year on a mandatory basis. Facilities emitting 10 kt CO₂e per year or more may apply to voluntarily participate. As of August 2024, the federal OBPSR applies in Prince Edward Island, Manitoba, Yukon, and Nunavut. All other provinces and territories operate their own industrial carbon pricing systems that meet the federal minimum national stringency standards for carbon pricing (“benchmark criteria”); some of these provincial or territorial approaches to carbon pricing have differing approaches to the electricity sector compared to the federal approach.

Federal non-regulatory initiatives include:

The Canada Growth Fund, a $15 billion arm’s length investment fund designed to spark private investment in low-carbon projects, technologies, businesses and supply chains. As of June 2024, the Fund has invested $340 million in three clean energy and clean technology projects, and has issued around $1 billion of its $7 billion allocation for “carbon contracts for difference” and carbon offtake agreements. In December 2023, the Fund announced a strategic investment in Entropy, a Calgary-based developer of carbon capture and storage (“CCS”) projects with the potential to significantly reduce emissions in Canada and worldwide.
The Canada Infrastructure Bank, which makes investments in projects that reduce GHG emissions and support economic growth, such as clean power. As of August 2024, the Bank had approximately $13 billion in current investments, financing projects collectively worth approximately $36 billion in total capital value. Of the 71 projects listed on the Bank’s website, 12 relate to clean power, one of which is Oneida Energy Storage LP, a joint venture between NRStor, Six Nations of the Grand River Development Corporation, Northland Power, and Aecon Concessions. The project will provide clean, reliable power capacity by drawing and storing renewable energy during off-peak periods and releasing it to the Ontario grid when energy demand is at its peak. The facility is expected to provide significant benefits to Ontario’s ratepayers by reducing the need and cost associated with using gas-fired power plants during times of peak demand. The project is estimated to help Ontario reduce GHG emissions by 1.2 Mt over the project life.
The Strategic Innovation Fund, which supports large-scale, transformative and collaborative projects across a multitude of sectors, including electricity. As of August 2024, the Fund has allocated $9.5 billion to 129 projects, including $189 million to 7 clean power projects with total project costs of $677 million. For example, the Fund invested $30 million in Hitachi Energy Canada, a three-year project which will include building a new state-of-the-art transformer test laboratory in Varennes, Quebec, in addition to expanding capabilities for high-voltage direct current (HVDC) technologies.
The Smart Renewables Electrification Pathways Program, which provides $4.5 billion until 2036 to support projects supplying clean, affordable and reliable power to Canadian electrical grids. As of November 2024, the Program has allocated nearly $890 million to announced projects with total project costs of $3.8 billion. One such project is the partially First Nations-owned Barlow Solar Park, a 27-MW solar farm located in Calgary, Alberta. This project deploys renewable energy and grid modernization technologies to support the supply of clean energy to the Alberta electricity grid, reducing GHG emissions by approximately 22 000 tonnes of CO₂e a year.
A suite of major economic investment tax credits (ITCs), including those which target the electricity sector, which will help achieve a net-zero economy:
- The Clean Technology ITC, a refundable tax credit for business investments in certain low-emitting electricity generation equipment, stationary electricity storage, low-carbon heating, and non-road zero-emission vehicles and related charging and refueling infrastructure. The Clean Technology ITC rate is 30% for eligible property that is acquired and that becomes available for use from March 28, 2023, to December 31, 2033, and is 15% for property that is acquired and that becomes available for use in 2034; it will be unavailable after 2034.
- The proposed Clean Electricity ITC, a 15% refundable tax credit for eligible investments in certain low-emitting electricity generation systems; stationary electricity storage systems; and transmission of electricity between provinces and territories. This tax credit would be available for property that is acquired and becomes available for use on or after the day of Budget 2024 for projects that did not begin construction before March 28, 2023. The credit would no longer be in effect after 2034.
- The Carbon Capture, Utilization, and Storage ITC, a refundable tax credit on eligible investments in CCUS projects, may also support investments in abated generation projects. From 2022 through 2030, the investment tax credit rates are set at: 60% for investment in equipment to capture CO₂ in direct air capture projects; 50% for investment in equipment to capture CO₂ in other CCUS projects; and 37.5% for investment in equipment for transportation, storage and use. Credit rates are reduced by half beginning in 2031 and no longer available after 2040.

Provincial and territorial initiatives:

Provinces have taken a number of important actions to move towards a cleaner electricity grid. Ontario began phasing out coal-fired electricity in the early 2000s and completed the phase-out in 2014. Ontario has also recently completed the largest ever Canadian procurement of energy storage capacity. Alberta finished phasing out coal power in 2024, several years ahead of its 2030 commitment. In recent years, Alberta has also been a leader in the deployment of wind and solar power. Saskatchewan has been a leader in the deployment of CCS technology in the electricity sector. In 2014, Boundary Dam Unit 3, a coal-fired electricity unit in Saskatchewan, became the first power station to successfully use CCS technologies. Nova Scotia has built the undersea Maritime Link transmission line, which enables Nova Scotia to reduce its reliance on electricity from fossil fuels by importing clean hydropower from Newfoundland and Labrador. By 2022, Nova Scotia had reduced its use of coal power by over 50% compared to 2008. New Brunswick has been exploring the conversion of its Belledune coal plant to fire biomass. In October 2023, the Governments of Canada, New Brunswick and Nova Scotia agreed to a Joint Policy Statement on Developing and Transmitting Clean, Reliable and Affordable Power in Nova Scotia and New Brunswick, which includes advancing a new intertie between the provinces. The provinces of Alberta, Saskatchewan, Ontario and New Brunswick have signed a memorandum of understanding (MOU) to collaborate on the development and deployment of small modular reactors (SMR). Building on their strong history of building and operating conventional nuclear facilities, Ontario and New Brunswick are expected to be the first provinces in Canada to have SMRs provide electricity to their grids.

Several provinces, including British Columbia, Manitoba, Quebec, and Newfoundland and Labrador already generate most electricity from renewable resources, largely due to abundant hydro resources. Hydroelectricity forms the backbone of their grids, and these provinces have continued to advance key projects to take advantage of Canada’s clean hydro advantage and expand other renewables. British Columbia’s Site C dam began generating power in 2024 and, once fully operational by 2025, it is expected to increase the province’s power production capacity by around eight per cent. Manitoba’s 695 MW Keeyask Generating Station was completed in 2022 and supports the continued provision of clean and affordable electricity in the province. The Muskrat Falls hydroelectric project in Newfoundland and Labrador was completed in November 2021 and included two main transmission lines, the Labrador-Island Link, which connects Labrador to Newfoundland (completed in 2023) and the Maritime Link, built by Nova Scotia, which connects Newfoundland to Nova Scotia (completed in 2017). Quebec is advancing wind power with a target of developing over 10 000 MW of new wind power generation by 2035. Meanwhile, Prince Edward Island generates most of its in-province electricity from wind and solar and relies on New Brunswick for electricity imports.

The Territories face unique circumstances when it comes to developing and expanding clean electricity as all three Territories are currently not connected to the broader North American electricity grid. Yukon and the Northwest Territories generate most of their electricity from hydro. Nunavut and most northern and remote communities in the other Territories are reliant on diesel generation of electricity.

Moving forward, a net-zero economy will require far more electricity than we use today: to cut GHGs, households and businesses will increasingly switch from fossil fuels to using energy in the form of electricity. For example, electric vehicles displace vehicles with internal combustion engines; buildings are heated with heat pumps rather than natural gas or oil; and electricity provides energy for a growing number of heavy industry applications. As a result, the impact of these Regulations will be felt far beyond the electricity sector itself, as these Regulations support emission reductions across Canada’s economy.

Canada’s electricity system: composition, generation, emissions, and technologies

Part 3 of the 2022 NIR provides a detailed breakdown of electricity generation and associated GHG emissions by province, using the Intergovernmental Panel on Climate Change’s (IPCC) sector definitions. In Canada, public electricity and heat production generated 584 000 GWh of electricity in 2022, emitting around 56 Mt of CO₂e. Of the electricity generated that year, around 15% came from the use of emitting sources (coal, natural gas, refined petroleum products, biomass and other), while the remaining 85% came from non-emitting sources (nuclear, hydro, wind, solar, tidal, and other). As depicted in Table 2, there are significant differences in the generation mixes and emissions profiles for each province and territory, with the highest levels of GHG emissions in 2022 coming from Alberta (25 Mt), Saskatchewan (15 Mt), Nova Scotia (6 Mt), Ontario (5 Mt), and New Brunswick (4 Mt).

Table 2. Electricity generation, generation mix, and GHG emissions for “public electricity and heat production” by region in 2022 (as reported in Part 3 of the 2022 NIR)
Region	Electricity generation (GWh)	Proportion non-emitting generation	Proportion emitting generation	GHG emissions from emitting generation (kt CO₂e)	Emissions intensity (t CO₂e/GWh)
Newfoundland and Labrador (NL)	40 400	98%	2%	690	17
Prince Edward Island (PEI)	490	100%	0%	1	2
Nova Scotia (NS)	8 770	23%	77%	5 790	660
New Brunswick (NB)	11 900	64%	36%	3 990	330
Quebec (QC)	196 000	99%	1%	230	1
Ontario (ON)	145 000	92%	8%	5 140	35
Manitoba (MB)	37 800	100%	0%	48	1
Saskatchewan (SK)	23 700	19%	81%	14 800	630
Alberta (AB)	52 200	17%	83%	24 600	470
British Columbia (BC)	66 400	97%	3%	890	14
Yukon (YT)	570	88%	12%	39	70
Northwest Territories (NT)	320	75%	25%	59	180
Nunavut (NU)	190	0%	100%	150	780
Canada^{table c2 note a}	584 000	85%	15%	56 400	100
Table c2 note(s) Table c2 note a Totals may not add up due to rounding. The 2022 NIR reports all generation and emissions data to three significant digits. Return to table c2 note a referrer

Aside from electric utilities, there are other types of generators that produce electricity in Canada. Specifically, a subset of industrial sectors produces electricity for their own operational use “behind the fence.” Such behind-the-fence generation produces heat for industrial processes, with electricity being a co-product, and are therefore referred to as “cogeneration” units. While some of those generators use all of the electricity they produce behind the fence, others sell a portion of that electricity to Canada’s electricity system. Accordingly, the total emissions attributable to Canada’s electricity system are the emissions from electric utilities, plus the emissions from the subset of industrial cogeneration that enters the system. Departmental modelling estimates that 82 GWh of electricity were generated by cogeneration units in 2022, emitting a total of 14 Mt of GHG emissions, of which, 3 Mt were associated with electricity sold to Canada’s electricity system. In the NIR, such emissions are attributed to the sector to which the cogeneration unit belongs, such as “oil and gas extraction” or “manufacturing industries,” unless the industrial operation reports to the North American Industrial Classification System as two separate business entities.

Canada’s electricity system is composed of electricity generation units (from electric utilities and industrial cogeneration that sells a portion of the electricity they produce to the system), electricity storage, carbon capture and storage (CCS) systems, interprovincial interties, and regional transmission and distribution systems. A wide range of electricity system technologies are, or are on track to become, widely available in Canada. Such technologies, along with normalized cost estimates across select specifications, are described in Table 3.

Table 3. Electricity system technologies and select specifications for 2022 (Canada average, 2022 constant dollars)
Technology	Description	Capital cost ($/kW)^{table c3 note a}	Fixed O&M cost ($/kW per year)^{table c3 note a}	Variable O&M cost ($/MWh)^{table c3 note a}	Average fuel cost ($/MWh)^{table c3 note a}	Operating lifetime (in brackets: economic lifetime)^{table c3 note b}
OGCT	Oil/gas combustion turbine (akin to Brayton cycle)	660	6	7	21	45 (30)
OGCC	Oil/gas combustion turbine equipped with waste heat recovery system and steam turbine (akin to Brayton cycle plus Rankine cycle)	768	9	7	22	45 (30)
Small OGCC	Similar to OGCC but with lower generating capacity	782	10	3	42	45 (30)
NG CCS	Natural gas combustion turbine (typically OGCC though OGCT is possible), equipped with carbon capture and sequestration technology	1,235	16	7	61	45 (30)
OG Steam	Steam turbine (akin to Rankine cycle) generation from oil/gas combustion	2,243	33	1	36	45 (30)
Coal	Steam turbine generation from coal combustion	1,637	22	3	10	45 (30)
Coal CCS	Steam turbine generation from coal combustion, equipped with carbon capture and sequestration technology	3,212	15	3	17	45 (30)
Biomass	Thermal generation utilizing biomass as fuel	1,782	64	3	40	45 (30)
Biomass CCS	Thermal generation utilizing biomass as fuel, equipped with carbon capture and sequestration technology	4,157	82	8	177	45 (30)
Waste	Thermal generation utilizing waste material as fuel	892	263	6	170	45 (45)
Nuclear^{table c3 note c}	Steam turbine generation utilizing nuclear fission as heat source	3,908	72	2	0	60 (60)
Base Hydro	Hydroelectric projects with little or no storage (akin to run-of-river)	3,548	29	1	0	100 (40)
Peak Hydro	Hydroelectric projects with associated reservoirs, able to generate power during peak demand periods	3,424	21	1	0	100 (70)
Pumped Hydro	Hydroelectric projects that are able to store energy for later use	1,413	10	0	0	100 (70)
Small Hydro	Similar to base hydro but with lower generating capacity	3,424	32	1	0	100 (40)
Onshore Wind	Onshore wind turbines	775	28	0	0	30 (25)
Offshore Wind	Offshore wind turbines	1,887	35	0	0	30 (30)
Solar PV	Photovoltaic solar panels	693	47	0	0	30 (25)
Geothermal	Thermal generation that utilizes geothermal energy to produce steam	2,760	69	1	0	30 (25)
Wave	Process that utilizes wave motion to generate power	3,812	188	0	0	20 (30)
Storage	Varying technologies capable of consuming energy in one time period then releasing energy in another time period, with an associated efficiency loss	854	257	0	0	15 (15)
Other	Undefined emitting technologies not covered above	2,468	73	3	132	45 (30)
Table c3 note(s) Table c3 note a Normalized cost estimates are calculated using outputs from the Departmental model E3MC. For more information on this model, see the Benefits and Costs section. Return to table c3 note a referrer Table c3 note b Operating lifetime estimates and economic lifetime estimates are those used by the Departmental model NextGrid. For more information on this model, see the Benefits and Costs section. Operating lifetime denotes the number of years over which a technology is expected to operate without refurbishment, while economic lifetime denotes the number of years over which the capital costs for a given technology are amortized. Return to table c3 note b referrer Table c3 note c In the model, all endogenous new nuclear is small modular reactors (SMR). To account for needed technological advancement, such technology is restricted to come online in the model until 2035 or later. The costs for nuclear in this table therefore represent the costs for SMR in 2035, presented in 2022 dollars. Return to table c3 note c referrer

The electricity system technologies in Table 3 can be categorized into four buckets: unabated emitting generation, abated emitting generation, non-emitting generation, and storage. Certain unabated emitting generation technologies are able to reach lower-emitting profiles by incorporating “clean fuels” such as renewable natural gas (RNG) or hydrogen. Abated emitting generation technologies reach lower-emitting profiles by deploying abatement technology such as CCS, which can be purpose-built, or installed in some facilities as a retrofit.

Some emerging electricity system technologies are expected to become more widely available in Canada as those technologies continue to develop. For example, fuel cells may offer longer-term energy storage than batteries (months or years versus days or weeks) but are currently underutilized since fuel cell technology has yet to reach the economic efficiency of batteries. Certain advanced variable renewable generation technologies such as offshore wind and geothermal are anticipated to become more available within the next decade, though the utilization of these technologies is subject to geological constraints. Small modular reactors (SMR) are expected to be increasingly deployed in the future due to their compact size and expected decreasing costs over time.

Abated emitting generation, non-emitting generation and storage are all expected to contribute significantly to Canada’s net-zero electricity system, though a high degree of future technological development will be required to get there. The management of electricity systems is within the jurisdiction of provinces and territories; as such, each jurisdiction can decide which types of electricity generation to deploy within their jurisdiction.

Economic competitiveness

Clean electricity is quickly becoming a competitive necessity to attract investment. An increasing number of businesses are striving to achieve net-zero operations, not only to combat climate change but also to drive innovation and secure long-term sustainability and regulatory compliance. In parallel, economics is a major driver for electrification as technologies become cheaper and more competitive.

The International Energy Agency’s World Energy Outlook 2024 finds that global electricity demand more than doubles by 2050 in all scenarios. This means that access to abundant electricity, especially that which is clean, is an increasingly important competitive advantage for Canada. In addition to addressing the threat to the environment and human health caused by climate change, these Regulations will also, as a secondary benefit, help make Canada an attractive place to invest.

Environmental, Social, and Corporate Governance (ESG) markets are surging globally and in Canada, with growth in responsible investment being driven by climate change and investor demand for ESG impact. Global markets continue to favour low carbon products because of a lower climate risk with $30.3 trillion invested globally in sustainable investing assets. Sustainable finance trends indicate that as markets learn more about the financial impact of climate change, they internalize risks and opportunities, favouring investments with lower climate risks. Sustainable investment assets are expanding across most regions, with Canada experiencing the largest absolute growth, as responsible investment in Assets Under Management (AUM), as found by the Responsible Investment Association (PDF), surged by 94%, rising from $1.5 trillion in 2015 to $2.9 trillion in 2022. Global investor momentum to embed sustainability reporting in capital markets is observing strong effects in Canada. GHG emissions are the most common ESG factor considered in investment decisions.

Indeed, Clean Energy Canada has documented global business leaders who have publicly commented on the importance of the availability of clean power in Canada as the one of the key reasons for selecting the country for establishing new manufacturing plants. Accelerating the uptake of clean electricity in Canada could strengthen Canada’s ability to provide clean technology, such as nuclear, to the world’s growing markets.

In most jurisdictions in Canada, electricity rates are set by independent regulators. As a result, electricity prices tend to be more stable than natural gas, diesel, and gasoline prices, which reflect international commodity prices. Clean electricity can reduce the impacts of price volatility on households and the economy (Canadian Climate Institute, 2024). Both the Roosevelt Institute and the International Institute for Sustainable Development have identified the role played by fossil-fuel energy in contributing to price volatility for businesses and households. Conversely, the same research, noting the historic price stability of the electricity sector vis-à-vis the fossil fuel sector, concluded that the shift to clean electricity can create energy price stability that is good for business and households. It can avoid price shocks brought about by certain global geopolitical events (e.g. international conflicts). In essence, an abundant and readily available supply of clean electricity can mean greater energy security that is good for economic competitiveness.

Objective

The objective of the Clean Electricity Regulations (the Regulations) is to help protect the health and environment of Canadians from the threat of climate change by prohibiting excessive emissions of carbon dioxide from fossil-fuel fired electricity generation. Achieving net-zero emissions in the electricity sector will also help to decarbonize other sectors of the economy, such as transportation and buildings, and aid in Canada’s commitment to achieve net-zero GHG emissions economy-wide by 2050.

Description

The Regulations will achieve emissions reductions by prohibiting emissions above an annual emissions limit (AEL) for electricity generating units, based on each unit’s electricity generation capacity (capacity). The Regulations include compliance flexibility mechanisms that adjust the scope of the prohibition to limit negative impacts on grid stability or disproportionately increasing compliance costs and therefore electricity prices.

The Regulations apply to electricity generating units that meet the applicability criteria. A unit means an assembly of equipment that is physically connected and operates together to generate electricity and must include at least a boiler or combustion engine and may include CCS systems.

Further information on the rationale of changes in regulatory design from the proposed Regulations as published in the Canada Gazette, Part I can be found in the Regulatory Development section below.

Application

The Regulations apply to any unit that meets the three following criteria:

Uses any amount of fossil fuels to generate electricity;
Has an electricity generation capacity of 25 MW or greater (or is a new unit located at a facility where the sum of all new electricity generation unit capacity is 25 MW or greater); and
Is connected, directly or indirectly, to an electricity system that is subject to North American Electric Reliability Corporation (NERC) standards (NERC-regulated electricity system).

For greater clarity regarding the second criterion, consider the hypothetical example of a facility that was comprised of a single unit of 20 MW commissioned in 2024. This unit would not be covered by the Regulations as its capacity is below 25 MW. If a new unit of 20 MW is commissioned at the facility in 2026, that unit would also not be covered by the Regulations as the capacity of this new unit is below 25 MW. However, if a second new unit of 10 MW is commissioned at the facility in 2035, then the combined capacity of the two new units is greater than 25 MW, and both new units would need to register as per the Regulations and meet its requirements. The 20 MW unit commissioned in 2024 would continue to not be covered by the Regulations as it was commissioned before January 1, 2025, and is below 25 MW of capacity.

Annual Emissions Limit

The Regulations will prohibit emissions above an AEL for electricity generating units based on each unit’s electricity generation capacity, measured in tonnes of carbon dioxide (CO₂) per year per unit. Each AEL is calculated with an applicable emissions intensity of 65 t/GWh during the period of 2035 to 2049 (inclusive) or 0 t/GWh in 2050 and onwards, using the following formula:

$Annual
Emissions
Limit(t/year/unit) = Applicable
emission intensity(2035-2049:
65 t/GWh
2050 & later:
0 t/GWh) \times MW(Capacity of unit) \times 8760 hours(Total hours in a year) \times 0.001(Unit Conversion)$

A unit may determine its electricity generation capacity based on a performance test of the unit’s maximum gross power or, if a performance test is not completed, the unit must use the maximum continuous rating (i.e. maximum net power) reported for the unit to its electricity system operator. The performance test must be conducted in the presence of a Performance Test Verifier and under the conditions specified in the Regulations.

If a unit subject to an AEL changes its capacity mid-year, then its AEL will be prorated based on its weighted average capacity for the year. However, when a unit becomes subject to the AEL mid-year (e.g. commissioning of a new unit) or when a unit ceases to be subject to the AEL (e.g. a unit ceases to generate electricity), the unit will be subject to an AEL based on the unit’s full capacity.

Timing for the Prohibition under the Regulations

The AEL begins to apply on January 1, 2035, to all units that meet the application criteria on or after that date, with exceptions of a later date for certain units with an end of prescribed life. The AEL starts to apply on:

January 1, 2035, for units that combust coal;
January 1, 2035, for a unit that has increased its electricity generation capacity (based on its maximum continuous rating reported to its electricity system operator) by 15% or more since registration of the unit, or January 1 of the year following the capacity increase;
January 1, 2035, for a unit commissioned on or after January 1, 2025, and which is not a planned unit;
January 1, 2050, for planned units; or
On the latter of January 1, 2035, or January 1 of the calendar year in which the prohibition set out in subsection 4(2) of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity would have begun to apply for converted coal-to-gas boiler units referred to in subsection 3(4) of those regulations.
On the latter of January 1, 2035, or January 1 of the calendar year following the calendar year that is 25 years after the commissioning date, for a unit commissioned on or before December 31, 2024.

A unit is exempt from the AEL in a calendar year if, for that calendar year, the facility at which the unit is located does not produce a net (annual) supply ^{footnote 9} of electricity, either directly or indirectly, to a NERC-regulated electricity system. Moreover, if a declaration of net supply is submitted in respect of a unit, it will not be subject to the prohibition as long as there is no net supply in any given calendar year. The exemption ends on December 31 of the calendar year before the calendar year in which the net supply from the facility is greater than zero and all quantification and reporting requirements begin to apply.

Planned units

Some units that are planned (i.e. in-flight) prior to the Regulations coming into force are eligible for an end of prescribed life of December 31, 2049. For any unit commissioned between January 1, 2025, and December 31, 2034, the AEL will start to apply on January 1, 2035, except for planned units that meet the following criteria:

On or before December 31, 2025, with respect to the unit:
- All information required to initiate an impact assessment or environmental assessment has been submitted to the appropriate federal and/or provincial authority; and
- the proponent responsible for the development of the unit owns or has a lease for the land on which the unit is located; and
- all information required to initiate the process to obtain any permit required to begin construction at the site where the unit is located has been submitted to the relevant authority; and
- the project proponent has entered into contracts totalling a minimum of $10 million for major equipment ^{footnote 10} pertaining to the unit; and
On or before December 31, 2027
- construction has begun at the site where the unit is located.

The Minister must be satisfied that all of the relevant criteria were met by the planned unit at the time of its commissioning and that the registered unit is substantially the same as the planned unit.

Early Opt-in

Units that have not yet reached their end of prescribed life may opt to become subject to the AEL prior to their end of prescribed life, but no earlier than January 1, 2035. As explained in the section below on compliance credits, these units — like all units subject to the AEL in a given year — would be eligible to be issued relevant compliance credits as of their new end-of-life date.

Compliance with the Prohibition

The Regulations set out the manner for determining compliance with a unit’s AEL in a calendar year. In general, for each unit, an operator would need to determine the unit’s total emissions, which can be determined using either a fuel-based method or a continuous emissions monitoring system (CEMS). A unit’s total emissions include, as applicable:

The quantity of emissions produced by the combustion of fossil fuels for electricity generation; and
The quantity of emissions associated with the production of any prescribed energy carrier that is used by the unit to produce electricity, regardless of the location or supplier.

The unit’s total emissions can exclude the quantity of emissions captured by a CCS system only if these emissions are permanently stored in a storage project that meets criteria set out in the Regulations.

To simplify quantification, a unit subject to an AEL may choose to assign a value of zero for the emissions allocated to electricity used onsite, for the emissions from the production of useful thermal energy, for emissions captured by a CCS system, or for emissions during an emergency period.

There are a number of compliance flexibility mechanisms that adjust the scope of the prohibition and are elaborated upon below.

Canadian Offset Credits

Between 2035 and 2049, inclusive, a unit may emit up to 35 t/GWh above the AEL’s applicable emission intensity by remitting an equivalent amount of eligible offset credits (i.e. Canadian offset credits). Beginning in 2050, a unit may emit up to 42 t/GWh above the applicable emission intensity, provided it remits an equivalent amount of Canadian offset credits. The increase in allowed eligible offset credits enables increased flexibility in achieving net-zero emissions by 2050, recognizing that the AEL’s applicable emission intensity changes from 65 t/GWh to 0 t/GWh in that year.

A unit’s maximum annual use of Canadian offset credits would be calculated using the following formula:

$Maximum Annual Use of
Canadian Offset Credits(t/year/unit) = Applicable offset
emission intensity(2035-2049:
35 t/GWh
2050 & later:
42 t/GWh) \times MW(Capacity of unit) \times 8760 hours(Total hours in a year) \times 0.001(Unit Conversion)$

Only offset credits issued under the Canadian Greenhouse Gas Offset Credit System Regulations and provincial offset credits recognized for use under the federal Output-Based Pricing System Regulations would be considered Canadian offset credits under the Regulations. In addition, the GHG reductions or removals must have occurred no more than 8 calendar years before the calendar year for which the credit is remitted.

Since other federal regulations also enable the use of Canadian offset credits, the Regulations establish that regulatees would be permitted to use Canadian offset credits to meet coinciding obligations under eligible systems and the Regulations if the following conditions are met:

The offset credits are used for compliance under the carbon pricing regime for the same year;
The offset credits are used for compliance under the carbon pricing regime in relation to the same unit; and
The offset credits are used to fulfill a requirement under the carbon pricing regime other than for a requirement that relates to an extraordinary situation, such as to replace a cancelled credit or as compensation for non-compliance with a requirement.

The Department will establish a list of eligible provincial carbon pricing systems where cross-recognition for these Regulations are authorized. The eligible federal system is a system for pricing GHG emissions established under Division 1 of Part 2 of the Greenhouse Gas Pollution Pricing Act. While the Regulations do enable the cross-recognition of these credits for multiple compliance obligations, this depends on other federal and provincial regulations allowing cross-recognition of one offset credit to account for the same tonne of CO₂ equivalent emitted.

In the reconciliation report, due by December 15 following the compliance year, the responsible person for a unit can remit up to the limited number of Canadian offset credits in order to comply with their compliance obligations for that compliance year. This can include Canadian offset credits that meet the criteria of cross-recognition. If, however, the Minister later determines that an offset credit was remitted that did not meet the criteria of cross-recognition, the responsible person would need to remit the relevant number of replacement offset credits by the deadline set out in the Regulations. If, within five years after remitting a Canadian offset credit to the Minister, the issuing province cancels that Canadian offset credit, the Minister must notify the responsible person of the number of Canadian offset credits that were cancelled by the province and the number of replacement Canadian offset credits that the responsible person must remit to the Minister.

Compliance credits: Issuance, remittance, banking and pooling

A unit may emit GHG emissions above its AEL by remitting eligible compliance credits equivalent to the amount of CO₂ emissions above its AEL. These credits are remitted through the reconciliation report for the unit with respect to the relevant compliance period. This flexibility is only available until December 31, 2049, and is in addition to the unit’s available allowance for applicable Canadian offset credits from 2035 to 2050.

As of the 2050 compliance year, all units to which the Regulations apply will be subject to an AEL with an applicable emissions intensity set to 0 t/GWh. Compliance credits will no longer be issued and cannot be remitted for a compliance year after the 2049 compliance year. Limited exceptions are available in the case of errors or omissions. However, Canadian offset credits will still be permissible in 2050 and thereafter.

Issuance and Remittance of compliance credits

All units that are subject to the prohibition in a calendar year may be eligible to be issued compliance credits equivalent to the difference between the AEL and the quantity of CO₂ emitted by that unit in the given year, where the quantity of emissions is less than the AEL. Of note, a unit will not be issued compliance credits for the calendar year it becomes subject to the AEL if it becomes subject on or after July 1 of the calendar year.

There are a number of criteria for the issuance and remittance of compliance credits. The Minister of the Environment issues compliance credits where the relevant conditions are met. Where those criteria are met, units subject to the prohibition in a given year can remit non-transferable credits issued in respect of that unit. All units subject to the prohibition in a given year are eligible for non-transferable credits; however, some units are eligible to be issued transferable credits instead (previously discussed as “pooling” during engagement). Transferable credits are described in the next section.

The timing of credit issuance, where applicable, follows the submission of a unit’s emissions report, due by the June 1 following the compliance year. In the reconciliation report, due by the December 15 following the compliance year, the responsible person for a unit can remit compliance credits in order to comply with their compliance obligations for that compliance year. This timing will provide an opportunity for credits to be issued so that they can be transferred to or from other eligible units before they are remitted.

Compliance credits may be remitted until five years after the year of their issuance. For example, a compliance credit issued in 2036 for the compliance year 2035, could only be remitted for the compliance years of 2035-2040, inclusive.

Transferable compliance credits: issuance and remittance (i.e. “pooling”)

Certain units are eligible to be issued transferable credits which that unit can either bank for its own use, or transfer to another unit that is eligible to remit transferable credits. In other words, the concept of “pooling” that was described in the winter 2024 Public Update (see Consultation section) has been operationalized through these transferable compliance credits. Remittance of transferable compliance credits ends with the 2049 compliance year.

In general, transferable compliance credits may be issued to, and remitted by, a unit if:

The unit is subject to an AEL, and
The unit was commissioned before January 1, 2030 (i.e. an existing unit or a new unit commissioned between 2025 and 2030) or is a planned unit, and
The unit does not combust any amount of coal, and
The unit does not produce useful thermal energy (e.g. cogeneration units).

Transferable credits can be transferred to any other unit subject to the Regulations, but can only be remitted (used) for a compliance year by units that were eligible to be issued transferable credits for that same compliance year and only if the transferable credit was issued to a unit which reports to the same electricity system operator as the unit remitting the credit (these units are generally within the same province). There is no limit to the amount of transferable and non-transferable credits a unit can remit in a given compliance year.

Although the Regulations limit the transfer of transferable credits between units that are subject to the Regulations, there are no requirements relating to the specifics of the transfer, such as setting prices or facilitating transfers. The responsible person for a unit must ensure the reconciliation report for the unit includes all transferable credits transferred from a unit, or received, and provide the registration number of the unit involved in that transfer. Any transferable credits included in the bank for a unit must be included in the reconciliation report of both units involved in the transfer, along with documentation with respect to the transfer. Reconciliation reports between the various units subject to the Regulations must align in the details pertaining to transferable credits. The Department will take the necessary measures to address any discrepancies.

Transferable compliance credits may only be remitted until five years after the year of their issuance and a unit cannot borrow compliance credits from the future. Additionally, new units may also be eligible to be issued transferable credits as per the swapping provisions described below.

Swapping the eligibility to issue and remit transferable credits

As noted above, only specified units are eligible to be issued and remit transferable credits. However, other units subject to an AEL can be issued, and then transfer and remit transferable credits if an existing unit that is eligible to be issued transferable credits designates it as a substitute unit (i.e. the units “swap” the ability to be issued transferable credits). The substitute unit must meet the following criteria:

The electricity generating capacity of the unit being “swapped in” must not exceed the electricity generating capacity of the unit being “swapped out”; and
The unit being “swapped” must report to the same electricity system operator.

Additionally, the substitute unit will only be issued transferable compliance credits if:

The substitute unit does not combust any amount of coal in the compliance year; and
The substitute unit does not have a commissioning date before January 1, 2025, or is not a planned unit, if it is a unit that produced useful thermal energy in the compliance year (e.g. existing and planned cogeneration units).

Once units have swapped, the unit that is “swapped in” (the substitute unit) would only cease to be a substitute if another eligible unit is designated in its place. To swap back into the pool, a unit must complete the steps to swap with a unit that is in the pool, subject to all the requirements of the swapping provisions. Furthermore, units must swap for complete compliance years (i.e. they cannot swap mid-year). The responsible person for both units must inform the Minister of the Environment of a swap before the start of the compliance year in which they wish the swap to apply.

Banking of compliance credits

Units that are issued compliance credits can bank them for use in future years up to and including the 2049 compliance year, or until five years after the issuance of the compliance credit, whichever comes first. Units may not, however, borrow compliance credits from the future.

Cogeneration

Like all units subject to the Regulations, units that produce useful thermal energy (“cogeneration units”) are only subject to the prohibition in calendar years where the facility in which the unit is located produces a net supply of electricity to a NERC-regulated electricity system. Additionally, the AEL of a cogeneration unit is based on the electricity generation capacity of the unit, either demonstrated through a maximum gross power performance test or as reported to the electricity system operator.

Unchanged from the proposed Regulations, any unit that produces useful thermal energy (e.g. steam which is not used to generate electricity) may subtract from its total annual emissions the emissions allocated to the production of that useful thermal energy.

For the 2035 to 2049 compliance years, for the purpose of determining compliance with their AEL, existing cogeneration units (commissioned before January 1, 2025, or those that qualify as planned units), will be able to deduct the emissions allocated to the generation of electricity that is used onsite from the unit’s total emissions. This deduction is never available for new units (commissioned on or after January 1, 2025, and that are not planned units). As of 2050, the deduction is no longer available for existing and planned units.

Emergencies

The emissions from the unit during periods of emergency circumstances can be deducted from the emissions total for the unit in a compliance year, if the relevant conditions are met. Additionally, electricity generation during periods of emergency circumstances can be deducted from a facility’s net supply. The deductions available for this period are not relevant to the calculation of a unit’s AEL (i.e. the AEL will always be calculated on an 8 760-hour basis).

During an emergency circumstance, the electricity system operator may direct a unit to operate if there is a disruption, or significant risk of disruption, to the electricity supply in the province (or a contiguous province or state) where the unit is located. This disruption, or significant risk of disruption, must have been triggered by the emergency circumstance. The responsible person must notify the Minister within seven days of receiving the direction to operate. There are two types of emergency circumstances:

an irresistible emergency event, determined by the electricity system operator, which is natural or arises from human action. The irresistible emergency event must be outside the control of the electricity system operator and the responsible person for the unit, and
a risk to human health and safety, of any duration, determined by the Minister of the Environment.

The emissions and net supply deductions are only allowed if the unit’s electricity generation will alleviate, or materially help alleviate, the disruption, or risk of disruption, to the electricity supply. The deduction can be made for a period of up to 30 days or until the disruption or risk of disruption has ended. The responsible person for the unit may apply for an extension from the Minister of the Environment before the end of the 30 days if the conditions arising from the emergency circumstances persist. If an extension is granted by the Minister, the deduction period will be extended for a period set out in the Regulations. If the application is denied, the deduction will extend for another 15 days after the 30th day or until the direction to operate by the electricity system operator ceases to apply, whichever comes first.

Units for which a declaration of net supply has been submitted must also comply with these emergency circumstances requirements to benefit from the deduction from their net supply due to an emergency circumstance.

Energy carriers

A unit’s total emissions include all emissions associated with the generation of electricity from fossil fuel. This includes both CO₂ emissions from the direct combustion of fossil fuel in the unit as well as CO₂ emissions from the production of hydrogen, ammonia, or purchased or transferred steam that are used in the unit for the generation of electricity. In the Regulations, these indirect sources of CO₂ emissions are collectively referred to as “energy carriers” which can be converted to other forms of energy such as electricity. An example of the production of an energy carrier from fossil fuels as covered by the Regulations would be the production of hydrogen from natural gas. Emissions are attributable to the unit in accordance with the Regulations if the energy carriers are produced outside the unit.

For clarity, the emissions associated with energy carriers do not include emissions that are upstream of an energy carrier’s production. For example, the emissions associated with producing the natural gas fuel/feedstock used in the production of hydrogen from steam methane reforming, or the emissions associated with the generation of electricity used in the production of hydrogen through electrolysis, are not included.

Indirect accounting of renewable natural gas

The unit’s total emissions will exclude the emissions associated with the combustion of biomass, including renewable natural gas (RNG), that occurred directly in the unit.

The unit’s total emissions will also exclude emissions from RNG that has been blended into a North American natural gas pipeline network that is physically connected to the unit using the fuel, if the volume of RNG is specified in a contractual agreement and all of the necessary conditions in the Regulations are met. This type of indirect accounting system recognizes the carbon neutral attributes of purchased low-emitting fuels for compliance purposes without requiring all physical molecules of the fuel purchased to be combusted directly in the electricity generation unit.

Registration and Reporting

The Regulations require all units that meet the applicability criteria to submit a registration report. The applicability criteria are that a unit i) has a capacity of at least 25 MW, ii) generates electricity using fossil fuels, and iii) is connected to an electricity system subject to the standards of NERC. The registration report must be submitted by the later of December 31, 2025, or 60 days after the day that the unit meets all three of the applicability criteria. The registration report includes information such as identification of the responsible person; the location and name of the unit and facility; a process diagram of the unit, including the commissioning date of each boiler or combustion engine; the commissioning date of the unit and the unit’s electricity generating capacity. Where applicable, documentation demonstrating that a unit is a planned unit must be submitted with the registration report.

Obligations to submit emission reports and reconciliation reports apply as of the calendar year that the prohibition begins to apply to the unit. The one exception to this timing (i.e. of the calendar year that the prohibition begins to apply) is for a short reconciliation report where a unit holds any transferable or non-transferable compliance credits in a calendar year before the prohibition has begun to apply to that unit.

The Regulations require all units that are located at a facility that produces a net annual supply of electricity to a NERC-regulated electricity system and that are subject to an AEL in a compliance year to submit an annual emissions report by June 1 of the year following the compliance year. The emissions report includes all information relating to the facility’s net supply, the unit’s total annual emissions in the compliance year and information required for the issuance of compliance credits. These same units are also required to submit an annual reconciliation report by December 15 of the year following the compliance year that includes information on Canadian offset credits being remitted, information on compliance credits that are being remitted or banked, as well as information on any tradeable compliance credits that were transferred or received. For clarity, the total emissions reported in the emissions report can exceed the unit’s AEL as long as the necessary credits are remitted in the reconciliation report to account for the difference. Remittance must be done in accordance with the rules and limitations with respect to the use of each of the Canadian offsets credits and compliance credits.

For units for which the prohibition has begun to apply, if the unit is located at a facility that did not have a net supply and is not subject to an AEL in a compliance year, a short emissions report is required that includes all information relating to the facility’s net supply. These units must quantify their emissions and keep all relevant records but are not required to report on those emissions. A short reconciliation report is also required for any unit that holds any transferable or non-transferable compliance credits in a calendar year, as mentioned above. The short emissions report and short reconciliation report are due by June 1 and December 15, respectively, of the year following the year which is the subject of the report.

If the intent is for a facility in which the unit is located to maintain a net supply of zero or less, the responsible person for that unit may choose to submit to the Minister a declaration of net supply for the unit. The declaration must be submitted within 12 months before the prohibition would apply to the unit. So long as the facility does not have a net supply, the unit is exempt from quantifying its emissions. A short emissions report including information on the facility’s net supply, including any applicable emergency circumstance deduction, is still required. The exemption ends on December 31 of the calendar year before the calendar year in which the net supply from the facility is greater than zero and all quantification and reporting requirements begin to apply.

Errors and Omissions

If due to an error or omission, too many compliance credits were issued to a unit, then the responsible person for the unit must remit to the Minister of the Environment a number of replacement credits that is equal to the difference between the number of compliance credits issued and the number that should have been issued. The replacement credits must be remitted in the following order of precedence:

Compliance credits issued in respect of the same unit and the same calendar year for which there was an error or omission;
If there is an insufficient number of compliance credits, any other compliance credit held for that unit on the day that the error or omission notice was submitted to the Minister;
If an insufficient number of compliance credits described above are held for the unit, then the responsible person can remit:
- any Canadian offset credit that was issued for emissions reductions or removals that occurred no more than eight years before the calendar year in which the Canadian offset credit is being remitted, and must not exceed the unit’s offset limit for the relevant calendar year, or
- any transferable compliance credit that was issued no more than five years before the calendar year in which it is being remitted if that credit was issued to a unit which reports to the same electricity system operator.

If the responsible person is unable to obtain a sufficient number of compliance credits or Canadian offset credits to fulfill the remittance obligation, the responsible person must remit the number of replacement credits that they are able to obtain in subsequent years until the number of replacement credits remitted is equal to the number of compliance credits issued in error.

Related amendments

The Regulations Designating Regulatory Provisions for the Purposes of Enforcement (Canadian Environmental Protection Act) are amended to add certain provisions of the Regulations to the relevant Schedule. When designated provisions are contravened and upon conviction, the offender would be subject to minimum fines and higher maximum fines. Offences chosen for designation are those involving direct harm or risk of harm to the environment, or obstruction of authority.

Additionally, section 3 of the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity are also amended to ensure that the emission limit under those regulations does not apply if the same unit is subject to an emission limit under the Regulations.

The Regulations contain provisions that will ultimately repeal the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity and for the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations.

Regulatory development

Consultation

The Regulations will make a significant contribution to reductions in emissions from CO₂ related to the generation of electricity supplied to the NERC-regulated electricity system to protect the health and environment of Canadians. As such, the Regulations are foundational to Canada’s net-zero commitments. The Department has undergone extensive engagement since March 2022 to understand the viewpoints of a wide variety of interested parties. Interested parties include electric utility companies, provincial and territorial governments, Indigenous groups, industry associations, environmental non-governmental organizations (ENGOs), unions and labour organizations, researchers and academics in the fields of climate change or energy, and the general public. Engagement with over three hundred different interested parties has included over 300 meetings and 7 webinars. The Department received a total of over 850 unique submissions, and received over 18 000 emails on the proposed Regulations as part of multiple letter-writing campaigns.

To seek out expertise, the Department initiated consultations with experts and multiple technical analysis contractors. Following the publication of the proposed Regulations in the Canada Gazette, Part I, the Department conducted regional tours with in-person meetings. During these engagements, provinces and interested parties brought forward compelling new evidence that the proposed Regulations as drafted would have significantly impacted reliability. In response to this evidence, significant changes were made to the regulatory design to provide more flexibility such as modifications to the prohibition that introduce an AEL (in tonnes of CO₂) for each unit based on its electricity generating capacity, allowing for a limited use of Canadian offset credits, and allowing for pooling of units through compliance credits. These changes support a more affordable and reliable net-zero transition while accounting for different starting points across the different regions in Canada and continuing to achieve significant emissions reductions.

Consultations prior to the publication of the proposed Regulations

In March 2022, the Clean Electricity Standard Discussion Paper was published to outline the overarching principles and scope of a clean electricity standard. Interested parties were invited to submit comments by April 15, 2022. In March 2022, the Department also hosted an Opening the loop webinar to review the Discussion Paper and share the Department’s engagement plans. The Department heard general support for the key principles that guided the development of the Regulations: emissions reductions while carefully considering the impacts that emission reduction measures could have on reliability and affordability.

A second round of engagement and consultation began in July 2022, with the publication of the Proposed Frame for the Clean Electricity Regulations, which provided an overview of the proposed regulatory design. Interested parties were invited to submit comments by August 17, 2022.

Following these consultations, more than 330 written submissions on the proposal were received and analyzed to inform the development of the proposed Regulations.

A summary of these submissions and a description of how the feedback was taken into account in the development of the proposed Regulations can be found in Regulatory Impact Analysis Statement for the proposed Regulations published in the Canada Gazette, Part I.

Consultations on the proposed Regulations published in the Canada Gazette, Part I

On August 19, 2023, the proposed Regulations were published in the Canada Gazette, Part I, followed by a 75-day public comment period.

During this comment period, the Department received over 600 unique written submissions. The Department also held national webinars attended by more than 550 participants, meetings with more than 75 organizations including electricity generators, utilities, provincial government officials, non-governmental organizations, academics and Indigenous groups, and in-person meetings with Alberta, Saskatchewan, Ontario, Nova Scotia and New Brunswick.

Throughout the engagement period following publication in Canada Gazette, Part I, industry and some provincial governments were primarily concerned about the 30 t/GWh emissions intensity limit, referred to in the Canada Gazette, Part I as “annual average performance standard.” Units would have been prohibited from emitting CO₂ above this limit. This emission intensity limit was perceived to be too strict. Provincial governments and utilities in regions with emitting electricity generation raised concerns that regional differences and varying electricity mixes amongst provinces were not adequately considered in the proposed regulatory design. They also noted that some provinces would face significant hardship complying with the Regulations as proposed. Interested parties raised concerns about the timing, indicating that the Regulations as proposed would cause utilities with investments underway to experience a loss of investment as planned (“in-flight”) units were not designed to comply with the proposed Regulations.

These concerns, highlighted by the Canada Electricity Advisory Council and backed by compelling evidence submitted by provinces and interested parties, provided the basis for restructuring the proposed Regulations to a prohibition based on an AEL, with a range of compliance flexibilities.

To this end, on February 16, 2024, the Department published a Public Update on the Clean Electricity Regulations (PDF) (Public Update), outlining “what we heard” during and after the Canada Gazette, Part I comment period. The Public Update also signalled several key changes the Department was considering for the final regulatory design, including a potential move from a prohibition on a unit’s emissions intensity (in tonnes of CO₂/GWh) to a prohibition on a unit’s emissions (an AEL in tonnes of CO₂) based on an applicable emissions intensity and tailored to each unit’s electricity generation capacity.

The release of the Public Update was followed by a 30-day public comment period to solicit feedback on the directions and potential changes under consideration for the final regulatory design. During this period, the Department received over 135 unique submissions, with most parties indicating broad support for changes under consideration, though many wanted to see more details, such as potential parameter values. Following the release of the Public Update, the Department held meetings with provincial and territorial governments, utilities, ENGOs, academics and interested parties from the electricity industry. These meetings included numerous technical workshops between April and July 2024.

The Department also shared its modelling assumptions and results with technical experts from provincial and territorial governments, academia, utilities, ENGOs, and electricity system operators to help validate and improve departmental modelling. The Department also shared information to enable these outside parties to perform their own modelling of the impacts of the proposed regulatory design. In addition to modelling collaboration with interested parties, the Department commissioned third-party modelling and technical analysis for additional verification of electricity sector modelling accuracy. Third-party modelling and federal modelling of the Regulations (including emissions impacts, load scenarios, system costs, rate impacts, forecasted changes in electricity mixes over time) was shared with interested parties, including interested parties from the electricity sector as well as provincial and territorial governments.

The breadth and depth of these consultation activities all helped to inform the development and final design of the Regulations.

Analysis and responses to feedback from interested parties following publication of the proposed Regulations in the Canada Gazette, Part I

Following the publication of the proposed Regulations in the Canada Gazette, Part I, the Department received comments from a broad range of interested parties from the electricity sector, as well as from provinces and territories, Indigenous groups, ENGOs, academics and private citizens. Most interested parties voiced support for the Government of Canada’s overarching goal of prohibiting excessive emissions from the generation of electricity supplied to the NERC-regulated electricity system and establishing a net-zero electricity system as a foundational element of achieving a net-zero economy by 2050. There was general acknowledgement of the need for regulations that support the decarbonization of Canada’s electricity system, and for doing so in a way that minimizes impacts to electricity affordability and reliability. There was also support for the basic regulatory commitments of the proposed Regulations, including a technology-neutral prohibition on excessive emissions with flexibilities so that electricity system operators and utilities can continue to use unabated fossil fuel-based electricity generation to a certain extent to support affordability and reliability during the transition towards greater low or non-emitting electricity generation.

Many interested parties from the electricity sector and some provinces raised concerns about the stringency of the prohibition in the proposed Regulations and the potential impacts to electricity affordability and reliability. The overarching theme from interested parties was the necessity of greater flexibility to meet the regulatory requirements. At the same time, many ENGOs and interested Canadians expressed concern over the continued use of unabated fossil fuel-based electricity generation and requested more stringent regulatory limits on emissions of carbon dioxide to accelerate the transition to a net-zero electricity system in support of Canada’s climate goals.

Extensive consultation and updated modelling provided evidence that the proposed Regulations, as they were drafted, would have been likely to negatively impact the reliability and affordability of electricity in some provinces within Canada. Given the importance of an affordable and reliable electricity system to the economy, the health and safety of Canadians and the decarbonization of other sectors in the Canadian economy to enable them to reach their net-zero goals, the Department proposed further changes to the Regulations to introduce more flexibility while maintaining the primary objective of achieving significant emissions reductions. This also has the secondary benefit of supporting a more reliable and affordable transition to a net-zero electricity system.

A summary of the concerns raised by interested parties and how the Department responded to those concerns is presented in the subsections below.

Adjusting the regulatory design to provide more flexibility

Many interested parties from the electricity sector and some provinces asserted that the emission intensity limit of 30 t/GWh of the proposed Regulations was too stringent and that the overall regulatory design needed to include more flexibility for unit operators. Further, there was concern that in order to remain compliant with the limit on an annual average basis, a unit would need to operate below that limit fairly consistently all the time, allowing little flexibility for operational variance. This was a particular concern for units that would be equipped with CCS, where consistency of a high-performance level is still unproven.

To address concerns about the stringency of a prohibition on CO₂ emissions based on an emissions intensity limit and to provide more flexibility, the prohibition in the Regulations is now a prohibition on CO₂ emissions, based on an absolute emissions approach (i.e. tonnes of CO₂ emissions per year), which has become the AEL. The AEL replaces the emissions intensity limit (i.e. tonnes of CO₂ emissions per GWh of electricity). All units subject to the prohibition will need to comply with an AEL for each unit calculated based on the electricity generation capacity of the unit and a prescribed emissions intensity. In effect, this AEL represents the total amount of emissions that the unit would produce in a year if it were to operate full time at the set emissions intensity.

This approach provides much more flexibility than was permitted under the proposed Regulations, as units will not need to meet a specific annual emissions intensity limit, but rather must not emit CO₂ above their AEL that is tailored to the capacity of a given unit. This approach provides responsible persons with additional flexibility, such as the ability to reduce operating hours over the year if the unit has an emissions intensity much higher than the applicable emissions intensity. Responsible persons may also choose efficiency improvements or abatement technologies (such as carbon capture, or blending with low-carbon fuels) to comply with their regulatory requirements as any improvement in a unit’s emissions intensity means that it can operate for more hours in a year. A refined approach for cogeneration units has also been included.

Shifting the regulatory design for the prohibition provides the opportunity for the Regulations to include a range of new flexibilities that were not part of the proposed Regulations. The additional flexibilities incorporated into the Regulations to adjust the scope of the prohibition and allow a unit to comply with its AEL. These additional flexibilities include Canadian offset credits, banking, and transferable compliance credits (“pooling”). By transferring and remitting compliance credits, emissions from units which emit above their AEL can be balanced out by units which emit below their AEL.

Feedback on the new approach with an AEL has largely been positive, with most interested parties viewing it as an improvement over the emissions intensity standard in the proposed Regulations.

Modifying the applicable emissions intensity

Interested parties from industry and some provincial governments were concerned that a prohibition of 30 t/GWh on a unit’s emission intensity would be too difficult for fossil fuel-based electricity generating units to meet in 2035, even with abatement technologies like CCS given the current performance of those technologies. Despite the proposed Regulations allowing for a time-limited exemption of 40 t/GWh for units equipped with CCS, interested parties warned that uncertainty about whether CCS technologies could comply with the proposed prohibition could unintentionally disincentivize investments in this technology. As such, many interested parties from the electricity sector and some provinces emphasized the need to reduce the risk for operators that implement CCS, given that operational requirements to maintain a reliable electricity system could compromise their ability to comply with the proposed Regulations. Many of these interested parties argued for a less stringent prohibition and suggested that allowing some use of offsets could help reduce risk for companies that consider CCS investments.

To address these concerns around the stringency of the Regulations and the potential impacts on affordability and reliability, in addition to the shift from an emissions intensity limit to an AEL, the stringency of the applicable emissions intensity was relaxed. Whereas the proposed Regulations contained a prohibition of 30 t/GWh on a unit’s emissions intensity, the AEL in the Regulations is based on an applicable emissions intensity of 65 t/GWh until 2050. In addition, the flexibility provided through the use of Canadian offset credits allows for a unit to exceed its AEL with a limited amount of offset credits determined based on an applicable emissions intensity of 35 t/GWh and tailored to each unit based on its electricity generating capacity until 2050. As of 2050, the AEL will be based on an applicable emissions intensity of 0 t/GWh, with an offset allowance based on an applicable emissions intensity of 42 t/GWh.

Departmental modelling has demonstrated that using an applicable emissions intensity of 65 t/GWh, along with the various other flexibilities included in the Regulations, would mitigate potential impacts to electricity reliability and affordability, while still achieving significant emissions reductions in the sector. Some interested parties argued for an even less stringent applicable emissions intensity of 100 t/GWh or higher. While this option was considered, Departmental modelling indicated that increasing the applicable emissions intensity used to determine the AEL to 100 t/GWh instead of the approach in the Regulations of a lower applicable emissions intensity of 65 t/GWh with compliance flexibilities from the beginning, could result in about 20 to 25% fewer emission reductions, while reducing total system costs by less than 10%, producing minimal benefits to rates and negligible impacts on reliability.

Allowing some use of offset credits

To address concerns about difficulties in complying with the prohibition in the Regulations, regulated units can remit eligible offset credits (i.e. Canadian offset credits in the Regulations and which include federal offset credits that have been recognized for use under the federal Output Based Pricing System). Canadian offset credits that are eligible for remittance represent verifiable emission reductions or removals. In order to comply with the prohibition, a unit can remit a limited amount of Canadian offset credits based on an applicable emissions intensity (35 t/GWh until 2050 and 42 t/GWh thereafter) and tailored to a unit’s electricity generation capacity. Before 2050, the combination of the AEL based on an emissions intensity of 65 t/GWh plus the Canadian offset credit flexibility based on an emissions intensity performance standard of 35 t/GWh, responds to the requests of many interested parties for a prohibition of 100 t/GWh on a unit’s emissions intensity.

Offset credits can support the reliability of electricity systems by providing additional flexibility to units to comply with the regulatory standards, without increasing net emissions in Canada or incurring the capital costs of constructing new generating capacity. Access to offset credits can also give industry and investors more confidence to make investments in growing technologies, like CCS, since enabling the use of offset credits provides an additional compliance option and means for continued operation if a technology does not perform as well as expected. Most interested parties are generally supportive of the inclusion of offset credits but have expressed concerns over the future availability of eligible offset credits.

The Department expects that offsets will be available for use by regulated parties. Departmental modelling suggests that the number of offset credits used as a compliance flexibility option under the Regulations would be relatively low given the substantial flexibility provided by other provisions in the Regulations and given that other compliance options are expected to cost less than purchasing eligible offset credits. The same modelling suggests that Canadian offset credits will only start to be required in higher amounts to meet the net-zero requirement in 2050; this provides 25 years during which Canadian offset credit markets can mature. It should be noted that the registration of projects in the federal system is growing (Canada’s Greenhouse Gas Offset Credit System was launched in 2022 and has 30 registered projects), and first credits expected to be issued in early 2025. Additionally, multiple policies are creating demand for offsets today, and the demand signal for offset credits can be expected to strengthen as governments move to net-zero. In this context, the Department remains confident that there will be sufficient supply of offset credits available for the demand created by the Regulations.

Regarding the use of offset credits, interested parties requested clarity on whether multiple offset credits would be required to compensate for the same tonne of emissions to comply with requirements under other various legal regimes. Interested parties from industry advocated that the same tonne of emissions should not be required to be compensated for multiple times to comply with overlapping legal obligations. Accordingly, the Regulations permit the use of eligible offset credits to meet overlapping obligations under carbon pricing regimes and the Regulations provided the conditions in the Regulations are met (see also the “Regulatory cooperation and alignment” section).

Supporting the transition to a net-zero electricity system

Some electric utilities and provincial governments expressed concerns that achieving a net-zero electricity system by 2035 was unrealistic in their jurisdiction, could jeopardize reliability and affordability, and that achieving a net-zero electricity system by 2050 would be more feasible and in line with provincial government goals.

Whereas the proposed Regulations did not prescribe a net-zero electricity system to be established in any time frame, the Regulations help to put Canada on track by 2035 to achieving its net zero grid and net zero economy by 2050 goals. The Regulations do this by shifting the applicable emissions intensity that the AEL is based on from 65 t/GWh between 2035 and 2050 to 0 t/GWh as of 2050, thereby achieving net-zero electricity.

In 2050, there is an increased Canadian offset credit allowance based on an applicable emissions intensity of 42 t/GWh. This supports the electricity sector in the transition to net-zero electricity by 2050 by supporting reliability. Reducing electricity system emissions is in line with achieving net-zero emissions economy-wide by 2050 and aligns with the goals stated by nearly all interested parties. Although the AEL requirement in 2050 is an increase in the overall stringency compared to the proposed Regulations, this is balanced by increasing the applicable emissions intensity (i.e. decreasing the stringency) for the period of 2035–2049 from the proposed Regulations and providing additional compliance flexibilities.

The continued use of existing fossil fuel-based electricity generation and reliability

Many interested parties from the electricity sector and some provinces expressed their need for continued use of unabated fossil fuel-based electricity generation units to ensure that there is a reliable and affordable transition to a net-zero electricity system. These interested parties also expressed concerns that the end-of-prescribed-life provisions of 20 years for existing units in the proposed Regulations were too short and would result in units being forced into retirement before sufficient low- and non-emitting units could be built to replace them. Conversely, ENGOs and many interested Canadians requested that the end-of-prescribed-life provisions remain at 20 years or be shortened to expedite emission reductions in the sector.

The concerns about forced early retirements are largely addressed by the change from a prohibition on a unit’s emissions intensity to a prohibition on a unit’s emissions, the AEL, since unabated units that have met their end-of-prescribed-life can continue operating in some capacity. The flexibility provisions for peaking units in the proposed Regulations would have permitted a capacity factor of up to 5%; now, the AEL and the use of eligible offset credits in the Regulations effectively permit a peaking unit a capacity factor of up to 20%. The Department further addressed these concerns by extending the end-of-prescribed-life provisions from 20 years to 25 years.

Some interested parties have continued to advocate for a longer end-of-prescribed-life of 30 years. While this option was considered, a 30 year end-of-prescribed-life would mean that fossil fuel-based electricity generating units commissioned between 2020 and 2025 could continue to operate unabated in 2050 or later. This would not align with the goal of net-zero by 2050, the Paris Accord goal committed to by Canada and many provincial governments. Departmental modelling also demonstrated that a 30-year end-of-prescribed-life would have significantly reduced emissions reductions (by 17 to 21%) with only minor reductions to electricity system costs (on the order of 1%). By contrast, a 25 year end-of-prescribed-life maintains flexibility, helps enable a reliable and affordable transition to a net-zero electricity system by allowing existing unabated fossil fuel-based electricity generating units additional time before having to comply with the prohibition in the Regulations, and supports the common goal of net-zero by 2050.

Providing flexibility for units already under development (planned units)

The Department also heard from interested parties in the electricity sector and some provinces that several planned units, which were supposed to be commissioned before 2025, were delayed due to material and labour shortages outside of their direct control. These interested parties argued that the proposed demarcation date of January 1, 2025 (which determines whether a unit is considered an “existing” unit with the relevant end-of-prescribed-life provisions) or if it is a “new” unit (must comply with the prohibition in the Regulations starting in 2035) would disadvantage and potentially cause the early retirement of these delayed units that have already undertaken substantial financial investments. These units could be disadvantaged as they would not be able to benefit from the end-of-prescribed-life provisions.

To address concerns about these planned units, the Regulations include planned unit provisions that enable a unit commissioned between 2025 and 2035 to have an end-of-prescribed life, similar to an existing unit, if that unit has met certain milestones in its development before being commissioned. This approach provides flexibility for units that are already under development and provides them until 2050 before the prohibition under the Regulations applies to them. By keeping the date that demarcates existing units from new units on January 1, 2025, this compromise approach helps mitigate the risk of a broader “dash-to-gas”, which was a concern raised by several interested parties, including ENGOs and many interested Canadians.

Enabling the use of the most efficient fossil fuel-based electricity generating units

Many interested parties from the electricity sector and some provinces raised concerns that the proposed Regulations did not include any flexibility, or incentives for utilities to allocate more operational hours to their most efficient (i.e. lowest emission intensity) fossil fuel-based electricity generating units and allocate less operational hours to their least efficient (i.e. highest emission intensity) units. In the context of the proposed Regulations, these interested parties suggested allowing “fleet-wide averaging” so that operators with multiple units could average the emissions intensity across their entire fleet, to provide increased compliance flexibility and allow the most efficient units to operate the most.

The Department recognizes the importance of enabling the operation of efficient fossil fuel-based electricity generating units as the electricity system transitions to net-zero. The AEL prohibition and the compliance flexibilities that adjust the scope of the prohibition in the Regulations enable more efficient units to operate for more time each year than less efficient units. Additionally, the Regulations allow eligible regulated units to be issued transferable compliance credits that can be transferred to another unit that is then able to remit transferable credits that allow the unit to produce more emissions but remain in compliance with its AEL for that year. With respect to the remittance of transferable credits, conditions apply, including, among other conditions in the Regulations, that both units involved in the transfer must report to the same electricity system operator, which is generally aligned with provincial or territorial boundaries.

This provision provides additional flexibility for responsible persons who will be able to transfer compliance credits from less efficient units to more efficient units allowing the unit to produce more emissions but remain in compliance with its AEL for that year. In general, most interested parties were in favour of the inclusion of these provisions (which were described during consultation as “pooling”).

Adjusting the treatment of industrial cogeneration of electricity to support reliability

Interested parties from multiple industries, as well as officials from Alberta and Saskatchewan, observed that a prohibition on a unit’s emissions intensity in the proposed Regulations would be difficult for most existing cogeneration facilities to meet. Since cogeneration units, like all regulated units, would only be subject to the prohibition if they produce a net supply of electricity, whether directly or indirectly, to a NERC-regulated electricity system during a given year, these interested parties expressed concern that cogeneration facilities might decide to stop exporting electricity to the electricity system in order to avoid being subject to the requirements of the proposed Regulations. This could negatively impact electricity reliability and affordability in Alberta and Saskatchewan, where cogeneration units contribute significant amounts of electricity to the grid. At the same time, the Department heard from several interested parties in the electricity sector that cogeneration units needed to be treated equitably to utility units to avoid an incentive for the build-out of more unabated cogeneration units.

The Department recognizes the important role of cogeneration in providing electricity, particularly in Alberta and Saskatchewan, but also in other provinces. To address the concerns about any risk of cogeneration units reducing, or stopping the export of electricity to the electricity system, the Regulations include a revised approach for existing cogeneration units that is significantly less stringent than the proposed Regulations as published in the Canada Gazette, Part I. The proposed Regulations provided less flexibility for cogeneration units to comply with the prohibition of a 30 t/GWh emissions intensity standard. All emissions associated with electricity produced by a cogeneration unit would have been relevant to compliance with the prohibition. The revised approach in the Regulations will enable existing cogeneration units to calculate their AEL based on their full electricity generating capacity, but only have to account for the emissions associated with the generation of electricity that is supplied to the grid (measured in terms of net supply, in case their host facility also purchases electricity from the grid) to comply with the prohibition. Emissions associated with electricity that is consumed on-site do not have to be included for an existing cogeneration unit to comply with its AEL, which will provide additional flexibility for complying with the AEL. Excluding the emissions of electricity used on-site avoids regulatory overlap, as these emissions are associated with industrial processes outside of the electricity sector. Other regulations, such as federal and provincial carbon pricing, may cover these industrial emissions. This also means that an existing cogeneration unit with net supply to a NERC-regulated electricity system would not need to take further action to comply with the Regulations if the emissions associated with their net supply of electricity to the grid remain below the unit’s AEL.

This approach strikes a reasonable balance compared to alternative options, such as counting all electricity emissions from cogeneration units or exempting cogeneration units entirely. The Department heard that counting all electricity emissions would create a risk that existing cogeneration units would choose to stop exporting electricity to the electricity system in 2035, especially since electricity sales are typically a secondary business for these units. Alternatively, the Department heard that completely exempting cogeneration from the Regulations would be unfair to utilities and would create an unintended incentive for building out more “behind the fence” cogeneration units, instead of building out electricity generation capacity in the electric utility sector.

To further ensure that there is fairness between cogeneration units and utility units, the Regulations require that all emissions from electricity generation for existing cogeneration units are relevant to compliance with their AEL, including electricity that is used behind-the-fence, starting in 2050. The Regulations also require new cogeneration units (i.e. those with commissioning dates on or after the demarcation date of January 1, 2025, and which are not planned units) to account for all emissions from electricity generation, including electricity that is used behind-the-fence, to comply with its AEL starting January 1, 2035.

Allowing banking to address year-to-year variability

Interested parties from regions that rely heavily on hydroelectricity raised concerns that during periods of prolonged droughts, there can be significant impacts to hydroelectric generation capacity, requiring these regions to rely more heavily on fossil fuel-based electricity generation in certain years. These interested parties requested that the Regulations enable some form of multi-year averaging, whereby years that require more fossil fuel-based electricity generation can be compensated by years that require less fossil fuel-based electricity generation.

To address these concerns, the Department has included “banking” provisions in the Regulations, which allow for the “banking” of compliance credits. Units subject to the AEL in a given year are eligible to be issued compliance credits when the unit’s calculated emissions are below its AEL. Thus, a unit can carry forward these compliance credits and exceed its limit in another compliance year by an equivalent amount. This provides flexibility to help address year-to-year variability caused by circumstances outside the operators’ control in the need for fossil fuel-based electricity generation. Separate from the banking provisions, it is also important to recognize the emergency circumstances provisions that may be available if the requisite criteria in the Regulations were to be met; note that if requirements for emergency circumstances are met, the use of banked credits would be unnecessary.

Use of low-carbon fuels

Some interested parties noted that the proposed Regulations did not contain any accounting systems for low-carbon fuels. These parties noted that without an indirect accounting system, there would be no incentive to purchase renewable natural gas (RNG) and other low-carbon intensity fuels through the natural gas delivery network, as only the low-emitting fuel received directly at the plant through the natural gas system (i.e. a tiny fraction of the amount purchased) could be counted towards compliance, rather than the full amount. Other alternatives, such as building a dedicated delivery pipeline for RNG to each unit or having RNG delivered by truck, would likely be financially unviable. Accordingly, these parties suggested that the proposed Regulations should incorporate an indirect accounting system to recognize the carbon neutral attributes of purchased low-emitting fuels for compliance purposes, even if such fuels were to be blended into the natural gas distribution network.

To address these concerns, the Regulations include an indirect accounting system to recognize the carbon neutral attributes of RNG in the Regulations. Eligible units will be able to exclude from their total emissions, the emissions associated with RNG that is blended into a North American natural gas pipeline network that is physically connected to the unit, if the volume of RNG is specified in a contractual agreement and all of the conditions in the Regulations are met.

Meeting electricity demand during peak time periods

Interested parties from the electricity sector and some provinces raised a concern that the “peaker provisions” in the proposed Regulations were too stringent and could negatively impact reliability, as the limit of 450 hours per year would have impaired the ability of some jurisdictions to provide sufficient peaking services. For clarity, “peaker” units are those that operate at times of peak electrical demand and are used to supplement other types of power plants, such as baseload units, that supply a more consistent amount of power throughout the day.

To address these concerns, the Regulations do not include any fixed hourly limit for peaker units. It is expected that the prohibition on emissions for units through the AEL approach, combined with a higher applicable emissions intensity and other compliance flexibilities, will allow for sufficient capacity factors for peakers, thus allowing for the removal of designated peaker provisions. The AEL approach of the Regulations, combined with the additional flexibilities, effectively permit an unabated natural gas peaker to operate up to approximately 20% capacity factor (with the use of offsets). In comparison, the approach in the proposed Regulations would have allowed a maximum of 5%.

Revising the approach to emergency circumstances

Many interested parties also expressed concerns that the provisions for emergency circumstances in the proposed Regulations were unworkable since they required the Minister of the Environment to approve emergency exemptions after the fact. The approval was considered retroactive and seen by these parties as potentially inhibiting the decision by unit operators to operate during emergencies as the unit operators would never be certain whether or not their emergency emissions would be included in their compliance determination.

To address the concerns about emergency circumstances, the Regulations allow emissions generated during a period related to an emergency circumstance to be deducted from a unit’s total emissions where the necessary conditions are met. In the case of an emergency circumstance, electricity system operators can trigger a temporary exemption of up to 30 days, from a unit’s total emissions for the year, for the emissions generated by a unit in order to alleviate the disruption or significant risk of disruption to electricity supply arising from emergency circumstances. This allows electricity system operators to direct fossil fuel units to operate for a temporary period to help alleviate the emergency. There are two types of emergency circumstance set out in the Regulations. The definition of an emergency circumstance is modified from its inclusion in the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. Moreover, it no longer appears as a defined term as the relevant considerations are all contained in the provisions relating to emergency circumstances. This approach removes the requirement for operators to obtain approval from the Minister of the Environment prior to responding to an emergency and therefore should not interfere with prompt emergency response. To extend the emergency exemption period beyond the temporary period, unit operators can apply to the Minister of the Environment for an extension. For increased public confidence in these provisions, the Minister of the Environment will publish all occurrences where the emergency provisions were used and associated relevant details, including a rationale from the party that declared the emergency, explaining how the event met the emergency definition.

An updated definition, which is the basis of the new provisions, was shared with provinces and territories, utilities, and electricity system operators during the Department’s engagement process and most interested parties have been receptive to this change.

Adjusting the scope of the Regulations – 25 MW capacity threshold

Most interested parties were supportive of the scope of the proposed Regulations, which indicated that the proposed Regulations would apply to units that have a capacity greater than 25 MW, are connected directly or indirectly to a NERC-regulated electricity system and combust fossil fuels. This scope exempted small units, which was seen as appropriate since many Indigenous, remote and Northern communities rely on small diesel units and do not currently have viable alternatives.

However, interested parties noted that the proposed minimum capacity threshold of 25 MW could create an unintended incentive to build multiple new units smaller than 25 MW to avoid being covered by the Regulations. At the same time, many Indigenous groups argued that any modification to the 25 MW criteria should continue to effectively exempt electricity generation in remote communities.

To address these concerns, the Regulations extend the applicability criteria to also cover new units located within the same facility, when the collective capacity of the new units is 25 MW or greater. This avoids creating the unintended incentive identified during consultations for a facility to aggregate multiple small units to avoid being subject to an emissions limit.

Improving departmental modelling of the electricity sector

Many interested parties from the electricity sector and provinces raised concerns with how the electricity sector had been modelled by the Department.

Since the publication of proposed Regulations in August 2023, the Department has made numerous improvements to the electricity sector modelling, with significant direct input from provincial governments and utilities and electricity sector experts. Some key interested parties signalled that using a model that restricts its analysis to the Canadian optimal, and that only looks at 12 representative days instead of all hours of the year, may overlook some regional or temporal specificities. To address this, two new versions of the Department’s electricity sector model, NextGrid, were developed: one that focuses on the optimal of specific provinces, and one that considers each hour in the year. These versions of the model are used as a check of the validity of the results of the national model.

The Department also made a variety of province-specific changes to model inputs, to better reflect provincial policies, plans and actual operating circumstances.

For example, the modelling changes made in response to information or requests from provinces include

Implementing a more detailed approach to Alberta’s Technology Innovation and Emissions Reduction Regulation (TIER) policy;
Changing the CCS assumptions for particular units as communicated by interested parties from the electricity industry, especially those who have been considering CCS projects;
Implementing a minimum capacity factor for select fossil units;
Restricting new growth of interties between provinces in the model;
Constraining hydropower development and limiting new natural gas capacity development in certain provinces at their request;
Limiting new wind power build-out in certain provinces between 2025 and 2029 based on inputs from provincial governments and crown utilities with historical or planned build-out of wind power; and
Incorporating a maximum power output constraint for wind power and incorporating additional costs associated with synchronous condensers and battery storage based on inputs provided by selected regions to better account for operational reliability, alongside wind power additions beyond a certain limit.

The numerous improvements that the Department undertook with respect to electricity sector modelling to conduct the cost-benefit analysis for the Regulations are explained in more detail in the “Benefits and costs” section.

Addressing requests to republish in the Canada Gazette, Part I

Following engagement with interested parties on changes to the proposed Regulations, some parties recommended that the Regulations should be republished in the Canada Gazette, Part I, due to regulatory design changes. However, the regulatory design changes are not new concepts to interested parties as they represent a natural evolution from the proposed Regulations that address the concerns raised by interested parties during the pre-publication period. In some instances (e.g. pooling, banking, AEL) the changes are based on suggestions made by interested parties during the consultation process. These changes therefore represent expected progression in the regulatory design process and do not need a second, formal, round of engagement through the Canada Gazette, Part I.

It is important to note that the Department has used the feedback received from interested parties throughout the regulatory design process to inform an iterative cycle of analysis to assess the impact of various parameters, to understand how emission reductions can be maximized without sacrificing reliability and affordability. The Department has undergone extensive engagement with interested parties to receive feedback on these changes beyond the Canada Gazette, Part I, consultation period following the publication of the proposed Regulations. This included the publication of the Public Update in February 2024 and, in September 2024, a series of webinars to groups of interested parties to provide them with additional policy updates that effectively explained the intended updates to the regulatory design. Following these targeted webinars, the Department had bilateral meetings with interested parties who wished to better understand, or offer further comment on, the information provided to them in the webinars. These extra steps provided an additional 30-day comment period on the suggested refinements to the proposed Regulations outlined in the Public Update and up to three weeks of informal comment time. The Government of Canada consultation and engagement period was nearly two and a half years in total length.

The prohibition in the Regulations does not come into force until 2035, and will be in place beyond 2050. As is the case for all regulations, opportunities will exist as required to review, and amend if necessary, regulatory provisions to ensure that they will achieve their intended effect.

Modern treaty obligations and Indigenous engagement and consultation

The Department has taken a distinctions-based approach^{footnote 11} to engagement with First Nations, Métis and Inuit (hereafter Indigenous Peoples unless otherwise specified), including

Inviting representatives of National Indigenous Organizations (NIOs) and rights holders to informational webinars and a First Nation-specific webinar to promote discussion on the proposed Regulations and related concerns;
Supporting Indigenous representatives to connect with federal partners leading the broader clean energy transition and investments (e.g. Natural Resources Canada and Canada Infrastructure Bank);
Introducing the proposed Regulations in June 2022 to Indigenous representatives, such as the Inuit Tapiriit Kanatami and Assembly of First Nations at the Joint Committee on Climate Action;
Proactively hosting over 20 bilateral meetings with NIOs and rights holders and extending an open offer to continue discussions throughout the development of the Regulations;
Supporting Indigenous groups, including NIOs and rights holders, with more than $85,000 in capacity funding to participate in the regulatory development process by providing feedback on the Regulations; and
Engaging experts on Indigenous energy opportunities and challenges to study potential impacts of the proposed Regulations, within the context of the broader clean energy transition for Indigenous Peoples.

Feedback received from First Nations, Métis and Inuit representatives

The Department received eight written comments as well as several questions during webinars and meetings on the proposed Regulations from Indigenous-led organizations and rights holders throughout the regulatory development process. The Department received oral and written feedback on the Discussion Document (March 2022), the CER Regulatory Frame Document (July 2022), as well as the draft Regulations in Canada Gazette, Part I (CGI), published August 11, 2023, and the Update Paper (February 2024). Most organizations expressed support for the broad ambition of the objectives of the Regulations to attain net-zero emissions for the electricity sector and mitigate the harmful impacts of climate change for future generations. In addition, several recommendations were proposed to the federal government on the broader clean energy transition beyond the Regulations, such as

The necessity of providing increased funding and capacity support for Indigenous investment in clean energy, to mitigate concerns about energy affordability;
Promoting the inclusion of Indigenous leaders in clean energy transition decision-making;
Providing supports for housing-related energy efficiency facing Indigenous Peoples and their communities; and
Developing a coordinated federal mechanism for recognizing Indigenous rights and implementing the UN Declaration on the Rights of Indigenous Peoples (UN Declaration). This mechanism could include a single-window approach for engagement and decision making on projects within Indigenous lands and territories, as well as on policies, regulations, or other initiatives that could impact respective Indigenous communities. This would support decolonization efforts in empowering Indigenous Peoples to be engaged proactively in the net-zero economy, ensuring they are full participants and not left behind.

The Department notes that

In 2023, the Government of Canada published its vision Powering Canada Forward: Building a Clean, Affordable, and Reliable Electricity System for Every Region of Canada, which included considerations on enabling Indigenous participation and inclusion in the clean electricity transition. Through A Healthy Environment and a Healthy Economy, the Government of Canada has established an interdepartmental initiative to improve access to funding and provide support for clean energy initiatives in Indigenous, rural and remote communities across Canada.
In support of the broader clean electricity transition, in addition to the Regulations, the Government of Canada has developed and implemented complementary measures, for example the up to $5 billion in loan guarantees available to Indigenous communities through the federal Indigenous Loan Guarantee Program is one such specific measure that is administered by other federal departments and agencies and is aimed at supporting Indigenous access to capital for ownership in resource projects. This funding, announced in Budget 2024, complements initiatives like Natural Resource Canada’s Indigenous Off-Diesel Initiative, the Clean Energy for Rural and Remote Communities Program, and the Smart Renewables and Electrification Pathways Program. The Department has limited funding available through projects supported by other programs not directly tied to the Regulations, such as the Department’s Indigenous Leadership Fund, which offers targeted support to Indigenous-owned and Indigenous-led renewable energy projects.
The Regulations effectively exempt all electricity generating units located in remote communities in Canada, which are largely reliant on diesel generators. The exemption is achieved by excluding electricity generating units that
- have a capacity of less than 25 MW, as long as a facility’s sum of all new capacity is also under 25 MW; or
- are not connected directly or indirectly to an electricity system that is subject to North American Reliability Corporation (NERC) standards. This effectively exempts all electricity generating units located in remote communities in Canada, which are largely reliant on diesel generators.
The Government of Canada continues to support Indigenous and remote communities, through the programs and initiatives mentioned above, as they seek options to reduce reliance on diesel in favour of non- or low-emitting technologies.

In addition to the above considerations, the Department has reviewed all verbal and written questions and comments received from interested Indigenous parties and responded where possible. Engagement will continue during the implementation of the Regulations.

Results of an assessment of modern treaty implications

As required by the Cabinet Directive on the Federal Approach to Modern Treaty Implementation, the Department completed an assessment of modern treaty implications (AMTI) for the Regulations. The assessment examined the geographic scope and subject matter of the Regulations in relation to the 26 modern treaties in effect at the time of assessment.

The Department notes that

The Department received feedback that the Regulations could lead to increased development of low- or non-emitting electricity generating sources on Indigenous land. Depending on how unit operators choose to comply with the Regulations and how provincial electricity systems are expanded after the prohibition begins to have effect in 2035, there could be indirect socio-economic development opportunities for rights holders through economic participation in clean electricity projects. These benefits could occur in a variety of ways, including but not limited to Indigenous groups developing or investing in clean energy projects and directly receiving the revenue they generate and benefitting from access to clean electricity sources; and Indigenous-led companies participating in the development of clean electricity infrastructure projects such as construction, operations, or environmental monitoring. Projects that may be undertaken in order to expand low- and non-emitting electricity generation have the potential to affect the rights and interests of modern treaty signatories with respect to the ownership, use, or management of lands and resources.
The AMTI concluded that the implementation of the Regulations would not have direct modern treaties implications, or result in federal obligations. As the Regulations are implemented, the Department will continue to assess modern treaty implications and work to address any issues that are identified.

United Nations Declaration on the Rights of Indigenous Peoples Act

The Regulations began development in 2022. The Department has strived to align the Regulations with the purposes of the United Nations Declaration on the Rights of Indigenous Peoples Act (UN Declaration Act) through continued consultation and cooperation with Indigenous representatives, which will continue following the publication of the Regulations.

The Regulations could promote substantive equality and combat discrimination, as well as respect and protect the environment in accordance with Indigenous perspectives through

Emissions reductions: The Regulations will reduce Canada’s GHG emissions and contribute to global climate action. Given that Indigenous Peoples are some of the more vulnerable populations to the adverse effects of climate change and hold an intrinsic relationship to and dependence on nature, the Department expects that more vulnerable demographic groups may benefit further from the positive impacts of successful mitigation of global climate change (Articles 21.1 and 29 of the United Nations Declaration on the Rights of Indigenous Peoples (UN Declaration).
Intergenerational equality: Indigenous Peoples are among the youngest and fastest growing populations in Canada, and future generations stand to benefit the most from emissions reductions and the build-out of clean electricity infrastructure over the long term (Article 22 of the UN Declaration).

The Department notes that

Obtaining Indigenous viewpoints and perspectives on the Regulations has been an important and ongoing process to inform regulatory development, which included maintaining open lines of communication with interested Indigenous representatives, Indigenous power producers and Indigenous Peoples.
Nonetheless, certain Indigenous representatives expressed the view that the proposal could be inconsistent with the UN Declaration, on the basis that the clean energy transition overall could create, or exacerbate inequality or discrimination and/or potentially fail to adequately support participation in federal decisions which affect Indigenous Peoples. These concerns about inequality focused mostly on energy affordability, while a failure to adequately support participation in federal decisions was expressed through calls for greater inclusion in the clean energy transition. Given that the Regulations only regulate CO₂ emissions from fossil fuel-based electricity generation, the broader conversation of inclusion is best suited to be addressed by NRCan’s Clean Electricity Strategy.
The federal government remains committed to meaningful engagement, including via the Permanent Bilateral Mechanism, the Indigenous Climate Leadership agenda, and via elements of Natural Resource Canada’s Clean Electricity Strategy including follow-up to the advice of the Wah-ila-toos Indigenous Advisory Council.
- The Council has influenced the federal government’s consideration of issues related to Indigenous rights and opportunities and the unique circumstances of Northern and remote communities. The Council developed consensus recommendations to the government in their November 2024 report, Kinship and Prosperity: Proven Solutions for a Clean Energy Landscape. In this report, the Indigenous Council made over 30 recommendations in areas that include ease of access to funding; developing consistent project eligibility criteria that prioritizes Indigenous community benefits; and sustainably funding Indigenous participation.
To address Indigenous concerns on the Regulations, the Government undertook the following actions since March 2022:
- working with the concerned parties to address their feedback on the Regulations;
- ensuring access to funding, such as ITCs, for utilities to manage potential rate impacts for consumers;
- incorporating additional flexibilities into the regulatory design to mitigate potential impacts on affordability;
- coordinating with relevant federal departments to address broader concerns related to the clean energy transition; and
- planning for continued engagement with Indigenous representatives post-publication of the Regulations.

Instrument choice

Given the increase in electricity demand from electrification and population growth that is expected to occur in the coming decades, it is important that excessive CO₂ emissions in the electricity sector are reduced starting as soon as possible to position Canada on a path for net-zero emissions economy-wide by 2050. In this way, as other key economic sectors such as transportation and buildings electrify, the electricity used to power this transition will be generated from low or non-emitting sources. There are a variety of regulatory and non-regulatory instruments being implemented by the Government of Canada and provincial/territorial governments in pursuit of decarbonization objectives outside the electricity sector. The Department considered and assessed two major potential pathways: modifying carbon pricing for electricity generation or developing a new regulation under the Canadian Environmental Protection Act, 1999 (CEPA). A summary of this assessment is presented below.

Option 1: modify carbon pricing for electricity generation

As noted in the Background section, emissions from fossil fuel-fired electricity generation are already subject to carbon pricing under the Output-Based Pricing System Regulations (OBPSR), or the applicable provincial/territorial carbon pricing systems deemed to meet the requirements of the federal benchmark. Under the OBPSR, most electricity generating units that combust gaseous fuel whose commissioning date is on or after January 1, 2021, face a linearly declining output-based standard from 247 t CO₂/GWh in 2024 to 0 t CO₂/GWh by 2030.

Carbon pricing systems in Canada could be modified to increase stringency for electricity generating facilities such that they face greater exposure to the carbon price. Such an approach would increase the average carbon cost (per unit of production) of unabated emitting electricity generation, and could, if significant enough, bolster the relative economic attractiveness of low or non-emitting generation.

Although increasing the average cost under carbon pricing for electricity generating facilities would increase the incentive to reduce emissions, it would not guarantee a specific environmental outcome for the electricity sector due to access to various compliance flexibilities which include, payment of the carbon price, use of eligible offset credits and trading of allowances and credits from other sectors. This means that modifying the existing federal OBPSR would not provide certainty that GHG emissions in the electricity sector decline at a particular rate or to a particular level. In other words, carbon pricing is designed to send a broad economy-wide price signal. Canada’s approach gives provinces and territories the flexibility to design their own pricing systems, including setting specific performance standards for individual sectors as they see fit as long as their system as a whole aligns with the minimum federal stringency requirements (the federal benchmark). Supplementary modelling conducted by the Department suggests that, if a carbon price of $170/tonne were to apply to all emissions in the electricity sector starting in 2030 (including those from electricity generating units that combust gaseous fuel whose commissioning date falls before 2021), then the rate of not investing in unabated emitting electricity generation and associated rate of investment towards low or non-emitting generation would be insufficient to put the electricity sector on a path by 2035 to aid in achieving net-zero emissions economy-wide by 2050. As such, this option was not selected.

Option 2: develop a new regulation under CEPA

Another pathway to reduce GHG emissions in the electricity sector is to introduce a new regulation under CEPA. In general, emission regulations under section 93 of CEPA can establish a prohibition that set a maximum amount of emissions that are allowable over a period of time and can grant certain flexibilities over the manner in which regulatees ultimately comply. The downside of achieving a set number of allowable emissions under a prohibition is “economic inefficiency,” whereby firms are unable to abate emissions at equivalent marginal costs to one another. In other words, while some firms would be able to reduce their emissions at a relatively low marginal abatement cost, other firms could only reduce the same number of emissions by incurring a relatively high marginal abatement cost. Such downsides to the prohibition can be mitigated by adjusting the scope of the prohibition with compliance flexibilities, such as pooling, banking, and permissible use of offsets.

A new regulation under CEPA would focus its scope on the electricity sector, moving the sector onto a path as of 2035 to reduce excessive CO₂ emissions from the electricity sector, while ensuring it contributes to achieving a net-zero emissions economy by 2050. In addition, given that the sector is already subject to the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity, a new regulation under CEPA would build on the existing regulatory framework that governs the electricity sector, marking a continuation of progress in the transition away from unabated fossil fuel-fired electricity generation and into low or non-emitting sources of generation.

Upon considering the pros and cons of each policy option, the Department determined that a new regulation under CEPA that i) prohibits excessive CO₂ emissions and ii) includes some compliance flexibilities that adjust the scope of the prohibition, is the most effective instrument to achieve the policy objective of reducing GHG emissions from the electricity sector, i.e. Option 2.

Regulatory analysis

Benefits and costs

In the context of federal regulatory development, a cost-benefit analysis (CBA) is a tool that provides a structured approach to identifying, and when possible, quantifying and monetizing all relevant positive and negative economic, environmental and social impacts of an initiative to inform decision-making. It does so by comparing the total impacts accrued under a scenario in which a specific regulatory initiative is undertaken (Regulatory Scenario) against the total impacts accrued under a counterfactual scenario in which the regulatory initiative is not undertaken (Baseline Scenario). By subtracting the value of impacts derived under the Baseline Scenario from those derived under the Regulatory Scenario, the incremental impacts of the regulatory initiative can be isolated and examined.

The Regulations are registered in 2024. Given that compliance efforts associated with the Regulations are expected to be undertaken in advance of the prohibition, and related provisions, coming into force in 2035, the analytical timeframe for the CBA is 2024 to 2050 (a 27-year period). Unless otherwise stated, all monetized values presented in the subsections that follow are in 2022 constant Canadian dollars, discounted to base year 2024 at a discount rate of 2%, consistent with the Social Cost of Greenhouse Gas Estimates – Interim Updated Guidance for the Government of Canada. Overall, the Regulations are estimated to result in total benefits of $54.9 billion and total costs of $40.3 billion, resulting in $14.6 billion in net benefits to society. Electricity sector GHG emissions are estimated to reduce by 17% relative to the Baseline Scenario, while electricity sector costs net of cost savings accounted for in the CBA are estimated to increase by 4%.

As noted in the Background section, Canada’s electricity system sources its power from electric utilities and a subset of industrial cogeneration. Throughout the CBA, all figures relating to the electricity system incorporate electric utilities and the proportion of industrial cogeneration that is sold to the system, unless otherwise stated. For all tables in the subsections that follow, totals may not add up due to rounding.

Departmental electricity sector models

The Department develops, stewards and continually updates two models that are used to project the Baseline Scenarios and Regulatory Scenarios modelling Canada’s electricity system between now and 2050: the Energy, Emissions and Economy Model for Canada (E3MC) and NextGrid.

E3MC is an internationally recognized, peer-reviewed and long-standing macroeconomic model used by the Government of Canada to forecast national emissions (i.e. the annual Reference Case and annual Additional Measures Case) reported to forums including the United Nations Framework Convention on Climate Change to track Canada’s progress under the Paris Agreement. E3MC is comprised of two sub-models. The first sub-model is Energy2020, which simulates the North American energy market to provide outputs such as energy use, energy prices, and emissions for an array of pollutants across fuels, geographic regions and sectors. The second sub-model is The Informetrica Model (TIM), which uses the cost, cost savings and investment information from Energy2020 to examine and simulate factors such as consumption, investment, production and trade decisions in the whole economy. TIM captures interactions and feedback effects between different economic sectors, tracking changes to producer prices, relative final prices and incomes, alongside government fiscal balances, monetary flows, interest rates and exchange rates to estimate impacts to Canada’s cumulative demand, output, employment, price formation and sectoral income. E3MC provides integrated results from both sub-models, projecting energy market outputs that take macroeconomic cross-effects into account.

NextGrid is a capacity expansion model designed to identify optimal investment and operation decisions across Canada’s electricity system by minimizing the system-wide (i.e. national) cost of meeting electricity demand subject to constraints such as system reliability and resource availability (e.g. geological and technological constraints). NextGrid is based on an open-sourced modelling platform (i.e. GridPath) and underwent several rounds of consultation with provinces, utilities, and other interested parties since its inception in 2021, and has been used extensively to develop and refine the final design of the Regulations. Unlike E3MC, which models supply and demand of all energy types (one of which is electricity) in all sectors of the Canadian economy, NextGrid focuses solely on the electricity sector, thereby enabling NextGrid to be much more detailed and nuanced in its depiction of the inner workings and operations of the electricity sector relative to E3MC. A selection of key differences in the model architecture between E3MC and NextGrid is presented in Table 4.

Table 4: Selection of key differences in the model architecture between E3MC and NextGrid
Aspect of comparison	E3MC (Energy2020 + TIM)	NextGrid
Model scope	All major North American economic sectors that produce or demand energy, including electricity	Canadian electricity sector
Model type	Deterministic	Deterministic
Electricity modelling time resolution	12 time periods within a year, consisting of 6 Summer and 6 Winter periods	12 representative days of 24 hours each, tested by the 8,760 hours per year version of the model^{table d1 note a}
Output resolution	Annual	5-year periods
Future planning horizon	Model can see two years ahead	Model can see all future time periods
Demand/load growth	Endogenous	Exogenous
Optimization logic	Makes decisions that balance electricity supply and demand in each region, subject to constraints	Makes decisions that minimize total (national) electricity system costs, subject to constraints, tested in a model version that optimizes one province at a time
Import/export	Endogenous (occurs if regional supply and demand are balanced and trade is profitable to the exporting region) and exogenous (electricity contracts between regions can be exogenously specified)	Endogenous (occurs if trade minimizes national system costs) and exogenous (electricity contracts between regions can be exogenously specified). Test runs using the provincial base model optimized system costs at the provincial level
Variable renewable energy unit operation	Constant capacity factor	Hourly profile
Electric cogenerating units	Modelled as single units	Modelled as two units (one portion that generates electricity for the grid and one portion that generates electricity for own industrial use)
Electric cogenerating unit buildout	New endogenous buildout determined by the projected economic growth of the sector to which the unit belongs	No new endogenous buildout
Residential electricity rates	Endogenous	Calculated ex-post
Able to make unit-by-unit decisions on how to comply with a regulation	No	Yes
System costs account for debt on infrastructure built prior to 2022	Yes	No (model does not incorporate historic data)
System costs account for capital costs on exogenous new builds	Yes	No (these are considered "sunk costs")
Able to build endogenous intraprovincial transmission/distribution lines	No	No
Able to build endogenous interprovincial interties	No	Yes
Carbon pricing – Price	The price on carbon reflects the national carbon price up to 2030 as announced under the federal carbon pollution pricing benchmark.	The price on carbon reflects the national carbon price up to 2030 as announced under the federal carbon pollution pricing benchmark.
Carbon pricing – Allowances	Allowances are based on the federal output-based pricing system (OBPS) or provincial systems implemented under the federal benchmark. In Quebec, the electricity sector is not receiving allowances to mimic Quebec’s cap and trade system.	Allowances are based on the federal output-based pricing system (OBPS) or provincial systems implemented under the federal benchmark. In Quebec, the Quebec electricity sector is not receiving allowances to mimic the cap-and-trade system.
Carbon pricing – Credits	Federal and Alberta’s TIER carbon pricing markets are balanced and electricity sector can trade its carbon pricing permits/credits with other sectors.	Credit trading is allowed under the TIER system in Alberta only, and trading is limited to actors within the electricity sector.
Table d1 note(s) Table d1 note a Another version of the NextGrid model exists that models every hour in one calendar year (i.e. 8,760 hours). This version of the model was used in tandem with the main model to confirm that the electricity system built by the main model is able to meet demand in every hour of a given test year. Return to table d1 note a referrer

As outlined in Table 4, E3MC and NextGrid have distinct model architectures that could reasonably lead both models to derive significantly different outputs from one another. During the public comment period for the proposed Regulations in the Canada Gazette, Part I, interested parties expressed concern with this lack of lack of output alignment. As a result, departmental modellers took significant steps to align both models as closely as possible on key data inputs and constraints (e.g. annual and peak loads, fleet specifications, planning reserve margins, capital and operating marginal costs, fuel prices, heat rates, availability factors, effective load carrying capabilities, endogenous buildout limits, and trade contracts), followed by adjusting some of the model logic on both sides to reach concordance as necessary. Starting from aligned data inputs, modellers of E3MC and NextGrid worked together to generate the outputs used to calculate impacts in the CBA. A schematic of the model relationships is presented in Figure 1.

Figure 1. Schematic of model relationships

Figure 1. Schematic of model relationships – Text version below the graph

Figure 1. Schematic of model relationships - Text version

Figure 1 is a flow chart showing how Energy2020 and TIM (collectively known as E3MC) and the NextGrid model interacted to create the modelling outputs used as inputs into the Cost-Benefit Analysis (CBA) and the Sensitivity Analysis. Following the arrows from top to bottom, aligned data inputs were incorporated into Energy2020 and NextGrid. Energy2020 generated its baseline scenario, which fed into TIM to generate the final E3MC baseline scenario used in the CBA, and whose exogenous units list also fed into NextGrid. NextGrid used this exogenous unit list to generate its baseline scenario and its regulatory scenario, for which it generated unit compliance decisions. These compliance decisions fed into Energy2020 to generate its regulatory scenario, which fed into TIM to generate the final E3MC regulatory scenario used in the CBA. The CBA drew from E3MC’s baseline scenario and E3MC’s regulatory scenario, while the Sensitivity Analysis drew from these scenarios alongside NextGrid’s baseline scenario and NextGrid’s regulatory scenario.

As outlined in Table 4, NextGrid models unit-by-unit “compliance decisions” by optimizing from the set of strategies available to fossil fuel-fired electricity generating units in each time step over the analytical period. For electric utilities, the available strategies are

early retirement;
retrofit to implement a CCS system;
fuel blend with RNG or hydrogen;
reduce annual hours of operation;
purchase carbon offsets up to the regulated limit; and/or
enter into a pool with other electricity generating units that meet the pooling criteria.

For industrial units (e.g. cogeneration units) that sell some of the electricity they produce to Canada’s electricity system, the available strategies are

the first five bullets specified above (i.e. everything except pooling); and/or
reduce sales of electricity to the system; or
cease selling electricity to the system (effectively taking the unit out of the scope of the Regulations).

As denoted in Figure 1, the compliance decisions undertaken by all exogenous units are modelled by NextGrid, which are then “hard-coded” into Energy2020 before being run through TIM to enable E3MC to produce the Regulatory Scenario used in the CBA. The Sensitivity Analysis uses a hybrid modelling approach, explained in detail in the Sensitivity Analysis section.

Canada Gazette, Part II model parameters and updates from Canada Gazette, Part I

There are several significant differences in the modelling that was conducted for the Canada Gazette, Part I versus the modelling that was conducted for the Canada Gazette, Part II. Importantly, if the regulatory approach as proposed in the Canada Gazette, Part I were to be remodeled using the current version of the models, the associated CBA results would be different from those presented in the Canada Gazette, Part I RIAS due to the ongoing improvements to Energy2020 and NextGrid (e.g. alignment of data inputs, technical input from key interested parties) and the changes to key modelling parameters. Accordingly, differences between the Canada Gazette, Part I CBA and the Canada Gazette, Part II CBA are not solely attributable to the policy changes undertaken between the proposed Regulations and the final Regulations. A summary of differences between the Canada Gazette, Part I and the Canada Gazette, Part II across key modelling parameters is presented in Table 5.

Table 5: Summary of key modelling parameters, the Canada Gazette, Part I versus the Canada Gazette, Part II
Key modelling parameter	Baseline Scenario (CGI)	Regulatory Scenario (CGI)	Baseline Scenario (CGII)	Regulatory Scenario (CGII)
Projection based upon	Ref22	Ref22 + CGI Clean Electricity Regulations	Ref23	Ref23 + CGII Clean Electricity Regulations
Electric Vehicle Availability Standard^{table d2 note a}	Proposed version	Proposed version	Final version	Final version
OBPS Carbon Price Schedule and Minimum National Carbon Price^{table d2 note b} and OBPSR tightening rates^{table d2 note c}	Proposed version	Proposed version	Final version	Final version
Natural gas-fired electricity regulations^{table d2 note d}	Final version	Repealed once all units have reached their "end of prescribed life", as per the proposed Clean Electricity Regulations in 2045	Final version	Repealed once all units have reached their "end of prescribed life", as per the final Clean Electricity Regulations in 2050
Coal-fired electricity regulations^{table d2 note e}	Final version	Repealed once the AEL in the proposed Clean Electricity Regulations comes into force in 2035	Final version	Repealed once the AEL in the final Clean Electricity Regulations comes into force in 2035
Suite of Budget 2023 announcements	No	No	Yes	Yes
Suite of Budget 2024 announcements	No	No	Yes	Yes
Clean Technology ITC	Yes	Yes	Yes	Yes
Carbon Capture, Utilization and Storage ITC	No	No	Yes	Yes
Proposed Clean Electricity ITC	No	No	Yes	Yes
Atlantic Loop intertie	Yes (online in 2030)	Yes (online in 2030)	No	No
New endogenous interties allowed	No (exogenous only)	Yes	No (exogenous only)	No (exogenous only)
Cogeneration unit treatment	Baseline Scenario	All cogeneration units with net exports to the electricity system implement CCS; emissions also reduce for behind the fence portion of generation	Baseline Scenario	Cogeneration units with net exports to the electricity system choose between different compliance strategies; covered emissions are only those associated with electricity sold to the system by existing units through 2049
Table d2 note(s) Table d2 note a Regulations Amending the Passenger Automobile and Light Truck Greenhouse Gas Emission Regulations. December 15, 2023. Return to table d2 note a referrer Table d2 note b Canada Gazette, Part 2, Volume 156, Number 22. Order Amending Schedule 4 to the Greenhouse Gas Pollution Pricing Act and Update to the Pan-Canadian Approach to Carbon Pollution Pricing 2023-2030 – Canada.ca Return to table d2 note b referrer Table d2 note c Regulations Amending the Output-Based Pricing System Regulations and the Environmental Violations Administrative Monetary Penalties Regulations. November 9, 2023. Return to table d2 note c referrer Table d2 note d Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. November 29, 2018. Return to table d2 note d referrer Table d2 note e Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. November 30, 2018. Return to table d2 note e referrer

As seen in Table 5, the Canada Gazette, Part II modelling is based on a modified version of the Department’s 2023 Reference Case (Ref23), which is a projection for GHG emissions in Canada that includes all federal, provincial and territorial policies and measures that are funded, legislated and implemented up to August 2023 (including the suite of announcements from Budget 2023). More information on Ref23 is presented in the subsequent subsection. In order to make the projection as up-to-date as possible when analyzing the impacts of the Regulations, Ref23 was modified for this analysis to include the federal Electric Vehicle Availability Standard) alongside the suite of Budget 2024 announcements and federal ITCs that pertain to the electricity sector, and thus does not include the 2024 Fall Economic Statement. By contrast, the Canada Gazette, Part I modelling was based on a modified version of Ref22, which only contained announced budget measures signalled in the 2022 Fall Economic Statement.

In the Canada Gazette, Part I modelling, the Atlantic Loop had been included in the Baseline Scenario. The Atlantic Loop does not feature in the Canada Gazette, Part II modelling. Additionally, the Canada Gazette, Part I modelling was set up such that NextGrid could model the build out of new endogenous interprovincial interties in order to lower national system costs. Based on feedback received during the public comment period in which provinces stated that they have no intentions to establish new interties beyond those that are already planned, the Canada Gazette, Part II modelling does not include any new interties (beside those already announced by provinces) to be constructed over the analytical timeframe.

The Canada Gazette, Part I modelling also assumed that all cogeneration units with net exports to the electricity system would undertake the compliance costs necessary to continue selling that portion to the system, and, consequently, that emissions would also reduce for the portion of generation retained behind the fence. Based on feedback received during the public comment period questioning the validity of the blanket CCS implementation behind the fence (relative to simply withdrawing electricity sold to the system), the Canada Gazette, Part II modelling is set up such that NextGrid can select between a suite of compliance strategies for cogeneration units, only one of which is to implement CCS. Moreover, due to a change in the regulatory approach for the Canada Gazette, Part II, emissions from cogeneration are only expected to reduce for the portion of electricity sold to the electricity system through 2049, after which, emissions from the portion of electricity retained behind the fence also count towards a unit’s emissions limit.

Under the Regulations, any electricity generating unit greater than or equal to 25 MW capacity that is connected to a NERC-regulated electricity system and is a net supplier of electricity as of 2035 (or the relevant compliance year) must not exceed its AEL, unless it meets all of the conditions related to one of the compliance flexibility provisions. The Regulations are “technology neutral” and do not prescribe any particular compliance pathway. All results presented in the CBA represent a modelled scenario indicating what may occur in response to the Regulations based on reasonable constraints and assumptions (i.e. central case modelling). The central case modelling does not represent the only path that the electricity sector could take to comply with the Regulations and should not be interpreted as being more probable than other potential paths. Likewise, it is important to acknowledge the vast degree of uncertainty when modelling structural changes associated with decarbonizing sectors over a long time horizon. A wide range of outcomes are ultimately possible, which could be driven by new or unanticipated technological development alongside macroeconomic factors, demographic shifts and policy landscapes at all levels of government that may fundamentally alter the Baseline Scenario on which the determination of incremental impacts depends. The sensitivity analysis section analyzes a wide range of such factors.

The Department’s 2023 Reference Case (Ref23) and its role in the CBA

Each year, the Department develops updates and publishes Canada’s GHG and air pollutant emissions projections using economy-wide model E3MC. These projections are used to report on Canada’s progress to the United Nations Framework Convention on Climate Change via biennial reports, and to help track progress towards Canada’s climate targets set out in Canada’s Nationally Determined Contribution. In its development of the Reference Case published each year, the Department undertakes extensive consultation processes with provinces and territories and other government departments on the projections for all modelled sectors (including the electricity sector). These consultation processes provide opportunities for provinces and territories to offer their input and commentary, including data, which are taken into account in the final Reference Case.

The Department’s 2023 Reference Case (Ref23) was published in Canada’s 2023 greenhouse gas and air pollutant emissions projections (2023 Emissions Projection Report, or 2023 EPR). As described in the 2023 EPR, Ref23 includes all federal, provincial and territorial policies and measures that are funded, legislated and implemented up to August 2023, such as the Output-Based Pricing System and Investment Tax Credits for clean energy. A complete list of policies and measures included in Ref23 can be found in Table A.31 and Table A.33 in the Emissions Projection Report. To generate Ref23, E3MC models all of these policies and measures across all sectors of the economy to project their combined impact on a variety of microeconomic (e.g. prices) and macroeconomic (e.g. trade) factors, as well as to project their combined impact on emissions over time.

To determine the incremental impacts of the Regulations in the CBA, a scenario with the Regulations in place (i.e. the Regulatory Scenario) is compared to a scenario without the Regulations in place (i.e. the Baseline Scenario). The Department modified Ref23 to generate the Baseline Scenario for the CBA, on which the discrete effects of the Regulations are overlaid to generate the Regulatory Scenario used in the CBA. The modifications to Ref23 (as summarized in Table 5) serve to update Ref23 based on policies and measures that became funded, legislated and implemented after the August 2023 cutoff as per the annual update process. Under the policies and measures incorporated in modified Ref23 alongside population growth, significant growth in electricity demand is projected to occur by 2050 in the Baseline Scenario, at roughly 1.5 times the demand observed 2020. Meeting this growth in demand in the Baseline Scenario will require significant capital investment to expand Canada’s electricity system. Such required investment in the Baseline Scenario will increase the costs of building and maintaining Canada’s electricity system between now and 2050; costs that are likely to be passed on to consumers in the form of increased electricity rates at the residential, commercial, and industrial levels. In the Baseline Scenario (i.e. without the Regulations), the cost of building and maintaining Canada’s projected electricity system between 2024 and 2050 is estimated at $690 billion in present-value terms^{footnote 12}, while residential electricity rates are projected to increase by a national weighted average of 9% between 2024 and 2050 in 2022 constant dollars. The impacts shown throughout the CBA depict the incremental change in results that occur when the Regulations are layered onto this Baseline.

As noted in the Background section, Canada is committed to achieving a net-zero emissions target by 2050 and has begun to announce and implement significant policies and measures to move in that direction. However, the suite of policies and measures that have been announced and implemented as of 2024 (i.e. those accounted for in modified Ref23) is not enough to set the economy onto a net-zero pathway. Achieving net-zero will require more action to be taken across all sectors of the economy over the coming decades. Accordingly, the Baseline Scenario does not depict the Canadian economy reaching net-zero emissions in 2050, as such an endpoint is not consistent with the current suite of policies and measures that have been announced and implemented. A scenario in which net-zero emissions economy-wide are reached by 2050 would require significantly greater expansion of Canada’s electricity system to meet the increased electricity demand needed to make that transition. As such, the growth in electricity demand expected from policies and measures in effect today does not necessarily reflect how large the growth in electricity demand could be in a scenario where new policies and measures that support this net-zero transition come into effect in the coming decades.

To illustrate how significant the transition to net-zero may be, the Canadian Climate Institute published a series of reports in 2022 entitled The Big Switch: Powering Canada’s Net Zero Future (CCI Electricity System Reports) to explore the implications that net-zero emissions economy-wide by 2050 may have on Canada’s electricity system. According to the CCI Electricity System Reports, national electricity demand in 2050 could increase 1.6 to 2.1 times above 2020 levels in a net-zero emissions economy. The CCI Electricity System Report imagines a hypothetical future in which unconceived and undefined actions have been taken across all sectors of the economy to achieve net-zero emissions in 2050. In this way, CCI’s modelling can be understood as a backcast (starting from a defined endpoint and determining how to get there) instead of a forecast (following current trends to an undefined endpoint). An assessment of how the incremental impacts of the Regulations may change in a world with higher electricity demand growth consistent with a net-zero emissions economy is presented in the sensitivity analysis section. In contrast to the central case (which is based on modified Ref23), the high load growth sensitivity analysis is based on a modified version of the Department’s 2023 Additional Measures Case (AM23), in which Baseline demand is estimated to increase 1.97 times between 2024 and 2050. More information on AM23, along with the incremental impacts of the Regulations under this sensitivity analysis, is presented in the sensitivity analysis section.

Electricity system mix in the central case modelling and associated reliability analysis

For the purpose of the CBA, “electricity system mix” refers to the set of infrastructure that makes up the electricity system (e.g. electricity generating units, electricity storage, CCS systems, interprovincial interties and regional transmission and distribution systems), alongside its technical specifications (e.g. electricity generation capacity, generation, fuel usage, emissions intensity, operation and maintenance factors), type (e.g. electric utility, industrial cogeneration) and usage (e.g. baseload, peak-load, back-up or emergency). Two important lenses to analyze Canada’s electricity system are its electricity generation capacity mix and generation mix. Electricity generation capacity is essentially the size of a unit, which denotes how much electricity that unit is capable of generating (typically expressed in kW, MW or GW), whereas generation is the utilization of that capacity, denoting the actual amount of electricity generated by that unit over a period of time (typically expressed in kWh, MWh or GWh). Importantly, electricity generating units are not always operated at full capacity. For example, a wind-powered unit would generate below its capacity when wind speeds are low, and a back-up natural gas-fired unit would only generate at capacity when required for reliability.

The main driver of incremental impacts in the CBA is the electricity generation capacity mix and generation mix projected for Canada’s electricity system in the regulatory scenario versus the Baseline Scenario. Under the framework outlined in Figure 1, departmental modelling projects that Canada’s electricity system would take on the electricity generation capacity mix denoted in Table 6 in the Baseline Scenario versus the electricity generation capacity mix denoted in Table 7 in the Regulatory Scenario, and the generation mix denoted in Table 8 in the Baseline Scenario versus the generation mix denoted in Table 9 in the Regulatory Scenario.

Table 6: Baseline Scenario: Canada-wide electricity system capacity mix by technology type, MW (in brackets: proportion of total electricity generation capacity)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting^{table e1 note a}	31,633 (22%)	30,353 (15%)	30,518 (13%)	28,675 (12%)	31,094 (12%)	34,775 (13%)
Abated emitting^{table e1 note b}	110 (0%)	110 (0%)	516 (0%)	822 (0%)	1,139 (0%)	1,436 (1%)
Nuclear	13,783 (10%)	11,112 (5%)	12,019 (5%)	12,334 (5%)	12,431 (5%)	11,856 (4%)
Hydro	77,738 (54%)	79,997 (39%)	88,628 (38%)	95,318 (39%)	99,123 (38%)	101,117 (36%)
Wind (onshore)	16,279 (11%)	57,744 (28%)	70,791 (30%)	74,512 (30%)	81,858 (31%)	88,984 (32%)
Solar	3,906 (3%)	14,323 (7%)	16,049 (7%)	19,897 (8%)	21,314 (8%)	20,905 (8%)
Other non-emitting^{table e1 note c}	10 (0%)	431 (0%)	431 (0%)	675 (0%)	1,435 (1%)	1,436 (1%)
Storage	225 (0%)	10,398 (5%)	14,650 (6%)	14,634 (6%)	15,573 (6%)	16,899 (6%)
Total capacity	143,684 (100%)	204,468 (100%)	233,602 (100%)	246,868 (100%)	263,967 (100%)	277,408 (100%)
Table e1 note(s) Table e1 note a For Table 6 through Table 9, "unabated emitting" refers to OGCT, OGCC, small OGCC, OG steam, coal, biomass, biogas, waste, and others. Return to table e1 note a referrer Table e1 note b For Table 6 through Table 9, "abated emitting" refers to NGCCS, coal CCS, and biomass CCS. Return to table e1 note b referrer Table e1 note c For Table 6 through Table 9, "other non-emitting" refers to offshore wind, geothermal, tidal, and wave. Return to table e1 note c referrer

Table 7: Regulatory Scenario: Canada-wide electricity system capacity mix by technology type, MW (in brackets: proportion of total electricity generation capacity)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting	31,633 (22%)	29,231 (14%)	28,448 (12%)	25,100 (10%)	23,866 (9%)	23,501 (8%)
Abated emitting	110 (0%)	110 (0%)	559 (0%)	880 (0%)	1,256 (0%)	2,255 (1%)
Nuclear	13,783 (10%)	11,114 (5%)	12,222 (5%)	12,532 (5%)	12,654 (5%)	12,075 (4%)
Hydro	77,738 (54%)	80,276 (39%)	88,956 (38%)	96,567 (38%)	101,469 (38%)	104,205 (36%)
Wind (onshore)	16,279 (11%)	58,096 (28%)	73,540 (31%)	79,975 (32%)	87,904 (33%)	98,357 (34%)
Solar	3,906 (3%)	14,349 (7%)	16,036 (7%)	19,997 (8%)	21,705 (8%)	21,892 (8%)
Other non-emitting	10 (0%)	431 (0%)	602 (0%)	935 (0%)	1,668 (1%)	1,670 (1%)
Storage	225 (0%)	11,350 (6%)	15,910 (7%)	16,655 (7%)	19,833 (7%)	24,412 (8%)
Total capacity	143,684 (100%)	204,958 (100%)	236,273 (100%)	252,642 (100%)	270,355 (100%)	288,366 (100%)

Table 8: Baseline Scenario: Canada-wide electricity system generation mix by technology type, GWh (in brackets: proportion of total generation)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting	80,393 (14%)	80,980 (11%)	63,738 (8%)	68,765 (8%)	64,164 (7%)	59,168 (6%)
Abated emitting	934 (0%)	743 (0%)	986 (0%)	1,534 (0%)	1,967 (0%)	2,581 (0%)
Nuclear	92,865 (16%)	80,921 (11%)	95,601 (12%)	97,011 (12%)	96,472 (11%)	95,582 (10%)
Hydro	358,643 (63%)	364,851 (50%)	394,829 (49%)	399,855 (48%)	411,427 (47%)	437,345 (48%)
Wind (onshore)	37,209 (6%)	181,293 (25%)	223,448 (28%)	230,748 (28%)	255,722 (29%)	279,924 (31%)
Solar	2,885 (1%)	23,620 (3%)	26,238 (3%)	29,170 (4%)	33,463 (4%)	32,479 (4%)
Other non-emitting	0 (0%)	1, 923 (0%)	1,924 (0%)	2,712 (0%)	5,806 (1%)	5,899 (1%)
Total generation	572,929 (100%)	734,331 (100%)	806,763 (100%)	829,795 (100%)	869,020 (100%)	912,979 (100%)

Table 9: Regulatory Scenario: Canada-wide electricity system generation mix by technology type, GWh (in brackets: proportion of total generation)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting	80,393 (14%)	77,676 (11%)	50,383 (6%)	45,351 (5%)	38,966 (4%)	17,921 (2%)
Abated emitting	934 (0%)	743 (0%)	997 (0%)	1,467 (0%)	4,693 (1%)	7,457 (1%)
Nuclear	92,865 (16%)	80,931 (11%)	97,251 (12%)	98,792 (12%)	99,081 (11%)	97,474 (10%)
Hydro	358,643 (63%)	365,861 (50%)	394,666 (49%)	403,912 (48%)	420,063 (48%)	451,959 (49%)
Wind (onshore)	37,209 (6%)	182,517 (25%)	233,852 (29%)	250,492 (30%)	277,584 (32%)	314,550 (34%)
Solar	2,885 (1%)	23,661 (3%)	26,230 (3%)	29,255 (4%)	33,909 (4%)	33,740 (4%)
Other non-emitting	0 (0%)	1,923 (0%)	2,973 (0%)	3,775 (0%)	6,825 (1%)	7,050 (1%)
Total generation	572,929 (100%)	733,312 (100%)	806,351 (100%)	833,044 (100%)	881,121 (100%)	930,152 (100%)

As a note of general interpretation of Tables 6 to 9, these findings are based on the suite of policies that are currently in place and do not include the possible outcomes of policies currently under consideration. As such, these findings present one possible future from amongst a broad swath of possible futures, some of which may be more preferable to provinces and territories. As seen in Table 6 through Table 9, Canada’s electricity generation capacity mix and generation mix are projected to shift towards low and non-emitting sources of electricity generation faster and to a greater extent in the Regulatory Scenario than was projected under the Baseline Scenario. Specifically, in the absence of the Regulations, Canada’s electricity system is projected to reduce its proportion of unabated emitting generation from 14% (80 TWh) in 2022 to 6% (59 TWh) in 2050 and to increase its proportion of non-emitting generation from 86% (492 TWh) in 2022 to 94% (851 TWh) in 2050. This result is due to a variety of factors, such as the regulations identified in Table 5 (i.e. the coal-fired electricity regulations, the natural gas-fired electricity regulations, the GGPPA benchmark increase, and the OBPSR tightening rates) alongside the falling costs to construct new variable renewable capacity over time that make renewables more attractive to replace aging infrastructure as older emitting units retire.

With the Regulations in place, Canada’s electricity system is projected to reduce its unabated emitting generation further than it would have without the Regulations. Specifically, in the Regulatory Scenario, Canada’s electricity system is projected to reduce its unabated emitting generation to a 2% (18 TWh) proportion in 2050 and to increase its non-emitting generation to 97% (905 TWh) in 2050, thus enabling significant GHG emissions reductions (estimated at 181 Mt over the 27-year analytical period). The central case findings represent a conservative demand growth scenario. Emissions reductions would be higher in a higher load scenario (see sensitivity analysis for the high load scenario). The CBA only considered the direct impacts attributable to the Regulations. It does not account for GHG emissions reductions achieved by other sectors of the economy that would leverage new clean energy opportunities that could lead to enhanced economic competitiveness. From a decarbonization perspective, the positive spillover effects that a net-zero electricity system in 2050 could have on other sectors of the economy could be significant (e.g. heavy industry), though such effects are out of scope of the analysis.

As seen in Table 10, Canada’s trade flows with the United States of America (U.S.) are also expected to shift. In the Baseline Scenario, imports from the United States are projected to decrease through the 2035–2039 time period then rise through 2050 for a 42% total increase in imports between 2022 and 2050. By contrast, exports in the Baseline Scenario are expected to peak in the 2035–2039 period, then fall slightly by 2050, for a 13% total increase in exports between 2022 and 2050. With the Regulations in place, import flows are projected to fall significantly relative to the Baseline Scenario in the post-2040 period, while export flows are projected to be similar.

Table 10: Baseline and Regulatory Scenario: Canada-wide electricity system international trade balances, GWh
Element	2022	2023–2029 (average)	2030–2034 (average)	2035–2039 (average)	2040–2044 (average)	2045–2049 (average)	2050
Imports (Baseline Scenario)	6,120	5,520	4,804	4,347	4,733	6,195	8,663
Exports (Baseline Scenario)	110,959	116,776	124,327	131,084	124,637	123,019	125,449
Net exports (Baseline Scenario)	104,839	111,257	119,522	126,738	119,904	116,823	116,786
Imports (Regulatory Scenario)	6,120	5,483	4,496	4,975	4,197	3,898	5,631
Exports (Regulatory Scenario)	110,959	116,497	122,585	127,247	125,026	128,129	124,291
Net exports (Regulatory Scenario)	104,839	111,014	118,089	122,272	120,829	124,231	118,660

The Regulations are crucial to ensuring that the important gains Canada has made to date in deploying clean electricity are not put at risk. Canada currently enjoys a clean electricity advantage, with over 80% of its generation coming from non-emitting sources. However, modelling projects that, in the absence of the Regulations, there is a significant risk of growing emissions in the electricity sector. Unabated natural gas can be cost competitive with options like abated natural gas and nuclear power. Electricity operators are also familiar with natural gas technology and value its ability to be easily integrated into the grid. Despite favourable conditions for renewable electricity deployment, Canada has comparatively lower levels of cheaper wind and solar than many other western countries, including all other G7 countries (e.g. 7% of Canada’s electricity mix is wind and solar compared to 39% in Germany, 34% in the United Kingdom, 15% in the United States). For these reasons, without the Regulations, more unabated natural gas would continue to be built and deployed to meet growing electricity demand. Without additional action, some modelling shows that in a scenario with higher demand growth, electricity emissions could more than double by 2050 relative to 2025 levels (See Figure 3). The Regulations ensure that as Canada’s electricity system grows, electricity emissions do not increase. These Regulations, which prohibit excessive emissions from electricity, are a key building block in helping Canada meets its net-zero economy target by 2050.

National electricity demand in 2050 in the Baseline Scenario is projected to be 1.49 times higher than 2020 levels while national electricity demand in 2050 in the Regulatory Scenario is projected to be 1.50 times higher than 2020 levels. The regulatory scenario therefore results in an 80,969 GWh increase in electricity sales, 0.5% more than in the Baseline Scenario. While these modelling results suggest that the Regulations are not expected to have a sizable impact on total nationwide electricity demand, however, there are regional variations to this result, explored in greater detail in the distributional analysis.

As depicted in Table 2 in the Background section, not all provinces are starting from the same point. Notably, Alberta, Saskatchewan, Nova Scotia, and to some extent, New Brunswick and Ontario, rely more on unabated emitting generation than the national average. Accordingly, these provinces are expected to experience the biggest shift in generation sources as a result of the Regulations. Modelled generation mixes in these five provinces are presented in Table 11.

Table 11: Electricity system generation mix by technology type in 2022 and 2050, select provinces, Baseline Scenario and Regulatory Scenario
	Scenario	Year	Unabated emitting	Abated emitting	Nuclear	Hydro	Wind (onshore)	Solar	Other non-emitting	Total generation (GWh)
NS	Both Scenarios	2022	71%	0%	0%	10%	18%	0%	0%	10,351
	Baseline Scenario	2050	11%	0%	0%	2%	65%	11%	11%	16,498
	Regulatory Scenario	2050	3%	0%	0%	3%	67%	10%	17%	17,347
NB	Both Scenarios	2022	29%	0%	40%	22%	8%	0%	0%	13,404
	Baseline Scenario	2050	6%	0%	5%	4%	75%	0%	9%	24,706
	Regulatory Scenario	2050	0%	0%	6%	5%	74%	5%	9%	24,983
ON	Both Scenarios	2022	10%	0%	54%	23%	10%	2%	0%	161,464
	Baseline Scenario	2050	6%	0%	44%	18%	32%	0%	0%	214,864
	Regulatory Scenario	2050	0%	0%	44%	23%	33%	0%	0%	216,188
SK	Both Scenarios	2022	72%	2%	0%	14%	10%	2%	0%	5,960
	Baseline Scenario	2050	32%	8%	0%	12%	45%	3%	0%	10,831
	Regulatory Scenario	2050	7%	22%	0%	17%	51%	3%	0%	11,064
AB^{table e7 note a}	Both Scenarios	2022	81%	0%	0%	4%	12%	3%	0%	66,318
	Baseline Scenario	2050	43%	0%	0%	3%	43%	11%	0%	75,249
	Regulatory Scenario	2050	16%	2%	0%	3%	71%	9%	0%	85,523
Table e7 note(s) Table e7 note a Modified Ref23 (on which this analysis is based) does not include Alberta’s recently announced restrictions on variable renewable buildout. Return to table e7 note a referrer

Defining reliability

The reliability of Canada’s electricity system is of critical importance and has been one of the three pillars of the Regulations’ development. A reliable electricity system requires both resource adequacy (having enough electricity supply available to meet the energy needs of electricity consumers at all times) and operational reliability (maintaining the electricity system’s ability to withstand sudden disturbances).

As depicted in Table 11, the vast majority of Canada’s electricity generation in 2022 was from technologies that provide “firm” capacity such as natural gas, coal, biomass, nuclear or hydropower, which are stable sources of generation that are not vulnerable to environmental factors (notwithstanding potential prolonged periods of drought). By contrast, generation from variable renewable energy (VRE) sources, such as wind and solar, naturally varies day-to-day, depending on environmental factors. To maintain reliability, firm capacity helps back up variable renewable energy (VRE) as they are incorporated into an electricity system. While the variability of wind and solar can introduce more complexity to the planning and operation of an electricity system, there are solutions for managing the variability of these sources. Key approaches include the use of dispatchable electricity generating units that can ramp up quickly such as those powered by hydro or natural gas (including those equipped with abatement technologies), alongside a wider adoption of nuclear units, energy storage, transmission interties, and operational approaches like flexible loads and demand energy response.

There are a variety of factors that could impact the reliability of the electricity system in the coming decades and would need to be considered in system planning, in both the Baseline Scenario and the Regulatory Scenario. One important factor will be increased demand for electricity, which may be driven by increased population growth, new sources of demand (e.g. the growth in data centres and artificial intelligence services) and by increased electrification of other sectors, such as transportation, buildings, and heavy industry. This increasing demand will necessitate an expansion of grid infrastructure, and a buildout of more electricity generation capacity. The required buildout of new electricity generation capacity presents an opportunity for more variable renewable energy (VRE) to be integrated into the electricity system, especially considering that the costs of wind and solar have come down dramatically in recent decades and are now an attractive non-emitting option in many regions, alongside other new innovations in distributed energy resources (DERs).^{footnote 13}For example, Nova Scotia is currently undertaking large-scale energy storage projects and plans to deploy a grid-stabilizing technology called synchronous condensers, to help ensure continued reliability of its electricity system as wind power grows to a much larger share of the province’s electricity generation.

Another consideration for reliability is the impact that climate change may have on hydropower. Climate change is expected to have an impact on precipitation patterns, resulting in more volatility and less predictability, which could have an impact on the availability and reliability of electricity generated from hydropower in years that experience low precipitation or even drought. While this consideration is not specifically incorporated into the model, the Regulations include banking provisions and enhanced emergency circumstances provisions to mitigate risks. Climate change is also projected to impact thermal generation using fossil, biomass and nuclear fuels as droughts can force lower utilization of these resources as it also reduces the amount of water available for equipment cooling; similarly, increased temperatures associated with climate change would also reduce plants efficiency.

Reliability and the role of variable renewable energy (VRE)

During engagement on the Regulations, some interested parties expressed concerns about integrating higher levels of wind and solar into the electricity system under the Regulations relative to the Baseline Scenario. Specifically, these parties expressed concern that regional electricity systems that already have high levels of VRE integration could face reliability challenges when attempting to integrate more, particularly in terms of operational issues like inertia and voltage.^{footnote 14} Further, these parties expressed concern that departmental modelling was constrained in its ability to account for the issue of maintaining enough inertia in regional power systems given its wide national scope.

As depicted in Table 8, the share of Canada’s electricity generation from VRE (“wind [onshore]”, “solar”, and “other non-emitting”) in the Baseline Scenario is projected to increase from 7% in 2022 to 35% in 2050, whereas (as depicted in Table 9), the share of Canada’s electricity generation from VRE in the Regulatory Scenario is expected to increase to 38% in 2050. Notwithstanding Prince Edward Island, which imports most of its electricity, supplemented by a small amount of own-generation that is nearly 100% VRE, the provinces that currently have the highest share of VRE-based generation are Alberta, Nova Scotia and Ontario. As depicted in Table 11, VRE-based generation in the Baseline Scenario from 2022 to 2050 is projected to increase from 18% to 76% in Nova Scotia, 8% to 75% in New Brunswick, 12% to 32% in Ontario, 12% to 48% in Saskatchewan, and 15% to 54% in Alberta. In the Regulatory Scenario, VRE-based generation in these provinces in 2050 is expected to be even higher, at 77%, 79%, 33%, 54%, and 80%, respectively.

When considering the country as a whole, the share of total electricity generation provided by wind and solar in Canada is below the international average. Specifically, the International Energy Agency’s Renewables 2023 report highlights that wind and solar have grown from 2% of global electricity generation in 2010 to 13% in 2023, and are projected to reach 25% of global electricity generation by 2028, nearly doubling their share from 2023 levels.

Many jurisdictions within Europe and the United States have reached levels of wind and solar integration well above these global averages and are seeing rapid growth in their deployment, while maintaining reliable grids. For example, in 2023, wind and solar accounted for about 67% of electricity generation in Denmark^{footnote 15}, 41% in the Netherlands^{footnote 16}, 39% in Germany^{footnote 17}, 39% in Spain^{footnote 18}, 38% in Ireland^{footnote 19}, and 34% in the United Kingdom (where the rate of integration has been particularly rapid, up from only 3% in 2010)^{footnote 20}. According to the US Energy Information Agency’s Electricity Data Browser, wind and solar provided 16% of all electricity generated in the United States in 2022, with states with various geographic locations (including some northern states that face similar seasonality to Canadian provinces) integrating wind and solar well above the US average. For example, in 2022, wind and solar accounted for 63% of electricity generation in Iowa, 58% in South Dakota, 48% in Kansas, 36% in North Dakota, 34% in California, 29% in Minnesota, and 27% in Texas.

Studies indicate that although the costs of maintaining reliability tend to increase along with the need to address reliability considerations like inertia and voltage as the share of VRE increases, the integration of high shares of VRE is manageable and feasible. VRE growth will also be impacted by regional circumstances, such as electricity system conditions, availability of transmission lines to other regions, the overall generation mix, and the use of energy storage technologies.

Based on where Canada’s regional electricity systems stand relative to European and US peers, it is reasonable to conclude that Canadian utilities would be able to integrate significantly more VRE into the electricity system than they have so far in a reliable manner, while also accounting for operational reliability considerations. The challenge of integrating higher shares of VRE remains even in the absence of a CER, as solar and wind are increasingly deployed in Canada for other reasons, including cost effectiveness and security of supply. The integration of high levels of VRE integration is manageable and realistic, given the time horizon over which the needed investments would be made (such as incorporating synchronous condensers, batteries and/or adding more transmission infrastructure), and given the extensive federal commitments available to support such investments in the electricity sector, including the Clean Electricity Investment Tax Credit, the Smart Renewables and Electrification Pathways Program, and financing from the Canada Infrastructure Bank for clean power infrastructure. Canada is also well equipped with a significant source of clean, firm power (notably hydropower), and has the potential to further realize the benefits of expanding grid interconnection, storage, and demand flexibility.

Modelling reliability

Key interested parties have consistently communicated that reliability must be a top priority for the Regulations, and while modelling cannot take account of all aspects of “operational reliability”, it was considered in the policy development process. To ensure modelling produced reasonable results, reliability constraints were built into the models.

As previously discussed, E3MC was used to generate the electricity modelling results that feed into the CBA, and NextGrid was used to project how individual units will respond to the Regulations. The projections about how existing units would comply with the constraints of the Regulations in NextGrid (e.g. if and when units will retire, install carbon capture, or continue operating without carbon capture) are used as inputs to the Energy2020 portion of E3MC.

In the NextGrid model, reliability concerns were considered in various ways. Specifically, NextGrid’s programming ensures that sufficient firm capacity is available in all modelled years to meet peak loads and reserve margins, and that different types of operating reserves are taken into account. When data was available, NextGrid has also included costs of synchronous condensers (a grid-stabilizing technology) and energy storage to meet higher penetration of wind and included limits to the integration of wind power at every time point. NextGrid has also checked the resulting projections in a model version that includes all hours of a year to ensure that there were no hours during which dispatchable generators, including backup peaking units, could not meet demand.

The Department’s modelling predicts high levels of wind and solar deployment in some provinces because it is often the cheapest source of electricity available. The buildout of wind and solar is always accompanied with firm capacity buildout, including natural gas peaking units that are sparingly used and hence contribute little to overall emissions.

The Energy2020 model uses a methodology for the capacity expansion in the electricity system, which adjusts capacity expansion to simulate the decision-making process at a particular time and location. The capacity expansion algorithm includes information on other factors such as the cost of new electricity generation capacity, desired reserve margins, political/social preferences, regulations, standards and subsidies.

Some provinces may require extra investments, such as deploying synchronous condensers, to ensure operational reliability on grids with high levels of variable renewable energy (VRE) penetration. The costs of necessary investments have been accounted for in the Department’s modelling where information was available or provided. Through its conversations with utilities, grid operators and provincial governments, the Department invited these parties to provide information on these extra investments if they believed it would impose incremental costs. One party provided this information and it was factored into the analysis.

The Department has examined at how leading international jurisdictions manage operational reliability on grids with high levels of VREs and has engaged with experts like the North American Electric Reliability Corporation (NERC) to hear their views on this topic and on the Regulations. NERC does not set any specific limits on the amount of VRE penetration for grid reliability reasons, as the practical limits would depend on the generation mix and the specific characteristics of the grid.

The Department also worked with third-party modellers with longstanding expertise in the electricity sector, with the intention of having them either substantiate the Department’s modelling results or demonstrate how the results are not representative. The results from this third-party modelling broadly aligned with the Department’s modelling results. All modelling results, including external third-party modelling, indicate that provinces could maintain reliability while complying with the Regulations.

Framework for the CBA and distributional analysis

A simplified schematic of electricity system variables and their relationships to one another is presented in Figure 2.

Figure 2: Key electricity system variables and relationships

Figure 2: Key electricity system variables and relationships – Text version below the graph

Figure 2: Key electricity system variables and relationships - Text version

Figure 2 is a flow chart showing the relationship between key electricity system variables in the analysis. Following the arrows from left to right, electricity demand drives changes in capacity mix, generation mix, and trade balance. Capacity mix impacts capital buildout, fixed operations and maintenance, refurbishment, retirements, and transmission. Generation mix impacts fuel usage, variable operations and maintenance, offsets, and carbon price. Trade balance impacts international flows and domestic flows. All of these impacts flow into total system costs, which drive changes to electricity rates. The generation mix impacts drive changes in GHG emissions and air pollutant emissions.

As depicted in Figure 2, national electricity demand ultimately drives Canada’s electricity generation capacity mix, generation mix, and trade balances. Electricity generation capacity mix comprises of the following costs: capital buildout, fixed operations and maintenance (O&M), refurbishment, retirements and transmission. Generation mix comprises of the following costs: fuel usage, variable O&M, offsets, and carbon price payments, and results in GHG emissions and air pollutant emissions. Trade balances are made up of international flows and domestic flows. Together, electricity generation capacity mix, generation mix, and trade balances interact to determine total system costs, which are distributed to consumers through electricity rates.

The CBA quantifies the incremental GHG emission reductions and the incremental air pollutant emission reductions attributable to the Regulations. The benefit associated with incremental GHG emission reductions is avoided global damage from climate change, which is measured in the CBA using the social cost of GHGs (SC-GHGs). The benefit associated with incremental air pollutant reductions is avoided adverse health impacts to Canadians and avoided adverse environmental outcomes, which are measured in the CBA using geospatial models in a simplified benefits-per-tonne (BpT) approach.

The CBA calculates incremental changes in capital buildout, fixed O&M, refurbishment, retirements, fuel usage, variable O&M, offsets, and international trade flows. The CBA does not calculate changes in transmission, as provincial and local distribution networks and operations are outside the scope of what can be modelled in NextGrid and E3MC. The CBA does not consider changes in domestic trade flows and carbon price payments, as these items are considered “transfers” under CBA methodology with a national scope. However, given that both parameters impact electricity rates, domestic trade flows and carbon price payments are presented in the Distributional Analysis section. Since electricity rates represent the flow-though of costs from the electricity sector to consumers, they are presented in the Distributional Analysis section, where affordability is also discussed.

Benefits

By prohibiting excessive CO₂ emissions, the Regulations will reduce the amount of CO₂, and as a co-benefit, other GHGs emitted by electricity generating units across Canada, as compared to the Baseline Scenario, resulting in avoided global damage from climate change. Specifically, the Regulations are expected to result in an estimated 181 Mt of GHG emissions reductions from the electricity sector between 2024 and 2050. In the Baseline Scenario, total GHG emissions over this time frame associated with Canada’s electricity system are estimated at 703 Mt. In addition, the Regulations will also reduce the amount of air pollutants emitted by electricity generating units, resulting in improvements to localized air quality, and associated avoided adverse health and environmental impact, relative to a scenario where the Regulations were not in place. Moreover, the Regulations are expected to result in net cost savings over time to the electricity sector in the form of avoided fuel usage and variable operations and maintenance costs and may help contribute to the attainment of broader long-term economic benefits. Each of these benefits is described in detail in the subsections below. The projected benefits are all above and beyond what would occur in the absence of these Regulations.

Avoided global damage from climate change

The Regulations will reduce the amount of GHGs emitted by electricity generating units across Canada, specifically, carbon dioxide (CO₂), methane (CH₄) and nitrous oxide (N₂O). As specified in Schedule 3 of the Greenhouse Gas Pollution Pricing Act, the Global Warming Potential (GWP) of CH₄ is estimated at 28 times that of CO₂, while that of N₂O is estimated at 265 times that of CO₂. Using these GWP factors as the basis to calculate CO₂e, the Regulations are estimated to result in incremental reductions of 181 Mt of CO₂e in the electricity sector over the 27-year analytical period (2024 to 2050) representing a 17% decrease in electricity sector emissions relative to the Baseline Scenario, with additional reductions of 12 Mt estimated from the use of offsets. A breakdown of these reductions over time is depicted in Table 12.

Table 12: Incremental GHG reductions (kilotonnes)
Description	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annual average
CO₂ reductions (electricity system)	12,138	31,748	47,573	50,841	17,485	159,784	5,918
CH₄ reductions (electricity system)	7	16	27	29	9	88	3
N₂O reductions (electricity system)	0	1	2	2	1	5	0
CO₂ reductions ("behind-the-fence")	0	5,241	4,413	4,340	3,708	17,701	656
CH₄ reductions ("behind-the-fence")	0	0	0	0	0	0	0
N₂O reductions ("behind-the-fence")	0	0	0	0	0	0	0
Total GHG reductions: electricity system (converted to CO₂e)	12,145	31,765	47,601	50,872	17,494	159,878	5,921
Total GHG reductions: "behind-the-fence" (converted to CO₂e)	0	5,241	4,413	4,340	3,709	17,702	656
Total GHG reductions: electricity sector (converted to CO₂e)	12,419	37,708	53,180	56,473	21,585	181,365	6,717
Offset usage	0	350	2,763	3,539	5,341	11,993	444
Total GHG reductions including offsets (converted to CO₂e)	12,419	38,058	55,944	60,012	26,926	193,358	7,161

The offsets permitted for use by the Regulations represent additional, unique and verified GHG reductions in line with the requirements of the Canadian Greenhouse Gas Offset Credit System Regulations. However, the analysis assumes that all incremental demand for offsets from the electricity sector (given an assumed price, see the Costs subsection for details) will be met by supply. Whether such offsets can truly be counted as incremental emission reductions relative to the Baseline Scenario depends on whether the generation of the offset credit is attributable to the Regulations. Depending on the extent to which the emission reductions of an offset credit are attributable to the Regulations, the range of incremental GHG reductions associated with the Regulations is 181 Mt to 193 Mt.

Any reduction in GHG emissions mitigates global damages from climate change. While direct impacts to Canadians are of paramount importance to federal regulatory development, the global welfare perspective must be considered in the case of pure public goods (such as the atmosphere), where no property rights are assigned and externalities accumulate. In order to be able to weigh the relative merits of proposals that reduce GHG emissions, policy-makers use a metric called the social cost of GHGs (SC-GHGs), which estimates the dollar value of a subset of global damages from climate change through time associated with one tonne of GHG emissions, or, conversely, the dollar value of avoided global damages from climate change through time associated with a one-tonne reduction in GHG emissions. The use of global SC-GHG estimates in regional policy making is widely considered to be justified given that the metric internalizes the externalities associated with GHG emissions, thereby allowing countries to calibrate their climate policies to socially efficient levels.

In December 2023, the United States (US) Environmental Protection Agency (EPA) published the technical report entitled Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances (US EPA Report) to explain the methodology underlying the set of SC-GHG estimates to be used henceforth in their Regulatory Impact Analyses, such as the Regulatory Impact Analysis performed for the 2024 Final Rule: New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units.

As explained in the US EPA Report, the updated SC-GHG values reflect the most recent state of climate science, derived from the interaction of four complex modules: socioeconomics and emissions, climate, damages, and discounting.^{footnote 21} The SC-GHG estimates include a variety of (negative and positive) climate change impacts such as changes in net agricultural productivity, human health effects, property damage from increased flood risk, changes in the frequency and severity of natural disasters, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services. Importantly, the estimates do not include several significant but difficult-to-model effects, such as extreme weather events, ocean acidification, and interactions or feedback loops across sectors. As such, the US EPA Report notes that the SC-GHG methodology is likely to underestimate the full impact of incremental GHG emissions.

Alongside the US EPA, the Government of Canada adopted the same SC-GHG estimates, as per the Social Cost of Greenhouse Gas Estimates – Interim Updated Guidance for the Government of Canada (Updated SC-GHG Guidance). As noted in the Updated SC-GHG Guidance, the estimates increase over time because incremental damages increase as GHG emissions accumulate in the atmosphere, and because growing incomes over time are associated with a higher willingness to pay to avoid economic damages. Estimates in Canadian dollars for the social cost of carbon (SC-CO₂), the social cost of methane (SC-CH₄) and the social cost of nitrous oxide (SC-N₂O) in select years are presented in Table 13.

Table 13: Annual SC-CO₂, SC-CH₄ and SC-N₂O values from the Updated SC-GHG Guidance in select years (2021 constant Canadian dollars per tonne, discounted to the relevant index year at 2%)
Index year	SC-CO₂	SC-CH₄	SC-N₂O
2020	$247	$2,107	$69,230
2025	$271	$2,589	$77,066
2030	$294	$3,073	$84,903
2035	$317	$3,634	$92,894
2040	$341	$4,194	$100,886
2045	$367	$4,803	$109,902
2050	$394	$5,410	$118,919

To estimate the benefit of the Regulations with respect to climate change, the SC-GHG values presented in Table 13 were converted from 2021 to 2022 constant dollars using a conversion factor of 1.0733 (derived from the GDP deflator estimates in E3MC), then multiplied by the tonnage reductions in each pollutant summarized in Table 13, before discounting the results back to base year 2024 at 2%. As seen in Table 14, the Regulations are estimated to result in $44.4 billion of avoided global damage from climate change attributed to the electricity sector over the 27-year analytical period, with additional estimated benefits of $2.9 billion associated with the use of offsets over that same period. As such, the range of incremental climate change benefits associated with the Regulations is estimated at $44.4 billion to $47.3 billion, depending on the extent to which those offsets are assumed to be incremental to the Baseline Scenario. To be conservative in this assumption, the low-end estimate is reported in the central scenario of the CBA.

Table 14: Avoided global damage from climate change (millions of dollars)
Description	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
From CO₂ reductions (electricity system)	$3,145	$8,007	$11,716	$12,188	$4,117	$39,173	$1,892
From CH₄ reductions (electricity system)	$19	$49	$83	$93	$28	$272	$13
From N₂O reductions (electricity system)	$28	$68	$122	$128	$37	$383	$18
From CO₂ reductions ("behind-the-fence")	$0	$1,323	$1,087	$1,041	$873	$4,323	$209
From CH₄ reductions ("behind-the-fence")	$0	$0	$0	$0	$0	$1	$0
From N₂O reductions ("behind-the-fence")	$0	$8	$8	$7	$3	$27	$1
Total climate change mitigation associated with electricity system	$3,217	$8,179	$12,002	$12,490	$4,205	$40,094	$1,936
Total climate change mitigation associated with "behind-the-fence"	$0	$1,332	$1,095	$1,049	$877	$4,352	$210
Total climate change mitigation associated with electricity sector	$3,217	$9,511	$13,097	$13,539	$5,082	$44,447	$2,146
Climate change mitigation from offset usage	$0	$88	$681	$849	$1,257	$2,875	$139
Total climate change mitigation including offsets	$3,217	$9,600	$13,778	$14,387	$6,340	$47,321	$2,285

Avoided adverse health impacts to Canadians

Air pollutant emissions decrease in tandem with GHG emissions when non-emitting generation replaces emitting generation. However, abated emitting generation (such as natural gas with CCS) are only designed to abate GHG emissions, and, all else equal, uses more fuel per MWh of electricity produced than unabated emitting generation in order to power the CCS system. Generally speaking, abated emitting generation combusts more fuel than unabated emitting generation and CCS technologies only abate GHG emissions. As such, whether air pollutant emissions decrease on net will depend on the extent to which non-emitting generation versus abated emitting generation displaces emitting generation in the Regulatory Scenario.

On net, the Regulations are expected to reduce the amount of air pollutants emitted by electricity generating units, including nitrogen oxides (NO_X), sulfur oxides (SO_X), primary particulate matter less than 2.5 microns in width (PM_2.5) and mercury (Hg). NO_X emissions lead to nitrogen dioxide (NO₂) concentrations in ambient air and contribute to the secondary formation of PM_2.5 and ground-level ozone in the atmosphere. SO_X emissions contribute to sulfur dioxide (SO₂) and sulphate concentrations in ambient air, also resulting in the secondary formation of PM_2.5 in the atmosphere.

Reductions in these air pollutants will result in some improvements to localized air quality, depending on the geographical and meteorological features of the emission sites, which, in turn, could result in some avoided adverse health impacts, depending on the size and proximity of populations relative to the emission sites. The Regulations are estimated to result in total air pollutant reductions over the 27-year analytical period of 346 kt of NO_X, 28 kt of SO_X, 9 kt of PM_2.5, and 34 kg of Hg, representing a 16%, 3%, 11%, and 1% decrease in electricity sector air pollutants respectively relative to the Baseline Scenario. A breakdown of these reductions over time is depicted in Table 15, and a breakdown by province is depicted in Table 16.

Table 15: Incremental air pollutant^{table e11 note a} emission reductions (tonnes)
Description	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annual average
NO_X (electricity system)	11,214	49,656	114,865	100,191	27,898	303,823	11,253
SO_X (electricity system)	5,884	2,122	3,687	4,836	1,931	18,459	684
PM_2.5 (electricity system)	159	915	3,046	2,439	588	7,147	265
Hg (electricity system)	0.005	0.002	0.004	0.007	0.002	0.02	0.001
NO_X ("behind-the-fence")	-2	13,617	11,779	11,560	4,823	41,778	1,547
SO_X ("behind-the-fence")	-2	2,495	2,495	2,440	1,679	9,107	337
PM_2.5 ("behind-the-fence")	24	515	547	545	215	1,846	68
Hg ("behind-the-fence")	-	0.01	0.004	0.004	0.002	0.01	0.001
Table e11 note(s) Table e11 note a E3MC accounts for air pollutant emissions from electricity generation as well as a relatively small amount of air pollutant emissions from operational processes including distribution. It is possible for some technology types to be associated with zero air pollutant emissions from electricity generation but positive air pollutant emissions from operational processes. The totals presented in Table 15 and Table 16 represent the sum of all sources of air pollutant emissions. Return to table e11 note a referrer

Table 16: Incremental air pollutant emission reductions (tonnes) by region, 2024 to 2050
Region	NO_X	SO_X	PM_2.5	Hg
NL	18	0	5	0
PE	0	0	0	0
NS	14,956	8,056	89	0.00713
NB	3,285	105	83	0
QC	-5	0	0	0
ON	178,565	1	6,595	0.00003
MB	0	0	0	0
SK	20,205	6,530	390	-0.00133
AB	143,613	12,973	2,057	0.02828
BC	527	56	14	0
YT	-63	0	-5	0
NT	0	0	0	0
NU^{table e12 note a}	-15,501	-155	-234	0
Total	345,601	27,567	8,993	0.03411
Table e12 note(s) Table e12 note a Due to the endogenous nature of E3MC, the model may select different pathways in the Regulatory Scenario than it does in the Baseline Scenario even if there is no regulatory requirement for such change. For example, even though electricity generating units in Nunavut are not expected to be subject to the Regulations over the analytical period, the model responds to different price signals (brought about by other changes in the Regulatory Scenario) than it did in the Baseline Scenario. In this case, the endogenous capacity constructed in the Baseline Scenario, is lower emitting and less expensive than the endogenous capacity constructed in the Regulatory Scenario. This is not due to regulatory requirements, but rather, due to dynamic price impacts that the model reacts to. As a result, E3MC shows higher incremental emissions relative to the Baseline Scenario. Return to table e12 note a referrer

As seen in Table 16, Ontario, Alberta, Saskatchewan and Nova Scotia are the regions modelled to incur the greatest amount of air pollutant emissions reductions, largely attributable to the switch from unabated emitting generation to low or non-emitting generation. The Regulations would result in varying levels of air quality benefits depending on the precise location of these air pollutant emission reductions.

Globally, air pollution is a major contributor to the development of disease and premature death, and a key environmental risk factor to human health. The health effects of exposure to NO₂, PM_2.5 and ozone are well documented, and have been reviewed in-depth by the Department of Health and by international organizations such as the World Health Organization.^{footnote 22} Exposure to air pollution increases the risk of premature mortality from heart disease, stroke and lung cancer, as well as the risk of adverse respiratory and cardiovascular diseases. Children, the elderly and individuals with underlying health conditions are particularly vulnerable to the adverse effects of air pollution. Moreover, scientific evidence shows that adverse health effects occur at very low concentrations for many pollutants, with no indication of a threshold below which there are no risks. Therefore, a small decrease in air pollution is associated with a reduction in the risk of adverse health outcomes for exposed populations.

Exposure to Hg is associated with a wide range of adverse health effects in humans (notably, the nervous system), with developing fetuses and children being the most susceptible to such exposure. The regulations would reduce Hg emissions by 34.1 kilograms over the 27-year analytical period, mostly in Alberta (28.3 kilograms). While the health impacts associated with Hg emission reductions were not quantified or monetized, these reductions are expected to reduce the risk of adverse health outcomes for affected populations, which would accrue into the future.

In Canada, air pollution is responsible for significant population health impacts. The Department of Health estimates that 17 400 deaths were attributable to exposure to ambient concentrations of PM_2.5, NO₂ and ozone in 2018 in Canada, as well as 3.6 million asthma symptom days and other morbidity outcomes, representing a total monetized value of $146 billion (2020 constant dollars).^{footnote 23} In addition, the Department of Health estimates that, in 2015, 150 premature deaths were attributable to exposure to air pollution from electricity generating units in Canada as well as many non-fatal outcomes, equivalent to $1.2 billion (2015 constant dollars) in monetized health impacts.^{footnote 24} While much of these negative health impacts associated with electricity generation in 2015 are expected to have been significantly mitigated by the existing Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, the Regulations are expected to further reduce adverse health impacts.

The impacts of the Regulations on air quality (i.e. on key air pollutants such as PM_2.5, NO₂, and ozone) and the resulting health benefits are monetized using a benefits per tonne (BpT) approach. The Department of Health conducted air quality simulations and health impact analyses based on defined changes in emissions in the electricity sector to derive estimates of the monetized value of health benefits associated with one tonne of emissions reduction for each of NO_X and PM_2.5 from the electricity sector at the national level. Given that coal-fired electricity generating units are the dominant source of SO_X emissions in the electricity sector, existing regulations are expected to considerably reduce national SO_X emissions by 2036; whereas the Regulations are only expected to result in small incremental changes in SO_X emissions in 2036 and beyond, in which meaningful differences in ambient air quality are not expected. Consequently, a BpT value was not derived for SO_X emissions.

To perform the BpT analyses, the Department of the Environment’s Global Environmental Multi-scale - Modelling Air quality and Chemistry (GEM-MACH) tool was used to estimate ambient air concentrations of PM_2.5, ozone and NO₂ associated with electricity generating units emissions in 2036. The results were then used in the Department of Health’s Air Quality Benefits Assessment Tool (AQBAT), version 3, to estimate and monetize the air pollution health impacts. AQBAT incorporates the changes in air pollutant concentrations (between the Regulatory Scenario and the Baseline Scenario) along with data on Canadian populations, health endpoint occurrence rates and concentration-response functions to estimate the number of adverse health outcomes, including morbidity and premature deaths, associated with the modelled change in ambient concentrations. In addition, AQBAT provides economic valuation estimates of those health impacts (i.e. monetized health impacts). AQBAT was used to estimate air pollution health impacts in 2036 as well as in 2043 and 2050, thus accounting for demographic changes (e.g. population size, age and health) over the entire analysis period.

Electricity sector-specific BpT values were estimated by first modelling a Baseline Scenario to ascertain the effects of NO_X emissions and PM_2.5 emissions on ambient concentrations in NO₂, PM_2.5 and ozone. Then, hypothetical scenarios were modelled in which NO_X emissions from the electricity sector fall by 20% (to produce a low-end estimate) or 100% (to produce a high-end estimate), and PM_2.5 emissions from the electricity sector fall by 100%. Under this methodology, emissions of NO_X and PM_2.5 from all emitting electricity generating units in Canada were uniformly reduced for only one pollutant in each simulation. Based on the incremental outcomes between each hypothetical scenario and the Baseline Scenario, the modelling exercise produced two BpT values, one low and one high, for NO_X emissions and a single BpT value for PM_2.5. These electricity sector-specific BpTs are presented in Table 17 below.

Table 17: National health benefits per tonne by pollutant for the electricity sector in select years ($/tonne, 2022 constant dollars, undiscounted)
Description	2036	2043	2050
PM_2.5	209,540	236,540	242,947
NO_X–high^{table e13 note a}	14,231	16,676	17,691
NO_X–low^{table e13 note b}	7,029	8,150	8,555
Table e13 note(s) Table e13 note a NO_X–high: represents the BpT values derived from the 100% reduction in NO_X emissions scenario. Return to table e13 note a referrer Table e13 note b NO_X–low: represents the BpT values derived from the 20% reduction in NO_X emissions scenario. Return to table e13 note b referrer

To estimate the value of health benefits due to the air pollutant emission reductions associated with the final Regulations, the Department of Health multiplied the appropriate BpT in Table 17 by the value of annual emission reduction in tonnes (Table 15). Specifically, the Department of Health used the 2036 BpT values to estimate the annual health benefits for each year during the 2024 to 2039 period. Similarly, the 2043 BpT values were used to estimate annual health benefits during the 2040 to 2046 period, and the 2050 BpT values were used to estimate the annual health benefits during the 2047 to 2050 period. BpT years closest to the analysis years were selected to generate the estimate of annual health benefits. Selecting the closest BpT years potentially minimizes over and underestimation of health benefits relative to using BpT from further years. Finally, the annual health benefits were summed and discounted over the entire period (2024–2050) to estimate the net present value of total air pollution health benefits between the Baseline Scenario and the Regulatory Scenario.

At the national level, the Regulations are estimated to result in present value of health benefits ranging from $3.3 billion to $5.3 billion between 2024 and 2050. The low-range estimate combines the estimates using the PM_2.5 and the NO_X–low BpTs, whereas the high range estimate combines the PM_2.5 and the NO_X–high BpTs. While the range provides reasonable guidance to inform the air pollution health benefits related to the Regulations, the low-end estimate is reported for the central scenario of the CBA as it is more conservative given the methodology selected. A breakdown of these results over time are presented in Table 18.

Table 18: Incremental health benefits (millions of dollars)
Description	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average
NO_X-low	70	341	723	595	167	1,896	92
NO_X-high	141	690	1,480	1,225	346	3,883	188
PM_2.5	35	229	596	456	116	1,431	69
Total – low	104	570	1,319	1,051	284	3,328	161
Total – high	175	919	2,076	1,681	462	5,314	257

More information on the general BpT methodology and limitations on its use is available in the Department of Health’s 2022 publication entitled Health Benefits per Tonne of Emissions Reduction (PDF). In brief, there are limitations to the analyses used to derive BpT estimates and to their application, which could influence the magnitude of the estimated health impacts. In this analysis, the BpT approach does not permit provincial or territorial breakdown of the benefits owing to methodological considerations. In addition, the benefits as shown in Table 18 could underestimate the actual health benefits related to emission reductions from the Regulations, because the BpT estimates do not include health benefits due to potential reductions in ambient air pollutants other than PM_2.5, ozone and NO₂. Further, the BpT approach is ideally used for smaller incremental changes in emissions than those associated with the Regulations. The combined effect of these uncertainties on the health burden estimates, in terms of magnitude and direction, cannot be estimated. While the application of BpT in the context of regulatory analysis of air pollution-related health impacts is novel in Canada, and not without limitations, the BpT method is used by other jurisdictions such as the United States, to estimate the air pollution health impacts associated with various sources of air pollution.^{footnote 25}

Avoided adverse environmental outcomes

To the extent that the reductions in air pollution depicted in Table 15 improve localized air quality, the proposed Regulations may also reduce environmental harms. Reducing environmental harms can improve yield for crop producers, improve health of forest ecosystems, and reduce risk of illness or premature death within sensitive wildlife or livestock populations. As well, reducing air pollution can lead to avoided cleaning costs for surface soiling, improved visibility, and enhanced recreational activities in proximity to the emission site.

The Department’s Air Quality Valuation Model 2 (AQVM2) was used to estimate the environmental impacts of air quality improvement associated with the Regulations on crops productivity, soiling, and visibility. As was the case with health benefits, electricity sector-specific BpT values were estimated by modelling a Baseline Scenario, then modelling hypothetical scenarios in which NO_X, SO_X, and PM_2.5 fall by 100%. Based on the incremental outcomes between each hypothetical scenario and the Baseline Scenario, the modelling exercise produced the BpT values presented in Table 19. Sector-specific BpT estimates were generated for the years 2026, 2036, 2043 and 2050 to account for the evolution of endpoints over time (e.g. population increase), which implicitly assumes that changes in air quality (and therefore benefits) are linearly correlated to changes in emissions.

Table 19: National environmental benefits per tonne by pollutant for the electricity sector in select years ($/tonne, 2022 constant dollars, undiscounted)
	2026	2036	2043	2050
PM_2.5	1,032	1,115	1,164	1,216
NO_X	188	214	233	254
SO_X	114	125	130	134

The sector-specific BpT estimates for each of the pollutants in Table 19 were multiplied by the expected emission reductions associated with the Regulations in Table 15. Annual results for the 2024–2031, 2032–2039, 2040–2046 and 2047–2049 periods were respectively prorated to the 2026, 2036, 2043 and 2050 BpT estimates, based on the annual emission changes for each pollutant. At the national level, the Regulations are estimated to result in environmental benefits of approximately $65 million between 2024 and 2050. A breakdown of these benefits over time is presented in Table 20. Due to limitations in the BpT methodology selected, the national benefits cannot be disaggregated by region.

Table 20: Incremental environmental benefits (millions of dollars)
Description	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average
Soiling	0	2	4	3	1	11	0.5
Visibility	2	8	16	13	4	43	2
Agriculture	0	2	4	3	1	11	0.5
Total	3	12	24	20	6	65	3

Air pollutant emissions contribute to the formation of secondary particulate matter, which may accumulate on surfaces and alter their optical characteristics. Such soiling may increase the frequency and costs of cleaning and generate aesthetic amenity losses. AQVM2 estimated the avoided cleaning costs for Canadian households associated with different levels of particulate matter of 10 micrometres or less in diameter (PM₁₀). Over the analytical period, avoided household cleaning costs of about $11 million are expected. These benefits should be considered as conservative as they do not account for avoided cleaning costs in the commercial and industrial sectors.

All else being equal, visibility increases as ambient concentrations of particulate matter decrease since particulate matter can block and scatter the direct passage of sunlight. Based on the willingness to pay for improved visual range and air quality changes, AQVM2 estimates the monetary change in welfare for different levels of deciviews.^{footnote 26} Welfare gains from improved visibility in the residential sector are approximately $43 million over the period.

Air pollutant emissions contribute to the formation of ground-level ozone, which may interfere with the ability of sensitive plants to produce and store food, as well as increase their vulnerability to certain diseases, insects, harsh weather and other pollutants. Reductions in air pollutant emissions would therefore decrease ambient concentrations of ground-level ozone, which may result in higher crop yields. Based on biological exposure-response functions for 19 different types of crops, AQVM2 estimated the changes in production (tonnes) associated with the changes in ozone concentrations for each Census Agricultural Region (CAR), as well as the associated change in sales revenue for Canadian crop producers. National benefits from increased crops productivity, expressed in the present value of sales revenue over the analytical period, are expected to be approximately $11 million.

The estimates should be considered as conservative since only the impacts on soiling, visibility and agricultural productivity were assessed by AQVM2. Reducing air pollutant emissions may also have other environmental benefits. For instance, the associated reduction in concentrations of ozone and particulate matter may benefit forest ecosystems health (therefore improving vegetation’s capacity to provide ecosystem services such as air filtration and carbon sequestration), while visibility improvement may result in higher enjoyment of recreational and increased tourism revenues. In addition, lower levels of ground-level ozone and particulate matter may reduce the risks of illness or premature death within sensitive wildlife or livestock populations, potentially resulting in avoided treatment costs or economic losses for the agri-food industry. However, due to data or methodological limitations, these benefits have not been quantified.

Fuel cost savings

Emitting generation requires the combustion of a fuel source (e.g. coal, natural gas, heavy fuel oil, biomass, waste) to generate electricity. By contrast, non-emitting generation uses renewable energy sources such as water, wind, nuclear, geological heat or the sun to generate electricity; some renewable energy source is provided intermittently by the natural environment. On net, the transition from emitting generation to low or non-emitting generation under the Regulations is expected to reduce the amount that the electricity sector spends on fuel. Specifically, the Regulations are estimated to result in 2,976 petajoules of avoided fuel usage in the electricity sector (Table 21) associated with $6.6 billion in fuel savings to the sector over the 27-year analytical period (Table 22), which represents an 8% decrease relative to the Baseline Scenario. Alternative assumptions regarding fuel prices and fuel availability are explored in the Sensitivity analysis.

Table 21: Incremental fuel usage (petajoules)
Fuel type	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annual average
Natural gas	-234	-679	-952	-891	-271	-3,025	-112
Coke oven gas, petroleum coke, and still gas	0	0	0	0	0	0	0
Heavy and light fuel oil	0	-3	-3	-3	-1	-8	-0.3
Diesel and gasoline	1	2	3	3	1	9	0.3
Coal	-6	0	0	0	0	-6	-0.2
Biomass and waste	-4	-15	-77	-77	-15	-188	-7
Renewable natural gas	0	82	53	58	45	239	9
Hydrogen	0	1	1	1	0	4	0.2
Total	-243	-611	-974	-907	-241	-2,976	-110

Table 22: Incremental fuel costs by province (millions of dollars)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	0	0	0	0	0	0	0
PE	0	0	0	0	0	0	0
NS	-34	175	-170	-166	-46	-591	-29
NB	0	0	-1	-352	-67	-420	-20
QC	0	0	0	0	0	0	0
ON	-115	-886	-1,388	-1,076	-348	-3,813	-184
MB	0	0	0	0	0	0	0
SK	-103	-101	-178	-99	-17	-497	-24
AB	-279	-98	-568	-515	-11	-1,471	-71
BC	-22	0	0	0	0	-22	-1
YT	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	15	35	57	66	14	187	9
Total	-537	-1,224	-2,248	-2,141	-476	-6,627	-320

Variable operations and maintenance cost-savings

As generalized from Table 3 in the Background section, the variable operation and maintenance (O&M) costs associated with most VRE is zero, while that of nuclear and hydro can be three to seven times lower than that of unabated natural gas. On net, the transition from emitting generation to low or non-emitting generation under the Regulations is expected to reduce the amount of money that the electricity sector spends on variable O&M. This impact is calculated by multiplying the changes in generation mix (Table 23) by the average variable O&M cost per technology type in a given region and year. Overall, the Regulations are estimated to result in $430 million in variable O&M savings to the electricity sector over the 27-year analytical period (Table 24), representing a 13% decrease relative to the Baseline Scenario.

Table 23: Incremental electricity generation (GWh)
Technology type	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annual average
Unabated emitting	-29,039	-98,375	-145,616	-153,602	-55,650	-482,282	-17,862
Abated emitting	-264	15,606	18,122	30,249	16,257	79,970	2,962
Nuclear	329	8,200	8,279	10,126	1,892	28,827	1,068
Hydro	5,952	5,071	30,438	54,804	14,614	110,880	4,107
Wind (onshore)	25,422	62,494	109,188	123,118	34,733	354,955	13,146
Solar	1,907	2,954	2,336	5,811	1,373	14,382	533
Other non-emitting	-5	6,125	5,742	5,288	1,151	18,301	678
Total	4,303	2,075	28,490	75,794	14,371	125,033	4,631

Table 24: Incremental variable O&M costs by region (millions of dollars)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	-2	0	-1	-15	0	-18	-1
PE	0	0	0	0	0	0	0
NS	-4	-22	-20	-19	-5	-70	-3
NB	0	0	0	-14	-3	-17	-1
QC	1	-2	5	27	4	35	2
ON	-9	-70	-81	-36	-17	-214	-10
MB	0	1	1	1	0	3	0
SK	-20	-18	-21	82	32	55	3
AB	-78	-14	-88	-72	49	-203	-10
BC	-3	0	0	0	-1	-3	0
YT	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	0	1	1	1	0	4	0
Total	-114	-126	-205	-46	60	-430	-21

Potential broader economic benefits associated with a clean electricity system

The CBA does not directly account for the broader economic benefits (i.e. to Canada’s industrial sectors) that would arise where new demand for electricity is supplied by clean, non-emitting sources of generation; however, this potential benefit is explored qualitatively. The Canada Energy Regulator, Trottier and others have found that demand for electricity will increase significantly as households and businesses respond to market signals and seek to decrease their carbon intensity. This demand is difficult to predict and is generally much higher in modelling scenarios that attempt to show how electricity systems evolve in a world where countries are meeting their climate targets and moving towards net-zero GHG emissions in 2050. As previously noted, the central case modelling for the CBA is based on the Department’s Ref23 Current Measures scenario in which demand for electricity grows significantly in both the Baseline and Regulatory Scenarios (i.e. 1.5 times 2020 demand). Given how difficult it is to predict demand as far out in the future as 2050, sensitivity analysis was performed to look at the implications of the Regulations under a wide range of scenarios where electricity demand is closer to double current demand, using various in-house and contracted models. Regardless of the demand scenario selected (central case or sensitivity case), the Regulations are expected to result in net benefits to society, with Canada’s electricity system being cleaner than it otherwise would have been, sooner than it otherwise would have been, therefore enabling the potential to reap broader benefits with respect to clean electricity.

New electricity demand in 2050 and beyond is anticipated to be supplied with clean, net-zero emission electricity to meet the global movement to net-zero economies; in this context, industries with access to clean electricity have less risk exposure to carbon reduction policies, such as border carbon adjustments and market pressures to produce low-carbon products. Though difficult to quantify (and beyond both the scope of the analytical time frame and the scope of the Regulations), this is expected to be a benefit for Canadian industries as they move to decarbonize their operations to meet the needs of their customers and keep pace with global competition. For example, the industrial sector accounted for 41% of Canada’s end-use energy demand in 2021 with natural gas accounting for 49% or energy used compared to 21% for electricity. Access to non-emitting electricity is a key factor for reducing carbon intensity of industrial production, including steel and aluminum (electric arc furnaces), mining (electrifying operations), oil and gas production electrifying upstream operations and liquified natural gas processing), chemicals (fuel switching for generating heat for production) and cement (electricity to help heat kilns).

Roughly 40% of the largest private companies and about 70% of the world’s largest public companies, with a total yearly revenue of $2.2 trillion and over $13 trillion respectively, have set net-zero targets.^{footnote 27} In a world where companies are following through on their net-zero commitments, the ability to supply key inputs, like steel and cement with lower carbon intensity than the competition, creates a competitive advantage for early movers. The availability of non-emitting electricity makes generating these inputs at lower carbon intensity more technically and economically feasible by enabling the use of fuel switching or emerging technologies such as electric arc furnaces and carbon capture and storage and direct air capture, which are energy-intensive processes. As such, with a net-zero emission electricity system, Canada can maintain and strengthen its competitive position for future international and commercial investment.

Costs

To realize the benefits outlined in the proceeding subsection, costs are expected to accrue to the electricity sector over time in the form of capital costs for new electricity system capacity, fixed operations and maintenance, refurbishment (i.e. cost of sustaining capital), net import expenditure, offsets, and residual value on early retirements and associated replacement costs for cogeneration heat needs. The Regulations will also result in increased administrative costs to the electricity sector and increased costs to the federal government. Each of these costs are described in detail in the subsections below.

Capital costs for new electricity system capacity

In the Baseline Scenario, under the policies and measures included in modified Ref23 alongside a projected 41% increase in electricity demand between 2024 and 2050, the electricity sector is projected to build out 158 GW in new electricity system capacity (including 18 GW of unabated emitting, 1 GW of abated emitting, 2 GW of nuclear, 73 GW of onshore wind, 24 GW of hydro, 20 GW of storage, 19 GW of solar, and 1 GW of other non-emitting) at an estimated total capital cost of $288 billion from 2024 to 2050. In the Regulatory Scenario, the rate at which VRE capacity is projected to expand over time is only slightly higher than in the Baseline Scenario, whereas the Regulatory Scenario tends to elicit a significantly higher rate of incremental buildout of nuclear, hydro, abated emitting electricity generation capacity, and to some extent, biomass, all of which are considered “firm capacity” (i.e. reliable sources of electricity to contribute to baseload and to back up VREs). Overall, the Regulations are expected to result in 14 GW of new electricity system capacity over and above the 158 GW expected in the Baseline Scenario.

The incremental capital cost of the Regulations is calculated by multiplying the changes in buildout of new electricity system capacity (Table 25) by the average capital cost per technology type in a given region and year. As generalized from Table 3 in the Background section, the capital cost to construct one MW of new electricity generation capacity in nuclear, hydro, and biomass is historically two to five times higher than that of unabated natural gas, while that of onshore wind, solar, and abated natural gas is on par to two times higher. Across sectors, capital costs for emerging technologies are known to decrease over time due to “learning by doing” and economies of scale, which are incorporated into the modelling. The modelling also incorporates the complete and uniform uptake of all ITCs on new electricity system capacity build-out for the years they are available.^{footnote 28} Accordingly, the results presented in this subsection are reflective of the costs faced by the electricity sector (i.e. net of all available ITCs). The portion of incremental buildout that is covered by the ITCs in the modelling is accounted for in the Government costs subsection.

Overall, the Regulations are estimated to result in $24 billion in incremental capital costs to the electricity sector over the 27-year analytical period (Table 26), representing an 8% increase relative to the Baseline Scenario. Alternative assumptions regarding capital costs and buildout constraints are explored in the Sensitivity Analysis.

Table 25. Incremental buildout of new electricity system capacity (MW) by region and technology type, 2024 to 2050
Region	Unabated emitting	Abated emitting	Nuclear	Hydro	Wind (onshore)	Solar	Other non-emitting	Storage	Total
NL	6	0	0	-2	0	0	-2	4	6
PE	0	0	0	0	0	0	0	0	0
NS	-1,299	0	0	0	343	0	236	1,387	667
NB	-195	0	25	1	0	995	0	374	1,200
QC	0	0	0	414	0	0	0	282	696
ON	-7,081	0	203	2,344	621	0	0	4,758	845
MB	-211	0	0	18	834	-3	0	270	908
SK	-687	410	0	278	302	3	0	400	706
AB	-692	2,190	0	0	7,429	153	0	32	9,111
BC	0	0	0	35	0	0	0	6	41
YK	0	0	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0	0	0
NU	3	0	-9	0	0	-4	0	0	-10
Total	-10,156	2,600	219	3,088	9,529	1,144	234	7,513	14,170

Table 26. Incremental capital costs for new electricity system capacity by region (millions of dollars)
Region	2024-2034	2035-2039	2040-2044	2045-2049	2050	27-year total	Annualized average (n=27)
NL	1	4	-1	-13	2	-6	0
PE	0	0	0	0	0	0	0
NS	-190	1,297	-10	-211	-27	858	41
NB	1	-8	227	469	0	689	33
QC	33	661	724	201	833	2,452	118
ON	172	3,719	4,765	2,704	-18	11,342	548
MB	-36	150	450	91	27	682	33
SK	685	237	180	-34	232	1,300	63
AB	1,876	1,805	885	248	2,189	7,003	338
BC	139	176	-26	-71	6	224	11
YK	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	-20	-27	-3	-13	0	-63	-3
Total	2,661	8,014	7,190	3,372	3,245	24,482	1,182

Fixed operations and maintenance costs

As generalized from Table 3 in the Background section, the annual fixed operation and maintenance (O&M) costs associated with nuclear, biomass, onshore wind, solar, unabated natural gas, and hydro is three to eight time higher than that of unabated natural gas, while that of storage is 29 times higher. On net, the transition from emitting generation to low or non-emitting generation under the Regulations is expected to increase the amount of money that the electricity sector spends on fixed O&M. This impact is calculated by multiplying the changes in electricity generation capacity mix (Table 27) by the average fixed O&M cost per technology type in a given region and year. Overall, the Regulations are estimated to result in $7 billion in incremental fixed O&M costs to the electricity sector over the 27-year analytical period (Table 28), representing a 2% increase relative to the Baseline Scenario.

Table 27. Incremental electricity system capacity (MW)
Technology type	2024-2034	2035-2039	2040-2044	2045-2049	2050	27-year total	Annual average
Unabated emitting	-7,703	-14,865	-28,888	-44,565	-12,804	-108,825	-4,031
Abated emitting	-14	2,467	2,702	2,747	2,600	10,502	389
Nuclear	41	1,009	1,039	1,102	219	3,410	126
Hydro	1,855	2,570	8,678	13,020	3,088	29,211	1,082
Wind (onshore)	7,440	15,720	30,345	33,916	9,409	96,829	3,586
Solar	426	789	1,791	4,532	1,024	8,562	317
Other non-emitting	0	1,140	1,444	1,164	234	3,982	147
Storage	5,946	6,900	15,412	25,783	7,513	61,554	2,280
Total	7,991	15,730	32,523	37,699	11,282	105,225	3,897

Table 28. Incremental fixed O&M costs by region (millions of dollars)
Region	2024-2034	2035-2039	2040-2044	2045-2049	2050	27-year total	Annualized average (n=27)
NL	0	0	-1	-1	0	-2	0
PE	0	0	0	0	0	0	0
NS	226	383	417	372	72	1,470	71
NB	0	0	43	112	24	180	9
QC	2	12	53	66	27	160	8
ON	3	143	432	724	185	1,486	72
MB	32	44	140	172	36	423	20
SK	116	72	54	45	25	311	15
AB	235	533	975	885	267	2,895	140
BC	8	22	19	9	2	60	3
YT	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	-2	-3	-4	-5	-1	-15	-1
Total	620	1,205	2,129	2,378	636	6,969	337

Refurbishment costs (costs of sustaining capital)

Refurbishment costs are capital costs undertaken to return an electricity generating unit that has reached the end of its operational life to a “like new” state. The year in which an electricity generating unit is expected to undertake refurbishment is estimated by taking that unit’s year of commissioning and adding the “estimated operating lifetime” from Table 3 in the Background section. For technologies with relatively short estimated operating lifetimes (e.g. storage and VRE), it is possible that new built-out undertaken within the projection period will require one cycle of refurbishment in or before 2050. Refurbishment costs are calculated by multiplying the changes in refurbished electricity generation capacity (Table 29) by the average cost of refurbishment per technology type in a given region and year. In the absence of unit-specific data, the average cost of refurbishment is estimated at one third the average cost of constructing a new unit of equivalent electricity generation capacity.^{footnote 29} Fossil fuel-fired electricity generating units that retrofit with CCS are assumed to remain on their original refurbishment schedules but to undertake incrementally higher costs of refurbishment at the end of their operational lifetimes to reflect the increased capital costs for abated emitting technologies relative to their unabated counterparts. On net, the Regulations are estimated to result in $709 million in refurbishment costs to the electricity sector over the 27-year analytical period (Table 30), representing a 2% increase relative to the Baseline Scenario.

Table 29. Incremental refurbished electricity generation capacity (MW)
Technology type	2035-2039	2040-2044	2045-2049	2050	27-year total	Annual average
Unabated emitting	0	-180	-574	0	-754	-28
Abated emitting	0	180	207	0	387	14
Nuclear	0	0	0	0	0	0
Hydro	0	0	0	0	0	0
Wind (onshore)	0	0	0	0	0	0
Solar	0	0	0	0	0	0
Other non-emitting	0	0	0	0	0	0
Storage	16	1,717	2,204	-3	3,934	146
Total	16	1,717	1,837	-3	3,567	132

Table 30. Incremental refurbishment costs by region (millions of dollars)
Province	2035-2039	2040-2044	2045-2049	2050	27-year total	Annualized average (n=27)
NL	0	0	0	0	0	0
PE	0	0	0	0	0	0
NS	0	184	0	0	184	9
NB	0	36	-94	0	-58	-3
QC	2	0	0	0	2	0
ON	0	0	505	0	505	24
MB	0	54	0	0	54	3
SK	0	73	0	0	73	4
AB	0	46	-98	0	-52	-3
BC	2	0	0	0	2	0
YK	0	0	0	0	0	0
NT	0	0	0	0	0	0
NU	0	0	0	-1	-1	0
Total	4	393	313	-1	709	34

International net import expenditure

As seen in Table 10, Canada is a net exporter of electricity to the US in the Baseline Scenario and the Regulatory Scenario, though to a lesser degree in the Regulatory Scenario due to an incremental decrease in both exports and imports. The cost impact is estimated by multiplying the trade flows by the region-specific projected spot market price of electricity. As calculated from the data presented in Table 10, imports are expected to decrease to a greater extent than exports in the Regulatory Scenario relative to the Baseline Scenario. However, as seen in Table 31, the average price per MW at which exports clear the spot market is lower in the Regulatory Scenario than in the Baseline Scenario, and the average price per MW at which imports clear the spot market is higher in the Regulatory Scenario than in the Baseline Scenario, thereby reducing the revenues received from trade. The price effect outweighs the quantity effect, resulting in a negative incremental effect for net import flows and a positive effect for net import expenditure. Overall, international trade costs (i.e., net import expenditure) for the electricity sector is estimated to increase by $3.5 billion over the 27-year analytical period (Table 32), representing an 8% increase relative to the Baseline Scenario.

Table 31. Weighted average^{table f7 note a} trade value ($/MWh, undiscounted)
Description	2024-2034	2035-2039	2040-2044	2045-2049	2050
Average export revenue (Baseline Scenario)	22.96	12.60	13.24	10.92	6.64
Average export revenue (Regulatory Scenario)	36.59	29.02	37.26	28.98	21.94
Average import expenditure (Baseline Scenario)	22.11	10.65	11.57	9.04	5.83
Average import expenditure (Baseline Scenario)	36.69	30.92	34.73	32.86	36.16
Table f7 note(s) Table f7 note a Weighted average calculated on the basis of trade flow in each region, then on the basis of trade flow in each time period Return to table f7 note a referrer

Table 32. Incremental international net import expenditure by region (millions of dollars)
Region	2024-2034	2035-2039	2040-2044	2045-2049	2050	27-year total	Annualized average (n=27)
NL	0	0	0	0	0	0	0
PE	0	0	0	0	0	0	0
NS	0	0	0	0	0	0	0
NB	9	-16	-91	-34	5	-128	-6
QC	15	47	358	600	1	1,021	49
ON	134	1,111	732	274	73	2,325	112
MB	-3	31	-75	-70	-3	-120	-6
SK	-27	-17	-3	4	9	-34	-2
AB	249	50	-319	-352	-12	-384	-19
BC	786	37	0	-1	0	823	40
YT	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	0	0	0	0	0	0	0
Total	1,163	1,244	602	422	73	3,503	169

Offset costs

In the regulatory scenario, regulatees are able to remit recognized Canadian offset credits that represent tonnes of CO₂ reductions for a prescribed maximum of emissions emitted above a particular electricity generating unit’s AEL. The analysis assumes that all incremental future demand for offsets from the electricity sector can and will be met by future supply, and the price of offsets will be the same as the minimum national carbon price in any given year. This means that, in 2030 onward, the price of offsets is assumed to be $170 nominal dollars (translated into real dollars using E3MC’s inflation projection, which averages 2% per year from 2030 to 2050). Alternative assumptions regarding the price of offsets are explored in the “Sensitivity analysis” section.

Departmental modelling suggests that, prior to 2050, the use of offsets as a compliance mechanism at the assumed offset price will be minimal, which suggests that offset uptake would be mainly used for backing up investment in CCS technologies in the event that such technologies do not reach a desired level of carbon capture efficiency in any given year. In other words, prior to 2050, the applicable emissions intensity of 65 t/GWh coupled with other compliance flexibilities such as pooling is expected to be sufficient to allow most of Canada’s electricity system to comply with the Regulations without relying on the use of offsets.

In 2050 onwards, the applicable emission intensity (upon which the AEL is based) for electricity generating units will reduce to 0 t/GWh. The amount of allowable offsets will increase at this time. As seen in Table 12 in the Benefits subsection, total offset usage in the regulatory scenario is expected to cover around 7 Mt of CO₂ emissions from 2024 to 2049, and around 5 Mt of CO₂ emissions in 2050. In total, the Regulations are estimated to result in $802 million in incremental offset costs to the electricity sector over the 27-year analytical period (Table 33).

Table 33: Incremental offset costs by region (millions of dollars)
Region	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	0	0	0	0	0	0
PE	0	0	0	0	0	0
NS	0	0	0	13	13	1
NB	0	0	0	0	0	0
QC	0	0	0	1	1	0
ON	0	0	0	11	11	1
MB	0	0	0	0	0	0
SK	34	28	25	41	128	6
AB	0	194	170	245	609	29
BC	0	0	38	2	40	2
YT	0	0	0	0	0	0
NT	0	0	0	0	0	0
NU	0	0	0	0	0	0
Total	34	222	233	313	802	39

Residual value of capital on early retirements and associated replacement costs of cogeneration heat needs

The Regulations do not prescribe any particular compliance pathway for any particular unit. All results presented in the CBA represent a modelled scenario indicating what may occur in response to the Regulations under a central case. The modelling selects a pathway for early retirement of units in response to the regulatory scenario when doing so minimizes total electricity system costs. As previously seen in Figure 1, NextGrid was used to model the decisions that exogenous (i.e. existing) electricity generating units that do not meet the CO₂ emissions intensity limit might take in response to the Regulations. Amongst affected units, 12% are modelled to retire earlier than they otherwise would have or, for cogeneration units, to have stopped selling electricity to the electricity system between 2035 and 2049, with an additional 8% of affected units retiring in 2050. Combined, these retirements and cogeneration withdrawals account for 3,855 MW of fossil fuel-fired electric generating capacity being decommissioned or no longer servicing the electricity system.

The value of this impact is calculated by multiplying the capital cost to construct a new electricity generating unit of equivalent size and technology type in the projected year of retirement by the proportion of operating lifetime remaining for the electricity generating unit in question, based on their online date as a proxy for commissioning date. For industrial electric cogenerating units that sell some of the electricity they produce to Canada’s electricity system, retirement means that the electricity generating unit is decommissioned and replaced with a fossil fuel-fired boiler to provide the needed process heat behind the fence. For those electricity generating units, the capital cost of new boiler capacity to produce equivalent heat is added to the residual value of capital on the early retirement.

Overall, the residual value of capital on early retirements and associated replacement costs of cogeneration heat needs is estimated to be $1.9 billion over the 27-year analytical period. Insofar that new electricity generation capacity would need to be constructed (or imports would need to rise) to replace the capacity of electricity generating units that retire early, accounting for the residual value of capital on early retirements may constitute “double-counting” of some costs within the CBA. Nonetheless, this impact is retained in the CBA to recognize any incremental costs to the electricity sector that may arise from unpaid debt servicing on assets that cease to operate over the projection period.

Administrative costs

As noted in the “Description” section, the administrative requirements of the Regulations apply to any fossil fuel-fired electricity generating units with electricity generation capacity greater than or equal to 25 MW that is connected to a NERC-regulated electricity system, while compliance requirements to meet the emissions limit apply to any fossil fuel-fired electricity generating unit with electricity generation capacity greater than or equal to 25 MW that has net sales to a NERC-regulated electricity system. Departmental modelling estimates that 122 facilities would be subject to administrative requirements,^{footnote 30} of which 124 would be expected to submit full-length annual reports. While certain facilities may be comprised of multiple electricity generating units, the CBA assumes that a constant administrative cost “per event” is incurred by each facility, regardless of the number of electricity generating units contained in each. The assumptions used to account for administrative costs are presented in Table 34.

Table 34: Administrative cost assumptions by activity (2022 constant dollars, undiscounted)
Administrative activity	Timing	Facility count (in 2024)	Occupational category	Hours spent	Hourly wage rate (including overhead)	Approximate cost per event
Learn about the regulatory requirements	2024	122	Natural and applied sciences and related occupations	15	$53.38	$800.65
Learn about the regulatory requirements	2024	122	Professional occupations in law and social, community and government services	10	$53.43	$534.30
Learn about the regulatory requirements	2024	122	Senior management occupations	4	$76.77	$307.10
Registration report – unit information and site map	2024	122	Natural and applied sciences and related occupations	15	$53.38	$800.65
Registration report – approval	2024	122	Senior management occupations	2	$76.77	$153.55
Registration number assignment	2024	122	Office support occupations	1	$31.19	$31.19
Annual emissions report - Fuel based – data retrieval and entry, sampling and analysis, CO₂ emissions calculations, calculations – other, determine net-exports, calculate the electricity generated, sending report	2036–2050	118	Natural and applied sciences and related occupations	27.5	$53.38	$1,467.85
Annual emissions report - Fuel based - calculations of net thermal energy produced (Eth)	2036–2050	62	Natural and applied sciences and related occupations	4	$53.38	$213.51
Annual emissions report - CCS captured emissions	2036–2050	9	Natural and applied sciences and related occupations	4	$53.38	$213.51
Annual emissions report - CO₂ emissions associated with hydrogen or purchased steam	2036–2050	4	Natural and applied sciences and related occupations	1	$53.38	$53.38
Annual emissions report – Approval	2036–2050	118	Senior management occupations	2	$76.77	$153.55
Annual short emissions report – Determine net-exports, sending the report	2036–2050	4	Natural and applied sciences and related occupations	3	$53.38	$160.13
Annual short emissions report – Approval	2036–2050	4	Senior management occupations	0.5	$76.77	$38.39
Credit issuance	2036–2050	122	Office support occupations	1	$31.19	$31.19
Reconciliation report - Compliance credits remittance calculations, non-transferrable compliance credits account book, transferrable compliance credits account book	2036–2050	118	Natural and applied sciences and related occupations	10	$53.38	$533.76
Reconciliation report – Approval	2036–2050	118	Senior management occupations	2	$76.77	$153.55
Record making	2036–2050	122	Office support occupations	1	$31.19	$31.19
Annual report for federal coal-fired electricity regulation (repeal)	2036–2042	1	Natural and applied sciences and related occupations	-2	$53.38	-$106.75

Under the regulatory scenario, Departmental modelling estimates that the total electricity system capacity across all fossil fuel-fired electricity generating units will decrease by a total of 5.5% between 2024 and 2050, for an average decrease in regulated capacity of 0.21% per year. This average annual decrease in regulated electricity generation capacity is used as a proxy measure for negative growth in the number of affected facilities over the analytical period. Using the inputs in Table 34 and the estimated negative growth rate for affected facilities, the Regulations are estimated to result in $3.2 million in incremental administrative costs to the electricity sector over the 27-year analytical period.

Government costs

Overall, the Regulations are estimated to result in $1.9 billion in incremental costs to the Government of Canada over the 27-year analytical period. Of this total cost, approximately $1.9 billion represents incremental uptake of federal ITCs by the electricity sector, $49 million represents incremental program administration, and $1.3 million represents incremental enforcement efforts. While government costs technically represent wealth transfers from the tax base, they are nonetheless important to capture within the CBA to reflect the opportunity cost associated with not spending those dollars elsewhere.

As previously noted, the incremental capital costs for new electricity system capacity presented in the CBA includes a modelled abstraction of all available ITCs. Factoring the ITCs into the capital costs is important to ensure greater accuracy in the projected buildout of the electricity system in the baseline scenario and the regulatory scenario. However, the portion of incremental buildout that is covered by the ITCs in the modelling should be accounted for in the CBA to ensure that the full economic value of these assets is represented. To this end, the portion of incremental buildout in Table 26 that is funded by ITCs in the modelling totals $1.9 billion.

In addition, the Department is estimated to spend $49 million on new program administration for the Regulations, mainly comprised of new salary allocations. For compliance and enforcement, the Department is estimated to incur $1.3 million in incremental costs. This includes one-time costs to develop an enforcement strategy, train enforcement officers, and perform strategic intelligence assessment work, which are assumed to occur in 2034 (i.e. one year prior to the year in which the emissions limit starts to come into force). From 2035 onward, the Department is estimated to incur annual costs for administration, coordination and analysis to support enforcement activities, inspections (including operations, maintenance, transportation and sampling costs), investigations, measures to deal with alleged violations, and for ongoing intelligence work.

Cost-benefit statement

Number of years: 27 (2024 to 2050)
Price year: 2022
Present value base year: 2024
Discount rate: 2%

Table 35: Summary of monetized benefits (in millions of dollars)
Impacted stakeholder	Description of benefit	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
Society	Climate change mitigation (electricity system)	3,217	8,179	12,002	12,490	4,205	40,094	1,936
Society	Climate change mitigation ("behind-the-fence")	0	1,332	1,095	1,049	877	4,352	210
Canadians	Health (low end) and environmental benefits	107	582	1,343	1,071	290	3,393	164
Electricity sector	Fuel cost-savings	537	1,224	2,248	2,141	476	6,627	320
Electricity sector	Variable O&M cost-savings	114	126	205	46	-60	430	21
All	Total monetized benefits	3,976	11,443	16,893	16,797	5,788	54,896	2,651

Table 36: Summary of monetized costs (in millions of dollars)
Impacted stakeholder	Description of cost	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
Electricity sector	Capital costs for new electricity system capacity	2,661	8,014	7,190	3,372	3,245	24,482	1,182
	Fixed O&M and refurbishment costs	620	1,209	2,522	2,691	635	7,678	371
	Offset costs	0	34	222	233	313	802	39
	Residual value of capital on early retirements	0	1,329	566	6	17	1,918	93
	International net import expenditure	1,163	1,244	602	422	73	3,503	169
	Administrative costs	0	1	1	1	0	3	0.1
Government	Government costs	1,804	142	4	4	1	1,954	94
All	Total monetized costs	6,248	11,973	11,107	6,729	4,284	40,341	1,948

Table 37: Summary of monetized benefits and costs (in millions of dollars)
Impact	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
Total benefits	3,976	11,443	16,893	16,797	5,788	54,896	2,651
Total costs	6,248	11,973	11,107	6,729	4,284	40,341	1,948
Net benefit	-2,272	-530	5,786	10,067	1,504	14,555	703

In the central case CBA, excluding (potentially) incremental emissions reductions from offsets and using a conservative estimate for health benefits, the Regulations are estimated to result in $54.9 billion of benefits and $40.3 billion of costs from 2024 to 2050, therefore resulting in an estimated $14.6 billion in net benefits.

Distributional analysis

CBA results by region

While the CBA takes on a national scope, this distributional analysis presents results by region. Total GHG emissions reductions (with and without offsets) by province or territory are presented in Table 38, and the total costs net of cost-savings accounted for in the CBA by region are presented in Table 39.

Table 38: Total GHG emissions reductions, by region (2024–2050, kilotonnes of CO2e)
Region	27-year total (without offsets)	Annual average (without offsets)	27-year total (with offsets)	Annual average (with offsets)
NL	0	0	0	0
PE	0	0	0	0
NS	8 185	303	8 411	312
NB	4 130	153	4 130	153
QC	0	0	15	1
ON	35 524	1 316	35 710	1 323
MB	0	0	0	0
SK	27 354	1 013	29 129	1 079
AB	106 815	3 956	115 991	4 296
BC	66	2	681	25
YT	0	0	0	0
NT	0	0	0	0
NU	-709	-26	-709	-26
Total	181 365	6 717	193 358	7 161

Table 39: Costs net of cost-savings accounted for in the CBA, by region (millions of dollars)^{table f15 note a}
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	-1	4	-2	-30	2	-27	-1
PE	0	0	0	0	0	0	0
NS	-3	1,484	400	-23	7	1,865	90
NB	10	-24	214	94	-41	252	12
QC	51	719	1,140	894	866	3,671	177
ON	187	4,017	4,459	3,094	-114	11,642	562
MB	-8	226	570	194	60	1,042	50
SK	651	207	169	24	322	1,373	66
AB	2,003	3,605	1,655	266	2,743	10,273	496
BC	908	237	-7	-24	10	1,123	54
YT	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	-6	6	50	50	13	112	5
Total	3,793	10,481	8,649	4,537	3,868	31,327	1,513
Table f15 note(s) Table f15 note a These totals include fuel cost-savings, variable operations and maintenance cost-savings, capital costs for new electricity system capacity, fixed operations and maintenance costs, refurbishment costs, international net import expenditure, offset costs, and residual value of capital on early retirements and associated replacement costs of cogeneration heat needs. These totals do not include administrative costs, government costs, nor the monetized benefits associated with GHG and air pollutant emissions reductions. Return to table f15 note a referrer

As depicted in Table 38, the largest estimated emissions reductions from the Regulations are in Alberta (107 Mt), Ontario (36 Mt), Saskatchewan (27 Mt), Nova Scotia (8 Mt), and New Brunswick (4 Mt), largely driven by changes in the electricity generation mix away from unabated emitting generation towards low and non-emitting generation. As depicted in Table 39, the total incremental costs net of cost-savings accounted for in the CBA are estimated at $31 billion. In the baseline scenario, these costs are estimated at $766 billion over the same period^{footnote 31}; therefore, the Regulations are estimated to increase these costs by 4% relative to the baseline scenario. As calculated from Table 39, Ontario and Alberta are modelled to take on nearly 70% of the total costs net of cost-savings accounted for in the CBA, largely driven by incremental capital costs for new electricity system capacity. However, it should be noted that the values presented in Table 39 are not best suited to assess the cost implications of the Regulations for individual regions. Instead, total electricity system costs (which differs in methodology from the CBA in a few key ways) should be used to make that assessment. Total electricity system costs by region are explored in detail below.

Total electricity system costs by region

Total electricity system costs denote the day-to-day costs of operating any given electricity system. This lens differs from that of the CBA in two distinct ways. First, capital costs for the buildout of new electricity system capacity are annualized over the economic life of the asset rather than lump-summed to reflect only the portion of the capital that is amortized in a given year. Second, certain impacts that are considered transfers given the societal scope taken in CBA methodology (and therefore excluded from the prior analysis) are important to include among the other costs and cost-savings when considering regional impacts. In this case, those impacts are carbon pricing payments and domestic net import expenditure, which can be significant revenue or expense streams for system operators that affect consumer electricity rates. Each of these impacts are described in detail in the subsections below, culminated by the presentation of total electricity system costs.

Annualized capital costs

Annualized capital costs consider the reality that large capital expenditures would not be paid off and cost-recovered in the year that the asset is set to come online, but rather, that such investments would be financed and paid back to lenders over time. In the analysis, annualized capital costs are calculated by establishing the amount of money that is paid yearly on each unit of new capital build over its economic lifetime (i.e. the annuity), then summing up the annuities across all units that are not yet paid off. The annuities on new capital are calculated by multiplying the total capital cost of a new asset by the capital recovery factor, which is a function of the real interest rate and the economic lifetime of the asset. The real interest rate is a function of the nominal interest rate (which is itself a function of the assumed annual return on equity, annual debt rate and utility debt leverage), and the inflation rate. Using the average nominal inflation rate projected by E3MC between 2024 and 2050 of 2%, the real interest rate over the analytical period is estimated at 3.9%. The assumed economic lifetime of each asset is presented in Table 3 in the “Background” section. Overall, the Regulations are estimated to result in $12.5 billion in incremental annualized capital costs over the 27-year analytical period (Table 40), representing a 6% increase relative to the baseline scenario.

Table 40: Incremental annualized capital costs by region (millions of dollars)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	0	1	1	-2	0	0	0
PE	0	0	0	0	0	0	0
NS	117	380	342	223	27	1,090	53
NB	1	0	31	196	43	270	13
QC	7	49	234	285	98	672	32
ON	7	424	1,673	2,488	542	5,133	248
MB	-6	27	148	153	32	355	17
SK	233	215	238	152	41	878	42
AB	299	785	1,339	1,136	362	3,921	189
BC	17	64	59	36	7	183	9
YT	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	-5	-8	-11	-10	-2	-36	-2
Total	670	1,936	4,055	4,655	1,150	12,466	602

Carbon pricing payments

Given that emissions in the electricity sector are covered by federal or provincially equivalent carbon pricing systems, the Regulations are expected to have an impact on the net carbon pricing payments that the sector makes. Specifically, regions with incremental emissions reductions relative to the baseline scenario are expected to experience relative cost-savings on their carbon price payments. Overall, the Regulations are estimated to result in $10.1 billion in incremental reduced carbon pricing payments over the 27-year analytical period (Table 41), representing a 62% decrease relative to the baseline scenario.

Table 41: Incremental carbon pricing payments by region (millions of dollars)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	0	0	0	0	0	0	0
PE	0	0	0	0	0	0	0
NS	-3	-209	-177	-153	-42	-584	-28
NB	0	0	-1	-105	-19	-124	-6
QC	0	0	0	0	-1	-1	0
ON	-29	-96	-165	-116	-39	-444	-21
MB	0	0	0	0	0	0	0
SK	-123	-95	-100	-67	9	-376	-18
AB	-689	-2,028	-2,954	-2,448	-492	-8,611	-416
BC	-3	0	0	0	2	0	0
YT	0	0	0	0	0	0	0
NT	0	0	0	0	0	0	0
NU	0	0	0	0	0	0	0
Total	-845	-2,429	-3,396	-2,888	-582	-10,140	-490

Of the $10.1 billion in cost-savings, more than $8.6 billion is attributable to Alberta, based on departmental modelling of Alberta’s Technology Innovation and Emissions Reduction (TIER) Regulation under which significant credits (i.e. revenues) accrue to operators of VRE. This $8.6 billion represents a 37% increase in TIER revenues relative to those in the baseline scenario for Alberta’s electricity sector. E3MC assumes that all credits generated under Alberta TIER sell at the minimum national carbon price ($170 nominal dollars per tonne from 2030 onward) and that these credits can be sold to other economic sectors outside the electricity sector.

Increased domestic net import expenditure

Alongside international trade, neighbouring provinces and territories can also trade with each other. In the modelling, maximum trade flows are restricted to the electricity generation capacity of existing or planned interties. Over the 27-year analytical period, the Regulations are estimated to result in 6,952 GWh of incremental electricity traded domestically at an estimated incremental economic value of $274 million, representing a 3% increase from the baseline scenario. As was the case with international net import, the cost impact is estimated by multiplying the trade flows by the region-specific projected spot market price of electricity. Incremental domestic net import expenditure by region is presented in Table 42, where negative numbers represent cost-savings relative to the baseline scenario.

Table 42: Incremental domestic net import expenditure by region (millions of dollars)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	21	-19	8	144	0	154	7
PE	11	2	15	-8	-1	19	1
NS	-45	-22	-24	-28	-1	-120	-6
NB	-15	-6	-11	-20	1	-51	-2
QC	10	-147	-372	31	0	-477	-23
ON	27	202	369	-123	1	476	23
MB	16	-7	26	-19	-12	3	0
SK	-67	8	109	108	32	190	9
AB	209	-17	-120	-87	-21	-35	-2
BC	-166	6	0	2	1	-157	-8
YT	-2	0	0	0	0	-2	0
NT	0	0	0	0	0	0	0
NU	0	0	0	0	0	0	0
Total	0	0	0	0	0	0	0

Total electricity system costs

Total electricity system costs in each region is calculated by adding the annualized capital costs for new electricity system capacity, carbon pricing payments, and domestic net import expenditure to the following costs or cost-savings from the CBA: fixed O&M costs; variable O&M cost-savings; fuel cost-savings; refurbishment costs; residual value of capital on early retirements and associated replacement costs of cogeneration heat needs; offset costs; and international net import expenditures. Overall, electricity system costs are estimated to increase by $9 billion over the 27-year analytical period (Table 43). In the baseline scenario, these costs are estimated at $679 billion over the same period,^{footnote 32} therefore, the Regulations are estimated to increase these costs by 1% relative to the baseline scenario.

Table 43: Incremental electricity system costs, by region (millions of dollars)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	20	-19	8	125	0	134	6
PE	11	2	15	-8	-1	19	1
NS	258	335	552	229	18	1,392	67
NB	-5	-23	6	-305	-16	-343	-17
QC	35	-39	278	1,009	130	1,413	68
ON	20	827	1,572	2,639	408	5,465	264
MB	39	96	294	237	53	718	35
SK	9	98	236	251	171	765	37
AB	-54	541	-964	-1,381	404	-1,455	-70
BC	618	131	78	84	13	925	45
YT	-2	0	0	0	0	-2	0
NT	0	0	0	0	0	0	0
NU	9	25	42	52	10	139	7
Total	957	1,974	2,117	2,933	1,190	9,170	443

As calculated from Table 43, Ontario is projected to incur more than half of the national net cost increase, while Alberta (and to a lesser extent, New Brunswick) is projected to experience electricity system cost-savings relative to the baseline scenario. For Ontario, the higher electricity system costs are driven primarily by capital costs for new electricity system capacity (which are significant even when annualized) and increased international net import expenditure. For Alberta, the costs associated with complying with the Regulations are outweighed by the incremental revenue stream coming in from carbon pricing credits under TIER, leading to a net decrease in electricity system costs. For New Brunswick, costs net of cost-savings accounted for in the CBA are negative in the 2035–2039 and 2050 periods. Under the electricity system cost methodology, the combination of the annualization of new capital costs and the decreased carbon pricing payments for New Brunswick render the electricity system costs decreasing throughout most time periods.

Electricity rates and associated affordability assessment

Generally speaking, electricity rates represent how the costs of building, operating, and maintaining an electricity system are passed on to end users of electricity at the residential, commercial, or industrial level. Electricity rates are a matter of provincial or territorial policy and are determined by regional utilities or by the market, depending on the electricity system in question. While the Regulations will bring about changes to the electricity generation capacity, generation, and trade mix that would be reasonably expected to induce provinces and territories to change their consumer-facing electricity rates, the Regulations themselves do not directly alter these rates.

Importantly, electricity prices in E3MC are not linear transformations of the total electricity system costs seen in Table 43. E3MC is a macroeconomic model that endogenously determines the consumer-facing price of a wide range of energy sources (e.g. natural gas, hydrogen, electricity) over a given projection period. In E3MC, the price of electricity is determined through the use of a common (i.e. non regionally specific) and complex equation that represents the weighted average price of electricity across both the fixed rate portion and the variable rate portion of an electricity bill, presented on a per MWh basis. As is the case with all consumer-facing energy prices in E3MC, simulated market forces within and between sectors can influence the price of electricity derived from the equation.

In E3MC’s electricity price equation, the market structure (i.e. vertically integrated utility, competitive, or hybrid) governing electricity in any given region can significantly impact the result. Specifically, the electricity price equation only considers the capital cost of new electricity system buildout when such costs have been factored into bilateral contracts, which is the case with all vertically integrated utilities. For competitive markets, there are no bilateral contracts and therefore the equation does not consider the capital cost of new electricity system buildout. In these cases, the equation only considers the marginal cost of electricity generation bought and sold on the spot market. For hybrid markets, the equation averages between the cost of purchased power from bilateral contracts and the cost of purchased power from the spot market. The equation also calibrates itself to historical electricity prices by adjusting a term that reconciles the gap between the sum total of all parameters in the equation, and the historic price of electricity. This term therefore acts as a proxy measure for the cost of transmission and distribution, the profits to power providers, and any other potentially missing variable within the rates equation, which is programmed to grow in-line with peak loads over the projection period.

The incremental impact of the Regulations on the residential price of electricity derived by E3MC’s equation is presented in Table 44 (2022 constant dollars).

Table 44: Weighted average incremental real residential price of electricity, undiscounted cents/kWh (in brackets: percentage change relative to baseline scenario)
Region	2024–2034^{table f20 note a}	2035–2039^{table f20 note a}	2040–2044^{table f20 note a}	2045–2049^{table f20 note a}	2050
NS	-0.8 (-4%)	-2.7 (-11%)	-3.0 (-12%)	-2.7 (-11%)	-3.0 (-12%)
NB	0.0 (0%)	0.1 (0%)	-0.1 (0%)	-0.3 (-2%)	-0.3 (-2%)
ON	0.0 (0%)	-0.1 (0%)	-0.4 (-2%)	-0.9 (-5%)	-1.2 (-6%)
SK	0.1 (0%)	0.2 (1%)	0.2 (1%)	0.2 (1%)	0.2 (1%)
AB	-0.2 (-1%)	0.0 (0%)	-0.4 (-1%)	-0.1 (0%)	-0.4 (-1%)
Rest of Canada^{table f20 note a}	0.0 (0%)	-0.2 (-2%)	-0.2 (-2%)	-0.4 (-4%)	-0.5 (-5%)
National^{table f20 note a}	-0.1 (0%)	-0.3 (-2%)	-0.4 (-2%)	-0.6 (-4%)	-0.7 (-5%)
Table f20 note(s) Table f20 note a Weighted average on the basis of total residential electricity sales in each region, as determined by E3MC. Return to table f20 note a referrer

Assessment of the impact of the Regulations on electricity prices is done by comparing the electricity price projected for the Regulations in a given year to what the electricity price would be, in absence of the Regulations, in the same year in the baseline scenario (e.g. the electricity rates projected in the regulatory scenario in 2045 are compared to the electricity rates projected in the baseline scenario in 2045. As indicated in Table 44, most regions are expected to experience a decrease in the residential price of electricity under the Regulations (relative to the baseline scenario — see Table 45), for a weighted average decrease relative to the baseline scenario nationwide of 2% when the emissions limits start coming into force in 2035 up to a 5% decrease by 2050. Nova Scotia is projected to experience the greatest incremental price decrease (up to 3 cents less per kWh relative to the baseline scenario), while most other regions are projected to experience incremental price decreases in-line or less than the national weighted average. The exception is Saskatchewan, which is projected to experience an incremental price increase of around 0.2 cents per kWh relative the baseline scenario.

To help contextualize these electricity price decreases relative to the baseline scenario, consider the rate of growth in the price of electricity over time presented in Table 44. It should be noted that electricity rates are expected to increase over time in constant dollar terms with or without the Regulations, due to the need to expand and maintain Canada’s electricity system commensurate with growth in electricity demand. This analysis looks only at the incremental difference between how much rates increase in the baseline scenario, without the Regulations versus in the regulatory scenario, where the Regulations are in place. This incremental rate impact (above and beyond what is expected in the baseline) is modest. Further, any small rate change needs to be considered in the context of overall household energy expenditures, which are expected to decrease over time as people switch from fossil fuels to more efficient technologies like electric vehicles and heat pumps.

Table 45: Percentage change in the projected real residential price of electricity between 2024 and 2050 in the baseline scenario and regulatory scenario
Region	Baseline scenario (i.e. without the Regulations)	Regulatory scenario	Incremental (percentage-point difference)
NS	74%^{table f21 note a}	52%	-21.7
NB	-15%^{footnote b}	-16%	-1.6
ON	24%	17%	-7.0
SK	15%	16%	1.0
AB	41%	39%	-1.8
Rest of Canada^{table f21 note a}	-5%	-9%	-4.6
National^{table f21 note a}	9%	4%	-5.4
Table f21 note(s) Table f21 note a Weighted average on the basis of total residential electricity sales in each region, as determined by E3MC Return to table f21 note a referrer

As seen in Table 45, the real residential price of electricity is projected to increase between 2024 and 2050 in the baseline scenario in most regions. Provincial and territorial governments, as well as electricity system operators, were consulted on the forecasts used for Ref 23, which was the foundation for this analysis. In the regulatory scenario, the residential price of electricity in most regions is also projected to increase, but at a rate that is, in some cases, markedly slower relative to the baseline scenario in some regions. For Nova Scotia, the biggest increase in the price of electricity in the baseline scenario (i.e.,without the Regulations) occurs between 2025 and 2026, associated with increased capital costs for new buildout of unabated emitting electricity generation capacity in 2026. After this increase, electricity prices remain relatively stable over the remainder of the analytical period. Notably, therefore, between 2024 and 2050, electricity prices in Nova Scotia are projected to increase by 74% in the baseline scenario, whereas, under the regulatory scenario, those prices are projected to increase by 52%, for a 22-percentage-point decrease in the growth rate relative to the baseline scenario. Likewise, Ontario, Alberta, and Saskatchewan are projected to experience increasing electricity prices over time in the baseline scenario, the rate of which is expected to slow by 7, 2, and 1 percentage points respectively in the regulatory scenario. For New Brunswick, a decrease in the price of electricity in the baseline scenario occurs between 2024 and 2025, associated with decreased generation from coal and increased generation from onshore wind and solar. After this decrease, electricity prices remain relatively stable over the remainder of the analytical period. Accordingly, New Brunswick is projected to experience a 15% decrease in the residential price of electricity between 2024 and 2050 in the baseline scenario, and a 1.6 percentage point additional decrease in the regulatory scenario.

Note that the residential prices are presented on the basis of a weighted average of total residential electricity sales in each region, as endogenously determined by E3MC.

The decreases in electricity prices in the regulatory scenario relative to the baseline scenario (i.e. the slowdown in the rate of growth of these prices over time) derived endogenously by E3MC’s equation can be explained in a variety of ways. As previously noted, the spot market price of electricity plays a significant role in regions with competitive markets (i.e. Alberta) and regions with hybrid markets (i.e. Ontario), in which “zero variable cost” technologies such as wind and solar bid into the spot market at zero, pulling down the average cost of purchased power. Another important factor is the total electricity sales delivered in a given region. In E3MC’s electricity price equation, the cost of purchased power is spread out over the total electricity sales in a given region. This means that in the baseline and regulatory scenarios, as households demand more electricity and as population increases, electricity system costs get spread over a larger denominator. While population growth is the same in both scenarios, consider the incremental change in residential electricity sales presented in Table 46.

Table 46: Percent change in residential electricity sales relative to the baseline scenario (in brackets: percentage change in total electricity sales)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050
NS	0.3% (0.04%)	1.0% (1.4%)	1.7% (2.7%)	2.1% (3.1%)	2.2% (3.3%)
NB	0.0% (0.0%)	0.0% (0.0%)	0.0% (0.0%)	0.0% (0.2%)	0.0% (0.4%)
ON	0.0% (0.0%)	0.0% (0.0%)	0.2% (0.2%)	0.9% (0.9%)	1.3% (1.5%)
SK	-0.1% (-0.01%)	-0.2% (-0.3%)	-0.3% (-0.4%)	-0.3% (-0.6%)	-0.4% (-0.6%)
AB	0.1% (0.1%)	0.3% (1.5%)	0.3% (1.1%)	0.3% (1.2%)	0.3% (1.6%)
Rest of Canada	0.0% (0.0%)	0.2% (0.3%)	0.3% (0.7%)	0.3% (1.0%)	0.4% (1.5%)
National	0.0% (0.0%)	0.2% (0.4%)	0.3% (0.6%)	0.5% (1.0%)	0.7% (1.5%)

As seen in Table 46, with the exception of Saskatchewan, total electricity sales are slightly higher in the regulatory scenario than they are in the baseline scenario, an effect that is most pronounced in Nova Scotia and Ontario. This is due to dynamic effects in the macroeconomic model whereby as prices fall, more electricity is demanded, and therefore, electricity sales increase. In summary, E3MC’s electricity price equation is such that as a greater proportion of low marginal cost electricity (relative to natural gas) comes online in the regulatory scenario, and as the cost of purchased power gets spread over more sales, the rate at which electricity prices are projected to increase over time tends to be lower in the regulatory scenario than it is in the baseline scenario. Commercial and industrial electricity prices are projected to exhibit a similar pattern to residential rates across each region.

To illustrate the effect of these model results on consumer spending, the residential electricity prices were multiplied by the residential electricity sales in each region, then divided by the regional population to derive a metric denoting the annual per capita spending on residential electricity payments (in E3MC’s forecasts, Canada’s population is projected to grow 32% from 2024 to 2050). The results of this analysis are presented in Table 47.

Table 47: Weighted average incremental real per-capita spending on residential electricity payments, dollars per year
Region	2024–2034^{table f23 note a}	2035–2039^{table f23 note a}	2040–2044^{table f23 note a}	2045–2049^{table f23 note a}	2050
NS	-41	-154	-172	-155	-177
NB	-1	4	-4	-17	-18
ON	0	-1	-8	-19	-22
SK	3	3	3	5	4
AB	-4	2	-8	0	-8
Rest of Canada^{table f23 note a}	-2	-16	-15	-29	-33
National^{table f23 note a}	-3	-15	-18	-28	-33
Table f23 note(s) Table f23 note a Weighted average on the basis of total residential electricity sales in each region, as determined by E3MC. Return to table f23 note a referrer

As seen in Table 47, relative to the baseline scenario, consumers across Canada are estimated to spend $15 less per capita annually when the emissions limits start coming into force in 2035, and $33 less per capita annually when the step-down to net-zero emissions comes into force in 2050 (in 2022 constant dollars). This impact is most pronounced in Nova Scotia, where consumers are estimated to save $154 to $177 per capita on annual electricity payments relative to the baseline scenario from 2035 to 2050, the highest savings among all provinces from the application of these Regulations. While electricity payments are expected to increase in Saskatchewan, this increase is between $3 to $5 per capita on annual electricity payments between 2035 and 2050. In addition to the Regulations’ role in reducing emissions, E3MC modelling finds that most Canadians will not see their electricity rates affected, or may even experience lower rates in some cases, with these Regulations in effect than they would under the baseline. This finding holds from 2024–2050 under a scenario of 1.5x growth in electricity demand.

To gain a wider perspective on how the impacts of the Regulations may be felt by electricity consumers, the Department contracted external parties to conduct independent analyses exploring the potential impacts of the Regulations. Alongside E3MC and NextGrid (see section “Departmental electricity sector models” and Table 4), other models that explored the potential impact of the Regulations on residential electricity rates were the gTech energy-economy model in combination with the Integrated Electricity Supply and Demand (IESD) electricity-sector model operated by Navius, and the North American Times Energy Model (NATEM) in combination with the RateVision operated by the Energy Super Modellers and International Analysts (ESMIA) Consultants. A summary of the incremental changes in electricity prices projected by each model for select provinces in 2035 and 2050 is presented in Table 48.

Table 48: Summary of incremental change in electricity prices in 2035 and 2050, by select province and by model
	2035 (E3MC)	2050 (E3MC)	2035 (NextGrid)	2050 (NextGrid)	2035 (NATEM - ESMIA)	2050 (NATEM - ESMIA)	2035 (gTech & IESD - Navius)	2050 (gTech & IESD - Navius)
NS	-7%	-12%	-2%	-1%	0%	7%	1%	6%
NB	0%	-2%	-5%	-1%	0%	4%	1%	8%
ON	0%	-6%	0%	-1%	0%	1%	0%	2%
SK	0%	1%	0%	2%	0%	1%	1%	7%
AB	-2%	-1%	2%	5%	12%	11%	1%	11%
Rest of Canada^{table f24 note a}	0%	-5%	0%	0%	N/A	N/A	0%	0%
National^{table f24 note a}	-1%	-5%	0%	1%	N/A	N/A	0%	3%
Table f24 note(s) Table f24 note a weighted average on the basis of regional residential electricity sales (E3MC), residential regional electricity consumption (NextGrid), and total electricity consumption (Navius) Return to table f24 note a referrer

Notably, relative to the baseline scenario, both E3MC and NextGrid project incremental electricity price decreases in Nova Scotia, New Brunswick, and Ontario, and incremental electricity price increases in Saskatchewan. In the independent modelling work done by ESMIA and Navius, incremental electricity prices are projected to increase in Nova Scotia, New Brunswick, Ontario, Saskatchewan, and Alberta, with the highest magnitude of electricity price impacts projected to occur in Alberta. These results for Alberta differ substantially from that projected by E3MC, in which credits to operators of VRE are modelled to generate revenues under Alberta TIER that have the effect of pulling consumer-facing electricity prices down relative the baseline scenario. Note that of the independent modellers, Navius accounted for TIER while ESMIA did not; the modelling done by CCI did not look at Alberta.

In 2035, with the exception of Alberta, all models indicate minimal impacts to electricity prices. By contrast, in 2050, there is a divergence in model results regarding the impact of a net-zero emission electricity system on electricity prices. The maximum increase projected by any model for each province in 2050 is 11% in Alberta (Navius and ESMIA), followed by 8% in New Brunswick (Navius), 7% in Saskatchewan (Navius) and Nova Scotia (ESMIA), and 2% in Ontario (Navius). In addition to the independent third-party modelling commissioned by the Department, CCI independently modelled the impact of a near-final (but stricter) version of the Regulations on electricity prices in Saskatchewan, yielding a 6% increase in 2035 and a 7% decrease in 2050 relative to a baseline scenario.^{footnote 33} The analysis also concluded that “compliance with the Clean Electricity Regulations, designed with the flexibilities proposed by Environment and Climate Change Canada in February 2024, is achievable within the technical and logistic constraints SaskPower has outlined”.

Affordability assessment

Government of Canada surveys have found that 69% of Canadians are interested^{footnote 34} in, or have already begun, transitioning from fossil fuel to electricity to power transportation, home heating and industry. A growing population and economy, along with increased electrification of the economy, is expected to significantly increase the demand for electricity in coming decades. However, the decision by Canadians to switch from fossil fuels to electricity, and by extension the effectiveness of electrification on helping to mitigate climate change, will largely depend on the price of electricity relative to fossil fuels.

The affordability of electricity is a significant concern for Canadians and was raised by key interested parties during engagement on the Regulations. Accordingly, the Department set affordability as one of the three core principles guiding the development of the Regulations. The importance of affordability has been recognized in the design of the Regulations through the introduction of compliance flexibilities. Operators can choose a higher use of existing electricity generating units to support reliability rather than build new capital stock to do so.

As discussed in the previous section, the Department, using its E3MC model, has determined the impact of the Regulations on electricity rates will be relatively minor. However, considering the importance that electricity rates will have on electrification, the Department also assessed the Regulations through a second internal model (i.e. NextGrid) and through the models of three, independent, third-party modellers with well-established reputations in the Canadian electricity sector. The results of this assessment are presented further in this section. While some models indicated that the Regulations could increase rates, the assessment by the third-party modellers indicated that, overall, the impacts of the Regulations on rates would be modest, or even beneficial.

As there are costs associated with the buildout of a cleaner grid, it may be surprising that rates could be lower under the Regulatory Scenario, than under the Baseline Scenario. This finding reflects the dynamics of the various electricity markets in operation in Canada. For example, in Alberta, renewable electricity can bid into the province’s competitive market at extremely low cost, thus lowering rates, and renewable electricity generators can generate valuable credits in the province’s carbon market. In Ontario and Nova Scotia, federal modelling found that the Regulations led to a higher percentage of electricity being generated from renewables, which run with zero fuel cost and thus reduce electricity prices. Lower electricity prices drive more electrification, which leads to more electricity sales, and thus spreads the capital costs of building out the electricity system over a larger rate base.

In the years ahead, as Canadian households switch from fossil fuels to non-emitting electricity, they are expected to spend more on electricity than they do today — but they are also expected to spend less on other energy costs. An electric car increases a household’s spending on electricity but cuts its gasoline costs. A heat pump means a household uses more electricity and less natural gas or home heating oil. And despite the modest impact of the Regulations on rates, electricity costs are expected to increase in some Canadian jurisdictions from now to 2050 as electricity systems expand.

The Department has sought to understand the affordability of a future that is predicated on clean electrification as delivered under the emission limits and provisions of the Regulations. A number of recent analyses have looked at what these changes mean for Canadians’ overall energy costs — a concept that some analysts call the household “energy wallet”. To understand the “energy wallet” impacts of a future that includes the Regulations, the Department commissioned the University of Regina’s Dr. Brett Dolter. The Department provided Dr. Dolter with federal (NextGrid) modelling of the rate impacts of the Regulations and asked him to use those rates as an input to assess total energy spending for Canadian households that switch to electric vehicles and to electric heat pumps. Dr. Dolter concluded that

Households that drive cars save money by switching to electric vehicles — and the more a household drives, the more it saves by using electricity relative to fossil fuels, e.g. gasoline. This holds true across provinces and income quintiles, with more savings for higher-income households because they drive more.
The financial benefits of switching to a heat pump are more nuanced. Households that currently use oil or electric baseboard heating are more likely to save money from switching, as are households with energy-efficient houses that require smaller heat pumps. However, households in Alberta, which has high electricity prices and low natural gas prices, are less likely to benefit from heat pump adoption; Saskatchewan households also saw fewer savings.

It can be deduced from Dr. Dolter’s study that, under moderate heat pump cost assumptions, 84% of Canadian households can be expected to save money from household electrification by 2035 as the financial savings from reduced fossil fuel use outweigh the increased spending on electricity.

Retail cost of electricity in a Regulations and no-Regulations scenarios

Increased electricity demand from the electrification of heating/cooling and transportation in the coming decades, in addition to factors such as inflation, will increase overall household electricity expenditure out to 2050. The NextGrid model predicts that the Regulations will incrementally increase electricity rates in the short to medium term for some provinces above and beyond those expected from electrification, but by a relatively small amount (less than two cents per kilowatt-hour). Much of the overall expenditure increase is due to growth in electricity usage, which is not attributable to the Regulations.

Whether electricity expenditures represent a larger portion of household expenditure depends on the rate of increase in electricity usage and electricity rates relative to the rate of income growth. Household income in Saskatchewan is projected to grow faster than residential electricity prices, which indicates electricity expenditures could fall as a share of income and total expenditure. The opposite is true in Ontario and Quebec, where households may experience affordability challenges as electricity expenditure occupies a growing share of income.

Irrespective of the Regulations, low-income households spend, on average, a greater proportion of their income on electricity and face the greatest affordability challenge as electricity usage and associated expenditures increase. Household electricity consumption is historically not highly responsive to income, meaning that as income rises, electricity consumption rises proportionally less than income; it remains to be seen if this will still be true as electric vehicle adoption increases.

Household affordability

The Dolter study sought to determine whether Canadian households would be likely to see financial savings or costs from electrification when also considering electricity rate changes attributable to the Regulations. Electrification in this context refers to adoption of electric vehicles for transportation and heat pumps for home heating/cooling.

A large part of savings from electrification comes from the adoption of electric vehicles instead of fossil-fuelled vehicles, with the household spending more on electricity and less on gasoline. The more a household drives an electric vehicle, rather than driving vehicles using fossil fuels (i.e. internal combustion engine vehicles), the more it saves. This holds true across provinces and income quintiles, with more savings for higher-income households because they drive more and drive larger vehicles.

The financial benefits of switching to a heat pump are more nuanced. Households that currently use oil or electric baseboard heating, such as in Atlantic Canada, are more likely to save money from switching. Owners of energy-efficient houses that require smaller heat pumps are also more likely to save money. However, households in provinces such as Alberta and Saskatchewan, which have high electricity prices and relatively low natural gas prices (combined with cold winters), are less likely to achieve savings from heat pump adoption.

Despite this result, households in provinces like Alberta and Saskatchewan could achieve energy wallet savings in some scenarios. For drivers, household savings from adopting electric vehicles could outweigh an increase in costs that result from adopting heat pumps in provinces, reducing total energy wallet expenditures.

The Dolter study found that the Regulations could lead to a marginal increase in household electricity expenditures as a result of modest increases in provincial electricity supply costs due to new investments needed in clean infrastructure. For jurisdictions that are dependent on fossil fuels (e.g. Alberta, Saskatchewan) these costs would increase residential retail rates in the short/medium term beyond what is expected from electrification without the Regulations. This is because of the assumption that without the Regulations, electrification in these provinces would likely be met by power plants firing on relatively inexpensive natural gas.

However, overall, electrification that would happen in the context of the Regulations is seen to maintain affordability. It can be deduced from the Dolter study that, in 2035, household energy costs are expected to be lower for at least 84% of Canadian households in a future based on clean electrification compared to a scenario that meets electricity demand through the continued expansion of fossil fuels.

The above findings are in line with similar work done by others. Specifically, in May 2022 the Canadian Climate Institute (CCI) published The Big Switch report (linked to in the Benefits and Costs section), analyzing household costs of electrification in view of reaching net-zero emissions. While the report is of significant value to the Department’s efforts to develop the Regulations, it did not adequately consider upfront capital costs associated with products such as electric vehicles and heat pumps, thus underestimating total costs. The Dolter Study incorporates upfront capital costs in its estimations, and still concludes that the Regulations will result in lower energy wallet spending for most Canadians. More recently (October 2024), Clean Energy Canada released its Opening the Door (PDF) report looked at the monthly energy savings that could be expected from switching from 1) fossil fuel for home heating to heat pumps and 2) internal combustion engine vehicles to electric vehicles. Clean Energy Canada concluded that almost all households in Canada, whether in detached houses, townhouses or condos, would see monthly savings resulting from electrification. While Alberta (-$21 per month to $64 per month) and Saskatchewan ($149 per month to $277 per month) saw the smallest savings, other provinces saw savings in the range of $220 per month to $921 per month. Note that Clean Energy Canada made assumptions that are more favourable to the economics of electrification than did Dolter.

Based on the Dolter study and the above third-party findings, the Department is confident that any rate increases that may be influenced by the Regulations will not disincentive electrification. For the majority of Canadian households, electrification in general will result in energy wallet savings. The modest rate impacts predicted for the Regulations do not negate the energy wallet savings that could be expected from electrification in the absence of the Regulations.

Sensitivity analysis

Sensitivity analysis provides a way to discern the impact of changes to uncertain variables on the outcome of the CBA. The sensitivity analysis for the Regulations was performed by isolating the impact of changes to one key input parameter at a time. The scenarios covered are varying SC-GHG steam, high load growth, varying capital costs, varying fuel costs, varying offset costs, varying wind buildout constraints, and endogenous interprovincial interties. Each of these scenarios is detailed in the subsections below.

Social cost of GHGs stream

As articulated in the Updated SC-GHG Guidance, the discount rate embedded in the damage functions over time has a significant impact on the present value of avoided damages from climate change. To this end, the SC-GHG Guidance includes two additional cost streams for the purpose of sensitivity analysis, a 1.5% stream and a 2.5% stream. The value of the SC-GHGs for these streams in select years is presented in Table 49.

Table 49: Annual SC-CO₂, SC-CH₄ and SC-N₂O values from the Updated SC-GHG Guidance in select years (2021 constant Canadian dollars per tonne, discounted to the relevant index year at 1.5% or 2.5%)
Index year	SC-CO₂ (1.5%)	SC-CH₄ (1.5%)	SC-N₂O (1.5%)	SC-CO₂ (2.5%)	SC-CH₄ (2.5%)	SC-N₂O (2.5%)
2020	$431	$2,948	$111,614	$150	$1,607	$45,053
2025	$460	$3,500	$121,750	$166	$2,033	$51,114
2030	$491	$4,052	$131,886	$184	$2,460	$57,175
2035	$522	$4,697	$142,050	$202	$2,958	$63,448
2040	$551	$5,341	$152,212	$221	$3,455	$69,719
2045	$583	$6,033	$163,573	$242	$3,995	$76,825
2050	$616	$6,726	$174,932	$262	$4,536	$83,931

To estimate the sensitivity of the CBA results to this factor, the SC-GHG values in Table 49 were converted into 2022 constant dollars, then multiplied over the emissions reductions from the central case scenario. All other elements from the central case scenario were also discounted by 1.5% and 2.5% to maintain consistency in the assessment of present value. Results from this sensitivity are presented in Table 50 to Table 52, and can be compared to the $54,896 in monetized benefits, $40,341 in monetized costs, and $14,555 in net benefits presented in the central case.

Table 50: SC-GHG stream sensitivity analysis costs (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	1.5% SC-GHG stream	2.5% SC-GHG stream
Capital costs for new electricity system capacity	26,601	22,559
Fixed O&M and refurbishment costs	8,420	7,009
Offset costs	769	621
Residual value of capital on early retirements	2,061	1,787
International net import expenditure	3,740	3,285
Government costs	2,016	1,895
Administrative costs	1	1
Total monetized costs	43,608	37,157

Table 51: SC-GHG stream sensitivity analysis benefits (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	1.5% SC-GHG stream	2.5% SC-GHG stream
Climate change mitigation (electricity sector)	78,011	26,462
Health (low end) and environmental impacts	3,727	3,092
Fuel cost-savings	7,258	6,058
Variable O&M cost-savings	459	403
Total monetized benefits (low end)	89,454	36,015
Climate change mitigation (offsets)	4,282	1,434
Health (high end) and environmental benefits	5,896	4,902
Total monetized benefits (high end)^{table g3 note a}	95,906	39,259
Table g3 note(s) Table g3 note a The high-end estimate adds the climate change mitigation associated with (potentially) incremental emissions reductions from the use of offsets, and uses the high-end estimate of monetized health benefits instead of the low-end estimate. Return to table g3 note a referrer

Table 52: SC-GHG stream sensitivity analysis benefits and costs (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	1.5% SC-GHG stream	2.5% SC-GHG stream
Total benefits (low end)	89,454	36,015
Total benefits (high end)	95,906	39,259
Total costs	43,608	37,157
Net benefit (low end)	45,846	-1,142
Net benefit (high end)	52,298	2,102^{table g4 note a}
Table g4 note(s) Table g4 note a If the high-end estimate for incremental health benefits is included and the (potentially) incremental climate change mitigation from offsets is excluded, the 2.5% SC-GHG stream sensitivity case results in $668 M in net benefits. Return to table g4 note a referrer

High load growth

As noted in the benefits and costs section, the CCI Electricity System Reports indicate that a net-zero emissions economy in the year 2050 would require Canada’s electricity system to meet a projected national electricity demand increase of 1.6 to 2.1 times above 2020 levels. The central case modelling used for the CBA was not predicated on meeting a net-zero emissions economy in 2050; rather the central case modelling includes a specific set of implemented policies and measures included in the Department’s 2023 Current Reference Case (Ref23), as depicted in Table 5 in the benefits and costs section, in which national electricity demand in the Baseline Scenario is projected to increase by 1.5 times between 2020 and 2050. In order to understand the implications of the Regulations in a hypothetical future where many new policies and programs that support electrification and net-zero emissions in other sectors are implemented, a sensitivity analysis using higher load growth consistent with net-zero futures was considered.

Alongside Ref23, Canada’s 2023 greenhouse gas and air pollutant emissions projections (Emissions Projection Report) also provides the 2023 Additional Measures Case (AM23) Baseline, in which several new electrification policies are implemented or accelerated within the projected period out to 2050. The Baseline Scenario for the high load sensitivity analysis is a modified version of AM23. Modified AM23 incorporates the additional measures that bolster electricity demand over time but excludes the additional measures that improve energy efficiency (which has the effect of reducing electricity demand as less electricity is needed to perform the same tasks) or any other policies. In modified AM23 (or high load Baseline Scenario), electricity demand in the Baseline Scenario is estimated to increase 1.97 times between 2022 and 2050. Canada’s electricity system mix in terms of electricity generation capacity and generation in the high load Baseline Scenario and the high load Regulatory Scenario are presented in Table 53 to Table 56.

Table 53: High load sensitivity case Baseline Scenario: Canada-wide electricity system electricity generation capacity mix by technology type, MW (in brackets: proportion of total electricity generation capacity)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting	31 633 (22%)	32 132 (15%)	40 231 (15%)	45 242 (15%)	51 384 (16%)	55 188 (17%)
Abated emitting	110 (0%)	110 (0%)	1 483 (1%)	2 460 (1%)	2 757 (1%)	2 757 (1%)
Nuclear	13 783 (10%)	11 491 (5%)	12 360 (5%)	13 365 (4%)	15 509 (5%)	16 673 (5%)
Hydro	77 738 (54%)	80 029 (38%)	94 143 (36%)	104 730 (35%)	110 187 (35%)	114 929 (35%)
Wind (onshore)	16 279 (11%)	68 448 (33%)	91 413 (35%)	102 909 (35%)	105 074 (33%)	105 930 (32%)
Solar	3 906 (3%)	15 514 (7%)	17 296 (7%)	24 507 (8%)	25 842 (8%)	27 042 (8%)
Other non-emitting	10 (0%)	431 (0%)	431 (0%)	432 (0%)	433 (0%)	437 (0%)
Storage	0 (0%)	1 036 (1%)	2 723 (1%)	3 483 (1%)	3 992 (1%)	4 752 (2%)
Total capacity	143 459 (100%)	209 191 (100%)	260 080 (100%)	297 129 (100%)	315 178 (100%)	327 708 (100%)

Table 54: High load sensitivity case Regulatory Scenario: Canada-wide electricity system electricity generation capacity mix by technology type, MW (in brackets: proportion of total electricity generation capacity)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting	31 633 (22%)	31 021 (13%)	30 237 (10%)	29 561 (9%)	28 332 (8%)	27 605 (7%)
Abated emitting	110 (0%)	110 (0%)	2 653 (1%)	11 735 (3%)	15 027 (4%)	17 249 (5%)
Nuclear	13 783 (10%)	11 491 (5%)	14 945 (5%)	17 248 (5%)	19 646 (6%)	20 954 (6%)
Hydro	77 738 (54%)	80 340 (34%)	94 270 (32%)	105 337 (31%)	112 060 (32%)	116 830 (32%)
Wind (onshore)	16 279 (11%)	70 193 (30%)	101 141 (34%)	105 103 (31%)	107 496 (30%)	108 669 (29%)
Solar	3 906 (3%)	20 104 (9%)	23 406 (8%)	33 393 (10%)	33 164 (9%)	35 409 (10%)
Other non-emitting	10 (0%)	431 (0%)	431 (0%)	431 (0%)	932 (0%)	1 364 (0%)
Storage	225 (0%)	20 542 (9%)	32 173 (11%)	34 486 (10%)	37 024 (10%)	41 024 (11%)
Total capacity	143 684 (100%)	234 232 (100%)	299 256 (100%)	337 294 (100%)	353 681 (100%)	369 104 (100%)

Table 55: High load sensitivity case Baseline Scenario: Canada-wide electricity system generation mix by technology type, GWh (in brackets: proportion of total generation)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting	80 393 (14%)	111 286 (13%)	81 678 (8%)	70 005 (7%)	72 879 (7%)	75 515 (7%)
Abated emitting	934 (0%)	743 (0%)	2 959 (0%)	3 032 (0%)	3 749 (0%)	4 951 (0%)
Nuclear	92 865 (16%)	85 562 (10%)	99 841 (10%)	108 531 (10%)	125 482 (11%)	135 394 (12%)
Hydro	358 643 (63%)	383 867 (46%)	455 726 (47%)	489 369 (47%)	516 568 (46%)	538 412 (47%)
Wind (onshore)	37 209 (7%)	213 133 (26%)	288 261 (30%)	330 636 (31%)	338 144 (30%)	342 228 (30%)
Solar	2 885 (1%)	34 976 (4%)	39 759 (4%)	49 696 (5%)	54 241 (5%)	56 133 (5%)
Other non-emitting	0 (0%)	1 912 (0%)	1 913 (0%)	1 918 (0%)	5 281 (1%)	6 232 (1%)
Total generation	572 929 (100%)	831 479 (100%)	970 136 (100%)	1 053 186 (100%)	1 116 344 (100%)	1 158 864 (100%)

Table 56: High load sensitivity case Regulatory Scenario: Canada-wide electricity system generation mix by technology type, GWh (in brackets: proportion of total generation)
Technology type	2022	2030	2035	2040	2045	2050
Unabated emitting	80 393 (14%)	107 116 (13%)	49 388 (5%)	29 827 (3%)	25 239 (2%)	16 797 (1%)
Abated emitting	934 (0%)	743 (0%)	6 928 (1%)	40 473 (4%)	52 636 (5%)	52 505 (4%)
Nuclear	92 865 (16%)	85 562 (10%)	120 589 (12%)	140 063 (13%)	159 536 (14%)	170 158 (14%)
Hydro	358 643 (63%)	384 312 (46%)	453 128 (45%)	489 052 (45%)	523 461 (45%)	557 713 (46%)
Wind (onshore)	37 209 (6%)	216 399 (26%)	327 913 (33%)	335 993 (31%)	344 604 (30%)	349 689 (29%)
Solar	2 885 (1%)	33 102 (4%)	38 448 (4%)	52 571 (5%)	53 800 (5%)	57 011 (5%)
Other non-emitting	0 (0%)	1 902 (0%)	1 924 (0%)	1 903 (0%)	4 104 (0%)	5 791 (1%)
Total generation	572 929 (100%)	829 137 (100%)	998 318 (100%)	1 089 882 (100%)	1 163 381 (100%)	1 209 662 (100%)

As seen in Table 53 to Table 56, under the high load growth sensitivity case, onshore wind capacity and generation are expected to increase significantly over time in the Baseline Scenario, from a 7% share of generation in 2022 to a 30% share of generation in 2050. While the share of hydro and nuclear capacity and generation are expected to decrease over time as more wind comes online, the absolute value of both are expected to rise in the Baseline Scenario. In absence of the Regulations, Canada’s electricity system is projected to reduce its proportion of unabated emitting generation from 14% (80 TWh) in 2022 to 7% (76 TWh) in 2050, and to increase its proportion of non-emitting generation from 86% (492 TWh) in 2022 to 93% (1 078 TWh) in 2050. In the Regulatory Scenario, Canada’s electricity system is projected to reduce its unabated emitting generation to a 1% (17 TWh) share in 2050 and to increase its non-emitting generation to 95% (1 140 TWh) in 2050, thus enabling significant GHG emissions reductions (estimated at 303 Mt over the 27-year analytical time frame). Notably, the high load Regulatory Scenario indicates a larger role for nuclear and abated emitting electricity generation capacity and generation to meet the regulatory requirements than was the case under the central case modelling. This result is seen more clearly by examining the incremental buildout of new electricity system capacity under the high load case in Table 57.

Table 57: High load sensitivity case: incremental buildout of new electricity system capacity (MW) by region and technology type, 2024 to 2050
Region	Unabated emitting	Abated emitting	Nuclear	Hydro	Wind (onshore)	Solar	Other non-emitting	Storage	Total
NL	4	0	0	-1	0	0	-6	-250	-253
PEI	0	0	0	0	0	0	0	0	0
NS	-328	0	0	0	1 741	0	-67	672	2 018
NB	-781	0	19	0	0	842	0	922	1 002
QC	0	0	0	998	0	0	0	105	1 103
ON	-13 187	0	4 267	2 183	0	0	0	7 905	1 168
MB	-434	0	0	14	661	-4	0	466	703
SK	-1 527	1 041	0	280	337	23	0	665	819
AB	-9 987	15 232	0	-2	0	10	0	71	5 324
BC	0	0	0	-1 570	0	0	0	2 045	475
YK	0	0	0	0	0	0	0	0	0
NT	3	0	0	-1	0	0	0	0	2
NU	5	0	-5	0	0	0	0	0	0
Total	-26 232	16 273	4 281	1 901	2 739	871	-73	12 601	12 361

While total incremental buildout is lower than what was observed in the central case (12.6 MW versus 14.1 MW), the mix of technologies that are being built out is significantly different. For instance, incremental new buildout of abated emitting electricity generation capacity is estimated to be 6 times higher than in the central case (16.3 GW versus 2.6 GW), while incremental new buildout of nuclear capacity is estimated to be 20 times higher than the central case (4.3 GW versus 0.2 GW). It is also worth noting that forgone new buildout of unabated emitting electricity generation capacity more than doubles from the central case (-26 GW forgone buildout versus -10 GW). In the high load scenario, onshore wind capacity is expected to come online predominantly in the Baseline Scenario, thus rendering incremental new buildout of wind capacity 3.5 times lower than in the central case (2.7 GW versus 9.5 GW).

Overall, these changes to Canada’s capacity and generation mixes under the Regulations are estimated to result in 303 Mt of emissions reductions between 2024 and 2050 (compared to 181 Mt in the central case), disaggregated by region as shown in Table 58. Using the 2% SC-GHGs streams, the societal benefit associated with those 303 Mt emissions reductions is $74.5 B (compared to $44.5 B in the central case), or 331 Mt emission reductions when accounting for offsets.

Table 58: Total GHG emissions reductions, by region (2024–2050, kilotonnes of CO₂e)
Region	27-year total (without offsets)	Annual average (without offsets)	27-year total (with offsets)	Annual average (with offsets)
NL	3	0	3	0
PEI	-5	0	-5	0
NS	17 970	666	18 325	679
NB	1 863	69	1 863	69
QC	0	0	15	1
ON	57 611	2 134	71 452	2 646
MB	0	0	0	0
SK	23 405	867	25 163	932
AB	202 048	7 483	213 526	7 908
BC	28	1	723	27
YT	-31	-1	-31	-1
NT	16	1	94	3
NU	-243	-9	-243	-9
Total	302 665	11 210	330 884	12 255

To analyze the distributional impact on regions, total electricity system costs for the high load case were calculated in the same manner as previously presented in the distributional analysis (i.e. using annualized capital costs instead of a lump sum, and including domestic trade and net carbon pricing payments to the other costs calculated in the CBA). As seen in Table 59, the Regulations are expected to result in total electricity system costs of $41 billion (compared to $9 B in the central case) over the 27-year analytical period. In the Baseline Scenario for the high load sensitivity case, total electricity system costs are estimated at $844 billion between 2024 and 2050, therefore, the $41 billion in incremental system costs represents a 5% increase relative to the Baseline Scenario.

Table 59: High load sensitivity case: incremental electricity system costs, by region (millions of dollars)
Region	2024–2034	2035–2039	2040–2044	2045–2049	2050	27-year total	Annualized average (n=27)
NL	38	233	461	325	-1	1,056	51
PEI	34	-43	-36	-3	-4	-52	-3
NS	399	-372	-535	-581	-96	-1,185	-57
NB	2,545	3,334	3,549	3,228	811	13,467	650
QC	248	1,333	3,103	3,025	313	8,022	387
ON	22	3,180	5,348	5,308	711	14,569	704
MB	36	-474	-346	-280	-43	-1,107	-53
SK	-335	-51	133	93	211	52	2
AB	-1,406	-425	3,434	3,065	1,312	5,979	289
BC	2,622	-360	-771	-1,308	-402	-219	-11
YT	-3	2	5	5	1	10	0
NT	1	0	-14	-16	-2	-31	-1
NU	2	2	13	22	6	45	2
Total	4,203	6,359	14,343	12,884	2,818	40,605	1,961

Given the high degree of uncertainty when developing a scenario for electricity demand in a net-zero future (e.g. the rate of policy and technological development, uptake of electrification in other sectors of the economy, and commercial/industrial considerations), the Department contracted external parties to conduct independent analyses exploring the potential impacts of the Regulations under a high load scenario alongside its in-house models, an exercise in which multiple models used various load growth assumptions to provide a range of perspectives on the matter. Alongside E3MC and NextGrid, the models used to explore this sensitivity case included the COPPER and SILVER models operated by the Sustainable Energy Systems Integration and Transitions (SESIT) Group from the University of Victoria, and the North American Times Energy Model (NATEM) operated by the Energy Super Modellers and International Analysts (ESMIA) Consultants. Each model used its own load growth assumptions to define a high electrification scenario, and projected the GHG emissions and electricity system costs with and without the Regulations to assess the incremental impacts.

In order to maintain the independent nature of the third-party modelling, the Department did not prescribe the utilization of any particular analytical parameters or Baseline Scenario, other than the utilization of the same regulatory design for inclusion in the regulatory scenario. Each model used its own Baseline Scenario, load growth assumptions, analytical time frame, and discount rates. The load growth assumptions for the Baseline Scenario used by the models ranged from 1.83 to 2.02 times increase between 2022 and 2050. Given that electricity demand is exogenous in NextGrid, the model was able to run two scenarios, one matching the load growth determined endogenously by E3MC (i.e. 1.97 times 2022 levels) and one using the Canada Net-Zero scenario from the Canada Energy Regulator report Canada’s Energy Future 2023 (i.e. 1.83 times 2022 levels across all provinces). The COPPER/SILVER model used provincial data for current load then applied the growth from the Canada Energy Regulator Canada’s Energy Future 2023 Canada Net-Zero scenario to the provincial data, resulting in an average load growth of 1.95 times 2022 levels. As with E3MC, load growth in the ESMIA model is endogenous, but the model assumes higher electrification of the economy than E3MC, resulting in an increase in electricity demand of 2.02 times 2022 levels.

A summary of model parameters is presented in Table 60.

Table 60: Summary of model parameters for the high load sensitivity scenario vs the central case scenario
Model	Central case load projection	Source of central case load projection	Sensitivity case load projection	Source of sensitivity case load projection	Analytical base year	Discount rate
E3MC	1.48	Endogenous	1.97	Endogenous	2024	2%
NextGrid	1.48	E3MC central case	1.97	E3MC sensitivity case	2022	2%
NextGrid	1.48	E3MC central case	1.83	Canada Energy Regulator Energy Futures 2023 Canada Net-Zero scenario	2022	2%
COPPER / SILVER (SESIT)	1.59	Province-specific data with expected growth from Canada Energy Regulator Energy Futures 2023 Canada Current Measure scenario	1.95	Province-specific data with expected growth from Canada Energy Regulator Energy Futures 2023 Canada Net-Zero scenario	2021	0%
NATEM (ESMIA)	1.43	Endogenous	2.02	Endogenous	2021	4% (until 2040); 3% (2041–2050)

Given the differences in modelling parameters illustrated in Table 60, comparing the raw results obtained from each model directly is not meaningful. In order to be able to make the results from other models comparable to those derived from E3MC, a percentage difference approach was utilized. Using this approach, all results are expressed as the relative difference, in percentage terms, of the change observed between each model’s high load sensitivity case and each model’s central case.

Specifically, the effect on emission reductions is provided as

${SA}_{E} = \frac{(E_{Regulatory}^{1} - E_{Baseline}^{1}) - (E_{Regulatory} - E_{Baseline})}{(E_{Regulatory} - E_{Baseline})} \times 100$

Where E’_Regulatory, E’_Baseline, E_Regulatory, and E_Baseline, represent the emissions (including offsets) from the sensitivity regulatory, sensitivity Baseline, central regulatory, and central Baseline Scenarios, respectively.

And the effect on incremental costs is provided as

${SA}_{C} = \frac{(C_{Regulatory}^{1} - C_{Baseline}^{1}) - (C_{Regulatory} - C_{Baseline})}{(C_{Regulatory} - C_{Baseline})} \times 100$

Where C’_Regulatory, C’_Baseline, C_Regulatory, and C_Baseline, represent the costs from the sensitivity regulatory, sensitivity Baseline, central regulatory, and central Baseline Scenarios, respectively.

The results of this exercise are presented in Table 61, denoting cumulative national impacts up through the year 2050. All results for emissions include offsets. In both the Baseline and Regulatory Scenarios, it is important to recall that greater electrification will lead to larger emissions reductions outside of the electricity sector, which are outside the scope of the analysis presented here.

Table 61: Percentage change in emissions and electricity system costs from each model’s high load sensitivity scenario relative to each model’s central case scenario
Model	Total emissions (Baseline Scenario)	Total emissions (Regulatory Scenario)	Emissions reductions (incremental)	Electricity system costs (Baseline Scenario)	Electricity system costs (Regulatory Scenario)	Electricity system costs (incremental)
NextGrid - 1.97x	43%	25%	92%^{table g13 note a}	39%	40%	66%^{table g13 note a}
NextGrid - 1.83x	41%	19%	98%^{table g13 note a}	20%	21%	120%^{table g13 note a}
COPPER / SILVER (SESIT) - 1.95x	15%	4%	23%	14%	14%	19%
NATEM (ESMIA) - 2.02x	55%	16%	120%	39%	37%	-3%
Table g13 note(s) Table g13 note a In the two scenarios analyzed by NextGrid, load growth is not concentrated in the same provinces. Specifically, load increases more significantly in the provinces that are more dependent on fossil fuel-fired electricity generation in the 1.83 times load growth scenario relative to the 1.97 scenario, ultimately leading to higher emissions reductions and incremental electricity system costs in the 1.83 times load growth scenario compared to the 1.97 times load growth scenario. Return to table g13 note a referrer

Using the results from NATEM (ESMIA) as an example, the way to interpret the results in Table 61 is as follows. Relative to that model’s central case scenario, that model’s high load sensitivity scenario results in 55% more emissions in that model’s Baseline Scenario, 16% higher emissions in that model’s regulatory scenario, and 120% more emissions reductions due to the Regulations. Relative to that model’s central case scenario, that model’s high load sensitivity scenario results in 39% higher electricity system costs in that model’s Baseline Scenario, 37% higher electricity system costs in that model’s regulatory scenario, and a 3% decrease in incremental electricity system costs due to the Regulations. The ESMIA model projects incremental electricity system cost savings relative to its central case because system costs increase in both the Baseline and the Regulatory Scenarios, but to a smaller extent in the Regulatory Scenario.

As seen in Table 61, all models project that high load growth will increase the emissions reductions attributable to the Regulations, ranging from a 23% increase (SESIT) to a 120% increase (ESMIA) relative to each model’s central case scenario. The models are more divergent in their projections of how the high load growth scenario impacts electricity system costs, ranging from a 3% incremental cost savings (ESMIA) to a 120% incremental cost increase (NextGrid-1.83x) relative to each model’s central case scenario. Variation in results between models is to be expected due to the independent nature of each model and the underpinning modelling structures and assumptions. Ultimately, the magnitude of emissions reductions and incremental electricity system costs projected by each model is highly dependent on the key modelling assumptions in place (e.g. the treatment of TIER in Alberta and the level of emitting generation projected in the Baseline Scenario), and on which provinces are expected to experience the most pronounced load growth changes.

The percentage change results presented in Table 61 can be multiplied by E3MC’s central case results for emissions reductions including offsets (i.e. 193 Mt) and incremental electricity system costs as denoted in Table 43 (i.e. $9 billion) to obtain comparable results to E3MC’s high load case, as presented in Table 62. The results in Table 62 are comparable to the results from E3MC’s high load scenario (i.e. 331 Mt of GHG emissions reductions and $41 billion in incremental electricity system costs).

Table 62: High load sensitivity analysis results: percentage change from each model applied to E3MC’s central case (normalized to Canada-wide 2024–2050 total)
Percentage change source (model)	Emissions reductions (Mt)	Electricity system incremental costs (billions of dollars, discounted)
NextGrid - 1.97x	371	15
NextGrid - 1.83x	384	20
COPPER / SILVER (SESIT) – 1.95x	238	11
NATEM (ESMIA) – 2.02x	424	8.9

Figure 3 depicts the projected yearly CO₂ emissions from the generation of electricity for the grid from years 2025 to 2050 under a high electrification scenario. The emissions, shown on the y-axis, are expressed in megatonnes of CO₂ (Mt CO₂). The Baseline Scenario is represented by a dashed line. It shows projected emissions starting at 35 Mt CO₂ in 2025, dropping to 30 Mt CO₂ in 2030, and then rising steadily to 74 Mt CO₂ in 2050. The Policy scenario is represented by a full line. It shows projected emissions starting at 27 Mt CO₂ in 2025, dropping to 19 Mt CO₂ in 2030, rising to 33 Mt CO₂ in 2035, after which there is a slow decline to 27 Mt CO₂ in 2045, followed by a sharp decline to 2 Mt CO₂ in 2050.

Without the Regulations, electricity emissions could more than double in a high electrification scenario (1.83x). With the Regulations, growth in demand is met, even as emissions decline after 2035, achieving a true net-zero by 2050.

Figure 3. Annual electricity sector emissions in NextGrid’s high electrification (1.83x) scenario

Figure 3. Annual electricity sector emissions in NextGrid’s high electrification (1.83x) scenario – Text version below the graph

Figure 3. Annual electricity sector emissions in NextGrid’s high electrification (1.83x) scenario - Text version

Figure 3 shows Canada’s projected annual electricity sector emissions in a high electrification (1.8x) scenario, using NextGrid modelling results. The vertical axis is labeled “Megatonnes CO₂,” starting at 0 MT and ending at 80 MT, in increments of 10. The horizontal axis represents the chronological years in increments of 5, starting in 2025 and ending in 2050.

There are two lines on the graph. The first line, “without the Regulations” is dashed, and shows Canada’s emissions steadily increasing from 34.7 MT in 2025 to 73.5 MT in 2050. The second line, “with the Regulations” is solid, and shows Canada’s emissions steadily increasing from 26.4 MT in 2025 to a high of 33.2 MT by 2035, then steadily decreasing to 1.9 MT by 2050.

The data is summarized in the following table. Figures are in Megatonnes of CO₂. Data is approximate and has been rounded.

Year	Without the Regulations	With the Regulations
2025	34.7	26.4
2030	30.1	19.3
2035	45.7	33.2
2040	60.3	32.2
2045	71.5	27.2
2050	73.5	1.9

Capital costs, fuel costs, offset costs, buildout constraints, and interprovincial interties

The remainder of the sensitivity analyses were performed using the NextGrid model, in which the costs and cost savings pertaining to a subset of CBA impacts were totalled to create a basis of comparison against the $31.2 billion indicated in Table 39: Costs net of cost savings accounted for in the CBA, by region (millions of dollars), and the $47.3 billion in climate change benefits (including offsets) indicated in Table 14: Avoided global damage from climate change (millions of dollars). Combined, these two figures form a net present benefit of $15.7 billion for the central case scenario against which the results of these sensitivity analyses can be directly compared. These values do not include health and environmental benefits from reduced air pollutant emissions, nor do they include government and administrative costs.

All costs and benefits in this section reflect cumulative totals for Canada (excluding the Territories) from 2025 to 2050, as NextGrid does not assess impacts in the North and does not assess impacts in the year 2024. The one-year difference in analytical period between the CBA and these sensitivity analyses is not anticipated to impact the interpretation of results, given that the majority of impacts in the year 2024 in the CBA pertain to administrative and government costs, neither of which are included in the Table 39 basis of comparison. Likewise, the exclusion of the Territories in the sensitivity analyses versus their inclusion in the CBA is not expected to significantly impact the interpretation of results, given that the regulatory requirements are not expected to apply to electricity generating units in the North. The impact of these sensitivity cases on health and environmental benefits were not assessed. In all tables presented in this section, totals may not add up due to rounding.

In order for the sensitivity analyses from NextGrid to be comparable to the results of the CBA, the results are expressed as the relative difference, in percentage terms, of the change observed between the NextGrid’s sensitivity case in question and NextGrid’s central case, using the same equations as shown in the high load sensitivity analysis. The percentage changes derived from this exercise were then applied to the relevant Canada total results from the central case to ascertain the impact that each scenario may have on the central case results in dollar terms. Given the agility of NextGrid to model multiple scenarios relatively quickly and its ability to reflect minute changes in important details between scenarios, this approach to the sensitivity analysis allowed for a much broader range of analyses to be performed.

Definitions for the sensitivity cases analyzed in this section are presented in Table 63 and a high-level summary of percentage change results (relative to the central case) is presented in Table 64. Detailed descriptions and monetized results for each sensitivity case are provided in subsections below.

Table 63: Sensitivity case definitions
Sensitivity case	Case definition
Capital cost of wind, solar, SMR, and CCS	Total of eight sensitivity cases: National Renewable Energy Laboratory (NREL) "Conservative" and "Advanced" technological learning curves for wind, solar, and CCS. ±25% for SMR
Cost of fuels (natural gas, RNG, and hydrogen)	Total of six sensitivity cases: ±25% for hydrogen and RNG (simultaneously) ±25% for natural gas ±50% for natural gas
Cost of offsets	Total of two sensitivity cases: ±$45
Wind buildout constraints	Total of two sensitivity cases: ±25%
Endogenous buildout of interprovincial interties	Total of one sensitivity case: endogenous new buildout allowed

Table 64: Percentage change in emissions reductions (including offsets) and select costs (net of cost savings) in each sensitivity case, relative to the central case
Sensitivity case	% change in emissions over Central Baseline	% change in emissions over Central Regulatory	% change in emissions reductions over Central	% change in costs (net of cost savings) over Central Baseline	% change in costs (net of cost savings) over Central Regulatory	% change in incremental costs (net of cost savings) over Central
Wind Advanced	-0.4%	0.0%	-1.5%	-0.1%	-0.3%	-5.6%
Wind Conservative	0.7%	-0.9%	5.0%	0.2%	0.8%	14.2%
Solar Advanced	0.0%	0.0%	0.0%	0.0%	0.0%	0.6%
Solar Conservative	0.0%	-0.1%	0.2%	0.0%	-0.2%	-3.9%
SMR -25%	0.0%	0.0%	0.0%	0.0%	0.0%	0.0%
SMR +25%	0.0%	0.0%	0.0%	0.0%	0.0%	0.0%
CCS Advanced	0.0%	-0.1%	0.3%	0.0%	-0.1%	-2.1%
CCS Conservative	0.0%	0.0%	0.1%	0.0%	0.0%	0.1%
NG -25%	3.1%	5.9%	-4.4%	-2.6%	-2.7%	-6.7%
NG +25%	-4.5%	-6.6%	1.2%	2.9%	1.6%	-26.9%
NG -50%	6.2%	13.1%	-12.5%	-4.6%	-4.6%	-3.3%
NG +50%	-12.0%	-10.2%	-16.6%	6.5%	3.6%	-64.8%
H₂ and RNG -25%	-0.2%	1.0%	-3.4%	-0.3%	-1.2%	-23.4%
H₂ and RNG +25%	0.1%	0.1%	-0.1%	0.3%	0.6%	8.7%
Offsets -$45	N/A^{table g16 note a}	0.4%	-1.2%	N/A^{table g16 note a}	-0.1%	-1.7%
Offsets +$45	N/A^{table g16 note a}	-0.3%	0.8%	N/A^{table g16 note a}	0.2%	4.6%
Wind Constraint -25%	0.6%	1.3%	-1.2%	1.9%	0.9%	-20.6%
Wind Constraint +25%	-2.7%	-1.7%	-5.5%	0.4%	-0.7%	-26.3%
Allow endogenous interties	N/A^{table g16 note a}	-1.4%	3.8%	N/A^{table g16 note a}	-10.5%	-259.0%
Table g16 note(s) Table g16 note a In these sensitivity cases, the central Baseline Scenario has the same value as the sensitivity Baseline Scenario. Return to table g16 note a referrer

In some cases, the sensitivity analysis results appear non-intuitive. For instance, when the price of natural gas increases in the sensitivity case, one might expect the incremental costs to increase relative to the central case. However, in both the Baseline Scenario and regulatory scenario of that sensitivity case, costs increase relative to the central case, and by a greater extent in the Baseline Scenario than in the regulatory scenario, thereby resulting in lower incremental costs in the sensitivity case relative to the central case. Similarly, when wind buildout constraints are tightened in the sensitivity case, one might expect the incremental costs to increase relative to the central case. However, costs in the Baseline Scenario increase by more than they do in the regulatory scenario, thereby resulting in lower incremental costs in the sensitivity case relative to the central case. When the wind buildout constraints are loosened in the sensitivity case, emissions in the Baseline Scenario decrease due to greater wind buildout, thereby reducing the need to decrease emissions in the regulatory scenario, resulting in lower emissions reductions in the sensitivity case relative to the central case. The percentage changes in the Baseline Scenario and the regulatory scenario in each sensitivity case (relative to the central case) are important factors to consider when interpreting the percentage changes in emissions reductions and incremental costs.

The intertie sensitivity case adds just under 8,500 MW of new intertie capacity to Canada’s electricity system, mainly between Alberta and British Columbia, and Quebec and Ontario. This sensitivity shows the most notable impacts, with a significant decrease in incremental costs relative to the central case (-259%). The marked decrease in costs is largely attributed to reduced new capital buildout in the regulatory scenario of the sensitivity case, including much less (expensive) hydro capacity being built relative to the central case. More interties replace the balancing role that hydro plays and allows more wind to be built out instead, ultimately decreasing total capital costs.

Capital cost of wind, solar, SMR, and CCS

The costs and benefits of the Regulations may be influenced by the speed in which the marginal costs of certain emerging technologies fall over time as a result of learning by doing, economies of scale, or other factors. Specifically, onshore wind, solar, NGCCS, and SMRs (nuclear) are emerging existing technologies that provide important low or non-emitting electricity generation in the Regulatory Scenario.

Figure 4 indicates the capital cost curves used in NextGrid’s central case and the sensitivity cases for solar, onshore wind, NGCCS, and SMR, while Table 65 indicates the sources used for the 2022 historical cost assumptions and learning curves used to derive the cost curves seen in the Figure. These costs are used for all regions across Canada and do not include the impact of ITCs, which were modelled on top of these curves.

Figure 4 : Central case and sensitivity case capital cost assumptions for onshore wind, solar, NGCCS, and SMR ($/MW, 2022 constant dollars)

Figure 4. Central case and sensitivity case capital cost assumptions for onshore wind, solar, NGCCS, and SMR ($/MW, 2022 constant dollars)– Text version below the graph

Figure 4 : Central case and sensitivity case capital cost assumptions for onshore wind, solar, NGCCS, and SMR ($/MW, 2022 constant dollars) - Text version

Figure 4 shows four graphs depicting the change in Capital cost assumptions for four technologies, onshore wind, solar, CCS and SMRs. Each graph has a y axis representing costs per MW in Millions of $, in Canadian 2022 dollars, and an x axis showing years from 2020 to 2050 in five year increments.

The first graph is the Cost of Onshore wind and shows three lines: one representing the advanced cost scenario, another representing the moderate cost scenario, and a third representing the conservative cost scenario. All scenarios have the same starting point at $1.9 million in 2022 and decline together to about $1.5 million in 2025, at which point the lines divide into three separate declining trajectories. The conservative cost line declines linearly arriving at $1.3 million in 2050, while the moderate costs arrives at $1.1 million, and the advanced cost arrives at $1.0 million.

The second graph is the Cost of solar and shows three lines: one representing the advanced cost scenario, another representing the moderate cost scenario, and a third representing the conservative cost scenario. All scenarios have the same starting point at $1.7 million in 2022 and decline in three separate trajectories to 2050. The conservative cost line declines the least landing at $1.0 million in 2050, while the moderate costs lands at $0.7 million, and the advanced cost lands at $0.6 million.

The third graph shows the costs of CCS in six lines: three lines are for Greenfield CCS installation, and three lines are for Brownfield installation. Each technology as a line representing the advanced cost scenario, another representing the moderate cost scenario, and a third representing the conservative cost scenario. For Greenfield CCS, all scenarios have the same starting point at $3.5 million in 2022 and decline in three separate trajectories to 2050. For Greenfield CCS, the conservative cost line declines the least landing at $2.6 million in 2050, while the moderate costs lands at $2.2 million, and the advanced cost lands at $1.9 million. For Brownfield CCS, the conservative cost line declines the least landing at $1.5 million in 2050, while the moderate costs lands at $1.3 million, and the advanced cost lands at $1.1 million.

The fourth graph shows the costs of SMR in three lines: one representing the central case assumption, another representing the central case less 25%, and a third representing the central case plus 25%. Each line is flat between 2022 and 2040 when the cost declines to a new level until 2050. The 25% less line starts at $9.6 million and declines to $8 million in 2040, the 25% plus line starts at $16 million, and declines to $13 million in 2040.

Table 65: Source of capital costs assumptions for onshore wind, solar, NGCCS, and SMRs
Technology	Source for initial value	Source for learning curve applied to initial value
Onshore Wind	Canada Energy Regulator: Canada’s Energy Future 2023	NREL: 2023 Electricity ATB Technologies and Data Overview
Solar	Estimated with consideration from various sources (including NRCan, AESO, BC Hydro, and NS Power)	NREL: 2023 Electricity ATB Technologies and Data Overview
NGCCS (greenfield and brownfield)^{table g17 note a}	AESO 2024 Long-term Outlook (PDF)	NREL: 2023 Electricity ATB Technologies and Data Overview
SMR	IESO 2022 Pathways to Decarbonization	Argonne National Laboratory: Small Modular Nuclear Reactors (PDF)
Table g17 note(s) Table g17 note a Greenfield costs are used for new NGCCS buildout while brownfield costs are used for conversions to NGCCS capacity. Return to table g17 note a referrer

The results of this sensitivity analysis are presented in Table 66 to Table 68.

Table 66: Capital cost sensitivity analysis results: benefits (Canada-wide 2024–2050 total)
Description of impact	Wind Advanced	Wind Conservative	Solar Advanced	Solar Conservative	SMR -25%	SMR +25%	CCS Advanced	CCS Conservative
GHG emissions reductions, electricity sector (Mt)	178	194	185	182	181	181	182	181
GHG emissions reductions, offsets (Mt)	12	13	10	12	12	12	12	12
Climate change mitigation, electricity sector (millions of dollars)	43,517	47,622	45,327	44,664	44,447	44,447	44,659	44,433
Climate change mitigation, offsets (millions of dollars)	2,798	3,128	2,362	2,858	2,875	2,875	2,880	2,941
Fuel cost savings (millions of dollars)	6,590	7,013	6,789	6,545	6,627	6,627	6,628	6,476
Variable O&M cost savings (millions of dollars)	337	545	448	435	430	430	435	360
Total monetized benefits (millions of dollars)	53,242	58,308	54,926	54,502	54,379	54,379	54,602	54,210

Table 67: Capital cost sensitivity analysis results: costs (Canada-wide 2024–2050 total, in millions of dollars)
Description of impact	Wind Advanced	Wind Conservative	Solar Advanced	Solar Conservative	SMR -25%	SMR +25%	CCS Advanced	CCS Conservative
Capital costs for new electricity system capacity	23,218	27,787	24,732	23,294	24,345	24,345	23,855	24,248
Fixed O&M and refurbishment costs	7,480	7,883	7,846	7,653	7,672	7,672	7,722	7,601
Offset costs	781	871	661	798	803	803	804	823
Residual value of capital on early retirements	1,918	1,918	1,918	1,918	1,918	1,918	1,250	1,918
International net import expenditure	2,956	4,348	3,422	3,647	3,503	3,503	3,553	3,388
Total costs	36,353	42,807	38,579	37,310	38,241	38,241	37,184	37,978

Table 68: Capital cost sensitivity analysis results: net benefit (Canada-wide 2024–2050 total, in millions of dollars)
Impact	Wind Advanced	Wind Conservative	Solar Advanced	Solar Conservative	SMR -25%	SMR +25%	CCS Advanced	CCS Conservative
Total benefits	53,242	58,308	54,926	54,502	54,379	54,379	54,602	54,210
Total costs	36,353	42,807	38,579	37,310	38,241	38,241	37,184	37,978
Net benefit	16,888	15,501	16,347	17,191	16,137^{table g20 note a}	16,137^{table g20 note a}	17,418	16,230
Table g20 note(s) Table g20 note a This sensitivity analysis result in the same net benefit because new SMR deployment in the central case is low, and varying the cost of the technology in the sensitivity case did not have a notable impact on increasing or decreasing that deployment. Return to table g20 note a referrer

Cost of fuels (natural gas, RNG, and hydrogen)

The costs and benefits of the Regulations may be influenced by the price of certain fuels, the most relevant of which is natural gas. Specifically, the price of natural gas can influence the future buildout of natural gas-fired electricity generation units in the Baseline Scenario, which in turn can influence the incremental impact of the Regulations. Additionally, two emerging fuels that can be leveraged in the regulatory scenario to “fuel blend” reduce a natural gas-fired electricity generation unit’s average emissions intensity. Those fuels are renewable natural gas (RNG) and hydrogen. Given the uncertainty associated with future production methods (e.g. blue or green hydrogen), feedstock availability and transport and distribution infrastructure, there is significant uncertainty around future prices for these fuels. In the central case modelling, RNG and hydrogen are rarely used given the central case price projections.

The NextGrid model uses fuel prices that are endogenously determined by E3MC for each region and year. In E3MC, historic fuel prices come from a variety of sources, including the Energy Information Agency (Annual Energy Outlook 2023), International Energy Agency (World Energy Outlook 2023), S&P Global, and Wood Mackenzie. For natural gas and other fuels, E3MC simulates supply and demand in all sectors of the economy to compute delivered prices over the projection period. For hydrogen specifically, the delivered price is a function of many cost factors including the method of production and its associated capital costs, operations and maintenance costs, fuel costs, and feedstock costs. Hydrogen production is assumed to be close or co-located with consumption, making transportation costs negligible. By contrast, RNG prices were determined by applying a multiplier to natural gas prices based on the ratio between RNG and natural gas prices charged by provincial utilities. The price of natural gas, RNG, and hydrogen used in NextGrid’s central case in each province in select years (2025 and 2050) is indicated in Table 69.

Table 69: Central case fuel costs for natural gas, RNG, and hydrogen (in 2022$/mmBTU)
Province	Natural Gas – 2025	Natural Gas – 2050	RNG – 2025	RNG – 2050	Hydrogen – 2025	Hydrogen – 2050
BC	3.89	4.92	6.20	7.28	9.83	10.05
AB	1.60	2.57	7.86	8.91	10.04	9.95
SK	2.45	3.51	11.62	12.99	11.52	11.83
MB	5.72	6.64	26.06	26.95	20.72	19.59
ON	5.40	6.16	26.80	26.99	12.34	11.97
QC	9.67	10.29	39.68	39.43	10.59	10.28
NB	7.65	8.86	34.59	36.69	30.29	30.67
NS	4.63	5.73	21.27	22.83	46.72	48.16
NL	2.57	3.70	12.16	13.79	70.03	72.06
PE	2.58	3.72	12.23	13.89	28.22	29.23

In the sensitivity case, the price of natural gas in each year of the projection period is adjusted from the central case values by ±25% and ±50%. RNG and hydrogen are considered somewhat interchangeable in NextGrid, meaning that, when fuel blending is an option, the lowest cost of the two will be selected. Accordingly, for the sensitivity case, the price of hydrogen and RNG are adjusted simultaneously by ±25%, which, in some cases, results in the price of hydrogen and RNG being cheaper than that of natural gas, after factoring in carbon pollution payments and (potentially) offsets costs. The results of this sensitivity analysis are presented in Table 70 to Table 72.

Table 70: Fuel cost sensitivity analysis results: benefits (Canada-wide 2024–2050 total, discounted)
Description of impact	NG -25%	NG +25%	NG -50%	NG +50%	H₂ and RNG -25%	H₂ and RNG +25%
GHG emissions reductions, electricity sector (Mt)	165	192	144	156	189	180
GHG emissions reductions, offsets (Mt)	12	10	9	4	1	13
Climate change mitigation, electricity sector (millions of dollars)	40,182	47,235	34,375	38,270	46,068	43,990
Climate change mitigation, offsets (millions of dollars)	2,920	2,461	2,119	987	353	3,099
Fuel cost savings (millions of dollars)	3,393	8,240	-1,555	6,900	3,262	6,820
Variable O&M cost savings (millions of dollars)	305	402	-775	-221	141	490
Total monetized benefits (millions of dollars)	46,800	58,338	34,164	45,936	49,824	54,399

Table 71: Fuel cost sensitivity analysis results: costs (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	NG -25%	NG +25%	NG -50%	NG +50%	H₂ and RNG -25%	H₂ and RNG +25%
Capital costs for new electricity system capacity	21,093	18,692	20,304	9,524	17,444	26,793
Fixed O&M and refurbishment costs	5,856	7,663	2,245	6,190	6,257	7,742
Offset costs	839	670	613	263	95	891
Residual value of capital on early retirements	1,250	1,918	1,049	1,918	1,918	1,918
International net import expenditure	1,922	4,466	-709	2,508	2,618	2,513
Total costs	30,960	33,409	23,502	20,403	28,332	39,857

Table 72: Fuel cost sensitivity analysis results: net benefit (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	NG -25%	NG +25%	NG -50%	NG +50%	H₂ and RNG -25%	H₂ and RNG +25%
Total benefits	46,800	58,338	34,164	45,936	49,824	54,399
Total costs	30,960	33,409	23,502	20,403	28,332	39,857
Net benefit	15,840	24,928	10,662	25,532	21,491	14,542

Cost of offsets

The uptake of offsets under the Regulations may be influenced by the assumed price of offsets. In the central case, the assumed price of offsets is equivalent to the minimum national carbon price (i.e. $170/tonne in nominal terms from 2030 out to 2050). In reality, the future price of offsets will be determined by their supply and demand in relation to other compliance mechanisms across a wide variety of initiatives. The price of offsets in the sensitivity case toggles the central case value by ±$45 in nominal terms. A $45 premium relative to the minimum national carbon price accounts for the potential added value of cross-recognized credits to industry. The results of this sensitivity analysis are presented in Table 73 to Table 75.

Table 73: Offset cost sensitivity analysis results: benefits (Canada-wide 2024–2050 total, discounted)
Description of impact	Offsets -$45	Offsets +$45
GHG emissions reductions, electricity sector (Mt)	160	197
GHG emissions reductions, offsets (Mt)	23	4
Climate change mitigation, electricity sector (millions of dollars)	39,122	48,287
Climate change mitigation, offsets (millions of dollars)	5,567	918
Fuel cost savings (millions of dollars)	6,150	6,325
Variable O&M cost savings (millions of dollars)	302	462
Total monetized benefits (millions of dollars)	51,141	55,992

Table 74: Offset cost sensitivity analysis results: costs (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	Offsets -$45	Offsets +$45
Capital costs for new electricity system capacity	23,821	25,669
Fixed O&M and refurbishment costs	6,934	7,945
Offset costs	1,237	307
Residual value of capital on early retirements	1,918	1,918
International net import expenditure	1,947	4,027
Total costs	35,857	39,866

Table 75: Offset cost sensitivity analysis results: net benefit (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	Offsets -$45	Offsets +$45
Total benefit	51,141	55,992
Total cost	35,857	39,866
Net benefit	15,285	16,126

Wind buildout constraints

In the central case modelling, new wind capacity is a major contributor to compliance under the Regulatory Scenario, and the assumed buildout limits on new wind is a binding constraint in some regions in some instances. As such, the costs and benefits of the Regulations may be influenced by the assumed buildout limits for wind capacity. Buildout limits represent factors that can influence the speed at which new capacity can be constructed and deployed. These factors may include the availability of land, transmission constraints, labour, or materials. The buildout limits for wind used in NextGrid’s central case is presented in Table 76. The 2025 to 2029 buildout constraints are based on feedback from provincial utilities during engagement, current (publicly available) announcements, or historical data, whereas the cumulative total future buildout constraints, 2025 to 2050, are based on internal expert assessment based on past engagement with utilities and public information.

Table 76: Onshore wind buildout constraint for total allowable new capacity in the central case (MW)
Period	BC	AB	SK	MB	ON	QC	NB	NS	PE	NL
2025 to 2029	6 725	6 725	1 678	5 000	5 000	7 500	1 200	1 248	1 000	1 000
2025 to 2050	15 000	15 000	10 000	5 000	20 000	20 000	5 000	5 000	1 000	1 000

For the sensitivity case, the wind buildout constraints are adjusted from their central case values by ±25%. The results of this sensitivity analysis are presented in Table 77 to Table 79.

Table 77: Wind buildout constraints sensitivity analysis results: benefits (Canada-wide 2024–2050 total, discounted)
Description of impact	Wind +25%	Wind -25%
GHG emissions reductions, electricity sector (Mt)	168	175
GHG emissions reductions, offsets (Mt)	12	14
Climate change mitigation, electricity sector (millions of dollars)	41,230	42,707
Climate change mitigation, offsets (millions of dollars)	2,770	3,281
Fuel cost savings (millions of dollars)	6,192	6,401
Variable O&M cost savings (millions of dollars)	362	441
Total monetized benefits (millions of dollars)	50,554	52,830

Table 78: Wind buildout constraints sensitivity analysis results: costs (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	Wind +25%	Wind -25%
Capital costs for new electricity system capacity	18,095	19,204
Fixed O&M and refurbishment costs	6,458	6,894
Offset costs	774	913
Residual value of capital on early retirements	1,918	1,918
International net import expenditure	2,391	3,229
Total costs	29,636	32,158

Table 79: Wind buildout constraints sensitivity analysis results: net benefit (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	Wind +25%	Wind -25%
Total benefit	50,554	52,830
Total cost	29,636	32,158
Net benefit	20,918	20,672

Endogenous buildout of interprovincial interties

The costs and benefits of the Regulations may be influenced by the assumption around future interprovincial intertie buildout. While NextGrid has the ability to build out new endogenous interties if doing so would be beneficial from a national system cost perspective, this option was not allowed in the central case modelling, which assumes that interprovincial interties cannot be expanded beyond the capacity of existing or planned interties. The buildout of new endogenous interties was a feature of the central case modelling performed for the Canada Gazette, Part I. However, during the public comment period, many key interested parties indicated that they do not have plans to build additional interties as a means of compliance with the Regulations. Accordingly, this compliance pathway was removed from the central case modelling performed for the Canada Gazette, Part II. Nonetheless, new interties remain a potential pathway for complying with the Regulations in a manner that could generate additional GHG reductions and reduced costs relative to the central case. The buildout of new endogenous interties in the Regulatory Scenario is therefore considered as a sensitivity case and the new intertie capacity and associated capital cost determined by NextGrid for this sensitivity case are presented in Table 80. The cost of each intertie depends on many factors including line length, infrastructure needed, and the line rating (voltage) and therefore might not be consistent per MW per kilometre (km).

Table 80: New endogenous intertie capacity, estimated average capital cost, and line length in the sensitivity case
Connected regions	New intertie capacity (MW)	Average capital cost ($/MW, 2022 constant dollars, in millions, undiscounted)	Line length (km)
AB – SK	139	2.9	320
AB – BC	1 200	1.4	400
SK – MB	61	2.1	700
PE – NB	250	0.8	75
NS – NL	579	4.3	346
QC – ON	6 266	0.9	350

The results of this sensitivity analysis are presented in Table 81 to Table 83.

Table 81: New endogenous interties sensitivity analysis results: benefits (Canada-wide 2024–2050 total, discounted)
Description of impact	New endogenous interties allowed
GHG emissions reductions, electricity sector (Mt)	193
GHG emissions reductions, offsets (Mt)	11
Climate change mitigation, electricity sector (millions of dollars)	47,369
Climate change mitigation, offsets (millions of dollars)	2,724
Capital cost savings for new electricity system capacity (millions of dollars)	45,983
Fuel cost savings (millions of dollars)	7,782
Variable O&M cost savings (millions of dollars)	1,696
Total monetized benefits (millions of dollars)	105,554

Table 82: New endogenous interties sensitivity analysis results: costs (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	New endogenous interties allowed
Capital costs for new interprovincial intertie capacity	6,505
Fixed O&M and refurbishment costs	10,416
Offset costs	764
Residual value of capital on early retirements	1,911
International net import expenditure	1,398
Total costs	20,994

Table 83: New endogenous interties sensitivity analysis results: net benefit (millions of dollars, Canada-wide 2024–2050 total, discounted)
Description of impact	New endogenous interties allowed
Total benefit	105,554
Total cost	20,994
Net benefit	84,561

The results show a capital cost savings in this sensitivity case because interties cannot be built in the sensitivity Baseline Scenario (this is the same scenario as the central case Baseline Scenario), but they can be built in the sensitivity regulatory scenario. As a result, in the Baseline Scenario, the model depends on more expensive non-emitting capacity to meet demand and provide flexibility. In the sensitivity regulatory scenario in which new interties are allowed, and the combination of less expensive interties and less expensive non-emitting capacity results in lower capital cost expenditures.

Small business lens

The Regulations do not impose any compliance or administrative requirements on small businesses as defined by the Treasury Board Secretariat of Canada (less than 100 employees or annual gross revenues below $5 million).

One-for-one rule

As per the Government of Canada’s Policy on Limiting Regulatory Burden on Business, the one-for-one rule applies given that the Regulations will increase the cost of administrative burden on business; namely, the electricity sector. The Red Tape Reduction Regulations specify the accounting of administrative burden as the sum of costs incurred during the first 10 years after a regulation is registered. As such, administrative burden associated with the Regulations only constitute the costs incurred from 2024 to 2033, and not those incurred from 2034 to 2050. Specifically, this means that the accounting of administrative burden does not include burden associated with annual reporting beginning 2035, and only includes burden associated with familiarization of reporting requirements and submission of a registration report and registration assignment in 2024.

Under Element A of the one-for-one rule, the Regulations are estimated to result in an annualized increase in administrative burden of $74,669, or $612.04 per facility, calculated by transforming the administrative costs incurred between 2024 and 2033 in Table 34 (in the Costs subsection) into 2012 constant dollars and discounted to base year 2012 using a 7% discount rate. Under Element B of the one-for-one rule, the Regulations will repeal two existing regulatory titles between 2035 and 2045, therefore resulting in a net decrease of one regulatory title.

Regulatory cooperation and alignment

Other federal policies and instruments

The Department has worked to ensure that the Regulations are in alignment with other federal policies and instruments, such as the announced investment tax credits available to the electricity sector, as well as the Canadian Net Zero Emissions Accountability Act and goal to be a net-zero emissions economy by 2050. The Regulations will repeal the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity in 2035 and 2050, respectively, for all electricity generating units previously covered under those regulations. The requirements in the Regulations will not overlap with regulatory requirements for industrial cogeneration units covered under the proposed Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations (OGECR) as published in the Canada Gazette, Part I.

As described in the Description section, Canadian offset credits are one of the compliance flexibility mechanisms to comply with the AEL for a unit. Since other federal regulations also enable the use of Canadian offset credits, the Regulations establish that regulatees would be permitted to use Canadian offset credits to meet coinciding obligations under carbon pricing regimes and the Regulations if the following conditions are met:

The offset credits are used for compliance under the carbon pricing regime for the same year;
The offset credits are used under the carbon pricing regime in relation to the same unit; and
The offset credits are used to fulfill a requirement under the carbon pricing regime other than for a requirement that relates to an extraordinary situation, such as to replace a cancelled credit or as compensation for non-compliance with a requirement.

The Department will establish a list of carbon pricing systems where cross-recognition for these Regulations is authorized. The proposed amendments to the Output-Based Pricing System Regulations (OBPS), published on November 9, 2024, would allow for this cross-recognition where the federal OBPS applies. While the Regulations do enable the cross-recognition of these credits for multiple compliance obligations, this depends on other regulations allowing cross-recognition of one offset credit to account for the same tonne of CO₂ equivalent emitted. Operationalization of cross-recognition in other jurisdictions would depend on a province making any necessary adjustments to their carbon pricing systems and entering into a recognition agreement with the Minister.

The conditions for cross-recognition would avoid double claiming, which is a form of double counting where an offset credit is used by more than one party to meet multiple and different obligations. This is because a responsible party can only use the eligible offset credit to meet their obligations associated with the GHG emissions from the same emissions under carbon pricing and the Regulations. Offset credits represent real emissions reductions and removals. The cross-recognition of these credits under carbon pricing and the Regulations would treat out-of-sector emission reductions consistently with in-sector abatement that may assist an operator meeting their obligations under both carbon pricing and the Regulations.

In terms of the indirect accounting of renewable natural gas blended into a North American natural gas pipeline network (as detailed in the Description section), the conditions to be met with respect to subtracting the emissions associated with the RNG, as well as the information to be submitted are based on the requirements under the Clean Fuel Regulations (CFR).

Provinces and territories

Some provincial governments regulate GHG emissions in their electricity sector. The Regulations may overlap with requirements in some provincial regulations, such as Saskatchewan’s Management and Reduction of Greenhouse Gases (General and Electricity Producer) Regulations and Nova Scotia’s Greenhouse Gas Emissions Regulations; however, the Regulations are expected to be more stringent than other regulatory schemes for the electricity sector in Canada. Given the timing of the coming into force of the emissions limits, the Regulations will not affect current or proposed equivalency agreements with Saskatchewan and Nova Scotia on the federal Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations.

Protection of the environment is shared between the Government of Canada and provincial governments. As a tool for minimizing regulatory duplication and offering flexibility in achieving equivalent policy outcomes, CEPA allows the Governor in Council of Canada, on the recommendation of the Minister of the Environment, to make an Order so that the provisions of the CEPA regulations that are the subject of an equivalency agreement do not apply in a province or territory. For this to occur, the province or territory must first enter into an equivalency agreement with the federal Minister of the Environment. An equivalency agreement is a written agreement entered into by the federal Minister of the Environment and the province or territory declaring that there are in force in the province or territory, laws containing provisions that are equivalent to the given federal regulations and laws containing provisions that are similar to sections 17 to 20 of CEPA for the investigation of alleged offences under environmental legislation of the province or territory.

Generally, provincial or territorial laws are considered to be equivalent to the federal regulations in question if they result in equivalent GHG emission outcomes, calculated in terms of carbon dioxide equivalent (CO₂e). In particular, GHG emissions under provincial or territorial regulations must be no greater than they would have been if the corresponding federal regulations had applied instead. This allows a province or territory to attain the GHG outcome that would have occurred under the federal regulations in a way that best suits its particular circumstances.

The Department is willing to consider entering into equivalency agreements for the Regulations with interested provinces and territories in order to reduce regulatory overlap and provide them greater flexibility to address unique regional circumstances and needs during the transition to a net-zero grid.

International

While electricity in Canada is largely domestically supplied, Canada and the United States are nonetheless significant international trading partners for electricity. The Regulations are not expected to greatly impact trade dynamics between Canada and the United States (as demonstrated in the Benefits and Costs section), with exports from Canada to the United States estimated to decrease by 0.1% and imports from the United States estimated to decrease by 11%, relative to the Baseline Scenario. Canada and the United States share common goals and approaches for regulating GHG emissions from the electricity sector. Notably, in March 2023, the President of the United States and the Prime Minister issued a joint statement in which they referenced commitments by both countries to achieve net-zero electricity systems, accelerate efforts to phase out new, unabated coal-fired electricity generation facilities and reduce GHG emissions from the North American electricity sector through regulations.^{footnote 35}

To this end, in April 2024, the US Environmental Protection Agency (US EPA) issued final carbon pollution standards for power plants that set carbon dioxide limits for new gas-fired combustion turbines and CO₂ emission guidelines for existing coal, oil and gas-fired steam generating units.^{footnote 36} Currently, the US Rules only apply an emissions standard to new base load combustion turbines, which must meet a standard of roughly 45 t/GWh by 2032. In contrast, the prohibition in the Regulations will apply to all new units starting in 2035. Between 2035 and 2049 (inclusive), the prohibition for each unit is an AEL calculated with an applicable emissions intensity of 65 t/GWh and based on the unit’s electricity generating capacity. The Regulations also apply to all existing units, but the emissions limit for existing units begins the later of 2035 or the end of prescribed life for these units. The US EPA is also proceeding with a new, comprehensive approach to reduce GHG emissions from existing natural gas-fired turbines, which may include future proposed rulemakings.^{footnote 37}

Effects on the environment

In accordance with the Cabinet Directive on the Environmental Assessment of Policy, Plan and Program Proposals, a Strategic Environmental Assessment (SEA) was conducted for the Regulations. The SEA concluded that the Regulations are expected to produce positive environmental effects that contribute to Sustainable Development Goal 7 - Affordable and Clean Energy. In addition, the SEA concluded that the Regulations are expected to support the 2022–2026 Federal Sustainable Development Strategy goal to “Increase Canadians’ Access to Clean Energy”.

By contrast, as Departmental modelling suggests that the Regulations are expected to increase deployment of low and non-emitting sources of electricity generation, potential secondary negative environmental effects could include localized land-use impacts associated with development and operations of new solar, wind and hydro power projects. There are also considerations around the storage and disposal of spent fuel from nuclear power plants and the impacts of the replacement and disposal of wind turbines and solar panels when they reach the end of their life span. Wind turbines are 85–90% recyclable by mass^{footnote 38}and solar panels are 90% recyclable by mass,^{footnote 39} so options exist to mitigate these impacts. These potential negative environmental effects are expected to be limited compared to the positive environmental effects associated with reducing the amount of GHGs and air pollutant emissions from the electricity sector.

Without the Regulations (i.e., under the Baseline Scenario), Departmental modelling suggests that the electricity sector would have continued producing electricity from natural gas-fired electricity generating units without the use of emissions abatement technologies (see Table 8 in the Benefits and Costs section), which would have contributed to negative health and environmental impacts. Under the Baseline Scenario, these emissions would have been expected to continue well into the 2040s. Furthermore, the Department has not found or received credible evidence, analysis, or modelling that indicates that under a Baseline Scenario, emissions from the electricity sector would have decreased significantly enough to enable a net-zero electricity system. As such, under the Baseline Scenario, Canadians can reasonably expect that there would be negative environmental effects related to the excessive emissions from the electricity sector post-2050. Given that the Regulations require the complete offsetting of emissions from the electricity sector starting in 2050, Canadians can reasonably expect that the Regulations will have (i.e., in addition to those benefits from the Regulations arising in the 27-year analytic period) significant environmental benefits post-2050, although these benefits were not estimated in the Benefits and Costs section as they fall out of scope of the analytical period selected for the CBA.

Gender-based analysis plus

Using a gender-based analysis plus (GBA+) approach, the Department has identified that relative to the general Canadian population, the Regulations may have disproportionate impacts on certain demographic groups. Factors considered in the GBA+ are summarized in the subsections below.

Disproportionately impacted populations and future generations

By virtue of their scope as a federal regulatory instrument, the Regulations help reduce Canada’s GHG emissions (as quantified in the Benefits section). These GHG emission reductions are particularly beneficial to demographic groups that are more exposed and disproportionately impacted by the adverse impacts of climate change and air pollution in Canada.^{footnote 40,}^{footnote 41} This includes coastal and drought-prone communities as well as rural, remote and northern communities which tend to have less resilient infrastructure and are more vulnerable to increases in the frequency or intensity of extreme weather events or those who live in close proximity to air pollution sources.^{footnote 42,}^{footnote 43}

Children, older adults, pregnant women and people with pre-existing illnesses are more susceptible to the health risks posed by climate change, such as extreme heat, air pollution and vector-borne illnesses.^{footnote 40} Weather-related evacuations are particularly difficult for people with limited independence and mobility. People with disabilities, lone-parent households, recent immigrants, racialized individuals and the Two-Spirit, lesbian, gay, bisexual, transgender, queer, intersex and additional people who identify as part of sexual and gender diverse communities (2SLGBTQI+) population are statistically more likely to lack the financial resources needed to adapt to climate change or may not have reliable access to resources or institutions to cope with extreme weather events due to discrimination, language, citizenship barriers, or other factors.^{footnote 44,}^{footnote 41} Children, youth and future generations will face increasingly severe climate change impacts over their lifetimes. These groups stand to benefit the most from the build-out of clean electricity infrastructure that has a long-term impact on GHG emissions reductions.

While the electricity sector has significantly reduced air pollutant emissions since 2015 particularly through the reduced reliance on coal-fired electricity generation,^{footnote 45}the Regulations are expected to result in some additional air pollutant emissions reductions across Canada (as quantified in the Benefits section). These reductions will result in some improvements to localized air quality, depending on the geographical and meteorological features of the emissions sites, which in turn will result in some level of avoided adverse health impacts and avoided adverse environmental impacts, depending on the size and proximity of populations relative to the emissions sites.

While all people living in Canada can benefit from improved air quality, the groups that are more susceptible and exposed to air pollutants emitted by the electricity sector are expected to benefit the most from the Regulations. Specifically, populations living near fossil fuel-based electricity generation units tend to be more exposed to the air pollutants released from those units. Since most fossil fuel-based electricity generation units are located in Alberta, Saskatchewan, Ontario, Nova Scotia and New Brunswick, people in those provinces who are more likely to be exposed to air pollutants from the electricity sector are expected to benefit the most from reductions in those air pollutants.^{footnote 46,}^{footnote 47}

Impacts on employment in the electricity sector

A shift away from unabated fossil fuel-based electricity generation towards low- and non-emitting electricity generation is expected with the Regulations. As outlined in the Costs subsection, there is an expectation that some unabated fossil fuel-fired electricity generating units will retire earlier or operate less than they otherwise would have without the Regulations. Workers at such locations may experience job loss and may need to relocate and undergo additional education, or vocational training, when transitioning to new employment opportunities.^{footnote 48,}^{footnote 49} In 2021, men accounted for 73% of the jobs in Canada’s electric power generation, transmission and distribution industry while 47% of electricity sector workers were at least 45 years old.^{footnote 50} As such, job losses that may be associated with the Regulations are more likely to affect men than women and are likely to have an impact on older workers, who may face age-related challenges in transitioning to new employment. Around 300 Canadian communities are at least moderately reliant on the energy sector for income and local employment.^{footnote 51} Surrounding communities may be negatively impacted by lost tax revenue and a decline in local jobs if specific electricity generating units operate less, retire, or are replaced by low- or non-emitting generation located elsewhere.^{footnote 52}

While men, older workers and specific energy-reliant communities may experience negative impacts due to lost employment, several other demographic groups may benefit from new job opportunities. Generally and in the absence of the Regulations, research and reports suggest that investments in clean electricity lead to net job creation and it is expected that there will be commensurate job growth in low and non-emitting electricity generation.^{footnote 53,}^{footnote 54,}^{footnote 55,}^{footnote 56} For example, the International Energy Agency’s November 2024 World Energy Employment report found that clean energy employment globally rose by 1.5 million in 2023 and contributed as much as 10% of economy-wide job growth in the leading markets for clean energy technologies. The solar PV industry alone added over half a million new jobs, spurred by record new installations. Electricity Human Resources Canada (EHRC) modelled job creation in the electricity sector under a path to net-zero scenario and projected 28 000 job openings, including workforce expansion of 12 000 to meet the increased electricity demand between 2023 and 2028 alone. EHRC also projects large labour supply gaps in the electricity sector in the near-term.^{footnote 57} Job creation can benefit all Canadians and presents an opportunity to build a more diverse and representative workforce. Increased access to clean electricity can also have long-term socioeconomic benefits for future generations by attracting industry and businesses that are increasingly seeking to reduce operational emissions through clean electrification.

Projected job growth in the electricity sector and labour supply gaps presents an opportunity to address the underrepresentation of women, 2SLGBTQI+ individuals, members of racialized groups, people with disabilities and Indigenous Peoples in Canada’s electricity sector.^{footnote 58}These groups are also underrepresented in electricity-related training and education programs.^{footnote 57} Many small municipalities and Indigenous communities in Canada can participate in the transition to clean electricity through partial to full ownership of renewable energy projects, which has already been identified as a source of revenue and a cost-saving measure.^{footnote 59} The federal government’s interim Sustainable Jobs Plan, launched in February 2023, may help marginalized and underrepresented groups realize their full and equal participation in the low-carbon economy.

Low-income households

Generally, and in absence of the Regulations, provinces and territories will need to make large investments in their electricity systems to meet the growing demand for electricity due to economic and population growth and electrification of the economy, which will result in commensurate increases to electricity rates. With the Regulations, it is anticipated that needed investments will shift towards low and low-emitting electric generation faster and to a greater extent than what would have been expected otherwise. As seen in the Distributional Analysis section, the incremental impact on electricity rates (over and above what would be expected without the Regulations) is expected to be low in most provinces and may even constitute a cost savings for certain provinces within the analytical period.

Affordability and energy poverty is a key concern impacting many Canadians and many households already struggle with affordability issues.^{footnote 60} Certain demographic groups, like single-parent households, particularly single woman with children, transgender men and women, non-binary people, racialized groups, Indigenous Peoples and immigrants are more likely to experience energy poverty due to a greater likelihood of having lower incomes.^{footnote 61} Households that are classified as low-income and that struggle with energy poverty are more likely than others to feel the impacts of even small electricity rate increases, making them disproportionately impacted by the incremental rate increases caused by the Regulations that may occur in certain regions.

At the same time, as articulated in the Distributional Analysis section, the Regulations may also indirectly contribute to overall household energy savings over the long-term by supporting the transition to clean electricity. Specifically, several studies have found that clean electricity can support relatively lower and more stable electricity rates, as many clean electricity sources do not require fuel as an input, which have volatile prices.^{footnote 62,}^{footnote 63,}^{footnote 64,}^{footnote 65} Furthermore, as households demand more electricity over time to power their cars and heat their homes, with commensurate decreases in demand for gasoline and natural gas, households may stand to save money over time by electrifying, even if electricity rates are rising. However, access to such savings often requires large upfront capital costs (e.g. to purchase an electric vehicle or install a heat pump), which may not always be attainable for low-income households, although work by the Department has indicated that the energy savings arising from clean electrification of homes will still offset these costs in most provinces (see the Distributional analysis). Government support, as highlighted below in the Mitigation Measures subsection, can help reduce these costs and support low-income households in accessing clean technologies that can contribute to household energy savings over the long-term.

Indigenous Peoples and Communities

While the Regulations will not apply to most electricity generating units located in remote and Indigenous communities, as they are effectively scoped out of the Regulations, Indigenous Peoples and their communities may still experience the certain distributional impacts of the Regulations as described in the previous subsections. Since First Nations, Inuit, and Métis communities can be more exposed to, and disproportionately impacted by, the adverse impacts of climate change and air pollution in Canada due to their location and socioeconomic status, these demographic groups may disproportionately benefit from any GHG emissions reductions.^{footnote 66,}^{footnote 67,}^{footnote 68,}^{footnote 69,}^{footnote 61} Climate change also threatens the displacement of Indigenous Peoples and the disappearance of Indigenous cultural artifacts, which can impact cultural identities, practices and history and could lead to the loss of Indigenous Science.^{footnote 70,}^{footnote 71} As the purpose of the Regulations is to protect the environment and human health from the threat of climate change by prohibiting excessive CO₂ emissions from the use of fossil fuel to generate electricity, the Regulations should therefore result in a net benefit to Indigenous Peoples and their communities. It is important to recognize that some Indigenous Peoples are currently employed at fossil fuel-fired electricity generating units and some Indigenous communities have invested in and own fossil fuel-fired electricity generating units, which may be negatively impacted by the transition towards low- and non-emitting electricity. However, the transition towards low-and non-emitting electricity generation expected to occur with the Regulations in place could support more employment opportunities for Indigenous Peoples and could increase the number of clean energy projects led by or partnered with Indigenous communities. Affordability has also been identified as a concern by Indigenous representatives, given that First Nations, Métis and Inuit communities and peoples are disproportionately impacted by rising living costs, including energy services for power, heating and transport.^{footnote 72}

Mitigation Measures

Given that the prohibition under the Regulations starts to apply in 2035, there is significant time for affected workforces to prepare for possible employment transitions. At least a decade of lead time and the flexibilities in the Regulations can provide workers with more certainty that the Regulations will not impact their employment in the short-term and give workers time to adapt their career pathways, if necessary. Young workers and students also have time to adapt their education and career paths to take advantage of a growing clean electricity sector. The Regulations also include an AEL on emissions (rather than an emissions intensity limit as per the proposed Regulations) and several compliance flexibility mechanisms. Regulated entities may therefore continue operation of some fossil fuel-fired electricity generating units after 2035. Additionally, unit operators can choose to invest in emissions abatement technologies like CCS, in order to continue operation of existing units. This could also increase employment opportunities.

The Regulations have been designed to effectively exempt most electricity generating units providing electricity to Indigenous communities from the prohibition given the applicability threshold of 25 MW generation capacity for a unit. However, Indigenous representatives have expressed a desire for greater inclusion of Indigenous Peoples in the clean energy transition in order to catalyze a transition away from diesel generation and promote local economic opportunities. Complementary measures that support Indigenous Peoples, communities, power producers and organizations may assist to overcome barriers and challenges that Indigenous Peoples and communities have historically faced in participating in the clean energy transition and in the development of low- and non-emitting electricity projects. The Government of Canada recognizes the important role that the clean electricity transition can play in economic reconciliation, and it will continue to engage with Indigenous partners and interested parties to build awareness of clean energy programs and funding opportunities for communities not connected to a NERC-regulated electricity system (i.e. “off-grid” communities). These efforts will support the Government’s broader commitments to reconciliation and renewed relationships with Indigenous Peoples.

The Department’s modelling suggests that the Regulations are expected to result in modest incremental impacts to electricity rates in some provinces, which can disproportionately impact low-income households. While household electrification can lead to energy savings over the long-term, further support for low-income households from all levels of government may be necessary to ensure that such energy savings are accessible to all households.

The Government of Canada is advancing a coordinated federal vision to transition Canada’s electricity sector to net-zero,^{footnote 73} which includes several measures and funding programs, such as the Clean Electricity Investment Tax Credit, the Smart Renewables and Electrification Pathways program, and strategic financing through the Canada Infrastructure Bank,^{footnote 74} which can support and accelerate the transition to net-zero electricity systems and likewise, reduce incremental impacts on electricity rates. The Government of Canada also has supports available to reduce capital costs and make clean technologies more affordable for households. Examples include the Incentives for Zero-Emissions Vehicles Program, which provides incentives for the purchase of zero-emission vehicles, and Canada Greener Homes Initiative, which includes several programs, including those tailored to low- and median-income households, to support the adoption of heat pumps and other retrofits that support energy efficiency. Several provincial and other jurisdictional programs also help to make clean technologies affordable for Canadians.

Rationale

The Regulations help to protect the health and environment of Canadians from the threat of climate change by prohibiting excessive emissions of carbon dioxide from fossil-fuel fired electricity generation. Achieving net-zero emissions in the electricity sector will also help to decarbonize other sectors of the economy, such as transportation and buildings, and aid in Canada’s commitment to achieve net-zero emissions economy-wide by 2050. This net-zero commitment was established to initiate action towards mitigating global damages induced by climate change.

These Regulations are made under CEPA, which provides authority for regulating GHG emissions. Departmental modelling shows that, relative to the Baseline Scenario, the Regulations would lead to an increase in electricity generation from non-emitting sources and the use of abatement technology for emitting sources, while significantly reducing unabated emitting generation starting by 2035, and nearly in full by 2050. Modelling results show that the Regulations are necessary, as they are under central case demand growth, for the electricity sector’s CO₂ emissions do not unduly increase under a scenario with high electricity demand growth.

A societal cost-benefit analysis was conducted for the Regulations, which indicated that they would result in a net reduction in GHG emissions of approximately 181 Mt CO₂e between 2024 and 2050 (191 including offsets) under a central scenario in which electricity demand increases by 50% between 2020 and 2050. The incremental benefit of achieving these reductions is estimated to be $54.9 billion, while the incremental cost is estimated to be $40.2 billion over the same period. This results in a net benefit to society of approximately $14.7 billion, which includes monetized emissions reductions and health benefits. This is also seen as a trend in the sensitivity analyses above.

Generally, there is a consensus that the level of electrification needed to achieve the 2050 goal could require Canada’s electricity supply to approximately double by 2050. Even in the Baseline Scenario, where the Regulations do not exist, provinces and territories are expected to make significant investments in electricity generation and transmission over the next quarter century to meet this growing electricity demand. In this context, the Department estimates that investments of more than $690 billion are needed as part of routine replacements of aging facilities and to expand generation to respond to increased demand. Population growth, economic expansion, increased volume of electric vehicles, the adoption of electric heating in buildings and the electrification of industrial processes such as steel and aluminum production would all contribute to growing electricity demand.

Without further regulatory action, Canada is expected to experience an increase in emissions from the electricity sector. Regulatory action has been determined to be the best approach to reduce excessive CO₂ emissions from the use of fossil fuel to generate electricity.

As a secondary benefit, clean electricity is quickly becoming a competitive necessity to attract investment. An increasing number of businesses are striving to achieve net-zero operations, not only to combat climate change but also to drive innovation and secure long-term sustainability and regulatory compliance. In parallel, economics is a major driver for electrification as technologies become cheaper and more competitive. Environmental, Social, and Corporate Governance (ESG) markets are surging globally and in Canada, with growth in responsible investment being driven by climate change and investor demand for ESG impact. Global markets continue to favour low carbon products because of a lower climate risk with $30.3 trillion invested globally in sustainable investing assets. Sustainable finance trends indicate that as markets learn more about the financial impact of climate change, they internalize risks and opportunities, favouring investments with lower climate risks. Sustainable investment assets are expanding across most regions, with Canada experiencing the largest absolute growth, as responsible investment assets under management surged by 94%, rising from $1.5 trillion in 2015 to $2.9 trillion in 2022. As found in the Canadian Responsible Investing Trends Report, global investor momentum to embed sustainability reporting in capital markets is observing strong effects in Canada. GHG emissions are the most common ESG factor considered in investment decisions.

Canada is already a leader on clean electricity, with approximately 85% of its electricity generation from non-emitting sources. With these Regulations, Canada will cement its place as a global leader in the transition to net-zero electricity while setting a standard for other countries to emulate, and advance progress towards a net-zero economy.

In addition to having a relatively clean electricity grid, Canada also has lower electricity costs relative to many other developed countries for industrial consumers. Canada ranks in the top 3 for electricity exporters globally and in the top quartile for both cleanliness of electricity generation and competitive cost of electricity to its industrial sector. With a strong starting position, as well as geographic diversity, access to raw materials and natural resources, an educated workforce and commitment to innovation, Canada is positioned to be a global leader in the energy transition and be a strong competitor for international commercial and industrial investment.

Regulatory action will require commensurate investment in clean electricity generation and infrastructure. While these investments will have costs, the impact of the Regulations on electricity rates is estimated to be minimal. Academic research also suggests that the overall energy transition, including both the switch to cleaner electricity and increased electrification, could ultimately reduce overall household energy expenditures over the coming decades. The Climate Change Institute’s Clean Electricity, Affordable Energy (June 2023) concludes that the average household spending on energy will decrease 12% by 2050 as people switch from fossil fuels to more efficient technologies like electric vehicles and heat pumps.

With the Regulations, the build-out of new generation will be clean and is expected to only represent a small impact to the overall cost of maintaining and expanding the electricity system. Nonetheless, the Government of Canada has announced more than $60 billion in financial support for the electricity sector to support the expansion of clean electricity generation and transmission infrastructure. This includes tax credits like the investment tax credits for clean electricity and clean technology, as well as targeted funding programs like Natural Resources Canada’s Smart Renewables and Electrification Pathways Program, and financing from the Canada Infrastructure Bank. The financial support from the Government of Canada can help utilities mitigate incremental rate impacts associated with the Regulations.

Implementation, compliance and enforcement, and service standards

Implementation

Upon publication of the Regulations in the Canada Gazette, Part II, the Department will develop and deliver compliance promotion activities, as required. This may include posting information on the Internet, sending email/letters to regulatees informing them of the publication, responding to information or clarification requests, and sending reminder letters (as appropriate).

Some provisions of the Regulations come into force January 1, 2025, with those tied to the prohibition coming into force in 2035; the AEL under the prohibition section of the Regulations comes into force starting on January 1, 2035. On the same day, the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations will be repealed. The Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity (Natural Gas Regulations) will be repealed on January 1, 2050. This means that while units may be covered by more than one regulation at a time, these regulations are coordinated so that units are only ever subject to the prohibition under one regulation. Nevertheless, a unit could be subject to the Natural Gas Regulations and still be required to meet other requirements, such as the registration requirements of the Regulations. Provisions in the Regulations state that, if a unit is subject to an emission limit under the Natural Gas Regulations, that emission limit will no longer apply if the unit becomes subject to the Regulations.

As noted in the Description section, an initial registration report is required for any electricity generating unit that is subject to the Regulations. The registration report is due on December 31, 2025, or 60 days after the day on which the electricity generating unit meets the applicability criteria, whichever comes later. For example, if a new electricity generating unit that meets the applicability criteria were to begin operating on December 31, 2027, a registration report would need to be submitted by March 1, 2028. In addition, an emissions report is required for any electricity generating unit that is subject to the prohibition. The emissions report is due as of June 1 of the calendar year following the calendar year that the electricity generating unit became subject to the prohibition. Accordingly, the first emissions report for any unit subject to the prohibition on January 1, 2035, will be due as of June 1, 2036. Moreover, a reconciliation report is required for any unit that is subject to the prohibition. The reconciliation report is due as of December 15 of the calendar year following the calendar year that the unit became subject to the prohibition. Accordingly, the first reconciliation report for any unit subject to the prohibition on January 1, 2035, will be due as of December 15, 2036.

A responsible person for a unit that is subject to the prohibition and operates during the year to alleviate an emergency must notify the Minister within seven days and must provide information on the emergency circumstance and relevant deduction periods in the unit’s emissions report. In addition, the Department will publish details of each emergency that has been declared, including the rationale for why the event was an emergency and other pertinent details, on an accessible site such as the Government of Canada’s webpage for the Clean Electricity Regulations.

Compliance and enforcement

As the Regulations are made pursuant to CEPA, Enforcement Officers will, when verifying compliance with the Regulations, apply the Compliance and Enforcement Policy for CEPA. This Policy sets out the range of possible responses to alleged violations, including warnings, directions, environmental protection compliance orders, tickets, ministerial orders, injunctions, criminal prosecution and environmental protection alternative measures (which are an alternative to a court prosecution after the laying of charges for a CEPA violation). The Policy explains when the Government of Canada will resort to civil suits by the Crown for cost recovery.

Contacts

Karishma Boroowa
Director
Electricity and Combustion Division
Energy and Transportation Directorate
Environment and Climate Change Canada
Email: ECD-DEC@ec.gc.ca

Matthew Watkinson
Executive Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Environment and Climate Change Canada
Email: RAVD.DARV@ec.gc.ca

Footnotes

Footnote a

S.C. 2023, c. 12, s. 55

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Footnote b

S.C. 1999, c. 33

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Footnote c

S.C. 2015, c. 3, par. 172(d)

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Footnote d

S.C. 2023, c. 12, ss. 33(1) to (6)

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Footnote e

S.C. 2009, c. 14, s. 80

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Footnote f

S.C. 2023, c. 26, s. 620

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Footnote g

S.C. 2008, c. 31, s. 5

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Footnote 1

SOR/2012-134

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Footnote 2

SOR/2018-261

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Footnote 3

SOR/2012-167

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Footnote 4

Under the Intergovernmental Panel on Climate Change (IPCC) accounting for the NIR, the category “public electricity and heat production” includes electric utilities and cogeneration from operations that split their North American Industrial Classification System (NAICS) reporting into two business entities.

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Footnote 5

One megatonne (Mt) is equal to one million metric tonnes.

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Footnote 6

UN Climate Action – Solutions – Net Zero, figure based on: Net Zero Tracker (2023), Net Zero Stocktake 2023, NewClimate Institute, Oxford Net Zero, Energy and Climate Intelligence Unit and Data-Driven EnviroLab.

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Footnote 7

The compilation methodologies and jurisdictional reporting to the CDD may have changed over time. The CDD webpage notes that: (i) There is currently no standardized guideline for collecting cost and loss data. Financial data can take years to finalize, and estimates are sometimes provided in the interest of keeping the database current. As such, information for recent events should be considered preliminary, possibly incomplete, and subject to change. (ii) The CDD may not be suitable for comparative analysis because of differences in jurisdictional responsibilities, the type of data that is available, and how it is collected and used over time.

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Footnote 8

Our World in Data: Greenhouse Gas Emissions, figures based on: Jones, M.W., Peters, G.P., Gasser, T., et al. (2023). National contributions to climate change due to historical emissions of carbon dioxide, methane, and nitrous oxide since 1850. Sci Data, 10:155.

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Footnote 9

Net supply means the quantity of electricity supplied to an electricity system during a calendar year, expressed in GWh, determined in accordance with the relevant formula in the Regulations. In this document “net supplier” refers to a facility with a positive net supply. During consultations following publication in Canada Gazette, Part I, the concept of net supply was called “net exports.”

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Footnote 10

Examples of major equipment might include a boiler, or combustion engine, or any other combustion devices such as duct burners, heat recovery systems and steam turbines or emission control devices and CCS system equipment and generators.

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Footnote 11

A distinctions-based approach means that the Department’s work with First Nations, Métis, and Inuit was conducted in a manner that acknowledges the specific rights, interests, priorities and concerns of each, while respecting and acknowledging these distinct Peoples with unique cultures, histories, rights, laws, and governments.

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Footnote 12

The $690 billion figure was derived by summing the total costs from 2024 to 2050 in the Baseline Scenario for new capital buildout, fixed operations and maintenance, refurbishment, and international net trade. Net trade is appropriate to include in this calculation as it represents a trade-off relative to building new generation capacity. This total does not include the costs associated with fuel nor variable operations and maintenance. In the CBA accounting, the expected incremental savings in those categories are considered benefits. Therefore, $690 billion is directly comparable against the $40 billion in incremental costs accounted for in the CBA. Please see footnotes 29 and 30 for further context.

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Footnote 13

Distributed energy resources (DERs) include small-scale energy generation and storage technologies typically installed where the electricity is used. Some examples of DER include rooftop solar panels, wind turbines, fuel cells, and energy storage systems. The use of DERs, including demand-side management and energy efficiency, is expected to be more widely utilized to support reliability as Canada transitions to a clean electricity grid.

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Footnote 14

“Inertia” in power systems refers to energy stored in rotating electrical generators (e.g. in fossil fuel, nuclear, and hydroelectric power plants), which allows them to continue rotating temporarily after a failure. Thus, inertia represents a source of stored energy that can be used briefly when a power plant fails. “Voltage” refers to the electrical pressure that pushes electrons through a circuit and causes electricity to flow, and voltage stability is an important aspect of electrical grid stability.

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Footnote 15

International Energy Agency (IEA). (2024). Denmark - Countries & Regions - IEA. IEA Data Services.

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Footnote 16

International Energy Agency (IEA). (2024). The Netherlands - Countries & Regions - IEA. IEA Data Services.

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Footnote 17

International Energy Agency (IEA). (2024). Germany - Countries & Regions - IEA. IEA Data Services.

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Footnote 18

International Energy Agency (IEA). (2024). Spain - Countries & Regions - IEA. IEA Data Services.

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Footnote 19

International Energy Agency (IEA). (2024). Ireland - Countries & Regions - IEA. IEA Data Services.

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Footnote 20

International Energy Agency (IEA). (2024). United Kingdom - Countries & Regions - IEA. IEA Data Services.

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Footnote 21

As outlined in the US EPA Report, the socioeconomic and emissions module relies on a new set of probabilistic projections for population, income, and GHG emissions developed under the Resources for the Future Social Cost of Carbon Initiative. The climate module relies on the Finite Amplitude Impulse Response model (a widely used Earth system model recommended by the National Academies), which captures the relationships between GHG emissions, atmospheric GHG concentrations, and global mean surface temperature. The socioeconomic projections and outputs of the climate module are used as inputs to the damage module to estimate monetized future damages from temperature changes. The discounting module discounts the stream of future climate damages back to the year of emissions using a set of dynamic discount rates that encompass a great deal of uncertainty.

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Footnote 22

Studies conducted by the Department of Health include the Canadian Smog Science Assessment (PDF) (2013), the Human Health Risk Assessment for Sulfur Dioxide (2016), the Human Health Risk Assessment for Ambient Nitrogen Dioxide (PDF) (2016), and the Canadian Health Science Assessment for Fine Particulate Matter (PDF) (2022).

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Footnote 23

Health Impacts of Air Pollution in Canada in 2018 (2024)

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Footnote 24

Health Impacts of Air Pollution from Transportation, Industry and Residential Sources in Canada (PDF) (2023)

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Footnote 25

United States Environmental Protection Agency. 2023. Technical Support Document – Estimating the benefit per ton of reducing directly-emitted PM2.5, PM2.5 precursors and ozone precursors from 21 sectors (PDF).

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Footnote 26

One deciview represents the minimal perceptible change in visibility to the human eye. A reduction of one deciview roughly corresponds to a 10% improvement in visual range, regardless of the initial range. The deciview scale is zero for pristine conditions and increases as visibility degrades.

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Footnote 27

Net Zero Tracker. A Distinctly Private Pursuit: Not going net zero. April 2024.

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Footnote 28

For the purposes of this analysis, no distinction was made between Crown corporations and private-sector generators.

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Footnote 29

Conceptually, the CBA treats refurbishments as the “brownfield” cost of replacing an old unit with a new unit of equivalent type and capacity. A new unit is considered brownfield when it is constructed using an old unit’s infrastructure as a basis, which is much less costly than constructing a new unit in a new area (which is referred to, by contrast, as “greenfield”). The most significant cost difference between brownfield and greenfield construction is the presence of fuel feedstock lines and electricity transmission lines that connect the unit upstream and downstream. By forgoing these expenses brownfield construction can be realized, on average, at a lower cost per MW than greenfield construction.

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Footnote 30

The breakdown of 122 affected facilities is estimated as follows: 91 facilities from NAICS 2211 (Electric Power generation, transmission and distribution), 17 facilities from NAICS 2111 (Oil and Gas Extraction), 7 facilities from NAICS 3221 (Pulp, Paper and Paperboard Mills), and 7 facilities from NAICS 3251 (Basic chemical manufacturing).

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Footnote 31

The $766 billion figure was derived by summing the total costs from 2024 to 2050 in the Baseline Scenario for new capital buildout, fixed operations and maintenance, refurbishment, international net trade, fuel, and variable operations and maintenance. As such, the $766 billion is directly comparable against the $31 billion in incremental costs net of cost-savings accounted for in this section. See footnotes 10 and 30 for further context.

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Footnote 32

The $679 billion figure was derived by summing the total costs from 2024 to 2050 in the baseline scenario for annualized new capital buildout, fixed operations and maintenance, refurbishment, international net trade, fuel, variable operations and maintenance, carbon pricing payments, and domestic net trade. As such, the $679 billion is directly comparable against the $9 billion in incremental electricity system costs accounted for in this section. Please see footnotes 10 and 29 for further context.

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Footnote 33